EPA-450/3-76-030a
August 1975
IMPACT
OF NATURAL GAS
CURTAILMENTS
ON ELECTRIC
UTILITY PLANTS
VOLUME I - TEXT
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
-------
EPA-450/3-76-O3Oa
IMPACT
OF NATURAL GAS
CURTAILMENTS
ON
ELECTRIC UTILITY PLANTS
VOLUME I - TEXT
by
Energy Division
Foster Associates, Inc.
Washington, D. C.
Contract No. 68-02-1452
Task No. 1
EPA Project Officer: Rayburn Morrison
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
Vugust 1975
-------
This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available frea of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - in limited quantities - from the
Library Services Office (MD35) , 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 of Foster Associates, Inc., Washington, D.C., in
fulfillment of Contract No. 68-02-1452, Task No. 1. 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 Protection
Agency. Mention of company or product names is not to be considered
as an endorsement by the Environmental Protection Agency.
Publication No. EPA-450/3-76-030a
11
-------
ACKNOWLEDGEMENTS
This study was prepared under the direction of John A.
Brickhill by the Energy Division of Foster Associates.
Participating in the preparation of the study were Joseph
Curry, Paul Wilkinson, Leon Tucker and William Blair. Wayne
Mikutowicz acted as technical reviewer for the study.
-------
VOLUME ONE
TABLE OF CONTENTS
INTRODUCTION
SUMMARY
CHAPTER I
CHAPTER II
CHAPTER III -
CONSUMPTION OF GAS BY ELECTRIC UTILITIES
A. Natural Gas Supply and Demand
B. Gas Consumption by Sector
C. Sources of Gas Supply to Electric
Utilities
CURTAILMENTS OF NATURAL GAS SALES BY
INTERSTATE PIPELINE COMPANIES
A. Traditional Gas Pipeline Economics
1. Pipeline Services
a. Character of Pipeline Service
2. Economics of Pipeline Operation
3. Characteristics of Demand for
Natural Gas
4. Regulation Under the Natural
Gas Act
B. The Development of Federal Power
Commission Policy Concerning Gas
Supply Curtailments
1. Design of End-Use Priority
Curtailments
C. Current Curtailment Plans of 38
Interstate Pipelines
D. Prospects of Gas Curtailment -
Electric Generation vs. Other
Industrial Use
CURTAILMENT OF NATURAL GAS SALES BY GAS
DISTRIBUTORS AND INTRASTATE PIPELINES
A. The NARUC Survey
1. Gas Curtailments
2. Restrictions on New or Added
Gas Services
3. Conservation of Gas
4. Programs for Additional Gas
Supplies
5. Other Questions and Responses
6. Summary
Page
viii
x
1-1
1-2
1-4
1-8
II-l
II-2
II-4
II-5
II-6
11-14
11-16
11-25
11-26
11-37
11-43
III-l
III-2
III-3
III-5
III-5
III-6
III-7
III-7
IV
-------
CHAPTER IV
CHAPTER V
Curtailment Plans in Intrastate Markets III-9
1. Texas III-9
2. Louisiana 111-16
3. Oklahoma III-18
The Impact on Electric Utilities and
Industrials of Curtailments by Distributors
and Intrastate Pipelines 111-19
THE PROJECTED AVAILABILITY OF NATURAL GAS
TO ELECTRIC UTILITY STEAM-ELECTRIC PLANTS
1975 TO 1980
A. Projections for Predominantly Interstate
Markets
1. Forecast of Gas Supplies Available
to California Steam-Electric Power
Plants, 1975-1980
B. Projections for Predominantly Intrastate
Markets
THE CURRENT AND PROJECTED USE OF ALTERNATIVE
FUELS BY GAS-BURNING UTILITY POWER PLANTS
A. Current Alternate Fuel Burning Capacity
of Gas-Burning Electric Utility Power
Plants
B. Summary of The Alternate Fuel Capability
in the Interstate Market
C. Summary of the Alternate Fuel Capabilities
in the Intrastate Market
D. Projections of Alternate Fuel Demand by
Electric Utilities Due to Reductions in
Gas Supply
E. Deterrents to the Use of Alternate Fuels
by Electric Utilities
F. The Relative Role of Natural Gas as an
Electric Utility Boiler Fuel by Region
IV-1
IV-7
IV-19
IV-31
V-l
V-l
V-4
V-ll
V-18
V-21
V-24
-------
INDEX OF TABLES AND CHARTS
Page
Table Summary of Electric Utility Purchases
of Natural Gas by Type of Supplier - 1973 IV
Table Summary of Current and Projected Gas
Consumption for Electric Utility Steam
Generating Plants 1973-1980 VIII
Chart Projected Decline in Gas Consumption by
Electric Utilities and the Resulting
Increases in Fuel Oil and Coal Consumption
Between 1973 and 1980 XI
Projected Increases in Fuel Oil and Coal
Consumption by Electric Utilities
Attributable to the Decline in Natural
Gas Consumption Between 1973 and 1980
Table 1. Trillions of Btu's XII
Table 2. Thousands of Tons of Coal
Barrels of Oil XIV
Table Natural Gas Consumption in Power Plants
and Electric Output from Natural Gas
Consumed 1966-1973 1-1
Table Industrial Gas Consumption by State - 1973 1-6
Table Electric Utility Gas Consumption by
State - 1973 . 1-7
Table Components of the Burner Tip Price of Gas
in 1973 II-7
Chart Monthly Distributor Sales of Gas in the
United States by Sector, July 1972 -
June 1973 11-15
Table Regulated Gas Utility Annual Sales by Service
Class, Percent of Total Sales, 1950-1973 11-36
Table Current and Projected Gas Consumption for
Electric Utility Steam Generating Plants IV-3
Table Illustrative Interstate Supply Projection IV-13
Table Illustrative Interstate Supplies by End-Use IV-14
Table El Paso Natural Gas Company Curtailment Plan
and End-Use Gas Requirements of System
Customers IV-22
-------
Table
Table
Table
Table
Table
Table
Table
Southern California Gas Company and
Pacific Gas and Electric Company 1973
Gas Supplies and Sources of Supply
Southern California Gas Company and
Pacific Gas and Electric Company
Allocation of 1973 Gas Supplies by
Priority of Service Steps of the
El Paso Natural Gas Company Curtailment
Plan
Southern California Gas Company and Pacific
Gas and Electric Company Projected Total
Gas Supplies 1974-1980 and Supply
Reductions from 1973 Supplies
IV-23
IV-24
IV-25
Southern California Gas Company and Pacific
Gas and Electric Company Estimated Total
Gas Supplies for Power Plants IV-26
Estimated Gas Supplies Available to Southern
California Gas and Pacific Gas and Electric
Company 1973-1980 IV-28
Gas Supplies to Power Plants 1974 as Percent
of 1973 IV-29
City of Burbank Public Services -
Burbank Plant
IV-30
vn
-------
INTRODUCTION
In light of the worsening gas shortage, federal and
state regulatory agencies have promulgated policies with
respect to the distribution of gas sales when demand exceeds
supply. Gas companies in turn have implemented or are about
to implement specific curtailment plans, the results of which
have a significant impact on natural gas consumption by electric
utilities and industrial concerns and thus could affect air
quality by requiring the use of alternate fuels such as coal or
oil.
This study analyzes curtailment plans of interstate pipelines,
intrastate pipelines and gas distributors, and ilso analyzes
state and federal policy with respect to implementation of these
curtailment plans. In light of applicable curtailment plans
and available information regarding the supply situations for
gas pipelines and distributors, the availability of gas to 415
electric utility power plants is projected annually to 1980.
These plants accounted for 93 percent of electric utility gas
consumption in the U.S. in 1973. The study appraises the
impact of the gas shortage on demand for fuel oil and coal
and the fuel burning capability other than gas for electric
utilities.
The study is contained in two volumes, one containing
text and the second containing schedules. Immediately following
this introduction is a summary of pertinent findings. The
vi i i
-------
main body of text begins with the analysis of the jurisdictional
aspects of electric utility gas consumption, describing the
gas purchases of 415 electric utility power plants. Chapter II
describes the curtailment plans of interstate pipelines, and
Chapter III explains curtailment policies of companies who do
not fall under Federal Power Commission jurisdiction. The
forecasts of gas availability for individual power plants
are explained in Chapter IV. The study concludes with Chapter V,
which deals with the alternative fuel burning capability of
electric utilities.
IX
-------
SUMMARY
Until the 1970's, natural gas consumption by electric
utilities accounted for a significant and growing proportion
of both total natural gas consumption by all users, and of
total electric power generated. In the 1970's, however, in-
creasing shortages of natural gas have reversed this trend.
Considerable variations exist in the amount of natural
gas burned by electric utilities in various parts of the U.S.
and in the sources of this gas. The following table sets
out the volumes of natural gas consumed in 1973 by EPA re-
gion and by types of supplier. The table is a summary of
the results of the analysis of 415 gas-burning power plants
which cover 93 percent of the natural gas consumed by elec-
tric utilities in the U.S.
Consumption of gas by power plants analyzed herein
amounted to 3.4 trillion cubic feet (Tcf) in 1973, of which
1.3 Tcf or 38 percent was sold by interstate pipelines. The
remaining 62 percent was sold to electric utilities by intra-
state pipelines or gas producers. Interstate pipelines are
regulated by the Federal Power Commission, and thus this agency
has significant influence on the amount of gas sold directly or
indirectly to power plants by interstate pipelines. In
gas producing regions, electric utilities can obtain gas from
producers or intrastate pipelines, which are subject to
-------
SUMMARY OF ELECTRIC UTILITY PURCHASES OF NATURAL GAS
BY TYPE OF SUPPLIER
1973
(Billions of Cubic Feet)
EPA
Region
I
II
III
IV
V
VI
VII
VIII
IX
X
TOTAL
From
Interstate
Suppliers
5.6
64.5
4.1
144.0
138.2
183.3
245.
58.
447.8
2.4
,3
,5
1,293.7
From
Intrastate
Suppliers
0
0
0
0
0
1,798.3
52.9
3.7
70.8
0
1,925.7
From
Producers
0
0
0
110.1
0
47.0
3.5
0
8.9
0
169.5
Other
Total
0
0
0
0
0
1.9
0
0
0
0
5.6
64.5
4.1
254.1
138.2
2,030.5
301.7
62.2
527.5
2.4
1.9 3,390.8
EPA Region I -
EPA Region II -
EPA Region III -
EPA Region IV -
EPA Region V -
EPA Region VI -
EPA Region VII -
EPA Region VIII -
EPA Region IX -
EPA Region X -
Massachusetts, Rhode Island, Vermont, Connecticut,
Maine, New Hampshire
New Jersey, New York
Delaware, Pennsylvania, Virginia, Maryland, West
Virginia
Alabama, Florida, Georgia, Kentucky, Mississippi,
North Carolina, South Carolina, Tennessee
Illinois, Indiana, Michigan, Minnesota, Ohio,
Wisconsin
Arkansas, Louisiana, New Mexico, Oklahoma, Texas
Iowa, Kansas, Missouri, Nebraska
Colorado, Montana, South Dakota, North Dakota, Utah,
Wyoming
Arizona, California, Nevada
Oregon, Washington, Idaho
-------
regulation by state regulatory bodies.
Interstate pipelines suppliers accounted for all gas
received by power plants in EPA regions I, II, III, V, and
X, and the majority of gas in regions VII, VIII and IX. In
region IV, the sources of gas to power plants were evenly
divided as between interstate and intrastate. In region VI,
where a total of 2.0 Tcf, or 60 percent, of total electric
utility consumption was burned in power plants, the sources
were largely from intrastate pipelines and producers.
Increasing natural gas shortages have necessitated the
development of curtailment plans by sellers of gas to deal
with their inability to satisfy contractual obligations.
The Federal Power Commission has formulated guidelines for
interstate pipelines which reflect end-use considerations in
determining the reductions in deliveries to customers. Vol-
umes for residential and small commercial use are treated as
the highest priority. The next priority is composed of larger
commercial users and industrial users, predominantly those
with small daily takes or who use gas for purposes which have
no alternatives to gas. Larger industrial customers with firm
contracts follow in the priority structure. Last in the
priority structure are volumes for users with interruptible
contracts, with curtailments reflecting size. Volumes for the
lowest priority of use are to be completely eliminated prior
to curtailment of volumes for the next priority. Since electric
utilities served directly or indirectly by interstate pipelines
xii
-------
generally purchase relatively large amounts of gas under interrup-
tible contracts, they would be theoretically curtailed first.
Not all interstate pipelines are operating under end-
use plans. However, traditional operating practice by gas
companies would result in initial curtailments falling first
on interruptible contracts. Also, in light of FPC policy
it is reasonable to assume that as shortages worsen, virtu-
ally all interstate pipelines will have end-use plans in
effect. Some variations in the specific priority structure
can be expected to accomodate difference? in the market
structure of various pipelines.
The curtailment policies of local regulatory bodies af-
fect results to ultimate consumers in those cases where gas
obtained by distributor companies from interstate pipelines
is subsequently resold and where gas flows directly from
producers or intrastate customers to ultimate consumers with-
out entering interstate commerce. Electric utility use is
generally among the first to be reduced in times of shortfalls
in most states for which information is available.
Electric utilities in Texas consume 37 percent of the
gas consumed by electric utilities in the U.S. In that
state, electric utility boiler fuel use also is considered
to be low i riority in curtailments. Moreover, the Texas
Railroad Commission has initiated hearings to explore the
phaseout of natural gas used as a boiler fuel in the state.
xiii
-------
It may thus be surmised that electric utilities initial-
ly will bear the brunt of the gas shortage in the U.S. The
following table summarizes the projections of electric util-
ity gas consumption to 1980 by year.
These projections reflect plant by plant projections
developed in this study. As data were available, individual
company situations with respect to supply and requirements
and curtailment plans in effect were reviewed.
The total volume of natural gas consumed by electric
utilities is shown to decline by half between 1973 and 1980.
In EPA regions I, II, III and V, it is projected to be virtu-
ally non-existent in the late 1970's.
By 1980, it is projected that within predominantly in-
terstate markets electric utilities in only two states --
Kansas and Florida -- will have appreciable gas consumption.
Nevertheless, electric utility gas consumption in both states
is forecast to decline significantly. California, New York
and Arkansas, three states in which electric utilities have
traditionally burned large amounts of gas, would have little
gas available for electric utility gas consumption after
1975. Thus, for predominantly interstate markets, it may be
concluded that gas will not be a major boiler fuel in the
future.
xi v
-------
oo
CM
co
O
CM
CO
Cfl
H 00
2 n-
3 a
o.
o •
H so
t— i r~-
fj ON
M — t
s
00 vO O CQ
• • •
CM \O ft
•4"
T-H
o
t— 1
H
o
&] /— N m
»-J w r*^
W - Ox
3 iH
OS O *-»
m CM >^> m
if\ r- m
(N CO
r-t
O oo pa
tn ON
^ """* o
0 1
M 03
E-t co C
ftj r- o
LO i-t f-*
2 -H
r- m c> o
* « • •
r- • * •
LO iX> JN O\
\£> m
CM
*-)
o
&
cu
Q
Z
<:
H
5S
W
Pi
C^
E3
U
f*^
O
PH-
Pi
O ^ "^
* • • * •
CN >*o oo o f-t
O St r-» CM
r^.
.H
O st m m m
CM £N «H r-H rH
in m CN CM
r*.
r-H
fi \o ft oo m
• • • * •
m CM r-- CM «-t
rH 00 CM CM
CO
iH
m o ^ 00 \O f"^
O CM CO
CN
CM O> VD CM in
* * * • >
co co in o CM
in o> m \D
O CM m
CM
O
.
rH
CM
ON
,— i
r-4
ON
00
rH
r-J
*
CO
CM
r-H
CM
vD
^0
r-4
r-
CM
CO
CM
m
CM
CO
•H
,
xjj
3
CO
00
K
C
O
'H
00
01
t*.
00
01
c
o
•H
t)C
01
0!
O-i
UJ
00
Pi
00
01
CL,
w
oo
(U
C
O
od
01
O-i
w
X
g
•H
00
01
«
4-1
en
"8
c
3
O
H
XV
FA-18962
-------
Gas consumption by electric utilities in EPA region VI
is shown to decline significantly, but not to the same rela-
tive extent as in other regions. Depending on actions by the
Texas Railroad Commission and other authorities in this re-
gion, this projection could be altered significantly.
The impact of the gas shortage on electric utilities
will be to displace a substantial portion of their energy
needs to other fuels. Each of the 415 gas-burning power
plants has been analyzed, based upon available data, to deter-
mine its capability to burn alternate fuels. With the
major exception of plants in EPA region VI, most of the
electric utilities in the U.S. are capable of burning oil
or coal in gas-burning plants with little or no boiler de-
rating.
The alternate fuel capability of gas-burning electric
utilities in EPA region VI is difficult to assess. In 1973,
the majority of plants had limited or no alternate fuel
capability. Since 1973, sovae plants have been modified so
as to be able to burn alternate fuels, and some electric
utilities indicate future plans for plant modification. However,
the exact number of plants which have undergone or will undergo
conversion cannot be estimated at this time.
By integrating the plant by plant projections of natural
gas availability with the plant by plant analysis of alternate
fuel capability, the effect of the gas shortfall on alternative
xvl
-------
fuel consumption can be estimated. The following chart and
table show the estimated use of alternative fuels by existing
electric utility plants due to reductions in gas supply from
1973 to 1980. The declines in gas consumption effect changes
in one of three categories -- demand for coal, demand for
oil and indeterminate (limited or no known alternative fuel
burning capability at this time).
It should be noted that on the table certain data are
shown in brackets, denoting negatives. This situation
arises for plants in which gas consumption is projected to
increase from 1973 levels and therefore the consumption of
alternative fuels would decline.
By 1980, shortfalls in gas deliveries in the U.S. would
result in additional coal consumption of over 348 trillion
Btu's and additional fuel oil consumption of 1074 trillion Btu's.
A net reduction of 273 trillion Btu's is shown for plants which
at this time have limited or no known alternative fuel burning
capability. Excluding those plants for which increases in
gas consumption are projected, the reduction in gas deliveries
by 1980 would be 349 trillion Btu's in plants which at this
time have limited or no known alternative fuel burning capability
Most of the indeterminate category is within EPA region
VI. Based upon the conversions of gas-fired plants to oil
which have already taken place, it might be assumed that to
the extent conversion is feasible, the most likely alternative
in this region is fuel oil.
xvii
-------
V77/////////.
I
I/////////////
to
LU
(ft
Q
\HL
QC
LLJ
to
QC
UJ
YZL
U/./77,
O
r^
O>
15
en
To
3
o>
CO
r^
en
" 3
O) eg
CM «- O CN
QUADRILLION BTU'S
xvm
-------
t-t MM
M M > W M M K
MWMf-«>>>>O
J M H
U I
FA-18972
XIX
-------
The table on the following page shows the same data
for fuel oil and coal in barrels and tons, respectively.
In 1980 the reduction in gas consumed by electric utilities
in the U.S. would result in consumption of 170.8 million barrels
of oil and 15 million tons of coal.
xx
-------
o
W 00
W 0.
H
H <
5 CO
U O\
M r-4
ii
to
ll
5 en
1s
gi
U *J
gl
M
0 5
rJ
£ H
>J
K; o
M Q
H W
c/i EC
PS O
O H
w W
ft Ei
o ^
w n
•-) M
g|
-i
•I
o
9
5
C-.
g
U
•3
01
O
I
to
0)
s,
M
01
4-1
o
o
•o
8
a
a>
O
"O
c
o
00
S:
00
IV.
O4-
0^
•D
3>
in
&>
r-<
•s!
o o
I
_
r-4 IB
O f
T-4 *
41 o
<"§
09
-g
BH
8
O
t-4 (B
•H r-l
T-4
at o
u
c
•-* O
o
•-* 9
1-1 T-4
O .fl
Is
Cu O
-i
a H
o
r-4 0)
1§
C o
0)
«£
o o
o
^-1
•
o .0
0) O
£ o
a
«-« o
SH
"§
o
••"•
^ m
ea
ft> O
8 8 s S S |
CN *O
r-- o r*- o cr» o
CM CO CM 00 »-l OQ
00 *-* •-! 00 CM CM *fi f*
CO 0 in Ov
to m QO '-^
CM CM
S 2 3 S 3 S
CM
VD <^ r- in £"
i CM y3 co ^- '
rH r-4
CM -J *-i 1-4
e t-i
< ja
• S-
•H O
O
•si
u
o c
o
*< 4J
*J U
o i
4) «
* ^
• O
a
ll
00
5 ° "
41
S S S
J*H
ft)
8" 1
i
a*
•^
i
0
«-j
S
£
1
1
i
•H
O
I
n
°°
•8
i
41
CO
«J
o
1
g
u
B
ea
1
u
1
o
u
•H
1
u
u
8
u
o
a)
4J
•o
B
O
m
o
CD
"H
jj
2
•8
4-1 *
g|
(0 Q
BvO
*
?.^
X
« u
^
at n
•S3
5,
•3
5| w
XXI
FA-19008
-------
CHAPTER I
CONSUMPTION OF GAS BY ELECTRIC UTILITIES
Until 1973, increasing quantities of natural gas had
been consumed annually by electric utilities in the U.S.
Moreover, an increasing share of total electric output
had been generated by consumption of natural gas up through
1970. These trends have been reversed in the last two years,
as shown on the table below.
Natural Gas Consumption Electric Output From
Year in Power Plants Natural Gas Consumed
Trillion Btu
Percent of
Million kwh
Total Gas Consumption
1966
1968
1970
1972
1973
2,536
3,081
3,920
4,271
3,651
14 . 2%
15.0
16.8
17.2
17.1
251,151
304,433
372,884
375,682
336,001
Percent of Total
Electric Output
26.5%
27.5
29.1
25.5
21.3
Source: Future Requirements Committee, Edison Electric Institute.
The proportion of total electric output attributable
to consumption of natural gas began to decline in 1971
despite continuing increases in total gas volumes, largely
because of sharp increases in electric generation with
nuclear fuel and fuel oil. The trend towards a declining
electric output share of natural gas will almost certainly
accelerate in the future as the sharpening natural gas
shortage makes further inroads into supplies of gas available
to electric utilities.
-------
The focal point of this study is to analyze the
availability of natural gas to electric utility steam-
electric plants. Major variables affecting gas consumption
are the total amount of gas available for all users and the
methods of allocating limited supplies among classes of
service -- residential, commercial, industrial, and electric
utility --by the sellers of gas. The purpose of this
chapter is to set the stage for subsequent analyses by
establishing general gas supply and demand considerations
which affect electric utility gas consumption, identifying
the gas burning power plants that are studied, and analyzing
the sources of gas supply to these power plants.
A. Natural^ Gas Supply and Demand
There is a critical and continuing shortage of natural
gas in the United States. Natural gas has been a major source
of energy in the United States since World War II, and has
become the "premium" fossil fuel for energy consumption
in the United States. From 1960 to 1973, consumption of
gas increased 86 percent, substantially more than consumption
of coal and petroleum, but substantially less than the increase
which would have taken place but for the gas shortage that
developed in the latter part of this period.
There are two major reasons accounting for the sub-
stantial increase in demand for gas -- 3ts unique physical
characteristics vis-a-vis other fossil fuels and its low
1-2
-------
price. The popularity of gas in part reflects its clean-
burning characteristics and the convenience of its use.
Since the sulfur content of gas is negligible at the burner
tip, gas does not foul or corrode the equipment in which it
is burned to the extent that coal and oil do. The clean-
burning characteristics of gas have taken on added impor-
tance in recent years because the United States has undertaken
a substantial effort to reduce air pollution. Users of
gas do not require on-site storage facilities which are
required for oil and coal. Also, natural gas has certain
physical attributes which make it desirable for use in
direct-firing applications or as a raw material in the
chemical industry.
However, the magnitude of the shortage indicates
that not all demands can be met for the indefinite future,
and indeed at the present time current contracts to deliver
specified volumes of gas to consumers cannot be fulfilled
due to lack of supply. Interstate pipelines curtailed
firm contracts by 1968 billion cubic feet (Bcf) in 1974.
Increasing curtailments by pipelines reflect declining
deliverability of natural gas reservoirs, caused by reserves
additionsi/ inadequate to support increased levels of
lY The term reserves additions means the annual net
change in proved reserves, reflecting discoveries
of new fields, new reservoirs in old fields, exten-
sions, and revisions of prior estimates.
I -3
-------
production. Proved reserves—' of natural gas have been
falling since 1968, declining to 205 trillion cubic feet
at the end of 1974. From 1968 to 1974, reserves additions
have been less than half of production. The natural gas
reserves-to-production ratio for the Lower 48 States has
fallen from 21.8 in 1956 to 15.8 in 1967 to 9.7 in 1973
and 1974. In 1974, production declined by 5.8 percent,
the first recorded production decline since a small down-
ward change in 1958.
B. Gas Consumption by Sector
Gas consumption by sector -- residential, commercial,
industrial and electric utility -- is set out on Schedule
1-1 as reported by the Future Requirements Committee.
Sheets 1 and 2 of the schedule show consumption of gas
in trillions of Btu's by region.2/ and state, and sheets 3
and 4 show the percentage distribution of gas consumption
by sector for each region and state.
I/ Proved reserves are the current estimated quantity
of natural gas which analyses of geologic and engi-
neering data demonstrate with reasonable certainty
to be recoverable in the future from known gas
reservoirs under existing operating and economic
conditions. Thus, proved reserves differ from the
potential reserves which have not as yet been found.
2J The regional designations utilized in the main body
~~ of text hereinafter are those of the Future Require-
ments Committee.
1-4
-------
In 1973, gas consumption in the Lower 48 United States
was 19,876 trillion Btu's, excluding field and "other" use.
Of this total, firm—' residential and commercial customers
consumed 36.4 percent, firm industrial customers consumed
31.3 percent, interruptiblej*/ industrial customers consumed
13.9 percent, firm electric utility customers consumed 10.6
percent and interruptible electric utility customers consumed
7.8 percent.
The distribution of gas consumption varies considerably
by region and state. At one extreme, over three-quarters
of the gas market in New England is comprised of residential
and commercial customers. Conversely, less than 11 percent
of the gas market in the Gulf Coast is comprised of residen-
tial and commercial customers -- the preponderance of con-
sumption is comprised of industrial and electric utility
fuel users.
Approximately two-thirds of industrial gas consumption
in the Lower 48 States occurs in eight states, which are
listed below.
lY Service offered to customers under schedules or contracts
~ which anticipate no interruptions. Certain firm service
contracts may contain clauses which permit unexpected
interruption in case the supply to residential customers
is threatened.
2_/ Low priority service offered to customers under
~ schedules or contracts which anticipate and permit
interruption on short notice, generally in peak-
load seasons, by reason of the claim of firm service
customers and high priority users.
1-5
-------
INDUSTRIAL GAS CONSUMPTION BY STATE
1973
Trillions Percent of
of Btu's National Total
Texas 2162 24.01
Louisiana 1120 12.4
California 702 7.8
Ohio 437 4.9
Illinois 378 4.2
Pennsylvania 375 4.2
Michigan 356 4.0
Indiana 282 3.1
All Other States 3182 35.4
Total 8994 100.0
Source: Future Requirements Committee.
The volume of industrial gas consumed in Texas,
Louisiana, and California reflects not only the overall
dimension of industrial energy requirements in these states
but also the heavy reliance on gas to meet industrial
energy requirements -- in 1973 gas met 83 percent of
California industrial energy consumption, and over 90
percent of industrial energy consumption in Texas and
Louisiana.
In each of the 8 largest industrial gas consuming
states with the important exception of California, firm
contracts dominate industrial consumption. Firm volumes
range from 67 percent of industrial gas consumption in
Michigan to 97 percent in Louisiana. Hov.'ever, in Califor-
nia firm gas is only 14 percent of total industrial gas
consumption, reflecting California policy of not allowing
firm industrial contracts over 200 Mcf/day.
1-6
-------
The remaining states, those with smaller volumes of
industrial gas consumption, rely upon interruptible con-
tracts to a greater degree. The distribution of firm
versus interruptible volumes, although varying somewhat
in degree for specific states, is approximately 50-50.
The following table shows electric utility gas consumption
in eight states which comprised 82 percent of electric utility
gas consumption in 1973.
ELECTRIC UTILITY GAS CONSUMPTION BY STATE
1973
Trillions Percent of
of Btu's National Total
Texas 1285 37.4%
California 468 13.6
Louisiana 387 11.3
Oklahoma 267 7.8
Kansas 156 4.5
Florida 148 4.3
Arkansas 49 1.4
New York 48 1.4
All Other States 628 18.3
Total 3436 100.0
Source: Form 423's accounting for 93 percent of total reported
electric utility gas consumption.
Thus, gas consumption by electric utilities is somewhat
more concentrated in a few states than gas consumption
by industrials. Some 37 percent of electric utility gas
consumption occurs in the state of Texas alone. There are 9
contiguous states which have no or negligible consumption of
gas by electric utilities. Moreover, it is interesting to
note that five of the eight largest industrial gas burning
states -- Ohio, Illinois, Pennsylvania, Michigan and Indiana
1-7
-------
are not among the above listing of the eight largest electric
utility gas consuming states.
In Texas, Louisiana, Oklahoma, and Florida, firm gas
consumption accounts for 75 to 100 percent of total electric
utility gas consumption. In California, Kansas, Arkansas
and New York firm volumes are of little or no relative
importance. Generally, most electric utilities in other
states!/ rely largely on interruptible gas.
C. Sources of Gas Supply to Electric Utilities
This section explores in greater detail the flow of
gas to electric utilities in the Lower 48 States. By
reference to data developed for each of 415 gas burning
electric utility steam electric plants, this section
identifies some key contractual provisions with respect
to gas purchases by electric utilities. In addition,
the sources (suppliers) of gas to these specific electric
utilities are traced.
The Environmental Protection Agency provided a
list of power plants which burned gas from 1969 to 1973.
some of which did not burn gas in 1973 or in prior years.
To develop the list of gas burning steam electric plants
utilized herein, some plants which did not burn gas in prior
years were included. Gas burning plants which began operation
after 1973 where added as well as some small gas burning plants
with nameplate ratings less than 25 Mw.
I/ Nevada and New Mexico are significant exceptions in
~ that electric utilities in these states burn greater
amounts of firm gas than interruptible gas.
1-8
-------
The plants utilized herein burned 93 percent of
reported electric utility gas consumption in 1973, which
includes some gas turbine use. It is believed that the
remaining 7 percent would be accounted for in gas turbine
use, small plants, or synthetic (refinery or blast furnace)
gas.
Schedule 1-2 shows for 415 gas burning power plants
the volume of firm or interruptible gas consumed in 1973
and whether or not the gas contract expires within 24 months,
as of December 1974 by supplier. The notes (column 8)
indicate changes which may have occurred in 1974 with
respect to the gas contracts, and other pertinent observa-
tions .
The total natural gas purchases shown at column (4)
were provided by the Environmental Protection Agency, except
as noted. The volumes attributable to firm and interruptible
contracts and individual suppliers were estimated by refer-
ence to FPC Form 423 data.
Column (5) shows the percent of gas consumption by
the power plant provided by the supplier indicated at
column (7). For example, the gas consumed by the Kendall
Square Plant in Massachusetts (sheet 1) burned 500 MMcf
of interruptible gas in 1973, all of which was supplied
by Commonwealth Gas Co., which in turn buys gas from
Algonquin Gas Transmission, an interstate pipeline.
1-9
-------
The second power plant shown on sheet 1 is the
Fitchburg plant, which burned 596 MMcf of interruptible
gas in 1973 representing an interdepartmental transfer.
Interdepartmental gas transfers often occur for combination
electric and gas utilities, whereby the electric department
purchases gas from the gas department. In the case of
Fitchburg Gas and Electric, the gas department purchases
gas from Tennessee Gas Pipeline Co., an interstate pipeline,
Thus, the company (ies) that actually sells (sell) the gas
is the first listed, and the company (ies) shown in paren-
theses is the next link in the transfer of gas.
The detailed information provided with respect to the
sources of gas supply to the electric utilities is critical
in determining the future volume of gas available to these
electric utilities, as the supply situation and type of
curtailment plan of the supplier will influence the amount
of gas to the power plants. Moreover, whether or not
the gas supply moves through interstate commerce subject
to tariff regulation of the Federal Power Commission (FPC)
is an important consideration. As discussed at length
in Chapter II, the FPC and pipelines operating under its
jurisdiction have developed curtailment plans which affect
the amount of gas that electric utilities will burn. Thus,
the denotation "interstate" following a pipeline's name
indicates that it falls under tariff jurisdiction of the
1-10
-------
FPC. Some pipelines, or gas transportation contracts,
although subject to certificate jurisdiction of the FPC,
are shown as intrastate because they do not fall under
FPC tariff jurisdiction. A substantial number of electric
utilities in gas producing states receive gas from intrastate
companies whose gas supply and transportation facilities
are entirely intrastate and these are indicated as intra-
state on the schedule.
Schedule 1-3 summarizes by state some of the data from
1-2, showing electric utility purchases of natural gas by
type of supplier. For example, columns (1), (2) and (3)
show gas burned by electric utilities which passes through
interstate pipelines subject to tariff regulation of the
FPC. Column (1) indicates interdepartmental transfers,
column (2) indicates direct purchases from interstate
pipelines, and column (3) shows purchases from intrastate
pipelines or distributors who in turn purchase gas from
interstate pipelines. Columns (4), (5) and (6) show
purchases of gas by electric utilities from intrastate
pipelines which do not pass through interstate pipelines
subject to tariff regulation of the FPC.— Column (7)
shows the amount of gas which is purchased by electric
utilities directly from producers, without transfer of
ownership to a distributor and/or pipeline.
I/ Column (6) shows purchases from intrastate pipelines
or distributors who in turn acquire their gas from
other intrastate pipelines.
1-11
-------
Schedule 1-3 shows that for the total U.S., electric
utilities directly or indirectly purchased 1294 Bcf from
interstate pipelines, 1926 Bcf from intrastate pipelines,
and 170 Bcf from producers. Of the volume purchased from
interstate pipelines 28 percent was transferred from the
gas departments of combination utilities, 34 percent was
purchased directly from interstate pipelines, and 38
percent was purchased from intrastate pipelines or distrib-
utors who in turn purchased the gas from interstate pipelines.
With respect to the gas consumed by electric utilities which
is not affected by FPC jurisdiction, the majority - 95 percent
is purchased from intrastate pipelines who in turn buy the
gas at the wellhead in those states.
Schedule T-3 also facilitates analysis of sources of
gas supply to electric utilities for specific regions
and states. Electric utilities in the New England and
Appalachian regions acquire all of their gas through
interstate pipelines, which generally flows to the power
plants via interdepartmental transfers.
In the Southeast region, less than half of electric
utility gas consumption is purchased from interstate
pipelines, with the remainder indicated as being purchased
from producers. Florida Power and Florida Power {j Light
purchase gas from producers in Louisiana and Texas which
is then transported to power plants in Florida by Florida
Gas Transmission, an interstate pipeline. While these
1-12
-------
transportation arrangements were subject to FPC approval,
it is believed that the volume of gas transported is not
curtailable— as are the actual sales to power plants by
Florida Gas Transmission.
In the Great Lakes and Northern Plains regions, all
of the gas consumed by electric utilities flows through
interstate pipelines. Approximately 24 Bcf is purchased
directly from interstate pipelines, 82 Bcf represents
interdepartmental transfers and 124 Bcf is purchased from
gas distributors who in turn buy from interstate pipelines.
States in the Mid-Continent and Gulf Coast regions
generally burn more gas in power plants than those in
other regions previously discussed. The Mid-Continent and
Gulf Coast regions contain most of the gas produced in
the U.S., and thus it is not surprising that electric
utilities burn large volumes of gas from intrastate sources.
In this region, only in Missouri and Mississippi do electric
utilities purchase all their gas via interstate pipelines.
Electric utilities in Kansas purchased 63.9 percent of their
gas from interstate pipelines, the remainder coming from
intrastate sources. Interrtate pipelines provided 92
percent of electric utility gas consumption in Arkansas.
The states of Oklahoma, Louisiana, and Texas are
characterized by large volumes of gas moving to power plants
I/ Except to the extent that pipeline capacity is unavailable
1-13
-------
without passing through FPC jurisdiction. In Oklahoma
99 percent of the 271 Bcf burned by electric utilities
was purchased from intrastate pipelines. Electric utilities
in Louisiana burned 369 Bcf of gas in 1973, of which 28
percent came from interstate pipelines.
Texas utilities burn 37 percent of the gas consumed
by electric utilities in the U.S., and less than 2 percent
of this gas is evidently subject to curtailment by interstate
pipelines. Virtually all of the electric utility gas in
Texas is sold through gas companies subject to Texas
Railroad Commission regulation.
Electric utilities in New Mexico acquire over half of
their gas from intrastate sources. However, total electric
utilities in this state burned but 64 Bcf of gas in 1973.
Thus, for purposes herein, the states of Texas, Louisiana,
Oklahoma and New Mexico are treated as predominantly intra-
state markets. The remaining states are treated as pre-
dominantly interstate markets.
Chapter II discusses the curtailment policies of
interstate pipelines which will affect the gas available
to the electric utilities they serve. Chapter III dis-
cusses state policies towards the allocation of gas in
times of shortage.
1-14
-------
CHAPTER II
CURTAILMENTS OF NATURAL GAS SALES BY
INTERSTATE PIPELINE COMPANIES
Curtailments of natural gas service by interstate pipe-
lines, reducing in part or entirely deliveries of gas on
certain days to selected classes of customers, and the
resulting similar curtailments by their local gas distri-
butor customers are not new events in gas pipeline history.
Since the early days of the industry, the 1930's, service
curtailments have been employed to achieve the maximum
economic results from the large dollar investment in pipe-
line capacity. These curtailments may be designated as
capacity curtailments -- reductions in deliveries to certain
customers (generally authorized under contract) when pipe-
line capacity is being fully utilized to serve other cus-
tomers. Until 1968, gas supply was not a problem. In
recent years, steadily diminishing supplies of natural gas
have resulted in the need for reduction in deliveries due
to insufficient overall supply rather than lack of pipeline
capacity.
The history of pipeline and gas distributor service
curtailments starts in the 1940-1950 decade when the great
expansion of the natural gas industry began. The industry
grew from a supplier of 14 percent of the national energy
requirements in 1947 to 33 percent in 1970.
This chapter initially deals with traditional gas
pipeline economics which significantly influence the design
of pipeline curtailment plans. Following this overview
-------
of the gas pipeline industry is "ii analysis of overall
Federal Power Commission policy towards pipeline curtailments.
This chapter concludes with a summary of the effective
curtailment plans for 38 interstate pipeline companies
and the impact of these plans on the availability of gas
for industrial and electric utility use.
A. Traditional Gas Pipeline Economics
Most of the discussion that follows has equal applica-
tion to both the interstate pipelines and their local gas
distribution customers. The most recent annual sales
statistics, for 1973, report that sales for resale by the
major pipelines to gas distributors comprised 90 percent
of total pipeline sales.
In general, the pipelines and their distributor cus-
tomers supply two kinds of service: firm or guaranteed
service available on demand on any day, and interruptible
or curtailable service available on days when firm gas
requirements are less than capacity in the case of pipelines,
and less than the total gas supplies the local distributor
can call upon. Pipeline capacity is designed and constructed
to equal or slightly exceed the estimated peak day require-
ments for firm service.
Before capacity curtailments became a normal procedure
in pipeline operations and equitable plans for curtailment
*
of service were instituted and enforced, there were problems
similar to those recently arising as curtailments of deliveries
due to gas supply shortages.
II-2
-------
An illustration of pipeline capacity curtailments during
the early development period of the industry and the problems
arising from refusal of some interruptible service customers
to obey curtailment orders is provided in the following com-
ment on page 270 of the report on the Natural Gas Investigation
1944-1946 (Gas Investigation Report):-'
"It seems reasonable to expect that recent
experiences with drastic curtailments and
the resulting chaotic conditions of service
may have contributed to a better understanding
of this situation on the part of both the
supplying companies and their interruptible
customers."
The "drastic curtailments and chaotic conditions of
service" referred to in the Gas Investigation Report led to
adoption of restrictions in the late 1940's on addition of
residential and commercial space heating customers in a
number of the gas consuming states. The restrictions were
imposed by the state regulatory commissions on the local gas
distributing companies until the capacity of the supplying
pipelines under construction (new pipelines or expansion of
existing pipelines) would be sufficient to meet winter
heating requirements. Rapid development of the interstate
pipeline industry in the 1945-1955 decade permitted state
!_/ Natural Gas Investigation, Docket No. G-580, Federal
Power Commission, Report of Commissioner Nelson Lee
Smith and Commissioner Harrington Wimberly transmitted
to Congress April 28, 1948.
[1-3
-------
imposed restrictions to be lifted and the addition of
space heating loads to be controlled in an orderly pattern
under the construction authorization granted to the
expanding interstate pipeline industry by the Federal
Power Commission.
The capacity curtailment experience of the pipelines
during the early stages of the pipeline industry was
influenced by the following factors:
a) The nature of pipeline service
b) Economics of pipeline operation
c) Characteristics of demands for natural gas
d) Regulation of pipelines under the Natural Gas
Act, as it applied to rates, tariffs service
rules and construction authorizations.
Pipeline Services
Interstate pipelines sell for resale -- wholesale
sales -- (1) to local gas distributors for their retail
sales to residential, commercial, industrial and govern-
mental consumers, and (2) to other interstate pipelines
for resale to local gas distributors and for retail sales
to industrial, commercial and governmental consumers.
Pipelines also sell gas (depending upon sales policies)
at retail to industrial and governmental customers located
adjacent to the pipeline system -- main line industrial
customers. In addition, pipelines, if capacity is available,
transport over varying distances the gas owned by other
pipelines and gas owned by local gas distributors and
II-4
-------
other parties (e.g., petroleum company gas from the
gas fields offshore to onshore and to inland refineries).
Character of Pipeline Service
In general, an interstate pipeline offers only two
qualities of service as defined — below for its sales and
transportation of gas:
Firm Service
Service offered to customers (regardless of
Class of Service) under schedules or contracts which
anticipate no interruptions of service. Certain
firm service contracts may contain clauses which
permit unexpected interruption in event the supply
to residential customers is threatened during an
emergency.
Interruptible Service
Low priority service offered to customers
under schedules or contracts which anticipate and
permit interruption on short notice, generally
in peak-load seasons, by reason of the claim of
firm service customers and higher priority users.—
Sales for resale to gas distributors and other pipe-
lines include both firm and interruptible service under,
\J Adapted from 1975 Gas Facts, Appendix A Glossary;
American Gas Association, Department of Statistics.
2J Refers to temporary sales of short duration to alleviate
an emergency and preferred interruptible sales, which
take precedence over other interruptible sales if
service is curtailed.
II-5
-------
in most instances, separate sales contracts. Transportation
of gas for others and main line industrial sales may be
firm or interruptible or a combination of both methods;
e.g., firm service up to a specified daily volume and any
additional daily volumes subject to interruption.
Economics of Pipeline Operation
Interruptible sales are made at lower prices than those
which apply to firm sales to compensate for the lower priority
of service during peak gas demands on the pipeline capacity.
The usual interruptible sales contract requires that the
customer maintain a reasonable supply of other fuel for
heat requirements during periods of gas curtailment.
The definition of firm and interruptible pipeline
services applies also to the same kind of services rendered
by local gas distributors.
The economics of natural gas transportation (as well
as distribution) is importantly influenced by the high
degree of capital intensiveness characteristic of the
industry. Reflecting the relatively large investment in
plant per unit of sales, a large proportion of the overall
annual costs of a pipeline are fixed costs. Thus, the
volume of throughput for a pipeline has a significant
impact on unit costs. Also, it is generally accepted that
per unit transportation costs decline when the diameter of
the pipe increases.
II-6
-------
The primary elements involved in the plant invest-
ment of a gas pipeline are pipe and compression. The
predominant diameter of all main transmission pipelines
was 30-inch in 1972 according to Commission reports. As
reported in 1974, the cost per mile of pipeline was $100,000
for 24-inch pipe and $200,000 for 30-inch pipe. Compressor
station costs reported in 1974 averaged $302 per horsepower.
The following table shows the three major components
of the price of gas paid by consumers in 1973.
Components of the Burner Tip Price of
Gas in 1973
(jr/MMBtu Percent of Total
Field Price 21* 26%
Transportation Cost 25 32
Distribution Cost 33^ 4_2
TOTAL 79* 100%
Source: American Gas Association, Gas Facts.
Distribution costs comprise the largest portion of
the overall price of gas paid by the ultimate consumer,
followed by transportation costs. Among final consumers
of gas, there is considerable diversity by consuming sector
in the prices paid -- residential consumers paid on the
average in 1973 125
-------
sales are predominantly high load factor— sales to
distributors or large industrial plants.
Nearly three-fourths of the transportation cost reflects
capital items -- taxes, depreciation, interest, and net
income. With respect to distribution costs, approximately
60 percent represent capital items.
The design of pipeline rates in part reflects the
large proportion of fixed costs associated with transportation.
Most pipelines utilize a two-part monthly demand and
commodity tariff for their firm service sales for resale
to gas distributors.
The demand-commodity rate, also known as the "contract
demand" rate, provides the lowest average rate to the local
utility customer for monthly purchases at 100 percent load
factor (i.e., sales to the customer are made at his
maximum daily contract demand on each day of the month).
The average rate increases as the customer's monthly load
factor decreases.
An illustrative gas pipeline demand-commodity rate
and the effect of the monthly load factor on average rate
are shown on the following page.
\J Generally refers to the relationship between average
~ (day or month) sales to peak (day or month) sales.
In the following section, load factor and the nature
of the gas market are elaborated upon.
II-8
-------
Monthly Rate Per Mcf:
Demand $ 3.04 x Billing Demand
Commodity 30.4* x Total Volume of Gas Purchased
Minimum Bill:
The monthly demand charge
Billing Demand:
The contract demand (Maximum Mcf entitlement per day)
Average Monthly Rate Per Mcf:
Load
Factor
100%
75
50
25
Averaj;
Demand (
10*
13. 3
20
40
ie Rate P(
Commodity
30.4*
30.4
30.4
30.4
;r Mcf
Total
40.4*
43.7
50.4
70.4
The first part of the demand-commodity rate, the
demand rate, is often a fixed rate -- the same for all months
applied to the billing demand which in most cases is the
maximum daily volume (24 hour volume) the customer is
entitled to receive and the pipeline is required to deliver
on demand. The maximum volume is called the contract demand
and is measured in units of 1,000 cubic feet (Mcf). The
monthly demand rate approximates one-twelfth of the allocated
annual demand costs which are composed of a portion of the
annual fixed costs of the pipeline. Fixed costs consist
of the investment costs, amortization, depreciation and
depletion taxes and return on investment in facilities
and any operating expenses that do not vary with month
to month sales volumes.
11-9
-------
The commodity rate consists of the remaining portion
of the annual fixed costs plus all variable costs such as
cost of gas purchased from producers and other operating
expenses that vary with month to month sales. It is applied
to monthly sales volumes measured in Mcf.
The minimum monthly bill is usually only the total
demand charge (rate x billing demand) but in some instances
may require a commodity charge in addition to the demand
charge, equal to monthly purchases at 60 to 90 percent load
factor.
The cost classification and allocation to determine
the demand and commodity costs is based upon a "test year" -
a 12-month period reflecting actual experience and known
future sales and costs. In pipeline rate cases Commission
approval is required of the final classifications and allo-
cations whether or not the rates are determined by public
hearing or by informal settlement agreements between the
pipeline, the customers and other intervenors, and the
Commission's staff.
In the early 1950's, the Commission in a pipeline
rate case of the Atlantic Seaboard Gas Company adopted a
cost classification and allocation that has remained a
standard for the pipeline industry and is known as the
Atlantic Seaboard Allocation. In general, pipelines have
been required to classify and allocate costs in accordance
with the Atlantic Seaboard procedure. Demand and commodity
11-10
-------
rates could depart from the allocated costs if good cause
were shown such as loss of large firm industrial loads
by the local gas utility customers to a competitive fuel
supply. The principal feature of the Atlantic Seaboard
cost allocation was the classification of fixed costs -- 50
percent to demand costs and 50 percent to commodity costs.
The 50-50 classification tended to reduce demand rates
and increase commodity rates since in prior years most
fixed costs had been classified by utilities as demand costs,
especially in the electric utility industry for large com-
mercial and industrial sales. The underlying theory for
the demand-commodity rate form contemplated that all fixed
costs would be recovered by the fixed monthly demand rate
and only variable costs would be assigned to the commodity
rate. The increase in commodity rates by the Seaboard
classification resulted in greater costs being assigned to
interruptible service with consequent higher rates to
both main line industrial customers of the pipelines and
interruptible industrial customers of the local gas utilities
The local gas utilities as a policy, have used the commodity
rate charged for gas purchased from the pipeline supplier
as the base on which to construct rates for industrial
customers receiving interruptible service.
In the past two years, 1973 and 1974, because of the
gas supply shortage the Commission has been requiring that
the demand and commodity rates level be not less than the
11-11
-------
costs obtained under the Seaboard classification -- a re-
versal of previous tolerance of departures. Also, there
have been indications that the Commission may require 75
percent instead of 50 percent of the fixed costs to be
assigned to commodity costs and to commodity rates. The
purpose is to raise the level of interruptible industrial
rates, pipeline and distributor, so as to approach the
prices of the alternative fuels, oil and coal.
Sales of gas by the interstate pipeline supplier
to the local gas distributors for resale are governed
by the two key documents filed with and accepted by
the Federal Power Commission, and kept up to date by
similar filings and acceptance of additions and revisions.
The key documents are the effective pipeline tariff
and the sales contract or contracts which are designated
by the Commission as service agreements. The pipeline
company tariff is required to provide a standard form
of sales contract for all customers, separately for firm
service, interruptible service, and other services, such
as storage, winter service, and transportation only of gas
The sales contract for firm service covering most
of the gas sold is also illustrative of the contracts
for the other services. Under the standard form, the
contract with each firm service customer incorporates by
reference to the effective pipeline tariff, (1) the
currently effective rate schedule and (2) the General
11-12
-------
Terms and Conditions of service which comprise among
others, gas quality standards, measurement of gas quantities,
meter error adjustments, billing and payment, determination
of quantities delivered, e.g., where both firm and inter-
ruptible service is purchased through one meter on the same
day; and the gas curtailment plans and policies.
Also under the standard form contract but with
variations among the customers, are the maximum daily
quantities of gas to be delivered (usually designated
as the contract demand), the location of delivery points, the
pressure of the gas delivered at each point, and the
term of service of the sales contract.
The initial contract term of service is almost
universally for 20 years. The contract automatically
extends from year to year unless advance notice of
termination by either party -- usually 12 to 24 months --
has been given. Generally, an addition or reduction in
contract demand agreed upon by the parties is implemented
by a new 20-year contract for the revised quantity. The
pipeline supplier can not discontinue or reduce contract
deliveries when the contract terminates without Commission
authorization as provided under Section (7) (b) of the
Natural las Act - Abandonment of Service. (Curtailment"
of deliveries because of the gas shortage is not subject
to Section (7) (b) of the Act as interpreted by the
Commission and the courts.)
11-13
-------
The gas distributor generally can terminate the contract
at the end of the term although the Commission may as a
practicable matter prevent termination, in the public interest
after hearing, by denying authorization for service to a
new supplier.
Characteristics of Demand for Natural Gas
The traditional characteristics of service by pipeline
systems reflect in part the nature of distribution economics
which are in turn related to the seasonal characteristics
of demand for natural gas. Particularly with respect to
the relative stability or seasonal fluctuation of demands,
it is necessary to distinguish among the classes of use.
The seasonal consumption of gas, both in the composite
and for the sectoral distribution, is not uniform through-
out the year. Space heating sales, which represent a large
proportion of residential and commercial demand, are
seasonal in nature, resulting in low-load factors (average
day -^ peak day) for residential and commercial requirements.
On the following page is a chart showing monthly
distributor sales of gas in the United States by sector
for the year July 1972-June 1973. From this chart the
seasonality of residential and commercial sales is quite
apparent, with the preponderance of sales occurring in
the October to March period. The "All Other" category on
the chart is primarily industrial and electric utility, both
11-14
-------
CD
LU
I—
I—
Q
LU
£
Z
< I
0~
iA
tt
O
3
CD
z
O
I
\
;8
O
O
Q.
CJ
o
O
ffl
o
o
o
o
o
o
O
O
O
O
O
00
O
O
(0
O
O
O
O
tr >
% 3
2 I
O fc
ss i
oe i
ui o
i §
y £
* I 8
S * -5
g | -
o I »
0 i 5
B]I
^ o ••
£ "£ 3
*~ ? •-
& 1 »
in .£ c
£ «
§11
o &
i •• S
I
? :
3
O
I33J Diaro
f* 11210
r r-is
-------
firm and interruptible. These categories are not separated
by the source. However, firm industrial sales generally
follow a seasonal pattern similar to residential and com-
mercial sales, although not nearly to the same degree. In
part, interruptLble sales offset this seasonality by occurring
predominantly in the period May to October. The combination
of firm and interruptible industrial sales has traditionally
resulted in relative seasonal stability for sales to the
industrial sectors.
Importantly, interruptible sales also contribute addi-
tional revenues to pipelines and distributors without
significant additional investment. Due in part to the
contribution of these revenues, prices to firm customers
have been lower than they would have been otherwise.
By definition and general practice, interruptible sales
have been curtailed for many years during periods in which
firm demands were high. These were, as has been noted
previously, capacity curtailments and considered normal
operating procedure.
Regulation Under The Natural Gas Act
Federal regulation under the Natural Gas Act over the
interstate pipelines since 1938 and over the sales of gas to
them by the gas producers since 1954, has an indirect but
important impact on gas curtailments.
11-16
-------
The Act which became effective in 1938 delegates the Federal
regulation to the Federal Power Commission (Commission)
which also regulates interstate movement and sales of
electricity. By U.S. Supreme Court decision in 1954 the
sales for resale in interstate commerce, i.e., the present
and future sales to the interstate pipelines by gas pro-
ducers, became subject to the Act and regulation by the
Commission.
Regulation under the Act is limited to the transporta-
tion and sale for resale of gas in interstate commerce.
Retail sales of gas by local gas distributors are regulated
by the State Regulatory Commissions. Mainline industrial sales
(retail sales) of the interstate pipelines are subject under
the Act to the transportation jurisdiction of the Commis-
sion but not to its sales and price regulation. Under
the Act, licenses for exports and imports of gas to and
from foreign countries are under the jurisdiction of the
Commission subject to agreement with Commission actions by
the Departments of State and Defense.
Sections 4 and 5 of the Act, the "rates and charges"
sections, and Section 7, the sales and facilities authoriza-
tions section, affect the curtailment of service policies
and practices of the interstate pipelines and therefore of
the state regulated local gas distributors that are depen-
dent for gas supply on the pipelines.
I 1-17
-------
Under the Act and the Commission's rules and regula-
tions to implement it, the interstate pipelines (natural gas
companies) are required (among other requirements) to keep
on file with the Commission and to have available at their
business offices for public inspection, their rate schedules
that are currently in effect. The separate schedules are
compiled in a book form designated as the tariff of the
company. As noted previously the tariff contains the
applicable curtailment plan of the interstate pipeline and
other pipeline service provisions.
The purpose of the filing and availability for public
inspection is to assure the equal treatment of their cus-
tomers provided for in Section 4(b) of the Act:
"No natural gas company shall with respect
to any transportation or sale of natural gas
subject to the jurisdiction of the Commission,
(1) make or grant any undue preference or
advantage to any person or subject any person
to any undue prejudice or disadvantage, or (2)
maintain any unreasonable difference in rates
charges, service, facilities, or in any other
respect, either as between localities or as
between classes of service."
The following table contains the most pertinent
Commission regulations applicable to r?te schedules,
tariffs and the implementation of Section 4(b).
11 -1:
-------
Selected Regulations and Definitions of the
Federal Power Commission Under Section 4 of
The Natural Gas Act.
IN GENERAL
§154.21 Effective tariff.
The effective tariff of a. natural-gas
company shall be the tariff filed pursuant
to the requirements of this part, and
permitted by the Commission to become
effective No natural-gas company shall
directly or indirectly, demand, charge or
collect any rate or charge for or in con-
nection with the transportation or sale
of natural gas subject to the jurisdiction
of the Commission, or impose any classi-
fications, practices, rules or regulations.
different from those prescribed in its
effective tariff and executed service
agreements on file with the Commission.
unless otherwise specifically provided by
order of the Commission.
I Order 144, 13 PR. 6371. Oct 30. 1948, 13 F.R.
6838, Nov 20, 1948]
§ 15V.22 Notice requirements.
All tariffs, and contracts or any parts
thereof shall be filed with the Commis-
sion and posted not less than thirty days
nor more than sixty days prior to the
proposed effective date thereof unless a
different period of time is permitted by
the Commission in accordance with
§ 154 51. Provided, however, That no
natural-gas company shall file under
this part any new rate schedule or con-
tract for the performance of any service
for which a certificate of public con-
venience and necessity must be obtame'
pursuant to section 7ic> of the Natur
Gas Act, until such certificate has bee
issued. Nothing herein shall be con-
strued as preventing the natural-gas
company from entering into any such
agreement prior to the granting of such
a certificate
I Order 144. 13 PR 6371. Oct 30 1948. 13 P R
S838. Nov 20. 1948|
§ 154.23 Acceptance for filing not up.
proval.
The acceptance for filing of any tariff.
contract or part thereof is not to be con-
sidered as approval by the Commission.
(Order 144. 13 F: 6371, Oct. 30. 1948; 13 F R.
6838. Nov 20. 1948 |
§ 154.11
DEFINITIONS
Rate schedule.
The term "rate schedule" means a
statement of a rate or charge for a par-
ticular classification of transportation or
sale of natural gas subject to the juris-
diction of the Commission, and all terms.
conditions, classifications, practices.
rules and regulations affecting such rate
or charge. This term also includes any
contract for which special permission
has been obtained in accordance with
§ 154.52.
(Order 144, 13 F R 6371. Oct. 30, 1948; 13 F.R.
6838, Nov 20. 1948 ]
§ 154.12 Contract.
The term "contract" means any agree-
ment which in any manner affects or
relates to rates, charges, classifications,
practices, rules, regulations or services
for any transportation or sale of natural
gas subject to the jurisdiction of the
Commission. This term includes an ex-
ecuted service agreement.
(Order 144, 13 F R 6371, Oct. 30, 1948; 13 F.R.
6838, Nov 20. 1948)
§ 154.13 Service agreement.
The term "service agreement" means
an unexecuted form of agreement lor
service under a natural-gas company's
tariff.
(Order 144. 13 FR 6371. Oct 30, 1948. 13 F R.
6838, Nov. 20. 1948(
§154.14 Tariff or FPC gas tariff.
The term "tariff" Or "FPC gas tariff"
means a compilation, in book form, of all
of the effective rate schedules of a partic-
ular natural-gas company, and a copy
of each form of service agreement.
(Order 144. 13 F R 6371, Oct 30, 1948. 13 F.R
6838. Nov 20. 1948!
154.15 Filing date.
The term "filing date" means the day
on which a tariff or part thereof or a
contract is received in the office of the
Secretary of the Commission for filing
in compliance with the requirements of
this part.
(Order 144. 13 FR 6371, Oct 30. 1948. 13 F.R
6838, Nov 20, 1948 |
§ 154.16 Porting.
The term "posting" means (a) making
a copy of a natural-gas company's tariff
and contracts available during regular
business hours for public inspection in
a convenient form and place at the nat-
ural-gas company's offices where business
is conducted with affected customers and
(b) mailing to each customer affected a
copy of such tariff or part thereof at
the time it is sent to the Commission
for filing.
(Order 144. 13 F R 6371, Oct 30, 1948. 13 F R
6838. Nov 20 1948 |
Source: Regulations Under The Natural Gas Act, Part 154,
Federal Power COIPTI i <^= i on
-------
Regulations especially pertinent to interstate pipeline
sales for resale and service curtailments are in Sections
154.21 and 154.11. The prices or rates and the curtailment
policies and practices are to be only those in the current
tariff. Public and customer inspection of the rate schedules,
tariffs and sales contracts is provided in Section 154.16,
Posting.
The regulations were instituted in 1948 by the various
Commission orders. These no doubt have helped to prevent
reoccurrence of the "recent experiences with drastic cur-
tailments and the resulting chaotic conditions of service"
referred to in the Gas Inves igation Report.
Many recent FPC curtailment hearings have been in-
stigated when the pipelines filed their curtailment plans
pursuant to Section 4 of the Act and the Commission's regul-
ations .
Mainline industrial sales of the pipelines, firm
and interruptible, are not covered by the regulations
quoted in part in the table since these are not sales
for resale subject to Commission jurisdiction. However,
copies of the sales contracts with large mainline customers
(50 million cubic feet annually and over) are required to
be filed with the Commission under Section 155 of the
Regulations and a full report on all but very small
customers, inclusive of sales volumes, revenues, average
price and type of service is required in the pipeline
companies' annual report of operations (FPC Form 2) to
the Commission.
11-20
-------
Section 5 of the Act enables the Commission to hold
public hearing and investigate upon its own motion or upon
complaints of local gas distributors, municipalities,
state regulatory commissions or States directed against
any rate, charge rule, practice or classification in a
pipeline company's tariff. If after the investigation
and hearing the Commission finds any of the above to be
unjust, unreasonable, unduly discriminatory or preferential
the Commission shall order the remedy needed.
Subsequent to Commission acceptance of a tariff filing,
relatively few hearings over the years have been initiated
pursuant to Section 5 by gas distributors or state authorities
However, the gas shortage curtailment plan filings have
resulted in more such complaints.
The pipeline may not attach a new mainline industrial
customer without first obtaining Commission authorization
as provided under Section 7 of the Act. This limited
control over mainline sales derives from Commission
jurisdiction over all interstate transportation of gas.
Section 7 of the Act in general requires authorization
(Certificate of Public Convenience and Necessity) for
construction or extension of interstate pipeline facilities
and the transportation or sale of natural gas by such
facilities in interstate commerce inclusive of new pipelines
and expansions of existing pipelines.
Under Section 7(e) of the Act, a pipeline applicant
must demonstrate that its request "is or will be required
by the present or future public convenience and necessity
I r- ^-i
-------
and that the applicant is willing to do the acts and to
perform the services proposed..." -- otherwise the application
will be denied.
A public hearing on all applications except for minor
facilities is required with reasonable notice to all.
"interested persons," such as adjacent and possibly
competing pipelines, gas distributors, municipalities
along the pipeline route, land owners, state and federal
agencies that may be interested, and others.
In the absence of an overriding vital objection in
the public interest, such as in recent years environmental
impact, the certificate application will be granted by
the Commission if three principal tests are satisfactorily
met: (1) adequate gas supplies, (2) adequate markets for
the new gas sales and (3) the economic feasibility of
the project.
The economic feasibility test has affected interruptible
industrial sales and the resulting curtailments of service.
Under this test, in addition to the overall cost of the
project and the method and cost of financing the
investment in facilities, the pipeline applicant is required
to show sufficient revenues from the new or expanded
sales -- sales for resale to local distributors and main
line industrial sales -- to meet all costb and provide a
reasonable return on the investment.
11-22
-------
Revenue sufficiency in the case of an existing pipe-
line would generally mean that the new or additional sales
would pay the incremental cost of the new facilities and
would not require rate increases to existing customers
who are not receiving a benefit from the expansion. In
general, to achieve the necessary revenues, new or
expanded industrial sales are required to offset winter
space heating sales. In other words, the sales to the
new customers and the increase in sales to existing
customers should be made at reasonably high load factors
so that the gas rates charged in the local markets will
not be so high as to discourage market growth. As an
example, because of a lack of a local manufacturing
industry, the sales proposed in a Section 7 proceeding by
a potential new distributor customer of a pipeline may be
limited to only residential and commercial consumers and
be principally space heating.
The very low load factor of the space heating sales
(25 to 30 percent) may require such high rates for gas
that only a few domestic and commercial customers would
convert from oil or coal to gas fuel. The addition of
large interruptible industrial sales would greatly improve
the load factor, reduce the local rates and enhance the
opportunity for market growth.
Other notable provisions of Section 7 of the Act
are 7(a) and 7 (b). Section 7 (a) provides that the Commission,
subiect to certain restrictions, may order a pipeline under
11-23
-------
its jurisdiction, after notice and opportunity for hearing,
to sell gas to a local distributor, municipally or privately
owned, that the pipeline has voluntarily refused to service.
Section 7(b) provides that a certificated sale of gas may
not be abandoned by a pipeline or gas producer without first
obtaining the Commission's permission. Other important
parts of Section 7 provide for temporary certificates
(these are also subject to Section 7(b) above) and the
Commission's power to attach "reasonable terms and conditions"
to the certificates issued.
During the 20 years, 1950 through 1969 -- a period of
spectacular expansion for the natural gas utility indus-
try -- the Commission issued over 4100 certificates for more
than 150,000 miles of interstate pipelines. These authoriza-
tions for sales to new and expanded markets are indicative
not only of the growth of the industry but also of certifi-
cate applicants' success in meeting the economic feasibility
test, an important part of which is the addition of indus-
trial sales for load factor improvement -- including both
firm and interruptible sales.
Historically, the state regulatory commissions may
not have approved but did not oppose interruptible indus-
trial sales by intrastate gas distributors. In general, the
higher load factors of these sales and the net revenues
earned served to reduce rates charged for domestic service.
11-24
-------
The lower rates for interruptible sales of gas for boiler
fuel as compared with competitive fuels helped to reduce
costs of local electric power generation and also helped
to reduce air pollution which would have resulted if
high-sulfur alternative fuels were burned.
B. The Development of Federal Power Commission Policy
Concerning Gas Supply Curtailments
The pipeline capacity curtailments of interruptible
industrial sales as needed continued as the only regular
service reductions until 1970. Firm service had been un-
affected over the years and gas supplies for market growth
were ample. Until 1968, gas reserves increased despite the
annual 6 percent increases in the gas production.
Interstate pipeline reserves and production which com-
prised over 60 percent of the Lower 48 States reflected the
national pattern: reserves decreased from 198 Tcf (1967) to
134 Tcf (1973) and production increased from 11.8 Tcf (1967)
to 14.2 Tcf (1972) but dropped to 13.7 Tcf in 1973.
The impact of the lessening supplies of natural gas was
not really apparent until late 1970 when the first major
pipeline curtailment case was brought to the Commission.
Seven major pipelines curtailed service for the first time
in the winter 1971-1972 because of gas supply shortages.
11-25
-------
Design of End-Use Priority Curtailments
The Commission required the pipeline companies to file
as a part of their effective tariffs any proposed curtail-
ment of service plans they instituted as a result of short
supplies. After analysis of the filings of 24 pipelines
between 1969 and 1972, the Commission on January 8, 1973 in
rule-making Docket No. R-469 issued a Statement of Policy
Order No. 467 — which prescribed nine priorities of service
based upon end-use of gas by the ultimate consumers that are
to be followed by the interstate pipelines when they curtail
gas service to their customers.
The nine service priorities are shown below:
END-USE OF GAS DURING CURTAILMENT - PRIORITY DESIGNATIONS
1. Residential, small commercial (less than 50
Mcf on a peak day).
2. Large commercial requirements (50 Mcf or more
on a peak day), firm industrial requirements
for plant protection, feedstock and process
needs, and pipeline customer storage injec-
tion requirements.
3. All industrial requirements not specified in
(2), (4), (5), (6), (7), (8) or (9).
4. Firm industrial requirements for boiler fuel
use at less than 3,000 Mcf per day, but more
than 1,500 Mcf per day, where alternate fuel
capabilities can meet such requirements.
I/ As amended by Orders Nos. 467A and 467B.
11-26
-------
5. Firm industrial requirements for large volume
(3,000 Mcf or more per day) boiler fuel use
where alternate fuel capabilities can meet
such requirements.
6. Interruptible industrial requirements of more
than 300 Mcf per day, but less than 1,500 Mcf
per day, where alternate fuel capabilities
can meet such requirements.
7. Interruptible requirements of intermediate
volumes (from 1,500 Mcf per day through 3,000
Mcf per day), where alternate fuel capabili-
ties can meet such requirements.
8. Interruptible requirements of more than 3,000
Mcf per day, but less than 10,000 Mcf per day,
where alternate fuel capabilities can meet
such requirements.
9. Interruptible requirements of more than 10,000
Mcf per day, where alternate fuel capabilities
can meet such requirements.
Curtailment would start with Priority 9 and proceed in
reverse order to Priority 1, residential and small commer-
cial service -- the last class of customers to be curtailed.
The end-use priorities apply to all sales by a pipeline:
sales for resale to local gas distributors and other pipe-
lines and retail sales to main line industrial customers.
For example, each local gas distributor will provide
the pipeline supplier with the daily volumes of gas needed
in the winter and in the summer months to supply its consumers
arrayed in accordance with the nine service priorities. The
pipeline supplier will composite these for all of its local
gas distributor customers and for all pipelines that it
serves -- the pipeline buyers having made the same deter-
minations and composites for their customers. Next, the
11-27
-------
pipeline supplier's own main line industrial sales will be
added to the distributor and pipeline composite require-
ments. The overall total daily winter and summer sales of
the pipeline supplier will thus be arranged by nine prior-
ities and curtailment orders will be issued starting with
Priority 9.
Order 467 provided the following instructions on the
scope of the Commission's nine service priorities, excep-
tions to their observance and method of operation under the
priorities during periods of service curtailments:
"The priorities-of-deliveries set forth above
will be applied to the deliveries of all jurisdic-
tional pipeline companies during periods of curtail-
ment on each company's system: except, however,
that upon a finding of extraordinary circumstances
after hearing initiated by a petition filed under
Section 1.7(b) of the Commission's Rules of Practice
and Procedure, exceptions to those priorities may
be permitted.
The above list of priorities requires the full
curtailment of the lower priority category volumes
to be accomplished before curtailment of any higher
priority volumes is commenced. Additionally, the
above list requires both the direct* and indirect
customers* of the pipelines that use gas for similar
purposes to be placed in the same category of priority.
Mainline industrial and other retail customers
of the pipeline are "direct" customers. The
customers of the local gas distributors supplied
by the pipeline are "indirect" customers.
II-2!
-------
Policy statements such as Order No. 467 are issued
infrequently to give notice to the companies under the
Commission's jurisdiction of the policies that will be
followed in the future concerning specific important and
generally controversial subjects that it will decide.
Excerpts from Order No. 467 that explain the Commission's
reasons for the end use service priorities follow:
"The curtailment procedures to be followed
must have as their basic objective the protection
of deliveries for the residential and small volume
consumers who cannot be safely curtailed on a daily
basis and requiring, as the initial level of cur-
tailment, reduction in deliveries for large volume
interruptible sales."
The Commission then quoted as follows from its decision
of January 5, 1973 in the Arkansas-Louisiana Gas Company
curtailment proceeding (Opinion No. 643 Docket No. RP71-122)
in regard to end-use of gas by the consumer and interrup-
tibles and firm service priorities:
"We are impelled to direct curtailment on
the basis of end use rather than on the basis of
contract simply because contracts do not neces-
sarily serve the public interest requirement of
efficient allocation of this wasting resource.
In time of shortage, performance of a firm con-
tract to deliver gas for an inferior use, at the
expense of reduced deliveries for priority uses,
is not compatable with consumer protection.
Secondly, we have determined that interrup-
tible sales are for the most part, predicated on
end-use considerations; those customers, be they
direct sales or indirect sales, who require gas
11-29
-------
for human needs service or non-substitutable indus-
trial service do not contract on an interruptible
basis. Interruptible service, at the lower rates
charged for such service envisions interruption.
And accordingly, interruptible customers can most
reasonably be expected to have alternate fuel facil-
ities already operational. We conclude, therefore,
that curtailment should first fall on those who have
not historically borne the full-fixed costs of pro-
viding gas service, particularly since these customers
are best prepared to accept interruptions in service
and clearly do not require uninterrupted service for
protection of life or property.
Finally, if curtailment reaches beyond the
level of interruptible service into firm contract
service, we commit ourselves to the proposition
that large volume boiler fuel usage is inferior
and should be curtailed before other firm service.
Aside from the established physical fact that com-
bustion of natural gas for raising steam in boilers
and its subsequent conversion into electricity or
mechanical energy results in a loss of roughly
two-thirds of the heating value of the gas used --
which we regard as unacceptably inefficient in time
of shortage -- we note also that those who "se gas
as boiler fuel generally can substitute other fuels
more readily and at lower overall cost than other
gas users; additionally, pollution control is more
practical because of the large size of individual
installations. Other fuels generally can be physically
substituted in large boiler fuel application with
less inconvenience and less possible adverse con-
sequences than in other industrial applications,
such as direct fired uses, and other uses demanding
precise temperature control, flame characteristics,
instantaneous response and atmosphere quality.
Finally, subordinating boiler fuel use with its
comparative ease of substitutability, to other large
scale industrial and commercial uses should tend to
minimize plant and business closings and the attendant
economic loss from decreased production and payrolls,
and the other personal hardships of unemployment
[Footnote omitted].
In establishing the priorities-of- service for
the use of the natural gas supply, it is obvious that
some direct and indirect customers use their supply
of natural gas for similar end-use purposes. Customers
11-30
-------
with similar usages for the fuel should be accorded
the same treatment to avoid any undue discrimination
or preference among them. Accordingly, we will place
the direct and indirect customers in the same priority-
of-service position as when their use of natural gas
is comparable.
In determining our priority-of-service listing,
we are cognizant of the economic impacts that will
flow from that listing. However, we believe that we
have no choice but to impose certain restrictions
on the sale of natural gas within the limits of
our jurisdiction during this time of supply shor-
tages. Our decision is made with full knowledge
that certain sales to ultimate customers are beyond
our jurisdiction. In those instances, we solicit
the cooperation of State authorities to aid imple-
mentation of this program.
The Commission also issued two rule making dockets,
Docket Nos-R-467 and R-468 to obtain comments on four pro-
posals that may be adopted in the future and on certain
changes proposed in its regulations to collect end-use
data and implement the service priorities:
Further, we are cognizant of the necessity
for a continual review and implementation of pol-
icies as will forestall or hopefully preclude
other pipeline companies from attaining similar
shortage problems on their system and to promote
the most efficient use of this natural resource
during this time of short supply. To these ends,
we solicit comments on several alternatives which
may be considered in arriving at a rational solu-
tion to the optimum allocation of limited gas
reserves at a time of shortage.
Only the first alternative or proposal is quoted be-
cause of its relevance to past Commission actions in regard
to rate design and cost allocations:
(1) Pipeline rates have been designed, in
part, on the basis of economics. Thus, certain
rates have been approved that encouraged indus-
11-31
-------
trial sales, which sales, in today's view, would
be placed in a low priority status. Such rate
design techniques will be reviewed to meet today's
supply situation and should encompass such matters
as elimination of conjunctive billing, modification
of the Seaboard formula, separate rate for jurisdic-
tional industrial service, elimination of annual
contract demands and, in lieu thereof, the use of
monthly or seasonal demands, and any other aspects
of rate design relating to the principles of con-
servation of natural gas supply within the concepts
set forth above.
The three other proposals dealt with minimum bills
under gas producer contracts, end-use of gas imported from
foreign countries and requiring the pipeline companies to
supply a complete market study that would reflect end usage
of their sales.
The nine service priorities established by the Commis-
sion leave to the pipelines the method of implementing the
priorities during curtailment periods. In general, the
following preliminary steps by the pipeline supplier are
needed:
1. Collect the end-use data from their distrib-
utor and mainline industrial (direct) custo-
mers arranged by the nine priorities of ser-
vice.
2. Establish the 12 monthly total gas volume
entitlements and maximum daily volume require-
ments in each month, for each customer. In
general, these volumes would be the actual
deliveries to the customer in a 12-month
period before the gas supply became defici-
ent; i.e., 1969 or 1970, with some allowance
for residential and small commercial load
growth during subsequent years.
3. Array the gas volume data in (2) for each
11-32
-------
customer in accordance with the nine service
priorities.
4. For each of the 12 months, usually separated
into winter and summer six-month periods, es-
timate the total supply of gas available to
the pipeline company.
The company then would have available (a) the total monthly
gas requirements and the maximum daily gas requirements dur-
ing each month for each customer divided into the nine ser-
vice priorities and (b) the total monthly gas supplies. The
difference between the total gas supply and the total re-
quirements for each month is the monthly supply deficiency
or the volume of gas to be curtailed during a particular
month.
The curtailment volume in any month will be prorated
daily to each customer's requirements in reverse order of
the nine service priorities -- starting with Priority 9,
curtailing all deliveries in that priority before any deliv-
eries are curtailed in Priority 8 and following the same pro-
cedure up through Priority 1 if necessary.
The composition by priorities of the customer's maxi-
mum daily needs in each month is important since a customer
on his own account may normally curtail completely low pri-
ority boiler fuel sales during days of severe winter weath-
er to protect domestic space heating requirements (Priority
1) and hence should not be ordered by the pipeline supplier
to curtail gas on such days. On other relatively warm winter
11-33
-------
days the same customer may supply all nine priorities of
service and should be curtailed as indicated above.
If the actual gas supply for a month is more or less
than the estimate, the daily curtailment volumes will be
adjusted accordingly. In general, no change in curtailment
will be permitted for variances in customer requirements
determined in the base period. —
The assignment of customer gas requirements to the
nine priorities of service may cause disagreement among the
customers or between the customers and the pipeline supplier.
In this event, the matter may be brought to the Commission
for hearing and decision.
It is important to note that a pipeline's curtailment
plan is a method of allocating gas to its customers, but
does not necessarily result in a specified level of consump-
tion at the burner tip. Most of an interstate pipeline's
sales are in turn sold by the pipeline's distributor customers.
Under a curtailment program, the amount of gas which a
distributor has to sell is directly influenced, but the
sectoral distribution of the distributor's actual sales
may differ from that which is implied by the curtailment
method of the pipeline. For example, a distributor may have
!_/ There is some controversy concerning the issue of
requirements based upon base period data. The question
is whether or not to periodically update base period
data to reflect market conditions.
11-34
-------
sources of gas supply other than purchases from the interstate
pipeline, such as direct purchases from producers, synthetic
gas, or propane-air mixtures. The distributor may also be
buying gas from two or more interstate pipelines with differing
curtailment plans in effect. Moreover, the distributor's
market structure may have changed somewhat from that which
would be indicated in the historical base period data upon
which the curtailment plan relies.
Order No. 467 was subjected to considerable criticism
by pipelines, local gas distributors, industrial consumers,
states and trade associations. Most agreed, however, that
the end-use concept was proper.
The following are among the more critical comments:
the firm and interruptible service classifications are not
defined the same throughout the industry so that an identical
end use could be classified either way, e.g., in Priority 5
or Priority 8; size classification should not be a factor --
only end use; end use of boiler fuel should be considered, e.g.,
boiler fuel for heating hospitals; sets nationwide priori-
ties without considering varying conditions including avail-
ability of alternate fuels, patterns of reliance, prior
investment by consumers in expectation of adequate gas
supplies, prior investment by gas distributors in supple-
mental gas facilities.
11-35
-------
The following table, which shows the percentage composi-
tion of the regulated gas utility industry market since 1950,
is illustrative of the potential for severe economic impact
through loss of industrial sales and revenues under the
priority of service curtailments:
REGULATED GAS UTILITY ANNUAL SALES BY SERVICE CLASS,
PERCENT OF TOTAL SALES, 1950-1973
Year
1950
1955
1960
1965
1970
1973
Residential
Priority 1
33
34
34
33
31
30
Commercial
Priorities 1 & 2
10
9
10
11
13
14
Industrial
Priorities 3-9
54
53
51
51
53
51
Other
Priority 2
3
4
5
5
3
5
Source: American Gas Association, 1973 Gas Facts.
Severe reductions in industrial sales of local gas
distributors and main line industrial sales of the pipeline
will have a substantial impact upon local employment.
Moreover, a reduction in industrial sales by the local
gas distributors because of the service curtailments
will require rates for residential and commercial sales to
be increased to recover costs of service. Lower sales to
the gas distributors will reduce the load factors of the
pipeline suppliers and require rate increases to the local
distributors.
11-36
-------
Schedule II-l shows for each reporting interstate pipeline
the total volumes of firm gas service curtailed during the years
1970 through 1974, and the percentages that the curtailments are
of annual firm requirements. In 1970, five companies cur-
tailed firm service, increasing to twenty-two in 1974. Ex-
cluding intercompany curtailments, curtailments increased
from 18 Bcf in 1970 to 1679 Bcf in 1974. Not shown on this
schedule are a number of pipelines which have not as yet
curtailed firm requirements.
Similar data are not available for interruptible
service curtailments during the 1970-1974 period. However,
for the twelve months ended August 1974, total interruptible
service curtailments were 248 Bcf, or 38 percent, of "normal"
interruptible service requirements; i.e., interruptible sales
that would be made if gas supplies were available but ex-
cluding normal capacity curtailments.
C. Current Curtailment Plans of 38 Interstate Pipelines
As a result of the gas shortage, many pipelines are
not able to fulfill their contracts to sell gas. Thus their
curtailment plans pertain to a very pragmatic problem -
the day-to-day and/or month-to-month allocation of insufficient
supplies to their customers, occasionally numbering in the
hundreds. The development of curtailment plans, the hearings,
11-37
-------
and ultimate acceptance by the FPC have been time consuming
and controverted processes, and are expected to continue
into the indefinite future.
Schedules II-3, II-4, and II-5 give specific case histories
for three major interstate pipelines, directly or indirectly
supplying gas ultimately used by electric utilities on
the West Coast, East Coast and Louisiana and Mississippi.
These case histories indicate the complexities of curtailment
procedures.
Because of the different markets served by various
pipelines as well as different supply situations, many of
the curtailment plans in effect differ among themselves and
from the guidelines promulgated by the FPC. ScheduleII-2
shows the status as of March 1975 of the curtailment plans
of 38 interstate pipelines for which data are available.
The 38 pipelines studied are representative of the
interstate pipeline industry since 27 of the 34 companies
classified as "major" pipelines are included.— The 27
major pipelines accounted for 98 percent of the city-gate
sales (i.e., sales to local gas distributors) and 77 percent
of the mainline direct sales by interstate pipelines in 1974.
\J The remaining 7 of the 34 companies do not sell gas
to local gas distributors or make direct industrial
sales. The companies either sell only to other
interstate pipelines or function solely as storage
or transportation companies.
11-38
-------
Schedule II-2, Column (1) identifies the pipelines and
the geographical regions in which their sales are made.
Column (2) indicates by the letter "X" the 27 pipelines
classified as major. Column (3) shows the docket numbers
assigned chronologically to the curtailment plans as they
were filed in response to Commission order. Columns (4)
through (6) designate the type of curtailment plan in
effect on March 1, 1975 -- FPC end use, pro-rata by sales
contract volume or other method. Columns (7) and (8)
show the effective date and where applicable the expiration
date of the filed curtailment plans.
Columns (9) through (13) show the principal reasons
that plans other than the FPC end-use are under investigation,
Column (14) for other than the FPC end-use plan shows
whether interruptible service is the first to be curtailed --
except for small industrial sales, the FPC plan provides for
curtailment of all interruptible service before firm service.
Column (15) provides brief descriptions of the curtailment
plans other than the FPC end-use plan.
Schedule II-2 shows that 16 pipelines are operating or
are about to operate under the FPC end-use plan, 14 use
the pro-rata contract plan, three use other plans, one
applies the FPC plan to 501 of the company's seasonal gas
supply and the pro-rata plan to the remaining 50% and five
11-39
-------
did not file with the Commission curtailment plans to be
implemented in the event of supply shortages.—
Under the pro-rata contract plan end-use by the consumer
is not considered, but interruptible service is usually the
first to be curtailed. After all interruptible service is
curtailed the pro-rata plan provides for equal percentage
curtailment of each pipeline customer's firm daily entitlement,
The curtailment percentage is the ratio of the daily volume
to be curtailed to the sum of the daily entitlements of
all customers. The pro-rata plan has been used historically
by the pipelines to reduce deliveries when outages occurred
because of storms, pipeline breaks and failure of pumping
equipment in the compressor stations. The FPC end-use
plan, by definition, would be unlikely to result in equal
percentage curtailments because of variations in the end-use
of gas by the consumers -- e.g., a local distributor serving
only residential and commercial consumers -- the highest
priority under the FPC plan -- may not be curtailed while
at the same time another distributor with large industrial
sales could be severely curtailed.
As column (9) of Schedule II-2 indicates, the Commission
has under investigation the curtailment plans of 10 pipelines -
9 of them major pipelines for deviations from its approved
\J Algonquin Gas Transmission uses two curtailment plans
as explained in Column (15).
11-40
-------
end-use plan: six of the investigations apply to the pro-
rata plans discussed above.—' However, nine companies with
pro-rata plans are not under investigation; one of these,
Great Lakes Transmission, receives its gas supply from
Canadian sources. Two companies, Florida Gas Transmission
and Michigan-Wisconsin had not reported any curtailments
as of the end of 1974. Two companies, Cities Service Gas
and Natural Gas Pipeline Company of America, according
to Schedule H-lj had substantial firm gas curtailments in
1974 of 12.5% and 17.5%. The 1974 firm gas curtailments of
the remaining four companies, according to Schedule II-1, ranged
from zero percent for Colorado Interstate to 1.8 percent for
Northern Natural Gas, 3.7% for Mid Louisiana Gas and 4.0%
for Louisiana-Nevada Transit as compared with the average
of 15.0% for all companies reporting curtailments. The
endeavor by four pipeline companies to equalize the impact
of curtailments among the customers by rate surcharges and
credits (Column (11)) has met strong Commission opposition
as discussed on Schedule II-4 in the case history of the Trans-
continental Gas Pipeline Corporation. The Commission has
found that these charges for undercurtailments and credits
for overcurtailments as compared with the system average
!_/ Inclusive of the 50-50% FPC and pro-rata plan used by
~ Transcontinental Gas Pipe Line.
11-41
-------
percentage of curtailment is contrary to the rate and
certificate sections of the Natural Gas Act.
In regard to Column (14) the FPC end-use plan requires
that large interruptible sales made by the pipelines and
their distributor customers be discontinued completely
before any firm service is curtailed. Under the pro-rata
plans and other plans, generally only the interruptible
sales made by the pipelines are first discontinued.
Column (15) of Schedule II-2 indicates that in most
cases the pro-rata and other curtailment plans appear to
be tailored to the characteristics of the market served by
the individual pipelines -- see Mississippi River Transmission
for an example.
In summary, Schedule II-2 covers the curtailment procedures
and status of plans of the domestic pipelines delivering
practically all of the gas sold for resale to the local gas
distributors and most of the gas sold directly to
industries by the pipelines. The schedule shows in compact
form the major problems and conflicts confronting the
Commission and the regulated pipelines in their attempts
to reduce historic gas requirements to a balance with the
dwindling gas supplies and at the same time achieve maximum
consumer protection.
11-42
-------
D. Prospects of Gas Curtailment
Electric Generation vs. Other Industrial Use
Under the Commission's end-use curtailment plan gas
requirements for electric generation supplied under inter-
ruptible service contracts will be curtailed to the point
of complete suspension before any substantial amounts of other
industrial service are curtailed. This result follows from
the wide difference in size of the power plant loads and
those for other industrial use, as well as the differing
contract types of the two categories of use. Thus, on a given
pipeline system operating an end-use curtailment plan, electric
utilities are likely to be cut off from gas prior to industrials
The average U.S. power plant generating unit has a name
plate rating of 142 megawatts which requires approximately
20,000 Mcf per day,I/ double the 10,000 Mcf per day that
institutes curtailment in Step 9 of the Commission plan. In
contrast, the average gas industrial customer used about 76
Mcf per day in 1973.£/ An interruptible industrial customer
using the average of 76 Mcf or less per day and over the average
of up to 300 Mcf per day would be in Step 3 of the Commission
plan and would not be curtailed until all service to larger
!_/ Derived from data in Steam-Electric Plant Construction
Cost and Annual Production Expenses, Twenty-fifth
Annual Supplement - 1972.Federal Power Commission,
April 1974.
2/ 1973 Gas Facts, American Gas Association.
11-43
-------
use customers (Steps 4-9) had been suspended. Firm service
industrial customers that do not use gas for boiler fuel
purposes would be in Step 3 regardless of the volume of
daily requirements or in Step 2 of the plan if the industrial
use is for feedstock or process needs. Finally, it is unlikely
that any substantial number of interruptible industrial customers
other than power plants who are supplied by the interstate
pipelines use in excess of the 1500 Mcf per day, the upper
limit of Step 6 of the Commission plan.
Not only the level of gas consumption, but also the typical
purchase contracts, tend to make electric utilities more
susceptible to curtailments than industrial users. In the
interstate market electric utilities buy gas on an interruptible
basis more commonly than industrial users. During 1973, electric
utilities in the interstate market purchased 71 percent of
their gas under interruptible contracts, while industrial
customers purchased 44 percent of their gas under interruptible
contracts. Only in a very few states -- Florida and Nevada
being examples -- does the proportion of firm gas reach a
significant level.
The predominance of interruptible contracts by electric
utilities reflects in many instances the use of gas as a
secondary fuel, with coal or oil being the primary fuel.
Chapter V provides greater detail on alternate fuel burning
capability of gas fired electric utility plants.
11-44
-------
CHAPTER III
CURTAILMENT OF NATURAL GAS SALES BY
GAS DISTRIBUTORS AND INTRASTATE PIPELINES
As noted in the previous chapter, the amounts of
direct sales to industrial and electric utility customers
and sales for resale to distributors by interstate pipelines
are directly affected by the interstate pipelines' curtail-
ment plans. In turn, the sales by the distributors to
their own customers reflect of course the total
amount of gas available to them, determined by the supply
situation and curtailment plan of the pipeline. However,
an added ingredient to understanding gas availability for
industrials and electric utilities served by distributors
is the policy of gas distributors and/or state regulatory
agencies, in light of FPC policies.
A substantial amount of gas, particularly for con-
sumption by industrials and electric utilities, moves from
the wellhead to the burner tip without passing through inter-
state jurisdiction. Under these circumstances, regulatory
policies determined within the state and corporate policies
are the essential factors in determining the disposition
of intrastate gas supply by sector.
This chapter summarizes available information with
respect to curtailment policies on a state level. In the
initial section, a recent survey by the National Association
of Regulatory Utility Commissioners is discussed and summarized,
III-l
-------
The coverage therefrom is deemed sufficient for the con-
elusions drawn herein with respect to the states served
largely by the interstate pipeline network. The second
section deals with the results of research with respect to
the intrastate market where there is substantial industrial
and electric utility gas consumption wholly within intrastate
commerce.
A. The NARUC Survey
In June 1974, the National Association of Regulatory
Utility Commissioners (NARUC) through its Staff Subcommittee
on Gas, sent two questionnaires to the regulatory agencies
of the 50 states, the District of Columbia, and two ter-
ritories to obtain current data principally on gas cur-
tailments restrictions on new or added gas service, con-
servation and increasing the available supply of gas. On
November 15, 1974, NARUC reported the results of its
survey.-
Of the 53 questionnaires sent, 32 responses were
received in time to be included in the report. Seven of
these did not have regulatory authority over the natural
gas industry. The information provided by the remainder, 25
states,-' varied considerably in responses to all of the
questions and in completeness of responses to each question.
I/ National Association of Regulatory Utility Commis-
sioners: Survey of Action by State Regulatory Agencies
a nd. _ I n trastate~Natural Gas Distributors to Meet Natural
Gas STTortages. November 15, 1974.
2/ Includes only Oklahoma of the large gas producing
states.
III-2
-------
Gas Curtailments
Schedule III-l summarizes the current methods of cur-
tailing gas (curtailment plans) in each of the 11 states
that supplied a description of the service priorities
applicable during days of curtailment. The schedule shows
in column (1) the classes of gas service supplied by dis-
tributors and in columns (2) through (12) the order
of curtailment from first to last in each state; e.g., "1"
means first service to be curtailed. Only two states,
North and South Carolina reported plans practically the
same as the Federal Power Commission's nine end use
priorities although all of them except one gave residen-
tial service the highest priority or last to be curtailed.
Five states that did not supply their curtailment plans
in response to the questionnaires stated that they would
implement the FPC end use plan.
In response to the inquiry as to 10 factors of poten-
tial use in establishing priority of service during curtail-
ment, seven state commissions said "end use" and "prac-
ticality of alternate fuel use," six said "public interest",
five said "economics," and three, "FPC guidelines." Gener-
ally, the curtailment plans provide lowest priority to the
larger customers in any service class, as shown on Schedule
L1I-1, based upon their greater economic ability to obtain
alternate fuels.
III-3
-------
Seventeen states replied to the question as to the
priority system used by the gas pipelines supplying their
states during curtailment: six states said FPC end use;
six said "pro-rata" (i.e., by pipeline sales
contract) and five said "mixed" (part pro-rata and part
FPC end use).
Nine of the 19 states that responded to the question
as to uniform curtailment if a local distributor received
gas from more than one interstate pipeline supplier said
the pipeline suppliers were not curtailing such local
distributors uniformly; one state said the curtailment
was uniform and the nine remaining states advised that
gas was received by their local distributors from only
one pipeline supplier.
The non-uniform pipeline curtailments (e.g., assuming
two pipeline suppliers to a typical large distributor,
one curtailing supplies by 20 percent and the other not
curtailing on that day) present some problems at the dis-
tributor level particularly to large gas distributors
serving many communities within a state. Under the ex-
ample above it may be physically impossible because of
lack of transmission facilities for the distributor to
move gas between separate communities so as to equalize
curtailments to industrial and other low priority consumers,
the result being full service to interruptible industrial
IIT-4
-------
customers in some communities and curtailment of all
industrial service in others.
Restrictions on New or Added
Gas Services __
Six states of the 25 responding to the question
about restrictions and priorities on new or added gas
service indicated that no statewide restrictions or
priorities were in effect. Two states restrict additional
residential gas service. Eight states prohibit all new
gas sales but four of the eight have established priority
lists for connections in the future. Nine states restrict
expansion of commercial and industrial sales to existing
customers .
of Gas
The state regulatory agencies responding to the ques-
tionnaires generally have not instituted programs to con-
serve gas but rather have encouraged the gas distributors
to initiate their own programs. Only two states instituted
measures for reducing requirements by a more efficient
use of existing supply. Three states ordered a reduction
in gas usage -- two for ornamental gas lighting and one
ordered a 15 percent reduction in gas usage from the
same period in the preceding year but postponed penalties
for non-compliance.
Conservation measures adopted by the distributors
and the regulatory commissions included the following:
1 1 T - 5
-------
public information by mass media on methods of conservation,
prohibition of promotional advertising, restriction of
swimming pool heating, and encouragement of insulation in
residences. The primary effort according to most responses
was directed toward public information on the need for
and methods of conservation.
The claims of volumes of gas saved by conservation
according to 18 responses, ranged from 2 to 15 percent
of the total volume used -- however, the authors of the
NARUC report recommended caution in interpreting the
volume and percent of gas conserved because of the dif-
fering bases of calculation used. The volume saved
(reported by 5 states) was 108 Bcf.
Reports by the American Gas Association indicate
that conservation of gas by residential and commercial
customers beginning in the Winter 1973-74 has a measurable
effect on gas sales, although it is offset somewhat by
additions of new customers.
Programs for Additional
Gas Supplies
Twenty-five states responded to the question on
regulatory commission action to encourage utility programs
to obtain additional gas supplies. Thirteen of the
responses indicated no such commission action; 12 indicated
encouragement -- two allowed the distributors to pass on
III-6
-------
pipeline supplier exploration costs to consumers, four
allowed the distributors to explore for gas and six en-
couraged utility peak shaving facilities for liquefied
natural gas, storage of gas and synthetic gas.
Nine state commissions made rate allowances for
distributor loans, investments or advances to obtain
additional gas supplies. Sixteen commissions did not
make such allowances.
Other Questions and Responses
Nine of 14 states responding indicated that dis-
tributors in their states had mutual assistance programs
to exchange gas in the event of a critical temporary
shortage. Seven states had mutual assistance programs
in the form of joint LNG, SNG facilities and shared
underground storage projects.
Fifteen of the 25 states responding said they had
taken steps to have gas consumers use alternate fuels
to meet natural gas shortages. Emphasis was directed
particularly to interruptible gas uses. One state asked
the interruptible customers to submit their alternate
fuel requirements so that planning for supplies for the
1974-1975 Winter could be made by the state. Use of
propane was encouraged; electric utilities were encouraged
to use fuel oil, coal and propane.
Summary
Although the data obtained by the NARUC questionnaires
III-7
-------
is incomplete in coverage of the Lower 48 States, the 25
states responding account for over 50 percent of the national
sales and only about 13— percent of the marketed production.
The report, thus, tends to fairly reflect conditions under
the gas shortages in the populous, gas receiving states. In
addition, the report is the most recent authoritative source
of information on state activities in this regard.
The summary of the gas curtailment plans in Schedule III-l
shows that on a state basis most distributors have adopted
the conventional type of curtailment -- first, interruptible
gas, next firm industrial and last, residential and com-
mercial service. The principles underlying curtailment
methods, however, depart from the FPC criteri; of reliance
on end use only -- the practicality of obtaining alternate
fuels is given equal weight with end use although the im-
portance of end use is not downgraded. Also, the economic
impact of gas curtailment, i.e., its effect on employment,
is important at the state level. Three of the states par-
ticularly include hospitals, schools, nursing homes,
and like institutions in their highest priorities.
The final impact of the pipeline supplier curtailments
occurs within the various states where the gas reaches the
burner tips. The need for alternate fuels by industries
I/ Oklahoma, one of the 25 states, provides about
60 percent of the group's marketed pi eduction.
III-8
-------
that have relied on natural gas where supplies were abundant
is also in the local communities. Thus, the state regula-
tory commissions are naturally cautious about adopting any
single plan of curtailment since they are responsible in
their states for the economic impact.- The commissions,
with good reason, would prefer to establish general guide-
lines and allow each local distributor to establish under
the guidelines the curtailment plan best suited to its
supply and markets both of which are best known to the
distributor.
B. Curtailment Plans in Intrastate Markets
Texas
Texas utilities, with nearly 32,000 megawatts of
generating capacity being gas-fired, burned 37 percent of
the electric utility industries total gas supply in 1973.
In light of the magnitude of the gas consumption by electric
utilities in the State of Texas (1,277.8 Bcf in 1973), and
the fact that over 98 percent of this gas is delivered from
intrastate suppliers not subject to FPC regulation, it is
important to obtain a clear understanding of the juris-
dictional structure with respect to gas supply within this
state.
Gas has been the primary boiler fuel in Texas since
the 1920's and 1930's when a switch was made from coal;
I/ 42 of the 48 states assign responsibility for cur-
tailment of gas service to the regulatory commission.
III-9
-------
today electric utilities in the state are approximately 90%
dependent on this fuel. The enormous volume of gas burned
within the state, virtually all of which is free from
Federal control, is subject to the rules and regulations of
the Texas Railroad Commission. This body dominates nearly
every phase of the natural gas industry within the state,
and the extent of their control is clearly defined in the
following excerpt from the Gas Utilities Act:—
Article 6050 to 6066, Inclusive, R.C.S.., 1925 (As
Amended) --
ARTICLE 6050. Classification -- The term "gas
utility" and "public utility" or "utility", as
used in this subdivision, means and includes per-
sons, companies and private corporations, their
lessees, trustees, and receivers, owning, managing
operating, leasing or controlling within this State,
any wells, pipe lines, plant property, equipment,
facility, franchise, license, or permit for either
one or more of the following kinds of business:
1. Producing or obtaining, transporting,
conveying, distributing or delivering natural gasJ
(a) for public use or service for compensation;
(b) for sale to municipalities or persons or com-
panies, in those cases referred to in paragraph 3
hereof, engaged in distributing or selling natural
gas to the public; (c) for sale or delivery of
natural gas to any person or firm or corporation
operating under franchise or a contract with any
municipality of other legal subdivision of this
State; or (d) for sale or delivery of natural gas
to the public for domestic or other use.
2. Owning or operating or managing a pipe line
for the transportation or carriage of natural gas,
I/ Eighty-second Annual Report of the Railroad Commission
of Texas; Gas Utilities Division, 1973.
111-10
-------
whether for public hire or not, if any part of
the right of way for said line has been acquired,
or may hereafter be acquired by the exercise of
the right of eminent domain; or, if said line or
any part thereof is laid upon, over, or under,
any public road or highway of this State, or street
or alley of any municipality, or the right of way
of any railroad or other public utility; including
also any natural gas utility authorized by law to
exercise the right of eminent domain.
3. Producing or purchasing natural gas and
transporting or causing the same to be transported
by pipe lines to or near the limits of any munici-
pality in which said gas is received and distributed
or sold to the public by another public utility or
by said municipality, in all cases where such business
is in fact the only or practically exclusive agency
of supply of natural gas to such utility or munici-
pality, is hereby declared to be virtual monopoly
and a business and calling affected with a public
interest, and the said business and property employed
therein within this State shall be subject to the
provisions of this law and to the jurisdiction and
regulation of the Commission as a gas utility.
Every such gas utility is hereby declared to
be affected with a public interest and subject to
the jurisdiction, control, and regulation of the
Commission as provided herein. (Acts 3rd C.S.,
1920, P. 18.)
A primary function of the Railroad Commission is the
allocation of inadequate gas supplies. This function stems
from its authority to "regulate and apportion the supply of
gas between towns, cities, and corporation.— The Railroad
Commission believes that this authority gives it the right
to apportion the state's entire intrastate gas supply,
although this contention is currently being disputed in a
I/ The discussion of legal authority and regulations in
Texas is largely adopted from two reports by the Gov-
ernors Energy Advisory Council of the State of Texas:
Project No. L/R4, "Legal and Regulatory Policy Aspects
of Energy Allocation," and Project No. L/R1, "Existing
Energy Law and Regulatory Practice in Texas." These
reports were submitted by the Office of the Attorney
General in November of 1974.
III-ll
-------
number of cases including: City of Austin, City of San
Antonio, Lower Colorado River Authority, v. Railroad Commission,
Civil No. 213478 (53rd Dist. Ct,, Jan. 1974). Under the
above mentioned authority, the Commission issued an order
in January 1973 which set up general rules governing the
priorities to be followed by gas utilities in the event
of a gas shortage. The gas utilities were then required to
submit their specific curtailment programs to the Railroad
Commission. The priority system of the Railroad Commission,
which would be utilized until those of the individual utilities
had been approved, is as follows:
A. Residences, hospitals, schools, churches
and other human needs customers.
B. Small industrials and regular commercial
(less than 3,000 Mcf per day) and use for
pilot lights and accessory equipment.
C. Large users of gas for fuel or as a raw
material where no alternative exists.
D. Large users of gas for boiler fuel or
other fuel users where alternate fuels
could be used.
E. Interruptible sales.
The majority of the gas utilities in the state
elected to adopt the priority list established by the
Railroad Commission, although separate curtailment pro-
grams were submitted by Lone Star Gas Co,, Pennzoil
Pipeline Co., Union Texas Petroleum, and Lo Vaca Gathering
Co. in 1973. In the list formulated by the Railroad
111-12
-------
Commission, as well as in most others submitted, the electric
utilities with firm contracts have a low priority status and
are curtailed immediately following interruptible cus-
i / 7/
tomers.- - Gas supplies were curtailed to a number of
Texas electric utilities in 1973 and 1974, including Houston
Lighting and Power, Texas Power and Light, and Dallas Power
and Light. More severe curtailments were suffered by the
customers of Coastal States Gas Corp. and its subsidiary Lo
Vaca Gathering Co. The utilities served by these gas sup-
pliers provide electric service for a substantial portion of
South-Central Texas, including the cities of Austin and San
Antonio. Power plants operated by the Lower Colorado River
Authority, the City Public Service Board of San Antonio, and
the Utility Fund of Austin burned considerable amounts of
oil in 1973 and 1974 due to recurring interruptions in gas
supplies. Gas curtailments were less severe in 1974 than in
1973, partially because of a relatively mild winter, but
these curtailments have become a matter of major concern for
the state's electric utilities as well as the Railroad
Commission.
A second item of concern for the electric utilities in
the state is the Railroad Commission hearing which began in
June, 197S. This hearing is being held to "allow all
I/ The majority of gas burned by electric utilities and
industrials in Texas is purchased under firm contracts.
2/ In a few specific cases, the Railroad Commission has
granted short-term relief from curtailments to power
plants.
111 -13
-------
gas utilities, owners or operators of gas-fired boilers, and
any interested party to appear and present evidence re^
garding the reduction or elimination of natural gas as a
boiler fuel in Texas and the development of a reasonable
schedule for phasing out the usage of natural gas as a
boiler fuel in Texas."-' The Railroad Commission feels
that "the public interest requires, among other things,
a determination of the reasonableness of reducing or elim-
inating natural gas as a boiler fuel."
A major contention of the opponents of such a move is
that the Railroad Commission cannot overrule existing
contracts. However, in the case of a public utility the rule
which may prevail provides that "a corporation organized for
a public purpose may not contract away its ability to
perform its obligations."- A further consideration is that
"parties cannot circumvent or limit -the power of the Com-
mission in administering the conservation laws by private
agreement."- These two rules, coupled with the general
\_l "Amended Order Setting a Statewide Hearing," in
re: "Elimination of Natural Gas Used as a Boiler Fuel
in Texas," Railroad Commission of Texas, Gas Utilities
Division, Docket No. 600, April 11, 1975.
II Lone Star Gas Co. v. Municipal Gas Co., 117 Tex, 331,
3 S.W. 2d 790, 792 (1928); Gulf C. + S.F. Ry. Co. v.
Mp_rri_s_, 67 Tex. 692, 4 S.W. 156, 158 "(1887)".
3/ Railroad Commission v. Mack-Hank Petroleum Co., 186 S.W.
2d 351, 357 (Tex. Civ. App.--Austin 1945), rev'd on
other grounds, 144 Tex. 393, 190 S.W, 2d 802 (1946).
ITI-14
-------
acknowledgement of the Texas courts of the broad powers of
the Railroad Commission, seem to indicate that a total
phaseout is indeed a strong possibility. The power of the
Railroad Commission was acknowledged by the Court of Civil
Appeals in Danciger Oil and Refining Co. v. Railroad Com-
mission:
"We recognize the rule that, in the
regulation and control of private rights and
properties of individuals by administrative
agencies of the state, the interests of the
individual, so far as consonant with the
public welfare, should be jealously guarded
and protected; and no authority not clearly
delegated to such agency by the Legislature,
or necessarily implied from that express
delegation, should be sustained. . . .
Because of the nature of the subject matter
involved here, however, that line of cases
does not furnish an accurate analogy. In
the instant case, the commission, as the
designated agency of the Legislature, was
given the mandatory direction to carry out
the mandate of the Constitution to prevent
waste of the natural resources. That duty
was expressly enjoined upon it. In construing
the validity of its acts in undertaking to do
so, we must consider the nature, character,
and extent of the subject matter placed under
its jurisdiction and the purposes sought by
the Legislature to be accomplished. So con-
sidered, any order of the commission bearing
a reasonable relationship to the general duty
imposed upon the commission, which is not
unreasonable nor unjust, and which is reason-
ably calculated to prevent waste, comes, if
not within the express powers granted to the
commission, clearly within those necessarily
implied; and is "confined to the obvious
purposes and directions of the statute."
111-15
-------
Spokesmen for the Railroad Commission have stated that they
do not wish to immediately abolish boiler fuel gas, as this
would have a detrimental effect on both the pipelines and
the utilities. One estimate is that the conversion process
might be of a ten-year duration, although an industry spokes-
man felt the process would take 30 years if done properly.
Three possible options available to the Railroad Commission
in order to achieve the phaseout are: (1) phase in a tax
incentive to convert to other fuels over a ten-year period;
(2) seek a new federal law permitting low-priced gas bought
under old contracts to be resold at higher prices (as to a
gas utility serving customers in another state) to com-
pensate for the cost of conversion or (3) develop phaseout
schedules on a case-by-case basis.— Decisions on the
elimination of natural gas as a boiler fuel in Texas will be
made in the near future, and they will be the object of
close scrutiny by the state's electric utility industry.
Louisiana
The volume of gas consumption in the electric utility
sector of Louisiana (369 Bcf in 1973) ranks third in the
U.S., with only Texas and California surpassing this level.
Gas is supplied by both intrastate and interstate sources,
with intrastate suppliers accounting for the lion's share
of the market, approximately 72 percent. Electric utilities
in the interstate portion of the market have been hit hard
I/ El^tlicJLl W^£k> May 19, 1975.
111-16
-------
by curtailments, especially those supplied by United Gas
Pipeline, the major interstate source of gas in the state.
In late 1973, the Extraordinary Session of the Louisiana
Legislature enacted Act No. 16 establishing a Division of
Natural Resources and Energy. This new Division was the
result of a study on energy matters within the state sub-
mitted to the Governor by an Energy Advisory Council. A
system of priority use for intrastate gas was established
by the Division of Natural Resources, but this system has
not been put into effect, and to do so would require an
emergency order from the Governor. Such an order is not
anticipated at this time. The priority schedule which
would go into effect in the event of a serious intrastate
gas shortage places large volume boiler fuel use (industrial
and electric utilities) in priorities eight and nine of
a nine-step plan. Large volume boiler fuel users with
alternate fuel capabilities (priority nine) would be
the first group to be curtailed,— followed by large
volume boiler fuel users with no alternate fuel capabilities
(priority eight). The Commissioner of Conservation has
the authority to curtail the gas supply of those plants
which he feels could be modified to accomodate alternate
fuels wit»; "minimal cost and delay." Gas required for
the protection of public health, safety and welfare,
I/ Interruptible gas sales represented less than
7 percent of total Louisiana gas sales in 1973,
and are not set out in the priority schedule
separately.
111-17
-------
including maintenance of gas and electrical service to
homes, schools, hospitals and services would fall in
priority one. An interesting feature of the Louisiana
curtailment structure is that no purchaser of gas shall
be subject to a curtailment in excess of 10 percent of
daily contracted demand. That is, after all users in
class nine are curtailed by 10 percent, cut-offs would
begin in class eight. The result of this type of plan
is that all users are forced to sacrifice to some degree,
rather than completely eliminating the supplies to one
specific group of users. What would follow the curtailment
of 10 percent of class one's gas, should a continuation
of the curtailment be necessary, has not been specified.
No actions similar to the proposed phaseout of
boiler fuel gas in Texas have been initiated in Louisiana,
and the feeling in this state regarding this matter seems
to be "wait and see" at this time.
Oklahoma
Electric utilities in Oklahoma consumed 271 Bcf in
1973, nearly 8 percent of the national total. This gas
was supplied almost entirely by intrastate sources, and
therefore falls under the jurisdiction of the Oklahoma
Corporation Commission rather than the FPC. The Corp-
oration Commission is a regulatory body which is now
provided with policy recommendations on energy matters
111-18
-------
by the State Department of Energy, a new agency created
in 1974 with the enactment of HB1638. The allocation
of fuels is an issue of primary importance to this agency.
No curtailment orders have been issued in Oklahoma,
nor has a priority structure yet been established. The
shortage of natural gas does not appear to pose a serious
threat in Oklahoma at this time, and the utilities in this
state have full confidence in their gas supplies. However,
even though existing gas-fired power plants are expected
to maintain or exceed their current levels of gas con-
sumption, new plants built in this state will be fueled
mainly by coal or nuclear sources. This switch will
become more evident in the later years of the 1970's.
C. The Impact on Electric Utilities and Industrials
of Curtailments by Distributors and Intrastate Pipelines
The supplies of gas available to local distributors
in the states outside of the major Southwest producing
states depend upon deliveries by the interstate pipelines
principally of Southwest gas and to some extent of gas
imported from Canada. The curtailment of deliveries by
most of the gas distributors in the country may therefore
be expected to reflect the priorities in the curtailment
plans of their pipeline suppliers -- curtailment first of
all interruptible deliveries including boiler fuel and
next of any firm service large boiler fuel sales. Residen-
tial and small commercial and industrial sales, hospitals
111-19
-------
and schools will be the last to be curtailed.
Thus, with some differences, the curtailments ordered
by the pipelines will be reflected in curtailments by the
distributors. The pipeline curtailments, those on the
Commission end-use plan and others temporarily in effect,
are aimed at interruptible sales and boiler fuel sales
as a class. But the distributor curtailment directly
affects individual industrial customers.
At the state level, consideration must be given to
the difficulties of the individual customers in obtaining
alternative fuels in much greater quantities than before
the gas shortages. Also the substantially higher prices
to be paid for the substitute fuels may affect the com-
petitive position of an industry in the market place.
Since these difficulties threaten plant shut-downs with
consequent loss of employment in many communities, the
state regulatory commissions may be expected to order
suspension of deliveries to power plants or frequent
curtailments before reducing other industrial deliveries.
Such action would be in accord with the FPC findings
quoted below:-'
"Finally, subordinating boiler fuel use
with its comparative ease of substitutability,
to other large scale industrial and commercial
uses should tend to minimize plant and business
closings and the attendant economic loss from
decreased production and payrolls and the other
personal hardships of unemployment."
I/ Federal Power Commission Opinion No. 643, Docket
No. RP 71-122, Arkansas-Louisiana Gas Co., 1/5/73.
111-20
-------
The deteriorating gas supply situation in Texas
indicates a similar but longer range treatment of power
plant sales in that state. The general statement on
priority of service by the Texas Railroad Commission
in the last two steps (D and E) has the same curtailment
effect as the Commission's end use priorities. Deliveries
of gas obtained from intrastate suppliers in other Southwest
producing states may be expected to follow the curtailment
procedures being introduced in Texas if the supply
situation in these states worsens.
111-21
-------
CHAPTER IV
THE PROJECTED AVAILABILITY OF NATURAL GAS
TO ELECTRIC UTILITY STEAM-ELECTRIC PLANTS
1975 TO 1980
With the increasing shortage of natural gas, the outlook
for gas availability is bleak. It is the purpose of this
chapter to set out specific forecasts of gas availability to
gas-burning electric utility power plants, on a plant-by-
plai t bc-si s .
The flow of gas to electric utilities was analyzed in
Chapter I. As indicated in that chapter, the majority of
gas consumed by electric utilities is purchased from gas
pipelines and distributors. Less than 5 percent of gas
consumed by electric utility power plants is purchased di-
rectly from producers. Thus, the amount of gas available
to electric utilities will depend on the supply of gas to
pipelines and distributors and the curtailment policies of
these pipelines and distributors.
As also indicated in Chapter I, approximately 62 percent
of the gas consumed by electric utilities in the United States
moves in intrastate commerce. This gas is not subject to
FPC jurisdiction and thus its consumption is not affected by
the curtailment plans of interstate pipelines. However, a
substantial volume of gas -r 1,294 Bcf in 1973 -- moves to
electric utilities through interstate pipelines. In the
-------
states of Texas, Louisiana, Oklahoma and New Mexico, the
majority of gas burned by electric utilities moves thereto
wholly in intrastate commerce. Most of the gas consumed in
Florida by electric utilities in Florida is transported by
an interstate pipeline but is purchased from producers in
Texas and Louisiana by the electric utilities. Gas to most
other electric utilities is purchased directly or indirectly
from interstate pipelines.
Chapters II and III indicated that there is consider-
able divergence in the curtailment policies of different
gas companies, reflecting markets, supply and regulatory
constraints. However, electric utilities are generally
among the first to be cut off from gas supplies if demand
exceeds supply. The end-use plans of interstate pipelines
would theoretically eliminate large volume interruptible
electric utility and industrial use before any other cate-
gory is curtailed. Many of the pro-rata plans of interstate
pipelines also result in initial curtailments falling upon
electric utilities. To the extent that state regulatory
agencies have promulgated policies with respect to natural
gas curtailments for gas companies falling within their
jurisdiction, the practical results of these policies will
be to reduce the availability of natural gas to electric
utilities.
Schedule IV-1 shows the projected availability of
IV-2
-------
CHAPTER IV
THE PROJECTED AVAILABILITY OF NATURAL GAS
TO ELECTRIC UTILITY STEAM-ELECTRIC PLANTS
1975 TO 1980
With the increasing shortage of natural gas, the outlook
for gas availability is bleak. It is the purpose of this
chapter to set out specific forecasts of gas availability to
gas-burning electric utility power plants, on a plant-by-
pi ai t has i 5.
The flow of gas to electric utilities was analyzed in
Chapter I. As indicated in that chapter, the majority of
gas consumed by electric utilities is purchased from gas
pipelines and distributors. Less than S percent of gas
consumed by electric utility power plants is purchased di-
rectly from producers. Thus, the amount of gas available
to electric utilities will depend on the supply of gas to
pipelines and distributors and the curtailment policies of
these pipelines and distributors.
As also indicated in Chapter I, approximately 62 percent
of the gas consumed by electric utilities in the United States
moves in intrastate commerce. This gas is not subject to
FPC jurisdiction and thus its consumption is not affected by
the curtailment plans of interstate pipelines. However, a
substantial volume of gas -- 1,294 Bcf in 1973 -- moves to
electric utilities through interstate pipelines. In the
-------
^5-aa, 0*la ° mOves there
e.
o trie i
use be any ^
rata s
ta
• -"lalCU ,tate regular
" ue extent tnat ^ o natural
' . . with respect
: - ^anie5 o£ these Nicies «»
..... -,,1 results electric
';-;-; ,,yo£ natural^"
. c
.e projec
-------
natural gas to electric utility power plants annually from
1973 to 1980, by plant, company, state and region. On Sheet
29, the total for the U.S. is shown to decline dramatically,
from 3.4 quadrillion Btu's in 1973 to 1.7 quadrillion Btu's
in 1980. This amounts to a 49 percent reduction in seven
years. As shown on the following summary table, predomi-
nantly interstate markets are projected to decline more
acutely than intrastate markets.
CURRENT AND PROJECTED GAS CONSUMPTION
FOR ELECTRIC UTILITY STEAM GENERATING PLANTS
(Quadrillion Btu's)
Predominantly Predominantly
Interstate Intrastate , Total
Markets Markets -' U.S.
1973
1974
1975
1976
1977
1978
1979
1980
a/ Texas, Oklahoma, Louisiana and New Mexico.
For the total U.S., electric utility gas consumption
declined somewhat in 1974 compared with 1973. However,
predominantly intrastate markets showed a slight increase,
while predominantly interstate markets experienced a de-
crease in electric utility gas consumption. The increase
in intrastate markets reflects not only the greater relative
IV-3
1
1
0
0
0
0
0
0
.43
.20
. 79
.31
.24
.22
.18
.15
2.
2.
1.
1.
1.
1.
1.
1.
01
10
93
81
76
70
65
59
3.44
3.30
2.72
2.12
2.00
1.92
1.83
1.74
-------
deliverability of gas, but also the warmer weather prevail-
ing in 1974 which ameliorated curtailments. Although elec-
tric utility gas consumption in the interstate market de-
clined in 1974, it is herein estimated that the decline
would have been more severe were it not for warm weather
and the impact of conservation and the recession.
Factors such as weather, conservation and the recession
affect the demand for gas in the residential-commercial and
industrial sectors, and thus the supply of gas for electric
utilities. Since by regulatory fiat or operating practice
electric utilities are given "low priority" status under
most curtailment plans, a decrease in demand by higher pri-
ority sectors results in increased availability for electric
utilities.
Electric utility gas consumption in predominantly
interstate markets is projected to decline by one-third to
0.8 quadrillion Btu's in 1975. This projection would be
substantially lower were it not for key assumptions with
respect to continuation of the recession and conservation
in 1975. After 1975, a resumption of economic growth is
assumed, and the overall gas supply situation is projected
to continue to deteriorate, resulting in virtual elimination
of interstate sales for power plant consumption. Another
key assumption is that all but one interstate pipeline
will be curtailing on some end-use basis after 1975. This
IV-4
-------
would result in electric utilities initially bearing the
brunt of the shortage. During this period, as the "cushion"
of electric utility gas consumption diminishes, industrial
curtailments will grow increasingly severe.
By 1980, it is projected that within predominantly
interstate markets electric utilities in only two states
will have appreciable gas consumption. It is projected
that some electric utilities in Kansas, with indigenous gas
some of which moves intr-istate, could still be burning gas.
In Florida, a substantial amount of gas transported to
electric utilities is not subject to pipeline supply curtailment
With respect to the amount of gas subject to pipeline supply
curtailment in Florida, the small proportion of high priority
markets in this state and the type of curtailment plan also
facilitates continued sales to power plants by the interstate
pipeline. Neveitheless, electric utility gas consumption in
both states is forecast to decline substantially.
California, New York and Arkansas, three states in
which electric utilities have traditionally burned large
amounts of gas, are shown to have little gas available for
electric utility gas consumption after 1975. Thus, for
predominantly interstate markets, it may be concluded that
gas will not be a major boiler fuel in the future. Even if
substantially more gas were available for all sectors than
the volume,, assumed herein, the electric utility sector
would not be the recipients. The industrial sector, generally
IV-5
-------
of higher priority than the electric utility sector, would
be available to absorb any additional volumes.
As shown in the summary table, gas consumption by
electric utilities in predominantly intrastate markets would
not decline as rapidly as in interstate markets. However,
this forecast assumes business as usual., especially in Texas.
It should be noted that the Texas Railroad Commission is
considering the phaseout of gas as a boiler fuel in Texas,
which might also lead to similar actions in other gas pro-
ducing states. Thus the projections to 1980 could be viewed
as an upper limit. If this projection were to prevail in
Texas, industrial gas consumption might well be reduced.
It should be noted that both the interstate and intra-
state forecasts assume an end of the recession by 1976 and a
resumption of real economic growth thereafter. Moreover,
the forecasts do not reflect any significant reduction in
industrial demand for gas due to energy conservation.
Dampening of industrial demand for gas could increase the
availability of gas for other sectors, including the electric
utility sector. As a practical matter, however, the above
assumptions with respect to economic conditions and conser-
vation have a more significant effect on the earlier years
of the forecast - 1975 and 1976 - than the later years to 1980
The following two sections explain and discuss in more
detail the forecasts. In Section A predominantly inter-
state markets are discussed, and in Section B predominantly
IV-6
-------
intrastate markets (Texas, Louisiana, Oklahoma and New
Mexico) are discussed.
A. Projections for Predominantly
Interstate Markets
The supply of natural gas available in the future to
a power plant attached to the interstate pipeline network is
determined largely by the supply situation on the specific
interstate pipeline from which it draws its supplies. Al-
though the overall interstate pipeline supply situation is
bleak, there are sufficient differences among the individual
pipelines and distributors which have significant effects on
the amount of gas for specific power plants.
On a given interstate pipeline, future supply availa-
bility for power plants is dependent upon several factors.
Deliverability on the pipeline system for all classes of
users in forthcoming years is, of course, the foremost con-
sideration. For any particular class of users, the share
which they may expect to obtain of the future overall supply
is determined largely by the curtailment plan in effect on
the pipeline specifying the manner in which supply inadequa-
cies will be handled. The dissimilarities of curtailment
plans in use by different interstate pipelines have already
been discussed. For power plants, the critical question is
the extei t to which they are treated as the first class of
users to be curtailed, and the degree to which others also
suffer early curtailments, on each individual pipeline sys-
tem .
IV - 7
-------
An additional factor of great importance is the aggre-
gate composition of different user classes on particular
pipelines. Some systems have predominantly residential and
commercial loads, others have greater industrial and power
plant demands in relationship to their residential and com-
mercial volumes. Even with given industrial and power plant
shares of the total pipeline demand, different pipelines
differ with respect to the proportion of firm and iriterrup-
tible deliveries. These relationships among several user
classes, termed the pipeline end-use profile, significantly
affect the way in which curtailment plans will impact upon
future gas supplies available to power plants.
In order to illustrate these effects, assume that two
pipelines each projected a 10 percent decline in system
deliverability, each had a curtailment plan in which all
interruptible industrial and power plant customers were
curtailed first, with firm industrial and power plant custo-
mers curtailed only after all interruptible loads had been
eliminated and with residential and commercial users cur-
tailed only after all industrial and power plant volumes
has been cut off. If one of the two pipelines had 50 per-
cent residential and commercial customers, 40 percent firm
industrial and power plant users and 10 percent interruptible
loads, then the 10 percent supply decline on the system as
a whole would totally eliminate all the interruptible volumes
If the other pipeline had only 20 percent residential and
IV-8
-------
commercial, 40 percent firm and 40 percent interruptible
consumption, then the 10 percent decline in systemwide
deliverability would result in only a 25 percent curtailment
of interruptible customer volumes. Given the practical fact
that residential and commercial users will not be curtailed
while any interruptible users are obtaining even a small
volume of gas, the immediate conclusion is that the larger
the residential and commercial proportion of the pipeline
end-use profile, the more vulnerable the interruptible custo-
mers are to drastic curtailments.
The same naturally holds for firm industrial and power
plant users with respect to the magnitude of residential
and commercial end-use on their pipeline supplier's system.
Firm users, however, are also affected by the proportion of
interruptible usage. Taking the same two hypothetical pipe-
lines as before, a further 10 percent decline in supplies
available to the first supplier would all be taken out of
firm volumes, and would amount to 25 percent of the firm
usage, since the first 10 percent supply loss had already
eliminated the interruptible categories on that pipeline.
On the second pipeline, however, the next 10 percent supply
loss would not affect firm users at all, because there was
still interruptible gas being delivered and available for
curtailment. Thus, the "low priority" usage acts as a cush-
ion for the higher priority usage.
IV-9
-------
The relationship between a power plant and its source
of interstate natural gas also affects the supply expecta-
tions. A power plant obtaining its gas by direct sale from
a pipeline may have a different supply picture than one
obtaining gas indirectly from the same pipeline by resale
from a local distribution company which has purchased gas
from the pipeline. In the former case, the theoretical
impact of the curtailment plan would be no different from
the actual impact. In the latter case, if the curtailment
instituted by the distributor differed from that of the pipe-
line, the theoretical results of the pipeline plan might not
be carried out.
The general framework for projecting the availability
of gas to power plants in predominantly interstate markets
involved three steps for each pipeline serving, directly or
indirectly, electric utilities. As the initial step, overall
pipeline supply was projected. The second step was obtaining
or estimating the end-use profile -- sales by sector -- for
the relevant pipelines. The third step was to allocate the
supply to specific power plants by reference to the curtail-
ment plans of the relevant pipelines and/or distributors.
As the basis for supply projections, the Form 15 reports
filed by the interstate pipelines in early 1974 were utilized.
These projections were in some cases modified by reference
to the latest FPC data on near-term curtailments and more
recent projections published in annual reports to stockholders
and prospectuses. The Form 15 forecasts take into account
IV-10
-------
projected deliveries from presently dedicated reserves but
do not take into account deliveries from reserves which may
be obtained in the future. For the near-term, the addition
of new supplies would not alter significantly the total
sales of a pipeline, but in the longer term the assumption
of no additional supplies becomes more precarious. As will
be discussed, however, a reasonable estimate of additional
future supplies would not significantly alter the availabil-
ity of gas to electric utilities through 1980.
End-use profiles were obtained for many pipelines from
filings in curtailment cases at the FPC. For those pipe-
lines for which no end-use information was available from
curtailment cases, end-use profiles were estimated from
available data.
By reference to the supply projection and the end-use
profile, the impact of the curtailment plan in effect as of
the beginning of 1975 (see Chapter II) was estimated. While
many pipelines are operating under curtailment plans which
follow the nine priority end-use structure, there are a
number of pipelines whose current plans differ to varying
degree from that structure. It was assumed in preparing
the forecasts that the plan in effect at the beginning of
1975 would be operative through the end of the year. It was
assumed that after 1975 most curtailment plans would be end-
use oriented. Thus, strictly pro-rata plans were assumed to
be abandoned in favor of end-use plans. The forecasts in
IV-11
-------
some cases could be higher after 1975 if these changes in
curtailment plans were not assumed.
The forecasts also incorporate certain assumptions with
respect to the impact of conservation practices largely in
residential and commercial sectors and the recession on
industrial demand. Unadjusted for these considerations,
the 1974 estimated consumption would show 10.4 percent less
power plant consumption in predominantly interstate markets
than actually occurred in that year. Hence, for the year
1975, a 6 percent downward adjustment in industrial require-
ments was made to reflect the recession, and a 4 percent
downward adjustment in residential usage was made to reflect
conservation. Economic growth was assumed to resume thereafter,
although the effect of conservation was assumed generally to
remain.
At this point it should be noted that the forecasting
methodology reflects static assumptions with respect to the
supply and requirements of interstate pipelines. The Form
15 supply projections, as modified for more recent data, do
not take into consideration production from new reserves
which may be acquired. With respect to demand, the base
period data utilized in implementing curtailment plans does
not take into consideration increases in demand in the high
priority sectors.
Schedule IV-2 shows the historical trend in reserves
additions, production (net withdrawals from reserves) and
IV-12
-------
total reserves for interstate pipelines. As shown on the
schedule, interstate production has declined from a peak
of 14.2 Tcf in 1971 and 1972 to 13.7 Tcf in 1973 and 12.9
Tcf in 1974. End-of-year reserves have declined 39 percent
since 1967, reflecting insufficient reserves additions to
replace production. In the last three years net additions
to reserves have been zero.
The extent to which the Form 15 supply projections may
be tenuous depends on the future level of reserves additions
by interstate pipelines. If interstate pipelines continue
to be unable to acquire new reserves, then the Form 15 supply
projections will be the fact.
Including the more prolific years of reserves additions,
reserves additions by interstate pipelines have averaged
6.4 Tcf per year since 1963. An illustrative supply projec-
tion to 1980 is shown below, assuming interstate reserves
additions of 3 Tcf in 1975 and 6.4 Tcf each year thereafter.
1974
1975
1977
1980
ILLUSTRATIVE INTERSTATE SUPPLY PROJECTION
(Billions of Cubic Feet)
Production from
Reserves as of
December 31, JL9_7_4
12,888
12,148
10,409
7,794
Production from
Assumed New
Reserves
910
2,386
Total
Production
12,888
12,148
11,319
10,180
IV-13
-------
What the above analysis suggests is that interstate
supply will decline to 1980, but the amount of decline is
dependent upon the assumed level of reserves additions.
These illustrative supply projections may be compared
to overall interstate patterns to estimate their impact on
various categories of end-use. Gas available to electric
utilities has already been forecasted at 662 Bcf in 1975,
113 Bcf in 1977, and 74 Bcf in 1980.^ If residential and
commercial uses are allowed to grow at 2 percent annually
7 /
from their 1973 level of 6,089 Bcf,- then it would reach
6,996 Bcf by 1980. The effect of these estimates is shown
below, with industrial consumption treated as a residual,
taking whatever is not assigned to the residential, commercial,
electric utility and other categories.
ILLUSTRATIVE INTERSTATE SUPPLIES BY END-USE
(Billions of Cubic Feet)
1975 1977 1980
Residential £ Commercial 6,335 6,591 6,996
Industrial 4,365 3,882 2,450
Electric Utility 662 113 74
Other 787 755 660
TOTAL 12,149 11,519 10,180
I/ Excluding Texas, Louisiana, Oklahoma, New Mexico and
Florida because of the predominance of intrastate sup-
plies and/or transportation of supplies.
2/ FRC data for 1973. Texas, Louisiana, Oklahoma and New
Mexico excluded.
IV-14
-------
The impact upon industrial consumption, even assuming
the drastic curtailments in electric utility supplies dis-
cussed in other sections of the study, is to reduce it to 47
percent of its 1973 level by 1980, a shortfall of 2,710 Bcf
from the 5,160 Bcf received by industrial customers in
1973.- Thus, in order to alleviate the industrial curtail-
ments, additional supplies will have to amount to 2,897 Bcf
in 1980, allowing for the resultant increase in other use,
in order to provide 2,710 Bcf of additional natural gas for
industries. Since the supply projection used herein already
includes additional new production of 2,386 Bcf in 1980,
the increase would have to be more than twice that great in
order to offset expected industrial curtailments. Even
then, with new production in 1980 amounting to 5,283 Bcf in
1980, or 68 percent of production that year from currently
existing reserves of interstate pipelines, no increase is
likely in electric utility supplies from the level forecast
to 1980 in the study. Thus the benefit of any additional
gas supplies will not accrue to electric utilities.
Assuming that electric utilities bear the brunt of
curtailments to the extent that their 1980 supply is ex-
pected to be only 5.8 percent of its level in 1973, there is
still a drastic impact on industrial supplies. Even with
the optimistic assumption that new interstate reserves addi-
tions amounted to 6.4 Tcf per year from 1976 onwards,
\_l FRC data for 1973. Texas, Louisiana, Oklahoma and
New Mexico excluded.
IV-15
-------
resulting in production from new reserves amounting to 2,386
Bcf in 1980, as compared to production from current reserves
of 7,794 Bcf in that year, the supplies for industrial users
would be barely 47 percent of their 1973 level. If produc-
tion from new reserves is less than projected, industrial
curtailments will rise further. Even if new reserves were
in excess of those illustrated, industrial users could
easily absorb the resulting production.
The consumption of natural gas by industries varies
considerably from region to region in absolute amount, in
proportion of national industrial usage, in comparison with
consumption for other uses in the same region, in distribu-
tion between firm and interruptible sales, in share of the
industrial market served by interstate supplies, and in
rapidity with which industrial curtailments are expected to
become significant.
Along the Atlantic Coast, comprising the regions of
New England, Appalachia and Southeast, industrial supplies
will probably be substantially reduced well before 1980
unless substantial new reserves are obtained by pipelines
serving the regions. The situation of Tenneco and Trans-
continental Gas Pipe Line Corp. are typical in these regions,
and their extremely severe supply losses in the near future
will all fall on industrial users, since the magnitude of
electric utility gas consumption, excluding that transported
to Florida, plants, is relatively small. Industrial users
IV-16
-------
in the Southeast obtaining supplies from Southern Natural
Gas Co., however, have a future supply outlook somewhat
better than the rest of the Atlantic Coast.
The Great Lakes region faces largely the same situation
as that prevailing along the Atlantic Coast. Based upon
production projections from presently dedicated natural gas
reserves, the interstate pipelines which serve significant
shares of the market, except for Michigan Wisconsin Pipe Line
Co., anticipate substantially reduced industrial loads well
before 1980. Even on Michigan Wisconsin, industrial service
will probably be substantially cut.
Despite having had a cushion of electric utility gas,
amounting to nearly 20 percent of the regional consumption
in 1973, the Northern Plains region is expected to experi-
ence very rapidly declining industrial supplies. Its domi-
nant pipeline suppliers, Northern Natural (which delivered
over half of the region's gas in 1973) and Natural Gas
Pipeline Company of America, both project rapidly falling
deliverability from current reserves. Only the dedication
of substantial new reserves to pipelines serving the region
would, to some degree, reduce prospective industrial curtail-
ments .
Far less pessimistic is the future of industrial sup-
plies to the interstate portions of the Mid-Continent region.
One factor which partially cushions the impact of curtail-
ments on industrial users is the existence of 37 percent
IV-17
-------
regional consumption by electric utilities in 1973. Another
factor is the relatively less severe supply forecast for
Cities Service Gas Co., which may satisfy a significant por-
tion of its industrial needs, even in 1980, from currently
dedicated reserves.
Industrial consumption in the Gulf Coast is mostly sup-
plied from intrastate sources, and is discussed separately.
The Rocky Mountain region, served largely by Colorado
Interstate Gas Co., faces less severe losses of industrial
supplies, based upon existing reserves. Curtailment of
industrial demand is expected to increase steadily, although
it is possible that firm industrial customers may not be
curtailed to any significant degree until nearly 1980.
The situation in the Pacific Southwest, dominated by
California, and by El Paso Natural Gas Co., indicates signi-
ficant possible industrial curtailments in 1975. By the
late 1970's, based upon production estimates from currently
dedicated reserves, much industrial consumption may be
eliminated except for those customers obtaining some portion
of Pacific Gas § Electric's imported Canadian supply.
Because the Pacific Northwest region has substantial
»
supplies of gas imported from Canada, which are not projected
to decline during the period studied, its industrial supply
outlook is better than for California. However, with elec-
tric utility consumption almost nil, and with residential
and commercial usage smaller than in most parts of the Nation,
IV-18
-------
any supply losses on that part of the region's natural gas
originating in the Southwest part of the United States will
be reflected proportionately in industrial curtailments.
In short, the industrial outlook is worst along the
Atlantic Coast and Great Lakes, slightly better, if at all,
in California and the Pacific Southwest, and better in
varying degrees in other parts of the U.S.
The following section describes step by step the fore-
cast of gas availability for power plants in California.
Electric utilities in California consume more gas than elec-
tric utilities in any other state in the predominantly inter-
state market and the forecast for California is considered
representative of the interstate market.
Forecast of Gas Supplies Available
to California Steam-Electric Power
The forecast of annual supplies of natural gas available
«
to the 35 California steam-electric power plants considered
in this study is based upon the increasing domestic shortage,
interstate and intrastate, of natural gas supplies available
to the state since 1970, The shortages require curtailments
of gas deliveries instituted under curtailment plans pre-
scribed by the Federal Power Commission (Commission) for
two— of the three interstate pipelines delivering gas at
I/ El Paso Natural Gas Company and Transwestern Pipeline
Company. The third pipeline, Pacific Gas Transmission
Corporation, transports Canadian gas to California for
the account of Pacific Gas and Electric Company. Suf-
ficient quantities of gas are expected to be available
to PGT to avoid curtailments of deliveries.
I V - 1 9
-------
the state border, and by the California Public Utilities
Commission (PUC) for gas utilities under its regulatory
jurisdiction.
The purpose of the Federal and state curtailment plans
is to protect gas service to residential, small commercial
and industrial, and other consumers where alternative fuels,
oil and coal, are infeasible to obtain or to use. Under
both the Commission and PUC orders, the steam power plants
are the first to have gas deliveries curtailed; i.e., have
the lowest priority of service on days when gas is in
short supply and therefore must use alternative fuels for
electric generation.
Twenty-two of the 35 California power plants are sup-
plied with gas directly or indirectly by Southern California
Gas Company (SCG).— Twelve (its own plants) are supplied
with gas by Pacific Gas and Electric Company (PG§E). The
remaining plant— is supplied by a California gas producer,
Atlantic Richfield Company.
The calendar year 1973 is the base year used for the
forecast of gas supplies for the California power plants.
The forecast method employs for SCG and PG§E: (1) the cur-
tailment plans of El Paso and Transwestern; (2) El Paso's
estimate of the distribution of natural gas requirements in
\_l San Diego Gas and blectric Company buys it entire gas
supply from SCG including that burned in power plants.
2_/ Mandalay Plant of Southern California Edison Company.
IV-20
-------
its market area by the priority steps of its curtailment
plan (referred to as the "end-use profile"); (3) the propor-
tions of total gas supplies received from the interstate
pipelines and from California production; (4) the projections
of future supplies, 1974-1980 from interstate pipeline
sources and local production; (5) the estimated additional
gas supplies available for use in power plants because of
the 1974-1975 recession and the conservation of gas; (6) a
summation of the foregoing in the form of the percentages of
1973 power plant deliveries available for the 1974-1980
requirements; (7j a test of (6) against reported actual
power plant gas supplies in 1974; and (8) application of the
percentages in (6) to each of the 34 California power plants
served by SCG and PG§E to forecast gas supplies for the
years 1975 through 1980.-^
Transwestern curtails gas deliveries under the Commis-
sion's prescribed plan with nine priority of service steps.
El Paso curtails under a five-step priority of service plan
prescribed after hearings by the Commission. Despite the
differences in number of priority steps, the plans are es-
sentially the same and both provide that deliveries to power
plants will be the first curtailed during periods of gas
shortages on the pipelines. The PUC plan for SCG and PG§E
\J The volumes of actual deliveries for 1973 and 1974 are
~~ available from the EPA tabulation and monthly reports
to the Commission on FPC Form 423.
IV- 21
-------
also provides that steam electric plants will be curtailed
first.
El Paso has supplied data on the end-use of system gas
deliveries by the five priority-of- service steps of its
curtailment plan. The steps of the plan and the percentage
of system gas deliveries applicable to each step are shown
in the table below.
EL PASO NATURAL GAS COMPANY
CURTAILMENT PLAN AND END-USE
GAS REQUIREMENTS OF SYSTEM CUSTOMERS
Priority of Service End-Use Profile
(percent)
Residential, small commercial needs
(less than 50 Mcf on a peak day) 38.4
2. Large commercial, industrial feed-
stock, process and plant protection
needs. Storage needs. 16.6
3. All industrial needs not covered in
(2) , (4) and (5). 20.5
4. Boiler fuel use, 1500-3000 Mcf per
day. !_/ 0.9
5. Boiler fuel use over 3000 Mcf per
day. !_/ 23.6
100. 0
\_l Where alternative fuel capabilities (exclusive
of propane and other gaseous fuels) can meet
the requirements.
Source: El Paso Natural Gas Co. tariff and filings with
the Federal Power Commission.
IV-22
-------
As the table shcnvs, large boiler fuel use such as for
steam electric plants comprises about 23.6 percent of the
total gas requirements supplied by El Paso -- some 75 per-
cent of which are in California. El Paso supplied about 50
percent of California's total 1973 gas receipts through
sales to SCG for resale in Southern California and to PG§E
for resale in Northern California. The large proportion of
El Paso's deliveries of the total California gas supply and
the wide geographical distribution to final consumers of
this gas support applications of the El Paso end-use profile
percentages in the table to allocate 1973 base year California
supplies among the five priority of service steps as a start-
ing point in the forecast of future gas supplies for the
California power plants.
The tables below show the 1973 gas supplies of SCG and
PG6JE by supply sources and the allocation of total gas sup-
plies of each company by the El Paso priority of service
steps (end-use profile).
SOUTHERN CALIFORNIA GAS COMPANY AND
PACIFIC GAS AND ELECTRIC COMPANY
1973 GAS SUPPLIES AND SOURCES OF SUPPLY
SCG PG§E
Bcf Percent Bcf Percent
1973 Gas Supply 96_6 100.0 1020 100.0
Suppliers
El Paso" 610 63.1 378 37.1
Tran.^western 274 28.4 -- , -- .
Pacific Gas Trans. -- . -- , S63-7, 3,5.6-/,
California Producers 82-7 8.5-7 279-' 27.3-7
a/ Estimated.
Source: 1973 Annual Reports, Form 2, to the Federal Power
Commission; 1973 California Gas Report to the
California Public Utilities Commission.
IV-23
-------
SOUTHERN CALIFORNIA GAS COMPANY AND
PACIFIC GAS AND ELECTRIC COMPANY
ALLOCATION OF 1973 GAS SUPPLIES BY PRIORITY OF
SERVICE STEPS OF THE EL PASO NATURAL GAS COMPANY
CURTAILMENT PLAN
SCG
(Bcf) (Bcf)
1973 Gas Supply 966-/ 1020-/
Priority of Service
Steps
1
2
3
4
5
371
161
198
9
227
392
170
209
9
240
a./ Estimated.
The next step in the forecast is to project the gas sup-
plies available to SCG and PG$E for the years 1974 through
1980 from each supply source shown previously. All sources
except Pacific Gas Transmission are estimated to experience
declining supplies. PGT supply is expected to remain the
same as 1973 since the basis is Canadian gas reserves. The
El Paso and Transwestern projections are taken from their
Annual Reports of Gas Supply, Form 15, to the Commission.
The California gas production estimates ard supplies from
PGT are taken from the 1973 California Gas Report.
The table on the following page summarizes the projected
future gas supplies of SCG and PG$E from a]1 sources determined
IV-24
-------
as described above for the calendar years 1974 through 1980
Columns (3) and (5) show the anticipated reductions from
1973 in total gas supplies.
SOUTHERN CALIFORNIA GAS COMPANY AND PACIFIC GAS AND ELECTRIC
COMPANY PROJECTED TOTAL GAS SUPPLIES 1974-1980
AND SUPPLY REDUCTIONS FROM 1973 SUPPLIES
(Billions of Cubic Feet)
SCG
PG&E
Year
(1)
1973
1974
1975
1976
1977
1978
1979
1980
Total Gas
Supplies
(2)
966
892
779
695
643
594
546
503
Reduc t ion
from 1973
(3)
—
74
187
271
323
372
420
463
Total Gas
Supplies
(4)
1020
869
800
746
723
687
656
625
Reduction
from 1973
(5)
—
151
220
274
297
333
364
395
The projected reductions from 1973 in total gas supplies
represent anticipated further curtailments of gas services
over those required in 1973. These would be applied ordinar-
ily to reduce the 1973 power plant deliveries in Step 5 under
Federal and state curtailment plans as shown in the table on
the following page.
1V - 2 5
-------
SOUTHERN CALIFORNIA GAS COMPANY AND
PACIFIC GAS AND ELECTRIC COMPANY
ESTIMATED TOTAL GAS SUPPLIES FOR POWER PLANTS
(Billions of Cubic Feet)
SCG PGSE
1973 Gas Supply 227 240
1974 Reduction (74) (151)
1974 Supply-Volume 153 89
Percent of 1973 67.41 37.083
However, it is estimated that for the years 1974 and
1975 and some part cf 1973, additional volumes of gas should
be available to the power plants as a result of conservation
of gas use by the residential customers and the effect of
the nationwide recession on industrial gas requirements.
The effect of these reductions in demand by the^e other sec-
tors translates to somewhat over 14 percent when applied to
1974 power plant gas supplies and would increase the percent-
age of 1973 supplies shown in the above table from 67.4 to
82.04 for SCG and from 37.08 to 51.73 for PG$E. The same
percentage increases are assumed for 1975 but not for the
years 1976 through 1980.-/
The following table sums up the curtailment effect of
the estimated reduced gas supplies, 1974-1980, heretofore
described on all market sectors supplied by SCG and PG§E
with particular emphasis on future power plant gas supplies.
I/ The effect of conservation would be offset by growth
~ in 1976 under current California policy.
IV-26
-------
Section A of the table shows the anticipated gas cur-
tailments on the SCG system in accordance with the El Paso
and California curtailment plans— adjusted in 1974 and 1975
for additional gas supplies transferred to power plants from
residential and industrial requirements as a result of con-
servation practices and the recession. The anticipated re-
ductions in system gas supplies for 1973 occurring in the
years 1974 through 1980 are deducted first from Step 5 --
power plant deliveries -- until these are fully suspended
(beginning 1976) and thereafter deducted from Steps 4, 3,
and 2 (in 1980) as needed.
Section B of this table shows the similar results of
future curtailments on the PG§E systems calculated as des-
cribed for Section A of the table.
Section C isolates the estimated power plant supplies
only and adds the percentages of 1973 gas deliveries expected
to be available to the power plants; 82.04 percent of 1973
in 1974 and 32.26 percent in 1975 for SCG, and 51.73 percent
and 22.98 percent, respectively, for PG§E. The forecast
percentages of 1973 power plant supplies show the steep de-
clines expected, particularly by 1975, and the zero level
of deliveries in 1976 and thereafter.
!_/ As previously noted, the Transwestern curtailment plan
is in practical effect the same as that of El Paso.
IV-27
-------
ESTIMATED GAS SUPPLIES AVAILABLE TO
SOUTHERN CALIFORNIA GAS AND PACIFIC GAS & ELECTRIC COMPANY
1973 - 1980
Priority of
Service Steps
TOTAL
(Billions of Cubic Feet)
1973 1974 1975 1976 1977
1978 1979 1980
A.
SCG
1
2
3
4
5
371
161
198
9
. 227
371
161
198
9
186
371
161
198
9
73
371
161
163
—
—
371
161
111
—
—
371
161
62
—
—
371
161
14
—
—
371
132
—
—
—
966
925
812
695
643
594
546
503
PG&E
1
2
3
4
5
392
170
209
9
240
TOTAL 1020
392
170
209
9
124
904
392
170
209
9
55
835
392
170
184
—
—
746
392
170
161
—
—
723
392
170
125
—
—
687
392
170
94
—
—
656
392
170
63
—
—
625
C. Power Plant Supplies
/ SCG
5 Bcf^' 227 186 73
% of 1973 100.0 82.04 32.26 —
/ PG&E
5 Bcf- 240 124 55
% of 1973 100.0 51.73 22.98 —
I/ From Step 5 of Sections A and B of this table.
Since the forecast percentages shown in Section C of
the table will be applied to actual 1973 gas deliveries of
each of the 34 power plants supplied by SCG and PG§E to
IV-28
-------
forecast future supplies, the 1974 derived percentages were
compared as shown below with actual 1974 percentages for
SCG and PG§E to the extent that data are available.
GAS SUPPLIES TO POWER PLANTS
1974 AS A PERCENT OF 1973
SCG PG§E
Section C 82.04 51.73
Actual 1974 79.60
12 months ending
6/30/74 -- 66.30
12 months ending
9/30/74 -- 53.90
Source: Table 6, 1973 California Gas Report; Pacific Light-
ing Corporation Annual Report Supplement 1974 for
SCG; PG$E Prospectuses, October 9 and December 17,
1974.
In addition, in the 1973 California Gas Report, SCG
forecasts 94 percent curtailment of total steam-electric
plant requirements in 1975, 98 percent in 1976 and 97
percent in 1980. PG§E forecasts in the Report that no
deliveries of gas will be made to its own power plants (98
percent of total power plant gas requirements) during
the years 1975 through 1982.
The foregoing tests of the estimated percentages
of 1973 power plant gas supplies indicate that the per-
centages are sufficiently accurate within the limits of
present information and anticipated future trends of gas
IV-29
-------
supplies available to SCG and PG§E to forecast the gas supplies for
the 34 California power plants.
A sample of the forecast of gas supplies to one of the
22 power plants supplied by SCG is shown below. The same
format and method were used for the remainder of the plants
supplied by SCG and PG§E.
CITY OF BURBANK PUBLIC SERVICES - BURBANK PLANT
Gas Supplier: Southern California Gas Company
Source of Supply: Calif. El Paso Transwestern
Prod. N.G. Co. Pipeline Co. Total
1973 Actual 5.9% 65.0% 29.1% 100.0%
Millions Billions
of C. F. of Btu —
5.
/ 106
i- 87
71 gq
*-' 34
:ed) 0
9% 65.0%
Millions of Cubic
1169
959
1089
377
0
29.1%
Feet
523
429
487
169
0
1798
1475
1675
580
0
1875
1538
1747
605
0
1973 (Actual)
1974 (Estimated)-
1974 (Actual)
1975 (Estimated)-
1976-80 (Estimated)
\l 1973 supply x 82.04%.
2J 1973 supply x 32.26%.
_3/ At average 1043 Btu per cubic foot.
The percentages used in the forecast for the Burbank Plant
are those for the total gas supplies for all of the power plants
supplied by the SCG. Total percentages are used also for the
irdividual plants supplied by PG§E. Since these are system
average forecast percentages, deviations will occur among the
individual plants as shown above for Burbank in 1974. However,
as total gas supply for the power plants declines sharply the
deviations in 1975 and subsequent years should be minimal.
IV-30
-------
This view is supported by the predictions of SCG and
PG$E in the 1973 California Gas Report as stated above.
The Mandalay plant of Southern California Edison Com-
pany obtains over 99 percent of its gas supplies from
California production by purchases from Atlantic Richfield
Company, a gas producer. The forecast of future gas supplies
from California production available to this plant is that
made by Southern California Edison in the 1973 California
Gas Report. The estimated supplies vary from 66.7 percent
of 1973 in 1975, to 18.6 percent in 1980.
B. Projections for Predominantly
Intrastate Markets
In the composite, gas consumption by electric utilities
in the states of Texas, Louisiana, Oklahoma and New Mexico
is projected to decline by 21 percent between 1973 and 1980.
This projected decline reflects only to a limited extent the
impact of curtailments by interstate pipelines, since electric
utilities in these states acquire most of their gas through
intrastate sources. More importantly, the projected decline
reflects deteriorating supply conditions in intrastate mar-
kets .
Due to ceilings on prices for gas which interstate
pipelines could pay, intrastate pipelines for many years
have been successful in obtaining a large proportion of new
gas found in the onshore producing areas . Most of new gas
reserves attached by interstate pipelines have come from the
Federal Domain offshore Louisiana. However, although
IV-31
-------
intrastate pipelines have attached a large share of new on-
shore reserves, the overall level of onshore reserves addi-
tions has been inadequate.
It is estimated that in 1973, total intrastate produc-
tion (consumption) of gas was 8.8 Tcf. From 1969 to 1973,
total onshore reserves additions in the U.S. averaged only
5.7 Tcf per year. Thus, the total amount of new gas theore-
tically available for intrastate consumption has been insuf-
ficient to support current levels of consumption.
Texas is a case in point. In 1973, electric utilities
in Texas burned more than one-third of the total volume of
gas consumed by electric utilities in the United States, and
over half of the gas burned by electric utilities in what is
denoted herein as the predominantly intrastate market.
Total Texas intrastate production in 1973 was approximately
4.9 Tcf, which accounted for most of total gas consumption
by all sectors in this state. Total reserves additions in
Texas have averaged less than a third of these consumption
volumes. Thus, total gas supply for consumption in Texas
may gradually diminish in coming years.—
As a result of these adverse supply trends, some cur-
tailments in Texas have already occurred. The Texas Rail-
road Commission has placed electric utility boiler fuel in
I/ In 1974, both interstate and intrastate production de-
clined in Texas.
IV-32
-------
a low priority in the event of curtailments by pipelines.
Moreover, reflecting the deteriorating supply-demand outlook,
and the potential impairment of gas service to industrial
customers, the Texas Railroad Commission is considering the
phaseout of electric utility gas consumption.
The forecasts developed herein may be considered as
"business as usual" and do not take into account potential
future regulatory reactions. For each of the electric
utilities burning gas, the supply situations of their
respective suppliers were reviewed. Reflecting the differing
supply situations of various suppliers of gas to power
plants, some diversity of trends is projected for the power
plants on Schedule IV-1. Sources of data included annual
reports to stockholders and prospectuses of both buyers and
sellers of gas, as well as reports by the Texas Railroad
Commission.
Although gas consumption by electric utilities is pro-
jected to decline, this "business as usual" approach also
suggests increasing curtailments of industrial plants.
There will be trade-offs between industrial and electric
utility gas consumption in Texas, but the quantification of
that trade-off is precarious unless assumptions are made as
to future regulatory actions.
The projections for Oklahoma show modest increases in
gas consumption through 1980. This forecast contrasts with
those for all other states, but reflects the unique situation
IV-33
-------
in Oklahoma. Two companies in that state accounted for 90
percent of electric utility gas consumption, and both have
been relatively successful in acquiring new gas supplies.
Both have significant control over the disposition of their
gas either through ownership of the pipelines or the actual
gas reserves. In their 1974 annual reports to stockholders,
both companies provided estimates of gas supplies for elec-
tric generation which have been incorporated into the pro-
jections on Schedule IV-1. A review of the overall gas
supply-demand situation in Oklahoma also suggests sufficient
gas availability for electric generation and industrial
needs.
Electric utility gas consumption in New Mexico is pro-
jected to decrease from 1974 to 1976, reflecting curtail-
ments by an interstate pipeline serving part of the state.
From 1976 to 1980, electric utility gas consumption is shown
to be stable, reflecting the apparent circumstances of the
major intrastate seller of gas in that state. The gas burn-
ing utilities in New Mexico do not foresee major curtail-
ments of gas service by intrastate suppliers. These favor-
able circumstances result from the increasing exploratory
effort in southeast New Mexico based upon increased intra-
state prices.
In Louisiana, electric utility gas consumption is pro-
jected to decrease by 35 percent between 1973 and 1980. A
substantial portion of this decline in the first two years
IV-34
-------
of the forecast is attributable to worsening curtailments by
interstate pipelines. These curtailments will also reduce
gas consumption by industrial concerns buying interstate
gas. However, the intrastate pipeline system in Louisiana
has been quite successful in obtaining new gas supplies, and
some electric utilities and industrial consumers have been
able to acquire gas supplies directly from producers.
According to available annual reports by electric utilities,
plants tied to intrastate supplies are in no imminent
j eopardy.
IV-35
-------
CHAPTER V
THE CURRENT AND PROJECTED USE OF ALTERNATIVE FUELS
BY GAS-BURNING UTILITY POWER PLANTS
As indicated in the previous chapter, the amount of gas
available to electric utilities throughout the United
States will diminish substantially. The impact of the gas
shortage on electric utilities will be to shift a sub-
stantial portion of their energy needs to other fuels. It
is thus the purpose of this chapter to analyze the ability
of gas-burning power plants to use alternate fuels, and to
appraise the potential alternate fuel demand by electric
utilities in light of reductions in gas supply.
A. Current Alternate Fuel Burning Capacity of Gas-
Burning Electric Utility Power Plants
Each of the 415 gas-burning electric utility steam
generating plants previously designated has been analyzed
with special emphasis on its primary fuel requirements
and ability to burn alternate fuels. As an initial but
integral step in this analysis, a summary of key data
from Form 423's and the FPC Form 36's is set out on Sched-
ule V-l. The Form 36, "Emergency Fuel Convertability Ques-
tionnaire," presents data which was filed in February 1973
and is in some cases outdated, but represents the only
available data on a relatively consistent basis of alternate
fuel burning capacity and is a useful starting point.
V-l
-------
Column (1) of Schedule V-l lists for each region and
state the gas-burning power plants included in the 415 plant
study; Column (2) shows the amount of gas burned by each plant
in 1973; and Column (3) shows the 1973 megawatt rating of the
plant. Based upon a print-out of Form 423 data for calendar
year 1974 obtained by Foster Associates, Inc., from Applied
Data Research, Incf, Columns (4) through (7) indicate the
relative purchases of oil, gas and coal for each plant. Column
(8) identifies the fuel or fuels which the plant was originally
designed to burn, taken from Steam-Electric Plant Factors,
published by the National Coal Association. Column (9) gives a
verbal description of the alternate fuel capabilities of
the plants. This verbal assessment largely reflects the
FPC Form 36. In some cases where the 1974 fuel consumption
indicated substantial change in fuel burning capability
since the end of 1972 (the effective date of the Form 36
data), and other factors partially confirmed that this
had occurred, the Form 36 data were modified accordingly.
Thus, for example, the first gas-burning power plant
listed is Kendall Square, owned by Cambridge Electric
Light Company in Massachusetts. The plant burned 500
million cubic feet in 1973 and has a 67 megawatt rating.
V-2
-------
In 1974, 41 percent of its fuel consumption came from gas
and 59 percent from oil, and the Form 36 indicates that oil
is the primary fuel. It may then be surmised that a re-
duction in gas deliveries could be accommodated by greater
utilization of oil without plant modification. As in many
other cases, the original fuel burning design (Column (8))
had been modified over the years.
Schedule V-2 is a state-by-state summary of the data
from Schedule V-l with the plants grouped by state and
FRC region. The number of plants, megawatt rating, and
1973 gas consumption are given for four categories of
plants, defined as follows:
(1) Gas is the primary fuel but an alternate fuel
could be burned with no boiler-generator de-
rating .
(2) Gas is the primary fuel and an alternate could
be burned, but some derating would result or
the alternate could not be burned in all boilers.
(3) Gas is the primary fuel and no alternate exists.
(4) Gas is a secondary fuel and is indicated as be-
ing burned as an alternate fuel or in conjunc-
tion with other fuels.
While che states are listed by FRC region in both Schedule
V-l and Schedule V-2, in the following analysis they have
been grouped according to similar consumption patterns.
V-3
-------
B. Summary of the Alternate Fuel Capability
in the Interstate Market
New England proper, New York, Pennsylvania, New
Jersey, Delaware, the District of Columbia and Maryland
constitute an area in which gas was generally consumed
as an alternate fuel for oil. Gas was burned in 27 plants
in these eleven states in 1973, and was considered to be
an alternate for oil in 24 of these. Two plants burned
gas as an alternate for coal, and one plant burned gas
and oil on a co-equal basis. The total 1973 electric
utility gas consumption in these states was 73.0 Bcf (46.8
Bcf in New York), or 2.2 percent of the U.S. power plant
total.
A second group of states which exhibited similar con-
sumption patterns was that of: Virginia, West- Virginia,
Kentucky, Tennessee, North Carolina, South Carolina,
Georgia and Alabama. In these eight states gas was again
mainly a secondary fuel, but the principal fuel in this
region was coal rather than oil. The 18 plants in this
area which burned gas in 1973 consumed a total of 62.5 Bcf,
less than 2 percent of the U.S. total. Of these 18 plants,
13 were fueled primarily by coal, 1 by oil, and 2 burned
gas along with another fuel. The 16 plants in which gas
played a secondary role accounted for 93 percent of the
region's gas consumption. The two remaining plants, one in
Alabama and one in Georgia, considered gas to be their pri-
mary fuel. However, both plants possess full alternate
V-4
-------
fuel capabilities, and would suffer no boiler derating if an
alternate fuel were consumed.
The seven state area of Ohio, Illinois, Indiana, Mich-
igan, Iowa, Wisconsin and Minnesota combined for a total
1973 gas consumption of 189.4 Bcf, just under 6 percent of
the U.S. total. Some 36 percent of the gas total was burned
in 24 plants which considered this fuel to be their primary
source of energy. Of these 24 plants, 17 had full alternate
sources of power (usually coal), 5 would suffer some minor
derating if an alternate were burned, and 2 had no alternate
fuel capability. The 7 plants with either limited or no
alternate capability consumed 19.2 Bcf in 1973, slightly more
than 10 percent of the region's total consumption. Gas was
usually burned as an alternate for coal in this region. In
43 of the 80 gas-burning plants gas was considered to be an
alternate fuel. Coal was listed as the primary fuel in 41
of these 43 plants, which accounted for 47 percent of the
area's 1973 gas consumption. Gas was burned in conjunction with
either oil or coal in an additional 13 plants, which consumed
17 percent of the region's gas in 1973.
A six state area accounted for 11.8 percent of the
electric utility gas consumption in 1973, with 70 plants
burning 401.3 Bcf. The six states were: Colorado, Kansas,
Nebraska, Missouri, Arkansas and Mississippi. The utilities
of this region placed heavy reliance on gas, but in most
cases alternative sources of energy were available under
V-5
-------
certain limiting restrictions. The majority of the plants
in this area (52 of 70) considered gas to be their primary
fuel. In all but one of these 52 plants, an alternate
fuel could have been burned in place of gas. While only
one plant had no alternate capability, 27 of the 52 plants
would either suffer some degree of boiler derating when
burning an alternate fuel, or they could not consume an
alternate in all boiler units. The impact on each plant
when burning an alternate is described in Column (9) of
Schedule V-l. Of the 52 plants which burned gas as their
primary fuel, 33 listed oil as their alternate, 10 listed
coal, 8 listed both oil and coal, and one had no alternate.
The State of Mississippi was included in this region,
and at first glance might seem out of place, since four
of the state's seven plants indicated that they had no
alternate fuel capability. However, the oil consumption
in each of these four plants has increased substantially
in every year since 1972 as a result of gas curtailments.
The 1974 data shows the percent of total Btu consumption
derived from oil to range from 21 percent to 82 percent for
the four plants, with three of the four over the 66 percent
mark.i' These plants were therefore placed in the category
I/ Mississippi Power § Light Co., the major gas-burning
~ utility in the state, has spent over $50 million to
modify its plants to burn oil as well as gas. Mississippi
Power Company, the second major gas-burning utility in
the state, was curtailed 69 percent of contracted supply
in 1973 and 80 percent in 1974. As a result, the company
is now generating approximately 65 percent of its power
with coal, as well as increasing amounts of fuel oil .
-------
of having gas as a primary fuel with oil as a partial
alternate.
Virtually all gas consumed by electric utilities in
Arkansas is received from interstate suppliers on an interruptible
basis. The Arkansas Power § Light Co. accounted for 90 percent
of electric utility gas consumption in 1973, but has increased
its dependence on fuel oil over the past two years due to gas
curtailments. It has made plans for both a nuclear and a
coal-fired plant, using Wyoming coal.
North Dakota, South Dakota, Montana, Wyoming and Utah
constitute an area in which gas played a minor role in the
electric utility sector. None of the eight plants in this
region which consumed gas considered it to be their primary
fuel. It was listed as an alternate for coal in five of
the plants, and an alternate for oil in the other three.
(However, one plant in South Dakota which listed oil as the
primary fuel did consume about three times as much gas as
it did oil in both 1973 and 1974.) These five states burned
7.2 Bcf in 1973 on an alternate fuel basis, 0.2 percent of
the U.S. total.
The dominant characteristics in Arizona, Nevada, Cali-
fornia and Florida, were: (1) substantial gas consumption;
and (2) high degree of substitutability between oil and
gas. These four states consumed nearly 20 percent of the
electric utility sectors' gas in 1973, and virtually all of
the 673.3 Bcf burned could have been replaced by oil. In
fact, the 1974 consumption data suggests that a switch from
V-7
-------
gas to oil was being made in a number of plants in this
area.
California epitomizes this group of states. The 35
plants in California burned 441,6 Bcf, over 13 percent of
the U.S. total. Of these 35 plants, 34 listed gas as the
primary fuel with oil as an alternate. In 1974, over 40
percent of the total Btu consumption in 22 of the 35 plants
was derived from oil. A similar situation was observed in
both Arizona and Nevada, where 14 of the 16 gas-burning
plants listed gas as the primary fuel and oil as the alter-
nate. In Arizona, 8 of the 11 gas plants received over
48 percent of their total 1974 Btu's from oil. The Nevada
plants were of similar design, and substantial amounts of
oil were consumed in 1974, but the pattern of oil-for-gas
substitution was not as striking in this state.
Florida was included with these West Coast states
because it fits the two established criteria. Gas consump-
tion in Florida totaled 145.8 Bcf in 1973, and nearly
all electricity generation could have been fueled by oil with
no boiler derating. Florida was similar to the other states
in that the overwhelming majority of plants (25 of 27)
burned some combination of oil and gas, with both fuels
being significant sources of energy. Although only 5 of
the Florida plants listed gas as the primary fuel, 18 of
the total 27 operated on a fuel supply which was at least
one-third gas.
V-8
-------
The next three-state area is that of: Idaho, Oregon,
and Washington. In these states gas played little or
no role in the generation of electricity in 1973. The only
state reporting gas consumption was Oregon, and this was
in two small plants which were generally used for standby
service. The total consumption of 2.4 Bcf for this area
in 1973 was less than 0.1 percent of the U.S. total.
The 283 electric utility steam generating plants located
in the interstate market burned 1,409.2 Bcf in 1973. Virtually
all of the power generated by gas in these plants could have
been fueled by either oil or coal, with the majority of the
plants suffering little or no boiler derating when consuming
an alternate fuel. Gas was considered to be the primary
fuel in 132 of the 283 plants in which it was burned; these
plants consumed 936.0 Bcf in 1973. Plants in which an alternate
could have been burned numbered 95 with no boiler derating,
and these plants consumed 50 percent of the gas consumed by
electric utilities in the interstate market. An alternate
fuel could have been burned in 34 plants with some derating,
ranging from 5 to 25 percent. In 3 plants there was
no alternate available for gas. Plants in which the burning
of an alternate would entail some derating consumed 15 percent
of the total, while those with no alternate consumed less than
1 percent. Gas was burned as a secondary fuel in 151 of the
283 plants. These plants burned 473.2 Bcf, just under 34
percent of the interstate total.
V-9
-------
In summary, 84 percent of the gas consumed by electric
utilities in these states in 1973 could have been replaced
by oil or coal with no loss in generating capacity. An
additional 15 percent of the gas could have been replaced under
some relatively minor boiler derating. The remaining gas
consumption, less than 1 percent of the total, could riot
have been replaced by an alternate fuel. Thus, gas curtailments
in the interstate market would have minor effects on the
generation capabilities of steam-electric power plants, assuming
alternate fuel would be available.
In terms of alternate fuels which would have been consumed
if gas had not been available, 1,043 Bcf of gas could have
been replaced by oil. This represents 74 percent of the total
gas consumption by electric utilities in the interstate market.
Coal could have been substituted for 352 Bcf, 25 percent of the
total JL/ The remaining 1 percent had no alternate available.
The substitution of these fuels for gas in all boilers would
result in relatively minor deratings. A total gas curtailment
would decrease the megawatt rating in the interstate market
by less than 21. The majority of the plants affected are
located in Nebraska, Kansas, Missouri, Arkansas, Mississippi,
Illinois.
I/ The fuel which a plant would substitute for gas may not
be apparent in all cases from the information contained
in Schedule V-l. For example, a plant with 8 coal boilers
and 2 gas/oil boilers would have more than one option
available in the event of a gas curtailment. It could:
(1) increase the output of the 8 coal boilers, or (2)
substitute oil for gas in the two gas/oil boilers. The
estimates here are based on the boiler-by-boiler require-
ments in the plants and the plants ' uti li zation of coal and
oil in the past.
V-10
-------
C. Summary of the Alternate Fuel Capabilities
in the Intrastate Market
Some 58 percent of all gas consumed by the electric utility
sector in 1973 was burned in the four-state area of Texas,
Louisiana, Oklahoma and New Mexico. The combined consumption
total for the year was 1,981.9 Bcf. The striking features of
this region were: (1) gas was the primary fuel in virtually
every plant (131 of 132); and (2) the majority of the plants
(96 of 132) were listed as having no alternate fuel capability.
Texas was the leading gas consumer in 1973 with 80
plants burning 1,277.8 Bcf. A total of 64 of these 80 plants
were listed as having no alternate capability. In the 16
plants in which an alternate could have been burned (9 of
which would suffer some boiler derating), oil was the alternate
fuel.
Louisiana burned 369.4 Bcf in 23 gas consuming plants,
16 of which had no alternate fuel capability. A total of
270.9 Bcf was consumed in the 16 Oklahoma plants, and 63.9
Bcf in New Mexico. In Oklahoma, 10 of the 16 plants had no
alternate capability, and the ratio was 6 of 13 in New Mexico.
In the plants in which an alternate fuel could have been
burned, including those which would suffer some derating,
oil was the choice in all plants in both Louisiana and
New Mexico. In Oklahoma 4 plants listed coal as an alternate,
and 2 listed oil.
V-ll
-------
At this point it becomes necessary to consider a rather
important time-lag problem. As mentioned previously, the
Form 36 data were submitted in early 1973. The assessment
of each company with regards to its alternate fuel capability
was made in light of the general conditions which prevailed
at that time. Over the past two years a number of factors
have significantly altered the status of some companies. The
supplies and prices of fuels available to electric utilities
have substantially changed, FPC and state regulatory agency
activities have increased, and the general economic climate
is vastly different than it was in 1973. As a result of
these and other factors, some companies have been forced
to make changes previously thought to be unfeasible.
The majority of the plants in the four-state area
were designed to burn gas, with the possible use of oil in
emergency situations. Oil combustion in a gas plant is
possible, but only for short periods and usually with some
boiler derating. To convert a plant from emergency oil-
firing to one which could burn either oil or gas for extended
periods of time, is an undertaking which requires both time
and capital investment. The magnitude of these variables
will depend on the original design of the specific plant
under study.
Because of the proportion of plants in this area which
indicated that gas was the primary fuel with no alternate
V-12
-------
available, further research was deemed necessary to ascertain
the present status of the major electric utilities in the
four-state region, as well as in Arkansas and Mississippi as
discussed in the preceding section. The 1973 and 1974 Annual
Reports to Stockholders of these companies were reviewed.
The general climate in these states appears to be one of
uncertainty with regards to gas supply. Not only are the
gas supplies contracted on an interruptible or interstate
basis thought to be in jeopardy, but also the viability of
some firm intrastate contracts appears to be in question due
to curtailment priorities established by state regulatory
authorities. The unclear picture regarding future gas supplies
has led a number of companies to diversify their fuel base,
both by increasing the convertability of gas plants to oil,
and by designing new plants for gas/oil, coal, lignite and
nuclear fuels.
Power companies in Oklahoma have apparently seen little
need for major plant conversions. Two companies burned over
90 percent of the electric utility gas in the state in 1973,
and both consider their gas supplies to be in solid shape.
Oklahoma Gas § Electric Co., the major electric utility in
the state, operates solely with intrastate supplies and this
company contracted substantial amounts of new reserves in
1974. However, they do plan a future gradual shift towards
low-sulfur coal. The Public Service Co. of Oklahoma owns
its supply system, with most gas reserves in the system dedicated
V-13
-------
for the life of the wells. This company has just completed
what they feel may well be the last major gas-fired plant
in the country, but they too foresee a future shift towards
coal. The shift from gas to coal in Oklahoma is merely in the
planning stages and seems to be applicable to new plants only.
Thus, most plants will operate almost exclusively on gas with
little conversion activity in the near future.
The situation in Louisiana is somewhat mixed, with both
interstate and intrastate supplies of gas. Louisiana Power
and Light Co., Gulf States Utilities Co., and New Orleans
Public Service Inc. accounted for over 80 percent of the
state's 1973 utility gas consumption. All three receive a
portion of their gas from the same interstate supplier, and
there have been serious curtailment problems with this supplier.
As a result they have tried to stabilize their fuel situation
by increasing their conversion potential and also by seeking
more intrastate gas. Of the 10 plants operated by these three
companies, six are undergoing some degree of conversion to
enable them to burn oil for longer periods. The following
statement from the 1973 Annual Report of New Orleans Public
Service, Inc. summarizes the situation of a number of utilities
in the state: "The severe curtailment of natural gas purchased
under contract by the company for fuel to generate electricity
has forced greatly increased use of oil as a power plant fuel.
A portion of approximately $12.5 million spent on new construc-
tion during the year was needed to continue modifications begun
V-14
-------
in 1972 at Michoud and Patterson stations to permit the
burning of oil for extended periods of time."
In Texas a large segment of the electric utility indus-
try receives its gas from sources not subject to FPC regulation.
Recent actions by the Texas Railroad Commission, however, have
placed the status of all gas used as a boiler fuel in some
doubt. The proposed phasing out of gas as a boiler fuel,
coupled with higher intrastate gas prices and curtailed inter-
state deliveries, has caused a good deal of activity in this
gas dominant state. Six of the major consuming utilities,
which burned nearly 75 percent of the state's electric utility
gas in 1973, indicated that operations are underway to increase
their ability to burn oil. The conversions will not allow
complete oil-firing in all units, but they will lessen the current
dependence on gas. Millions of dollars are being spent on
converting plants to a multiple fuel capability, oil storage and
handling facilities are increasing, and a number of plants
under design will operate on coal or lignite. The largest gas-
consuming utility in the state, Houston Lighting and Power,
reported in its 1974 annual report that it presently has more
than 1,700,000 kilowatts of generating capacity which can burn
oil or gas continuously. This amount will increase to 4,350,000
kilowatts in 1975, and 5,100,000 in the future. This company will
also expand its oil storage capacity to 6.7 million barrels by
1977, and an intra-company oil pipeline is under construction.
V-15
-------
The company was hit by curtailments of 12.3 percent by one
of its two major gas suppliers in 1974, and has therefore
extended and revised its second gas contract to satisfy current
needs. They estimate that the new contract will provide the
company with 64 percent of its fuel requirements through 1978,
and 20 percent from 1979-1984. The outlook of this company
typifies that of others in the state, and may be summarized
by the statement that the amended gas contracts will "facilitate
an orderly transition from fuel-burning capability based almost
entirely on natural gas to one based on natural gas and other
fuels, including oil, nuclear and coal."
The gas-burning plants in New Mexico are similar to
those in Oklahoma in that gas supplies are largely of an intra-
state nature, and little conversion has taken place at this
time. Both the Public Service Company of New Mexico and
Southwestern Public Service Company, with 6 gas plants and
60 percent of the state's 1973 consumption, expressed confi-
dence in their natural gas supply. The Public Service Company
of New Mexico emphasized a new contract which extends through
1989 and the reassurances of its intrastate suppliers, while
Southwestern Public Service Company pointed out that all of
its gas is intrastate and 25 percent of the reserves are from
dedicated wells.
Thus, alternate fuel requirements in the four-state
(intrastate) region are difficult to assess. Texas, Oklahoma,
Louisiana and New Mexico plants consumed 58 percent of the
V-16
-------
U.S. electric utility gas supply in 1973. The Form 36 data
indicate that the majority of the plants in these four states
(96 of 132) could burn only gas. Further research indicates
that their alternate fuel capability has significantly
increased since 1973, and will continue to do so in the future.
Plant modifications have been most noticeable in Texas and
Louisiana, two of the largest gas consumers in the electric
utility sector. The companies in these two states have
initiated serious efforts to diversify their fuel base.
They have sought to: increase the ability of gas plants to
burn oil, design future plants for multiple fuel firing, and
increase experimentation with fuel forms previously unexploited
in this area (coal, lignite, nuclear). The exact number of
plants which have undergone conversion or will undergo
conversion cannot be estimated at this time, but some efforts
have been made by most utilities in the two states. Gas
will continue to be the primary fuel in the near future, as
long as it is available and remains a feasible energy source,
but precautionary measures are being taken.
The majority of the gas plants in New Mexico and Oklahoma
have little or no alternate fuel capability at this time.
Due to favorable gas reserves positions, the companies in these
two states have shown little desire to decrease their dependence
on gas, although some mention was made of increased use of coal
in future plants in both states.
V-17
-------
Thus, this four-state region is vastly different from the
rest of the country. Gas is the primary fuel in far more
plants, and alternate fuels may not always be substituted
for gas. A total dependence on gas exists in many more
plants than in the rest of the country, but not as many as
might be inferred from Schedules V-l and V-2. Oil could
have replaced 210 Bcf in the four-state area, 11 percent
of total consumption in this region. Coal could have been
burned in place of 27 Bcf, 1 percent of the total. A large
portion of the gas burned, 868 Bcf or 44 percent, could not
have been replaced by an alternate fuel. The residual 44 percent,
or 877 Bcf, was of a questionable status. It was burned in
plants which have undergone some conversion, but the degree
of conversion is unknown at this time. It may only be said
that the most probable alternative to these 877 Bcf is oil.
Any estimation of the total boiler derating when burning
alternate fuels in these four states would be highly
speculative at this time. The overall effect would be
far more significant than in the interstate market, but to
determine an exact magnitude would require an extensive plant
conversion study as insufficient data now exists.
D. Projections of Alternate Fuel Demand by Electric
Utilities Due to Reductions in Gas Supply
Schedule V-3 shows the estimated use of alternative fuels
by electric utilities due to reductions in gas supply from
1973 to 1980. The declines in gas consumption are attributed
V-18
-------
to one of three categories -- demand for coal, demand for
fuel oil, and demand for indeterminate fuels. The latter
category reflects plants which are indicated to have limited
or no known alternative fuel burning capability at this time.
By integrating the plant by plant projections of natural gas
availability from Chapter IV with the plant by plant analysis
of alternative fuel burning capability, the forecasts show
for each state the effect of the gas shortfall on existing
power plants. It should be noted that no consideration is
given to the need for overall increasing generation, and the
resultant increase in demand for other fuels due to the
unavailability of gas.
On Schedule V-3, column (2) shows for each region and
state the amount in trillions of Btu's of gas consumed in 1973.
Columns (3) through (20) show, as a result of declines in gas
volumes, the displaced demand for alternative fuels. For
example, in 1973 electric utilities in New England burned
5.7 trillion Btu's of gas. In 1975, the reduction in gas supply
from 1973 levels is estimated at 0.2 trillion Btu's. Column
(4) shows that the plants suffering this reduction have alter-
native fuel burning capability in terms of fuel oil. Thus,
it is projected that in 1975 electric utilities in New England
will burn an increment of 0.2 trillion Btu's of fuel oil due
to a comparable reduction in natural gas availability.
V-19
-------
It should be noted that on the schedule certain data
are shown in brackets, denoting negative demands for alternative
fuels. This situation indicates that natural gas consumption
is projected to increase from 1973 levels, resulting in a
decline in demand for an alternate fuel. Thus, for the State
of Minnesota as an example, column (4) shows a negative 1.6
trillion Btu's. This means that in gas burning plants with
fuel oil burning capability, gas consumption in 1975 is
projected to increase by 1.6 trillion Btu's in 1975 compared
with 1973. In cases where bracketed values appear in the
"indeterminate" column (see Oklahoma for example), this means
that increases in gas consumption by plants which do not
have alternate fuel capability are projected.
The schedule shows that in 1973 gas consumption on the
part of power plants in the U.S. analyzed herein was 3436.1
trillion Btu's. In 1975, reductions in gas consumption by
these plants is projected to result in the consumption of
103.6 trillion Btu's of coal and 589.7 trillion Btu's of oil.
Some 27.5 trillion Btu's of the decline in gas consumption is
"indeterminate" -- will take place in plants which have limited
or no known alternative fuel burning capability.
By 1980 the shortfall in gas deliveries would require
additional coal consumption of 348.5 trillion Btu's and
additional fuel oil consumption of 1074.0 trillion Btu's.
The remaining portion of the net reduction in 1973 gas
V-20
-------
consumption -- 272.6 trillion Btu's -- would take place in
plants which at this time have limited or no known alternative
fuel burning capability. Excluding those plants which have
limited or no known alternative fuel burning capability but for
which increases in gas consumption are projected, the reduction
in gas deliveries by 1980 to plants which have limited or no
known alternative fuel burning capability would be 348.8 trillion
Btu's.
E. Deterrents to the Use of Alternate
Fuels by Electric Utilities
The conversion of a gas-only plant to a coal based unit
would entail major modifications to the boiler/furnace unit
resulting in a substantial derating of the unit. These modi-
fications would be of such a magnitude that the construction
of a totally new and separate coal plant might offer a more
feasible alternative.
Additional space at the plant site would have to be
available for coal storage and intra-plant coal car movement.
In addition, provisions for on-site disposal of sludge and
ash might be required. Environmental quality standards
would necessitate the utilization of electrostatic precipi-
tators and possibly stack-scrubber devices for the control
of ash and sulfur oxide emissions, both of which require
additional plant space.
V-21
-------
The conversion process would further be severely
hampered by the physical size of the boiler/furnace unit.
Gas units tend to be relatively smaller than oil or coal
units due to favorable flame characteristics and also because
gas is a clean burning fuel producing no waste products.
Coal releases soot and ash when burned, which can cause
severe corrosion and slagging problems. Slagging, the
excessive accumulation of ash particles between the water
tubing throughout the boiler/furnace, might not even be
corrected with the addition of soot blowers unless all
tubing was re-spaced at wider intervals, which entails
essentially a rebuilding of the boiler. The addition of an
ash hopper would require the elevation of the entire unit,
which could be equivalent in size to the fourteen story
building.
A conversion from gas to oil is a far more manageable
task, although a number of modifications would have to be
made for continuous oil-firing. Gas recirculation fans
would have to be added to: prevent the overheating of
wall tubing, aid in increasing super reheat temperatures,
and reduce sulfur oxide emissions. The clogging caused by
ash deposits would require the installation of soot blowers,
and also necessitate periodic water washings. Additional
superheat and reheat surfaces would be required because of
the lower temperature of the oil-firing process, a situation
V-22
-------
only partially alleviated by the addition of gas recirculation
fans. The oil flame would create a high heat flux in the
wall tubes, and these tubes would tend to overheat if the
flame was of a sufficient size to obtain maximum plant
capacity. Thus the unit might be forced to operate below
capacity.
Plant site modifications would include the addition
of unloading and storage facilities, as well as pumping
and heating stations (for fuels that are viscous) if pipeline
deliveries were to be used. Two final modifications necessary
for residual, but not distillate oil-firing, would be the
addition of steam coil air heaters and a small ash hopper.
If low-sulfur oil (less than seven-tenths of one percent)
was not available, high-sulfur oil would further complicate
the conversion process. Measures would have to be taken to
prevent vanadium corrosion, and the higher ash and sulfur
contents would require the use of electrostatic precipitators
and some type of SC^ emission control device as in the case
of gas-coal conversion. Finally, sludge and ash disposal
would again have to be dealt with.
The cost of converting facilities from gas to other
fuels will vary from plant to plant. As an example, evidence
before the Texas Railroad Commission by Houston Lighting
and Power Company in the proposed curtailment plan case of
Penzoil Pipeline Company indicates that the cost is substantial
In 1973 Houston Lighting and Power Company operated ten steam-
electric plants with a generating capacity of 7,375 megawatts.
V-23
-------
The company felt that a conversion to coal was virtually
impossible, and that a conversion to oil for all units would
require a project seven to ten years in duration with an
investment in excess of $100,000,000 ($13.56/kilowatt of
capacity in 1973 dollars).
In many instances there may be little economic incentive
for utilities to burn alternate fuels. Generally, gas is a
lower priced fuel than either oil or coal. In 1974, the
average price of gas burned by electric utilities was 48
-------
The use of gas is most significant in four FRC regions:
the Northern Plains, Mid Continent, Pacific Southwest, and
Gulf Coast. The percent of total utility energy needs
met by gas in these regions ranged from 23 percent in the
Northern Plains to 82 percent in the Gulf Coast in 1973.
All states in these regions place a heavy reliance on gas,
with the exceptions of North Dakota and South Dakota.
The utilities in five of the remaining six FRC regions
rely on fuel oil or coal to a much greater extent than gas
to meet their energy needs. In these regions only Florida,
Colorado, and Utah derived more than 10 percent of their
total requirements from gas. However, even though the
market share of gas in some of these states is small, the
impact of a curtailment should not be minimized. For example,
gas supplied less than 7 percent of the power for New York
utilities in 1973, but this amounted to 47 Bcf and a total
curtailment would require the substitution of 7.7 million
barrels of oil or 2.1 million tons of coal.
V-25
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1 REPORT NO.
EPA-450/3-76-030a
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Impact of Natural Gas Curtailments on Electric
Utility Plants—Two Volume Report: Volume I, Text,
and Volume II, Schedules (Data and Summary Tables)
5. REPORT DATE
August 1975
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
1O. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-1452, Task 1
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 curtailments
on electric utility plants through the review of the curtailment plans of inter-
state pipeline, intrastate pipeline and gas distributors. This analysis determined
the availability of natural gas through 1980 to 415 electric utility power plants,
the alternate fuel burning capability of these plants and the impact of gas cur-
tailments on the need for alternate fuels such as fuel oil and coal. The study
results are presented in a two volume report: the first contains the narrative
with pertinent findings and conclusions; the second contains the schedules or data
summaries.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIF'ERS/OPEN ENDED TERMS C. COSATI Field/Group
Fuels
Natural gas curtailments
Steam plants
United States
Government
Regulations
Air pollution
Natural gas
Electric power
generation
Air pollution control
18. DISTRIBUTION STATEMENT
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
158
Unlimited
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
V-26
-------
30
CD
m
2
------- |