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Federal Reserve
I
William A. Testa
’ king paper series on
Natural Gas Policy
and the Midwest Region
Bank of Chicago
NATURAL GAS POLICY AND THE MIDWEST REGION
William A. Testa
Federal Reserve Bank of Chicago
April, 1983
Table of Contents
Chapter
Title
List of Tables
I.
II.
III.
IV.
V.
Page
i
List of Figures
ii
Acknowledgments
iii
Executive Summary
1
Delivery, Production, and Consumption of Natural Gas
7
The Federal Regulatory Environment
19
The Recent State of the Natural Gas Market
27
The Market Outlook Under Natural Gas Decontrol
43
Conclusions
56
Footnotes
59
Appendix I
61
Bibliography
66
List of Tables
Table
Number
I.
II.
III.
IV.
V.
VI.
VII.
Title
Natural Gas Dependence by Type of User 1970-80
11
Percent Residential Units Heating with Natural Gas 1980
12
The Distribution of Natural Gas Consumption by EndUse Sector 1970-8C
14
Per Capita Natural Gas Production and Consumption
1970-80
15
Gas Utility Industry Average Prices 1970-1981
17
Scheduled Decontrol Dates of NGPA Gas Categories
24
Estimated Parity Prices of Natural Gas and Residual
Fuel Oil
54
i
Page
List of Figures
Title
FIGURE 1
FIGURE 2
FIGURE 3
FIGURE 4
FIGURE 5
Principal Agents in the Domestic Market for
Natural Gas
8
Interstate Transmission Pipelines Serving
Seventh District States
9
Interregional Disparities in Price-Controlled
Natural Gas
39
Price Impact of Average Cost Pricing in the
Presence of NGPA Price Ceilings
48
Estimated Price of Residual Fuel Oil and
Natural Gas, 1960-1981
53
ii
Page
ACKNOWLEDGMENTS
Many thanks to David R. Allardice, Herbert L. Baer, Gary L. Benjamin,
Kenneth W. Costello, and Jerry W. Szatan for their substantive comments and
editorial advice.
The staff of the Information Services Department of the
Federal Reserve Bank of Chicago provided first-rate assistance.
Appreciation
is also extended to Shirley Harris for word processing assistance.
O’Connell and Roger P. Thryselius created the graphics.
those of the author.
Thomas P.
Any errors remain
Opinions expressed in this manuscript do not represent
the views of the Federal Reserve Bank of Chicago or the Federal Reserve
System.
iii
Executive Summary
Energy consumers in the Seventh District, especially residential
consumers, depend on natural gas to fulfill many of their energy needs.
The
five Seventh District states (Illinois, Indiana, Iowa, Michigan, and
Wisconsin) use natural gas to meet approximately 28 percent of their overall
energy consumption.
For this reason, national policy toward natural gas
production and delivery remains critical to this region.
The natural gas
policy decisions of the next few years, including the issue of accelerated gas
market decontrol, will affect the economic vitality and direction of
industrial, commercial, and residential activity in the Midwest.
In the past, the complex structure of gas market regulations has carried
mixed blessings to the District states.
Federal price ceilings on the
domestic production of gas were able to hold down customer prices for natural
gas, but only at the expense of the Midwest supply shortages experienced in
the 1970s.
Intermittent shortages in supply moved federal policy toward major
revisions of gas market regulation.
The Natural Gas Policy Act of 1978 (NGPA)
secured greater supplies of natural gas for interstate customers, including
Seventh District residents, through favorable allocation directives and higher
producer prices.
In addition to a continual easing of wellhead prices for natural gas, the
NGPA set a complex schedule of price ceilings over most production from
domestic gas wells.
NGPA price ceilings on most existing gas categories,
especially gas from wells of recent discovery, will be removed on January 1,
1985, covering an estimated 55-65 percent of domestic gas production.
Some
natural gas wells of older vintage remain under price control indefinitely.
2
Consequently, the current decontrol timetable-gradually frees gas production
from price control as the gas from older wells becomes exhausted.
The NGPA price schedule-was intended to gradually raise average gas
prices to parity with petroleum prices by the time of partial decontrol in
In this manner, decontrol would not subject gas consumers to - price
1985.
shocks.
A regulatory middle route was fashioned between the development goal
of spurring energy production and the immediate necessity of holding consumer
prices at bay.
Despite the intent of the NGPA to restrain consumer price increases,
post-NGPA price levels have risen at a much faster rate than had been
anticipated.
On average, gas prices rose at rates of almost 20 percent per
year in recent years, easily outstripping the general rate of price inflation.
Most analysts concede that climbing world energy prices, led by the 1979 OPEC
round, are mostly responsible for climbing domestic prices of natural gas.
Nevertheless, regulatory features of the NGPA, coupled with erroneous market
regulation of an earlier era, have accommodated gas price increases by
insulating producers and pipelines from declining market demand while gas
consumers-pay final prices that may lie above market-clearing levels.
In
addition, the structure of NGPA price ceilings may be deterring exploration
and recovery of gas for future consumption, portending future prices for
natural gas -that are greater than they need to be.
Over the past two years, domestic and world energy demand have fallen due
to conservation and world-wide recession.
While the petroleum market has
responded to sagging demand by lowering prices, wellhead gas prices have
continued to rise despite slack demand and excess production capacity.
Although falling consumption does create some problems for the production
3
sector, the past and present regulatory structure has protected producers and
pipelines from falling consumer prices!.
Shortages of interstate gas•supplies in the 1970s, caused by pre-NGPA
ceilings on interstate gas, induced pipelines to contract for inordinately
large deliveries of high-priced gas in today's market under so-called
"take-or-pay" contract clauses.
Pipelines must pay for these deliveries even
though much of this gas cannot be sold to pipeline customers at contracted
prices.
Since renegotiation or "market out" clauses are absent from many
pipeline-producer contracts, pipelines cannot force producers to renegotiate
wellhead prices to reflect current market conditions.
Moreover, many producer
prices continually rise under existing contracts along with the highest
regulated rate prescribed by NGPA price ceilings.
Other contract terms
specify percent escalation in gas prices over time or tie the current price of
gas to residual fuel oil.
As a result, wellhead prices to pipelines have
risen while pipeline sales have fallen.
Pipelines escape the full impact of rising wellhead prices because the
NGPA allows them to automatically pass through wellhead price increases to
their main line customers and distributors.
Purchased Gas Adjustments (PGAs)
are filed with the Federal Energy Regulatory Commission (FERC) up to twice a
year to reflect cost increases from rising wellhead gas prices.
Insofar as
PGAs allow rate hikes to reflect only the price of gas which is sold by
pipelines to their customers, some pipelines have elected to sell the most
expensive gas to distributors while storing lower-cost gas supplies for sale
at a later date.
This practice further contributes to the rate of increase in
the price of gas sold to distributors and other pipeline customers.
Under current regulatory provisions, distributors behave in much the same
manner as pipelines.
Some distributors are paying such high prices for
4
natural gas that this gas cannot be profitably sold to their customers.
Again, take-or-pay contract provisions of an earlier era, along with the lack
of alternative suppliers, restrain distributors from refusing delivery of
high-priced gas.
In turn, distribution utilities typically pass along rising
gas prices to their customers via state versions of PGAs, though these
practices have recently met political resistance in some states, such as
Michigan.
Recent gas price hikes and predictions of future gas price increases have
caused a re-examination of our policies toward gas production and delivery.
To many observers, excess production capacity coupled with rising price levels
suggests that the gas market should be more responsive to falling demand for
energy.
Current gas prices to consumers are higher than market clearing
levels in spite of and because of NGPA price ceilings and other regulatory
features.
Take-or-pay contracts and other regulatory policies have trans
formed NGPA price ceilings into price floors during this current period of
slack demand.
Federal legislation to allow producer-pipeline renegotiation of existing
contracts has been proposed as one way to remedy gas market irregularities!.
In addition, diminishing the ability of distributors and pipelines to pass
along wellhead price increases through PGAs may give a greater incentive to
pipelines to renegotiate onerous contract terms.
Other changes include
establishing interstate pipelines as common carriers so that local
distributors and customers could purchase gas directly from the lowest-cost
producer.
The possibility that current wellhead gas prices have risen beyond their
equilibrium has given new impetus to those who advocate accelerated decontrol
of all wellhead prices.
The current tiered structure of price ceilings
5
stifles the incentive to discover new domestic reserves and to enhance
production capacity.
Price decontrol could lower the resource costs of
current production and increase future supplies.
In turn, increases in future
supplies would lower the extent of future price levels to natural gas
consumers.
To the extent that price levels currently exceed their
market-clearing levels, accelerated decontrol would not raise prices to
consumers in the near term so long as amendment of contract features and
regulatory policies accompanied such a measure.
Opposition to accelerated decontrol arises from both distributors and
consumers who perceive the NGPA as a decontrol action which did little to hold
the line on consumer prices.
Wary of any new measure that claims to lower
prices by allowing an apparent acceleration of current policy, many
individuals favor a rollback of current price levels as a guarantee of
rational price levels for natural gas.
Forecasts of future price levels and production under market decontrol
remain uncertain for many reasons.
The volatile behavior of world energy
prices carries over to natural gas, a substitute for petroleum use in many
sectors.
Moreover, the future level of energy demand, including natural gas,
is difficult to predict because of the depth of the current recession and the
timing of recovery.
In addition to these uncertainties of market behavior,
removal of present regulatory policies on natural gas will influence market
demand and supply in countervailing directions.
Despite the difficulties in predicting gas market behavior under
accelerated decontrol, the current price of substitute fuels for natural gas,
particularly fuel oil, provides an approximate anchor for a deregulated gas
price estimate in the short run.
Within the Seventh District states, natural
gas prices in 1982 rose to parity with residual fuel oil.
This evidence,
6
coupled with the present inefficiencies in natural gas production, suggests
that the Seventh District residents would not be seriously affected, on
average, by the price effects of accelerated decontrol.
Rather, the market
signals to producers that accompany decontrol would work to increase future
supplies of natural gas and moderate future price increases.
Moreover,
enhanced domestic energy production presents a major counter punch to OPEC
dominance of world energy prices.
Of course, any recommendation to accelerate decontrol of wellhead prices
must be accompanied by renegotiation of existing pipeline-producer contracts
and revision of other NGPA features.
One problem associated with accelerated
decontrol involves provisions within existing contracts between transmission
pipelines and natural gas producers.
One type of contract provision, the
’’most-favored nation clause", immediately lifts the price of gas to the
highest price paid in the well’s producing area upon the advent of price
decontrol.
This can result in above-normal post-decontrol price levels for
gas under these contracts because the structure of present regulations can
distort the price of gas from nearby deep wells above reasonable levels.
Thus, most-favored nation provisions can cause a "fly-up" in gas price above
the eventual equilibrium price at the time of decontrol.
These contract pro
visions and others must be amended or renegotiated if accelerated decontrol is
to accompany moderate price levels in the near future.
Chapter I:
Delivery, Consumption, and Production of Natural Gas
There are four principal agents that bring natural gas from under the
ground to the homes and factories of the United States.
These agents are
wellhead producers, transmission pipelines, distribution utilities, and final
customers (Figure 1).
Typically, wellhead producers sell their natural gas to
interstate or intrastate transmission pipelines under long-term agreements.
Allowable prices for all domestic wellhead gas are regulated by the Federal
Energy Regulatory Commission (FERC).
This regulatory agency administers
allowable natural gas prices under the authority of the Natural Gas Policy Act
(NGPA), enacted in 1978.
Transmission pipelines serve as an intermediary transport system between
wellhead producers and distribution utilities (as well as some large
commercial and industrial customers).
Transmission pipelines differ from
common carriers, such as railroads, in two respects.
First, the profits of
transmission pipelines are regulated by the federal government so that they
can best be considered as public utilities.
Second, transmission pipelines
purchase the product that they transport from wellhead producers.
Pipeline
purchase of natural gas serves to secure long-term supplies of natural gas to
energy-dependent regions of the country.
It has also contributed to certain
long-term contract provisions that are hindering short-term declines in
natural gas prices during the present recession.
The major portion of natural gas delivered to the Seventh District states
is provided via 11 transmission pipeline companies.
In the Midwest region,
interstate transmission pipeline systems deliver the bulk of natural gas from
the Southwestern states of Texas, Oklahoma, and Louisiana (Figure 2).
Lesser
volumes of natural gas originate from local wells, Appalachian gas fields, and
Figure 1
Principal Agents in the Domestic Market for Natural Gas
Regulatory Sector
------------------- ► Impact of Regulation
•
*
Flow' of Natural Gas
Production—Consumption Sector
Figure 2
Primary Transmission Pipelines Serving Seventh District States
1. Michigan Gas Storage Co.
2. Michigan Wisconsin Pipe Line Co.
Midwestern Gas Transmission Co.
4. Mississippi River Transmission Corp.
5. Natural Gas Pipeline of America
6.
7.
8.
9.
10.
Northern Natural Gas Co.
Panhandle Eastern Pipe Line Co.
Texas Gas Transmission Corp.
Trunkline Gas Co.
Great Lakes Transmission Co.
11. Northern Border Pipeline Co.
Source:
U.S. Department of Energy,
---------- Boundary
Major Natural Gas Pipelines,
of Seventh Federal Reserve District.
U.S.G.P.O., 1979.
10
foreign countries (largely Canada and Mexico).
Unlike domestic petroleum
consumption, however, U.S. imports of natural gas account for only a small
portion of domestic consumption, ' slightly over 5 percent in 1981.
Transmission pipeline companies generally sell natural gas to public and
private distribution utilities as well as large industrial customers and
electric utilities.
Sales of natural gas by transmission pipeline companies
are also regulated by the FERC.
Increases on gas costs are passed through to
utilities via Purchased. Gas Adjustment clauses (PGAs).
These clauses, filed
with the FERC, are intended to compensate pipeline companies for ongoing
increases in the price of gas that are paid to wellhead producers.
Distribution utilities, both public and private, purchase natural gas
from transmission pipelines and deliver it to final customers through a
network of buried pipes.
State regulatory agencies, typically public utility
commissions, oversee delivery and pricing of natural gas to final customers.
In most states, distribution utilities are able to pass through cost increases
of purchased gas to final customers without regulatory approval by way of
state versions of PGA clauses.
to this practice.
The State of Michigan represents one exception
Michigan requires public utility commission approval of PGA
gas utility rate hikes.
Natural Gas Consumption and Production
In 1980 natural gas accounted for 27.6 percent of overall energy
consumption within the five states (Illinois, Indiana, Iowa, Michigan, and
Wisconsin) of the Seventh District.
nation (Table I).
This compares with 26.9 percent for the
Contrary to what would be expected in an era of rising
prices of imported fuels, national and regional dependence on natural gas has
decreased from 1970 to 1980, indicating a general substitution of alternative
energy sources for natural gas.
The national dependency, which had exceeded
Table I
Natural Gas Dependence by Type of User 1980 (1970)*
(percent)
Year
All Uses
Illinois
1980
(1970)
29.5
(32.6)
Indiana
1980
(1970)
Iowa
Electric
Transportation
Utilities
Commercial
Industrial
54.6
(53.4)
36.2
(34.4)
25.1
(26.2)
1.8
(3.7)
1.8
(16.7)
20.5
(25.1)
37.0
(40.0)
31.3
(40.7)
19.1
(22.0)
2.1
(3.0)
(--)
(5.6)
1980
(1970)
27.0
(40.2)
35.9
(45.7)
40.4
50.7)
28.4
(29.1)
5.5
(9.0)
2.9
(45.3)
Michigan
1980
(1970)
32.0
(30.5)
54.1
(50.9)
46.1
(40.7)
25.8
(24.2)
2.0
(1.8)
3.2
(11.0)
Wisconsin
1980
(1970)
26.4
(26.5)
35.7
(32.5)
37.5
(33.4)
28.2
(26.8)
2.6
(2.5)
3.4
(10.7)
Region
1980
(1970)
27.6
(30.4)
47.3
(47.0)
38.6
(38.0)
24.1
(24.9)
2.4
(3.4)
2.0
(14.2)
U.S.
1980
(1970)
26.9
(32.6)
31.9
(37.3)
25.2
(29.5)
27.6
(32.9)
3.3
(4.6)
15.6
(24.8)
Residential
♦Dependence is defined as dry natural gas consumption as a share of total energy consumption from all fuels.
Consumption is measured in MMBTUs (heat content of energy input). The following definitions summarize each use.
Residential Sector: energy consumed by private households primarily for space heating, water heating, and other
household uses. Commercial Sector: energy consumed by non-manufacturing business establishments, non-profit enter
prises, and government. Industrial Sector: Energy consumed by manufacturing, construction, mining, agriculture,
fishing, and forestry. Transportation Sector: Energy consumed to move people and commodities in both the private
and public sectors. Electric Utility Sector: Energy consumed by publicly-and privately-owned establishments which
generate electricity for resale.
SOURCE:
State Energy Data Report 1960 through 1980, DOE/EIA-0214(80), July, 1982.
12
that of the District states in 1970, fell by twice as much as the regional
share.
Michigan and Illinois are particularly dependent on natural gas.
Michigan’s 32 percent consumption share and Illinois' 29.5 percent share are
significantly greater than the nation’s average.
Both Iowa and Wisconsin
consume natural gas in close proportion to the national average.
Consuming
only 20.5 percent of its energy in the form of natural gas, Indiana lies
significantly below the national average.
The residential and commercial sectors in Seventh District states are far
more dependent on natural gas than the overall nation.
All five states
maintain a higher proportion of residences with gas heating than the nation’s
average (Table II).
In this regard, Illinois ranks first in the nation and
only five other states rely on gas for home heating to a greater extent than
the State of Michigan.
Table II
Percent of Residential Units Heating With Natural Gas 1980
State
Percent Housing Units
Illinois
Indiana
Iowa
Michigan
.Wisconsin
U.S. Average
82.5
61.3
66.7
76.5
58.1
53.3
Rank in U.S.
1
16
13
6
21
—
SOURCE: U.S. Department of Commerce, Bureau of the Census, "Provisional
Estimates of Social, Economic, and Housing Characteristics," Table H-3, Fuels
and Financial Characteristics of Housing Units 1980.
Michigan’s dependence on gas in the residential and commercial sectors,
and its overall dependence, greatly increased over the past decade.
Illinois and Wisconsin also witnessed increasing gas dependence in the
residential and commercial sectors.
As a result, the Seventh District became
13
more gas dependent in these sectors while the nation has experienced
significant declines.
Within the industrial sector, only Wisconsin and
Michigan's gas shares of total energy turned upward, countering both overall
regional and national trends.
Both the region and the nation showed a reduced
dependence on natural gas in the transportation sector between 1970 and 1980.
And while the nation greatly reduced its dependence on gas used to generate
electricity, Seventh District states reduced gas consumption in this sector to
an even greater extent.
The industrial sector consumes the lion's share of natural gas in the
United States, over 41 percent in 1980 (Table III).
However, in the Seventh
District states, especially Michigan and Illinois, the residential natural gas
share exceeds other sectors, comprising about 40 percent of regional gas use
in 1980.
The industrial end-use sector is a close second, representing
approximately 35 percent of total regional gas consumption.
Overall, the
region's gas consumption accrues in the residential and commercial sectors to
a much greater extent than the nation.
Natural gas is used to generate
electricity to a greater degree in the nation than in Seventh District region
where coal rather than gas is the primary input.
Regions vary not.only in their relative dependence on natural gas but
also in their absolute consumption of energy and natural gas.
Seventh
District consumers utilized about 91,000 cubic feet of gas per capita in 1980,
exceeding the national by about 3,000 cubic feet (Table IV).
While per capita
gas consumption in the region declined by 9,000 cubic feet from 1970 to 1980,
per capita consumption nationally fell by over 16,000 cubic feet.
Conse
quently, regional per capita consumption changed from a lower-than-national
total in 1970 to an amount in excess of national per capita consumption in
1980.
Table III
The Distribution of Natural Gas Consumption by End-Use Sector 1980 (1970)
as a Percent of Total Consumption
Year
Residential
Commercial
Industrial
Transportation
Electric
Utilities
Total
Illinois
1980
(1970)
43.9
(37.4)
20.9
(16.5)
32.0
(32.4)
1.3
(2.8)
1.8
(11.3)
100
(100)
Indiana
1980
(1970)
33.4
(29.0)
14.3
(14.2)
49.9
(49.2)
1.8
(2.0)
.4
(5.4)
100
(100)
Iowa
1980
(1970)
31.5
(27.6)
18.8
(16.4)
42.5
(28.3)
4.7
(5.3)
2.6
(22.3)
100
(100)
Michigan
1980
(1970)
44.8
(42.0)
22.0
(16.4)
28.8
(32.4)
1.2
(1.3)
3.1
(7.9)
100
(100)
Wisconsin
1980
(1970)
35.0
(31.1)
21.9
(16.1)
36.8
(41.7)
2.3
(2.0)
3.9
(9.1)
100
(100)
Region
1980
(1970)
40.4
(35.4)
20.1
(16.0)
35.4
(35.8)
1.9
(2.3)
2.2
(10.4)
100
(100)
U.S.
1980
(1970)
23.9
(22.9)
13.1
(11.3)
41.2
(43.8)
3.2
(3.4)
18.7
(18.6)
100
(100)
Note: The consumption share is defined as dry natural gas consumption by end-use as a share of all dry
gas consumption.
SOURCE:
State Energy Data Report 1960 through 1980, DOE/EIA-0214(80), July, 1982.
Table IV
Per Capita Natural Gas Marketed Production and Consumption, 1970-1980
Consumption
Cubic Feet Per Capita
1970
1980
% Change
b,c
Production
Cubic Feet Per Capita
1980
1970
% Chang
Illinois
105,670.6
95,430.4
- 9.7
436.5
137.8
-68.4
Indiana
104,908.5
89,101.1
-15.1
28.1
84.3
200.0
Iowa
123,539.8
92,512.4
-25.1
0.0
0.0
0.0
Michigan
91,083.0
93,437.4
2.6
4,374.1
17,097.1
290.8
Wisconsin
76,505.2
74,767.7
- 2.3
0.0
0.0
0.0
Region
99,235.7
90,726.2
- 8.6
1,343.0
4,753.3
253.9
103,978.3
87,756.5
-15.6
107,823.3
89,970.6
-16.6
United States
SOURCE:
Natural Gas Annual 1980, February 1982, DOE/EIA-0131(80), and State Energy Data
Report, 1960-1980, DOE/EIA-0214(80).
£
Production includes marketed production including nonhydrocarbon gases.
^Consumption includes “Lease and Plant Fuel" and “Pipeline Fuel".
0
Production figures contain nonhydrocarbon gas while consumption figures exclude this gas
Production data, net of non-hydrocarbon gas, is not available for all states,
16-
By all accounts, the Seventh District consumes much more natural gas than
it produces.
Michigan produces the only significant amounts of natural gas
among Seventh District states.
Michigan produced over 17,000 cubic feet of
gas per capita in 1980, an increase of almost 300 percent from 1970.
Natural Gas Prices in the Midvest
Natural gas prices have risen in approximate unison among states of the
Seventh District over the last decade.
From 1970 to 1981, retail natural gas
prices increased by almost six-fold (Table V).
While the nation's gas prices
climbed at a compound average annual rate of just over 17 percent over this
period, the increase in each District state was slightly lower.
Four of five
Seventh District states witnessed an average gas price level above the
national average in 1970, but only the average price in Michigan and Wisconsin
remained above the national average in 1981.
Concurrently, Indiana
experienced the lowest regional average gas price level in 1981, 11 percent
below the national average.
Prior to the NGPA in 1978, national average gas prices rose at a slower
pace than in the post-NGPA era.
Post-NGPA price acceleration was consistent
with NGPA intentions of spurring national gas development to a limited degree
through price incentives.
Among District states, the average annual growth
rate of prices lagged behind the nation in the eight years preceding the NGPA
of 1978, a period characterized by restrictive price controls on interstate
gas and intermittent supply shortages in the Midwest.
In the post-NGPA era,
the average annual increase in gas prices exceeded the national average in
every Seventh District state except Illinois.
Table V
Gas Utility Industry Average Prices (all customers) 1970-1981
($/millions of btus)
Illinois
Indiana
Iowa
Michigan
Wisconsin
U.S.
SOURCE:
1970
1978
1979
1980
1981
$.73
.71
.62
.78
.80
.64
2.27
1.93
1.96
2.17
2.26
2.18
2.72
2.38
2.36
2.51
2.66
2.52
3.26
2.82
2.81
3.06
3.42
3.13
3.66
3.26
3.45
3.70
4.19
3.66
Compound Annual
Rate of Increase
1970-78
(percent)
15.2
13.3
15.5
13.6
13.9
16.6
Compound Annual
Rate of Increase
1978-81
(percent)
Compound Annual
Rate of Increase
1970-81
(percent)
17.3
19.1
20.7
19.5
22.8
18.9
15.8
14.9
16.9
15.2
16.2
17.2
American Gas Association.
Note: A British thermal unit (btu) equals the amount of heat required to raise the temperature of one pound of
water one degree Farenheit.
18
The price of gas in the highest-priced District state, Wisconsin,
exceeded that of the lowest price state, Indiana, by . just over 28 percent in
1981.' While substantial variation in average price levels between Seventh
District states can be observed, the variation among smaller market areas most
likely exceeds that between states.
In addition to differences in distance
from the wellhead, delivery costs differ according to volume with large
customers generally being less-costly to serve than others.
Differences in
retail prices also arise from the variety of transmission pipeline companies
serving the region.
Transmission pipelines sell natural gas to distribution
utilities in the Seventh District at average rates that reflect their ability
to secure gas'at varying prices within NGPA price ceiling categories.
For
this reason, local utilities within a state or region may purchase natural gas
at significantly different prices than their immediate neighbors.
A recent survey of selected transmission pipeline companies indicates the
substantial variation in the mix of purchased wellhead gas by transmission
pipeline companies.*
Among those pipelines selected in the sample that serve
the Seventh District s.tates, the highest average wellhead price exceeded the
lowest average price by over 62 percent. '
These price variations largely
reflect the historical position of pipelines in cementing long-term contracts
for volumes of ' natural ■ gas at favorable prices and other ■ contract terms.
II.
The Federal Regulatory Environment
Two primary goals of current federal legislative policy can be
identified, though these goals have not been fully realized.
First,
legislation has been enacted to protect certain classes of residential and
commercial users from a worsened economic position by limiting the rise in the
price of natural gas and by insuring delivery priorities to these customers.
Although price limitations are intended to protect consumers from deteriora
tion in purchasing power, these same limitations can result in shortages and
bottlenecks in supply thus negating the potential benefits to be derived from
price protection.
To compensate, additional legislative measures insure
delivery priorities to preferred gas users, which are primarily residential
and commercial customers.
The second goal of current legislation attempts to bring gas production
and consumption into harmony with our comprehensive national energy needs.
Together with coal development and energy conservation, natural gas develop
ment represents a major counterpunch to OPEC dominance of energy supplies and
costs.
By substituting coal and natural gas for imported oil, we can improve
our terms of trade with other countries, and possibly erode OPEC’s pricing
power.
Although the goals of current natural gas policy are laudable, these
goals have not been realized under the market incentives created by the myriad
of present regulations.
Clearly, current regulations have failed to protect
consumers from near-term price increases.
Moreover, the development of
domestic gas production has fallen short of its potential.
The history of gas
20
market regulation in the U.S. reveals a morass of counterproductive
intervention and the needless restriction of market forces.
Federal Government Regulation:
A Synopsis
Although natural gas deposits were readily available for production early
in this century, delivery to large urban markets awaited the technological
breakthrough that made natural gas competitive with fuel oil.
2
The
development of the seamless welded pipe in the 1920s ushered in the era of
natural gas and natural gas delivery systems.
Since pipeline systems require
large fixed costs, Congress moved to prevent the monopoly pricing of natural
gas to local utilities by interstate pipeline transmission companies.
The Natural Gas Act of 1938 (NGA; Pub.L. 75-688) gave the Federal Power
Commission (FPC) the authority to regulate interstate pipeline gas price and
contract terms.
Transmission companies that did not cross state boundaries,
intrastate pipelines, remained uncontrolled by .federal authority.
Under FPC control interstate gas markets grew rapidly through the early
1950s.
Standard "allowed rate of return" and "historical cost" price controls
on interstate pipelines were not serious impediments to market development and
expansion.
By 1950, natural gas accounted for about one-sixth of total
domestic energy consumption,
structure of gas markets.
in 1954, the U.S. Supreme Court altered the
Contending that wellhead prices substantially
affect ultimate consumer prices, the Supreme Court in Phillips Petroleum v.
Wisconsin interpreted the FPC's regulatory power as extending to wellhead
3
prices,of interstate natural gas.
in essence, producers who chose to sell
natural gas to interstate pipelines became public utilities while producers
who sold to intrastate pipelines market remained largely unregulated by the
federal government.
21
As a result of this court decision, producers experienced two
disincentives to develop and sell gas to interstate pipelines.
Regulated
prices to interstate gas producers began to fall significantly below the
market determined price of gas sold to intrastate pipelines.
The FPC tried to
regulate interstate producer gas prices in a fashion similar to the regulation
of prices on gas sold by transmission pipeline companies to distribution
utilities.
Determination of "historic cost" and "allowable rate of return"
for each producer, however,
process.
proved to be an overwhelmingly costly and slow
By 1960 applications for over 2,900 rate increases had been filed
with the FPC, bu- only 10 had been completed.
In an attempt to expedite
regulatory processes, the FPC adopted "area rate pricing" in the early 1960s.
Area rate pricing established consolidated regulated prices for producers '
within broad geographic areas.
Despite improvements in expediting price
increases, area rate pricing failed to achieve a balance between intrastate
and interstate wellhead gas prices.
The pricing differential encouraged
drilling in areas served by intrastate pipelines at the expense of areas
served by interstate pipelines.
As a result, the committed reserves of gas to
interstate pipelines declined during the latter 1960s and early 1970s while
intrastate reserves remained fairly constant.
Insofar as consumption remained
fairly level throughout this period, eventual supply shortages in the
interstate market became inevitable.
In addition to delays in wellhead price increases, the Federal Power
Commission may have aggravated the interstate supply problem in another
respect.
Once producers committed producing wells to interstate pipelines,
they were not allowed to withdraw these reserves from public access without
regulatory permission.
Although this regulation initially maintained gas that
was already committed to interstate markets, it also may have discouraged some
22
producers from committing any new reserves to the interstate market for fear
they could not respond to changes in future conditions by selling to alternate
buyers.
In any event, the stock of intrastate and uncommitted gas reserves
remained fairly constant from 1963 through 1977.
Concurrently, interstate
reserves fell by almost 50 percent.
Two segmented natural gas markets arose in this regulated environment.
The intrastate market, located in gas producing states, experienced higher gas
prices but plentiful supplies.
In contrast, the interstate market was
characterized by lower relative prices than the intrastate market but also by
dwindling supplies.
By the winter of 1972, shortages occurred at places in
the interstate markets where market demand at stated prices could not be met
by pipeline supply.
Severe shortages occurred again in the winter of 1976-77,
temporarily closing many factories and schools in the Midwest.
In response to these regulatory failures, Congress moved to redress the
severe imbalance in the natural gas market.
During 1978 several legislative
enactments markedly altered the regulatory environment.
The most significant
legislative reform appeared as the National Gas Policy Act of 1978 (NGPA).
NGPA replaced the Federal Power Commission with the Federal Energy Regulatory
Commission (FERC) as the regulatory authority of natural gas distribution.
FERC's regulatory authority was extended to intrastate gas production in an
effort to partially unify the two markets that had developed over the
preceding 25 years.
Although market segmentation continued under NGPA
regulations, the intrastate gas market disappeared as a vestige of free market
production.
Pre-NGPA regulation redirected regional gas consumption away from
interstate pipeline regions by capping interstate prices while ignoring
intrastate prices.
This diverted gas supplies to the gas producing regions of
23
the South and Southwest.
The NGPA alleviated supply shortages in interstate
pipelines by several methods.
First, NGPA caps intrastate gas prices thus
diverting greater available supply to interstate markets.
In addition, gas
production from federal land on the outer continental shelf can no longer be
sold to intrastate pipelines.
A primary feature of NGPA was the establishment of an extensive and
complex schedule of wellhead price ceilings. These price ceilings vary in
their application to interstate and intrastate markets in the present period
and in the price decontrol dates in 1985 and 1987 as scheduled in the NGPA
(Table VI).^
Maximum prices also vary according to the physical
characteristics of the well, its proximity to other wells, prior commitment to
interstate pipelines, and the date of well initiation.
NGPA ceilings on wellhead gas prices apply to all except Section 107
wells, which are characterized by a drilling depth of over 15,000 feet (Prices
of gas from Section 107 wells are determined by market forces.)
prices are allowed to rise at the rate of inflation.
All ceiling
"New gas," gas from new
wells and gas from those wells placed in production since 1977, rises in price
at an additional four percent per year as measured by the GNP deflator.
Price
ceilings for most new gas are to be eliminated as of January 1, 1985 and some
classes of older vintage intrastate gas also become decontrolled in 1985.
It
is estimated that the wellhead price on 55 to 65 percent of all domestically
produced gas will be unregulated in 1985.*
In addition to the wellhead ceilings and a price decontrol schedule, the
NGPA set forth a scheme of incremental pricing.
Incremental pricing allocates
the costs of rising wellhead gas prices to certain industrial uses, large
Table VI
Scheduled Decontrol Dates of NGPA Gas Categories*
NGPA Classification
Date of Deregulation
Description
1/1/85
1/1/85
1/1/85
not deregulated
102, New Natural Gas
.
.
.
.
103, New Onshore Wells
(certain wells started
post 2/19/77)
. wells deeper than 5,000 feet
. wells shallower than 5,000 feet
1/1/85
1/1/87
104, Gas dedicated as
interstate pre-11/9/78
. various categories
not deregulated
105, sold under
existing intrastate
contracts
. all types
1/1/85
106, sales under
"rollover" contracts
. interstate
. intrastate
not deregulated
1/1/85
107, high-cost gas
. wells greater than 15,000 feet drilled
after 11/1/79 and other types
. tight sands and other types
11/1/79
certain new onshore wells
new onshore reservoirs
offshore leases effective after 4/20/77
new reservoirs on old offshore leases
not deregulated
3
108, stripper wells
. produced at rate less than 60,000 ft /day
not deregulated
10°, other
. Prudhoe Bay and other
not deregulated
Imported gas
. price- set by approval of the FERC and
the Economic Regulatory Administration
not deregulated
*In general, wells qualifying under more than one category are eligible for the price
ceiling and decontrol status of choice. See Appendix I for a more complete description
of decontrol categories and ceiling prices.
25
industrial boilers in particular.
The price of gas sold in these industrial
uses, however, may not exceed the regional price of high-sulfur residual fuel
oil which is a close substitute for gas in industrial boiler consumption.
This latter restriction inhibits the switching of gas for fuel oil to insure
greater price subsidization of residential, commercial, and electric utility
customers.
Concurrent with NGPA, the Powerplant and Industrial Fuel Use Act of 1978
(FUA) altered the demand for natural gas.
The FUA sought to encourage the use
of coal, shale oil, and alternate fuels for industrial purposes in place of
oil and gas.
The FUA prohibits new electric powerplants and industrial
boilers from burning oil or gas if coal or other fuels remain an alternative.
Exemptions are granted to the extent that alternative fuels are prohibitively
costly or environmental regulations deny the use of alternatives.
Through the NGPA and the FUA, Congress intended to steer a middle course
between allowing gas prices in the long term to rise to oil-price equivalents
and holding down the increases in the short term to protect certain classes of
customers.
Although the ceilings served to limit the rise in gas prices to
residential and commercial customers, Congress foresaw continuing gas
shortages in the short run because of the ceilings.
Consequently, allocation
directives such as curtailment priorities, demand restrictions, and
incremental pricing of industrial gas attempted to contain expected shortages
to industrial users and electric utilities.
At the same time, the removal of
ceilings on "deep wells" and the accelerated price increases on new gas were
designed to encourage gas development and production in order to foster
alternatives to petroleum imports and augment future supplies of natural gas.
By increasing future supplies and gradually raising average gas prices, it was
thought that protective price controls would become unnecessary. This process
26
of gradual price decontrol was intended to lift new gas prices to approximate
parity with oil by the time of partial price decontrol in 1985.
In this
manner, decontrol would not subject gas consumers to price shocks.
A
regulatory middle route was fashioned between the development goals of the
free market and the immediate necessities of holding consumer prices at bay.
Unfortunately, the intentions of our most recent natural gas policy have not
been realized in actual market behavior.
III.
The Recent State of the Natural Gas Market
A declining domestic demand for natural gas, coupled with certain
regulatory features of the NGPA, have given rise to both rapidly rising prices
and excess production capacity.
Moreover, market regulations of both the
pre-NGPA and post-NGPA era have conspired to insulate suppliers of natural gas
from falling demand while final consumers of gas bear the costs of unneeded
investment in the production of costly gas supplies.
These developments have
re-opened the issues concerning the regulation of the natural gas industry.
Legislative movements are underway to make the supply side of the market more
responsive to falling market demand.
At the same time, the high level of
current gas prices has given new impetus to an acceleration of the current
price decontrol schedule.
If gas prices currently exceed market clearing
levels, accelerated decontrol of wellhead prices, accompanied by legislation
that allows the current market to respond to falling demand, may result in
more rational production incentives without further price shocks to gas
consumers.
Post-NGPA Natural Gas Market Behavior
The scheduled partial decontrol of natural gas, beginning in 1985, was to
be preceded by an average gas price that was close to parity with competitive
oil products.
However, the NGPA schedule of price decontrol did not
anticipate the near-doubling in the price of crude oil from 1978 to 1981.
As
a result, the price of natural gas fell significantly below the price of crude
oil in the years immediately following NGPA.
At that time, many observers
predicted a sharp price spike to accompany partial decontrol in 1985 because
natural gas consumption, which is a close substitute for fuel oil in
industrial use, was expected to rise as customers switched from oil to gas to
lower overall energy costs.
28
Forebodings of sharp price hikes in 1985 were exacerbated by certain
contract provisions between interstate gas producers and interstate pipelines.
In anticipation of eventual price decontrol and rising energy prices, gas
producers included "escalator” clauses in contracts with transmission
pipelines which raise the price of previously committed gas over time.
Interstate pipelines accepted many of these contract terms under the duress of
looming shortages.
Some escalator clauses continually raise prices to the
level of the highest allowable regulated wellhead rates which rise as ceiling
prices increase over NGPA categories of gas.
Other clauses simply include
definite percent escalations in future prices of delivered natural gas.
One type of escalator clause, the deregulation provision, causes
particular alarm in discussion over price hikes accompanying partial
decontrol.?
At the same time of partial decontrol, these provisions lift
wellhead prices of contracted gas to free market rates or to other indefinite
levels such as 110 percent of the price of residual fuel oil.
In the absence
of deregulation clauses, the advent of partial decontrol of gas from new wells
in 1985 would witness moderated average price increases because some gas that
had been committed prior to decontrol would be locked into low contract
prices.
One particular type of deregulation provision, the "most-favored nation"
clause, has the potential to cause severe disruption with the onset of partial
decontrol in 1985.
In general, a most-favored nation clause stipulates that
the transmission pipeline pay the average of the two or three highest prices
being paid in the producing area or the highest price being paid for similar
g
gas.
Pipelines often cannot cancel out of these contracts,
While most-favored nation clauses alone might temporarily throw market
prices above their equilibrium in 1985, the NGPA magnifies the impact of these
29
clauses.
The price of deep-well gas, Section 107 gas, is
currently decontrolled in toto.
Many gas pipelines have bid up the price of
Section 107 gas because of their practice of average cost pricing.
Pipelines
generally average the costs of old, low-price gas along with the cost of more
expensive new gas to establish a single price to any given distribution
utility.
Transmission pipelines can use the price "cushion" of
previously-contracted cheap wellhead gas to bid competitively for uncontrolled
expensive domestic gas or wellhead imports from Mexico and Canada in an effort
to meet the demand of existing customers at average prices.
As a result, the
average price paid for all gas falls below the marginal price paid for
deep-well gas by the pipeline.
This has led to wellhead prices of $10 per MCF
or more for Section 107 gas while average wellhead prices hover around $2.50.
In the event that producers require pipelines to take delivery of decontrolled
gas at Section 107 prices in 1985 under most-favored nation clauses, wellhead
prices could jump significantly above market equilibrium prices.
Though price
would eventually settle back to equilibrium, the initial price shock could
cause serious disarray within the natural gas market.
Some of the early concern over a sudden price jump in 1985 has abated as
natural gas prices climbed much faster than anticipated, lowering the extent
of potential price hikes.
While many gas industry analysts were asserting
that acceleration of the decontrol schedule would lessen the economic costs
associated with a sharp price spike in 1985, residential gas prices rose by
almost 63 percent from January, 1980 to September, 1982.
These rapid price
hikes were accompanied by falling energy consumption, falling prices for
substitute fuels and falling natural gas consumption.
The current recession has lowered domestic demand for all energy
products. Total domestic gas consumption declined from 19,877 billion
30
g
cubic feet (Bcf) per year to 19,404 Bcf from 1980 to 1981.
In the first
three quarters of 1982, consumption fell by over 6 percent in comparison to
the first three quarters of 1981.
Decreases in consumption cannot be wholly
attributed to downturns in the domestic economy.
weather conditions influence gas consumption.
selves encourage conservation by gas customers.
Year-to-year changes in
Moreover, rising prices them
Still, prior to the 1981-1982
recession, total domestic gas consumption rose slightly from 19,627 Bcf in
1978 to 19,877 Bcf in 1980 despite a rapid rise in prices.
This suggests that
the present economic slump may account for part of the recent slack in gas
demand.
.
Despite the recent downturn in demand for natural gas, both consumer and
wellhead prices continue to climb.
The average wellhead price of gas in
creased by over 21 percent from September, 1981 to September, 1982 while
average residential gas prices rose almost 19 percent.
In comparison, average
heating oil prices declined by almost 4 percent over the same period and the
domestic average wellhead value of crude petroleum declined by over 10
percent.
Rising gas prices accompanied by slack demand for natural gas leads many
observers to conclude that gas price decontrol, as exemplified by the NGPA,
fails to benefit anyone except wellhead gas producers.
Baffled at price
increases in the face of slack demand, many consumers maintain that price
decontrol allows monopoly rents to accrue to producers with no benefit
whatsoever to consumers.
31
Why Have Gas Prices Continued to Climb?
Natural gas prices have continued to rise in the wake of slack demand for
several reasons.
First, the second OPEC round of petroleum price hikes in
1979 led to a doubling in world oil prices.
Insofar as petroleum and natural
gas are substitutes in energy consumption, petroleum price hikes placed upward
pressure on the demand and price of.natural gas.
The structure of NGPA price ceilings on domestic gas accommodated and
exacerbated upward pressure on gas prices in several respects.
The NGPA
created a price-decontrolled category of gas, Section 107 gas, as a production
incentive.
Some pipelines used their surfeit of price-controlled gas to
subsidize their price bids on Section 107 gas.
As the price of Section 107
gas subsequently increased, it helped to pull the average price of gas up to
unforeseen levels.
In addition to price increases in Section 107 gas, NGPA price ceilings
themselves have grown at a rate outstripping the general rate of price infla
tion.
While ceiling prices on some categories of gas climb at the rate of
inflation, the ceiling price on Section 102 gas, (new natural gas), was per
mitted to increase at an annual rate of 3.5 percent more than inflation
through April 20, 1981, and at a rate of 4 percent more than inflation through
the end of 1984.
As older vintage supplies of gas have been depleted, a
greater proportion of production has fallen into NGPA categories covered by
higher ceiling prices and into categories with ceilings that rise more rapidly
than inflation, greatly contributing to gas price increases to final
customers.
In addition to the price ceiling structure of NGPA, the federal gas
regulation of an earlier era contributed to recent gas price hikes.
Contract
terms between pipelines and wellhead producers reflect the relative strength
32
of these two parties in bilateral contract negotiation.
In this regard, the
tight producer price ceilings imposed on wellhead gas in the pre-NGPA era
restricted available reserve commitments by producers to interstate pipelines.
In the absence of adequate price rewards, producers were able to bargain for
inclusion of "non-price" or "shadow price" conditions into interstate
contracts that were entered into during the last decade, including the period
immediately following the passage of the NGPA.
In an effort to secure
adequate supplies in anticipation of growing demand and continuing shortages,
pipelines included escalator clauses, take-or-pay clauses, and other
unfavorable conditions into their contracts with wellhead producers.
In
general, these contract clauses have protected producers from unanticipated
declines in final market demand, much to the detriment of transmission
pipelines, distribution utilities, and especially final consumers.
Escalator clauses continually raise the purchased price of natural gas
sold to pipelines.
Price escalations can take the form of the highest
regulated price allowed under NGPA regulations or they may only specify
certain percent increases in wellhead prices over time.
While these contract
terms alone cannot ratchet prices upward during eras of excess gas supplies,
contracts have been accompanied by "take-or-pay" provisions which discourage
downward price movements during periods of slack demand.
These provisions
require pipelines to pay for contracted volumes of gas on a specified schedule
regardless of whether pipelines take the gas.
Department of Energy surveys
indicate that pipelines were most willing to accept take-or-pay provisions in
the "973-77 era, though they apply to over 80 percent of post-"978 contracted
volume as well.^
As a result of these contract provisions, the gas market
has not responded to the recent period of slack natural gas demand at the
wellhead.
The wellhead price of natural gas in the U.S. climbed by over 2"
33
percent from September, 1981 to September, 1982.
Concurrently, the domestic
wellhead price of petroleum decreased by over 10 percent.
While take-or-pay contract features have assured that wellhead producers
do not suffer from recent declines in gas demand, purchased gas adjustment
clauses, PGAs, have insulated pipelines from much of the sagging market
demand.
To date, FERC has granted pipeline price hikes associated with
increased wellhead gas costs without major delays via Purchased Gas Adjust
ments (PGAs).
PGAs can be filed up to twice a year to reflect increases in
the prices that pipelines pay for gas at the wellhead.
Perhaps more galling to consumers than recent price increases in the
presence of falling demand, transmission pipelines continue to purchase
high-priced categories of natural gas for resale to customers while available
supplies of cheaper wellhead gas remain in storage or in the ground.
For
example, Columbia Pipeline Co. stopped taking gas from 20,000 low-volume wells
in Appalachia which was available at prices as low as $.45 per Mcf.
At the
same time, the pipeline continued to purchase gas from other sources at prices
exceeding $5.00 per Mcf.
These practices have raised the average price of gas
that pipelines sell to distribution utilities.
Pipelines are thought to decrease their takes of low-cost gas during
periods of slack demand because PGAs only allow a price pass-through for
wellhead gas that is sold by the pipeline to a distributor or other customer.
In turn, pipelines may seek to preserve a favorable cash flow by receiving PGA
compensation for the largest possible portion of their expenditures.
High-priced gas, usually being of more recent vintage, is more likely to
contain high take-or-pay provisions, reducing the incentive for pipelines to
sell older low-priced gas to distributors in place of high-price gas con-
tracted under take-or-pay provisions.
12
34
In addition to costs arising from take-or-pay provisions and other
contract terms, pipelines incur large fixed costs due to pipeline construction
maintenance, and operation.
These costs are also rolled into customer prices.
In fact, any costly venture can be potentially rolled into final consumer
prices.
For example, in the 1970s Panhandle Transmission Company and its
Trunkline subsidiary heavily invested in facilities to import liquified gas
from Algeria in anticipation of severe gas shortages in the 1980s.
13
In
addition, pre-construction costs from the Alaska gas pipeline venture and a
Wyoming synthetic fuel project led to large sunk costs.
No matter the
availability and price of domestic wellhead gas in coming years, Panhandle's
midwestern distributors and main line customers'will bear some of these
investment costs because regulatory agencies will allow Panhandle to raise
prices to achieve a fair rate of return on all investments, good and bad.
Distribution utilities usually have little choice in paying increased
pipeline prices.
First, distribution utilities themselves have often signed
contracts containing high "takes" from transmission pipelines.
Distributors
served by interstate pipelines have agreed to contract terms under the similar
duress of anticipated shortages in supply that interstate pipelines
experienced in the 197.0s.
One additional market feature enhances the ability of pipelines to
pass on price increases to distributors.
Unlike petroleum pipelines, gas
transmission pipelines are not common carriers.
Hence, even if distributors
are not hampered by high "takes" of expensive pipeline gas, they are not free
to purchase less-expensive gas directly from producers because their pipeline
connection may refuse transport of this gas at reasonable prices.
Distribution utilities pass through price increases to final consumers of
gas in much the same manner that distribution utilities pass through price
35
increases in wellhead gas.
State public utility commissions usually maintain
their own versions of PGAs to reflect ongoing price increases resulting from
increased wellhead costs.
Despite the apparent ability of pipelines and distributors to pass higher
costs on to consumers, many pipelines and distribution utilities worry about a
cost squeeze resulting from recent slack gas demand and rising producer
prices.
Price increases by utilities and pipelines can be met by consumer
resistance in both the market and political arenas.
14
For example, voters in
Michigan recently passed a ballot issue to abolish automatic fuel and gas
adjustment clauses and to limit the number of rate cases the commission can
hear at one time.
Legal challenges by consumer groups can delay or minimize
expected price hikes by gas pipelines as state public utility commissions
become reluctant to increase allowable rates in the face of consumer outrage.
Transmission pipeline companies may confront similar difficulties in rate
cases held before the Federal Energy Regulatory Commission.
In addition to unyielding regulatory commissions, pipelines and
distribution utilities can suffer from sudden declines in demand as natural
gas prices approach parity with residual fuel oil.
In particular, industrial
customers often switch to fuel oil when it becomes more economical than gas.
These consumption swings force utilities to spread the fixed portion of
delivery costs (and take-or-pay provisions) over fewer customers thus raising
the delivered price of gas further still.
However, the greater the price
elasticity of demand for natural gas, the greater the consumption swing to
utilities resulting from changing prices. In some instances, price increases
of any magnitude cannot preserve a profitable position for pipelines or
utilities as total revenues decrease with loss of volume.
36
Many distribution utilities are attempting to design rate structures to
limit load loss by discounting rates charged to those customers with the most
elastic demand.
Typically, discounts are offered to industrial customers to
discourage their switching from gas to alternative fuels such as fuel oil or
to prevent actual plant closings.^
the general public.
These discounts are often unpopular with
But to the extent these discounts maintain a utility’s
volume of gas deliveries, the discounts can limit price increases to all gas
customers by spreading fixed costs and the operating costs of utilities over a
greater volume of customers.
State and federal authorities are often
reluctant to approve these price schemes, however, because such
price-discrimination practices may maintain high gas volume by imposing
proportionately higher prices on politically sensitive consumers, especially
residential customers.
Although all gas customers are vulnerable to rising gas prices,
residential customers may have the most cause for concern.
Residential gas
demand is generally more inelastic in response to price rises because these
customers are less able to substitute alternative fuels to reduce energy
bills.
In contrast, some industrial users, such as industrial boiler
customers, can easily switch to alternative fuels in response to gas price
hikes.
As industrial customers switch to alternative fuels, typically
residual fuel oil, the fixed costs of pipeline and distributor operations are
increasingly borne by commercial and residential customers.
Issues in the Current Policy Debate
Recent price increases and speculation over price jumps accompanying 1985
decontrol have greatly expanded public discussion surrounding gas policies.
In addition to concern over the increasing burden of higher gas bills, concern
over NGPA-induced inefficiencies has grown.
The Reagan administration has
37
directed energy policy toward a greater free market orientation.
Those that
favor free market policies, including immediate decontrol of all natural gas,
point out the market distortions and inefficiencies that NGPA has cost the
nation.
One inefficiency arises from NGPA's decontrol of deep-well gas that has
created a so-called "market-ordering" inefficiency in production.
Insofar as
deep-well gas remains free from price controls at the same time that other gas
prices are capped, some production of high-cost deep-well gas is exploited in
place of low-cost gas.
For an equal output of gas, fewer of society’s
resources could be spent by extracting gas under a single-price scheme.
This inefficiency is aggravated by pipelines’ average cost pricing
practices which foster extra-marginal bidding on deep-well gas.
Pipeline
companies use cost savings derived from low-cost, long-term gas contracts for
old gas as a cushion to bid in the deep-gas market.
As a result, much of the
cost-savings resulting from price limits on older vintages of gas are used to
subsidize extensive production of deep-well gas rather than to lower average
gas prices to gas customers.
A second perceived inefficiency stems the from regional allocation of gas
supply under NGPA pricing.
Pre-NGPA regulation redirected regional gas
consumption by capping interstate prices while ignoring intrastate prices.
This diverted gas supplies to the gas producing regions of the South and
Southwest.
Pre-NGPA regulation allowed intrastate prices to rise and
plentiful intrastate supplies followed.
The NGPA alleviates supply shortages in interstate pipelines by several
methods.
First, NGPA caps intrastate gas prices thus diverting greater
available ■ supply to interstate markets.
Second, gas production from federal
land on the outer continental shelf can no longer be sold to intrastate
38
pipelines.
This limits supply to intrastate markets and increases available
supply in interstate markets.
disparities among regions.
Third, NGPA harbors gas price "cushion"
Those pipeline companies
that are in the fortu
nate position of holding long-term contracts for cheap, old gas or that are
supplied by committed reserves of controlled interstate reservoirs hold a
larger price cushion to bid for decontrolled gas.
As a result, high-cushion
pipelines can supply greater quantities of gas to customers at a lower price.
To illustrate, consider two pipeline companies , A and B (Figure 3).
Suppose that both pipeline companies face the same customer demand and that
each company charges a single average price.
The pipelines differ, however,
in the amount of cheaper gas that was previously purchased under long-term
contracts at the old price Pqjj»
As shown in Figure 3, pipeline company A
receives the amount q° of old cheap gas in the present period while pipeline
a
company B can only buy cheap gas in the amount q°.
Any other gas supplied to
customers by pipeline companies must be purchased at the market-clearing,
decontrolled price Pnew«
To the extent that pipeline A averages a larger
quantity of cheaper gas into its price, it is willing to supply greater
quantities of gas at any given price.
Hence, Pipeline A’s average cost supply
schedule, AC , is lower than that of Pipeline B, AC, .
a
■
d
If pipeline companies
choose to purchase new gas up until the point where all customers are
satisfied with available gas at an average price, customers of pipeline A
receive total gas supply q
T
at the lower price P .
a
a
In contrast, if both
pipelines maintained the same cushion (the same amount of cheaper gas), gas
deliveries and price would be identical in regions served by pipelines A and
B.
Figure 3
Results of Inter-Regional Disparities in Quanities of
Price—Controlled Gas
V
\
40
Regional disparities in price cushions distort delivery, both between
intrastate and interstate pipeline areas and among interstate pipeline areas,
by directing supply to large-cushion regions.
Interstate pipelines tend to
hold greater price cushions than intrastate pipelines owing to a longer
history of regulation in that market.
pipelines can also be substantial.
The disparities among interstate
A 1981 Department of Energy survey reveals
that some interstate pipeline companies pay up to twice as much to acquire gas
compared to their counterparts with less expensive proportions of old, new,
and decontrolled gas.^
Although regional gas allocations are certainly redirected under NGPA
regulations, the NGPA allocation may well represent a significant improvement
over the pre-NGPA allocation.
Shortages and curtailments in gas delivery have
vanished from intrastate and interstate markets alike, though the present
recession and above-equilibrium gas prices may be largely responsible for the
current gas glut:.
The size of the old-gas cushion disparities between intrastate and
interstate pipelines will - increase under the present decontrol timetable.
Some categories of old intrastate gas are decontrolled in 1985 while old
interstate gas price controls remain, increasing the size of interstate
cushions of lower-priced gas.
To the extent that NGPA regulations distort the
free market location of gas delivery, advocates of accelerated decontrol argue
that-these inefficiencies should be removed to promote national economic
growth - and development.
Other advocates of accelerated decontrol point out that a potential
"fly-up" of gas prices in 1985 and beyond will throw gas-dependent commerce
into a tailspin.
As an alternative, accelerated decontrol will smooth out the
inevitable price hike, enabling commerce to more easily adjust to higher
41
prices over time.
In addition, accelerated decontrol will moderate future gas
price levels by bringing rational production incentives to producers.
For
example, one analyst forecasts that, in addition to smoothing price climbs
over the coming years, immediate decontrol will lower the eventual level of
prices confronting consumers by the latter 1980s.This assertion derives
from an estimated stifling of gas exploration under current NGPA guidelines.
Insofar as the NGPA decontrols wellhead prices for deep-well gas only,
companies explore and drill in some decontrolled fields with relatively lower
pay-offs in reserves than price-controlled fields.
As a result, lower
additions to gas reserves are estimated to ensue through 1985 under present
controls, raising the eventual price of natural gas.
Although some observers have advocated an acceleration of the NGPA
schedule since its inception, decontrol has gained recent momentum from the
current market conditions of slack demand and rising prices.
To the extent
that these market conditions indicate market prices above their
market-clearing levels, it is argued that accelerated decontrol can be
attained without a price increase to consumers.
To accomplish this end,
complementary legislation, such as permitting renegotiation of take-or-pay
contracts and amending PGA clause procedures, must accompany accelerated
decontrol.
At the same time that market inefficiencies have heightened the interest
of some observers for accelerated gas decontrol, others have increased their
support of continued controls under NGPA.
Some even go so far as to advocate
the extension of price controls beyond current NGPA mandates and the imposition of immediate price ceilings on all wellhead prices of natural gas.
18
It
is argued that consumers have suffered enough from recent gas price jumps.
The spectre of presently climbing residential and commercial fuel bills leads
42
to arguments that decontrol of gas awaits a future date, a date that is
approached by a long transition of gradually rising prices.
Views favoring
continued controls are largely based on the belief gas prices would indeed
rise under accelerated decontrol, much as prices have risen in the post-NGPA
era.
Whether or not the federal government moves to accelerate the NGPA
schedule of wellhead gas, other changes in regulatory policy will be con
sidered to make the gas■industry more responsive to falling gas demand.
These
include conversion of interstate pipelines to common carrier status so that
distributors and main line customers can choose among alternative suppliers of
natural gas.
Federal legislation to lower the obligations of pipelines to
take delivery of high-priced gas under existing contracts presents another
possible remedy.
In addition, the incentive for pipelines to voluntarily
renegotiate existing contracts and discontinue practices of selling high-
priced gas to customers when low-priced gas is available may be established by
making it more difficult for pipelines to pass along cost-increases of
wellhead gas through PGA clauses.
Both federal and state government will also consider rate designs that
allow pipelines and distributors to offer discounts to large industrial users
and electric utilities who are on the verge of switching from gas to fuel oil
consumption.
In the absence of properly-designed rate structures, load loss
may foist a larger share of pipeline and distributor costs of gas delivery
onto commercial and industrial customers.
As an alternative method of
restraining price increases to residential and commercial customers in the
face of excess delivery capacity, state regulators may decide to lower the
rate of equity return to pipelines and distributors by limiting the size of
future rate hikes in gas prices.
IV.
The Market Outlook Under Natural Gas Decontrol
Predictions of equilibrium price and consumption of natural gas under
decontrol are uncertain for several reasons.
First, removal of NGPA price
ceilings alone will not remove current contract clauses that may be preventing
possible declines in short-term prices.
Hence, consideration of decontrol
pre-supposes complementary legislation to allow renegotiation for existing gas
production.
Above and beyond this, freeing the restraints of current
regulations including wellhead price ceilings, FUA use restrictions and
incremental pricing, releases countervailing forces on demand and supply which
are difficult to measure.
Despite the difficulty in untangling the complex knot of current
regulatory forces, free market prices of gas can be loosely tied to the price
of substitute fuels.
To the extent that natural gas substitutes for other
fuels, such as residual fuel oil, price estimates of gas can be aligned to
existing market prices of these fuels.
Insofar as world petroleum prices are
volatile, price estimates beyond the near term become increasingly poor.
In
the near term, however, these prices serve as a probable indicator of market
prices for natural gas.
Using the average energy-equivalent price of residual
fuel oil as a barometer, it is doubtful that average natural gas prices in the
U.S. and in Seventh District states would rise significantly in response to
accelerated gas decontrol.
Market Effects From Removal of Regulations
The effects of deregulation on gas consumption and price under
accelerated decontrol are somewhat uncertain for several reasons.
First, over
the past 40 years, tight regulatory controls distorted gas production,
delivery, and consumption.
As a result, recent experience cannot foretell the
behavior of buyers and sellers confronted by market signals to produce,
44
conserve, and switch consumption among alternative fuels.
Second, the pre
ceding decade witnessed an enormous upheaval in energy markets due to
cartelization of the petroleum industry.
Both buyers and sellers are con
tinuing to adjust to ten-fold price increases.
Moreover, insofar as the
prices of all energy products tend to move in unison, continued volatility in
world oil markets lends additional uncertainty to gas price forecasts.
Finally, the world economy lies amidst the deepest recession since the 1930s.
Concurrently, the booming energy industry has slumped.
strength of economic recovery remain uncertain.
Both the timing and
For these reasons, acceler
ated natural gas decontrol may unleash market behavior that is accompanied by
either allied or countervailing market forces.
On the demand side of the market, gas decontrol will directly raise
demand by lifting remaining FUA restrictions on gas use by industries and
electric utilities.
quantity.
Generally, this would tend to raise market price and
In some regional markets, however, increased loads could spread
utility fixed costs over greater volume, actually reducing final prices in the
near term.
The elimination of incremental pricing to industrial customers will
encourage their consumption.
At the same time, however, elimination of
incremental pricing will tend to raise the price to residential customers,
discouraging gas consumption by this sector.
Depending on the elasticities of
demand and market shares among these groups of customers, lifting of FUA
provisions can either raise or lower the overall demand schedule for natural
gas.
In the past, regulatory provisions may have dampened gas demand in a less
direct fashion than by imposing use restrictions and incremental pricing.
Potential gas customers, especially industrial users, could not be assured of
45
adequate long-term gas supplies.
Price controls on wellhead gas foreshadowed
future shortages to users because producers might withhold gas from the market
in the event that controlled prices did not guarantee profits.
Wellhead price
controls also led to declining drilling activity and proven reserves, a
further warning of eventual shortages.
Insofar as residential customers
comprised a sizable market share, political realities indicated that shortages
would primarily impinge on industrial customers.
These market conditions,
along with direct user limitations on certain customers, indicate a present
pent-up, albeit uncertain, demand for natural gas by some industrial cus
tomers.
While decontrol of the natural gas market will tend to raise demand,
market forces that reduce demand may coincide with decontrol.
The demand for
all energy sources—including natural gas—has tended to become more elastic
(it has fallen) in response to the sudden energy price rises of the 1970s.
the near-term, demand is inelastic or unresponsive to price increases.
In
As
time passes, however, buyers discover substitute goods (including conserva
tion) for higher-priced commodities, and reduce demand in response to
increased prices.
This tendency occurs no less with energy than other goods.
Energy consumption declined by almost 4 percent from 1979 to 1980 and by
almost 3 percent from 1980 to 1981.
While it is difficult to ascertain the
extent to which current slack energy demand merely reflects a temporary
downturn in the world economy, the demand for gas may decline in response to
price increases of the past several years as energy conservation continues.
Similar to natural gas demand, the supply of natural gas can either
increase or decrease in response to decontrol.
positively to price increases.
Generally, supply responds
As the wellhead price of gas rose over the
1970s, however, evidence suggests that the supply response was generally
46
disappointing despite tremendous exploration and drilling activity.
From 1974
to 1981, the domestic average wellhead price of gas increased by over
eight-fold from 21.6 cents to $2.06 per thousand cubic feet, greatly exceeding
the rate of increase of overall prices.
In response to these price
incentives, new domestic gas well completions more than doubled from 7,240
wells in 1974 to 17,894 wells in 1981.
Unfortunately, the average production
capacity of new gas wells has greatly diminished over the past decade.
Additions to proven reserves have not kept pace with current production,
contributing to a declining stock of proven domestic gas reserves of almost 15
percent over the same period.
Although rising average wellhead price levels have not halted declining
domestic reserves, price structure rather than price level may be the cause.
Much of the observed increase in average price over the past few years
reflects the decontrolled price of deep-well gas which has climbed as high as
$10 per thousand cubic feet in comparison to regulated wellhead rates for new
shallow gas of only $2-3 per thousand cubic feet.
By encouraging exploration
of deep-well gas at the expense of other gas, NGPA may have lessened the
reserve payoff per average dollar of exploratory activity.
On the other hand, wellhead price ceilings on older vintages of gas have
stimulated overall production and exploration by channelling price savings of
pipelines from price-controlled purchases into price bids for deep-well gas.
Inasfar as transmission pipelines roll controlled gas prices into average
prices,, pipelines use the difference between average and controlled prices to
bid higher prices for decontrolled gas, stimulating production of these
categories.
For example in Figure 4-a, the domestic supply curve of gas is
represented by the marginal cost schedule, MC, of wellhead producers.
For
47
simplification, this schedule is composed of only two types of gas, controlled
gas and decontrolled deep-well gas,
A kink occurs in the MC schedule at price
Pc where controlled gas is not forthcoming at higher general price levels
because price controls render further production of this class of gas
unprofitable.
Beyond quantity q£, production'only represents the supply of decontrolled
deep-well gas.
Transmission companies attempt to fill desired demand at
average cost along the schedule AC where average cost at any quantity is a
price-weighted average of controlled gas and decontrolled gas.
This average
cost is represented below in equation (1):
(i) ac = pcqc + pd(q§_qc)
where pc is the average ceiling price of gas and qc the quantity of gas
forthcoming at the ceiling price.
The symbol p^ represents the price of
decontrolled gas and q*-qc the production from wells not under control.
These
latter amounts are assumed to be determined by competitive market behavior.
The price of decontrolled gas, pc, at any equilibrium quantity, such as q*,
can be read off the MC schedule.
Only at a price, such as p^ will additional
gas, q* - qc be forthcoming to satisfy consumer demand at the average price,
v
Total market deregulation will influence gas supply by moving toward a
more uniform price for all gas.
respects.
This will affect price and quantity in two
First, the average cost schedule will tend to coincide with the
marginal cost schedule at the present position of the MC line in figure 4-a.
Insofar as transmission pipelines no longer can use price cushions on
controlled gas to bid high prices on decontrolled gas, the price of deep well
gas will fall from pc to pc along the MC schedule to the intersection of
Figure 4
The Price Impact of Average Cost Pricing in the Presence of NGPA Price Ceilings
(a)
(b,
Pa = average price of gas in equilibrium under NGPA.
Pu = post-decontrol equilibrium price of gas if production of formerly-controlled
NGPA categories of gas remain constant after decontrol.
p' = post-decontrol price of gas assuming increased production of NGPA
categories that were formerly controlled.
q' = post-decontrol production of gas assuming increased production of
NGPA categories that were formerly controlled.
qu = post-decontrol production of gas if production of formerly-controlled
NGPA categories of gas remain constant after decontrol.
49
demand and ■ marginal cost while the price of decontrolled gas, pc> will rise to
the same unified price, p^.
to fall from q* to q^.
At the same time, marketed production will tend
On average, price has increased from p& to p^ and
production has declined from q* to qy.
As a second countervailing force,
however, the marginal cost schedule will tend to push further to the right as
the production of additional old shallow-well gas becomes profitable and
enters the market at a price higher than p£.
This is illustrated by a
rightward extension of the MC schedule beyond its present kink in Figure 4-a
to a position represented by the line MC'=AC’ in Figure 4-b.
Supply increases
will tend to lower average price to p’ and increase production to q*.
As constructed in figure 4-b, total market decontrol lowers average price
from pa to p* and increases marketed production from q* to q* .
These results
depend on optimistic assumptions concerning increased production of
newly-decontrolled categories of natural gas.
If, on the contrary, the new
market supply schedule, MC’=AC’, shifts outward to a much smaller degree, the
average price of natural gas will rise and production fall in the
post-decontrol period.
This latter scenario may be more likely in the period
following deregulation because a time lag may exist between the time of
deregulation and the time when exploration and drilling of price-decontrolled
wells start producing.
Nevertheless, increased supplies of newly-decontrolled
gas may immediately follow regardless of exploration-production lags if well
owners are withholding gas production in expectation of price decontrol.
The Price Effects of Decontrol on Average Price in the Seventh District
Despite the many market complications, some observers believe that the
price of gas will eventually settle at an energy-equivalent price of a close
substitute, residual fuel oil.
19
Low-sulfur residual fuel oil and its
50
residential counterpart, home fuel oil, substitute for natural gas as general
boiler fuel for producing heat.
Homes and commercial buildings burn both gas
and fuel oils for space heat; electrical utilities burn them to generate
turbines, manufacturers use both as a steam boiler fuel, and some industrial
users substitute either fuel for process heat equipment.
If fuel oil prices
remain in excess of gas prices to some final consumers, decontrol may be
accompanied by substitution of natural gas for oil up to the point where gas
prices are bid up to parity with oil at the burner tip.
In many regions of
the U.S., recent gas price increases have led to switching of fuel oil for gas
by industrial users and electric utilities.
On average, however, the national
price of gas at the burner tip presently remains below residual fuel oil.
The extent that gas price will approach parity with fuel oil under
accelerated decontrol crucially depends on the ability of gas to economically
replace fuel oil..
Potential customers may realize large costs in converting
to gas burning facilities.
If these costs are small enough so that some
conversion to gas still occurs, the end-user price of gas must remain below
fuel oil price to compensate new customers for conversion costs.
Gas prices
and consumption will rise but not to parity with fuel oil.
In the cost extreme, gas might not physically substitute for fuel in
enough applications to raise gas price or consumption to any significant
degree.
For example, within the transportation sector, gas cannot currently
replace oil in most uses because the internal combustion engine cannot yet
efficiently burn natural gas.
If the transport sector were the only energy
sector, the demand for gas would remain low relative to supply.
gas price would lie below fuel oil on an energy-equivalent basis.
Consequently,
In those
end-use categories of transport that were capable of burning gas, the low gas
51
price would induce gas conversion and completely crowd petrol use out of these
sectors.
In contrast, if enough end-users can quickly and easily switch from fuel
oil to natural gas upon decontrol, natural gas may rise to complete parity
with fuel oil.
Under this scenario, gas market decontrol eliminates excess
demand for gas by allowing producer and consumer prices to rise.
As prices
rise, some greater production ensues from high-production-cost producers.
At
the same time, higher prices ration greater available supplies to those
Buyers bid up gas
customers who are willing and able to pay market prices.
prices to oil price ' parity because it is economical to do so if gas prices
remain below oil parity.
In the short-term, there is even a possibility for natural gas prices to
overshoot residual fuel oil prices.
If certain classes of customers reduce
gas consumption in response to either recessionary business conditions,
moderate weather conditions, or to past price increases that encourage
conservation of energy, local utilities and transmission pipelines may attempt
to spread fixed costs over remaining volume by raising retail prices.
Price
levels that cover total utility costs may subsequently exceed the costs of
alternative fuels, such as residual fuel oil.
Short-term inelastic demand of
certain classes of customers, such as residential customers, will prevent loss
of the entire market and sustain higher-than-equilibrium price levels.
1 1
: t;('" foil ovi r o rb i •
,
+
i
*
■
52
moderate future price levels to all customers by preventing fuel-switching by
some categories of gas users.
From 1960 to 1972, the energy-equivalent prices of residual fuel oil and
natural gas remained close to parity.
Estimated gas price actually exceeded
fuel oil price for several years in the mid-1960s (Figure 5).
Over the last
few years, however, the latest OPEC-induced price hike, along with domestic
oil decontrol, have caused the price of residual oil to pull away from natural
gas.
Although this gap . has narrowed recently because of softening oil prices
and rising gas prices* the domestic price ' of residual oil remained almost 39
percent above the energy equivalent price of natural gas in 1981.
In the recent past policymakers have become concerned that gas price
decontrol would sharply lift gas prices to parity with residual fuel oil.
This suggested that decontrol be phased in gradually to defuse large and
sudden price hikes.
Recent evidence indicates that the sharp gas price hikes
to fuel oil price parity no longer lie at issue, except those that may arise
from indefinite price escalator contract clauses, because gas prices have
already soared beyond expectations.
In the Northeast Region (Maine, New
Hampshire, Vermont, Massachusetts, Rhode Island, Connecticut, New York, New
Jersey, and Pennsylvania), for example, natural gas price has settled at
parity or above for the last two years.
20
In other regions of the country, a
confluence of recent events brought gas prices close to parity with fuel oil
without natural gas decontrol.
The world recession has contributed to de
clining demand for all energy materials.
While this has brought fuel oil
prices tumbling down in recent months, gas■prices have continued to climb.
Climbing gas prices can potentially result from large fixed costs facing
utilities.
As volume declines, these costs are spread over remaining
customers.
Somewhat unique to the U.S. gas industry, these fixed costs
FIGURE 5
ESTIMATED PRICE OF RESIDUAL FUEL OIL AND NATURAL GAS, 1960—1981
X.OXJUJ J3C3_i_jcca:co\xxa«-^
TEAR
GAS“DIRMOND
OIL=STAR
SOURCE:AMERICAN GAS ASSOCIATION AND U.S.D.0.E.. STATE
PHYSICAL UNIT DATA BASE. TABLE P-3
Table VII
Estimated Parity Prices of Natural Gas and No. 6 Residual Fuel Oil
1981
Gas Price
($/mmbtu)
(dollars)
Illinois
Indiana
Iowa
Michigan
Wisconsin
U.S.
3.66
3.26
3.45
3.70
4.19
3.66
Fuel Oil Price3
($/mmbtu)
(dollars)
5.17
5.17
5.17
5.17
5.17
5.17
Percent difference
in Natural Gas Price to
Parity with Fuel Oil
(percent)
41
59
50
40
23
41
August, 1982
Illinois
Indiana
Iowa
Michigan
Wisconsin
U.S.
SOURCE:
4.46C
3.97
4.21
4.51
5.11
4.46
4.52
4.52
4.52
4.52
4.52
4.52
1
14
7
—
(-12)
1
American Gas Association and the U.S. Dept. of Energy.
aSource; DOE/EIA-0035 (82/12).
The conversion factor for No. 6 residual
fuel oil is 6.287 MMBTU/Barrel.
This monthly average is reported from the source as national average
retail residual fuel oil price, DoE/EIA-0035 (82/12). Again, it is assumed
that residual fuel oil sells for the national average price in all states.
^This column assumes that each regional 1981 gas price climbed to
parity to fuel oil, i.e. (column 2—column 1)/column 1.
c
The August, 1982, average retail price to all customers is
estimated as follows. All 1981 regional figures are expanded by national
percent Increase in average residential gas heating prices between the month of
August, 1982, and the year 1981. Average residential heating prices are sampled
by the Department of Commerce and reported in DOE/EIA-0035.
55
reflect "take-or-pay" contract provisions between pipelines and producers,
forcing pipelines to purchase gas they cannot profitably sell.
Also,
long-term contracts lock buyers into rising allowable ceiling prices under
Market price adjustment to equilibrium under current arrangements
NGPA.
appears to be slow.
Within the Seventh Federal Reserve District region, it is estimated that
if natural gas prices had risen to parity with residual fuel oil in 1981,
price jumps would have varied between 23 percent in Wisconsin to 59 percent in
Indiana (Table VII).
As a result of climbing gas prices and falling fuel oil
prices, much smaller price jumps in natural gas would have had to occur by
August, 1982, to achieve fuel oil parity.
In fact, estimates reveal that some
average gas prices in Wisconsin may already exceed parity with fuel oil.
portends large price increases to some residential consumers.
This
As industrial
customers switch to fuel oil, residential customers who have invested in gas
heating furnaces may come to bear a greater portion of utility fixed costs.
Conclusion
Insofar as natural gas prices have already approached approximate parity
with fuel oil within Seventh District states, accelerated decontrol of natural
gas would have limited , negative impact, on average, in this region.
Of
course, intra-regional variation in natural gas prices to consumers suggests
that higher gas prices would accompany accelerated decontrol in some areas
while lower gas prices would prevail in others.
Moreover, prevention of
general gas price increases under accelerated decontrol can only be accom
plished with complementary state and federal regulation.
At the federal
level, damaging contract provisions entered into during the past decade,
including take-or-pay provisions, must be amended to lessen pipeline costs of
holding unsold gas.
56
At the state level, public utility commissions need to evaluate potential
rate structures of public utilities that discount gas prices to certain
categories of customers.
Without such rate spreads in final gas prices or
reductions in equity returns to - utilities, residential customers may come to
bear excessive final prices for natural gas as possible load loss increases
the residential share of utility operating costs.
This concern is critical to
residents of Seventh District states, who largely depend on natural gas for
home-heating purposes.
VIII.
Conclusion
Past public policy actions attempted to balance the merits of controlling
prices to certain classes of natural gas consumers against the merits of
developing gas resources for the benefit of future customers and some present
energy users.
In the process, resulting market inefficiences in gas produc
tion cost the nation in overall national income.
Recent NGPA regulations do
not appear to have alleviated these costs to any significant degree and many
analysts have argued that recent regulations have actually exacerbated produc
tion inefficiences.
Although arguments of those supporting accelerated market
decontrol were persuasive, the spectre of sudden gas price jumps caused by
unexpected OPEC oil price increases contributed to delays in accelerating the
price decontrol timetable.
Npw, the events of worldwide recession, climbing gas price ceilings, and
post-NGPA contract provisions that ratchet gas prices to highest allowable
rates, have conspired to raise natural gas prices to approximate parity with
residual fuel oil in both the region and the nation.
With some caveats,
immediate natural gas decontrol would not lift prices much beyond
57^
a?
their current levels.
As one caveat, some existing contract terms between
transmission pipelines and wellhead producers stipulate that contract price on
gas jump to the highest price being paid 'on similar gas at the time of
decontrol.
To the extent that these priftes lie above equilibrium, pipelines
would attempt to pass greater costs onto’ffconsumers, especially if
producer-pipeline contract provisions inlUuded "take-or-pay" provisions on
wellhead gas.
Thus, accompanying Congressional amendment permitting
renegotiation of current contract terms and other regulatory features of the
NGPA would be necessary to forestall immediate and temporary price shocks
arising from market decontrol.
These same regulatory revisions must be
considered regardless of any acceleration of the NGPA decontrol schedule so
that the gas market can respond to declines in consumer demand.
State regulation of public utility pricing practices are also critical in
preventing accelerated decontrol from resulting in higher price levels.
State
public utility commissions should consider rate spread structures that allow
local gas utilities to discount prices to industrial customers.
Such rate
structures may be necessary to prevent price increases to residential
customers that result from loss of utility volume*.
However, these rate
structures can also raise prices to residential customers under some circum
stances if they are not'warranted or if they are not properly designed.
While the five Seventh District states are more dependent on natural gas
than other states, Seventh District prices appear to equal the nation’s
average.
In the absence of expected absolute or relative price rises, the
region need not fear any added competitive disadvantage from decontrol.
This
is not to say that gas prices will not rise anywhere within Seventh District
states.
Some prices will rise and others will fall.
Some firms with fragile
profit positions may suffer from the moderate price increase that may ensue
58
with accelerated decontrol.
Others will benefit from lower prices that result
from removal of take-or-pay provisions in contracts between pipelines and
producers.
In contrast to the mid-1970s, supplies of natural gas to Seventh District
firms and industries are plentiful.
NGPA provisions increase available supply
to interstate pipelines at the expense of intrastate pipelines serving gas-
producing regions.
Although this would seem to give a competitive advantage
to the Midwest region in securing industrial supplies of gas, other features
of the regulated gas market have left excess supplies in every region at
current prices.
Similarly, price ceilings favor interstate pipelines because
these pipelines control relatively larger stocks of gas at controlled ceiling
prices.
Nevertheless, other market features have led to price levels in the
Seventh District that do not differ from the national average.
At best, the Seventh District receives only short-term and small advan
tages over other regions from the overall structure of national gas policy.
These benefits are not justified by the absolute damage caused by NGPA to the
natural gas market and the nation's overall energy policy.
By increasing the
nation's productive efficiency in gas production, accelerated decontrol can
aid the region by securing adequate future supplies at reasonable costs,
increasing national income, and pressuring world energy markets into
submission toward lower prices.
In this regard, bringing rationality to
national energy markets presents a modest but effective Midwest development
policy ,in reviving this older industrial corridor.
59
FOOTNOTES
*See The Current State of the Natural Gas Market,Part I, DOE/EIA-0313,
U.S.G.P.O., Washington, D.C., December, 1981, pg. 68.
2
This history borrows heavily from The Current State of the Natural Gas
Market, ibid.
3
Phillips Petroleum Company v. Wisconsin, 347 U.S. 672 (1954).
AIbid, DOE/EIA-0313, Pg. 10.
“See Appendix I for exact classifications and scheduled decontrol.
g
Recent trends indicate that the actual figure will lie closer to 60
percent or more.
See Analysis of Economic Effects of Accelerated Deregulation
of Natural Gas Prices, DOE/EIA-0303, August, 1981, for estimates under a
variety of assumptions concerning the 1985 statutory and regulatory
environment.
For estimates of controlled quantities of natural gas through
1990, see The Current State of the Natural Gas Market, Part I, Table II.
?See The Current State of the Natural Gas Market, Part II, for an
extensive discussion of recent contract terms and their implications.
For contract quantities covering post-NGPA wells, contracts covering
approximately 59 percent of contract volume of post-NGPA wells have
deregulation classes, ibid, p. IX.
g
More recent trends are toward "market out" provisions in new gas con
tracts. Market-out provisions permit the buyer to cancel contracts if the gas
delivery is not marketable at redetermined prices.
9
These figures and those that follow may be found in the Monthly Energy
Review, DOE-0035(83/01), January, 1983.
lOlbicl. Part II, page. 41.
^On December 30, 1982, the FERC ruled that Columbia Gas Transmission
Corp. must refund $100 million■or more to customers residing in Northeastern
states because the pipeline had purchased excessive quantities of high-priced
gas while reducing purchases of cheaper gas.
12
If a pipeline takes delivery of gas, it can promptly pass the costs
along to consumers through a PGA.
If not, the pipeline must recover these
costs later in a rate increase. If a pipeline must choose between delivery of
a low-priced and high-priced shipments covered by take-or-pay agreements, it
may choose delivery of high-cost gas and suffer prepayments on the low-priced
gas in order to preserve cash flow. Nevertheless, it is not certain that
pipeline profits are always maximized by such a choice*.
13
See "Panhandle Eastern: A gas-shortage gamble is blowing up in its
facie", Business Week: May 24, 1982, pp. 106-110.
60
Fifteen midwestern gas utilities, 28 Michigan industrial concerns, and
prominent political leaders from Michigan and Ohio have petitioned FERC to
rescind Panhandle’s authorization to purchase Algerian LNG. Even if this
petition proves successful, a loss of over $500 million in a Louisiana
unloading facility will be borne by customers and possibly by shareholders.
Consumer groups have also criticized FERC for approving transmission pipeline
rate increases without close scrutiny of rate hike justification.
Insofar as these companies can easily pass along cost increases to local
utilities via PGAs, it is contended that pipelines have little incentive to
bargain for cheap wellhead prices or to economize on careful long-term supply
planning.
In response, FERC has stated that it will review future PGAs with
closer scrutiny. This suggests that shareholders of pipeline utilities may
come to bear greater risks from investment ventures and wellhead contract
negotiations.
l^For example, Northern National Gas Company of Omaha has asked the FERC
for approval on price breaks to Iowa fertilizer (anhydrous ammonia) producers
who face shutdowns in plant operations because of natural gas price hikes.
See "High Natural Gas Prices Cripple Iowa Fertilizer Industry”, Des Moines
Register, October 10, 1982.
Among Seventh District states, fuel switching appears to be most severe
in Wisconsin. Wisconsin Gas Company began charging prices higher than that of
residual fuel oil on November 1, 1982. See "Feared shift to oil may be bad
news for gas customers", Milwaukee Journal, Section 2, pg. 1., October 3,
1982.
16Ibid., DOE/EIA-0313, Pg. 66.
l^See Paul W. MacAvoy, "The Time to Deregulate is NOW", New York Times,
September 26, 1982, pg. 73.
18
Numerous bills that placed new lids on wellhead prices were introduced
into the post-election session of the 97th Congress. None were enacted into
law.
19
For example, see Robert A. Leone, "Natural Gas Decontrol and the
Northeast Economy", paper presented . at the Western Economic Association
Meetings, July, 1982.
20
See Kalt, J., Lee, H., and Leone, R.A., Natural Gas Decontrol: A
Northeast Industrial Perspective, Energy and Environmental Policy, Harvard
University, Cambridge, 1982.
The authors suggest that decontrol can only help the Northeast region by
eliminating the energy cost advantage of other regions.
APPENDIX I
Natural Gas Policy Act Maximum Gas Ceiling Prices
Section
of Act
Ceiling
Description
January 1983
Ceiling Prices
Date of
Per Million
Btu
Deregulation
New Natural Gas
102
$1.75 as of 4/20/77
plus monthly inflation
and inflation and
escalation adjustments
$3.299
1/1/85
- New onshore wells at least 2.5 miles from
nearest marker well or at least 1,000 feet
deeper than any completion within 2.5
miles.
1/1/85
- New onshore reservoirs
1/1/85
- New Outer Continental Shelf (offshore)
leases effective on or after 4/20/77.
Not Deregulated
- Reservoirs discovered after 7/27/76
on old offshore (OCS) leases
New Onshore Production Wells
103
$1.75 as of 4/20/77 plus
monthly inflation
adjustments
Gas Category
$2.722
- Wells with surface drilling starting
after 2/19/77, satisfying applicable
Federal or State well-spacing require
ments and that are not within a pro
ration unit
el/l/85
- gas from wells deeper than 5,000 feet
e7/l/87
- gas from wells shallower than 5,000
feet
APPENDIX I (Continued)
Natural Gas Policy Act Maximum Gas Ceiling Prices
Section
of Act
104
Ceiling
Description
January 1983
Ceiling Prices
Per Million
Btu
Date of
Deregulation
Gas Category
Gas Dedicated to Interstate Commerce Before the NGP Enactment Enactment (11/9/78)
$2.254
the just and reasonable
price as of 4/20/77 plus
monthly inflation adjustment
b$l.908
Not Deregulated
- Post-1974 gas
Not Deregulated
- 1973-1974 Biennium gas
Not Deregulated
- Flowing gas
Not Dregulated
- Certain Permian Basin Gas
Not Deregulated
- Certain Rocky Mountain Gas
Not Deregulated
- Certain Appalachian Basin Gas
Not Deregulated
- Minimum Rate Gas
c$1.459
b$ .539
C$ .424
b$ .640
c$
.562
b$0.640
c$0.539
b$0.508
c$0.475
1$0.280
Gas Sold Under Existing Intrastate Contracts
105
The lower of (a) the contract
price under the contract terms
as of 11/9/78 (b) the Section
102 price.
The higher of (a) the contract
price as of 11/9/78 plus monthly
inflation adjustment and (b) the
Section 102 price
f1/1/85
f1/1/85
- If contract price was less than
$2.078 on 11/9/78
- If the contract price was more than
$2.078 on 11/9/78
APPENDIX I (Continued)
Natural Gas Policy Act Maximum Gas Ceiling Prices
Section
of Act
January 1983
Ceiling Prices
Per Million
Btu
Ceiling
Description
Date of
Deregulation
Gas Category
Sales: of Gas Under "Rollover" Contracts
106
The higher of (a) the just
and reasonable price as of
the rollover date plus
monthly inflation adjustment
and (b) $.54 as of 4/77 plus,
monthly inflation adjustment
The higher of (a) the price
$ .837
8$i.553
Not Deregulated
^1/1/85
- Interstate
- Intrastate
paid under the expired con
tract as of the rollover date
plus monthly inflation adjust
ment or (b) $1.00 as of 4/77
plus monthlj,inflation
adjustment.
High Cost Natural Gas
107
Section 102 price or higher
incentive price.
market price
11/1/79
- Gas produced from wells 15,000
feet or deeper drilled
Otherwise applicable
or higher incentive price
market price
11/1/79
- Gas produced from geopressured
brine, coal seams and Devonian
Shale
$5.444
Not Deregulated
- Gas produced from tight sands
Section 109
price
Not Deregulated
- Qualified production enhancement (only for 105 gas)
APPENDIX I (Continued)
Natural Gas Policy Act Maximum Gas Ceiling Prices
Section
of Act
Ceiling
Description
January 1983
Ceiling Prices5
Per Million
Btu
Date of
Deregulation
Gas Category
Stripper Well Natural Gas
108
$2.09 as of 5/78 plus
monthly inflation and .
escalation adjustments
$3.535
Not Deregulated
- Nonassociated natural gas produced at an
average rate less than or equal to 60,000
cubic feet per day over a 90 day period
Other Categories of Natural Gas
109
$1.45 as of 4/77 plus
monthly inflation adjustment
$2,254
Not Deregulated
- Prudhoe Bay gas
- Gas not otherwise covered
0
Beginning 1/1/85, gas from wells shallower than 5,000 feet receive a price midway between the price specified
by this formula, and the 102 price.
^Small producers - independent producers not affiliated with a Class A natural gas pipeline company whose total
jurisdiction sales on a national basis, including those by affiliated producers, do not exceed 10 Btu on a 14.73
pressure basis.
Q
Large producers - producers that are not small producers.
^Ceiling prices may be raised if just and reasonable.
Interstate production from 103 wells on dedicated acreage committed on 4/20/77 is not deregulated.
^If contract price exceeds $1.00 by 12/31/84, except a price established under an indefinite price
escalator clause.
®0r expired contract price, whichever is higher.
^If the price is more than a dollar on 12/31/84.
^Natural gas production in which a state government or an Indian tribe has royalty or other
interest is to receive the Section 102 price if it was not committed to interstate commerce
on 11/8/78.
^High-cost gas provisions elective, i.e., do not apply if special tax provision are
utilized.
k
These prices have been escalated monthly, in addition to the inflation adjustment factor,
by 3.5 percent annually.
Starting April 1981 they escalated by 4 percent annually.
^Dollars per thousand cubic feet.
SOURCE:
The Current State of the Natural Gas Market, Part I, EIA/DOE and U.S. Federal
Energy Regulatory Commission, Docket No. RM80-53, (Issued Oct. 21, 1982).
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@FedFRASER