EPA-450/3-77-017a
March 1977
IMPACT OF NATURAL GAS
SHORTAGE ON MAJOR
INDUSTRIAL FUEL-BURNING
INSTALLATIONS -
VOLUME I. TEXT
.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
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EPA-450/3-77-017a
IMPACT OF NATURAL GAS SHORTAGE
ON MAJOR INDUSTRIAL
FUEL-BURNING INSTALLATIONS -
VOLUME I. TEXT
by
J.A. Brickhill
Energy Division
Foster Associates, Inc.
1101 Seventeenth Street, NW
Washington, D.C. 20036
Contract No. 68-02-1452
EPA Project Officer: Rayburn Morrison
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
March 1977
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This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - in limited quantities - from the
Library Services Office (MD-35), Research Triangle Park, North Carolina
27711; or, for a fee, from the National Technical Information Service,
5285 Port Royal Road, Springfield, Virginia 22161.
This report was furnished to the Environmental Protection Agency by the
Energy Division, Foster Associates, Inc., 1101 Seventeenth Street, NW,
Washington, D.C. 20036, in fulfillment of Contract No. 68-02-1452. The
contents of this report are reproduced herein as received from Foster
Associates, Inc. The opinions, findings, and conclusions expressed are
those of the author and not necessarily those of the Environmental Protec-
tion Agency. Mention of company or product names is not to be considered
as an endorsement by the Environmental Protection Agency.
Publication No. EPA-450/3-77-017a
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ACKNOWLEDGEMENTS
This study was prepared under the direction of John
Brickhill by the Energy Division of Foster Associates.
Paul Wilkinson acted as assistant task manager and Wayne
Mikutowicz acted as technical reviewer for the study. Other
technical personnel participating in the preparation of «
the study were Isobel Bowen, Warren Crane, George Warholic,
and Ghislaine Zon.
Without the input of the Energy Strategies Branch of
EPA, the chapter dealing with emissions could not have been
prepared. Rayburn Morrison and C. Hai Kuo expended considerable
effort to provide the necessary data base to Foster Associates.
As well, the Federal Energy Administration, Office of Coal
Utilization, provided the basic MFBI information pertaining
to major combustors and aid with respect to the analysis
thereof. We thank John Dean and his staff from that office
for their assistance.
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VOLUME ONE
TABLE OF CONTENTS
Page
INTRODUCTION i
SUMMARY vi
CHAPTER I - GAS DEMAND AND SUPPLY PROJECTIONS FOR I-l
MAJOR MFBI GAS COMBUSTORS
Determination of Demand for Gas by 1-2
Major MFBI Gas Combustors
Comparison of the MFBI Supply Forecasts 1-6
with Other Studies
Gas Supply Assumptions and Methodology 1-10
Projected Gas Consumption and Short- 1-15
ages by AQCR and AQMA
CHAPTER II - ALTERNATIVE FUEL USE AS A RESULT OF II-l
GAS SHORTAGES IN MAJOR MFBI GAS
COMBUSTORS
Methodology and Assumptions II-l
Projected Alternative Fuel Use by AQCR II-6
and AQMA
CHAPTER III - PROJECTION OF INCREMENTAL EMISSIONS III-l
OF SULFUR DIOXIDE AND PARTICULATE
MATTER RESULTING FROM SHORTAGES OF
GAS IN MAJOR MFBI GAS COMBUSTORS
General Assumptions and Data Used to III-l
Determine Emissions
Calculation of Sulfur Dioxide Emis- III-6
sions
Calculation of Particulate Matter III-8
Emissions
Summary of Estimated Incremental 111-13
Emissions
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Page
CHAPTER IV - NATURAL GAS SUPPLY AND CONSUMPTION
IN THE UNITED STATES IV-1
Natural Gas Consumption in the U.S. IV-1
The Role of Natural Gas in Fulfilling
Energy Requirements by Sector in
the U.S. IV-5
Trends Underlying the Current Gas
Shortage in the U.S. IV-10
Recent Natural Gas Pricing Developments IV-14
Comparison of Forecasts of U.S. Gas
Supply IV-19
The GRC Forecast of Consumption IV-23
Sources of Gas Supply by State IV-24
Direct Sales of Natural Gas to MFBI
in 1974 by Interstate Pipelines IV-33
Individual Pipeline Supply Situations IV-36
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INTRODUCTION
The end result of this study is an estimate of the
incremental emissions of sulfur dioxide and particulate
matter from major industrial gas combustors resulting from
gas supply inadequacy between 1976 and 1980. To reach
this end result, three separate but nonetheless interrelated
analyses were performed. Natural gas supply and demand were
projected for 1087 industrial plants containing major gas
combustors; at plants where gas shortages were projected,
the use of alternative fuels by type was estimated; and
reflecting the use of the alternative fuels, increases in
emissions of sulfur dioxide and particulate matter were
calculated based upon federally enforceable air pollution
regulations. Natural gas is the cleanest burning fossil
fuel, containing negligible sulfur and ash compared with
coal and fuel oil. Thus, as a result of the gas shortage -,
emissions of sulfur dioxide and particulate matter will be
higher than if more gas were available.
Data on the fuel^burning characteristics of the gas
combustors dealt with in this study were obtained from a 1975
survey of large, primarily industrial fuel-burners conducted
by the Federal Energy Administration (FEA). Included in the
category of industrial plants are some Federal, state and local
facilities as well as a few universities and hospitals.
Specifically excluded from this study are electric utility
power plants and a few liquefied-natural-gas and synthetic-
natural-gas facilities owned by gas utilities. The results
of the FEA survey were made available to Foster Associates
through the Environmental Protection Agency.
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The FEA survey was intended primarily for determining
the coal-burning potential of industrial combustors; the
FEA questionnaire was entitled "Major Fuel Burning Install-
ation Coal Conversion Report." The coverage of this study
reflects the limitations of the FEA survey. FEA requested
data on 1973/1974 fuel consumption and the capability to
burn alternate fuels only for combustors with a heat input
capacity of at least 100 million Btu per hour. This means
that the data which the surveyed plants reported to FEA
were not designed to reveal the plant's total fuel use, total
gas use, nor total capability to burn alternate fuels; it
also means that surveyed plants which had no combustor of the
capacity described did not report any fuel use or alternate
fuels capability. Since, however, gas use in large combustors
would normally be curtailed first and the large combustors
represent the larger potential polluters, this study provides
a good estimate of potential increases in pollutant emissions
s
through 1980.
The following table summarizes the coverage of the
industrial sector represented by the major— gas burning MFBI
analyzed herein. Column (2) shows the number of major gas burn-
ing MFBI in each state; Column (3) shows gas consumption in
the major gas combustors of those MFBI; Column (4) shows the
percent of total industrial gas consumption in that state
represented by the major gas combustors; Column (5) shows the
total fossil fuel consumption (gas, fuel oil and coal) in the
major gas combustors of these MFBI; and Column (6) shows the
percent of total industrial fossil fuel consumption in that
state represented by the major gas combustors. The regional
totals in Columns (4) and (6) indicate the percent of total
industrial gas consumption and total industrial fossil fuel
consumption in that region represented by major gas combustors.
I/ A major MFBI is one which contains at least one corn-
Bus tor with a capacity of 100 MMBtu/hr.
11
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Summary Table 1
Sheet 1 of 2
COMPARISON OF GAS AND TOTAL FOSSIL FUEL CONSUMPTION OF
MAJOR GAS BURNING MFBI WITH TOTAL INDUSTRIAL GAS AND
FOSSIL FUEL CONSUMPTION BY STATE IN 1974
EPA Region/State
(1)
Number
of
Plants
(2)
GL.S tonsumptli.n oy Major
MFBI
Percent of
Total
Industrial
Trillion Gas
Btu's Consumption
(3) (4)
Fossil Fuel Consumption .
by Major Gas Combustors—
Percent of
Total
Industrial
Trillion Fossil Fuel
Btu's Consumption
(5) (6)
Region I
Connecticut
Massachusetts
Maine
New Hampshire
Rhode Island
Vermont
Total
Region II
New Jersey
New York
Total
Region III
District of Columbia
Delaware
Maryland
Pennsylvania
Virginia
West Virginia
Total
Region IV
Alabama
Florida
Georgia
Kentucky
Mississippi
North Carolina
South Carolina
Tennessee
Total
Region V
Minnesota
Wisconsin
Michigan
Ohio
Illinois
Indiana
Total
Region VI
Arkansas
Louisiana
New Mexico
Oklahoma
Texas
Total
Region VII
Iowa
Kansas
Missouri
Nebraska
Total
3
10
13
13
26
21
28
59
56
60
33
257
25
15
17
8
65
n/
14
7
21
48
31
32
13
55
12
23
40
254
40
466
8
47
988
1,549
30
26
20
11
87
5.62
12.7
74.5
3.7
10.0
20.5
22.7
14.7
16.5
21.3
16.8
25.9
35.8
19.5
17.5
50.7
13.8
29.1
24.9
26.9
28.8
18.9
33.1
24.6
25.4
31.4
27.4
n/.
11
27
14
41
41
32
34
13
120
1.2S
4.6
7.7
n/
2.9
12.9
17.6
21.6
8.9
18.6
15.3
31.5
21.
15.
30.
20,
26.0
39.3
26.4
23.6
40.4
24.2
40.5
40.3
39.2
25.4
20.2
22.7
19.2
22.3
FA-20847
-iii-
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Summary Table 1
Sheet 2 of 2
COMPARISON OF GAS AND TOTAL FOSSIL FUEL CONSUMPTION OF
MAJOR GAS BURNING MFBI WITH TOTAL INDUSTRIAL GAS AND
FOSSIL FUEL CONSUMPTION BY STATE IN 1974
Gas Consumption by Major
MFBI
EPA Region/State
(1)
Region VIII
Colorado
Montana
North Dakota
South Dakota
Utah
Wyoming
Total
Region IX
Arizona
California
Nevada
Total
Region X
Idaho
Oregon
Washington
Total
10
89
2
101
10
17
29
56
Trillion
Btu's
(3)
31
16
1
1
28
27
104
28
• 186
2
216
10
14
61
85
Percent of
Total
Industrial
Gas
Consumption
(4)
58.52
42.2
29.0
8.4
58.1
56.9
52.7
46.9
31.7
16.8
32.8
31.4
25.2
58.8
44.2
Fossil Fuel Consumption .
by Major Gas Combustors^
Percent of
Total
Industrial
Trillion Fossil Fuel
Btu's Consumption
(6)
(5)
59
19
2
1
59
42
182
14
21
77
112
71.3%
32.2
12.4
9.9
61.6
56.1
53.9
47.5
28.9
14.5
30.3
29.6
21.4
46.3
35.9
Total Lower 48 States
1.087
2,871
33.02
3,784
29.42
a/ Excludes fossil fuel consumption by non-gas combustors of gas burning MFBI.
n/ Negligible.
FA-20847
-iv-
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As shown on the table, gas consumption by the major gas
combustors represents one-third of total industrial gas
consumption in the Lower 48 States.— Many of these com-
bustors also consume other fuels, and the major gas combustors
represent 29 percent of total industrial fossil fuel con-
sumption. Coverage varies significantly by EPA Region,
representing only 10 percent of Region I's industrial gas
consumption and 12 percent of Region II, but ranging as high
as 40 percent in Region VI, 44 percent in Region X, and 53
percent in Region VIII.
The results of this study are summarized in the imme-
diately succeeding section. Following the Summary are the
texts of Chapters I, II, III and IV, respectively detailing
the gas supply and demand forecasts, the alternative fuel
use estimates, the emission calculations and background
information on national and regional gas situations. The
schedules of data described in Chapters I to IV are con-
tained in Volume Two. Volume Three is an appendix which
analyzes and summarizes the data pertaining to the fuel
consumption characteristics of not only gas burning com-
bustors but also combustors which do not consume gas.
_!/ Unfortunately there are no data on the gas or energy
consumption of the combustors with capacity less than 100
MMBtu/hr. at these 1087 plants. These plants probably con-
sume -nearly as-much gas~ in smaller combustors as in the
larger. Thus it is estimated that these 1087 plants may be
responsible for between one-half and two-thirds of total
industrial gas consumption in the U.S.
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SUMMARY
This study projects a severe and worsening shortage
of natural gas in the United States to 1980. In the aggregate,
industrial gas consumption will decline sharply between 1974
and 1980, and gas shortages will steadily rise at the 1087
industrial plants analyzed in this study. Both boilers and
other types of combustors, even some without existing alter-
nate fuel capabilities will be affected. To maintain opera-
tions, industrial plants will have to use alternate fuels.
Consequently, emissions of sulfur dioxide and particulate
matter will increase.
This study projects by plant the annual gas shortages,
associated use of alternative fuels, and resultant emission
increases from 1976 to 1980. These estimates are displayed
and calculated to reflect the net increase over 1974 levels.
Thus, the volumetric gas shortages for 1976 to 1980 do not
include any shortages which may have existed in 1974, the
base year; the amount of alternative fuel use projected
equates to the amount of gas shortage and thus does not
include the volume of alternative fuels which was used in
1974 by these combustors; and the emissions are the incre-
mental increase over 1974 levels as a result of the gas
shortage.
The table on the following two pages summarizes the
projected gas shortages in major MFBI gas combustors by
state and EPA Region.
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Summary Table 2
Sheet 1 of 2
PROJECTED GAS SHORTAGES IN MAJOR MFBI GAS COMBUSTORS BY STATE,
1976 - 1980
(Trillions of Btu's)
1974
Gas Shortages
EPA Region/State Consumption 1976 1977 1978 1979 1980
Region I
Connecticut 0.9 0.3 0.3 0.4 0.5 0.5
Massachusetts 3.9 1.1 1.2 1.4 1.8 1.9
Maine
New Hampshire 0.7
Rhode Island
Vermont
Total 5.5 1.4 1.5 1.8 2.3 2.4
Region II
New Jersey 14.3 3.0 3.8 4.1 4.4 4.6
New York 6.5 1.4 1.4 1.0 0.9 0.9
Total 20.8 4.4 5.2 5.1 5.3 5.5
Region III
Delaware 1.2 0.3 0.3 0.3
Maryland 13.7 4.4 5.2 4.9
Pennsylvania 51.9 9.8 12.2 13.5
Virginia 8.6 5.4 6.6 7.1
West Virginia 16.6 1.5 1.1 1.5
Total 92.0 21.4 25.4 27.3 29.3 31.5
Region IV
Alabama 47.6 14.1 21.0 23.0 26.7 30.5
Florida 31.2 10.9 11.4 13.2 13.6 14.2
Georgia 32.1 3.7 6.4 5.2 7.6 10.2
Kentucky 13.5 4.2 5.3 6.1 6.6 7.4
Mississippi 54.7 6.1 9.3 11.9 12.6 14.2
North Carolina 11.6 7.7 9.2 11.0 11.6 12.1
South Carolina 2.3.3 3.1 5.3 4.9 5.6 7.7
Tennessee 39.5 18.5 22.9 25.2 26.7 28.5
Total 253.5 68.3 90.8 100.5 111.0 124.8
Region V
Illinois 96.2 5.6 10.3 26.6 37.9 44.4
Indiana 84.0 4.3 11.1 21.1 27.2 33.4
Michigan 115.1 9.0 17.9 23.6 27.0 29.7
Minnesota 28.4 2.1 3.5 5.2 7.1 7.7
Ohio 107.1 23.3 24.6 23.3 24.4 26.9
Wisconsin 25.8 0.5 6.2 7.8 8.9 10.9
Total 456.6 44.8 73.6 107.6 132.5 153.0
Region VI
Arkansas 40.0 8.3 9.3 10.7 11.7 12.6
Louisiana 465.5 6.6 9.7 12.8 16.3 20.0
New Mexico 8.2 1.0 1.7 2.3 2.4 2.5
Oklahoma 47.4 — — _____
Texas 988.4 — — 16.9 50.9 96.3
Total 1,549.5 15.9 20.7 42.7 81.3 131.4
Region VII
Iowa 30.0 2.5 6.3 8.3 , 8.3 10.3
Kansas 26.5 5.5 7.5 9.0 10.2 11.8
Missouri 20.2 2.8 3.3 4.5 5.2 5.9
Nebraska 11.0 0.3 0.9 1.0 1.2 1.4
Total 87.7 11.1 18.0 22.8 24.9 29.4
-vii-
FA-20959
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Summary Table 2
Sheet 2 of 2
PROJECTED GAS SHORTAGES IN MAJOR MFBI GAS COMBUSTORS BY STATE,
1976 - 1980
(Trillions of Btu's)
EPA Region/State
1974
Gas
Consumotion 1976
Shortages
1977
1978
1979
1980
Region VIII
Colorado
Montana
North Dakota
South Dakota
Utah
Wyoming
Total
Region IX
Arizona
California
Nevada
Total
Region X
Idaho
Oregon
Washington
Total
31.6
15.9
0.9
0.6
27.8
27.1
103.9
28.0
185.7
2.1
—
7.6
0.4
0.4
2.0
1.7
12.1
8.3
10.1
0.2
1.1
9.9
0.4
0.6
—
1.2
13.2
11.1
40.7
0.3
2.0
10.2
0.4
0.6
—
2.6
15.8
15.0
56.6
0.3
2.9
10.5
0.5
0.6
1.6
4.4
20.5
16.8
79.6
0.3
3.7
10.9
0.5
0.6
3.6
6.0
25.3
17.5
82.9
0.3
215.8
18.6
85.4
52.1
0.7
6.9
7.6
71.9
1.2
8.3
9.5
96.7 100.7
1.2
7.9
0.5
7.4
9.1
7.9
Total Lower 48 States
2,870.7
203.4 308.1 405.0 512.9 611.9
Note: In some cases the projected shortage can exceed actual 1974 consumption due to
increased demand.
n/ Negligible.
-viii-
FA-20959
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The first column of data shows the 1974 gas consumption
of major MFBI gas combustors by state, followed by the pro-
jected gas shortages annually from 1976 to 1980. For example,
in Connecticut, major MFBI gas combustors consumed 0.9
trillion Btu's in 1974, and the gas shortage in these com-
bustors is expected to be 0.3 trillion Btu's in 1976 increasing
annually to 0.5 trillion Btu's in 1980. The shortages shown
reflect the arithmetic difference between supply of and
demand for gas by these combustors.
For all major MFBI combustors in the U.S., the volumetric
gas shortage is shown to triple between 1976 and 1980.
These growing shortages reflect the compounded effect of
declining supplies and increasing demand.
Demand for gas by major combustors at MFBI is tied to
projections of economic activity and overall industrial energy
demand for the Nation in the aggregate. For purposes of
this study, demand for gas at MFBI is calculated to reflect
the same trend as industrial demand for energy in general.
The gas supply forecasts for individual plants are
situation specific, and reflect available public information..
Overall, however, it was assumed that conventional gas pro-
duction from wells in the Lower 48 States would continue
to decline to 1980 but the rate of decline would be lower
than that experienced in 1974 and 1975 due to a projected
increase in new supply. Since onshore exploration for gas
has increased substantially in response to the rapid rise
in intrastate field prices, and since it is assumed that
offshore drilling will increase due to the recent rise in
-ix-
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interstate price levels for new gas, an increase in reserves
additions compared to the last few years is forecast. The
projections also incorporate supplemental gas (LNG, SNG from
liquid hydrocarbons and Canadian gas), but not in sufficient
volume to offset the shortage.
The gas supply and demand forecasts were constructed
on an annual basis assuming normal weather. Moreover, it was
assumed that gas companies will have sufficient storage and
peaking capacity to meet all residential and small commercial
requirements under these weather conditions. To the extent
that weather is abnormally cold, as it has been during the
1976-1977 winter, the industrial gas shortages will be even
more severe. Although there may be sufficient gas on an
annual basis to cover an industrial plant's needs, unexpected
capacity and supply difficulties can occur and cause sub-
stantial economic dislocation which is not reflected or
analyzed in this-study. This study assumes that all gas
shortages are offset by consumption of alternative fuels, as
shown by the table on the following two pages which sum-
marizes the increased use of alternative fuels by state and
EPA Region.
*
Column (2) shows the annual average alternative fuel
use, which equates to the annual average gas shortage.
Columns (3) through (6) depict the percent distribution of
this alternative fuel use among residual oil, distillate oil,
coal and other (primarily LPG). For example, in Connecticut,
increased alternative fuel use will average 0.4 trillion
Btu's per year in major MFBI combustors to make up for the
-x-
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Summary Table 3
Sheet 1 of 2
THE DISTRIBUTION OF ALTERNATIVE FUEL USE BY TYPE AS A RESULT
OF GAS SHORTAGES IN MAJOR MFBI GAS COMBUSTORS
BY EPA REGION AND STATE
1976 - 1980
EPA Region/State
(1)
EPA Region I
Connecticut
Massachusetts
Maine
New Hampshire
Rhode Island
Vermont
Total
EPA Region II
New Jersey
New York
Total
EPA Region III
Delaware
Maryland
Pennsylvania
Virginia
West Virginia
Total
EPA Region IV
Alabama
Florida
Kentucky
Georgia
Mississippi
North Carolina
South Carolina
Tennessee
Total
EPA Region V
Illinois
Indiana
Michigan
Minnesota
Ohio
Wisconsin
Total
EPA Region VI
Arkansas
Louisiana
New Mexico
Oklahoma
Texas
Total
EPA Region VII
Iowa
Kansas
Missouri
Nebraska
Total
Annual Average
Alternative Fuel
Use
(Trillions of ,
Btu's) - Residual
(2)
0.4
1.5
1.9
4.0
1.1
5.1
0.3
5.1
13.2
6.8
1.6
27.0
99.1
24.9
19.4
21.5
5.1
24.5
6.9
102.3
10.5
13.1
2.0
32.8
58.4
7.1
8.8
4.4
0.9
Percent Distribution by Fuel Type
Distillate Coal Other
(6)
(3)
(4)
(5)
96.37.
100.0
99.2
100.0
85.5
96.9
100.0
56.4
68.9
72.6
39.5
66.1
72.6
73.2
37.
77.
66.
83.
80.
50.5
66.3
67.8
60.
37.
74,
62.
21.2
43.3
57.6
82.8
66.9
91.9
34.6
52.5
22.7
75.0
75.0
54.1
3.7%
0.8
14,5
3.1
43.6
26.4
11.2
32.3
25.8
3.8
25.8
49.1
5.9
28.7
7.6
6.8
31.8
19.6
7.0
8.2
18.6
15.6
25.7
47.6
17.3
17.2
32.5
8.1
65.4
47.4
21.4
0.8
3.8
100.0
12.8
4.7%
16.2
28.2
8.1
23.6
13.1
16.2
9.3
12.5
.17.7
13.4
19.7
30.7
43.5
10.1
11.8
9.1
23.7
55.9
24.2
21.2
33.1
1.0%
5.1
0.7
5.5
0.2
1.4
0.6
0.1
FA-20958
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Summary Table 3
Sheet 2 of 2
THE DISTRIBUTION OF ALTERNATIVE FUEL USE BY TYPE AS A RESULT
OF GAS SHORTAGES IN MAJOR MFBI GAS COMBUSTORS
BY EPA REGION AND STATE
1976 - 1980 •
Annual Average
Alternative Fuel
Use
(Trillions of . Percent Distribution by Fuel Type
EPA Region/State Btu's) - Residual Distillate Coal Other
(1) (2) (3) (4) (5) (6)
EPA Region VIII
Colorado 1.9 38. BZ 9.6% 51. 6%
Montana 9.8 41.6 58.4
North Dakota 0.5 100.0
South Dakota 0.6 100.0
Utah 1.4 1.7 95.3
Wyoming - 3.2 88.2 11.8 —
Total 17.4 49.9 44.4 5.7
EPA Region IX
Arizona 13.7 54.8 39.9 5.3
California 54.0 69.2 25.3 5.1 0.42
Nevada 0.3 — 100.0 — —
Total 68.0 66.0 28.6 5.1 0.3
EPA Region X
Idaho „/ — n/ „/
Oregon 0". 7 92.2 T.8 ~£ Q
Washington 7.2 66.6 33.4 -- —
-xii-
Total 7.9 68.8 30.6 0.6
Total Lower 48 States 408.3 61.4% 25.5% 12.5% 0.6%
n/ Negligible.
a/ Equates to annual average gas shortage from 1976 - 1980.
FA-20958
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annual average gas shortage of an equal amount. Residual
oil is shown to comprise 96.3 percent of this increased fuel
use in Connecticut.
For the Nation as a whole, residual oil is depicted as
making up for 61.4 percent of the gas shortage, distillate
oil for 25.5 percent, coal for 12.5 percent, and other for
0.6 percent. Considerable diversity occurs by plant, state
and region. Residual oil is the predominant alternative to
gas in many states, and coal use is dominant only in Michigan,
Iowa, and Colorado. Distillate oil is dominant in Kentucky,
Wisconsin, Texas, Nebraska, Montana, Utah and Nevada.
The selection of alternative fuels to gas at MFBI was
based on what the individual plants reported as of the end
of 1974. In cases where a combustor had no existing alter-
nate fuel capability, conversion to the fuel used by similar
plants was assumed.
The table on the following two pages sets out the
projected annual alternative fuel use by type in conventional
units.
-xiii-
-------
Summary Table 4
Sheet 1 of 2
ANNUAL AVERAGE INCREASE IS ALTERNATIVE FUEL USE AS A RESULT OF GAS
SHORTAGES IN MAJOR MFBI GAS COMBUSTORS EXPRESSED IN CONVENTIONAL UNITS
EPA Region I
Connecticut
Massachusetts
Maine
New Hampshire
Rhode Island
Vermont
Total
EPA Region II
New Jersey
New York
Total
EPA Region III
Delaware
Maryland
Pennsylvania
Virginia
West Virginia
Total
EPA Region IV
Alabama
Florida
Kentucky
Georgia
Mississippi
North Carolina
South Carolina
Tennessee
Total
EPA Region V
Illinois
Indiana
Michigan
Minnesota
Ohio
Wisconsin
Total
EPA Region VI
Arkansas
Louisiana
New Mexico
Oklahoma
Texas
Total
Residual Oil
(Thousands
of Barrels)
(1)
61
238
__
—
300
632
149
781
52
455
1,442
786
101
2,836
2.663
1,475
356
820
1,139
1,363
683
1,957
10,457
2,691
1,880
1,292
604
2,438
472
9,378
1,387
1,391
290
1,807
4,876
1976 - 1980
Distillate Oil
(Thousands
of Barrels)
(2)
3
--
3
27
27
380
595
131
90
1,196
149
561
499
67
532
133
62
1,329
3,333
299
273
685
137
1,081
560
3,035
312
729
?s
*O
3,682
4,750
Coal
(Thousands
of Tons)
(3)
—
"I
25
/ /•
44v^
18
87
220
31
43
39
27
173
533
198
240
376
21
117
25
976
_—
*™ —
__
LPG
(Thousands
of Barrels)
(4)
~™
~""
— —
— —
~
—
~
-.—
II
__
31
138
169
343
11
354
21
—
— ~
21
FA-30036
-xiv-
-------
Summary Table 4
Sheet 2 of 2
ANNUAL AVERAGE INCREASE IN ALTERNATIVE FUEL USE AS A RESULT OF GAS
SHORTAGES IN MAJOR MFBI GAS COMBUSTORS EXPRESSED IN CONVENTIONAL UNITS
1976 - 1980
Residual Oil
(Thousands
of Barrels)
(1)
Distillate Oil
(Thousands
of Barrels)
(2)
Coal
(Thousands
of Tons)
(3)
LPG
(Thousands
of Barrels)
(4)
EPA Region VII
Iowa
Kansas
Missouri
Nebraska
Total
EPA Region VIII
Colorado
Montana
North Dakota
South Dakota
Utah
Wyoming
Total
EPA Region IX
Arizona
California
Nevada
Total
EPA Region X
Idaho
Oregon
Washington
Total
259
1,050
519
1,828
119
649
72
89
4
445
1,379
1,199
5,944
7,142
104
761
865
263
12
29
162
466
32
985
244
65
1,325
943
2,340
50
3,333
1
2
412
416
161
86
37
284
40
40
29
112
140
~2
2
49
49
Total Lower 48 States
39, SAO
17,883
2,063
594
Btu Contents: Residual 6,287,000 Btu/Bbl; Distillate 5,825,000 Btu/Bbl;
Coal 24,835,00/ short ton; LPG 4,011,000 Btu/Bbl.
n/ Negligible.
FA-30036
-------
Summary Table 5 on the following two pages shows the
projected annual average incremental emissions of sulfur
dioxide and particulate matter resulting from gas shortages
to major combustors at the 1087 MFBI from 1976 through 1980
by state. The annual average incremental increase in sulfur
dioxide emissions for the total Lower 48 States is shown to
be 370 thousand tons per year, as compared with 48 thousand
tons per year of particulate matter. The areas with the
greatest increases are of course those with the greatest gas
shortages, as well as those with more lenient emission
regulations. Nearly 40 percent of the total increase in
emissions is attributable to Region IV, while 20 percent is
attributable to Region V and 11 percent to Region IX.
The emission increases were calculated assuming that
fuels substituted for gas would emit at the maximum allowable
level as stipulated in the applicable federally enforceable
regulations. A brief summary of the results of this study
organized by EPA Region, is set out following the table.
-xvi-
-------
Summary Table 5
Sheet 1 of 2
A.VNXVJ. AVERAGE INCREMENTAL EMISSIONS OF SULFUR DIOXIDE
AND PARTICULATES AS A RESULT OF GAS SHORTAGES
IN MAJOR MFBI GAS COMBUSTORS BY STATE
1976 - 1980
(Tons Per Year)
EPA Region/State
(1)
Region I
Connecticut
Massachusetts
Maine
New Hampshire
Rhode Island
Vermont
Total
Region II
New Jersey
New York
Total
Region III
District of Columbia
Delaware
Maryland
Pennsylvania
Virginia
West Virginia
Total
Region IV
Alabama
Florida
Kentucky
Georgia
Mississippi
North Carolina
South Carolina
Tennessee
Total
Region V
Illinois
Indiana
Michigan
Minnesota
Ohio
Wisconsin
Total
Region VI
Arkansas
Louisiana
New Mexico
Oklahoma
Texas
Total
Region VII
Iowa
Kansas
Missouri
Nebraska
Sulfur
Dioxide
(2)
111
1,012
20,590
149;699
Total
71,911
8,512
24,108
941-
12,340
11,512
6,094
1.180
31,126
Partlculates
(3)
39
90
129
218
50
268
49
249
1,121
562
63
2,044
10,593
11,268
3,485
-xvii-
FA-20963
-------
Summary Table 5
Sheet 2 of 2
ANNUAL AVERAGE INCREMENTAL EMISSIONS OF SULFUR DIOXIDE
AND PARTICULATES AS A R£SULT OF GAS SHORTAGES
IN MAJOR MFBI GAS COHBUSTORS BY STATE
1976 - 1980
(Tons Per Year)
Sulfur
EPA Region/State Dioxide ' Particulates
(1) <2) (3)
Region VIII
Colorado
Montana
North Dakota
South Dakota
Utah
Wyoming
Total 9,503 2,-702
Region IX
Arizona 6.160 534
California 29,516 10.364
Nevada 22
Total 35,698 10,948
Region X
Idaho 6 . 2
Oregon 632 12Q
Washington 7,594 430
8,232 602
Total Lower 48
States 369,990 48,153
-xviii-
FA-20963
-------
Region I
The incremental increases in sulfur dioxide and par-
ticulate emissions are minimal in Region I, projected at
1.1 and 0.1 thousand tons per year, respectively. Region
I is heavily dependent on fuel oil, and gas supplied only
5 percent of the total energy consumed by all major com-
bustors in this region in 1974. Residual fuel oil is expected
to be substituted for virtually all gas shortfalls. However,
the incremental increase in alternate fuels for Region I
represents less than 1 percent of the total increase in
alternate fuel consumption for the Lower 48. Roughly half
of the Region I increases are concentrated in the Boston AQMA.
Region II
The projected annual increases in emissions are also
relatively small in Region II — 1.0 thousand tons of sulfur
dioxide and 0.3 thousand tons of particulate. Region II is
similar to Region I in that residual fuel oil is the major
source of energy for large combustors. Also, the sample
accounts for only about 11 percent of industrial gas con-
sumed in these regions, indicating that most gas is consumed
in smaller combustors. Another factor influencing the low
emission levels in these two regions is that emission regula-
tions are relatively stringent. The New Jersey-New York
AQMA accounts for nearly three-fourths of all incremental
emissions projected for Region II, with the lion's share
attributable to the New Jersey portion.
-xix-
-------
Region III
The annual increases in Region III are projected at 21
thousand tons per year of sulfur dioxide and 2 thousand tons
per year of particulate, 5 percent of the Lower 48 total
increase. Gas shortages are projected to average 27 trillion
Btu,1 s per year, approximately one-third of the region's gas
consumption by major combustors in 1974. Fuel oil will be
substituted for 25 of the 27 trillion Btu shortfall. Nearly
80 percent of the emissions increases in Region III are from
Pennsylvania and Virginia. Substantial increases are fore-
cast for the Petersburg-Colonial Heights-Hopewell AQMA in
Virginia, as well as the Southwest Pennsylvania AQCR.
Region IV
Gas consumption by major MFBI combustors is projected
to decline by 41 percent in Region IV from the 1974 level of
254 trillion Btu's. This severe decline will necessitate
the substitution of some 99 trillion Btu's per year of
alternate fuels — 66 trillion Btu's of residual fuel oil,
20 trillion Btu's of distillate fuel oil, and 13 trillion
Btu's of coal. It is estimated that the substitution of
these fuels for gas will increase sulfur dioxide emissions
by 150 thousand tons per year, and particulate emissions by
11 thousand tons per year. The fact that alternate fuel
consumption in Region IV represents 24 percent of the Lower
48 total but sulfur dioxide emissions represent 40 percent
of the Lower 48 total is indicative of the generally more
lenient emission regulations in these 8 states. Nearly half
of the estimated emissions increases are forecast for Alabama
and Tennessee.
-xx-
-------
Three AQMA in Region IV are shown to have sulfur dioxide
emissions in excess of 5 thousand tons per year: Birmingham,
Mobile and Savannah. Relatively high sulfur dioxide emissions
are also forecast for 3 AQCR: Mobile-Pensacola-Panama City-
Southern Mississippi (36 thousand tons per year); Metro
Memphis (21 thousand tons per year); and East Tennessee (15
thousand tons per year).
Region V
The gas consumption by major MFBI combustors in Region
V is projected to decline by 25 percent over the forecast
period, from 457 trillion Btu's in 1974 to 342 trillion
Btu's in 1980. This heavily industrialized region accounts
for 20 percent of all Lower 48 emissions, 72 thousand tons
per year of sulfur dioxide, and 11 thousand tons per year of
particulates. The estimated particulate emissions are
greater for Region V than any other region, as the incre-
mental coal consumption in Region V represents nearly half
of the Lower 48 total. Over half of the estimated emissions
in 1976 are attributable to the state of Ohio. Total
emissions increases (both sulfur dioxide and particulate)
are notably high in a number of AQMA: Cincinnati (10 thousand
tons per year); Detroit (12 thousand tons per year); and
Illinois - Indiana - Wisconsin (21 thousand tons per year).
The latter AQMA is predominantly within the metropolitan
Chicago area.
Region-VI
Although Region VI accounted for 54 percent of the
total 1974 MFBI gas consumption in the Lower 48 States it is
-xxi-
-------
projected to account for only 11 percent of the incremental
increase in emissions — 41 thousand tons per year of sulfur
dioxide and 6 thousand tons per year of particulates. Although
significant declines in gas consumption are forecast for
Arkansas and New Mexico, consumption is projected to remain
fairly stable in Texas and Louisiana, and increases in
industrial gas consumption are expected in Oklahoma. In the
latter years of the forecast significant increases are
expected in a number of AQMA in Texas, including Beaumont,
Corpus Christi, and Houston as a partial boiler fuel phaseout
mandated by the Texas Railroad Commission is implemented.
Other AQMA with noticable increases are Little Rock (4
thousand tons of sulfur dioxide and particulates per year)
and Shreveport (8 thousand tons of sulfur dioxide and par-
ticulates per year).
Region VII
The 25 percent decline in gas consumption by major com-
bustors in Region VII is shown to produce 31 thousand tons
in additional sulfur dioxide emissions per year and 3 thousand
tons in additional particulate emissions per year. Approxi-
mately 33 percent of the total energy supplied by alternate
fuels in Region VII is projected to come from coal, as
compared with only 11 percent for the rest of the Nation.
Four trillion Btu's of the 7 trillion Btu annual increase in
additional coal consumption is attributable to Iowa, and
this state accounts for over 40 percent of the Region's
total increase in emissions. The greatest average annual
increases in emissions for AQMA in Region VII are in Kansas
City — 6 thousand tons per year of sulfur dioxide and 0.6
thousand tons per year of particulate.
-xxii-
-------
Region VIII
It is estimated that emissions of sulfur dioxide will
increase by 10 thousand tons per year as a result of gas
shortages to major combustors in Region VIII, and particulate
emissions will increase by 3 thousand tons per year. Over
half of the increase in sulfur dioxide emissions and 60 per-
cent of the increase in particulate emissions are attrib-
utable to Montana, as it is expected that the significant
portion of gas previously exported from Canada to Montana
will sharply decline. The AQMA with the greatest expected
increases in emissions is Anaconda-Butte, with average
annual sulfur dioxide increases of 2.8 thousand tons per
year and particulate emissions of 1.1 thousand tons per
year.
Region IX
The increase in sulfur dioxide emissions in Region IX
is forecast at 36 thousand tons per year, about 10 percent
of the Lower 48 total, and the increase in particulate emis-
sions is forecast at 11 thousand tons per year, 23 percent
of the Lower 48 total. The fact that Region IX accounts for
17 percent of the Lower 48 annual increase in alternate fuel
consumption but only 10 percent of the increase in sulfur
dioxide emissions is indicative of the relatively strict
sulfur dioxide emission regulations in California. Over 80
percent of the total energy of all major MFBI combustors in
Region IX was supplied by- gas. in . 19.74_, _and the 44 percent
decline in gas supply by 1980 will result in an increase in
alternate fuel consumption of 68 trillion Btu's per year.
-xxiii-
-------
Of this 68 trillion Btu's per year, 64 trillion Btu's will
be supplied by fuel oil. Two AQMA in California, Kern
County and South Coast, account for' nearly half of the
average annual increase in emissions.
Region X
Gas consumption by major MFBI combustors is projected
to decline by only 1 percent by 1980 in Region X, and thus
incremental increases in emissions are expected to be
relatively small. Total increases in emissions are pro-
jected to average 9 thousand tons per year, 8 thousand tons
of sulfur dioxide and 1 thousand tons of particulates,
roughly 2 percent of the Lower 48 total. Over 90 percent of
the total emissions forecast are for Washington, and the
Puget Sound AQMA is shown to emit about half of the Region's
increase in both sulfur dioxide and particulates.
-xxiv-
-------
CHAPTER I
GAS DEMAND AND SUPPLY PROJECTIONS
FOR MAJOR MFBI GAS COMBUSTORS
The purpose of this chapter is to discuss the methodology
underlying the gas demand and supply projections for individ-
ual major gas combustors at MFBI and to summarize the results.
In the last chapter of this study a more thorough analysis
of the national and regional gas supply outlook is provided.
The reader should also be referred to "The Impact of Gas
Curtailments on Electric Utility Plants," prepared by Foster
Associates in 1975 for EPA, which among other things con-
tains a detailed discussion of curtailment plans by gas
pipelines and distributors.
The gap between gas supply and demand at each MFBI is a
shortage, which requires the burning of alternate fuels,
which in turn generates emissions of sulfur dioxide and
particulate matter. Since the alternative fuel use pro-
jected in, this study is estimated by equating the alternative
fuel needs in Btu's, with the heat content of the gas shortfall
in Btu's, the emissions which are the end result of this
study are quite sensitive to the gas supply and demand
projections.
Initially discussed below is the basis for the demand
projections used in this study, followed by a general des-
cription of the methodology underlying the gas supply
projections. It should be recognized that greater effort
has been expended in the analyses of supply compared to
demand. This chapter concludes with a discussion and explana-
tion of the regional, state and local gas supply and shortage
projections.
1-1
-------
Determination of Demand for Gas
by Major MFBI Gas Combustors
There are a large number of variables which as a
practical matter will result in somewhat different trends in
the demand for gas in the various combustors at each of the
1087 plants analyzed. These variables include the price and
availability of alternate fuels and expectations thereof;
weather; output of manufactured goods and thus demand for
the products of the plants; and conservation efforts within
these plants. However, such individual plant analyses are
beyond the scope of this study. For purposes herein, demand
for gas by major combustors at MFBI is tied to projections
of economic activity and overall industrial energy demand
for the Nation in the aggregate.
Demand for gas at these industrial plants is calculated
to reflect the same trend as industrial demand for energy in
general. On the basis of heat content, natural gas is
generally priced lower than alternate fuels in most indus-
trial markets, and if sufficient supply were available at
these prices gas consumption would increase relative to
other fuels. However, the incremental emissions measured
herein are from combustors which used gas in 1973 or 1974,
and do not include those emissions which would have been
avoided if sufficient gas were available to penetrate new
markets.
A number of regressions, linear, log-linear and non-
linear, were attempted relating industrial energy consumption
to various economic indices of industrial activity as well as
to wholesale energy prices. Dummy variables were in some
instances employed to accommodate the impact of conservation
1-2
-------
which first appeared during the oil embargo. As hypo-
thesized, the most significant variable explaining changes
in industrial energy consumption is the level of industrial
economic activity, measured by the Federal Reserve Board
Index of Industrial Production. The addition of other
variables does not improve the statistical significance
of the equation nor does it substantially change the relation-
ship between industrial production and industrial energy
consumption.
Industrial energy demand-from 1976 to 1980 is estimated
by reference to industrial production, in log-linear
form. The base year is 1974, and thus the forecast incor-
porates substantial conservation. As well, continuing
conservation albeit at a modest rate is implicit in the fore-
cast, and the rate of increase in demand is reduced by ten
percent to reflect continuing conservation effects. This
ten percent adjustment does not appreciably affect the results,
as by 1980 demand would be only one percent higher without
the ten percent adjustment. For purposes of projections,
industrial production (the FRB index, excluding electric power
generation) is assumed to increase by ten percent in 1976
and at a four percent annual rate thereafter.
The following table compares the forecast with the
historical experience.
1-3
-------
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
FRB
(1967 = 100.0)
66.8
72.4
76.7
81.8
COMPARISON OF INDUSTRIAL ENERGY DEMAND AND THE
FEDERAL RESERVE BOARD INDEX OF INDUSTRIAL PRODUCTION
Industrial Energy Consumption
(Trillions.of Btu's)
16,198
16,840
17,869
18,602
19,184
19,815
19,965
21,297
22,172
22,468
22,294
23,020
24,042
23,033
21,657
22,864
23,365
23,889
24,426
24,964
89.3
98.1
100.0
105.5
110.3
105.6
105.5
113.8
124
123
111.7
121.8
126.6
131.7
137.0
.2
,4
142.4
a/ Excludes electric utilities.
From 1961 to 1973, industrial production increased at
an annual average rate of 5.3 percent. Between 1970 and
1971 the sole decline during the period occurred, and that
was less than 0.1 percent. The maximum year to year increase
of 9.9 percent occurred in 1966. During the entire 12-year
period, industrial consumption of energy increased at an
annual average rate of 3.3 percent. Consistent with the
trend in industrial production, energy consumption declined
only once — in 1971 — but at a rate of 0.8 percent.
From 1973 to 1975, both industrial production and
industrial energy consumption declined markedly. Industrial
1-4
-------
production declined 0.6 percent in 1974 and 9.5 percent
in 1975. Industrial energy consumption declined 4.2 percent
in 1974 and 6.0 percent in 1975. It is hypothesized that
a significant and lasting conservation effect was experienced
during this time.
The forecast assumes a 10 percent rise in industrial
production for 1976 and 4 percent per year thereafter, with
the former possibly being optimistic in light of more recent
economic results and projections, and the latter being slightly
lower than historical rates. Industrial energy demand is
projected to increase by 5.6 percent in 1976 and approximately
2.2 percent per year thereafter. Until 1979, industrial
demand for energy is projected to be below the 1973 peak.
The range in possible industrial demand for gas to 1980
is not nearly as great as the range in possible industrial
gas supply, as there is substantially more uncertainty in
the supply forecasts than in the demand projections. However,
a change in the levels of demand forecast in this study,
all other things being equal, would alter the projected
volume of shortage, alternative fuel use and emissions. For
example, nationally, if gas demand by MFBI was unchanged
between 1974 and 1980, the projected shortage in 1980 would
be reduced by 40 percent, as would be projected alternative
fuel use and emissions. A 10 percent increase in demand
over what is projected herein to 1980 would increase the
projected shortage, alternative fuel use and emissions by
51 percent in 1980. ....
1-5
-------
Comparison of the MFBI Supply Forecasts
with Other Studies
The volume of gas consumed by the industrial sector
declined substantially in 1974 and 1975. Most forecasts
suggest further reductions through 1980 but not as severe
on an annual basis as these recent declines. For example,
between 1974 and 1980, the Department of Interior forecasts
a 9 percent decline in overall gas supply and a 10 percent
decline in industrial gas consumption, while the Gas Require-
ments Committee (GRC) forecasts a comparable decline in
overall gas supply and a 23 percent decline in industrial
gas consumption. While other studies do not project indus-
trial gas consumption, they generally project declining
overall gas supply to 1980. The independent analyses prepared
for this study also confirm this general outlook.—
Among the available sources, only GRC provides projections
of industrial gas consumption by state and year to 1980.
The GRC projections of industrial gas consumption are dis-
played on Schedule 1-1. The following table compares the
percent decline in industrial gas consumption between 1974
and 1980 by state from GRC with the decline herein projected
for major MFBI gas combustors.
I/ Chapter IV contains a thorough discussion of the
national supply outlook, including a more detailed
review of available forecasts of gas supply.
1-6
-------
Sheet 1 of 2
COMPARISON OF THE INDUSTRIAL GAS CONSUMPTION FORECASTS
IN THIS STUDY WITH THE
CRC FORECASTS BY STATE
Percent Change Between
1974 and 1980
EPA Region/State
(1)
Region I
Connecticut
Massachusetts
Maine
Nev Hampshire
Rhode Island
Vermont
Total Region I
Region II
New Jersey
New York
Total Region II
Region III
Delaware
Maryland
Pennslyvania
Virginia
West Virginia
Total Region III
Region IV
Alabama
Florida
Georgia
Kentucky
Mississippi
North Carolina
South Carolina
Tennessee
Total Region IV
Region V
Illinois
Indiana
Michigan
Minnesota
Ohio
Wisconsin
Total Region V
Region VI
Arkansas
Louisiana
Nev Mexico
Oklahoma
Texas
This Study
(2)
(47)2
(41)
39
(35)
(23)
(5)
(18)
(21)
(33)
(22)
(79)
(5)
(26)
(55)
(37)
(23)
(46)
(18)
(96)
(25)
(64)
(41)
(38)
(31)
(17)
(19)
(17)
(33)
(25)
(21)
4
(22)
8
(1)
Total Region VI
GRC
(3)
(21)2
(2)
5
3
(3)
3
(8)
(32)
(4)
(15)
(41)
(34)
(27)
(56)
(32)
(31)
(40)
(49)
(36)
(35)
(35)
(54)
(22)
(56)
(42)
(12)
(28)
(13)
(35)
(38)
(20)
(23)
(16)
(52)
1
76
(8)
(18)
1-7
FA-20916
-------
Sheet 2 of 2
COMPARISON OF THE INDUSTRIAL GAS CONSUMPTION FORECASTS
IN THIS STUDY WITH THE
GRC FORECASTS BY STATE
EPA Region/State
(1)
Percent Change Between
1974 and 1980
This Study
(2)
GRC
(3)
Region VII
Iowa
Kansas
Missouri
Nebraska
Total Region VII
Region VIII
Colorado
Montana
North Dakota
South Dakota
Utah
Wyoming
Total Region VIII
Region IX
Arizona
California
Nevada
Total Region IX
Region X
Idaho
Oregon
Washington
Total Region X
(26)2
(36)
(21)
(4)
(25)
(3)
(60)
(50)
(94)
(5)
(14)
(16)
(54)
(43)
(8)
(44)
8
5
(4)
(1)
(28)%
(30)
(20)
(30)
(27)
1
(52)
(55)
(44)
(26)
(20)
(23)
(39)
(18)
(25)
(20)
12
7
(1)
Total Lower 48 States
(13)Z
(23)%
Note: Brackets denote negative.
1-8
FA-20916
-------
The foregoing table shows that for the total Lower 48
States, GRC projects a more severe decline (23 percent) than
this study projects for major gas combustors (13 percent).
However, this apparent divergence nationally is primarily
attributable to differences in the forecasts for EPA Region
VI, comprised of the following states: Arkansas, Louisiana,
New Mexico, Oklahoma and Texas. With state-to-state variation,
GRC projects an 18 percent decline in industrial gas con-
sumption in Region VI while this study projects essentially
no change in the availability of gas for major combustors.
It should be recognized, however, that the coverage of"
this study does not extend to the entire industrial sector
but rather pertains to large combustors at specific plants.
The gas supply outlook for plants not analyzed herein can
differ from these projections. For example, the MFBI in
Louisiana were served by intrastate suppliers to a greater
extent than the state as a whole, and it is the interstate
pipelines which have substantially reduced deliveries in
Louisiana.
As stated previously, the advantage of the GRC forecast
is its detail, which facilitates comparison with the results
of this study. The GRC forecast of gas consumption by
sector and state is the composite of projections by the
individual gas distributors and pipelines serving particular
markets and thus it reflects the respondents' assessments of
future gas supply. With regard to Federal, state and local
policies concerning price regulation-, -allocations,- priorit-ies-
of service and other factors which might affect future con-
sumption patterns by sector, the data reflect individual
distributors' own evaluations. There may be different outlooks
1-9
-------
for the gas supply available to be sold to industrial cus-
tomers in various areas of a state served by more than one
distributor and/or pipeline.
The GRC reports were extremely useful in the preparation
of this study. As a starting point for all projections, the
GRC forecasts were reviewed for each state. In a few instances,
the GRC industrial gas consumption projections were directly
applied to the MFBI. The following section describes the
procedures underlying the MFBI supply forecasts.
Gas Supply Assumptions and
Methodology
For individual MFBI the specific supply forecasts were
developed by using publicly available data related to: gas
supply nationally; individual industrial plants; and
the gas distributors and pipelines serving these plants. Key
general assumptions with regard to gas supply are listed
below.
1) It was assumed that normal weather would prevail
from 1976 to 1980. Colder than normal weather would
not only increase gas demand for industrial space-
heating but also reduce the supply of gas available
for industrial consumption. Residential-small commercial
demand is normally regarded as the first-priority
commitment by sellers of gas (and regulatory authorities)
and is satisfied out of available supply before indus-
trial sales are made. With colder than normal weather,
such as that which has occurred to date during the
1976/1977 winter, industrial gas supply would be lower
than herein projected because of higher residential-
commercial consumption. Moreover, to satisfy high
1-10
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priority needs, gas companies are withdrawing substantial
volumes of gas from storage which will have to be
replenished during the ensuing summer at the expense of
industrial gas sales.
2) It was assumed that conventional gas production
from wells in the Lower 48 States would continue to
decline to 1980 but the rate of decline would be lower
than that experienced in 1974 and 1975 due to a pro-
jected increase in new supply. Since onshore exploration
i
for gas has increased substantially in response to the
rapid rise in intrastate field prices, and since it is
assumed that offshore drilling will increase due to the
recent rise in interstate price levels for new gas, an
increase in reserves additions is forecast.
More specifically, the supply forecasts used herein
reflect an approximate 10 percent increase in 1976 and
20 percent increase thereafter in new supply attachments,
compared to their 1972-1975 experience, by major inter-
state pipelines. It is assumed that no further write-
downs in estimates of existing proved reserves or
deliverability therefrom will occur. Most of the increase
in new reserve attachments by interstate pipelines are
projected to be in the Gulf of Mexico. Thus, there
is considerable diversity in the projected reserves
additions for various interstate pipelines, reflecting
their relative accessability to offshore reserves.
Without any new reserves, total interstate pipeline
supply would decline at an annual rate of over 10 percent.
The foregoing assumptions regarding reserves additions
reduce the annual rate of decline to approximately 4
percent.
1-11
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3) The forecasts also reflect supplemental gas (LNG,
SNG from liquid hydrocarbons, and Canadian gas) but
not in sufficient volume to offset the projected shortage.
Most supplemental gas projects have experienced delays
and are not expected to be onstream before 1980.
With respect to LNG, it is assumed that two major
projects, primarily benefiting certain states in EPA
Regions I, II, III, IV and V, will be operational. The
Eascogas project, bringing Algerian LNG to EPA Regions
I and II, is assumed to be onstream in mid-1978 at scheduled
volumes. The first El Paso LNG project, which will
import 1 Bcf/d of Algerian LNG to be purchased by the
Columbia Gas System, Consolidated Gas Supply and Southern
Natural Gas is also expected to be onstream in 1978.
With respect to SNG from liquid hydrocarbons, no
new plants are assumed. Plants which were built by the
end of 1976 are projected to be the only sources of SNG
available through 1980. Thus, no coal-gasification plants
are forecast to be in operation. The output from existing
SNG plants is consumed entirely in EPA Regions I, II, III
and IV.
Canadian gas, which currently accounts for 5 percent
of U.S. gas supply, is projected to remain nearly constant
to 1980 and thus remain the largest single category of
supplemental gas. Existing export licenses are expected
to be met but upon expiration of their term, are assumed
to be phased out. Canadian gas is important in EPA
Regions V, VIII, IX and X.
1-12
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4) The Federal Power Commission has instituted
procedures (Order 533) whereby industrial gas users
who need gas for processes in which only gas is feasible
can purchase gas directly in the field at above-ceiling
rates and have this gas transported by interstate pipe-
lines.— Through November 15, 10 of the MFBI had received
approval -for these arrangements. In 9 of the 10 plants,
however, the gas is dedicated to combustors with capacity
less than 100 MMBtu/hr. Thus, the volumes authorized
under Order 533 arrangements will have no impact on the
shortages projected for the larger combustors (all boilers)
in the nine plants which are analyzed by this study. There
. is one MFBI which has obtained Order 533 gas for process
combustors over 100 MMBtu/hr., and this study assumes
that demand at this plant will be met beyond the two
year term of authorization.
Order 533 procedures can and will alleviate some
of the gas shortages in process combustors of MFBI.
Unfortunately, it is impossible to forecast which MFBI
will be the beneficiaries of such arrangements in the
future.
The outlook for specific MFBI was developed by researching
a host of publicly available material and converting this
material into a forecast. Initially, the types of sellers of
gas — distributors or pipelines — to the MFBI had to be
estimated. Over 10 percent of the MFBI purchase gas directly
from interstate pipelines, and in these cases the type of
contract — firm or interruptible — could be ascertained from
I/ Chapter IV contains a detailed discussion of Order 533
arrangements.
1-13
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Form 2's filed by the relevant interstate pipelines. In
the remainder of cases, the MFBI received gas from distribu-
tors who in turn buy from interstate pipelines or, in gas
producing states, the MFBI received gas through intrastate
pipelines. It is not possible to ascertain with certainty
the type of contract involved in these cases.
The next step was to investigate the supply circumstances
of the relevant sellers of gas within the states. Helpful
guides to the immediate outlook for individual states, pipe-
lines and distributors were Projected Natural Gas Curtailment
and Potential Needs for Additional Alternate Fuels, FEA; the
FPC Staff reports on the Winter Impact of Natural Gas Cur-
tailments with Respect to Nineteen Individual Pipeline Com-
panies prepared in FPC Docket Nos. RP76-116, et al.; Form
16*s and 69's filed by interstate pipelines with the FPC;
and FPC summary reports on the curtailment situations of
interstate pipelines.
For the longer term outlook with respect to individual
sellers of gas, a number of sources were reviewed to assess
not only the gas supply outlook but also the marketing and/
or curtailment strategies of the gas companies involved. The
available sources of information vary in usefulness from
company to company but include Annual Reports to Stockholders,
Form lOK's filed with the SEC, prospectuses and hearings
before and decisions of state and Federal regulatory authorities,
Taking into account the national gas supply perspective pre-
viously described, individual pipeline supply forecasts were
generated reflecting deliverability from existing reserves
as of January 1, 1976 plus an allowance for LNG, SNG and pro-
jected new reserves additions.
1-14
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The above research essentially confirmed the GRC indus-
trial forecasts for some states. If there was no apparent
regional diversity within the state in these instances, the
MFBI forecasts were developed by trending the GRC projections
forward from 1974 actual data. In other cases independent
industrial gas consumption projections were constructed.
Projected Gas Consumption and Shortages
by AQCR and AQMA
The purpose of this section is to summarize the individ-
ual MFBI gas consumption and shortage projections. Schedule
1-2 shows the forecast by region, state, AQCR and AQMA. It
is important to bear in mind that this and all subsequent
schedules summarizing the MFBI pertain only to the designated
large combustors burning gas, and do not necessarily represent
the entire industrial sector in any state. Moreover, the
annual volumetric shortages displayed on the schedule do not
include any shortages which may have existed in 1974, the base
year. The derivation of the shortages reflects the arithmetic
difference between demand and supply, in other words the net
increase in the shortages over 1974 levels. The AQMA on the
schedule are shown below the AQCR in which they fall and are
indented and preceded by a dash.
EPA Regions I and II
Gas consumption by major combustors in EPA Regions I
and II (New England, New York, and New Jersey) totaled 26
trillion Btu's in 1974, less than 1 percent of gas consumption
in all major combustors in the Lower 48 States. This low
percentage representation reflects the predominant use of
1-15
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alternate fuels by the industrial sector in these regions
as well as the predominant use of gas in combustors with a
capacity less than 100 MMBtu/hr. Gas consumption by major
combustors represented only 11 percent of total industrial
gas consumption in these regions.
Overall, gas consumption by major MFBI combustors in
Regions I and II is projected to decline but the rate of
decline will be reduced due to supplemental gas. A number
of SNG plants are already operating in these areas and LNG
is assumed to be available beginning in 1978. Most of the
MFBI gas consumption is in New Jersey, and these MFBI are
largely served by the particular distributors who have ob-
tained additional gas supplies. The southern New Jersey
glass industry which is experiencing considerable difficulties
is not represented at all in the data.
EPA Region III
In EPA Region III -- consisting of Delaware, Maryland,
Pennsylvania, Virginia and West Virginia — major industrial
combustors consumed 92 trillion Btu's of gas in 1974. Over
half of this gas was used in Pennsylvania, particularly in
the Metro Philadelphia AQMA and the Southwest Pennsylvania
AQCR. The states in this region are served by a number of
different interstate pipelines, all of which have been cur-
tailing deliveries to their distributor customers. Trans-
continental Gas Pipeline (Transco), which is curtailing
deliveries more severely than most other interstate pipelines,
serves Delaware and parts of Virginia and Pennsylvania.
Columbia Gas Transmission, although curtailing conventional
1-16
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gas supplies, has been able to partially offset the impact
of these curtailments through the sale of SNG. Columbia,
which serves Maryland and West Virginia as well as parts of
Virginia and Pennsylvania, anticipates the purchase of
substantial LNG volumes beginning in 1978. Pennsylvania is
also served in important degree by Consolidated Gas Supply
and Texas Eastern Transmission. Over a third of West Virginia's
gas supply is from wells within the state.
A steep decline in gas consumption between 1974 and
1976 is projected for Region III, but supply is shown as
essentially stable thereafter. This reflects the projections
for essentially stable supply to 1980 for some of the pipelines
serving the region as well as the introduction of LNG.
Also, emergency relief has been granted to the U.S. Steel
plants in Southwest Pennsylvania, which consume significant
volumes of gas for process purposes. Another important
factor is that minimal residential growth is projected in
this region, which means that as long as overall supply is
stable, industrial supply will remain the same.
The most significant declines are projected for Virginia,
reflecting the fact that a number of MFBI in this state are
indirectly served by Transco. Continued declines in overall
supply are projected for this pipeline. Although Transco is
an important supplier to other states in this region, and
also Region II, few of the MFBI herein analyzed are indirectly
served by this pipeline.
EPA Region IV
In EPA Region IV — consisting of Alabama, Florida,
Kentucky, Georgia, Mississippi, North Carolina, South Carolina,
1-17
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and Tennessee — major industrial combustors during 1974
consumed 254 trillion Btu's of gas. This volume represents
9 percent of gas consumption by all major industrial combustors
in the Lower 48 States. All of the states in this region
consume substantial volumes of gas in large industrial com-
bustors, led by Mississippi with 55 trillion Btu's.
A number of pipelines sell gas in this region, and each
state has a different supply and demand situation. Overall,
MFBI gas consumption is projected to decline by 28 percent
between 1974 and 1976 and by a further 18 percent between 1976
and 1980. Because demand increases, the shortage is projected
to nearly double between 1976 and 1980. Both declining sup-
ply for the pipelines serving this region and increasing
consumption by residential and commercial customers in many
states contribute to the declining availability of gas for
industrial users. It should be noted as well that a number
of the MFBI in this region purchase gas directly from interstate
pipelines.
MFBI in Alabama are served primarily by Southern Natural
Gas, both indirectly and directly. In addition, Alabama-
Tennessee Natural Gas and United Gas Pipe Line Co. make direct
sales of gas to a number of MFBI in the state. Overall gas
supply for the state is projected to decline, but the impact
on the industrial sector will be even more severe as residential-
commercial growth is projected. Southern Natural will
import LNG beginning inr 1978, offsetting in part the declines
in conventional supply. It is assumed that United will not
have sufficient gas to make any sales to MFBI .after 1977,
and that Alabama-Tennessee will have phased out its inter-
ruptible sales by 1978.
1-18
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Florida is served primarily by Florida Gas Transmission,
although United makes a few direct sales to MFBI in the
northern part of the state. The projections reflect an end
to boiler fuel sales by United after 1977 and a substantial
reduction in 1976 deliveries by Florida Gas Transmission, but
slightly increasing thereafter.
Kentucky is served primarily by Texas Gas Transmission
but also receives substantial volumes of gas from Columbia
Gas Transmission and Tennessee Gas Pipeline (Tenneco). A
very substantial decline through 1978 is projected for both
overall gas supply and industrial gas consumption; after 1978
continued but more modest declines are forecast. No residen-
tial-commercial growth is projected. Absent this assumption,
the projections of industrial gas supply would be more pessi-
mistic.
Georgia is served largely by Southern Natural and partially
by Transco. As with Alabama, this state will receive sub-
stantial volumes of LNG beginning in 1978. However, when
coupled with substantial residential-commercial growth which
is expected, the overall supply situation will result in
declining industrial gas supply. Particularly hard hit will
be the direct industrial boiler fuel customers of Southern
Natural Gas which is curtailing deliveries under an end-use
plan.
Mississippi is served by a large number of pipelines,
but over half of the MFBI with major gas combustors purchase
gas directly from United. No residential-commercial growth
1-19
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is projected. Nonetheless, the forecast shows a substantial
decline in gas consumption, reflecting the rapid phase-out
of boiler fuel sales by United. With respect to the gas
combustors without alternate fuel capabilities using gas for
process purposes, it has been assumed that sufficient supply
will be available to meet requirements.
North Carolina is served by Transco, and the virtual
cessation of boiler fuel consumption by MFBI is projected.
While some of the MFBI have made Order 533 arrangements for
process combustors, these combustors are not large enough
\
for coverage herein.
Over two-thirds of South Carolina is served by Southern
Natural, with the remainder served by Transco. The research
herein confirmed the outlook projected by GRC, and hence
the MFBI projections reflect the GRC forecast.
Tennessee is served largely by Tennessee Gas Pipeline
and Texas Gas Transmission. Although minimal residential-
commercial growth is projected, industrial gas supply is
forecast to steadily decline as overall supply declines.
The complete elimination of boiler fuel use in markets served
by Texas Gas Transmission (particularly Memphis) and by
MFBI served directly by other pipelines is projected after
1977. One MFBI in this state with large process combustors
has obtained Order 533 gas.
There are a number of AQCR and AQMA in Region IV which
will experience large volumetric shortages. The Mobile-
Pensacola-Panama City-Southern Mississippi AQCR, located in
Mississippi, Florida and Alabama, will experience shortages
of over 30 trillion Btu's by 1980 in major combustors.
Notable of the AQMA which will experience shortages are
Birmingham, Mobile and Savannah.
1-20
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EPA Region V
EPA Region V — Illinois, Indiana, Michigan, Minnesota,
Ohio and Wisconsin — is often characterized as the indus-
trial heartland of the U.S. Second only to EPA Region VI
in terms of industrial gas consumption, the region contains
257 MFBI with major gas combustors which account for 16
percent of gas consumption in all major combustors in the
Lower 48 States. Region V combustors with capacity greater
than 100 MMBtu/hr. represent 27 percent of total industrial
gas consumption in the region.
MFBI gas consumption is projected to decline by 25
percent to 1980, but in varying degree in each state. In
1980, the gas shortage in major combustors is shown at 153
trillion Btu's.
Illinois, particularly the Chicago area where most of
the MFBI are located, is served primarily by Natural Gas
Pipeline Co. of America. The impact of significant pipeline
curtailments has been largely ameliorated to date by SNG
plants operated by gas distributors. After 1977, however,
continued declines in pipeline supply coupled with projected
residential-commercial growth is expected to result in sub-
stantial declines in boiler fuel consumption. The forecasts
assume that the requirements of gas combustors, excluding
boilers, without alternate fuel capabilities will be met.
Indiana is served by five different pipelines which
are Panhandle Eastern, Natural Gas Pipeline Co., Texas Gas
1-21
-------
Transmission, Midwestern, and Texas Eastern, in order of
importance. No supplemental gas is projected for this state,
but some residential growth is expected. For 1976 and 1977,
the most significant declines are projected for the central
and northern parts of the state served by Texas Gas and
Panhandle. After 1977 continued declines are projected for
all parts of the state.
Half of Michigan's supply is provided by Michigan-
Wisconsin Pipeline, with the remainder of pipeline supply
from Panhandle Eastern, Trunkline Gas Co., and Northern
Natural Gas Co. The state also has indigenous production
which has increased in recent years as well as SNG. In 1975
one of the two major distributors in the state received 20
percent of its supply from its SNG plant and 12 percent from
intrastate production and thus was able to offset significant
reductions in conventional pipeline supply. The forecasts
reflect residential-commercial growth and the assumption that
requirements in gas combustors without alternate fuel capa-
bilities will be met. Thus, the decline shown is attributable
to predominantly interruptible boiler fuel consumption.
Minnesota gas supply comes virtually entirely from
Northern Natural Gas Company. The gas supply outlook for this
company appears to confirm the GRC projection, which shows
substantial residential growth and declining industrial con-
sumption. Thus, the GRC projection has been used, except that
it has been assumed that high priority industrial needs will
be met out of available supply.
Wisconsin is served by Michigan-Wisconsin Pipeline Company,
which imports substantial volumes of Canadian gas into the
1-22
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state. Residential-commercial growth is expected for the
state, with the gas shortage falling entirely on interruptible
industrial customers. Thus, the declines shown after 1976
are entirely attributable to boilers with alternate fuel
capabilities.
Over half of Ohio's gas supply comes from Columbia Gas
Transmission, with most of the remainder from Consolidated
Gas Supply which serves the eastern part of the state. Both
of these companies expect to import LNG beginning in 1978,
which importantly affects the industrial gas supply forecast.—
Both companies have active exploration and gas purchase programs
in offshore Louisiana and have recently announced the attach-
ment of significant new reserves. No residential-commercial
growth is projected. The forecast for Ohio reflects these
factors and assumes that high priority industrial gas needs
will be met to the detriment of boiler fuel usage.
EPA Region VI
Region VI is by far the predominant gas consuming region
in the country, encompassing the states of Texas, Louisiana,
Oklahoma, Arkansas and New Mexico. The 1974 gas consumption
of major MFBI combustors in 1974 was 1,549 trillion Btu's,
nearly 54 percent of the Lower 48 total. Gas shortages to
major MFBI combustors are projected to be 16 trillion Btu's
in 1976, increasing to 131 trillion Btu's in 1980. The
average yearly shortfall of 58 trillion Btu's represents 14
percent of the Lower 48 shortfall. Although the gas shortfall
I/ The Columbia SNG plant is located in Ohio, but this
gas is sold in a number of states served by Columbia.
1-23
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in Region VI is projected to increase yearly, the projected
consumption in 1980 is 1,549 trillion Btu's, the same as in
1974. Thus, the shortage reflects increasing demand.
The fact that Region VI is such a large gas consuming
region should not automatically pose a forecasting problem.
However, the vast majority of the gas consumed in Region VI
is not transported across state lines, and it is therefore
not subject to regulation by the Federal Power Commission.
(Intrastate gas represents approximately 93 percent of the
total supply in Texas, 85 percent in Louisiana, 87 percent in
Oklahoma, 70 percent in New Mexico, and 12 percent in Arkansas.)
As a result of the dependence on intrastate sources in Region
VI, the' data available pertaining to interstate gas is of
little value for this region. The forecast for Region VI was
based on whatever information was publicly available (annual
reports to stockholders, pipeline and distribution company
prospectuses, and various state collected data), and also on
conversations with some state officials and industry representa-
tives.
Texas is the largest gas consuming state in the Nation,
accounting for one-third of the total Lower 48 MFBI gas con-
sumption. Gas production in Texas has steadily declined since
1973. Total marketed production of gas for the first 10 months
of 1976 was some 17 percent less than in the comparable period
of 1973. However, this decline in production has had a rela-
tively greater impact on the amount of gas sold to interstate
pipelines for consumption outside the state than on the amount
of Texas produced gas retained for internal consumption. Texas
produced gas exported over the first 10 months of 1976 was
26 percent less than in 1973, while the portion of Texas gas
retained within the state declined by only 9 percent.
1-24
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Because of the declining gas production in Texas, and
because of a series of intrastate curtailments in both 1973
and 1974, the Texas Railroad Commission has ordered a partial
phaseout of gas consumed as a boiler fuel. In March of 1976
the Railroad Commission ordered that any gas user who con-
sumed an average of 3,000 Mcf/d or more as a boiler fuel in
1973 or 1974 must reduce his consumption by 10 percent by
January 1, 1981 and by 25 percent by January 1, 1985.
Intrastate curtailments in Texas in 1975 and 1976 were
less than in 1973 and 1974, and a number of major companies
indicated they were in a surplus deliyerability situation.
They attributed their better position primarily to sluggish
gas demand, citing the effects of recession, conservation, •
and mild weather. The current severe winter has resulted in
some intrastate curtailments, although it is not known what
portion of these curtailments stem from inadequate supplies
and what portion stems from pipeline capacity restraints.
The forecast for Texas utilized herein reflects a one
percent decline in MFBI gas consumption as compared with a
somewhat more pessimistic 8 percent decline forecast by GRC.
The one percent overall decline assumes a 10 percent decline
for all boiler fuel, reflecting the order of the Railroad Com-
mission, while it is assumed that supply will meet demand
for all non-boiler applications. It should be noted, however,
that many of the boilers have no alternate fuel capability.
Thus, it is assumed that investments in boiler modification
will be made.
MFBI gas consumption in Louisiana in 1974 was 465 trillion
Btu's, 16 percent of the Lower 48 total. Shortages to MFBI
in Louisiana are projected to be 7 trillion Btu's in 1976 and
1-25
-------
20 trillion Btu's in 1980. The shortfall is mainly attributable
to those few MFBI served by the interstate pipelines servicing
Louisiana: United Gas Pipe Line, Arkansas Louisiana, and
Mid Louisiana Gas Company. It appears that only about 13 per-
cent of the Louisiana gas consumption is linked to interstate
supply sources. For MFBI served by intrastate pipelines it
is assumed that gas supply will equal gas demand for any non-
boiler applications for the entire period, and that boiler
demand will be met until 1978, after which supply will
remain constant.
No gas shortages are projected for the state of Oklahoma,
which had an MFBI gas consumption of 47 trillion Btu's in
1974. The reasons for this optimism regarding the situation
in Oklahoma are indicated in the following facts concerning
Oklahoma Natural Gas Company, the state's major supplier:
industrial gas sales increased 14 percent in 1975 and an
additional 11 percent in 1976; gas reserves showed a net gain
of 26 Bcf in 1976; new industrial contracts are still being
accepted, including the expected sale of some 46 Bcf per year
to three ammonia plants beginning in 1976; and excess gas
has been available for emergency sales to interstate pipelines,
as much as 36 Bcf in fiscal 1975. Although curtailments by
interstate pipelines have occurred in the state, none of the
major MFBI are served by these pipelines.
A relatively modest 8 trillion Btu's were consumed in
1974 in the four MFBI located in New Mexico. Three of the
four MFBI are located in areas served by Southern Union Gas
Company, and the GRC projection of an essentially constant
1-26
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supply was applied to them. The fourth MFBI, served by
El Paso, is shown to have a reduction in boiler fuel con-
sumption of approximately 25 percent per year.
Roughly 80 percent of all gas consumed in Arkansas is
supplied by the Arkansas Louisiana Gas Company, an inter-
state pipeline company. The gas consumption by major MFBI
of 40 trillion Btu's in 1974 is projected to fall to 31
trillion Btu's by 1976, and remain constant at this level
through 1980. GRC also assumes a substantial reduction in
industrial gas consumption at the outset of the forecast
period (although slightly less than the decline used in this
study), and then a relatively constant supply through the
remainder of the period.
Although it is assumed that supply will equal demand in
Texas through 1977, significant shortages are forecast for
a number of AQMA for the period 1978 through 1980. The
three year average shortage for Houston is projected at 17.3
trillion Btu's per year, while shortages for Beaumont and
Corpus Christi are 15.1 and 6.3 trillion Btu's per year,
respectively. The average yearly shortage in Shreveport,
Louisiana is estimated at 3.6 trillion Btu's for major MFBI
combustors, and a 4.2 trillion Btu per year shortage is
forecast for Little Rock, Arkansas.
EPA Region VII
The major--MFBI combustors in the~"four states" of Region
VII — Kansas, Missouri, Iowa, and Nebraska — consumed 88
trillion Btu's of gas in 1974, 3 percent of the Lower 48
total. It is estimated that consumption will fall to 66
1-27
-------
trillion Btu's by 1980, a decline of 25 percent. This decline
is quite comparable to the 27 percent decline forecast by
GRC.
Most of the gas consumed in these four states is trans-
ported by interstate pipelines, although there is some intra-
state production in Kansas. The primary sources of gas supply
in Region VII are as follows: Iowa - Northern Natural (64
percent of total supply) and Natural Gas Pipeline (26 percent);
Kansas - Cities Service Gas (48 percent), Northern Natural
(13 percent), and various intrastate producers (27 percent);
Missouri - Cities Service Gas (49 percent) and Mississippi
River Transmission Co. (35 percent); and Nebraska - Northern
Natural (61 percent) and Kansas-Nebraska Natural Gas (31
percent).
Although it is expected that consumption by customers
with firm contracts will be fairly stable over the forecast
period, significant cutbacks are anticipated in the inter-
ruptible industrial consumption in Region VII. The forecast
assumes a 33 percent reduction in interruptible boiler con-
sumption in Nebraska by 1980, a 35 percent reduction in
Missouri, a 55 percent reduction in Iowa, and a 62 percent
reduction in Kansas.
The greatest incremental shortages in Region VII are
forecast for two AQMA in the Metro Kansas City AQCR. The
average annual shortage forecast for Kansas City, Missouri
is 2.9 trillion Btu's per year, as compared with 2.2 trillion
Btu's per year for Kansas City, Kansas.
1-28
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EPA Region VIII
Region VIII consists of six states: Colorado, Utah,
Wyoming, Montana, North Dakota and South Dakota. The major
MFBI gas combustors in these states consumed 104 trillion
Btu's of gas in 1974, less than 4 percent of the Lower 48
total consumption. Gas consumption in Region VIII is fore-
cast to decline by 16 percent to 87 trillion Btu's by 1980,
as compared with a 23 percent decline forecast by GRC.
Approximately 83 percent of the 1974 MFBI gas consumption
in Region VIII was accounted for by three states: Colorado
(32 trillion Btu's); Utah (28 trillion Btu's); and Wyoming
(27 trillion Btu's). These three states are similar in that
a'large portion of their gas is supplied from fields within
the three state area. Two interstate pipelines supply over
half of the gas consumed in these three states, Colorado
Interstate and Mountain Fuel Supply, while another 25 percent
of the total supply comes from intrastate sources, including
Western Slope Gas Company of Colorado. The forecast utilized
herein assumes a constant supply of gas to boilers in Colorado
from 1976 on, and a modest decline in Utah and for most MFBI
in Wyoming. A few MFBI in these states are served by other
interstate pipelines, including Northern Natural and Kansas-
Nebraska. The supply outlook for these MFBI is somewhat more
pessimistic.
Over 56 percent of the average annual gas shortage in
Region VIII (10 trillion Btu's) is accounted for by the state
of Montana, even though this state's MFBI gas consumption was
only 16 trillion Btu's in 1974. The primary reason for the
1-29
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more serious decline in Montana is that the state's major
source of gas, Montana Power Company, imports about 70
percent of its gas from Canada under two long term contracts.
One of the two contracts which supplied up to 20 Bcf per year
expired in 1974. A limited extension was granted and 10 Bcf
were imported in 1975-1976, and imports of 5 Bcf have been
approved for 1976-1977. An application for an extension of
the original contract volume has not been approved by the
National Energy Board of Canada, and this forecast assumes
that the original contract will not be renewed.
Gas consumption by major MFBI in North Dakota and South
Dakota was less than 1 trillion Btu's per year in 1974, as
there is only 1 MFBI in each state. South Dakota is served
by two interstate pipelines, Montana-Dakota Utilities and
Northern Natural, while North Dakota is served by Montana-
Dakota Utilities, Midwestern Gas Transmission and various
intrastate suppliers.
The only AQMA in Region VIII with an annual average
shortage exceeding 2 trillion Btu's per year is Anaconda-
Butte, projected at 5.6 trillion Btu's per year. Four other
AQMA have annual averages projected to be in excess of 1
trillion Btu's per year: Billings, Helena, and Missoula —
all in Montana; and Sweetwater in Wyoming.,
EPA Region IX
In EPA Region IX — Arizona, Nevada and California —
there are 101 MFBI containing major gas combustors, most
of which are located in California. Major combustors in this
1-30
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region account for 8 percent of gas consumption by all
major combustors in the Lower 48 States. Of total industrial
gas consumption in this region, major combustors represented
33 percent.
Arizona is served entirely by El Paso Natural Gas Company,
and the forecast decline in MFBI gas consumption reflects
the diminishing supply of that company. No gas is expected
to be available for boiler fuel uses after 1977 and significant
shortages are projected even for combustors without alternate
fuel capabilities.
Nevada contains only 2 MFBI with major gas combustors,
one of which is indirectly served by El Paso and the other
of which is served by Northwest Pipe Line. The MFBI receiving
gas from El Paso is projected to have no gas after 1977. On
the other hand, the requirements of the MFBI served by North-
west — which is projected to have increasing overall supply —
are projected to be met as the combustors do not have alternate
fuel capabilities.
California is served by El Paso and Transwestern and also
has indigenous production. Moreover, northern California
receives substantial volumes of Canadian gas. The forecasts
of both demand and supply for each MFBI were taken from the
California Gas Report for 1976, which contains each distribution
company's projection of gas availability by priority category.
For each MFBI the priority (ies) was (were) determined according
to the industrial classification, combustion process and
alternate fuel capabilities.
In total, MFBI gas consumption in California is shown to
decline by 43 percent between 1974 and 1980. More severe
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reductions are shown for southern California than northern
California for two reasons. The Canadian gas used in northern
California is the only source of gas not expected to decline
to 1980. Secondly, substantial curtailments of electric
utilities are expected in northern California as supply declines.
Southern California does not have this "cushion" upon which
to fall. Thus, by 1980 the gas shortage for major combustors
is forecast to be 43 trillion Btu's in the South Coast AQMA,
over half of the total shortage in California.
EPA Region X
In EPA Region X — Idaho, Oregon and Washington -- there
are 56 MFBI which contain major gas combustors. Major com-
bustors in this region account for 3 percent of gas consumption
by all major combustors in the Lower 48 States. Of total
industrial gas consumption in this region, major combustors
represented 44 percent.
Region X is supplied almost entirely by Northwest Pipe ,x
Line. Northwest in turn acquires approximately two-thirds
of its gas supply from Canadian imports, with the remainder
purchased in the Rocky Mountain and San Juan areas. The
company experienced significant curtailments from its Canadian
supplier in 1974 and 1975, which were passed on to its cus-
tomers. However, Northwest estimates an increase in gas
availability from reserves under contract beginning in 1976
and has obtained additional gas as well.
Thus, an overall increase in gas supply for Region X
is projected. Residential-commercial consumption is expected
to increase substantially, along with high priority industrial
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needs. The declines in consumption and shortages shown on
the schedule are attributable solely to boilers with alternate
fuel capabilities, and reflect the trends projected by GRC.
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CHAPTER II
ALTERNATIVE FUEL USE AS A RESULT OF GAS SHORTAGES
IN MAJOR MFBI GAS COMBUSTORS
Once the gas supply-demand-shortfall situation has been
projected for individual MFBI, the next step in the plant by
plant analysis is the determination of which fuel or fuels
would be burned in order to offset any shortfall. Assuming
that a plant intends to maintain operations, the substitute
fuels which would be burned if the gas supply was inadequate
are estimated. These estimates directly impact the calcula-
tion of sulfur dioxide and particulate emissions, which may
vary according to fuel type.
Methodology and Assumptions
In order to determine the alternate fuel consumption
necessitated by a gas shortage, the various options available
to each MFBI were analyzed. The choice of the most likely
-.-^ .
alternate fuel was then made, based on a variety of economic
and technical factors. The first step in the analysis was
to refer to the MFBI printout provided by FEA. The contents
of this printout are more fully discussed in the appendix
of this study, Volume Three. Both the primary and alternate
fuels are indicated on the printout, whether they be gas,
residual fuel oil, distillate fuel oil, coal or "other." No
clarification is provided on the printout for primary or
alternate fuels shown as "other." However, the original
questionnaires from which the printout was derived were re-
searched in some instances. In most cases the other fuels
were consumed at crude oil refineries, steel mills, and pulp
and paper mills, and included such energy sources as coke
oven gas, blast furnace gas, wood chips, and black liquor.
Propane was rarely specified. The term "other" is also used
II-l
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on the printout as a combustor type, along with boilers and
burners. Other combustors generally refer to unique types
of combustors such as lime kilns, open hearth furnaces, and
blast furnaces.
Perhaps the easiest case for the determination of the
alternate fuel consumption involves a plant with one combustor,
where gas is burned as the primary fuel, and the alternate
fuel is specified as residual fuel oil, distillate fuel oil,
or coal. In this case a gas shortage of 50 billion Btu's in
a given year would be assumed to result in a 50 billion Btu
increase in the consumption of the specified alternate fuel.
The result would be identical if the primary fuel was residual
fuel oil, distillate fuel oil, or coal, and gas was the
alternate. That is, gas is assumed to be completely inter-
changeable with the alternate fuel when it is the primary fuel,
and completely interchangeable with the primary fuel when it
is the alternate.
^ In a plant with more than one combustor the question is
somewhat more complicated. For example, a gas-primary oil-
alternate combustor might be located at an MFBI with five
coal combustors which do not burn gas. There are two
options available in the event of a 50 billion Btu gas
shortage — an additional 50 billion Btu's of oil could be
consumed in the gas-oil combustor, or an additional 10
billion Btu's could be burned in each of the five coal com-
bustors. It has been assumed that the former option would
be exercised, that is, more oil would be burned in the gas-
oil combustor. The reasons for this assumption are twofold:
first, the output of the six combustors might not be inter-
changeable; and second, the coal combustors might already be
operating at maximum capacity.
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A second problem at multiple combustor plants is that
gas might be consumed with different alternate fuels in
different combustors. That is, a plant with a gas-coal
combustor and a gas-oil combustor might increase only coal
or only oil consumption in the event of a shortage. If all
combustors at the MFBI were of the same type, i.e., all
boilers or all burners, it was assumed that the shortage
would be borne by various combustors in proportion to their
1974 gas consumption. Thus, if the gas-oil combustor con-
sumes 75 percent of the gas it will suffer 75 percent of the
shortage, and the gas-coal combustor would suffer 25 percent
of the shortage.
A third complication dealt with at multiple combustor
sites involves MFBI with more than one type of combustor.
For example, an MFBI may have two combustors, one boiler and
one burner (or other), both of which consumed 100 billion
Btu's of gas in 1974. In the event of a 50 billion Btu gas
shortage, each combustor could consume an additional 25
billion Btu's provided by alternate fuels, or the boiler
could bear the brunt of the entire shortage. In cases such
as this it was assumed that the entire shortage would be
borne by the boiler. There are a variety of factors which
influenced this assumption. As discussed in Chapter III of
this study, the emissions of boilers are subject to combustion
regulations. Burners and others, however, may be governed
by process regulations which tend to be more strict than
combustion regulations.
In general, the allowable rate of emission from a boiler
is directly proportional to its heat input. Allowable emissions
from burners and others may be governed primarily by the input
weight of process weight and tend to be more strict. Thus,
II-3
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the rational choice of a profit maximizing firm would be to
cut back only the gas supply of the boiler. This decision
would result in the dirtier alternate fuel being burned in
the boiler with the more lenient emission regulations, and
thus pollution control costs and fuel purchase costs would
be minimized. Secondly, there may be an incentive to restrict
the shortage to the boiler in order to insure process quality
in the burners (or others). Finally, burners and others may
be more susceptible than boilers to damages caused by the
impurities contained in coal and oil. The cost of maintain-
ing equipment might therefore be lower if the incremental
alternate fuel consumption was restricted to boilers when
possible.
In some instances the primary fuel is listed as gas on
the MFBI printout, and no alternate fuel is indicated.
Plants lacking the capability to substitute an alternate
fuel for gas might reduce operations if faced with a shortage,
or they might.even temporarily shut down. (In fact, a number
of plant shutdowns resulting from gas shortages have been
reported this winter, reflecting the extremely cold weather.)
For purposes herein, it was assumed that all gas shortages
could be offset by the utilization of an alternate fuel.
Since this study covers a five-year period on an annual
basis, the short-run or temporary relief measures undertaken
at gas-short MFBI may differ from the expected long-run
strategies. For example, unexpected spot interruptions of
gas service on peak winter demand days might be met with a
substitution of propane. A long term interruption, however,
might be more likely to result in an increased usage of less
expensive residual fuel oil. Further, propane might be used
during the modification of a combustor to some other fuel.
It is also possible that a temporary plant shutdown could be
a more economically feasible short-run option than a major
plant conversion. Various assumptions involving the "no
alternate" case are set out below.
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In some cases, even though a combustor is shown as
having no alternate fuel capability, some quantities of oil
or coal were consumed in 1973 or 1974. In such cases, these
other fuels were considered to be a viable alternate to gas.
Further, if there are other combustors at the plant which
appear to be operating below maximum capacity and which
appear to have an interchangeable output with the gas
combustor, it was assumed that the output and primary fuel
consumption of these other combustors would increase to
offset the decline in the gas combustor. Even if the re-
maining combustors at the plant are not interchangeable with
the gas combustor they might represent a potential means to
minimize the effects of a gas shortage. For example, a
plant might have five coal-gas combustors used to produce
process steam and one gas combustor with no alternate fuel
used to generate electricity. It is assumed that in the
event of a shortage gas would be taken from the coal-gas
units and allocated to the gas only unit in order to keep it
in operation. Thus, the gas shortage would result in an
increase in coal consumption even though the combustor under
consideration has no reported alternate fuel.
A few coal combustors are listed as having no alternate
fuel capability, and yet some minor amounts of gas were
consumed in 1973 and 1974; e.g., one percent of total com-
bustor consumption. It was assumed that this gas is used
either as a starter fuel or for flame stabilization purposes.
It was further assumed that the only alternate to this gas
would be propane, unless some minor quantity of fuel oil was
also consumed. In any cases where no alternate to gas was
indicated, and where the above discussed approaches were
inappropriate, the most likely alternate to gas was used
(including propane).
II-5
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In some cases, gas is the alternate fuel and the primary
fuel is shown as "other." The "other" primary fuel may be
coke oven or blast furnace gas at steel mills, refinery gas
at crude oil refineries, or wood at pulp and paper mills.
In general, these "other" types of fuel are plant by-products
and may be consumed at little or no expense. It was there-
fore assumed that these plants already use as much of the
"other" fuel as is available, and gas is consumed as a
supplemental fuel. Thus, these combustors could not burn
more "other" in the event of a gas shortage. The procedure
for the determination of the applicable alternate in these
cases was therefore similar to the gas-no alternate case;
i.e., reference was made to other combustors at the plant,
and to any other fuels which may have been consumed in the
gas-"other" unit. If these approaches were not feasible, a
"most likely" alternate was chosen.
Projected Alternative Fuel Use by AQCR and AQMA
Schedule II-l sets out the projected alternative fuel
use as a result of gas shortages in major MFBI gas combustors
by AQCR and AQMA from 1976 through 1980 in billions of Btu's
per year. It should be noted that the increases in alternate
fuel consumption indicated on Schedule II-l are identical in
quantity to the gas shortage projections of Schedule 1-2
for corresponding geographic areas.
The increase in alternative fuel consumption for the
Lower 48 States is projected at 203 trillion Btu' s in 1976,,
increasing to 612 trillion Btu's in 1980. The average-
annual increase of 408 trillion Btu's is distributed by fuel
type as follows: residual fuel oil - 251 trillion Btu's
(61.4 percent); distillate fuel oil - 104 trillion Btu's
(25.5 percent); coal - 51 trillion Btu's (12.5 percent); and
"other" - 2 trillion Btu's (0.6 percent).
II-6
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The incremental increase in residual fuel oil consumption
projected for these major MFBI gas combustors in 1980 is 357
trillion Btu's, approximately 17 percent of the Lower 48
total industrial residual fuel oil consumption in 1974. The
comparable figures relating distillate fuel oil and coal to
the 1974 industrial totals are 39 percent and 5 percent,
respectively. A summary of the results by EPA region follows.
Total fossil fuel consumption of all major MFBI combustors
in Region I in 1974 was 110 trillion Btu's. Of this amount
over 93 percent was supplied by residual fuel oil, and only
5 percent by gas. As might be anticipated, virtually all
shortages in Region I are expected to be offset by increased
residual fuel oil consumption. The gas shortage for major
combustors in Region I is projected to increase from a
modest level of 1.4 trillion Btu's in 1976 to 2.4 trillion
Btu's in 1980; 99 percent of this amount to be replaced by
residual fuel oil and 1 percent by distillate fuel oil.
Most of the increased alternate fuel consumption is shown to
occur in Massachusetts (1.1 trillion Btu's in 1976, 1.9
trillion Btu's in 1980), with approximately 50 percent of
the state total attributable to the Boston AQMA.
Major combustors in Region II are similar to those in
Region I in that most energy is derived from residual fuel
oil. Some 21 trillion Btu's were supplied by gas in 1974,
about 9 percent of the region's total fossil fuel consumption,
by all major MFBI combustors. The gas shortage in Region
II is projected to be 4.4 trillion Btu's in 1976, increasing
to 5.4 trillion Btu's in 1980. The impact of the gas shortage
will be lessened somewhat in Region II due to expected
increases in supplemental gas in the form of LNG0 The 4.4
trillion Btu shortage in 1976 will be met by an increase in
residual fuel oil consumption of 4.2 trillion Btu's — 3.0
trillion Btu's in New Jersey and 1.2 trillion Btu's in
II-7
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New York. Most alternate fuel consumption is projected to
occur in the New Jersey portion of the New York-New Jersey
AQMA.
Natural gas supplied 92 trillion Btu's of the 753 trillion
Btu's consumed by all major MFBI combustors in Region III
in 1974, roughly 12 percent of the regional total. The
gas shortage in Region III is projected to average 27 trillion
Btu's per year over the five-year forecast period. In order
to offset this shortage an additional 18 trillion Btu's per
year of residual fuel oil will have to be burned, as well as
7 trillion Btu's per year of distillate fuel oil and 2
trillion Btu's per year of coal. Pennsylvania is expected
to account for 49. percent of the projected increase in
alternate fuel consumption, including some 9 trillion Btu's
per year of residual fuel oil, 3 trillion Btu's per year of
distillate fuel oil, and 1 trillion Btu's per year of coal.
Most of the increases in Pennsylvania are shown to occur in
the Metropolitan Philadelphia and Southwest Pennsylvania
AQCR. Alternate fuel consumption is projected to exceed 2
trillion Btu's per year in four of the Region III AQMA:
Baltimore and Potomac River, Maryland; Metro Philadelphia,
Pennsylvania; and Petersburg-Colonial Heights-Hopewell,
Virginia.
The alternate fuel consumption in Region IV resulting
from gas shortages is projected to average 99 trillion Btu's
over the five-year period. This shortage is projected to be
met by an increase in residual fuel oil consumption of 66
trillion Btu's per year, along with 20 trillion Btu's per
year of distillate fuel oil and 13 trillion Btu's per year
of coal. Nearly 30 percent of the additional oil consumption
is in the Mobile-Pensacola-Panama City-Southern Mississippi
AQCR, while most of the coal increases are scattered throughout
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the region. The three AQMA with the largest expected annual
increases in alternate fuel consumption are: Mobile, Alabama
(5.7 trillion Btu's per year of residual fuel oil); Birmingham,
Alabama (4.6 trillion Btu's per year of coal and 1.2 trillion
Btu's per year of residual fuel oil); and Savannah, Georgia
(3.4 trillion Btu's per year of residual fuel oil). Two
AQCR in Tennessee are shown to have increases in alternate
fuel consumption of approximately 10 trillion Btu's per year
each: Metro Memphis (fuel oil) and East Tennessee (both fuel
oil and coal).
The projected increases in alternate fuel consumption
are larger in Region V than in any other region, some 3
percent greater than those projected for Region IV. The
average annual increase of 102 trillion Btu's is distributed
as follows: residual fuel oil - 59 trillion Btu's per year;
distillate fuel oil - 18 trillion Btu's per year; coal - 24
trillion Btu's per year; and "other" - 1 trillion Btu's per year,
The incremental increase in coal consumption is relatively
high in Region V, accounting for 24 percent of the region's
total increase in alternate fuel use, and 47 percent of the
average annual coal increase for the Lower 48 States. Nearly
70 percent of the coal increase is attributable to 2 AQMA:
Illinois-Indiana-Wisconsin (9.0 trillion Btu's per year) and
Detroit (7.3 trillion Btu's per year). On the other hand,
over 50 percent of the region's increased fuel oil consumption
is projected to occur in 3 AQMA: Illinois-Indiana-Wisconsin
(19.4 trillion Btu's); Cincinnati (11.1 trillion Btu's); and
Detroit (8.5 trillion Btu's).
Gas consumption by all major MFBI combustors in Region VI
in 1974 was 1,549.5 trillion Btu's, 92 percent of their
total fossil fuel consumption. These combustors thus accounted
II-9
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for 54 percent of the Lower 48 total gas consumption, but
are projected to account for only 14 percent of the average
annual increase in alternate fuel consumption (58.4 trillion
Btu's). A number of gas combustors in Region VI do not
have alternate fuel capabilities, and thus it has been assumed
that combustor modification will take place as the need arises,
The distribution of the increases by fuel type in Region VI
indicates almost an even split between distillate and residual
fuel oil, 27.7 trillion Btu's vs. 30.7 trillion Btu's while
no increases in coal consumption are projected for these
combustors. Distillate accounts for 47 percent of the
increase in fuel oils, noticeably higher than the 26 percent
share in the remaining 9 regions. The amount of combustor
modification is less for the lighter oils.
/'
Two AQMA in Region VI located outside of Texas, Little
Rock and Shreveport, have projected average annual increases
in fuel oil consumption of 4.2 trillion Btu's and 3.6
trillion Btu's, respectively. No increases are projected
for the state of Oklahoma, due t.o the optimistic intrastate
supply picture in that state, nor are any increases projected
for Texas in 1976 or 1977. The average annual increase in
fuel oil consumption (based on three years) for four major
AQMA in Texas is set out as: Houston - 17.3 trillion Btu's;
Beaumont - 15.1 trillion Btu's; Corpus Christi - 6.3 trillion
Btu's; and Galveston - 3.4 trillion Btu's.
The annual increase in alternate fuel consumption is
projected to average 21.2 trillion Btu's per year in Region
VII, approximately 5 percent of the Lower 48 total. The
portion of the total increase accounted for by coal is high
in Region VII relative to the other nine regions, 33 percent
vs. 11 percent. Four trillion Btu's of the 7 trillion Btu
per year increase in coal consumption are projected for
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Iowa. The AQMA in Region VII with the greatest annual in-
crease in alternate fuel consumption is Kansas City, averag-
ing 4.5 trillion Btu's in residual fuel oil consumption and
0.6 trillion Btu's in coal consumption.
The total fossil fuel consumption of all major MFBI com-
bustors in Region VIII in 1974 was 212 trillion Btu's. Of this
total, roughly one half was supplied by gas. The average
annual increase in alternate fuel consumption resulting from
gas shortages is estimated at 17.4 trillion Btu's — 8.7
trillion Btu's from residual fuel oil, 7.7 trillion Btu's
from distillate fuel oil, and 1.0 trillion Btu's from coal.
The incremental alternate fuel consumption is relatively
small in all states, except Montana, "for two primary reasons:
some states have very few MFBI (North Dakota and South
Dakota) and the intrastate gas supply outlook is fairly good
in some states (Colorado, Utah, Wyoming).
The increase in alternate fuel consumption in Montana
accounts for over 55 percent of the Region VIII total,
averaging nearly 10 trillion Btu's per year. The fundamental
reason for the situation in Montana is that imports of
Canadian gas to the state's primary utility are rapidly
declining due to the termination of a major contract. AQMA
in Montana with average annual alternate fuel increases
exceeding 1 trillion Btu's per year include: Anaconda-Butte
(5.6 trillion Btu's, distillate fuel oil); Helena (1.5
trillion Btu's per year, residual fuel oil); Billings (1.3
trillion Btu's per year, residual fuel oil); and Missoula
(1.0 trillion Btu's per year, residual fuel oil). It might
seem surprising that no increases in coal consumption are
projected for Montana. It should be remembered, however,
that the instant report deals only with a specific set of
large gas burning combustors, not the entire industrial
sector of the state.
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Over 80 percent of the total energy consumption of all
major MFBI combustors in Region IX in 1974, or 215.8 trillion
Btu's was supplied by natural gas. The increases in alternate
fuel consumption projected for this region average 68.0
trillion Btu's per year -- 54.1 trillion Btu's attributable
to California, 13.7 trillion Btu's attributable to Arizona,
and less than 1 trillion Btu's attributable to Nevada. Fuel
oil, the overwhelming choice as a substitute fuel in Region
IX, is shown to alleviate 64.4 of the 68.0 trillion Btu
shortfall.
The incremental use of alternate fuels to offset gas
shortages is projected to be greater for California than any
other state in the" Lower 48. Since most large industrial gas
users in California purchase gas on an interruptible basis,
many plants can accommodate both gas and fuel oil (coal is
usually not a viable alternative due to the relatively
stringent air pollution regulations in California and the
traditional availability of gas and oil). The state's
average annual increase in alternate fuel consumption is
largely attributable to 3 AQMA: South Coast (17.3 trillion
Btu's of residual fuel oil and 9.5 trillion Btu's of distillate
fuel oil); Southeast Desert (8.0 trillion Btu's per year of
residual fuel oil); and San Francisco Bay (4.8 trillion
Btu's per year of residual fuel oil and 1.3 trillion Btu's
of distillate fuel oil).
The increase in alternate fuel consumption in Region X
is relatively small, exceeding only the increases in Regions
I and II. The average annual increase in Region X is esti-
mated at 7.9 trillion Btu's per year (all from fuel oil), as
compared with the total major combustor gas consumption in
1974 of 85.4 trillion Btu's. Over 90 percent of the average
annual increase is accounted for by the state of Washington,
included in which are the following AQMA: Puget Sound (3.7
trillion Btu's per year increase), and Portland-Vancouver
(0.9 trillion Btu's per year increase).
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CHAPTER III
PROJECTION OF INCREMENTAL EMISSIONS OF SULFUR DIOXIDE
AND PARTICULATE MATTER RESULTING FROM SHORTAGES
OF GAS IN MAJOR MFBI GAS COMBUSTORS
The end results of this study, as discussed in this
chapter, are the projected emissions of sulfur dioxide and
particulates resulting from alternate fuel use. Natural
gas is the cleanest burning of fossil fuels, generally con-
taining negligible amounts of sulfur and ash as compared to
coal or oil. Hence, the use of alternate fuels to replace
dwindling gas supplies will result in additional emissions
of air pollutants.
First this chapter sets out the general assumptions
and overall methodology used to determine the incremental
emissions of sulfur dioxide and particulate matter resulting
from shortages of gas in major MFBI gas combustors. Then
the results by area as well as specific state and local air
quality regions are discussed.
General Assumptions and Data Used to Determine Emissions
This study determines the increase in emissions attributable
to alternate fuel use by major MFBI gas combustors. More
specifically, the projected emissions reflect the maximum
allowable increase subject to the constraints imposed by the
individual State Implementation Plans (SIP's). The emissions
resulting from alternate fuel use are, to a large degree,
dependent upon the physical characteristics of the fuel
consumed and the availability and capabilities of control
equipment. Therefore, it is possible that the incremental
emissions associated with alternate fuel use could be less
III-l
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than the maximum allowable. However, due to the generally
greater costs associated with higher quality fuels and
control equipment, it was assumed the MFBI would be operated
at the maximum allowable rate of emissions. (Of course, it
is also possible that some sources may not be in compliance
with EPA standards, and thus an estimation based on a maximum
allowable level could understate actual emissions.)
The primary reference source of the sulfur oxide regula-
tions used in the calculation of emissions in this report
is State Implementation Plan Emission Regulations for Sulfur
Oxide: Fuel Combustion.— A similar publication, State
• Implementation Plans for Particulate Matter: Fuel Combustion,—•
provided most of the data used in the calculation of particu-
late emissions. These reports contain a summary of each
state's implementation plan for the control of sulfur oxides
and particulate matter as interpreted by EPA's Strategies and
Air Standards Division.
Moreover, Mr. Rayburn Morrison of the .EPA's Energy
Strategies .Branch and Mr. C. H. Kuo were consulted during the
preparation of this study in order to identify any recent changes
in the status of the state emissions regulations and to provide
assistance in the formulation of assumptions and guidelines
required for the calculation of incremental emissions.
I./ U.S. Environmental Protection Agency, State Implementation
Plan Emissions Regulations for Sulfur Oxides: Fuel Combustion,
Office of Air Quality Planning and Standards, Research Triangle
Park, North Carolina, March 1976, (EPA-450/2-76-002).
2/ U.S. Environmental Protection Agency, State Implementation
Plans Emissions Regulations for Particulate Matter; Fuel
Combustion, Office of Air Quality Planning and Standards,
Research Triangle Park, North Carolina, August 1976, (EPA-
450/2-76-010).
III-2
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Regulations reported in the above documents are pri-
marily applicable to fuel combustion equipment. Although
the definition of fuel combustion equipment may vary from
state to state, these regulations generally apply to steam-
electric generating plants and industrial boilers which burn
fuel to generate power and steam (i.e., indirect heat trans-
fer applications).
Fuel combustion regulations are not applicable to many
industrial processes utilizing direct heat exchangers in
which products of fuel combustion come in direct contact with
process materials. Examples of these industrial processes
include steel production, cement and lime production, and
driers used in the agricultural processing industry. In
such cases, process regulations are applicable.
Calculations of the emissions from these industrial
processes were based upon the process regulations presented
in The World's Air Quality Management Standards.— This
publication is a compilation of the applicable process
regulations for both sulfur dioxide and particulate matter
emissions by state and also by county or city, where such
local regulations exist. Other sources used were the State
Air Laws published in the Bureau of National Affairs, Inc.,
Environmental Reporter, and the State Implementation Plan
files maintained by the Office of Air Quality Planning and
Standards. Only those local regulations which are part of
the state implementation plans were included in the emissions
calculations.
I/ U.S. Environmental Protection Agency, The World's Air
Quality Management Standards, Volume II: The Air Quality
Management Standards of the United States, Office of
Research and Development, October 1976, (EPA-650/9-75-001-b).
III-3
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In order to determine which emissions regulations were
applicable, combustion regulations or process regulations,
certain assumptions were required in classifying the MFBI
data. All combustors classified as boilers in the MFBI
data were considered to be subject to the fuel combustion
regulations, since this is an indirect heat transfer applica-
tion. Additionally, it was assumed that any combustor with
more than 50 percent of its output classified as electrical
generation or process steam was used primarily for indirect
heat transfer and therefore was also subject to combustion
regulations. The remaining combustors were further evaluated
with respect to the plant operations as identified by the
SIC code reported in the questionnaire. In some instances,
the plants reported specific applications of these combustors
in the MFBI data. If the specific application was not re-
ported, a determination of the "most likely" application was
made, based upon the general technology and requirements
of the associated industry. The combustor application was
then used to determine whether the combustion or process
regulations were applicable.
Process regulations are somewhat more complex than
combustion regulations since most state process regulations
are specified as a functional relationship with the maximum
allowable emissions being a function of some combustor varia-
ble. In most cases, the most important variable determining
the allowable rate of emission is rate of change of process
material and solid fuels to a combustion facility (commonly
known as charging rate, c, or process weight per unit time,
p) expressed in pounds per hour or tons per hour. Such
variables were not contained in the MFBI data, but in some
cases they were provided by the EPA. When the necessary
III-4
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information was not available an estimate of incremental
emissions was calculated based on the average sulfur content
of the fuel and/or emissions factors as discussed in a
subsequent section.
It was sometimes necessary to distinguish between new
and existing combustors in order to determine the applicable
regulation. Combustors constructed or subjected to major
modifications after the formal proposal of new source regula-
tions by individual states must comply with the new source
state regulations (in addition to the Federal new source
performance standards). Since the date the combustor was
designed or ordered may qualify as the date of construction,
and due to the long lead times required for combustor instal-
lation, almost all combustors reported as operating in 1974
in the MFBI data are exempt from the state new source regula-
tions. It was assumed that a one year lead time was required
for the installation of an oil or gas burning combustor with
a design firing rate of 250 million Btu's per hour or less.
Oil or gas burning combustors with a design firing rate
greater than 250 million Btu's per hour and all coal-fired
combustors were assumed to require a two year lead time for
installation.
Several state emissions regulations, for both sulfur
dioxide and particulate matter, also include an excess air
factor (X) in the determination of allowable emissions.
Some state regulations specify the excess air factor, usually
at 50 percent. When the excess air was not specified by the
regulation it was assumed that the excess air was 10 percent
for oil-fired combustors and 30 percent for coal-fired
combustors.
III-5
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Calculation of Sulfur Dioxide Emissions
State regulations enacted to control ambient air con-
centrations of sulfur dioxide (S02) may limit either the
sulfur content of fuel or the emission of sulfur dioxide.
The units specified in state regulations vary among the
states and include: percent sulfur of fuel, pounds of SC»2
per million Btu, pounds sulfur per million Btu, parts per
million S0« in exhaust gas, pounds S02 per hour, and impact
on ambient air quality in parts per million. With the
exception of regulations stated in terms of the impact on
ambient air quality, the emission limitations were converted
to equivalent units of pounds of S02 per million Btu, using
appropriate conversion factors.
Where states had implementation plans that specified
no sulfur emission limits or specified emissions limitations
in terms of the impact on ambient air quality, an estimate
of the increase in emissions resulting from alternate fuel
use was developed based upon the sulfur and heat content
of fuels burned in the geographical area in which the MFBI
was located. For example, if an MFBI reported residual fuel
oil as an alternate fuel, the average sulfur content and
the average heat content of residual fuel oil consumed in
the area were determined. It was then assumed that the MFBI
would burn this same type of residual fuel oil. The ratio
of sulfur content to heat content provided an estimate of
pounds of sulfur dioxide per million Btu's emitted if the
fuel were used as an alternate.
Allowable sulfur dioxide emission rates as enacted by
the states may apply to (1) the entire plant, (2) an individual
combustor, or (3) an individual stack. In this study, emis-
sions were calculated on a combustor by combustor basis.
III-6
-------
Each combustor was assumed to remain in compliance with
the applicable regulation. Therefore, this procedure
effectively insured compliance for individual stacks and
the entire plant. An alternative, and more complex, method
of emission calculations for regulations applicable to the
.entire plant (or individual stacks) would be to assume some
combustors would exceed the plant regulation while some
combustors would operate significantly below the regulation
as long as the average emissions did not exceed the plant
limitation. However, due to data limitations this alternative
was not feasible.
Some states have sulfur dioxide regulations which are
a function of a given industrial plant operating variable.
For example, in Minnesota the sulfur dioxide emission rate
is expressed as a function of the heat input rate to the
entire plant. Such regulations, therefore, require an
estimate of heat input rates. In these instances it was*
assumed the average industrial plant combustors operated at
90 percent of installed capacity. Therefore, Q, the heat
input rate, was assumed to be 90 percent of the total design
firing rate (TDFR) for the entire plant. In other words,
when the plant was operating, it was assumed to operate at
a rate which was 90 percent of its design firing rate.
Similarly, when Q was defined as the heat input for an
individual stack, the applicable Q was determined as 90 per-
cent of the installed firing rate of major combustors associated
with a given stack.
The calculation of the incremental increase in sulfur
dioxide emissions attributed to the gas shortfall involved
III-7
-------
multiplying the sulfur emissions regulation or limitation
(Ibs. of S02/MMBtu) by the Btu equivalent of the required
alternate fuel (MMBtu/yr.). This resulted in an estimate,
stated in thousands of pounds per year, of the increase in
emissions from the alternate fuel.
Calculation of Particulate Matter Emissions
State regulations for allowable particulate emissions,
like the sulfur dioxide regulation, are expressed in various
units of measurements. These include: pounds of particulate
per million Btu, pounds of particulate per hour, pounds of
particulate per thousand pounds of stack gas, grains per
standard cubic foot (SCF), and grains per standard cubic
foot, dry basis (SCFD). To facilitate the necessary cal-
culations, all regulations were converted to equivalent pounds
of particulate matter per million Btu.
Many state particulate matter regulations are a function
of the heat input value, Q. The applicable emission limita-
tion must be calculated in the same manner as the sulfur
dioxide regulation for Minnesota as previously noted.
Generally, the heat input value (Q), expressed in MMBtu/hr.,
pertains to (1) the aggregate heat content of all fuels burned,
(2) maximum design heat input, or (3) the maximum of (1) and
(2).. If the regulation specified Q as the aggregate heat
content of all fuels burned at a plant, it was estimated at
90 percent of the plant's total design firing rate (TDFR).
When Q was specified as the maximum design heat input, it
was estimated at 100 percent of the TDFR.
I
Additionally, the heat input value in some cases pertains
to individual combustors or individual stacks. In these cases
III-8
-------
the relevant factor, either 90 percent or 100 percent, was
applied to the reported design firing rate of the individual
combustors or to the total reported design firing rate of
the major combustors associated with a given stack.
Other types of particulate matter limitations frequently
encountered in the state regulations specify a fixed maximum
allowable rate, such as 0.1 pounds per million Btu, or a
limitation based upon ASME Standard APS-1, with a specified
maximum allowable rate. With the ASME Standard APS-1 (repro-
duced here on the following page) the allowable emissions
are a function of the combustor capacity rating in million
Btu per hour and the associated stack height. The applicable
regulation would then be the minimum of the value obtained
from the graph or the maximum allowable rate.
It should also be noted that when the ASME Standard
APS-1 was specified as the relevant state particulate emissions
regulation, the emissions limitation could vary from stack
to stack, depending upon the individual stack heights. (There
would be no variation in a state such as Minnesota where the
total equipment capacity refers to the entire plant, but there
could be a variation in a state such as Wisconsin where equip-
ment capacity refers to individual stacks.) The method of
allocating alternate fuels among the different stacks could
produce different estimates of emissions. As discussed in
Chapter II, when all combustors at an MFBI were classified
as indirect heat applications, the consumption of alternate
fuels due to the gas shortfall was apportioned to the individual
combustors or stacks in proportion to the 1974 gas consumption
of the units. Therefore, the weighted average allowable
III-9
-------
ASME STANDARD, APS-1, FIGURE 2
PARTICULATE EMISSION, FUEL BURNING OPERATIONS
1.5
3
Q.
z
3
+-
GO
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0.9
0.8
0.7
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oc
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0.1
1 ' I ' '"I ' ' ' I ""I
NONS fO* A SMOKI IIGUIATION OtDINAMO iA|M| 144
'0.11 » OU»f »lt tOOO Ib OF GASH. \* \
MAAIMUM •ICOMMfNOlO IMIHION lHlfSVICTIVI Of 1T*C* HUGH!
MA1IMUM GIOUNO IIVIL DUST CONOMTtATION
S 100 Wt mj 'O* 1-tS mln
£ JO »f mj fOI 10 mm - I hr
S if wf mJUr 1* hfi
t. •% O' HIAT IN»UT UP STACK *S
4. GRAPH IS tOt A SINGH STACK
1 510 50 100 500 1,000 5,000 10,000
TOTAL EQUIPMENT CAPACITY RATING, 106 Btu/hr INPUT
111-10
-------
emissions limitation for the total MFBI was constant through-
out the forecast period.
However, when the MFBI contained combustors used for
direct and indirect applications, it was assumed the MFBI
would be operated in a manner to protect the gas requirements
of the direct applications, thereby allocating the shortfall
to the indirect applications. In this case, the emissions
limitation would be that regulation applicable to the
combustors used in indirect applications. The emissions
regulations associated with the direct applications did not
enter into the calculations until all the gas was displaced
from the indirect applications and the direct applications
required alternate fuel. . When this occurred, the weighted
average allowable emissions limitation for the total MFBI
changed from year to year to reflect the emissions limitations
on the use of alternate fuel in the indirect applications
plus the emissions limitation associated with the increasing
use of alternate fuel in the direct applications.
Several states have no limitation on particulate emis-
sions or have regulations expressed in terms of the impact
on ambient air quality. In these cases the incremental
emissions were calculated through the use of emissions
factors. These emissions factors are representative estimates
of the particulate matter emitted when fuels are burned in
uncontrolled industrial combustors.— Representative calcula-
tions for distillate fuel oil, residual fuel oil, and bituminous
coal are set out below.
I/ U.S. Environmental Protection Agency, Compilation of
Air Pollutant Emission Factors, Second Edition, Office of
Air Quality Planning and Standards, Research Triangle Park/
North Carolina, February 1976 (AP42).
III-ll
-------
Estimated Particulate Matter Emitted by
Uncontrolled Industrial Combustors
Particulate
Emissions
Fuel (#/MMBtu)
Distillate Fuel Oil (@ 139,-OOQ Btu/gal.) 0.11
Residual Fuel Oil (@ 150,000 Btu/gal.) 0.15
Bituminous Coal (@ 15% ash, 12,000 Btu/lb.) 10.00
For some combustors, used in direct heat transfer
applications, no incremental increase in particulate emis-
sions was calculated since the available data indicated these
combustors were most likely not in compliance with the appli-
cable particulate regulations. This non-compliance is
associated primarily with particulate matter emitted from
industrial processes other than fuel combustion. For these
types of processes the emissions from fuel combustion generally
constitute a negligible fraction of the total emissions from
the process. Since the allowable level of emissions in
these processes was most likely exceeded, no incremental
increase in allowable emissions was possible. Examples of
the applications for which no increase in allowable emissions
were calculated are: cement and lime kilns, driers used in
food processing and industrial inorganic chemicals, asphalt
batch plants, and sintering plants in the steel industry.
After all relevant state emissions regulations were
identified and converted to an equivalent pounds per million
Btu basis, the incremental increase in emissions attributed
to the use of alternate fuel was calculated by multiplying
the particulate emissions limitation (Ibs./MMBtu) by the energy
equivalent of the alternate fuel that would replace gas
consumption (MMBtu/yr.). This calculation yielded the esti-
mated increase in allowable particulate emissions in thousands
of pounds per year.
111-12
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Summary of Estimated Incremental Emissions
The incremental emissions of both sulfur dioxide and
particulates are set out by EPA Region, state, AQCR and
AQMA for the period 1976 through 1980 at Schedule III-l.
The increase in sulfur dioxide emissions due to the gas
shortage for the Lower 48 States is estimated at 214 thousand
tons in 1976, increasing to 509 thousand tons in 1980. The
average annual increase is 370 thousand tons, of which 40
percent is attributable to Region IV and 20 percent is
attributable to Region V.
The major gas combustors at the 1087 MFBI are also
projected to emit an additional 48 thousand tons per year
of particulate matter, 22 thousand tons in 1976 and 71
thousand tons in 1980. Region V accounts for over 23 percent
of the average annual increase in particulates, while Regions
IV and IX account for 22 and 23 percent, respectively.
The incremental emissions of sulfur dioxide in EPA
Region I are estimated at 837 tons in 1976 and are projected
to increase to 1,412 tons in 1980. Approximately 90 percent
of the total sulfur dioxide emissions in Region I over the
five year period are attributable to MFBI located in Massa-
chusetts, while the remainder is attributable to MFBI
located in Connecticut. The projected emissions increases
are most concentrated in the Boston AQMA, which a'ccounts for
more than one-half of EPA Region I emissions.
The incremental emissions of particulates in Region I
are projected to increase from 92 tons in 1976 to 165 tons
.in 1980. Massachusetts and Connecticut produce all the pro-
jected incremental emissions. More than one-third of the
111-13
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incremental particulate emissions is attributable to the
Boston AQMA.
In Region II, the incremental sulfur dioxide emissions
are projected to be 932 tons in 1976 and 981 tons in 1980.
The largest incremental increase in Region II is projected
for 1977, when the increase is estimated at 1,093 tons. The
New Jersey-New York AQMA emissions account for approximately
two-thirds of the region total in 1976 and more than three-
fourths in 1980. Within the New Jersey-New York AQMA, the
New Jersey portion accounts for approximately 70 percent of
the increase in sulfur dioxide emissions in 1976 and more
than 82 percent in 1980. The Niagara Frontier AQMA accounts
for approximately 28 percent of the Region II emissions in
1976 but its share declines to about 10 percent in 1980.
The incremental particulate emissions in Region II are
projected to increase from 227 tons in 1976 to 289 tons in
1980. The New Jersey-New York AQMA accounts for approximately
80 percent of the Region II total. Within the New Jersey-
New York AQMA, approximately 77 percent of the incremental
increase is attributed to the New Jersey portion in 1976,
while in 1980 the New Jersey share is estimated at 87 per-
cent. The portion of the incremental particulate emissions
in Region II attributed to the Niagara Frontier AQMA declines
from approximately 10 percent in 1976 to 3 percent in 1980.
In Region III, the projected incremental emissions of
sulfur dioxide amount to 16,701 tons in 1976 and gradually
increase to 23,914 tons in 1980. Pennsylvania accounts for
approximately 36 percent of the emissions and Virginia
accounts for about 44 percent over the forecast period. Four
111-14
-------
AQMA account for almost one-third of the projected increases
in emissions. These are the Petersburg-Colonial Heights-
Hopewell and the Lynchburg AQMA in Virginia, and the Potomac
River and Baltimore AQMA in Maryland.
The incremental particulate emissions in Region III are
projected to be 1,588 tons in 1976 and are expected to in-
crease to 2,402 tons in 1980. More than one-half of the in-
crease is attributable to Pennsylvania and about one-fourth
is attributable to Virginia. Three AQMA, each with projected
emissions greater than 100 tons in 1976, account for approxi-
mately 42 percent of the incremental increase in particulate
emissions in Region III. These are the Potomac River AQMA
in Maryland, the Metro Philadelphia AQMA in Pennsylvania,
and the Petersburg-Colonial"Heights-Hopewell AQMA in Virginia.
In Region IV, the incremental emissions of sulfur
dioxide are projected to increase from 101,352 tons in 1976
to 190,053 tons in 1980. The two states with the largest
projected increases are Tennessee and Alabama. During the
forecast period, these states account for more than 45
percent of the regional total. Seven AQMA in Region IV are
projected to have incremental emissions greater than 1,000
tons in 1976. These AQMA are: Gadsden, Birmingham and
Mobile in Alabama; Lakeland-Winterhaven in Florida; Savannah
in Georgia; and Chattanooga and Nashville in Tennessee.
The incremental particulate emissions in Region IV are
projected to increase from 7,280 tons in 1976 to 13,216 tons
in 1980. Tennessee and North Carolina account for more than
50 percent of the increase in 1976. Five AQMA — Birmingham,
Mobile, Savannah, Chattanooga and Nashville — are projected
to have incremental emissions greater than 100 tons in 1976.
111-15
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In the calculation of both particulate and sulfur
dioxide emissions for Florida, it was assumed that all MFBI
are subject to the regulation pertaining to MFBI consuming
more than 250 MMBtu/hr. The Florida implementation plan
requires that sources consuming less than 250 MMBtu/hr. must
use the "latest reasonable available technology" in emissions
control.
In Region V, the incremental emissions of sulfur dioxide
-are projected—to increase~~from 34,144 tons in 1976 to 105,333
tons in 1980. In 1976, Ohio accounts for more than 50
percent of the increase. In 1980, Ohio's share declines to
about 20 percent of the total, while Illinois and Indiana
each account for about 25 percent of the total. Six AQMA in
Region V are projected to have emissions greater than 1,000
tons in 1976. These are the Illinois and Indiana portions
of the Illinois-Indiana-Wisconsin AQMA, Detroit, Cincinnati,
Toledo, Akron-Canton, and Columbus. By 1980, the Illinois
and Indiana portions of the Illinois-Indiana-Wisconsin AQMA ^
and Detroit are projected to have emissions in excess of
10,000 tons each and will account for more than 30 percent
of the total Region V incremental emissions of sulfur dioxide.
(The sulfur SIP for Ohio promulgated by EPA on August 27,
1976 is currently being challenged in the courts.)
The incremental emissions of particulates in Region V
are projected to increase from 4,255 tons in 1976 to 16,715
tons in 1980. Michigan and Ohio account for 67 percent of
the incremental emissions in 1976. Five AQMA"— Detroit,
Minneapolis-St. Paul, Cincinnati, Toledo, and the Indiana
111-16
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portion of the Illinois-Indiana-Wisconsin AQMA — are
projected to have incremental increases greater than 100
tons in 1976.
The Illinois projection assumes there are no "controlled"
sources as defined in the state's implementation plan. All
coal used as an alternate fuel in Michigan was assumed to be
pulverized coal and therefore subject to a stricter regula-
tion.
Region VI incremental emissions of sulfur dioxide are
projected to increase from 19,289 tons in 1976 to 70,352
tons in 1980. The majority of the increase is attributed to
Louisiana, which accounts for 63 percent of the Region VI
total in 1976 and 53 percent in 1980. No incremental in-
crease in emissions is attributed to Oklahoma during the
forecast period and no increase is projected for Texas until
1978. Emissions projected for the Shreveport, Louisiana
AQMA are almost 8,000 tons in 1980. In addition, the Little
Rock, Corpus Christi and Houston AQMA are projected to have
emissions in excess of 4,000 tons in 1980.
Incremental particulate emissions in Region VI are
estimated at 2,232 tons in 1976 and are projected to increase
to 11,892 tons in 1980. Louisiana's share of the increase
amounts to 88 percent in 1976 and 50 percent in 1980. By
1980 the Shreveport, Beaumont and Houston AQMA are projected
to have incremental particulate emissions in excess of 1,000
tons.
In Region VII, incremental sulfur dioxide emissions are
projected to increase from 15,860 tons in 1976 to 43,239
tons in 1980. Iowa and Kansas account for more than 75 percent
111-17
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of the increase. Iowa's share of the Region VII total in-
creases from 28 percent in 1976 to 41 percent in 1980. Six
of the eight AQMA represented in the MFBI data are projected
to have incremental increases greater than 1,000 tons in
1980. The largest increases are projected for the Missouri
portion of the Kansas City AQMA and the Des Moines AQMA.
The combined increases for these AQMA account for almost
one-fourth of the Region VII total in 1980.
__Incrementa 1-^artieui-ate—emrs~s±ons~~in Region VII are
projected to increase from 1,676 tons in 1976 to 4,880 tons
in 1980. The increases are most concentrated in Iowa, which
is attributed with more than 55 percent of the total in
1980. Three AQMA are attributed with incremental increases
of approximately 400 tons in 1980. These are Cedar Rapids
and Waterloo in Iowa, and Kansas City in Missouri and Kansas.
Incremental sulfur dioxide emissions attributable to
alternate fuel use in ..Region VIII are projected to increase
from 7,233 tons in 1976 to 13,591 tons in 1980. The largest
increase, more than 50 percent of the 1976 Region VIII
total, is attributed to Montana. AQMA with projected emissions
greater than 1,000 tons in 1980 include: Pueblo, Anaconda-
Butte, Salt Lake City and Provo.
Incremental particulate emissions in Region VIII are
estimated at 1,989 tons in 1976 and are projected to in-
crease to 3,842 tons in 1980. More than 60 percent of the
increase in 1976 is attributed to Montana. The increased
emissions are most significant in the Anaconda-Butte AQMA,
which accounts for almost one-third of the Region VIII total-
in 1980.
111-18
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In Region IX, the incremental emissions of sulfur
dioxide are projected to increase from 11,560 tons in
1976 to 51,691 tons in 1980. These emissions are primarily
attributed to California and Arizona. Nevada's share of the
emissions is less than one percent during the forecast
period. California's share of the emissions increases from
67 percent in 1976 to 85 percent in 1980. Eight of the
eleven AQMA represented by the MFBI data in Region IX are
attributed with emissions in excess of 1,000 tons in 1980.
Two California AQMA, Kern County and Southern Coast, are
attributed with 44 percent of the Region IX total in 1980.
Region IX incremental particulate emissions are pro-
jected to increase from 2,125 tons in 1976 to 17,282 tons in
1980. California's share of the total is estimated at 79
percent in 1976 and 96 percent in 1980. The remainder of
the emissions during the forecast period are attributed to
Arizona. Quantitatively, the particulate emissions are most
significant in the Southern Coast and San Francisco AQMA. In-
•-x
cremental emissions are projected to increase from 786 tons
in 1976 to 12,247 tons in 1980 in the Southern Coast AQMA,
while the increase in the San Francisco AQMA is estimated to
increase from 624 to 2,412 tons during the forecast period.
Region X incremental sulfur dioxide emissions are pro-
jected to increase from 5,807 tons in 1976 to 9,874 tons in
1978 and then decline to 8,449 tons in 1980. The increases
are primarily attributed to Washington, since Oregon's
maximum yearly share of the total is less than 11 percent
and Idaho's share is less than one percent during the fore-
cast period. The Washington portion of the Portland-Vancouver
AQMA and the Puget Sound AQMA are attributed with more than
60 percent of the Region X incremental sulfur dioxide emissions
in 1978.
111-19
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Incremental particulate emissions in Region X are pro-
jected to increase from 365 tons in 1976 to 754 tons in
1978 and then decine to 587 tons in 1980. Washington's
share of the total varies between 70 and 100 percent during
the forecast period. The remainder is almost entirely
attributed to Oregon. Only one AQMA, Puget Sound, is pro-
jected to have incremental particulate emissions in excess
of 100 tons during the forecast period.
111-20
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NATURAL GAS SUPPLY AND CONSUMPTION
IN THE UNITED STATES
For a number of years there has been a shortage of
natural gas in the United States and this shortage is likely
to continue. Gas supply has been insufficient to meet
demand by existing industrial and electric utility users,
and prospective residential and commercial users. As a
result/ emissions of sulfur dioxide and particulate matter
have been higher than they would have been if more gas had
been available.
The purpose of this chapter is to discuss gas supply
and demand trends, emphasizing the industrial consuming
sector and the role of natural gas in this sector. Partic-
ular attention is given to supply factors affecting the
level of industrial gas consumption in the future. Various
supply forecasts are reviewed and compared to provide a
framework for the industrial gas consumption projections in
Chapter I. As well, available data with respect to the
near-term outlook for industrial gas availability are dis-
cussed.
Natural Gas Consumption in the U.S.
Natural gas accounts for nearly a third of total primary
energy consumption in the U.S. The distribution of gas
consumption in 1974— by sector — residential, commercial,
I/ 1975 data are shown on sheets 5-8 of Schedule IV-1 but
are not discussed in the text. Since the latest actual data
for MFBI are 1974, it is appropriate that gross consumption
data be discussed for the 1974 base period.
IV-1
-------
industrial and electric utility — is set out on Schedule
IV-1 as reported by the Gas Requirements Committee. Sheets
1 and 2 of the schedule report gas consumption in billions
of Btu's by EPA Region and sheets 3 and 4 show the per-
centage distribution of gas consumption by sector for each
region and state.
In 1974 gas consumption in the Lower 48 States was
19,542 trillion Btu's. Of this total, firm residential and
commercial customers consumed 36.3 percent, firm industrial
customers consumed 33 percent, firm electric utility cus-
tomers consumed 11.2 percent, interruptible commercial
customers consumed 1.5 percent, interruptible industrial
customers consumed 11.6 percent, and interruptible electric
utility customers consumed 6.4 percent.
Among the various EPA Regions, considerable variation
occurs in the distribution of consumption by sector. For
example, nearly 75 percent of gas consumed in Regions I and
II was consumed by the residential-commercial sector. Con-
versely, industrial usage predominated in Regions IV, VI,
and X where industrial sector consumption was, respectively,
52.2 percent, 57.3 percent, and 60.9 percent. Electric
utilities, consuming 17.6 percent of gas consumed in the
Lower 48 States, had gas usage of less than 5 percent in
Regions I, III, V, and X. Largest electric utility sector
shares of gas consumed were in Regions VI and VII — 31.8
percent in the former and 24 percent in the latter. Review
of the schedule also indicates considerable diversity in the
distribution of consumption by state, both within and across
EPA Regions.
Compared to electric utility and industrial gas con-
sumption, residential-commercial gas consumption is relatively
IV-2
-------
more evenly distributed across the 48 states. Approximately
56 percent of 1974 residential-commercial gas consumption
occurred in -8 states — California, Illinois, Ohio, Michigan,
New York, Pennsylvania, Texas and Indiana, in descending order
of importance.
In contrast, four states — Texas, Louisiana, Oklahoma,
and California — account for 66 percent of electric utility
gas consumption. Texas predominates, accounting alone for
over a third of electric utility gas consumption.
More than two-thirds of industrial gas consumption
occurred in 1974 in the eight states listed in the table
below.
INDUSTRIAL GAS CONSUMPTION BY STATE
1974
Percent of Lower 48
Trillions of Btu's State Total
Texasr ' 2,338 26.9
Louisiana 1,141 13.1
California 585 6.7
Ohio 436 5.0
Illinois . 379 4.3
Pennsylvania 353 4.1
Michigan 348 4.0
Indiana 267 3.1
All Other States 2,857 32.8
Total 8,704 100.0
Source: Gas Requirements Committee
Texas, Louisiana, California, and Ohio were the four
largest industrial gas consumers with a combined total of
nearly 52 percent of Lower 48 State consumption. Regions V
and VI were the leading industrial gas consuming regions
IV-3
-------
with, respectively, 19.1 percent and 44.3 percent of Lower 48
State consumption.
Excluding California, in each of seven of the largest
gas consuming states firm contracts dominate industrial con-
sumption. Firm volumes are 90 percent or greater in Penn-
sylvania, Ohio, Illinois, and Texas, and as high as 98.5
percent in Louisiana. However, in California firm gas is
only 15.1 percent of total industrial gas consumption,
reflecting California regulatory policy of not allowing firm
industrial contracts over 200 Mcf/day.
In most of the remaining states interruptible contracts
are relied upon to a greater degree. A partial list includes
Florida, Georgia, and South Carolina in Region IV; Wisconsin
in Region V; Oklahoma in Region VI; Kansas and Missouri in
Region VII; North and South Dakota, Montana, Utah, and
Wyoming in Region VIII; and Washington in Region X.
In recent years, gas consumption by all sectors has
declined, in part due to warm weather, conservation and
the economic recession, and in part due to insufficiency of
supply. Schedule IV-2 shows trends in the supply and con-
sumption of natural gas in the Lower 48 States since 1960.
Residential-commercial gas consumption increased each
year from 1960 to 1972, at an annual average rate of 5.0
percent. Since its 1972 peak, it declined by 3.2 percent
in 1973, 1.7 percent in 1974, but increased 1.9 percent in
1975. The declines are attributable to warmer than normal
weather, conservation which first occurred during the Oil
Embargo and has persisted thereafter, and limitations on the
attachment of new customers which are prevalent in various
parts of the U.S.
IV-4
-------
Electric utility gas consumption, which increased
rapidly to 1971, has decreased even more rapidly since a
negligible decline in 1972. In 1973 gas consumption dropped
9.5 percent, in 1974 gas consumption dropped 5.0 percent,
and in 1975 gas consumption dropped 8.4 percent.
Industrial gas consumption peaked in 1973 and has
declined sharply sinc.e then. In 1974, industrial gas con-
sumption dropped 5.0 percent and in 1975 it dropped a further
16.2 percent. Available information for the first few months
of 1976 indicates a further but not nearly as large reduction
compared with the like period in 1975.
The Role of Natural Gas in Fulfilling Energy
Requirements by Sector in the U.S.
Gas competes in varying degree with other forms of
energy in all market sectors. The discussion in this section
focuses on the role of gas as an energy source vis-a-vis
other fuels in the consuming sectors, especially the indus-
trial sector. Energy consumption by stationary users in
1974 is set out by sector, EPA Region and state on Schedule
IV-3. Sheets 1-2 show the distribution by fuel type in
the residential-commercial sector;— sheets 3-4 show the
distribution by fuel type in the industrial sector; and
sheets 5-6 show the distribution by fuel type in the
electric utility sector.
Especially with respect to the industrial sector, it
is important to note that the data on IV-3 cover all users
in each sector. The MFBI data with respect to large combustors
discussed in previous chapters which are the focal point of
I/ The sources of data do not permit a basis for separating
the residential and commercial sectors of the market.
IV-5
-------
this study comprise only a portion of the industrial sector.
It is estimated that the large industrial combustors analyzed
by this study account for 33 percent of industrial gas con-
sumption and 44 percent of industrial energy consumption.
With respect to the residential-commercial sector, gas
is the dominant fuel in the United States. Of total residential-
commercial energy use, gas accounted for 49.5 percent. Fuel
oil and electricity follow in importance with 22.9 and 21.5
percent, respectively. Least significant are coal and LPG
with a combined total of 6.1 percent.
Fuel dominance and the energy mix vary significantly by
EPA Region and state within the residential-commercial
sector. In 1974, gas was the dominant residential-commercial
fuel in Regions III, V, VI, VII, VIII and IX, with shares of
energy consumption greater than 50 percent and as high as
68.2 percent in Region IX. Distillate fuel oil predominated
as an energy source in Regions I and II with 59.1 percent
and 43.9 percent of Btu's consumed, respectively. Electricity
was the most important energy source in Regions IV and X —
39.2 percent of Btu's consumed in the former and 41.7 per-
cent of Btu's consumed in the latter.
In the electric utility sector coal is the primary fuel
utilized to generate power. Excluding electricity generated
for hydro and nuclear, coal accounted for 55.4 percent, gas
for 22.4 percent, residual fuel oil for 19 percent and
distillate fuel oil for 3.2 percent.
Residual fuel oil is the predominant electric utility
fossil fuel in Regions I and II, followed by coal. Residual
IV-6
-------
fuel oil is also predominant in Region IX, followed by gas.
Coal is predominant in Regions III, IV and X, followed by
fuel oil in varying degree, and in V, VII, and VIII, fol-
lowed by gas. Gas is predominant only in VI, followed by
coal.
Gas is the dominant energy source for industrial users.
In 1974, industrial sector energy consumption amounted to
12,887 trillion Btu's. Of this total, gas accounted for
8,704 trillion Btu's, or 67.5 percent; residual fuel oil—
for 2,054 trillion Btu's, or 15.9 percent; coal for 1,578
trillion Btu's, or 12.3 percent; distillate fuel oil for 449
trillion Btu's, or 3.5 percent; and LPG for 102 trillion
Btu's, or 0.8 percent.
Again, as in the other sectors, fuel dominance and
energy mix vary significantly by EPA Region and state. In
1974, gas dominated as an industrial energy source in all
EPA Regions except Regions I and II, where residual fuel oil
was by far the most important energy source, accounting for,
respectively, 80.2 percent and 65.5 percent of industrial
energy consumption. Gas utilization ranged from as low as
13.8 percent of industrial energy consumption in Region I to
as high as 79.3 percent in Region IX and 93.2 percent in
Region VI. Coal was most significant as an industrial
energy source in Regions III and V, accounting for about 26
percent of all Btu's consumed by industrial users. In addition,
coal and oil competed more or less equally as industrial
energy sources in Regions III, IV and VIII; and, excluding
I/ Includes No. 6 heating oil and all other residual type
oils sold to industrial customers and oil companies.
IV-7
-------
relatively insignificant LPG use, industrial energy con-
sumption in Region III was more evenly distributed among
fuel oil, gas, and coal than in all other EPA Regions.
The relative roles of gas, residual fuel oil, and coal
as industrial energy sources are seen from the table below
to vary significantly in several of the largest industrial
energy consuming states.
INDUSTRIAL ENERGY CONSUMPTION BY STATE
1974
Trillions of Btu's
Percent Distribution by Fuel Type
Fuel Oil
Gas Distillate Residual Coal LPG Total
93.7%
1.4%
2.3%
2.4% 0.2% 100.0%
94.9
55.1
79.7
50.7
60.4
20.3
58.0
67.5
2.2
4.3
4.1
3.6
2.7
2.7
4.6
3.5
1.8
4.0
14.1
24.3
18.1
67.0
20.5
15.9
-
36.2
0.1
20.7
17.7
9.5
16.0
12.3
1.1
0.4
2.0
0.7
1.1
0.5
0.9
0.8
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
Texas 2494
Louisiana 1203
Ohio 792
California 734
Pennsylvania 696
Illinois 627
New York , 550
All Other States^ 5791
Total 12887
a/ Excluding Alaska and Hawaii.
In Texas and Louisiana, where 1974 industrial energy
consumption was about 29 percent of the Lower 48 State
total, gas utilization accounted for greater than 90 percent
of industrial energy consumption. Though not to the same
extent, California is similar to Texas and Louisiana in that
gas was the primary fuel burned for industrial purposes.
Conversely, in New York, where residual fuel oil dominated
with 67 percent of 1974 industrial energy consumption, gas
for industrial use accounted for only 20.3 percent of Btu's
consumed.
IV-8
-------
Illinois, Pennsylvania, and Ohio, states where gas was
the dominant fuel, differ from Texas, Louisiana, and Califor-
nia, not only in the degree of dependence on gas as an
industrial energy source, but also in that coal and/or
residual fuel oil were more significant factors in the
energy mix. Whereas coal accounted in 1974 for 36.2 percent
and residual fuel oil for 4 percent of industrial energy
consumption in Ohio, coal and residual fuel oil had more
equivalent shares of industrial Btu's consumed in Pennsyl-
vania and Illinois. Residual fuel oil was a more significant
factor in Pennsylvania than in Illinois, accounting in the
former for about 24 percent of industrial energy consumption,
and in the latter for approximately 18 percent. Coal,
though not as important an industrial energy source as in
Ohio, accounted for 20.7 percent of industrial Btu's con-
sumed in Pennsylvania and 17.7 percent of industrial Btu's
consumed in Illinois.
IV-9
-------
Trends Underlying The Current Gas Shortage In The U.S.
It is evident that the Nation's gas supply picture has
been deteriorating for some years, as shown on Schedule IV-4.
Proved reserves have been declining since 1967, although pro-
duction increased during most of this period. Production
peaked in 1973, and declined in 1974 and 1975 by nearly six
percent and eight percent, respectively. It is estimated
that during the first eight months of 1976, production has
further declined by slightly over two percent.
The precipitous drop in proved reserves since 1967,
culminating in declining production, reflects the failure
of reserves additions to replace production. In 1968 re-
serves additions were less than production for the first time
since World War II, and this situation has continued in the
Lower 48 States every year since 1968. From 1971 to 1975,
reserves additions have averaged 8.8 Tcf per year, thus re-
placing only 41 percent of production during this period.
This low level of reserves additions in part reflects
large negative revisions to previous estimates incorporated
in more recent estimates. These changes in previous esti-
mates may result from geologic or engineering data provided
by additional drilling, production history, or the applica-
tion of cycling or other recovery techniques. Exclusive of
all revisions (both positive and negative) reserve additions
have averaged 10.1 Tcf per year for the last five years.
With respect to interstate markets for natural gas,
trends in production and reserves additions reflect a worse
picture than the Nation as a whole. Schedule IV-5 shows that
IV-10
-------
over the last five years, reserve additions have replaced
only three percent of production - considerably below the
experience for the Nation as a whole. Interstate production
peaked in 1972, a year before total production in the U.S.
peaked. Thereafter, interstate production has declined
steadily at a faster pace than overall U.S. production - by
3.5 percent in 1973, 5.1 percent in 1974, 6.9 percent in 1975,
and by 4.9 percent for the first five months of 1976. These
adverse trends reflect the difficulty faced by interstate
pipelines in competing for new onshore gas supplies against
intrastate purchases which are not restricted by FPC price
ceilings.
In recent years the primary source of new gas reserves
for interstate pipelines has been offshore areas of the U.S.,
primarily the Louisiana portion of the Gulf of Mexico. It
is evident from Schedule IV-5, however, that the experience
of interstate pipelines in the Gulf of Mexico has not been
able to offset the impact of onshore developments.
Schedules IV-6 and IV-7 show trends in production and
reserves additions for major producing areas in the United
States. With respect to production, the data on Schedule IV-6
reveal the increasing importance of offshore South Louisiana.
By 1975, this area accounted for 17 percent of total production
in the Lower 48 States compared with 10 percent in 1970 and
2 percent in 1960. Offshore South Louisiana accounted for
a substantial portion of the growth in Lower 48 production
from 1965 to 1970 and was the only major producing area
between 1970 and 1975 to experience any substantial growth.
From 1974 to 1975 production declined significantly in all
major producing areas except offshore South Louisiana, where
production increased by only 0.6 percent, its lowest annual
growth since before 1960.
IV-11
-------
A generally similar picture is evident with respect to
reserves additions. Again, offshore South Louisiana accounted
for a major share of Lower 48 reserve additions since 1967,
approximately one-third. Comparing reserves additions for
the 1960-1967 period with the 1968-1975 period, average re-
serve additions during the more recent period declined
substantially in all major producing areas except the offshore
South Louisiana, Hugoton-Anadarko and Rocky Mountain areas.
Reserve additions in the latter two areas, however, have been
nevertheless insufficient to replace production during this
period.
Underlying these trends in reserves additions are two
major components thereof - well drilling and productivity.
The term productivity refers to the relationship between
exploration inputs (e.g., well drilling) and outputs or the
results (e.g., reserves additions). As used herein, the term
productivity refers to additions of non-associated gas re-
serves per foot of gas well drilled.
Schedule IV-8 shows trends in well drilling in the Lower
48 States. As shown on the schedule, well drilling -
successful oil and gas wells and dry holes - steadily declined
from 1960 to the early 1970's. This decline in well drilling
in large measure explains the drop in reserves additions
beginning in the late 1960's. But, applicable to all well
drilling and particularly gas, the level of well drilling has
increased substantially in recent years. Gas well drilling
is now at record highs. As shown on the following table,
most of the increase in gas well footage has been onshore.
IV-12
-------
TOTAL U.S. GAS WELL FOOTAGE
(thousands of feet)
Onshore Offshore Total
1971 20,463 2,161 22,624
1972 25,109 1,656 26,765
1973 33,079 2,522 35,600
1974 37,249 1,738 38,986
1975 39,999 1,929 41,927
During the first half of 1976, total gas well footage,
both onshore and offshore, has increased still further. The
steep rise in onshore footage during the 1970's is generally
attributed to the substantial increases in gas prices for
intrastate markets.
Despite the overall increase in gas well footage, reserve
additions have not increased. The decline in the productivity
of drilling in recent years has been responsible. Schedule
IV-9 shows additions to reserves per foot of gas well drilled.
The data vary erratically from year to year and even five
year moving averages do not display a smooth trend. Never-
theless, the data show that productivity during the period
1969 to 1975 was sharply lower than in prior years, varying
between 113 Mcf per foot to 475 Mcf per foot compared to an
average of 616 Mcf per foot from 1958 to 1968. In its most
recent new gas rate determination - Opinion 770 discussed
more fully at a later point - the Federal Power Commission
employed a productivity factor of 300 Mcf per foot.
IV-13
-------
It is evident from the foregoing discussion that the
continued low level of reserves additions has been in large
degree brought about by the sharp decline in productivity.
Some particular comment seems in order concerning the future
productivity of drilling in light of the conspicuous decline
since 1969. In the longer-term, it may be anticipated that
productivity will decline as the volume of remaining reserves
to be found decreases. This long-term tendency may, neverthe-
less, be subject to short-term unpredictable reversals as new
petroleum provinces are opened up in the exploration process.
Recent Natural Gas Pricing Developments
The price of natural gas in the field obviously influences
the incentive to find additional gas, and thus the purpose of
this section is to briefly discuss natural gas pricing develop-
ments which will influence gas supply to 1980.
An important factor which explains the inability of
interstate pipelines to acquire new onshore gas reserves has
been the wide disparity between the ceiling price interstate
pipelines could pay and the prices being offered by intrastate
purchasers. This problem has existed for a number of years,
but the difference between interstate and intrastate prices
has been increasing. Prior to 1972, the intrastate purchaser
needed only to offer a modest premium over interstate prices
to obtain gas. Competition among intrastate purchasers in-
creased subsequently as the gas shortage worsened, and
prevailing intrastate prices soared. In 1974 intrastate
prices averaged 92C/Mcf, compared with the 51$ national rate
promulgated by the FPC at the end of that year and lower
rates prior thereto. By the second quarter of 1976, the
IV-14
-------
average price for new intrastate contracts reached $1.59/Mcf.
There are, of course, variations in these prices by area, but
it is generally believed that these intrastate prices have
elicited the substantial upturn in gas drilling in onshore
areas.
In July of 1976, the FPC increased the national rate
for new gas to $1.42/Mcf. This was equivalent to somewhat
less than a doubling in prospective price to the producer,
after adjustment for tax and royalty components.— The new
national rate remains below prevailing intrastate prices in
most onshore areas, and thus will have only a limited impact
on onshore gas acquisitions by interstate pipelines. However,
the new rate should provide a greater incentive than would
have existed otherwise for offshore drilling.
Producers can also apply to the FPC for special relief,
or higher prices, if "out-of-pocket" expenses exceed revenues.
Prior to the release of the $1.42 rate determination, the
FPC approved a number of prices above the then existing
national rate on the basis of cost. The future direction of
the FPC in special relief cases cannot be assessed at -this
time.
Particularly applicable to industrial gas supply and to
a few MFBI is the FPC's Order 533 procedures, although not a
pricing policy per se. The FPC's Order 533, adopted October
1975, makes available natural gas supplies to industrials in
the interstate market from the intrastate market.
I/ Due to the elimination of the depletion allowance, the
FPC included income taxes as a cost in the $1.42 deriva-
tion which was not included in the earlier $0.51 derivation.
IV-15
-------
Under the terms of this policy, jurisdictional pipelines who
are granted transportation certificates of public convenience
and necessity may transport-natural gas supplies purchased
by an industrial or commercial customer from an independent
gas producer for non-resale, high priority end-uses (Priorities
2 and 3), for delivery at the customer's plant. This pro-
cedure is subject to the following conditions:
1. The transporting pipeline must be curtailing
deliveries of gas to its customers and have available
unused capacity to transport natural gas.
2. The pipeline must be capable of ascertaining a
firm price to be paid.
3. The Order 533 volume is not considered part of
the pipeline's available supply, therefore, it is
not subject to the Commission's curtailment policies.
4. The Order does not apply to gas sold by an affiliate
of a jurisdictional pipeline or gas sold by a producing
division of such a pipeline.
5. The certification period is for a maximum of two
years.
6. The Order applies only to existing customers
whose deliveries for high priority uses are curtailed
because of curtailments by the jurisdictional pipeline
supplier, or whose deliveries are subject to imminent
curtailment.
IV-16
-------
7. Since purchasers buy directly from the producers,
sales are non-jurisdictional.
8. The Order applies only to customers who have no
alternate fuel capabilities for their combustors, and
require a minimum of 50 Mcf per peak day.
9. Purchasers must submit a monthly report to the
transporting pipeline, who in turn submits it to the FPC,
containing the amount of gas consumed and for what end-
use in that month.
10. A detailed description of the nature of the emergency
must also be provided.
Very significant curtailments have been experienced by
Transcontinental Gas Pipeline, Columbia Gas Transmission,
Texas Eastern Transmission and Panhandle Eastern Pipeline.
It is predominantly those four who have filed applications
for Order 533 transportation certificates.
Approximately 54 industrial companies with a total
volume of 52 Bcf per year have been granted such certificates.
Ten MFBI are included, with a volume of 2,819.5 Mmcf per
year of gas to be transported as compared with 3,761.8
Mmcf of gas consumed by their major combustors in 1974. The
emergency gas represents 75 percent of the 1974 gas con-
sumption in major combustors for these MFBI.
Of the 10 plants included, a majority are in the textile
manufacturing industry with a few in the agricultural chemicals
and paper manufacturing field. All are located in EPA Region IV
with the exception of one which is in Region III. The emergency
gas is transported by Transcontinental Gas Pipeline for all
IV-17
-------
plants with the exception of one being transported by
Tennessee Gas Pipeline. The volume of emergency gas for the
MFBI in Region III is 620.5 Mmcf per year as compared with
339.9 Mmcf consumed in their major combustors in 1974. In
Region IV the volume is 2,199.0 Mmcf per year for the 9
MFBI compared with 3,421.9 Mmcf of gas consumed by their
major combustors in 1974.
According to their applications, these plants were
faced with total or near-total plant shutdown, plant lay-
offs and production cutbacks because of their essential need
for natural gas and the resultant curtailments. For the
textile companies natural gas is necessary for their process
needs in a number of direct-fired finishing operations. The
heat-setting and resin curing of some plants require an even
flame which can only be achieved with natural gas or propane.
The agricultural chemical plants utilize natural gas in
direct-fired operations in nodulizing kilns which require
intense heat for calcining, plant protection (Priority 2)
and processing usage (Priority 3); also used in applications
to generate process steam, operate incinerators and sulphur
deodorizing units in the manufacture of pesticides.
Of the ten MFBI authorized to receive Order 533 gas,
nine will use it in combustors other than those considered.
The pertinent MFBI intend to use the emergency gas in smaller
process combustors, while the combustors which are studied
herein are large boilers. Thus, it is apparent that Order
533 volumes to industrials authorized to date will have a
limited effect on the shortages forecast in this study.
IV-18
-------
Comparison of Forecasts of U.S. Gas Supply
Schedule IV-10 compares recent estimates of Lower 48
gas production by government and industry sources. As dis-
cussed earlier, Lower 48 production has already declined
substantially, from 22.5 Tcf in 1973 to 19.6 Tcf in 1975.
The striking feature of all the forecasts depicted on Schedule
IV-10 is the unanimity of opinion that production will
continue to decline to 1980 and thereafter, unless gas
prices are deregulated. Even with deregulation, those
forecasts which assume these higher prices indicate only
modest increases in production.
The FPC Bureau of Natural Gas prepared three alternate
forecasts of gas production, termed "Low," "Medium," and
"High." The "Low" case, which shows nearly a two-thirds re-
duction in gas production to 1985, assumed no reserves
additions and is thus useful only for illustrative purposes.
Basically, this forecast indicates a 9.4 percent annual de-
cline in production from existing proved reserves. In the
"Medium" forecast, which could be characterized as a con-
tinuation of trends since 1968, reserves additions were
assumed.to be at levels experienced from 1969 to 1973. With
reserves additions averaging approximately 9.5 Tcf per year,
this forecast indicates a 3.4 percent annual decline in
production to 1985. The "High" forecast assumes reserves
additions of 14.7 Tcf, the average between 1960 and 1973,
and this forecast indicates a 1.2 percent annual decline to
1985. Since the base year for the FPC projections was 1973,
and actual reserves additions during 1974 and 1975 have been
lower than forecast in the "High" case, the "High" production
forecast in 1980 may be slightly overstated.
t
The Gas Requirements Committee (GRC) forecast is comparable
to the FPC "Medium" case, and seems to reflect a continuation
IV-19
-------
of recent trends. Since the GRC summarizes projections of
individual gas companies throughout the U.S., this forecast
does not specify assumptions. Each company makes its own
assumptions regarding gas supply and regulatory climate.
Thus, the GRC forecasts reflect the best estimates of
sellers of gas as to future supply and consumption of gas.
Shown next on the schedule is the most recent forecast
by the U.S. Department of Interior. Interior also forecast
a steady decline, but at a slightly lesser rate than the
"Medium" FPC and GRC forecasts. Important assumptions made
by Interior regarding gas supply are-1) deregulation of oil
prices; 2) relaxation of Federal Power Commission wellhead
price controls; and 3) continued leasing of the Federal
offshore areas at the accelerated pace currently proposed by
the Department of Interior.
The Federal Energy Administration generated six forecasts
of Lower 48 production with their PIES models, all of which
are shown on Schedule IV-10. Four of the scenarios assume
deregulation of both oil— and gas, while two assume continued
price regulation for gas. All the forecasts shown assume
world oil prices of $13/bbl. in 1975 dollars. The reference
deregulation case shows a very slight increase in production
in 1985, the optimistic deregulation case shows a larger
increase, and the pessimistic deregulation case shows a
marked decline. The various deregulation cases make dif-
ferent assumptions as to the amount of potential gas remaining
to be discovered, the amount of OCS leasing, and the invest-
ment tax credit. Under deregulation (the reference or base
case) FEA projects a significant improvement in interstate
supply, but a reduction in intrastate supply.
I/ Oil prices and hence oil production affect associated-
dissolved gas production.
IV-20
-------
The FEA Projection of
Interstate and Intrastate
Net Domestic Supplies—
(Tcf)
Present Regulation Deregulation
Interstate Intrastate Interstate Intrastate
1974
1985
11.6
6.6
7.2
9.3
11.6
12.1
7.2
7.9
a/ Gas consumed by end-users, excluding SNG and imports
but including Alaskan gas.
The next forecast depicted on Schedule IV-10 is by Shell
Oil Company. Shell's projection appears to reflect a continu-
ation of recent trends and is comparable to the FPC "Medium"
case and the GRC forecast.
Three forecasts by the American Gas Association (AGA)
are shown. The AGA deregulation projection indicates a
<-v
virtually imperceptible increase in gas production. Of the
available forecasts, AGA was the only source to project gas
production, assuming regulation, taking into account the
recent upward revision in the national interstate rate.
This forecast shows production declining, but not falling to
the levels that would occur if current trends were maintained.
With respect to the AGA forecasts, it should be noted that
substantial East Coast Offshore production is projected for
1985.
Future gas consumption will not, of course, be limited
to conventional Lower 48 production. At the present time,
imports of Canadian gas account for nearly 5 percent of U.S.
consumption and propane air and SNG for about 2 percent. Addi
tionally, it is expected that Alaskan ^as, imported LNG, and
IV-21
-------
increased volumes of SNG will play an important role in
meeting gas requirements. Schedule IV-11 compares forecasts
of total gas supply in 1980 and 1985 by four of the sources
previously discussed in the context of conventional production.
For both 1980 and 1985, three of the four sources show
very similar projections - a small decline from 1974 levels.
The mix and volumes of supplements varies among GRC, Interior
and Shell Oil, but the totals are comparable. FEA's 1985
total supply, which also assumes deregulation, is substan-
tially higher. However, FEA's total is less of a projection
of what will be, and this projection should be construed as
what could be if various positive actions are taken.
The GRC forecast of total gas supply is shown by
component - SNG, propane air, and LNG - on Schedule IV-12.
Substantial and increased amounts of SNG and LNG are pro-
jected to 1980 and 1985. To 1980, the forecast of SNG from
liquid hydrocarbons, which are the largest components of the
total SNG, is deemed reliable because it is apparently based
largely on plants already constructed„ However, the SNG
forecast includes coal gas in the amount of 34 trillion
Btu's in 1979 and 96 trillion Btu's in 1980 which probably
reflects a plant contemplated to serve the West Coast.
Since the publication of the GRC forecast, this plant has
experienced delays in go-ahead and likely will not be in
full operation by 1980. Also experiencing delays have been
the East Coast LNG projects which are reflected in the GRC
projections beginning in 1976.
IV-2 2
-------
The GRC Forecast Of Consumption
Of all the forecasts discussed, only GRC projected gas
consumption regionally (and by state) by sector. Schedule
IV-13 shows the GRC consumption projection by sector and
EPA region. Since the GRC forecast is made by gas sellers,
who make their own assumptions as to supply and regulatory
climate, the GRC forecast reflects company marketing strategies
and regulatory curtailment strategies. The GRC supply fore-
cast to 1980 appears to represent the concensus of opinion,
and hence the resultant forecast of consumption under these
supply conditions is extremely useful.
National gas consumption at the end-use level— is pro-
jected to decline from 19,541 trillion Btu's in 1974 to
17,347 trillion Btu's in 1980 - an annual rate of decline of
2 percent. Forecast trends by sector are divergent, however,
with residential and commercial consumption increasing and
industrial and electric utility use decreasing. Residential
and commercial consumption are expected to grow at annual
rates of 2.2 percent, while industrial use is projected to
decline at a rate of 4.2 percent, and electric utility use is
projected to decline at a rate of 7.3 percent.
These trends reflect prevailing marketing and curtail-
ment strategies by gas companies and regulatory agencies.
New residential and commercial customers are being added in
some parts of the country, while existing industrial and
electric utility gas users are being curtailed. Most affected
I/ Lower 48 states only. Includes gas usage in the
residential, commercial, industrial, and electric utility
sectors; excludes gas consumed for field use and gas usage
not accounted for in specific categories (i.e., pipeline
fuel, company use, transmission loss).
IV-2 3
-------
are interruptible electric utility and industrial gas users.
The combination of generally declining or even stable gas
supply and increasing higher priority consumption results in
large declines in the availability of gas for lower priority
uses.
These trends are generally projected for all EPA regions
but in varying degree. Residential consumption is shown to
increase in every region, and commercial consumption is shown
to increase in all regions except Region III. Industrial
consumption is anticipated to decline in all regions except
Region X, where 0.6 percent annual growth is expected.
Declines range from 1»3 annually in Region I— to 6 percent
in Region III and 8.6 percent in Region IV. Generally,
interruptible industrial consumption is shown to decline more
severely than firm consumption. Substantial declines in
electric utility consumption are projected in all EPA Regions.
Sources of Gas Supply By State
Schedule IV-14 shows the sources from which each state
obtained its gas supply in 1974. Reading downward, the
columns show the percentages of total state consumption which
were delivered by each of the major interstate pipelines, by
the other interstate pipelines grouped together, and also the
percentages derived from production within the state and de-
livered by intrastate facilities.
Region I was almost completely dependent on two pipe-
\
lines, Tenneco and Texas Eastern. New Hampshire was entirely
served by Tenneco while Connecticut and Massachusetts received
I/ This decline occurs in 1976, after which consumption is
shown to increase, presumably due to anticipated receipt of
LNG.
IV-2 4
-------
about half of their supplies from Tenneco and half from
Texas Eastern via Algonquin. In Massachusetts, the Boston
and Providence areas in the East were served mainly by
Texas Eastern and the rest of the state mainly by Tenneco.
The supply of gas to Vermont was entirely from Canadian
sources.
In Region II, Transcontinental was the chief supplier.
New Jersey received 60 percent of its gas from Transcontinental,
34 percent from Texas Eastern and 6 percent from Tenneco.
The northern part of the state, and parts of the southwest
were served by Transcontinental and Texas Eastern supplied
Ocean County in the east. New York received 29 percent of
its gas supply from Consolidated which supplied gas in
Rochester and across the center of the state. Transcontinental
supplied 28 percent and was important in the area close to
New York City. Columbia, Tenneco and Texas Eastern each
contributed 6 or 7 percent of the state's total supply.
Columbia supplied Binghamton,.and Tenneco and Texas Eastern
brought part of the supply to the northwest. A further
21 percent of New York's gas was supplied by Tenneco, Con-
solidated and others through the National Fuel Gas Supply
and Distribution Corp. and this gas was mostly delivered
in the Buffalo area.
In Region III, Delaware was entirely supplied by Trans-
continental and Maryland almost entirely by Columbia with
about 2 percent from Transcontinental in the East.
Pennsylvania received 27 percent of its gas from
Columbia, 15 percent from each of Texas Eastern and Trans-
continental, 13 percent from Consolidated and 6 percent from
Tenneco. A further 12 percent came from National Fuel Gas
IV-25
-------
which itself obtained most of its gas from these five major
pipelines. The Philadelphia area was served mainly by
Texas Eastern and Transcontinental and the southwest mainly
by Columbia, Texas Eastern and Tenneco. Consolidated contri-
buted some of the gas in the northwest. Pennsylvania also
received 6 percent of its gas from intrastate suppliers.
The greatest part of Virginia supplies (62 percent)
came from Columbia. The state also received 32 percent from
Transco and 6 percent from Tenneco. Columbia gas went to
most parts of the state. Transco supplied Danville, and
contributed with Columbia to the southeast. Tenneco contri-
buted to the supply in the Valley of Virginia.
In West Virginia, over half (56 percent) of the supply
came from Columbia which provided gas in the Charleston,
Huntington and Bluefield areas and also in Wheeling. Relatively
small amounts of gas came from Consolidated and Tenneco, and
over a third of the total supply was locally produced, and
delivered by intrastate lines.
In Region IV, Southern Natural was the most important
supplier, serving gas in six of the eight states in the
region and bringing 60 percent or more of the total supply
to three of them. In Alabama, 60 percent of the supply was
provided by Southern Natural, 13 percent by each of Tenneco
and United, some smaller amounts by other pipelines and 8
percent was intrastate gas. Southern Natural, through the
Alabama Gas Corporation, served the Birmingham and Montgomery
areas, and central and southeast Alabama. Tenneco provided
gas in the Tennessee River Valley area in the north and
United was the chief supplier in the Mobile area in the south-
west.
IV-2 6
-------
Four-fifths (82 percent) of the gas requirements in
Florida were provided by Florida Gas Transmission Co. It
supplied the area around Jacksonville in the north, and was
the sole supplier for central and southern Florida. United
was the next largest supplier, bringing 11 percent, and it
served the Pensacola area in the northwest. Southern Natural
contributed 3 percent and served the area surrounding
Tallahassee in the north. Florida also had some intrastate
supplies, amounting to 4 percent of the total.
/
Georgia depended on two suppliers only. Southern Natural
provided 89 percent and served gas in all parts of the state.
Transcontinental supplied the remaining 11 percent in the
north and northeast parts of the state.
The chief supplier in Kentucky was Texas Gas, providing
55 percent of supplies. The next largest was Columbia with
23 percent, and Tenneco provided 13 percent. The main dis-
tributor in the western third of the state, the West Kentucky
Gas Co., was supplied by Texas Gas and Tenneco - Texas Gas
being most important in the west. Texas Gas also supplied
the Louisville area and north central Kentucky. Columbia
Gas supplied the Lexington - Richmond - Winchester area and
Tenneco supplied Ashland. Kentucky also had some local pro-
duction and 3 percent of total supplies came from intrastate
sources.
In Mississippi, gas was provided by ten of the major
pipelines but six of these contributed 2 percent or less of
total supplies. The largest supplier was United, bringing
35 percent; Southern Natural brought 13 percent; Texas Gas
10 percent; and Tenneco 9 percent. A further 21 percent of
supplies was due to "other interstate pipelines," most of
this coming from offshore Louisiana. Southern Natural
IV-2 7
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served the Vicksburg and Yazoo areas; and United supplied gas
in central and southeastern Mississippi, except for Standard
Oil's refinery at Pascagoula which was supplied direct from
offshore Louisiana by means of its subsidiary,.the Chandeleur
Pipeline Company.
The entire requirements of North Carolina were supplied
by Transcontinental.
South Carolina was served by Transcontinental in the
north, bringing 29 percent of the total supply. The southern
part of the state, including Columbia and Aiken County, was
supplied by Southern Natural which provided 71 percent of the
total supply.
Tennessee received 53 percent of its gas requirements
from Tenneco. This pipeline supplied Nashville and its
environs and all the eastern half of the state, comprising
the Chattanooga, Knoxville and Johnson City areas. Southern
Natural contributed part of the Chattanooga supply. Texas
Gas supplied 35 percent of the state's consumption,, providing
gas for the Memphis area where there are eight MFBI and
also for Jackson in Madison County. Hardin and Humphreys
Counties are served by Tenneco.
In Region V, the chief suppliers were Columbia, Michigan-
Wisconsin, Natural, Northern and Panhandle. The predominant
supplier in Illinois was Natural, which supplied 64 percent
of requirements. This company served the Chicago area
(Cook and Wills Counties) where most MFBI were located,
and most other parts of the state including the Decatur area
IV-2 8
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and East St. Louis. Panhandle provided 13 percent of total
f@$uif$ffl€nt§ in the central part of the state and in the
northwest. Midwestern provided 10 percent, mainly in the
northeast, and Mississippi River brought 5 percent in and
around East St. Louis.
Indiana received one-third of its supplies from Panhandle,
27 percent from Natural, 19 percent from Texas Gas and 17 per-
cent from Midwestern. Nearly half of the MFBI in Indiana
were in the northwest corner, in Lake County. The gas for
the northern part of the state came mainly from Panhandle,
Natural and Midwestern. Central Indiana (Indianapolis,
Anderson and Muncie) was served by Panhandle and Michigan-
Wisconsin. Texas Gas supplied Terre-Haute, in Vigo County
and the southern parts of the state including Posey County
in the southwest and Clark County in the southeast. Dearborn
County was supplied by Texas Eastern.
In Michigan, the chief supplier was the Michigan-Wisconsin
Pipe Line Co. which delivered half of the total state require-
ments. The next in importance was Panhandle, with 19 percent,
then Trunkline with 17 percent. Most MFBI in Michigan were
concentrated in the Detroit area which is served mainly by
Michigan-Wisconsin and Panhandle.. Michigan-Wisconsin served
west central Michigan, including Grand Rapids and Muskegon,
and also the northwest, but the Ishpeming area was supplied
by Northern. The southwest and south central areas and also
the east central area around Midland, Saginaw and Bay City,
were supplied by Panhandle and Trunkline. Local producers
contributed 8 percent to Michigan's supplies via intrastate
sales.
IV-2 9
-------
Minnesota was almost completely dependent on Northern
Natural Gas Co. which delivered 93 percent of supplies.
Midwestern contributed 2 percent and some Canadian gas is
imported.
More than half of the gas used in Ohio was supplied by
Columbia. Consolidated provided 29 percent, Panhandle 7
percent, and 6 percent came from intrastate supplies. Columbia
delivered gas in most parts of the state, the main exception
being the city of Toledo, which was served by Panhandle, and
the northeast (Cleveland, Akron, Canton and Youngstown area)
which was served in part by Panhandle but mainly by Consoli-
dated. Marietta was also served by Consolidated.
Wisconsin was served mainly by the Michigan-Wisconsin
Pipe Line Co. which brought 92 percent of the supply.
Northern Natural Gas supplied 7 percent and was important in
the Eau Claire and La Crbsse districts.
In Region VI, intrastate withdrawals far exceeded the
amounts of gas delivered by the interstate pipelines although
the proportions differed as between states. In Arkansas
only 12 percent of the supply was intrastate. Arkansas-
Louisiana Gas Co. provided 80 percent (some of this being
gas produced in Arkansas). Mississippi River contributed
about 2 percent, supplying gas in Fort Smith, Blytheville
and some districts in the south of the state. A further 2
percent was supplied by Natural.
In Louisiana 85 percent of the gas supply was from
intrastate sources. Most of the remainder was brought by
United, which served gas in New Orleans, Norco and other
parts of the south. Arkansas-Louisiana supplied gas.in the
Shreveport area in northwest Louisiana.
IV-30
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Intrastate supplies in New Mexico amounted to 70 percent
of the total supply. Almost all of the interstate gas came
from El Paso which supplied Southern Union Gas Co., the chief
distributor in the state, serving the Albuquerque and Silver
City areas.
Oklahoma received 87 percent of its gas supply from
intrastate suppliers. Of the remainder, Arkansas-Louisiana
brought 4 percent and served gas in Stephens and Pontotoc
Counties; Cities Service brought 3 percent and served
Oklahoma City, while some areas in the south and southeast
were supplied by Texas producers via the Lone Star Gas Co.
If gas supplied by Lone Star within Texas is included
in intrastate supplies, only 7 percent of the requirements of
Texas were delivered by interstate pipelines. Of this,
El Paso supplied 2 percent, and Northern and United each con-
tributed 1 percent.
In Region VII, there was not much local production except
in Kansas. The chief supplier in Iowa was Northern, which
supplied nearly two-thirds of the gas used. About a quarter
was delivered by Natural and the rest by Michigan-Wisconsin.
Northern was the sole supplier in the northern half of the
state, Natural contributed in Des Moines and served the
Cedar Rapids, Clinton and Davenport areas. Michigan-Wisconsin
brought supplies to the south and southeast.
In Kansas, 27 percent of the gas supply in 1974 was from
intrastate sources. Two-thirds of the remainder (48 percent
of total supplies) was delivered by Cities Service and 13
percent was brought by Northern. Kansas-Nebraska, providing
IV-31
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5 percent, served the northwest corner, Arkansas-Louisiana
delivered supplies in Rice and Reno Counties in the middle
of the state. Cities Service was predominant in Kansas
City, Topeka and the southeast.
Cities Service was also the chief supplier in Missouri,
delivering 49 percent of total requirements. Mississippi
River brought 35 percent and Panhandle 11 percent. The
west of the state was served mainly by Cities Service, with
some gas from Panhandle in the Kansas City area. In the
east, Pike County was supplied by Panhandle, and St. Louis
and Genevieve County by Mississippi River.
In Nebraska, Northern supplied most of the gas (61 per-
cent) serving Omaha and Cass and Lancaster Counties in the
east. Kansas-Nebraska provided 31 percent over a wide area
including Scottsbluff in the west. Nuckolls County in the
south was supplied by Cities Service.
Region VIII contains North and South Dakota, and four
other states grouped together. There was one MFBI in each
of the Dakotas. In North Dakota, the plant had main line
delivery from Montana-Dakota, and in South Dakota the plant
was in the southeast and would have been served by Northern.
In the other four states of this region, Colorado, Montana,
Utah and Wyoming, the chief supplier was Colorado Interstate
which brought 38 percent; intrastate sales accounted for 24
percent; Mountain Fuel for 19 percent; and Montana-Dakota
for 4 percent. In Colorado, most MFBI were in the Denver
area which was served by Colorado Interstate. This pipeline
served all MFBI except those in Logan and Sedgwick Counties
in the northeast which were dependent on Kansas-Nebraska.
IV-3 2
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In Montana, the southwest of the state was served by
Montana Power which was mainly supplied by Canadian imports.
The Billings area was served by Montana-Dakota.
Utah was supplied 99 percent by Mountain Fuel. Wyoming
was served by Montana-Dakota in the north, by Mountain Fuel
in Sweetwater County, by Kansas-Nebraska in the Casper area
and in Carbon and Goshen Counties, and by Colorado Interstate
in the southeast.
In Region IX, Arizona received all but 1 percent of its
gas from El Paso. This pipeline also supplied half of the
gas used in California, mainly in the southern half of the
state. California also had a significant supply of intra-
state gas (19 percent), and 13 percent was delivered by
Transwestern. San Francisco and the northern part of the
state was in part dependent on Canadian gas but also used
gas from local wells. Nevada received just over half its
supplies from El Paso and this pipeline served the southeast
of the state. The north and central parts of the state were
served by Northwest.
Region X, consisting of Idaho, Oregon and Washington,
was supplied almost entirely by the Northwest Pipe Line,
largely by imports from Canada.
Direct Sales of Natural Gas To MFBI In 1974
by Interstate Pipelines'
Approximately 1087 major MFBI used natural gas in
1974. Of these, approximately 128 received at least part
of their requirements by means of main line sales.
IV-3 3
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(A further 16 had had main line deliveries within the period
1970-73 but not in 1974.) The major MFBI were matched as
far as possible with the customers listed in Table 4 in the
Bureau of Mines Information Circula "Main Line Natural Gas
Sales to Industrial Users";— where the point of delivery to
a customer was at or close to the location of a major MFBI
owned by that customer, it was presumed that delivery was
made to the MFBI.
The 128 plants which were identified (12 percent of
the total) used 329 trillion Btu's of gas out of about
2,900 trillion Btu's consumed by all major MFBI in the
study - about 11 percent of total consumption.
Main line deliveries to these plants amounted to 419
Bcf of which about 75 percent was listed as firm gas. In
the majority of individual cases, main line deliveries
exceeded the FEA consumption figure, which implies that gas
was used in other ways than as fuel for the major combustors
in these plants - e.g., as fuel for combustors with capacity
of less than 100 MMBtu/hr., or as feedstock.
In 29 cases (comprising 35 plants as some MFBI were
grouped together in the same county), main line sales did
not exceed or fall short of the MFBI consumption figure by
more, than 10 percent. Differences of this amount might be
accounted for by such factors as variations in Btu content
of the gas or in the exact period to which consumption re-
i \ t
lates.
I/ U.S. Department of the Interior: 1C 8688
IV-34
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In 12 cases (15 plants) consumption of gas exceeded
main line deliveries by more than 10 percent, in a few cases
by considerably more. These plants were apparently ob-
taining a considerable portion of their supplies from other
sources; plants in the gas producing areas may have had
supplies from local wells. In the case of two plants in the
same county, possibly only one was served by main line and
the other by a different supplier.
The extent to which the requirements of major MFBI com-
bustors were met by main line deliveries varied considerably
between regions and between states within regions. Schedule
IV-15 shows by state, the pipelines delivering gas to MFBI
and the amount delivered, the number of MFBI receiving main
line gas and their consumption in major combustors, and the
total number of gas-burning MFBI in the state along with
their consumption in major combustors. The greatest propor-
tionate use of main line service was in Region IV where 46
plants had deliveries. In Alabama 13 out of 24 MFBI had
main line service, and in Mississippi 13 out of 16; gas
consumption by these plants was in each case over two-thirds
of the consumption by major MFBI combustors in the state. In
Region VI, 35 plants had main line service, but smaller
proportions of plants and of gas were involved than in the
case of Region IV except for the state of Arkansas where 13
out of 15 MFBI had main line deliveries, and their com-
bustors used over 90 percent of the MFBI gas consumption in
that state. In Region V only 11 MFBI had main line deliveries,
four in Illinois, none in Indiana, three in each of Michigan
and Minnesota, and one in Ohio; and the gas so purchased was
IV-3 5
-------
not a considerable part of supplies. Main line deliveries
were important in Nebraska and Arizona.
Thirteen of the major pipelines made main line sales of
gas to MFBI (pipelines wholly supplied by a major pipeline
being included with the supplier).
United sold to the largest number of MFBI and sold a
large amount of gas (73 Bcf) entirely in Regions IV and VI,
mainly in Florida, Mississippi and Louisiana. The largest
amount of gas sold direct to MFBI, however, was sold by,
Arkansas-Louisiana Gas Co. and 89 percent of this was sold
in Arkansas. Southern Natural was an important direct
supplier in Region IV; El Paso in Arizona; and Mississippi
River in Arkansas, Illinois and Missouri.
Individual Pipeline Supply Situations
The diverse consumption projections by GRC discussed
in earlier sections reflect not only different curtailment
strategies but also variations in supply situations. Within
interstate markets, the predominant source of supply has
traditionally been interstate pipelines. Thus, this section
discusses individual pipeline company supply situations. In
light of LNG and SNG projects contemplated or operated by
distributors, as well as the ability of some industrial
concerns to obtain their own supply, it should be recognized
that circumstances exogenous to the pipeline can affect in-
dustrial gas consumption in some local areas.
IV-3 6
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Schedule IV-16 sets out estimated requirements and
curtailments by interstate pipelines for the year ending
August 1977, compared with actual data for the year ended
August 1976; Sheet 1 shows firm curtailments and Sheet 2
shows interruptible curtailments. As shown on Sheet 1, firm
curtailments by interstate pipelines are projected to in-
crease by nearly 800 Bcf for the coming year. However, net
deliveries are projected to decline by only 411 Bcf, with
the remainder of the increase in curtailments being attri-
butable to increased requirements. The "increased" require-
ments may reflect assumed normal weather compared with
warmer-than-normal weather for the actual period ended
August 1976. With respect to interruptible sales (only a
small portion of pipeline sales), requirements are shown to
decline, but again, this may be related to weather adjust-
ments. Interruptible deliveries are projected to decline
by 33 Bcf.
Many of the individual pipelines depicted on Schedule
IV-16 forecast approximately the same deliveries during the
forthcoming year as during the past year. Notable among
those which show continued declines in sales are United
Gas Pipe Line, Transwestern Pipeline Co., Transcontinental
Gas Pipe Line, Texas Gas Transmission, Tennessee Gas Pipeline,
Southern Natural Gas, Northern Natural Gas Co., Natural Gas
Pipeline Co., Midwestern Gas Transmission, Michigan-Wisconsin
Pipe Line Co., and El Paso Natural Gas Co. The following
table shows for these pipelines the primary states affected
and the projected declines.
IV-3 7
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Pipeline
!1 Paso
LLchigan-Wisconsin
lidwestern
latural Gas Pipeline
lorthern Natural
Southern Natural
Tennessee
Texas Gas
Transcontinental
Franswestern
[Jnited
States Primarily Affected
California, Arizona, New Mexico
Michigan, Wisconsin
Illinois, Indiana
Iowa, Illinois, Indiana
S. Dakota, Minnesota, Nebraska,
Iowa, Kansas
Alabama, Georgia, S. Carolina
Northeast, Tennessee, Alabama,
Mississippi, Kentucky
Kentucky, Mississippi, Tennessee
Delaware, D.C., Pennsylvania,
New York, New Jersey, North &
South Carolina
California
Alabama, Florida, Louisiana
Deliveries(Bcf) Year Ended
Aug. 1976 Aug. 1977 % Decline
1156 994 14%
774 735 5
290 281 3
989 957 3
755
582
1102
599
644
262
835
692
566
1077
552
555
221
735
8
3
2
8
14
16
12
The above data with respect to interstate pipelines
pertain to their sales predominantly to gas distributors
and do not necessarily reflect shortages by end-users.
The term curtailment in this context means the difference
between the amounts of gas a pipeline is required to de-
liver, by contract or otherwise, and the amounts it is
actually able to deliver. In the past, demand factors such
as warm weather and the recession have acted to lessen the
shortages at the end-user level.
IV-3 8
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However, FEA has analyzed the supply-demand situation
at the end-user level, and the FEA data indicate that the
above discussed pipeline curtailments are resulting in gas
shortages. Schedule IV-17 shows FEA's projected industrial
gas consumption and shortages by state for this winter com-
pared with last winter. The decline in gas availability is
more severe for the industrial sector than overall because
of the large increase in residential-commercial consumption
evidently predicated on weather colder than last year. The
industrial shortage is also aggravated by the projected in-
crease in gas requirements for this sector, apparently
reflecting the improved economic climate. By reference to
FEA's projections, the states experiencing the largest
volumetric declines are California, Arizona, Indiana, and
North Carolina.
The foregoing discussion pertains to the very near-term
situation but is useful to verify that demand factors are
no longer largely ameliorating the gas shortage. Over the
period to 1980, it can reasonably be assumed that gas de-
mand will continue to increase and thus reductions in gas
supply will have a greater impact than in the past.
A key supply factor in interstate markets will be the
deliverability of gas from existing reserves, which is
shown on Schedule IV-18 for major pipelines. In total,
production from existing reserves is shown to decline at an
annual rate of over 10 percent. This is a severe decline,
and reflects the rapid decline in deliverability for the
older reservoirs which are more prevalent for interstate
pipelines. As discussed earlier, interstate pipelines have
not been successful in acquiring new reserves in recent
IV-3 9
-------
years; pipelines showing annual declines of 10 percent or
more include Columbia Gas Transmission, Transcontinental,
Trunkline, Panhandle, Northern Natural, Arkansas-Louisiana,
United, Transwestern and El Paso.
It is unlikely that these pipelines could acquire suf-
ficient new reserves to offset these declines. In total,
these pipelines would have to acquire over 10 Tcf of gas per
year to maintain 1975 production levels. For those pipelines
without access to offshore reserves the prospects for in-
creased reserves additions are limited. The outlook for
offshore reserves additions is now more favorable, but the
lead time between offshore exploration and ultimate con-
sumption of the resultant discoveries is 3 to 5 years.
For purposes herein, an interstate pipeline supply pro-
jection has been developed. This forecast assumes a 20 per-
cent increase in reserves additions for 1977 to 1979, com-
pared with the previous four years, and no further negative
revisions. Coupled with the deliverability from existing
reserves, this forecast shows a 4.4 percent annual decline
in interstate pipeline supply between 1975 and 1980.
Thus, the outlook is for continued declines in inter-
state supply to 1980, albeit at a lower rate than in recent
years. Coupled with increasing higher priority gas consump-
tion, the result is diminishing industrial gas supply.
IV-40
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TECHNICAL REPORT DATA
(Please read Instnictions on the reverse before completing}
1. REPORT NO.
EPA-450/3-77-017a
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE ANDSUBTITLE
Impact of Natural Gas Shortage on
Major Industrial Fuel-Burning Installations - Volume I
Text
5.
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Brickhill, J.A.
8. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Energy Division
Foster Associates, Inc.
1101 Seventeenth Street, N.W.
Washington, D. C. 20036
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-1452, Task 10
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Strategies and Air Standards Division
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
Contract Report
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
EPA Project Officer: Rayburn Morrison
16. ABSTRACT
This study was conducted to analyze the impact of natural gas shortages on
major fuel burning installations. The analysis consisted of the review of gas
curtailments plans, natural gas supplies, FEA survey data for MFBI and applicable
state air pollution control regulations. This analysis estimated the availability
of natural gas through I960 for major fuel burning installations, the alternate
fuel burning capability of these plants, the need for alternate fuels such as fuel
oil and coal to offset the gas shortages and the estimated increase in sulfur
dioxide and particulate emissions from the burning of these alternate fuels. The
study results are presented in a three volume report: the first contains the
narrative for the analysis of natural gas shortages on the gas fired plants with
pertinent findings and conclusions; the second contains schedules or data summaries
for the natural gas fired plants; and the third presents a limited analysis of all
the MFBI data.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Fuels
Natural gas curtailments
Steam plants
United States
Government
Regulations
Air Pollution
Combustion
Sulfur dioxide
Particulates
Natural gas
Fuels
Air Pollution control
Stationary sources
Non-Utility sources
13. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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