U.S. Coal Development--Promises, Uncertainties

Published by the Government Accountability Office on 1977-09-22.

Below is a raw (and likely hideous) rendition of the original report. (PDF)

                         DOCUMENT RESUME
03411l - [12713907]

U.S. Coal Development--Promises, Uncertainties. EMD-77-43;
B--151071. September 22, 1977. 359 pp. + 8 appendices (69 pp.).
Deport to the Congress; by Elmer B. Staats, Comptroller General.

Issue Area: Energy (1600); Science and Technology (2000);
    Environmental Protection Programs (2200).
Contact: Energy and Minerals Div.
Budget Function: Natural Resources, Environment, and Energy
     (300); Commerce and Transportation: Ground Transportation
    (404); Community and Regional Development: Area and Regional
    Development (452).
Authority: Clean Air Act. Department of Energy Organization Act.
    Energency Petroleum Allocation Act. Federal Energy
    Administration Act of 1974. Energy Reorganization Act of
    1974. Energy Policy and Conservation Act.
          Coal represents 90% of the Nation's total fossil fuel
reserves, but it currently supplies only 18% of energy needs.
The administration proposes to double annual coal production and
use 1.2 billion tons by 1985, up from 665 million tons in 1976.
This report is intended to be a reference document as well as an
identifib:a ion of the principal problems, tradeoffs, and
alternatives to assist the Congress and other decisionmakers in
formulating a national energy policy,. Findings/Conclusions:
Achieving 1.2 billion tons by 19P5 is highly unlikely--in fact,
it will be very difficult to achieve 1 billion tons annually by
1985. While the actual tonnage of coal produced and used has
increased through the years, coal use has declined relative to
other fuels. Coal is less convenient than alternative fuels and
causes more harm ':o the environment. Major areas which need to
be explored and in which policy decisions are needed include:
How such coal do we need? How much coal do we have? How do we
get the available coal? How can we get the coal to where we want
it? How can we make the coal usable? and How do we solve the
social problems involved in increased use of coal? (SC)


 U.S. Coal Development--
 Promises, Uncertainties
Coal represents 90 percent of the Nation's
total fossil fuel reserves. Yet, it currently sup
plies only 18 percent of energy needs.
The administration proposes to double annual
coal production and use to 1.2 billion tons by
1985, up from 665 million tons in 1976.
GAO believes that achieving 1.2 billion tons is
highly unlikely--in fact, it will be very diffi-
cult to achieve 1 billion tons annually by
In this report, GAO summarizes availabie
knowledge on U.S. coal development and
seeks to identify under these chapter headings
policy issues that must be considered.
       --How much do we need?
       --How much do we have?
       --How do we get it?
      --How can we get it to where we need it?
      --How can we make it usable?
      --How can we solve the social problems?
      --What is the U.S. position in ,he world
           coal market?
      --Where do we go from here?

EMD-7743                                            SEPTEMBER 22, 1977
                          WASHINGTON, D.C.   M064U


To the President of the Senate and the
Speaker of the House of Representatives

       This report presents our analysis of the prospects for
developing America's vast coal resources. The report
summarizes available knowledge on U.S. coal development,
and seeks to identify the major policy issues that must
be considered--especially if we are to achieve the coal
production and use goals in the Administration's National
Energyav Plan.
     We made our review pursuant to the Budget and Accounting
Act of 1921 (31 U.S.C. 53), and the Accounting and Auditing
Act of 1950 (31 U.S.C. 67).

     To assist our analysis, we selected two energy
scenarios--the Bureau of Mines (high-growth) energy
forecast through the year 2000, and the Edison Electric
Institute low-growth scenario.   We believe that these
scenarios represent possible ranges of high and low energy
demands, and that actual future energy demand likely
will fall somewhere between the two. The coal projections
in the Natiornal EnergL Plan were not available until near
the end of our review, but we have considered them wherever

Why is America's Coal Important?

     Coal represents 90 percent of our total fossil fuel
reserves, yet it currently supplies only 18 percent of
our energy needs.

     Our coal resources become even more important when
we consider that

    -- our domestic oil and gas supplies are limited, and
       declini-ng rapidly;
    -- nonconventional energy sources, such as solar and
       geothermal, are unlikely to contribute significantly
       to our energy supplies for the next 25 years or
       so; and
     --the Administration proposes to reduce our ever
       increasing dependence on insecure foreign energy

Why Aren't We Using More Coal?

     While the actual tonnage of coal produced and used
has increased through the years, coal use has declined
relative to other fuels.  Coal is less convenient than
alternative fuels and causes more harm to the environment.

     Recent coal prices have not been as attractive as
those of other energy resources for a number of reasons,

     -- Uncertain environmental standards (both land and

     -- Possible increased capital and operating costs
        due to environmental control requirements.

     -- Transportation and storage problems.

     -- The relative cost advantages of nuclear power.

     In the following chapters, we discuss the status,
prospects, and major issues in U.S. coal development
from the standpoints of demand, supply, production,
transportation, environmental and socioeconomic impacts,
and America's position in the world coal market.

     Copies of this report are being sent to the Secretary
Designate, Department of Energy; the Director, Office of
Management and Budget; the Secretaries of the Interior
and Transportation; the Administrators of the Federal
Energy Administration, the Energy Research and Development
Administration, and the Environmental Protection Agency;
the Chairman, Federal Power Commission; and to the chairmen
of energy related congressional committees.

                                 Comptroller General
                                 of the United States
        COMPTROLLER GENERAL'S                      U.S. COAL DEVELOPMENT--

       D I G E S T

               Why is America's coal important?

               It represents 90 percent of the Nation's total fossil
               fuel reserves. Yet, it currently supplies only 18 per-
               cent of energy needs. Coal's importance grows, however,
               when you consider that

                       -- domestic oil and gas supplies are limited, and
                          declining rapidly;

                      -- nonconventional energy sources, such as solar and
                         geothermal, are unlikely to contribute signifi-
                         cantly to energy supplies for the next 25 years
                         or so; and
                      -- depeneence on insecure foreign energy sources
                         continues to increase.
              In its National Energy Plan, the administration expects
              annual coal production and use of 1.2 billion tons by
              1985, up from 665 million tons in 1976.

              Can this Nation double its annual coal production and
              use by 1985? GAO believes not.

              GAO's recent report An Evaluation of the National Ener
              Plan pointed out tha acieving      12billion tons is
              highly unlikely--in fact, it will be very difficult to
              achieve one billion tons annually by 1985. (See pp.
              and 2.41,)                                           2.40

             This report offers the detailed analyses that support
             GAO's conclusions. GAO discusses the status, prospects,
             and major issues in U.S. coal development from the
             standpoints of demand, supply, production, transporta-
             tion, environmental and socioeconomic impacts, and
             America's position in the World coal market.
             For analytical purposes, GAO selected two energy growth
             scenarios representing possible high and low energy
             demand ranges--the Bureau of Mines (high growth) energy
             forecast through the year 2000, and the Edison Electric
             Institute low-growth scenario. Actual energy demand
             likely will fall somewhere between the two.

CereS'    Upon removal, the report
tier de*should be noted hereon.                              EMD-77-43
Wherever possible, GAO also used the coal projections
in the National Energy Plan, although they were not
available unt l near the end of the review.


There is no hard, fast figure on how many tons of coal
the Nation needs by 1985.
The coal demand estimates that are available vary tre-
mendously. The Edison Electric Institute scenario calls
for 779 million tons annually by 1985, the Bureau of
Mines says 988 million tons, and the National Energy
Plan calls for 1.2 billion tons. (See pp. 2.41 and 4.1.)
Given the objectives of reducing   energy imports and
protecting our dwindling oil and   gas supplies, the
Nation needs all the coal it can   possibly mine and burn--
without doing irreparable damage   to the environment.
Why aren't we using more coal? The actual tonnage of
coal produced and used has increased through the years,
but has declined relative to other fuels. Coal is less
convenient than other fuels and causes more harm to the
environment. Coal has not been as attractive as other
fuels for a number of reasons, including
     -- uncertain environmental standards (both land and
     -- possible increased capital and operating costs
        due to environmental control requirements,

     -- transportation and storage problems, and

     --the apparent relative cost advantages of nuclear
       power.  (See pp. 2.1 to 2.5.)

GAG believes that a substantial increase in coal use will
occur. However, there are a number of obstacles that
will hinder doubling coal production and use by 1985.
The opportunities for greater coal use are discussed in
relation to:
     -- Short- and long-term opportunities for coal use
        in the electrical sector.  (See p. 2.8.)
     -- Coal use in other sectors through direct burning
        and synthetic fuel development.  (See p. 2.23.)

             In the near term--the next decade or so--coal will
             used principally for electric power, and to a lesser
             extent to provide steam for Industrial purposes.
                                                                In the
             long term, depending on technological development
             the cost of alternative fuels, coal may be convert.d
             into gases and liquids and substituted for natural
             and petroleum. (See pp. 2.3 and 2.4.)               gas

             The electrical sector has the best potential for coal
             substitution. The 1973 oil embargo aiid subsequent
             increases stimulated Government action to force electric
             utilities and others to switch from ratural gas and
             to coal.                                             oil
                       (See p. 2.8.)
            Under the Energy Supply and Environmental Coordination
            Act, this conversion effort has noti lived up to expecta-
            tions. This is principally due to the difficulty
            cost in switching to coal and burning it in compliance
            with clean air standards. GAO believes the provisions
            of the act could be strengthened to expedite the fuel
            conversion process. (See p. 2.8 to 2.12.)

            More coal could be substituted for oil and gas by
            increasing electricity use ana efficiency. One possi-
            bility is reducing peak load electricity demand
                                                             by making
            it more expensive than off-peak electricity. Another
            improving coordination among power pools or other      is
            tric power exchange mechanisms. Another short-term elec-
            possibility is making electricity generation and use
            equipment more efficient so that less energy is wasted.

            Were all three of these actions to occur, electricity
            could become much more attractive and electric utility
            coal consumption could rise substantially. This,
            turn, would ,iean an offset to U.S. oil imports.  in
            pp. 2.12 and 2.13.)

            Over the next 25 years, coal and nuclear power increas-
            ingly will displace oil and qas for baseload electric
            capacity. Hydroelectric and geothermal energy develop-
            ment opportunities are limited and these sources
            likely to Decome significant.                    are not
                                           (See p. 2.17.)
            Until recently, utility expansion plans indicated
            nuclear energy was the apparent choice for baseloaathat
            electric power generation, because it was considered
            least costly. (See p. 2.18.)

Teat Shae
The potential for nuclear power is less certain now than
it once was, however, becase there is a growing aware-
ness that previous estimates of nuclear power have been
too optimistic.   In addition, recent moves by the admin-
istration to stop nuclear fuel reprocessing and defer
the fast breeder reactor further becloud the long-term
outlook for nuclear power. As utilities have reduced
their expansion plans, they have cancelled more proposed
nuclear powerplants than coal plants. (See pp. 2.18
to 2.23.)
in the resiCential/commercial sector, there    is not much
opportunity fco direct coal use, but a large    portion of
the increased energy use to 1985 may be from    electricity
generated with coal in lieu of gas and oil.     (See p.
The industrial sector has some potential for direct sub-
stitution of coal--as boiler fuel--but will mainly rely
on electricity.  (See pp. 2.25 and 2.26.)
The transportation sector appears to be the least amen-
able to increased reliance on coal. This s-ctor relies
on oil almost exclusively. TVie prospects for coal sub-
stitution here depend ca the

     -- outlook for electric rail transport,
     -- growth of electrified intra-city mass transit
     -- outlook for the electric car, and

     -- development of coal-based synthetic liquid fuels.
        (See p. 2.26.)
Energy demand and coal's portion dre difficult to prcject
because of three variables--population and economic
growth; composition of national output; and the cost of
energy relative to that of other resource inputs. (See
p. 2.33.)
In its earlier report to the Congress, An Evaluation of
the National Energy Plan, GAO assessed the various -adiTn-
istration recommendations to increase coal use and con-
cluded that a lot more needs co be done. (See p. 2.40.)

The work GAO was then doing for this report raised
doubts about achieving the administration's goal of pro-
ducing and using 1.2 billion tons of coal annually by

      1985. Given all the physical, economic, environmental,
      and public health considerations, it appeared
                                                     to GAO
      that producing and using even one billion tons
      by 1985 would be very difficult.                per year
                                        (See p. 2.40.)
     GAO calculated that using the average Btu conversion
     rate faccors used by Lhe administration, a
     ton shortfall in 1985 would cause the need 200 million
     tional 2.3 million barrels of imported oil for an addi-
                                                per day.
     (See p. 2.40.)
     Subsequently, using more appropriate conversion
     which reflect each end ,,se where coal would     factors
     for oil, GAO estimated , e oil shortfall noted
     2.2 million barrels of oil equ.'valent per      above at
                                                day.  (See p.
     Using this samn conversion factor analysis,
     estimates thai the oil equivalency ot the     GAO also
                                                 remaining one
     billion tons of coal could be 1.1 million
     equivalent per day less than the aoministration's of oil
     as shown ir the fuiel balance tables in the         figures,
     Plan.                                        National  Enelqi
            (See pp. 2.41 to 2 '3.)
    If this further difference implies   a real world shortfall,
    it would have to be made up in one   of three ways: addi-
    tional imports, increased dome-_ic   production from other
    sources; or increased conservation   efforts.
    2.43.)                                         (See p.

    If, on the other hand, the oil equivalent
    the National                                ncumbers in
                   'lergy Plan simply reflect a mech nical
    use t an average conversion factor from detailed
    mates based on actual quantities,                    esti-
                                        there would be no
    shortfall. However, both supply and demand
    in barrels of oil equivalent using the GAO would be less
    factors.                                     conversion
              'See p. 2.43.)
   GAO believes its work raises questions about
                                                  the oil
   equivalent figures for other domestic energy
   which in turn raises questions about the administra-
   tion's total estimates regarding energy supply
   demand. While not part of this study, GAO        and
   its analysis and will be reporting its findings continuing
   Congress.                                         to the
              (See p. 2.43.)

5aLshbSJ                      v
There are no hard, fast figures that policymakers can
rely on. Current data on coal resources and reserves
are extremely spotty and outdated.
The current "best estimate" says we have 3.9 trillion
tons of coal--1.7 trillion are called identifTe--resour-
ces, and 2.2 trillion tons are called hypothetical
(undiscovered, resources.  (See p. 3.1.)
Why are accurate data so important?

First, because coal is a finite resource and will not
last forever. Of the identified resources, 256 billion
tons presently are considered to be economically recov-
erable. That amount would last only about 74 years
under the Bureau of Mines high-growth scenario.  (See
p. 3.1.)
Secondly, certain coal with highly desirable qualities
is much more limited in supply. For example, accurate
reserve data on metallurgical coal, essential in manu-
facturing steel, could affect policy decisions on
exporting it.   (See pp. 3.16 and 8.1.)
Furthermore, coal varies greatly in terms of heat value,
pollutants, accessibility, and combustion characteris-
tics. For example, low-sulfur coal is desirable because
of air quality standards. However, most low-sulfur coal
is located in the Western States--considerable distance
from traditional coal consuming centers.   (See pp. 3.5,
3.11, and 3.12.)
Accurate reserve data on low--sulfur coal could affect
both air pollution regulations, and leasing decisions
for the vast Federal coal resources in the West.   (See
pp. 3.10 to 3.14.)
GAO believes that more accurate coal resource and
reserve data are needed to permit sound public policy
decisions on what kind of coal to mine, where, and when.

Such data could be obtained in several ways, including:
     -- Federal stratigraphic drilling and mapping.

     --Tax -r- other incentives to coal companies for
       submitting accurate, uniform reserve data to
       the Government.  (See p. 3.22.)

 We will mine it, of course, but
                                 it is not quite that
 To achieve the coal production
                                levels in the two scen-
 arios, we will have to

      --open 438 to 825 new mines,

      -- recruit and train 288,300 to
                                      531,600 new miners,
      -- manufacture enormous quantities
         ment,                           of mining equip-

     -- come up with $26.7 to $45.5
                                    billion in capital,
     -- continue to improve mining health
                                           and safety
        conditions and increase productivity.
        4.1.)                                   (See p.

The coal industry may be hardpressed
requirements.                        to meet these
               However, GAO found that 11 major
producers believe the industry                  coal
                               can double coal produc-
tion by 1985 and triple it by 2000
ditions. (See p. 4.16.)            under existing con-

This may be true, but GAO believes
                                   many things must
fall into place.

For example, mining equipment manufacturers
to fill orders promptly, and coal           will have
the foresight and capital to open producers must have
production is needed.             mines when the added
                       In addition:
    -- Coal mining productivity (tons
                                       produced per
       worker day) must improve.  It has been declining
       since 1969.  (See pp. 4.5, 4.6, 4.24, and 4.25.)
    --Good labor-management relations
                                        must be estab-
       lished.  (See pp. 4.27 to 4.31.)
    -- New workers must be found and
       includes mining engineers.    trained. This
                                   (See pp. 4.21 to
    -- Mining technology must be improved.
       4.25 and 4.26.)                       (See pp.

 The declining productivity, especially in underground
 mines, has resulted from many factors including:

      -- The 1969 Federal Coal Mine Health and Safety Act,
       ,which resulted in more personnel in the mines.
      -- The introduction of numerous inexperienced
     -- Additional personnel required per union agree-

     -- Unscheduled interruptions due to wildcat strikes
        and absenteeism.
     -- Changes in mining conditions such as quality of
        mine roofs, types and widths of coal seams, and
        distances from mine entrances to the operating
        faces.  (See p. 4.6.)
Labor-management relations might be the most important
consideration.  In years when a national agreement is
renegotiated, the lost time due to work stoppages is
considerable. In 1974, for example, eight percent of
the total worktime was lost.  (See pp. 4.28 and 4.29.)
The current national agreement will expire on December 6,
1977. This involves the United Mine Workers and the
Bituminous Coal Operators Association, Western Surface
Miners, and National Construction Contractors. A major
point of contention between union and industry at present
in the right to strike over local grievances.  (See p.
Another major constraint GAO sees is the leadtime
required to open new mines. This can range anywhere
from 1 to 15 years depending on the location and type
of mine.  (See pp. 4.10 to 4.12.)
Railroads carried 65 percent of this Nation's coal during
1975, and they will continue to be the principal coal
transporters in the forseeable future. (See p. 5.3.)

Other transportation modes also will expand as part of
the total transportation system. However, these other
modes are ultimately limited by physical, economic, and/
or environmental constraints. (See pp. 5.1, 5.2, and

          The Nation's inland waterway system,
                                                  for example, carries
          over 100 million tons of coal each
          cheapest transportation mode.       year,   and is the
                                          However, the system does
          not directly serve many areas scheduled
          development and is hindered by ice         for major coal
          physical capacity of its locks.      in the winter and the
                                            (See pp. 5.28 to 5.30.)
          Trucks cannot compete with railroads
                                                 because of costs.
          A 1974 report to the Interagency
                                            Coal Task Force showed
          truck costs per ton-mile to be five
                                                times higher than
          railroads ($.05/ton-mile vs. $.01/ton-mile).
          5.5.)                                            (See p.

          Another alternative is to build
                                           powerplants near the
          mines and transport the electricity
          voltage transmission lines. A recentover extra-high
          study, however, found this to be        Bureau of Mines
          expensive than shipping the coal  about  30 percent more
                                            on railroads.   (See p.
           Coal slurry pipelines appear to
           tive with railroads, but they are economically compet'-
                                                constrained by many
           other problems. For example, pipelines
           amounts of water at the point of           require enormous
                                              shipment--a key con-
           straint in arid western coal fields.
          problem of disposing of the pipeline There is also a
          destination.   (See pp. 5.22, 5.26, andeffluent
                                                            at the

          Coal slurry pipelines also face
                                            a big legal hurdle in
          trying to assemble rights-of-way,
          owned by the railroads.              often over property
                                    (See pp. 5.25 and 5.26.)
          Obviously it will fall to the railroads
          of any greatly expanded coal production. to move the bulk
          are confident they can handle the             The railroads
                                               amounts forecast in
          the energy growth scenarios and
                                            in the National Energy
         Plan. They expect to move 95 percent
         than they did in 1974.                    more coal in 1980
                                   (See pp. 5.7 and 5.8.)
         There will be problems, however,
                                             particularly in finding
         enough capital to purchase equipment
         ing lines.                               and upgrade exist-
                      (See pp. 5.15 to 5.17.)
         A recent survey of the railroads
         planned investments to meet 1980 showed the following
                                            coal needs:

     Item                      Total Investment
                                  (mi lions)
     Hopper cars                    $2,900
     Locomotives                       665
     Physical plant                  1,559
     Maintenance facilities            103

Over half of this investment will occur in the western
rail district.  (See p. 5.10.)
That $5.2 billion does not include the $4.9 billion,
10-year rehabilitation program for Conrail, the Federally
subsidized consolidation of insolvent eastern and mid-
western railroads.  (See pp. 5.11 and 5.19.)
GAO concludes that the Nation's transportation system
can be expanded to meet expected needs. In part, this
conclusion reflects the transportation industry's confi-
dence that transport facilities can be put into place
as fast or faster than new mines can be opened and new
boiler capacity installed.  (See p. 5.31.)
The environmental issue is paramount.

We cannot use one billion tons of coal in one year with-
out harming our environment. At least not with current
This is a tradeoff. We are relinquishing some of our
environmental quality to reduce our energy imports and
extend the life of our dwindling oil and gas reserves.
The tradeoff is made in each step of the coal fuel
cycle--mining, transporting, and using.   (See p. 6.1.)
The environmental problems fall into three general

    -- problems we have been aware of for a long time
       and have taken steps to control,
    -- problems we have more recently become aware of
       and are taking steps to control, and
    -- new problems on the horizon which we are just
       beginning to study.

               The first category primarily
               caused when coal is burned. deals with air pollution
               Congress enacted a number     Beginning in 1963, the
                                         of laws to control air pol-
               lution.  (See p. 6.2.)
              The law most affecting current
                                               coal combustion is the
              Clean Air Amendments of 1970,
              directed the Environmental      as amended. This law
              lish minimum national air Protection Agency to estab-
                                         quality standards.    This
              resulted in primary and secondary
              lished for various classes          standards  being  estab-
              and 6.3.)                   of pollutants.    (See pp. 6.2
              These standards will necessitate
                                                   scrubbers and desulfur-
               ization techniques in many
              techniques can help maintain  coal-burning  plants. These
              are costly.                     our air  quality,  but they
                            (See pp. 6.3 to 6.5.)
              CAO estimates the cumulative
              for controlling emissions to additional capital costs
              billion in 1985 and 2000,       be $19.1 billion and $26.4
             costs w uld be $1.3 billion  respectively.    Annual operating
             respect H7e year. These costsand $2.3 billion in each
             buted across the Nation, but will not be evenly distri-
             phic region. (See pp. 6.5       will vary widely by geogra-
                                           to 6.8.)
             The second category of environmental
             involves adverse impacts                 problems primarily
             mining operations.         from underground and surface

             The major reclamation problem
              ing with surface disruption.    in surface mining is deal-
                                              (See p. 6.23.)
             The Bureau of Mines scenario
                                            estimates that between now
             and 1985, surface mining annually
             square miles of land. This            will disrupt over 150
             will be digging up an area    means   that each year we
            District of Columbia.        over   twice   the size of the
                                     (See pp. 6.34 and 6.35.)
            The recent Surface Mining
            prohibits such mining in certain and Reclamation Act
            that surface-mined land be           areas, and requir.es
            ticable to its original contour.         as nearly as prac-
                                                  (See pp. 3.17 to 3.19.)
            Underground mining poses somewhat
            problems. These include               different reclamation

                 -- controlling or preventing
                                               the land from sinking,
                 -- controlling or abating acid
                    pollute underground water, drainage that can

t3IL Sort
     -- disposing of waste materials mined with the coal,
     -- controlling or extinguishing coal fires.   (See p.

These reclamation efforts aie neither easy nor inexpen-
sive. Under the Bureau of Mines scenario, total surface
and underground mining reclamation costs would be about
$1.2 billion in 1985 and $1.9 billion in the year 2000.
This is almost as much as the annual cost of operating
emission control scrubbers.  (See p. 6.32.)

The third category of environmental problems involves
those that have not yet been fully studied and for which
we cannot presently estimate all the potential conse-
quences. These include:
     -- Enormous quantities of sludge that accumulate in
        air pollution control devices and which must be
        disposed of.  (See pp. 6.20 and 6.21.)

     -- Currently uncontrolled erissions from coal burn-
        ing plants, including trice elements, particu-
        lates, carbon dioxide, and waste heat.  (See pp.
        6.15 to 6.20.)
Scrubbers may be a key element in cleaning up air pollu-
tion from coal. But, they will give rise to a whole new
pollution problem--sludge. Under the Bureau of Mines
scenario, by 1985 the amount of sludge generated each
year could be about the same as the total municipal solid
waste produced in America inoneyear. (See    pp 6 ,
6.21, and 6.50.
Coal combustion also releases about 53 elements referred
to as "trace elements." These include mercury, lead,
beryllium, arsenic, and fluorine. Coal combustion also
releases minute "particulates" of soot and fly ash.
Both the trace elements and particulates are considered
dangerous, but very little research has been done on
them.   (See pp. 6.15 to 6.18.)
Another uncontrolled substance is car'bon dioxide.   Its
build-up in the atmosphere, accordirn  to some experts,
causes a "greenhouse effect." This could eventually
cause global warming trends, and result in redistribution
of temperature patterns and rainfall levels.    (See p.

 In the years ahead as we begin to use more coal,
 more will be heard about these developing environmental
 Increased coal production will expand both the
 and communities surrounding the development areas.
 The newcomers will need public facilities and
 immediately, but the revenues to pay for them
 be available--not until the powerplants, mines,      not
 citizens begin paying taxes.                     and  new
                               (See pp. 7.1, 7.4, 7.30,
 and 7.40.)
 To meet this time lag, communities will need
                                              advance or
 front-end financing. On a nationwide basis,
                                              these costs
 might run as high as $4.4 billion by 1985, and
 $10.5 billion between 1985 and 2000. (See pp. another
                                                7.9 and
The biggest impact will be oil sparsely-populated
such as those in the West. The people brought       areas,
communities by the coal development projects     to  these
outnumber the original residenta              may   well
own social, political and moral values, will  bring their
                                         and will change
the character of the communities.   (See pp. 7.30 to
Through adequate planning and financing, the
                                              blow can
be cushioned, to be sure, but it will be a blow
less, and the social fabric of the community      nonethe-
                                              will  be
rent and another formed from it.   (See p. 9.10.)
America's coal resources make up more than 25
of the world total, and we are the world's largest
ducer and exporter.                                pro-
                     (See p. 8.1.)
Our 1975 coal exports contibuted $3.3 billion
                                               toward a
favorable balance of payments. Of the 65.7 million
exported that year, about 50.6 million tons (77      tons
were used metallurgically by foreign steel manufacturers.
Over 86 percent of that was purchased by Japan,
and the European Economic Community. (See pp. Canada,
                                                8.1 and
U.S. metallurgical coal is among the highest
the world, and both domestic and foreign steelquality in
want it for their steel making processes. (See
                                                 p. 8.1.)

Despite strong.er competition from other exporting coun-
tries, U.S. exports of metallurgical coal are expected
to increase from about 51 million tons in 1975 to
between 55 and 6i million tons in 1985, and between
70 and 77 million tons in 2000.   (See pp. 8.13 and 8.14.)
Supplies of metallurgical coal are limited, however, and
data on its production, use, and export have not been
routinely collected by the Bureau of Mines. This has
led to some uncertainty about the quality of metallurgi-
cal coal exported, and whether these exports will hinder
U.S. steel production.  (See pp. 8.1, 8.13, and 8.15.)
U.S. steam coal, used by foreign utilities to generate
electricity, is not competitive and, except for Canada,
its exports are expected to increase only slightly.
(See p. 8.13 and 8.14.)


If coal is to help reduce our dependence on oil imports
and relieve pressure on our dwindling domestic natural
gas reserves, then certain Federal Government actions
will be necessary. The administration has already pro-
posed in the National Energy Plan a number of Federal
actions to increase coal use. T-ese include

     --a regulatory program requiring coal use by
       utilities and large industries, with allowances
       for exceptions;

     --an oil- and gas-users tax and rebate/investment
       tax credit system providing an economic stimulus
       to convert to coal;
     -- an environmental policy for coal to achieve the
        energy goals without endangering public health
        or degrading the environment; and

     --a research program for coal conversion, mining,
       and pollution control technology. (See pp. 9.13
       and 9.14.)
In its report, An Evafuation of the National Energy Plan,
GAO pointed out that the administratior's plan deals
with some of the constraints to increased coal use, but
does not deal with transportation, productivity, and
other constraints to achieving 1.2 or even one billion
ton: of coal production and use in 1985. GAO noted the
need for

                   -- capital to upgrade large portions of the
                      railroads, particularly in the Eastern States,
                      together with the need to expand existing
                   -- congressional resolution of the rights-of-way
                      issue for coal slurry pipelines;

                   -- improved labor relations to prevent
                     due to wildcat strikes, together with the
                     for improved miner health and safety conditions,
                     recruitment, and training;
                   -- greater productivity;

                   -- accelerated Federal research to determine
                      health and environmental effects of burningthe
                      greater amounts of coal; and

                   -- less costly and more reliable technology
                      control air pollution from coal burning to
                      ties.                                    facili-
                             (See p. 9.14.)
             The coal industry's very short run capacity
             so) is limited to what can be extracted      (a year or
             production at existing mines (surge capacity).   increased
                                                              (See p.
             9.15 to 9.17.)
             So many interrelated elements would have
                                                       to work to
             double coal production by 1985, that GAO
             it could happen: to name only two, mining does  not believe
                                                        equipment manu-
             facturers would have to fill orders
             companies must have the foresight andpromptly  and mining
                                                    capital to be able
             to open new mines when the added output is
             p. 9.14.)                                   needed.   (See

             During the period to 1985, coal is not only
             strained, but is also demand constrained      supply con-
             that utility and industrial users are not in the   sense
                                                        going to buy
             coal if they cannot use it. There are long
             involved just in building and installing     lead times
                                                       boilers at
             existing plants, not to mention the lead
                                                       times involved
             in planning and building completely new coal
             plants. (See pp. 9.14 and 9.15.)               burning

             In the medium term (1985-2000), coal is demand-con-
             strained. The possibilities of direct substitution
             oil or gas are very limited on an economy-wide       for
             The prospect for indirect substitution by
             electricity, while more promising, is limited
             economics and the current state of industrial too by
             portation technology.                          and trans-

Tear ZShmt
Over a longer term (beyond 2000), coal seems to be both
supply-constrained, especially in terms of low-sulfur
and metallurgical coal, and demand-constrained. GAO
believes that the very long-term prospects for increased
coal demand ride upon the hope of coal gases and liquids
becoming environmentally-safe and economical.  (See p.
These, ther, are the physical and economic limits of the
coal solution.
If maximum coal output and consumption can be achieved
within these limitations, the tradeoffs will be costly,
particularly in terms of human life and disease.  These
tradeoffs can only be considered tolerable when viewed
in the broader context of the Nation's inadequate oil
and gas resources as well as the risks and limits of
nuclear power.  (See p. 9.15.)
Indeed, the coal tradeoffs are important enough to
reemphasize the need for vigorous energy conservation--
not as an alternative to coal, but to temper somewhat
coal's very high social and economic costs. (See p.
Because of the long leadtimes to translate Government
policy and action into actual coal production and con-
sumption, GAO believes it is realistic to assume that
government policies set in motion now will have some
effect by 1985, but the greater impact will be in the
1985-2000 period.  (See p. 9.15.)
With all the constraints, however, increased coal use in
absolute terms will still be substantial.  Electric util-
ity plans through 1985 call for an increase of over 300
million 'ons.  Given all the constraints, this is prob-
ably on the high side, but it is unclear how much. Indus-
trial use will increase also, but more slowly. (See p.
There is no question that coal will supply a large part
of the Nation's energy future. So will foreign oil and
nuclear power. Natural gas will decline and probably
have to be restricted to optimum end uses such as home
heating, etc.; domestic oil will decline. Solar energy
will increase slowly, aF a complement to other fuel
types.  (See p. q.17.)
On the demand side, che best answer to the Nation's
energy bind is conservation, through increased effi-
ciency and decreased use.   (See p. 9.17.)

Agency Comments
A draft of this report was provided to numerous
agencies for their review. The agencies generally
with the report, and their comments were considered agreed
preparing the final report.
A copy of the final draft was provided to the Energy
Policy and Planning staff in the Executive Office
the President. The staff's only major area of       of
tive disagreement is with GAO's conclusion that substan
be very difficult for this Nationi to produce and it will
one billion tons of coal annually by 1985. The     use
comments are included at page VIII.1. GAO's evaluation
of those comments begins on page 9.17.




   1      INTRODUCTION                                 1.1
               What is the problem?                    1.1
               Is coal the answer?                     1.1
               What are the tradeoffs?                 1.3
               what are the alternatives?              1.5
               What's in this report?                  1.8
   2      HOW MUCH DO WE NEED?                         2.1
               A perspective on challenges
                 to coal use in the overall
                 energy market                         2.3
               Substitution of coal for other
                 fuels in the electrical sector        2.8
               Substitution of coal in other
                 sectors                               2.23
               Implications of coal use for
                 widely different energy needs
                 and use patterns                      2.33
               Summary                                 2.43
  3       HO' MUCH DO WE HAVE?                         3.1
               Coal resource and reserve concepts:
                 Definition and measurement            3.2
               Problems related to the determination
                 and recoverability of U.S. coal
                 resources and reserves                3.6
               Summary                                 3.22
  4       HOW DO WE GET IT?                            4.1
               Description of the coal industry        4.2
               Productivity                            4.4
               Industry requirements to meet
                 expanded production                   4.12
               Research and development to increase
                 productivity and to finance mine
                health and safety                      4.52
              Summary                                  4.56

                                               IT?     5.1
                Adequacy of the Nation's transpor-
                  tation system to move coal
                Expansion o0 railroad capabilities     5.3
                Coal slurry pipelines and Western      5.7
                  coal development
                Future coal transportation on
                  the Nation's waterway system
               Air quality                            6.1
               Economic and environmental effects
                  of coal development
               Air quality: Prohlems and concerns     65
               Mining and Reclamation                 6 0
               Economic impact of reclamation         6.2
               Discussion of the mining and
                 reclamation concerns
              Availability of water for energy
                 development                         6.41
              Environmental control research
                 and development
              Summary                                6.45
               Accurate and timely information:      7.
                 A planning necessity
               Initial financing will be required    1.1
                 by local governments
               Social changes caused by coal         7.4
               Planning for long-term economic       7.30
              Geographic differences of the
                 effects of coal development
              Summary                                7.39
 CHAPTER                                                    Page
             THE WORLD COAL MARKET?                        8.1
                World coal                                 8.2
                U.S. coal                                  8.10
                U.S. metallurgical coal in the
                  World market                             8.15
                Coal use in the European Economic
                  Community and in Japan
                Summary                                    8.29
    9      WHFRE DO WE GO FROM HERE?                       9.1
                Substitution                               9.3
                Supply constraints                         9.4
                Abatement costs                            9.6
                Tradeoffs                                  9.8
                Special concerns for policymakers          9.10
                Necessary Federal actions                  9.13
                A final note                               9.14

   I       Technical appendix on models                    I.1
  II       A further look at coal consumption
             in 1985 and 2000
 III       Current Federal efforts to accelerate
             coal development through research          III.1
  IV       Possible future changes in transportation
               of coal to public utilities

Letter dated August 26, 1977, from the Energy
  Policy and Planning Staff in the Executive
  Office of the President
                              CHAPTER 1

       In late 1973 and early
 quadrupled the price of crude1974,
                                     the international oil cartel
 nations within the cartel temporarily in addition, the Arab
 to the United States. These acti.,n9--onewithheld oil shipments
 political--made it very difficult            economic, the other
 the unpleasant facts about U.S.     to ilnore for any longer
                                  domestic oil supply. U.S.
 proved oil reserves and production
                                      had, indeed, been declining
 since 1970.   The Nation had relied increasingly
 imports to fill the gap between                    upon oil
 ply and growing domestic consumption.        domestic oil sup-

      The lesson to be drawn from those
 was simple enough:                       international events
                      imported oil is vulnerable--to
 tions in supply and to large price                   interrup-
 premise, the policy                 increases.   And given this
 can the United Statesconsideration is easily agreed upon:
                        become less dependent                 How
                                               on oil imports
 to meet its energy needs?

      But from here on, nothing is simple
States is even more reliant on oil          or easy. The United
 in 1973--oil imports account for     imports  today than it was
sumption, compared with 35 percent 42  percent  of U.S. oil con-
                                      4 years ago.   This is a
tribute to both the complexity
of our energy system as         and   short-term  intractability
cal institutions have inwell  as to the difficulty our politi-
                          grappling with them. Energy
decisions inevitably cut across                           policy
                                 many deep-seated special
interests--regional, economic, and
result is political conflict which environmental--and the
to resolve. Decisions about coal is especially difficult
                                    are no exception.

      Coal is part of the
 interest today in coal as answer.    That there is
                            an alternative energy renewed
increased development might reduce                     source whose
imported oil is due to coal's principal,        States  reliance on
attribute--there is a lot of it.               perhaps  only
it seldom occurs where you need      Coal is dirty; it is bulky;
in quality, in terms of chemical   it;  and it varies widely
                                    impurities, heat content,
and combustion characteristics.
development, coal has problems--inAt every stage of its
                                       mining, refining,
transporting, storing, and burning.
therefore, that coal demana has           It is not surprising,
to other energy sources, especially      declining   relative
for the past 15 years. In 1950          oil  and  natural  gas,
the United States' total energy coal met 34 percent of
                                  demand. By lC75, it had sunk

to 17 percent. Commercial, household, and transportation
uses of coal have dropped to almost nothing. In industry,
coal declined from 46 percent of the energy consumed in
1950 to 19.5 percent in 1975. Only in the electrical
generation sector has coal held its own. In 1950 some
45 percent of the energy consumed by electric utilities
came from coal.  In 1975 it was just a point lower
--44 percent.

      From the standpoint of national energy planning, coal
poses some special problems, the foremost of which is that
coal is not readily substitutable for oil. In transportation,
which accounts for 53 percent of U.S. oil consumption, it is
not currently substitutable at all; its transportation poten-
tial lies with development of electric locomotives, and
light, short distance road vehicles, and possibly some
synthetic liquid fuels from coal in the future. In space
heating and air conditioning, the substitution possibilities
are usually indirect--oil is replaced by electricity, some
of which is generated in coal-fired plants.   In the industrial
sector oil boilers can be replaced with coal boilers, but it
is expensive and because of the inherent disadvantages of
coal--bulk and dirt--industries tend to substitute electricity
for oil instead.   In the future, synthetic gas and liquids
could supplement supplies of the industrial and residential/
commercial sectors if the economic, technological, and politi-
cal problems are resolved.   Even the most promising area for
direct substitution of coal for oil--the electric utility
sector--is fraught with uncertainty. To date, utilities have
not reconverted many oil-fired pla ts to coal. There are
several reasons for this reluctance including the high cost
of capital in general, the capital cost differential between
oil and coal plants, the greater cost of pollution control
for the coal plant, and the nuisance factor of handling coal
compared to otter fuels.

     For electric utilities to expand coal use, they need
stability of coal supply and use conditions over the life of
their generating stations in order to make affirmative coal
decisions. Similarly, coal producers and transporters
require long-term commitments for the development of mines
and transportation systems. Factors of stability include
the environmental conditions, cost, and associatea technology
under which coal i: mined, transported and burned. Federal
and State air pollution controls have been in a state of
flux since 1968. Air pollution legislation has forced utili-
ties into long-term technology investments for which they
question the reliability and permanence. Major changes in
State severance taxes can also add to the uncertainty of
long-term investment decisions made by utilities, mining
companies and transporters of coal.

       Further, it takes time if the utility decides, in
 of the uncertainties, to substitute coal for oil. It spite
 5 to 10 years to plan, build, and make operational a takes
 fired powerplant.                                     coal-
                     (For a nuclear powerplant, which also is
 subject to uncertainties, it takes even longer--10 to
 years.) In other words, plans started today for new
 city to increase coal's share of the electricity generation
 market by replacing oil cannot have any impact on oil
 until at least 1982.                                   imports

      There is no question, however, about coal's abundance.
 U.S. coal reserves contain three times as much potential
 energy in Btus as Middle East oil reserves. Even under
 projections for coal demand, U.S. domestic coal supplies high
 should be adequate for at least another 70 to 80 years
 maybe longer at comparatively reasonable prices.

      Coal is presently mined
which can be grouped roughly in  seven coal mine provinces
                              in three broad geographic regions.
The Eastern region, the oldest coal producing area in
Nation, encompasses most of the Appalachian States. Bituminous
coal found and mined in this region, generally characterized
by high heat value, includes valuable metallurgical  or coking
coal prized by the steel industry here and abroad. In
most of the U.S. coal exports, which annually account fact,
                                                       for about
11 percent of total U.S. coal production, come from this
The sulfur content of this region's coal varies, but only region.
about 20 percent of available deposits are estimated to
sulfur content requirements of the Clean Air Act.

    Moving west, the Ohio, Illinois, and Indiana area has
large deposits of bituminous coal, unfortunately with
sulfur content. Its current market as a fuel for utilities
is limited, primarily because of air pollution regulations.
Surface (strip) mining is dominant in this region.
     Most coal reserves of the United States are found in
Western coal region. These large reserves of the subbituminous
and lignite varieties have a relatively low heat
also a low sulfur content. Thick seams close to value   but
                                                 the surface
make cheaper stripping methods the logical technique of
mining. It is here that large-scale new coal development
expected to occur.

        Energy policy decisions relate to certain broad national

        -- reliability of supply,

    -- efficient resource allocation,
    -- minimum environmental damage,

    -- independence of foreign policy,
    -- equitable distribution of costs, and

    -- economic growth.

     Our starting point is the first energy policy goal--
reliability of supply. Specifically, can the t';iited States
achieve reliability of energy supply through increased depend-
ence on domestic coal? And equally important--what are the
costs--human, environmental, economic, and social--of increas-
ing coal production? Can these costs be mitigated?

     We have attempted in this report to identify those costs
which cannot be fully mitigated; this is crucial for it is
the only way the tradeoffs can be weighed. For example,
some farmland which is stripped for coal and then carefully
recovered to close to its former condition, may not regain
its original productivity per acre. Is this irreversible cost
worth the contribution made to reliability of supply?
     For another example, there are certain irreversible human
costs to achieving this goal. Underground coal mining is the
most dangerous occupation in the United States. However
vigorously health and safety regulations are pursued, in a
mining operation some miners are going to get black lung
disease (pneumoconiosis) or meek with accidents, many fatal.
This is another tradeoff for greater reliability of supply.
Or for another example, increased coal development in
Sweetwater County, Wyoming, will inevitably change the
fabric of that area's way of life--it will become noisier,
more impersonal, and less relaxed, regardless of the socio-
economic countermeasures which are implemented. This is a
tradeoff for greater reliability of supply.
     for further example, increased coal consumption will
lead directly to increased levels of small particulate pollu-
tion because, as yet, there exists no known technology for
control on a large scale. According to public health experts,
small particulate pollution increases the incidence of
respiratory disease. This is a tradeoff too--increased
reliability of supply through increased coal production
is acbieved and one of the expenses is diseased lungs in

an indeterminable number of persons. Finally, to what degree
should supply reliability through coal development be achieve
in relation to the other major alternatives--particularly
nuclear power, energy conservation, and the renewable energy
resources (solar, geothermal, fusion)? It is only through
a consensus reached on these kinds of tradeoffs that energy
decisions can be made.


      The means of attaining energy policy goals have been the
 subject of debate in the administraticn, the Congress, and
 the Nation. Energy legislation enacted since the international
 oil crisis includes the Emergency Petroleum Allocation Act,
 the Federal Energy Administration Act, the Energy Supply and
 Environmental Coordination Act (ESECA), the Energy Reorganiza-
 tion Act, the Energy Policy and Conservation Act (EPCA),
 the Energy Conservation and Production Act (ECPA), and,
 recently, the Surface Mining and Reclamation Act of 1977 and
 the Department of Energy Organization Act. President
Carter's National Energy Plan is a further step in the direc-
tion of identifying national energy problems, goals, and pro-
grams. All these measures constitute a partial framework in
which a national energy policy can be pursued. But ultimate
decisions have yet to be made concerning the role of conserva-
tion, an acceptable level of foreign oil imports, the use of
coal, research and development for synthetic fuels and
renewable energy resources, the long-term future of nuclear
power, and the balance to be struck between the various
energy policy goals--supply, environment, efficiency,
foreign policy, equity, and economic development.   In other
words, many energy steps taken to date are in the right
direction and are not inconsequential, but given the unresolved
issues and the dimensions of the problem we are still very
far away, indeed, from implementation of a full-fledged
national energy policy.

     A plethora of unresolved energy problems, such as air
pollution (including the increasing carbon dioxide loads in
the atmosphere), oil imports, and nuclear waste build-up,
still confront us. The potential for saving Btus by more
efficient end use of energy is sufficiently large that it
alone could substantially reduce the magnitude of these
unresolved, energy supply problems.

     There are many levers available to the Federal
if it chooses to favor a given energy option such as Government
conservation. Through regulations, the Government can require
that energy efficiency performance standards be met for cer-
tain products. Through the tax system, the Government can
provide incentives for the installation of more energy

efficient systems. The Government can also subsidize energy
conservation--through direct payments to help meet the capi-
tal costs of more energy efficient systems or through support
of development and demonstration of conservation technology.
     An equally wide variety of levers is available to the
Federal Government if it chooses to push the coal option but
at the same time gets involved directly in trying to mitigate
the human, environmental, and socioeconomic costs of increased
coal production. The Government could, for example, national-
ize the coal industry, as most other Western industrialized
countries have done. Great Britain is an example. By nation-
alizing the coal industry, the Government assumes direct
responsibility for controlling coal's consequences and for
coal's future capital investment. Whether or not the Govern-
ment's relative success, if any, in this regard would be
worth the tradeoff of diminished free enterprise is another
matter. We have not seen evidence in our review to support
such a conclusion. A variation on the nationalization
approach is being tried in West Germany where the government
consolidated the coal industry into three operating companies
under the control of a semipublic holding company. The
West German government provides substantial direct subsidies
to the industry while at the same time taking part in the
industry's decisionmaking process by having public repre-
sentatives on all key industry executive boards.

     Near the other extreme, the Government could rely soleiy
on its tax powers to tilt the energy market in coal's favor.
It could, for example, raise coal's 10 percent depletion
allowance as well as raise the ceiling on the amount of
income to which depletion can be applied--currently depletion
cannot exceed 50 percent of a company's income. Actions
such as these would make coal more competitive, though not
necessarily more economical. Alternatively, it could,
for example, put a $5 tax on every barrel of imported
oil, or lower the uranium 20 percent depletion allowance.

      In addition, the Government could use its taxing powers
to discourage adverse environmental effects on coal consump-
tion.   It could, for example, place a graduated tax on the
amount Cs pollution emitted by utilities.

     Another option the Government could take is to pay for
the pollution control devices needed to make coal as
competitive as possible from an environmental standpoint.
Still another option, very controversial, would be to recon-
sider the present sulfur limitations.

     The Federal Government currently relies almost exclu-
sively upon its power to regulate in order to mitigate the
consequences of increased coal production and consumption,
especially in the areas of miner safety and health, air
pollution, and strip mining on public lanas.

     At present, there are so many different Federal policies
that affect coal's development, many of which seem to work
at cross-purposes. It is literally impossible to say whether
their net effect is to encourage or discourage coal develop-
ment. For example, the Federal Government encourages coal
in relation to oil or natural gas by subsidizing a greater
portion of its research and development. On the other hand,
the Government discourages coal in relation to oil by pro-
viding oil with certain tax advantages such as the foreign
tax credit. In the opposite direction, the Government
provides a substantial indirect subsidy to coal by paying
a pension to miners who have contracted pneumoconiosis.
This kind of back-and-forth analysis could go on and on.
we do not try to address all of these options in this report,
but we do attempt to deal with the more important ones.

     One conclusion can be drawn. It is clear that the energy
market in which we find coal today bears only the slightest
resemblance to the classical economic model of a free market.
For better or worse, Government decisions influence the
future of this industry every bit as much, if not more, than
do the individual, microeconomic decisions of the market's
private sellers and buyers. Government decisions affect
everything from the rate a railroad can charge for hauling
a ton of coal from Montana to Chicago, to the sulfur content
of coal which a Chicago utility is allowed to burn.

      President Carter's National Energy Plan relies heavily
on regulatory, economic, environmental, and research and
develorm.ent policies to stimulate expanded use of coal to
help ill the growing gap created by (1) rising energy demand
and (2) relatively stable or declining production of domestic
oil and gas.
     The administration estimates that the plan would increase
the use of coal in 1985 to 1.2 billion tons. Without the
plan, the administration estimates that coal production will
reach 1 billion tons in 1985. The administration's plan

    --a regulatory program to require coal use by utilities
      and large industries.

         -- an oil- and gas-users tax and rebate/investment tax
            credit system to provide economic incentives to
            convert to coal;
         --an environmental policy for using coal to minimize
           risks to public health and environmental damage; and
         --a research program for coal conversion, mining, and
           pollution control technology.
     These proposals are assessed in an earlier GAO
entitled An Evaluation of the National Energy Plan. report
     Although the administration's plan deals with some of
the constraints to increased coal production, it does not
deal with transportation, productivity, and other constraints
that will, in our opinion, make the achievement of even
1 billion tons of coal production in 1985 highly unlikely.

     This report discusses the implications of reaching coal
production and use levels of about 1 billion tons by 1985 and
1.5 billion tons by 2000. Our work indicates that there are
many tradeoffs that must be accepted and many problems that
must be resolved to achieve these levels. Some of the trade-
offs have been pointed out above. In our earlier report to
the Congress, An Evaluation of the National Energy Plan, we
identified a number of problems thaw would need to be resolved
in order to reach the coal production and use objectives of
the administration. These problems include the need for

     -- capital to upgrade large portions of the Nation's
        railroads, particularly in the eastern States, to-
        gether with the need to expand existing capabilities;
     -- congressional resolution of uncertainty concerning
        the issue of rights-of-way foL slurry pipelines;
     -- improved labor relations to prevent disruptions due to
        wildcat strikes, together with the need for improved
        miner health and safety conditions, recruitment, and

*Note:    Numbered footnotes to ch. 1 are on p. 1.14.

      -- greater manower   and equipment productivity;

      -- accelerated Federal research to determine the health
         and environmental effects of burning greater amounts
         of coal; and

     -- less costly and more reliable technology to control
        air pollution from coal burning facilities. 2/

     These and other problems are discussed further      in the
main body of this report.

     This report synthesizes existing literature and informa-
tion on the coal energy supply option and addresses the areas
of coal demana, resources, and production, as well as the envi-
ronmental, socioeconomic,  and international implications of
coal development.  The report is intended to be a reference
document as well as an identification of the principal problems,
tradeoffs, and alternatives to assist the Congress and other
decisionmakers in formulating a national energy policy.

      In performing the study, we researched literature on the
subject and discussed coal development problems with represen-
tatives of numerous Federal agencies including the Departments
of the Interior, Transportation, Labor, and Agriculture; the
Energy Research and Development Administration; the Interstate
Commerce Commission; the Federal Energy Administration; the
Environmental Protection Agency; the Federal Power Commission;
the Federal Trade Commission; and the Office of Management and
Budget. We met with representatives of various State agencies,
institutions of higher education, coal producers, coal mining
equipment manufacturers, coal transportation companies, coal-
related trade and union organizations, electric utility
companies, and coal exporters.   In addition, we discussed
international implications of U.S. coal production with repre-
sentatives of the Organization for Economic Cooperation and
Development in Paris.

      In the following chapters, we have usea two long-term
energy scenarios as analytical tools--the Bureau of Mines
study, United States Energy Through the Year 2000 (Revised) 3/
and the Edison ETectric Institute   ow-growth case from its
study, Economic Growth in the Future. 4/   We also have ",sea
projections from other sources, including President Carter's
National Energy Plan in some cases.

     Table 1 summarizes the two scenarios we used. Comparative
analysis of these projections, however, requires a strong word
of caution. Each scenario was performed at different times,
using different assumptions about economic growth, prices,
Government policies, demand elasticities, and so on. They
serve to give us a feeling of the overall parameters of ex-
pectation in this area; we do not view either of them as the
"right" projection. The real world will undoubtedly fall
somewhere between the two with a mix of fuel supplies and
demands somewhat different than both.

      These scenarios do not show regional coal supply and
demand projections, but rather present gross national numbers.
For purposes of our study, we wanted to disaggregate the gross
numbers on a regional basis. For this regional analysis, we
assumed that (1) all future mine openings and additions pro-
jected by the coal industry up to 1985 would actually occur,
(2) the coal required to be replaced from mine retirements
for the period 1975-1985 would total 137 million tons, and
(3) heat content for all coal mined in a particular State
would remain constant.   Industry data on coal mine expansion
is not available after 1985. To make projections for the year
2000 under these circumstances, we further assumed that (1)
any necessary deletions or additions required to meet the sce-
nario levels in 2000 would be made based upon each State's
proportional contribution to the estimated total U.S. mining
capacity in 1985 and (2) the proportion of underground and
surface coal production would remain at the same level after
considering all mine capacity additions and deletions in 1985.

     For coal demand in the electric utility sector, we assumed
that (1) all plants which were designed to use coal as a boiler
fuel would use coal, (2) new plants will come on-line as
scheduled, (3) plant retirements will occur at an annual rate
of 2.5 percent, (4) 1975 heat rates, i.e., Btus required to
produce 1 Kilowatt hour of electricity, for geographic regions
will continue. (5) coal-fired plants will continue to operate
at 46 percent capacity in 1985, but in 2000, capacity utiliza-
tion will increase to 60 percent, and (6) any necessary addi-
tions required to meet scenario levels in 2000 will be made
based upon each region's proportion of the new total additions
during 1975-85.



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                                                                    4)            wC0 u               0     4)              UU                           l         01         V
      In this report, we attempted to standardize our reporting
 on a three-region geographic basis--Eastern, Central,
 Western.  When we began to accumulate our source information,
 however, we discovered that a consistent presentation
                                                       was not
 entirely possible because the source data included diverse
 geographic areas--one State only, Southeastern Appalachian
 States, Rocky Mountain States, or other combinations.
                                                        In cases
 where the source data permits, we present the information
 on a three-region basis; otherwise, we present the information
 as it was originally developed.

      In preparing this report, we received comments from
varied group of consultants knowledgeable about coal
related areas.   This di_ rse group included individuals
in the fields of economics, finance, and geology as well
those with experience in coal production and environmental

     A draft of this report was reviewed by various Government
organizations.  Their formal comments have been recognized
in finalizing the report.  The organizations include:
     -- Department of Labor.

     -- Department of the Interior.

     -- Department of Transportation.

     -- Department of the Treasury

     -- Energy Research and Development Administration.

     -- Environmental Protection Agency.

     --Federal Energy Administration.

     -- Federal Power Commission.

     -- Interstate Commerce Commission.

     --Tennessee Valley Authority.

     -- Office of Management and Budget.

     -- Department of Commerce.

     In the chapters which follow, we first discuss the
for coal in the various economic sectors.  This is followed by
an analysis of coal reserves in chapter 3. The next

chapters present data on coal
                              supply and methods for trans-
porting it to relevant markets.
environmental and socioeconomic Chapters 6 and 7 discuss
                                constraints associated withthe
coal usage and supply. Chapter
foreign trade. Chapter 9        8 discusses U.S.
                          presents the principal coal in
of the report. Several special
in the appendices.              considerations are discussed

                    FOOTNOTE REFERENCES

1/United States General Accounting Office, An Evaluation of
  the National Energy Plan, EMD-77-48 (Washlngton: U.S.
  General Accountinc; Office, July 25, 1977), Chapter 5.
2/Ibid., p. 5.1.
3/Walter G. Dupree, Jr. and John S. Corsentino, United States
  Energy Through the Year 2000 (revised) (Washington:
  Government Prinfing-Tiice, -1975----p. 1-65.
4/Edison Electric Institute, Economic Growth in the Future
  (New York: McGraw Hill, 1976T,ppT 1T7rT69.

                            CHAPTER 2
                       HOW MUCH DO WE NEED?
       Energy fuels serve two separate categories
  A consideration of these needs (along with        of needs.
  forms of fuels suitable for them) is necessary   types and
  reasonable projection of the demand for          to form a
                                           coal and the cap-
  ability of coal to supply energy needs
  expected conditions.                    under present and

        One category of fuel need involves
  sector--automobiles, trucks, railroads, the transportation
                                            airplanes, and ships.
  Coal once fueled some of these transportation
  longer does. Synthetic liquid fuel from          modes, but no
  short-term reality, but may be a source    coal  is not a likely
                                            of transportation
  fuel in the future. There are some other
 opportunities for coal in this category,     potential
 electrified mass transit systems and the    in the form of
                                             electric automobile.
       The second need category is for stationary
 tion plants, such as electric utility generating
 and commercial and industrial heating systems.       stations,
 coal has the capability to replace oil              In this area
 some extent in existing plants, but more and  natural  gas--to
                                             importantly for
 new growth.

     This chapter focuses on determinants and
for greater coal demand between                opportunities
                                now and 1985, and 2000.    It
considers future demand as assumed in
for analysis, as well as the future demand scenarios selected
National Energy Plan.                       assumed in the

      In relative terms, coal demand has been
more than half a century. 1/ Even as late       declining for
                                             as  1950, coal
supplied 20 percent of energy in the transportation
36 percent in the household/commercial sector, and     sector,
50 percent of fuel in the industrial sector.          nearly
                                                2/ However,
by 1975 coal was no longer a significant
the transportation or household/commercialfactor   in either
                                             sector, and its
share of the industrial sector
declining. 3/ In the meantime, was  22 percent and apparently
                                 coal's share of the electrical
sector equalled roughly 44 percent, down
                                          from 53 percent a

Note:   Numbered footnotes to ch. 2 are on pp.
                                               2.47 to 2.53

decade earlier.* 4/ Despite this historical trend away from
coal, many policymakers view coal as a major substitute for
other fuels, particularly imported oil.

     What are the determinants and opportunities for greater
coal use? These matters are discussed in the following four

    -- A perspective on coal use in the overall energy market.

    -- Substitution of coal for other fuels in the electrical

    -- Substitution of coal for other fuels in other sectors,
       through direct burning and synthetic fuel development.

    -- Implications of coal use for widely different energy
       needs and use patterns.

     The discussion on fuel substitution focuses on the pos-
sibilities of increased coal use in various sectors of the
economy, leaving foL later discussion the implications of
varying overall energy needs.  The section on the electrical
sector has two main parts.  The first focuses on what appears
possible regarding short-term increases in coal energy inputs.
The second part examines present planning for coal use over
the next decade or so.  The discussion in this and other
sections emphasizes prospective coal use in the period tv 1985,
though we do consider some developments to 2000.  This emphasis
on the next eight years principally reflects the state of
available knowledge and data.

     In the third section, we discuss the implications of coal
for diverse energy needs and use patterns and we note that
past efforts to forecast these patterns have not been very
successful.  The purpose of this section, however, is not
to predict, but rather to explore the possible range of coal
use patterns in the context of varying energy needs. To do
this, we chose scenarios for consideration which vary widely
in terms of total energy growth, as well as in the mix of
fuel supply.

     Our main observation is that coal use will increase
significantly in absolute terms due to the expanding energy
market but it may not gain a larger percentage share of
that market than it now has. Present and prospective

*Of course, in absolute terms, coal experienced modest growth,
 especially in the electrical sector.

 circumstances do not inevitably lead to greater relative
 coal use. While coal is comparatively inexpensive in terms
 of heat content, the true economic cost of burning coal must
 take into account the costs of transportation, distribution,
 handling, and pollution control.

      Thus far, decisionmakers and forecasters have been
acting as if a shift to coal from other fossil fuels may not
occur.   To change this outcome, substantial changes
needed in coal's relative attractiveness as an energyareinput.
Over the next decade or so the chief determinants of coal
use for electrical power generation will be (1) pollution
control costs and (2) development of cheaper, more flexible
transportation of coal in raw form or as electricity, etc.
In the longer perspective the potential for further coal
development will depend on whether it can be economically
manufactured into gas or liquids. Such technological improve-
ments would have dramatic consequences for coal demand in both
the intermediate and longer terms. A consensus of energy
forecasts, however, reflects doubt that such developments
will occur. For the period beyond 1985, the most important
variables affecting coal demand are the rate and direction
of technological changes for coal and the competition with
nuclear power, not the trend in total energy needs.


      Coal is by far our most plentiful fossil fuel energy
source under present technological capability. Oil shale
is plentiful but not usable with existing technology. For
the next several decades coal and nuclear energy offer the
best hope of reducing our dependence on overseas energy
sources, and of conserving our dwindling supplies of natural
gas and petroleum for uses to which they are today uniquely
suited. However, there are disadvantages to the greater
use of coal, and some believe for environmental and health
reasons that every effort should be made to restrict its use.

     To determine the probabilities of how great the demand
for coal will grow in the next decade and beyond, it is
helpful to examine the factors which have influenced choices
between competing fossil fuels--coal, oil and natural gas--
in the past, and then to determine to what degree each of
these factors will contribute to fuel decisions unde: current
economic, environmental, social, and international conditions.

     It is also necessary to compare the extent of demand
fluctuations between these fuels in recent years, and to
study the relationship which each has to the other--both in
total demand and in the competitive process.

     Coal was the initial fuel (after wood) for stationary
uses, as it was also for running railroads and steamships,
and it retained its dominance until about the end of the first
third of the twentieth century. Then, for various reasons,
a rather massive movement toward residual oil for large
furnaces and steam turbines, to distillates or light heating
oil for homes and other small heating plants, diesel oil for
railroads, and natural gas for everything from residential/
commercial heating to industrial and utility use took place
from the end of World War II through the 1960s.

     All in all, the demand for coal, once the Nation's
principal energy source has been declining relative to
other fuels for about half a century. Why did this happen?

     The causes for coal's relative decline irnclude the
development of means to capture and transport cleaner and
more convenient fuels, notably natural gas, and the demise
of both coal-fired locomotives and furnaces in residences.
However, these events may merely be symptoms of a more
fundamental deficiency of coal.

     Coal is the least convenient fossil fuel.. It is bulky,
causing difficulty in handling, storing, or transportation.
It creates problems when extracted and when burned. Indeed,
efforts to develop coal slurry pipelines and make synthetic
fuels from coal can be viewed as attempts to make coal as
much like oil and gas as possible. Aside from use in metal-
lurgical production processes, coal will be consumed only
when its costs are sufficiently below those of other alter-
native fuels to outweigh its disadvantages, or when the
national interest clearly requires it as against greater
use of foreign oil and scarce domestic oil and gas. 5/

      In the last several decades, coal use has become pro-
gressively more concentrated in the electric utility sector,
as shown in table 1. Table 1 shows some other interesting
features in the part that coal has played in the Nation's
energy picture. Domestic demand for coal dropped to less
than 400 million tons by 1960. However, because of rising
needs for electric generation during the past 15 years,
with coal still the favored fuel in that sector, total domestic
demand rose steadily from 398 million tons in 1960 to above
600 million tons by 1976. In this same period, total utility
coal demand climbed from 179 milliori tons to 457 million.
However, as shown in table 2, coal's total share of the
utility market declined from 52 percent in 1960 to 44 per-
cent by 1975. Also, referring back to table 1, coal's
share of the total U.S. energy market declined from 38 per-
cent in 1950 to 23 percent in 1960 and to 19 percent in 1976.

                               Table 1
             Domestic Coal Consumption--1950-76

                        1950      1960    1970    1973    1975   1976
                        ------------- (million tons)------------
Total domestic
  coal demand            494       398     524     562     561    602
                     Demand by User Sectors

  utilities (tons)      93.9    179.2    234.9   387.8   415.3. 457.5
                         19%      45%      62%     69%     74's   76%
Other steam (tons)       (a)    127.4     94.3    73.1    56.1   54.2
                                  32%      18%     13%     10%     9%

Metallurgical (tons)     (a)     87.6    99.6    101.2   89.8    90.3
                                  22%     19%      18%    16%     15%
           Coal's Share of Total U.S. Energy Use

All uses (note b)       38        23      19       18     18      19
     a/Not available.
     5/Exports not included.

     Currently, more than 70 percent of all domestic coal con-
sumption is used as boiler fuel for electric power generation.
It is the single most important fuel in the electrical sector.
Even here, however, its position has not been uncontested.

     During 1962-69. the average cost of fossil fuels to
utilities exhibited a downward trend relative to the general
level of prices. Daring this period coal enjoyed approxi-
mately a 23 percent cost advantage over oil. 6/ Despite this
advantage, nearly 29 thousand megawatts (MW) of coal-fired
capacity was converted to oil during 1965-72. 7/ Furthermore,
during the 10-year period ending in 1973, less than one-third
of new electrical generating capacity was coal-fired. 8/ In

 general, the shift to residual fuel oil* was greatest after
 1966, when import controls were effectively removed on the
 East Co-ast.** 9/

      The relative decline of coal use in the electrical
 sector is summarized in table 2. Even in absolute terms,
 total coal consumption grew by only 67 million tons during
 1950-75, 10/ an annual growth rate of only 0.49 percent.

                              Table 2

            Electric Generation by Energy Source

          Coal       Nuclear       Oil   Gas     Hydro/other
                 …----…----(Percent of total Btus)---

1955      52.8           -         7.3   18.1           21.3
1960      51.5           -         6.8   21.6           20.1
1965      52.8          0.3        6.5   21.6           18.6
1970      44.7          1.4       12.9   24.7           16.3
1975      44.0          8.2       16.4   15.8           15.6
     Coal, therefore, entered the 1970s being seriously
challenged in its most important remaining market.   The
challenge was three-pronged:   (1) other fossil fuel prices
were stable or trending downward relative to coal, (2)
stringent air pollution control requirements were being
developed which increased total user cost when burning
coal, and (3) large-scale nuclear installations appeared
to offer significant cost-savings for baseload electric
power generation.

     The oil price revolution of 1973-74, along with
increasingly difficult circumstances involving the use
 E natural gas as a boiler fuel for power generation,

*Residual fuel oil    is the main type of oil product used by

**The switch after removal of import controls may have
  reflected, in part, apparent trends toward stricter clean
  air standards.

appears to be reducing two threats to continued coal use.
The extent of coal's future as an energy source is still
uncertain, however.  In the next decade or so, as in the
recent past, its future rests primarily on developments
associated with electric power generation and consumption.
Continued or increased acceptance of coal as an energy
input will hinge on the cost of making it environmentally
acceptable in terms of current and prospective standarCs
and how these costs compare to costs associated with other
electric generation opt'ons.

     The most severe current environmental challenge to
coal use relates to the control of sulfur oxides.  Coal
burning powerplants account for as much as one-half of
all sulfur oxides emitted nationally.  No easy control techni-
ques are available.  Stack gas scrubber technology is advancing
slowly. Increased reliance on low-sulfur coal has shifted
some demand from traditional producing centers, in the
East and Midwest, to new mines in the West.  Currently,
however, nearly 50 percent of all coal consumption for
powerplant use is out of compliance with existing
clean air standards. 11/

     Current coal costs for power generation compare very
favorably with those of oil.  Data in table 3 show that in
1973, coal cost one-half as much as fuel oil in the electrical
sector.  Although gas had been even cheaper than coal, except
for the major gas producing States few utilities were able
to obtain gas for use as a boiler fuel. Price movements since
1973 appear to favor coal even more.

     These developments, however, are seriously affected by
user costs associated with environmental control.   It is
estimated that when costs of adapting to prospective environ-
mental requirements are taken into account, true costs of coal
use per million Btus may be increased by about 26 percent. 12/
Hence, the price data in table 3 may overstate the relative
cost advantage of coal.

                               Table 3

            Relative Fuel Costs to Electric Utilities
                        1973-76 (notea-

 Fuel       1973        1974              1975    1976
           ------ (1975 cents per million Btus)------

 Coal      52.7        77.4               81.4    81.0
Oil       104.4       209.5              202.0   191.0
Gas        43.9        52.4               75.4    98.8

a/Fuel prices converted to 1975 values on the basis of
  changes in the Wholesale Price Index for commodities.


Short run opportunities

     The preceding section noted the importance of the
electrical sector when considering fuel substitution
possibilities.   Even in the short-term there may be sub-
stantial opportunity.   One month preceding the Organization
of Petroleum Exporting Countries (OPEC) oil embargo,
the Federal Power Commission (FPC) was optimistic about
the utilities' ability to convert from oil to coal in
an emergency:

        "It appears that the nation's electric power
        generating industry could, within three weeks,
        absorb a cut in residual oil supply of per-
        haps 2.2 million barrels per week (annual
        rate of 114 million barrels equivalent to
        18.9 percent of 1972 residual oil imports)
        and at the end of one year 3.8 million
        barrels per week (annual rate of 198 million
        barrels equivalent to 31.0 percent of 1972
        residual oil imports)." 13/

     Shortly thereafter, the Congress passed the Energy
Supply and Environmenta.l Coordination Act (ESECA), with
an expiration date of June 1975, evidently presuming
a 1-year conversion program to be adequate.   The act

 has been renewed twice. As of
                                 December 1976, 74 conversion
 orders had been issued by the Federal
 (FEA). Only 11, however, have receivedEnergy Administration
 Environmental Protection Agency           approval by the
 have been Lonverted. Fifty-one   (EPA)  and only three plants
                                  orders have been stayed
 pending the installation of improved
 equipment.                             pollution control

       Table 4 shows that the FPC originally
  some 23.7 thousand MW of electric              estimated that
                                      generating capacity could
  eventually be converted. 14/ In
  the Congress, FEA estimatej that its April 1976 report to
                                    as much as 20.4 thousand
  MW could be converted by June 30,
  represented about 0.5 percent of    1977. 15/ This would have
 scheduled to be operative in early total  generating capacity
 of July 1977, only three utility      1977.  16/ In fact, as
 capacity had been issued final     powerplants    with 158 MW of
 Nonetheless, table 4 also shows prohibition     orders.* 17/
 eventually occur--the Nation willthat--if the conversions do
                                     save about 151 million bar-
 rels of oil while using an additional
 coal per year. 18/ Since utilities       47 million tons of
                                        used 404 million tons of
 coal in 1975, 197 the impact of the
 existing plants-would be to raise      ESECA orders affecting
 percent.                            utility   coal use about 12

*In effect, a prohibition order means
 from burning any fossil fuel except a utility is prohibited

                           Table 4

          Anticipated Impact of Orders to Convert
          Existing Oil-Fired Powerlants to Coal

                         Impact and cost of existing
                    utility powerplant conversions (note a)

                            Estimated         Estimated
                           January 1973      April 1976
Megawatts (thousands)
of oil-fired capacity
convertible to coal
  within one year                21.1
     Total                       23.7         b/20.4
Oil savings (million
barrels Der year)
  within one year              178              -
     Total                     198             151
Additional coal
required (note c)
  (million tons)
  within one year               68              -
     Total                      74              47
Conversion cost
(millions of 1975
dollars) (note d)           e/$ 137          $1,270
a/Conversion results and costs estimated in April 1976
   for conversions to be achieved by June 30, 1977.
b/Includes conversion of gas-fired plants.
c/Includes coal required for powerplants converted
  from gas to coal.
d/Converted to 1975 dollars with Wholesale Price Index
  for Materials and Components for Construction.    Econo-
  mic Report of the President, January 1977, p. 249.
e/During 1965-72, 28,785 MW of coal-fired capacity
  were converted to oil.   Of this capacity, the FPC
  estimated that 22,704 MW could be reconverted to
  coal eventually.   The data presented in the table
  include all plants believed convertible to coal,
  whether they were initially coal-fired or not.
  However, the 1973 cost estimate pertains to the 22,704
  MW estimated as reconvertible to coal and the 1976
  estimate to cumulative eventual cost.

       ESECA calls for conversion
                                    where practical from
  both an air quality and cost
                                 standpoint.  Unfortunately,
  the estimated costs of conversion
 $137 million to $1,270               have increased from
                         million, or about 850 percent.
 A principal contributor to
                             these costs is the need for
 pollution control equipment.
                                  Of course, these conver-
 sion costs may be partially
                               offset by lower fuel costs.
 Total offset is unlikely,
 $1,270 million capital costhowever, and the estimated
                               for conversion works out
 $63 per kilowatt (kw) of                                 to
                           generating capacity.    This compares
 with estimated construction
                              costs for new coal-fired
 plants of $360-480 per kw.
      The initial FPC estimates
                                  pertained almost exclusively
 to powerplants originally
                            designed to burn coal.   As concern
 about natural gas use in
                           boilers heightened, some urged
 that natural gas boilers also
                                be subject to conversion

      About 70 percent of ail gas
occurs in the South Central         used as a utility boiler
                              States*, which accounts for     fuel
90 percent of total U.S. gas                                nearly
                               production. 21/   An investigation
of conversion opportunities
                              revealed that while utilities
in this area derived 99 percent
                                  of their fuel-generated
electricity from gas in 1970,
                                reliance had been reduced
to 87 percent by 1975 22/,
                            and a further 40 percent
by 1985 was already scFheduled.
                                 23/                   reduction
                                       In fact, by 1983 the
baseload generating capacity
                               in this area is expected tc
be completely coal and nuclear.

     Efforts to accelerate conversion
                                        appear to be very
costly.   For example, assume that
                                    all gas and oil boilers
were discontinued, effective
                              January 1, 1985, and replaced
with new coal-fired capacity
percent reduction presently    instead of the roughly 70
                             scheduled. 24/   For the Southwest
Power Pool Area of Texas
                          alone**, this would increase
generation costs more than                               annual
investment costs would rise 34 percent by 1985; cumulative
                             by approximately $4 billion.

*Defined for purposes of
                          this section as consisting
 Arkansas, Kansas, Louisiana,                        of
                               Oklahoma, and Texas.
**This comprises about one-fourth
                                  of the area in Texas.
  The bulk of the State is
                           represented by the Electric
  Reliability Council of Texas.

      Also under ESECA there is a program dealing with new
 powerplants. Under this program new powerplants are
 required to have the capability of burning coal as a primary
 energy source. By June, 1977, over a hundred such orders
 (construction orders) have been issued, affecting over 50
 thousand MW of capacity. 26/

     Although this sounds impressive, these figures may not
be meaningful since many utilities might have elected
such coal-firing capability anyway, because of gas curtail-
ments and higher oil prices. Hence, the extent to which
the ESECA program has had an impact here remains uncertain.
The estimates, therefore, presented in table 4 exclude
consideration of the program related to new powerplants.

     In summary, the ESECA program to convert existing
powerplants (prohibition orders) to coal has thus far not
lived up to expectations. The principal reason is the
inability of utilities to burn coal in these p :Ints so
as to comply with clean aiz standards. Such compliance
would appear, in many cases, to result in substantial conver-
sion costs. Furthermore, acceleration of conversion to
coal from gas would seem to impose substantial burdens
on electricity consumers in affected States such as Texas.

      A potentially more attractive means of substituting
coal (and nuclear) for oil or gas involves improved load
management. 27/ For purposes of the present discussion,
load management is defined broadly to include two phenomena
often considered separately. The first embodies the usual
definition of load management:   the leveling of the load
curve of an individual utility to make more efficient
use of existing equipment. Improved load management here
could involve adoption of some new technologies. However,
the principal change would involve greater use of differ-
ential electric rates for peak and off-peak periods. For
all retail users, this could mean higher rates in one
season (e.g., summer) than in others. For large retail
users, this could mean higher rates during certain hours
of the day (e.g., 3-6 p.m.) than at other times. Rate
schedules such as these have been common in Great Britain
and France for many years and are becoming more prevalent
in the United States. 28/

     Were these and other load management techniques
adopted, greater relative use of baseload electrical
generating equipment would result.  Since baseioad

                           2. .2
 equipment is largioy coal-fired at present (versus oil
 or gas-fired for peaking equipmertc) 29/, greater use of
 load management techniques would lea'-to substitution
 of coal for other fossil fuels.*
     The second form of load management Dower pooling, is
broader in scope, and is in considerable use now. ;it the
level of retail sales, it involves several utilities, often
organized into a power pool, attaining r:aximum coordination
through organization devices such as a central dispatch. At
the level of wholesale sales, it involves more exchanges and
sales vf power, even among widely separated utility groups.
And, in general, load management in this sense involves full
coordination, interconnection, planning and use of electric
generating facilitites with a view to auglent-ing capacity
utilization. 30/ Ultimately, improved loaG management of this
type would ].1ely lead to expansion of the wholesale market.

     If the capacity factors of baseload generate.    'uipment
could be raised through these two types of load     ,olent,
substantial substitution of coal for other fos'-     'ols
could result. However, thy basic questions are:    how much
substitution and how soon?

     While definitive answers to these questions are not
possible, some rough estimation is. Consider the stock ~
coal-fired electric generating equipmenr- in place and
scheduled to be operative by 1.985. Surveys by the National
Electric Reliability Council (NERC) estimate this coal-fired
capacity at 320 thousand MW by 1985 (versus 798 thousand
MW in total). 31/ To generate this amount of electricity,
NERC estimates that utilities wo!ild use 827 million tons
of coal by 1985. 32/

     The potential increase in -gal consumption wi ch would
result from improved load management at the retail level is
hard to estimate. However, FEA was calculated that more
effective load manage. :c.it, at the retail level alone could
increase utility usage of c al by 52 million tons by 1983.
33/ The potential for the second type of load management
(power pooling) discussed above is even miore difficult to
determine. However, it is worth n ;ting that seven Eastern

*There would also be substitutions of nuclear power for
 electricity from oil- and as-fired plants because nuclear
 powerplants are exclusively baseload.

Reliability Council Regions are currently capable of exchan-
ging substantial amounts of electricity. 34/ Such capability
was important in Jan:uary, 1977, as evidenced by the export
of 548 million kilowatt hours (kwh) from the Mid-Atlantic
area to other utilities. 35/ Similarly, West Virg :nia in 1974
produced 61.5 billion kwh electricity while needing only 18.4
billion kwh for its own use.* Hence, over 43 billion kwh
were exported from this one State alone. 36/ Assuming 1974
fuel rates, 37/ this means an "export" of-T5 million tons
of "coal by wire" from West Virginia alone.**   In fact, one
estimate suggests savings of almost one million barrels
per day (bpd) of oil could be achieved by 1983 were
full use of "coal by wire" made. 38/

     Savings of one million bpd of oil would yield a coal
equivalent of about 267 thousand tons per day or about 97
million tons of coal per year.***  If this is added to the
52 million tons estimated by FEA, the total from both types
of load management is about 149 million tons per year.

     Thus far, the discussion has been in terms of using
more coal and less of other fossil fuels. The increased
coal usage necessarily leads to a concern with environmental
and socioeconomic effects, as discussed in chapters 6 and 7.
     Yet, the equivalent of substitution of coal for oil
or gs could possibly occur without completely offsetting
increases in coal use. Such an outcome might be attainable
with improvements in the conversion efficiency of electrical
generating equipment.
     At present electrical generation is characterized
by the conversion of over 10,000 Btuis of energy into one kwh
of electricity. 39/ Since a kwh is normally rated at 3,412
Btus, 40/ electrical generation wastes two-thirds of the

*In 1975, the United States consumed 1,876 billion kwh.

**This represents about 12 percent of 1974 utility
   coal consumption.
***This assumes 6.3 million Btus per barrel of oil and 21.7
    million Btus per ton of coal.

gross energy input.*  In any event, the conversion process
is usually summarized in terms of the heat rate, which
is an index of thermal efficiency defined as the number
of Btus of energy input needed to generate one kwh of
electricity. Measured in this way, the heat rate has
been approximately constant for some 20 years. 41/

     Nevertheless, a recent Edison Electric Institute
(EEI) study projects improvement in the future course
of heat rates for baseload generating equipment as
follows. 42/

                    Heat Rates of Electric .
                Generating Plants (Btus per kwh)

                             1975       1985         2000
      Coal                 10,575      9,575        9,250
      Nuclear              10,660     10,400       10,000

     Such improvement is conceivable, given the incentive
to cut fuel costs engendered by the recent increases in
fuel prices.  But such improvements are by no means
inevitable and since such improvements would be confined
to new plants, the overall rate of improvement depends on
the level of new powerplant construction. In any event,
heat rate improvements of the magnitude suggested by EEI
imply potential coal use savings of as much as 150 million
tons per year by 1985.**

     Unfortunately, we do not know now much such improve-
ments would cost.   Current research efforts along these
lines by the Energy Research ana Development Administration
(ERDA) seem modest.   It would appear that a potential
exists to simultaneously increase reliance on coal as
a fuel by improving the efficiency of its use at the same
time reducing the rate of depletion of this resource.

*Similar efficiency losses occur with more direct use
 of fossil fuels, but are less easily measured.

**This estimate results from a comparison of the actual 1974
  fuel rate with that projected by EEI for 1985.  The fuel
  rate is defined as the number of pounds of coal required
  to generate one kwh of electricity.

     Table 5 summarizes key quantitative aspects ot the
preceding discussion.   Significant opportunities exist
for shifting from oil to coal in the electrical utility
sector even without a major change in the basic structure
of the generating base.   These opportunities can be
achieved, however, only in conjunction with changed
electrical marketing practices both at the retail and
wholesale level.

     Were all three actions in tablt i to occur by 1985,
the net effect would be to raise utility coal consumption
by only 46 million tons. Adding this to the NERC estimate
of 827 million tons, however, results in utility coal
consumption of 873 million tons, which is more than double
1975 consumption by utilities.

     Nonetheless, this amount of coal usage by utilities
is uncertain because the demand for electricity may not
increase as much as expected by NERC.

     The National Energy Plan promotes adoption of load
management techniques, particularly at the retail level.
GAO supports the efforts to improve the rate structure of
electric utilities.  The administration's proposal is
predicted to save about one million barrels of oil equivalent
per day in the electrical sector.  This compares with the
projected savings of 1.8 million barrels of oil equivalent
per day in table 5. The largest source of the difference
appears to be the savings which may be obtainable, at
least in part, through better load management at the
wholesale level.

                                   Table     5

      lAdditionalon    nsumption of Coal by Utilities       in 1985
                      Un-rF Alternative Action-s

                      Additior.al usage          Equivalent savings
                      of coal (note a)             in oil (note b)
                                   Percent                     Percent
                         Tons      of 1975           Millions  of 1975
     Action            (millions)   usage              bpd     imer rts
 Full conver-
 sion of utility
 powerplants                47          12            0.4              7
Optimal load
management                 149          37            1.4             23
Maximum thermal
efficiency              (-150)           -

     Net effect            46                         1.8
a/The additional coal usaae trom conversion
                                             is an FEA coal
  estimate.  The other two sources of additional coal
  are GAO estimates based on EEI estimates
                                            of fuel rates
  and NERC estimates of electrical generating
b/For purposes of this computation coal
                                        was evaluatea
  at 21.7 million Btus per ton and oil at
                                          6.3 million
  Btus per barrel.

Long-term opportunities

     Under current and foreseeable cost and
                                             other condi-
tions, little oil or gas will be used for
generating  of electricity.*  Hydroelectric sites are
less plentiful and geothermal generation
                                          is likely to be
important--if at all--only in California.
                                            Hence, the
contest for baseload generation for the
                                         next 25 years
is between coal-fired and nuclear-powered

*New England may be an exception.  In addition, aelay in
 construction and operation of nuclear plants
                                              may necessitate
 greater use of oil or gas in areas such
                                         as New England or
 the southwestern, gas-producing States.

      Current industry plans for electrical generating
equipment are summarized in table 6. 43/    In terms of
capacity, coal-fired plants are expected to increase
modestly in relative importance.   Announced decisions
on new capacity indicate coal's share will rise from
38 percent in 1975 to 40 percent in 1985.    During this
same period, nuclear's share is projected to rise
almost threefold.   Beyond 1985, present plans indicate
an even greater relative reliance on nuclear.    To
the extent that announced utility expansion plans are
indicative, nuclear and coal are viewed as the significant
energy sources of the future for baseload electric power

     Announced utility expansion plans, however, have
not materialized,  For example, of the 21,272 MW scheduled
to be placed in service during April 1 through September 30,
1976, only 12,505 MW were actually placed in service. 44/
Furthermore, nuclear units accounted for more than one-half
of the uncompleted capacity in MW. 45/   In contrast, over 80
percent ot the coal-fired units scheduled for commercial
operation during April 1 through September 30, 1976, were
actually entered into service during that period. 46/
This recent experience suggests that predicting the future
role of nuclear power presents special complications,
a subject discussed below. The pest data available at
this time, however, indicate that both coal and nuclear
power will become increasingly important during the next
25 years.

                            Table 6

          Currently Scheduled Generating Capacity
                 LiAajpor Fuel Category, 1975-95

Fuel Category            1975          1985           1995

                          (Percent of total mw capacity)

Coal                     38.5          40.2            (a)
Total fossil             69.7          60.2            50.3
Nuclear                   7.7          21.2            33.9
Hydro                    13.0          10.4             8.0
Other (note o)            9.6           8.2             7.8
a/Not available.
b/Includes peaking, which    is also fossil   fuel.

       Despite recent indications that nuclear is
 to live up to earlier expectations, current       unlikely
 are still predicated on expansion of nuclear utility  plans
                                               power relative
 to expansion of coal-fired generation. Even
                                              in those areas
 in which coal is mined and plentiful, utilities
 to be electing the nuclear option. For example, appear
 in two midwestern Electric Reliability Councils, the utilities
 and MAIN**, are located above the coalfields       ECAR*
 Appalachia and the Midwest. Yet more than     of northern
 additions scheduled by these utilities for half the capacity
                                             1986-95 are
 nuclear, as shown below in table 7. 47/

                               Table 7
        Capacity Mix as a Percent of Total Capacity additions,
          SelecteFueili and Reliabity Cu76-5

                     1976-85      1986-95    1976-85      1986-95
 Fuel                          ECAR                    MAIN
                  (Percent of total capacity additions (note a)
Coal                  57               (b)    38              (by
Total fossil          61               46     53              45
Nuclear               37               51     47              55
Other                  2                3
a/Data for 1976-85 are net additions.
b/Not available.
     What determines the choice between coal and
Generally, utilities choose the least costly      nuclear?
generating electricity. The relative importance      of
major cost categories are indicated by the data   of
table 8. 48/                                     in

*East Central Area Reliability Coordination
 (Illinois plus parts of Wisconsin and Missouri).
**Mid-America Interpool Network (Michigan, Indiana,
  Kentucky, West Virginia, plus parts of Pennsylvania,
  Maryland, and Virginia).

                           Table 8

 Projected Costs for Baseload Plants in 1985 (Mills/kwh)

                            Plant type
Cost                      Low-sulfur coal     High-sulfur coal
category        Nuclear    without scrubber     with scrubber
Capital           13.5               9.3              11.7
Operating &
  maintenance    a/1.8               2.0               3.5
Fuel               3.0             10.1                6.9

   Totals         18.3             21.4               22.1

a/This estimate does not include costs of waste disposal
  or decommissioning.

     Nuclear apparently is three mills cheaper than coal
plants without scrubbers and nearly four mills cheaper
than coal plants with scrubbers, a cost advantage of 15
to 20 percent.  Individual components of cost differ
markedly. Nuclear generation is substantially more capital
intensive than is coal-fired generation even with scrubbers.
The assumed advantage of nuclear has been in projected
fuel costs of only one-third to one-half those incurred
with coal-fired generation.

     All of these costs are, of course, projections.   That
is, they reflect best estimates of the comparative future
costs of alternate means of baseload power generation.
Lately, increasing doubts have been raised regarding   the
superiority of the nuclear option. These doubts concern
costs of waste disposal and decommissioning, ai.i the risks
of fuel reprocessing and the fast breeder reactcr.

     To better understand the nature of the planning process
in the electrical sector and of the nuclear versus coal
investment decisions, GAO interviewed 12 of the largest
private and public electric utilities in several major
sections of the country.  These utilities were asked a variety
of questions, but the principal ones concerned their per-
ception regarding interfuel substitutability.

        Specifically, utilities were
   native types of powerplants           asked to compare alter-
   in 1985. The comparisons wereexpected     to be operational
   costs per kwh for three classes  made   in  terms of annual
   maintenance, fuel costs, and      of   costs--operating  and
        In general, the view expressed
  able large changes in projected          was that only improb-
                                     costs would significantly
  alter current decisions for
                                nuclear generation.
  it was stated that either nuclear                      For example,
  to more than double or coal           fuel costs would have
                               prices would have to fall
  by at least one-half to shift
  Alternatively, it was noted     the balance in favor of coal.
  would have to rise 40 percentthat   nuclear capital costs
                                  or more relative to coal for
  the nuclear advantage to disappear.

       Recent developments seem
  shifts in the comparative coststo suggest, however, that wide
  not be as improbable as our           of nuclear versus coal may
  In 1976, PEA estimated the cost  interviews   seemed to indicate.
                                       of a nuclear powerplant
  as $550 per kw. 49/ Now the
 construction time for coal-fired   cost is higher because the
 five years. In contrast, for            plants remains at about
 from eight to ten years. Another    nuclear   plants it has increased
 cost of uranium versus the cost          recent  shift is in the
 price for uranium was $7.90           of  coal.   In 1974 the average
 projected prices under           per pound. 50/ Since then,
                             new contracts have increased
 51/ In contrast, the price                                  sharply.
                                  of coal has not changed much
 (table 3).      In summary, substantial changes
 costs could occur, especially                       in relative
 is to 1 9 8 5                      since   the  relevant time horizon
               --and beyond.
       Further doubts about the accuracy
 costs have been noted in a                   of projected nuclear
                             recent study by the Council
 Economic Priorities (CEP).                                    on
 estimates (table 8) assumed The earlier comparative cost
 both nuclear and coal plants plant capacity factors for
 Actual experience in recent    to average 70 percent. 52/
 expectation for nuclear. Operatinghas not supported This
 equalled only 58 percent. 53/           rates have, in fact,
experience is indicative or-the   The  CEP   believes current
plants will have as much as         future   and that nuclear
                              15  percent
vantage when compared to coal-fired          operating  disad-
this be true, coal may prove             facilities. Should
                               to be a superior choice in
future baseload investment decisions.
coal-fired plants are required               Of course, if
capacity usage may be less        to  have   scrubbers, their
coal-fired plants.          than   that   of  conventional

     This disappointing experience may have contributed to
the recent trend toward deferral of completion dates for
nuclear units. During October-December 1976, deferrals of
commercial service for electric generating units amounted
to 7,727 MW of capacity. 54/ Of this, 4,507 MW was nuclear
steam. 55/
      Though the outcome is still uncertain, the contest
between nuclear and coal-fired plants is getting closer.
In recent months, there has been increased awareness that
previous estimates of the costs of nuclear power such as
those in table 8, have been too low. A sellers' market
exists in uranium; the price of Government enrichment facili-
ties is expected to rise as ERDA changes its costing proce-
dures; reactor design changes may contribute to further
capital cost increases; and, perhaps most significantly,
decommissioning and waste disposal costs appear likely
to increase. For these and other reasons, recent orders
for nuclear reactors have declined dramatically.

     The potential seriousness of the decline in orders for
nuclear reactors is highlighted by a comparison of the most
recent FPC estimates and those projected by the Atomic Energy
Commission (AEC) only t±oree years ago. In 1974, the AEC Ebd
predicted an increase of nuclear capacity to 127 thousant
MW by 1980. 56/ Yet, in March 1977, the FPC estimated that
nuclear capaciTty would be only 77 thousand MW by 1980. 57/
However, the actual 1976 nuclear generating capacity was 1.6
thousand MW less chan that predicted by NERC in June 1976. 58/
In contrast, during 1976, utilities' orders for fossil fueled
plants were virtually all for coal-tired plants and none of
these orders were cancelled.

      Changing investment decisions regarding new baseload
units are currently subject to the combined interaction of
three factors. The first relates to downward revisions in
near- and long-term electrical demand. The second ini ilves
increasing uncertainties regarding environmental hazards
associated with new plant installation. These uncertainties
surround both nuclear and coal-fired plants. A stellar
example regarding the latter involves the recent cancellation
of the 3000 MW Kaiparowits project. T~,e third involves
the prospective comparative economics of coal versus nuclear.
The data in table 9 raise questions about the validity
of FPC estimates of plant capacity additions presented
earlier in table 6. Juxtaposed, these tables indicate the
problems inherent in forecasting fuel choices beyond 1985,
and the apparent narrowing of the competitive choice between
nuclear and fossil fuel plants.

        Available information regarding
  reactors during 1973-76 suggests          orders for nuclear
  have something close to a nuclear    that  we currently
                                        moratorium, if that phrase
  is taken to mean no new orders
  are being placed. The potentially for nuclear powerplants
  associated with the development         large impact of problems
  has encouraged study of the        of  nuclear   generating capacity
                                implications    of  various possible
  types of nuclear moratoria.
  implications of a 6-year ban   One  such   study  examined the
                                 on new building applications.
       Were such a ban to be instituted,
 capacity was estimated to be                 nuclear generating
                                 some   200  thousand MW less
 by 1990. 60/ However, total
 also be some 100 thousand MW   generating     capacity would
 the cost of electricity was     less, presumably because
                               higher without the low cost
 nuclear option. 61/ This
 demand for electricity. 62/ turn would mean a reduced
 not calculate the impact of This particular study did
 coal usage.                   this limited moratorium on

      Consider now anoLher kina of
 In this case, all capacity         nuclear moratorium.
 to be operative by 1985 is in existence  and scheduled
                            shut down.   What would this
 mean for utility coal consumption?

       NERC estimated that by 1985
 burn 827 million tons of coal.     utilities would annually
 and operating nuclear capacity 63/ If currently scheduled
                                 were shut down and the slack
 taken up by existing and scheduled
 this would increase utility          coal-fired capacity,
                              coal consumption in  1985 to
 over 1.5 billion tons assuming
 This wou d mean consumption     that much could be produced.
                              would be more than three times
 as high as 1976 levels (see
                              table 1).
      In summary, the near-term potential
of coal for other fuels in                 for substitution
                            the electrical sector is substan-
tial.   In a longer timeframe, the
is limited only by the rate        potential for substitution
                             at which new, environmentally
acceptable capacity is installed.

      The electrical sector enjoys
choi-e.                              the widest range of fuel
          Furthermore, electricity is
conveni¢rc ana flexible form            probably the most
role as an energy source for   of fuel  use. Given coal's
an increased reliance on electricity         can we foresee
as a whole and thus, indirectly,        generally  in the economy
on coal as an energy input?        an  increased  reliance

     Various factors determine the choice of electricity
as compared to other energy inputs in the e3conomy. Yet
the important point is that a number of prominent studies
have concluded that the future potential for electricity
use is very substantial. 64/  Table 9 shows a projection of
consumption, by consuming sector, for the years 1985 and
2000. 65/

Indirect Substitution of Coal Through
Increased Reliance on Electrici-ty

     As shown in table    9,   the household/commercial sector
currently derives some    40   percent of its energy from electri-
city. This is expected    by   EEI to rise to as much as 60 percent
by 1985 ann 75 percent    by   2000.

                           Table 9

     Consumption of Electricity as Percent of Total Ener
        Consumtion, 972 and Potential 1985-2000

  sector            1972               1985        2000
Residential          40                 60          75
Commercial           42                 55          77
Industrial           27                41           62
Transportation        u                  5          29

      In 1975, some 50 percent of the newly constructed single
family homes and 60 percent of the multi family homes had
electric heat.   Electricity's share is expected to rise,
so long as residential gas hookups remain scarce and retail
gas prices continue to increase faster than electr:city
prices.*   While coal furnaces and stoves in residences
are a thing of the past, we can probably assume that almost
one-half of increased energy use in the household/commercial
sector to 1985 will be from coal-generated electricity
because of

*During 1935-75, retail gas rates increased nearly twice
 as much as retail electric rates.  The increase for fuel
 oil was four times as great as for electric rates.  66/

      --the higher relative costs of fuel oil
      --the growing unavailability of natural

      --the absence of prospective technological
        which would reduce electricity's share   changes
                                               of new
        household/commercial uses.*

      Many industries i ivolving light or even
                                               heavy manufac-
 turing are similar to the household and
                                          commercial sectors
 in terms of factors determining energy
                                         use patterns.
 Principal reliance is on gas, oil, and electricity.
 reasons noted above, the choice is likely             For
 electricity in the future.                 to favor heavily

     Overall, Past trends indicate an increasingly
reliance on electric energy. Manufacturing           heavy
                                             use  of purchased
electricity increased from 187 billion
                                        kwh in 1954 to 518
billion kwh in 1971, a compound annual
                                       growth rate of 6.2
percent. 67/ In contrast, total energy
                                         use in manufacturing
during the same period rose from 2,220
                                       billion kwh
(equivalent) to 3,850 billion kwh (equivalent),
                                                 an annual
growth rate of 3.3 percent. 68/ Direct
                                         use of coal declinea
from 91 million tons in 1954-to 61 million
                                            tons in 1971,
a rate of decline of 2.4 percent per
                                     year. 69/
    A continued increase in reliance on electric
                                                   power as
a proportion of total energy demand depends
price movements. Though difficult to predict,on relative
                                                it appears
that electricity costs will continue to
                                        rise  less rapidly
than those of other energy sources--particularly
                                                   in relation
to natural gas.** Among all energy sources,
demand is most sensitive to shifts in relative
FEA estimates such sensitivity to be greater    prices.
                                              by 50 percent
or more compared to natural gas and petroleum
                                               products. 70/

*Increasing use of heat pumps would reduce
                                           demand for total
 kwh hours per household, but would likely
                                           also increase
 the share of electricity in the market
                                        for heating of new

**While all energy costs are expected to
                                         increase, it is
  the trend of relative prices which is important
                                                  for many

On this basis it would appear likely that increased reliance
on electricity will evolve over the next decade. A continua-
tion of trends evident in the manufacturing sector during
1954-71 is likely to result in electricity increasing to
the level shown in table 9.

     The transportation sector is the least amenable to
increased reliance on electricity as a main energy source.
In the transportation sector, at present, some 96 percent
of energy use is derived from oil.  Since the coal-fired
locomotive is unlikely to return, the prospects for
substitution here may depend on

     -- the outlook for the electric car;

     --the outlook for electric rail transport; and,
     --tlie growth of electrified, intra-city mass transit
        relative to use of cars and busses.

     A massive shift toward use of electricity would
require major changes in the composition of our trans-
portation capital stock. Since such Cghanges take time, not
until the year 2000 does the most optimistic projection of
electricity use in transportation indicate significant pene-
tration (table 9). Such penetration apparently requires radi-
cal changes in electric car technology and transportation use
patterns. 71/ It would probably also require a major diversion
of funds from the Highway Trust Fund for mass transit. 72/

Substitution of coal
through direct burning
      Recent FEA surveys, together with data from other
sources, indicate a dramatic long-term decline in the
direct burning of coal.   In recent years some 20-25 percent
of coal-fired boilers in industry were converted to oil
or gas to comply with clean air standards. 73/ Theoretically,
these converted boilers coula be reconverte--back to coal. 74/
Such reconversions may be too costly because the existing
stock of coal-fired boilers in industry is old and getting
older. 75/ Also, in some instances, coal unloading and
handling facilities have been dismantled.

     The prospects for greater coal use through orders for
new boilers seem brighter.  In 1973, only six percent of the
total capacity of new industrial boilers were coal-fired. 76/
Even this low figure represented an increase over 1967-72.-77/
Furthermore, preliminary ev.dence indicates that as much
as one-third of the steam generating boiler capacity ordered

 by industry in 1976 was coal-fired. 78/
                                           Yet these data also
 imply that considerably more than ha-t
                                         of industrial boiler
 orders are for oil or gas-firrd units
 curtailments and                       79/, despite gas
                      the   rising prices of oil     and gas   suggested
 by table 3.

       Coal-fired boilers are orderpd less frequently
 because tniiy cost two to four times as               mainly
                                         much as gas- or
 oil-fired units. 80/ Unfortunately,
                                       reliable data on the
 total relative costs--capital, operating
 and fuel--of differing industrial boilers and maintenance,
                                            are presently
 being developed. 1/ Also, unlike the
                                         situation in the
 utility sector, industrial firms do not
 expansion plans in a systematic manner   announce their
                                         se eral years into
 the future. 82/   Other reasons for current industrial
 ference for   o-1-   or gas-fired                       pre-
                                       boilers   include   the desire
 to comply with environmental stanaards,
                                          convenier-ce, and
 the unavailability of coal hauling and
                                         handling equipment.
      In view of these disadvantages or using
                                               coal to generate
steam, the prospective industrial demand
                                           for coal for direct
burning is uncertain. On the one hand,
                                          recent trends regar-
ding orders for new boilers suggest a
                                        resurgence of coal
as an industrial boiler fuel.   On the other hand, the new
coal-fired boilers may principally  replace older coal
equipment so that net increases in coal-fired
might be modest.
     While the impact on total coal use due
                                            to greater direct
burning in industry may be too smell,
                                      the potential in terms
of relative use of natural gas by certain
greater.                                  key industries is
          In particular, four industries (cement,
paper, and steel) presently account for           chemicals,
     -- two-thirds of manufacturing coal consumption,

     -- one-half of manufacturi,.o oil consumption,
     --one-third of manufacturing gas (and
      One recent study has concluded that tnese
industries could, in the aggregate, by
                                         1985, substitute
enough coal to conserve anntally some
                                       10 to 15 million
barrels of oil and some 325 to 400 billion
of gas.   For these industries, these savings wouldfeet
represent up to 17 percent of 1971 aas
In terms of individual industries, the consumption. 84/
                                        largest substiTution
occurs in cement and the smallest in
                                      steel. 85/

     The results of this study are based on substantial
increases in both coal and gas prices, with somewhat
smaller increases in oil prices. 86/ The possibility of
greatly increased natural gas curtailments was, however,
not considered. Therefore, the substitution of coal in
the amount of 17 percent of 1971 gas consumption may under-
state likely future reductions in industrial gas usage.

     Of course, this gas is most likely to be replaced
by electricity, not coal, as noted previously. Nevertheless,
these results suggest that coal as a direct burning option
can make a significant contribution to reduced usage
of gas as an industrial boiler fuel in selected industries.
At the same time, coal will indirectly provide industrial
energy through coal-fired electricity.

     Ten years ago industry generated 17 percent of its
own electricity requirements. 87/ The current percentage
is somewhat less. 88/ It is interesting to consider whether
this share might rise in the future.

     Industrial generation of electricity has declin, ]
over time in the United States because electric rates for
large industrial users have declined. In large part, these
industrial electric rates have declined because electric
utilities have benefited from increasing economies of scale.
However, in recent years, such economies have been less
attainable and the recent increases in fuel prices have
made the fuel component of electrical generation costs more

     In that regard,   it is i F.    ant to note that while the
thermal efficiency of indust      electrical generation by on-
site powerplants is greater t n central station
generation 89/, the overall efficiency of central station
generation lhs historically been greater mainly because
large powerplants benefit frcnt substantial economies of
scale. Since 1970, opportunities for further increases
in cost savings through economies - scale have diminished
and fuel costs have increased un     ably. If rising fuel
costs are not compensated by tec iological advances in
the utility sector, the resulting higher prices of
electricity may stem (or even reverse) the decline
in industrial generation of electricity.
     Whenever industrial steam is generated, there is a
potential opportunity for generating electricity although
this is taken advantage of in only a minority of cases.
using steam produced by industrial boilers for the dual
purpose of electric generation and other industrial needs

  is a major example of cogeneration. Under
 concept, additional energy is added to raisethe cogeneration
 of the steam to that required to drive a         the quality
                                            generating turbine
 and produce electricity. The waste steam
                                            from the turbine
 is then used for other industrial processes.
 boilers produce a large enough steam load       Not all industrial
                                             to  make
 economically attractive. However, the unexploited cogeneration
 seems substantial.                                     potential
                      In fact, one recent study has concluded
 that by 1985 the equivalent of 680 thousand
 be saved through greater reliance on industrialbpd of oil could
 of electricity. 90/ However, a variety of           cogeneration
 be overcome if fuel savings of this magnitudeimpediments    must
 obtained.                                         are to be

      Utilities have had long standing policies
                                                  that discourage
 industrial generation of electricity. Rate
                                              schedules have
 been designed to favor large industrial
 utilities as a standby source for backingusers. The rise of
                                            up industrial
power generation has been discouraged through
                                                high demand
charges which are levied even if no electricity
In addition, utilities are reluctant to buy        is consumed. 91/
produced by industry because it is often      the  excess power
                                           erratically produced.
92/ The extent to which the cogeneration
                                            plant will become a
regulated enterprise is also a crucial factor.
lation on sales of any excess power to individuals State regu-
utilities is a consideration.                         or public
generated is sold across State And  if any of the power
                                lines, the facility will
probably become subject to Federal regulations
                                                 under the
Federal Power Act. 93/

      While the potential for increased cogeneration
 electricity by the industrial sector seems             of
 the effect that such an increase, if it should
                                                  occur, would
 have on the direct burning of coal by the
 seems limited. A large percentage of industrial         sector
 is produced with oil- or gas-fired boilers.         steam
                                                As pointed out
 earlier, conversion to coal will be made
 the cost of a coal-fired plant may be two reluctantly   because
 that of a gas or oil-fired plant and the to four times
                                           former creates
material handling, storage, and environmental
      Some of the disadvantages of burning
come using a variant to the cogeneration coal can be over-
                                           technique described
above. This technique involves a large
located within a cluster of industrial orcentral   powerplant
The powerplant sells both electricity and   residential   users.
                                            processed steam
to consumers within the complex.   In this way, the powerplant
has a purchaser for a larqe quantity  of what might otherwise
be waste heat.

     Cogeneration facilities located within major industrial
clusters offer advantages in burning coal because of economies
in coal purchasing and handling, powerplant size, and in
financing of such ventures.  Also, environmental problems
can be better dealt with at large cogeneration plants. 94/
This type of cogeneration could increase the amount of
electricity produced through the direct burning of coal.
However, it would seem that only a limited number of indus-
trial sites could meet the criteria.  Thus, the likely
effect on the amount of coal burned by the industrial

     In summary, the immediate prospects for substitution of
coal as direct burning in the industrial sector are limited.
Indeed, the administration projects a four percent compound
annual growth rate in coal usage by industry versus a
nine percent growth rate for oil consumption unless the
National Energy Plan is implemented. 95/ Such implementation
is predicted togeaFtly increase coal usage by industry.
However, GAO has considerable doubt that implementation
of the National Energy Plan will have the     full impact
Substitution of coal through
synthetic fuel deveioiment

     Gas manufactured from coal was once relatively
important. 96/ For years some observers have been anti-
cipating a comeback as natural gas reserves diminish.
In 1972, the Bureau of Mines (BOM) predicted the following
scenario for synthetic gas from coal (versus 20,400 trillion
Btus currently derived from natural gas in 1975). 97/

                                      Trillion Btus of
             Year                       gas from coal
             1980                              430
             1985                            2,000
             2000                            7,140

That same study also forecasted 2,140 trillion Btus of
synthetic liquids from coal. 98/
     In its 1975 forecast, BOM revised these estimates
substantially downward. 99/ However, given that the Congress
has chosen not to accelerate development of the synthetic
sector at this time, the downward revisions are probably
still too high.

      What are the prospects for synthetic
                                            fuels in the
 absence of major financial assistance
                                       by the Government?
 The answer obviously depends on relative
                                           costs.  The
 most recent forecast of such costs by
                                       ERDA is presented
 in table 10 below.

                            Table 10

                   ERDA Best Estimate of
        Wholesale Prices for Major Fossll Fuels and
         Synthetic Fuels Derived from Coal (notte
                                   Wholesale Prices (note b)
          Fuel                           1985           2000
                                  (1975-cost per million Btu)

          Oil                           $2.24         $2.87
          Gas                            1.93
          Coal (note c)                                2.19
                                         0.61          0.69
          Synthetic crude              d/3.45
          High-Btu gas                               d/3.57
                                       d/3.54        d/3.65
a/These estimates were prepared by
                                    ERDA and presented in
  the unpublished draft of the 1977 National
  ERDA has reviewed these estimates and       Energy Outlook.
                                         has not objec
  to their inclusion in this report.
b/These wholesale prices are not immediately
  to the prices in table 3. However,
                                      approximate delivered
  prices to utilities for the year 2000
                                        are projected at:
        residual oil           $3.15 per million/Btus
        gas                     2.41 per million/Btus
        coal                    1.14 per million/Btus
  Comparing these data to those in table
                                          3 leads to the
  inference that coal's price advantage
                                         over oil may be
  wider in 2000 than in 1975.

c/Assumes approximately 60 percent surface
                                           and 40 percent
  underground mining.

d/Te.nessee Valley Authority officials,
  report, believe that 1985 prices for   in commenting on tht
                                        synthetic fuels are
  too low. They believe synthetic crude
                                         prices would be
  nearer $5.90 and the high-Btu gas should
                                            be above $4.00
  per million Btus.

     The unmistakable message of table 10 is that synthetic
fuels from coal are unlikely to be cost effective in this
century. Consequently, synthetic fuels would only become a
major factor if gas and oil were unavailable at projected
price levels.  Such a circumstance could occur if, in the
face of declining domestic production, limits are set on
imports and price controls based on cost and are continued
indefinitely.  Even under such circumstances, however, it
is as likely that coal would be used to generate electricity
as to manufacture synthetic fuels.

     For certain purposes, however, such as household and
commercial heating, high-Btu gas compared to electricity may
have a more promising future than implied by table 10.
Another alternative, which GAO hopes to consider further,
involves transport of coal to consuming centers, conversion
to low- or medium-Btu gas, and used as gas for industrial,
commercial, residential heating, etc., to replace natural

Recapitulation of overall
fuel substitution

      The potential for substitution of coal is greatest
in the electrical sector.   By 1985, roughly half of the
energy input to this sector will likely be derived
from coal.   Considerable uncertainty surrounds the prospects
for coal after 1985.   Whether coal's share in this sector
rises noticeably above 50 percent in this century or beyond
depends crucially on relative shifts in the risks and econo-
mics of electric power sources. A well developed nuclear
option will reduce the projected increase for coal.   On the
other hand, there are indications that the opposite could

     Beyond the issue of how much coal is used for power
generation is one which asks how much power generation
is needed in the context of any aggregate'energy use pattern.
Indications are that significant past trends of increasing
relative reliance on electricity will persist in the future.
As a result, if coal merely holds its own in the fuel mix
for power generation, demand is likely to rise, as energy
users shift from gas and oil to electricity.

     Given the limited potential for direct burning of coal
and the economic and technological uncertainties of coal
synthetics, the principal prospects for coal seem ;nextri-
cably tied to the prospects for electricity for t    emainder
of this century.

     The extent of substitution is principally a func-
tion of time.   In the electrical sector, high degrees of
coordination among utilities permit some substitution of
coal for other fuels within days or weeks. Within several
months or a year, some conversion of powerplants is possible,
and differing plants can be utilized at varying capacity
rates. In the course of several years, some new plants
can be added and others scrapped. Full substitutability
must also consider the time it takes to build a nuclear
powerplant--about 10 years. Given time, substitution rates
also depend on growth rates for electricity and the deprecia-
tion rates for electric powerplants.

     The future of coal and of electricity depends on relative
price movements among alternate energy sources. Though coal
at present offers a price advantage in terms of costs per
Btu as compared to other energy sources, this advantage
is greatly diminished and often eliminated when costs of
use are considered. These costs are mostly related to the
adverse environmental consequences of coal combustion.
Current economics indicates that the competition among
electrical utility fuels is now most keen between coal
and nuclear.

     Differing levels of aggreaate energy demand and
electricity usage could affect the demand for coal in various
ways. For example, rapid increases in energy demand
could lead to higher energy prices, thereby making synthetic
fuels from coal cost effective. Or the increased relative
importance for the electrical sector could enhance the
role of coal in supplying energy needs.

     The future of aggregate national energy needs is
uncertain. In the past, even without the turbulence
generated by OPEC, forecasters were not able to clearly
perceive the future. Develc ments in recent years make
projections even mcre suspect.

     Factors which make energy forecasting difficult are
readily identifiable. At least three are of great
importance--population and economic growth trends; composi-
tion of national output;  rnd cost of energy relative to
that of other resources. To develop an estimate of
energy needs for a year, for example, 1985 or 2000, one
must, at least implicitly, presume future trends to some
etent regarding each of these factors. In addition, one
m, t specify whet implications these trends have for over-
al energy consumption.

     The relationship among energy use, relative energy
costs, and the rate of economic growth has been highly
variable. The ratio of gross energy use to gross national
product (GNP' rose from 1909 to 1919, declined from 1923
to 1944, ant has remained relatively constant since then. 100/
The energy/GNP ratio in 1975 was 71 percent of its 1923
value and approximately equal to its lowest value since
1969. 101/ The future value of this ratio continues to
be a source of much speculation.

     There is a brief discussion of these relationships in
chapter 2 of the National Energy Plan, and the administration's
overall goal of achieving a 46 percent increase in GNP
by 1985 while reducing the annual growth of energy demand
to below 26 percent.

     The relationship between relative energy cost and
use is even less known.  Most agree that higher relative
energy costs will reduce energy use but the question of
just how much and over what period has resulted in various
answers.  These and other factors account
in the total energy growth and the fuel mixfor differences
                                             of the two
scenarios examined in the following pages: the BOM energy
forecast through the year 2000 and the EEI low growth

     These two were chosen because they were, at the time
this study was begun, representative of possible ranges
of energy demand. Furthermore, BOM has an important historical
role in research related to coal, while EEI presumably
reflects current thinking in the electric utility industry.*
President Carter's National Energy Plan was not available
when this study was started, so we were not able to use it
as one of our scenarios for analytical purposes.  However,
we have been able to compare the coal supply and use goals
of the National Enery Plan with the BOM and EEI scenarios.
These comparisons are ncte- in the following discussion.
See also, GAO's report "An Evaluation of the National Energy
Plan" (EMD-77-48, July 25, 1977).

*It should be noted that EEI presented several scenarios.
 GAO chose to utilize the EEI "low growth" or low energy
 demand scenario as a "counterweight" or reference point
 with which to compare the BOM forecast, which projected
 high energy demand.

       A summary of energy needs and electrical
  under the BOM and EEI scenarios is            generation
                                     presented below. 102/
                              Table 11
               Summary of Energy Needs and
              Under Altternative Senarios, Electric Use
                                           1 5 and- 2000
                            Gross Energy          Electrical
        Scenario               Demand             Generation
                            1985    2000         1985   200C
                         (Quadrillion Btus)    (TFT-ion kwT7
          BOM              103.5       163.4     3.96          8.65
          EEI              1.01.2      109.5     3.17
          Actual 1975                                          5.17
           consumption              71.1                1.88
       As table 11 indicates, the two estimates
  are fairly similar. However, they                for 1985
  the year 2000. To understand the    diverge  markedly  by
  scenarios, an effort was made to construction of these
                                   determine and compare the
 nature of underlying assumptions.
 1985, insofar as assumptions were For the period through
 these estimates, they are similar made explicit in building
                                    with regard to expected
 national growth patterns and the
 use and economic activity. 103/ relation between energy
 explain differences subsequent to Two principal factors
                                    1985. EEI assumes a slower
 growth rate and higher energy prices
                                        than does BOM. The
 slower growth explains about 16 quadrillion
 difference, while relative price               Btus of the
                                  differences appear to
 explain most of the balance. It should
 both scenarios imply a greater aggregatealso be noted that
 for 1995 than President Carter's           energy demand
                                  national energy goal.
       For the purposes of discussion here,
 scenarios have special interest because      the BOM and ELI
 implications for coal demand. Both        of   their potential
 expansion in national reliance on     project   substantial
                                    electric power. Table 12
 shows that the projected growth rates
                                         for the electrical
 sector far exceed those for all combined
 under the EEI scenario the electrical      sectors.     Indeed,
five times as fast as all combined       sector   grows nearly
                                     sectors: 2.82 percent
per year for the electrical sector
for all combined sectors. These      versus   0.53 percent
                                   higher  growth   rates for
the electrical sector naturally imply
fication and use of coal, both in        increasing   electri-
President Carter's proposals in -hisrelative   agreement   with
By the year 2000, therefore, the      National Energy Plan.
                                   share of the electrical

sector rises to nearly one-half under both scenarios, as
depicted in the bottom part of table 12.*

                          Table 12
            Growth of Electrical Sector Versus Total

                                             Growth rates
                                       -9775 1985=     1985 --T00
                   1975               BOM    EEI      BOM     EEI
                (Quarillion)            … --    (Percent) ----

Total energy
(gross input)     71.1                3.83   3.59          3.09   0.53
(gross input)     20.1                6.89   5.28          4.77   2.82
         Proportion of Electrica. Input to Total Energy

                 1975               1985                 2000
                Actual       BOM       EEI      BOM         EEI
                  ------------ (percent)--------------
                  28           38       33          48       47

     The two scenarios anticipate that nearly half of our
energy will be converted into another form rather than be
used directly. Such a trend favors coal and uranium
over natural gas and oil.

     The EEI scenario is of special interest since between
1985 and 2000 total energy use is expected to decline in
nearly every major consuming sector except electrical where
an increase of more than 50 percent is assumed.  In the
EEI scenario, electricity consumption rises from 1.88 trillion
kwh in 1975 to 3.17 trillion in 1985 principally because
electric rates are projected to decline in 1975 dollars
from 2.07 cents per kwh to 1.97 cents per kwh, during
1975-85. This decline in electricity prices is based
on the expectation in the EEI scenario that technological
change will offset the effects of rising fuel prices on
the costs of electrical generation. 104/

*The data in tables 12 and 13 are derived from more detailed
 data presented in app. II.

     During 1985-2000, the EEI scenario expects real prices
for electricity to remain roughly constant. Accordingly,
the growth in electrical generation declines to 2.8 percent
per year during this period, versus 5.2 percent per year
during 1975-85.

     The BOM forecast contains no explicit assumptions
about energy prices. 105/ However, the BOM forecast appears
consistent with an assumption that electricity prices will
decline during 1975-2000 at half the past rate of decline
in such prices up to 1970. 106/

     Despice the fact that each scenario reflect. strong
expectations regarding growth in electricity use, .i'ilar
expectations are not projected for coal use. This is
shown in table 13 which compares annual growth rates for
coal and total energy, and coal's importance in the
total energy picture under the two scenarios.

                                                    Table 13

                                   Growth of Coal Versus Total Energy

                                    Annual growth-rate (percent)
                               1975-85                     - -19-2000
                BOM        BOM      EEI     EEI    '5Oi       OM     EEI                          EEI
                         without                  wi thout              witE-ut                 witFiOut
                        synthetics               synthetics            synthetics              synthetics
energy           3.83       -             3.5w        -         3.09        -            0.53
Coal             4.98       4.73          2.21       1.50       3.33       1.65          1.20      (-0,31

                          Coal Input as aPercent of Total Energy Input
        1975                      1985                                           2000
       Actual BOM          BOM           EEI        EEI        BOM        BOM           EEI       EEI
                         withowitut               without               witut                   wi-ut
                        synthetics               synthetics            synthetics              synthetics
         18.8   20.6       20.1          16.1       15.0       21.3       16.3          17.8        14.0

     The most important information in table 13 is contained
in the upper right hand side.  These figures show that
during 1985-2000, both scenarios predict faster growth
for total energy than for coal outside the synthetic fuels
sector.  In fact, the EEI low demand scenario projects
an absolute decline in coal usage unless a synthetic fuels
sector can develop.

     Table 13 also reveals that, under the comparatively
"optimistic" BOM scenario, the share )f coal in the total
energy picture will rise to only 21 percent by 2000. As
shown in table 1, this was coal's approximate share in
the 1960s.

      In summary, the most optimistic growth rate in demand
for coal is assumed by BOM for the period to 1985 and equals
4.98 percent, as compared to an expected overall growth rate
of 3.83 percent.   In the contect of this high growth scenario,
there will not be a significant demand for coal in the
future.   The EEI scenario expects even less demand for coal.
Coal growth through 1985 is expected to be about half that
of overall energy needs. Beyond 1985 coal use will generally
decline except as a :ynthetic.   Even in the electrical sector,
in which a 50 percent expansion is projected, coal use
is expected to decline.

     The key assumption in the two scenarios, which greatly
affects electric utility demand for coal, is an increasingly
heavy reliance upon nuclear power generation. While in
1975 non-fossil fuel generation accounted for 4.8 quadrillion
Btus of total consumption, by 1985 the expected contribution
is set at between 14 and 16 quadrillion Btus, and for 2000,
between 32 and 52 quadrillion Btus. 107/

     As already noted, considerable uncertainty surrounds
fuel mix decisions in the 1980s and even more in the future
years.  A .eview of the two scenarios indicates that the
future of coal relates principally to its ability to compete
on an interfuel basis, regardless of levels of aggregate
energy demand.  If the future contains an efficient and
comparatively economical and environmentally acceptable
nuclear option, coal may not even hold its present position
in the Nation's fuel mix.

     But what if the nuclear option does not materialize,
or what if it is possible to significantly lower the relative
cost of coal use? What implications would this have for
aggregate coal demand, particularly if the Nation chooses to
increase its overall reliance on electric power? Neither
of the scenarios considered here are of any help in answering
questions such as these.

      We attempted to answer these questions through use of
 the FEA's National Coal Model (NCM). In effect, the NCM
 was asked to determine the level of coal consumption under
 the two scenarios with the supply assumptions incorporated
 in the model. These supply assumptions related to levels
 and types of electrical generating equipment, prospective
 markets for synthetic fuels, etc.

      Unfortunately, definitive and reliable answers
 not be obtained in time for inclusion in this report.could
 NCM is new and further adjustments seem necessary beforeThe
 its projections can be accepted with a high degree of con-
 fidence. However, the projections and other data obtained
 from our use of the NCM were approximately consistent with
 comparable projections from other sources. Therefore, we
 can summarize the principle findings obtained from our use
 of the NCM.
     The most important result of the NCM output made
available to GAO was that the potential consumption of coal
in the electrical sector was far greater than envisioned by
either the BOM or EEI scenario. The principal reason for
this difference was the relative optimism, of both the BOM
and EEI scenarios, about the future development of nuclear
power. The NCM projects a considerably smaller relative
role for nuclear power in the electrical sector.  This
result also implies that the key to coal development is
the cost and convenience of using coal compared to competing
alternatives. The level of demand for electricity is, at
least potentially, less important.

      The NCM also enabled us to analyze geographic patterns
of coal development. Consumption of coal by utilities by
1985 was projected to grow nearly twice as fast in the West
as in the East* while the Central** area consumption was
projected to grow at only one-third the rate of the West.
These differences were not affected much by the level of
electrical generation for the Nation. Of course, electricity
demand can be expected to grow faster in the West. Yet some
of this difference is due to prospective gas curtailments
and the relatively low cost and convenience of burning coal
in certain western areas.

*The East consists of Census Regions 1-3 and West is
 Regions 6-9.

**Census Regions 4-5.

      The geographic pattern of utility coal consumption is
approximately matched on the production side.    For example,
the growth rate of production during 1975-85 was projected
by the NCM to be more than five times as great in the
Northern Great Plains as in Appalachia or the Midwest.
This difference reflects the low-sulfur content of coal
from the Northern Great Plains and its comparatively lower
mining costs. These advantages would apparently enable coal
from States west of the Mississippi to successfully capture
markets previously served by Midwestern and Appalachian
producers. Furthermore, coal prices have increased more
than coal transport rates so that the relative importance
of transport costs in the price of coal has declined. This
contributes to the current advantages of western coal.
Once again, these regional differ'-ees were generally un-
affected by the overall level           ical generation.
So, regional differences -         .     ment appear to
depend more on decisie    r1              nce taxes, air
quality standards, etc. ha.n               of electricity
demand. Conceivably, the most             factor affecting
regional coal development patter.        oe the methods
chosen for meeting clean air stando.,s, a subject discussed
in chapter 6.

      In summary, many pc  b     ma    levels for coal can
be projected, even in the cor, .A of the next decade. How
coal fares in competition with other electric power generation
alternatives is of vital importance. Even an economy which
relies primarily on electrical energy will not automatically
turn to heavier use of coal in relative terms since current-1
it is not viewed by all as a superior alternative to nuclea;r4

      The probability of rapid coal development is apparently
erinanced more by the relative cost advantage for coal than
by the rapid growth in energy usage. If rapid growth in coal
usage is attained, above average growth could occur in
coal production--and consumption--in the West. The extent
of a shift to the East, if any, as a result of requiring
scrubbers on all plants has not been determined.

      In our earlier report to the Congress, An Evaluation
of the National Energy Plan, we assessed the various
recommendations of the administration to increase coal use
and concluded that a lot more needs to be done. 108/ We also
noted that the work we have been doing on the production and
use of coal raises serious doubts about the possibility of
achieving the administration's plan of producing and using
1.2 billion tons of coal by 1985. Given all the physical,
economic, environmental, and public health considerations,

it appears to us that producing and using even a billion tons
by 1985 would be difficult. Assuming, however, that the
difference between the administration's plan and reality is a
matter of 200 millior tons, we calculated that this would be
; shortfall on the do'es~tic energy supply side equivalent to
an annual use of 2.3 million barrels of imported oil per day,
as presented in the fue' balance tables in Lhe National En.erg
Plan. GAO's calculation was based on the administrafion's
estimates of what a shortfall of 200 million tons of coal
would entail using the administration's conversion factors.
However, the administration used an average Btu rate con-
version factor which does not reflect the true value of the
oil equivalent of coal.
     Using appropriate conversion factors for each use
where coal would substitute for oil, GAO estimates thai the
2.3 million barrels of oil shortfall noted above would actu-
ally be 2.2 million barrels of oil equivalent per day.

     Upon further review, we have discovered an additional
problem. As noted above, the administration calculated supply
and demand on the basis of quadrillion Btus and then converted
these to millions of barrels of oil a day equivalent. Using
the same conversion factor analysis as above, GAO estimates
that the oil equivalency of the remaining one billi)n tons of
coal could be 1.1 million barrels per day less than the admin-
istration's figures shown in the fuel balance tables in the
National Energy Plan. Thus the number of barrels of oil equiv-
alent per dayshown in the fuel balance tables for one billion
tons of coal (without the energy plan) should be 11.1 million
barrels per day instead of the 12.2 million barrels shown.*

     The following table compares the two approaches and
shows the difference in the results as f ~r as coal is con-

*These figures should be aIjusted downward by 1.4 million
 barrels per day equivalency for metallurgical coal which
 has no oil substitutability.

                        a,                   I
                        C               4
                        ._ I             .,

               .-       4        ,       n86 .                     -0
                   C Lo.

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                                                           4                                                                                                                   .

       As the table indicates, the GAO and administration
  estimates of trillion Btus are identical,
                                             but there is a
  difference of 1.1 million barrels of oil
                                            a day equivalent
  between the two estimates beciause of the
  factors used.                             different    conversion
                 Under the administration's average conversion
  factor, the production of one billion tons
                                               of coal would equal
  9.5 million barrels of oil equivalent while
                                                under a historical
  conversion rate, it would equal only 8.4
                                            million barrels of
 oil equivalent.   If this difference in conversion factors
  implied a real world shortfall, it would have
                                                  to be made up in
 one of three ways: additional imports; increased
 duction from other sources; or increased             domestic pro-
                                            conservation efforts.
 If, on the other hand, the oil equivalent
                                             numbers in the
 National Energy Plan simply reflect a mechanical
 average conversion factor from detailed estimates use of an
                                                       based on
 actual quantities, there would be no shortfall
 supply and demand would be less in barrels        since both
 As discussed in the next paragraph, we are   of  oil  equivalent.
                                              continuing our
 investigation into this possibility.

       In any case, these considerations raise
                                               questions about
 the factor used by the administration in
 of oil equivalent per day for other       converting   to barrels
which in turn ra.ses question; about domestic  energy sources,
                                       the administration's total
estimates regarding energy supply and demand.
the administration should either have presented GAO believes
                                                   its analysis
on the basis of Btus or used a more detailed
                                               set of conversions
to oil equivalency which recognized historical
                                                 and other trend
data in developing the conversion factor.
                                             Otherwise,   GAO
believes that the net effect could be to
                                           increase the total
energy supply and demand estimates when stated
                                                 in barrels of
oil equivalent. While not nart of this study,
                                                 we  are contin-
uing this analysis and will be reporting
                                           our findings to the


      Coal usage declined markedly during the past
                                                    25 years
relative to natural gas and oil.   Even in absolute terms,
total coal consumption grew at an average
                                           annual rate of only
0.49 percent during 1950-75.   Coal is not as convenient to use
as gas and oil because it is more difficult
ship, and, mcst importantly, it causes more to handle and to
                                             pollution when
burned. Evern now, for example, nearly 50
                                           percent of all coal
consumption for powerplant use is out of
                                          compliance with
existing air quality standards.

     Our main observation ill this chapter is
                                               that coal use
will increase significantly in absolute
increase much as a percentage of the Nation's    but may not
                                                total energy

     Given the Nation's growing reliance upon oil imports,
the conversion from oil to coal and nuclear is an important
alternative to consider. To promote conversion, Congress
passed the Energy Supply and Environmental Coordination Act.
109/ As of December 1976, 74 conversion orders had been issued
 y the Federal Energy Administration.  However, only 11 have
received approval by the Environmental Protection Agency, and
only three powerplants with 158 MW of capacity have been con-
verted. Fifty-one orders have been stayed pending the instal-
lation of improved pollution control equipment.

     The direct conversion possibilities in the transportation
sector between the present and the year 2000 are not very
great; in the residential and commercial sector they are also
very small; and in the industrial sector they are limited.   It
is in the utility sector that the direct conversion possibili-
ties look most promising.

     An attractive means of inducing the substitution of coal
(and nuclear) for oil or gas in the utility sector involves
improved load management through such measures as peak load
pricing and central dispatching (for better coordination).
Broadly defined, improved load management could increase
coal utilization by utilities by 149 million tons.

     With full conversion of oil- and gas-fired utility power-
plants to coal, optimal load management, and maximum thermal
efficiency, electric utility consumption of coal could rise
to some 873 million tons in 1985.  Of course, this level
of coal usage by utilities is highly unlikely by 1985.   One
reason is that the growth in electricity demand will most
likely not be sufficient to warrant Lich large coal
purchases.  Furthermore, the ability of the utilities to
burn coal in compliance with air quality standards at an
acceptable cost to the consumer has yet to be demonstrated.
The key point seems to be that improved load management,
particularly through rate reform, offers considerable
promise for promoting greater coal utilization.

     Future relative demand for coal depends almost entirely
upon the outcome of the contest between nuclear and coal-
fired electricity generating plants.   If the future contains
an efficient and comparatively economic ano environmentally
acceptable nuclear option, coal may not hold its present
relative position in the Nation's total energy consumption

     Nuclear's future looks more uncertain than it once did.
For example nuclear units accounted for over one-half of the
uncomjleted capacity in MW in the April 1 to September 30,
1976 period.  Of the total 21,272 MW scheduled to be placed

 in service, only 12,505 MW were actually
                                          put on line.   In
 contrast over 80 percent of the coal-fired
 for commercial operation during the period units scheduled
                                            were actualiv
  litered into service.

       Despite these recent indications that nuclear
  unlikely to live up to earlier expectations,
 plans are still predicated on expansion          current    utility
                                            of nuclear power
 relative to expansion of coal-fired generation.
 apparent advantage is three mills over                Nuclear's
 scrubbers and nearly four mills for coalcoal plants without
                                             plants with scrub-
 bers--a cost advantage of 15 to 20 percent.
                                                Nuclear generation
 is substantially more capital intensive
 generation even with scrubbers.           than   is coal-fired
                                    The assumed advantage
 of nuclear has been in projected fuel costs
                                                of one-third to
 one-half that of coal-fired facilities.
                                             Lately, however,
 increasing doubts have been voiced regarding
                                                 the superiority
 of the nuclear option.   These doubts concern costs of
 radioactive waste disposal and decommissioning,
 risks of fuel reprocessing and the fast              and the
                                           breeder reactor.
      GAO interviews with utility officials indicated
they believe that only large changes in
                                           projected costs
would significantly alter the current choice
of nuclear generation.                           in favor
                         Recent developments seem to suggest.
however, that wide shifts in the comparative
                                                 costs of
nuclear versus coal may not be so improbable.
the utility officials noted that nuclear            For example,
have to more than double or coal prices     fuel  costs   would
                                          would have to fall
by one-half or more to shift
Given recent trends in uraniumthe  balance in favor of coal.
                                 prices, a doubling of nuclear
fuel costs is certainly not impossible.

     Though the outcome is still uncertain,
                                            clearly the
contest between nuclear and coal-fired
                                       plants is getting

      Synthetic fuels from coal are unlikely
                                               to be cost effec-
tive in this century. Such fuels would
                                          only become a factor
if gas and oil were unavailable at projected
                                                price levels.
     A regionial analysis of future coal development
that the coal industry could experience
                                          greater expansion
west of the Mississippi.   Appalachia and
apparently grow at only one-half the rate the Midwest could
                                            for the industry
as a whole.   A requirement for scrubbers on all coal-fired
plants could reduce the advantage of western
coal and will have an effect on this analysis.
are complex, involving considerations of           The factors
versus lower eastern transportation distances      western
                                                 and costs,

lower western surface mining costs versus higher eastern,
and higher eastern Btu content versus lower western.

     We have doubts about the possibility of achieving
the administration's plan of producing and using 1.2 billion
tons of coal by 1985 or, for that matter, even the level
of one billion tons the administration assumes will be
achieved without its plan. Given all the physical, economic,
environmental, and public health considerations, it appears
that producing and using even a billion tons by 1985 will be
difficult. Assuming, however, that the difference is 200
million tons, the shortfall on the domestic energy supply
side in terms of oil equ valent would be 2.3 million barrels
per day.  In addition, tAO does not agree with the adminis-
tration's formula fur computing the oil equivalents of Ooal.
The magnitude of the difference in the administration's
calculations as compared to GAO calculations, as far as coal
is concerned, is about 1.1 million barrels of oil equivalent
per day.
     These considerations raise questions about the factor
used by the administration in converting to barrels of oil
equivalent per day for other domestic energy sources, which
in turn raises questions about the administration's total
estimates regarding energy supply and demand.

                         FOOTNOTE REFERENCES

 l/United States Department of Commerce, Statistical Abstract,
   1976 (Washington:  Government Printing Office,777), tab-Te
  906,     p. 549.
2/United States Department of the Interior, Energy
  Perspectives 2 (Washington: G3vernment Printing Office,
  139761 pp.
           -65to   76.



5/Richard L. Gordon,  U.S. Coal and the Electric Power
  Industry  (Baltimore:  The Johns Hopkins University
  Press, 1975), p. 6.

6/Federal Power Commission, Steam-Electric Plant
  Construction Cost and Annual Production Exenses
  (Washington:  Government PrintRg Office-,  972), p.                 XVII.

7/Federal Power Commission, The Potential for Conversion
  of Oil-Fired and Gas-FiredETectric GeneFraing Units
  to Use of Coal (Washington: FeeFral Powe-- Commission,
  1T7T7,    p. 2.
8/UnpuBlished data provided by Federal Power            Commission,
  Bureau of Power (February 25, 1977).

9/Cordon, _o. cit.,     p.   18.

10/United States Department of            the Interior, op.   cit.,   p.   63.
11/Thomas W. Hunter, Effects of Air Quality Reguirements
   on Coal Supply   (Washington: Bureau of Mines, 1976)
   p. 4; Tc should also be noted that some State implementation
   plane may become less stringent over time, although
   what effect these actions will have on compliance
   is unknown at this time.

12/Federal Energy Administration.  National Energy Outlook
   (Washington:  Government Printing Office, 1976), p. 178.

13/Federal Power     Commission, The Potential        for C nversion
  of Oii-Fired and Gas-Fired-lectric Generati                 Units
  to Use of Coal, op. cit., p. 7.

14/Ibid., pp. 2 to 3.

15/Federal Energy Administration, "Implementing Coal
   Utilization Provisions of EneLgy Supply and Environ-
   Iu Atal Coordination Act," April, 1976 (mimeo),
   table I-1.

'6/National Electric Reliability Council, Fossil and
   Nuclear Fuel for Electric Utility Generation-
   Require.nents and Constrainrrts,    1976-19S5 (Pr'inceton:
   National ElectErlc ReLiabilty Council, 1976), p. 12.

17/Capacity estimate obtained in telephone conversation
   with FEA official on July 20, 1977.

]8/Federai Energy Administration, "Implementing Coal
   Utilization Provisions of Energy Supply and Environ-
   mental Coordination Act," loc. cit.
19/National Electric Reliability Council, op. cit.,        p. 20.

23/Federal Energy Admainistration,       National Energy Outlook,
   op_. tit., p. 311.
21/Federal. Power Commission, Fort Worth Regional Office,
   The Phasing Out of Natural Gas and Oil For Electric
   Power Generation:   Southwst   ower Pool and iectric
   Reliab-lity Council of Texas, Part II (Fort Worth:
   Fe eral PoweTrommission,,-75) , p. 1.
22/Ibid., pp. 2 to 3.

23/Ibid., p. 7.

24/Ibid., pp. 86 and 89.
25,/Ibid., pp. 9J and 93.
26/Federal Energy Administration, "Implementing Coal
   utilization Provisions of Energy Supply anC Environmental
   coordination Act," op. cit.,       table I-1.

27/Federal Power Commission, Fort Worth Regional Office,
   oP. cut., p. 5.

28/National Economic Research Associates, Anplvsis of
   Electricity Pricing in France and Great BrLtain
   (New York: National Economic Research Associates,
   1977), p. vi; J. Robert Malks and David Stipanuk, "Electric
   Peak Load Pricing:   A Wisconsin Framework," Public
   Utilities Fortghtly,    July 15, 1976, pp. 1 to 4.
29/Federal Power Commission, The 1970 National Power
   Survey, Part I (Washington:  Government Printing
   OfTfic, TM7T), chapter 5, pp. 7 and 8; National Electric
   Reliability Council, op. cit., pp. 12 to 15.

30/Federal Power Commission, The 1970 National Power
   survey, Part I, op. cit., chapter 17.

:!/Natio-al Electric Reliability Council, op. cit.,
   pp. 12 to 13.

32/Ibid., p. 20.
33/Federal Energy Administration, Energy Conservation
   Paper Number 35, chapter 2, p. 9. Coal management
   at th-e retal level was estimated to require an
   additional 1.2 quadrillion Btus from coal.  The 52
   million ton estimate assumes a heat content of 23
   million Btus per ton.

34/Federal Power Commission, News Release, No. 22493,
   July 16, 1976, pp. 9 to 11.

35/National Electric Reliability Council, 1976 Annual Report
   (Princeton: National Electric Reliability CouiTc,   1977-7.
36/ICF Incorporated, The National Coal Model (Washington: ICF
   Incorporated, 1°76), chapter III, pp. 97Tand 98.

37/National Coal Association, Steam-Electric Plant Factors/
   1'75 (Washington: National Coal Association, 1976),
38/Brief of Richmond Power and Light Representative
   Michael Harrington, May 4, 1976, p. 29.

39/Federal Power Commission, Steam-Electric Plant Construction
   Cost and Annual Production Expenses, op. cit., p. XXVIII.



 42/Edison Electric Institute, Economic Growth in the Future
    (New York:  McGraw-Hill, 1976), p. 143.

 43/Federal Power Commission,  News Release, No. 22763,
    December 8, 1976, table 4; National Electric Reliability
    Council,  Fossil and Nuclear Fuel for Electric Utility
    Generation: Requirements and Constraints, 1976-1985
    2o. cit., p.   .
 44/Federal Power Commission, News Release, No. 22972,
    March 8, 1977, p. 1.


46/Ibid., table 1.

47/See footnote 42.

48/Federal Energy Administration, National Energy Outlook,
   op. cit., p. 220.
49/Ibid.,   p. 321.

50/Federal Energy Administration, National Energy
   Outlook, op. cit., p. 258.


52/Federal Energy Administration, National Eneg
   Outlook, op. cit., p. E-24.

53/Federal Power Commis3ion, News Release, No. 23030,
   March 28, 1977, p. 3.

54/Federal Power Commission, News Release, No. 232?4,
   July 25, 1977, pp. 1 to 2.


56/Federal Power Commission, News Release, No. 23030,
   op. cit., p. 1.

58/Ibid.; National Electric Reliability Council, Fossil and
   Nuclear Fuel for Electric Utility Generation:  Requirements
   anid Costnrants, i7-95, _    op. cit., p. 12.
59/P. Joskow aid M. Baughman, "The Future of the U.S.
   Nuclear Enerly Industry," Bell Journal of Economics,
   Spring, 197E, p. 18.

 60/Ibid., p. 19.
 61/Ibid., p. 20; GAO computations.
 62/Ibid., pp. 18 to 20.

 63/National Electric Reliability Council, Fossil and Nuclear
    Fuel for Electric Utility Generation:   Requirements and
    Constraints, 1976-i   , 2op. cit., p. 20.
 64/For example, see Edison Electric Institute, op. cit.,
    pp. 190 to 192; Federal Energy Administration, National
    Energy Outlook, op. cit., pp. 215 and 238; Walter
    G. Dupree, Jr. and Joi S. Corsentino, United States
    Energy Through the Year 2000 (Washington:  Department
    of the- I'nterior,-T97q , p.- 5.
 65/Derived from Edison Electric Institute, op. cit.,
                                                       p. 192.
 66/United <States Bureau of the Census, Historic-l Statistics,
    1975, Volume 1, p. 214; United States Bureau of Labor
    Statistics, Monthly Labor Review (various years); GAO
    computations of compoundannual growth rates.

67/United States Bureau of the Census, "Fuels and Electric
   Energy Consumed," 197" Census of Manufacturers (Washington:
   Government Printing Office, T977), table 6, p. 84.
69/Ibid., p. 7.
70/Federal Energy Administration, National Energ2y
   Outlook, op. cit.,   p. c-7; GAO computations.
71/"A New Spark Revives Electric Car Makers," Business
   January 17, 1977, pp. 86 and 87.                    Week,

72/"A New Route for the Highway Trust Fund," Business
   January 17, 1977, pp. 84 and 85.
73/Science Communication, Inc., Intra Industry Capability
   to Substitute Fuel (Washington: National Technical
   Information Service, 1974), p. 32.
75/Federal Energy Administration, "Implementing Cual
   Utilization Provisions of Energy Supply a.d Environmental
    oordinatiion Act,"p. ct. ta lT-T

 76/Dow Chemical, Eneg       Industrial Center Study,      1975, p. 30.

 78/Coal Week, March 14,     1977, p. 10.

 79/Information obtained during telephone conversation with
    Mr. William Axtman of American Boiler Manufacturers
    Association, April 8, 1977.

80/Science Communication, Inc.,       op. cit., p. 34.
81/Seminar on ESECA Program, Washington, D.C.,
   August 27, 1977.


83/Science Communication, Inc.,       op. cit.,   pp.   ii to iii;
   GAO computations.

84/United States Bureau of the Census, "Fuels and Electric
   Energy Consumed," op. cit., table 3; GAO computations.


86/Science Communciation, Inc., 2i. cit., p. iii.

87/Dow Cnemical, op. cit.,     p. 21.


89/Science Communication, Inc.,       op. cit., p. 34.
90/Dow Chemical, op. cit.,     p. 116.
91/Ibid., pp. 7, 8, 15 and 16.

92/Tom Alexander, "Industry Can Save Energy without
   Stunting Its Growth," Fortune, May 1977, p. 195.

93/"Coal Takes on Added Significance," Electrical World,
   May 15, 1977, p. 53.

94/Ibid.,   pp. 52 and 53.

95/Executive Office of the President, The National Energy
   Plan {Washington:  Government Printing Office, 1'77),
   p. 94.

  96/Burton Kolb, "The Rise and Fall of
                                        Public Utilities:
     An Appraisal of Risk," Journal of Business,
     1964, p. 337.
  97/Dupree, Jr. and Corsentino, op. cit.,
                                           pp. 44 and 45.

 100/United States Congress, House of
     Committee on Interstate and Foreign Commerce,
     "Energy Demand Studies--An Analysis and
     Middle and Long-Term Energy Policies      Comparison,"
     Part 7 (Wasig                         and
                    t n--- Goverment PrintTing Alternatives,
                                                Office, 1976),
     pp. 76 and 77.
 102/Data in table 11 are derived from:
                                              Dupree, Jr. and
     Corsentino, op. cit.,   pp. 28 and 36;
    Institute, op. ct., pp. 161 and 163; Edison Electric
    Reliability Council, Fossil and NuclearNational Electric
    Electric Utility Generao:                Fuel for
       i9-6I98~,    cit.7,
                    op.  p. 16-
_03/Dupree, Jr. and Corsentino, op. cit.,
                                           pp. 24 to 26;
    Edison Electric Institute, 2p. cit.,
                                          pp. 147 to 169.
104/Information obtained from Edison
                                     Electric Institute.
105/Dupree, Jr. and Corsentino, op. cit.,
                                           p. 25.
i06/GAO computations based on estimates
                                         of price and income
    elasticity of demand for electricity
    Robert Halversen, "Demand for Electriccontained in:
    the United States," Southern Economic Energy in
    1976, pp. 610 to 625.                  Journal, April,

]07/Table 1, appendix II, p. II.3 of
                                      this report.
108/United States General Accounting
                                      Office, An Evaluation
    of the National Energy Plan, EMD-77-48
    General-Iccounting Office, 1977), p.    (Washintgton:
109/Public Law 93-319 (June 22, 1974),
                                        15 U.S.C. 791 et seq.
    (Supp. V, 1975).

                           CH'APTER 3

                      HOW MUCH DO WE HAVE?

      As of January 1974, there were 3.9 trillion -ons of coal
resources in the United States, according to the U.S.
Geological Survey (USGS). 1/ Of this total resource, 1.7 tril-
lion tons were classified as identified resources and 2.2
trillion were classified as hypothetical or undiscovered
resources. 2/ Coal resources in the ground that can be mined
economically are termed reserves*, i.e., the quantity that
can actually be mined given present technological, economic,
and legal constraints. According to the Bureau of Mines,
about 256 billion tons of the identified resources are classi-
fied as reserves and are equivalent to about 5,040 quadrillion
Btus**   3/ When compared with other domestic fossil fuel
reserv s (oil, natural gas, oil shale, and tar sands), coal
represents about 90 percent of the Nation's fossil fuel
rese ves. 4/ The high coal demand fo'ecast considered in
this report in 2000 shows coal consumption at 1,586 million
tons.   If the high forecast for 2000 materializes which assumes
coal production grows annually at 3.69 percent from the 1976
production level of 665 million tons, the reserves of 256 bil-
lion tons, estimated under present economic and technological
conditions, could meet U.S. coal demand for about 74 years.
However, as coal prices increase, coal resources which were
not profitable to mine previously would become profitable.
This would extend the life of the U.S. reserves.

     Despite the vastness of U.S. coal deposits, there are
several problems which may influence the potential recover-
ability of certain reserves and in turn affect national
and regional levels of recoverability. These problems are
discussed under the following sections

*As used in this chapter, the term reserves denotes recoverable

**To illustrate the vastness of the Btu equivalency of esti-
  mated coal reserves, 1 quadrillion Btus provide enough energy
  to electrically heat and cool about 7 million typical AmeLi-
  can homes for one year, and are equivalent to 180 million
  barrels of oil or 1 trillion cubic feet of natural gas.

Note:   Numbered footnotes to ch. 3 are on pp. 3.24 to 3.29.

      -- Coal resource and reseive concepts:    definition
         and measurement.

      -- Reliability and usefulness of   reserve and resource

      -- Sulfur content of coal resources and reserves.

      -- Reccverabilit7 of reserves.

      -- Implications of Federal coal ownership.


     The criteria for measuring and estimating coal deposits
embrace tio commonly used concep's--.resource and reserve.
Resources are deposits of coal in such form that e'ttraction
is currently and/or potentially feasible; reserves are
coal deposits that can be extracted under current economic
and technological condition:.

Coal resources

      Within the framework of resources, coal deposits are
estimated by the U6GS and are classified as identified resour--
ces and undiscovered resources.*   Ie~entif ea resoe,-- s refer co
deposits of coal whose location, quality (sl'Lur, ash, mois-
ture, Btu content, tic.) and quantity have. been mapped and are
known to exist from geologic evidence suppotted by engineerir.g
and measurements of geologic reliability. The concept of un-
discovered resources recognizes deposits of coal surmised to
exis- in unmapped and unexplored areas on thLe basis of broad
geologic knowledge and theory.   Both subclassifications of
resources include coal deposits in beds of minimum thiickness
(14 and 30 inches, depending on col rank)** occurring at
depths to 6,000 fe',t. 5/

*Our discussion on undiscovered resources reters to hypo-
 thetical resources.

**identifi,:d resources (anthrac 4te coal excluded, inclJde beds
  of bituminous coal 14 inches or more thick, and beds of sub-
  bituminous coal and lignite 30 inches or more thick.

Coal reserves
     The term reserves refers to portions of identified coal
resources that can be mined under current engineering and
economic conditions; estimates are referred to as the
demonstrated reserve base and reserves. The demonstrated
reserve base relates to coal deposits at depths and seam
thicknesses similar to those from which coal is currently
being mined--generally having a seam thickness of 28 inches
or more for bituminous coal and 60 inches or more for sub-
bituminous and lignite coal at depths to 1,000 feet. 6/
BOM has estimated the demonstrated reserve base to be 429
billion tons. 7/ That portion of the demonstrated reserve
base which can actually be mined given present technological,
economic, and legal constraints is termed reserves.
     Reserves are classified, by mining method, as either sur-
face or underground. Presently, surface reserves can be econo-
mically mined at depths generally no greater than 120 to
250 feet 8/; underground mineaale reserves, at depths to
1,000 feet. Traditionally, an average of 80 percent of the
surface mineable demonstrated reserve base has been recovered
while only 50 percent of the underground demonstrated reserve
base has been recovered. 9/ These recovery rates when applied
to the demonstrated reserve base yield "recoverable'" reserves
of 256 billion tons.

Location of P!.S; coal
resources and reserveb
     For purposes of analyzing coal deposits, coal-bearing
States have beeui grouped into three regions: the Eastern,
Central, and We-tern regions. The Eastern region includes
all coal-bearing States east of the Mississippi River,
except those in the Central region--Illinois, Indiana, and
Ohio. The Western region includes all coal-bearing States
west of the Mississippi River. Table 1 summarizes estimated
resources and reserves for the three regions.
     About 82 percent, or 3.2 trillion tons, of total coal
resources are located in the Western region. Of the 429 bil-
lion tonb associated with the demonstrated reserve base,
46 percent is found in the Eastern and Central regions (about
23 percent in each region) and 54 percent in States west
of the Mississippi River. Estimates of reserves show 58 per-
cent in Western States with the remainder about evenly split
between the Eastern and Central regions.

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                                                                                                           3.~ 4 ~          ~
 Quality dimensions of
 resources andreserves
      Coal is commonly classified as to particular chemical
 and physical properties which relate to the quality
 for usage purposes (direct combustion in boilers     of coal
 conversion into synthetic fuels).                 or for
                                    The qualities in coal
 which are recognized as important are its heat
 (Btu per pound), sulfur, trace element, moisture,
                                                    and ash
 contents. 10/ Coal deposits of the Eastertn and
 regions have a higher heat content than most
                                              of those found
 in Western States.

      Coal deposits in the Eastern and Central regions
 predominantly bituminous in --nk, having a heat        are
                                                 content range
 of 10,500-14,000 Btus per pou..d. Western coal, on the other
 hand, consists of bituminous, subbituminous,
                                              and lignite,
 Subbituminous coal, which comprises about 72 percent
Western region's demonstrated reserve base, has        of the
                                                 a heat
content ranging from 8,300 to 11,500 Btus per
                                               pound; bitu-
minous coal accounts for about 17 percent of
                                              the western
'demonstrated reserve base and lignite, about
                                              11 percent.
Lignite has a heat content ranging from 6,300
                                               to 8,300 BtuF
per pound.

     Sulfur and ash contents are undesirable properties.
Sulfur contributes to corrosion, to the formation
                                                   of boiler
deposits, and to air pollution.  Overall, western coal is
appreciably lower in sulfur content compared to
                                                coal found
in the Central and Eastern regions. 11/ Ash and
content vary according to coal types but generally
coal has a higher moisture content than eastern
while ash contents vary within each region.

      The sulfur content of coal has become important
                                                       in recent
years, with the enactment of air quality legislation
controls.                                             and
            As noted in chapter 2, increased reliance on
low-sulfur coal has shifted some demand to new
                                                mines of low-
sulfur coal in the West. As discussed in chapter
                                                   6, future
environmental concerns over clean air are expected
sharper focus on the regional distribution of       to bring a
                                               coal reserves
largely driven by reserve quality differences,
sulfur content.

     In terms of conversion into synthetic fuels,
                                                  some coal
is also more desirable than others for conversion
thetic fuels because of physical properties.      into syn-
                                              Under current
technology, western coal is more desirable than

 coal due to its noncaking* attributes when subjected to
 intense heat and pressure. Eastern coal requires costly
 pretreatment in order to minimize its caking characteristics.

 Reliability and usefulness of
 reserve estimates
      The usefulness of existing coal resource and reserve esti-
mates variec according to the purpose for which they are
 In broad terms, the estimates do provide a rough idea as used.
 the size of the Nation's coal inventories fron which present
and future production potential can be projected.   In specific
terms, the reserve estimates are of crucial importance
assessing coal as an alternative energy source. That is,when
given current and expected future coal (and substitute fuels)
prices, reserve estimates oug.t to tell decisionmakers how
much coal is and will be available.  13/ There are, however,
grounds for questioning the reliability and usefulness of
current coal estimates in terms of their use for specifi-
decisionmaking purposes. 14/ Our study indicates that
available data do not permit a useful delineation of U.S.
coal reserves.

      Furthermore, since coal must compete with other energy
sources, a decisionmaker must know the total cost of con-
verting coal to energy in order to make a choice. One part
of this total cost is '    extraction or mining cost.
reserve estimates are based on the assumption that onlyCurrent
a portion of the demonstrated reserve base will actually
be mined due to technological, economic, or legal constraints.
This condition occurs because not all of the demonstrated
reserve base can be economically (profitably) recovered with
current technology under current cost (price) conditions.
     Some reserves are not mineable at specific locations
because of several factors.  In the Eastern and Central re-
gions, most of the mining to date has been accomplished in

*Caking coals, when heated, pass through a plastic stage
 cake or stick together into a mass and, as a result, do
 combust fully and clog the system.

areas where multiple seams of coal are present. For economic
reasons, it can be reasoned that the most profitable (least
cost) seams of coal are mined first. This procedure often
leaves the seams above and below unused. BOM counts unused
seanis as mineable, which may not necessarily be true. If the
intervial between a mined seam and an unused seam above or
beneath it is not sufficiently thick, the unmined seam may
be fractured and subsided to such an extent that the seam is
not mineable under any conditions. Water seeping through
fractures may make the roof unsupportable and, therefore, the
seam is lost for mining. Yet these unmineable seams are still
included in the demonstrated reserve base. 16/

     In addition, seams of coal under populated areas, Federal-
and State-owned forests, parks, reservations, airports,
navigable rivers, and streams, etc., which are not legally
mineable, are also included in the demonstrated reserve base.
The land surrounding oil and gas wells is often not mineable
as large blocks of coal have to be left standing to prevent
the hazard of oil and gas seepage, but it, too, is included
in the demonstrated reserve base. 17/
     To account for the portions of the demonstrated reserve
base which cannot be recovered, some estimates employ differ-
ential rates of recovery for the underground and surface-
mineable demonstrated reserve base. Traditionally, these rates
have been 50 percent for the underground demonstrated reserve
base and 80 percent for the surface-mineable demonstrated
reserve base. Debate surrounds the appropriateness of these
recovery rates. Previous studies indicate that the amount of
coal that can be recovered from a known deposit can vary from
about 35 percent to 90 percent. 18/ Such e wide variation in
recovery rates has raised questions as to che usefulness of
current estimates at certain locations based on the generalized
recovery rates of 80 and 50 percent. 19/
      In addition to the above geologic factors, economics
plays a major role in determining which reserves will actually
be recovered. For example, the greater the depth at which
reserves are recovered, the more costly is the operation. 20/
Reserves mineable by underground methods are influenced by
factors other than reserves mineable by surface mining
techniques. Among the important factors besides depth of seam
in underground mining are thickness and consistency of coal
seams, unsafe roof conditions, water deposits,

 methane* liberation, and poor floor conditions. Such factors
 increase the hazards of mining, reduce mine productivity, and
 increase production costs. 21/

      The distribution and severity of these factors for
specific coal reserves is not systematically available in
current publications. Cost conditions are handled vaguely.
Common to most USGS and BOM publications is the reference
to current costs without any definition of cost levels or
the distribution of costs for underground reserves at specific
locations. 22,/ In commenting on this report, USGS stated
that neither -- hey nor BOM have the authority to obtain actual
mining costs from industry. As presented in USGS and BOM
analyses, cost conditions are assumed to be uniformly
distributed on the basis of the criteria employed for
delineating underground reserves by geological assurance,
minimum seam thickness, and maximum depth of 1,000 feet with
few exceptions at specific locations.

     Available data, therefore, do not permit a
delineation of reserves on the basis of economic useful
                                                  costs at
alternative deptns of deposit nor on other conditions affec-
ting productivity (costs) at specific locations. 23/

     Surface reserves, on the other hand, are influenced
by fewer cost factors with depth of overburden being the pri-
mary one. Generally, surface mining is economical when the
depth of overburden to be removed is of a certain relation
to the seam thickness of the coal
tion is normally expressed in termsto ofbe teet
                                            recovered.  This rela-
                                                of overburden
removed per foot of coal recovered, referred to as a stripping
ratio.** What is considered to be an economical (profitable)
stripping ratio is determined largely by technology in the
form of ear,n moving equipment (shovels and draglines) although
terrain characteristics also influence productivity levels.
For example, in the Eastern region, an economic stripping
ratio varies between 15:1 and 24:1. Stripping ratios
considered economical in the Central region vary from 15:1 to

*Methane (commonly called natural gas) is a colorless, odor-
 less, gaseous hydrocarbon and is formed by the decomposition
 of plant and animal matter, and occurs in pockets in under-
 ground coal mines, presenting the danger of fires and explo-
**For example, a stripping ratio of 10 to 1 (10:1) means that,
  on an average, 10 feet of overburden have to be removed
  for each foot of coal recovered.

20:1, while in the Western region they range between 1.5:1
to 30:1. 24/

     Available data give some indication of economic strip-
ping ratios but only at the State level.  As currently com-
piled, the data do not present calculations of stripping
ratios at specific coal deposits, making it difficult to
identify and delineate surface mineable reserves on a cost

      In addition to questioning the reserve estimates on
an economic basis there is some concern as to the validity
of the data sources used to derive coal estimates. The
methodology used by the USGS and BOM relies heavily upon
secondary sources.   Examples of secondary data sources include
publications by State geological surveys, drilling records
of coal mining companies, petroleum exploration firms, and/or
water-well drilling companies, information in the files of
State coal mine inspectors, and private records obtained
from individuals. 25/ Coal reserve estimates obtained from
coal companies and other proprietary sources are possibly
understated due to incentives to avoid property taxes.   Many
States and political subdivisions within States where coal
deposits are vast derive substantial tax revenues from pro-
perty taxes levied on mineral deposits.   Although the tax
incentive may bias reserve estimates, the exact magnitude
of the underestimation is not known. 26/

     Although a uniform set of criteria has been adopted
recently by the USGS and BOM for measuring resources and
reserves 27/, the application of such criteria to such diverse
secondary data sources, without analysis, may result in adding
together dissimilar data bases.   Much of the secondary data
used by USGS was accumulated in the early 1900s and has not
been refined since that time. 28/

     Frevious studies have shown that there are inherent
limitations of coal resource and reserve estimates currently
available at the USGS and BOM. 29/ Alternatives that have
been discuss-d to improve the reliability and usefulness of
the estimates include: 30/

     -- Stratigraphic drilling and mapping.

     -- Submission of coal reserve estimates by companies,
        including some degree of verification.

     These could generate a more accurate picture of useable
coal reserves.  This is particularly important in the Eastern
and Central coal regions where current estimates date back
to the earlier part of this century.  Since coal production
could be quite significant in these regions, it is important

that a reliable coal reserve estimate be obtained. A sub-
stantial revisinn in estimates of the quantity and quality
of eastern coal fields would lave an impact on the level and
need for investments in western coal mines and transportation
facilities. Furthermore, if refined resource estimates indi-
cated that Eastern and Central utility markets could be sup-
plied with low-sulfur reserves from eastern coal fields, the
Federal coal leasing programn in the West could be modified

     There are some problems relating to the legality and the
efficacy of a federally funded stratigraphic drilling program.
One potential legal problem is the authority of a Federal
agency to explore and conduct drilling programs on privately
owned lands, particularly in eastern coal fields.   In eastern
coal fields, surface as well as mineral rights are largely
privately held. Although no comprehensive study of eastern
coal ownership rights has been undertaken, available evidence
indicates widespread private ownership in the Central and
Eastern fields. In the Western coal region, ownership is less
of a problem since the Federal Government owns about 70 per-
cent of the mineral rights of coal-bearing lands west of the
Mississippi River. The Government's ownership pastern
of western coal lands has the potential of influencing the
development of another 20 percent of western coal-bearing
lands (owned by States, railroads, and individuals) bordering
on Federal lands. 31/
      In the Northern Great Plains States of Montana, North
Dakota, South Dakota, and Wyoming, the Federal Government
owns about 14 percent of the surface rights and about 60 per-
cent of estimated coal reserves underlying about 91.6 million
acres (143,125 square miles) of coal-bearing lands. These four
States own 5.4 percent of the remaining surface area and 6.3
percent of all mineral rights. 32/ Federal drilling in these
coal-rich States is less constrained by ownership, and in
fact, exploratory drilling by the USGS on Federal lands is
authorized under recently enacted Federal Coal Leasing Amend-
ments Act of 1975 (Public Law 94-377), prior to additional
leasing of Federal coal lands.
      Cost of conducting a stratigraphic drilling program
depends on several geologic and economic factors. For
example, in fiscal year 1976, the USGS's cQal exploratory
drilling pro-ram was funded for $1 million with which
500 holes were drilled at an average cost of $2,000 pe. hole.
For fiscal year 1977, the Survey's drilling program is
funded for $2.5 million with which 1,255 holes are to be
drilled. USGS's drilling program _has been and will continue
to be heavily concentrated in Mon-ana, Wyoming, and North
Dakota; these States include about 75 percent of all USGS
drilling activity. The average cost of drilling per

vertical foot varies according to terrain condition
(flat, hilly) and depth and composition of overburden.
These costs vary in the Western States from a low of $2.35
per foot to a high of $25 per vertical foot. 33/ In the
Central and Eastern regions, these costs range from $il
to $15 per foot. 34/
     Given probable legal constraints, if a systematic nation-
wide drilling program were to be undertaken, it is likely that
new Federal legislation would be required to allow such acti-
vity on private lands, particularly in the East and Midwest,
     The second means of refining resource and reserve
estimates--submission and verification of privately hield
records--wojld serve to enhance data reliability at a lower
cost compared to a comprehensive or select drilling ard
mapping program. However, this approach may not produce
data for large areas of coal-bearing lands as not all coal
lands throughout known coal fields have been previously
explored and drilled. To produce meaningful results, a
verification program would also likely require limited
drilling and mapping of unexplored coal fields which may
hold large quantities of desirable (low-sulfur) coal. To
gain the cooperation of industry and minimize legal delays,
incentives or legislative changes may be useful. An example
of an incentive would be a Federal tax credit to firms that
developed and reported their coal reserve holdings according
to specified criteria.
Sulfur content of coal
resources and re.erves
     Under existing Federal and State air quality standards,
coal consumers are limited to using coal with low-sulfur
levels, reducing sulfur contents before combustion (washing
and blending) or removing emissions following combustion.
Accordingly, a crucial question is whether thctre are
sufficient supplies of low-sulfur coal to satisfy our energy
needs from coal through 2000. Because control technology
currently available for removing sulfur from coal before com-
bustion increases capital and production costs, electric utili-
ties are generally inclined to choose low-sulfur coal to reduce
or eliminate the problem of removing emissions following com-
bustion using current control technology.
     Sulfur occurs in coal in the form of organic sulfur and
as pyritic sulfur. The former is bonded in the coal and cannot
be removed by mechanical washing while some pyritic sulfur can
be removed. A recent BOM study based on 455 U.S. coal samples

concluded that current coal-cleaning technology will
significantly increase the amount of coal which can be
directly burned in accordance with Federal new source
performance standards promulgated under the Clean Air
amendments of 1970 (Public Law 91--604)--1.2 pounds of
dioxide per million Btus. 35/                           sulfur

      Current estimate! of low-sulfur coal are mostly made
 the context of the demonstrated reserve base. The sulfur in
 tent of the remaining identified resources is not accuratelycon-
known. 36/ Estimates of low-sulfur coal reserves may
reliable to the degree desired for long-term national not be
planning but they do give some idea as to their gross
bilities. BOM estimates reveal that about 31 percent availa-
                                                       of U.S.
reserves, or about 78.9 billion tons, can be used for
combustion and meet Clean Air Act standards without being
cleaned prior to combustion. Of the estimated 78.9 billion
tons, 8 billion are located in the Eastern region, .3
tons are in the Central region, and 70.6 billion (89 billion
of the total estimate) are in the Western re2ion.     percent
delineates estimated reserves by region of location,Table  2
of mining, and pounds of sulfur dioxide per million
Btus. 37/
     Two Western States--Montana and Wyoming--have ibout
80 percent of the country's 78.9 billion tons of low-sulfur
coal, according to BOM estimates. Montana alone is estimated
to have about 69 percent of the Nation's known reserves
low-sulfur coal, according to BOM data.                  of

     The regional distribution of low-sulfur reserves
a dislocation in terms of both future coal production presents
                                                       and coal
use. That is, a large portion of these reserves is located
in the Western region and is a considerable distance
                                                      from tra-
ditional coal consuming centers, particularly the Eastern
United States, and new coal consuming areas in the southern
and Southwestern United States. 38/

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                                                                                                 3. 13
     Assuming no change in current pollution standards, low-
sulfur coal will most likely be used to a great extent to meet
air pollution standards. Table 3 shows a compa-ison of low-
sulfur coal reserves and cumulative demand requirements for
the scenarios.   As shown in the table, we can surmise that
known estimates of low-sulfur coal reserves will be depleted
by almost one-third by the year 2000 (column 5 in the table)
if low-sulf'lr coal is the only coal used to satisfy added coal

      Assessing the adequacy of low-sulfur reserves must also
take into account the reserves of metallurgical coal which,
among several unique qualities, has low-sulfur content. 39/
The majur use of metallurgical coal (also called "met coa-T"
or coking coa     is production of coke, an essential ingredient
in the manufac.urinr   of iron and steel. 40/ Coke is usually
made front blends of several metallurgical-qrade coals which
are broadly classified as either premium-grade coking coal or
marginal-grade coking coal. 41/ According tc BOM, premium-
gra-i coking coal, as generaTTy accepted, conuains no more
than eight percent ash and one percent sulfur when mined or
after conventional clean ng. Marginal-grade contains between 8.1
?nd 12 percent ash, and between 1 and 1.8 percent sulfur. 42/
(oking coal used for metallurgical coke production must have
relatively small amounts of ash and sulfur, as all of the ash
and a large portion of the sulfur remain in the coke and can
reduce the quality of the metals. 43/ Reduction of ash and
sulfur in the metal]urgical process is essential and
costly. 44/

      The broad classifications of premium-grade and merginal-
grade metallurgical coals are further distinguished by the
amo..nt of fixed carbc.i and volatile matter* they contain. 45/
BO;: classifies co-. as, low-volatile it it contains from 14
to 22 percent volatile matter and medium-volatile if it
contains 22 to 31 percent. 46/ Low-volatile metallurgical
coal included in a coal blenZ serves to increase the yield of
a coke manufacturing operation, and to produce a higher strength
coke, with slow-burning, even-heat advantages for steel manu-
facturing and other high-value uses.    BOM reports that as yet
there are no accurate estimates of coking coal reserves, but
prior Bureau reports have indicated that about 20 billion tons
of the demonstrated bituminous coal reserve base of 233 billion
tons consists of premium-quality coking coals, 47/ An assessment
by BOM indicates that about 7 billion tons is low-volatile
coking coal. 48/

*Volatile matter consists mainly of combustible gaseous
 hydrocarbons but includes some inert gases such as carbon

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      Coking coal occurs in about 20 States, but it is esti-
 mated that at least 90 percent of all coking coal is in
 the Eastern region. West Virginia has, by far, the largest
 quantities of both premium- and marginal-grade coal,
 followed by Pennsylvania and Kentucky. Kentucky coking
 coal, however, has high-volatile matter content while
Pennsylvania has high-volatile as well as undetermined
quantities of medium- and low-volatile coking reserves.
Known deposits of low-volatile coking coal occurs only in
West Virginia, Pennsylvania, V rginia, Maryland, Arkansas,
and Oklahoma. 49/    The lack of accurate and reliable data
regarding premi-um-grade coking coal has fostered a contro-
versy concerning how much low-volatile premium-grade coal
is produced and exported, and whether these exports will
affect unfavorably our future domestic steel production
capabilities. 50/ In 176, about 250 million tons of metal-
lurgical coal were produced. Of that amount, 90 million
tons were used by the domestic steel industry, and 50
million tons were exported, leaving some 110 million
tons for other uses, most likely by electric utilities
in search of low-sulfur coal. 51/

      Although metallurgical coal requirements were included
in the above analysis er the adequacy of low-sulfur reserves,
 it should he noted that market pressures may restrict the use
of metallurgical coal deposits by electric utilities. For
example, recent data show the average (spot market) price
(FOB mine) range of metallurgical coal to be $26 to $50 per
ton as compared to an average price range of about $7 to $20
per ton for steam coal. 52/ Becaose of these price differen-
tials, the steel companies who own substantial amounts of
metallurgical coal reserves may continue to be the principal

     The data, as indicated above, reveal that about 110
million tons of metallurgical coal may have been consumed by
electric utilities in need of environmentally acceptable
low-sulfur coal. We were unable to determine whether this
coal was of premium-grade quality since official data are
not available, making it speculative whether this represents
a future trend. Availability of acceptable environmental
control technologies and potential Federal requirements for
their use at electric utilities could reduce the demand for
low-sulfur coal.

Recoverability of reserves

     Coal can be mined by three techniques--underground,
surface, and auger mining. Auger mining is essentially
a form of surface mining. On an economic basis, surface
mining offers significant cost advantages over underground

 mining. Over the past several years, the Congress had debated
 and passed legislation, which was subsequently vetoed, on
 setting standards for surface mining and reclamation.
 95th Congress and the new administration placed a high The
 priority on controlling surface mining, which resulted in
 passage on the Surface Mining Control and Reclamation Act
 of 1977 (P.L. 95-87). 53/

      Surface mining has received national attention because
 of its adverse environmental impacts. lner; impacts can
 be reduced by regulating the coal industry's surface mining
 activity. The nature of these adverse environmental
 impacts is discussed in chapter 6.

     The recently enacted surface mining legislation
(P.L. 95-87), prohibits mining of certain coal reserves
because of the potential adverse environmental effects during
and after mining operations. Among the restricted areas
     -- Alluvial valley floors,
     -- Steep slopes,

     -- Federal lands where surface owners' rights are
      P.L. 95-87 contains an alluvial valley floor restric-
 tion which will eliminate some reserves from being mined.
 However, it allows for the continuation of current mining
 operations producing coal in commercial quantities in
year preceding enactment of the law, or which had obtained
permit approval by State regulatory authorities. 54/
Alluvial valley floors consist of unconsolidated eeposits
 formed by streams or channels where ground-water levels
are high enough to permit irrigation which is vital to farming
and ranching operations. 55/ As defined in P.L. 95-87,
the restriction would affect parts of Montana, Wyoming,
North Dakota, Utah, and Colorado. Recent studies indicate
that the amounts of surface areas and coal reserves affected
by the restriction in these regions would be small--only
about 3 percent of the surface area. 56/ One study concluded
that perhaps .6 to 2.4 billion tons of-surface-mineable
reserves may be restricted in order to protect alluvial
valley floors in agriculturally developed areas, a small
amount when compared to the vastness of western surface-
mineable reserves. 57/

     Surface mining restrictions based on the angle of the
slope overlying coal reserves are also provided in

P.L. 95-87. The act defines a steep slope to be any slope
above 20 degrees, or such lesser slope as may be defined by
regulatory authority (the Secretary of the Interior or the
State involved) after considering regional environmental
and geological factors. 58/ For all practical purposes, the
Eastern region areas of southern West Virginia, eastern
Kentucky, Virginia, and eastern Tennessee would be
affected most by steep slope reserve restrictions. However,
accurate estimates of economically recoverable reserves
lost to mining by the steep slope restriction are not
available. Technological advances in the practice of
mountaintop removal* may permit recovery of some reserves
under steep slopes at certain locations 59/ in an environ-
mentally acceptable manner. 60/

      Public Law 95-87 also provides protection to owners
of surface rights overlying federally-owned coal. Written
consent from surface owners must be obtained by the Secretary
of the Interior befor. such land can be leased for surface
mining. 61/ No accurate estimate exists as to the amount
of Federai coal mineral rights that is overlai by non-Federal
surface rights. One study indicates that as much as 14
billion tons of coal could be prohibited from surface
mining under this provision in the seven-State region
consisting of Colorado, Montana, New Mexico, North Dakota,
Oklahoma, Utah, and Wyoming. 62/ This highly uncertain
estimate indicates the need for more reliable and accurate
reserve data on Federal coal lands.

     Recoverability of coal resources at some locations
may also be reduced because of incremental mining costs
associated with reclamation and restoration requirements
in the act. The act (1) prohibits leaving "highwalls"--
nearly vertical overburden formations similar to highway
corridors cut through mountains--after reclamation;
(2) imposes strict criteria for mining steep slopes,
generally found in Appalachia, including the prohibition
of placing overburden on hillsides in order to prevent
landslides and other environmental damage; (3) minimizes
disturbances to the prevailing hydrologic balance in surface

*Mountaintop removal mining is practiced where coal
seams are close to the Lops of mountains. This technique
is the most economical method of mining these coal deposits
and requires the removal of all overburden covering the coal

and ground-water systems during and after mining operation
activities at the mine site and associated areas; and
(4) requires that mined land be restored to its approx-
imate original contour with exceptions for mountain-
top removal operations and other variances permitted
by the act. 63/ Public Law 95-87 also establishes a fund
to reclaim aE-andoned mined lands financed by a 35 cents
per ton fee on all surface-mined coal* and a 15 cents
per ton fee on deep-mined coal or 10 percent of the
value of the coal at the mine gate, whichever is less. 64/
     These reclamation and restoration requirements
will increase the cost of mining coal at specific locations.
Some States already impose reclamation and restoration
requirements similar to the Federal regulations. (5/
The major cost element for most surface mining recTamation
operations is the cost of handling overburden. When
backfilling and regrading is performed to restore terrain
to its approximate original contour, mining costs increase
as a result of more extensive rehandling of overburden. 66/
Operating costs as well as capital costs per ton of coal
recovered will be increased since additional labor and
equipment will be required to reclaim and restore the
terrain disturbed during mining operations. Although
no accurate estimate of these incremertal costs on a per
ton basis by region is available, a recent study indicates
wide variations in reclamation (operating) costs per acre
for existing mines, ranging as high as $4,895 (1976 dollars)
on near-level terrain to $7,743 (1976 dollars) on steep
slopes, and up to $11,125 (1976 dollars) on very steep
slopes. 67/
     Because cost variations can range widely it is diffi-
cult to determine with accuracy the magnitude of surface-
mineable resources affected by P.L. 95-87 at various levels
of coal demand and prices. However, the impact will vary
from one location to th'e next as terrain, technological,
geologic, and economic conditions differ.

*The reclamation fee for lignite coal is 2 percent
of the value of the coal at the mine gate, or 10 cents
per ton, whichever is less.

 Implications of Federal coal ownership

     The Government is in a good position to influence the
recoverability of coal reserves due to its control over much
of the mineral rights in the Western United States.   In the
States west of the Mississippi River, the Government owns
about 70 percent of the coal and can influence the develop-
ment of another 20 percent bordering on Federal lands. In
addition to its western holdings, the Government owns about
4.6 million acres of coal land in Alabama, Arkansas,
Kentucky, Mississippi, and Virginia.
     Western coal has assumed an important role in this
Nation's coal development because (1) it is Generally
easier and more economical to produce because it is surface-
mineable and it occurs in very thick seams, (2) western
lands are usually easier to obtain in large tracts than
eastern lands and, therefore, can be more efficiently mined,
and (3) western lands are rich ir deposits of low-sulfur
coal. 68/

     Under :he Mineral Lands Leasing Act (30 U.S.C. 181), and
 .ieMineral Leasing Act for Acquired Lands (30 U.S.C. 351),
the Federal lands containing coal deposits may be leased
for mining coal. The Government has currently issued leases
for coal deposits thought to contain an estimated 17.3
billion tons of reserves. There are an additional 10.3
billion tons under Preference Rights Leasing Applications.
69/ However, the cumulative coal production on Federal
lands was only about 380 million tons through 1976. 70/

      The Department of the Interior's (DOI) estimate of 17
billion tons of reserves under lease is at best a rough and
conservative appoximation of the actual resources under
lease. The reliability of the estimate is questionable
because most of the information used in arriving at it is
based on 1973 conditions, a time at which coal market
 (FOB mine) prices were considerably lower than those ob-
served today. 71/ The higher prices, particularly if they
are anticipated-to remain at or above current levels in
relation to production and transportation costs, have the
potential impact of increasing the amount of recoverable
reserves on coal lands currently under Federal lease. At
higher prices, identified resources which were not consi-
dered to be economically recoverable may now be recovered
profitably.   If higher prices expand reserve estimates, this
might obviate the need for new Federal leasing, at least
on a temporary basis, as demands for low-sulfur western
coal increase. With accurate information on coal
reserves, Federal decisionmakers could choose either to

lease more Federal land or to maintain the current number of
leases and promote higher future production levels. Addi-
tional information is also needed as to the role o! non-
Federal coal in western coal development before responsible
Federal leasing policies can be formulated.

     Coal reserves under Fedetal lease and associated issues
surrounding Federal coal leasing policy are currently being
reviewed in an ongoing study by our Office. Our study will
analyze 250 of the 536 current leases, representing about
65 percent of DOI's estimate of reserves under lease, as of
December 1975. Preliminary findings show that of the 250
leases, 130 are in Fome stage of development, indicated by
either an approved mining plan, a mining plan under DOI
review, or a mining plan in preparation. These preliminary
findings, particularly if they remain consistent for the
balance of the leases to be audited, indicate an expanding
role of Federal coal in the Nation's total energy picture.

     In summary, at this time, the extent of the need for
new Federal coal leasing is unclear, due to the little
information on the current reserve situation and the many
policy options affecting Federal coal leasing.
      In addition to coal deposits on Federal lands adminis-
tered by the Bureau of Land Management, there are sizable
quantitites of coal resources on Indian reservations. The
Bureau of Indian Affairs is responsible for all phases of
management of minerals on -Indian lands through the leasing
process. Although an accurate estimate of coal resources
on Indian lands does not exist, the USGS has estimated that
33 reservations in 11 States, spread over a total of 34.5
million acres, contain from 100 to 200 billion tons of
identified coal resources. 72/ These resources on Indian
lands represent about 7 to T5 percent of the Nation's
identified coal resources. Available estimates of the coal
.eserves on Indian lands are limited to leased Indian lands
only and have been estimated to be about 5.4 billion tons.
About 3.5 billion tons are considered recoverable, as of
March 1975. 73/
     Currently, five coal mines are operating on Indian
lands. Two are located in Arizona on joint-use land of the
Navajo and Hopi Tribes; two are in New Mexico on Navajo
land, and one mine is operating on land leased by the Crow
Tribe in southeastern Montana.
     In terms of western coal development, Indian coal lands
are available in large tracts not subject to checkerboard
surface-ownership patterns which characterize vast amounts
of federally-owned coal lands in the Northern Great Plains.

This checkerboard ownership pattern has been said to delay
the consolidation of logical mining units on Federal coal
lands because public hearings can be requested under Public
Law 94-377 before the Secretary of the Interior can approve
consolidation. For these reasons, Indian coal lands now
under lease or potentially leaseable may become more attractive
to western coal developers.


     As of January 1974, there were 3.9 trillion tons of coal
resources in the United States. Of this, 1.7 trillion were
classified as identified resources.

     Coal resources which can be mined given current tech-
nological, economic, and legal constraints are termed
reserves. U.S. coal reserves are about 256
billion tons and represent 90 percent of the Nation's fossil
fuel reserves.

     Under the high coal demand forecast in this report--an
annual coal growth rate of 3.69 percent--today's known coal
reserves will satisfy demand for about 74 years.

     Coal in the Eastern and Central regions has a higher
heat content than most found in the West. But overall,
western coal is appreciably lower in sulfur content.

     Available data do not permit a useful delineation of
reserves on the basis of economic costs at alternative depths
of deposit nor on other conditions which affect productivity
(costs) at specific locations. Available data give some
indication of economical stripping ratios (ratio of overburden
to coal) but only at the State level.  In addition, the reserve
estimates of the USGS and BOM are questionable because they
rely so heavily upon secondary sources. Coal reserve
estimates obtained from coal companies and other proprietary
sources are possibly understated due to incentives Lo avoid
property taxes. The exact magnitude of the underestimation
is not known.

     The usefulness and reliability of coal data could be
advanced by federally-sponsored stratigraphic drilling and
mapping, and by verification of coal company reserve estimates.
Given probable legal constraints, if a systematic nationwide
drilling program were to be undertaken, it is likely that
new Pederal legislation would be required to allow such
activity on private lands, particularly in the East and

      A substantial revision in estimates of the quality and
 quantity of eastern coal fields (current estimates date back
 to the earlier part of this century) would have at, impact
 on the level and need for investments in western coal mines
 and transportation facilities. The timing of Federal coal
 leasing would also be affected.

     A specific problem of coal resource and reserve estimate
reliability is whether there are sufficient supplies of
low-sulfur coal to satisfy the demand through the year 2000.
Generally, electric utilities are inclined to choose low-
sulfur coal to reduce or eliminate the problem of removing
emissions following combusion using current control tech-

     BOM estimates that about 31 percent of the Nation's
coal reserves can be used for direct combustion and meet
Clean Air Act standards. About 89 percent of this coal is
in the West. Wyoming and Montana account for 80 percent of
the Nation's low-sulfur coal.

     BOM reports that as yet there are no accurate estimates
of the Nation's metallurgical coal reserves;  this coal is:
used to produce coke, an essential ingredient in the
manufacturing of iron and steel. The lack of accurate and
reliable data regarding metallurgical coal, especially
premium-grade metallurgical coal, has fostered a controversy
concerning exactly how much premium-grade metallurgical coal
is produced and exported and whether these exports will
unfavorably affect the Nation's future domestic steel pro-
duction capabili ies.

     Recent surface mining legislation partially restricts
surface mining in alluvial valley floors or on steep slopes.
Recent studies indicate that the coal reserves affected
by the alluvial valley prohibition would be small. No
accurate estimates exist, however, concerning reserves
under steep slopes.

     The legislation also provides for the protection of
surface owner rights on Federal coal lands. One study
indicates that as much as 14 billion tons of coal could be
prohibited from surface mining under this provision in the
7-State area of Colorado, Montana, New Mexico, North Dakota,
Oklahoma, Utah, and Wyominq. This estimate, it should be
noted, is highly uncertain, indicating the need for more
reliable and accurate data on Federal coal lands.

                       FOOTNOTE REFERENCES

   1/Paul Averitt, Coal Resources of the
     January 1, 197T7T,SGS Bulleti-ln    United States,
                                      l (Wash-ington: Government
     Printing Office, 1975), p. 1.

  j/The 256 billion tons of reserves was
                                          derived by using BOM's
    estimate of the demonstrated reserve
    excluding anthracite deposits) and thebase (429 billion tons,
                                            application of 80
    percent and 50 percent recovery rates
    underground mineable portions of the   for the surface and
                                          demonstrated reserve
    base, respectively.
  4/N. A. Parker and B. C. Thompson, U.S.
                                           Coal Resources and
    Reserves, Federal Energy Administration
                                             Bulletin FEA/B-76/
    210 l(Washington: National Energy Information
    1976), p. 2.                                   Center, May

  5/United States Bureau of Mines and United
    Survey, Coal Resources Classification     States Geological
                                          System of the U.S.
    Bureau of Mines andU.S. Geological Survey,
    140- TWashington: Govrnment Printing         USS Builetin
                                             Ofice, 1976),
    p. B-4.
 6/Ibid., p. B-6.
 7/Zane E. Murphy, et al., Demonstrated
                                         Coal Reserve Base of
   the United States,,a sulfur Category, on Janar 1, 1974
   (Washington: Bureau of Mnes s,  ay 9757. The 429 biTl-on
   ton estimate excludes anthracite coal
  8/United States Department of the Interior,
    Strippable Reserves of Bituminous Coal       Bureau of Mines,
    United States, In~orm'atiorn Circu-laF-  and  Lignite in the
    Government Printing Office, 1971), p.   31T-Washington:
 9/Robert D. Thompson and Harold F. York,
                                             The Reserve Base
    of U;S. Coals by Sulfur Content, Inform-ion
    (Washington: Government Frinting Office,        -TFEular 6 80
                                                 1975), p. 8.
10/United States Department of the Interior,
    Management, Final Environmental Impact      Bureau of Land
    Proposed FederalCoal Leasin Pga,
    Bureau of Land ManagemFent, 1975 , pp.   (Washington:
                                            I-33 to 1-38.
ll/Ibid., p. 1-34.

12/G. Alex Mills, "Gas From Coal: Fuel of the Future,"
   Environmental Science and Technolo y (December 1971),
   p. 1T82; H. C. Hottel ani J. B. Howard, New Energy
   Technoloy: Some Facts and Assessments (Cambridge: MIT
    ress, 1971), c-aptTer 3- Fossil-Fuel-to-Fuel Conversion,"
   pp. 103-138; United States Department of the Interior,
   National Petroleum Council, U.S. Energy Outlook: Coal
   Availability (Washington: National Petroleum CouncTl,
   i9737,p. 65; United States General Accounting Office,
   Status and Obstacles to Commercialization of Coal
    igueaTon and-G-siiTcation, RED-76-81, May 3, 1976,
   pp. 43-45.

13/Spurgeon M. Keeny, Jr., et al., Nuclear Power Issues and
   Choices (Cambridge: Ballinger Publishing Company,i197m,
   p. 7r.
14/Sam H. Schurr, et al., Energy in the American Economy,
   1850-1975 (Baltimore: Johns Hopklns University Press,
   1960), p. 324; Richard L. Gordon, U.S. Coal and the
   Electric Power Industry (Baltimore: Johns Hiopins Univer-
   sity Press, 1975), pp. 88-89, 101-108; United States
   General Accounting Office, Domestic EneL   Resource
   and Reserve Estimates--Uses, Limitations, and Needed Data,
   EMD-77-6 (Washington:   .S. Genera Accounti    Office,
   March 17, 1977), p. 28.
15/united States General Accounting Office, Ibid., p. 15.

16/Richard A. Schmidt, "Location of Low Sulfur Coals and
   Western Power Generation Needs," presented at EPA/EPRI
   Symposium on Particulate Control in Energy Processes,
   San Francisco, C-aifornia, May 13,     76, p

18/Averitt, op. cit., pp. 29-30.

20/Martin B. Zimmerman, The Supply of Coal in the Long Run:
   The Case of Eastern Deep Coal, Energy Laboratory Report
   NO. MIT-EL 75-021  Cambridge:  Massachusetts Inbtitute
   of Technology Energy Laboratoy, September 1975), pp. 16-17.

21/Ivan A. Given, editor, SME Mining Engineering Handbook,
   Volume I 'New York:  Society of Mi'niTg Engineers of the
   American Institute of Mining, Metallurgical and Petroleum
   Engineers, Inc., 1973), p. 12-33.
22/Schurr, et al., op. cit.

 24/Bureau of Mines, Information Circular 8531,
                                                op. cit., p. 12.
 25/Averitt, op. cit., p. 3.

 26/Donald A. Brobst and Walden P. Pratt, United
                                                 States Mineral
    Resources, United States Geological Survey Professional
    Paper l'- (Washington: Government Printing Office,
    p. 6; Stephen M. Long, "foal Taxation in the         1973),
    The Need for a Regional Tax Policy," Natural Western  States:
    Journal, Volume 16 (April 1976), p. 425.     Resources

 27/United States Bureau of Mines and United States
    Survey, op. cit.

 28/Averitt, o2.   cit., p. 47.
2 9/Previous
             studies include those specific ones cited in
    footnotes 1, 13, 14, 15, 16, 20, and 21.
30/United States General Accounting Office, Domestic
   Resource and Reserve Estimates--Uses, Limitations, Energy
   Needed Data, op. cTt., p. T                           and
                                  S. P. SchweinfTurth
   H. .' Arndt, and K. J. Englund, Description of
                                                    Core From
   Three U.S. Geological Survey Core Holes in Cairboniferous
   Rocks in West Vrginia (Reston: U.S. GeoTogical
   1976);Weston Observatory - Boston College, The Survey
   Pennsylvanian Coal-Bearinq Strata of the Narragansett
   Basin, Interim report to National Science Foundation,
   Grant No. AER 76-02147, NSF/RANN Document NSF/RA
   (Weston, Massachusetts: Weston Observatory         76-0337
                                                 - Boston
   College, 1976).
31/U.S. Department of the Interior, Bureau of
                                              Land Management,
   Coal: An Analysis of Existing Federal Coal Leases
   (Washington: Bureau of Land Management, March
                                                  176), p. 1.
32/Northern Great Plains Resources Program, Effects
                                                     of Coal
   Development in the Northern Great Plains (Washington:
   Government Pr-nting Offi    Apr     7), p., 8.
33/Data on drilling cost and USGS drilling program
   and 1977 obtained from Conservation Division,    for 1976
   Geological Survey, February 1977.
34/Data on drilling cost for Eastern and Central
   obtained from discussions with State geologistsregions
   Kentucky, and Pennsylvania, February 1977.       in Illinois,

35/J. A. Cavallaro, et. al., Sulfur Reduction Potential of
   the Coals of the United States, Report of Investigations
   8T8 (Wash-ington:  Govern ent Printing Office, 1976), p. 2.
36/Based on information provided by Bureau of Mines, February
37/Data in Table 2 are unpublished     '-ta obtained from Bureau
   of Mines.
38/Richard L. Gordon, "Coal: Our Li    Ad Vest Fuel Resource,"
   in The Energy Question: An International Failure of Policy,
   Volume 2, edtediby Edwar3"W.Erickson and Leonard Waverman
   (Buffalo: University of Toronto Press, 1974), p. 50.

39/Eugene T. Sheridar Supply and Demand for United States
   Cokin 9 Coals and Met    iic-l Coke Wa-sEington: Bureau
              1i7g, p. 2.         Coikes,
40/Ibid., p. 3.

41/Ibid., p. ;.
42/Ibid., pp. 3, 10.

43/Ibid., p. 2.

44/Ibid., p. 2.

43/Ibid., pp. 2-3.

46/Ibid., p. 6.

47/Paul H. Mutschler, Impact of Changing Technology on the
   Demand for Metallurgica Cl    and Coke Produced in tFi-
   United Sates to     95, InTomatlon     ircular   8677
   (Washington:   Bureau of Mines, 1975), p. 7.
48/Sheridan, op. cit., p. 13.

49/Ibid., p. 5.
50/United States General Accounting Office, letter report
   to the Administrator, Federal Energy Administration,
   B-178205, April 14, 1976.
51/Information supplied by the Bureau of Mines.
52/Coal Outlook, September 2, 1976, p. 4.

53/The Surface Mining Control and Reclamation Act of 1977 was
   signed into law on August 3, 1977.

54/P.L. 95-87, subsection 510(b)(5).
55/United States Congress, House of Representatives, Committee
   on Interior and Insular Affairs, Surface Mining Control and
   Reclamation Act of 1976, Report to Committee, 94th Congress,
   2nd Session, together with Additional, Dissenting, and
   Separate Views to accompany H. R. 9725 (Washington:
   Government Printing Office, 1976), p. 65.

56/Ibid., p. 66.
57/ICF Incorporated, Energy and Economic Impacts of H.R.
   13950 ("Surface Mining Control and Reclamation Act of 1976,"
   9E'h-Congress), Draft Final Report submitted to the Council
   on Environmental Quality and Environmental Protection
   Agency, contract No. EQ6AC016 (Washington: U.S. Environ-
   mental Protection Agency, February 1, 1977), p. 12.
58/P. L. 95-87, Subsection 515(d)(4).

59/Nicnolas P. Chironis, "Cross-ridge Mining of Mountaintops:
   A Better Technique for Appalachia?", Coal Age (December
   1976), pp. 74-78; Skelly and Loy Enaineers - Consultants,
   Economic Engineerin Analysis of U.S. Surface Coal Mires
   and Effective Reclamation (Washington: Bureau of Minez;
   -- 75, pp. -7-3 to 3.48.
60/P. L. 95-87, Subsection 515(c)(3).
61/Ibid., Section 714.
rc/ICF, Incorporated, 2p. cit., p. 15.

63/P. L. 95-87, Section 515, "Environmental Protection
   Performance Standards."
64/Ibid., Subsection 402(a).
65/ICF,   Incorporated, ao. cit., pp. 4-5.
66/Ibid., p. II-29.
67/Ibid., p. II-41.  ICF reports these cost in 1978 dollars,
   but we converted the costs to 1976 pcliars using conversion
   table on page II-4 of the ICF study. Due to the Federal
   requirements, the study estimated the highest incremental
   operating costs to occur in Virginia and Alabama because
   of steeper slopes. These E'ates are followed by eastern

68/United States General Accounting Office, Role of Federal
   Coal Resources in Meeting National Enerv Goals Needs to
   be-etermined-'ai dhe         L'easing
                                    Process Irmroves
                                                   , RED-76:79
   (Washingt-on:   U.S. General Accounting Office, April 1,
   1976), p. 2.
69/United States Department of the Interior, Bureau of Land
   Management, Final Environmental Impact Statement on Proposed
   Federal Coal Leasing Program,          e.    cit., p. I-81.

70/Parker and Thompson       it.,         p. 10; coal production
   aata on Federal landsq or "75          and 1976 obtained from
71/United States General Accounting Office, Role of Federal
   Coal Resources in Meeting National Energ-eeds-to be
   Determined and   Te-eL-easd      ogp. m,                      cit .,
   p.   12.
72/United States General Accounting Office, Indian Natural
   Resources -Part II: Coal, Oil, and Gas Better Management
  Can ImproveDevepmen        and               aseedan    Income and

  Employment, RED-76-84 (Washington: U.S. General
  Accounting Office, March 31, 1976), p. 2.

73/Parker and Thompson, op. cit., pp. 7 and 9.

                              CHAPTER 4
                          HOW DO WE GET IT?
     Our reference scenarios of future energy needs forecast
that annual coal production will be from 779 to 988 million
tons by 1985 and from 942 to 1,586 million tons by the year
2000. The importance of these projections is apparent when
examining recent production data. During 1975 bituminous and
lignite coal production in '!-eUnited States amounted to 648
million tons. 1/ The coal industry employed an average of
189,880 miners of which 134,710 worked in underground mines
and 55,170 in surface--strip and auger--mines. 2/ As esti-
mated by the Bureau of Mines, 665 million tons of coal were
produced in 1976, and average employment increased to 208,000
miners. 3/

     The expected growth in the coal industry within the
25-year period of 1975 to 2000 is important. Achieving the
forecasted production goals will require the following:

        -- Opening 438 to 825 new mines.

        -- Recruiting and training 288,300 to 531,600
           new miners.
        --Manufacturi.g considerable quantities of mining
          equipment for underground and surface mines.
        -- Securing $26.7 to $45.5 billion in capital.

        -- Continuing research and development efforts by BOM,
           the Mining Enforcement and Safety Administration
           (MESA), and the coal industry to improve mining safety
           and health conditions and increase productivity levels.

     To determine the potential problems in achieving these
goals, our review of coal production addressed the following

        -- Coal industry plans for opening and operating new
           mines needed to satisfy future coal production.
        -- The number of qualified personnel needed to produce
           the coal.
        -- The equipment needed to achieve coal production goals.

Note:    Numbered footnotes to ch. 4 are on pp. 4.60 to 4.71.
    -- The capital required to meet expected development

    -- The possible horizontal divestiture by oil companies
       of coal interests and their related impact on capital
       availability to coal mining.

    -- The impact of the Federal coal mine loan guarantee
       program on capital availability.

    -- Legislative and tax impacts on current and planned
       coal mine operation and expansion.
    -- Research and development efforts being made
       currently and contemplated for the future
       to improve mine health and safety conditions and
       to increase productivity.
     The nature of the coal industry and the outlook for coal
production and potential problems are discussed in the
following sections.


    There are three types of coal mine operations: 4/
    -- Mine operations (captive mines) belonging to utility,
       metal, and mineral companies, which are generally
       large in size.
    -- Major diversified corporation holding companies,
       multiproduct, and multinational corporations,
       (including oil companies) for which coal mining is
       one of several interests.

    -- Independent companies with coal as their primary
Business structure

     A study by BOM, "The State of the U.S. Coal Industry,"
issued in 1976, points out that there have been great changes
in the structure and behavior of the industry. The report
st.ted that the producers started out as cmall companies.
Until recently, because of the vigorous competition from
natural gas and oil, the coal industry has not experienced
any sustained growth, although there was a brief expansionary
period during and shortly after World War II.   Th _ promise of
nuclear energy in the early 1960s further limit~e the market
outlook for coal. The report concluded,

      "Accordingly the industry which was extremely
      fragmented with about 5,000 companies (few large
      and many small) made little capital investment
      in new mines, expansion and improvement of
      existing mines, or purchase of machinery."
      In the 1960s other resource-based companies, especially
major oil companies, moved to purchase coal-producing com-
panies and acquired coal reserves through outright purchase
and lease. In testimony on April 5, 1977, before the Senate
Committee on Energy and Natural Resources, the President
the National Coal Association stated that coal companies
trolled by oil interests now own roughly 18 percent of U.S.
coal reserves. Most of the large companies (annual production
of more than 3 million tons) became subsidiaries or affiliates
of major oil companies, utilities, steel companies, or other
mineral resource producers. Nearly all of the top 15 coal
producers are in this category.

     Major steel, public utility, chemical, and metal com-
panies have accelerated their move toward coal self-suffi-
ciency and, like the oil companies, are aggressively acquiring
small coal companies and coal reserves. Although several
coal companies were formed and existing companies added    small
ventures as their principal line of business, the trend has
been toward fewer but larger companies. 5/

     The BOM report points out that today's coal mines
costly mining equipment, Additicnail excpensive machineryuse
also be installed to meet regulatory standards for health,must
safety, and environment. Opening ne" ..ines and expanding
existing ones requires enormous amour   of capital and takes
a long time. 6/

     The report further states

     "The number of small companies will no doubt
     continue to decline owing to increased cost of
     operations and difficulties in attracting new
     capital for mine improvement and expansion,
     purchase of mining equipment, and opening of
     new mines. The long leadtime for completion,
     coupled with the full impact of expenses of the
     1969 Coal Mine Health and Safety Act, compounds
     this difficulty. Morecover, many of the natural
     resource-based companies have accelerated their
     acquisition program of coal reserves and small
     producers." 7/
     BOM estimates that there are about 3,900 companies,
including subsidiaries, producing coal. Of these, 597

companies account for 94.5 percent of the national coal
production. The remaining 3,393 companies each produce less
than 100,000 tons of coal per year, or about 8,000 tons per
month, and represent approximately 5.5 percent of the national
total. Those companies producing less than 100,000 tons of
coal per year account for a smaller portion of total
production--declining from 17.8 percent in 1949 to 5.5 percent
in 1974. A summary of coal producers, by size, is shown in
the following table. 8/

                                   Table 1

                      Number of Coal Companies in 1974

                             bySize and Production

                               Number of                      Percent of
       Size class              companies     Production    total production
                                               of tons)

3,000,000 tons and over             31         347,437           57.8

1,000,000 - 2,999,999 tons          42           78,489          13.0

500,000 - 999,999 tons              59           40,740           6.8

100,000 - 499,999 tons             465          101,759          16.9

Less than 100,000 tons         a/3,303           32,575           5.5

    Total                        3 900       b/ 601,000         100.0


     In describing the coal market, the BOi4 report estimates
that about 85 percent of all coal mined is sold domestically
or exported under long-term contracts (5 to 30 years), or
produced by captive mines; this leaves approximately 15 per-
cent on the open market, known as the "spot" market. Both
the long-term contract and spot markets are competitive in
terms of price, service, and quality of prod"ct. In
addition, they are subject to competition from other energy
sources. 9/

     Initially, coal was obtained primarily by stripping and
limited tunneling into the side of a hill (drift mines).   In
the drift mines, coal was urdercut by hand and wedged down

 until explosives came into general use. In
 undercutting machines driven by steam and, later,1870s coal
 air were used to increase productivity. 10,        compressed

     The era of underground coal mechanization
productivity began in the late 1930s. All majorand increased
powered and productivity rose in the 1940s from tools became
                                                4 to 6 tons
per worker-day. In the 1950s production increased
per worker-day. The late 1950s marked the beginningto 11 tons
a new machine called the continuous miner, and       of
                                               in the 1960s,
after its use increased, productivity also increased
16 tons per worker-day. 71/                          to about

     In the 1960s the introduction of longwall and
mining equipment and techniques for controlled
sulted in the increased recovery of available   subsidence re-
The continuous miner room and pillar technique coal resources.
                                                recovers only
50 percent of the available coal, while zhortwall/longwall
mining techniques can recover from 80 to nearly
of the available coal resources. 12/             100 percent

      Surface mine operations raised productivity through
the development and greater use of drillers,
                                              bulldozers, hau-
lers, scrapers, front-end loaders, shovels,
vators, and draglines. Further productivity  bucket  wheel exca-
                                             gains ocurred
through increases in the size of coal equipment.
of all these developments was a sharp increase    The result
worker-day and an increased dependence on equipment.output per
was also a steady rise in surface mining which          There
more productive. 13/                            is  inherently

     The following table highlights the changes in
productivity that have occurred during             mining
                                       the past 36 years. 14/

                                       Table 2
                           Productivity and Mining Trends
       UOnderground                                             Production
                          -  Strface           Underround   _      S--urface
                         tip    AurTotal                                       Total
      Yeas            (tons per woir-day)        ------ (milion tons) -----------
      1940        3.86       15.63               418
      1945                                                            43         461
                  5.04       15.46               468                110
      1950        5.75       15.66                                               57J
                                                 393                123          516
      1955        8.28       21.12     22,22     344
      1960                                                          121         465
                10.64        22.93     31.36     285                131
      0965      14.00        31.98                                              4J6
                                       45.85     333                179         512
      1970      ;3.76        35.96     34.26     339
      1973                                                          264         603
                11.66        36.30    4!.33      299                292
      1975        9.54                                                          591
                               a/26.69           292                3$6
      1976       8.50           1/2s.00                                         64¢
                                                 296                369         665
         (note b)
     a/Strip aid auger combined (see glossary for description
       mining).                                               of auqer
     b/All 1976 figur. are estimates.

      Productivity has declined since 1969 especially in
 underground mines.  This decline is attributiable to many fac-
 tors. BOM indicated the following among the principal .auses.
        -- Requirements of the 1969 Federal Coal Mine Health and
           Safety Act which increased the number of ptrsonnel
           in the mines.

        -- Changes in mining        conditions such as the quality of
           mine roofs, types        and widths of coal seamns, distances
           from entrances of        mines to the operating face, and
           overburden ratios        and characteristics.

        -- Introduction of great number of                inexperienced miners.

        -- Increased exploration activity by all companies,
           especially surface mines.

        -- Requirements for additional personnel in accordance
           with provisions of union agreements.

        -- Unscheduled interruptions in production caused by wild-
           cat strikes and absenteeism.

Effects of productivity on pricing

     Increases in productivity, in part, allowed p;ices to
remain stable in spite of inflationary trends in the 1950s
and 1960s, but after 1970, prices rose steadily with a sharp
increase in 1974.  The following table shows the trend in
mine-mouth prices and labor costs over the past 21 years.
                                        Table 3

                         Coal Prices and Earnings (note a)

                                                                 Miners' earnings
  Average price per ton (FOB mine)          Hourly earning       per ton of coal
Year    UndergLound Strip    Auger          of Coal miners    Underground Strip   Auger
1955         $10.14     $7.51   $7.51             $5.15          $4.99    $1.94   $1.86
1960           9.53      6.93    6.25              5.82           4.37     2.04     1.48
1965.          8.44      6.11    5.75              5.98           3.41     1.48     1.04
1970          10.31      6.53    8.47              6.38           3.70     1.42     1.32
1971          11.75      6.88    8.71              6.43           4.28     1.44     1.32
1972          12.34      6.97    8.32              6.81           4.57     1.52     1.27
1973          13.04      '.35    8.89              6.90           4.73     1.52     1.22
1974          21.71        b/13.39                 6.80           6.62        1.65
1975          26.28        U/13.44                 7.23           6.06        2.17
1976          27.10   _     /14.00                  N/A            N/A          N/A
  (note c)

a/All data other than 1976 are in 1975 constant dollars.
]/Strip and auger combined
c/All 1976 figures are estimates.

       Miners' earnings per ton of output
 overall average output per worker-day     are based on the
 the years concerned, using the average  for  each category in
 should also be noted that the above      wage  rate shown, It
                                      prices represent average
 prices for the country. In 1975 the
 face-mined coal in North Dakota was average price for sur-
 $5.06, in West Virginia $24.04, and $3.17 per ton, in Montana
 average price for underground coal   in Arkansas $32.76. The
                                     by State ranged from a
 low of $10.62 in Iowa to a high of $33.77
 We assume that the differences in price     in Alabama. 17/
 production costs and the quality and      are  based mainly on
                                       grade of coal.
        Comprehensive and up-to-date
  tion are not available from any of cost figures on coal produc-
 during our review. The March 1976 the sources we contacted
                                        study of coal prices per-
  formed by the Council on Wage and Price
                                              Stability pointed
  this out and noted that costs vary
 They also pointed out that the averages,:bstantially      among mines.
 rose much more rapidly than labor costs     value    per  ton of coal
 They concluded, "Unless all other costs       in  1974   and  1975.
 quickly than labor costs (which appears      have    grown   more
 price has also outpaced total costs."        doubtful), the average
 companies showed that from 1970 through study of selected
 and in 1973 the average net income           1973 profits declined
                                       was only 20 cents per ton.
 In 1974, prices rose and net profits
                                          rose to
 18 percent of the average  value per ton. 18/ $2.80 per ton or
       In 1976 BOM prepared estimates of production
                                                            costs for
 use in projecting capital requirements;
based on the 1974 Bituminous Wage Agreement projections are
 indices. We did not verify the accuracy            and 1975 prices
but believe that they provide a reasonable the estimates
paring production costs between various           basis for com-
                                             mine sizes and
between surface and underground mines.
not be compared with the average price These figures can-
                                            per ton since the
average price represents all mine sizes
or degrees of mechanization. The             regardless of location
costs are shown in table 4. 19/      BOM  estimates     of production

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     A principal factor for the variation in productivity
and cosu between mines is the thickness of the coal seam.
BOM estimates that the selling price for surface-mined coal
varies considerably, based on the thickness of the seam. 20/

     -- Coal mined in the Eastern province* could sell at
        $6.94 per ton from a 6-foot seam and $11.63 per ton
        from a 3-foot seam.
     -- In the Interior province**, the coal from a 6-foot
        seam could sell at $6.03 per ton and from a 3-foot
        seam at $10.07 per ton.
     -- In the Northern Great Plains province***, the coal
        could sell at $2.39 per ton from a 50-foot seam and
        $6.58 per ton from a 10-foot seam.

     All these prices assume a 15 percent rate of return after
taxes and are exclusive of transportation cost, which is an
important factor. In 1974 railroad freight charges averaged
$4.71 per ton, 21/ rising in 1975 to $5.25 per ton.  22/ Rail
transportation costs can vary from $,47 per ton to a Hi'gh of
$10.00 per ton. Many factors account for these extremes such
as distance, type of train (unit train or mixed freight), and
ownership of cars (utility or railroad).  23/
Additional production capacity

      In 1975 over 648 million tons of coal were produced, and
BOM estimates that existing operations could have produced
a peak of 692 millions or 44 million tons more than were
actually extracted. 24/ It is also estimated that between 10
and 60 million tons oradditional coal could have been mined
by small operetors, those producing less than 200,000 tons
each per year. These mines are generally profitable only
during periods of high coal prices.   It is usually during
periods of peak coal demand that such mines operate. 25/

  *Includes coal fields in Maryland, North Carolina, Chio,
   Pennsylvania, Georgia, Virginia, eastern Kentucky, and
   parts of Alabama and Tennessee.
 **Includes coal fields in Illinois, Indiana, Iowa, Kansas,
   Missouri, Michigan, Oklahoma, Nebraska, western Kentucky,
   and parts cf Arkansas and Texas.
***Includes coal fields in North Dakota, South Dakota, and
   parts of Montana and Wyoming.

Opening of niew mines
     GLeat amounts of time and effort are required to perform
the various tasks from conception until actual commencement
of production. Because of the time required to open a new
mine, supply of coal is flexible in the long run and con-
strained in the short run. The short run capacity of the in-
dustry is limited to what could be extracted through increased
production (surge capacity) at existing mines. In other
words, coal is usually demand-constrained in the long run and
supply-constrained in the short run.
     BOM has categorized the various tasks for opening new
mines into the following steps. 26/
     -- Initial examination--including all those steps neces-
        sary to determine whether the coal should be mined.

     -- Mine assembly--including those steps necessary to
        determine how and in what manner the coal should be
        mined, the acquisition of the rights to mine the coal,
        and determination of the annual production.

     -- Cost analysis--determining the cost elements and
        performing an economic analysis on the profitability
        of mining the coal.
     -- Market development--including those steps necessary
        to secure a customer and negotiate the terms of the

     -- Environmental and related studies--performing all
        the steps required to determine and report the
        environmental and socioeconomic effects of mining
        the coal.

     -- Preliminary design and equipment ordering--designing
        the mine, showing how the coal will be extracted,
        determining what equipment will be needed, and
        ordering the equipment.

     -- National Environmental Policy Act (NEPA) process--the
        steps taken by the Government when assessing the en-
        vironmental impact of the mining of Federel lands.
     -- Permits--securing necessary State permission for use
        of water at the mine, for mining and reclamation
        operations, and for other regulatory requirements.

      -- Design and construction--preparing the final design
         of the mine, and constructing the mine and related
         facilities including access roads, rail line, and
         power supply.

      -- Mining preparation--the final stage before opening
         the mine, involving installation of mining, loading,
         and support equipment and personnel recruitment and

     The following table shows BOM's estimates of the time
required for each of the above steps, relating to surface and
underground mines in the East and the West.  The extent of
effort and the time required to complete each step are in-
fluenced by the location of the mine, size of the intended
operation, ownership type and pattern, and environmental con-
siderations. Since some steps can be performed simultaneously
with others, the total length of time may be less than in-
dicated here.

                                         Table 5
                  Time Requirements for New Mine Openings

                                            Surface                                 Underground
                                  East                   West                 East             West
                           Min.        Max.           Min. Max.         P        M
                                                                                 Max.       Min. Max.

                            ---------------------             (years)------------

Initial examination        .10        .20            .15    .50        .10          .20    .10    1.50
Mine assembly              .15        .30            .25   1.50        .15          .30    .20    2.00
Cost analysis              .00        .10            .10    .50        .00          .25    .10     .50
Market development         .00        .15            .10    .50        .00          .15    .10     .50
Enviionmental and
  related studies*         .00        .10            .50   1.50        .00          .10    .25    1.50
Preliminary design and
  equipment selection      .50        .75            .50   1.50        .75      1.00       .50    1.00
NEPA process*              .00        .00           1.50   4.00        .00       .00      1.00    3.00
Permits*                   .25        .50            .50   2.00        .25       .50       .25    1.50
Design and construction    .50        .75            .30   2.00        .75      1.25       .30    2.00
Mining preparation         .00        .15            .10    .50        .50      1.25       .20    1.00

     Total                1.50a/3.00                4.00 15.00      2.50        5.00      3.00 13.50

a/A few of the large mines in the East could exceed this figure.

     The timespans for the West relate primarily to environ-
mental and other governmental considerations, which can
account for a considerable portion of the time required, as
shown in table 6.

                            Table 6

              Time Needed for Environmental and
                Governmental Actions-(note a)

                     Minimum                 Maximum
                          Percentage              Percentage
                  Years    of total       Years    of total
Underground        1.5         50         6.0            44
Surface            2.5         63         7.5            50
a/Steps designated with (*) in table 5.
Accordiagly, environmental considerations and governmental
actions could be a major factor in the time required for
opening of a mine.


     If the bituminous coal industry is to produce the ccdl
supply levels projected by.the two scenarios, it will
have to open new mines, recruit Pnd train miners, improve
health and safety conditions, purchase needed equipment, and
secure the needed capital to accomplish the above tasks to a
greater degree than ever experienced in the years prior to
1975. The following are the production level projections of
the scenarios for 1985 and 2000.

                              1975        1985          2000
                            --------- (million tons)--
Edison Electric Institute      648         779           942
BOM                            648         988         1,587
     The above figures compare with the 1985    goals of President
Carter's National Energy Plan of 1.2 billion    tons and 1 billion
tons with and without the plan respectively.     Our analysis of
the various requirements shown above and the    actions being
taken or scheduled for future implementation    is described in
the following sections.

Industry expansion capability
     A viable industry structure is needed if new mines are
to be opened and operated to meet the production requirements
projected by the scenarios. An indication of the industry
expansion potential is the extent to which it is actively
planning for the future and takinc some of thfe preliminary
steps necessary towards achieving those goals.

      In performing our analysis, we reviewed coal production
statistics; held discussions with coal operators and their
associations, labor union representatives, and academic ex-
perts; and reviewed several reports based on questionnaires
senc to operators, which showed planned mine openings.

        Bituminous coal production in 1900 was over 212 million
tons, all from underground mining. By 1910, it had almost
doubled to about 417 millio' tons, all from underground mines.
By 1920, it had increased to over 568 million tons, with about
8 million tons from surface mines and the balance from under-
ground mines. There have been constant fluctuations in
production since 1920, and in 1947 it reached a level of 631
million tons. From 1947 until 1961, there was a downward
trend but from 1961 to the present there has been a steady
upwa -ri trend. In addition, surface mining has increased,
unti     it now exceeds underground mining.
     Table 7 shows some of the more important 20th century
production data, that is the high and low production years
in each decade.  27/

                           Table 7

                 Important Coal Production Data

                                             Percent of total
 Key                        Persons            production
years       Production.     employed     Surface   Underground
          (million tons)

1920            568.7       639,547        1.5        98.5
1926            573.4       593,647        3.0        97.0
1932            309.7       406,380        6.3        93.7
1937            445.5       491,864        7.1        92.7
1942            582.7       461,991       11.5        88.5
1947            630.6       419,182       22.1        77.9
1954            391.7       227,397       26.2        73.8
1956            500.9       228,163       27.0        73.0
1961            403.0       150,474       32.3        67.7
1969            560.5       i14,532       38.1        61.9
1970            602.9       140,140       43.8        56.2
1974            603.4       166,701       54.0        46.0
1975            648.4       189,880       54.9        45.1
1976 (note a)   665.0       208,000       55.4        44.5
a/Estimated figures for 1976.
     We projected the future production leeis by coal-pro-
ducing regions and type of mining--surface or underground.
Table 8 shows the anticipated coal production requirements
for each of the scenarios. 28/

                             Table 8
                Future Coal Production Scenarios

                  1974             1985                 2000
                 (actual)   EEI           BO_     EEI          BOM

                  ------------ (million tons)-----------------
Eastern           377.7      337.6        428.0   407.9        687,6
  Underground     212.3     211.1         295.4   281.6        474.7
  Surface         165.4     126.5         132.6   126.3        212.9

Central           142.5     147.8         161.4   153.6        257.5
  Underground      54.8      64.8          72.6    69.2        116.1
  Surface          87.7      83.0          88.8    84.4        141.4

Western            83.2     293.8         398.6   380.5        641.3
  Underground      10.2      26.5          41.7    39.8         67.0
  Surface          73.0     267.3         356.9   340.7        574.3
Uiited States     603.4     779.2         988.0   941.9    1,586.4
  Underground     326.1     302.4         409.7   390.5        657.8
  Surface         277.3     476.8         578.3   551.4        928.6

New mines
  (1975 to
  1985)            -        152           254
New mines
  (1986 to
  2000)                                           286          571

    Opening of new mines
     A survey conducted for the Federal Energy Administration
identified planned and projected mine openings by 1985.  In-
formation was collected directly from coal producers--existing
and potential--for over 300 planned and possible coal mine
developments. The survey took into consideration 1974 pro-
duction of 603 million tons, retirement of mines producing
an estimated 137 million tons, and planned and possible new
mine openings which could produce 546 million tons annually
(the possible openings amounting to 135 million tons). The
survey concluded that over 1 billion tons could be produced
in 1985. 29/
     This potential capacity is in excess of the requirements
shown in the high scenario for 1985, and is in the same range
as the National Energy Plan.  It should be noted that the
survey projected that the small mines--200,000 tons or less--
would continue to produce at a level of 140 to 160 million
tons annually. 30/
     Our discussion with 11 major coal producers (including 9
of the top 15 producers in 1975) showed that all believed the
industry could double production by 1985 and triple production
by 2000, assuming certain conditions. Since 648 million tons
were produced in 1975, a tripling of this production level
would be well beyond the 1.586 billion tons required under
the high projection for the year 2600.
     GAO believes that there are serious obstacles which could
delay achievement of a level of 1 billion tons to beyond 1985.
These obstacles include such factors as long leadtimes to open
mines, environmental restrictions, capital problems, and labor
and productivity problems.  On the other hand, a production
level of 1.5 billion tons by the year 2000 coult be achievable.
At that point the constraining factors would be related
primarily to demand.


     The increased automation of coal mining, the agreements
reached in the National Bituminous Coal Wage Agreement of 1974,
and the requirements of the Federal Coal Mine Health and Safety
Act of 1969 have all had great effects on the mining work
force. The once labor intensive coal industry has, over the
years, shifted towards heavy reliance on equipment and a
highly skilled work force well versed in equipment operation
and repair. This applies to both underground and surface
mining. 31/

     We estimate that to continue to increase annual production
to the various tonnages projected by BOM and EEI for 1985,
between 93,100 and 157,000 new employees would have to enter
the work force, with the average number of employees in 1985
being between 185,500 and 243,500.  Similarly, to azhieve the
tonnages projected for 2000, from li5,200 to 374,600 additional
employees will have to enter the work force and the average
number of workers in 2000 will be from 232,000 to 390,600.

     Our estimates of employee requirements, shown in table
9, are based on State productivity level statistics for 1974.
These productivity figures are used to compute the employee
requirements for the production levels forecast for 1985 and
2000. 32/

                              Table 9
                  Future Personnel Requirements

                         1974             1985                    2000
                       (actual)     EEI             BOM     EEI             BOM
 Eastern                134,296   131,000        176,100   167,900       282,900
    Underground         101,773   103,900        147,700   140,800       237,300
    Surface              32,523    27,100         28,400    27,100        45,600
 Central                 25,246    30,700         33,700    32,200        53,800
    Underground         14,057     18,400         20,600    19,700        33,000
    Surface             11,189     12,300         13,100    12,500        20,800
 Western                  7,159    23,800         33,600    32,000        53,900
    Underground          3,586     11,100         16,500    15,700        26,500
    Surface              3,573     12,700         17,100    16,300        27,400
 Total U.S.            166,701    185,500 a/243,500        232,100       390,600
    Underground        119,416    133,400 a/184,900        176,200       296,800
    Surface             47,285     52,100 -  58,600         55,900        93,800
   (1976-1985)            -        93,100        157,000      -             -
   (1986-2000)                       -              -      195,200       374,600
 a/Differences due to rounding

     The projections assume that productivity   will remain
constant; that is, gains in productivity will   b.! offset by
other factors requiring additional personnel.     In addition,
the number of new miners include replacements   necessary due
to retirements, deaths, and other reasons for   leaving. 33/
     To evaluate the capability of the coal industry to meet
these goals and the potential implications, we examined the
following matters.
     -- Availibility of new miners for the coal industry,
     -- Industry ability to attract people to spar ely
        populated areas, such as in the West,
     -- Training requirements,
     --Mine productivity,

     -- Effect of labor-management disagreements,

     -- Current and future effect of mine health and
        safety regulations.
     Personnel availablity
     Because of the type of work and the health and safety
hazards, the conjecture is that there might not be sufficient
applicants to satisfy underground mining requirements. 34/
Also, there is some concern whether both new and experienced
miners will move to those areas where new mines are being

     Underground miners--In recent years, risks and hardships
of the underground miner's life have been partially offset
by pay scales higher than inl any other major industrial occupa-
tion. 35/ In December 1975, the underground bituminous coal
miner earned an average wage of $7.70 hourly, against $6.42
for metal mining, $6.89 for motor vehicles and equipment,
$3.55 for textile mills, and an average of $5.00 for all
manufacturing. 36/ We assume that this favorable relationship
will be maintaiiied and that coal price levels will continue
to permit the operator to recover labor costs.

     The underground iinet operators we interviewed did not
believe there would be a problem in securing new applicants.
These views were supported by various studies on coal's future
which conclude that, although the hazards are great, they
will be offset substantially by other factors, such as
improved safety conditions- unemployment trends, compensation

differential, and fringe benefits. Accordingly, the studies
predict that there will be sufficient applicants or the
potential openings. The United Mine Workers of .merica
(UMWA), in the 1974 agreement with the operator., negotiated
for increases in underground workers by the assignment of a
helper to crews. It has been estimated that 7,500 more
workers were classified as helpers in mid-i975 compared with
1974. 37/ These helpers should eventually be able to fill
higher skilled jobs.

     In an effort to reduce the serious sickness and accident
record associated with the mining of coal, the Congress en-
acted the Federal Coal Mine Health and Safety Act in December
1969. As a result of the actions taken in accordance with
the act, the Secretary of the Interior, reported, in his 1974
Annual Report, that improvements have been made in the working
conditions of mines. Although mining is still a hazardous
occupation, progress has been made. Since 1970 the fatality
rate has been reduced by more than 50 percent and the non-
fatal injury rate by 35 percent.

     Recent increases in mine employment further indicate
that there will be applicants. The average work force for
miners in 1974 of 16b700 (of which 119,400 were working
underground) increased in 1975 to 189,880 (of which
134,700 worked underground). 38/ This is an increase of 23,180
employees overall, including -5,300 underground employees,
a 13 percent increase over the 1974 underground work force.
Preliminary 1976 figures show an increase to 208,000 miners.
39/ In addition, during 1976 there were over 450,900
unemployed individuals in the coal mining regions who could
provide a labor base for future expansion.

     Flexibility of work force--The UMWA pointed out that
while the increased demand for coal has brought economic gains
to the miners, increased buying power has not solved a chronic
problem for coal miners--housing. In fact, expansion of
coal mining to meet the new demand is aggravating the prob-
lem. 40/ To the degree that housing and other requirements--
schooTs, hospitals, entertainment, and shopring--are a problem
in existing coalfields, they will be more severe in those
rural areas where new coal mines are being developed, such
as in the Northerr Great Plaino.

     To retain experienced miners from closed mines and at-
tract new miners from the labor market, efforts will be
needed by industry, and local, State, and Federal governments
to provide the needed infrastructure. These matters are
discussed more fully in chapter 7.

     Mining engineers--During 1973 and 1974 there were short-
ages of mining engineers, and it was necessary to hire engi-
neers from other countries. 41/ However, in 1976, BOM
reported that increased enro~lment in the Nation's mining
and mineral universities is evidence of an "encouraging
reversal" of a downward trend. Total student enrollment in
mining-related programs is currently 3,638, an increase of
668, or 22 percent, over the 1974-75 academic year.  In the
mining engineering area, the enrollment is 2,325, an increase
of 544, or 31 percent, over last year.

     Table 10 presents a comparison of student enrollment
and graduation for the 1974-75 and 1975-76 academic years. 42/

                             Table 20
             Student Enrollment and Graduation Levels

                                  Enrollment          Degrees
                               1974-75   95-76 1   94-5 19757
Mining engineering              1,781    2,325     360    459
Metallurgical and mineral
  processing engineering        1,052   1,176      258    325
Mineral economics                 137      137      43     43
     Total                     2,970    3,638      661    827
According to an FEA-commissioned study in 1975, the number
of engineers in bituminous coal and lignite mining would have
to increase from 1,600 in 1974 to 3,000 in 1985. 43/ The
numbers of enrollees and graduates appear to be w-ithin the
range of satisfying these requirements.

      Officials at three schools of mining that we visited
did not believe that there would be any shortages of engineers
in the future. In addition, the Secretary of the Interior on
November 3, 1975, in reply to the Senate Committee on Interior
and Insular Affairs, stated there is a strong interest in
mining research and education. He pointed out that the Energy
Research and Development Administration, the National Science
Foundation, and BOM all provided funding to universities
through grants and contracts to support various mineral and
energy research projects. Private industry is also supporting
mining education and training by providing endowments to col-
 .eges for purposes of scholarships and student loan funds,
as well as faculty positions. He concluded that the growing
need for mining expertise could be met through increasing

 salaries and dissemination of information on the desirability
 of mining engineering careers. 44/

      Miners--Figures in the revised UMWA pension plan, which
 went into effect in 1976, suggest that of a total of 131,375
 active member miners as of October 17, 1974, 18,172 or
 about 14 percents would be eligible for retirement. In some
 mines, it is possible that one-third of the work force would
 be eligible for retirement. 45/ In addition to the replace-
 ment of r:tired miners, the projected increase in coal pro-
 duction will require the recruitment of many new miners.

     The trend in employment has been towards replacemi.ent
of older miners with younger individuals which should result
in a work force predominantly between 18 to 35 years ot
Table 11 shows an age comparison of active mine workers age.
by the UMWA Health and Welfare Fund. The UMWA includes a
major portion of the coal industry work force, over 80 per-
cent. 46/

                                     Table 11
            Aqe Distribution of Active Miners in UMWA

                                 (As of December 31)
                   1 97__3                     1974__              1975
                             % Or         of       %                      % of-
Age group    Number          total     Number      total      Number      total
18-24        18,533           15.3     23,596       17.5      30,011       19.0
25-34        32,560           26.8     39,214       29.1      49,933       31.6
Subtotal     51,093                    62,810       46.6      79,944
35-44        23,131          19.1      24,a71       18.4      29,151      18.5
45-54        28,748          23.7      29,548       21.9      29,981      19.0
55-64        17,514          14.4      16,874       12.5      17,900      11.3
65 & over       862             .7        852           .6       974         .6
  Total     121,348       100.0       134;955      100.0     157,950   100.0
     The current shift from older to younger miners might cause
a shortage of foremen and other middle management personnel.
This problem could be temporary because the continued influx
of miners should provide the base for new managers. There is
some question as to whether there is a shortage of possible
candidates for the positions, or simply a problem in training
available candidates. 47/

     The complexity of the work in coal mines
health and safety precautionary measures to be astaken
                                                   well as the

that each employee be technically qualified to perform each
task. Because of the specialized nature of the qualifications,
actions must be taken to assure that the required personnel dre
properly trained. 48/
     The leaders of both industry and labor agree that train-
ing of the work force--both workers and supervisors--is
necessary, and provisions for training are included in the
1974 union agreement. 49/ In addition to company and on-the-
job training, the industry has cooperated with engineering
colleges in developing mining-related programs. 50/

     An August 27, 1975, FEA report, "Determination of Labor
Management Requirements in the Bituminous Coal Industry to
Meet the Goals of Project Independence," summarized training
as follows. 51/
      "Our review of training activities in the coal
      industry indicates that (1) the National
      Bituminous Coal Wage Agreement of 1974 has a
     number of provisions affecting training acti-
     vities directly and indirectly; (2) a large
     proportion of mine training is accomplished
     on-the-job by foremen or fellow workers; (3) a
     significant number of pre-employment training
     programs for coal miners are developing or are
     underway; (4) the construction industry,
     especially the Coal Construction Industry, and
     coal mining equipment manufacturer (sic) are
     providing much of the skilled maintenance man-
     power, and therefore the training, for surface
     mining; (5) training of foremen is primarily
     on-the-job and foremen are usually selected
     from the ranks of workers; and (6) public
     education facilities contribute greatly to
     coal miner training, especially in the training
     of maintenance personnel and professional

     Management/union training agreement--The National
Bituminous Coal Wage Agreement of 1974 as the following
provisions that directly affect training. 52/

     --The establishment of a joint industry training
       committee which consists of three representatives
       appointed by the union and three by the industry.
       The committee is charged with fostering and
       promcting the advancement of effective training
       in the industry.

      --The requirement of 4-day orientation programs empha-
        sizing health and safety for new inexperienced
        employees. State and Federal pre-employment pro-
        grams are recognized, to the degree that they cover
        the program required by the contract.
        the 4 days of orientation are a part of Inthemost cases,
        training program.
      -- The requirement for retraining programs emphasizing
         health and safety, which would require 8 hours for
         each employee in each calendar year.
     -- The requirement that no new inexperienced employee
        shall, for 90 days, operate any mining machines at
        the face or shall operate any transportation, mobile,
        or high voltage electrical equipment.
     The agreement also provides for a 120-day period of
on-the-job training for a helper-trainee continuous mining
machine operator or roof bolter to become fully qualified
for the position. Further, the employer has to provide
training for maintenance jobs. The time set for training
in maintenance positions in underground mines is 6 months for
a trainee to progress to the minimum level of competence
and an additional 21 months to progress to the highest rated
maintenance job.

     The agreement provides that in addition to orientation,
miners will ha,-e on-the-job trainir and training of various
kinds on a periodic basis.

      Institutional training--In most areas of coal production,
especi    y ln underground mining areas, there are courses in
coal mining or mine-related subjects available through local
educational institutions such as vocational schools, secondary
schools, community colleges, and, in a few cases, universi-
ties. 53/ A recent BOM tabulation showed the
of insEitutions offering courses in mining and following
subjects. 54/

                                              Number of
Junior colleges and technical schools             40
Vocational schools                                30
Universities                                      22
     The students in junior colleges and technical schools
receive associate degrees in engineering and training  in
mining technology. The vocational schools a're teaching

reclamation, mechanics, and other mining skills at both the
high school and post-high school level.

     These programs should provide the trained personnel
to satisfy projected coal production needs.  In relation
to training of maintenance personnel, it is believed the
most effective means for training is in cooperation with
educational facilities combined with on-the-job training.   55/

     Training of surface mining employees--There is not much
emphasis in training for surface mining operations, since
most of these employees are hired from the equipment manu-
facturing companies, equipment erection companies, or the
construction industry. Training programs are primarily of
the on-the-job variety.  However, there is some classroom
training for special skills.  For example, electricians are
given 90 hours of classroom and on-the-job training con-
cerning the equipment. 56/

     Health and safety training--MESA is required to promote
health and safety education and training.  In this connection,
MESA conducts courses for industry instructors, who in turn
instruct mining personnel. 57/ The extent of such training
will be discussed later in the section on miner health and

     Miner productivity

     In order to keep mining costs to a minimum and thereby
assure that coal will increase or at least maintain its
competitive status with other fuels, there is a need to
improve the current rate of productivity, that is, tons pro-
duced per worker-day.  In the past several years, the U.S.
coal mining industry has experienced declining productivity.

     Before 1975, the highest annual coal production was in
1947, when 630 million tons were produced with 419,182 workers
producing 6.42 tons per worker-day.  The year with lowest
production after that date was 1954 when 392 million tons
were produced and 227,39' personnel employed, producing 9.47
tons per worker-day.  Productivity reached its peak in 1969
when an average 19.90 tons per worker-day were produced for
all types of mining; 15.61 tons per worker-day was the under-
ground rate.  It has since declined each year; in 1975 the
rate was 14.74 tons per worker-day overall and 9.54 tons per
worker-day for underground operations. 58/

                                Table 12
                Mining Productivity Per Worker-Day
Year              Underground        Strip   Auger    Average
                  ------------------- (tons)---------------
1940                  4.86          15.63               5.19
1950                  5.75          15.66               6.77
1955                  8.28          21.12    22.22      9.84
1961                 11.41          23.00    30.61     13.87
1969                 15.61          35.71    39.88     19.90
1970                 13.76          35.96    34.26     18.84
1974                 11.31          33.16     N/A      17.58
1975                  9.54          26.69     N/A      14.74
1976 (note a)         8.50          26.00     N/A      13.50
a/1976 figures are estimated.

     Pinpointing the causes of declining productivity is
difficult because they are so varied, hard to measure, and
the subject of disagreement. 59/ A BOM official who had
queried industry officials as-To the causes for the decline
stated that there was no single cause but a combination of
causes including: 60/

       -- Increased requirements related to health and safety.

       -- Introduction of many new miners and opening of n-w

       --Increased reclamation work.
       -- Increased exploration work.

       -- Physical conditions, such as increased depth of
          overburden, increased distance of working areas from
          the mine entrance especially in older mines, poor
          roof conditions, and other comparable factors.
       -- Increase in underground work force required by
          UMWA agreement.

       -- Disruptions in production caused by wildcat strikes,
          and absenteeism.
     Improvements in mining technology and increased employee
motivation are considered the ways by which this downward
trend can be reversed. 61/ BOM is directly concerned with
improvements in technology. The Director, BOM, at the Third

Conference on Mine Productivity in April 1976, stated that
the scientists and engineers in BOM believed that the three
underground coal mining systems currently in use in this coun-
try have theoretical excavation capacities (tons/shift) that
are not being used as shown in the following chart. 62/

                           CHART 1
                    BY COAL MINING SYSTEM


   20,000                        AVERAGE CAPACITY

                              16,-EJBEST TO DATE



            CONVENTIONAL        CONTINUOUS           LONGWALL
                            COAL MINING SYSTEM

      The Director also pointed out that although the
 cal limits may never be reached, it is possible
                                                 to achieve
 considerable gains. He concluded that a substantial
 and development program is essential if such improvements
 are to be realized.
       Although the Director's address highlighted underground
 mining, BOM is also concerned with improving surface
 productivity. Considerable research and development mining
 are being conducted on both underground and surface   efforts
 equipment and technology. 63/ (See page 4.52 for
 details on existing and future projects to improve further
 ti' ity. )                                          produc-

     At the productivity conference, an industry representa-
tive said that there is a ne-d eo convince the
                                                 miners that
only a profitable company witi. ravorable long-term
can cosider long-term investments which will provide prospects
nent, well-paying jobs.    In addition, there is a need for
the industry to assure that the grit     -  procedure is fair,
effective, and .)sompt so that the      ?    nfrontation and
distrust is reduceo.   63/
     UMWA contends that unreachable productivity
not be set. It suggests that the companies hire levels should
                                                   and train
substitutes to replace persons who are absen' because
ness or accidents, to avoid shutting down               of sick-
do." They concluded that, "Firms that try tj be     "making
in their policies, are fairly liberal, and operateprogressive
will have the best motivation among their employees."safe mines,
     In conclusion, as noted by the BOM Director, if
tivity levels were raised to the 1969 levels, coal
would be increased by 100 million tons annually      production
ing a single new mine. '/                        without open-

     Management/urn.Lon relations
     The - tent of interrupted production resulting
labor disagreements has been a matter of concern
                                                 to the coal
operators. During 1975 the coal industry lost
1.6 million days due to unauthorized work stoppages.
     UMWA represents about 80 percent of the produ-
ers employed in the coal industry. Other coal-rc      ion work-
                                                    iced unions
are the Southern Labor Union, the Progress've Mine
and, in the western coal lards, the International Workers,
Operating Engineers. 67/                           Union of

      Statistics maintained by the U.S. Department of Labor on
strikes in the coal industry show an increased number  of work
stoppages in the past few years. Although the number of work
stoppages has increased, the percentage of total working
time lost is not substantial, except in years when a national
agreement is renegotiated. For example, in 1973 less than 2
percent of total industry working time was lost in work stop-
pages. In 1974, however, 8 percent of the working time was
lost. Table 13 shows the work stoppages and time lost during
the last 10 years. 68/

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     Contract agreements--Over the years, union and management
have negotiated increases to wages, better working conditions,
procedures for handling grievances, and various fringe benefits.
The agreement reached in 1974 includes the following. 69/

     -- Increases in wages and vacations, and adjustments to
        pay scales.
     -- Addition of helpers to certain work crews.

     -- Increases to pension fund payments by employers and
        greater benefits to retirees.
     -- Establishment of sick leave and sickness and accident
     -- Substantial revisions to job training requirements,
        including adoption of a requirement that new employees
        must spend their first 90 days in "nonhazardous" jobs.

     -- Granting union safety committees the right to inspect
        all work areas and the right for miners to withdraw
        from any area they consider unsafe.
It should be noted that the union failed to obtain the right
to strike over local grievances, including safety matters. 70/
     Current agreements of the UMWA and the Bituminous Coal
Operators Association, Western Surface Miners, and National
Coal Mine Construction Contractors expire December 6, 1977.
The upcoming negotiations were the subject of the union's
convention held from September 23 through October 2, 1976. 71/
     The following are some of the demands agreed to at the
1976 UMWA convention in negotiating the 1977 agreement. 72/
    -- The "right to strike" provision had the greatest
       support. Local unions would have the option of solving
       a legitimate complaint through filing of a grievance
       or calling a strike. Therefore, the companies could
       be prevented from obtaining injunctions in these
    -- The establishment of more efficient grievance proce-

     --All mines will have a full-time union safety committee-
       person properly trained who "shall have the power to
       shut down a jobsite, mine, or mine facility for health
       and safety reasons."
     -- Various safety demands, including the mandatory
        establishment of professionally trained mine rescue
        teams at all mines and a provision that no employee
        work alone.

     -- New health and retirement benefits and the provision
        of additional social services to western miners.
     The election of national officers scheduled for November
1977 was moved up to June 1977 so there wculd be more time
available for the president-elect and other incoming
officers to prepare for the negotiations.73/

     Role of the Government in coal industry dispute
settlement--For purposes of determ ing whether striking
miners can be discharged or otherwise disciplined, the
National Labor Relations Board must determine whether the
strike is a protected or unprotected activity. The operator
cannot take adverse action when the circumstances show
that the strike is a protected activity. There are four
well-defined categories of protected strikes. 74/
     -- Strikes involving unfair labor practices.

     -- Strikes at the expiration of an agreement.
     -- Strikes over abnormally dangerous working conditions.

     -- Strikes over matters the contract leaves expressly
        to local settlement.
     Unprotected strikes are those with an illegal purpose
such as imposing a secondary boycott; those accompanied by
illegal conduct, such as violence and intimidations at the
picket line; also unprotected are strikes occurring during
the life of a contract which contains a no-strike clause.

     Section 301 of the National Labor Relations Act, pro-
vides that labor organizations that breach a labor-management
agreement are subject to lawsuits for damages. Using this
provision, the National Labor Relations Board has ruled that
since the national coal agreement has a mandatory grievance
procedure, it is equivalent to a no-strike clause. Striking
in the face of such a mandatory procedure is a breach of con-
tract and the Board considers the strike to be unproteted.

Although the Board has reached this conclusion, the courts
have been anything but consistent in deciding whether the
miners' contract has an implied no-strike clause. 75/

     The companies take the view that only a small percentage
of the strike situations in the organized sector of the coal
industry are protected strikes and have filed over $400 million
in lawsuits against the union for allegedly illegal strikes.

     The companies' primary concern is getting the miners back
to work.  Accordingly, they apply for cease and desist orders
from the Board.  However, if a strike is not proved to be a
refusal to bargain, the Board cannot find it to be an unfair
labor practice and cannot issue a cease and desist order.   On
the other hand, the courts have eased the way for companies
to win court injunctions for violations of section 301. 76/

     The Board will decline to settle charges of unfair
labor practices where there is an arbitration procedure
established by a labor-management agreement. 77/ Such an
agreement is in existence in the coal industry and was
established by the 1974 agreement. A tripartite (independent
arbitrator-industry-union) Arbitration Review Board is the
final step in the grievance procedure.  It was instituted
to resolve conflicting decisions by different panel arbitra-
tors and to insure uniform interpretations of the contract.
The main complaint by the union against the Arbitration
Review Board is that it has acted too slowly. 78/

     The rule followed by the Labor Relations Board is that
it will not review a charge where "the proceedings have been
fair and regular, all parties had agreed to be bound, and the
decision of the arbitration panel is not clearly repugnant to
the purpose and policies of the Act".  [Spielburg Manufacturing
Company, 112 NLRB 1080, 36 LRRM 1152 (1955)] 79/

     In GAO's evaluation of the National Energy Flan, we
recognized the seriousness of the impacts that management/
labor disputes could have on a large, stable supply of coal
and recommended that Congress expand the plan for coal to deal
with the need for improved labor relations to prevent disrup-
tions due to wildcat strikes.

Miner health and safety

     In an effort to reduce deaths, disabling injuries, and
disease incurred in coal mining, the Congress, in December
1969, enacted the Federal Coal Mine Health and Safety Act
(30 U.S.C. 801).

      The act prescribed interim mandatory health
 standards applicable to all underground coal       and safety
 the Secretary of the Interior promulgated     mines  until
                                            standards. Health
 standards and safety standards for underground
 published in the Code cf Federal Regulations    mines were
 70 and 75) and became effective in June 1970  (30  C.F.R. Parts
 1970, respectively. Health and safety standards November
 mines were published in 30 C.F.R. Parts 71         for surface
 1972 and May 1971, respectively.            and 77  in March

      The act and the regulations prescribe
 for controlling respirable coal dust which health standards
 pneumoconiosis, known as black lung. Healthis the cause of
                                               standards are
 also prescribed for dust resulting from drilling
 for respirable dust when quartz is pFesent,       in rock,
 Miners are offered the opportunity to have   and tor noise.
                                             periodic chest
 x-rays for the detection of black lung.
       The major safety provisions of the act and
                                                   the regula-
 tions relate to roof control, ventilation,
 systems and equipment. Safety requirements  and  electrical
 also for (1) combustible materials and rock  are  established
                                              dusting, (2)
 blasting and explosives, (3) equipment for
 miners, (4) emergency shelters, (5) communications,
 fire protection.                                      and (6)

     Mine operators must adopt a suitable roof
approved by MESA, for each underground mine.     control plan,
give the criteria to be followed by district   The  regulations
                                              office managers
in approving the plans. Roof falls are one
causes of fatalities in underground          of the principal
                                    coal mining and approved
roof control plans must be reviewed by MESA
                                             every 6 months.
For calendar years 1974 and 1975, mine operators
MESA that fatalities from this cause numbered      reported to
                                               49  and
respectively, or about 50 percent of all underground 47,
ties. 80/                                              fatali-

      To minimize the danger of explosions and electrocutions,
 the electrical systemli and equipmn-t must meet
etablished by the Secretary of the Interior. specifications
cations are to be applied uniformly to all         These specifi-
                                              mines. The act
also prescribes a program of coal mine inspections
which is to consist of complete safety and              by MESA
of each underground mine at least four times  health   inspections
special spot inspections once every 5 working    a year  and
mines having certain hazardous conditions.        days  of all
                                               MESA has adminis-
tratively determined that special spot inspections
also be made every 10 working days of certain           should
mines.                                            other  hazardous
         In addition, the act requires that representatives
of the mine operators make certain health
                                             and safety examina-

     The act also provides for expanded and upgraded health
and safety education and training activities and technical
assistance to mine operators.  It further provides for a
program of research and technical support aimed at making
coal mining a healthier and safer occupation. Seven -ears
have elapsed since the passage of the act and some progress
has been made in health and safety, but many problems

     The respirable dust standard of 2.0 milligrams per
cubic meter of air became effective on December 30, 1972.
It was established to prevent new miners from contracting
black lung and to prevent further progression of the dis-
ease in miners who had already gotten it. 81/
     MESA was established in 1973 to carry out the provisions
of the act. Before 1973 these responsibilities were carried
out by BOM. 82/ Among its functions is conducting inspec-
tions related to compliance with the dust standards. Dust
samples taken by operators and by MESA in the 4,414 mine
sections that were active for some portions of 1975 showed
that 1,374 (31 percent) exceeded the standard at least
once during 1975 and 3,040 (69 percent) were in compliance
with the standard every time they were sampled.
     Although reaching this level of compliance with the
dust standards is an improvement over previous dust levels,
full compliance with dust standards is considered essential.
There are compelling human and economic reasons for elimin-
ating pneumoconiosis. The human pain and suffering is ob-
vious.  In addition, monthly benefit payments for those who
have black lung were over $73 million in June 1975 and total
benefits paid through June 1975 were over $3.6 ailion. 83/
     Table 14 shows the fatality statistics since 1969. The
number and frequency of fatal injuries in bituminous coal
mining dropped steadily from 255 deaths in 1970 to 131 in
1973. The number of deaths was 131 in 1974 but increased
to 152 in 1975. The frequency rate, deaths per million
worker-hours, remained unchanged because of increased employ-
ment in 1975. During the 11-month period ended November
1976 there were 125 deaths which included the 25 men killed
in the Scotia disaster. 84/


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     A comparison of fatality rates per million worker-hours
for the various segments of mining, table 15, showed that
although underground operations were the highest, surface
fatality rates could not be considered low. 85/

                           Table 15
          Fatalty Rate in Bituminous Coal Industry
                 per Million Worker-hours
       Underground mines     Sarface mines       Preparation   Overall
      Undergroun    Oter      trip     Other        plant        rate
1959      .98        .72           a/.64            .50         .85
1970    1.26         .75           a/.59            .31        1.02
1971     .91         .45           a/.43            .25         .73
1972     .64         .23           a/.33            .43         .53
1973     .51         .36           a/.30            .42         .45
1974     .44         .28     .40           .57      .43         .42
1975     .39         .33     .49           .81      .36         .41
1976     .41         .13     .27           .00      .18         .35
  (note b)
a/Strip and auger combined.
E/Data Fvailable for 11 months only.

     In terms of fatalities per million tons, underground
rates would be higher because of the lower productivity
per worker-hour of underground mining-

     An accident prevention prograr was initiated by MESA
in 1973 to decrease the number of non-fatal injuries in
coal mines by devising safer mining methods. Initially the
program was directed to underground mines employing 200
miners or more which had a disabling frequency rate higher
than the national average. This was expanded in 1975 to
include mines employing 150 or more miners. 86/ Inspectors
were assigned to these mines on a daily basis to review opera-
tions and coordinate with management and employees. MESA
made 3,331 such inspections in 1974 and contends that the
lower injury rate in 1974 is in part attributable tc this
program. 87/

     The trend of disabling accident rates is shown in table
16. American National Standards Institute, Inc., defines
disabling injury as a work injury which results in death,

 permanent total disability, permanent partial disability
 or temporary total disability which results in the
 of at least one complete work shift. 88/

                             Table 16
                       Disabling Injuries in
                  Bitumi'nous Coal IndJstry-(note a)

                                                 Rate per million
                       Number of accidents         work-hours
 1969 (note b)               10,120
 1970 (note b)                                         42.61
                             11,812                    45.40
 1971                        11,539
 1972                                                  47.13
                             12,165                    46.55
 1973                        11,011                    40.54
 1974                         8,429
 1975                                                  28.90
                             11,009                    30.31
 1976 (note c)               13,800                    36.16
a/Includes fatalities.
E/Includes anthracite mine statistics.
c/Prel iminary.

     The rate of occurrence of disabling injuries
creased by almost 25 percent since 1973. However, has de-
absolute number of such injuries is still high.    the

     Assuming that the fatality and disability injury rate
does not improve greatly from the 1975 rate, we estimate
that as many as 3,400 miners might
disabled in accidents under the EEI belevels
                                        killed and 253,000
                                             of production
for the 25-year period ending 2000. For the BOM scenario,
as many as 4,700 miners might be killed and 351,000
                                                      may be

      Reducing the number of accidents and the resulting
 fatalities and disabling injuries is an important
to all parties in coal production. MESA has been concern
 inspections to assure compliance with the Federal
Mine Health and Safety Act and to detect areas whichCoal
quire corrective action.   It believes that miners deserve
and need more intensive training and has drafted regulations
for mandatory training of miners.   It is also considering
establishing qualifications, certification, and licensing
certain mining and supervisory jobs. Efforts have             of
exerted in research and development for new equipmentbeen
well as improvements to existing equipment. The numberas
miner's lives that have been saved- from roof falls
and canopies installed on underground equipment has  by  cabs

great, and 36 lives were reported saved in 1975 by these
safety accessories. 89/
     The coal industry is cooperating with MESA and considers
safety and safety training very important. 90/ The industry
is also cooperating in health and safety research and develop-
ment projects. UMWA is.vitally concerned with health and
safety and many safety items are included in their demands
for negotiating with the industry. UMWA contends that MESA
training requirements should be expanded beyond what has
been proposed. 91/

     As already noted the coal mining industry has become
increasingly automated. This is especially true in surface
mining where huge equipment is used to move large amounts of
earth and rock (overburden) to get the coal. 92/
     Equipment shortages during the 1974 surge in coal output
raised questions as to the availability of equipment to meet
future production needs. 93/ The questions to be resolved
are how much new equipment will be needed to achieve the pro-
duction goals established for the years 1985 and 2000 and
will such equipment be available in time.

     Predictions of the type and quantity of equipment that
will be needed to support given production levels are depend-
ent upon several factors. Maximizing safety while minimizing
costs are the key objectives in proper equipment selections.
The equipment selected will depend upon: 94/
    -- Required rate of production to meet customers' needs.

    -- Depth and volume of overburden to be moved in surface
       mining, and the location and depth of the coal seam
       in underground mining.
    -- Characteristics of the overburden as they relate to
       removal problems in surface mines and roof support
       requirements in underground mines.
    -- Overburden segregation requirements required for proper
       reclamation in surface mining.
    --Distance, route, and elevation from the bank to spoil
      pile or discard area for surface mines.

       -- Coal characteristics, such as quality and thickness of
          the seam and the extent of partings or intermittent
          layers of foreign matter.
       -- Coal haul distances and elevation changes.

  The quantities of new equipment to be procured depend on the
  number of mines to be opened and the equipment in existing
  mines to be replaced by 1985 and the year 2000.

       Using BOM projections of equipment needs to achieve 1.2
  billion :'ns of coal production by 1985 as a baseline, 95/
  we have estimated replacement and new installation requlre-
  ments for 10 selected equipment items. These estimates are
  for the production levels cited in the EEI and BOM scenarios
  for 1975 to 1985 and 1986 to 2000. Table 17 summarizes these

                                 Table 17

                Estimated   New£_guipment       Requirements
                               1974           1976 to 1985       1985 to 2000
                             In use           EEI      BOM       EEI      BOM

Annual production
(millions of tons)              603           779      988       942    1,586
Underground items

    Continuous miners        1,976          3,300   4,500      3,450    6,550
    Longwall equipment          50             30      60        110      180
    Cutting machines         1,600            800     800        600      800
    Mobile loaders           1,800            800     800        650      850
    Shuttle cars             6,500          5,500   6,800      5,400    9,100
    Conveyors                3,985          6,550   8,500      5,900   11,000
    Locomotives              3,095            550     550        650      880
    Mine cars               43,330          7,700   7,700      9,250   12,300
Surface items

   Draglines (large)    a/100                 180     250        150      310
   Coal loading shovels a/600                 550     700        900    1,270


     Timing of procurement is important since the most modern
coal mining equipment is not mass produced.   Common and
standard mining equipment is delivered within  a minimum
amount of time, but larger, more sophisticated equipment will
take longer.  BOM indicated that some equipment can take from
6 months to 4 years to manufacture depending upon its com-
plexity.  Equipment delivery time further depends on the
availability of raw mAterials and the manufacturer's productive
capacity. 96/
     During the 1974 surge in output, increased demands were
pl-ced on equipment manufacturers to furnish needed equipment.
At the time, the equipment manufacturers were not prepared
for the sudden flood of orders, which caused backlogs and
extension of delivery times. Manufacturers of both surface
mining and underground mining equipment had difficulty
obtaining raw materials, particularly steel, to meet demands.
The problem was most acute for the large draglines used for
surface mining, where production time increased from 2 to
5 years. 97/ Recent studies performed by BOM and by a consul-
ting firm-Tor FEA have indicated that equipment availability
would present no great problems, with the possible exception
of the large draglines. 98/

     We discussed this matter with coal producers and dragline
manufacturers who told us that the extensive backlog situation
has been overcome. Many of the orders received during the
1974 surge have been deferred by the coal producers. Equipment
manufacturers' capacity is being expanded to meet expected
coal demands, and production time has been reduced from
5 to 2-1/2 years. Consequently, if there is adequate planning
by the coal mining industry in its ordering of equipment,
the manufacturers should be able to produce and deliver
the items. Dragline production continues to be a question,

     BOM has observed that, although productive capacity
of existing dragline producers has expanded, there might
be short periods when backlogs in dragline deliveries might
occur. One of the dragline manufacturers disputed this point,
indicating that there would not be any shortage.
     Backlogs could delay the opening   of a surface mine and
the commencement of coal production.    However, there is other
earthmoving equipment available which   could be used as a
stopgap measure, although it would oe   more costly.

      Capital investment needed to expand future coal production
 will be substantial compared with current rates of investment
 in the industry. Based on recent BOM estimat-s of capital
 costs per annual ton of new production capacity, we estimate
 that capital requirements to achieve the scenario levels
 of coal production through expansion of old mines and opening
 of new mines may range as follows: 99/

                             Table 18
                Cumulative Capital Requiremen.s
                         -    -- UD
                         1975t2     -       -
                             LEI-scenario         BOM scenario
1975 to 1985                  $ 9.0                    $15.7
1986 to 2000                   17.7                     29.8
   Total                      $26.7                    $45.5
     Other recent estimates of coal industry capital needs
to achieve a production capacity of about 1 billion tons
annually by 1985 follow:

  Estimating                                      Capital
 organization          Level of output       requirement (note a)
                      (billions of tons)             (billions)
MITRE Corporation               1.1                  $ 9.8
Banker's Trust of New York      1.1                   12.5
BOM                             1.3                   14 4
Continental Ill nois Bank
  of Chicago                    1.0                   20.0
Rational Coal Association       1.2                   18.2 to 22.1
FEA                             1.04                  17.7
a/All requirements are in 1975 constant dollars.

     Total ccal industry capital expenditures fram 1965 to
1974 was $6.5 billion, or an average of $650 million per
year; this indicates the need for an unprece ented
rate of capital investment under both the BOM and EEI
scenarios. 100/ Financial experts expect at least half
of the industry's capital must be provided from external
sources. 101/

     As an illustration of the current cost of opening new
mines, BOM has recently made the following estimates for
mines with a capacity of 1 million tons per year. The costs
are shown in table 19. 102/

                           Table 19
                Capital Cost Per Annual Ton
                of New Productive Capac-ty-
                           Underground mines   Surface mines
Initial investment                  $31              $18
Deferred needs--over
  operating life of mine             10                3
   Total                            $41              $21

     The BO.I estimates mean that $41 m ..lion would be needed
to open and operate a 1 million ton per year underground
mine. A surface mine of similar capacity would require $21
million. These estimates reveal a sharply rising trend in
capital requirements. Similar BOM estimates prepared in
1974 showed capital needs of from $15.20 to $31.37 and
from $16.65 to $22.53 per annual ton of production, respec-
tively, to open new underground and surface mines. 103/
Increased capital costs are attributable primarily to
inflation in the cost of coal mining equipment, which has
increased two t     ree times as much as that of the rest
of the economy      /
Sufficiency of capital investment
     The capital requirements of the coal mining industry,
while large in comparison to past needs, constitute only
a small portion of t' total future capital need. of all
energy industries,    :mated by FEA at $580 billion, to
provide for the er. jy requirements in 1985. 105/
     Future coal projects, such as new mine openings, will
have to compete in the capital market for investment funds
with other energy and nonenergy related projects. 106/

 Possible impact of horizontal divestiture
 on coal industry capital acquisitilon

      During early expansion years and through the industry
 stagnation in the 1960s, the coal industry traditionally
 financed new ventures from internal funds. More recently,
 the entry of major oil and other companies, such as railroads,
 into coal mining activities has made new sources of capital
 available. For example, oil companies, now control about
 18 percent of U.S. coal reserves. Railroads control about
 9 percent. 107/ These companies have provided the coal
 industry wit--sources of funds not previously available.

      Financial experts told us that if Federal legislation
requiring horizontal divestiture of coal interests by oil
companies is adopted, the coal industry will lose an important
source of capital. 108/ Horizontal divestiture is the subject
of another review being conducted by GAO and the issue and
its various implications will be addressed in a separate

The Federal loan guarantee program for
new underground, low-sulfur coal mines

      To encourage the development of new underground, low-
sulfur coal mines, Title I, Section 102 of the Energy Policy
and Conservation Act or i76 ( .r. 94-163), provides
guarantees (not to exceed $30 million each) totaiinr for  loan
                                                      up to
$750 million. To date, no guarantees have been granted
these provisions, nor have implementing regulations been under
promulgated by FEA. FEA and banking officials observed
if implementing regulations closely follow the provisionsthat,
the act with respect to the requirements for guarantees, of
relatively few guarantees would be granted, because eligibil-
ity criteria are no more lenient than the usual credit
ments of commercial banks. Those marginal projects thatrequire-
be financed through commercial lending institutions--whichcannot
the program is presumably intended to encourage--probably
would not qualify for loan guarantees. 109/ In view of
history, we believe the Congress should consider the needthis
amend this section.

Tax considerations

     Taxes can change economic decisions, especially where
profit margins are small.  Coal is produced generally
incorporated firms subject, for the most part, to the hy
Federal tax rate and provisions as other incorporated
concerns.                                             domestic

     The investment tax credit

     Coal firms,, as well as other domestic firms, are permitted
a tax credit equal to 10 percent of up to 100 percent of the
purcnase price of qualifying machinery and equipment, 110/
The purpose of this provision is to stimulate the acquisition
of selected equ pment wiich, in turn, will affect economic
growth and employment.   The amount of this credit, referred
to as the investment tax credit, is subtracted from the
firm's Federal tax liability.   At the corporate tax rate
of 48 percent the credit is worth almost twice the value
of a usual business deduction because the corporate income
tax rat? decreases the after-tax value of the deduction
to about half but the credit is already valued in after-tax
terms.  Hence, in after-tax terms, a $10.00 deduction is
worth only about $5.00 but a credit of $10.00 retains its
worth of $10.00.

     The credit is, however, subject to a limitation; it
generally cannot exceed 50 percent of tax liability after
the first $25,000 of tax liability (for which the sole limita-
tion is that the credit cannot exceed tax liability).   If
a firm cannot use this credit in the year incurred, the
firm can apply that credit against the Federal taxes of
the previous 3 years and the ensuing 7 years. 111/

     The limitation provision, therefore, tends to bias the
effect of the credit so that it works efficiently only in
more profitable firms.  For purposes of this discussion,
profit is considered to be similar to taxable income. An
industry with high capitalization requirements (high
investment reyuirements) and a small profit, such as has
characterized the coal industry in the past, would nut benefit
as greatly as a similar industry with higher profits.  Internal
Revenue Service statistics show that the coal industry has
generally qualified for more of these credits than it could
use, thereby forcing firms to carry over such benefits to
subsequent years. 112/

    The depletion allowance

     Industries are permitted a deduction for the depletion
and exhaustion of natural resources, such as minerals or
timber, in which they have an economic interest. 113/ This
is similar in principle to the depreciation of equipment, in
that it is the recovery of cost at the rate the mineral is
produced. 114/ This ratable cost recovery is known as cost
depletion .TT5/

     Coal producers are accorded an option to cost depletion;
a percentage depletion deduction of 10 percent of gross
income from mining, not to exceed 50 percent of the taxable
income from each mine, calculated without regard to the
depletion allowance. 116/ While this is not as high as
the 22 percent previously allowed crude oil and natural
gas producers, and still accorded sulfur, uranium, and many
other domestic minerals, 117/ it is, in most instances greater
than depletion based on cost. Percentage depletion ignores
and can exceed the cost of property. The deduction for per-
centage depletion may be claimed so long as the property
is producing. The deduction for cost depletion, however,
is permitted only until the original cost of the property
is recovered. 118/
     The net income limitation for the coal depletion deduc-
tion allowance has the same effect that the limitation poses
for the Investment Tax Credit. Marginal mines are precluded
from realizing the full tax benefits that more profitable
mines enjoy. In general terms, this means that it is pos-
sible to have a larger depletion deduction than the limita-
tion allows. This can occur when profit (taxable income) is
low relative to gross receipts. In other words, when it costs
more money to operate a coal mine (relative to other busines-
ses), the depletion limitation can impose an additional
financial disincentive by postponing tax benefits to future
years. In extreme cases, a firm can lose tax benefits
entirely when the limitation period expires.
     Depreciation- allowance
     Under the Internal Revenue Code, a firm may depreciate
all of its depreciable mining assets over an 8- to 12-year
period. It may also use accelerated methods, such as double
declining balance and sum of the years digits. 119/ While
these methods represent faster cost recovery, ti-e provide
no special benefit to coal since all other industries enjoy
similar tax treatment of capital assets. 120/

    Rapid-amortization-of coal
    mine safety equipment
     There is a special provision allowed for coal mine
safety equipment placed in service prior to Jar, :y 1, 1976,
in the Internal Revenue Code. 121/ The purpose of this pro-
vision is to give coal mine operators an incentive to purchase
coal mine safety equipment. This provision permitted the

purchaser of qualified equipment the option of either depre-
ciating this equipment the same way he would other equipment
or amortizing it evenly over a shorter 60-month period. 122/
However, the rapid amortization election precluded the pur-
chaser from using the Investment Tax Credit 123/ and with the
recent increases to the credit, removed any -ncentive to use
the rapid amortization as against using normal depreciation
and the full investment tax credit allowance.

     Capital gains treatment of
     coal royalty income
     Owners of coal property (as well as owners of timber
and iron ore properties) can treat royalty income as
long-term capital gains. 124/ Capital gains tax treatment
is considered preferential tax treatment since lower taxes
are paid on such income. This benefit, while available to
owners, is not available to producers--unless, of course,
they own the coal property too, which is sometimes the case.
125/ The congressional in:.ent here was to assist coal royalty
owners, many of whom had entered into long-term contracts
calling for royalties expressed in cents per ton which,
of course, do not provide adjustments for price changes
as do royalties expressed as a percentage of the value of
the mineral produced. This contrasts sharply with other
coal tax benefits which generally do not give preference
to mineral ownership over production.

     Nonpreferential treatment of
     coal exploration costs
     A tax benefit accorded oil and gas but not accorded
coal is the treatment of intangible drilling costs. These
may be expensed or capitalized at the option of the taxpayer
without repaying the tax benefit in the future. 126/ The
counterpart for the coal industry is exploration costs which
are also expensed or capitalized at the option of the tax-
payer. But the coal exploration costs, if expensed, are
"recaptured" when the mine begins to show a pro'  . that is,
the coal producer repays the tax benefit accord    im earlier
while the oil and gas producers do not. 127/

Legislative and regulatory constraints

     There are particular measures which include obstacles
to the rapid development of coal. These measures which have
been enacted

     -- create uncertainties as to whether certain coal
        reserves can be mined or
     -- increase the costs of the coal.

     Disincentives-to coal production
     thrcugh_ axation
     In certain instances, the taxes imposed by a given State
may serve as a disincentive to coal production in that State
in a normal competitive economy. Some State taxes, such as
severance taxes, increase coal production costs (and/or the
sales price) while others such as income taxes reduce profits.
      Eleven States accounted for over 90 percent of domestic
coal production in 1973. 128/ We restricted our survey of
State taxes to these 11 States. Usually States do not levy
identical taxes; even if two States have similar taxes with
identical rates (e.g., a sales tax of 4 percent), they impose
that tax on different items. For example, Illinois imposes
a sales tax on all purchases by manufacturing firms, 129/
while Ohio levies a sales tax on purchases by manufacturers
but exempts machinery used directly in the manufacturing
process. 130/ In Alabama, some items purchased by manu-
facturers are taxed at rates lower than the general sales
tax rate. 131/
     Several States have categorized their taxes one way,
(e.g., a sales tax) when they are more precisely something
else (e.g., a gross receipts tax). For purposes of this
discussion, taxes are categorized according to the nature
of the tax.

     Corporation income taxes--Most coal firms are taxed as
businesses at corporate tax rates.

     For the eleven States studied, the State corporation
income tax rates are shown in table 20.

                          Table 20
              State Income Tax Rate Comparison

                                       Corporate income
     Kentucky 132/            4.0       up to $25,000
                              5.8       over $25,000
     West Vircinia 133/       6.0
     Pennsylvania 1T47        9.5
     Illinois 135/            4.0       over $ 1,000
     Ohio 136/                4.0       up tG $25,000
                              8.0       over $25,000
     Virginia 137/            6.0
     Indiana 1387             3.0
     Alabama 1-9/             5.0
     Wyoming 1TT/             (a)
     Montana TIT/             6.75
     New Mexico-142/          5.0
     a/Wyoming has no incone tax.

     While the definition of taxable income varies from State
to State, it is generally similar to the definition of taxable
income for Federal tax purposes. Pennsylvania also levies
a 1 percent capital stock tax which is a levy or the actual
value of the corporation as determined by net worth, or capi-
talized earnings and the market value of the shares. 143/
Corporate income taxes are generally levied on all types of
firms regardless of the nature of their business. This form
of tax generally produces a large proportion of the State's
revenues. Since it primarily affects the companies' pro-
fits, it has little impact on the rate of production and on
marginally productive mines. 144/

     Sales taxes--Generally, the addition of a sales tax to
an item has the effect of reducing the number of items that
will be sold since they will be available at a higher
price. For those States levying a sales tax, it generally
provides about one-third of each Stati's revenues.

     Sales taxes are imposed by almost all of the 11 States
considered in this study; however, a substantial amount of coal
production is .sually exempted from the sales tax by these
States. One-third of the States levy no sales tax on coal
whatsoever and the remaining two-thirds exempt resources used

in the manufacturing process, interstate transactions, coal
purchased for resale and/or coal used to produce energy.

      Illinois is the only State studied which has a true
sales tax (the Retailers Occupational Tax) affecting a
significant amount of coal sold. Illinois has a State sales
tax of 4 percent plus an additional 1 percent for the county,
levied at the point of sale and stated explicitly in the
termas of the sale. 145/ Indiana also has a 4 percent sales
tax on coal sold at the retail level; however, exemption
certificates for certain uses exclude substantial amounts
of coal sales from the tax (e.g., coal sold for the produc-
tion of energy). 146/
     Production taxes--There are various types of taxes levied
on the total production of coal firms. Prominent among them
are severance taxes, gross receipts taxes, and ad valorem*
taxes. This type of tax generally has a heavy impact on coal
firms. In some cases, these taxes are levied exclusively on
coal and not on other products.

     West Virginia's gross receipts tax on coal is 3.85
percent of gross proceeds from the sale of coal. 147/ This
tax produced more tLan $100 million in revenues in T975, over
14 percent of the State's total revenues in that year. This
tax is credited against State income tax liability. 148/

     Kentucky levies both a specific and an ad valorem seve;-
ance tax, which amount to 50 cents per ton and 4.5 percent of
gross value, respectively. The specific severance tax is
merely a floor or alternative minimum tax to protect the
State's revenue position. in 1975, with these taxes at
30 cents per ton and 4 percent, respectively, the State
collected almost $100 million, or about 8 percent of total
revenues. 149/
     Pennsylvania levies no production tax on coal and
neither does Illinois nor Indiana. However, as mentioned pre-
viously, Illinois and Indiana do impose a sales tax on coal
that is sold.

     Ohio levies a specific severance tax of 4 cents per ton
150/ while Virginia authorizes a county tax of 1 percent of
gross receipts. 151/ Alabama has a 13.5 cents per ton specific

*In proportion to the value.

severance tax on coal; 152/ Wyoming levies a 6 percent (effec-
tive 1978) ad valorem tax which, when combined with its so-
called property tax on assessed value (value is determined by
the price of the coal extracted) amounts to a 12 percent ad
valorem tax. 153/
     Montana has both a specific and an ad valorem severance
tax. The specific severance tax, unlike Kentucky's, is
tied to the wholesale price index but nevertheless acts as a
floor or alternative minimum tax. For surface-mined bituminous
coal, the ad valorem tax is levied at a 30 percent rate (at
least 40 cents per ton) with an additional 0.5 percent for a
resources indemnity tax. 154/ For deep-mined coal, Montana's
taxes are 4 percent (at least 12 cents per ton) and 0.5 per-
cent, respectively. 155/
     New Mexicu levies a gross receipts tax of   4 percent plus
a 0.5 percent severance tax and a 0.75 percent   resources ex-
cise tax. Local governments also levy about a    3 percent ad
valorem tax on the Ijusted gross value of the    coal. 156/
     Production taxes are variable costs and as such add to
the costs of production. The economic impact of such taxes
by a State, assuming a normal competitive industry, is to
reduce the production of coal in that State. Specific
severance taxes (and similar taxes) pose the additional
problem of hastening the depletion of readily accessible and
most profitable high grade reserves, relative to less acces-
sible or low grade reserves. Although production taxes and
sales taxes have been dealt with separately for purposes
of this review, the economic effects of these taxes
are similar.

     Comparative analysis of alternative tax options
     The evaluation of coal taxes is complicated by tne fact
that Federal and State governments mzy establish different
and sometimes conflicting goals and objectives. The Federal
Government's goals include national security, energy inde-
pendence, the economic allocation of goods and services (or
the neutrality of taxes among goods and services), and the
raising of revenues to finance the Federal Government and
its programs. The State's objectives include the maximni-
zation of revenues subject to the preservation of the State
industry's competitive position, the mitigation of the socio-
economic costs of coal development, the general economic
development of the State, and the economic neutrality
between coal and all other energy resources.

     High severance taxes, for example, may accomplish all
of the State's goals, but such taxes, by increasing produc-
tion costs, may reduce the production of coal and its consump-
tion relative to other energy resources such as imported oil
and gas. Compounding this problem is the fact that a tax
credit is allowed on the Federal tax return for foreign
taxes paid on imported oil and gas while only a deduction is
permitted for State taxes paid for domestic coal production.

     Other uncertainties

     Taxation is not the only cause of uncertainty. The
Government has established Various policies relating to
environmental considerations in an effort to reduce damage
done by coal production and consumption to the air, water,
and land. Although the need for such protection is
recognized by the coal industry, they .re critical of policies
which, in their opinion, create uncertainty and are subject
to revision. 157/
     During the years of debate and compromise, the issues
surrounding national surface mining legislation raised doubts
as to whether coal could be mined as planned. 158/ Other
examples are the need to file detailed mi:?ing plans to States
and to prepare and file environmental assessments to the De-
partment of the Interior which prepares the environmental
impact statements for approval. 159/ In addition to delays,
the operator is faced with the possibility that the permit
will be denied or have conditions attached which would make it
uneconomical to mine the coal and deliver it to the consumers
based on the price negotiated.

     The possibility of changes in air quality standards by
the States and the Federal Government have also created
uncertainties as to wether the coal planned to be mined would
meet revised standards. 160/

     Problems facing the Federal Government in establishing
environmental and air quality standards are discussed in
chapter 6.

     Industry has also complained that recently enacted legis-
lation on leasing of Federal coal lands does not permit long-
range planning. 161/ Industry officials claim that the
time limits for exploration and consolidation of leases into
logical mining units (2 years) and for providing coal in com-
mercial quantities (10 years) are unrealistic and too


        A critical element affecting coal's ability to meet future
   energy needs is the development of technology to extract coal
   more efficiently and at acceptable economic and social costs.
   BOM's research and development activities are directed toward
   these goals, through three primary areas--advancing mining
   technology, mining health and safety, and environmental pro-
   tection.  Environmental research is discussed in chapter 6.
   Table 21 shows the estimated 5-year funding levels.

                                                     Table 21

                           Estimated 5-Year Budget for Coal
                        Extra-Eion- Technology Program (note* a)

                                   - Fiscal-year
Research segment      1976- 1977T 1977   1978    1979                       1980   1981   Total

Underground coal
  mining             $45.8 $11.4            $47.0 $ 60.5 $ 63.7 $ 62.,7 $ 59.5            $350.6
Surface coal
  mining               9.3       2.3.         11.7           13.7    15.5   15.0   14.7     82.2
Coal mine health       3.5          .9          4.1            4.6    4.2    3.6    2.8     23.7
Coal mine safety      25.9       6 4          25.5           29.7    28.9   28.5   30.9    175.8
        Total        $84.5 $21.0            $88.3 $108.5 %1i2;3 $109.8 $107.9             $632.3

a/The figures presented in this table, obtained from BOM's draft report
  entitled Strateaic and Tactical Plan, dated January 1976, are not precise
  but are indicatve of possibe-aocations based on BOM management judgment
  at the time.

b/This is a transition period of 3 months (one-quarter year) from the
  previous fiscal year period beginning July 1 to the newly adopted
  fiscal year period beginning September 1.

     This table indicates that the technology program funding
peaks in 1979 with an estimated budget of $112.3 million, a
33 percent increase over fiscal year 1976. The surface mining
technology budget is $15.5 million and represents a 67 percent
increase over the fiscal year 1976 level. Underground mining
also increases; however, the projected funding level is only
a 39 percent increase over fiscal year 1976. The significant
increase in surface mining technology research is more than
likely a reflection of the relative importance surface mining
will play in near term coal production. It should also be
noted that the projected funding for health and safety research
beginning in fiscal year 1978 is more than the current $30
million limit. Exceeding the limit will require a change
in the Coal Mine Health and Safety Act of 1969.

Advanced coal mining technology
     BOM has identified certain bottlenecks to increasing
coal mine productivity, such as installing roof supports;
transporting coal, men, and supplies in underground mining
operations; and reliability of continuous mining equipment.
They are attempting to develop technology to overcome these
obstacles and their aim is to develop and make improved mining
technology available to industry as soon as possible. 162/
     The objectives of the advanced mining research program
are to improve present surface and underground mining and
environmental practices, automate present systems (such as
continuous mining and longwall mining), and develop and
demonstrate new mining systems that substantially improve
productivity. The program's emphasis is on improving under-
ground mining techniques because the majority of coal reserves
is at depths which make underground mining the only feasible
long-term method of extraction.
     BOM's underground mining research efforts are specifi-
cally directed to:
    -- Increasing the average production per shift.

    -- Accelerating the use of longwall mining.
    -- Developing mining systems to recover 80 percent of
       western coal deposits.
    -- Reducing the time required to open new mines.

    -- Developing technology to provide protection of surface
       environment from underground mining, such as subsidence
       and water contamination.
    -- Conducting feasibility studies of new mining systems.

       BOM has estimated that some of the technology being
 developed will be available for commercial application in

     Research into improving surface mining is also important
because a significant portion of the projected coal require-
ments will come from such operations.   The overall objective
of surface mining research is to improve productivity along
with health, safety, and environmental standards.  BOM is con-
ducting research on:

       -- Integrating excavation and reclamation systems to
          reduce environmental impact.

       -- Investigating mining techniques that represent alter-
          natives to cu-'ent surface mining techniques.

       -- Im    c'
                 -    -           automation,    the entire coal mining
          C}'   e.

       -- Developing               on techniques for arid and serL-
          arid regions

     Equipment and    'thodology developed under the surface
mining rese' Ah    -tAm,   like the dragline augmentation device:
and   the wi         *,,-'   % .;er blade,   should be   ready for   industry,
use beginning i.,.        v78.

Coal mine health and safety

      Coal mining is the most hazardous occur 4 iz4n inr
States. 163/ The social and economic costs c¢ coal mi,'.
reflecteTd  n the injuries, occupational illnesses, and deaths
suffered by coal miners are high.

     Increased production will necessitate increased numbers
of miners, and based on historical correlation, could lead
to increased fatalities and injuries if there are no health
and safety improvements.

     BOM has, since its inception in 1910, performed research
and development to improve working conditions in the coal
mines. The Federal Coal Mine Health and Safety Act of 1969,
among other things, directed the expansion of research and
development programs aimed at preventing coal mine accidents
and diseases. Until 1969, BO.m's research was an in-house
effort.  The 1969 act augmented this effort by including a
contract and grant research program and authorized a total
health and safety research program with fun "ng of up to $30

million per fiscal year.  The act further required that
research be done in a number of specific research areas,

     -- Improved working conditions and practices in coal
       luine s.

     --De-eloping new or imprced methods o_ recovering
       persons in coal mines after an accident.

     -- Developing methods of reducing concentrations of
        respiraule dust in active working areas of coal mines.

     -- Developinq new and improved underground equipment and
        other sources of power for such equipment which will
        provide greater safety.

     In response to the research areas enumerate,' in the act,
BOM's research program .,as addressed the major causes of
injuries in coal mines--the hazards associated with electrical
and mechanical equipment, tire and explosions from combustible
gases and dust, and health problems associated with respirable
coal dust generated during mining.

     The specific objectives of BOM's research into coal mine
health and safety are to:

    -- Develop means to reduce the amounts of respirable dust,
       carbon monoxide, and other noxious or toxic contaminants
       introduced or produced during mining operations.

    -- Develop means to reduce excessive noise   introucued or
       produced during mining operations.

    -- Develop means for th'- removal, dilution, and protection
       against the remaining environmental contaminants,
       including excessive humidity and low &nd high

    -- Develop means for elimination or reduction 7f fire
       and :xplosion; failure and outburst of roof, rib,
       face, and highwall surfaces; inundation; and electri-
       cal and machinery hazards.

    -- Develop more efficient and safer means for survival
       and rescue of miners and for miner recovery in event
       o - disasters.

    -- Continially ide.tify new health and safety problems
       and de',elop advanced mining systems and subsystems
       to eliminate these hazards. 164/

     Some of the research efforts into health and safety have
been implemented by the coal industry. Accomplishments are:

     --Air curtain devices for protecting personnel from dust.

     -- Pneumatic drill mufflers to reduce noise.

     --W&ter infusion of     coal seams for dust control.

     -- Pumpable roof bolts for    improved roof support.

     -- Improved lighting systems for mining macnines.


      The scenarios of future energy demand used in this report
forecast that annual coal production will reach a level of
from 779 to 988 million tons by 1985 and from 942 to 1 586
million tons by the year 2000. The high scenario is a.. the
approximate range of President Carter's National Energy
Plan.   Coal production in 1976 was 665 million toils.

     The expected growth in the coal industry within the
1975 to 2000 period will require:

     -- Opening 438 to 825 new mines.

     -- Recruiting and training 288,300 to 531,600 new miners
        (current average emplo_ _nt is 208,000).

     -- Investing $26.7 to $45.5 billion in new capital.

      The short-run production capacity of the industry is
limited to what cah be extracted through increased pro-
duction (surge capacity) at existing mines.   In other words,
coal is usually demand-constrained in the long run and supply-
constrained in the short run.   In English, this means that
on the supply side significant amounts of time and effort
are required to open new mines. Given time, coal companies
can produce the coal if the demand is there. When conEtruc-
tion time, equipment acquisition, environmental and related
studies, permits, and so on are taken into consideration, it

     -- 1.5 to 3 years to open a surface rane in the East,

     --4 to 15 yE   £s for   · surface mine in the West,

     -- 2.5 to 5 years for an underground mine in the East, and

     --3 to 13.5 years for an under -      -- mine in the West.

     GAO uiscussions with 11 major coal producers (including
9 of the top 15 producers in 1975) showed all believed the
industry could duble production by 1985 and triple pro-
duction by 2000, assuming certain conditions. GAO believes,
on the other hand, that a number of factors, including long
leadtimes required to open mines, environmental constraints,
time problems in delivery of heavy equipment, capital problems,
and labor and productivity problems will delay beyond 1985
the achievement of a production l-vel of 1 billion tons,
let alone the 1.2 billion tons reflected in the National
Energy Plan. On the other hand, a level of 1.5 billion-tons
may be achievable by 2000 on the production side.   By then
the primary constraints will be on the demand side.

      In addition to environmental restrictions discussed in
chap:er 6, several other key factors affect coal production.
First is productivity, that is, the tons produced per
worker-day. Productivity has declined since 1969, especially
in underground mines. This can be attributed to:

     -- The 1969 Federal Coal Mines Health and Safety Act
        which increased the number of personnel in the mines.
     -- Changes in mining conditions such as widths of coal
        seams, distances from entrances of mines to the
        operation faces, and amount of overburden.
     -- Intrcduction of large numbers of inexperienced
        workers into the mines.
     -- Requirements for additional personnel in accordance
        with union agreements.
     -- Unscheduled interruption in production caused by
        wildcat strikes.
      Concerning the last item, it should be noted that in
years when a national agreement is renegotiated the lost
working time due to work stoppages is substantial. For
example, 8 percent of the total working time was lost in
1974 for this reason. Current agreements of the UMWA with
the coal companies expire December 6, 1977. The right to
3trike over local grievances is a major bone of contention
between labor and management.

     The second factor is industry structure. In recent
years, the coa3 industry has undergone significant change.
Major steel, utility, chemical, and metal companies have
accelerated their move toward coal self-sufficiency and,
like 'he oil companies, are aggressively acquiring small coal
companies and coal reserves. The trend is definitely toward

fewer but larger companies. These changes are thought to
have improved the capital position of what was once a capital-
starved industry.
     The third factor is worker availability and training.
Wages in the coal industry are higher than in many other
industries and should attract new miners. The training of
those new miners is a more significant problem. Industry
and Federal Government efforts in this regard need to be
more extensive.

     Fourth is the availability of mining equipment. If
there is adequate planning by the coal mining industry in
its ordering of equipment, the manufacturers should be able
to produce and deliver most of the machinery on time.
However, it appears that delivery of large draglines,
critical to big surface mining operations, could still be a

     GAO discussions with economists and experts in the
coal mining and financial communities indicated a consensus
that future coal projects should be able to receive financing
as long as coal demand remained reasonably good.
     Seven years have elapsed since the passage of the Federal
Coal Mine Health and Safety Act and some progress has been
made in mine health and safety records. But problems remain.
More needs to be done to reduce nonfatal injuries and to
achieve full Compliance with the dust standards.

     Statistically, min: :g remains more dangerous than other
major industrial occupations. Assuming that the fatality
and disability injury rates do not improve significantly
from the 1975 rate, GAO estimates that as many as 3,400
miners might be killed and 253,000 disabled in accidents
under the EEI scenario levels of production for the 1975 to
2000 period. Under the BOM scenario as many as 4,700 miners
might be killed and 351,000 disabled.

     The impacc of taxes upon the coal industry is very
uneven. Some taxes encourage increased production while
others discourage it. Coal mining receives a tax break with
a percentage depletion deduction of 10 percer' of gross
income, but the deduction must not exceed 50 perceit of the
taxable income. On the other hand, a tax benefit accorded
oil and gas but not coal is the treatment of intangible
drilling costs--these may be expensed or capitalized at
the option of the taxpayer without repaying the tax benefit.
In addition, a foreign tax credit is allowed on the Federal
tax return for imported oil and gas while only a deduction
is permitted for State taxes paid on domestic coal production.

These tax provisions put coal at a disadvantage compared with
oil and gas.

     State taxes on coal production vary widely. State taxes
such as Montana's 30 percent tax on the malket value of surface
mined coal may accomplish State goals, but such taxes, by
increasing production costs, may reduce the production of
coal and its consumption relative to other energy resources
such as imported oil anid gas. On the other hand, State
taxes are a means of internalizing into the price of
coal external socioeconomic and environmental coal costs.


 1/United States Bureau of M4ines,     'Weekly Coal Report No.
   3090", Mineral Industry Surveys, December 3, 1976, p. 3.
 2/United States Bureau of Mines, "Weekly Coal Report No.
   3092", Mineral Industry Surveys, December 17, 1976, p. 3.
 3/United States Bureau of Mines, "Bituminous Coal and Lignite
   in 1976", Mineral Industry Surveys, January 3, 1977.

 4/Bureau of Mines reply to request of Ken Hechler, Chairman,
   Subcommittee on Energy Research, Development and Demonstra-
   tion (Fossil Fuels), U.S. House of Representatives,
   Committee on Science and Technology, July 1]76, Issue
   No. 16.
 5/T. T. Tomimatsu and Robert E. Johnson, The State of the
   U.S. Coal Industry, Information Circular--70-7-TWasiington:
   BureTu o MRTies,-T976), pp. 8 to 11.
 6/Ibid., p. 4.

 7/Ibid., p. 9.

 8/Ibid., p. 11.

 9/Ibid., pp. 1, 5, and 6.
10/Howard N. Eavcnson, The First Century and a Quarter of
   the American Coal Industry (Pittsurgh -Bal-timore Waverly
   Printers,sTI42, pp7. 7-7 and 378.
 l/"Thi Yardstick of Productivity.     . Is ;t High Tons Per
   Mail-day Or Is It Low Cost Per Ton?", Coal Age, July 1975,
   p. 93.

12/Naticnal Coal Association, Coal Facts, 1974-1975, pp. 12
   and 82; Eugene R. Palowitch- an   1fi-n CoTwlne,-The
   Bureau's Program to Automate Longwall Mlining", Coal
   A e, July 1975, p. 122; Elchanan Cohn, et al., Th1
   Bituminous Coal Industrry:  A Forecast (University Park:
   'Th-ePennsylvania State UniverTity Institute for Research
   on Human Resourcas, 1975), p. 84; J. Richard Lucas,
   Manpower Requirements in the Coal Industry to 1985,
   NationaT Research ouncil -FeebtaryTT767 p -l.
13/"The Yardstick of Productivity", Coal Age, op. cit.,
   p. 94.

 14/National Coal Association, Coal Data 1975 Edition, pp. 15,
    26; United States Bureau of Mines, wrWeekly Coal Report
    No. 3092," loc. cit.; United States Bureau of Mines,
    "Bituminous Coal and Lignite in 1976," op. cit., pp. 1
    and 2; United States Bureau of Mines, "WeeklY-Coal Report
    No. 3090," op. cit., p. 3.
 15/Leonard 'Jesterstrom, Bureau of Mines, personal interview;
    Kramer Associates, Inc., Determination of Labor Management
    Requirements in the Bituminous Coal Industry -t Meet the
    Goals of Project Indep    enc'-for FEA (Wdshlngton:  Kramer
    Associates, Inc., 1975), pp. 13 to" .
 16/Nationai Coal Association, Coal Data 1975 Edition,
    fOw   cit., pp. 39, 69; United tates Bureau of Mines,
      wee1Tj; Coal Report No. 3090," op. cit., p. 4; United
    States Bureau of Mines, "Bituminous Coal and Lignite
    1976,"     _p.
                 cit., p. 2.
17,/United States Bureau of Mines, "Weekly Coal Report
   No. 3090," loc. cit.

18/Council on Wage and Price Stability, Executive Office of
   the President, A Study of Coal Prices (Washington: Govern-
   ment Printing Office- 167.Tpp. 7    to 39.
19/Sidney Katell, L. L. Hemingway, and L. H. Berkshire, Basic
   Estimated Capital Investment and Operating Costs for
   'nderground iituminous Coal- M-Tnes,Informatlon Circ-lar
    682AAW--isiington: GovernmeF-t'iinting Office. 1976),
   pp. 1, 11, 20, 29, 39; Sidney Katell, E. L. Hemingvay,
   and L. H. Berkshire, Basic Estimated Capital Invest.ment
   and Operating Cost for Coal Strip Mine, Informat..oi'--
   Circular 873 (Washlington: Government Printinr  Office,
   1976), pp. 1, 12, 21, and 30.

20/Katell, Hemingway, and Berkshire, Information Circullar
         8703, o.   cit., p. 6.

21/National Coal Association, Coal Data 1975 Edition, op. cit.,
   p. 69.
22/United States Bureau of Mines, "Weekly Coal Report
   No. 3056", Mineral Industry Surveys, April 9, 1976,
         p. 10.

23,'r.      T. Lethi. et al., Analysis of Steam Coal Sales and
         Purchases (McLean: MITRE Corporation, 1975), pp.
         and 52.

24/United States Bureau of Mines, "Weakly Coal Report No.
   3056," loc. cit.

25/ICF Incorporated, Coal Mine Expansion Stud   (Washington:
   ICF Incorporated, 19'7), p.

26/Bureau of Mines reply to request of Ken Hechler, o2. cit.,
   Issue No. 9.

27/National Coal Association, Coal Data, 1975 Edition, Op.
   cit., pp. 10 and 12; United States Bureau o--f
                                                Mines, Weekly
   'oal Report No. 3090," op- cit., p. 3; United States Bureau
   of Mines, "Bituminous Cial and Lignite." 1976, op. cit.,
   pp. 1 and 2.
28/GAO disaggregation is as follows:
        Eastern     - Alabama, Kentucky (eastern), Maryland,
                      Ohio, Pennsylvania, Tennessee, Virginia,
                      West Virginia
        Central     - Arkansas, Illinois, Indiana, Iowa,
                      Kansas, Kentucky (western), Missouri,
        Western     - Alaska, Arizona, Colorado, Montana,
                      New Mexico, North Dakota, Texas, Utah,
                      Washington, Wyoming.
29/ICF Incorporated, op. cit., pp. i, 2, 9, 11, 16, 18, and 23.

30/Ibid., p. 9.
31/Kramer Associates, Inc., op. cit., pp. 3 to 5, 12 to 14,
   and 18.

32/See footnote 28 for disaggregation data.
33/We estimated that 4.5 percent of the average work force
   would need to be replaced each year.
34/J. Bhutani, et al., An Analysis of Constraints on Increased
   Coal Productlon,-MTR-8-3U (McLeaTn  MITRE Corporation,
   T75), pp. 5-9 and 5-12.

35/Text of address by Mark Wesley A. Edwards, Manpower
   Requirements to Meet U.S. Energy Needs, at Westinghouse
   International Enviionmen-Tal anManaqement School, Fort
   Collins, Colorado, July 21, 1975, pp. 11 and 12;
   J. Richard Lucas, op. cit., pp. 8 and 9,

36/National Coal Association, Coal Data 1975 Edition, op.
   cit.,   p.   39.

37/Kramer Associates, Inc., op. csit., p. 14.
38/National Coal Association, Coal Data 1975 Edition, o.,
   cit., p. 31; United States Bureau77 Mines, "Weeki Coal
   Report No. 3092," op. cit., p.

39/United States Bureau of Mines, "Bituminour Coal and
   Lignite in 1976," op. cit., p. 2.

40/Beth Spence and Deborah Tuck, "There's No Place to Go,"
   United Mine Workers Journal, 87th year, Nc. 4, February
   1 7 ,7 pp.7 an-d 7.

41/Federal Energy Administration, Project Independence, Coal
   Task Force Rert (Washington: Government Printing Of-ice,
   1"/)O, p. 47-

42/UniLed States Bureau of Mines, "Upturn Reported in Mining
   School Enrollmnents", News Release, February 11, 1976, pp. 1,
   4, and 10.

43/Kramer Associates, Inc.,     op. cit.,   p. 43.
44/Royston C. Hughes, Assistant Secretary of the Interior,
   letter reply to Senator Henry M. Jackson, Chairman Com-
   mittee on Interior and Insular Affairs with respect to
   S. 62, November 3, 1975.

45/Mark Wesley A. Edwards, "Bituminous Coal Industry Labor
   Relations", Bureau of Mines unpublished paper, 1975,, pp.
   11 and 12.

46/Krimer Associates,   Inc.,   op. cit., p. 32.

47/S. W. Zanolli, Vice President, Industrial Relation, Kaiser
   Industries Corporation and Kaiser Steel Corporation,
   "Manpower and Manaaement Training and Development in the
   Bituminous Coal Industry", paper presented at 1976 Coal
   Show of American Mining Congress, t Detroit,   i--IEigan,
   May 113, 1976.

48/Kramer Associates,   Inc., op. cit., p. 5; J. Richard Lucas,
   o2. cit., p. 6.

49/Joseph P. Brennan, President, Bituminous Coal Operators
   Association, Inc., testimony before the Senate Committee
   on Public Works, June 11, 1975, pp. 7 and 8; United Mine
   Workers Journal, 87th year, No. 2 , December T-15, 1976,
   p. 11; Bureau of Labor Statistics, Current Wage Develo-
   ments, volume 26, number 12, DecewmbFTr97T4, p. 2.

50/Krame£ Associates,      Inc., op. cit., pp. 49 to 53.

51/Ibid.,    p. 45.

52/Kramer Associates,      Inc., op. cit., pp. 45 and 46.

53/Ibid., pp. 47 to 54.

54/Bureau of lines reply to request of Ken Hechler, op. cit.,
   Issue No. 17.

55/Kramer Associates,      Inc., op. cit., pp. 47 to 54.

56/Ibid.,    pp. 54 ana 55.

57/United States Department of the Interior, 1974 Annual
   Report of the Secretary of the Interior under the Federal
   coal Mine Health and Safety Act, part i, pp. 47-2,--23,,

58/National Coal Association, Coal Data 1975 Edition,
   op. cit., pp. 10 and 26; United States Bureau of Mines,
   "WeeI e Coal Repvrt No. 3092," op. cit., p. 3; United
   States Bureau of Mines, "Bituminous Coal and Lignite in
   1976," oo. cit., p. 2.

59/Robert L. Frantz (ed.), Developing Eastern Fossil Fuel
   Reserves (University Park: Pennsylvania State University,
   1T76),pp. 1 and 95.

60/See footnote 15.

61/Frantz,    op. cit.,   pp. 2 and 3.

62/Ibid., pp. 95, 100, and 101

63/Ibid., pp. 66 to 94.

64/IbiJ., pp. 7 and 8.

6',"'Productivity and the UMW," Coal Age, July 1975, p. 98.

 66/Frantz, op. cit., p. 103.
 67/Bituminous Coal Mine Operators and United Mine Workers of
    America, A Wage 1Ch ronoThog  E teer933 - N'oveiber 197-7
     iBulTeiTn i79 (Washington:  Government Printing Office,
    1973), p. 1; David B. Hecker, "Internal Politics Split
    Mine Workers Convention", Monthly Labor Review, Volume
    100, No. 1, January 1977, p. 61.

68/United States Bureau of Labor Statistics, "Bituminous Coal
   Industry, 1974", Collective Bargaining Summary (Washington:
   Bureau of Labor Statistics,        p. 5.
69/United States Bureiu of Labor Statistics, Current Wage
   Development, Volume 26, No. 12, December 1TT7 pp. 1 anrd 2.
70/United States Bureau of National Affairs, Inc., "Wage
   Patterns and Wage Data Coal", Collective Bargaining
   Negotiations and Contracts, January 2, 1975, P 18:6,
   p.   4.

7l/Hecker, op. cit., p. 58.

72/Ibid., pp. 58 to 61.
73/Ibid., p. 59.
74/Keith Dix, et al., Work Stoppages and the Grievance
   Procedure in thy Appchn CoalT Ind's-try (Morgantown:
   Institute fir Labor Studies, unated    pp. 61 and 62.
75/Ibid., p. 63.

76/Ibid., pp. 64 and 65.

77/Ibid., p. 66.
78/Hecker, op. cit., p. 60.

79/Dix, et al., op. cit., pp. 66 and 67.
80/United States Mining Enforcement and Safety Administration,
   "Coal-Mining Industry Fatalities in 1975", MESA Safety
   Reviews, January 1976, p. 7.

81/Frantz, op. cit., p. 285.

82/Ibid., p. 282.
83/Ibid., pp. 285 and 288.

84/National Coal Association, Coal Facts, 1974-1975, o2. cit.,
   p. 89; U.S. Mining Enforcement and Safety    Ii stration,
   "Coal Mine-Fatalities in November 1976", MESA Safety
   Reviews, Jenuary 1977, pp. 1 and 7 and "CoaT---Mlnng
   Industry Fatalities in 1975", op. cit., pp. 1 and 7.
86/Frantz, op. cit., p. 296.

87/United States Department of the Interior, 1974 Annual
   Report of the Secretary of the interior un`er the-
                    Health anda¢a       ,       op. clt.,
                                                        p. 5.
88/American National Standards Institute, Inc., Method of
   Recording and Measuring Work Iniury Experience,
   ANT-S1T .1-1
            T-67, December-77,  .  .7., pp. 7, 8,-9, and 12.
89/Frantz, op. cit., pp. 296 and 298.

90/R. C. Cinnemann, Corporate Safety and Health Policy
   (Greenwich:   AMAX, n   .,   9
                                97 --       -
91/United Mine Worker Jonrnal, 87th year, No. 20, 2oi    cit.,
   p. 11.
92/"The Yardstick of Productivity', Coal Age, op. cit.,
   pp. 93 and 94.

92/Federal Energy Administration, Project Independence, Coal
   Task Force Report; op. cit., pp. 49 to 51.  -
94/Bureau of Mines reply to request of Ken Hechler, op. cit.,
   Issue No. 9.
95/Richard J. Eielicki and David C. Uhrin, Coal Mine Equipment
   Forecast to 1985, Information Circular 87I-(Wasiting i --
   Government Printing Office, 1976!, pp. 9 to 35.
96/Bureau of Mines reply to request of Ken Hlechler, op. cit.,
   Issues l(a) and (b).
97/Ibid.; Federal Energy Administration, Project    Independene,
   - a- Task Force Report, op. cit., p, 49

98/Bureau of Mines reply to request of Ken HechleL, op. cit.,
   Issue l(a); Bielicki and Uhrin, op. cit., pp. 30,-31,and
   36; J. J. Davis Associates, Survey oEquipment Manufac-
   turing Research and Development Nees     Lean: J. 7. Davis
   AssociaT ees
             ST   575 pp. II-1 and II-11 to II-21.
99/GAO computation based on Bureau of Mines estimates of
   capital costs per annual ton of new productive capacity--
   $41 per annual ton for underground mine and $21 per annual
   ton for surface mines--and new capacity projectibns--
   additional and replacement mines.
100/Federal Energy Administration, National Energy Outlook
    (Washington: Government Printing Office, 1967), p. 307.

101/Wallace W. Wilson, "Financing New Coal Mine Development in
    the Decade Ahead," text of address presented to Amercian
    Mining Congress in 1976 Financial Conference, April 9, 1976,
    pp. 4, and 7 to 10; Wallace W. Wilson, "Coal Mine Develop-
    ment Financing During the Next Decade," text of address at
    Professional Lease Management, Inc., Second Coal Conference,
    March 10, 1976, p. 11; and Bankers Trust Company, Capital
    Resources for Energy Through the Year 1990 (New York:-
    tankerSTrust Company,    --7, pp.77   37 , and 33.
102/Bureau of Mines reply to request of Ken Hechler, op. cit.,
    Issue No. 16.

103/Federal Energy Administration, Project Independence Coal
    Task Force Reorr,   op. cit., pp. 21 and 22.

104/Frantz, op. cit., pp. 104 and 117.
105/Federal Energy Administration, National Energy Outlook, op.
    cit., p. 43.

'06/Tomimatsu and Johnson, op. cit., p. 32; Wilson, "Coal Mine
    Development Financing Du-ring the Next Decade", op. cit.,
    pp. 11 and 12; and Capital Resources for Energy-Throgh
    the Year 1990, op. cit., pp.-Ti2 aa-29.

107/Statement of Joseph Mullan., Vice-President, National Coal
    Association, before Senate Subcommittee on F:nergy Produc-
    tion and Supply, April 5, 1977; GAO computation based on:
    1976 Keystone Coal Industry Manual (New York: McGraw-Hill,
    Yi.,-3737-pp. 7T35 t-73-7.

108/Wilson, "Financing New Coal Mine Development in the Decade
    Ahead," op. cit., pp. 3, 4, and 14; Wallace W. Wilson
    statement beire the Senate Subcommittee on Antitrust and
    Monopoly, Committee on the Judiciary, July 14, 1975, p. 9.

109/Wilson, "Coal Mine Development Financing During the Next
    Decade," op. cit., pp. 10 and 11

110/Commerce Clearing House, Inc., 1977 United States Master
    Tax Guide (Chicago: Commerce CTi-eing House, Inc.,7T7),
    PP. T2-To 434.

111/Commerce Clearing House, Inc., Internal Revenue Code
    (Chicago: Commerce Clearing House, Inc., 179,    sections
    38 and 46.

112/Internal Revenue Service, "1972 Source Book of Statistics
    of Income", unpublished book, Washington, 1976, industry
    code 1100.

113/Internal Revenue Codt!,     Section 611(a).

114/Commerce Clearing House, Inc., 1977 United States Master
    Tax Guide, op. cit., ppo 434 co-4T7.

115/Internal Revenue Code, Section 612.

116/'Ibid.,   Section 613(a) and (b).

117/Ibid.,    Section 613(b);

118/Commerce Clearing House, Inc.,        1977 U.S. Master Tax Guide,
    op.   cit.,   p.   437.

1i9/Internal Revenue Code, Section 167(b),        (m), and Revenue
    Procedure 72-10.

120/Internal Revenue Code, Section 167(a).

121/Internal Revenue Code, section 187 (1976 el.).     Section
    187 has been repealed with respect   to taxable ye   s begin-
    ning after December 31, 1976.   P.L.  94-455 (October  4,
    1976), sections 1901(a)(31) and  1901(d).


123/Ibid., Section 48(a)(8).  As a result of the repeal of
    section 187, the reference to section 187 in section
    48(a)(8) has been deleted in the 1977 edition of the Code.
    See note 121 above.

 124/Ir.Lernal Revenue Code (1977 ed.), section 631(c).

 126/Ibid., Section 2 6 3(c).

 127/Breeding, BurKe & Burton, 1977 Income Taxation of
     Resources (Chicagu: Commerce Clear--ng Houe,· Inc. I97),
     pp. 112, 113, 120 to 122.
 1 28/Nutional
               Coal Association, Lal Data:    1971 Edition
      (Washington: National Coal Associa-ion,--rT75), p. 21.
 1 29/Prentice
              Hall, Inc., State Tax Guide:  All States
     (Englekod Cliffs:   Pren-Tc -HaT,- Inc.-T976), Illinois,
     para. 1360.
 130/Ibid., Ohio, pera. 1340.

 131/Ibid., Alabama, para, 1340.

132/Ibid., Kentucky, para. 1320.

133/Ibid., West Virginia, para. 1320.
134/Ibid., Pennsylvania, para.      1320.
135/Ibid., Illinois, rara. 1320.

136/Ibid., Ohio, para. 1320.

137/Ibid., Virginia, para. 1320.
138/Ibid., Indiana, para. 132J.

139/Ibid., Alabama, para. 132,.
140/rbid.,   Wyoming, para. 1010.
141/Ibid., Montana, oara. 1320.
142/Ibid., New Mexico, para. 1320.

143/Ibid., Pennsylvania, para. 1330.

144/Stephen C.M. Long, "Coal Taxation in the Western States:
    The Need for a Regional Tax Policy,' Natural Resou'ces
    Journal, vol. 16, April 1976, p. 15.
1 4 5/Prentice
                 Hall, Inc., op. cit., IllinJis, para. 1340.

146/Ibid.,   Indiana, para 1340.
147/Commnerce Clearing House, Inc., State Tax Rea2orts: West
    Virginia (Chicago: Commerce Clearing House, Inc., T773),
    para. 650.
148/Prentice Hall, Inc., op. cit., West Virginia, para. 1320.
149/Commerce Clearing House, Inc., State Tax Reports: Kentucky
    (Chicago: Commerce Clearing House, Inc., W76), para. 650.

150/Prentice Hall, Inc.. op. cit., Ohio, para 1430.

151/Statement by W. Luke Witt, President, Virginia Coal
    Association, telephone interview, September 21, 1976.

152/Prentice Hall, Inc., op. cit., Alabama, para. 1430.

153/Ibid., Wyoming, para. 1430.
154/Statement of Pat Hooks, Mcntana Coal Council, telephone
    interview, September 29, 1976.

156/Statement by Bill Darmitzel, New Mexico Mining Associa-
    tion, telephone interview, September 23, 1976.

157/J- J. Davis Associates, op. cit., pp. II-38 to II-41;
    Dean Witter and Company, Inc., Dean Witter Research "The
    Coal Observer" R49, January 30,-T76, pp. 4, 5, and 6;
    Dean Witter and Company, Inc., Dean Witter Research "The
    Coal Observer, R 350/86-09, Auoust 3       7=6, pp. 13 and 14;
    Carl E. Bagge, "Coal and the Public Lands and Why the
    Former Isn't Coming from the Latter When the Nation Needs
    It; A Case Study in National Masochism" text of address
    before the Rocky Mountain Energy - Minerals Conference,
    Billings, Montania, October 1.5, 1975; Wallace W. Wilson,
    "Capital for Coal Development", text of address at Coal
    Age - Coal Week - AMR Conference or Coal Energy,
    Washington, D.C., November 21, 1975, pp. 10 to 13; James
    R. Jones, "Coal Mine Permits - The Importance of Timing"
    paper presented at 1976 Coal Show of American Mining
    Congress at DetroiticT-Tcgan on May 11, 1976; T;le
    Obstacles to Coal Development", Society of Miring
    Engineers, May 1975, pp. 34 to 37.

159/Bureau of Mines reply to request of Ken Hechler, op. cit.,
    Issue No. 9.

160/See footnote 157.

162/Unite.d States Bureau of Mines, Bureau of Mines Strategic
     and Tactical Plan, draft reports(Waiington: Bureau of
    WRIne?7s   7T7 , p. iv.18.
163/United States Bureau of Mines, Mining Research Review,
    June 1975, p. 4.
164/United States Bureau of Mines, Mining Technology Research.

                          CHAPTER 5

     An effective and efficient transportation system is
essential to permit coal to play a major role in meeting the
Nation's future energy needs. While production capabilities
must be greatly expanded to nieet the future demands of utility
and industrial consumers, the development of adequate trans-
portation capabilities is equally important to insure that
the increased coal output will be move, from mine to user.
Scenarios forecasting production increases from the 1976
level of 665 million tons to as much as 988 million tons in
1985 and 1.586 billion tons in the year 2000 also entail a
need to expand transportation system capabilities accordingly.

     The existing system, comprised primarily of railroad,
barge, and truck transport, has demonstrated its ability to
move the current level of coal output and to handle tempo-
rary demand surges, as was demonstrated during and after the
oil embargo. But, increased output will, in some instances,
place added burdens on currently marginal system capabilities
which already require improvements. More importantly, however,
potential increases in coal production, particularly in the
West, will place new demands on the Nation's coal, transpor-
tation system that must be met by building new facilities
and expanding existing capabilities.
     Future coal transportation requirements can be met, but
Federal action may be needed. The railroads have the capabi-
lity to expand, but expansion will not be without problems,
particularly capital acquisition. Resolving uncertainties
afrecting future coal traffic volume would assist the rail-
roads in planning and acquiring capital for expansion. The
environmental impacts of increased rail coal traffic on cer-
tain communities en route may be severe.   In the East and
Midwest, Consolidated Rail Corporation's (Conrail's) rehabili-
tation efforts will need to include actions to insure that
its coal-carrying capabilities are upgraded.
     Coal slurry pipelines* are a possible option for moving
coal in certain cases. Some significant environmental and
institutional problems will need to be resolved. Development

*A pipeline which transports fine particles of coal sus-
 pended in a liquid carrier, such as water.

is being hindered by difficulty
Development could be additionallyin assembling rights-of-way.
water at the points of origin,     affected by shortage of
by environmental problems causedparticularly in the West, and
destination.                      by effluent disposal at the

     Expanding inland waterway
to substantially increase coal capacity may also be necessary
                                barge traffic.
     The more important aspects
                                 of the total transportation
issue are:

    -- Adequacy of the Nation's
                                transportation system to
       move coal.

         --Future coal transportation
    -- Railroad expansion capability
       production.                    to handle future coal

        -- Future rail coal traffic.
       -- Railroad plans to meet 1980
                                      coal transportation
       -- Ability of railroads to
                                   acquire the capital
          needed to finance expansion.
       --Environmental impacts of
                                    rail coal traffic.
       -- Adequacy of Conrail's rail
          tu efficiently transport increased and its ability
                                              coal traffic.
       --Adequacy of rolling stock
                                   to move anticipated
         future coal output.
   -- Role of coal slurry pipelines
      coal.                         in the development of

      -- Coal slurry pipelines and
                                   the Federal power of
         eminent domain.
       --Adequacy of water for slurry
                                       pipeline use.
       --Disposal of effluent from
                                   slurry pipelines.
  -- Capability of inland waterway
     future coal transportation    system to meet


      Coal moves from mine to user principally by rail,
water, and truck. Tramways, conveyors, and pipelines
each transport lesser quantities. As an alternative to
moving coal itself, coal can be converted to electricity
by generating plants near the mine and the energy transmitted
by wire to consumers. When the technological and economic
problems are solved, the same approach would be possible
for synthetic gas converted from coal at the mine and trans-
ported to the user by pipeline.
     Coal shipments by the various modes of transportation
from 1973 through 1975 are shown in table 1. 1/ Railroads
carried about 65 percent of the coal traffic -n 1975, compared
to about 69 percent in 1973.

Note:   Numbered footnotes to ch. 5 are on pp. 5.32 to 5.37.

                               Table 1
                        1973-75 Coal Shipments
                  by Mode of Origination (note a)

    Mode of
 transportation                          1973      1974       1975
                                         ----- (million tons)-----
      Rail                               397.2     397.2      418.1
     Water                                68.6      67.8       69.1
     Truck                                57.3      66.4      79.4
     Used at mine-mouth generating
       plants                             64.4      66.6      73.5
       (including slurry pipeline
       and miscellaneous use at
       mine)                               4.3       5.5       8.3
         Total output                    591.8     60395     648.4
a/This table shows shipments by originating modes
  modal transfers, particularly between rail and water, inter-
  increase the total coal traffic handled by these modes
  substantially. For example, total coal traffic moved
  water in 1974 amounted to 141 million tons, including by
  tonnage originated by other modes, but delivered to    the
  by barge. 2/

     Transportation costs represent a major portion of
delivered price of coal.                                the
                          These costs range from approximately
25 percent of the cost of coal delivered from eastern
fields to as much as 75 percent or more of the delivered
of coal shipped from Montana and Wyoming to electric
ties in the Midwestern States. 3/ From 1974 through   utili-
                                                      1976, rail
transportation costs accounted for the following percentages
of the delivered coal price. 4/

                                Table 2
                   Average Rail Transportation Share
                         of Delivered Coal Prices
         Price per ton   Average           Delivered    Transportation
Year      f.o.b. minne rail charge        price per toi     share

1974           $15.75         $4.71            $20.46             23
1975             19.24         5.25             24.49            21
1976 (note a) 20.00            5.75             25.75            22

     A sample of selected coal-using utilities, repurted
in an April 1975 MITRE Corporation study entitled "Analysis
of Steam Coal Sales and Puirchases," showed that transportation
costs varied from $0.47 a ton to $10 a ton, depending on dis-
tance and mode of transport. 5/

     Of the three currently most prevalent modes of coal
transport, barge hauling ranks as the least costly, followed
by rail and truck. 6/

                              Table 3
               Comparative Modal Costs per Ton-Mile
           Mode of                               Approximate
       transportation                               cost
           Barge                              $0.003 to $0.004
          Rail                                          .01
          Truck                                         .05
     A recent Bureau of Mines study of alternative electricity
costs based on four western coal transportation alternatives
indicated that slurry pipeline costs would be comparable to
rail costs, but the cost of generating electricity near the
mine and then shipping it by extra-high-voltage transmission
lines was found to be about 30 percent higher.  (See table
12, p. 5.25.) 7/

Future coal transportation needs
     If future coal traffic by the various modes were projected
in the same ratio as they were in 1975, the 1985 and the
year 2000 BOM and Edison Electric Institute scenarios output
levels would be allocated as shown in table 4. 8/

                                Tatle 4
                 Future Coal Transportation Shares

                        1975            - 1985" '·     - 2-00U
                       actual          EEI    BOM     EEI    BOM
                       ------------- (million tons)----------
Rail                     418          503      637    608   1,023
Water                     69              83   106    101     170
Truck                     79              95   120   115      193
Mine-mouth use            74              89   113   107      181
Other (including
  slurry pipelines)        8               9    12    11       19
       Total output      648          779      988   942    1,586

      If production increases, vast quantities of coal will
have to be moved from areas served by transportation systems
which, if not improved, co-ild prove inadequate to the task.
Western coal production, for example, may increase nearly
fivefold by 1985 over 1974 levels and will require major
improvements to existing western rail systems or supplemen-
tation with alternate modes of transportation such as slurry
pipelines. Increased ccal production will also place added
demands on eastern rail systems and on the Nation's inland


      Railroads will be the principal mover of U.S. coal in
the foreseeable future. The waterway system does not directly
serve many of the areas scheduled for major coal development
and is limited in its capability to expand by the present
physical capacity of its locks system. There are also prob-
lems with ice in the winter.   The trucking industry
cannot compete with the railroads from a cost standpoint for
high-volume, long-distance traffic. Large-scale generation
of electricity near mines and long-distance transmission by
extra-high-voltage lines over great distances is unlikely
in the short term due to higher costs resulting from trans-
mission losses* and may also be limited in some areas by
regional shortages of water necessary for steam generation
as well as public opposition because of environmental impacts.
A proposed alternative to railroads for high-volume long-
distance shipment--the coal slurry pipeline--is presently
hindered by difficulties in obtaining rights-of-way and could
prove infeasible due to shortages of water in originating
regions, as well as the environmentiL and economic aspects
of disposing of the effluent at the receiving end.

     Production of coal-based synthetic high-Btu gas in
large quantities is not anticipated in the near future. 9/
When synthetic high-Btu gas becomes economically producible,
it is expected to be transported to the extent possible by
the existing natural gas pipeline systems. 10/ If low-Btu
gasification is used, a separate, larger capacity pipeline
system would have to be installed.

     The future of coal transportation through 1985, there-
fore hinges primarily on the railroads' capability to expand
and improve their existing facilities, although the alternate
modes will play important roles in meeting future requirements.
Future rail coal traffic

     Thrcllqh 1980, railroads anticipate a large increase
in coal traffic, as illustrated by information developed
during a recen.t survey of the major coal-carrying railroads
sponsored by the Department of Transportatior,'s (DOT's)
Transportation Systems Center (TSC). 11/ The railroads
surveyed originated 93 percent of the total 1974 rail coal
traffic. 12/

*To offset losses experienced over the length of trans-
 mission lines, larger powerplants with greater coal
 consumption would be required than would be needed if
 bulk coal were transported to the user.

    By 1980, these railroads anticipate
    the 1974 coal traffic originations. a 95 percent increase over
                                          The railroads' expecta-
    tions may be optimistic* but they
                                       do indicate an awareness
    of the magnitude of their potential
    projections of 1980 coal traffic     expansion needs. Their
                                      originations are shown
    below. 13/

                                    Table 5
                         Originated Coal Traffic
                       1974                    1980
    Rail       Mi    Mll-on Percent      Million Percent    Percent
    district**    tons      of total      tons   of total   increase
    Eastern       195        52.6             288    39.8     48
    Western        66        17.8             279    38.5    323
    Southern      110        29.6             157    21.7     43
        Total     371       100.0             724   100.0     95

     The railroads surveyed expect
in originated coal traffic to occur the most dramatic increase
by western railroads--323 percent.   in the areas served
development of the vast reserves     This  is attributable to
Western States--principally Montana  low-sulfur  coal in the
                                     and Wyoming. Coal from
this region is expected to move more
markets in Midwestern                 than 1,000 miles to
                      and South Central   States. 14/

*    Railroads' plans may have been moderated
     vey repcrt was issued in April 1976.     since the TSC sur-
                                           TSC has since under-
     taken a new survey of rail coal transportation
     1985.                                          needs through

**Western rail district consists
  Mississippi River; Southern rail all States west of
                                    district includes Kentucky
  and North Carolina and all other
  east of Mississippi River; and theStates south, as well as
                                      Eastern rail district
  includes all States north of Kentucky
  and east Gf Mississippi River.         and North Carolina

     Traffic increases originating on eastern and southern
rail district lines, although not as spectacular as those
anticipated i, the West, will still be substantial. Eastern
coal originations are projected to increase by 48 percent,
principally from West Virginia, Pennsylvania, and Kentucky.
Traffic originating on southern rail district lines is
expected to increase by 43 percent, moving coal from Eastern
and Central region coalfields to Southern and Southeastern
States. 15/
     Major coal traffic originations by State, as projected
by the railroads, are shown in table 6. 16/

                           Table 6
         Projected 1980 Rail Originated Tonnage Sby    tate
       (States with over 1 million tons of rail originations)

           State                       Rail originated tonnage

         Alabama                                13.0
         Colorado                               c0.2
         Illinois                               66.6
         Indiana                                17.9
         Kentucky                              119.8
         Maryland                                2.0
         Montana                                51.3
         North Dakota                            3.3
         Ohio                                   25.3
         Pennsylvania                           57.6
         Tennessee                               7.5
         Texas                                   8.1
         Utah                                   14.2
         Virginia                               54.7
         West Virginia                         116.9
         Wyoming                               135.0
              Total                           713.4

      The recent TSC-sponsored survey showed that
                                                   in 1980 coal
 would generally move in the following patterns.
 Coal traffic originations b~
                                             Would move to markets in
 Western rail district lines in
   -- Norti-rn Great Plains coal             -- Midwestern and South
      fields                                    Central States
 Eastern rail district lines in
   -- Appalachian coalfields                 -- 36 States but predomin-
                                                antly to Midwestern and
                                                Atlantic Coast States
 Southern rail district lines in

   --Appaldchian and Mideastern              -- Sout ern and South-
     Interior coalfields                        eastern States
   --Midwestern InterioL coalfields          -- Midwestern States
Railroad plans to meet 1980 coal
transportatin-reui remerEts
     The railroads surveyed by TSC planned large
in hopper cars, lo ),motives, and physical
to provide for additional coal traffic,    plant improvements
                                         as shown in table
7. 18/

                               Table 7
       Planned RKilroad Investment to Meet 1980
                                                Coal Needs

                                           Rail district
 Investment category       Southern        Western        Eastern          Total
                                            ---~Tnm(Tmil 1 ons)            --
Hopper cars (note a)     b/$667          b/$1,044    b/$1,189          $2,900
Locomotives                b/60             b/539         b,/66                 665
Physical plant              242             1,135             182          1,559
Maintenance facilities        I               102             -                 103
                          $T7f            $ 20
                                             -_,8        $1       $1,227
a/Includes replacement of retired equipment.
b/astimated based on TSC survey breakdown
                                          of regional
  or hopper car/locomotive requirements.

      The planned capital investment in physical plant shown
above does not include Conrail's rehabilitation prngram which
totals about $4.9 billion over a 10-year period (See p. 5.19.)
Conrail'sa program includes improvements necessary to move
many commodities and does not relate exclusively to coal.
    Wtstern railroad expansion requirements

     As noted before, the most dramatic increase in coal traf-
fic is expected in the West. Their planned expansion require-
ments call for 29,000 new hopper cars 19/, 1,500 new 3,000-
horsepower locomotives 20/, and over $1.2 billion in fixed
plant expenditures.

     The major movers of western coal during 1975 are shown
in table 8. 21/

                           Table 8
            Principal Rail Carriers of Western Coal

                                   1975 coal traffic
                              Originatbd    Total movements
                                      (million tons)
Burlington Northern                36.2            39.0
Chicago and Northwestern            3.8            16.1
Union Pacific                      12.4            15,4
Denver and Rio Grande
  Western                          10..            13.0
    Total                          63.3            83.5

     A recent study by the Federal Energy Administration's
Office of Coal, entitled "Coal Rail Transportation Outlook,"
included the following comments on the status and problems
of these lines: 22/
     Burlington Northern
     "The Burlington Northern is by far the most optimistic
of the coal carrying railroads over expected traffic growth
in that fuel during the next decade * * *

     "BN [Burlington Northern] predicts a growth in coal
carried of from 16 million tons in 1974 to between 140 and
150 million tons by 1980. While no solid projections have
been made beyond this, railroad spokesmen say that some
predictions have indicated total coal volume of 225 million
tons by 1985, and this is being used as a 'target.' * * * The
company's track is generally in adequate condition for near
term traffic needs, and is continually being upgraded. * * *

     "Most of the   BN's self-originated coals which, as noted,
come from Montana   and Wyoming, is delivered to Texas, the
Northern midwest,   and to Mississippi River points for
transfer to other   railroads or barges for final
delivery. > * *

     "Future competition may develop from coal slurry pipe-
lines now being considered or planned for the west. BN says
that 25 million tons of coal traffic per year, which one
planned pipeline would haul from Wyoming to Arkansas, would
mean $150 million per year in coal freight revenue lost to
the railroad. * * *

      "BN expects unit trains[*] in operation to increase from
55 per week to about 200 by 1985. * * * To meet a five-fold
coal traffic increase by 1982 would not pose insurmountable
problems, since it is already expected to handle almost a
four-fold increase by 1980. * * * The company now foresees
a need to finance road and equipment improvements of about
$1 billion. This will include substantial ballasting and
rail replacement work, on one route in particular. * * * It
will be necessary to sell a large bond issue or issues to
raise the necessary funds. * * *

     "The BN, along with several other roads, also has
advocated a statutory authorization of a freight rate
structure that would make possible long term rate
assurances to provide rail shippers with incentives
for initiating and continuing rail use for substantial,
predetermined periods.

*Defined as a complete train of dedicated cars on a regularly
 scheduled cycle movement between a single origin and a single
 destination. Coal unit trains typically consist of over 100
 cars of 100-ton capacity each. 23/

      "Under the Interstate Commerce Commission interpretation
of the Interstate Commerce Act, freight rates are now
filed for a 12 month period.* Although they are usually
renewed at the same level, there is not assurance that
they will be, and thus railroads feel they are at a
disadvantage in negotiating coal carrying agreements
at a specific and foreseeable level over a period of
several years." 24/

     Chicago and Northwestern
     Transportation Company
     "A large coal traffic increase is expected by 1985
due to the new 116 mile rail line to be constructed
through the Powder River Basin coal deposits in Wyoming.* * *
Future coal traffic increases will originate along the
new railroad line in Wyoming for Texas, Arkansas, Illinois,
and Wisconsin markets. Present coal traffic volume is
up over last year. A five-fold increase by 1982 would
require a considerable investment to upgrade track and
increase the number of hopper cars and locomotives.
What is needed to accomplish such a feat are iron-clad
contracts. Unit trains average about 35 per week and
are on the increase. * * * No constraints are expected
to coal traffic increases as the railroad is currently
expanding. This expansion is contingent upon the coal
production in Wyoming coming on line." 25/

    Union Pacific Railroad
     "Due to the increase anticipated for western coal
production, a moderate increase in coal traffic is
expected by 1985. * * * The rail beds are upgraded to
carry 100 ton cars. Current track speed is 40 mph loaded
and 50 mph empty. Continual upgrading of the track will
allow this speed to increase slightly by 1985.

     "The principal area of coal origin is southern Wyoming,
and this coal is consumed in the Mid-dest. Unit train
use is on the increase and currently averages 23 per
week. * * * A planned coal slurry pipeline will be in
direct competition for coal traffic, and to a lesser

*According to the Interstate Commerce Commission, Burlington
 Northern is referring to "annual volume rates," which have
 been limited by the Commission to periods from 12 to 18
 months. Annual volume rates require that a shipper in a
 designated period tender a specified amount of freight to
 qualify for a reduced rate.

 degree so is the Burlington Northern, but there is no
 competing barge traffic. * * *

      "A five-fold increase in coal carrying could be main-
 tained without undue strain on the system. No significant
 constraints exist that would prevent the rapid expansion of
 coal traffic capacity.

      "Here the potential coal traffic capacity exists.   The
 problem is to get increased western coal demand and
 increased western coal production." 26/

     Denver and Rio Grande Western Railroad

     "Large increases in coal traffic are anticipated due to
an expected increase in the use of low sulfur western coal
by 1985. * * * The rails are set up to handle 100-ton unit
train cars with a track speed maximum of 50 mph loaded and
70 mph empty. The tracks are continually being upgraded.
     "Most of the coal originates in Colorado and Utah. * * *
Unit train use is on the increase and averages 25 per
week. * * *

      "Corporate planning is indefinite due to the
uncertainties of government actions and a national energy
policy. The railroad maintains that if an energy emergency
develops political action cannot substitute for a 2- to 3-year
lead time required to plan, purchase, and manufacture the new
facilities to carry expanded coal traffic." 27/

     Western railroad expansion

     A 1975 study by BOM concluded that:

     "The capacity of the railroads to cope with substan-
     tially more western coal does not seem to be an unduly
     serious matter. The railroads can probably enlarge their
     capacity to handle larger amounts of coal as rapidly
     as their potential competitors [i.e., coal slurry
     pipelines] can be constructed. * * * This is not to
     imply that improvements in the western rail systems
     are unnecessary. But the basic requirements are there
     or can be met without having to endure long delays in
     meeting the conditions of high-standard service." 28/

     Our discussions with selected western carriers--the
Burlington Northern, the Denver and Rio Grande Western, and
the Union Pacific--and with DOT officials of the Federal Rail-
road Administration and TSC corroborate this conclusion.

A key underlying factor is that less time is required to ex-
parnd rail facilities than to construct new mines or electric
utility powerplants.
     However, western rail expansion will not be achieved
without problems. These problems will include:

     -- Acquiring sufficient capital, hindered by
        uncertainties over future western coal
        development and slurry pipelines.
     -- The environmental impact of increased western
        unit train traffic.
Capital acquisition problems

     Capital requirements for expanding the coal carrying
capacity are larger in the West (see table 7, p. 5.10) than in
the East and South, where lesser percentage of increases
are expected (although Conrail will require massive

     DOT and railroad officials contended that the railroads'
ability to raise capital could be affected by uncertainties
as to future coal traffic volume caused by:

     -- Uncertainties as to the impact of air quality
        restrictions on the type and source of coal that will
        be demanded in the future (i.e. western low-sulfur
        coal versus eastern coal). 29/
     --The possibility that coal slurry pipelin es could receive
       the Federal right of eminent domain and threaten to
       draw off some of the profitable high-volume rail coal
       traffic. 30/
     --The inability ,,nder the Interstate Commerce Commission's
       (ICC's) interpretation of the Interstate Commerce Act
       to enter into long-term (volume) rate agreements with
       shippers at reduced rates that would provide shippers
       with the incentive to initiate and continue rail use
       for substantial predetermined periods. 31/

     Railroad practices which have tended to alleviate
rail capital acquisition problems and shift the capital
burden to shippers are:

    -- Ownership of unit train rolling stock by coal
       producers and utilities.

      -- Spur line financing by shippers, the cost of which
         is refunded by the railroads during an initial
         predetermined period of operation.

      Uncertainty of the future role
      of western low-sulfur coal
     Future governmental actions to resolve energy/environ-
mental conflicts could have a major effect on demands
for western coal.  For example, a relaxation of air quality
standards to permit greater use of high-sulfur eastern coal
could substantially lessen anticipated demands for western
low-sulfur coal. Recently enacted surface mining legislation
will also affect western coal development. In view of the
uncertainties in demand and the related lack of assurance
of future traffic and revenues, the railroads face difficul-
ties in planning and acquiring capital for expansion.

     Uncertainty created by proposed, large-scale
     slurry pipeline development
      Should the several proposed slurry pipelines (see p. -
 -.22) be constructed, the railroads fear that the pipelines
  ould draw off the more profitable high-volume coal traffic.
Railroads contend that this uncertain prospect, valid or not,
raises doubts as to future revenues, affecting the willingness
of investors to provide capital for expansion. 32/

     In addition, railroads point out that, ir.their role
as common carriers, they would be required to carry increasing
volumes of coal in the period before pipelines are constructed
and would be faced with losing this business, curtailing
operations, and laying off employees when pipelines are finally
completed. 33/

     Slurry pipeline advocates contend, however, that
road jobs will be lost because coal pipelines will not noreplace
rail business. Railroads will handle increased coal traffic
in the West even if slurry pipelines take a share of the ex-
panding market. 34/

     ICC prohibition of rail contract
     rate agreements
     ICC's interpretation of the Interstate
which has precluded long-term contract rate Commerce Act,
denies railroads a tool which could facilitate rail planning
and financing.

     The act does not specifically authorize or prohibit
railroad use of contract rates. However, ICC's inter-
pretation of the act, as evidenced by previous commission
decisions, is essentially based on the premise that
contract rate agreements except in limited circumstances
constitute a "destructive competitive practice," as described
and prohibited by the National Transportation Po: icy. 35/

      Railroads point out that, of the three cooperating
businesses involved in coal transportation--the mining
companies, the power companies, and the railroads--only
the railroads are without long-term contract protection
for their substantial investment. 36/ To encourage capital
investment and thus assist in the rehabilitation and re-
vitalization of the railway system, Congress enacted section
206 of the Railroad Revitalization and Regulatory Reform
Act of 1976 (P.L. 94-210). This section, which adds subsec-
tion 15(19) to the Interstate Commerce Act, authorizes the
publicatior of capital incentive railroad rates if a rail-
related capital investment of $1 million or more is made by
carrier, shipper, or third party. Such rates may remain in
effect for five years, subject only to adjustments to meet
variable costs of the railroad. Railroads and shippers are
thus assured a greater degree of certainty to predict the
effect of a major investment on their future operations.

     Long-term contract rate agreements could provide shippers
with greater assurance of transportation costs at foreseeable
levels and with the incentive to initiate and continue rail
use for substantial predetermined periods. This, in turn,
could provide railroads with assurance of long-term future
revenues which the railroads consider necessary for planning
and capital acquisition. 37/
Environmental impacts of expanded
Western rail coal traffic

      Most western coal output will be handled by 10,000-ton-
capacity unit trains dedicated to continuous service between
the mine and the user. 38/ FEA reported in its May 1976 "Coal
Rail Transportation Outlo-ok" that the four major western
coal carriers were operating an average or 138 unit trains a

                              Table 9
                  Weekly Unit Train Traffic of
                Principal Western Coal Carriers

                                            Number of unit
            Railroad                        trains a week
     Burlington Northern
     Chicago and Northwestern
     Denver & Rio Grande Western
     Union Pacific

      By 1985 unit train traffic is expected
 fold. The Burlington Northern, for example, to expand several-
 about 200 unit trains per week by 1985.      expects to operate

     Increased unit train traffic could have
                                              a major impact
on communities en route, interrupt motor
subject community residents to increased  vehicle traffic, and
tion. Some Wyoming communities could      noise and air pollu-
of between 30 and 48 unit trains a day experience coal traffic
rail traffic. 39/                       in addition to other

       Public concern over the environmental
 ing unit train traffic is causing citizens' impacts of increas-
 groups to seek closer Federal scrutiny         and environmental
                                          of coal traffic buildup.
 The Sierra Club, for example, has filed
 District Court to require ICC to more     suit in the U.S.
                                        closely examine the
environmental impact of a PIroposed 116-mile
jointly constructed by the Chicago and          coal route to be
                                         Northwestern and the
Burlington Northern through the Wyoming
to the Sierra Club, the route could carrycoalfields. According
daily through a number of small towns.       as many as 48 trains
      Action will be required to reduce the
                                              safety hazards and
disruption of vehicular traffic and
                                      community services that
may be caused by unit train operations.
improvements such as overpasses, crossing Grade crossing
                                             gates, and
warning lights will be needed.

     Presently, the railroads and affected communities dis-
agree over who will bear the cost of these improvements.
Railroads have contended that grade crossing improvements are
not their responsibility, and affected communities seem un-
likely to receive financial assistance from the rail
industry. 41/ However, Federal funds are available to the
states for construction of highway overpasses and grade
crossing improvements under provisions of title 23, United
states code (which contains the Federal Aid Highway legis-
lation), some of which could be used to help alleviate railway
and highway crossing problems caused by unit train traffic.
Conrail's system rehabilitation needs
     Increased coal production will require expanded rail
transportation capabilities in the northeastern and mid-
western areas served by Conrail, the federally subsidized
consolidation of insolvent eastern and midwestern railroads
established under the Regional Rail Reorganization Act of
1973 (Public Law 93-236). The Railroad Revitalization  and
Regulatory Reform Act of 1976 made $2.1 billion available
to Conrail for system rehabilitation. The United States
Railway Association (USRA) has monitoring responsitility
and authority over Conrail funding. According to a recent
FEA coal transportation study, the Penn Central--the Nation's
second largest coal handler and Conrail's major component--
anticipates an increase in its total coal traffic from about
75 million tons in 1974 to 225 million tons in 1985. 42/
     Deferral of maintenance by the insolvent lines has led
to accelerated physical deterioration and operational
deficiencies, thereby impairing Conrail's coal handling
capability. FEA has observed that a large portion of Penn
Central's track is in poor condition, causing reduced speeds
and costly derailments. Massive upgrading of track and able
rolling stock are needed to assure that Conrail will be
to transport the projected volumes of coal. 43/
     Conrail has undertaken a $4.9 billion, 10-year program
to upgrade and maintain its 16 State right-of-way. As part
of the program, about 1,100 miles of rail will be improved
annually. The program will be completed in 1985 and is
expected to ultimately result in greater car utilization
and faster service. 44/

     However, right-of-way rehabilitation is given priority and
is funded on the basis of traffic volume handled (i.e. those
lines carrying the highest traffic density receive the highest
priority). Conrail officials pointed out that coal lines
wire not, in all cases, among the highest density lines and
may not receive the highest priority in rehabilitation plan-
ing. However, Conrail officials commented that additional
rehabilitation of spur lines serving coal producers could be
accomplished if the shippers provided funding which Conrail
would refund during the initial five years of shipments. 45/

     An FEA in-depth study of Conrail's coal transportation
needs and plans is scheduled to be completed in 1977.
     Conrail's rehabilitation requirements are numerous
and the amount and timing of resource allocation to coal
service could be critical to Conrail's future coal handling

Availability of rolling stock to
move anticipated
             f   Tuture coal
                          ou   tput
     Shortages of hopper cars have been mentioned as a possible
constraint to transportation of future coal output. The
existing fleet of hopper cars totals about 363,000, including
railroad and shipper-owned cars. 46/ Either the fleet
will have to be expanded or car utilization will have to be
improved to accommodate future coal transportation demands.

     Estimates of future hopper car needs can vary, depending
on the assumptions made as to the trend or future car
utilization. For example, BOM, in its "Coal Transportation
Practices and Equipment Requirements to 1985," estimates
that total hopper car requirements for coal production at
the 1.2 billion-ton level could range from 604,500 to
642,500, assuming that current car utilization rates prevail
through 1985. On the other hand, if the best possible
car utilization is achieved, BOM estimates that about
25 percent of the total hopper car requirement, or 125,700
to 141,500 cars will be needed. 47/

     It is clear that the railroad industry's ability to
improve car utilization can dramatically change the number
of hopper cars needed. On the basis of our review of existing
studies and discussions with railroad and DOT officials, we
believe the trend toward more efficient utilization will
continue through further expansion of unit train operations
and improved traffic management, and car requirements will
be considerably less than BOM's estimated maximum requirement.

     Using a study performed by the MITRE Corporation for
the Department of the Interior as a baseline 48/, we estimated
the following hopper car requirements needed to handle the
scenario levels of coal output. 49/
                              Table 10

               Estimated   Hopper Car Requirements
                       as of 1985 and 2000

                              EEI              BOM
                            scenario         scenario
        1985                  220,000         232,000
        2000                  229,000         263,000

The MITRE study assumes that most future increased coal traffic
will be moved by unit trains.
     Annual car-building requirements to prcvide replacements
for retirements front the existing fleet and to add new cars
to handle increases in coal traffic are projected as shown
in table 11. 50/
                           Table 11

           Average Annual Hopper Car Requirements
                                  EEI                  BOM
                                scenario             scenario

    Through 1985                 15,600               16,600

     1986 to 2000                16,000               18,300

     Our discussions with the Federal Railroad Administration,
the railroads, and representatives of the car-manufacturing
industry indicated that the manufacturers have the capability
to augment the existing fleet to meet future rail transpor-
tation needs. 51/ Freight car deliveries in 1975 tended to
support this view. The car-building industry delivered more
than 72,000 cars, of which 17,000 were open-top hoppers
appropriate for coal service. Additional production capa-
city is available in the railroads' car-building shops. 52/

     A recent study sponsored by the Electric Power Research
Institute concluded that the railroad car-building industry
would have the capacity to provide needed quantities of
hopper cars (more than 20,000 cars a year). 53/

     Railroads, moreover, can do much to improve car utiliza-
tion and thereby reduce car requirements. Such improvements
are available through expanded unit train operation!;, improved
traffic management, and upgrading of railroad plant and
equipment to permit faster, more reliable service.

      Coping with the transportation of increased tonnages
of western coal will pose problems that could be solved by
several alternate modes or combinations of modes. 54/ Western
rail lines have already embarked on expansion programs, and
their unit trains are expected to move much of the antici-
pated traffic. Because of the magnitude, however, an
alternative--the slurry pipeline--is now under consideration.
Five new pipelines have been proposed, which could move as
much as 75 million tons of coal annually. One proposed
pipeline would move 25 million tons a year more than 1,000
miles. 55/ Advocates for such pipelines contend they are
needed because the railroads will not be able to handle the
anticipated western coal traffic. 56/

     At present, only one slurry pipeline is operating in
the United States--a 273-mile, 18-inch diameter line trans-
porting 4.8 million tons of coal annually from mines at Black
Mesa; Arizona, to a powerplant in Nevada. From 1957 to 1963,
an Ohio pipeline moved coal 108 miles from Cadiz to Eastlake.
It ceased operations because it was unable to compete with
reduced railroad unit train rates. 57/
     Like unit trains, slurry pipelines can be well suited to
western coal transportation. Both modes can provide the
relatively low-cost service per ton-mile that permits high
volumes of cheaply mined western coal to compete in markets
long distances away. 58/
     However, slurry pipelines face critical problems. These
problems relate to the need for the power of eminent domain
to assemble rights-of-way, massive water needs in arid western
areas, and technological and environmental problems of dispos-
ing of the effluent at the receiving end.

Slurry pipelines versus railroads--
advantages and disadvantages

     Although selection of transportation modes is made
primarily on the basis of cost, other factors also influence
the choice of the optimum mode for a particular transporta-
tion requirement. 59/ Railroads offer the advantages of 60/

     -- an established, extensive, an"   .pandable
        nationwide system;

     -- the ability to serve high- and low-volume applications;
     -- adaptability to multiple uses and to carrying
        commodities other than coal; and
     -- more job opportunities.
On the other hand, railroads have the disadvantages of 61/

     -- environaental problems as more traffic causes
      increased community disruption and noise and air
     -- greater exposure to inflation b 7ause a greater
      percentage of their operating custs are variable
       (e.g., labor); and
     -- topographical constraints from grading and track
        requirements causing indirect routing.
Slurry pipelines could provide the following advantages of 62/

     -- causing less air or noise pollution than railroads
        due to underground construction;
     --greater inflation protection because a lower
       percentage of operating costs are variable; and
     -- more direct routing over difficult terrain.
Disadvantages of slurry pipelines may include 63/

    -- dependence on long-term, high-volume, continuous
       long distance coal movements to attain low cost cf

     -- service may be limited to single origin and single
        destination coal applications, since multiple
        sources and destinations would adversely affect cost;
     -- fewer employment and other economic benefits to
        communities en route;
     -- massive water requirements, sometimes in arid
        coal-producing areas; and
     -- environmental problems caused by massive water
        discharges at the receiving end.

     Comparative costs
     Available evidence does not clearly demonstrate the cost
superiority of either unit trains or slurry pipelines.
Relative cost advantages will depend on the specific circum-
stances of each application. 64/

     A 1975 BOM stuCy of alternative electricity costs
based on five alternatives for western coal-base. energy
transportation indicated that there was little to choose
between unit trains and slurry pipelines from a cost stan-
point for a 25 million ton annual movement of coal 1,000
miles from eastern Wyoming coalfields. Two othec modes of
energy transportation using Wyoming coal---conversion to
electricity near the mine and transport by extra-high-
voltage transmission lines or conversion to gas at the
mine and shipment by pipeline with subsequent conversion to
electricity--were found to be more costly. The least costly
method that BOM looked at involved mine-mauth gasification,
transport by pipeline, and direct use for home 'eating,
itc. 65/ The big differences between the cost of using
coal gas directly as gas compared to various forms of
electrical conversion raise some interesting analytical
questions which GAO hopes to address in future work. GAO
is particularly interested in an alternative that BOM
did not look at, which involves transportation of coal
to medium-size utility and industrial plants, gasification,
and direct use of the gas.

     According to the BOM study, the comparative consumer
costs per million end use Btus for the alternatives studied,
ranred as shown in table 12. 66/

                             Table 12

           Comparative Costs for Western Coal/EnergX
                   Transportation Alternatives

                                     Cost per million
            Mode                    end use Btus (note a)
                                       (1975 dollars)
        Slurry pipeline/
          conversion to
          electricity                   $ 6.18
        Unit train/conversion
          to electricity                  6.23
        Mine-mouth conversion
          to electricity/shipment
          by wire                        8.20
        Mine-mouth gasification/
          pipeline/conversion to
          electricity                   11.28
        Mine-mouth gasification/
          pipeline/direct-use            2.87
        a/Assuming all-equity financing.
     Other studies do not agree with the BOM figures in
table 12. For example, a 1976 Energy Research and Develop-
ment Administration study shows significant cost advantages
for slurry pipelines over unit trains for movements of over
six million tons of coal per year over distances of 1,000
miles. 67/

     The BOM figure of $2.87 per million end use Btus for
direct use of synthetic gas is low compared to other esti-
mates. In 1976 GAO reported that the cost was expected
to be from $4.00 to $5.00 per million Btus. 68/ A 1977
study by the American Gas Association estimates the
cost per mnillion Btus to be $4.45 delivered at the
residence, and $6.95 when the end use efficiencies of
home appliances are taken into account. 69/

    The eminent domain question

     Construction of long distance interstate coal slurry
pipelines is presently constrained by developers' inability

 to assemble necessary rights-of-way. Such pipelines
 need to cross the rights-of-way of their competitors, would
 railroads, who resist pipelines passing beneath their
 tracks. 70/

      Currently, seven States--West Virginia, Ohio, North
 Carolina, North Dakota, Texas, Oklahoma, and Utah--have
 granted the right of eminent domain specifically to slurry
 pipelines. 71/ As a result, slurry pipelines, which would
 have to cross several States, and many railroad rights-of-
 way, face tremendous obstacles in acquiring rights-of-way.
 Legislation granting the F: 4ral right of eminent domain is
 seen by pipeline advocates as the most effective means of
 removing these difficulties.

     A precedent was set in granting Federal eminent domain
to natural gas pipelines. In the case of natural gas trans-
portation, no other mode was feasible. 72/ However, with an
expandable rail system already in place, such is not generally
the situation for coal pipelines. The decision whether or
not to grant eminent domain power to slurry pipelines, either
generally or on a case-by-case basis, will involve a balancing
of the economic and social advantages and disadvantages that
pipelines and railroads have to offer.

     Adeguacy of water supplies
     for slurry pipeline use
     Coal slurry pipelines require massive quantities of
water--about one ton of water for each ton of coal moved.  73/
A coal pipeline moving 25 million tons of coal annually
requires about 15,000 acre-feet* of water per year at its
source. Much western coal development is expected to occur
in semiarid western States, where water is in relatively
short s,,pply.  Slurry pipeline demands would have to compete
with pu'blic. industrial, and agricultural needs. The Bureau
of the Census, Department of Commerce, has projected that the
population of the Western States will increase at double the
national average through the year 2000, further complicating
the task of setting water use priorities. 74/

     Fresh surface water in many coal-rich Western States is
already totally committed or will be in the near future.
Underground resources, or ground-water, have thus become an
important source for the future, but there is inadequate
information on their availability or the environmental effects
of their use. Ground-water used in one area can affect supplies

*One acre-foot of water equals about 325,000 gallons.
hundreds of miles away. Large withdrawals in Montana or
Wyoming, for example, could affect supplies in the Dakotas. 75/
     In some cases, however, such as the Black Mesa to Nevada
pipeline, water availability may not present insurmountable
problems to slurry pipeline development. Water shortages
therefore could constrain pipeline development in some, but
not necessarily all, instances.   Each application will re-
quire in-depth evaluation  of the impact of pipeline withdrawals
on present and future water requirements.
     If water is unavailable at the point of slurry
origination, it would be necessary to pipe water from an
available source of supply. According to a recent
DOT-sponsored study, piping water 300 miles from the
Missouri River for use by the proposed 1,000-mile Wyoming
to Arkansas slurry pipeline would raise its costs for each
ton-mile by 25 to 40 percent. 76/ If slurry pipelines
enjoy only marginal economic aavantages over rail
service--as suggested by BOM (see table 12, p. 5.25)--then
the unavailability of water at the beginning of the system
would make it uneconomical.
     A possible substitute for fresh water in slurry pipelines
is the saline ground-water that underlies many western coal
regions. The extent of these resources and whether in fact
they can be used have not yet been determined, however. 77/

     Other possible alternative fluids under study as
slurry mediums are oil, wuste mine water, municipal and
industrial waste water, and methanol. 78/
     Environmental problems caused b
     disposal of slurryppeine    effuents
     The other side of the problem of slurry pipeline
water availability is what to do with the massive residual
effluent at the slurry destination. As previously stated,
about one ton of water is used for each ton of coal trans-
ported. Therefore, when the coal is Lemoved from the
slurry, most of the water transport medium must be disposed

     This effluent contains fine particles of coal and
other organics which pass through the dewatering stage.
For a considerable time these fine particles remain suspended
in the water.

     Under current environmental restrictions on water dis-
posal, such effluent cannot be directly discharged into
natural water areas. A choice then must be made to either
remove these particles by mechanical, chemical, or other means
or to divert the water to ponds to permit the particles
to settle out.
     To remove the particles by additional processing, re-
quiring the investment in ancillary plants, raises the ques-
tion of whether the slurry system will be economical.

     Diverting the water to settling ponds assumoes the
availability of the necessary land and the type of terrain
necessary to create these ponds. A slurry pipeline would
require many acres for this purpose, depending on the climatic
conditions in the locality selected for the plant.

     Another possibility that has been considered in
situations where water supply at the mine is very restricted
is to reuse or recycle the water from the delivered slurry by
sending it back to the mine in a return pipe. This probably
would be done only in unusual situations because of the
considerable additional capital cost.

     The Congressional Office of Technology Assessment
(OTA) expects to complete a study of the railroad/slurry
pipeline question by the end of 1977. The OTA study will

     -- coal production, transportation, and use
        needs and problems;
     -- the environmental impacts of slurry pipelines and
     -- the economics of both modes; and

     -- the leg 1 implications (e.g., precedents and water

     More than 100 million tons of ccal are transported
annually on the Nation's waterway system.* However, the

*There are very few places in the Nation where coal goes
 directly from mines to barges. Nearly all barge coal
 movements are preceded by a rail movement or truck

physical capacities of the system's locks and channels could
limit its ability to move greatly increased quantitities of
coal on some parts of the system. Expected future growth in
waterway tonnage would add to the need for expanded waterway
facilities. 79/

     Expanding waterway facilities would permit increases
in coal and other commodity traffic, but such expansion is
costly. For example, one of the bottlenecks on the upper
Mississippi River is the Alton, Illinois, locks and dam 26.
The Army Corps of Engineers' proposal to moderately raise
its capacity from 73 million tons to 86 million tons by
replacing the existing locks and dam would cost $390
million. 80/ A study by the MITRE Corporation indicates
that this lock is 1 of 13 on the Mississippi, Illinois,
and Ohio Rivers where traffic levels are expected to reach
lock capacity by 1985. 81/
     It is not clear whether expanded waterway facilities
will be essential to carry added quantities of coal. Parts
of the existing system are presently under capacity and might
be used to carry coal, depending on the origins and destina-
tions of future coal movements. A DOT report on replacing
the Alton locks and dam 26 suggests that much of the anti-
cipated increased western coal output may not be transported
through the Alton locks. Also some of the high-sulfur coals
moved upriver to midwest markets may be displaced by lower
sulfur coals. 82/ If major increases in development occu. in
eastern and/or-Midwestern coalfields rather than in the
West, however, much greater demands may be placed on the
inland waterway system. 83/
     An official of DOT's Federal Railroad Administration
has expressed concern that Federal expenditures to expand
waterway capacity without an equitable charge to users
would provide further advantages to the barge industry
over competing railroads. 84/
     It is claimed that the lower cost of barge operations
(see table 3, p. 5.5) is partially attributable to the barge
industry's use without charge of the inland waterway system,
which is maintained by the Corps of EngineeLs, whereas rail-
roads build, maintain, and pay taxes on their rights-of-way.
     There is currently a bill (H.R. 5885) before the Congress
that would require users of the Inland Waterway System to
pay fees. This controversial bill has passed both the Senate
and the House of Representatives, but was referred to a
House/Senate conference on June 24, 1977. As of August 1,
1977, the bill was still in conference.

     Care must be exercised to assure that expansion of
railroads or waterways will not unfairly jeopardize the
competitive position of the other. Assessments of impacts
on the total transportation system are needed before informed
railroad, pipeline or waterway expansion decisions can
be made.   The President has recognize3 the need for an
assessment of the Nation's energy transportation needs
and will create a commission to study and to make recommenda-
tions by the end of this year. One purpose of the study will
be to develop means to encourage use of energy supplies
nearest to consuming markets in order to reduce the need for
long-distance transport.

     Potential increased coal production, particularly in
the West, will place new demands on the Nation's coal trans-
portation system that must be met through expansion of
existing capabilities. Future coal transportation require-
ments can be met, but Federal action may be needed.

      Transportation costs represent a substantial portion
of the delivered price of coal. These costs range from
approximately 25 percent of the cost of coal delivered
from eastern coal fields to as much as 75 percent or more
of the delivered price of coal shipped from Montana and
Wyoming to electric utilities in the Midwest. A recent
BOM study of western coal transportation alternatives indi-
cated that slurry pipeline costs would be comparable to
rail costs, while mine-mouth generation and shipment of
electricity through extra-high-voltage transmission lines
was found to be about 30 percent more costly. Other studies
conclude that slurry pipelines would have an economic
advantage in some cases.
     In 1975, railroads carried about 65 percent of the coal
traffic. Railroads will be the principal mover of coal in
the foreseeable future as well. The waterway system (the
least costly mode) does not directly service many of the
areas scheduled for major coal development and it is limited
in its capability to expand by the present physical capacity
of its locks and by ice in the winter in some areas.
Trucks and extra-high-voltage lines cannot compete in
terms of price. And coal slurry pipeline development is
constrained by difficulty in assembling possible rights-of-way
as well as by shortages of water at points of origin,
particularly in the West, and by environmental problems
associated with the disposal of the effluent at the destination.

     By 1980, railroads anticipate a 95 percent increase
over 1974 coal traffic originations. Substantial invest-
ments in hopper cars, locomotives, and roadbeJs will be
required to handle the additional coal traffic.
     GAO discussions with selected railroads and with the
Federal Railroad Administration indicate that the rail-
roads will be able to expand their coal handling capacity,
even in the West where the increase will be most dramatic.
An important consideration in this matter is that it takes
less time to expand rail facilities than to construct new
mines or electric utility powerplants. In the West, the
social and environmental consequences of unit trains--
interruptinq motor vehicle traffic and subjecting community
residents to increased noise and air pollution--appear to
be a tradeoff for increased coal development.
     Substantial investment in track and rolling stock will
be needed. The railroads' ability to attract the needed capi-
tal to meet future coal traffic demand would be enhanced if
the ICC lifted its prohibition on long-term rail contract
rate agreements and if the future demand for western low sulfur
coal due to air pollution regulations was less uncertain.
     Increased coal production will also require expanded
rail transportation capabilities in the northeastern and
midwestern areas served by Conrail, the federally-subsidized
consolidation of insolvent eastern and midwestern railroads.
Conrail's rehabilitation requirements are substantial and the
amount and timing of resource allocation to coal service
could be critical.

                      FOOTNOTE REFERENCES

1/Connie Holmes and Wilbur C. Helt, Coal Data. 1975 Edition
  (Washington: National Coal Association, 1976), p. 82;
  United States Bureau of Mines, preliminary unpublished
  data furnished by M. W. Edwards, Division of Interfuel
  Studies, February 10, 1977.
2/Mildred M. Lovelace and Kinglin, Coal Traffic Annual
  (Washington: National Coal Association, 1975), p. 45.
3/Leonard M. Westerstrom, "Bituminous Coal and Lignite,"
  Mineral Facts and Problems, 1975 Edition (Washington:
  Bureau of Mines, 1975), p. 10.

4/R. E. Harris and M. S. Lanier, "Production of Coal-
  Bituminous and Lignite, 1976, per week," Mineral Industry
  Surveys, Weekly Coal Report No. 3056, April 9, 1976), p. 10;
  Leonard M. Westerstrom,-,Tituminous Coal and Lignite in
  1976," Mineral Industry Surveys Annual, Preliminary,
  January 3, 1977, p. 2.
5/M. T. Lethi, et. al., Analysis of Steam Coal Sales and
  Purchases (Mctean: MITRE Corporation, 975),  pp. 51 to 52.
6/Battelle Columbus Lpt&iatories, A Report to
  the Interagency Coa:. Task Force, Pro'ect Independence
  Blueprint, on the Mudii TranSportation Costs for Coal in the
  United States (Coliumus: Battelle -CoiumEus LaEoratorles,
  T-74), p. 25.
7/United States Bureau of Mines, Comparison of Economics
  of Several Systems for Providinq Coal-based Energy to Users
  1,00- Miles Southeasrrom  foiinq
                                 Eastern         Coal Field
  Four Modes of Energy Transportation and Electricity versus -
  Gas as the End Use Energy Forms, (Washington: Bureau of--
  Mines, T175), p.-
8/GAO calculated on the basis of:  1975 coal shipment data
  shown in table 1, p. 5.4 and BOM and EEI scenario coal
  production total shown in Chapter 4, table 8, p. 4.15.
9/United States General Accounting Office, Status and Obstacles
  to Commercialization of Coal Liquefaction andGasif ication,
  RED-7-81, (Washington:i United States GeneriT Accounting
  Office, 1976), pp. i to iii.

10/Statement by Dr. A. B. Flowers, Manager, Residential,
   Commercial, and Industrial Research and Engineering,
   American Gas Association, Personal interview,
   February 16, 1977.
11/Samir A. Desai and James Anderson, Rail Transportation
   Requirements for Ccal Movement in 1986(Cambridge: Input-
   Output Computer Services, Inc., 197'67, pp. XIII and XVII.

12/GAO calculated on the basis of: 1974 coal shipments,
   Chapter 5, table 1, p. 5.4 and 1974 originated coal
   traffic, Chapter 5, table 5, p. 5.8.
13/Desai and Anderson, op. cit. p. XXIV.

14/Ibid., pp. XXV to XXVII.

15/Ibid., pp. XXV to XXVI.

16/Ibid., p. XXVII.

17/Ibid., pp. XXV to XXVI.

18/GAO calculated on the basis of:
   Desai and Anderson, op. cit., pp. XXIX, XXXII, XXXIII and

19/Desai and Anderson, op. cit., pp. 2 to 14.

20/Ibid., pp. 2 to 15.
21/Association of American Railroads, Economics and Finance
   Department, unpublished data furnished orally January 1977.

22/M. C. Schneider and W. McClanahan, Coal Rail Transportation
   Outlook, (Washington: Federal Energy Aministration, 1976).
23/Alec Sargent, Western Coal Transportation: Unit-Trains or
   Slurry Pipelines (Wash-ngton: Department of Transportation,
   1976), pp. 28 and 29.
24/Ibid., "Burlington Northern".

25/Schneider and McClanahan, ao. cit., "Chicago and
   Northwestern Transportation Company".

26/Ibid.,   "Union Pacific Railroad".

 27/Ibid., "Denver and Rio Grande Western
 28/T. C. Campbell and Sidney Katell, Long
                                            Distance Coal
    Transport: Unit-Trains or Slurry Pipe ines,  Bureau of Mines
    Information Circular 86W-, (Was ington:
    1975), pp. 19 and 20.                    Bureau of Mines,

 2 9 /Statement
               by James W. Boone, Director of Rail Economics
    and Operations Federal Railroad Administration,
    Department of Transportation, personal interview,U.S.
    August 12, 1976. Statement of Dr. David
                                              L. Anderson,
    Chief, Industry Analysis Branch Transportation
    Center, Department of Transportation, personal Systems
    October 15, 1976.                               interview,

 30/Statement by Louis W. Menk, Chairman and
                                              Chief Executive
    Officer, Burlington Northern, Inc., before
    Coal Slurry Pipeline legislation by the     Hearings on
                                             Committee on
    Interior and Insular Affairs, House of Representatives,
    November 7, 1975.
 31/Statement by Louis W. Menk, Burlington
    before the Hearings on Greater Coal Utilization Inc.,
    Senate Committee on Public Works, June 11,       by the
3 2 /Association
                 of American Railroads, The Case Against
     Aipeinesr,                                          Slurry
                pp. 13-14; Louis W. MenkChairman and Chief-
    Executive Officer, Burlington Northern, Inc.,
    before the Hearings on Greater Coal UtilizationStatement
    Senate -ommittee on public Works, June 11,       by the
                                                1975, pp. 8 to 12.
3 3 /Association
                of American Railroads, The Case Against Slurry
    Pipelines, p. 5.
34/Slurry Transport Association, Railroads
                                           vs. Coal Slurry
   Pipeline: A Rebuttal, p. 2.
35/R. L. Banks and Associates, Study to
                                           Identify and Analyze
   Existing Impediments to Use o_ Railroad
                                              Contract Rates in
   the United States, (Washlngton: Department
   Transportation, 973), pp. 14 and 15.          of

3 6 /Statement
             by Louis W. Menk, Chairman and Chief Executive
   Officer, Burlington Northern, Inc., before
   on Coal Slurry Pipeline Legislation by the the Hearings
                                              Committee on
   Interior and Insular Affairs, House of Representatives,
   94th Congress, November 7, 1975.

37/Statement by Louis W. Menk, before the Hearings on Greater
   Coal Utilization by the Senate Committee on Public Works,
   June 11, 1975.
38/Desai and Anderson, Rail Transportation Requirements for
   Coal Movement in 1980, op. cit., pp. 2 to 5.

39/Bill Richards, "Cutting through Wyoming: 100-Car Trains
   Move It Out," Philadelphia Inquirer, December 11, 1976.


42/Schneider and M.Clanahan, Coal Rail Transportation Outlook,
   oy. cit., pp. 3 to 5.

44/"Target for 1976:  727 Miles of Welded Rail," Conrail
   Magazine, June/July 1976, pp. 2 and 3.
45/Statement by Charles Wolfinger, Conrail, Assistant Vice
   President, Coal and Ore, personal interview, August 24,

46/Association of American Railroads, Yearbook of Railroad
   Facts, 1976 Edition, p. 52.
47/Gary M. Larwood and David C. Benson, Coal Transportation
   Practices and Equipment Requirements to 1985, Bureau of
   Mines Information Circular 8706 (Washfington: Gover:ment
   Printing Office, 1976), pp. 44 and 46.

48/J. Bhutani, et al., An Analysis of Constraints on
   Increased Coal Production (McLean: MITRE Corporation, 1975),
   pp. 8-9 to 8-13.

49/GAO calculated on the basis of: J. Bhutani, et al., op.
   cit., p. 8-13 adjusted to fit EEI and BOM scenario output

51/Statement by James W. Boone, Director of Rail Economics and
   Operations, Federal Railroad Administration, personal
   interview, August 12, 1976; Statement by Richard Hagamann,
   Market Manager, Denver and Rio Grande Western Railroad,
   personal interview, August 5, 19'6; Statement by
   Thomas B. Graves, Jr., Assistant Vice President, Marketing,

   Union Pacific Railroad, personal interview, August 4, 1976;
   and Statement by Robert Matthews, Vice President, Railway
   Progress Institute, personal interview, August 11, 1976.

52/Statement by Robert Matthews, Railway Progress Institute,
   personal interview, August 11, 1976.

53/Bertram E. Rifas and Sally J. White, Coal Transportation
   Capability of the Existing Rail and Barge Network, 1985
   and eyond ealo ATlto: Electric Power Research Institute,
   T-76), p. 6.
54/Campbell and Katell, op. cit., p. 3.
55/J. Mergel, Assessing the Impacts of Coal Slurry Pipelines,
   Problem Overview ana Propose   naApproa         Staff
   Study (Cambridge: Transportation Systems Center, 1976),
   pp. 2 and 3.
56/Slurry Transport Association, op. cit., p. 1.

57/Mergel,   op. cit., p. 1.
58/Campbell and Katell, op. cit., p. 5.
59/Larwood and Benson, op. cit., p. 17.

60/Association of American Railroads, The Case Against Coal
   Slurry Pipelines, pp. 5-9, 11 and 12.

61/Slurry Transport Association, oa. cit., p. 4-5; Coal Slurry
   Pipelines, Background Information, p. 2.


63/Association of American Railroads, oP.   cit., pp. 2 to 5, 10.
64/Campbell and Katell, op. cit., pp. 23 and 24.

65/United States Bureau of Mines, op. cit., pp. 2 to 4.
66/Ibid., p. 4.

67/United States Energy Research and Development Administration,
   Energy from Coal, (Washington: Energy Research and Develop-
   ment Administration, 1976), pp. viii-5 and viii-6.

68/United States General Accounting Office, Implications of
   Deregulatin[ the Price of Natural Gas, OSP-76-11,
   (Washington: Unite--tai-es  GeneraTccounting Office,
   1976), p. 23.

69/American Gas Association, Energy Analysis, April 26, 1977,
   pp. 10 and 11.

70/Slurry Transport Association, Coal Slurry Pipelines,
   Background Information, p. 1.

71/Interstate Commerce Commission response to report

72/Associat"'n of American Railroads, go. cit.,         pp. 11 and 12.

73/Slurry Transport Association, Coal Slurry Pipelines:
   Some Answers, p. 2.

74/James K. Rice, James M. Evans, and Murray Warner,
   "Envi-onmental Considerations of the Use of Saline Water
   in Coal Slurry Pipelines," The NUSLETTER, Winter 1976,
   pp. 8 and 9.

75/Ibid., pp. 9 and 10.

76/Sargent, op. cit., pp.   39 and 40.

77/Rice, Evans, and Warner, aE.      cit., pp. 10 to 12.

78/Slurry Transport Association, op. cit.,      p. 2.

79/Bhutani, et al.,   op. cit., pp. 8-5 and 8-27.

80/Craig Roach, Alton Locks and Dam:   A Review of the Evidence,
   staffworking paper (Washingt      on:ressiona-r-Bu-getffce;
   1976), pp. VII, 33;  United States Department of Transpor-
   tation, The Replacement of Alton Locks and Dam 26
   (Washington: Department of Transportation, '-5T7, p. 64.

81/Bhutani,   et al., op. cit., pp. 8-27 and 8A-69.

82/United States Department of Transportation, op. cit.,
   p.   19.

83/Ibid., pp. 6 and 7.

84/Statement of James W. Boone, Director of Rail Economics and
   Operations, Federal Railroad Administration, personal
   interview, August 12, 1976.

                            CHAPTER 6
                   HOW CAN WE MAKE IT USABLC?
       The previous chapters have been concerned with
                                                        the demand.
 availability, supply, and transportation of coal
markets. Getting coal out of the ground recuires to available
 and expansion of existing mines. Transporting       new mines
                                                 coal requires
 new transport systems and more intensive use of
 systems. Expanded use of coal means converting existing
powerplants and building new ones, and, to a lesser electric
constructing facilities for the manufacture of         extent,
fuels. All these developments will require substantial
capital just to build the facilities. There will
                                                     also he
great environmental and social costs--both monetary
nonmonetary. Perhaps the most important costs          and
tary--degradation of the environment and social  are  nonmone-
that will occur in some alias, and the effects on
health and welfare which may occur due to increasedpublic
use. Socioeconomic impacts are discussed in chapter
      When coal is mined, transported, and used,
produces environmental degradation of the land, it usually
water, as well as increased water consumption--a air, and
cor-ern in the arid West.                          particular

     This chapter discusses major environmental problems,
what is oeing done, what can be done to minimize
who is doing it, and the cost.                   the problems,

     Environmental problems discussed here are:
     -- The effects of burning coal on air quality and
        effect that air quality regulation changes will
        on coal development.
     -- Costs of air quality control technologies.

     -- The environmental effects of extracting cc-¢
        and the impact:s of State and Federal mining
        reclamation legislation.
     --Water availability problems in the West.

      Greater use of coal wi'l entail some enviro
compromises and socioeconomic adjustments. There rental
tradeoffs to be considered, balances to be struck, are
prices to be paid.   In the following section we discuss
th.. impact of burning coal on
of air quality regulations on air  quality and the impact
                               coal use.


     Coal is burned to produce heat and power for homes and
industry. But, coal combustion also emits a number of
potentially dangerous elements into the air that at sufficient
concentration levels have been associated with increased
incidence of respiratory diseases, and death rates in
humans, crop damage, loss of domestic animals and wildlife,
and deterioration of building materials.

     The amount of emissions can be enormous. For example,
annual sulfur dioxide emissions are estimated to be 150
million tons worldwide, of which 33 million tons are
emitted within the United States. Coal-fired powerplants
account for over 50 percent of the U.S. emissions. 1/
Coal burning must comply with Federal and State regulations
to insure that environmental objectives are met.
Pertinent legislation
affecting coal development
     Beginning in 1963, the Conqress enacted a number of laws
to enhance and protect the quality of the Nation's air
resources. These actions range from authorizing Federal
emission control research to establishing national air
quality standards (pollution concentration levels). The law
which most affects current coal combustion is the Clean Air
Amendments of 1970, as amended (42 U.S.C. 1857), which directed
the Environmental Protection Agency to establish minimum
national air quality standards.

     EPA established primary and secondary standards for six
classes of pollutants--sulfur dioxide, particulate matter,
carbon monoxide, hydrocarbons, nitrogen oxides, and photo-
chemical oxidants. Primary standards were set at levels
necessary to protect the public health and were to be met
no later than July 1, 1975. Secondary standards were
designed to protect the public from such adverse effects
as crop damage, reduction in atmospheric visibility, and
corrosion of materials. Secondary standards were to be met
in time frames considered reasonable by EPA.

     While tle national ambient air quality standards were
established to protect the health and welfare of the Nation,
it is difficult to identify conclusively the threshold
level of concentration for each type of emission below

Note:   Numbered footnotes to ch. 6 are on pp. 6.52 to 6.54.

which adverse health effects will not occur.  In addition,
the area of long-term or genetic effects of exposure to the
emissions is not known since the present state of knowledge
allows only an approximate estimate for such effects.

     Under the 1970 act, States were responsible for
achieving the standards by developing State implementation
plans (subject to EPA approval or modification) which
included programs and timetables for meeting the Federal
standards. Implementation plans to attain and maintain
these standards have been submitted by all the States, but
both primary and secondary standa-ds have not yet been
attained in many regions (not all plans were approved
oy EPA).
      In addition to the national ambient standards,
Clean Air Act of 1970 directed EPA to establish (1) the
standards of performance for new or modified stationary
sources of pollution to insure that they are designed,
built, equipped, and maintained so that minimum emissions
occur, regardless of the source locations (new source
performance standards) and (2) air quality standards for
controlling other hazardous emissions, which would include
coal combustion. The new source performance standards were
set at levels which will require installation of the best
systems cf emission reduction which the Administrator of
EPA has determined as being adequately demonstrated. Cost
factors are considered in making this determination. Standards
for controlling other hazardous emissions from coal combustion
will be promulgated as dea& regarding their effect become

     Two of the most significant impacts of the Federal
regulations and the State implementation plans involve
controlling sulfur dioxide and particulate emissions.
For utilities to be operated in compliance with these
    --A large number of plants probably will have to
      install flue gas desulfurization technology, a method
      of cleaning coal combustion gases, to meet sulfur
      oxide emission requirements. (Low-sulfur coal supplies
      would have to be developed very quickly to provide
      a means of complying with the emission requirements
      short of desulfurization.)

    -- All plants must install particulate scrubbers
       electrostatic precipitators, fabric filters,
       or bag houses to meet particulate matter standards.

Available control technologies for
reducing coal combustion emissions

     Electric utilities that use coal have limited alterna-
tives in complying with national ambient air quality standards
and new source performance standards for sulfur oxides,
particulates, and nitrogen oxides emissions. EPA believes
that meeting the applicable standards requires the installa-
tion of controls on nearly all new coal electric powerplants
through the 1970s and on many existing plants. President
Carter's National Energy Plan recommends that all new coal
burning facilities, including those that burn low-sulfur coal,
be required to use the best available control technology. 2/
A summary of available technologies for controlling these
emissions follows.

     Sulfur oxides emissions

     Sulfur oxides emissions are directly related to the sulfur
content of coal being burned, and there is little in the way
of conventional boiler design or operation that can influence
the level of emissions from coal during combustion. 3/

     Most electric utilities now try to meet sulfur oxides
ambient air quality standards by using coal with lower sulfur
levels, reducing sulfur content before combustion (washing
and blending), collecting emissions following cbmbustion
(scrubbers), or by tailoring emissions to current meteorolog-
ical conditions to maximize natural atmospheric dispersion
(intermittent controls). Using tall smoke stacks is another
method for maximizing atmospheric dispersion. None of the
dispersion measures reduces pollution, except locally; they
just spread it around.
     Particulate emissions

     Various particulate control devices have been installed
on nearly all coal-fired boilers to collect microscopic
ash particles emitted during coal combustion. The specific
method is largely determined by the sulfur oxides control
method selected by an electric utility. For example,
electrostatic precipitators are expected to be installed
on powerplants which use low-sulfur coal for sulfur
oxides compliance and a particulate scrubber will be
installed in combination with a sulfur oxides scrubber
at other locations. The particulate control devices
are much less effective in collecting finer particu-
lates (1 micron or smaller).

      Nitrogen oxides emissions
      According to EPA, there are no true nitrogen
 scrubbing processes available at an economically oxides
 price. Emission of nitrogen oxides can be          viable
 influenced by boiler design and operating
 major factor, however, affecting nitrogen conditions.     The
                                            oxide formation
 is the temperature of combustion.
 exist, many electric utilities are 4/  Although several methods
                                     expected to choose one
 of two available compliance methods to meet
 emission standards--both require changes     nitrogen oxides
                                           in boiler operation.
 The methods, although not always effective,
 formation of nitrogen oxides near the flame involve retarding
                                              by controlling
 the air/fuel ratio--reducing the excess air--thereby
 to lower nitrogen oxide formation.                     leading


     GAO developed estimates of effects
by electric utilities on production costsof increased coal use
levels under two coal demand scenarios. Demandpollution
for 1985 and 2000 were developed by using        data
                                           the Bureau
of Mines scenario 5/ and a second scenario
on industry estimates of planned additions for 1985 based
                                            to generating
capacity. The demand levels are:

                               Coal Electric Demand

                                (quadrillion Btus)

                                  1985     2000
     Industry plans 6/            12.9      (a)
     Bureau of Mines              15.7     20.7
     a/A demand "planned" projection was not
                                             made by industry
       for the year 2000.
     The cost of pollution control equipment for
powerplant may vary widely* depending on several an individual
including                                        factors,

*For example, in a 1975 analysis performed
                                            for EPA by Pedco
 Environmental Specialists, Inc., scrubber costs
 $33,000 to $205,000 per megawatt of capacity.    ranged from

     -- specific sulfur dioxide control technique used;
     -- pollution emission removal requirements for sulfur
        oxides and particulate matter;

     -- condition of terrain and subsurface;
     -- status of the powerplant, new or existing;

     -- system reliability; anC
     -- management preference.

On an aggregate basis, however, a rough . 2proximation of
compliance costs may be projected by r.oltiplying the
capacity expected to use each compliance method by a
representative cost for that method.

      The electric utilities' cost to control emissions in
compliance with national standards can be categorized into
capital costs, and operating and maintenance costs. Capital
costs include the cost of pollution control equipment; energy
penalties (added capacity to operate control equipment);
capacity losses (cost associated with compensating for a
reduction in effective capacity caused when switching from
high to low-sulfur coal when the Btu heat value is reduced
by 15 percent or more); and boiler modification costs
(changes in plant configurations and material handling
equipment required for use with larger amounts of low-sulfur
     Under the BOM scenario, we estimated the cumulative
capital costs for emissions control* to be about $19.1

*Although powerplants placed into service in 1977 or later
 will be required to comply with EPA emission regulations
 for nitrogen oxide, these costs are for sulfur oxide
 and particulate control only. EPA, however, estimates
 that the electric utility industry will invest $450 to
 $500 million between 1975 and 1985 to comply with nitrogen
 oxides emission standards.

billion* by 1985 and $26.4 billion by 2000. Annual operating
and maintenance (O&M) costs for this scenario would amount
to approximately $1.3 billion in 1985 and $2.3 billion
by 2000. Comparatively, the cost impacts under the industry
planned projection for 1985 are $15.9 billicni for capital
expenditures and $1.1 billion annually for O&M cost.

      In commenting on our report, the Federal Power Commis-
sion questioned the accuracy of several elements in our cost
analysis. The FPC has recently issued a report on flue gas
desulfurization technology in which actual planned scrubber
capacity and cost figures were obtained from electric
utilities. Consequently, FPC believes that the megawatt
capacity expected to retrofit to scrubbers is overstated by
about 10 times (39,000 MW versus 4,200 MW), and the unit
cost for scrubber installation is understated by about 23
percent ($70 per kw versus $90 per kw.) Our cost estimates
were based on figures from a May 1976 EPA report entitled
"Economic and Financial Impacts of Federal Air and Water
Polluition Controls on the Electric Utility Industry",
and our estimates of installed generating capacity by
1985 and 2000. In any event, the dollar difference
(about $350 million) between the two calculations is
a relatively small part of the total multibillion dollar
capital outlay we arL talking about.

     The impact of these emission control costs will not be
felt uniformly across the Nation. Costs to control sulfur
oxides and particulate emissions will vary widely between
geographic regions due to variances in existing capacity and
projected additions. For example, existing coal-fired
electric generating capacity among the nine Bureau of the
Census regions ranges from a low of 0.6 percent in the Pacific
region to 30.3 percent in the East North Central region.
Percentage changes to capacity under the scenarios also

*Costs are 1975 dollars and reflect the following composite of
 control technologies utilized:

       Scrubbers                       39   percent
       Low-sulfur coal                 22   percent
       Medium-sulfur coal               8   percent
       Washing and blending             9   percent
       No controls                     22   percent

                                     100 percent

 vary widely. Consequently, the economic impacts diffeL
 widely among regions. The following table illustrates
 these variances for both the BOM scenarios and the industry

                                 Table 1
                             Regional Ranges
                       Capital costs           O & M costs/year
                    From             To        From          To
                (millions)      (billions)            (millions)
1985 BOM             $36           $4.9        $1.7            $353
1985 Industry
  plan                12              4.0        .3                305
2000 BOM              72              6.9      3.8                 600
      In seven of   the nine regions, control of sulfur oxides
accounts for the    major portion of the capital expenditure.
In the remaining    two regions, controlling particulate matter
accounts for the    major cost allocations.
Impact on consumer
cost for electricity

      Regardless of the elements and distribution of the costs
incurred to meet air quality standards, these costs represent
a major investment which will be passed on to the consumer
by the utility companies. Based on the total pollution costs
of procuring and operating pollution control equipment under
the 1985 BOM and 1985 industry plan scenarios, the average
residential consumer electric bill could increase by
and 4.04 mills per kilowatt hour, respectively.* These3.61
lution control costs will represent increases of about 9 and
10 percent, respectively, in the average residential consumer's
electric bill in 1985 under the two scenarios. The increase
for certain electric systems may bp substantially greater,

*GAO calculations based on information contained in a May
 1976 EPA publication.

     Levels of pollutants emitted
              al com cbustIon
     The amount of pollutants emitted during coal combustion
can be enormous, even with control technology. Even more
staggering is the sludge problem created when control
technology, such as scrubbers, is employed. The following
table puts these problems into perspective (with and without
control technology) under the two 1985 scenarios and the BOM
scenario for the year 2000:
                               Table 2
                    Table of Emissions Levels (note a)
                            (GAO calcul-ations)
                                        Annual Emissions
                                 1985            1985          2000
                             Industry_plan       BOM           BOM
                          -------------    …-(tons)---------------
Using No Controls (note b)
  Sulfur oxides               26,058,000 31,714,000      41,814,000
  Particulates                  1,060,380    1,290,540    1,701,540
  Nitrogen oxides               4,760,100    5,793,300    7,638,300
  Carbon monoxide                  264,450     321,850      424,350
  Solids                      65,145,000 79,285,000     104,535,000
Using Controls (note c)
  Sulfur oxides                2,605,800       3,171,400     4,181,400
  Particulates                      265,740      323,420       426,420
  Nitrogen oxides              4,760,100       5,793,300     7,638,300
  Carbon monoxide                264,450         321,850       424,350
  Solids                     188,340,000      29,220,000   302,220,000
a/Calculations were made by multiplying the rate of emissions
  by the quadrillion Btu level associated with each scenario.
b/Conventional steam powerplant burning coal with an ash
  content of 12.53 percent and sulfur content of 2.59 percent.
c/Conventional steam powerplant using a wet limestone
  scrubber system. Coal burned is the same as with no

     Solid wastes without controls consist of coal soot and
fly ash.  Solid wastes in systems where control technology
is employed include sulfur, particulate matter, and limestone,
as well as the soot and ash. As the table above shows, using
controls for sulfur and particulates nearly triples the amount
of solids which must be handled. To put the solids problem
into perspective, the waste material generated under the 1985

 industry plan scenario with controls is about equal
                                                      to the
 tons of municipal waste generated by all the people
 United States during the course of one year. Land    in the
 ity and disposal costs of such wastes is a significant
 which industry and government must address.
      Emissions control is the principal area of concern
 with regard to coal-related air quality objectives.
 adequate controls requires large expenditures to develop
 procure pollution control equipment. Several concerns     and
 ing future coal development are raised by current Federal
 standards as well as future changes. They are:

      -- The impact future changes in air quality regu-
         lation will have on coal development.
      -- Conflict of air quality objectives with coal
         development objectives.
     -- The effect of possible regulation of trace elements
        other uncontrolled emissions on future coal development.
     -- The effect of sludge disposal on coal development.
Modifications to air
 uality egulations

      During the 95th Congress, the Clean Air Act was amended
to adopt revised procedures for preventing significant
quality deterioration from new sources of pollution     air
95-95, August 7, 1977).

      EPA regulations--promulgated in 1 9 74--set
pollution concentration increments which may notallowable
                                                   be exceeded
by a major new source for three classes of geographic
Briefly, class I areas would allow little or no         areas.
                                                  change in
air quality levels, class II applies to areas where
erate change would be tolerated, and class III appliesa mod-
areas where air quality would be allowed to deteriorate to
to the national standards. The EPA regulations
designated all areas as class II, subject to redesignation
to class I or class III at the initiative of a State
local authority. EPA anticipated that class I redesignations
would be made to protect existing clean air resources
areas such as national parks and wilderness areas.      in
III redesignations would occur where State and local
allowed extensive industrial development, but pollutionpolicies
could not exceed national ambient air quality standards. levels

     The Clean Air Act Amendments of 1977 retain the three
classes of geographic areas but allow for variances from
some class I areas. The variances can allow some class I
air quality standards to be exceeded up to 18 days per year
for sulfur oxides.

     A few areas (national parks, wilderness areas) are
designated mandatory class I. All other areas are initially
designated class II, subject to reclassification by individual
States. A new facility must obtain a construction permit in
any area subject to the significant deterioration provisions.
The permit can only be obtained if it is demonstrated that
the new source will not interfere with maintenance of the
area classification.
     The new amendments require new fossil-fuel boilers to
meet a numerical sulfur oxides emissions limit (such as
pounds of emissions per hour), and if the plant can meet the
emissions limit by burning low-sulfur coal, some treatment
must still be applied to reduce emissions by some unspecified
percentage. This additional percentage reduction will be
determined by EPA. The new sources can meet the new require-
ment by any method which need not necessarily be scrubbers.*
The control used must be continuous rather than intermittent.

     While most of the emphasis concerning future changes
in air quality regulations focuses on the desire for more
stringent controls or standards, one school of thought favors
relaxation of requirements by allowing the use of intermittent
control syste...

     Intermittent controls do not significantly reduce total
emissions but tailor them to current meteorological conditions
to avoid violating (ground level) ambient air quality
standards. When meteorolgical conditions are favorable,
natural atmospheric dispersion of sulfur oxides emissions would
enable the standards to be met at ground level. During
periods of unfavorable meteorological conditions, sulfur
oxides limitations would be met by using a temporary supply
of low-sulfur fuel or curtailing operations and shifting
the electrical load to another powerplant.

*Capital costs for installing scrubbers on all coal-fired
 powerplants would be $23.67 billion under the 1985 industry
 plan scenario and $25.4 billion and $35.0 billion under
 BOM's 1985 and 2000 scenarios, respectively (our calcu-

       At first EPA rejected their
 were unreliable and unenforceable.use,Nowbelieving   the systems
 sufficient advances in monitoring systemsEPA   believes that
                                              have been made
 to allow the use of intermittent controls as
 compliance method for a limited number of plantsan interim
 continuous emission control technology is installed.  only until
 intermittent control systems would be feasible             The
                                                    at relatively
 isolated plants which contribute a major proportion
 oxides in their area.                                    of sulfur

      EPA and the Energy Resources Council
Congress in 1975 an amendment to the Clean recommended
                                                        to the
would permit use of intermittent controls on    Act,  which
                                              an interim
basis with permanent controls required by 1985;
no congressional action was taken. Over and      however,
                                              above EPA's
proposal, the utiility industry supports intermittent
techniques as a permanent means of compliance          control
limited to an interim period of 10 years. The and not just
believes intermittent controls would represent
                                                a cost
compromise while still maintaining some control
                                                 over emissions.
     The problem
      The concern raised by future modifications
lity legislation involves the effects they would of air qua-
U.S. coal development and air quality. According have on both
EPA estimates 7/, changes to Federal air quality to 1976
would have increased the electric utility industry's
requirements from 1975 to 1990. The increase            capital
related to the required use (on a              was  primarily
best available control technology case  by case basis) of the
                                   for new pollution sources.
Specifically, EPA estimated that the industry's
requirements would have been increased by $11.2 capital
billion. These figures represent an increase      to $11.6
cent in the industry's planned capital        of about 3 per-
     Proponents of the more stringent regulations
they would minimize air quality deterioration      believe
taining establishment of coal-fired utilities while  main-
adequate economic development. Opponents argueand  their
                                                that the
regulation would decrease coal production, increase
consumption of imported oil, and increase costs      U.S.
trolling emissions. 8/                          for  con-

      Concerning the implications of using intermittent
 controls, EPA estimated 9/ that, depending on the option
 adopted, capital expenditures for control technology could
 be reduced by between $1.3 and $1.8 billion over the short run
 in favor of higher ($1.9 to $3.1 billion) expenditures over
 the long run, since both intermittent aend permanent controls
 will have been financed.

      Proponents of intermittent controls contend that these
 controls consume less energy, are less expensive, and are
 immediately available. Industry, with some exceptions,
 argues that scrubber technology is not sufficiently reliable
 to require widespread installation, and that advanced coal
 combustion technologies will not be commercially available
 before 1985.

     Opponents of intermittent controls maintain that, while
they are less expensive, the use of intermittent controls
does not significantly reduce total emissions but merely
disperses them at opportune times. This constant input of
emissions into the air may cause or aggravate pollution
hazards caused by area sulfate concentrations (e.g., health,
visibility, acid rain, climate changes). 10/ This argument
is strengthened by an incomplete knowledge of the potential
effects of such increased concentrations. Although
intermittent controls may represent a compromise of short-
term cost impacts, many argue that they could in fact
compromise our environment and well-being in the long run.

     Most of the above points regarding intermittent con-
trols also apply to use of tall stacks, which basically
export the problem downwind.

Conflicting environmental
and coal development objectives
     A problem which must be considered regarding future coal
development and its impact on air quality is the apparent con-
flict between maintaining air quality and utilizing increasing
amounts of domestic coal resources. This conflict is
manifested at two levels: State versus Federal, and within
the Federal Government itself.

     The States' rights to maintain better air quality
than required by the Federal Government have always
been protected in Federal air quality legislation, but the
implications of States' rights may influence the Nation's
ability to meet its energy objectives.  For example, some
State implementation plans have established sulfur oxides
emission regulations which are mo:e stringent than necessary
to achieve national primary standards. In 1975, EPA estimated

that about 124 million tons of coal burned annually by electric
utilities to comply with State emissions regulations could
have been replaced by coal with higher sulfur content without
exceeding national ambient air quality standards. 11/ Thus,
lower sulfur coal would be freed for use by other facilities
which otherwise would either burn another fuel, or install
expensive control technology. Consequently, the EPA Admini-
strator was directed by the Congress, under the Energy Supply
and Environmental Coordination Act of 1974, to review each
State implementation plan and report to the State whether
such plans could be revised to allow use of higher sulfur
fuels without interfering with the attainment and main-
tenance of national ambient air quality standards.

     In reviewing the State implementation plans, EPA identi-
fied three reasons for the existence of regulations more
stringent than necessary to meet the national air quality
     -- the adoption of State ambient air quality standards
        more stringent than national standards;
     -- the use of stringent emission regulations required
        to maintain air quality in an industrialized section
        of a State as the regulation for the entire State,
        including less industrialized regions; and
     -- use of large, isolated sources in an air quality
        control region as the basis for establishing regula-
        tions for the entire air quality control region.
     As a result of EPA's encouragement, however, many States
have revised or submitted for revision their implementation
plans allowing higher sulfur coal to be substituted for up to
1i3 million tons of lower sulfur fuel annually. 12/
     The apparent discord between environment and energy
development objectives is not just limited to EPA and the
States, but also within the Federal Government--between the
Federal Energy Administration and EPA. FEA is responsible
for increasing reliance on domestic energy sources, and
therefore has pressed EPA to effect additional revisions
of State implementation plans. In fact, an FEA official
noted that, while progress has been made, FEA is not
satisfied that all States with potential revisions
have been identified.

     EPA is trying to cooperate with national energy programs
but is charged with responsiLility for giving primary
consideration to achieving and maintaining national primary
standardsin accordance with the Clean Air Act.    Therefore,
in reviewing proposed State implementation plan revisions,
EPA has allowed relaxation of sujffer oxides emission regulations
only to the extent that national air quality primary standards
are still maintained.

Uncontrolled coal emissions may
influence future coal development

     Coal emissions not currently regulated can be cate-
gorized into three areas--trace elements, fine particulates,
and other emissions.  Should these emissions be regulated,
they will influence the extent to which and the manner
in which coal will be develope:i .ld used in the future.

     Trace elements

      In addition to the previously d-   ,~ d  air pollutants
(sulfur oxides, nicrogen oxides, pea,      ace matter) caused
by coal combustion, a number of ot;.er eieme- :s such as mercury,
lead, beryllium, arsenic, fluorine, cadmium and selenium
(called trace elements) may be emitted as a result of the
inorganic mineral composition of coal.    There are about 53
commonly known trace elements which have be-     associated with
coal.   Although available data show trace eie ents to be a
potential problem, more knowledge is needed on sources,
formation, and transport of trece elements before control
options and emission tolerance levels can be addressed
in an ideal way.

     Only limited research and developmeit efforts have been
undertaken in trace elewgents. (See p. 6.48.)  Although, not
a trace element itself, a discussion of the iulfate problem
can serve co illus  ate the magnitude of this lack of know-
ledge and the associated problems of implementing trace
element and other emission regulations.

     Sulfates related to coal combustion occur as a result
of sulfur dioxide emissions which are converted to sulfates
by various chemical processes.  About 150 million tons of
sulfate equivalents are emitted each year into the *atmosphere.
The majority of the acidic sulfates* are attribute'i co coal

*Those sulfates ,hich contribute to the acid rain problems
 and, therefore, are most harmful.

combustion facilities.   The emissions not only affect the
human and natural environment but also reduce visibility
and ma} possibly modify the climate. Sulfate control in
the atmosphere may not depend only on the control of sulfur
dioxide but on control of precursors suwh as fine particu-
lates and nitrogen oxides. Therefore, even with proper
enforcement of State implementation plans and new source per-
formance standards, EPA projects the sulfate levels in 1990
to be similar to the 1975 ievel--a level which may cause
serious health problems.

     EPA's position is that there is enough knowledge on
the effects of sulfates to recognize that they are a threat
to the health and welfare of the Nation.  However, this know-
ledge is not sufficient to quantify levels at which sulfates
should be controlled nor how to control sulfates to maintain
such a level. This reluctance stems from uncertainties of
the solution and poses a significant public policy issue,
that is, what level of proof is necessary to establish that
an element is harmful before EPA is justified to promulgate
a national standard?

     Specifically these unknowns include the following points:

         -- Field measurement technology is not available.
         -- The atmospheric chemistry and meteorology
            involved in conversion of sulfur dioxide and
            hydrogen sulf-ide to sulfates is uncertain.

         --The health effect of exposure to given levels of
           specific sulfate compounds over given periods of
           time cannot be specified.

         -- The interrelationships between sulfates and
            other pollutants in inducing adverse health
            effects are unknown.
     Similar problems regarding trace elements are even more
complicated because the knowledge and research on them is
generally less than known about the sulfate problem. To put
the magnitude of these emissions into perspective, we developed
estimates of the tons of trace element emissions under three
scenarios.   (See table 3, p. 6.j7.)

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     Fine particulates (soot and fly ash less than 3 microns
in size) may be a health hazard because, in contrast to coarse
particulates (3 microns or larger), they bypass the body's
respiratory filters and penetrate deeply into the lungs.   In
addition to their own innate toxicity, their porous character
enables them to act as a transport mechanism for more toxic
substances which otherwise might have been filtered in their
natural state.  Fine particulates also remain airborne
for extended periods of time, obstructing light, and causing
problems with visibility--haze and smog.  In addition,
because they scatter and absorb both solar and terrestrial
radiation, they affect the earth's heat balance in what
has been called the "icebox effect."   Moreover, greater
amounts of rain and snowfall have been observed in areas where
particulate emissions have been heavy.

     Technology exists today to partially control fine partic-
ulate emissions. However, even when the best available high
efficiency collection devices are used, 1 to 2 percent of the
particulates are not captured. These particulates are for the
most part less than 1 micron.  EPA is conducting research to
control these finer particulate emissions, but to date their
efforts have been limnited.

    Other emissions

     Coal combustion produces the emission of other elements
and gases which may have an adverse effect on our environment.
These are emission of uncontrolled elements such as carbon
dioxide, and waste heat discharged during electric pcwer
generation.  There are, in addition, estimates that coal
burning plants emit more radiation than oil burning plants.
The implications of these other emissions are not clear, but
th2 National Academy of Sciences has recently released a
study on the effects of carbon dioxide. 13/

        Carbon dioxide--Whenever fossil fuels are
  dioxide-is emitted. While some carbon dioxide       burned, carbon
  by plant life and the oceans, much of it            is absorbed
  upper atmosphere. These carbon dioxide     accumulates     in the
 cept heat radiation from the earth, trapping                   inter-
 the atmosphere causing what has been termed       the  heat  within
 effect." Accurate projections                   as a "greenhouse
                                  of carbon dioxide's impact on
 global temperatures are not possible because
 ledge; however, it is known that temperatures of limited know-
 rising carbon dioxide levels. For example,         increase with
 of 1 degree to 2 degrees centigrade could       a  global   warming
                                              cause serious reper-
 cussions on the earth's surface including
                                              shifting of wind
 circulation belts and redistributing temperature
 precipitation levels. Numerous secondary               patterns and
 with these primary effects will also occur.effects associated
                                                  An example of
 the effects of even a relatively small
                                          climatic change (temp-
erature changes of tenths of a degree), may
 failure of Russian grain crops which were      be the recent
to small climatic fluctuations in marginal largely attributable
                                               growing areas.
       Worldwide,* the increased global temperature
rising concentrations of carbon dioxide may              caused by
                                                produce some
melting of the polar ice caps, causing a
                                            sea level increase
of tens of feet, gradually inundating coastal
lands, and perturbation of marine biology.         plains and low
growth in the use of fossil fuels, the effect   With   continued
coal combustion on climatic conditions may         of  increased
                                              become    an important
problem during the next 50 years.
      Waste heat eneration--During power generation,
much o--t e      gy released by the ourning fuel is converted
 into waste heat rather than electrical energy. Currently,
 the best overall thermal efficiency of fossil-fuel
 is about 40 percent, with many older plants          plants
efficiencies considerably less than that.     operating  at
is partially dispersed through the smokestacks   waste  heat
Most of it, however, is released into rivers     irnto the air.
water flowing through condensors (used to      or lakes by
                                           change steam back
into water) and returning to its source
                                         at a much higher
temperature (an average of 15 to 20 degrees

*It is speculated that the effects of carbon
 Northern Hemisphere are counteracted for     dioxide in the
                                           the most part, by
 the effects of the large amounts of particulate
                                                  matter in
 the atmosphere.   In the Southern Hemisphere, where particu-
 late matter is not a problem, temperature
 potentially greater.                       increases are

     Unlike air pollution from fossil-fuel steam plants, waste
heat released to the atmosphere is not considered directly
dangerous to public health. The primary problem caused by
waste heat released into water is its effect on aquatic life.

     While the effects of increased water temperatures on
aquatic life are not known with great precision, the extent
of damage is determined by the relative water temperature
and volume released compared to the temperature and size of
the receiving lake or river. Water temperature changes, long-
term or short-term, will alter the composition of fish and
algae population. This occurs not only because the warmer
water reduces the amount of oxygen in the water (proving lethal
to some species) but also because various fishes will no longer
be able to reproduce or compete with other types. In addition
to fish damage, temperature variations affect the growing
conditions of plant life in the water. Guidelines for control
of water pollutants, including thermal pollutants, were
established pursuant to the provisions in the Water Pollution
Control Act of 1972.
     Dispersion of waste heat into the atmosphere also has
potentially adverse effects, especially in urban areas. This
heat dispersion, which can compose up to 15 percent of the heat
generated during the combustion process, can affect the atmos-
phere and climate of a locality by contributing to what is
known as a "heat island effect". This phenomenon occurs when
pockets of warm air settle over an area, increasing the atmos-
pheric temperature and decreasing the air pressure, thereby
influencing the local weather and pollution patterns.

     The emission of harmful elements and gases into the air
raises questions regarding the desirability of increasing
reliance on coal as an energy source and the cost of control-
ling Lhe harmful emissions. The questions are magnified by the
extreme lack of knowledge regarding both trace elements and
other currently uncontrolled emissions.

The environmental aspects of slud e
 enerated by-air quality control
     Handling and disposal of solid wastes (sludge) from flue
gas desulfurization units (scrubbers) is a complex problem
complicated by land availability and disposal costs. Scrubber
waste consists of three general types of material:  fly ash,
calcium sulfate/sulfite salts, and scrubbing liquor associated
with the partially dewatered and chemical characteristics.
For example, trace elements are found almost exclusively in

 the fly ash.   The calcium sulfite nas very poor physical
 properties resulting in inadequate dewatering and structural
 stability features and the liquor contains concentrated
 dissolved salts produced from the scrubbing process.   Despite
 these complexities, disposal and treatment methods have
 started to evolve. However, until the characteristics of
 each sludge component are understood, problems such as
 trace element leachability, sludge dewatering, and beneficial
 use of scrubber wastes cannot properly be addressed.

     EPA, as well as several other public and private
concerns, has initiated field evaluation projects on this
waste disposal problem.  EPA, for instance, has established
a powerplant site field evaluation of the disposal of
untreated and treated flue gas cleaning wastes.  This program
began in September 1974 and is scheduled to continue to
mid-1977 to verify the environmental effects of several
disposal techniques and scrubbing operations, and to develop
cost estimates of alternative disposal methods.

     EPA estimates total sludge fixation and disposal costs
at between $7.30 and $11.40 per ton of waste (dry).* Applying
this cost range to the scenarios, the annual cost for solid
waste disposal would be as follows:

                              Table 4

             Calculation of Annual Waste Disposal Costs

                     for 1985 and 2000 Scenarios

                                   1985                       2000
                            From           To          From            To
    No controls

       Industry plan   $   475.6    $     742.7   $     -      $       -
       BOM                 578.8          Q03.8       763.1          1,191.7
    Using controls

       Industry plan    1,374.9         2,147.1         -               -
       BOM              1,673.3         2,613.1    2,206.2           3,445.3

*Using a 50 percent load factor and a 5-mile disposal site--
 1975 dollars.

 Environmental impacts of
 synthetic fuels

      One option in addressing the adverse air quality
associated with coal combustion is to convert the coal
                                                         to a
synthetic fuel through gasification or liquefaction.
synthetic fuels, however, affect the environment, because
the conversion process itself includes operations
                                                   that can
release pollutants which have been attributable to
nerve ailments, liver diseases, and fatal poisonings.
actual pollutants, their concentrations, and the extent
their adversity are currently unknown.

     The following list shows some of the known or suspected
pollutants associated with gasification or liquefaction

      Air pollutants                    Water pollutants

     Particulate matter                     Ammonia
     Sulfur oxides and                      Cyanide
       other sulfur compounds               Thiocyanate
     Nitrogen oxides                        Phenols
     Hydrocarbons                           Sulfide
     Carbon monoxide                        Alkalinity
     Trace metals
     Hydrogen cyanide

     Some pollutants (sulfur oxides, nitrogen oxides,
                                                      and carbon
monoxide) can be controlled to varying degrees using
existing technology; however, others such as hydrocarbons
could nose a significant health hazard to plant  aerators
and the surrounding environment, and thereby jeopardize
acceptability of the conversion processes.

     To quantify the problem's magnitude, it has been
estimated that a coal liquefaction plant, consuming
tons of coal daily, would produce between 4 and 30
                                                    tons of
sulfur oxides, 60 and 90 tons of nitrous oxides, and
                                                      3 tons
of particulates.  Gasification plants are also expected to
be heavy polluters.  Up to 115 tons of air pollutants
could be emitted for every 40,000 tons of processed coal.
For every ton of coal gasified, at least 1 ton of water
be used. 14/ Solid waste disposal will be an additional would
blem to contend with.

     EPA and the Energy Research and Development Administra-
tion are in the process of assessing the potential environmen-
tal impacts of the synthetic fuels processes. It is hoped
that economical control technology will be developed, enabling

 the gasification and liquefaction processes
 A discussion of EPA's and ERDA's research    to be utilized.
                                           and development
 efforts in this regard can be found on pages
                                               6.45 to 6.49.


      Both surface and underground mining disturb
preduce wastes that require disposal, affect        the surface,
                                                water resources,
and expose materials that produce acids when
                                                combined with
air and water. 15/ In surface mining, the
                                            major reclamation
problem is dealing with surface disruption.
                                                This normally
 involves smoothing out piles of overburden
                                             and attempting to
revegetate the area.   Comprehensive reclamation programs
include restoring the surface topography,
                                            replacing the top-
soil, fertilizing and revegetating, and returning
                                                     the land to
some productive use, whether agricultural,
                                             commercial, resi-
dential, or recreational. 16/   The reclamation
associated with undergroun--mines vary somewhat problems
                                                   from surface
mines.   Reclamation efforts are directed at controlling
                                                           or pre-
venting subsidence, controlling or abating
                                             mine drainage,
disposing of waste materials mined with the
                                              coal, and con-
trolling or extinguishing coal fires.

     The environmental side effects from increased
mining, in general, can seriously affect
                                         the quality and uses
of our land and water.  Such impacts, furthermore, are not
confined to the  immediate mining site, but can be found many
miles away. Some of the more serious environmental
include acid mine drainage, land subsidence, orphanedeffects
denuded lands, and soil erosion and sedimentation.     lands,
tion efforts are necessary during and after the mining
to prevent severe environmental damage and return       process
                                                   the land
to a productive, useful, nonpolluting, and aesthetically
pleasing state.
     A major problem facing policymakers is that some
cannot be abated in an economically feasible manner. effects
Furthermore, the internal incentives to reduce damage
surface productivity or water quality appear to be     to
given existing surface values and current reclamation
costs. 17/ Consequently, chere is some evidence
reclamaETon efforts fail, or have not been made, making
environmental quality a tradeoff for coal development
some areas.                                            in

     The Federal Government has recently enacted legislation
(P.L. 95-87) prohibiting surface mining of certait.
reserves because of potential adverse environmental coal
This legislation is discussed in chapter 3r beginning
p. 3.17.

Environmental effects
     For purposes of this analysis, we segregated coal mining
into three areas--Eastern, Central, and Western. Most of the
environmental effects, such as soil erosion and sedimentation,
are evidenced in each region. However, some impacts are unique
or more significant in a particular region, because the impacts
are a function of climate, topography, and the mining method.
Eastern coal region

     This region is comprised largely of the area known as
Appalachia extending from Pennsylvania to Alabama. The
region's topography is mountainous and most of the area
receiv3s 40-50 inches of precipitation per year.
     Historically, much of the Appalachian economy has been
structured around mining and related activities. Both
surface and underground mining methods are used for coal
     The region is dotted with abandoned surface-mined lands
and waste piles. This mining activity, combined with the
mountainous terrain and humid conditions, has created
serious environmental problems. For example, ' e region
experiences large amounts of acid mine drainaye'and threats
of subsidence from abandoned underground mines. In order to
more fully appreciate the relative impact of the environmental
problems associated with Appalachian mining, it is useful
to ccmpare the magnitude of Appalachia's problem with the
rest of the United States. This can be seen in the following
table. 18/

                             Table 5

              Coal Mining Environmental Problems:

               Appalachia and the United States

                              Acid mine   Subsidence     Unreclaimed
                              drainage       area           lands
                               mile-;                (acres)

 Total Appalachian Region      6,300        73,730         381,180

 Total United States           6,737        99,130         470,000

 Appalachian (percent of
   total)                       93.5         74.3              81.1

       Acid mine drainage
      Acid mine drainage is a mixture of
                                          sulfuric acid, iron,
 and aluminum salts which results from
                                        the oxidation of pyritic
 materials associated with coal and mineral
                                              deposits. The
 reaction produces an acidic pollutant
 life and often carries toxic mineral   which  can damage aquatic
                                       elements (lead, arsenic,
 and copper) which, at sufficiently
 humans and wildlife.               high levels, can threaten

       An accurate assessment of the mine
 difficult because abatement efforts        drainage problem is
                                      are being implemented,
 new mine areas are being worked, and
 being shut down. However, within the mined-out areas are
 the problem is considered severe, as Appalachian region,
                                       evidenced by the table
 above. To further illustrate the severity
 measurements of stream acidity taken          in the East,
 as compared to the Central region showin  northern  Appalachia
 variance of over 10 times--1,700 parts   a  concentration
 versus 140 ppm, respectively. 19/        per million (ppm)

 Land subsidence

      Land subsidence is the collapse or
                                           instability of surface
 land resulting from the cave-in of abandoned
mines. It is a common phenomenon in             underground
                                       the Eastern region.
Subsidence has serious implications
                                     on land use limiting the
potential for building homes or other
face.                                   structures on the sur-
        In Wore rural areas, the subsidence
the land's productive use for farming         threat can restrict
                                        or grazing.
      In most cases, the surface area affected
exceeds the area of the seam extracted.          by subsidence
for instance, a total of 10.6 acres        In  central Appalachia
sidence of 2 acres of coal mined by is affected by the sub-
                                     the room and pillar
method. 20/
Orphan lands

      Orphan lands are abandoned surface
little or no effort has been made to      mine areas wnere
productive or natural state. Pennsylvania mined land to a
alone have some 40 percent of all unreclaimedand West Virginia
in the country. These orphan lands              coal mined lands
to erosion and sedimentation problems,    unsightly, contribute
land use alternatives. Furthermore,      and significantly limit
acres of unvegetated waste banks in there are over 48,500
                                     the East, about 70 percent
of the United States total.

Central region
     The Central region for this particular analysis is an
8-State area* in the midwestern part of the country. The
region has a generally flat to rolling topography, with
the majority of the area receiving 32-48 inches of pre-
cipitation per year. Both surface and underground mining
methods are used within this region.

     The Central region has relatively small coal mining-
related environmental problems compared to the East.
Erosion, acid mine drainage, and siltation problems are
somewhat ameliorated by the relatively level terrain.
Furthermore, precipitation is sufficient to support
vegetation after mining. However, there is one environ-
mental consequence from mining which can be considered
a major problem in this region---that is denuded lands.

     Denuded lands

     Mining causes a chemical and physical decomposition
of the soil which restricts land utilization for agriculture
and may affect the land's capability to support any vegetat-
ion whatsoever. Consequently, land which once was productive
cropland can become a partially denuded wasteland until the
nutrient consistency of the soil is restored. Current fig-
ures indicate that, nationally, about 70,000 acres are
annually being affected by surface coal mining. The
Central region (plus the States of Ohio, Nebraska, and
Michigan) account for nearly 41,000 acres of that total. 21/
Much of the land disrupted during surface mining in the Central
region is classified as prime agricultural land. BOM has
estimated that many of these acres will remain under-
utilized due to mining operations and the loss of soil
Western region
     Western coal reserves underlie 128 million acres of lands
located in areas of diverse climate and terrain such as the
Northern Great Plains, the Rocky Mountains, and the Southwest
Deserts.   Ihe average annual precipitation, for instance,
ranges from 24 inches in the plains to less than 8 inches
in the arid desert areas.   The topography changes from the

*This area includes the States of Arkansas, Illinois,
 Indiana, Iowa, Kansas, Missouri, Oklahoma, and western

 jagged mountains of the Rockies to
                                    the gently rolling hills
 of the plains.  This region has two serious environmental
 problems--disruption of the hydrology
                                       and revegetation.
      Many strippable coal beds in the West
 surface drainage channels and underground   are near or underlie
 meable rock called aquifers.               waterways of per-
 of this coal could cause serious impacts, and surface mining
 rupting the West's fragile hydrologic      significantly dis-
                                       system and causing
 serious s, condary effects.

      During surface mining, for instance,
 channels are often diverted to facilitate natural drainage
Diversion channels are usually constructed coal extraction.
                                             of easily
erodable soil and, during heavy rains,
ways are often polluted by their erosion,        and water-
plant life and fish life.                   affecting  both
                            In addition, underground mining
can contaminate (through saline solutions
usable aquifers which support human,       and other minerals)
                                      animal, and plant life.
In many cases, there is seldom an
thereby significantly reducing the alternate source of water,
                                    already limited ground
water supply.

      Of special interest in the West is
alluvial valley floors--downstream        the preservation
                                    valleys fed by surface of
or near surface streams. These valleys
lands for agriculture and cattle ranchingare the productive
Mining in or near these areas can           in the West.
causing a loss of recharge to the  disrupt  drainage patterns,
                                   alluvial floors and
reducing the valley's productivity.
mining legislation will protect these The recent surface
                                       valleys.   (See p. 3.17.)
     Denuded land

     Established methods for rehabilitating
                                            and revegetating
mined areas in humid environments
                                  are not
ferable to the more arid Western region.  directly  trans-
                                          Therefore, surface
mining in this region can produce
                                  the temporary or permanent
degradation of large land areas.

     The potential for rehabilitating any
area in the West is critically site-specific.
application of proven technologies               The proper
                                    is particularly crucial
if rehabilitation efforts are to be
                                     successful.   Revegetation
of many areas can only be accomplished
and major sustained inputs of water     with good management
                                     and fertilizer.   And in
the case of drier areas of the West,
                                      even these efforts may

not reclaim the land. The National Academy of Sciences, for
instance, has concluded that in desert areas with ten inches
or less of precipitation, permanent revegetation may be
impossible. The only reclamation feasible in these areas
may be to restore hydrologic conditions and minimize
erosion allowing natural rehabilitation to take place, but
this may take more time than is acceptable to society. 22/


     There is a cost associated with mining reclamation
practices. It differs from region to region because the
-osts and efforts necessary are a function of the mining
method, terrain, and climate.
     A 1975 BOM survey of reclamation costs at 31 surface
mine sites provided the basis from which we calculated
the costs per ton and costs per acre of land disturbed.
The following table shows these costs by region and for each
reclamation cost category. See chapter 3 for a discussion
of the cost of restoring mined areas to the original contour
of the terrain.

                                                     Table 6

                                   Surface Mine Reclamation Costs

                              East                                                          West
                                                                     Central-             (7 sites)
                           (15 sites)                               (9sites)              (note
                                                          Cost Per      acre (note b)
                                           Percent                       Percent                   Percent
 Pr     _ining
      anti-pollution    $        233         2.96         $     710       14.55    $      555       19.79
 Permits and    fees              46           .58               30         .61              35       1.25
   bur-ien handling         7,324           92.98          4,048          82.93     2,043           72.81
 Revegetation                274             3.48               93         1.91          173         6.]6
                       $7,877              100.00         $4,881         100.00    $2,806         100.00

                                                               Cost per ton
                                           Prrcent    -                  Percent                  Percent
  anti-pollution       $     -         -                      $.14       15.73          $.04       25.00
Permits and fees            .01               .35
  burden handling       2
                            .70            95.53              .73        82.02           .12       75.00
Revegetation                .12             4.12              .02         2.25           -
                       $2.91            100.00             $.89         10i.o0      S.16          100.00

a/The western sites do not include
                                   irrigation costs in the revegetation
  estimate.  One researcher estimated that this
  per acre by about $500.                       could increase the cost

b/The per-acre cost figures and
                                  the per-ton cost figures are not
   proportions due to variances                                    in di, ect
  Those categories showing less inthan
                                    coal seam thickness of the sample
  totals because they would not affect$.01 have not been included in the
                                         the totals when rounded.

     For underground mining the two primary environmental
effects to which cost factors can be related are subsidence
and acid mine drainage. The following table shows the
cost estimates for these abatement practices:
                          Table 7

             Underground Mine Reclamation Costs
                         Cost per ton
                           (note a)

                                Range_            Average

Subsidence 23/               $1.00-5.00           $1.50

Acid mine drainage 24/       None cited             .0587

a/These costs represent those borne by society to abate past
  damage primarily through demonstration proje-ts. Due to
  technological limitations, coal produce :s are usually not
  required to incur these costs. Curren.. legislation will
  most likely change this situation.

Cost to abate future
environmental impacts
     To estimate possible future environmental impacts, we
used the coal projections included in BOM and Edison Electric
Institute energy     ,arios. For comparison, we used a coal
supply level bas     . industry estimates of planned capacity
additions through  ,85 as a middle of the road case. Note
that the BOM projection is in the approximate range of the
level recommended in President Carter's National Energy Plan.
The following table presents the production levels of the
three scenarios broken down by region and by method of mining:

                                                Table 8
                             Regional Distribution of Coal

                         Production Under Selected Scenarios

                                               1985                                    2000
                                       -    --mTnustry          -
                                 BOM          capacity      EEI                BOM             EEI
                               --------------        (million       tons)      ---- --------.-....
   Eastern                     132.58
   Central                                       133.55    126.53             212.91          126.30
                                88.78             87.48     02.92             141.31
   Western                     357.55                                                          84.43
                                                 281.96    267.30             574.35          340.70
     Total surface             578.91            502.99    476.75             928.57          551.43
   Eastern                     295.42            222.69    2.1.12             474.65          281.58
   Central                      72.58
   Western                                        68.17     64.65             116.06           69.]7
                                41.71             27.97     26.49              67.00           39.76
     Total underground         409.71            318.78    302.26             657.71          390.51
     Total coal production    988.62            821.77     779.01           1,586.28          941.94

 Note:   These figures differ somewhat from
                                             those in chapter 4 because in
         this analysis, Kentucky was divided
                                              into eastern and western.

     We then took these production levels
to the reclamation costs presented earlier and related them
                                            and calculated
the following annual cost to reclaim
                                     surface-mined land,
prevent subsidence, and treat acid mine

*Acid mine drainage occurs, for the
                                    most part, only in the
 East, and will only be applied to coal
 underground mines.                     produced from eastern

                                         Table 9

                          Cost to Abate Environmental     Impact

                     of Coal Mining in 1985 and 2000 Under Various

                                 Production Scenarios

                                                   1985                        2000
                          Cost factor     BOM      capacity    EEI       BOM           EEI
                                         -------------- (millions)----------------
Surface reclamation

  Eastern                      $2.91     $385.8     $388.6 $368.2      $619.6         $376.5
  Central                         .89      79.0       77.9   73.8       125.8           75.1
  Western                         .16      60.8       47.9   45.4        97.6           57.9
    Total surface
      reclamation cost                   $525.6      $514.4   $487.4   $843.0         $500.9

Under rourd Mining


  Eastern                       1.50      $443.1     $334.0 $316.6     $7,12.0        $421.1
  Central                       1.50       108.9      102.2   96.9      174.1          103.7
  Western                       1.50        62.6       41.9   39.7      100.5           59.6
    Subtotal subsidence
      control costs           $614.6                 $478.1   $453.2   $986,6         $584.4

Acid mine drainage (note a)

  Eastern                         .06       17.3       13.1     12.4     27.9           16.5

    Total underground
      mining reclamation
      costs                               $631.9     $491.2   $465.6 $1,014.5         $600.9

Total abatement cost                    $1,157.5   $1,005.6 $953.0 $1,857.5       $1,101.4

        a/It should be recognized that acid mine d:ainage control costs do not
          supply perrmianent solutions but must be continued for several decades
          after the initial extraction.    Thus, these figures can be conservative.

        An analysis of these costs by region for each scenario
   is summarized in graph 1:

                                                    Graph I
                   EAST                             PERCENT DISTRIBUTION OF RECLAMA TION
                                                    COSTS BY REGION UNDER 1985AND 2000
                                                    PRODUCTION SCENARIOS

                   PerLentage distribution                                 Total cost (millions)

         BOM                                        73 1     16.2   10.7              $1,157.5

   INDUSTRY                                          73.2     17.     99              $1,005.6

 1985        EEI                                     73.2            8.9               $953.0

        BOM                                           lul
                                                    73.2     16.1   10.7            $1.857.5

2000         EEl                                    73.1     16.2   10.7             $1,101.4
EMD-77- 43

     The regional comparison shows that, in all cases, the
Eastern region accounts for about 73 percent of the total
costs because:

     -- Almost 44 percent of the expected coal production
        is in the East.
     -- The cost per ton of handling topsoil and overburden,
        which is 95 percent of the cost in the East, is better
        than four times that in the Central region, and about
        24 times greater than the cost in the West. This is
        probably the direct result :f variances in the mining
        terrain between the East and the rest of the country.
     -- The revegetation costs in the East are higher due to
        the need to mulch reclaimed mining sites to prevent
        serious erosion problems.

     Our further analysis shows that mining thicker seams
in the West results in a higher yield per acre of land
disturbed, therefore, making reclamation cost per ton much
less. Overburden handling in the East, for instance, costs
about 6-1/2 times that of overburden handling in the West
when considered on a per-ton or per-acre basis.*
Acres affected by mining
     Another way of quantifying the impact (other than cost)
of coal mining activities under the various scenarios is to
identify the number of surface acres which could be disturbed
in mining the coal necessary to produce a given level of
energy. The following table identifies the number of acres
which may be disturbed under each of the three scenarios
for surface mining activity only. A Ttrojection of acreage
disturbed for underground mining was not attempted
due to the large number of variables associated with
such an estimate.

*Some of this cost variance can be a    buted to the topo-
 graphical characteristic differences, out much of it is
 due to the seam thickness variances.

                                  Table 10
                Estimate of Acres Disturbed Annually

                      During Surface Mining (note a)

                           1985                                2000
                        - ndustry
                        I                --          -
 Region        EEI      capacity              BOM        EEI            BeO,
               ------------------- (acres)--------------

Eastern      55,085      58,141          57,718     54,985             92,691
Central      24,563      25,905          26,305     25,016             41,870
Western     11,440       12,068      15,303         14,582             24,582
   Total    91,088       96,114      99,327         94,583            159,143

a/These figures are based on the following
                                           ton/acre ratios:
  East = 2,297/acre; Central = 3,375/acre;
                                           West = 2 3 ,365/acre.
  (Computations are based on the ton/acre ratio
                                                of 31 surface
  mine sites studied by BOM.)

     To put this into perspective, under
scenario for 1985, the acreage disturbed the  industry plan
                                         is equivalent to
about 150 square miles. For comparison purposes,
                                                    the District
of Columbia is approximately 68 square miles.
we would be digging up annually an area over    So, by 1985,
of the District.                              twice  the size

             C   ONCERNS
     Two major concerns to which we believe
turn their attention have emerged as a resultpolicymakers should
                                               of our review:
     --The environmental consequences of coal extraction
       the degree to which these will become the
       coal development.                          tradeoff for

    --The effect of mining reclamation laws
                                            on coal production.

Environmiaental consequences
of coal mlnlna

     Many environmental consequences can be minimized with
careful planning and current technology. For example, proper
contouring with planned drainage patterns can minimize erosion
and sedimentation from waste piles and mine sites. Denuded
and orphan ladnds can be mulched and fertilized until revege-
tation is established.   (Burying toxic materials under topsoil
increases revegetation success.) The problem, however, is
that current technology and planning cannot economically
abate all impacts of mining, specifically acid mine drainage,
land subsidence, denuded lands, and hydrologic disturbances.

     Acid dra.nage
     According to EPA, acid drainage is the most serious
pollutant arising from mining activities. Utilizing available
technology, acid drainage could be treated or abated; but the
cost has proved uneconomical and, therefore, -he techniques
are not widely practiced.

     Acidic pollutants are generated from both surface and
underground mining. This problem is continually perpetuated
by acidic runoff from abandoned mine lands and unreclaimed
waste piles.  Increased coal mining activities to meet future
energy demands will continue to aggravate the problem.
Sealing underground mines or treating polluted streams to
neutralize the acid are two of the available abatement prac-
tices. The financial commitment necessary to implement these
practices, however, is enormous. For example, a single plant
on Pennsylvania's Rausch Creek neutralizes acid drainage from
18 abandoned and 25 active underground and surface mines.
The plant can treat up to 32 million gallins of acid water
per day and has cleaned a reported 28 miles of streams.
The treatment plant was constructed at a cost of $2.5
million 25/ and has an annual operating cost of $167,000.

      In 1970 the Department of the Interior estimated that
it could cost as much as $6.6 billion to clean up all the
existing acid mine drainage in the Nation. 26/ In addition,
under increased coal development, more waterways would be
polluted by acid drainage, which would lead to additional
abatement costs.

     Land subsidence

     Land subsidence is a serious consequence of underground
mining and, although technology has been developed to control
subsidence, the methods are generally costly and not practiced
other than through demonstration projects.

       Control methods include providing additional
 with grout column3,* or backfilling mine           roof support
 waste, fly ash, or sand and gravel. The   shafts with mine
                                           mining method can
 also influence the subsidence potential,
 ccnsidered a control methodology.         although it is not
                                     For instance, room-and-
 pillar mining leaves columns of coal to
 ports, but deterioration of these naturalserve as roof sup-
                                            pillars leads to
 failure and eventual surface subsidence.

      Estimates of subsidence control methodology
 at best tentative. For perspective purposes,      costs are
 utilized the cost factors of about $34,000     however, GAO
 backfilling and $75,000 per acre for grout per  acre for
 utilizing these estimates to stabilize the columns.  27/
                                            acres already
 affected by subsidence, the Nation would
 $3.4 and $7.4 billion.                   expend between

      Denuded land
      Surface mining in the arid regions
result in a large area of land becoming of the West can
                                          denuded for a long
period of time.   In some areas, in fact, vegetation can never
be restored. Although current reclamation
succeed in humid areas, the practices are techniques can
more arid regions.                           unacceptable in
                     In desert areas, for instance, the only
reclamation potential will be to
hydrologic conditions and minimizerestore  the original
                                    the offsite effects of
erosion. Rehabilitation of some sites may
but probably on a time scale unacceptable     occur naturally,
it may take decades, or even centuries,     to  society because
reach stable conditions. 28/              for  these areas to

      Current revegetation research addressing
 is meeting with good success.                   this situation
                                However, it is only in the
experimental stages with many questions
Commercial application, Therefore, is a still unanswered.
an ever increasing amount of land to remain way off, leaving
                                              barren and scarred.
      The projected cost to implement any of these
methods will be high. In Montana, for example,       research
to revegetate one project area totaled about       the cost
                                               $711 per
acre, 29/ or about four times the average
an acre of land in the West.               cost to revegetate
                               (See Table 6, p. 6.29)    In
addition, the undefinable social costs of
                                           the land which

*Grout columns are constructed from the
                                        surface by drilling
 holes from the surface to the mined cavity
 a mixture of cement and fly ash or gravel and poluring in
 spaces of the abandoned mine.              to fill , rtial

can never be restored must be considered in determining the
consequences of this problem.

     Hydrologic imbalances

      Surface mining operations in the West (especially the
arid and semiarid areas) can have a significant impact on
the hydrologic balance* of the mined area and its environs,
The total extent and severity of these impacts are unknown;
howe'e:r, a few documented cases illustrate the consequences
of the primary and secondary (occurring many miles away)
effects of such an imbalance.

     The hydrologic balance of an area is a complex relation-
ship maintained by a number of factors, including flow patterns
of aquifers, quantitites of surface water, and the erosion,
transport, and disposition of sediments.  The impacts of mininq
on any of these factors can trigger serious consequences
throughout the system. Although mining in arid and semiarid
areas of the West bhs not existed long enough to allow full
analysis of the hydlogic consequences of such activities,
some studies have demonstrated the potential severity.

     For example, in one documented case,

          "The destruction of vegetation in part of
          an alluvial valley triggered substantial
          erosion leading to the deepening of stream
          channels. This lowered the ground water
          levels of adjacent alluvial valley floors
          which in turn resulted in additional
          vegetation loss. As erosion increased
          in the newly denuded lands, the cycle
          worsened. Eventually the entire alluvial
          floor was affected by reducing the amount
          of and changing the nature of the vegetation
          which was essential to the local economy
          as well as the long-term productivity and
          stabilization of the land." 30/
     While this may be an extreme example of the consequences
associated with surface mining in the West, similar disasters
could result from any expansion of mining in highly vulnerable
areas. The primary drawback in preventing such occurrences,
however, is that there is little consensus on which land areas
are, in fact, vulnerable. This stems from a lack of knowledge
and data on what constitutes an aquifer or an alluvial valley

*The hydrologic balance is the equilibrium established between
 the ground and surface water of an area and between the re-
 charge and discharge of water to and from that system.

 floor. Consequently, the leasing and mining continues in
 areas in or adjacent to known alluvial areas. The full
 impact of this situation may not be evident for many years,
 but it is certain that any impact will be long term and
 costly to reconcile, even if reclamation is possible.

      Given the specific level of coal development that may be
 necessary to meet energy needs, the Nation must decide to
 what degree these environmental consequences will become a
 tradeoff to that development.

Mingflreclamation laws

      Until recently, the only Federal control over mining
reclamation applied to mining of coal on federally owned lands
through DOI regulations. In July 1977, the Surface Mining
Control and Reclamation Act was passed (P.L. 95-87), estab-
lishing a nationwide program for protection from the adverse
effects of surface coal mining.

      In 1974 and again in 1975, the Congress passed bills
on regulating the surface mining of coal; both were
vetoed by the President. Federal legislation pro-
posed in 1976 (H.R. 9725) was tabled by th,.n House Rules
Committee. Provisions of this bill were designed to set mini-
mum reclamation standards and provide environmental protection
omitted in regulations applicable to Federal lands and
various States' laws. For instance the bill provided

     -- special reclamation standards for mining areas
        that are difficult to reclaim, that is,
        alluvial valley floors and steep slopes;
     -- requirements to regraae to approximate
        original contour and bury toxic substances;
     --funds for reclaiming orphan lands; and

     -- some control on the surface effects of undercround

     In vetoing earlier reclamation bills, the previous admin-
istration cited several unfavorable results of a Federal law.
Reclamation standards for alluvial valley floors and steep
slopes, for instance, were cited as potentially reducing
mineable coal resources. It was also argued that small mine
operators would not be able to fully comply with. the law's
provisions, resulting in further reductions in coal supply
and increasing unemployment within the industry. In the
final analysis, the administration claimed the proposed sur-
face mining controls would reduce production in the short run,

raise coal prices and higher utility bills,   Ana   increase
reliance on foreign crude oil.

     The new mining reclamation legislation recently passed
in the 95th Congress incorporates many of the environmental
protection provisions of the 1976 legislation.  In addition,
P.L. 95-87 makes the States primarily responsible for
developing, issuing, and enforcing mining and reclamation
regulations which are (at the very least) consistent
with federally established minimum standards.  A federally
established program will be implemented in instances
in which a State fails to comply with the "State program"
requirements.  Furthermore, the act provides for the desig-
nation of areas which are deemed unsuitable for surface
coal mining activity (that is, aquifer lands, prime agricul-
ture land, etc.).  Also off-limits to surface mining because
of the potential adverse environmental effects are: alluvial
valley floors, steep slopes, and certain lands where surface
owners rights are protected.

     Proponents of Federal strip mine legislation contended
it would provide more technically sound reclamation and
better protection of the environment than a system of indivi-
dual State laws.  It is argued that States are disinclined
to impose thorough reclamation standards because this puts
local business at a competitive disadvantage and Federal
legislation will be more consistently enforced and subject
to less political pressure.

      Generally, States favor the development of coal within
their boundaries but want to control the rate of development
-- including the level of reclamation required.  Thirty-four
States currently have some form of reclamation law.   Some of
them are sophisticated and technical with detailed require-
ments, such as segregation of topsoil and regrading to certain
specifications.   Other States have strict laws but do not
have the staffs or funds to adequately enforce them.   Still
other States have laws requiring only minimum reclamation
standards to be met.   In some instances, this laxity results
from the State's desire to stimulate or encourage industrial


       Water supply problems are more regional than
 In certain parts of the West, for instance, water national. 31/
                                                    is either
 in short supply or is already fully allocated, though
 necessarily fully utilized. State and Federal laws, not
 state compacts, international treaties, and Indian      inter-
 treaties govern water availability. In some areas,
 uses or diversion of water, such as with increased
 developmen2, will almost certainly mean a sacrifice energy
                                                       of an
 existing usage or an environmental effect leading
 cost.                                              to  a social

     Major coal deposits in the West are located in several
water resource regions as defined by the Water Resources
Council. As discussed below, the supply of water
                                                  and commit-
ments for water use vary among regions and within
                                                  a single

     The Missouri region encompasses areas of large coal
deposits in Montana, most of Wyoming, and eastern
Water availability varies considerably, both seasonally
over time; droughts occur periodically. Ground-water     and
bility and water quality are also subject to variation.

     This region has potential hydroelectric sites which
be developed. There also exist potential sites           may
                                                for coal-fired
electric generating plants.

     Major problems can be expected in this region. Water
rights for energy must be established with due consideration
for environmental consequences. In some areas competition
for water is expected to be intense.  Facilities are required
to move water to the coal or the coal to the water.
planning and development will be required to protect Careful
     The upper Colorado region includes areas of western
Wyoming and Colorado, eastern Utah, and northern New
which contain large bituminous and subbituminous      Mexico,
deposits as well as petroleum, natural gas, and oil
resources. There are also plans to expand coal-firedshale
generation in this region.                             electric

     Most available surface waters are committed to local
downstream delivery and transmountain transfer.            uses,
                                                 Stream flows
fluctuate widely in time and space. The quality
                                                 of the sur-
face water is generally very good, although it decreases
the lower regions. Ground-water quality varies considerably
and is generally not as good as that of the surface

The availability of water for use is limited by physical condi-
tions, institutional regulations, economic considerations,
and environmental and social impacts. Although thermal pollu-
tion has been minor to date, it is expected to increase.

     The major problem is limited water supply in an area
of major energy resources.  The water rights granted by the
States in some streams of the region exceed the water available
during low flow periods.

     The lower Colorado region encompasses Arizona and
western New Mexico. The region has significant coal deposits,
and plans are being made for a steam-electric generating
     The Colorado River compact obligates the upper Colorado
region not to den'"        flow entering the lower Colorado
region below ~        .'.. if 75 million acre-feet over any
10-year p '    ·    '.o.    rage annual amount of 7.5 million
acre-feet, ;he               gion has a priority to 4.4 million
acre-feet. In aa,.           re is some precipitation as well
as ground-water to .        supplies. Water quality in this
region is generally n_. as good as in other parts of the

     Withouc  A       n. qater imports, ground-water overdraft
(pumping ouL mot, .atel- than is replenished naturall,0 will
continue. Increasing the water supply without increas'
ground-water overdraft is a major problem in this area.

Use of water for energy development
     The largest water withdrawals in the United States a.e
for cooling purposes in electric generating plants. The cur-
rent most widely used system--which can be referred to as a
once-through system--returns the water to the rivers. Other
systems that use less water have been proposed. Some of
these alternative systems are cooling ponds and dry and wet-
dry systems. Water will also be consumed in the processes for
converting coal to gas or liquid fuels. The following table
shows the water needs for various energy processes. 32/ The
wide range of numbers in the water requirement column reflects
a variety of available practices.

                             Table 11

              Water Needs for various Energy Processes
    Enegx system                     Water needs
Steam-electric nuclear
 Evaporative cooling       17,0n0   dcre-ft/yr/i,'OOMW    unit
 Pond                      12,000   acre-ft/yr/i,OQOMW    unit
 River                      4,000   acre-ft/yr/l,000MW    unit
 Wet--dry radiator          2,000   acre-ft/yr/l,000MW    unit
Steam-electric coal
 Evaporative cooling       15,000   acre-ft/yr/1l,000MW   unit
 Pond                      10,000   acre-ft/yr/l,000MW    unit
 River                      3,600   acre-ft/yr/l,OOO0MW   unit
 Dry radiator               2,000   acre-ft/yr/l,OCO4W    unit
Geothermal                 48,000 acre-ft/yr/l,OOOMW unit
Natural gas                50,000 acre-ft/yr throughout the West
Crude oil                  50,000 acre-ft/yr throughout the West
P£fineries                 39 gal./barrel/crude
Oil shale                   7,600 to 18,900 acre-ft/yr/100,000
                            bpd plant
Coal gasification         10,000 to 45,0r0 acre-ft/yr/250
                          million standard cubic fec,/day plant
Coal liquefaction         20,000 to 130,000 acre-ft/yr/100,000
                          bpd plant
Coal slurry pipeline       20,000 acre-ft/25 million tonti       coal
Coal mining
  vegetation re-          .5 t, 4 acre-ft/acre/yr (some areas
  establishment           may require 2 years)

     Although the table shows water needs of various energy
processes, in some nrocesses the water is returned 'o streams
and can be r-used for industrial, agricultural, and municipal
treatment. Therefore, it is informative to consider the
consumptive wa'er requiremerts for various processes. The
following table sets out the water requirements of several
energy processes per million Btus. 33/

                              Table 12

                     Water Consumption Requirements

                     For Selected Energy Processes

     Energy source                Consumptive water requirement
  Steam-flectric-nuclear    200   to 2,000   lbs.   water/million   Btus
  Steam-electric-coal       200   to 1,350   lbs.   water/million   Btus
  Coal gasification         800   to 1,350   lbs.   water/million   Btus
  Oil shale                 100   to   240   lbs.   water/million   Btus
  Coal slurry pipeline        0    to 110    lbs.   water/million   Btus
     The water needs of energy processes, presented above,
suggest that western water resources would be better
served by shipping a coal slurry out of the region than
shipping out electrical power or synthetic gas.          by
from a water standpoint the shipping of coal by convy
means of transportation (for example, rail, barge, etc.)
do not normally have a consumptive water requirement,
                                                       is more
attractive than the slurry pipeline.

     Competition for water rights may increase water prices
but probably would have an insignificant effect on
of water used for energy production.                the amount
                                      The dollar return for
water used for energy p-F'uction is undoubtedly'much
than it is in many other .ses, sucn as agricultural
irrigation.  Therefore,  arke- effects may diver- water from
agricultural and industr.al u_. to energy production.

      The primary control mechanisms for water use in the
are with water rights and other agreements                   West
                                             for water alloca-
 tion and not necessarily water supply.   International treaties
with Canada and Mexico control streams flowing   across U.S.
boundaries.   Additionally, the Congress has approved numerous
interstate compacts on interstate streams.    The waters are
generally apportioned among the States and each State
                                                         is then
left to allocate its share of the water among intrastate
      Indian water rights stem from treaties and agreements
approved by the Congress or executive orlers.    These claims
have water right priority as of s.,edate the reservation
established and maintain their validity even though         was
exerci.ed.   In ad;ition, State and Federal regulations further
control and even   estrict water use in Western States.
these agreements and allocations deplete the water         All
                                                     supply "on
paper," though they are not necessari)- physically depleted.

In any event, water for additional uses, such as energy
development, may not be available. As western coal deposits
are developed, an increasing demand will be placed on water
resources for coal conversion and generation of electricity.
Potentially, this demand for water may not be met in the West
because of reluctance to convert water rights from existing
uses and coal may have to be shipped to other geographic areas
where water is more plentiful.

     Expanding the use of coal as an energy supply source
(with its resulting adverse environmental impacts) is not an
either/or proposition, because the adverse impacts may be
mitigated through good management bnd continued research and
development. A discussion of the Federal Government's efforts
to develop environmental control technology follows.

     Seventeen Federal departments and agencies conduct
energy related environmental research under the auspices of
the Interagency Energy/Environment Research and Development
Program. The Interagency Program, which is planned and
coordinated by EPA, is a 5-year effort begun in fiscal year
1975 to stimulate the development of domestic energy resources
by providing both the environmental data and control techno-
logies necessary to safeguard human health and welfare.

      Environmental control technology research is conducted
in three areas: coal extraction and preparation, direct
burning, and coal conversion. The research is carried out
primarily by three Federal agencies--rPA, BOM, and ERDA.
However, the Department of Agriculture and the ¶Tnnessee
Valley Authority (TVA) also perform control technology
research. The objectives of this research are to develop
techr.-'ques or technology that will allow coal to be mined,
converted, and burned without serious environmental impacts.

     Research is being done on controlling coal combustion's
harmful atmospheric emissions. Although further improvement
is desirable, methods are currently available for controlling
sulfur oxides and nitrogen oxides emissions.  However, control
technology is not currently available for trace elements and
for fine part.culates that are less than 1 micron in size.
.n addition, the process of converting coal to synthetic fuel
gives off certain emissions which may be harmful.   Little is
known about the environmental consequences of conversion pro-
cesses, but resfearch is currently underway to assess the
emissions from these processes and develop control technology.

     Research into controlling the environmental effects
of coal mining addresses the problem areas of land sub-
sidence, acid mine drainage, and land reclamation. There
are methods of treating acid mine drainage and controlling
land subsidence in abandoned mines; however, the cost of
treatment is high. Due to the high cost, the current
research effort is directed to prevention of acid mine
drainage and land subsidence.
     Most mined lands can be reclaimed with current tech-
nology. However, some lands in arid and semiarid regions
like those in the West are not currently reclaimable, and
it is on those lands that research is concentrated. In
addition, research is being done to improve reclamation
methods and reduce the cost of all land reclamation. If
the low-sulfur coal deposits of the Western United States
are to be developed, it is essential that adequate land
reclamation techniques be developed. Further, since
increased coal production means opening more mines, it
is essential that methods for preventing acid mine
drainage and land subsidence be developed.
Coal extraction and preparation
     Research in the extraction program addresses potential
problems and control methods for underground and surface
coal mining. The overall objectives of Federal research
efforts in this area are to provide data and analysis to
assure that coal mining operations, surface and underground,
can be conducted with adequate land and water protection.
Underground mining research specifically addresses methods
of controlling or preventing acid mine drainage and lard
subsidence, and disposing of mine waste. Surface mining
research addresses techniques for returning mined lands
to a usable form and reducing adverse environmental impacts
on affected land and water resources.

     The products from this research will be instruction
manuals which delineate the problems and provide cont-ol
methods, technical handbooks on vegetation of surface mined
lands and spoils in the Eastern and Western coal mining
regions, and improved mining equipment and techniques.
The manuals and handbooks should be available for use by the
coal indust:y and other related groups in the early 1980s.

     The primary objective of coal preparation resedrch is
to develop commercially available processes for reducing
ash, sulfur, and potentially hazardous trace elements
from coal prior to combustion. Coal cleaning results in a
less polluting and more efficient fuel. Research in this area
is being conducted by EPA, ERDA, and BOM. These research

efforts involve evaluating current coal cleaning technology
and developing advanced technologies for cleaning coal.
Methods being evaluated or developed include

     -- conventional ash removal methods to remove
        pyritic sulfur;
     -- advanced coal cleaning methods; and
     -- chemical cleaning methods involving leaching,
        hydrogenation, acid, or caustic treatment.
EPA estimates these types of coal cleaning technologies
may be available to industry by the end of 1981.

Direct burning
     Developing technology which will control the pollutants
released in coal combustion may permit expanded use of coal.

      The technology to remove sulfur dioxide after com-
bustion is called flue gas desulfLtrization (FGD). This
removal process can be divided into two major categories--
nonregenerable and regenerable.* FGD systems which reduce
sulfur oxides emissions to acceptable levels are commercially
available, but reliability problems and high maintenance
costs have restricted widespread application. EPA's
research efforts in this area are directed toward upgrading
operating performance and reliability, minimizing maintenance
costs, developing second generation regenerative FGD systems,
improving waste product disposal techniques, and improving
byproduct recovery techniques.

     TVA, BOM, and ERDA also sponsor flue gas cleaning
research projects. EPA iz currently estimating that the final
report on the FGD control technology development program will
be completed by 1979.

*In a nonregenerable FGD system, an agent (lime or limestone)
 combines chemically with the sulfur oxide- from the flue gas,
 and the resulting product is then removed from the system and
 discarded. The discarded product presents waste and water
 pollution problems, and the proper disposal of the residue
 is very important.  In a regenerable system, the waste dis-
 posal is a lesser problem because after the sulfur oxides are
 removed from the flue gas, the agent (metal carbonates or mag-
 nesium oxide) and sulfur are recovered for reuse.

      Nitrogen oxides emissions from coal combustion can be
generally controlled by either modifying the combustion system
or by employing flue gas denitrification technologies. EPA's
research efforts are directed toward developing both of these
controls. EPA's analysis has shown that the combustion modi-
fication approach can meet current nitrogen oxides emission
standards. The program builds on the existing techniques,
while also generating new technology. The research efforts
range from minor hardware changes on existing boilers for
near-tern control technology to complete combustion system
redesign. EPA estimates that the technology for combustion
modification will be accomplished in the 1980-1985 time frame.

     EPA is also researching flue gas treatment techniques
for removing nitrogen oxides. This effort is relatively new.
A 196S study concluded that combustion modification and not
flue gas treatment offered the most promising control

      Fine particulates pose a health hazard as already noted.
 When these particulates combine with trace elements, the health
 hazards are compounded.  (See p. 6.15 for effects.) Technology
 exists to remove most fine particulates but 1 to 2 percent
 usually escape into the atmosphere. They are usually less
 than 1 micron in size and are thought to be the most harmful.
 EPA's control research program is seeking remedies for
.deficiencies in existing control equipment, and advances in
 removal technology. EPA currently predicts research will be
completed in 1978.

     EPA does not currently have a control technology program
specifically for trace elements, but the Agency contends
that the technologies for sulfur oxides, nitrogen oxides,
and particuilates will remove and control some trace elements.
EPA is assessing trace elements as part of 4 ts Combustion
Pollutant Assessment Program and will develop control

Coal conversion

     Synthetic fuel processes are being developed to convert
coal to clean burning gas or oil. These conversion pro-
cesses themselves, however, include various operations
which would release hazardous particulates and hydrocarbons
into the air and ha'ardous chemicals into water sup!?lies.
The actual detriment to the environment, if any, of the
conversion processes is not known.

     EPA has the primary responsibility for assessing the
environmental factors of energy technology and for developing
controls to protect the environment from adverse effects.

 EPA and ERDA have research and development programs which
 seek to insure an environmentallly sound synthetic fuels
 industry. These research efforts have two objectives--
 to determine the potential environmental impacts of syn-
 thetic fuel processing operations and to develop control
 technology to minimize the negative aspects of these
 impacts. EPA programs underway in this area are:

      -- Evaluating the environmental problems associated
         with conversion of fossi. fuels into synthetic
         fuels, using an approach that will characterize
         all potential pollutants which would be generated
         during synthetic fuels development.
      -- Developing and demonstrating technology to
         control pollutants resulting from synthetic
         fuel development.
     ERDA's research efforts are directed to defining
problems and quantifying environmental effects of both
existing coal conversion processes and those under
development. ERDA's research efforts are:

     -- Classifying processes in terms of   11 pollutants
     -- Surveying coal processing programs funded by
        ERDA to assess environmental studies planned
        and needed.
     -- Surveying available pollution control technology
        from existing and planned pilot plants.   (Controls
        in related industries are being considered for
        adaptation to copl processes.)
     -- Developing test programs for analysis of pollutants
        from each synthetic fuel process.
     -- Selecting, instil.
                         1 ing,
                                and observing pollutant
        monitoring instruments.
     As stated earlier, the environmental effects of coal
conversion processes are unknown, and it is important for
these effects to be identified and proper control techniques
developed before coal conversion processes are commercial-
ized. Several of the second generaton conversion
will be demonstrated on a relatively large scale in technologies
                                                     the next
5 years.


     Of all the costs associated with increased coal produc-
tion and consumption, the nonmonetary ones are perhaps the
most important--the degradation of the environment
and the social changes that wi! - occur in some areas. Social
changes are discussed in chapter 7.

     The amount of pollutants emitted during coal combustion
can be enormous.  Current Federal and State regulations seek
to control certain coal pollutants--sulfur oxides, nitrogen
oxides, and particulate matter.  This effort is costly.  Under
the BOM scenario, GAO estimated the cumulative capital costs
for emissions control to be about $19.1 billion in 1985 and
$26.4 billion by the year 2000.  Under an industry scenario,
these costs will amount to about $15.9 billion by 1985.  Con-
sequently, the average residential consumer's electric bill
could increase by 9 to 10 percent in 1985 under these

     In addition, disposing of the sludge collected in
pollution control devices such as scrubbers will be costly.
To put this sludge problem into perspective the pollution
control waste material generated annually under the industry
scenario in 1985 is equal to the municipal waste generated
in the United States during the course of one year.

     Despite the costs, there are certain coal emissions
which are not currently regulated.

     First, the pdrticulate cozntrol technology in use today
is only partially effective in preventing fine particulates
(1 micron or smaller) from escaping into the air.   These fine
particulates are alleged to pose a special health hazard
because of their ability to penetrate the respiratory system.

     Second, the current regulations do not control other
pollutants which are considered dangerous    human health.
In particular, there are no controls on th   mission of
trace elements emitted in coal combustion :.ch as mercury,
lead, beryllium, arsenic, fluorine, cadmium, and selenium.

     Moreover, the majority of the acidic sulfate pollution
is attributed to coal combustion.   Control of sulfates in
the atmosphere may not depend solely on the control of
sulfur dioxide, but on control of precursors such as fine
particulates and nitrogen oxides.   EPA projects the sulfate
levels in 1990 to be similar to the 1975 level--a level
which may cause serious health problems as well as acid
rains which h.arm plant and animal life.

     Another coal pollutant which is not controlled is carbon
dioxide. This carbon dioxide build-up could cause global
changes in the weather. With continued growth in the use of
fossil fuels, the effect of coal combustion on climatic con-
ditions may become an important problem during the next 50

     The chief environmental problems of coal production
include acid mine drainage, land subsidence, denuded lands,
soil erosion, and sedimentation. A major problem facing
policymakers is that some of these effects cannot be abated
in an economically feasible manner. Further, the internal
incentives to reduce damage to surface productivity or water
quality appear to be modest, given existing surface values and
current reclamation costs. Consequently. some reclamation
efforts fail or are not even taken making the environmental
quality a tradeoff for coal development in some areas. The
Surface Mining Control and Reclamation Act of 1977 (P.L. 95-87)
established a nationwide program for protection from adverse
effects of surface coal mining.

     Surface mine reclamation, subsidence prevention, and
abatement of acid mire drainage will cost about $1.2
billion under the BOM scenario and about $1 billion under
the industry scenario by 1985. The Eastern region
accounts for 73 percent of these total costs.

     Under the BOM scenario, some 99,327 acres of land
will be disturbed annually by coal mining in 1985 and 159,143
in the year 2000.  Under the industry scenario, some 96,114
will be disturbed by 1985.

      In the Western region, a special problem associated
with increased coal development is water availability.
surface mining can adversely affect the hydrology of certain
areas, causing a lowering of ground-water levels. Coal
electricity generation and coal gasification-liquefaction
processes require large amounts of water. As western coal
deposits are developed, an increasing demand will be placed
on water resources for coal conversion and generation of elec-
tricity. Potentially, this demand for water may not be met
in the West, because of the reluctance to convert water rights
from existing uses, and coal may have to be shipped to
other geographic areas where Rater is more plentiful.

     Seventeen Federal agencies and departments conduct
energy related environmental research and all phases of
coal production and consumption are being studied.

                     FOOTNOTE REFERENCES

 1/United States Environmental Protection Agency, National
   Strategy For Control of Sulfur Oxide From Electric Power
   Plants (Washington: EnvlronmentaT Protection Agency,
   T974T),   p. 1.
 2/Executive Office of the President, The National Energy
   Plan (Washington: U.S. Government Printing Office,
   T77), p. 67.
 3/University of Oklahoma, Energy Alternatives: A Comparative
   Analysis (Norman: University of Oklahoma,97S5, p. 12-8.

 5/United States Department of the Interior, United States
   Energy Through the Year 2000 (Revised) (Washington:
   Department orttIe-Inteior, -197/, -p. 3.
 6/National Coal Association, Steam-electric Plant Factors
   (Washington: National Coal Ass, -iation, l17T    pp.- rto 72.
 7/United States Environmental Protection Agency, A Preliminary
    Analysis of the Economic IL.lpact On the Electric -Utlity
   ·Industry o AEernative Approaches to Significant Deteriora-
    tion (Washington:  EnvironentaProtection Agency,
    1976), p. 1-2.

 8/Federal Energy Administration, "Letter to Senator Moss
   Outlining the administration's Views on the 1976 Proposed
   Amendmients to the Clean Air Act" (Washington: Federal
   Energy Administration, 1976), pp. 1 and 2.
 9/Temple, Barker & Sloane, Inc., Economic and Financial Impacts
   cf Federal Air and Water Pollution Contro-s on T.;e Electrlc
   Utl-ty- Indust   (Wcllesley Hills: Templ    Bardm   & Sloane,
   Inc., -1976, pp. 29 to 31.
10/Robert E. Trumbule, et al., Research and Development Relating
   to Sulfates in the Atmospher  (shington:    The Library
   of Congress,7 975, pp. 2 to 6.

11/Federal Energy Administration, Electric Utilities, Clean
   Air Act Amendments, and Sulfate -(Washington:  F-e-eral
   Enerqy-A'm-inistratio.a, 1975) , p 5.

 12/United States Environmental Protection Agency, Clean Fuel
    Policy Status Report (Washington: Environmental
    Protecton Agency, 975), p. 1.
 13/National Academy of Sciences, Geophysics Study Committee,
    Energy and Climate (Washington: National Academy of
    Sciencies, T-'77).
 14/Stewart W. Herman, et al., Energy Futures - Industry and
    the New Technologies (New York:  Inform, Inc., 1976), pp.

15/University of Oklahoma, op. cit., p. 1-37.

17/Richard Nehring and Benjamin Zycher, Coal Develojment and
   Government Regulation in the Northern Great Plains: A
   Preliminary Report   -aaiaMonica: Rand Corporation, T976),
   p. viii.

18/H. W. Durrwachter, et al., Environmental & Natural Resources
   Program Design Vol. II - Part 3 (State College: HRB -
   Singer, Inc., 1 , -p. 15:     -
19/University of Oklahoma, 2o.    cit., p. 1-53.
20/Ibid., p. 1-56.
21/krgonne National Laboratory, Surface Mined Land in the
   Midwest: A Regional Perspectve for Recimatio'n PlannTing
   (Argonne: Argonne -Fatialo n & iaratory, 197~) p. 14.
22/National Academy of Sciences, Rehabilitation Potential of
   Western Coal Lands (Cambridge: Ballinger PublT-shi-  Company,
   1974), p. 2.
23/National Academy of Sciences, Underground Disposal of Coal
   Mine Wastes (Washington: National Academy of Scienes,
           p. 71.
24/Elsie F. Kendrick, et al., Appalachia (Washington:
   Appalachian Regional Commission, 1974 p. 7.

25/Karl E. Gustafson, "Project Report:   Rausch Creek Acid
   Stream Treatment Plant" (report provided at the Rausch Creek
   Treatment Plant, Valley View, P,'nnsylvaiia, July 14, 1l76).

26/Kendrick, op. cit., p. 6.

27/Durrwachter, et al., op.   cit.,   p. 10-21.

28/National Academy of Sciences, Rehabilitation Potential of
   Western Coal Lands, op. cit. p. 2.
29/Ibid.,   p. 87.
30/United States Congress, House Committee on Interior and
   Insular Affairs, Surface Mining Control and Reclamation
   Act of 1976, Committee Report, 9 Coingress,   2d Sess-io-n,
   on H.R. 9775, March 12, 1976 (Washington: Government
   Printing Office, 1976), p. 59.
31/J. Bnutani, et al., An Analysis of Constrzints on Increased
   Coal Production- McLean: The MITRE Corporatin, 197i),
    .   10-*.

32/Western States Water Council, Western States Water Require-
   ments For Energy Development to 1990 (Salt Lake City:
   Western States Water Council, 197-; p. 25.

                          CHAPTER 7
     Increased coal development will entail costs as well as
benefits for the localities in which they occur, and che
smaller and more rural the community, the more significant
the impact will be. New miners, construction workers, and
plant employees will be required in these areas. With the
influx of population will come an immediate need for public
facilities and services which will require advanced planning
and financing if they are to be provided in time to meet the
need for them. The newcomers will bring new ideas, values,
and behavior patterns; and the old social order will change.

     Later, a bust condition may occur. The coal will be
depleted or market conditions may change. If sufficient
economic diversification is achieved in a region, however,
it may reduce the effect of a decline in one industry.

     Socioeconomic concerns that will arise with new coal
development are:

     -- Local governments should have advance information
        on development and the capacity to plan for it.
     -- Local governments should have the initial financing
        for the increase in needed facilities and services.
     -- Social changes must be expected.

     --Coal development areas may experience bust conditions
       arising from a sudden reduction or termination ot coal
       development. Such an eventuality should be planned for
       and measures taken to avoid adverse impacts.

     --Coal development areas will experience socioeconomic
       changes that should be considered in policy decisions.

     Developers dr, not always provide accurate and timely
data about their plans to local governments, thus preventing
the governments from taking action to prevent or mitigate
undesirable effects of rapid growth. This was demonstrated
in the case of Rock Springs, Wyoming.   in January 1970,
before any announcement of energy development, the city
hired a planning firm to give the city a plan fo.- develop-
ment. Five months later, cwo industrial firms announced
plans for a coal-fired steam electric plant, with 285

additional employees by 1971 and 920 additional employees
by 1974.  Based on these figures, there appeared to the
city government to be no problems with any -rdinary five
percent growth rate and normal planning procedures.   Then,
two things happened which ignited the boom.   Plant employ-
ment soared to 3,000 people in 1973, instead of 920 people
in 1974, and four major chemical plants in the immediate
vicinity had plans for major expansion but told the city
nothing about them.   In addition, related service industries
were attracted to Rock Springs, which swelled the population
even more. 1/

      In January 1972, the city received the plan it had con-
tracted for.   On the basis of employment projections furnished
by mineral, utility, and construction employers, the plan
projected a population increase to 15,000 by 1975 and 26,000
by 1990.   Rock Springs actually reached the 1990 figure of
26,000 in 1973. 1/

      Some companies recogni-e that it is in their best
interest to convey their plans to local governments because
community living conditions can affect workers' pro-
ducti.vity.  Action has been taken by some to provide local
governments with timely information.   In Gillette, Wyoming
(near which eight new coal mines are planned or under
construction, a coal-fired electrical generation plant is
being constructed, and a 120-mile long railroad line is
planned to be constructed) developers have for at least two
years furnished forecasts of their activities, including
estimates of employment by year, to the local governments.
These estimates were used to prepare a profile of future
economic activity included in a 1976 study of economic
base and growth potentials commissioned by the local gcvern-
ments, with funding assistance from the State and Federal
Governments. 2/ With the information in the report, the local
governments siould be in a position to plan for future

     Industry possesses the most advanced information on
development and the time needed for community develop'nent.
Companies which recognize a relationship between wor, r pro-
ductivity and maintaining an acceptable quality of life in
a community will more likely volunteer their plans to local
governments and work with them to plan for needed facilities
and services.

Note:   Numbered   footnotes to ch.    7 are on pp.   7.42   to   7.50.

       Irdustry probably cannot be expected to take
 initiative in all cases, but Stateu can take        thne
                                               actions to
 encourage or require developers to provide
 arid accurate data to local governments.    advance notice
                                           Such actions include
      --creatino author 4 ty, either legislatively
                                                   or or:
        Executive oLder    requiring advance notification
        of development, and

      -- setting, by development permit, derinite
         periods between the annou:nement and comlencement
         of development to allow local governments
                                                    to plan
         for and begin providing needed facilities.
     The Federal Government could, in some
involved in assuring that information neededcases, become
for coal development at the local level is     for planning
                                             provided    In 1976,
the administration Proposed bills to the
                                           Congress whiich would
directly or indirectly involve the Federal
subsidizing of energy projects, including    Government in the
                                            development of
synthetic fuel production from coal.   Suc ' legislation may
in the future again be considered by the
                                          Congress and
could include a. provision to require the
                                           industry receiving
the funds to work with local 'governments
                                          to keep them abreast
of development plans.

      :t should also be noted that much ot the
                                                coal in the
West is on Federal lands.   iedcarai coa lessees could be
required to make their plans for A6velopment
                                               known cuarly
enough to enable local governments t{ act,
connection with requirements that industry   In  addition, in
                                            tile detailed
development plans with the appropriate Federal
management agency, these Federal agencies
                                           could also be
given a responsibility for keeping the local
informed at each stage of development.

     Currently, the Office of Managemeni and Budget
Circular A-95 suggests that Federal agencies
                                                engaged in
direct development of Zederal projects should
local governments that might be affected         consult with
                                            by those projects.
OMB informed us that -hey n.aty change A-95
                                             to require that
Federal agencies notify local governmrents
actions and that this requirement would include nropcsed
coal leases.  This action might improve the flow of infor-
mation to local governments arid better enable
for meeting the needs of rapid population        them to plan
                                             growth resulting
from Federal coal 1( aseq.


     The ability of local governmenits to provide new and
expanded public services is one of the most critical socio-
economic problems associated with coal development. Capital
outlays of significant magnitude will be required to provide
public facilities and services, such as schools, health care,
municipal water services, sewers, parks, playgrounds, roads,
and jails. During a period of rapid population growth, ser-
vices will be needed immediately, whereas revenues will not
come until the plants go on the tax rolls and residents become
taxpaying citizens. The time disparity between the need for
public services and the revenue to pay for them can cause
considerable social disruption as well as dissatisfaction
with local governments.
     An example:   Sweetwater County, Wyoming

     Rock Springs and Green River in Sweetwater County,
Wyoming, illustrate what happens to communities that are
unprepared and underfinanced to face rapid population
increases. Concurrent rapid devciopment of oil and gas
resources, construction of a coal-fired electric generating
plant, and development of Ather mineral resources caused the
county's population to rise from about 18,000 in 1970 to about
37,000 in 1974. In the process, the local government's abi-
lity to provide necessary services was impaired, industrial
productivity dropped, and the quality of life declined.
Sweetwater County's population had grown at a compound annual
rate of about 19 percent. A five percent compound annual growth
rate from 18,000 to 22,000 is about all that could have been
easily absorbed without some adverse socioeconomic
effects. 4/
     The population grew beyond the capability of existing
institutions to cope with their needs. With few vacant
houses, the permanent housing market was insufficient to
accommodate the construction workers brought from the outside,
and prices of recently built homes rose too high for the
average worker.  Little sewage treatment capacity was avail-
able, so developers of large housing projects had to build
treatment facilities. About half of the land around the com-
munities was federally owned, and the remainder was closely
held by a few private owners. The scarcity of available land
resulted in high land costs. High interest rates drove rome
mortgage costs to record highs. Permanent housing units could

 not be built fast enough to keep pace with demand. As
 result, 4,500 to 5,000 mobile homes were used to accommodate
 the growth in Sweetwater County. 5/

      Other problems also degraded the quality of life.
 In 1970, Sweetwater County had a ratio of 1 doctor for
 1,800 people. In mid-1974, the ratio had fallen to 1
 for every 3,700. The statewide average was I to 1,100  doctor
 and the nationwide average was about 1 to 612. 7/ Health6/
care became a major problem for the county and about
                                                      40 per-
cent of its residents had to seek care elsewhere. 8/
      The mental health clinic caseload grew ninefold, while
the population was doubling. Long-time residents accounted
for much of the increase. The rates of alcoholism, broken
homes, suicide attempts, and suicide all increased. 9/
      Much of the population increase after 1970 was housed
outside incorporated communities in scattered fringe
developnirnts. Such settlements offered little opportunity
or encouragement for newcomers to participate in the
community. Social cohesion suffered as alienation and
emotional distress fed on each other. 9/

     Recreational, cultural, and adult education facil-
ities did not keep pace with growth.  Organized year-round
recreation for youths was particularly lacking, and extensive
expansion of indoor facilities was needed. 10/

     Many schGols were strained beyond capacity. Both the
Green River and Rock Springs school districts were bonded
to the State constitutional limit of D1,percent of assessed
valuation. They were not able to finance  the needed coun-
seling, school social workers, or other personnel to
                                                     meet the
needs of the students. 10/

     Retailing and service facilities also failed to expand
aE rapidly as total employment. Crime rates went up.
Burglary and larceny particularly increased tremendously.
Telephone service suffered. The cost of living rose
than the national rate, and local salaries, particularly
local services employment, did not keep pace.             in
                                               In addition,
because of the emphasis on construction and mining,
ment for women lagged behind total employment. 11/ employ-

     The problems affecting the quality of life were more
than a matter of inconvenience; tney disrupted industrial
activity in Sweetwater County. Employee turnover rose

in 1973, ranging from 35 to 100 percent among the different
mining employers. Both employee turnover and reduced pro-
ductivity were attributed to difficulties in recruiting and
retaining satisfactory employees willing to live under boom
town conditions. 12/
     The demands on Green River and Rock Springs for addi-
tional municipal services, such as police and fire protection
and the capital construction costs for water, sewer, and
sanitation, surpassed the communities' abilities to pay for
them. They supported themselves through revenue sharing
funds and a variety of taxes and fees, but these revenue
sources offered no increased borrowing capacity. As a
result, the local government in Sweetwater County was
underfinanced and unable to furnish the basic services and
facilities required by growth. 13/
     Beginning in early 197 . the growth rate leveled off,
giving Sweetwater County and its cities some timc to catch
up with needed expansion of facilities and services. The
slowdown in the growth rate since 1974 was accompanied by
substantial increases in assessed valuation and bonding
limits. 14/

     Measures have been taken by local governments to
improve the quality of life in the county. The Rock Springs
school district has expanded its capacity and added to its
special education staff. The broadened tax base will support
needed special education programs, additional teaching staff,
and facilities with minimum reliance on borrowing. 15/

      Health care capacity in Sweetwater County has been
improved by bringing in more physicians (mostly through
the National Health Service Corps program) and physician
assistants. Additionally, a health maintenance organization,
subsidized by the Federal Government has been added; con-
struction of a new county funded hospital has begun; and
there has been an expansion of professional psychological
counseling services. The level of health services is still
inadequate and will require continued attention and
effort. 16/

     Housing demands have been largely met by considerable
single and multifamily construction, mobile homes, single
worker complexes, and some substandard housing. New
mobile home parks are under construction. With a decrease
in construction employment levels, mobile home spaces have
become increasingly available. There has been an increase

 in permanent housing in Rock Sprir.gs, and
 available for single tamily units Irom bothfinancing is
 anti savings ana loan associations. Permanentcommercial banks
                                                housing will
 s ill not be available to all who desire it--the
 too expensive for a large segment of the potentialhousing is
 Construction workers have aitticulty in qualifying market.
 mortgage loans, and a shortage of land arid Lestrictions
 sewage treatment facilities have limited development     on
 alternatives. 17/

      Community programs to proviae recreational facilities
 have been limited; however, an extensive recreational
 is being planned north of Rock Springs by the          complex
 county for completion in 1977. 18/            city and

     Traffic problems make travel within Rock
time-consuming. s'he city has set aside money Springs
improving traffic flow and hire¢ professional for
                                              planners to
cope with the problem. The problem of providing
police protection has been partially alleviated. adequate
       The aemand for retail and local services
partially met by the construction of a shoppinghas been
motels, and restaurants. However, recreation, center, new
more shopping facilities are still needed. 19/ daycare, and
                                                   And, more
growth is on the way for Sweetwater Cointy.
another unit of the electrical ro3wr plant is   Construction  of
                                                 planned. Five
new coal mines are expected to be opened. The
gas production will expand. As a result, the area's oil and
probably begin growing again in 1977 and by 1985 ponulation will
to ircLease by 82 percent from the estimated         is expected
'io Keep abreast of these developments, further 1976  population.
                                                  expansion of
local services will be required. 20/

      Projections of future income indicate that the
government, Rock Springs and Green River               county
and the Rock Springs school district will be    governments,
                                               able to meet
the projected operating and capital costs. But
River school district may have trouble fulfillingthe Green
ana financial aid will be necessary to meet         its needs,
requirements. 21/
      Sveetwater County and the cities of Rock Springs
Green River appear to have reached a point where
of lize is improving and fiscal resources are     the  quality
with the fairly high average annual population adequate. Even
                                                growth rate
whic-. is anticipated, 6.9 percent, it is reasonable
                                                      to expect

that the problems resulting from boom conditions of 1970 to
1974, when the growth rate was much higher, will not return
because they will have the financial capacity to meet the
projected operating and capital expenses connected with the
new growth.

     Infrastructure costs: How much is needed?

     Per capLta costs--Many factors affect the amount of
assistance that will be needed to cope with the effects
of rapid growth. The rate of future resource development
is perhaps the variable that most determfnes the amount
of assistance that communities will require. Other factors
bearing on the amount of assistance needed, such as con-
dition of existing facilities, size of the existing tax
base, and legal bonding limitations, will vary from
community to community. The amount of assistance required
can be computed only after the extent and timing of
development are known.

     Several studies have estimated per capita costs of facil-
ities based on analysis of individual communities.   The
costs es*imated vary widely.  Discussed below are  costs
developed by two studies which represent low and high per
capita estimates.

     Study A addressed the effects of locating a coal
mine near Gillette, Wyoming. The study estimated that
the mine would eventually produce 10 million tons annually,
resulting in a population increase of 2.090 people to a
town of approximately 11,000.  The study estimated that
the local capital expenditures would amount to $3,121 per
person. 22/

     Study B estimated per person growth costs of $4,892
based on a community of 33,000. 23/ .A comparison of esti-
mated costs of facilities and services are shown in the
following table.

                             Table 1
                 Estimated Per Capita Costs
        of Community Facilities ana Services (note a)
Type of facility or service            Study A      Study B
Streets and roads                      $   730      $1,144
Water                                      625         583
Sewage and solid waste                     500         613
Education                                  888       1,678
Recreation                                 130         118
Fire and police protection                 148          71
Libraries                                   46          45
Health care                                 54         241
Other                                        -         399
    Total                              $3,121      $4,892
a/1975 dollars

      Cumulative costs under different growth rates--Local
governments will collectively incur large costs-perhaps
several billion dollars--over the next 20 to 30 years to meet
the needs of new population attracted by coal mining, con-
struction of electrical generation plants, and construction
of synthetic fuel plants. Although the collective costs are
high, it should be remembered that they will be spread over
time and over a large number of communities and that some of
the areas have relatively large populations and will be cap-
able of absorbing additional population with little problem.
Nevertheless, the possibly great magnitude of needed invest-
ment and the fact that at least some portion of the needs may
occur in -.mn.unities which are unable to meet then. without
outside help make it useful to look at what the total required
investment could be.
     Costs will vary according to the regions affected. They
will be lower if most development takes place in the East,
rather than in the West, because fewer people will have to
move to eastern development areas.

     Using the Bureau of Mines and Edison Electric Institute
scenarios of future coal production and the BOM scenario for
future electrical generation and synthetic fuel plants, we
computed local government infrastructure costs that might
be required by 1985 and 2000.  In total, these costs, which
are shown in tables 2 through 7, might run as high as $4.4
billion between 1974 and 1985 and $14.9 billion between 1974
and 2000. However, because this figure is based on a high
scenario and does not consider the availability of any local
labor, a more realistic figure might be half or less. A
significant number of the miners and construction workers
required for new development will come from the area of the
development, but the percentage will vary with the location
because of such factors as the size of the existing population
and unemployment rates.
      Tables 2 and 3 show costs associated with coal mining.
Costs associated with mine operations are shown rather than
costs associated with opening coal mines because studies
indicate that although approximately the same number of
wor'.ers age needed to open a coal mine as to operate it, the
pc elation that ccmes with operating personnel is greater
taan that which comes with the temporary personne' involved
in opening the mines. These tables are based on the assump-
tion that all workers will come from outside the region and,
therefore, do not consider regional differences in expected

                                      Table 2

                 Local Govern;ment Infrastructure Requirements
                       Due to Increased Coal Production
                                  1974 to 1985

   Coal                                             Infrastructure costs
production      Population increase           M--       EEl        BOM           EEI
  region          BOM         EEI           high        high       low           low

                                            ----------- (thousands)----------------

East            215,509      39,650     $1,054,270     $193,968   $    672,604     $123,748

Central          51,716      27,166        252,995      132,896        161,406         84,785

West            173,370     110,090        848,126      538,560        54',088         343,591

       Total    440,595     176,906      $2,155,391 $865,424      $1,375,098       $552,124

                                      Table 3

                 Local Government Infrastructure Requirements
                       Due to Increased Coal Production
                                   1974 to 2000

   Coal                                              Infrastructure costs
production     Population increase        BOM            EEI       BOM                 EEi
  region          BOM        EEI          hihhigh                     lo.              low
                                          ------------- (thousands}----------------

East           1,063,388   166,509     $5.202,094 $     314,562 $3,318,834 $           519,675

Central          230,048    40,836      1,125,395       199,770       717,980          127,449

West             321,601   161,981      1,573,272       792,411   1,003,717            505,543

       Total   1,615,037   369,326     $7,900,761 $1,806,743 $5,040,531 $1,152,667

These tables assume:

1. High and low infrastructure costs of $4,892 and $3,121 in 1975
2. That for each new miner there will be a population increase of
   6.5 persons, including the miner, his family, persons engaged in
   service and related industries ano their families.
3. That all workers will come from outside the region.
4. That mine productivity will remain constant at 1974 levels.

     Tables 4 through 7 show local government infrastructure
costs resulting from construction of electrical generating
plants and synthetic fuels plants. Costs were computed on
the basis of the estimated number of construction workers
needed to build these facilities. Costs associated wit;
operating personnel were not used because unlike the situ-
ation with opening and operating new mines, the construction
phase work torce and accompanying population in these cases
will be much greater than the operating phase work force and
accompanying population. 24/
                             Table 4

                 Local Government Infrastructure
                 Requirements for Construction of
              Coal-Fired Electrical Generation --Tants
                           1974 to 1985
                              BOM                    BOM
                           population         Infrastructure costs
   Region                   increaseh                        low

New England                    -          $      -        $        -
Middle Atlantic              11,172            54,653          34,868
South Atlantic               54.016           264,246         168,584
East North Central           66,643           326,018         207,993
East South Central           23,959           117,207          74,776
West North Central           55,112           269,608         172,005
West South Central          102,950           503,631         321,307
Mountain                     72,071           352,571         224,934
Pacific                          17                83              53
    Total United States     385,940       $1,888,017      $1,204,520

                            Table 5
                 Local Government Infrastructure
                 Re uirements for Construction of
             Coal-Fired Electricai Generatio Plants
                          1974 to 2000
                              BOM                    BOM
                          population         infrastructure costs
    Region                increasenigh                      low

New England                   -          $       -_     $
Middle Atlantic             11,172             54,653        34,868
South Atlantic              54,016            264,246       168,584
East North Central          66,643            326,018       207,993
East South Central          23,959            117,207        74,776
West North Central          55.112            269,608       172,005
West South Central         116,723            571,009       364,292
Mountain                    72,071            352,571       224,934
Facific                         17                 83            53
    Total United States    379,713       $1,955.395     $1,247,505

These tables assume:

1. High and low infrastructure costs of $4,892 and
   $3,121 in 1975 dollars.
2. That all construction workers come from outside
   the local community. About 60 percent may bring
   their families, with an average family size of
   3.7 persons.
3. For each construction worker, 0.6 secondary
   workers will be required. Forty percent of these
   secondary workers will have families, 40 percent
   will not, and 20 percent will be local residents
   (not adding to the population). 24/
4. That all plants are operating at-~6 percent of
   capacity in 1985 and 60 percent in 2000 in
   accordance with the BOM scenario, and that all
   plants require the same number of workers at both
   capacity percentages.

                               Table 6
         In.:astructure Cost for the Construction
       of Synthetic Fuel Plants in the United States

                     BOM                             BOM
                 population                    infrastructure cost
Year              increase                  high

1985                63,750              $     311,865    $     198,964
2000             1,032,750                  5,052,213        3,223,213
This table assumes that all construction workers will
come from outside the local community.

                               Table 7
          Comparison of Infrastructure Costs Assuming
         Total Immigration and Partial Immigrationfror
the Construction of-Synthetic Fuel Plarts in the United States

            Total             Partial immigration:
         immigration            50-50 allocation
Year       (note a)            of plants (note b)              Difference
             ------------------ (thousands)-----------
1985     $     311,865            $     146,577                $     165,288
               198,964                   93,513                      105,451
2000         5,052,213                2,374,540                    2,677,673
             3,223,213                1,514,910                    1,708,303
a/This column assumes that all construction workers will come
  from outside the local community.
b/This column assumes that some construction workers will
  come from the local community.  Immigration rates of 34
  percent were used for the East and 60 percent for the West.
  It was assumed that the allocation of synthetic fuel plants
  between East and West would be equal.
Bo'h tables above assume high and low infrastructure
co ts of $4,892 and $3,121 in 1975 dollars.

     Infrastructure requirements will be considerably lower
if development takes place primarily in the East rather than
in the West because fewer people will have to move to eastern
development areas. Tables 8 and 9 are an attempt to show
the effect of lower immigration rates expected in the East.
     As shown in table 9, estimated costs associated with
constructing synthetic fuel plants under the BOM scenario
for 2000, if 75 percent of the plants are built in the West,
might be $2.7 billion; however, if 75 percent of the plants
are built in the East, the total cost might be reduced by
$656 million to $2.05 billion. Synthetic fuels plants wore
used to illustrate the magnitude of differences that might
occur as a result of different geographic distributions of
development   The geographic mixes used in the table are
for illustrative purposes only and not based on any known

                             Table 8
              Local Population Increases Due to
              constructing Synthetic Fuel Plants
           in Different Parts of the United States

                         Allocation of plants
       75 percent West     50 percent West      25 percent West
Year   25percent East      50 percent East      75 percent East
1985        34,106              29,963             25,819
2000      552,521             485,393            418,264

                                Table 9
                 local Infrastructure Cost Due to
                Constructing Synthetic Fuel Plants
             in Different Parts of the United States

                             Allocation of plants
           75 percent West      50 percent West         25 percent West
  Year     25 percent East      50 percent East         75 percent East
             ----------------- (thousands)------------
High-1985    $     166,847       $     146,579      $     126,307
Low-1985           106,445              93,515             80,581

High-2000        2,702,933           2,374,543          2,046,147
Low-2000         1,724,418        1,514,912             1,305,402
These tables assume:

1. High end low infrastructure costs of $4,892 and $3,121
   in 1975 dollars.
2. That for each new construction worker there will be a
   population increase of 4.25 persons including the worker,
   his family, persons engaged in service and related
   industries and their families.
3. Some construction workers will come from the local com-
   munity and are based on a 34 percent construction worker
   immigration rate for the East and 60 percent for the West.

     What is being done?
     Because the socioeconomic costs of rapid coal development
are beyond the immediate means of many communities, they look
to their State government, the Federal Government, and industry
for assistance. Some States have enacted legislation intended
to mitigate the effects; the Federal Government has provided
limited assistance; and industry has provided assistance in a
few cases. Collectively, these action provide limited

     What is being done   y_ the States?
     Western States--The legislatures of some coal producing
Western States have considered bills that could provide the
mechanisms and funds for planning, designing, and building
to at least partially offset the effects of energy resource
development.  In 1975, Wyoming enacted a package of laws to
help its communities finance solutions to the problems of
rapid growth. Montana, North Dakota, aid Utah passed laws
which will provide significant assistance, and Colorado and
New Mexico enacted laws to provide limited assistance.

     Wyoming created a community development authority, which
is authorized to issue up to $100 million in revenue bonds,
the proceeds of which are to be used to maku loans to local
jurisdictions for a wide range of civic facilities. The
proceeds can also provide home loan capital funds to communi-
ties through savings and loan institutions. 25/ In addition
to a four percent severance tax, Wyoming levied a 0.4 percent
tax on the value of coal mined in 1974 which will increase
to two per.ent of the value of coal mined in 1978 and later.
Collections from the latter tax can be granted or loaned to
areas affected by coal production and can be used in financing
public water, sewer, highway, road, and street projects. 26/

     Wyoming also enacted several other laws in 1975 to aid
affected communities. One law increased the maximum rates
for school district taxes. 27/ An existing law was amended
to allow cities and counties to combine for public projects
voluntarily, enabling localities to solve tax imbalances (for
instance, when resources are developed in a county, but
greatest effects are on a city). 28/

     Montana passed the highest surface-mined coal severance
tax in the Nation. The tax rate is 20 percent of the selling
price of low-grade lignite coal and 30 percent on other coal.
29/ Large amounts of revenue are expected from the tax. One
study estimated that by 1985 between $266 million and $1.1
billion in severance taxes will be collected on the coal from
the two largest Montana coal producing counties. 30/ Statewide,
Montana expects proceeds through 1977 to total $67.6 million.
The proceeds are to be distributed as shown in table 10.

     Funds will not be used primarily for affected areas,
however. About $11.7 million (17.5 percent) will be put in a
local impact fund, which will be used to pay the expenses of
a coal board and to Dake grants to affected communities; $6.7
million (10 percent) will go for coal area highway

improvement; and $2.7 million (four percent) will be returned
to the coal producing county. After June 1977, the percentage
of the severance taxes allocated to the local impact fund will
be reduced to about 11 peLcent, which in turn will reduce
the total designated specifically for the coal producing areas
to 25.7 percent of the total severance tax collected.

                             Table 10
            Allocation of Montana Severance Tax Funds
      Allocation to                     Percentage 31/    Amount
7eneral fund                                40.0          $26.6
Local impact fund                           17.5           11.7
Educational trust fund                      10.0            6.7
Coal area highway improvement               10.0            6.7
State equalization aid to
  public schools                           10.0             6.7
Return to the coal generating
  county                                    4.0             2.7
Alternative energy research                 2.5             1.6
Park funds                                  2.5             1.6
Renewable resources development             2.5             1.6
County land planning                        1.0              .7
    Total                                 100.0           $66.6

     The actions that Wyoming and Montana have taken to provide
local impact funds from severance taxes will help to provide
needed initial financing assistance. Table 11 shows a com-
parison of severance tax funds earmarked by States for local
impacts with estimated infrastructure funding requirements
using the BOM and EEI scenario projections of expected coal
production by 1985 and 2000.

     The table shows that in Montana there will be far more
available impact funds than will be needed. This finding
corresponds to that of a December 1976 Resources for the
Future, Inc., study. This study focused on two Montana
counties--Rosebud and Big Horn--where future coal develop-
ment is expected to occur on a large scale. 32/

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                                                                                7.19Orrm                                                 c~c
     North Dakota enacted legislation that created a coal
development office which is responsible for disbursing funds
collected from two taxes. One is a tax on electricity and
gas produced by coal-fired electrical generating plants and
coal gasification plants. The first $100,000 collected from
each plant annually is returned to the county. Revenues above
$100,000 are divided between the county and the State. The
other tax, levied at a rate of 50 cents per ton of coal,
increases with rises in the wholesale price index. Thirty-
five percent of the coal tax will be put in a coal development
impact fund, which is expected to total about $4 million by
mid-1977. This fund can be used for grants to impacted
political subdivisions. 33/

     Utah enacted a package of laws aimed at mitigating
socioeconomic effects of projects. The key bill of the
package allows developers to voluntarily prepay sales or use
taxes. Under the Utah law, the developer can pay the taxes
before installing the equipment on which the tax applies.
Taxes will be deposited in a fund which can pay for public
projects related to the development. 34/

     The bill allowing prepayment of taxes was aimed primarily
at development in southern Utah, where a major power plant
complex and mine were to be built and where no town existed.
It was intended to facilitate the financing of facilities
needed for a new town. The Governor of Utah stated that
companies would have an incentive to prepay taxes for
developing new towns because the companies will not be able
to get employees without helping fund community development.
Although the companies later withdrew from the project, scme
taxes were prepaid prior to withdrawal.

     New Mexico levies a severance tax of 0.5 percent of the
gross value of the coal and a resources excise tax of 0.75
percent of the value of the coal less royalties. Colorado
levies ti.e lowest of all State-level coal severance taxes
at 0.7 cernts per ton. 35/

     Legislatures of other States in the area wrestled with
numerous land use, mineral tax, and impact aid bills during
their 1975 legislative sessions. Many laws were enacted, but
none are sufficient in scope to provide aid needed by affected
     Eastern States--Five Eastern coal producing States--
Kentucky, West Virginia, Alabama, Virginia, and Tennessee--
have coal production based taxe3. Pennsylvania and Maryland

have none. Of the five having coal taxes, three--Kentucky,
West Virginia, and Tennessee--collect them statewide and
return a portion of the tax to the counties where the coal
is extracted. Tennessee returns 99 percent of a 20-cent
per-ton tax; West Virginia returns 0.2625 percent of the
gross proceeds from the sale of coal by the producer; and
Kentucky returns a dollar amount set by the State
legislature. 36/

      Counties use their share of the tax for a wide variety
of purposes. In Kentucky, $5 million each year from the
Coal Severance Economic Aid Fund is distributed to the coun-
ties to be used for capital projects, excluding road or school
projects. In addition, $12 million in fiscal year 1976 was
allocated to coal producing counties for road improvements
from the Er .gy Road Fund. Additional coal severance tax
revenues are earmarked for highway construction, worker's
compensation, and area development programs. The remainder
of the revenues are kept in the State General Fund. In
Tennessee, the counties must expend 50 percent of the funds
for highway maintenance and water pollution control and 50
percent for education. West Virginia permits the county com-
iissions to decide how they will spend their share of the State
 ,usiness and Occupation Tax. 36/

      Some States have enacted laws permitting counties to levy
coal production based taxes. Alabama has authorized two coun-
ties to levy a severance tax on coal mined in those counties.
Iiindications are that other coal producing counties will be
authorized by the legislature to levy similar severance taxes
on coal production. 37/ Virginia has permitted counties to
levy a local gross receipts tax on coal production up to a
maximum rate. 38/

     In Pennsylvania, an attempt to institute a severance tax
for mining conservation and reclamation was defeated because
counties already have the authority to require coal companies
to post performance bonds against damage to any transportation
facility and to require land reclamation. 39/
      Central States--Of the three Central States, only
Illinoi's-ias taken measures intended to aid communities
affected by coal development. In Illi.ois, local sales taxes
on coal sold for use in Illinois are returned to the county
where mining occurred. Ohio has a coal production based tax,
the proceeds of which are used for environmental protection
activities and strip mine reclamation. None of the   proceeds
are used to mitigate socioeconomic impacts of coal development.

Indiana has no coal severance tax and does not provide
financial assistance to communities affected by coal
development. 40/

     What is being done by the Federal Governmelt?
     Funds that can be used to plan for or mitigate energy-
related effects are provided to communities urzer numerous
Federal programs and are allocated in competition with non-
energy-related needs. Communities compete for funds; and the
small communities which are affected by coal development some-
times have trouble qualifying or competing with larger com-
munities and communities having needs related to highly
visible programs, such as programs for high poverty areas
and Indian reservations. Nevertheless, under existing
agency policy and regulations, some programs and projects
can and have been used to deal with coal development effects.

     In the Western States--Sixty-two percent of the 1974
coal production in the West came from 10 counties in 7
States. 41/ As shown in the table 12, Federal grants and
loans for community and economic development, loans and
loan guarantees for housing, and grants for revenue sharing
made to these counties in Arizona, Colorado, New Mexico,
North Dakota, Montana, Texas, and Wyoming in fiscal year
1975 amounted to $75.1 million. 42/

                            Table 12
               Federal Dollars to the Tin Top Coal
                 Producing Counties in the West -
                        Fiscal Year 1975
     Purpose                    Grants       Loans     Total
Community and economic
  development                 $44,408       $11,363   $55,771
Housing loans and loan
  guarantees                     -           15,693    15,693
Revenue sharing grants          3,625          -         3,625
    Totals                    $48,033      $27,056    $75,089

     In the West, Federal agencies attempted, through the
Mountain Plains Federal Regional Council, to coordinate
Federal efforts to aid affected communities. The Council is
1 of 10 Federal Regional Councils (FRCs) established by Execu-
tive order to assist State and local governments by coordina-
ting Federal program grants and operations. The Council is
composed of the principal regional officials of the Depart-
ments of Commerce; Labor; Health, Education, and Welfare;
Housing and Urban Development; Agriculture; the Interior;
and Transportation as well as the Federal Energy Administra-
tion, the Community Services Administration, the Environmental
Protection Agency and the Law Enforcement Assistance Admi-
istration. The Mountain Plains Council is responsible
for Federal Region VIII--the States of Colorado, Montana,
North and South Dakota, Utah and Wyoming. It is responsible
to the Under Secretaries Group (USG) for Regional Operations
chaired by OMB's Deputy Director.

     USG has given the FRCs permission to provide on request
technical assistance to State and local governments on
approaches for mitigating the effects of socioeconomic impacts
and to respond to the requests from State and local govern-
ments for integrated or coordinated funding of categorical
programs normally administered by regional offices. In late
1975, the Mountain Plains Council began a small project
to help communities assess their needs and to advise them of
possible sources of financial and technical assistance.
     In March 1976, the USG assigned FEA lead-agency responsi-
bility for all FRC energy-related activities.  FEA established
a small office in Denver with fiscal year 1976 goals of in-
suring coordinated action in programs and projects focused
or the mitigation of negative energy impacts and monitoring
and streamlining national and regional data efforts. The
office, which was not fully staffed until early 1976, had

    -- participated with FRC in planning and implementing
       projects associated with the socioeconomic impact

    -- taken over and expanded on the FRCs' socioeconomic
       data gathering efforts,

    -- participated with Wyoming in a project to demonstrate
       and evaluate the effectiveness of statewide systems
       and strategies in dealing with impacts of energy

     --assisted in a joint project with Colorado and the local
       Council of Governments in helping one Colorado com-
       munity analyze its needs and formulate plans to
       finance projects, and

     -- entered into a contract for a Colorado special census
     In addition to the funds provided in the past, the
Federal Government recently increased funds to the States
which can be used to aid energy-affected communities. These
funds are derived from Federal minerals and lands and will,
therefore, be primarily available to Western States.

     In August 1976, the Mineral Leasing Act of 1920 was
amended to greatly increase the royalties collected on coal
and to increase the royalties returned to States from mineral
leases on Federal lands from 37.5 percent to 50 percent. 43/
Royalties to the States from coal resulting from these changes
have been estimated by the Department of the Interior to rise
from $3.4 million in 1976 to $126 million in 1985. 44/

     In October 1976, the Congress enacted the Federal Land
Policy and Management Act of 1976, enabling the royalties
returned to States to be used as the legislatures of the
States direct.  It gave priority to subdivisions of the States
socially or economically impacted by development of Federal
minerals leased under the act for planning, constructing, and
maintaining public facilities and providing public services.
The act also provided for loans to States and political sub-
divisions in order to relieve social or economic impacts
occasioned by the development of Federal mineral leasing.
Loans can be made up to the anticipated mineral royalties to
be received by the recipients for any prospective 10-year
period. 45/
     In the Eastern States--Sixty-one percent of the 1974 coal
production1n  the East came from 24 counties. 46/ As shown
in the table below, Federal grants and loans miae t. these
counties in Appalachia and western Kentucky in fiscal year
1975 totaled $461.8 million. 47/

                             Table 13
                 Federal Dollars to the Top Coal
             Producing Counties in the East (note a)
                        FiscaliYear 1975

     Purpose                    Grants        Loans      Total
                               ---------- (thousands)-----------
Community and economic
  development                  $299,759     $ 31,406   $331,165
Housing loans and loan
  guarantees                       -          72,928     72,928
Revenue sharing grants           57,665         -        57,665
    Totals                     $357,424     $104,334   $461,758
a/Aid to cities with over a 25,000 population is excluded.

     The Appalachian Regional Commission has allocated money
specifically to help coal-affected communities. A program
was approved in December 1375 to meet increased housing and
related public facility needs in areas of the region impacted
by energy production. In many instances, the Commission's
proposals represent commitments by industry, labor, and
government jointly to address housing needs in areas impacted
by energy production. 48/ As of July 30, 1976, eight pro-
jects in coal areas ha(-been approved for funding with a total
Appalachian Regional Commission contribution of $2,435,070. 49/

     In recent years, the Tennessee Valley Authority, acting
in its role as energy developer, has assessed the socioeco-
nomic impact of its major projects and has attempted to offset
adverse temporary conditions caused by the project. When
needed, mitigation programs have been developed specifically
for each project based on the size of the project and the
particular local area. Thus, the mitigation programs have
varied from project to project. 50/
     An example of the TVA program is the Hartsville nuclear
project, located near Hartsville and Carthage, Tennessee,

where a substantial effort is planned to mitigate socioeco-
nomic impacts of an electric utility plant. 51/ The socio-
economic impacts related to the influx of population to the
community are similar for both construction of coal burning
or synthetic fuel plants and for nuclear utility plants. 52/
TVA has agreed to provide necessary financial, technical,
or equipment assistance in a timely manner so that small com-
munity budgets are not significantly overburdened by long-
or short-term indebtedness associated with immigrating con-
struction workers. Assistance will be provided in the areas
of housing, job training and recruitment, and education as
well as for water and sewer facilities, local government
budgets, health and medical services, employee transportation,
planning, and monitoring. Total program cost is expected to
be $10.8 million over an 11-year period. 53/

     The rationale for the Hartsville impact mitigation pro-
gram is to finance corrective action from project funds.
Adverse socioeconomic impacts are considered a direct conse-
quence of carrying out the project and, therefore, a respon-
sibility of TVA, the major area employer and resource develop-
ment agency. 54/ The amount of money spent on mitigating
socioeconomic problems is negligible, considering the total
project construction cost of $2.5 billion. 55/

     In the Central States--Sixty percent of the 1974 coal
production in the Central region came from 10 counties. 56/
As shown in the table below, Federal grants and loans maUi
to these counties in Illinois, Indiana, and Ohio in fiscal
year 1975 amounted to $98.7 million. 57/

                          Table 14
           Federal Dollars to the Ten Top Coal
     producing Counties in the Central States (note a)
                     Fiscal Year 19-5

         Purpose                      Grants     Loans     Total

                                     ------- (thousands)-------
C3mmunity and economic development $59,316      $18,333   $77,649
Housing loans and loan guarantees        -       15,580    15,580
Revenue Sharing grants                  5,489      -          489
     Total                           $64,805    $33,913   $98,718
a/Aid to cities with over a 25,000 population is excluded.

     What is being   done by industry?

     In the Western States--Industry has provided assistance
to affected communities in a few cases. Industry provided
funds to communities in Sweetwate: County for public projects
because the degraded quality of life had caused high employee
turnover and productivity decreases. New town feasibility
studies were prepared by industry for several areas.
     Industry has also provided housing. In Colstrip,
Montana, a virtual ghost town a few years ago, the energy
developer who owns the town planned community expansion and
constructed parks, a shopping area, recreation facilities,
and housing, which it rents or sells to its employees.
Several energy developers in the Gillette, Wyoming, area are
constructing homes, but only because high interest rates and
labor unavailability have driven away home construction

     Although industry has provided some assistance, it is
generally reluctant to do so. According to an Exxon official
     "* * * industry should not be cast in the role of
     government by being responsible for planning and
     constructing public facilities due to its impact.
     Government should not expect business to be any
     better in this role than business expects government
     to be in the business role. On the other hand,
     business should--and could--pay its fair
     share for its impact.
     "* * * industry must be willing to freely
     communicate its plans to government and to
     pay its fair share of taxes so government can
     handle the impact problems." 58/

     Another corporate official outlined several industry
policy changes that he believes are needed if th,: Rocky
Mountain area is to produce the minerals required to meet
the Nation's energy needs. He believes that industry should:
     -- Reinvest a larger share of its profits in the area,
        especially if the increased production of minerals
        results in increased costs to the local society or
        local government.

     -- Make its development plans available to local govern-
        mental units so that local and State agencies can plan
        for the population influx.

      -- Help plan and fund technical education and the re-
         training and relocation of skilled workers.
      -- Spend more money for research on the issue of local
         impact, aimed at specific regional problem solving.
      -- Help provide solutions to social problems. 59/

     According to the same officia         here is too often a lack
of coordination and communication          een industry and govern-
ment, and long-range planning bet, ..      them is either virtually
non-existent or proceeds in different      directions. 60/
     In the Eastern States--The coal industry in the East has
taken measures in some scattered instances to help mitigate
socioeconomic impac s of coal development. For example,
companies have                                           coal

     -- donated land with a value of $153,000 for a housing
     -- provided a $100,000 interest free loan for a housing
        project, and

     -- donated $350,000 to $400,000   v   build a new high school
        gymnasium. 61/

     Coal industry efforts to mitigate socioeconomic impacts
of their developments vary widely in Appalachia. The willing-
ness of industry to help impacted communities varies from
active participation to an attitude that the impacts are
public sector problems. A spokesman of one coal company purely
that they have recently taken a mnore active interest in
helping communities plan for socioeconomic impacts and assis-
ting them in providing mitigation measures. This company
believes it receives benefits from improving th- quality
community life because workers are more productive and effi-
cient and there is less turnover. 62/

     In the Central States--The coal industry in the Midwest
has participated to some extent in social and civic activities
of coal communities by such things as donations to the Boy
Scouts, Girl Scouts, local baseball team, etc. One coal
industry official explained that coal mining is a tradition
and way of life in the Midwest. Generally speaking, the
pacts of increased development are reduced because needed im-
and the labor force are already in existence near new mine towns
openings or expansions. 63/

       Additional assistance
       Early financing assistance must
                                       be provided in some areas,
  especially in the West. The States,
                                       the Federal Government,
  and industry could all contribute.

       By taking appropriate steps, the
                                         States can provide much
 of the aid needed by affected communities.
 various mechanisms available for               The States have
 ting it to needy communities without       money  and distribu-
 States' populations.                   directly taxing the
                        These mechanisms
 severance taxes on extracted resources; include levying
 authority to issue special revenue        creating a bonding
 which can be used to make loans     bonds,  the proceeds of
 ments; and using discretionary   repayable  by  local govern-
 programs.                       Federal  funds  under existing

      Severance taxes oi. energy resources
 mate energy consumer paying for           result in the ulti-
                                  the aid provided to
      States could provide incentives
similar to those provided by Utah        for industry participation
Vuluntarily prepay sales or use       in allowing industry to
could also require industry to     taxes.    If necessary, States
                                  post performance bonds to c.,ver
the cost of local planning
which would be forfeited if,andas designing oi infrastructure
decision, development does not a result of an industry
                                  occur. Thus, the prepaymer
of taxes could provide the community
end funds, and the requirement of        gith additional front-
                                     a performance bond would
provide the State and local governments
the risk inherent in providing              with insurance against
                                 facilities and services before
growth occurs.
     Federal programs that have provided
                                          aid to communities
generally (1) are not specifically
communities cope with rapid population       to help small
administered by a number of agencies    growth and (2) are
The efficiency and effectiveness     with  little coordination.
                                 of Federal aid to affected
communities probably would be increased
made responsible                         if one agency were
                 to coordinate the Federal  role.
      Industry could contribute
meet the socioeconomic impacts significantly in helping to
                                of energy resource development.
Prepayment of corporate, sales,
                                 and use taxes would help States
to provide facilities and services
prior to development. Industry      whkre few or none existed
prepay its taxes in this situation     have an incentive to
                                    because it will be better
able to attract employees to live
to commute to an area (and reduce in and work in an area or
costs) if basic public facilities construction and operating
                                   and services are available.

Industry does not generally favor prepayment of taxes because
it would increase a company's capital needs and total costs
prior to receipt of income on a project.

     The new growth accompanying the construction of new
facilities, such as mining operations, can cause effects
beyond the problems of land use, housing, and financing. 64/
There are certain social changes accompanying rapid popula-
tion growth which a community will undergo regardless of how
carefully it has planned influx or how adequately it has been
financed. 65/ The newcomers bring new ideas, values, and
behavior patterns which affect the socio-cultural structure
to the community. 66/ As a result, the old social order may
disappear. 67/

     How and where the population growth occurs will substan-
tially affect the urban-rural mix within the regions. The
largely rural character of the regions will undergo change
towards a more urbanized society. 68/ The lives of both the
new and old residents may be affected as the traditional rural
heritage gives way to new tastes and cultural backgrounds.
In rural communiities a relatively small group of people inter-
act in activities, friendships, and formal and informal insti-
tutions. As the population increases, these relationships may
collapse. 69/ A change in quality of life is'often evidenced

     --a quickened pace of life;
     -- congestion and overcrowding;

     -- inflation in prices;

     -- lack of activities and sense of belonging for new
        families; and
     -- alcoholism, drug abuse and other mental health
        problems. 70/

     Even though rural political systems are becoming more
integrated with the national system, they still differ from
urban political systems. Rural governments are distinguished
by the personalism with which decisions are made, leaders are
chosen, and policies are implemented. As development occurs,
the political system will become more complex and more imper-
sonal. 71/ The long-time residents may luse control of the
community, as the new population or industry takes over local
affairs. 72/

     The effect of a new large development on a region is
inversely proportional to the size: of the existing popula-
tion. 73/ The changes which accompany increased coal
development are more significant in sparsely populated areas
than in more heavily populated areas. 74/ New development
is more readily and easily absorbed; in the latter due to a
larger existing work force and service base, higher levels
of existing community services and more diversified
populations. 75/
     According to a Pennsylvania powerplant siting studyr
social impacts are dependent on current community attitudes.
Areas which have remained residential in character are un-
likely to be receptive to development. In a declining
industrial region, where the economy and jobs are prime con-
siderations, public reaction might be totally different. 76/
     Some of the new jobs created will be taken by the un-
employed of the region. 77/ The hiring of unemployed workers
is a critical part of satisfying the labor demand for the
mining operation. 78/ However, the jobs created by increased
coal development probably cannot be filled entirely by local
people. As a result, workers must be recruited from else-
where. 79/ The more jobs that can be filled by local labor
or by commuters from surrounding areas, the less severe the
social change caused by the development will be.

     Commuting is an important aspect in evaluating the ef-
fects of increased coal development. Workers who commute to
the job do not disrupt the existing socioeconomic stability
of a community. The more workers living within commuting
distance of the development, the less likely there will be
adverse socioeconomic changes. 80/

     The West will probably experience a more significant
population increase and more severe social changes than either
the Midwest or Appalachia. Population growth associated with
coal development will not be evenly distributed throughout
the West. 81/ Rapid population increases will be concen-
trated in small, isolated towns. Most of these small, homo-
geneous communities will be in a poor position to deal with
the rapid growth. These communities will have to build addi-
tional public facilities in order to absorb the new population.

     Substantial immigration will be necessary if labor needs
are to be met. Since the region does not have high unemploy-
ment or underemployment, there is little surplus labor
available. 82/ Workers will not be able to commute from
their present residence because development sites are far
from population centers. 83/
     Even though mining is not new to some Western areas,
agricultural activities have been the principal economic
base. 84/ The sudden, large demand for employees will
shift t-e local economy base from agriculture to energy. 85/
     Western history is recent but   traditions are deep.
Many of the families which created   the communities are still
living in them. These communities    have not been diversified
by massive immigration like Denver   and Billings. 86/

     Residents of small, rural western towns are generally
uncertain about growth and development. Their perceptions
of life style changes are subjective and range from hostility
to enthusiasm. People's attitude toward change appeat to
be influenced by their personal expectations and past experi-
ences in the community. 87/ When residents perceive the
development will end the rural, neighborly way of life they
have sought and enjoyed, they may strongly oppose it. 88/
Individuals with higher incomes who have recently moved-into
the community and who prefer the rural life tend to be hostile
to change. Lower income residents generally favor the changes
that accompany growth. 89/
     A recent study by the Old West Regional Commission
surveyed the attitudes of long-time residents and newcomers
concerning construction projects in their community. There
was a tendency for those who had lived in an area more than
15 years to be more dissatisfied than those who had lived there
for less time. When asked why they were glad the project came
to the area, long-time residents indicated job opportunities
and financial benefits. The reasons most frequently given for
being unhappy were community related, such as town problems,
increased population, And inadequate community facilities.
     The newcomers also cited job-related factors as what
they liked most about living in the community. When asked
what they disliked about living in the affected communities,
the newcomers most frequently gave answers concerning the
environment, physical surroundings, and inadequate community
facilities. 90/

     Appalachia, a major resource area for coal, has been
characterized by high unemployment rates, low average family
incomes and a high rate of migration to other areas. There
was a significant decline in job opportunities during the
1950s and 1960s, and much of Appalachia suffered severe
population losses. As the Nation's major coal-producing
region, Appalachia bore the brunt of the decline in jobs
and production. Coal employment in the region fell from
427,600 in 1947 to 144,914 in 1961, a decline of 65
percent. 91/ Between 1950 and 1970, an estimated one million
people 927-migrated out of central Appalachia as young people
left the area to find employment. 93/ This trend was rever-
sed between 1970 and 1975, when it was estimated that the
population of Appalachia grew by 750,000. 94/ The recent
upsurge in coal demand offers an opportunity to accelerate
the development of Appalachia. 95/
     Rural Appalachia has been characterized by undereducation,
simple life styles, and extreme poverty. 96/ Unemployment
and underemployment have been and remain Appalachia's most
severe economic problems. 97/ During 1976, the eastern coal
producing counties had an annual average unemployment rate
of 7.5 percent and 250,987 people were unemployed. Increased
coal development would be an important socioeconomic stimu-
lus. 98/
     The population density of the East is much greater
than that of the West. 99/ Even though coal development
will occur in predominantly rural areas, some of the areas
are within commuting distance of population centers. 100/
As a result, many workers will be able to commute from their
present residences to their jobs. Some Appalachian communities
which will be affected if increased coal development occurs
are located in rugged terrain and are relatively remote from
metropolitan areas. 101/ Workers will not be able to easily
commute to these areas. Scarcity of housing will be a problem
in some mountain communities and there is little land suitable
for housing because of the rugged terrain. 102/

     Increased development of Central coal will be in areas
where people have lived with coal mining for many years. The
population has been decl.ning, and the area has been economi-
cally depressed, primarily because of the recession in the
coal industry. Unemployment has been a problem in the region

and there have been some significant poverty areas.  Increase4
coal development will create new and expanded job opportuni-
ties which should lead to higher income levels.

      Few studies of the possible effects of increased coal
development have been done. Apparently most people believe
there will not be significant negative effects. Based on
conversations with many State and Federal officials, we
concluded that the social impacts of population growth in
the Central region may not be as severe as in the West. The
population density in the Central region is generally greater
and towns are not as far apart. Since several communities
may be located within commuting distance, the effects may
be more equitably distributed.   In many cases, the increase
would be added to an existing population and service base,
so the effects may not be much of a problem.

     Heavily populated areas, such as the Eastern and Central
regions, are more able to absorb the effects of coal develop-
ment than less populated areas. Lifestyle conflicts would
not be as severe in populated areas; they would also be
easier to resolve. Population concentrations are larger and
coal development will probably occur near large towns. Fewer
people will have to relocate in the Eastern and Central
regions since most of the labor will be available locally or
within commuting distance.

     Even though some eastern communities may experience
substantial population increases, the social conflict should
be minimal because:
     -- Most people have a positive attitude toward the
        increased coal development and the accompanying
        population increase.
     -- Many of the people who left Appalachia during the
        1950s and the 1960s are moving back. If this trend
        continues, cultural and family ties of the people
        returning to Appalachia should reduce the   cial

     Bust conditions are local economic depressions which
can occur in communities and local areas whJse economies are
dependent on one industry when that industry's production
declines. They can also follow boom conditions caused by
the construction or expansion of powerplants, synthetic fuel

plants, or any other activity that causes a rapid influx of
population to an area. Studies indicate that the bust problem
is two-fold. First, if new facilities and services are pro-
vided for community residents during the boom or expansion
period, then there is likely to be an overcapacity after the
boom or expansion period is complete. And, as workers begin
to leave, the community may no longer be able to support the
same level of services. Second, employment opportunities
generated in the community due to the boom conditions may no
longer be available, and unemployment may become a major
problem. 103/

     The economic conditions that have occurred in Appalachia
serve as an example of the problem. As the Nation's most
important coal-producing region, Appalachia bore the brunt of
cyclical booms and busts in the coal productirn industry. 104/
With the decline in coal production during the 1950s, the
Appalachian States found themselves locked in a circle of
poverty and deprivation. 105/ Low wages were prevalent in the
coal industry, and limited income meant limited services. 106/
Furthermore, lessening demand for coal accompanied by improved
mining technology left thousands of miners unemployed. No
severance taxes were levied on the coal industry, heavy coal
trucks damaged already poor roads, and State and local govern-
ments benefited little from the depletion of coal
resources. 107/

     The 1950s were a time of migration from Appalachia.
There was a shortage of jobs and lack of retraining programs.
The financial burdens of the States were complicated by the
loss of their most productive people. Fewer people were
paying taxes, and more were demanding services. The States
lacked the expertise and resources to acquire their fair
share of Federal dollars. Most Federal programs required
matching money on the State or local level, and the Appala-
chian States did not have the money. State and local govern-
ments were crippled with the following socioeconomic problems:

     -- Inadequate and dangerous highways.

     --One of the worst housing conditions in the Nation.

    -- Thousands of rural residents without health care.
    -- Educational systems unable to afford programs to
       train people in economically viable skills.

     --An inability of local governments to afford modern
       water and sewer systems.
     --A general lack of amenities that improve the quality
       of life. 107/

     What is being done?

     Although the impact of a slowdown in coal production
would probably cause local economic problems in coal producing
areas, economic development and industrial diversification
minimize adverse effects of bust conditions on local economies.
According to several studies, the long-term economic vitality
and stability of communities in coal producing areas is im-
proved when investments are made in industries other than
coal. 108/ Therefore, economic diversification as an alter-
native to bust conditions, should be considered by local
governments. There are presently numerous Federal, State,
and local programs which encourage community economic develop-
ment and diversification.
     By State and local governments
     A wide variety of State anrd local programs exist to
attract industry and promote economic development in the coal
producing States. All the coal producing States provide
mechanisms or have programs to promote economic development
through financial assistance, industrial bonds, tax incen-
tives, pollution control incentives, and special incentives,
services, and aids. Furthermore, host coal producing States
have promotional advertising progra s. Of course, the number
and type of mechanisms used to attrat- industry vary from
State to State. 109/
     The funding for State industrial development agencies
in the coal production States is shown in table 15. 110/
Much more money was spent on State activities to promote
industrial development in the Eastern and Central coal
regions of the United States than in the West. In fact, on
the average, Eastern and Central States spend about four
times more per capita on such activities than do Western
States. 111/

                                Table 15
                    Industrial Development Agency Fundin
                     in the Coal Production States (1975)

                 Department       Industrial              development
State               total     development (note a)        advertising
   Alabama       $ 1,655,000             $      650,000        $    45,000
   Arkansas         1,032,000                   602,000            160,000
   Kentucky         2,836,400                   270,300
   Maryland                                                        125,000
                    4,929,000                   319,000            141,000
   Pennsylvania    16,623,000                 5,560,000            600,000
   Tennessee        4,407,000                   454,000            200,000
   Virginia         1,290,000                   645,000
   West Virginia                                                   315,000
                    3,291,000                   334,000             96,000
        Total       $36,063,400          $ 8,834,300        $1,682,000
  --               $ 80,811,000          $      724,000     $
  Illinois                                                          30,000
                      5,222,600               1,527,800              -
  Indiana             1,304,922                  83,000            139,000
        Total      $ 87,338,522          $ 2,334,800        $      169,000
  Total East
    and Central $1;3,401,922              $11,169,100       $1,851,000
   iAaska       $     2,088,000           S     498,000
  Arizona (note b)
  Colorado            1,014,284                 144,760     $       97,500
  Iowa                1,326,000                 248,000            103,000
  Kansas              2,070,538                 163,347             50,000
  Missouri            1,109,244                 212,453             40,000
  Montana               429,000                  97,000              -
  New Mexico          1,651,000                 345,000             45,000
  North Dakota          155,650                 102,000
  Oklahoma                                                          14,000
                        744,000                 264,000            100,000
  Texas                 801,000                  82,000            262,000
  Utah                1,714,000                 180,000            189,000
  Washington          2,404,000                 269,000              -
  Wyoming               615,599                  99,317              2,000
        Total     $_16,122,315           $ 2,700,877       $       902,500
   Grand total    $139,524,237           $13,869,977       $2,753,500
a/Excludes expenditures for industrial development advertising.
5/State not reporting.

      By the Federal Government
     Numerous Federal programs are available to attract
industry and promote economic development. The Department of
Commerce, through the Economic Development Administration (EDA)
and the regional economic development commissions, implement
many of these programs. 112/ Other agencies involved in indus-
trial development programs include the Small Business Adminis-
tration and the Rural Development Program of the Farmers Home
Administration. 113/

     The underlying objective of EDA and the commissions is to
improve the economic condition of people in depressed
areas. 114/ This is attempted with a wide variety of grants,
loans, and technical assistance conducive to economic growth
and development. 115/

     There are eight multi-State regional economic development
commissions in operation which cover all or parts of 41 States.
The Appalachian Regional Commission was established under the
Appalachian Regional Development Act of 1965. The other seven
Regional Action Planning C"mmissions were established by the
Secretary of Commerce under the provisions of Title V of the
Public lWorks and Economic Development Act of 1965, as
amended. 116/

     To the extent that the Appalachian Regional Commission's
efforts toward economic diversification are successful, the
economic impact of future coal busts should be cushioned. 117/

      The primary goals of the Appalachian Regional Commission

      -- to furnish every person in the region with the health
         and skills needed to compete in everyday life and
      --to attract new industry and manufacturing, thus crea-
        ting more employment and a more diversified economic
        base and self-sustaining economy. 118/
     In order to achieve these goals, Appalachia needs an
adequate transportation system, community facilities (sewers,
water, solid waste disposal systems, housing, and related
amenities), schools, and hospitals. Commission investments
have been in transportation, health and child development,
education, community facilities, housing, energy, environment,
natural resources, research, and technical assistance. 119/

       According to the Commission's
  region's economy has been improving economic indicators, the
  improvement has been as a result of since 1965. 120/ The
 chian economy into a variety of new expansion of the Appala-
                                       industrial activities as
 well as growth in its traditional
 manufacturing. 121/ Industrial park economic  bases--coal and
 has proven a successful means of diversifying        for example,
 industrial growth in central Appalachia          and promoting
 of the country. 122/ Analysis of          as well as other parts
 trends in the regron since 1965 indicate economic and social
 improvement has occurred in such areas     that substantial
                                          as employment, per
 capita income, health education, and
 lachia still lags behind national      housing, although Appa-
                                    trends in many of these
 areas. 123/

     Each coal region in the country will
benefits and incur socioeconomic costs     derive economic
development. The net benefits to        from increased coal
                                   the areas will differ
widely, as we have seen. It appears
Eastern coal regions will derive the that the Central and
because of their high unemployment    greatest net benefits
                                    and depressed economies.
Furthermore, the social costs of increased
be greater in the West.                     production will

     Effects of increased coal development
     in the Central and Eastern Regions

     in 1976 the average unemployment
and Eastern coal producing counties    rate for the Central
involved 357,471 people. There are   was  7.5 percent and
unemployed in nearby population centers, a large number of
Pittsburgh, Pennsylvania; Birmingham,      such as
Ohio; and Charleston, West Virginia.   Alabama;  Youngstown,

      Increased coal development offers
accelerate the economic development     an opportunity to
                                     of these areas. The
economic situation should improve
                                   as new jobs are created
and the high unemployment rate drops.
                                        This is an important
step toward eliminating the socioeconomic
these areas have experienced. Furthermore,problems which
Federal economic development programs,        the need for
Regional Commission, may be reduced     such  as the Appalachian
improves.                            as th,  economic situation

     Since coal mining is a well established industry in the
Central and Eastern regions, its expansion should not have as
serious social consequences as in the West. When coal was
first developed in the East, it disrupted the self-contained
agrarian lifestyle and displaced the older community structure.
The major social transformations from coal development may
have already occurred. Through proper planning, the addi-
tional coal miners should not radically affect the way of life
in the traditional coal areas of the East.
     Some communities may not be able to accommodate a rapid
population influx without substantially improving their
facilities and services. This is particularly a problem
to many eastern communities that are having difficulty alle-
viating present socioeconomic problems. These communities
may have trouble meeting the additional infrastructure require-
ments of an increased population.

     Effects of increased coal
     development in the West

     Many Western States are large and sparsely populated,
making it difficult to provide quality services to all resi-
dents. Revenues from coal development could improve the pro-
vision cf State services, thereby benefiting the entire State.
     A properly coordinated and phased program of development,
which includes some industrial diversification, could provide
stable long-term employment for the populations.
      Socioeconomic effects are of particular concern to
sparsely populated areas, such as those in the West. Many
of the existing communities will not be able to absorb the
new population without constructing additional public facili-
ties.   If facilities and services are not available when the
population arrives, the quality of life will suffer. Since
these communities are small and homogeneous, their social
profile and way of li.e will change.

     Increased coal develcpment means an influx of people
into coal areas. The newcomers will need public facilities and
services. The problem is that the revenue needed to pay for
increased facilities and services will not become available
until coal-fired powerplants and coal mines go on the tax
rolls and residents become taxpaying citizens. To meet this
time lag problem, communities need advanced financing. They
also need timely and accurate information if they are to plan
adequately for expansion.

     Rock Springs and Green River in Sweetwater County,
Wyoming, are examples of what happens to communities that
are unprepared and underfinanced to cope with rapid popu-
lation increases. Public facilities for health care,
schools, recreation, sewage, and traffic were unable to
keep up with demand.

     Local government infrastructure costs due to increased
coal development might run as high as $4.4 billion between
1974 and 1985, and $14.9 billion between 1974 and 2000.

     Some portions of these socioeconomic costs may be beyond
the immediate means of many communities. Some States (Wyoming
and Montana, for example) have enacted legislation intended
to mitigate these socioeconomic costs. The Federal Government
has provided limited assistance.

     Regardless of whether Federal assistance is expanded
or not, the efficiency and effectiveness of Federal aid to
affected communities probably would be increased if one
agency were made responsible to coordinate the Federal role.

     The West will probably experience a more significant
population increase than either the Midwest or Appalachia,
and will probably experience more severe social change than
the Midwest or Appalachia as a result. Most of these small,
homogeneous western communities are in a poor position to
deal with the rapid growth. The social changes these com-
munities will undergo are a tradeoff for increased coal

     It appears that the Central and Eastern regions will
derive the greatest net benefits from increased coal develop-
ment because of their high unemployment and depressed economies.

                     FOOTNOTE REFERENCES

1/Paul Wataha, Mayor, Rock Springs, Wyoming, statement before
  the First National Conference on Financial Requirements for
  Energy Development in the Western States Region, Albuquerque,
  New Mexico, October 1975.
2/Analysis enf the Economic Base and Growth Potential    1976-
  1990 Gillette and Campbell Countx,Griadstone Associat -s,
  June 176.    -

3/Federation of Rocky Mountain States, Energy Development
  In the Rocky Mountain Region: Goals and Concerns (Denver:
  Federation of Rocky Mountain States, T75),  p. 89.

4/John S. G lmore and Mary K. Duff, The Sweetwater County
  Boom: A Challenge to Growth Manaqement (Denver: University
  of Denver Research TInstitutei  97), p. 1.

5/Ibid., pp. 14 and 15.

6/Ibid., p. 16.
7/Gene Roback and Henry R. Mason, Physician Distribution and
  Medical Licensure in the U.S., 1974 (Washington: American
  Medical Association,,T75-), p. 7~.
8/Gilmore and Duff, op. cit., p. 16.

9/Ibid., p. 17.
10/Ibid., p. 18.

11/Ibid., p. 19.

12/Ibid., p. 20.

13/Ibid., pp. 21 to 23.
14/John S. Gilmore, et al., Analysis of Financing Problems in
   Coal and Oil Shale Boom Towns, Appendix (Denver:   Unver-
   sity oT-Denver Research Instftute and Bickert, Browne,
   Coddington & Associates, Inc., 1976), pp. A-7 and A-8.
15/Ibid., p. A-23.

16/Ibid., pp. A-23 and A-24.

17/Ibid., pp. A-24 and A-25.

18/Ibid., p. A-25.
19/Ibid., Dp. A-25 and A-26.
20/Ibid., pp. A-8, A-9, A-11, and A-12.

21/Ibid., p. A-21.
22/R. L. Lindauer, Jr., Solutions to the Economic Impact on
   Boomtowns Caused by Large Energy Developments, Attachment
   VI (Denver: Exxon Company, U,    1975U) p. .
23/United States Energy Research and Development Administra-
   tion, Synthetic Fuels Commercial Demonstration Program Fact
   Book (Washington: Energy 'esearch and Development Adminis-
   tration, 1976), Tab 0, pp. 7, 8, and 9.
24/United States Departmer: of Housing and Urban Development,
   Rapid Growth From Energy Projects:  Ideas for State and
   LocaT Action (Washington: Department- oHousing and-Urban
   Development, 1976), p. 5.
25/Wyoming Senate Enrolled Act 49 - Wyoming Community Develop-
   ment Authority Act of 1975.
26, yoming House Enrolled Act - 118 of 1975.

27/Wyoming House Enrolled Act - 86 of 1975.

28/hyoming Senate Enrolled Act - 81 of 1975.

29/Montana Senate Bill - 13 of 1975.

30/John V. Krutilla, Anthony C. Fisher and Richard E. Rice,
   The Regional and Fiscal Impacts of Energy Resource
   Develoomen    A Case tu    of Northern Great Plains Coal
   (Washington: Resources for the Future, 1966;,p   , 39.
31/Montana Senate Bill - 87 of 1975.

32/Krutilla, Fisher and Rice, ao. cit., pp. 95 and 263.

33/North Dakota Century Code, 57-60-14 and 57-62-02.

34/Utah Resource Developmen    Act.
35/The Council of State Governments, Coal-State Coal Severance
   Taxes and Distribution of Revenues (Lexington: The Council
   oftEate Governments, 176T,   pp. 17, 18, 23, and 24.

36/Ibid., pp. 16-19, 28 and 29.

37/Ibid., pp. 16 and 17.
38/Discussion with the official of the Department of Taxation,
   Commonwealth of Virginia.
39/Discussion with Mr. Dennis Seipps, Governor's Energy
   Council, Commonwealth of Pennsylvania.

40/Discussion with Mr. John Chaille, Assistant Director,
   Indiana Energy Office; The Energy Resources Center of the
   university of Illionois, "Coal Gasification Plant Siting:
   Environmental, Social and Economic Impacts," December 1975,
   p. 10; The Council of State Governments, op. cit., pp. 1,
   and 27-28.
41/GAO computations based on:
   United States Bureau of Mines, Coal--Bituminous and Lignite
   in 1974, (Washington: Bureau ofMiTnes, 1976), pp. 24 to 31.
42/GAO computations based on:
   Executive Office of the Pr-sident, Fiscal Year 1975 Federal
   Outlays, 50 volumes (Washington: Government Printing
   Office, 1975).
43/Public Law 94-377.

44/Figures furnished by the Department of the Interior.

45/Public Law 94-579.
46/GAO computations based on:
   United States Bureau of Mines, Coal--Bituminous and Lignite
   in 1974, op. cit.

47/GAO computations based on:
   Executive Office of the President, Fiscal Year 1975 Federal
  Outlays, 50 Volumes, op. cit.

48/Appalachian Regional Commission, Housing in Energy Imp
   Areas--Recommendations (Washington Appaac-- ian Regional
   Commission, 1976),pp. 1 to 5 and the Appendix.

49/Appalachian Regional Commission, "Approved Housing - Energy
   Impact Projects (30 July 1976)," unpublished data.

50/Tennessee Valley Authority, Office of Tributary Area
   Development, "Review of Socioeconomic Impact Mitigation
   at Major TVA Power Generation Construction Projects since
   1966," unpublished material, p. 1.

51/Ibid., p. 6.

 52/Information obtained from official of Tennessee Valley
    Authority, Office of Tributary Area Development; Statement
    by Mr. Frank Clemente, Environmental Policy Center,
    Pennsylvania State University, personal interview.

53/Tennessee Valley Authority, Office of Tributary Area
   Development, "Hartsville Construction Project Impact on
   Local Goveilmet Budgets," unpublished material, p. 1;
   "Hartsville Project Socioeconomic Impact Mitigation
   Actions," unpublished material, pp. 1, 11, and 12;
   Tennessee Valley Authority comments on draft report.
54/Hartsville Impact Subgroup of the Projects Coordination
   Committee, "Hartsville Project Impact Area Proposed Impact
   Mitigation and Community Development," unpublished material
   p. 5.
55/GAO computations based on:
   Ibid., p. 2; Tennessee Valley Authority, Office of Tribu-
   tary Development, "Hartsville Project Socioeconomic Impact
   Mitigation Actions,' op. cit., p. 11.  Statement of
   Mr. Jack A. Thomas, Tennessee Energy Office, State of
   Tennessee; Tennessee Valley Authority comments on draft
56/GAO computations based on:
   United States Bureau of Mines, Coal--Bituminous and Lnite
   in 1974, op. cit., pp. 25 and L8.

57/GAO computations based on:
   Executive Office of the President, Fiscal Year 1975 Federal
   Outlays, 50 volumes, op. cit.
58/R. L. Lindauer, Jr., "Solutions to the Economic Impacts of
   Large Mineral Development on Local Governments," Energy
   Development in the Rocky Mountain Reion: Goals and
   Concerns,   . clT., p. 68
59/Roy Peck, "Industry Responsibility in Seeking Solutions to
   Regional, Economic, Environmental and Social Impacts Caused
   by the Rapid Development of Energy Minerals," Energy Develop-
   ment in the Rocky Mountain Region: Goals and Concerns,
   -. -cE., pp. lu- toPIrU.
60/Ibid., p. 110.

61/Appalachian Regional Commission, Housing in Ene._y Impacted
   Areas--Recommnendations, o. cit., Kentucky Program, p. 3
   and Virginia riogram, p. ,.

62/Statement by Mr. Steve Anderson, Corporate Communications
   Department, Westmoreland Coal Company, Philadelphia,
   Pennsylvania; Material furnished by Mr. Mike Musulin II,
   Public Relations Coordinator, Island Creek Coal Company,
   Lexington, Kentucky.

63/Statements by Mr. James Whitney, Assistant Public Relations
   Officer, Peabody Coal Company, St. Louis, Missouri, and
   Mr. Mike Rogers, Public Relations Officer, Amax Coal
   Company, Indianapolis, Indiana.
64/McFarland-Johnson Engineers, Inc., Socio-Economic Impacts
   of Coal and Industrial Development in the 1970s/1980s    for
   Llncoln-WaYne Counties in Region II, (Binghamton:
   McFarland-Johnson Engineers, Inc., 1976) p. VII-1.

65/Upper Midwest Council, Northern Great Plains Coal
   Conflicts and Options in Decision Making (Minneapolis:
   Upper Midwest Councii, ,-r976), pp. 5-37 and 5-38.
66/Frank Clemente, "What Industry Really Means to a Small Town,"
   Farm Economics, April 1975, p. 3; The Energy Resources
   Center of the University of Illinois, op. cit., p. 12.

67/Social, Economic, and Environmental Imacts of Coal
   Gasification and Lquefaction Plants (Lexington:  Institute
   for Mining an-iinerais Research, T76), p. 132.
68/Architecture Planning Research Associates, Environmental
   Assessment - Land Use, Socio-Economic and Transportation
   Issues Resulting from Larse Scale Mlinin and Refinina
   Co     nes, (Washigton:   ArchitectF     P-annlng Research
   Associates, 1975), pp. 68 and 69.

69/The Energy Resources Center of the University of Illinois,
   op. cit., p. 11.
70/McFarland-Johnson Engineers, Inc., loc. cit.

71/Northern Great Plains Resource Program, Socio-Economic and
   Cultural Aspects Work Grou Report (Washington: Department
   of Agriculture, l174T, pp. 43-45.

72/Federation of Rocky Mountain States, op. cit., p. 78.

73/Upper Midwest Council, op. cit.,    p. 5-36.
74/Upper Midwest Council, Northern Great Plains Coal Issues
   and 2ptions for Suppliers and Users Minneapolis- Upper
   Mirawest~ oun`MIT, 9§75),T i7. -

75/Upper Midwest Council, Northern Great Plains Coal
                                      aking, op. cit.,
   Conflicts and Options in Decision --
   p. 5-36.

76/School of Urban and Public Affairs, Power Plant Siting
   Policy Alternatives for Pennsylvania, (Pi'ttsburgh:
   Carnegie-Mellon University, 197), p. 68.
77/Synfuels Interagency Task Force, Synthetic Fuels
   Commercialization Program, Draft Environmental Statement,
   (Washington: Government Printing Office, 1975), p. IV-47.
78/McFarland-Johnson Engineers, Inc., op. cit., p. V-9.

79/Social, Economic, and Environmental Impacts of Coal
   Gasification and Llquefaction Plants. op. cit., pp. 118
   and 199.

80/Text of address by David Myhra, Boomtown Planning:
   Examples of Successful Applications at Nuclear Power Plant
   and WesternT Coal Mininges, at5't        Annual Conference
   oA-f"Amer'can  'nstituteof Planners, San Antonio, pp. 4 and
   5; Upper Midwest Council, Northern Great Plains Coal Issues
   and Options for Suppliers and Users,          1 p. -3;
    -Schoo-l o U-r5n and P       Affairs,lo
                              ubic          c. ct.

81/Northern Great Plains Resources Program, Effects of Coal
   Development in the Northern Great Plains (Washington:
   Government PrinTi-ng Office, 1975), pp. 122 and 123;
   Socio-Economic and Cultural Aspects Work Group Report,
    Ep. cit., p. 33.

82/Jack R. Davidson, Coal-Energy Development in the Northern
   Great Plains (Laramie:  Water Resources Research Institute,
   undated), p. 86.

83/Synfuels Interagency Task Force, op. cit., p. V-21; Northern
   Great Plains Resources Program, Effects of Coal Development
   in the Northern Great Plains, op., cit., p. 123T
84/Architecture Planning Research Associates, op. cit., pp.
   58 and 62.

85/Social, Economic, and Environmental Impacts of Coal
   Gasificat3ni-Z Lquefaction     isants., op. cit., p. 121.

86/Gilmore,   et al., op. cit., p. 78.

87/Federation of Rocky Mountain States, op. cit., pp. 76 and

 88/social, Economic, and Environmental Impacts of Coal
    Gasification and Liquefaction Plants, op. cit., pp. 118
    anc--   .
 89/Federation of Rocky Mountain States,    op. cit., pp. 76
    and 77.
 90/Mountain West Research, Inc., Construction Worker Profile
    Summary Report (Washington: 01T West Region-al Commission,
    1975), pp. 18 m-, e9.

 'I/1;;illiam H. !4iernyk, "Coal and the Future of the Appalachian
     E.onom-,"' pp1Racbia, October/November 1975, p. 29.
 92/Big Stone Gap, Virginia and LENOWISCO Planning District,
    Town of Big Stone Gap Special Impact Project in Order to
     eet Hous ng anP     Ic   Facility Needs,   976, pp. 2-ang-5.
 93/National Association of Counties, Preparing for Anticipated
    Growth Greene County Pennsylvania (Washington:  Federal
    EneLgy AamlnHstration, 1976), p. 3.
 94/Big Stone Gap, Virginia and LENOWISCO Planning District,
    loc. cit.

 95/Appalachian Regional Commission, The Appalachian Regional
    Commission (Washington: Appalachian Regionai Commission,
    undated), p. 9.
 96/Architecture Planning Research Associates, op. cit., p. 78.

 97/McFarland-Johnson Engineers, Inc., op. cit., p. V-9.
 98/Architecture P'anning Research Associates, op. cit., p. 122.

 99/Battelle Census Center, "U.S. Population Distribution Map,"
    More Facts on Ohio (Columbus: Ohio Department of Economic
    an6Community Development, 1976), p. 2.
100/Architecture Planning Research Associates, op. cit., p. 1;
    Battelle Columbus Laboratories, Technology Facility Siting
    Characteristics and Infrastructure Needs  (ColuIibus:
    Battelle ColumSus Laboratories, 1976), pp. 5-21 and 5-25.

101/Edward E. Holm, "The Diversity of Virginia's Appalachian
    Region and the Different Stages in Development of its
    Subregions," The Virginia Economic Review (Virginia Divi-
    sion of Industrial Develpment, August 1973) p. 8; Myhra,
    op. cit., p. 4, Synfuels Interagency Task Force, 2E. cit.,
     p. III-3.

 102/Beth Spence and Deborah Tuck, "There's No Place to Go,"
     United Mine Workers Journal, 87th Year, No. 4, February
     16-29, 7,    p.-.
 103/Centaur Management Consultants, Inc., Managing the Social
     and Economic Impacts of Energy Develo ments (Wa-sington:
     Energy Research and Development Administration, 1976), pp.
     13 and 18; School of Urban and Public Affairs, op. cit.,
     pp. 69 and 70; Upper Midwest Council, Northern Great Plains
     Coal Issues and Options for Suppliers and Users, op. cit.,
     pp. 8-, T, and 103.

104/Miernyk, op. cit., p. 29.
105/Appalachian Regional Commission, 1975 Annual Report
                                                         of the
    Appalachian Regiornal Commission (Was-ington: AppalaEiian
    Regional Commission,   75),  p176.
106/Miernyk, op. cit., p. 29.

107/Appalachian Rcgional Commission, 1975 Annual Re ort
                                                         of the
    Appalachian Regional Commission, op. cit.,  p. 6.
108/Centaur Management Consultants, Inc., o2.  cit., pp. 13
    and 18; Upper Midwest Council, Northern Great Plains Coal
    Issues and Options for Suppliers and Users, op. cit., pp.
     0" T1, and 103 ; Hitman Associates Inc., Underground Coal
    Mining: An Assessment of Technology (Palo Alto: Electric
    Power Resear    Institute, T976), p. 9-20.
109/GAO analysis based on:
    New York Senate Research Service Promoting Economic
    Development (Albany: New York Senate Research Service,
    T   76),
           Appendix B.
110/New York Senate Research Service, op. cit., Appendix
111/GAO computations based on:     Ibid.
112/Wendell Associates, Federal Assistance Programs and Energy
    Development Impacted Mu             (Washington: Fede--
    Energy Aaministration, 1976), pp. 4-23, 4-24 and 4-26.

1i3/Division of Industrial Development, Commonwealth of
    Virginia, Virginia Facts and Figures, 1976 (Richmond:
    Commonwealth of Virginia,- 176), p. 25.
114/Wendell Associates, op. cit., pp. 4-23 and 4-24.

115/Division for Industrial Development, State of Tennessee,
    Tennessee Community Guide for an Industrial Development
    Program, (Nashville: Division ir Indutri'al Developmeit,
    undated), p. 10.
116/United States Department of Commerce, Office of Regional
    Economic Coordination, Basic Facts About Multi-State
    Regional Economic Development Commissions (Washington:
    Department of Commerce, 1976), pp. 3 to-5; Appalachian
    Regional Commission, 1975 Annual Report of the Appalachian
    Regional Commission, °o.   clt., p. 6.

117/Appalachian Regional Commission, The Appalachian Regional
    Commission, op. cit., p. 10.

118/Ibid., pp. 4 and 8.

119/Ibid., pp. 4 and 5.

120/Ibid., pp. 10 and 11.
121/Appalachian Regional Commission, 1975 Annual Report of the
   Appalachian Regional Commission, op. cit., pp.2 16,20,
    and 2.
122/Daniel Good, "Industrial Parks: How to Succeed in
    Business by Really Trying," Appalachia, OcteoeL/November
    1974, p. 55.
123/Appalachian Regional Commission, The Appalachian Regional
    Commission, op. cit., pp. 10 and 1

                       CHAPTER 8
                IN THE WORLD COAL MARKET?

     The United States has more than 25 percent of the world's
coal, and is the world's largest coal producer and exporter.
The Soviet Union, the People's Republic of China, and Poland
are major producers; the Soviet Union and Poland are also major
exporters. Japan and the European Economic Community (EEC)
nations are major importers of coal.

     Traditionally, the United States has exported between 9
and 11 percent of its annual bituminous coal production,
which in 1975 contributed $3.3 billion to its balance of
payments. The United States exported 65.7 million tons of
coal in 1975, of which 50.6 million tons (77 percent) was
used metallurgically by foreign steel manufacturers. Japan,
the EEC nations, and Canada purchased over 86 percent
of U.S. coal exports in 1975.

     Future U.S. coal exports will be used chiefly in foreign
steel production. Despite stronger competition from other
exporting nations, U.S. exports of metallurgical coal are ex-
pected to increase to between 55 and 61 million tons in 1985
and to between 70 and 77 million tons in the year 2000. Ex-
cept for exports to Canada, U.S. exports of steam coal used
by foreign utilities to produce electricity are not competi-
tive, and are expected to increase only slightly.

     The quality of U.S. metallurgical coal is one of the
highest in the world, and both domestic and foreign steel
producers want to use it in their coke-making processes.
Supplies of metallurgical coal are limited, and data on its
production, use, and export have not been routinely collected
by the Bureau of Mines. This has led to some controversy con-
cerning exactly how much is produced and exported and whether
these exports will unfavorably affect U.S. steel production.

     Foreign investment in the U.S. coal industry is minimal.
U.S. coal companies that are wholly owned or partly financed
by foreign companies accounted for 4.4 percent of total 1973
U.S. production. Foreign companies invest in the U.S. coal
industry to assure security of supply and because the in-
dustry is profitable. They also seek secure sources of sup-
ply by entering into long-term purchasing contracts with
U.S. exporters.

     Since 1960 EEC nations have depended less on domestic
coal and more on imported oil to meet their energy needs.
EEC energy plans for 1985 call for a large increase in the
use of nuclear power and only a slight increase in the use
of coal. However, there is some doubt that the nuclear
goal will be met, and any shortfall will probably be made
up by increased use of natural gas and imports of oil rather
than increased use of coal. The United States is expected
to continue as one of the EEC's major suppliers of metal-
lurgical coal.
     In our discussions with officials in Europe, we found
that coal was generally thought of as a resource of the past
and a resource with use problems, whereas nuclear power
is thought of as a resource of the future. Economic con-
siderations may also be important. Coal production in the
EEC is beset with problems, including high costs; in-
creased coal use (except in the United Kingdom and Federal
Republic of Germany) would mean large amounts of imports,
causing dependence on foreign energy sources. Despite the
need to import uranium, EEC nations have the capability of
using nuclear power to meet some of their own energy needs
while, at the same time, developing an industry--nuciear

     Japan currently depends heavily on imports of oil to
meet its energy needs. Imported oil is expected to become
relatively less important between now and 1985, with nuclear
power becoming more important. Coal will probably continue
to meet about 12 percent of Japan's energy requirements
and as energy requirements grow, coal imports will have to
increase. Because of greater competition, however, U.S.
coal exports to Japan are expected to increase only slightly.
Reserves and production

     According to the 1974 World Eneigy Conference Survey of
Energy Resources, the United States has 26.1 percent of the
world's economically recoverable coal reserves. Chart 1

 shows worldwide distribution of recoverable coal reserves,
 which total 765 billion tons.*                  1/

                                         CHART 1
                             WORLD RECOVERABLE COAL RESERVES

        CANADA-0.8%                                   POLAND-0.5%
       (6 Billion Tons)                               (4 Billion Tons)
                               (4 Billion Tons                           (301 Billion Tons)

                                ST        OK                 {                           8    &
                             EERMANY-5.                            CHINA-14.6%*
                          (44 Billion Tos)                       (111 Billion Tons)
(200 Billion Tons)

     OTHERS-5.7                                                INDIA-1.7X
                                                               3 Bllion Tons)
    (44 Billion Tons)                                        (13 Billion Tons)
                                         REP. SO. AFRICA-1.5%,
                                           (12 Billion Tons)                     AUSTRALIA-3.5s
                                                                                 (27 Billion Tons)

*In this chapter, the word "ton" refers to net or short tons.
 The estimate of 200 billion tons shown by this source for
 the United States is probably low. See chapter 3, which
 estimates the U.S. reserves to be 256 billion tons.

Note:      Numbered footnotes to ch. 8 are on pp. 8.30 to 8.33.

      In 1975 approximately 2.3 billion tons of hard coal
(bituminous and anthracite) were produced worldwide, of which
60.3 percent was produced by the United States, the Soviet
Union, and the People's Republic of China.
     Marketable hard coal production for 1974 and 1975
is shown in table 1. 2/

                             Table 1
                       Hard Coal Production
     Producer                                 1974         1975
                                              -TmIllion tonsji
     United States                            590.6       624.9
     People's Republic of China (note a)      396.0       413.6
     Soviet Union (note a)                    328.5       336.1
     Poland                                   178.2       188.7
     United Kingdom                           120.1       140.6
     Federal Republic of Germany              104.4       101.7
     India                                     91.6        95.5
     South Africa                              71.5        76.9
     Australia                                 70.0        72.8
     Czechoslovakia                            30.7        30.9
     Canada                                    19.6        23.9
     Other countries                          171.8       174.9
          Total                            2,173.0     2,280.5

a/Figures for the Soviet Union and the People's Republic
  of China were reported in gross figures and were reduced
  to marketable production.

     BOM ha= projected that, by the year 2000 the United
States, the Soviet Union, the People's Republic of China,
Poland, and India will be the principal coal producers. 3/
Pr incipal exporters and importer s

     In 1975, six countries accounted for 94.1 percent of the
214.5 million tons of hard coal exported and other countries
accounted for only 5.9 percent. 4/

                                      CHART 2
                       PRINCIPAL WORLD COAL EXPORTS
                              BY COUNTRY, 1975

                       42.3 MILLION
                        MNET TONS               UNITED STATES
                                                 66.3 MILLION
                                                  NET TONS


       'IS 7 MILLION
         INET TONS                                                   /
                                                          12.7 MILLION
                                          7,4X \ 6,0r\NET TONS
                                           i      ;212.        OTHERS
                              USSR /      IL ION MitLL.
                              13.4X      NET     NET TONS
                         28.7 MILLION                   AdD
                          NET TONS        REPUL
                                         OF GERMANY

The countries that imported this coal are shown in                   table 2. 5/

                              Table 2
                 Principal World Coal Imports
                       By_Country (17
Country                         Tons             Percent of
                              (miT'ion)         world imports
Japan                          68.5                 31.9
France                         19.1                  8.9
Canada                         16.8                  7.8
Italy                          13.6                  6.3
Soviet -nion                   10.7                  5.0
Belgium-Luxembourg              6.9                  3.2
Bulgaria                        6.9                  3.2
Federal Republic of Germany     6.9                  3.2
German Democratic Republic      6.4                  3.0
Czechoslovakia                  5.7                  2.7
United Kingdom                  5.6                  2.6
Others                         47.5                 22.1

     Poland is currently second only to the United States as
a coal-exporting country. However, because of the availabil-
ity of their economically recoverable coal reserves and
current high production levels, the People's Republic of
China and the Soviet Union may become more important in
future world coal trade.

     A discussion follows of the role that coal plays in
meeting energy demand in the leading coal exporting countries
and of these countries' current and future marketing prospects.

     Poland, the world's fourth largest coal producer,
possesses roughly 0.5 percent of the world's total econom-
ically recoverable coal, or 4 billion tons. Because of its
reliance on indigenous coal, its fuel-energy position is
unusual among developed nations, owing to its low degree of
dependence on imported liquid and gaseous fuels, as shown
in table 3. 6/

                                 Table 3
                DistribLhcion of Primary             aner
                                                     aIV           Y

                      1970               1975               1980
                      Coal(pecent)---      -          -      ---
Coal                  82.3               76.5               69.3
Oil                   10.1               14.2               20.6
Natural gas             6.0               7.8                9.0
Hydropower              0.6               0.4                0.3
Other                   1.0               1.1                0.8
     The increase in oil consumption is caused by the
continuing modernization of Poland. Even though coal use
is declining in relation to crude oil use, the amount of
coal actually used to produc. electrical power, steam, and
hot water and to manufacture coke is expected to increase. 7/

     Coal and lignite are expected to produce about 95
percent of Poland's total electric :.', :ntil
                                         2-    198C.   From
1981 to 1990 it Z]ans to rely more              * e;.i.y
                                                     .   on nuclear power
for electrical generation and to !.rJe this use to
12 to 14 percent of total electrical generation by the year
2000. 8/
     Poland also plans to increase exports o" hard coal to
45 to 50 million tons by 1985. Hard coal · *duction may reach
276 million tons by 1990, which will necessitate the develop-
ment'and modern).zation of transport facilities. Port facil-
ities are currently being exp.nded in Poland's major Baltic
ports. Coking coal is good quality and priced to sell, and
steam coal is offer-d at good prices. Poland has planned to
remain a major coal exporter at least through tne year 2000. 93/

     People's    RFplic of China
     The People's Republic of China is presently the world's
second la.gest coal producer and possesses roughly i4.6
percent of the world's recoverablie coal reserves, or 1ll
billion tons.

     In 1952 coal accounted for 96 percent of China's total
energy supplies, but by 1974 it had declined to 6"' percent.
This was offset by increased use of oi.l and natu -i gas
during the same period. Production projections oL coal,
oil, natural gas, and hydroelectricity, which assume further
substitution of oil for coal, are shown in table 4. 10/

                                  Table 4
                          Total Energy Production
              Coal        Oil            Gas        Hydroeletricity
           ----------   …------------ (percent)---------------------
1974             67        23             9               1
1980       51 - 63      26 - 35      10 - 13              1
     Even though the percent of coal used to produce energy
is decreasing, coal production has increased from an average
of 286 million tons during 1967-1971 to 413.6 million tons
in 1975. 11/ This indicates a growth in China's economy,
because its coal exports are minimal.

     The Chinese are interested in the use of nuclear power
to generate electricity.  In 1972 and 1973 they sent indus-
trial survey teams of power and nuclear specialists to Japan
and Canada. However, nuclear power is not expected to be a
significant factor in energy production before 1985. 12/

     Priority is being given to the development of large coal
resources for internal steel and energy requirements and for
future expcrt. China exported 447 thousand tons of coal to
Japan in 1974 and hopes to expand its exports. 13/ Its coal
industry already compares in size with that of TEe United
States and the Soviet Union, and its annual output of
marketable coal may reach 560 million tons by 1985. The
coking coals are generally of good quality. 14/

     China has the potential of becoming an important coal
exporter. However, coal production centers, and possibly a
port, must be developed. 15/ China lacks foreign currency
for purchasing capital equipment and has a shortage of mining
machinery. 16/

       Soviet Union
     The Soviet Union currently ranks as the world's third
largest coal producer and possesses roughly 300 billion tons
of recoverable coal, 39.3 percent of the world's total.

     The 1976-80 Soviet 5-year plan for energy projects
increased coal, oil, and natural gas production, as shown
in table 5. 17/

                                 Table 5

                     Soviet Enery        Projections

            ....Actual .......     --         -1975                    1980
           1972    1973    1974      Planned          Estimated      Planned
           --------------- (million tons)----
RaW coal
  ranks)   697.4   717.2   737 0        764.5          770.0       869 to 691
  hard   a/      a/     a/                            b/          c/
  coal     313.2 -320.2 -328.5            -            336.1      -384 to 394
  oil      434.5   471.9   507.1        545.6          539.0       682 to 704
           -------------- (billion cubic meters)---------------
  gas      229.0   250.0   280.0        320.0          285.0       400 to 435
           -------------- (billion kilowatt hours)--------------
  power   850.0    913.0   985.0    1,065.0       1,035.0      1,340 to 1,380
 (note d)

    a/Production 1972-75 from BOM.
     S/Actual 1,975 marketable production.
    c/Estimated on basis of actual ratios between raw
       coal and marketable hard coal production during
    d/The 1976-80 projections include commissioning of 13
       million to 15 million kilowatts of capacity at
       nuclear powerplants.

     In 1960 coal accounted for 70 percent of all fuel
consumed in the Soviet Union, but by 1974 this had declined
to 45 percent. The combined share of oil and gas rose from
20 to 50 percent during the same period.  In the current

5-year plan, coal will be useu more widely in domestic power
generation, primarily to save oil and gas for petrochemicals
and export. 18/

     Development of coal reserves will be accelerated in the
next few years through construction and operation of massive
deep mines and strip mines. By 1985 the annual output of
marketable hard coal should reach between 440 million and
500 million tons. 19/
     Exports are   controlled only by market availability and
the Soviet Union   wants to expand exports to Western countries
and to Japan. A    new port is being constructed in the East to
facilitate trade   with Japan. 20/

     As noted, U.S. coal exports consist primarily of metal-
lurgical coal and thus have little impact on the supply
domestic coal for power generation. Total imports* for
were only 0.94 million tons and domestic production was 1975
million tons. Chart 3 illustrates domestic production, 640
domestic coking coal use, imports, and exports in 1975.

*Imports of coal may increase in the future as the price
 of coal in the United States rises, making foreign coal
 economically attractive. A recent order for 7.7 million
 tons was given by a Florida utility to a coal mining
 company in South Africa. This decision was made after
 the utility found that it could purchase the low-sulfur
 coal at a more favorable price than could be negotiated
 in the United States.

                                                                CHART 3
                                                         DOMESTIC COAL USE


               640.9 Million not tons includes imports of 0.9 million not tons


              U8.3 million not tons


              65.6 million net tons (50.6 million net tons,or 77.1%, used metllurgicelly)
   KEY:         '::.-?   Portion of Exports Used for Power GCneration

                         Portion of Exports Used Metollurgiclly

      The majority of U.S. exports originates in the Eastern
region and moves to ports or to Candda by rail. About
75 percent of all coal exports are shipped overseas out
of Hampton Roads, Virginia. Lesser amounts move through
Baltimore, Mobile, New Orleans, Philadelphia, and Los Angeles.
Coal exporters cited a need for more railroad hopper cars and
better storage facilities at the ports to facilitate movement
of coal to the ports and loading of coal onto ships. Delays
in transporting and processing coal ultimately increase its
price, possibly damaging the competitive position of U.S.

     Foreign purchasers generally enter into long-term con-
tracts (some as long as 15 years) for U.S. metallurgical coal
to promote incentives for capital investment in production
facilities. The contracts contain cost escalation and
renegotiation provisions and rely on mutual good faith--
the abilities of the U.S. producer to supply coal and of the
importer to buy it. Coal exporters believe that the foreign
buyers should not be made to suffer more than domestic users
in the event of a supply crisis.

Foreign investment in coal industry

     According to a study by the Federal Energy Administra-
tion, 15 foreign companies wholly own or partly finance 19 U.S.
coal companies or mines, which produced approximately 26 mil-
lion tons of coal in 1973, 4.4 percent of total U.S. coal
production. 21/ The investments include equity acquisitions,
joint venture agreements, and loans sometimes offered as ad-
vance payments.

      Increasing foreign interest in investing in U.S. coal
production indicates the current trend of foreign countries
to seek secure supplics to support their steel industries.
For example, Japanese companies have entered into two agree-
ments whereby money loaned to various U.S. coal-producing
companies will be repaid by long-term contract deliveries.
Also, companies from Canada, France, the Federal Republic
of Germany, Japan, and the Netherlands have invested in
partial or total ownership of new mines, which would probably
not be opened without this foreign investment. 22/ Thus
American jobs are created by foreign money.

     The desire to invest in a profitable enterprise is an
additional incentive for foreign investment in the domestic
coal industry. For example, a company from the Federal Repub-
lic of Germany is negotiating to buy at least two more U.S.
cbal-producing properties to add to its other operations in
West Virginia and Kentucky. Its present U.S. subsidiaries
produce about 2 million tons annually, most of which is being
sold to U.S. steel producers under long-term contracts. 23/
Also, a British investor has purchased 25 percent of the
11th largest U.S. coal-mining corporation, which produces
roughly 10 million tons of coal annually. 24/

     According to U.S. coal exporters, increased foreign in-
vestment does not appear to be a matter of concern and the
percent of U.S. coal production controlled by foreign inter-
ests is so small that the possibility of foreign control of
domestic coal markets is unlikely.

     The United States also invests in foreign coal industries.
For example, a few U.S. coal companies or their parent com-
panies control 70 to 75 percent of the Australian coal
industry. There is also some U.S. investment in the Canadian
coal industry.

 Prospects for increased coal exports
       Bituminous coal exports in 1975 totaled 65.7
 tons--50.6 million (77.1 percent) for metallurgicalmillion
                                                      use and
 15.1 million primarily for utilities' use. Canada imported
 9.6 million tons for use by utilities and 7.2 million
 metallurgical use. 25/ The United States benefits from for
 coal shipments to Canada, because Canada exports to the steam
 States the equivalent of about 33 percent of such shipments
 in the form of electric energy.

     U.S. coking coals, although high priced, have remained
competitive, since they have stronger coking properties
a lower ash content than those of most foreign competitors.
Japan rated the United States as one of its most reliable
coking coal suppliers. 26/ In April and May 1976, Japan
paid $63.35 a ton* for o&al from the United States,
$55.33 from Poland, $52.81 from Canada, $50.24 from
Soviet Union, and $47.03 from Australia.

      Unlike coking coal, U.S. steam coal has no particular
quality advantages and there are considerable world
of this type coal.   Steam coal prices are based on Btu and
sulfur content. The United States cannot compete with
foreign steam coal prices, and its exports, other than
Canada, are minimal.                                     to
                       The Federal Republic of Germany imports
mostly steam coal and in 1975 paid $47.64 a ton c.i.f.
the United States, $38.11 from Poland, $36.48 from the from
United Kingdom, $27.26 from the Soviet Union, and $25.33
from the Republic of South Africa. 27/ It appears, therefore,
that steam coal exports overseas wilT remain at low levels.
     Both steam and metallurgical coal exporters face vigorous
competition from Poland and the Soviet Union, because
countries' pricing practices reflect overall national those
economic goals rather than cost factors. The People's
lic of China may also be expected to use this pricing Repub-
tice, if in the future it becomes a major exporter.    prac-

     European countries and Japan stress strong nuclear pref-
erences for meeting future energy demands, since, except
the United Kingdom and West Germany, they lack coal resources.
A total nuclear moratorium is considered improbable because
of the desire of these countries to gain nuclear capabilities
and to lessen dependence on imported oil. 28/

*Includes cost of coal, insurance, and freight (c i.f.).

     U.S. coking coal exports in 1985 and beyond will depend
on foreign requirements for steel.   In 1975 foreign raw steel
production totaled 601.6 million tons, causing a coking coal
demand of roughly 476.7 million tons--0.79 tons of coking
coal for each ton of raw steel produced. The United States
supplied 10.6 percent, or 50.6 million tons, of this coking
coal. The Coal Task Group of the National Petroleum Council
and BOM estimate that (1) foreign raw steel requirements
for 1985 will be 975 million tons, a growth rate from 1975
to 1985 of 4.95 percent annually, and (2) foreign coking
coal needs in 1985 will be 527 million tons---0.54 tons of
coking coal for each ton of raw steel produced. The decreased
use of coking coal to produce raw steel assumes that future
technology will reduce the amount of cake required to produce
a ton of pig iron. Thus the growth rate for coking coal
demand will be one percent a year between 1975 and 1985. 29/

     BOM estimates that total U.S. coking and steam coal
exports will be 75 million tons by 1985 (roughly 11 percent
of the foreign market) and 100 million tons by the year
2000. Over the past six years, an average of 77.4 percent
of exports was used metallurgically. This average, applied
to the BOM projections for exports, is shown in
table 6. 30/

                            Table 6
                       Exort Projections
Year      Metallurgical use        Steam use     Total exports
          ------------- :=--(million tons)-------------------…
1985            58.1                  16.9            75.0
2000            77.4                  22.6           100.0
     According to BOM projections, metallurgical coal
exports will increase at an annual rate of 1.39 percent
between 1975 and 1985 and 1.93 percent between 1985 and
2000, or at an overall annual rate of 1.71 percent be-
tween 1975 and the year 2000.

     A working party of the Organization for Economic Cooper-
ation and Development reassessed the role of coal and esti-
mated that 1985 U.S. coking coal exports will be between 55
million and 61 million tons. 31/ An official of the Coal Ex-
porters Association estimated that such exports would be be-
tween 55 and 57 million tons in 1985 and 70 and 71 million
tons in the year 2000.

     Except for modifications that will result in somewhat
lower coke ratios, technological changes in steel manufac-
turing are not expected to substantially alter demand with-
in the next decade. Metallurgical coal is the most economi-
cal and technically satisfactory coal to use in making coke
for the production of steel.  Two publicized experimental
processes (formed coke and direct reduction) that do not
use metallurgical coal are being tested in this country, but
they are not expected to be economical within the next de-
cade. 32/
     A July 28, 1976, statement on metallurgical coal by
the American Iron and Steel Institute emphasized that U.S.
low-volatile coal resources are limited. 33/ Coal exporters
share this view but believe that the magnTEude of low-
volatile exports does not adversely affect domestic steel
industry supplies nor seriously jeopardize U.S. reserves.

     The exporters note that long-term contracts are required
for financing new mines and that without export trade some
mines would have to be closed. They also contend that the
steel industry has assured the availability of low-volatile
coal through captive mines and resources. The Institute
expressed concern about the possible future use of metal-
lurgical-type coal for power generation because of environ-
mental constraints. It suggested that data be gathered on
production, consumption, and foreign trade of premium-grade
metallurgical coal by low-, medium-, and high-volatile

     As reported on page 3.14, there are no accurate estimates
of coking coal reserves, but previous BOM studies have indi-
cated that about 20 billion tons of the demonstrated bituminous
coal reserve of 233 billion tons consists of premium-quality
coking coals.  An assessment by the Bureau indicates that
about 7 billion tons is low-volatile coking coal.

     By relating production to quality in a fuel data bank,
BOM estimated 1975 U.S. production by grade and volatility,
as shown in chart 4. 34/

                                         CHART 4

                                       1975 U.S. Production: 640 Million Net Tons

    GRADE             GRADE      GRADE
     COAL         LOW-VOLAT       M
                                 LE                              PREMIUM GRADE HIGH-VOLATILE COAL
 184.5 Million        O           OATILE                     \         139.4 Million Not Tons
   Not Tons         24.2 Mi llion COAL

                  Di MEDI UVLA         _f      GGRAN
 |69.2 YIWilton LGOACOAL    15.5
                     1o (.Mll    Mi 0
                              .S5tlll      I 47.8 Million Net Tons
   Not Tons                  Tons

                                                                    ::::::          ............

386.3 illi                    : . .:.:...%
  Not Too A         . .      .   ..........

                          :: .'.:.:~:''.%.;·
                                    .''.....          '
                                                   :,:..%             .**               ~
                                                                                    .%.%:..:*..*.     .:..%:.
                                                                                                           : .:.:::::
                                                                                                                : ::

   ot TMorginal Grade Co.:                                              M::u:::o:a:i:. Co%:

      Of the estimated 30 million tons of U.S. low-volatile
coking coal produced in 1975, approximately 17 million
tons were used for domestic production of metallurgical coke,
4 to 5 million for electric power generation, 2 million
for industrial fuel and heating, and 6 million tons for
export. The end use of the remainder could not be determined.
Not much low-volatile metallurgical grade coal is used
domestically to generate electric power, but BOM and
electric power officials note that, in addition to
steam grade coal, higher volatilities of premium- and
marginal-grade coking coals are used for this purpose. 35/
Higher categories of coking coal are generally not used
for power generation due to their higher price and the
limited flexibility of utility boilers regarding the type
of coal they can burn.
     BOM estimates coking coal exports from fragmentary
data supplied by shippers and consumer country reports.
Most countries and private companies have varying classifica-
tions of coal but none report on the volatile matter content
of imported coal. The high-, low- and medium-volatile coal
classifications of the BOM are of academic interest only,
since the use of company name brands and the mixing of
coals before shipping is the usual practice. The volatile
matter and ash content and other elements of the coal analysis
are determined to ascertain conformance to contract specifi-
cations and are precisely known only by the shipper and the
purchaser. These specifications vary from purchaser to
purchaser and do not usually coincide with BOM criteria.
Thus BOM contends that no precise data is reported for
low-volatile coal and that, in the absence of identical
standards for volatility, estimates of low-volatile bituminous
coal exports cannot be made with certainty. 36/

     Our report of April 14, 1976, (B-178205) stated that
the Federal Energy Administration was not fully complying
with a congressional mandate to maintain information on coal
exports. The President of the Coal Exporters Association
of the United States, Inc., suggested that the Shipper's
summary Export Declaration, now filed with the Department
of Commerce, be amended to report whether exported coal
is'of steam or metallurgical grade, and, if metallurgical
grade, whether it is low-, mediumor high-volatile as
defined by American Society for Testing and Materials stan-
dards.  In commenting on this report, FEA stated that they
had reached agreement with the Department of Commerce for a
system for collecting information on coal exports. The new
system should be in operation shortly.

     The United States exports primarily bituminous coal.
Anthracite exports (primarily to Canada arnd the EEC) and
lignite exports totaled only 1.4 percent of U.S. coal exports
in 1974. Bituminous coal exports have consisted of over 77
percent metallurgical coal since 1973 (see table 7). 37/
This figure was somewhat inflated in 1974, when some nations
faced the possibility of shortages of metallurgical grade
coal and bought lower grade coal for metallurgical use.

                                       Table 7
               Destination of U.S. Bituminous Coal Exports by Use

                           -1973               1974                   1975
                  Metal-                 Metal-               Metal-       Percent of
                 lurgical Total         lurgical Total      lurgical Total total 1975
 Destination       use   exports          use   exports        use exports exports

                 ----------------------- (thousand tons)-----------
Canada            7,733      16,231      7,488     13,706     7,168   16,735    25.5
Latin America     2,946       2,963      2,761      2,761     3 728    3,801     5.8
European Economic

  Luxembourg      1,205       1,205      1,109      1,109       627      627
France                                                                           1.0
                  1,866       1,866      2,510      2,510     1,735    3,583     5.5
West Germany         32       1,632         49      1,484        50    1,989     3.0
United Kingdom      895         941        915      1,405       888    1,888     2.9
Italy             3,192       3,294      3,786      3,903     4,410    4,493
The Netherlands                                                                  6.8
      (note a)    1,780       1,780          545    2,545     292      2,093     3.2
  Total EEC       8,970     10,718      10,914     12,956     9L802   14,673    22.3
Other European
  Countries     3,534        3,534       2,899      2,899     4,180    4,498     6.9
Japan          19,190       19,190    b/27,346     27,346    25,423   25,423    38.7
Other             234          234         258        258       319      537     0.8
  Total          42,607     52,870      51,666     59,926    50,620   65,667   100.0

  use of total
  coal exports
  (percent)               80.6                 86.2                    77.1
a/ Includes some tonnage transshipped to other European

b/ Includes some tonnage not customarily classified as
   metallurgical coal.


European Economic Community

     The use of coal as a source of energy has declined in
the EEC* since 1960, because domestic coal production has be-
come more difficult and costly. As shown below, 1985 objec-
tives of the EEC Commission, the Community's administrative
body, show that the primary emphasis will be placed on oil
and natural gas, with coal and nuclear energy providing
about the same, but smaller, levels of energy input. 38/

                                        CHART 5
                              PRIMARY ENERGY REQUIREMENTS                     (note a)
tons of coal equivalent (note b)





       1960                                      1973                                        1985
                                              PROVISIONAL                                OBJECTIVES
2/lncludes requirements for pouer generation, steelmaking and llother uses.

 /One ton coal equivalent equals 2.8X10 7 Btu.

*Belgium, Denmark, Federal Republic of Germany, France,
 Ireland, Italy, Luxembourg, the Netherl&nds, and the
 United Kingdom.

      In 1975 EEC produced 275. '-ill.n tons of
 percent of the world total. Average production  coal, 12.1
                                                 during 1967-71
 was 361.9 million tons, 17.8 percent of the
                                             world total.
 Netherlands' coal industry has been completely             The
                                                phased out.
 Belgium, the United Kingdom, the Federal Repblic
 and France are the only remaining major EFC       of Germany,
                                             coal producers. 39/
       EEC mines in genera]
 Difficult mining conditionsare old and nearly depleted.
                              have led to high costs and low
 productivity despite mechanization. From
                                            1970 to 19 4, aver-
 a3e output per worker per shift in underground
 about 3.9 tons while the number of miners        mines remained at
                                            decreased from
 411-,000 to 341,000. 40/ Many mines have beeni
marily to provide employment in economically     kept open pri-
                                                depressed areas.
       The EEC imported 39 percent of its energy
1973 it was importing 61 percent, primarily       in 1963. By
of crude oil almost tripled from 1963 and     because   imports
creased 37 percent. At the same time, production  production  de-
gas increased by a factor of ]0. 4i/                 of  natural

      Thus in 1973 the EEC depended on imported oil
                                                      for about
56 peLcent of its energy needs. 42/ EEC nations
tempting to lessen this dependence hy stressing are now at-
ment of nuclear power and North Sea oil --I        the develop-
by providing for a modest increase in coal    gas  fields and
                                             production from
its 1973 level.

     Future energy requirements
     The EEC Commission's "Medium-term guidelines
                                                   for coal
1975-1985," dated November 21, 1974, stated
of 1973 demand that the EEC reduce dependencethat the events
energy and that coal should continue to play on imported
generating electricity and making steel for a role in
                                             a long time. 43/
     Commission energy goals for the year 2000
nuclear and gas to supply 50 percent and       anticipate
respectively, of .-                      33 percent,
                  he total energy needs. To accomplish these

    -- Nuclear power station construction would
                                                have to
       be accelerated so that by 1985 nuclear power
       would supply half the electricity requirements.
    -- Indigeious and imported supplies of natural
       gas must be increased and used optima. iy.

     --Consumption of coal and lignite must be raised above
       current levels, calling on increased production and

     The Commission quantified these goals as follows,
based on planning goals of the EEC members. These goals
are not binding but are intended as policy guides. 44/
                                   Table 8

                      Primary Energy Re_2          _rements of the EEC
                                            1973                 1985
                      1960              provisional          objectives
                       ------         p    ere t)-----------

Solid fuels           60.0                    22.6                16
Oil                   33.0                    61.4                41
Natural gas            1.7                    11.6                24
 power, etc.           5.2                     3.0                 2
Nuclear energy         0.1                     1  i               17

     Projections for solid fuel use in 1985, by market, are
shown in table 9. 45/
                                    Table 9

                      Solid Fuel Use in the EEC

                         1973                         1985
                          (iiillion tons coal equivalet-?-
Hard coal:
     Power stations          119                                149
     Coking plants           107                                115
     Other markets            64                                 40

                             290                                304

Other solid fuels             35                                 53

  Total                      325                                357

     To meet this modest increase in coal use with little
increase in domestic production, imports would have to in-
crease from 33 million tons in 1973 to 55 million tons in
1985 (1975 imports were 44 million tons).  Poland and the
United States are expected to continue as the major exporters
to EEC, but, as discussed before, the U.S.
would probably be mostly limited to coking market share
                                           coal. 46/
     To compare overall EEC objectives with individual coun-
try plans, we spoke with government and steel, coal, and
electrical industry officials in the United Kingdom, Federal
Republic of Germany, France, and Belgium. These officials,
except for those in the United Kingdom, agree with the Com-
mission view that domestic produiction will increase only
slightly in the next 10 years. They do not agree that there
will be an increase in steam coal consumption and, thus, a
need for increased imports.

      In our discussions, we found that coal is generally
thought of as a resource of the past and a resource with
usage problems, whereas nuclear power is thought of as a
resource of the future. Economic considerations may also be
important. Coal production in the EEC is beset with problems,
including high costs, and increased coal use (except in the
United Kingdom and Federal Republic of Germany) would mean
large amounts of imports, causing dependence on foreign energy
sources. Despite the need to import uranium, EEC nations
have the capability to develop nuclear power to meet some
of their energy needs while at the same time, giving them an
export industry--nuclear reactors and other equipment.

     Federal Republic of Germany
     Government officials in the Federal Republic of Germany
plan for coal production to remain constant at 1973 and 1974
levels. Among the measures taken to stimulate use of domestic
coal and reduce rising dependence on foreign oil are (1) a law
generally prohibiting the construction of new oil- or gas-
fired electrical generating plants, (2) an import quota of
about 6 million tons of coal a year, and (3) subsidies to the
coal industry amounting to $3.20 (in 1975) per ton of produc-
tion. The goal is to be more than self-sufficient in coal up
to the year 2000.

     The use of coal in total energy needs will remain con-
stant to the early 1980s, when nuclear power is expected to
begin replacing steam coal for electrical generation.
Nuclear power is projected to meet 40 percent of the electri-
cal demand in 1985, but the forecast may be revised downward.
An increase in EEC steel production and the resultant demand
for coking coal may balance the decreased domestic demand for
steam coal as existing coal-fired power stations are phased

     Energy consumption goals for 1985 are shown in table
10. 47/

                              Table 10
                West German Energy Consumption

                                 1973             1985
      Oil                          55               44
      Hard coal and lignite        31               21
      Natural gas                  10               18
      Nuclear energy                1               15
      Other                         3                2
     Small amounts of coal are currently imported, mostly for
use by utilities. Since it has an excess supply of coal,
officials do not expect an increase of steam coal imports.

       west German steel producers are obligated, by agreement,
to buy only West German coking coal, if available.    Coal
proaucers do not anticipate domestic coking coal demands to
increase, despite increased demand for steel throuc'ih 985,
because of technological changes in the steelmaking process.
The domestic supply of coking coal should more than meet
aemand¢ .

     The United Kingdom
     The United Kingdom plans to expand coal production
about 145 million tons by 1985, but coal use as a percentto
of total energy consumption is expected to decrease slightly.
Further expansion is expected at least to the year 2000.
increased coal production and consumption is an integral
part of its goal of energy self-sufficiency. Energy demand
goals for 1985 ale shown in table 11. 48/

                           Table 11
                    British Enerey Demand

                                1973               1985
                                       (per ent)
      Oil                       49.9                 44
      Hard coal and lignite     35.3                 31
      Natural gas               11.2                 18
      Nuclear energy             3.2                  7
      Other                      0.4                  -

      -he United Kingdom currently has an excess capacity for
power generation and is not overly concerned about nuclear
power. Coal is seen as a more feasible source of power in
the near future. Nuclear power will be more important beyond

     Reserves of oil and natural gas in the North Sea are
expected to reap economic benefits amounting to almost 8 per-
cent of the gross national product by 1985. 49/ British North
Sea oil production is expected to be about 2 million
barrels a day in 1980, which, as a comparison, is equivalent
to about one-eighth of current U.S. oil consumption. The oil
will be used for domestic and export purposes.  It is expected
to have little effect on steam coal use.

     British officials expect that domestic production of
steam coal will meet needs for the next several years and also
allow about 3 million tons for export.

     Steel production is expected to increase through 1985.
Government officials believe that demand for coking coal Aill
remain constant because of technological advances, but steel
industry officials see coking coal needs increasing by 25
percent over current needs. The United Kingdom has large
reserves of coking coal but must import two to three million
tons of high-quality coking coal a year. Gc-,ernment officials
see no additional demand for coking coal imports, whereas
steel industry officials do. The United States is currently
the United Kingdom's largest metallurgical coal supplier
and is expected to remain so, despite the fact 'hat some
British officials feel that the United States     not always a
reliable supplier.

     France and Belgium
     The small coal industries in France and Belgium survive
only with heavy government subsidies. Belgian officials say
that coal production in Belgium will remain at current levels
through 1985.  Production in France is expected to decline.
Nuclear power is expected to play a large role in meeting
both nations' electrical power needs by 1985, but levels of
nuclear production are uncertain.

     Both countries will have to import steam coal until
their nuclear goals are met. Nither country currently im-
ports mu:!h U.S. steam coal nor are they expected to do so
in the future.

      Coking coal requirements in both nations are expected to
remain constant through 1985 and most will have to be imported.
The United States will probably remain an important supplier.
     Due to Japan's limited domestic resources and dependence
on overseas supplies, the Ministry of International Trade
and Industry has formulated a new energy policy for Japan.
The new policy's basic premise is that slowing Japan's rate
of economic growth will slow the accompanying energy demand.
Japan intends to shift its long-range economic emphasis from
massive energy--consuming industries* to low energy-consuming,
labor intensive industries in order to promote more efficient
use of energy. 50/

     Projected energy demand and supply are shown in table
12. 51/

*One major effort will be to   shift or- conversion facilities
 (i.e., aluminum, copper) to   the ore    ~ducing country.
 This decision may portend a   future tL.,ld by those countries
 that are heavy importers of   raw ores.

                                  Table 12
                      Japanese Energy Demand and Su2ly

                                   1973       1980         1985
                                   -------- (percent)
Hydropower                         4.7           4.2
Geothermal ene-gy                                          3.7
                                   0.0           0.1       0.5
Domestic petroleum and
  natural gas                      0.9           1.2
Domestic coal                                              1.8
                                   3.8           2.5       1.9
Nuclear power                      0.6           4.4
Imported liquified natural                                 9.6
  gas                              0.8         5.2         7.9
Imported coal                     11.8        13.4
Imported petroleum                                        11.2
                                  77.4        68.9        63.3

     Despite some domestic opposition to nuclear powerplants,
Japan's use of nuclear power is projected to increase
percent in 1973 to 9.6 percent in 1985, which will     from 0.6
roughly 26 percent of total electric power production.
     Coal is expected to remain important in Japan, but
used primarily for steel production, as shown in table will be
                                                        13. 53/
                                   Table 13
                               Japanese Coal Use
                      1973                1980               1985
                     Percent                 Percent              Percent
                       of                      of                   of
             Amount energy          Amount energy Amount          energy
            (million               (iiT-on-n         (miIITTin
              tons)                  tons)              tons)
Domestic coal 23.8       3.8         22.0         2.5
Imported coal 63.8                                        22.0       1.9
                        11.8        101.2        13.4    112.6      11.2
 steam coal)    (0)                  (5.2)               (16.1)
    Total      87.6     15.6        123.2     15.9       134.6      13.1

     Australia, the United States, and Canada will continue
to oe Japan's principal coal sources, but by 1980 Australian
and Canadian coal is expected to account for a slightly
share of Japan's total coal imports, while the United
share decreases by about 10 percent.  Imports from the Soviet
Union, the People's Republic of China, and Poland are
ed to increase. 54/ Thus,, the United States will face
creasing competition in the Japanese coal market.

Views of the International Energy Agency

     The Secretariat of the International Energy Agency (IEA)*,
the IEA's administrative body, has expressed doubts about
energy projections of its members.  A discussion paper, dated
June 8, 1976 stated in part that:

     --A special IEA study gives reason to believe that the
       Agency's nuclear capacity will be significantly be-
       low member projections for 1985.

     --Oil and natural gas are limited in quantity and,
       worldwide, the present generation face3 the probable
       end of the oil era.

     -- New technologies (e.g., solar power) are unlikely
        to produce energy on a major scale before 1990
        or later.

     The Secretariat believes that, for these reasons,
should be a serious and sustained reexamination of coal there
that the subject should receive no less attention than
clear power. 55/ It had stated earlier that, unless
                                                      more coal
and the facilities to use it are available, any nuiclear
fall may have to be offset with additional amounts
                                                    of im-
ported oil. 56/

*The IEA, established in November 1974, consists of
                                                     18 mem-
 bers of the Organization for Economic Cooperation
                                                    and Devel-
 opment, including all EEC nations (except France),
 United States, Canada and Japan. Its purpose is to
 cooperation in energy matters among its members,
                                                   other oil-
 consuming nations, and oil-producing nations,

      It seems logical that the IEA would prefer its members
to use more coal and less oil. A primary objective of the
IEA is to reduce its members' dependence on imported oil.
IEA members produced slightly over one-third of the world's
coal in 1974, an amount only slightly below their demand.
However, they produced about 20 percent of world production
crude oil, an amount equal to only 40 percent of their

     This reasoning may appear less logical to the Agency's
EEC members. Five of them produce almost no coal at all
the three that do see production problems and lack of de- and
mand as major hindrances to expanded coal production.

      The United States is the largest producer and exporter
of coal in the world. Despite stiffer competition, especially
from the Soviet Union and Poland, in the years to come,
United States should continue to do well in the world coal
mark.et due to the high quality of its metallurgical coal.

      In 1975, United States coal exports made a positive
contribution of $3.3 billion to the Nation's balance of
ments. In that year, 77 percent of the United States coal pay-
exports were metallurgical coal to foreign steel manufacturers.

     Metallurgical coal exports are expected to increase
an annual rate of 1.71 percent between the present and theat
2000. Exports of United States steam coal, which is less year
petitive, are expected to increase more slowly than metallur-
gical coal exports. Historically, the United States exports
from 9 to 11 percent of its annual bituminous coal production.

     Whether the continued export of metallurgical
adversely affect domestic steel manufacturers in thecoal will
                                                      future is
a matter of dispute. Better data ale needed concerning
size and characteristics of metallurgical-grade          the
                                                coal deposits
in the United States.

     Foreign investment in the United States coal industry
accounted for about 4.4 percent of total production in 1973
and is not considered a policy problem.

                       FOOTNOTE REFERENCES

1/"A Look at Global Coal Resources," World Coal, Vol. I,
  November 1975, p. 37.

2/United States 'ureau of Mines, International Coal Trade,
  Vol. XLV, April 1976, p. 31.

3/George Markon, "World Overview," unpublished paper, p. 11.

4/United States Bureau of Mines, International Coal Trade,
  Vol. XLV, August 1976, p. 25.

6/Boteo Tachkov, "The Mineral Industry of Poland," 1973
  Bureau of Mines Minerals Yearbook (Washington: Government
  Printing Office,-T975), p.7 C.

7/United States Bu> au of Mines, International Coal Trade,
  Vol. XLV, March i.76, p. 14.

8/National Coal Association, World Coal Trade (Washington:
  National Coal Association, T175), p. 51.

9/Ibid.; Tachkov, op. cit., pp. 7,8; M. Swiss, "Polish Review
  an-Prospects," Worl' Coal, Vol. I, November 1975, p. 42;
  H. P. Drewry Limited, Coal Cargoes Through the 1970's
  (London: H. P. Drewry ELmited, T73, ~pp. 2='    6;
  United States Bureau   of Mines, International Coal Trade,
  Vol. XLV, March  1976,  pp. 14,15; United States Bureau
  of Mines, International Coal Trade, Vol. XLV, June 1976,
  p. 14; H. E. Collins, "Prospect of Coal Availability
  Up to 1985," Annex I, Prospects for Coal in the IEA
   (Paris: International Energy Agency,-T76T, p. 13.
10/Central Intelligence Agency, Research Aid, China:
   Energy Balance Projections (Waisi-gton: Library of
   Congress, 197), pp. 6,1

11/United States Bureau of Mines, International Coal Trade,
   Vol. XLV, April 1976, p. 31.
12/K. P. Wang, The People's Republic of China (Washington:
   Government Printing Office, 197), pp 27,28,92.
13/Ibid., p. 20; National Coal Association, uE. cit., p. 47.

14/Wang,   op. cit., pp. 20,92.

15/Ibid., p. 20.

16/Collins, op. cit., p. 12.

17/United States Bureau of Mines, International Coal Trade,
   Vol. XLIV, December 1975, p. 20.

18/National Coal Association, op. cit., p. 58.
19/Collins, op. cit., p. 12.

20/Drewry, op. cit., p. 24.

21/Federal Energy Administration, Foreign Ownership
   Control and Influence on Domestic Energy Sources and
        y (Washington: Government Printing Office, 17n),
   pp. vii,ix.
22/Ibid., pp. 24,25.

23/Coal Week, Vol. II, May 31, 1976, p. 1.
24/Executive Office of the President, Council on Wage
   and Price Stability, A Study of Coal Prices
   (Washington: Government Printlng Office, 1976), p.97.
25/United States Bureau of Mines, International Coal Trade,
   Vol. XLV, June 1976, p. 7.

26/Eastern Gas and Fuel Associates, Remarks: 1975 Update
   Seminar for Financial Executives and Analysts,
   (Boston: Eastern Gas and Fuel Associates, 1975), p. 38.
27/United States Bureau of Mines, International Coal Trade,
  Vol. XLV, June 1976, p. 14.

28/Henri Hymans, "Tokyo on a Nuclear Bandwagon," Far Eastern
   Economic Review, Vol. XCII, May 14, 1976, p. 5 -;
   Commission of the European Economic Community, "Medium-
   Term Guidelines for Coal 1975 to 1985," Official Jcurnal
   of the European Communities, Vol. XVIII, January 30, 1975,
        72; Organization or Economic Cooperation and Develop-
   ment, Joint Ad Hoc Working Party of the Energy Committee
   and the Committee for Scientific and Technological Policy
   on the Reassessment of the Role of Coal, Coal Supply and
   Demand Prospects to 1985 (Paris: Organizaton for Economic
   Cooperation and
                 D   'eve
                        o-pment, 1975), p. 93; International
   Energy Agency, Standing Group on Long-Term Cooperation,
   Suggested Work Programme in the Coal Sector (Paris:
   International Energy Agency,-T7Tp. 1.T

29/Paul H. Mutschler, Impact of Changin rTchnology on
   the Demand for MetalcFicT Co'I-aZ n     ke Produce-
   in the Unit-States to 1985, Info-rmation Circular
   ;-77 (W-ashington: Bureau ofMines, 1975), pp. 23, 25;
   Coal Task Group of the Other Energy Resources Sub-
   committee of the National Petroleum Council's
   Committee on U.S. Energy Outlook, Coal Availability
   (Washington: National Petroleum Council, 973)-
   pp. 105,109.
30/W. G. Dupree, Jr., and J. S. Corsentino, United States
   Energy Through the Year 2000 (Revised) (Washington:
   Bureau of Min7es7975), p. 1.

31/Organization for Economic Cooperation and Development,
   Joint Ad Hoc Working Party of the Energy Committee and
   the Committee for Scientific and Technological Policy
   on the Reassessment of the Role of Coal, op. cit.,
   pp. 52, 65.
32/The Pittston Company, Annual Report (New York: 1975),
   pp. 7,8.
33/American Iron and Steel Instituce, Statement on
   Metallurgical Coal (Washington: 1976), pp. i--v.
34/Eugene T. Sheridan and George Markon, Supply and Demand
   fol United States Coking Coals and MetalurgicaT Coo'
   TWashing7ton: Bureau of Mines, 1/7-), pp. 9,sI.
35/Ibid., pp. 7,8,11.

36/Ibid., p. 12.
37/United States Bureau of Mines, Intelnational Coal Trade,
   Vol. XLV, June 1976, p. 1.

38/Commission of the European Economic Community, op. cit.,
   p. 22/2.
39/United States Bureau of Mines, International Coal Trade,
   Vol. XLV, April 1976, p. 31.                 -

40/Statistical Office of the European Communities,
   Eurostat (Luxembourg: European Economic Community, 1975),
   p. 68.
41/Ibid., pp. 4,68,123,182.

 42/Ibid., p. 40.
43/Commission of the European Economic Community, op.   cit.,
   p. 22/1.

44/Ibid., p. 22/2.

45/Ibid., p. 22/4.
46/Ibid., p. 22/8.
47/The Federal Minister of Economics, First Revision of the
   Energy Policy Programme for the FederaI-Reub.ic oT-
   Germany, November 1974, p. 16.
48/Commission of the European Communities, Report on the
   Achievement of the Community Energy Policy 0be4 tives
   for 1985 (Brusse-i: European Economic Community, 976),
   p. 19.

49/Information Division of Her Majesty's Treasury,
   "The North Sea and the Balance of Payments," Economic
   Progress Report, July 1976, pp. 1,3.
50/Ministry of International Trade and Industry, Japan's
   Industrial Structure--A Long Range Vision, 1975 dition
   (Tokyo), pp. 90,92, Ministry of International Trade and
   Industry, Japan's New Energy Policy (Tokyo), pp. 13,81.
51/Ministry of International Trade and Industry, Japan's
   Industrial Structure--A Lonq Range Vision, 1975- -tion
   (Tokyo), p.7; Minstry    oInternational Trade and
   Industry, Japan's New Energy Policy (Tokyo), pp. 20,87.
52/Ministry of International Trade and Industry, Japan's
   New Energy Policy (Tokyo), pp. 20,72.
53/Ibid., p. 20.

54/Drewry, 22. cit., pp. 34,36.
55/International Energy Agency, Prospects for Coal
   in the IEA (Paris: International Energy Agency, 1976),

56/International Energy Agency, Standing Group on
   Long-Term Cooperation, loc. cit.

                           CHAPTER 9
               WHERE DO WE GO FROM HERE?
      Fifty years ago coal provided 80 percent of the Nation's
energy; 25 years ago 38 percent; in 1976 about 19 percent;
but renewed interest is emerging. The renewed interest in
coal as an energy source is a matLer of necessity rather than
choice. If it were strictly a matter of choice, coal's
decline relative to other fuels would continue. Coal would
not be chosen over oil and gas for several basic reasons:
coal is mined rather than pumped and therefore is more
dangerous and difficult to extract from the earth; it is
bulkier and therefore more difficult to transport and to
handle; and it is dirtier and therefore causes more pollution
when burned.

     Todav       -           et its increasing demand for oil,
the Unitr    tt,       .      rt ever larger quantities. Despite
a quadrupil,, -.               in the past four years, the United
States' dependency            mports has grown from 35 perceit
of total oil consun.         a about 50 percent during the
especially cold month: of January and February 1977. And
unless action is t- -n by the Feueral Government, this
dependence     fcr -'-, oil will continue to grow. During 1976
the United    :p-       ..,ed 7 million barrels of oil per day
(9 million duringj Lhe months of January and February 1C7"
and this could rise to 11.5 million by 1985. Domestic
reserves are no longer adequate to meet demand. In t.,
of natural gas, domestic reserves are actually declin
have not been able to meet demand for several years.
     Domestic coal resources, in contrast, are very abunuant.
Indeed, coal reserves represent 90 percent of the Nation's
total fossil fuel reserves. It is no wonder, therefore, that
coal is being turned to as one of the major solutions (along
with energy conservation) to the oil and gas problem. Coal
may be dirty, bulky, and costly to extract, but there is a
lot of it. The same can no longer be said for domestic oil
and gas resources when they are compared with the Nation's
rate of consumption.

     The purpose of this study has been to assess the extent
to which coal can relieve the Nation's oil and gas problem,
and the costs to society for this particular solution.
    Our overall observations are that:
    -- The probability that coal will relieve the oil
       and gas supply problem is very slight through
       1985. Whether this probability increases through
       2000 depends on what Government action is taken.

      -- Broad Federal Government action may be
         required in all phases of the coal fuel
         cycle if coal is to make a significant dent
         in the oil and gas supply problem.
     -- The more successful the Government is in
        pushing the coal sc.ution, the greater will
        be .he public health andi environmental costs.
        Given the current state of coal extraction
        and combustion technology, the Government
        will be able to moderate these costs to a
        certain extent but not eliminate them. There-
        fore, these public health and environmental
        costs are tradeoffs in exchange for reduced
        dependence on foreign energy sources, a poli-
        tical and economic necessity.

     -- Rapid coal development will leave the Fed- al
        Government with difficult problems. When do the
        costs of the coal solution become unacceptable,
        or when do the coal costs exceed the considerable
        benefits of reduced dependence on foreign energy
        sources? It is not a problem which can be answered
        by comparing one set of numbers labeled 'costs"
        ard another set labeled "benefits." The full
        costs of increasing coal use cat. never be com-
        pletely quantified nor can the benefits of
       decreased dependence on foreign energy sources.
        It is, ultimately, a matter of value judgment,
       and the only way of resolving it in our syster
        is through the democratic process. If it is
       decided that the costs of coal use beyond a
       certain level are too much and that incre-sed
       oil imports is not a tenable alternative, then
       the Nation, it seems to us, has only two major
       alternatives open to it between the present
       and the year 2000.* One, the United SLates
       can accelerate the expansion of conventional
       nuclear power so that nuclear-generated electricity
       substitutes for oil or gas use wherever possible;
       and, two, increased energy conservation,

*This assumes that renewable energy sources such as solar
 energy or the breeder reactor cannot make a significant
 contribution to the Nation's energy supply until sometime
 in the next jentury.

      The nuclear option, however, is limited in this period
by the time it takes to plan, license, and build new nuclear
plants--about ten years--and nuclear power has social costs
of its own which must be carefully weighed.   Energy conserva-
tion is limited too---limited by the time it takes to replace
less energy efficient equipment and processes with more
efficient technology and by availability of capital. The
turnover rate in the Nation's automobile fleet is about 10
years, but the Nation's stock of buildings and industrial
capital equipment is replaced over an even longer time.

     This, then, leaves only one other major option for the
medium term--the next 25 years--and that is reduction in
energy consumption beyond what can be achieved through
greater efficiencies. But to date, there is no indication
that the great majority of Americans are willing to take
this course. To be effective, it would require substantial
changes in behavior patterns, especially in transportation,
in housing, and in the workplace. The tradeoffs in this
case could be inconvenience and curtailed growth in income.

     The prospects of substituting coal directly ior oil or
gas are limited in the industrial sector and almost negligible
in the other major sectors of the economy--transportation,
commercial, and residential.

     A more promising prospect is the substitution for oil and
natural gas of coal-generated electricity in the short-term
combined with coal-generated    ,thetic fuels later on. The
primary constraints in this case are the time it takes to
build new coal-burning electricity generation facilities--five
years--and the availability of capital to replace oil- and
gas-burning facilities. The advent of synthetic fuels awaits
resolution of complex technclogical and economic problems.

     Our study indicates that a most promising short-term
opportunity for substituting coal for oil or gas is through
improved electricity load management. Oil and gas are used
primarily to meet peak load electricity demand while coal
(along with nuclear power) is used for baseload. Therefore,
leveling the load curve and improving coordination between
power systems would increase utilities' consumption of
coal and reduce their demand for oil and gas. GAO's calcula-
tions indicate that improved load management could increase

utility consumptior. of coal by 1985 by as much as 149 million
tons. This represents a savings of 1.4 million barrels of
oil equivalent per day.

      In the future, the most significant opportunities for
coal substitution feor oil and gas are through coal gasifica-
tion and licuefaction. But, according to the Energy Research
and Development Administration's "best estimates," coal
gas prices in the ye.:: 20C0 wili be 24 percent higher than
projected natur!al ga; prices and coal liquid prices will
be 66 percent hi:gher than projected oi.! prices. ''hus, if
coal liquids or gas are to make a significant contribution
to the Nation's oil and gas supplies sonetime !efore the
year 2000, Irassive Federal subsidies may be required to
overcome their economic disadvantage.    In addition, it appears
that the coal gasification a:nd liquefaction processes will
also cr-a.:e air and water pollution hazc:ds. Methods to
mitigate 'hese hazards are being researched.


      For purposes of analysis, GAO used the Bureau of Mines
and Edips n Electric Institute scenarios. Both projected
significant growth in coal production--to 779 or 988 million
tons by 1985. Coal production in 1976 in the United States
was 665 million tons. These increases would require an
annual growth in coal production of from 1.8 percent to
4.5 percent, compared with the annual growth rate during
1950-1976 of less than 1 percent. (President Carter's
National Energy Plan calls for an increase in coal production
orf even greater  imensions--to 1.2 billion tons by 1985.)
      By the year 2000, the scenarios project coal production
of 942 million co 1.6 billion tons. According to GAO calcu-
lations, an expansion of coal production of this magnitude
woul(. require:

     --Opening 438 to 825 new l.ines.

    --Recruiting and training 288,300 to
      531,000 new miners (current average
    --Manufacturing significant quantities
      of mining equipment (draglines, etc.,).

     -- Capital investments (just for extraction)
        of $26.7 to $45.5 billion.
     The coal industry and the coal-equipment manufacturers
may be hardpressed to meet these requirements. However,
GAO's discussions with 11 major coal producers (including
9 of the top 15 producers in 1975) showed that all believed
the industry could double production by 1985 and triple
production by 2000 under existing conditions. Whether the
increased level suggested in the National Energy Plan can,
in fact, be achieved depends upon several interrelated
but difficult to predict factors:
     --Coal mining productivity, i.e., tons
       produced per worker day--it has been
       declining since 1969.

     -- Good labor-management relations.
     -- Worker availability and training,
        including mining engineers.
     -- Improved mining technology.

     Of all these factors, labor-management relations could
perhaps have the most impact. In years when a national agree-
ment is renegotiated, the lost working time due to work
stoppages is considerable--for example, eight percent of the
total work time was lost in 1974. The current agreement of
the United Mine Workers and the Bituminous Coal Operators
Association, Western Surface Miners, and National Construction
Contractors expires December 6, 1977. The right to strike
over local grievances 4, a major point of contention at the
present between the union and the industry.
     The regional impacts of increased coal production will
be quite varied. While increased coal output may be difficult
from a production standpoint, it will also place added demand
on the transportation system.

     Railroads will be the principal mover of coal ii the
foreseeable future. Railroads carried about 65 percent of
the coal traffic in 1975. The waterway system, although the
cheapest way of transporting coal, does not directly serve
many of tne areas scheCuled for major coal development and
is limited physically by ice in the winter .nd by the capacity
of its locks. Trucks and high-voltage power lines cannot
compete in terms of price. For example, a recent BOM study
of western coal alternatives found that mine-mouth generation

and shipment of electricity by extra-high voltage transmission
lines was aboLt 30 percent more costly than railroads. That
leaves slurry pipelines, and they appear to be competitive
in terms of price with railroads.  However, slurry pipeline
development is being hindered by difficulties in assembling
rights-of-way, by water shortages at point of origin, espec-
ially in the West, and by environmental problems caused
when the effluent from the pipeline is disposed of at the
     By 1980, the Nation's railroads anticipate a 95 percent
increase over 1974 coal traffic. The most dramatic increase
will occur in the West. The entire upsurge in coal volume
will require large investments in hopper cars, locomotives,
and improved facilities, especially track beds.

     GAO's discussions with selected western carriers and
with the Federal Railroad Administration indicate that the
western railroads will be able to expand their ccal handling
capacity. An important element in this conclusion is the
fact that less time is requ 4 red to expand rail facilities
than to construct new mines or electric generation plants.
Even so, the railroads will have to raise considerable capi-
tal in order to be able to deliver the future volume of
coal. Among the factors that inhibit their capital formation
is the Interstate Commerce Commission's restrictions on
long-term coal contracts. Railroads point out that they
are the only major participants in the coal fuel cycle who
do not operate on the basis of long-term coal contracts.

     In addition, increased coal production will require
expanded coal transport capacity in the Northeastern and
Midwestern areas now served by Conrail, the federally-
subsidized consolidation of the insolvent eastern and
midwestern railroads. Therefore, it will be the Federal
Government's responsibility to see that adequate funds
are allocated to increase coal handling capacity during
Conrail's costly rehabilitation.

     The most crucial factor facing the goal to increase
coal use is the environmental issue. With the passage of the
recent surface mining legislation, only time will tell if
sufficient coal will be able to be mined.   It appears to us
that the National EnergyPlan's goal of 1.2 billion tons by
1985 likely will not    met. The air quality restrictions
will be the primary deterrent. Utilitie3 and other coal
burning industries have been reluctant to make the investment
decision to install scrubbers, having been uncertain about
the final air quality standards and what will constitute "best
available control technology." These utilities and industries

in turn are therefore naturally reluctant about awarding
long-term contracts to coal producers. The coal producers,
under these conditions, naturally hesitate to conclude the
necessary expansion plans and order the needed equipment.

     Controlling the air pollutants emitted by coal-burning
powerplants, as required by the Clean Air Act of 1970, as
amended, will be costly.  GAO estimates cumulative capital
costs of about $19.1 billion by 1985 and $26.4 billion by
the year 2000.  These costs will vary among regions.   But
the average residential consumer's electric bill could
increase four mills per kilowatt--an increase of about nine
percent by 1985--to cover the cost of sulfur oxides and
particulate pollution abatement.

     CAO further estimates that the cost of codl mine
reclamation, subsidence prevention, and acid mine drainage
control would cost about $1.2 billion by 1985 under the BOM

     Moreover, the disposal of the sludge which collects
in such air pollution control devices as scrubbers also
will be very costly.  To put this problem in perspective,
the amount of solid waste generated annually under the BOM
scenario by 1985 by air pollution control devices will be
roughly the same as the total municipal solid waste produced
in the United States during the course of a year.

      Increased coal production will also mean a population
influx into coal producing areas.   To meet the needs of
the increased population, local communities will have to
expand such public facilities as schools, roads, hospitals
and health clinics, and sewage systems.   GAO estimates that
these irnfrastructure costs to local governments might run
as high as $4.4 billion between 1974 and 1985 and $14.9 bil-
lion letween 1974 and 2000.   Some States, such as Wyoming,
have taken steps to help local communities deal with these
costs.   The Federal Government has also provided limited
assistance through various Frograms. Regardless of whether
Federal assistance is expanded, the effectiveness and
efficiency of the Federal aid to affected communities would
be enhanced if one Federal agency was made responsible to
coordinate the Federal effort.


 Human health

     Coal combustion emits a number of potentially dangerous
pollutants into the air. Some of these, such as sulfur
oxides, are regulated. However, for other pollutants from
coal the current state of knowledge and technology is such
that regulation is not possible. Hence, increased public
health and environmental damage are tradeoffs for increased
coal production and use.

      Small particulate pollution--The current particulate
control devices ail to capure many of the particulates
one micron or smaller in size which are emitted during coal
combustion. These small particulates are thought to pose
a special public health hazard because they penetrate the
respiratory system's natural filters and lodge deep within
the lungs, These could represent the major vehicle by which
chemicals such as sulfur oxides cause illness and premature

     Trace element pollution--Coal pollution also contains
quantities o mercury, ea, beryllium, arsenic, fluorine,
cadmium, and selenium. Data about them are limited but enough
is known to suggest that they could cause serious consequences.

      Coal mine health and safety--Coal mining also causes
premature deaths, disabling injuries, and illness (black
lung disease) among miners. Since the passage of the Federal
Coal Mine Health and Safety Act in 1969, some progress has
been made in making mines safer places to work, but many
problems remain. Coal mining is still the most dangerous
occupation of its kind in the Nation. For example, the
fatality rate among underground and surface miners was .41
per million worker-hours in 1975, compared with .03 in i,lanu-
facturing overall.   If the current fatality and disability
rates do not change, GAO estimates that some 4,700 coal miners
might be killed and 351;000 disabled under the BOM scer.ario
through the year 2000. This, too, is a tradeoff folr mo :e
Global climate change
Carbon dioxide emissions from coal combustion are not con-
sidered directly harmful to human hbalth but their accumula-
tion in the atmosphere could triggez climatic changes with
potentially serious consequences.

     There is no question that carbon dioxide build-up in
the atmosphere has increased in this century and that coal
combustion has contributed greatly to the build-up. Meny
believe this build-up could cause a global warming trend,
but they do not know how or of what magnitude.  The hypothesis
is that carbon dioxide in the atmosphere allows solar radia-
tion to reach the earth but, acting somewhat like a greenhouse,
does not allow as much heat to escape as normally would.
Knowledge of the phenomenon is sufficient to arouse concern
but not adequate to provide a basis for meaningful action.

      Some have warned that after the carbon dioxide accumula-
ticn in the atmosphere reaches a certain, undetermined point,
it may set in motion chances in global weather patterns. An
annual global climate change of only 1 to 2 degrees centigrade
could have implications affecting global air movement patterns,
and redistributing temperature patterns and precipitation

     Because of tne very limited data, this is a risk
which is uncommonly difficult to assess.

Diminished agriculture output

     The sulfur oxides pollution from pow-rplants, even
those with controls, causes some crop dnd plant damage.
Coal mining, particularly surface mining, will also reduce
agricultural and forest production by the sheer disruption
of land--at least during the life of the mine and perhaps
afterward.   The productivity of some surface-mined land
can be restored if care is taken to replace the overburden,
especially the topsoil, after mining.   This assumes, however,
that the area receives adequate rainfall (more than 10
inches on average) and is not too steep a slope (20 degrees
or less).  But it has yet to be demonstrated whether the
croplands of the Midwest can regain their former level of
productivity after surface mining.   This is another tradeoff
for more coal.

     Under the BOM scenario, over 99,000 acres of land will
be disrupted annually by surface mining from the present
through 1985; more than 159,000 acres will be disturbed
by the year 2000.  By _'85, we would be digging up an area
twice the the size of the District of Columbia.

Water quality and supply

     Another tradeoff of ii.zreased coal producing is reduced
water quality in the Eastern United States; in the West the
tradeoff is less water availability for municipal and
industrial use, agriculture, and recreation.

     Drainage from coal mines has polluted over 6,700 miles
of this Nation's streams with a mixture of sulfuric acid,
iron, and aluminium salts--a compound sufficiently potent
to kill aquatic life. Over 90 percent of these streams are
in Appalachia. It is not certain how much of this drainage
can be controlled and more acid mine drainage may be a tradeoff
of increased coal production.

     In the West, coal development makes the already scarce
water resources even scarcer.   In particular surface mining is
known to lower ground-water fables and disrurt underground
aquifers.  And coal-related developments such as coal-burning
powerplants and coal gasification and liquefaction facilities
are big water users.   In relatively large areas of the West,
water supplies are already overbooked through interstate,
international, and Indian agreements, ground-water tables
are steadily dropping in some areas as more is consumed each
year than nature can replenish. The increased demand of 'oal
development will certainly cause legal as well as environmental
difficulties relating to water in the West and will divert
water from other uses.
Social change

       Even if communities affected by coal development manage
to obtain adequate initial financing to meet their increased
public service needs, social patterns will change with the
population influx. Obviously, the extent of the change will
vary greatly from community to community, but in general,
communities in the more sparsely populated West will feel
t*b   impact more than those in the East. Their way of life
  i 'l change. This is a tradeoff. Once quiet and highly
personal in character, these communities will become more
crowded, faster-paced, more impersonal. Examples of tha
phenomenon, which are described in this study, are Rock Springs
and Green River in Sweetwater County, Wyoming, but there will
be ot[ers as coal development increases. Through adequate
planning and financing, the impact can be cushioned, but it
will be an impact nonetheless, end the social fabric of the
community will chance.

     If, despite the tradeoffs, it is decided to try to double
coal use by 1985 and to triple it by the year 2000, policy-
makers will be faced with a set of special, coal-related

     One is that the current data concerning coal resources
and reserves are extremely spotty and outdated. Why is this
a concern when coal resources and reser' s are so large?

 First, because coal is a finite resource and will not last
 forever.   Current coal reserves, for instance, will last
 only 74 years under an annual demand growth rate of 3.69
 percent.   Furthermore, certain coal with highly desirable
 qualities is much more limited in supply, and to make
 decisions affecting their use, more accurate estimates of
 their reserves are necessary.   For example, reserve figures
 ror metallurgical coal, which is essential in the manufacture
 of steel, could affect Government decisions regarding its
 export.  Or reserve figures for low-sulfur coal could affect
 the air pollution regulations and the Federal Government's
 leasing of its vast coal resources in the West. The Federal
 Government owns about 70 percent of the coal in the West
 and can influence the development of another 20 percent
 bordering Federal lands.

     The alternatives that may be considered for improving
the reliability and usefulness of coal data include increased
Federal exploration--stratigraphic drilling and mapping--
as well as providing coal companies with special tax and
other incentives ':o submit reserve estimates to the Government
that are accurate and conform to certain criteria, such
as the sulfur content and metallrgical qualities of
the coAl, if any.

     Coal reserve figures now received from coal companies
and other proprietary sources are possibly understated in
an effort to minimize property taxes.  The exact magnitude
of the underestimation is not known.

      Recent surface mine legislation restricts surface mining
in alluvial valley floors, because they are important to
water systems and agriculture, and on steep slopes.    The
amounts of coal reserves affected in the first instance are
small; in the second they are are unknown.   The legislation
also seeks to protect surface owner rights on Federal coal
lands. One study indicates that as much as 14 billion
tons of coal could be withdrawn from potential production
u.ider such measures, although this estimate is highly
uncertain because more reliable and accurate reserve data
on Federal coal land are needed.

     A second coal-related concern for policymakers    -- the
matter of how to handle external costs.   In principle,
the external costs of producing and burning coal should
be irternalized into the price of coal whenever possible.
In this way, the users of the coal, or of the electricity
generated by coal, will be paying the true cost of the
)roduct and may have a greater incentive to use it
Efficiently.  In practice, this is difficult to do. For

one reason, how do you include the cost of a human life
when coal pollution causes a premature death? In addition,
the more that external costs are internalized, the higher
will be the price of col or electricity, and the more
attractive will become oil and gas. Thus, the goal of
reducing dependence upon foreign energy sources will have
been thwarted to a certain extent.

       For example, in an effort to raise revenue to meet the
socioeconomic and environmental costs of coal development,
Montana now imposes a 30 percent tax on coal (market value)
  nat is surface-mined. This is, in other words, an effort
to internalize these external ccits.    However, by so doing,
Montana inhibits the achievement of two national goals--clean
air, because a significant amount of the Nation's low-sulfur
coal is found in Montana, and reduced dependence upon oil
imports and dwindling natural gas reserves. For anotner
example, New Mexico now taxes electricity produced within
the State and then rebates the amount of tVb tax to citizens
of the State. This is, in effect, an energy export tax
-- raising the price of electricity, which is primarily
coal generated, to consumers in Arizona and California,

     The utility industry reiies far more heavily on Govern-
ment-financed research and development than do many other
industries. In a sense, this is a form of subsidy to
electricity users because otherwise they would have to bear
a greater share of research and development costs. One
solution would De to place a Federal tax on electricity that
is earmarked exclusively for research and development in
technologies for electricity gereration which are clean and
do not rely on oil or natural ga~. However, such a tax
might discourage the substitution of electricity for oil
and natural gas because of the added expense.

     Another area of concern for policymakers is coal prices.
The concern here is that coal producers do not reap windfell
profits from Government-induced market trends. For example,
if the Guiernment prohibited the further use of oil or
natural gas by utilities, coal producers might be in such a

     When coal prices more than doubled in 1974, the Council
on Wage and Price Stability concluded:  "Unless all
costs have grown more quickly than labor costs (whichother
doubtful), the average price has also out 'aced total costs."
Their study of selected coal companies in 1974 found thar net
coal profits rose to $2.80 per ton, or 18 percent of the
average value per ton.

     In this context, it should be noted that the structure of
the coal industry has undergone a radical transformation in
the past 15 years. The number of independent firms in the
coal business is declining sharply and ownership patterns are
changing. As of 1974, 31 firms accounted for approximately
58 percent of total coal output. At present, of the 20
biggest holders of domestic coal reserves, only two are
independent coal companies. Eleven are oil companies. There
is little evidence, tc date, however,, that the increasing
concentration of power within the coal industry has made
for an uncompetitive market. One effect of large oil,
chemical, and other non-coal companies buying up smaller
coal independents has been to greatly increase the capital
available to the industry for expansion.
     A final area of special concern for policymakers is coal
exports. Traditionally, the United States exports 9 to 11
percent of its annual bituminous coal production.  in 1975
coal exports contributed $3.3 billion to the Nation's
balance of payments. This must be kept in mind if policymakers
are considering export curbs, for instance, in the case of a
temporary coal shortage.
     About 77 percent of U.S. coal exports was metallurgical
coal for foreign steel manufacturers. Although stiffer
competition from other coal exporting nations is expected
in the future, U.S. metallurgical coal exports are projected
to grow at an annual rate of 1.71 percent, according to BOM.
U.S. steam coal is less competitive and exports are expected
to increase only slightly.


     If the coal solution is to work--that is, help reduce
dependence on oil imports and relieve pressure on dwindling
domestic natural gas reserves--then certain Federal Govern-
ment interventions in the coal market place will be necessary
at key points.
      The administration has already proposed in the National
uEnerY Plan a number of Federal actions to increase the
use of coal. These include

     -- a regulatory program to require coal use by utilities
        and large industries, with allowances for exceptions;

     --an oil- and gas users tax and rebate/investment tax
       credit system to provide an economic stimulus to
       convert to cral;

      -- an environmental policy for coal which the administra-
         tion hopes will achieve its energy goals without
         endangering the public health or degrading the environ-
         ment; and
      -- a research program for coal conversion, mining, and
         pollution control technology.
     In GAO's An Evaluation of the National Energy Plan, we
assessed the specific administration proposas  and oointed
out that while the administration's plan deals with some
of the constraints to increased coal use, it does not deal
with transportation, productivity, and other constraints
that will hinder the achievement of one billion tons of
production and use in 1985. Based on the work then underway
in preparing this particular report, we also noted the need

     -- capital to upgrade large portions of the Nation's
        railroads, particularly in the Eastern States,
        together with the need to expand existing capabilities;
     -- congressional resolution of uncertainty concerning
        the issue of rights-of-way for slurry pipelines;
     -- improved labor relations to prevent disruptions due
        to wildcat strikes, together with the need for improved
        miner health and safety conditions, recruitment, and
     -- greater productivity;

     -- accelerated Federal research to determine the health
        and environnmental effects of burning greater amounts
        of coal; and
     -- less costly and more reliable technology to control
        air pollution from coal burning facilities.

     As we have seen, the short run capacity (a year or
of the coal industry is limited to what can be ex:tracted so)
through increased production at existing mines (surge capacity).

     Many interrelated elements would have to work if coal
production and use were to double by 1985: mining equipment
manufacturers would have to fill orders promptly and mining
companies must have the foresight and capital to be able
open new mines when the added output is needed, to name only
two. The time required to open a new mine varies: surface

mines in the East take 1.5 to 3 years to open; in the West
they take longer--3 to 13.5 years; underground mines in the
East take 4 to 15 years to open and 2 to 5 years in the West.
In the short-term coal is also constrained on the consumption
end, in the sense that utility and industrial users are not
going to buy coal if they do not have the physical capacity
to use it. There are long leadtime involved just in building
and installing boilers at existing plants, not to mention
the leadtimes involved in planning and building completely
new coal burning plants.  It is impossible to predict whether
the coal fuel cycle can, in fact, be pushed to the extent
of doubling production and use by 1985. The uncertainties
are many, but sufficient to raise serious doubts.

      In the medium term (1985-2000), coal is demand-
constrained. The possibilities of direct substitution for
oil or gas are very limited on an economy-wide basis. The
prospect for indirect substitution by coal-generated elec-
tricity, while more promising, is limited too by economics
and the current state of industrial and transportation tech-
nology. Over a longer 'erm, coal seems to be both supply-
constrained, especially in terms of low-sulfur coal, and
demand-constrained.   The long-term prospects for increased
coal demnand ride upon the hope or coal gas and liquids
becoming environmentally-safe and economical energy fuels.

     These, then, are the physical and economic limits of
the coal solution.

      If maximum coal output and consumption can be achieved
within these limitations, the tradeoffs may be costly,
particularly in terms of human life and disease. These
tradeoffs can only be considered tolerable when viewed
in the broader context of the Nation's inadequate oil and
gas resources as well as the risks and limits of nuclear
power. The coal tradeoffs are sufficiently significant
to put renewed emphasis on the need for vigorous energy
conservation, not as an alternative to coal, but to temper
somewhat coal's very high costs.

     Because of the long leadtimes to translate Gcve. -
ment policy and action into actual coal production and
consumption, we believe it is more realistic to assume
that while Government policies set in motion now will have
some effect between now and 1985, the greater impact will
be in the 1985-2000 period.

     In our report to the Congress, An Evaluation of the
National Energy Plan, we assessed the various recommendations
of the administration to increase coal use and concluded that

a lot i,,ore needed to be done. We also noted that the work
we have been doing in GAO on the production and use of coal
raises doubts about the possibility of achiefjing the admin-
istration's plan of producing and using 1.2 billion tons of
coal by 1985. Given all the physical, economic, environmen-
tal, and public health considerations, it appears to us that
producing and using even a billion tons by 1985 would be difti-
cult. Assuming, however, that the difference between the
administration's plan and reality is a matter of 200 million
tons, we calculated that this would be a shortfall on the
domestic energy 6sply side equiivlent to an arnual use of
2.3 million barrel; of imported oil per day, as presented in
the fuel balance tables in the National Energy Plan. Our
calculation was based on the administration's estimates of
what a shortfall of 200 million tons of coal would entail.
However, the administration used an average Btu rate conver-
sion factor which does not reflect the true value of the oil
equivalent of coal.

     Using appropriate conversion fa,:tors for each use where
coal would substitute for oil, we estimat<~ that the 2.3 mill,.n
barrels of oil shortfall noted above would actually be 2.2
million bdrrels of oil equivalent per day.

     Upon further review, we have- escoered another problem.
As noted above, the administration calculated supply and
demaiJ on the basis of qualril.'on Btus and then converted
these to millions of b-irrel?' c.f oil a Aay eauivilent.    Using
the same conversion factor ar,a,--is as above, we estimate
that the oil equivalency of the rema.ning or.~
coal could be 1.1 million barrels per day less billion     tons of
                                                  than tnra admin-
istration's figures shown in the fuel balance tables in the
National Energy Plan. Thus the number of barrels of oil
equivalent per day shown in the fuel balance tables for cne
billion tons of coal (without the energy plan) should be 11.1
million barrels per day inste.a of the 12.2 millinn barrels

     The GAO and administration estimates of quadrillion Btus
are identical. The difference of 1.1 million oariels of oil
per day equivalent results from the different conversion
factors used. If this difference implied a real world short-
fall, it would have to be made up in one of three ways:
additional imports; increased domestic production from other
sources; or increased conservation efforts.  If, on tne oth2r

*These figures should be adjust.ed downward by 1.4 million
 barrels per day equivalency for metallurgical coal which
 has no oil substitutability.

hand, the oil equivalent numbers in the National Energy Plan
simply reflect a mechanical use of an average conversion
factor from detailed estimates based on actual quantities,
there would be no shortfall since both supply and demand would
be less in barrels of oil equivalent. As discussed in the next
paragraph, we are continuing our investigation into this

     In any case, these considerations raise questions about
the factor used by the administration in converting to barrels
of oil equivalent per day for other domestic energy sources,
which in turn raises questions about the administration's total
estimates regarding energy supply and demand. We believe
the administration should either have presented its analysis
on the basis of Btus or used a more detailed set of conver-
sions to oil equivalency which recognized historical and other
trend data in developing the conversion factor. Otherwise,
we believe that the net effect could be to increase the total
energy supply and demand estimates when stated in bar'e!.s of
oil equivalent. While not part of this study, we are Tontin-
uing this analysis and will be reporting our findings to the
      With all the constraints, however, the increase in
use of coal in absolute terms will still be substantial.
Electric utility plans through 1985 call for an increase
of over 300 million tons. Industrial use will increase also,
but more slowly. There is no question that coal will supply
a part, a large part, of the Nation's energy future. So will
foreign oil and nuclear power. Natural gas will decline and
may have to be restricted to optimum end uses such as home
'ieating, etc.; domestic oil will decline. Solar energy will
incre.se slowly, as a complement to other fuel types. On the
demand -ide, the best answer to the Nation's energy bind is
conservation, through increased efficiency and decreased use.

     Numerous Federal agencies provided comments on a draft
of this report, as did private industry organizations and
technical consultants. We took those comments into consider-
ation in preparing the final report.
     We also provided a copy of the final draft report to
the Energy Policy and Planning Staff in the Executive Office
of the President. The Staff's comments are included at page

     The Staff states that its only major area of disagreement
is with our conclusion that "no more than one billion tons of
coal could be produced between now and 1985." The Staff then
discusses several points regarding this conclusion.
    The staff identifies three basic areas of disagreement:
          -- Recent surface mining legislation.
          -- Railroad expansion problems.

          -- Air quality regulations.

     We support the surface mining legislation as an essen-
tial tool for protecting the environment, but recognize that
it will be a constraint to coal development, although the
impact of that legislation from a coal development stand-
point has not been fully evaluated.
     Railroad expansion problems are a major constraint, in
our view, along with the substantial expansion difficulties
that will face coal producers and coal users who will be
dealing with heavy capital and operating costs and long lead
time problems for mine opening, land reclamation, boiler
installation, air pollution control, and scrubber sludge

     The Staff's comments regarding air quality regulations
are not very clear. For example, the Staff says that the
requirement that coal-bucning plants make use of best avail-
able control technology (BACT) would not be in effect until
1982, and thus would have minimal impact by 1985. The very
point we are making is that the uncertainty over those
requirements is causing problems (see pp. 6.50, 6.51, 9.6,
and 9.7).  In any case, the impact on coal production and
use (particularly of higher sulfur coal) is bound to be sub-
stantial because both consumers and producers must take BACT
into account in their long-range planning.
     As far as the regulations regarding prevention of signi-
ficant deterioration and EPA's offset policy for non-attain-
ment areas are concerned, the Energy Policy Staff raises the
question of whether these are substantial constraints or
deterrents to coal development. Whether the air regulation
constraints will be substantial, when taken individually,
is a matter of judgement, but when considered collectively
we are persuaded by the weight of the evidence we have
reviewed that the coal fuel cycle--production, transportation,

and use--will not expand as fast as the administration anti-
cipates. We want to affirm, however, that we do support the
air quality regulations as necessary environmental protec-

     The Energy Staff also states that GAO has not addressed
how much of an increase in coal production can be achieved
due to the initiatives in the National Energy Plan. We
believe we have argued that point to a reasonable-conclusion,
both in our earlier repor,., An Evaluation of the National
Energy Plan, and in this report. Using the administration's
own figures, the National Enery Plan would increase utility
use of coal only aiw-milTlion tons per year. The balance of
the 200 million tons per year projected impact of the National
EnerqyPlan is anticipated in the industrial sector. We
believe tHis is extrem'.ly unlikely to occur in the 1985 time-
frame because of the -riad of constraints to rapid develop-
ment of the coal fuel cycle we have documented in detail in
this report.

     The Staff fails to address other, very important issues
that we raise--issues that we see as major constraints to
achieving annual coal production ard use of one billion tons
by 1985. Those issues are identified, with appropriate page
references, in the Digest to this report.

APPENDIX I                                           APPENDIX I


     During the course of this review, we analyzed all
of the major energy models* which might have provided us
with additional insight into :he problems of coal development.
We were, however, unable to use these models because 'hey
did not accord requisite attention to coal and were not
fully developed and operational. The following is a discus-
sion of our analysis of the major energy models--Federal
Energy Administration's National Coal Model (NCM); Data
Resources, Inc. (DRI) energy mode]; Wharton Econometric
Forecasting Associates, Inc. Coal Satellite Model; Chase
Econometric Associates, Inc. energy model; and Stanford
Research Institute (SRI) energy model.

     A new coal model available in 1977 is FEA's NCM and
related support models. We believe tris model will be a
significant contribution to coal analysis for several reasons.
It is large enough in size to deal with major economic
variables on a national as well as a State level. While
specializing ir coal, it also considers the economic trade-
offs to other energy resources. NCM relies upon the FEA
Project Independence Evaluation System (PIES) model and
a related econometric model to determine consumer demand
for coal and energy related products. In the course of
this brief description, we merely refer to this group of
models as one, namely, NCM.

     NCM is new and, therefore, we were unable to judge
its predictive accuracy. Its structure is unique enough,
however, to warrant some description. Most energy models
are of an econometric variety. Specifically, they rely
upon the historical relationships of certain factors and
the assumption that those relationships will persist in
the future. An example of one such relationship would

*The, term model, as used here, means the mathematical repre-
 sentation of things as they are. Energy models deal with
 energy and energy related variables, whereas macro-models
 deal with a wide range of general economic variables such,
 as interest rates, fixed investment, disposable income,
 gross national product, and economic growth. The term
 econometric is used to describe the statistical technique
 used to test the form and strength of historical relation-
 ships among economic variables.

APPENDIX I                                              APPENDIX I

be the growth in eneigy demand relative to the gross national
product. NCM, on the other hand, is a linear programing
model relying principally upcn current relationships. Since
there is no historical (time series) data in NCM, it is
3aid to have no "memory." Accurate information on current
data and relationships is essential because NCM cannot
rely upon historical data to temper its forecasts. A
linear programing model such as the NCM typically asks
the question: What is the most (or least) coal that will
be produced given such constraints as known reserves, anti-
cipated demand, substitute products, market prices, transpor-
tation costs, etc.?
     The strengths of NCM are in its ability to deal with
such a wide variety of coal related variables (such as
production and transportation costs, types of coal, and
geography) and its handling of the supply sector.        Its short-
comings are principally  due  to the  fact   that it is  not
completely developed yet and that it must deal with known
resources (having no ability to deal with undiscovered
resources on the level of detail required).       It is not now,
nor is it expected to be,   available   to all  potential  users
in the future.  Due to  the  nature  of  its  constraint  equations,
it has to assume some seemingly unrealistic assumptions
such as perfect knowledge in the market place,* and the
unchanging nature of price relationships.
     The major alternatives to NCM are the econometric
models designed by private organizations such as DRI, Wharton
Econometric Forecasting Associates, Inc., Chase Econometric
Associates, Inc., and SRI. The DRI model is the simplest
to use and was available in 1975; the others will be available
in 1977 or later.
     A thorough study of these models would consider predic-
tive accuracy, basic structure, and other such characteristics.
This review does not attempt such a study. However, we have
examined each of the major models to ascertain its principal
strengths and weaknesses.

*Producers and consumers do not have perfect knowledge.
 They do not know each others costs, profits, and other
 economic constraints. This imperfect knowledge precludes
 a producer or consumer from making the best decision in
 each situation.

                                                      APPENDIX I

      The DRI energy model has been available for some time
 and, consequently, considerable effort has been made
 refine it.                                             to
             The Chase model expects to have greater detail
 on a geographic basis. Both of these models deal with
 energy and rely upon links with their respective macro-models
 of the entire United States to develop a complete economic
 picture. Wharton also relies upon its macro-model for
 suppurt; however, it differs from the other two in two
 respects. First, it is a coal model--not a general
model--and addresses coal problems more specifically. energy
considerable effort was expended to develop the supply
side of the model, a weakness of most other econometric
models. Nonetheless, it does not handle the broad range
of detail on the supply side that the NCM does. SRI
has an energy model somewhat similar in nature to the
other econometric models. Due to its extended forecast
horizon (year 2025). it is of necessity more general.
essentially establishes a series of supply and demand It
equations which it solves simultaneously given the forecast
assumptions, and other exogenously determined variables.
It is not publicly available through timesharing as the
other econometric models are and it requires additional
development to handle the same types of problems the
econometric models do.
     While the four econometric models differ considerably,
they can be grouped and compared, as an econometric
to NCM. Of course, such a comparison is necessarily compositz,
                                                    a rough

     Our study of these models was not intended to determine
ti  best model. Each model has an intended purpose not
necessarily related to the particular purpose of another
model. Best, therefore, can only be determined in
ship to a specific question or analytical requirement.
have attempted here to highlight some of the strengths We
and weaknesses of each model insofar as information
available to us.

     A summary of the relative strengths and weaknesses
of NCM and the econometric models is shown in table
     Earlier portions of this report have shown
development is limited by demand. We found that that coal
casting demand in detail was difficult after about 1985.
This makes most models imprecise for addressing the basic
question: To what extent can coal substitute for other
fuels, especially after 1985?

APPENDIX I                                         APPENDIX I

     Much has been said of the modeling capability available
today, and we are convinced that some of these models will
be able to make substantial contributions to analysis of
the coal market in the future.
     Econometric models currently tend to break down in
predictive accuracy as the period of forecast is extended.
This deficiency is usually finessed by aggregation, i.e.,
the detail is eliminated and only major variables on a
national level are forecast. This type of forecast was
insufficient for our review.

     Linear programi.g models have no memory; working
only with cross sectional data they are only as useful
as the analyst is skillful in his estimation of future
demand. NCM, unfortunately, is still in a developmental
stage, and, therefore, was not used extensively in this
review. We expect that NCM will be very useful in the
comparison of various scenarios when it is complete.
     For the above rea3ons, the present study makes very
limited use of NCM or econometric models.

APPENDIX I                                                                                                                                                                    APPENDIX I
                                                                                        o                    ao

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APPENDIX II                                        APPENDIX II

                       IN 1985 AND 2000

     In chapter 2 we summarized coal demand in 1985 and
2000 under two alternative scenarios. This appendix will
delineate and discuss the implications of these two scenarios
in greater detail.
     The decomposition of gross energy demand by major
consuming sector and by principal fuel category is contained
in table 1. This is rather complex material, some of which
has already been discussed.

     Table 1 illustrates that the contribution of natural
gas under the Edison Electric Institute scenario declines
markedly during 1985-2000 from about 28 to 18 quadrillion
Btus. A smaller decline in oil consumption also occurs.
     The oil and gas decreases under the EEI scenario are
more than offset by the development of synthetic gas from
coal and the growth of nuclear power. Note that the decline
in oil consumption is almost entirely absorbed by the
transportation sector, which shrinks during 19E5-2000.
Shrinkage for oil and gas also occurs in the d:irect energy
input to the household/commercial and industrial sectors.
Unlike transportation, however, these ocher sect:ors can
use the output of the electrical sector to a significant
     Under the high demand (Bureau of Mines) scenario in
table 1, usage of oil increases some 22 percent during 1985-
2000. The BOM scenario also shows that oil usage by utilities
declines during this period, while under the EEI scenario,
utility oil usage remains constant. In effect, the EEI
scenario assumes that increasingly scarce oil supplies
during 1985-2000 would not be "bid away" from, or re-
allocated from, the electrical sector to the transport
sector. Such an assumption appears implausible.
     The BOM scenario also projected some unlikely
occurrences. Synthetics from oil are projected to
increase six-fold during 1985-2000, despite the limited
commercial development thus far. Similarly, the growth
rate for total energy under the BOM scenario is 3.4
percent per year for 1975-2000. In contrast, equiva-
lent growth rates for selected periods in the past were
as follows.

APPENDIX II                                        APPENDIX II

However, the BOM scenario shows that oil usage by utilities
declines during this period, while under the EEI scenario,
utility oil usaae remained constant. In effect, the EEI
scenario assumed that increasingly scarce oil supplies
during 1985-2000 would not be "bid away" from, or re-
allocated from, the electrical sector to the transport
sector.  Such an assumption appears implausible.
     The BOM scenario also projects some unlikely
occurrences. Synthetics from oil are projected to
increase six-fold during 1985-2000, despite the apparent
lack of commercial development thus far.  Similarly, the
grrwth rate for total energy under the BOM scenario is
3.4 percent per year for 1975-2000. In contrast, equiva-
lent growth rates for selected periods in the past were
as follows.
                                   Annual growth rate
            Period                  in energy demand
              1925-50                    1.97
              1925-75                    2.48
              1950-75                    2. 9
              1965-75                    2.91
      The EEI scenario, taken by itself, predicted utility
coal consumption to be 437 million tons by 1985. This
level was apparently attained in 1976. In summary, the
assumptions incorporated in the two scenarios appear
pessimistic regarding the future coal, but optimistic
regarding the level of gross energy demand in 1985 and
the contribution of synthetic fuels and nuclear power
during 1986-2000.

APPENDIX II                                                             APPENDIX II

                                   Table 1

                        Frojected Consumption of Ener
                 bYMajor Consumin Sector and bMaior Fuels
                  Under Alternative Scenarios, 1985 and 2000

  Consuming                                                  hydro      Total gross
  sector                 Coal       Oil           Gas      geothermal   inputs (note a)

                          ---------------quadrillion Btus---------------

  High demand (BOM)
  Hou secomm.             0.1       7.9           8.5           -        16.5
  Industrial              4.9       8.4           9.5           -        22.8
    tation                  -       3.0           0.6           -        23.6
  Electrical             15.7       6.2           1.5          15.7      39.1
  Synthetics               0.5      1.0             -             -         .5
    Total (note a)       :T7~      437           2U1__
                                                   7T7T            7
  Low demand (EEI)
  House/comm.             0.2       8.9           7.5           -        16.6
  Industrial              3.4       8.3          14.1           -        25.9
    tation                -        23.0           1.0           -        23.7
  Electrical             11.5       2.8           5.0          14.2      33.6
  Synthetics              1.1       0.1            -            -         1.2
    Total (note a)         '7      T7            Y7714.2                TiTr


  High demand (BOM)
  House/comm.             -         8.0           9.0           -        17.0
  Industrial              5.9      10.4           9.0           -        25.3
    tation                -        28.2           0.6            -       28 8
  Electrical             20.7       4.7           1.0          52.2      78.6
  Synthetics              8.1       5.7            -             -       13.9
    Total (note a)        __       _7_           1T9.6       7-_          =_4
  Low demand (EEI)
  House/comm.             0.1       8.2           3.0          -         11 3
  Industrial              3.3       8.5           9.7          -         21.5
    tation                -        19.6           0.6          -         20.2
  Electrical             11.1       2.8           4.6         32.5       51.0
  Synthetics              5.0       0.4            -           -          5.4
       Total (note a)    Irz5      T5            Tl77§         As

a/May not total due to rounding.

APPENDIX III                                     APPENDIX !I1


     The prospects for coal development depend crucially
on our ability to solve the environmental problems resulting
from burning coal. In chapter 2, table 11 we noted that
manufacture of gas and oil from coal is not likely to be
cost-effective in this century. Yet there is a need to
deve'np such new ways to use coal as a supplement to an
oil .id gas substitution and conservation effort.
     This appendix explores the nature and extent of
current Federal efforts to promote further coal utili-
zation through research and develop mnt.

APPENDIX   IIi                                   APPENDIX III

     The Energy Research and Development Administration
has, among other things, responsibility for Federal coal
utilization and conversion research activities. ERDA's
conversion research programs have primarily been focused
on coal gasification* and liquefaction** which will
serve as substitutes for domestic and imported petroleum
and natural gas. Processes for converting coal to liquids
and gases have existed for years and are generally
considered less efficient and more costly than "second

*Coal gasification is the process of converting coal to
 synthetic gas. To accomplish this, coal is fed with
 steam and air or oxygen, into a high temperature pres-
 surized reactor. The raw gas produced is referred to
 as low-Btu gas or utility/industry fuel gas. Low-Btu
 gas has a lower heat content compared to natural gas and
 cannot be economically transported over long distances
 by pipeline. The gas is valuable, however, as a fuel
 supply for electrical power generation plants or indus-
 trial processes using gasified furnaces when a coal
 conversion plant is located in close proximity. Low-
 Btu gas can be upgraded by a process called methanaticn
 tc high-Btu gas. High-Btu gas has approximately
 the same heat content as natural gas and can be
 substituted in existing pipeline networks to satisfy
 the demands of natural gas users.

**Coal liquefaction is the process of converting coal into
  a liquid. One method of accomplishing this is by direct
  catalytic hydrogenation. In this process pulverized
  coal is slurried with a coal-derived recycled oil mixed
  with hydrogen and fed into an ebullated bed with a
  cobalt-molydbate catalyst producing liquids and gases.

APPENDIX III                                     APPENDIX III

generation" processes currently being developed by ERDA.*
These conversion techniques are long range solutions to
increasing coal usage and current estimates are that they
will not have a significant impact on energy supply until
around the year 2000. ERDA is currently predicting that
synthetic fuels will supply between .2 and 1.1 quadrillion
Btus of energy in 1985; and between 1.9 and 9.5 quadrillion
Btus in 2000.** Both projections are small in terms of
total demand.

     Utilization research is concerned with direct com-
bustion processes. Direct combustion research has been
oriented primarily on developing fluidized bed boilers,***
which it is hoped will be a more efficient and more
environmentally sound means for burning coal. This process
may be ready for commercialization in the mid-1980s.

     The objective of ERDA's coal program is to develop the
technology needed to make fuels derived from coal available
in the form and quantity needed and to insure the development
of coal resources on a technically sound, economically
feasible, and environmentally acceptable basis. To accomplish
these goals, ERDA has divided its program strategy into
near-, mid-, and long-term objectives.

     Near-term objectives (1975-1985) include the development
of improved processes for the direct combustion of coal
for electrical power generation and industrial heat, and
the conversion of coal to clean liquid and gaseous fuels.
Process development includes the construction and operation
of demonstration plants which are modules of commercial
size plants.

*ERDA's recently published "Fossil Energy Program
 Report" stated that ERDA is seeking "to determine
 if any of the processes under development are, in
 fact, improvements over existing technology."

**Estimates provided by ERDA's Planning, Analysis, and
  Evaluation Group.
***Fluidized bed combustion involvcs the burning of
   coal in a fluidized (suspended) bed of inert ash
   and either limestone or dolomite. The fluidized
   state is maintained by the injection of air through
   the bottom of the bed at controlled rates.

APPENDIX III                                          APPENDIX III

     Mid-term objectives (1985-2000) include the development
of advanced processes for the combustion of high sulfur
coals, the development of advanced electrical power generation
systems directly utilizing coals, and the demonstration
and transfer of synthetic fuels technology to the private
     Long-term objectives (beyond 2000) include the develop-
ment and demonstration of advanced technologies for producing
electric power and process heat at increased efficiency, the
development of new synthetic fuels, and the development
of underground gasification recovery techniques for coal
deposits not recoverable by available technology.

     ERDA hopes to increase coal use by developing several
parallel and complementary processes rather than selecting
only a few processes for intensive development. ERDA argues
that the varieties of coal to be processed, coupled with
the market requirements for a wide range of fuels, will
necessitate the development of several coal conversion
and utilization processes. As of February 1976 ERDA had
at least 271 fossil energy related contracts outstanding.
Some of the processes under development will serve many
of the same market requirements.

     The development of a process from the initial concept
through operation of a demonstration plant normally requires
15 to 20 years.

                              Table 1
               Typical Process Development Sequence
                        (15 to 20 years)
                        1-4 years   4-6 years   5-8 years    8-12 Xears
Concept   Exploratory   Process        pilot    Demonstra-    Commer-
           research     develop-       plant    tion plant    cial
                        ment Unit                             plant
     The technical capabilities of each process being developed
by ERDA are required to be evaluated at each phase to determine
the feasibility of carrying the project to the next higher
phase.  ERDA also performs tentative economic and environmental
evaluations beginning with process development units and
continuing through pilot and demonstration phases. Sound
research and development practices would dictate that inferior
processes be identified early in the development cycle

APPENDIX III                                     APPENDIX III

so that research efforts can concentrate on promising
processes.  In a report prepared for the Office of Management
and Budget, ERDA stated that it has been unable to develop
reliable techniques for selecting one process, from among
competing processes, for further development. ERDA has
contracted with Stanford Research Institute to develop
a methodology which will aid in selecting on a cost/benefit
basis among competing technologies.

     ERDA has organized its coal program into nine subprograms.
Four subprograms deal with coal conversion, three with the
direct use of coal, one with demonstration plants, and another
with advanced research and supporting technology.
     The cost of developing coal conversion and utilization
technology will be high. Funding levels have increased
dramatically since the Office of Coal Research began its
coal program in 1961. Between fiscal -ar 1970 and 1974,
the Federal Government spent $277.4 million on coal utiliza-
tion and conversion research. Between fiscal years 1975
and 1981, ERDA is forecasting it will spend $4.15 billion.
(See chart 1.) This is $3.51 billion in constant 1975
dollars. This represents a significant increase even dis-
counting the effects of inflation. An additional $1.7 billion
is expected to be spent by industry for cofunding pilot
and demonstration plants. ERDA's coal research and development
subprograms are discussed on the following pages.

APPENDIX III                                          APPENDIX III

                            Chart 1

              Estimated Expenditures for Coal
     Research and Development Between FY 1975 and 1981
           by Major Program xpenditures (note a)
                               ----------- Billions------------
      Direct utilization
       (28 percent):
    Direct combustion          $ .375
    Advance power systems        .307
    Magnetohydrodyramics         .497

                                        Coal conversion
                                          (45 percent):
                                 Liquefaction          $ .926
                                 High-Btu gasification   .399
                                 Low-Btu gasification    .348
                                 In situ                 .177
           (27 percent):

     Advanced research      $ .367
     Demonstration plant      .753

               Total                         $4.149

a/Source for these estimates is ERDA's Fossil Energy
  Five Year Commitment Projections dated February 4, 1976.

 APPENDIX III                                   APPENDIX III

 Direct combustion

     The expanded use of coal in utility and industrial
boilers is restricted by national emission standards. Yet,
curtailments of natural gas, the high cost of oil, and
the uncertainty of foreign oil supplies have creaked a
need for the capability to burn coal cleanly and economically.
Current new source performance standards for stationary coal-
fired steam generators limit sulfur dioxide emissions to 1.2
pounds per million Btus and nitrogen oxides to 0.7 pounds
per million Btus. The high cost of removing sulfur dioxide,
through such means as stack gas scr_.bbing and coal pretreat-
ment, have restricted the expanded use of coal containing
high levels of sulfur.

     ERDA's direct combustion subprogram is attempting to
develop and commercially demonstrate, in the near-term,
the direct combustion of high sulfur coal and coal of all
ranks in an environmentally acceptable way. The subprogram
focuses almost entirely on developing atmospheric and
pressurized fluidized bed combustion systems although some
effort is being expended on combining coal and oil together
as a fuel source, and improving the reliability and efficiency
of present boilers. Direct combustion research is only
about nine percent of ERDA's fossil energy research budget.

     One atmospheric fluidized bed boiler is under construc-
tion and one pressurized system is being designed.   Technical
problems relating to erosion/corrosion rates and the
operational stability of large-sized fluidized bed combustion
systems remain to be solved before transfer of the technology
to the private sector will be considered.

     Fluidized bed combustion, under current programs and
plans, will be available to industry during the 1980s.
In addition, the Environmental Protection Agency, the
Bureau of Mines, and ERDA are conducting and sponsoring
research on controlling coal combustion stack gas emissions.
These research efforts are necessary and vital to any
future expanded use of coal.

Synthetic fuels

     Liquefaction subprogram
     Products derived from coal liquefaction processes
could substitute for petroleum refined products in two
distinct markets. One market uses boiler fuels suitable

APPENDIX III                                      APPENDIX III

for either electrical power or industrial steam generation.
The other market uses quality fuels such as gasoline, methanol,
diesel oil, heating oil, and chemical feedstocks.

      ERDA supports projects in four liquefaction areas--
direct hydrogenation, solvent extraction, pyrolysis, and
indirect liquefaction. Most of the projects are currently
at the PDU stage of development.   H-Coal which is a direct
hydrogenation project, is under the pilot plant design

     Several technical problems common to most liquefaction
processes remain to be solved: (1) solid/liquid separation,
(2) durability of equipment such as pumps and valves, (3)
a catalyst capable of demonstrating long-term performance,
(4) improved reactors for coal and hydrogen contact and
(5) upgrading crude liquids to refined products. Several
delays have occurred at PDU and pilot plant stages within
the last year. ERDA is projecting that liquefaction processes
will be available for commercialization after 1990.

     High-Btu gasification
     ERDA's high-Btu gasification subprogram seeks to develop
second and third generation technologies and improve the
economic and technical capabilities of first generation
gasification processes.

     Improved gasification processes are expected to produce
a substitute natural gas capable of augmenting diminishing
supplies of natural gas. ERDA is still uncertain, however,
if second and third generation processes actually do repre-
sent improvements over first generation processes. As in
the case with the liquefaction subprogram, ERDA is pursuing
several gasification processes that are similar. Each pro-
cess represents a different approach to high-Btu gasifica-
tion, but they all have one purpose, the production cf
substitute natural gas.

     The major technical problems commonly encountered when
gasifying coal include:  (1) clogging equipment, (2) equip-
ment failure under high temperatures and pressures, (3)
difficulties in materials handling and gas cleaning, (4)
variations in product yields, and (5) inefficiency of the

APPENDIX III                                     APPENDIX III

methanation processes.* ERDA's gasification projects
have also suffered delays due to construction problems
in th, past year, but based on ERDA's demonstration plans
high-Btu gasification processes could be ready for initial
commercial application after 1985.
     Low-Btu gasification subprogram

     Low-Btu gasification is a promising method of using
coal as a fuel for electric powerplants and industrial
processes. Development of low-Btu gasification techniques,
although simpler, are not as far advanced as high-Btu
techniques. Two projects are at the pilot plant stage
of development. Although technical problems are somewhat
similar for both low- and high-Btu processes, low-Btu
appears to be cheaper and more efficient than high-Btu
gasification techniques. ERDA has been critized for
not !ircing enouqh emphasis on developing low-Btu gas-
ificatiLn techniques. In fact, ERDA estimates that low-
Btu gasification processes may be competitive with liquified
natural gas (LNG) now. LNG currently sells for about
$3 per thousand cubic feet, and ERDA is estimating
low-Btu synthetic gas at $2.25 to $2.80 per thousand
cubic feet. The $2.25 would be for an improved second
generation process.
     In situ gasification
      In situ gasification, the process of burning coal in its
natural occurring place and capturing the gases, producing
low- and medium-Btu gas is a highly speculative but potentially
attractive technology. Its main advantages are that it
eliminates the need for mining coal and provides a means
for utilizing otherwise unusable coal resources.   Four tech-
niques for b urning coal underground are under development--
packed bed, longwall generator, steeply dipping bed,
and linked vertical well. This subprogram receives the
least amount of funding among the nine subprograms
and is not expected to be ready for commercial use until
around 2000.

*Methanation is the reaction of carbon monoxidc and hydrogen
 which produces methane and water. This process steps low/
 medium-Btu gas up to high-Btu gas. Methane is the main
 ingredient in natural gas.

APPENDIX III                                      APPENDIX III
(MHD) subprgram
     MHD*, a type of advanced power system, has been
singled out by ERDA for intensive development. The major
objective of the subprogram is to develop an electrical
generation system utilizing coal as the primary fuel.

     A recent report, partially funded by ERDA, stated
that MHD's future value in power generation is highly
controversial. Small companies have defended MHD technology
while larger companies see more potential in gas turbine
technology. Tho reasons expressed for this difference are
that gas turbines offer greater efficiency and the tech-
nical problems with MHD, Darticularly using coal as a
fuel, makes commercialization risky. None of the companies
surveyed for the report were pursuing MHD research. Section
107 of Public Law 93-404 directed ERDA to immediately
undertake the design and planning of an MHD engineering
test facility to provide the data for construction of a
commercial scale MHD plant in the 1980i,.  ERDA is committed
to developing and operating a commercial scale demonstration
MHD electric powerplant by the late 1980s.   ERDA is hoping
that as encouraging results of pilot scale efforts begin
to appear, industry will be enticed to cofund further

     Technical problems being addressed are the development
of durable materials and equipment capable of withstanding
high temperatures and the manufacture of special magnets
weighing 2,000 tons.
Advanced power
systems subprogram

     Steam turbine driven generator systems which approach
40-percent efficiency produce almost all of the baseload

*MHD generates electricity directly by forcing a hot
 stream of coal-combustion gases or other electrically
 conductive fluid through a magnetic field.

APPENDIX III                                      APPENDIX III

electric power in the United States. ERDA's advanced power
systems subprogram is trying to increase the efficiency
ratio by developing high temperature advanced gas turbines
that can be combined with available low temperature
steam systems.* ERDA is supporting research for
developing three turbines it considers most promising--
open cycle gas turbine, closed cycle gas turbine, and
alkali metal vapor turbine.

     Development of the open cycle gas turbine is considered
to be further advanced than the other two turbines. ERDA
considers the demonstration of full-scale turbines will
be accomplished after uncertainties concerning cost and
risk are resolved at the "technology readiness" stage
bypassing the need for pilot plant scale development.

     At least 30 large gas turbines which burn natural gas
and oil are commercially producing electricity. But experi-
ments to drive gas turbines on coal have resulted in the
clogging and corrosion of the turbine's machinery. ERDA
expects to overcome these technical problems in the mid-term
(1985-2000). Successful operation of advanced power
systems depends, however, on the ability to produce clean
synthetic fuel. An ERDA official interviewed is worried
that ERDA's coal conversion processes may not even be
able to produce enough synthetic fuel within the next
10 years to even be able to perform tests on the turbines.
p 1ant subprogram

     The objective of the demonstration plant subprogram
is to demonstrate, on a near commercial scale, the technical
and economic feasibility of selective coal technology.
The successful operation of demonstration plants will facili-
tate the timely transfer of coal conversion and utilization
techniques to the private sector. ERDA's plan is to
cooperate with private industry in the design, construction,
and operation of demonstration plants. The design phases
will be funded by the Government, with the construction
and operation phases being cost shared, 50 percent from
industry and 50 percent from the Government.

*Combined cycles consist of gas turbines (essentially a
 stationary jet engine) that are used to generate electricity.
 In addition, the hot exhaust gases are captured and used
 in a conventional boiler (called a waste heat recovery boiler).

APPENDIX III                                      APPENDIX III

     To date, one contract has been awarded for a plan to
demonstrate the conversion of coal to clean boiler fuel.
Detailed designs for the plant are underway. However,
because of technical problems the project has been delayed
about two years. ERDA is also presently considering five
proposals for a high-Btu gas demonstration plant and 14
proposals for three low-Btu gas demonstration plants for
specific electric power utility or industrial uses.
Responses to ERDA's proposals for constructing demonstration
plants are not limited to those projects being developed
by ERDA. And no one really knows if any processes
being developed by ERDA will eventually advance to the
demonstration plant phase.

      ERDA currently estimates that liquefaction, high-Btu,
low-Btu, and direct combustion demonstration plants will
complete operation by 1985. Assuming the demonstration
program is successful, the second generation processes
could be ready for initial commercial application by

APPENDIX III                                            APPENDIX III

                              Table 2

      Fossil Demonstration Plants Division Planned Program
            Schedule for Second Generation Processing

                                                    operation Dates

Clean boiler fuel (Coalcon)                    a/Fiscal years 1980-83
Pipeline A&B (high-Btu)                         Fiscal years 1981-83

Fuel gas utility (low-Btu/medium-Btu)           Fiscal years 1981-83

Fuel gas industrial (low-Btu/medium-Btu)        Fiscal years 1981-83

Fuel gas small industrial (low-Btu/             Fiscal yeai:s 1980-81
Direct combustion                               Fiscal years 1982-84

Advanced liquefaction                           Fiscal years 1983-85

   Design time is estimated             2-1/    years

   Construction time is estimated       2-1/2 years

   Operations time is estimated         2 years

               Total                    7 - 8 years

a/This project has been delayed about 2 years while a
  technical assessment and additional research and
  development are performed.

      ERDA's demonstration plant subprogram aims at trans-
ferring second generation coal utilization and conversion
processes to the private sector by proving the technical
and economic viability of selected processes. No demon-
stration plant has yet been operated, but ERDA believes
that once this is accomplished little technical risk should
exist in scaling demonstration plants up to commercial

APPENDIX III                                     APPENDIX lII

     ERDA's scheduling shows that the seven coal demonstration
plants now being planned will not be completed until 1980-85,
if the projects proceed as planned. Assuming the current
pace of development continued- it appears highly unlikely
that second generation coal cr -ersion techniques can
begin having any commercial ;    t. until the late 1990s.

Advanced research
and supporting
technology subprolram

     This subFpogram supports ERDA's other coal subprograms
by performing supporting research and system studies.
The general objective of the advanced research and supporting
technology subprogram is to develop third generation
coal conversion and utilization techniques, and perform
research to improve second generation techniques being
developed by ERDA. Research projects are grouped into four
main categories--material and components, conversion pro-
cesses, direct utilization technology, and systems studies.

                           111 .14
APPENDIX IV                                                  APPENDIX 1V


                      OF COAL TO PUBLIC UTILITIES

     Working with Bureau of Mines 1/ and Federal Power
Commis;ion data 2/ we examined the-potential intermodal
shifts in the transport of coal within and between regions*
in 1985. This analysis did not consider new national
initiatives affecting utilities or industrial users of
gas or oil. Such factors would further affect the shifts
between transport modes as well as between and within regions.
     Based upon these data and projections made from them,
coal transportation to utilities shows the f.!lowing
                                    Table 1
                              At Point of Origii
                          Percent Share of the Market
Method of
transpor-     Northeast      Southeast     Southwest   Northwc-         tional
  tation      1975 1985      1975 1983     1975 1985   1975 19 :        75 1985
Railroad       57    59       36    57      40    32    66    6-,      57    58
Trucks         14    13       21    14      25    54    13    14       15    19
Water          25    25       25    17      -            8        4    21    15

Other*          4     3       18    12      35    14    13    13        7     8

  Total       100   100      100   100     100   100   100   1u       100   i00

  *Includes slurry pipelines, trams, conveyors, etc..

*With the exception of a portion of Tennessee, utilities
 were grouped the same as the mining districts established
 by BOM and were combined as shown on the map, p. IV.5.

Note: Number2d footnotes to app. IV are on p. IV.6.

APPENDIX IV                                         APPENDIX IV

The foregoing table shows that transportation growth could
vary among regions and transportation modes, reflecting
particular producer/consumer market decisions. Note the
relative stability of the Northeast and Northwest compared
to the relative changes among modes in the Southeast and
Southwest. Also note the relative increase for trucking
on a national basis compared to a relative decrease for
water transportation.
     The following table shows projected increases in traffic
by region and mode of transport.

                                 Table 2
                         At Point of Origin
                 Projected Traffic Growth byMode
 Mode of
 trans-     Northeast Southeast Southwest Northwest    National
portation    1975-85   1975-85   1975-85   1975-85     1975-85
              ----…----------(percent increase)---------------…

Railroads       31         141          166   299         86
Truck           13          -           621   321        125
Water           28                      -     112         31
Other*          11          -            27   153         53
*Includes slurry pipelines, trans, conveyors, etc..

     The above tables depict coal traffic among carriers and
regions in relative terms. The following table compares
interregional movements in absolute terms.

                                 IV 2
APPENDIX IV                                                         APPENDIX IV

                                       Table 3

                       Inter-Regional Movements of Coal
                             By Mode of Transport
To     :             Northeast                            Southeast
                     TI         Water                  Rail        Water
               t97 f        19753T93§              1T75 1985     13=73 9

              --------------       (Million       tons)-------------------
     edst        -             -   -          -       24       32       9        11
     west       15        26       5        10         0       28       -        -
     west                               -                              -_    -

      Total    15         26       5        10        24       60       9   11

To     :             Northwest                                Southwest
                Rail           Water                       Rail         Water
              157    i~     I95 1985               1985              1975


  east           2             2   2          2        9       14       3        5
     west        -             -   -          -        3       52       -        -
     west        4             4   -

      Total      6             6   2          2      i2       66        3        5

     These tables are indications of the possible impacts of
regional demands upon the various transport modes currently
anticipated by the electrical utilities. However, substantial
growth in consumption is indicated for the Southwest region and
a somewhat lesser amount is expected for the Southeast. The
increase in truck transport may be indicative of the utilities
decision to locate facilities near mines.
APPENDIX IV                                       APPENDIX IV

     These tables also show that a large portion of the
increase in interregional coal traffic will be in move-
ments from the Northwest to the Southwest and Southeast.
For the most part, however, the major share of the coal
consumed will not be moved interregionally, but will be
used within the region where it is produced.

                          a   j:    I

             ~        I

                 I~;j          ~i

18a~~~~~~v        5
APPENDIX 1V                                       APPENDIX IV


1/United States Bureau of Mines, "Bituminous Coal and
  Lignite Distributioui, Calendar Year 1975," Mineral
  Industry Surveys, April 12, 1976, pp. 8 to 41.
2/Federal Power Commission, Status of Coal Supply
  Contracts for New Electric GeneraiaEng Units 1976-1985
  (Wahington-: iFee-aI PowerCommission, 1977), pp. 24
  to 26.

 AEC      Atomic Energy Commission
 BLS      Bureau of Labor Statistics
 BN       Burlington Northern Railroad
 BOM      Bureau of Mines

bpd       Barrels per day
Btu       British thermal unit
CEP       Council on Economic Priorities
Conrail   Consolidated Rail Corporation
DOI       Department of the Interior
DOT       Department of Transportation
DRI       Data Resources Inc.
ECAR      East Central Area Reliability Coordination Agreement
EDA       Economic Development Administration

EEC       European Economic Community
EEI       Edison Electric Institute
EPA       Environmental Protection Agency
ERDA      Energy Research and Development Administration
ESECA     Energy Supply and Environmental Coordination Act
FEA       Federal Energy Administration
FGP       Flue Gas Desulfurization
FPC       Federal Power Commission
FRC       Federal Research Council
GAO       General Accounting Office
GNP       Gross National Product

ICC       Interstate Commerce Commission

IEA    International Energy Agency

kw     Kilowatt
kwh    Kilowatt hour

LNG    Liquified natural gas
MAIN   Mid-America Interpool Network

MW     Megawatt
MESA   Mining Enforcement and Safety Administration

MHD    Magnetohydrodynamics
NAS    National Academy of Sciences

NCA    National Coal Association

NCM    National Coal Model

NEO    National Energy Outlook
NEPA   National Environmental Policy Act

NERC   National Electric Reliability Council
NSF    National Science Foundation

OPEC   Organization of Petroleum Exporting Countries
OTA    Office of Technology Assessment

PIES   Project Independence Evaluation System
ppm    Parts per million

SRI    Stanford Research Institute
TVA    Tennessee Valley Authority

TSC    Transportation Systems Center

UMWA   United Mine Workers of America

USG    Under Secretaries Group
USGS   United States Geological Survey

USRA   United States Railway Association


Ambient             Conditions in the vicinity of a reference
                    point, usually related to the physical
                    environmernt (e.g., the ambient temperature
                    is the outdoor temperature).

Anthracite coal     A high-rank coal with high fixed carbon,
                    percentages of volatile matter and
                    moisture; a late stage in the formation
                    of coal.
Aquifer             Water-bearing permeable rock, sand, or
Auger mining        Generally practiced but not restricted to
                    hilly coal-bearing regions of the country.
                    Utilizes a machine designed on the
                    principle of the auger, which bores
                    into an exposed coal seam and conveys
                    the coal to storage site or bin for
                    loading and transporting.
Baseload            Minimum load of a power generator over a
                    given period of time.
Bituminous coal     An intermediate-rank coal with low to high
                    fixed carbon, intermediate to high heat
                    content, a high percentage of volatile
                    matter, and a low percentage of moisture.

British thermal     The amcunt of energy necessary to raise
  unit (Btu)        the temperature of one pound of water
                    by one degree Fahrenheit.

Coal                A combustible natural solid formed from
                    fossilized plants.
Coking/metallurg-   Designates certain bituminous coal which
  ical coal         when heated at high temperature in the
                    absence of air, softens then solidifies
                    into a porous solid mass that is called
                    coke. Only bituminous coal possesses
                    such properties and certain bituminous
                    coal possesses coking properties in
                    a greater degree than others. Coke is
                    used in blast furnaces.

Combined cycle      Combination of a steam turbine and a gas
                    turbine in an electrical generation plant.
Continuous miner    A single machine used in underground
                    mining which accomplishes excavation,
                    loading, and transportation.
Demonstrated reserve
  base (coal)        Portion of identified coal resources
                     to depths of 1,000 feet and seam
                     thickness similar to those from which coal
                     is currently being mined, generally 28
                     inches or more.
Eminent domain      The right of a government to appro-
                    priate private property for public
                    use, usually with compensation to the
Flue gases          Gases usually carbon dioxide, water
                    vapor, oxides of nitrogen, and other
                    trace gases which result from combustion
Fluidized bed       A body of finely crushed particles
                    with gas blown through them. The gas
                    separates the particles so that the
                    mixture behaves like a turbulent liquid.
Fly ash             Lightweight solid particles which are
                    carried by stack gases.
FOB mine            The price of coal at the mine gate.
                    It does not include cost of trans-
                    porting the coal to its final destination.
Gasification        Commonly refers to the conversion of
                    coal to a gaseous fuel.
Generator, electric A mechanism which converts mechanical
                    energy to electrical energy.
Heat rate          An expression   of the conversion
                   efficiency of   a thermal powerplant
                   or engine, as   heat input per unit of
                   work output:    for example, Btu per

 High-Btu gas        An equivalent of natural gas, pre-
                     dominately methane; energy content
                     is usually 950 to 1,000 Btus per
                     cubic foot.
 resources (coal)    Deposits of coal whose location,
                     quality, and quantity have been
                     mapped and are known to exist from
                     geologic evidence supported by
                     engineering and measurements of
                     geologic reliability. Includes
                     deposits in beds of minimum thick-
                     ness of 14 to 30 inches, depending
                     upon rank to depths of 3,000 feet.
 Kilowatt           One thousand watts.
Kilowatt hour       The total energy developed by a power
                    of one kilowatt acting for one hour;
                    a common unit of electric power
Lignite coal        The lowest rank coal with low heat
                    content and fixed carbon and high
                    percentages of volatile matter and
                    moisture; an early stage in the
                    formation of coal.
Liquefaction        Commonly refers to the conversion
                    of coal to liquids.
Low-Btu gas         Gas obtained by partial combustion
                    of coal with air; energy content is
                    usually 100 to 200 Btus per cubic
Megawatt            A million watts or a thousand kilo-
                    watts and is used to measure the
                    amount of power as electricity that
                    can be produced by a facility at any
                    one time.
Methane             A colorless, odorless, flammable,
                    gaseous ..;drocarbon that is a product
                    of decomposition of organic matter
                    in marshes or mines or the carbon-
                    ization of coal.

Micron             A unit of length equal to one
                   thousandth of a millimeter.
Overburden         The rock, soil, etc., covering a
                   mineral to be mined.
Particulates       Microscopic pieces of solids which
                   emanate from a range of sources and
                   are the most widespread of all
                   substances that are usually considered
Peak load          The maximum instantaneous load or
                   the maximum average load over a
                   designated interval of time, also
                   known as peak power.
Quadrillion        The cardinal number represented by 1
                   followed by 15 zeros; one quadrillion
                   Btus of energy is the equivalent of
                   180 million barrels of oil.
Reserves (coal)    Portion of coal resources in the
                   ground that can be economically
                   extracted at current prices (costs)
                   using current technology.
Resources (coal)   Coal deposits in the ground as of a
                   stated date. Coal resources are
                   classified by the USGS as identified
                   and undiscovered resources.
Scenario           An outline of a hypothesized chain
                   of events.

Scrubber           Equipment used to remove pollutants
                   such as sulfur dioxide or particulate
                   matter from stack gas emissions
                   usually by means of a liquid solvent.
Seam               A bed of coal or other valuable
                   mineral of any thickness.

Slurry             A mixture of a liquid and solid.
                   Slurries of oil and coal or water
                   and coal are used in coal processing
                   and transportation.

 Stack gas             Gases resulting from combustion.
 Stack gas cleaning    Referring to the removal of
                       from combustion gases before pollutants
                       gases are emitted to the atmosphere.
 Steam coal            A designation for a whole range
                       coal that can be utilized in      of
                       to produce steam for purposes
                       generating electricity.        of

 Strip mining          A mining method which uses giant
                       power shovels or other earth-moving
                       equipment to remove overburden
                       that covers the coal seam.
                       the coal is exposed, it is broken
                       up usually by explosives and
                       loaded by smaller power shovels
                       into huge trucks.
Stripping ratio       Cubic yards of overburden per
                      of coal recovered.            ton

Subbituminous coal    A low-rank coal with low fixed
                      carbon and high percentages
                      volatile matter and moisture.of
Sulfur dioxide        One of several forms of sulfur
                      the air, an air pollutant generated
                      principally from combustion
                                                  of fuels
                      that contain sulfur.
Unit train            A term used to designate a train
                      which carries a single commodity.
                      Coal unit trains normally contain
                      about 100 cars with each car
                      a capacity of about 100 tons having
                                                   of coal.
Volatile              Readily vaporizable at a relatively
                      low temperature.


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                      WASHINGTON, D.C. 20500

                                     August 26,   1977
Dear Mr. Staats:

The GAO report, "U.S. Coal Development:  Promises and Uncer-
tainties," addresses a number of issues of vital importance
for energy policy.  The only major area of substantive
disagreement is the conclusion reached by the report that no
more than one billion tons of coal could be produced between
now and 1985.

One reason advanced by GAO is that strip mine legislation
will constrain expansion.  Since the new strip mine legisla-
tion has not been translated into regulations, it is very
difficult to understand the basis for this conclusion.
However, regardless of the stringency of the implementing
rules, it is doubtful that the effects would produce a
substantial shortfall.

GAO raises questions about possible transportation constraints.
However, recent investigations by the Department of Transporta-
tion demonstrate that railroad capacity is generally adequate
and that the capital requirements for additional capacity
would represent only a small portion of prospective railroad
On the demand side, GAO's estimate of shortfall is based on
expected impacts of strict enforcement of air quality regula-
tions. Although no quantitative analysis of the major
economic sectors is presented, GAO focuses arguments on
three policies: best available control technology (BACT)
requirements; prevention of significant deterio.ration (PSD)
policies in clean air areas; and EPA's offset policy for
non-attainment areas.
Since BACT requirements do not come into effect until 1982,
the impacts on coal use will be miaiimal by 1985. The PSD
policy is not likely to affect coal consumption substantially.
Studies indicate that large coal-fired power plants with
BACT can be located as close as six miles from a Class I
area that has the most stringent dete oration limits.
Industrial units, which are similar, .An be located even
closer. EPA's offset policy for non-attainment areas will

 not affect new power plants because they will not be built
 in non-attainment areas.  Also, conversions generally
 increase sulfur oxide emissions but reduce particulate
 emissions, whereas most non-attainment areas violate parti-
 culate standards and not sulfur oxide.

The GAO report does not address how much of an increase in
coal production can be achieved due to the initiatives in
the National Energy Plan.  In general, the report seems to
be criticizing the base case projection that without the
National Energy Plan, production will be about one billion
tons per year.  The one billion ton base estimate of coal
production of 1985 is consistent with several different
surveys, including GAO's survey of producers.

Although we disagree with GAO's assessment, the-e are a
number of factors that could limit coal demand and hence
total coal use. The Department of Energy plans to monitor
coal production carefully and if shortfalls occur, the
Department will take or recommend appropriate remedial


                                   Alvin L. Alm

The Honorable Elmer B. Staats
Comptroller General of
  the United States
Washington, D.C.  20548