United States
Environmental Protection
Agency
Region 8
1860 Lincoln Street
Denver, Colorado 80295
October, 1980
United States Economics Department
Department of Colorado State University
Agriculture Fort Collins, Colorado 80523
&EPA Colorado
Coal Resources,
Production and
Distribution
-------
ii
COLORADO COAL RESOURCES,
PRODUCTION AND DISTRIBUTION
by
John W. Green
Norman L. Dalsted
Michael H. Moffett
Dennis K. Winters
Natural Resource Economics Division
Economics and Statistics Service
United States Department of Agriculture
Economics Department
Colorado State University
Fort Collins, Colorado 80523
and
Scott R. Grace
Energy Policy Coordination Office
United States Environmental Protection Agency
Region 8
Denver, Colorado 80295
October, 1980
Energy Policy Coordination Office
United States Environmental Protection Agency
Region 8
Denver, Colorado 80295
-------
FOREWORD
On behalf of EPA and USDA I am pleased to provide you with a copy of
a report on Colorado coal. This jointly prepared report discusses resources,
production and consumption history, and future demand/supply.
The Coal Use and Development Project has been jointly funded by the
U.S. Environmental Protection Agency's Office of Research and Development and
by the U.S. Department of Agriculture's Economics and Statistics Service,
since 1975. A major portion of the research has been located in the Economics
Department at Colorado State University, Fort Collins, under the direction of
Dr. John W. Green. Several data bases have been developed describing U.S. coal
resources, production and distribution. It is one objective of the Project to
organize these statistics into individual state reports and make them available
to the public. This Colorado report is the first of the anticipated series
and was completed with the cooperation of the Energy Policy Coordination Office,
U.S. EPA, Region VIII, Denver, Colorado.
Additional copies of this report may be obtained from the National Technical
Information Service.
-------
ABSTRACT
The primary demand for Colorado coal is for steam-electric power gener-
ation. Approximately 14.66 million tons of the 18.13 million tons of coal
produced in Colorado in 1979 was used for this purpose. Over 36 percent of
the coal required by Colorado power plants in 1979 was provided by Wyoming
mines. Colorado utility coal demand will increase approximately 33 percent
between 1980 and 1985. Colorado utilities will add 2,150 megawatts of coal-
fired capacity in that same period. Northwest Colorado will produce nearly
80 percent of all coal produced in 1985 compared to 91 percent in 1975.
Labor and land impacts will vary depending on the type of mining and the
local topography.
-------
TABLE OF CONTENTS
Abstract i
Foreword 11
List of Tables iii
List of Figures iv
Introduction 1
Colorado Coal Resources and Reserves 1
Colorado Coal Reserves 2
History of Colorado Coal Production 5
Existing Colorado Coal Mines 6
Mine Employment 15
Mine Land Disturbance and Reclamation 17
Distribution of Colorado Coal 18
Colorado Coal Consumption 18
Existing Coal-Fired Electric Generating Plants-- 20
New Coal-Fired Electric Generating Plants 24
Industrial Coal Use 27
Cooling 27
Ash Sluicing 29
Flue Gas Desul furization 30
Existing and Future Water Requirements 30
Solid Waste Removal 34
Coal Preparation 36
Coal Transportation in Colorado 37
Conclusions 41
-------
LIST OF TABLES
Table 1 -- Demonstrated reserve base, January, 1976 — 4
Table 2 -- Colorado coal mine summary 8
Table 3 -- Coal mines in Colorado 9
Table 4 -- Future Colorado coal mines 14
Table 5 -- Colorado coal mine employment and
productivity, 1975-79 16
Table 6 -- Estimated land disturbance by Colorado
coal production 17
Table 7 -- Distribution of Colorado coal, 1975-1979 — 19
Table 8 -- Consumption of coal energy by type,
Colorado, 1960-1978 20
Table 9 -- Existing coal-fired electric generating
plants in Colorado 22
Table 10-- Proposed new coal-fired electrical
generation capacity 100 megawatts or
greater, Colorado, 1980 to 1985 25
Table 11-- Industrial users of Colorado coal, 1976
and 1977--- - 28
Table 12-- Institutional users of Colorado coal, 1976-- 28
Table 13-- Water use in coal-fired electric generation
plants over 100 megawatts in Colorado,
1975 31
Table 14-- Projected coal-fired electric generation
plants over 100 megawatts in Colorado 32
Table 15— Existing and projected solid inputs, wastes,
and waste heat for coal-fired power
plants in Colorado 35
Table 16-- Major coal transportation rail links in
Colorado 39
-------
LIST OF FIGURES
Figure 1 - Coal regions and fields in Colorado 3
Figure 2 - Colorado Coal Production, 1880-1979 7
Figure 3 - Map of coal mines in Colorado 13
Figure 4 - Major Coal-Fired Facilities in
Colorado 1979 21
Figure 5 - Major Coal Rail Links in Colorado 38
-------
Colorado Coal Resources, Production, and Distribution
By
John W. Green, Norman L. Dalsted, Mike H. Moffett,
Dennis K. Winters, Scott R. Grace*
Introduction
The increased demand for coal as a fuel for steam electric power generation
during the 1970's has significantly impacted Colorado coal production. The cost
of transportation, combined with cheap oil and natural gas, previously made
use of Colorado coal less economical. Recently, prices of oil and gas increased
relative to coal. This, combined with more efficient transportation methods,
has made western coal competitive.
Coal is used primarily for steam electric power generation. Historically,
Colorado electric energy needs have been met by a comparatively small regional
coal industry. This industry's status will change significantly in Colorado
and throughout the West by 1985. Demand will continue to increase because of
low production costs, low sulfur content, higher regional electrical demands
stemming from rapid growth, and the establishment of a synthetic fuels industry.
Colorado Coal Resources and Reserves
Colorado contains some of the highest quality coals found in the western
United States. Some of Colorado's coal deposits can and are being surface
mined. Colorado's subbituminous coal is used in steam electric generating
plants in the state and elsewhere, particularly in the Midwest. Several
long-term contracts have been signed with both in-state and out-of-state
*Regional Economist and Project Leader, NRED-ESCS-USDA, stationed at Fort
Collins; Ph.D. candidate, Economics Department, Colorado State University;
Research Analyst, TEKNEKRON, Berkeley, CA and former Master's candidate,
Economics Department, Colorado State University; and Master's candidate,
Economics Department,Colorado State University; Environmental Engineer/
Hydrologist, Energy Policy Coordination Office, USEPA, Denver; respectively.
-------
2
utilities. Markets for Colorado's metallurgical grade coal should remain
stable or possibly expand slightly.
Colorado Coal Reserves
The States' coal-bearing lands are divided into five resource regions:
Green River, Uinta, San Juan River, Raton Mesa, and Denver (Figure 1, 2).
Separate fields exist within each region. Three additional fields are outside
all regions. Detailed reserve estimates totaling 82 billion tons have been
made covering about 5,300 square miles. Another 15,000 square miles contain
undetailed reserves which are beneath 3,000 feet of overburden. Estimated
reserves for the state total about 370 billion tons at depths to 3,000 feet.
According to the U.S. Bureau of Mines (1977), Colorado ranked seventh
among states in the U.S. in the total demonstrated reserve base — of coal
(16.3 billion tons) and fourth in the reserve base of bituminous coal. These
numbers are similar to those published by the U.S. Geological Survey
(Table 1). — Approximately 3.8 billion tons (23 percent) are surface mineable.
Colorado ranks first in the U.S. in the reserve base of underground mineable,
low sulfur, bituminous coal. The sulfur content generally varies from .2 to
1.1 percent and averages approximately .5 percent. Ash content typically
varies between 2.1 and 15 percent, averaging about 6 percent. The moisture
content in most Colorado coal ranges from 1.0 to 20 percent. Heating values
vary between 11,440 and 14,500 Btu per lb. Average values are about 11,370
Btu per lb. as received and 13,905 Btu per lb. on a dry and ash free basis.
A significant part of Colorado's bituminous coal reserve base is coking or
metallurgical grade.
17 The demonstrated reserve base includes all coals that occur to depths
of 1,000 feet. Only bituminous coal and anthracite in beds 28 inches or
more in thickness and subbituminous coal and lignite in beds 60 inches or
more in thickness are included in the demonstrated reserve base.
2/ Reserve and resource estimates from alternative sources usually do not
agree because of differing assumptions and/or incomplete knowledge.
-------
40 20 0
120 160 200
- MILES
COAL REGIONS AND FIELDS IN COLORADO
COAL REGIONS COAL FIELDS
I Canon City (field)
II Denver Basin
III Green River
IV North Park
V Raton Mesa
VI San Juan River
VI South Park (field)
VIII Uinta
1.Yampa
2.Book Cliffs
3.Grand Mesa
4.Somerset
5.Crested Butte
6.Carbondale
7.Grand Hogback
8. Dan forth Hills
9.Lower White River
lO.Durango
11.Wa1senburg
12.Trinidad
13.Boulder-Weld
14.Colorado Springs
15.Canon City
16.North Park
17.Middle Park
18.South Park
19.Pagosa Springs
20.Nucla-Naturita
Figure 1. Coal regions and fields in Colorado.
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4
Table 1—Demonstrated reserve base, January, 1976
Heat
County
Seams
Deep
Strip
Total
S
Ash
HO
content
No.
Mill ions
of short tons
Percent
c.
Btu per lb.
Adams
3
122.64
0
122.64
0.3
6.0
23.7
8,670
Arapahoe
1
70.12
0
70.12
N/A
N/A
N/A
N/A
Archuleta
1
92.10
0
92.10
0.6
13.0
3.7
12,370
Boulder
7
163.24
0
163.24
0.3
5.8
19.1
9,940
Delta
9
270.76
0
270.76
0.5
6.1
9.7
11,910
Douglas
1
5.07
0
¦ 5.07
N/A
N/A
N/A
N/A
Elbert
1
248.81
0
248.81
0.4
8.0
32.9
6,330
El Paso
1
123.89
0
123.89
0.2
6.1
22.4
8,890
Fremont
7
180.32
0
180.32
0.4
8.8
10.1
11,030
Garfield
19
552.99
0
552.99
0.8
7.4
6.6
12,130
Gunnison
19
916.62
0
916.62
0.4
6.1
5.9
12,690
Huerfano
28
278.32
0
278.32
0.6
10.8
5.2
11,920
Jackson
11
823.51
127.00
950.51
0.3
5.9
16.5
10,120
Jefferson
1
175.91
0
175.91
0.3
4.6
18.9
9,850
La Plata
2
322.06
0
322.06
1.4
7.2
3.9
13,120
Las Animas
49
831.96
0
831.96
0.5
13.3
2.1
12,640
Mesa
5
238.34
0
238.34
0.6
8.9
8.1
11,790
Moffat
56
2,570.55
270.00
2,840.55
0.2
3.8
11.5
11,510
Montezuma
1
19.11
0
19.11
0.5
7.9
5.5
12,750
Montrose
5
143.05
60.00
203.05
0.6
9.4
5.4
12,390
Ouray
1
762.59
0
762.59
0.5
7.5
15.7
10,140
Park
4
25.31
0
25.31
0.4
6.3
15.5
9,770
Pitkin
12
88.60
0
88.60
0.5
8.1
2.8
13,660
Rio Blanco
70
1,067.37
0
1,067.37
0.4
6.0
11.7
11,210
Routt
27
3,413.89
413.00
3,825.89
0.8
6.4
9.4
11,560
Weld
7
464.31
0
464.31
0.3
4.8
21.2
9,810
State Total -1974
13,971.44
870.00 14,841.44
0.5
7.2
11.8
11,610
1976 Updated Data
12,465.5 3
,791.1
16,256.6
0.5
7.2
11.8
11,160
Source: (26, Appendix 11-2; _13, p. A-2)
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5
The Colorado Geological Survey estimates over 80 percent of the state's
total coal resources are mineable only by underground methods. Recovery of
the coal in place probably will be much less than 50 percent unless major
breakthroughs in mining technology are achieved.
Most of Colorado's potentially surface mineable coal is located in the
Denver coal region (75 percent), in the San Juan River region (16 percent),
and in the Green River region (5 percent). Approximately 20 billion tons of
lignite, in beds at least four feet thick occurring at less than 1,000 feet
in depth, may exist in the central part of the Denver basin. Urban growth
pressures in the front range corridor, as well as increasing oil and gas
drilling activity in the region, will affect the amount of lignite coal that
will ultimately be mined.
History of Colorado Coal Production
Significant coal production commenced in the western U.S. in the late
1960's as use by electric utilities and industry increased. New air quality
regulations induced a shift from high to low sulfur coals. Also important
was the fact that much of the coal in the West can be surface mined. Nearly
84 percent of the low sulfur (less than 1.0 percent sulfur, by weight)
coal reserves in the U.S. are found in the Western States. Colorado con-
tains 4.5 percent of western low sulfur coal. (14) The EPA Region 8 States
(Colorado, Wyoming, Utah, Montana, North Dakota) produced approximately 147.9
million tons of coal in 1979. Colorado annual production has increased every
year since 1971. {2, 7)
1971 5.31 million tons
1972 5.53 million tons (4 percent increase)
1973 6.23 million tons (13 percent increase)
1974 6.96 million tons (12 percent increase)
1975 3.27 million tons (19 percent increase)
1976 9.46 million tons (14 percent increase)
1977 11.97 million tons (27 percent increase)
1978 14.36 million tons (20 percent increase)
1979 18.13 million tons (26 percent increase)
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6
Top production of about 12.7 million tons was recorded in 1918 from Colorado
mines (Fig. 2, ]). Prior to 1917 production, which began in 1864 and passed one
million tons in 1332, rose irregularly to this peak. Following 1917 coal pro-
duction declined irregularly to 5.6 million tons in 1948. Only in 1933 and 1934
had production been lower.
A further era of decline began in 1948 as traditional home heating and
railroad markets withered away. Production had fallen by 1954 to a low of 2.9
million tons, the lowest since 1889. The trend then turned gradually upv/ard
until, by the mid-1960's, a production plateau of about 5.5 million tons had been
achieved. Since 1864, the year of the first production, to 1980 about 640 million
tons of coal have been produced.
Surface mining in Colorado began in 1931. It became significant in 1948
when over 5 percent of the production came from this source. This trend
continued through 1979, accounting for about 68 percent of Colorado's pro-
duction.
Utility coal has expanded its market share to about 81 percent of the
state's production {22). Industrial coal constitutes about 16 percent and the
remaining 3 percent goes to other markets.
Existing Colorado Coal Mines
This section provides a summary of coal mines in Colorado current as of
August, 1980. The data was verified with the Denver Office of Surface Mining.
The information reflects recent startups and closings. Also indicated are
mines that are currently idle but which may resume production at some future
date.
Table 2 describes the categories of Colorado coal mines. There are 23
surface and 28 underground active mines and 7 surface and 12 underground
idle mines. There are 5 surface and 11 underground planned mines. Thus there
is a total of 51 active, 19 idle, and 16 planned mines in Colorado.
-------
Figure 2. Colorado Coal Production, 1880-1979
Colorado Coal Production 1880-1979
Cumulative Production to 1-1-80
640,490,000 Short Tons
I
-------
8
Table 2--Co1orado coal mine summary
Exi sti ng
: Idle
: Planned
: Total
S : U
: S : U
: S : U
: S : U
Number
23 28
7 12
5 11
35 51
51
19
16
86
Source: (16)
S=surface
U=underground
Colorado had 37 mines in 1972, 67 in 1975, and 72 in 1979 as opposed to
over 110 operations in 1961 (annual publications, Colorado Division of Mines).
The gradual decline in the number of operations before 1972 was probably
a result of economic forces rather than Federal regulations. The number of
mines has been increasing since 1972 as markets for Colorado coal have
expanded.
Table 3 describes each existing coal mine in Colorado, by county, including
the mine name, type of operation, operator name, type of lease, annual pro-
duction for 1976 through 1979, the 1980 status of closed and idle mines,
and market for the coal. Figure 3 gives a general indication of the location
of coal mines in Colorado. The mine locations are keyed by number to mine names
in Table 3. Planned mines are shown in Table 4, including estimated production
for 1980 through 1985 and 1990.
Colorado operators face traditional industry problems including distance
from market and costly production. In fact, Wyoming thick-seam, surface-
mined coal is used in some coal-fired electric generation plants in Colorado.
-------
No
1
2
3
4
4
5
6
7
8
12
9
10
11
13
14
15
16
17
Table 3—Coal mines in Colorado
Type
of 3/
mine—
Operator
Type
,of i/
lease-
Production
1976 : 1977 : 1978 : 1979
Thousand tons
19804/
status-
s
Penna Resources
P
0
4.1
35.2
78.8
A
u
Sunflower Energy
P
0
16.6
15.3
89.4
A
s
Coal by Mining Co.
X
0.1
0
0
0
C
u
Westmoreland
F
14.0
286.1
435.9
722.5
A
u
Grand Mesa Coal
P
0
0.4
0.4
9.8
A
u
Grand Mesa Coal
P
0
0
0
0
I
s
Quinn Coal Co.
P
0
24.2
41.2
70.7
A
s
Capstan Mining
P
0
0
0
0
S
u
Dorchester Colomine
P
0
0
0
14.3
A
s
GEC Minerals
P
44.9
30.1
0
0
C
s
GEC Minerals
3.3
0
0
0
C
s
GEC Minerals
P
0
19.5
80.0
85.6
A
s
Cedar Canyon
P
2.2
2.3
0
0
C
s
Robert Hastings
P
0
0.1
2.6
10.4
I
s
Newlin Creek Coal
P
0
1.6
5.3
17.7
A
u
Twin Pines Coal
P
40.7
37.1
36.7
37.1
A
U
Eastside Coal
P
0
0.3
0.3
0
U
Sheridan Enterprises
F
0
46.0
1.6
3.4
u
Sheridan Enterprises
F
0
20.5
80.4
0
u
Henry Bendetii
P
0.4
0.4
0.3
0.1
u
Eastside Coal
P
1.0
1.8
0.5
0.5
Continued
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i-ia
_No
18
19
19
20
21
22
23
24
25
26
27
28
29
30
31
32
32
33
34
35
36
Table 3—Coal mines in Colorado—continued
Type
of 3/
mine—
Operator
Type
,of i/
lease-
Production
1976 : 1977 : 1978 : 1979
Thousand tons
19804/
status—
u
Bear Coal
F
109.2
226.2
226.7
250.2
A
u
Western Slope Carbon
F
26.8
190.3
331.0
436.7
A
u
Western Slope Carbon
F
155.7
155.7
12.4
0
I
u
Henry L. Weaver
F
3.3
3.7
1.5
0.3
A
u
U.S. Steel
P.F
950.2
914.6
650.2
900.8
A
u
Anchor Coal
X
0
0
0
0
S
s
Viking Coal
P
0
0
16.3
49.7
A
s
Sigma Mining
P
20.3
148.6
193.8
97.9
A
s
Kerr Coal
P
249.8
347.4
513.9
687.6
A
s
Arness-McGri ffi n
P
0
1.2
13.8
3.6
I
s
National King Coal
F
16.8
22.6
66.0
93.7
A
s
Peacock Coal
P
0.1
1.8
0
0.1
1
u
Menefe Land Co.
P
0
0
0
0
S
u
CF & I Steel
F
618.9
582.3
495.1
634.7
A
s
National Energy Res.
P
0
0
0
2.6
I
s
Delaqua
P
0
6.7
35.0
0
I
s
Delaqua
P
0
0
4.0
39.0
A
s
Horner Coal
P
12.8
96.0
18.3
0
I
u
Animas Coal
P
0
0
0
19.0
I
s
Horner Coal
P
17.8
25.6
6.1
0
I
u
CF & I Steel
P
0
31.8
86.9
125.4
A
Continued
-------
na
Mo
37
38
39
40
41
42
42
42
43
43
44
45
45
45
45
45
45
45
46
47
Table 3—Coal mines in Colorado—continued
Type
?f 3/
mi ne-
Operator
Type
of ,
leaser-
Production
1976 : 1977 : 1978 : 1979
Thousand tons
19804/
status-
u
GEX Colorado
P
0.1
0
0
31.8
A
u
Dorchester Colomine
P
0
0
0
1.1
I
u
GEX Colorado
P,F
57.1
300.2
449.7
827.8
A
s
Colowyo Coal
F
0
290.5
1109.6
1699.4
A
s
Utah International
S,C,F
0
345.9
1333.0
2328.7
A
s
Empi re
P
54.1
0
0
0
C
s
Empi re
P
0
0
242.1
42.9
A
s
Utah International
70.6
0
0
0
C
u
Empire
S
382.3
447.5
539.6
556.1
A
u
Empi re
F
0
0
79.1
173.0
A
s
Peabody Coal
P
97.9
94.4
102.4
121.8
A
u
Mid-Continent
F
115.5
58.4
38.7
46.1
A
u
Mid-Continent
P
108.9
123.2
137.9
139.3
A
u
Mid-Continent
P
132.4
232.5
161.2
147.1
A
u
Mid-Continent
P
268.9
208.1
225.5
208.2
A
u
Mid-Continent
P
263.1
298.4
318.2
268.3
A
u
Snowmass
P
0.5
7.5
15.7
18.9
A
u
Snowmass
P
0.2
8.4
19.6
14.0
A
u
Northern Coal
P
0
0
0
6.2
A
u
Sewanee Mining
F
0
8.8
36.0
83.0
A
Continued
-------
Table 3--Coal mines in Colorado—continued
County and mine :
Type
of 3/
mine-
: Operator
: Type
: of 1/
: lease^
: 1976
Production
: 1977 : 1978
: 1979 :
19804/
status—
: Map?/
: No.-
Thousand
tons
Routt
Apex #2
U
Sunland
F
14.2
10.4
14.4
0
I
48
Denton
Melner Coal
8.3
0
0
0
C
Edna
S
Pittsburg & Midway
P»F
1140.2
1094.3
962.8
1165.9
A
49
Energy #1
S
Energy Fuels
P,F
1478.2
3048.6
2909.3
2353.3
A
50
Energy #2
S
Energy Fuel s
F
1009.5
416.5
261.8
654.3
A
50
Energy #3
S
Energy Fuels
P
518.9
385.5
334.7
425.4
A
50
Grassey Creek
S
Rockcastle
P
0
0
17.0
127.4
A
51
Hayden Gulch
S
H-G Coal
P
0
0
0
378.3
A
52
Johnnies Mine
U
Lombardi Jr.
P
0
0
0
0
s
53
Meadows #1
S
Sun Coal
P
0
62.9
207.8
201.1
A
54
Middle Creek
u
Ener
Seneca II
s
Peabody Coal
S
1283.5
1291.0
1372.3
1611.8
A
56
K-400 Strip
s
KCF Associates
P
0
0
0
0
s
57
San Miguel
El der
u
Holland & Sons
P
0
0
0.2
0.4
I
Mad Jack
u
Tri-Island Mining
P
0
0
0
0.2
I
58
Weld
Eagle
Imperial Coal Co.
P
32.2
0
0
0
c
59
Lincoln
u
Imperial Coal Co.
P
34.6
105.1
72.9
0
c
60
1/ P= private
F= federal
S= state
C= county
X= not available
2/
See Figure 3
3/
U=
S= surface
underground
4/ A=
C=
1=
s=
active
closed
idle
started
Source: (J_, 13;, 1JL)
-------
COLORADO
5£06 tV/CA
Figure 3. Map of coal mines in Colorado
-------
Table 4--Future Colorado coal mines
Type
of Planned production
County & mine mine Operator 1980 1981 1982 1983 1984 1985 1990
Million tons
Delta
Fanners
U
Pittsburg & Midway
--
—
--
--
1.0
2.0
Garfield
Unnamed (2 mines)
U
Sheridan Enterprises
—
—
—
--
--
4.0
Gunnison
Mt. Gunnison
U
Arco
—
--
--
—
0.2
2.8
Jackson
Bourg
Unnamed
S
S
Flatiron Paving
AMCA
_
no information
2.0
2.0
2.0
Las Animas
Lorenci to
S/U
Freeport
—
—
—
—
0.2
0.6
0.6
Mesa
Cottonwood Creek
#1, 2
Coal Canyon
McGinley
U
U
U
Mid-Continent
Mid-Continent
Village Land
0.1
0.1
0.2
no information
no information
0.2 0.2
0.3
Moffat
Eagle #6 & 7
Sugarloaf
U
Empire Energy
Energy Fuels
—
_ —
0.8
0.9
1.0
1.0
1.5
2.0
1.5
2.5
Rio Blanco
Deserado
Meeker
U/S
Western Fuels
Consol
::
—
—
—
1.2
1.2
0.8
1.2
1.6
Routt
Fish Creek
Trout Creek
Trout Creek
U
u
u
Pittsburg & Midway
Pittsburg & Midway
Sun Coal
0.2
0.2
0.1
0.3
0.3
0.3
0.3
0.1
0.4
0.3
0.3
0.4
0.3
1.3
0.4
0.3
TOTAL
0.3
0.3
1.4
2.0
6.4
10.6
20.2
Source: Keystone Industry Manuals, Office of Surface Mining files, J7
-------
15
The trend toward siting coal consuming plants near raw material sources, rather
than at electric load centers, will ease Colorado's distance and cost problems.
Most expansion in Colorado's coal industry will take place west of the front
range.
Mine Employment
Table 5 summarizes mine employment, production and productivity for
Colorado from 1975 through 1979. The number of mines increased significantly
between 1975 and 1976 but has remained relatively stable since. The
number of underground mines increased by 19 in 1975-79 while there were
11 new strip mines.
The number of employees has increased rather steadily from 1,914 in 1975
to 4,366 in 1979, a 128 percent increase. Most of the increase came in strip
mining which increased from 399 employees in 1975 to 1,751 employees in 1979,
a 339 percent increase. Nearly one-half (46 percent) of the total number
of employees were employed in underground mining in 1979 but only 32 percent
of total production came from underground mines.
Table 5 also indicates that mines in Colorado are getting bigger. The
average number of employees per mine increased from 43 in 1975 to 59 in 1979.
Average production per mine increased from 186,000 tons in 1975 to 245,000
tons in 1979, a 32 percent increase. Almost all the increase came in the
strip mining portion of the industry. The number of employees in strip
mining more than doubled between 1975 and 1979 while the average production
per strip mine increased 40 percent.
Total average productivity per employee decreased by 216 tons over the
1975-79 period. This was a 4.9 percent decrease, nearly 0.5 per year. This
total average figure masked a substantial decrease in productivity in strip
-------
Table 5—Colorado
coal mine employment and
productivity,
1975-79
Category
1975
1976
1977
1978
1979
Number of Mines
45
60
68
67
74
Underground
30
38
47
41
49
Strip
14
20
19
26
25
Auger
1
2
2
0
0
Employees (number)
1,914
2,259
2,944
3,645
4,366
Underground
1,209
1,382
1,637
1,856
2,025
Surface
306
330
343
429
590
Strip
399
547
964
1,360
1,751
Production (tons)—''
8,364,326
9,461,513
11,971,143
14,359,399
18,134,726
Underground
3,468,148
3,348,634
4,243,375
4,542,864
5,860,866
Strip
4,896,178
6,109,626
7,726,604
9,816,535
12,273,860
Auger
0
3,253
1,164
0
0
Average days worked per mine
161
149
169
179
177
Man-hours worked
3,627,135
4,339,966
5,632,504
6,306,176
8,912,455
Daily production per miner (tons)
27
28
24
22
23
Daily capacity of all mines (tons)
44,382
63,500
70,835
80,220
102,456
Average employees per mine (number)
43
38
43
54
59
Underground
40
36
35
45
41
Strip
28
27
51
52
70
Average production per mine (tons)
185,874
157,692
176,046
214,319
245,064
Underground
115,605
88,122
90,285
110,802
119,610
Strip
349,727
305,481
406,663
377,559
490,954
Auger
0
1,626
582
0
0
Average production per employee (tons)
4,370
4,188
4,066
3,939
4,154
Underground
2,869
2,423
2,592
2,448
2,894
Strip
12,271
11,169
8,015
7,218
7,010
If These production numbers, obtained from State sources, do not agree with the numbers obtained
from Federal sources, shown in Table 7. The unexplained disparity is wide for 1975, 1976 and
1977. Differences for 1978 and 1979 are not great.
Source: (J,, 2, 3, _4, J5)
-------
17
mining; from 12,271 tons per employee in 1975 to only 7,010 tons in 1979, a
43 percent decrease. Underground mine productivity per employee remained
relatively stable over the period. An average employee in an underground
mine produced slightly less than one-half what his counterpart in a strip
mine produced in 1979 (2,894 tons vs. 7,010 tons).
Mine Land Disturbance and Reclamation
The acres of land disturbed per unit of production varies greatly between
underground and strip mines, and even between mines of the same type, because
of coal quality, depth of overburden, and thickness of the seam. The U.S.
Department of Agriculture Coal Use and Development Project at Colorado
State University has estimated land disturbance per million tons of pro-
duction (Table 6). The Project has determined that strip mines disturb
roughly three times as many acres per unit of production as underground
mines. Projections of coal production in Colorado indicate that about
750 acres will be disturbed annually by 1985. Each acre of land disturbed
to produce coal usually requires an acre of reclamation.
Table 6—Estimated land disturbance by Colorado coal production
Land
Area disturbance
Acres per
million tons
Strip mines
Northwest
49
West
46
Southwest
58
Underground mines
Northwest
18
West
20
Southeast
18
Projected, 1985, statewide
48
Source: U.S. Department of Agriculture Coal Use and Development
Project
-------
18
Distribution of Colorado Coal
Colorado coal was distributed to 12 states in 1975 (Table 7). By
1979 it was being distributed to 21 states. During that period Colorado
coal production doubled. Distribution within the state increased from 5.76
million tons in 1975 to 9.95 million tons in 1979. California, Colorado, and
Utah each used over one million tons of Colorado coal in 1975. By 1979 Illinois
and Indiana had joined that trio as the use of Colorado coal in the electric
utility industry increased. Arizona, Iowa, Mississippi, Nebraska, and Texas
were also big users of Colorado coal by 1979. Most Colorado coal used in
California and Utah was metallurgical grade.
Colorado Coal Consumption
Total consumption of coal in Colorado was 13.25 million tons in 1979
(Table 8). This was an increase of 10.30 million tons or 449 percent over
the 1960 consumption of 2.95 million tons. The majority of coal consumed
in Colorado in 1979 went to electric utilities (11.58 million tons or 87
percent). Electric utilities consumed 41 percent of the total in 1960.
Coal use by electric utilities increased 948 percent from 1960 to 1979 and
376 percent from 1971 to 1979. The industrial-commerical sector was the
second largest user in 1979. In 1960 it was the largest user, accounting
for 55 percent of total state consumption. The consumption in the industrial
sector has remained constant in the years from 1960 to 1978. Figure 4 indi-
cates the location of the major coal-burning facilities in 1979.
Residential, commercial, and transportation coal use was a small portion
of total coal use in 1960. Residential and commercial uses nearly disappeared
by 1975 but have since returned to nearly their 1960 levels. Transportation
-------
19
Table 7--Distribution of Colorado coal, 1975-1979
Destination
1975
1976
1977
1973
1979
Thousand tons
Arizona
1
_ -
8
518
California
1,070
1,175
1,171
925
1,029
Colorado
5,760
5,850
5,252
7,114
9,946
Idaho
--
—
11
17
11
Illinois
14
1,084
1,712
2,030
1,767
Indiana
2
20
259
524
1,210
Iowa
160
220
353
814
606
Kansas
--
—
19
92
—
Mexico
221
18
--
22
12
Michigan
42
—
—
3
Minnesota
101
—
11
5
Mississippi
—
—
—
256
664
Missouri
—
—
--
572
—
Montana
28
38
31
12
31
Nebraska
205
189
353
381
414
Nevada
13
50
37
71
New Mexico
--
18
1
30
87
Ohio
63
276
—
--
Oklahoma
—
—
—
—
9
Oregon
—
1
3
3
2
Pennsylvania
5
—
—
_
South Carolina
—
—
—
2
--
South Dakota
—
12
9
10
5
Tennessee
--
—
—
2
1
Texas
—
—
—
39
639
Utah
1,407
1,388
1,494
1,224
1,247
Washington
—
6
3
5
11
Wisconsin
—
—
--
9
—
Wyomi ng
—
10
1
—
Destinations not
9
2
7
_ __
revealable
Destination not
available
11
—
--
--
—
Coal used at mines
13
11
—
3
7
Net change in mine inventory
43
14
—
—
—
Total—
9,064
10,363
10,738
14,243
18,295
_1/ These production numbers, obtained from Federal sources, do not agree with
the numbers, obtained from the State sources, shown in Table 5. The
unexplained disparity is wide for 1975, 1976, and 1977. Differences for
1978 and 1979 are not great.
Source: (8, 9^ 10, 19, 20)
-- = no shipments reported
-------
20
Table 8—Consumption of coal energy by type, Colorado, 1960-1978
Year
Total
Residential
Commercial
Industrial
Transportation
Electric
utili ties
Thousand
short tons
1960
2,951
90
167
1,448
25
1,221
1961
3,293
95
177
1,628
8
1,386
1962
3,395
115
214
1,511
6
1,549
1963
3,811
94
174
1,714
7
1,823
1964
3,847
102
190
1,644
6
1,904
1965
4,242
112
207
1,736
6
2,181
1966
4,765
120
222
1,699
5
2,719
1967
4,781
95
176
1,530
4
2,977
1968
4,960
98
183
1,692
4
2,983
1969
4,610
110
204
1,418
2
2,877
1970
5,112
80
149
1,668
3
3,212
1971
4,611
78
145
1,309
2
3,077
1972
5,307
73
145
1,678
2
3,404
1973
6,301
63
116
1,742
1
4,379
1974
6,492
35
66
1,650
1
4,740
1975
7,602
7
14
1,870
0
5,710
1976
9,022
19
35
1,688
0
7,280
1977
10,692
28
53
1,774
0
8,837
1978
10,535
75
139
1,377
0
8,945
1979
13,252
58
— 1,617 ---
0
11,576
Source: (£, 1_1)
sector coal use declined to zero in 1975 when coal-fueled locomotives were
phased out. It is not expected to reappear. (However, both the Cumbres-Toltec
and Durango-Si1verton recreational scenic railroads are fueled by Colorado
coal).
Existing Coal-Fired Electric Generating Plants
Coal-fired electric generating plants are generally estimated to burn
about 3 million tons of coal per 1,000 megawatts of installed capacity.
Table 9 lists current coal-fired electric generating plants in Colorado.
Their locations are shown in Figure 4. The power plant sizes given are the
-------
COLORADO
Figure 4. Major Coal-Fired Facilities in Colorado 1979
-------
Table 9—Existing coal-fired electric generating plants in Colorado
Pov/er plant, town, Nameplate Amount Amount
utility and location capacity Year received burned Mine source Water source
MW Thousand
tons Percent
Arapahoe
232
1975
575.2
66
Edna
South Platte River
Denver
1976
607.9
72
Energy
Public Service Co. of Colorado
1977
931.2
94
Eagle
Denver County
1973
635.3
93
Lincoln
1979
853.1
11
Rosebud (WY)
Cameo
66
1975
157.4
GO
Edna
Highline Canal
Palisade
1976
168.7
53
Public Service Co. of Colorado
1977
176.6
52
Energy
Mesa County
1978
152.6
63
Bear
1979
162.2
1/
Apex #2
King
Edna
Cherokee
710
1975
2,517.5
79
Energy
South Platte River
Commerce City
1976
1,681.7
37
Belle Ayr (WY)
Public Service Co. of Colorado
1977
2,031.8
93
Eagle
Adams County
1978
1,919.4
98
Rosebud (WY)
1979
1,973.6
1/
Big Horn (WY)
Clark
42
1975
97.0
52
Cedar Canyon
Arkansas River
Canon City
1976
110.5
59
Twin Pines
Central Telephone Utility
1977
123.6
6(3
Fremont County
1978
137.3
81
1979
182.3
1/
Comanche
700
1975
1,607.5
99
Belle Ayr (WY)
St. Charles River
Pueblo
1976
2,638.5
100
Eagle Butte (WY)
Public Service Co. of Colorado
1977
2,537.5
100
Pueblo County
1978
2,817.3
100
1979
2,734.1
1/
Conti nued
-------
Table 9—Existing coal-fired electric generating plants in Colorado—continued
Power plant, town,
utility and location
Nameplate
capaci ty
Year
Amount
received
Amount
burned
2/
Mine source —
Water source
MW
Thousand
tons
Percent
Drake, Martin
262
1975
458.5
67
Edna
Colorado Springs
Colorado Springs
1976
685.3
89
Empi re
Colorado Springs Public Utilities
1977
891.0
90
Sunflower
El Paso County
1978
727.5
99
Colowyo
1979
1,016.6
1/
Corely S & A
Eagle #5
Hayden
460
1975
645.1
100
Seneca
Yampa River
Hayden
1976
934.2
100
Colorado-Ute Electric Assn.
1977
1,068.0
100
Routt County
1978
1,553.0
100
1979
1,692.0
11
Nucla
37
1975
101.9
100
Nucla
San Miguel River
Nucla
1976
96.7
100
Colorado-Ute Electric Assn.
1977
93.1
100
Montrose County
1978
101.3
100
1979
119.0
1/
Valmont
274
1975
230.9
33
Energy
City of Boulder
Boulder
1976
265.5
43
Rosebud (WY)
Public Service Co. of Colorado
1977
462.4
66
Eagle
Boulder County
1978
508.8
71
1979
435.3
1/
1/ Not available
2J The mine source does not apply to any specific year and may not be an exhaustive list for each plant.
Source: Federal Energy Regulatory Commission Form 423 data for 1975-79. The utility companies report
slightly different data. Plants with units totaling less than 25 MW are not included. Examples
are the Bullock, Oliver and Walsen plants.
-------
24
nameplate ratings. The actual generation capacity varies with quality and
type of fuel used, elevation and temperature, and pollution control tech-
nology.
Most coal-fired power plants in Colorado are 100 percent coal burning.
Some use supplementary gas or oil. The amount of coal burned annually in 1975
through 1979 is given in Table 9. The Colorado mines listed as the coal
sources were described earlier in this report. The transportation system for
coal distribution is discussed subsequently. Water consumption is also des-
cribed below and is generally estimated between 6 and 7 lb. of water per lb.
of coal.
According to Table 9, in 1979 the Public Service Company of Colorado
burned approximately 6,158,300 tons of coal. Colorado-Ute Electric Assn.
burned 1,811,000 tons, Colorado Springs Public Utilities burned 1,016,500
tons, and Central Telephone Utilities burned 182,300 tons of coal. Approxi-
mately 9.2 million tons of coal were burned during 1979 by Colorado utility
companies in large units to generate electric power.
New Coal-Fired Electric Generating Plants
There are four new coal-fired electric generation plants planned for
Colorado in 1980-1985 (Table 10 and Figure 4). These power plants will all be
100 megawatts or greater in nameplate capacity. Six units are scheduled for
operation at the four power plant location sites.
The Colorado-Ute Electric Association, Inc. is planning two more units to
join the Craig 1 unit located at Craig in Moffat County. Unit 2 began oper-
ation in early 1980 and has a nameplate capacity of 400 megawatts. Unit 2
will require 1,225,000 tons of coal per year. All its coal is to be supplied
by the Utah International Trapper Mine located in Moffat County, making this
-------
Table 10—Proposed new coal-fired electrical generation capacity 100 megawatts or greater, Colorado,
1980 to 1990.
Utility and
plant
Operating
date
: County
: Town :
: Coal : Coal source
Capacity: required: State : County : Mine
: Water
: source
Year
MW Tons
Colorado
-Ute Electric Association, Inc.
Craig 1
1980
Moffat
Craig
400 1,225,000 Colorado Moffat Trapper
Yampa River
Craig 2
1980
Moffat
Craig
400 1,225,000 Colorado Moffat Trapper
Yampa River
Craig 3
1983
Moffat
Craig
400 1,225,000 Colorado Moffat Colowyo
1/
Southwestern
1988
Del ta
Delta
800 3,000,000 Colorado Garfield Unnamed
1/
or Mesa
or Mesa
Craig 4
1990
Moffat
Craig
400 1,225,000 Colorado Moffat Trapper
1/
Colorado Springs Department of Public Utilities
R.D. Nixon 1
1980
El Paso
Fountain
200 750,000 Colorado Moffat Colowyo
Ground water
R.D. Nixon 2
1988
El Paso
Fountain
350 767,000 Colorado Moffat Colowyo
Transmountain
Diversion
Public Service of Colorado
Pawnee 1
1981
Morgan
Brush
500 1,600,000 Wyoming Campbell Belle Ayr
South Platte via
Eagle Butte
new reservoir
Pawnee 2
1987
Morgan
Brush
500 1,600,000 1/ 1/ 1/
South Platte
Southeastern
#1
1988
1/
1/
500 1,600,000 1/ 1/ 1/
1/
Southeastern
#2
1990
1/
1/
500 1,600,000 1/ 1/ 1/
1/
Platte River Power Authority
Rawhide 1
1985
Larimer
Wellington
250 800,000 Wyoming Converse NERC0 Inc.
Colorado River via
transmountain
diversion
JV Unknown
Source: Scenario tables are generated from multiple sources and maintained by researchers at Colorado State
University. All units, especially those scheduled for more distant years, are subject to delay or
cancellation.
-------
26
a mine mouth operation. Units 1 and 2 get their cooling water from the Yampa
River. The Colorado-Lite Electric Association is also planning a third unit for
operation in 1983. This unit will also be 400 megawatts in capacity and will
use approximately 1,225,000 tons of coal per year. Coal for this third unit,
and additional coal for units 1 and 2, will be obtained from the Colowyo mine
near Axial, Colorado. A water source for this third unit has not been
identified. Colorado-Ute is also planning a fourth unit at the Craig Station
for 1990 and a unit in Delta or Mesa County in 1988. The operating dates for
these latter two units is very uncertain.
The Colorado Springs Department of Public Utilities is planning two
units for the R.D. Nixon plant at Fountain, Colorado in El Paso County. The
first unit is to be operational in 1980. It is a 200 megawatt unit using
750,000 tons of coal per year. This coal is scheduled to be obtained from
the Colowyo mine located in Moffat County. The water source for the two units
will be ground water wells and transmountain diversion return flows. Unit 2
of the Nixon plant is scheduled for operation in 1988. It will be a 350
megawatt unit using at least 767,000 tons of coal per year. The mine source
has not been determined.
Public Service of Colorado is planning one new coal-fired electric
generation plant in the 1980-1985 period. Unit 1 of the Pawnee plant will be
located near Brush in Morgan County. It is scheduled for operation in
1981. It will be a 500 megawatt unit requiring 1,600,000 tons of coal annually.
The coal is scheduled to come from the Belle Ayr mine in Campbell County,
Wyoming and possibly from a mine in Utah. The water source will be the South
Platte River via a new reservoir now being planned. The scheduled operating
date for the second unit of the Pawnee plant is 1987. It will also be a 500
megawatt unit using approximately 1,600,000 tons of coal annually. The coal
is also expected to come from the Belle Ayr mine in Campbell County, Wyoming.
-------
27
Public Service of Colorado is also planning two units to be located
somewhere in southeastern Colorado. Each unit will be 500 megawatts in
capacity and use approximately 1,600,000 tons of coal annually. The coal is
likely to come from'Wyoming. The water source for these units is not known.
The Platte River Power Authority is planning a unit for the Rawhide
Plant to be located near Wellington in Larimer County. This unit is scheduled
for operation in late 1984 or early 1985 and will be 250 megawatts in capacity.
It will use approximately 800,000 tons of coal annually from the Northern Energy
Mine in Converse County, Wyoming. Water will be from the Upper Colorado River
via a transmountain diversion.
Industrial Coal Use
Consumption of coal by the industrial sector has declined for several
years (Table 8). This is the result of increasing dependence by the sector
on electric utilities for energy. However, in 1976 and 1977, the industrial
sector used 1,688 and 1,774 thousand tons,respectively (18.7 and 16.6 percent
of total coal use). (_U) Table 11 lists in-state and out-of-state industrial
users of Colorado coal in 1976 and 1977. Table 12 lists the same information
for institutional users.
Water Uses in Steam Electric Generation
Water is used in all aspects of the conversion of coal to electricity. It
is a primary input to all processes from mining the coal to the electric energy
end product. This section describes the major water uses involved in the coal-
fired generation of electric power. There are three major uses in fossil-
fired electric generation plants besides process conversion.
Cooling
Water serves as the primary medium for the transfer of heat from the con-
version process to the outside environment. The ability of a given generation
-------
Table 11—Industrial users of Colorado coal, 1976 and 1977
Company : Location : Mine source
Adolph Coors Company
Golden, CO
Lincoln, King, Eagle
Great Western Sugar
Fort Morgan, CO
Edna
Great Western Sugar
Greeley, CO
Edna
Great Western Sugar
Loveland, CO
Edna
Corn Products
CPC International, Inc.
Pekin, IL
Ideal Basic Cement
Florence, CO
Ideal Basic Cement
Ft. Collins, CO
CF & I Steel
Pueblo, CO
Hawk's Nest, Wise Hill #5
Colorado Fuel & Iron Co.
Pueblo, CO
Hawk's Nest, Wise Hill #5
U.S. Steel
Orem, UT
Somerset, Bear Creek, Coal Basin, Dutch Creek
1 & 2, L.S. Wood
CF & I Coke Plant
Pueblo, CO
Allen, Maxwell
U.S. Steel
Fontana, CA
Bear Creek, Coal Basin, Dutch Creek 1 & 2,
L.S. Wood
American Smelting & Refining
Helena, MT
Bear
Holly Sugar
Delta, CO
Bear
Kennecott Copper
McGill, NV
Bear
Henderson Mil 1 (AMAX)
Henderson, CO
Marr Strip #1
Cumbres-Toltec Railroad
Antonito, CO
King
Durango-Si1verton Railroad
Durango, CO
King
Ash Grove Cement
Louisville, NE
Edna
Great Western Sugar
Gering, Bavard, NE
Edna
Celanese Chemical, W.R. Grace Pampa, TX
Hayden Gulch (1979)
Source: (_7)
Table 12 —Institutional users of Colorado coal, 1976
Company :
Location :
Mine source
Colorado State Penitentiary
Canon City, CO
Black Diamond
Colorado State Hospital
Pueblo, CO
Black Diamond
Pueblo Army Depot
Pueblo, CO
Bear
Iowa State University
Ames, IA
Canadian Strip
Colorado School for Deaf & Blind
Colorado Springs, CO
Healey Strip
Nucla School District
Nucla, CO
Nucla
Source: (_7)
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29
plant to effectively remove heat is a major determinant of the generating
efficiency of the plant. If heat cannot be effectively removed the efficiency
of the conversion process will be lower, thereby increasing the cost of gener-
There are four types of cooling systems presently in use.
1. Once-through-cooling where water is withdrawn from a source,
used for cooling, then returned to the source.
2. Cooling ponds or canals where a stationary body of water is
used as the source of withdrawal and the water, when returned
to the source, dissipates the heat to the atmosphere.
3. Wet cooling towers where water is withdrawn from a body of
water, circulated through condensers, pumped into towers, and
allowed to fall in small droplets. The water is usually
collected and recycled through the plant. The term "make-
up" water applies to this method because a portion of the
water evaporates during the process and must be replaced.
Wet cooling towers consume more water than do once-through-
cooling or cooling pond systems. Consumptive use varies
with ambient weather conditions. A further distinction is
made between mechanical and natural draft towers. Mechanical
draft towers use fans to increase the movement of air through
the tower while natural draft towers are designed to allow
efficient movement of air without mechanical assistance.
4. Dry cooling towers employ the same concept as wet (evaporative)
cooling towers except that air is used as the transfer medium.
Towers can be mechanical or natural draft. Dry cooling also
depends greatly on ambient air conditions which affect the
ability of the generation plant to operate efficiently, i.e.,
the ability of warm air to "take-on" additional heat is limited.
Cooling systems may be used in combination, depending on local conditions.
Wet and dry cooling towers may be used simultaneously in arid areas. The
basic determinant of the cooling system installed is availability of water
and its associated cost.
Ash Sluicing
The removal of ash resulting from the burning of coal provides another
demand for water. Ash (slag) collects at the bottoms of the furnaces and
water serves as a means of removal. Water also may be used to remove fly ash,
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30
i.e., the ash that escapes with the hot gases of the stack after the coal
is burned. The amount of ash removal (bottom and fly) depends on the ash
content of the coal being burned.
The amount of water required for ash removal is significantly less than
for cooling. Water is mixed with ash and the resulting sludge is piped to
settling ponds. After the water evaporates ash is disposed. Several ash
disposal systems allow for partial recovery of the water. There are also
other systems of ash disposal with differing water requirements. Projections
of water use for this purpose should reflect the method of ash disposal
planned for the unit.
Flue Gas Desulfurization
Water is also used to remove particulates and sulfur dioxide gases
generated as coal is burned. The efficiency of sulfur dioxide removal
depends on the type of scrubbing process and the scrubbing agent.—^
Existing and Future Water Requirements
This section examines the water use and consumption of existing plants
(Table 13) and the expected demands of coal-fired plants scheduled for
operation by 1985 (Table 14). Primary water demands and consumptive uses, in
addition to the conversion process, include cooling of waste heat, ash
sluicing (ash removal from boilers and furnaces), and flue gas desulfurization
(sulfur dioxide and particulate removal from stack gases). Table 13 identifies
withdrawal, consumption, discharge, and sources of water for coal-fired power
3/ Knowledgeable industry executives indicate that the cost of removing
the smaller quantity of SO in low sulfur coal is much greater on a per unit
basis than with high sulfur coal. Thus, 90 percent removal from high sulfur
coal is cheaper and easier than 90 percent removal from low sulfur coal.
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31
Table 13--VJater use in coal-fired electric generation plants over 100 megawatts
in Colorado, 1975.
Plant
Nameplate
plant
capaci ty
Water
withdrawal
: Water
: di s-
: charge
: Water
: con-
: sumption
: Source :
Type of
cooli ng
s.ystem3/
MW
Cubic feet per
second
Drake
263
2.3
0.4
1.9
Municipal
CP,CT
Hayden
190
5.4
1.0
4.4
Yampa R.
CT
Arapahoe
250
4.1
0.9
3.2
S. Platte R. CT
Cherokee
801
31.4
14.9 1/
16.5 1/
S. Platte R
CT
Comanche
765
6.3
2.1
4.2
St. Charles
R. CT
Valmont
281
4.5
2.4
2.1
Reservoi r
CP
Total
2,555
54.1
21.6
32.5
Acre-feet pe
r year 2/
39,158
15,634
23,523
1/ The discharge and consumption of water varied considerably from the data
reported for 1973 for the same plant.
2] Based on conversion of cubic feet per second to acre-feet per year.
3/ CP = cooling ponds
CT = cooling towers
Source: Federal Energy Regulatory Commission, 1975 Form 67 computer data tapes
and information provided by utilities.
plants 100 megawatts or greater in 1975. A cubic foot per second (CFS) is
equivalent to 723.8 acre-feet per year. Total water withdrawal for the six
existing plants (assuming that requirements and consumption do not vary greatly
from year to year) is 39,150 acre-feet per year. Consumption is 23,500 acre-
feet per year and discharge is 15,600 acre-feet per year.
Two of the six existing Colorado plants use cooling ponds in combination
with wet cooling towers. The remaining four plants have cooling towers.
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32
Table 14--Projected coal-fired electric generation plants over 100 megawatts in
Colorado.
Plant
Uni ts
Plant
capaci ty
Water
withdrawal
Water Water Type of
1/ discharge 2/ consumption 2/ cooling
No.
MW
—Cubic feet per
second
Nixon
1
200
4.1
1.6
2.5
tower
Craig
3
1200
20.3
0
20.3
tower
Pawnee
1
500
10.3
4.1
6.2
tower
Rawhide
I
250
4.7
1.9
2.8
tower
Total
6
2,150
39.4
7.6
31.8
Acre-feet
28,500
5,500
23,000
1) Estimates of total water demands (from various published sources) of
coal-fired plants utilizing wet cooling towers range from 9,300-15,200 acre-
feet per MW of generating capacity. Plants utilizing cooling towers in
Colorado in 1975 used approximately 15,000 acre-feet per MW.
2) Based on the current discharge and consumption rates of existing
plants in Colorado, a gross estimate of discharge is 40 percent. The Craig
units are zero discharge units.
Wet cooling tower techniques result in substantial quantities of water being
consumed (approximately 60 percent of total withdrawal in 1975) relative
to other cooling methods such as once-through-cooling. National rates do not
reflect the high rate of consumption demonstrated in Colorado. Since the
majority of coal-fired plants in the U.S. in 1975 utilized once-through-
cooling (181 of 297 plants over 100 MW), national consumption rates are lower.
However, future trends indicate increased use of cooling towers due to
competing water uses and increased costs of acquiring sufficient water resources.
Plants employing wet cooling towers are the greatest users of water in terms
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33
of consumptive rates. Consumptive rate becomes an important issue because
this water is removed from the source and not returned. Thus downstream
users, such as agriculture, nave less available for their use.
Current projections indicate that 6 coal-fired units with a total mega-
watt capacity of 2,150 will be constructed by 1985. Table 14 identifies each
plant and unit and estimates the consumptive water use. All future plants are
designed to utilize mechanical cooling towers.
Water, important in the process conversion of fossil fuels to electric
power, also serves a primary role in cooling and removal of other wastes.
Since the Clean Air Act of 1970 and the Water Act of 1972 electric power
utilities and companies have had to comply with stringent Federal air and
water quality standards. Utilities have been forced to install equipment to
reduce or eliminate thermal and air pollution from new and existing plants.
The consumptive use of water associated with new coal-fired steam
electric plants in Colorado depends on two interdependent factors. These
factors, in order of importance, are thermal efficiency and plant design. All
of the 6 new units projected for Colorado are expected to use wet cooling
towers. When all 6 units are constructed, annual water withdrawal requirements
for process conversion, cooling, ash disposal, and flue gas scrubbing is
estimated to be 28,500 acre-feet. The amount of water evaporated (consumptive
use) ranges between 60 and 80 percent and could reach 90 percent as technology
advances (i.e., zero discharge designed units such as the Craig units).
Estimated annual consumptive use ranges from 17,000 to 28,500 acre-feet,
equivalent to annually applying 12 inches of water to 24,000 irrigated acres
(assuming an 80 percent evaporative rate). — Water consumption by thermal
TJ These estimates are based on criteria discussed in Davis, George H. and
Leonard A. Wood, Water Demands for Expanding Energy Development, Geological
Survey Circular 703, U.S. Department of Interior, Washington, D.C., page 8.
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34
generation plants is expected to increase relative to withdrawal. Greater
emphasis on thermal and air pollution control has contributed to increased
consumption of water. Projected fresh water withdrawals are expected to reach
a maximum about 1985 and then decrease slightly by the year 2000 as more plants
5/
utilize closed evaporative systems. —
Solid Waste Removal
Water also plays a major role in the removal and disposal of wastes
generated at coal-fired electrical power plants. Table 15 indicates the major
coal and chemical solids used for treatment of water in Colorado's six large
coal-fired plants. It also lists quantities of disposable wastes. The primary
inputs include coal, oil, and/or natural gas, and the chemicals used in cooling
and boiler water makeup. The primary waste, for which water serves as a
transfer medium, is ash (top-stack and bottom-boiler). Waste heat is a form
of waste but difficult to capture. —
The total reported solid wastes from the six plants in 1975 was 450,400
tons of ash. Solid waste as a percent of total coal and chemicals used
averaged 11.2 percent for the six facilities. Waste heat loss in 1975 was
19,350 billion Btu (excluding the Drake plant), equivalent to 967,500 tons
of coal with an average energy content of 10,000 Btu per lb. (18 percent
of the total coal utilized in 1975. If technology were available to capture
the waste heat plant efficiencies would be increased substantially (estimated
14 to 15 percent). This could result in a plant efficiency rate of 45 to 55
percent compared to the present 30-40 percent rate.
37 U.S. Water Resources Council, Supplemental Reports to the Second
Annual National Water Assessment - Water for Energy, Number 1, 2120 L~Street
N.W., Washington, D.C., 1978, p. 3.
6/ Waste heat is unused heat which escapes through equipment, air, and
water.
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Table 15--Existing and projected solid inputs, wastes, and waste head for coal-fired power
plants in Colorado
Plant
Category
: Uni t
: Drake
: Hayden
:Arapahoe:Cherokee:Comanche:
Valmont
: Total :
1975-85
n /
Percent
Sol id input —
Coal
Thousand tons
441.6
648.1
645.1
2,151.1
1,218.4
179.8
5,284.1
Oil
Thousand gallons
0
266
0
0
1,425.8
0
1,691.8
Natural gas
Billion cubic feet
4.430
0
7.065
12.131
0.036
7.365
31.027
Cooling makeup
Tons-chemicals
4.67
85.72
2.50
92.32
533.77
13.50
732.48
Boiler makeup
Tons-chemical
0.15
59.90
4.68
9.51
174.89
1.06
250.19
Sol id wastes
Ash disposal
Thousand tons
42.9
68.2
52.8
199.6
71.8
15.1
450.4
Thousand tons
(42.9)
(160.0)
(15.9)
(161.3)
(119.8)
(25.4)
(525.3)
+16.6
Air Emissions
Sulfur oxides
Thousand tons
6.4
5.8
7.3
22.4
34.9
3.0
79.8
Thousand tons
(6.4)
(4.7)
(2.4)
(17.5)
(31.9)
(4.9)
(67.8)
-15.0
Nitrogen oxides
Thousand tons
4.0
2.1
7.3
21.7
11.1
3.1
49.3
Thousand tons
(4.0)
(5.2)
(1.9)
(15.8)
(17.1)
(2.8)
(64.5)
+30.8
Waste heat
Trillion Btu
N/A
1,037
3,478
8,307
4,332
2,196
19,350
Trillion Btu
(2,560)
(841)
(5,751)
(7,057)
(1,341)
(17,550)
-9.3
JV The numbers in parenthesis represent estimates of wastes.
2J Drake plant is excluded from total. Waste heat losses are via stack gases.
3/ Most input numbers do not agree with data furnished by the utilities during the manuscript review process.
Source: Federal Energy Regulatory Commission Form 67, 1975, and data provided by utilities.
CO
en
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36
Coal Preparation
Coal preparation, benefication, or cleaning refers to the removal of ash,
sulfur (inorganic) and other impurities (rock, dirt, etc.) from coal. With
the implementation of stringent emission standards the physical cleaning of
coal has increased. Coal preparation is not a costly process when compared to
retrofitting a power plant with pollution control equipment. Coal character-
istics, however, vary tremendously from state to state, from seam to seam, and
even within a seam. Therefore, each preparation facility must be designed
specifically for coal with certain characteristics.
Water is a very important input in the coal preparation processes. Most
coal cleaning utilizes water as a medium to remove impurities. Coal is lighter
than most impurities and can be separated. Impurities chemically bound to
coal cannot be removed by cleaning (such as organic sulfur). Therefore, the
characteristics of certain coals may not be improved by cleaning.
Colorado has two coal preparation facilities. They are the Imperial Coal
Company plant located at the Erie mine and Mid-Continent Coal and Coke plant
located at Carbondale (Coal Basin Preparation Plant). Data is not available
concerning the amount of coal being cleaned or the amount of water being used.
The process used by the Erie mine plant is heavy media washers and centrifuges
while the Coal Basin plant uses a heavy media washer and flotation units.
Both plants require water to separate the impurities from the coal.
Coal Transportation in Colorado
Railroads are the dominant means of transporting coal in Colorado (Figure 5
and Table 16). In general, it is concluded that the railroad's capacity to haul
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FIGURE 5
MAJOR COAL RAIL LINKS IN COLORADO
to
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38
Table 15--Major coal transportation rail links in Colorado
Counties
Connecting Points
Number
of
Tracks
Signal
System
Owni ng
Rail road
Mesa
Utah-Grand Junction
1
CTC
DRGW
Mesa, Garfield
Grand Junction-Glenwood Springs
1
CTC
DRGW
Garfield, Eagle
Glenwood Springs-Dotsero
1
CTC
DRGW
Eagle
Dotsero-Bond
1
CTC
DRGW
Eagle, Lake Chaffee
Dotsero-Pueblo
1
CTC
DRGW
Fremont, Pueblo
(Dotsero/Canon City/Pueblo)
1
CTC
DRGW
Eagle, Grand, Gilpin,
Bond-Denver
1
CTC
DRGW
Jefferson
Denver, Adams, Weld,
Denver-Brush
1
CTC
BN
Morgan, Logan
Logan
Brush-Peetz
1
ABS
BN/UP
Washington, Yuma
Brush-Wray
1
CTC
BN
Denver, Arapahoe,
Denver-Pueblo
Douglas, El Paso,
(70 miles)
ABS
DRGW/ATSF
Pueblo
(30 miles)
1
CTC
DRGW/ATSF
Pueblo
Pueblo-east of Avondale
2
CTC
MP/ATSF
Crowley, Kiowa
east of Avondale-Towner
1
ABS
MP
Otero
east of Avondale-La Junta
1
ABS
ATSF
Otero, Bent
La Junta-Las Animas
1
ABS
ATSF
Prowers
Las Animas-Kansas border
1
ABS
ATSF
Bent, Baca
Las Animas-Oklahoma border
1
none
ATSF
Pueblo, Huerfano
Pueblo-Walsenburg
none
CS/DRGW
Huerfano, Las Animas
Walsenburg-Trinidad
1
ABS
CS
Las Animas
Trinidad-Branson
1
none
CS
Weld, Adams, Denver
Carr-Denver
1
CTC
UP
Las Animas
Allen Mine-Trinidad
1
none
CS
Mesa, Delta
Oliver-Grand Junction
1
none
DRGW
Garfield, Pitkin
Woody Creek-Glenwood Springs
1
none
DRGW
Moffat, Routt
Craig-Bond
1
none
DRGW
NOTES: Abbreviations
ABS = automatic block signals
CTC = centralized traffic control
ATSF = Atchison, Topeka & Santa Fe Railway
BN = Burlington Northern Railroad
CS = Colorado & Southern Railroad (BN subsidiary)
DRGW = Denver & Rio Grande Western Railroad
MP = Missouri Pacific Railroad
UP 3 Union Pacific Railroad
Source: ,(26)
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39
coal in and through Colorado by 1935 will be sufficient due to the excess
capacity that currently exists and the financial capabilities of the relevant
railroads. However, sufficient capacity does not imply a lack of serious
impacts. Railroads cause delays at grade crossings, accidents, and right-
of-way disturbances. Considerable grade crossing delays are currently being
experienced along the front range and such delays will increase as coal use
increases unless this problem is mitigated.
Highway trucking of coal is commonly used by small mines for moving
coal distances averaging less than 50 miles. Less than 10 percent of
Colorado's coal production involves highway trucking. Highway transportation
of coal will continue to be a factor for small mines and users not located
on rail lines. Electricity can also be generated in a plant at or near the
mine site and transported to the consuming region via high voltage trans-
mission lines.
Two coal slurry pipelines are currently in the planning stages
which could have an impact on Colorado. One is the Energy Transportation
Systems Incorporated (ETSI) pipeline which may pass through Colorado.
The other is the San Marco pipeline. The ETSI pipeline is planned to
transport Wyoming coal to utilities located in Arkansas and Louisiana.
The San Marco pipeline is to transport primarily Colorado coal to Texas
utilities. There is significant opposition to slurry pipelines by
railroads, environmental groups, and labor groups. The two main issues
concerning slurry pipelines are water usage and right-of-way problems.
Colorado is located on rail routes between several coal producing
and consuming regions. The major east and southeast rail route serving
coal regions in eastern Utah runs through Colorado, a major segment of
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40
which is owned by the Denver and Rio Grande Western Railroad. In theory,
Utah coal moving east could be transported via the Union Pacific railroad
through southern Wyoming. This does not occur because the Denver and Rio Grande
Western, which also services coal fields in eastern Utah, has a longer haul
on its own lines by moving coal directly east rather than passing it off
in Utah to the Union Pacific Railroad.
East and southbound coal movements from Northwest Colorado will move
through Denver using the Moffat Tunnel instead of the Tennessee Pass
route for several reasons. The Tennessee Pass route is longer and requires
more trains and crews than the Moffat Tunnel route to points east and
south and, secondly, the connection of the rail line from Craig to the main
line at Bond is physically configured so that westbound movements from the
branch line require numerous switching movements. The Moffat Tunnel route
is currently more economical. As traffic increases on that segment, it may
become more economical to route the empty coal trains returning to the Craig
line via the Tennessee Pass.
Existing eastbound capacity should be sufficient to accommodate all
levels of projected 1985 movements of Utah and Colorado coal. The existing
capacity cushion of east-west trackage will be nearly exhausted under high
development scenarios. However, it is reasonable to assume that rail
improvements will be made permitting capacity to accommodate traffic
requirements.
Existing main line capacity on currently used north-south coal routes
will be exhausted on links north of Sterling and south of Walsenberg by
1985. But it is reasonable to conclude that Burlington Northern will expand
the capacities of these two links as needed (26). The rail link between
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41
Denver and Pueblo will bear all Montana and Wyoming coal traffic passing
through Colorado. The existing capacity of this link can accommodate highest
projected 1985 flows although a large number of coal trains will require
some changes in present operating procedures.
Cone!usions
The primary demand for Colorado coal is for steam-electric power generation.
Historically, electrical energy needs of Colorado's residents has been met by a
comparatively small regional coal industry. Production of Colorado coal for
electrical generation, both in-state and out-of-state, in 1979 was approx-
imately 14.66 million tons. The generation capacity of coal-fired plants
within the state was 2,852 megawatts in 1979 requiring 11.576 million tons
of coal. Over 26 percent of this demand was supplied by mines in Wyoming.
The status of the coal industry in Colorado will change significantly by
1985. The demand for Western coal will continue to increase because of low
production costs, low sulfur content, higher regional electrical demand stemming
from rapid growth, and the establishment of a synthetic fuels industry. Colorado
utility coal demand will increase from 5.71 million tons in 1975 to approximately
15.4 million tons in 1985, an increase of 270 percent. Colorado utilities
plan to add 2,530 megawatts of capacity of which 2,150 megawatts are to be coal-
fired. The magnitude of this growth is evident when comparing the 1975 coal-
fired capacity, 2,555 megawatts, with the projected 1985 capacity of 4,705
megawatts. In spite of the rapid growth in Colorado coal production, large
quantities of coal are contracted from out-of-state sources, primarily Wyoming.
The major impacts of coal development in Colorado will be confined to the
producing areas. Nearly 91 percent (3.211 million tons) of 1975 Colorado
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42
steam-coal production originated in Moffat and Routt Counties in northwestern
Colorado. In 1985, however, these counties will supply only 79 percent of state
production as new mines begin production in other areas of the state. A majority
of the increased production will be located in the west-central area of the
state, primarily in Gunnison, Pitkin, Delta, Montrose, and Garfield Counties.
These counties will increase their steam-coal production from 1,300 tons in
1975 to approximately 2.865 million tons in 1985. Another area projected to
experience increased production is the northern front range.
A discussion of specific impacts is beyond the scope of this report.
Generally, underground coal mining requires a large labor component. Therefore,
those areas with large projected increases in underground mining (west-central
Colorado) can anticipate substantial inflows of labor with accompanying
increased demands for public services. Since only minor land disturbances are
associated with underground mining, significant effects on agriculture or other
competing land uses are not anticipated.
The impacts resulting from the surface mining of coal are quite different
from those of underground mining. Because of the more capital intensive nature
of surface mining and relatively small labor requirements, the employment
impacts will not be as severe. Land disturbance, however, is of major concern.
Present estimates are for approximately 750 additional acres to be disturbed
annually by 1985. All but 63 of these acres are concentrated in Moffat and
Routt Counties.
The factors affecting these projections are numerous. It is probable that
steam plant operation schedules will suffer delays. These delays may lower
1985 production levels. Other factors such as rail rate changes, surface mine
reclamation regulations, federal leasing policies and air and water quality
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43
regulations could have major impacts on the rate of growth and importance of
Colorado coal.
The Colorado Energy Research Institute has recently published energy
production projections for the 19801s for Colorado. (2_1) They project 27 million
tons of coal to be produced in 1985 and 28.6 million tons to be produced in
1990. They state that increases in Colorado's coal production during the next
ten years are likely to be less than what some popular analyses have portrayed.
This will be due mainly to a weak market for Colorado coal and the lag time
between market shifts and production requirements. They believe there will not
be enough demand in the 1980's to purchase the amount of coal presently avail-
able from existing Colorado coal mines, currently proposed mines, and federal
lease sales.
The Institute also believes that underground production will surpass
surface production by 1986. The major reasons for this reversal are the
depletion of strippable reserves in northwest Colorado and the increase in
underground production from both northwest and west-central Colorado. They
believe that demand for metallurgical coal will remain stable through 1990.
The importance of Colorado coal has been clearly demonstrated by the
statistics presented. However, Colorado coal does not appear to have an
overwhelming competitive advantage when compared to Wyoming. Therefore,
Colorado coal production is likely to increase but not as rapidly as pro-
duction in other western states.
The demand for electricity in Colorado is likely to increase very rapidly
as a result of growing population numbers and greater levels of industrial
activity. Additions to electric generating capacity are likely to be coal-
fired but not all new units will utilize Colorado coal.
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44
BIBLIOGRAPHY
1. Colorado Division of Mines. A Summary of Mineral Industry Activities in
Colorado 1977 Part 1: Coal. April 1978.
2. . A Summary of Mineral Industry Activities in Colorado 1978
Part 1: Coal. April 1979.
3. . A Summary of Mineral Industry Activities in Colorado 1979
Part 1: "CoaT April 1980.
4. . Coal 1975. April 1976.
5. . Coal 1976. April 1977.
6. . State Coal Mine Inspections Monthly Report(s). 1977-1980.
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Source Book. Colorado Geological Survey, 1978.
8. Department of Enerqy. Bituminous Coal and Lignite Distribution Calendar
Year 1978, D0E/EIA-0125/4Q78. April, 1979.
9. . Bituminous and Subbiturn nous Coal and Lignite Distribution
Calendar Year 1979, D0E/EIA-0125(79/40). April, 1980.
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11. . State Enerqy Data Report. DOE/EIA-0214(78) Energy Infor-
mation Administration. April 1980.
12. . Western Coal Development Monitoring System. D0E/RA-0045.
October 1979.
13. Department of the Interior. Federal Coal Management Report FY '79.
March 1980.
14. . Final Environmental Statement: Federal Coal Management
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15. . Mineral Industry Surveys. "Bituminous Coal and Lignite Distri-
bution Calendar Year 1975," Bureau of Mines. April 12, 1976.
16. . Office of Surface Mining. File Data from Region V office.
August 1980.
17. Environmental Protection Agency, Office of Energy. Existing and Proposed
Surface and Underground Coal Mines Region VIII Summary^ EPA-908/4-79-001.
EPA Rocky Mountain-Prairie Region. February 1979.
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45
18. Kolstad, Charles D. The 1975 Energy Production System in ths States of the
Rocky Mountain Region. Los Alamos Scientific Lab., December 1976.
19. Lin, King. Coal Traffic Annual 1973. National Coal Association, 1979.
20. . Coal Traffic Annual 1979. National Coal Association, 1980.
21. Martin, Joan E. Colorado Energy Production for the 80's. Colorado Energy
Research Institute. February 1980.
22. . Colorado Energy Fact Book 1980/81. Colorado Energy Research
Institute. 1980.
23. Martin, Joan E. and others. Colorado Energy Production for the 80's.
Colorado Energy Research Institute. 1980.
24. Murray, Keith 0., 1979 Summary of Coal Resources in Colorado. Colorado
Geological Survey. 1980.
25. Parker, Gary E. and George Boulter. Region 8 1977 Power Plant Summary.
EPA-908/4-78-002. U.S. Environmental Protection Agency. March 1978.
26. The 3R Corporation. Report: Coal Transportation in Colorado: An Analysis.
Colorado Energy Research Institute. June 1979.
27. URS Company. Coal Train Assessment Final Report. Four Corners Regional
Commission. December 15, 1976.
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