Order Code RL30815
CRS Report for Congress
Received through the CRS Web
Natural Gas Prices:
Overview of Market Factors and Policy Options
January 23, 2001
Specialist in Energy Policy
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress
Natural Gas Prices: Overview of Market Factors and
Natural gas prices increased steadily during 2000, as demand for gas-fired
electric power production grew sharply. When cold winter weather arrived, heating
demand – coupled with ongoing electric power demand – drove spot prices up. In one
short-lived and isolated episode, gas touched $30 per thousand cubic feet (mcf) – the
energy equivalent of $175 per barrel oil.
Residential customers rarely buy spot market gas themselves. At the start of
2001, they were paying just over $9 per mcf for delivered gas on a nationwide
average basis, an increase of 39% from a year ago. It is likely that this price will be
higher when January 2001 bills are mailed to consumers, as spot market prices have
remained high. Most gas supply arrangements only offer short-term protection against
price volatility; they ultimately converge on spot prices.
Large commercial, industrial and electric generation consumers generally procure
their own gas supplies and arrange for transport. Since they do not have to pay local
utility distribution charges, these big users pay less for delivered gas. For 2000,
industrial and utility users paid about 40% of residential levels.
Low wellhead prices and deregulated long-distance transport costs led to
growing demand during the 1990s. Demand – which grew 36% from its 1986 low –
reached a peak in 1996 and 1997. Most notable was demand from gas-fired electric
power plants, where consumption rose by almost 50% during the 1990s.
Warmer winters in 1998-99 and 1999-2000 kept gas demand low, and masked
a decline in supply; as U.S. gas output fell about 9%, prices remained stable until
2000. Another mitigating factor has been growing imports from Canada, which helped
offset most of the domestic output drop. Imports held prices steady into 2000, when
the growth in demand interacted with inelastic supply and prices rose sharply. LateJanuary spot prices are in the $7 to $8 range, plus transportation and distribution
charges. If average flowing gas prices converge on spot, current markets suggest that
residential prices, for example, could rise by another $1 to $2 per mcf.
How might the present supply-demand relationship be resolved so that prices
return to more accustomed levels? On the supply side, it is likely that U.S. production
will increase as the number of wells being drilled has doubled during the past 12
months. More output should flow in response to higher prices. More imports of
liquefied natural gas (LNG) are being planned at four existing terminals.
With regard to energy policy, the discussion has barely begun. Policymakers
may focus on the role of gas in power production, producer incentives – including
making more federal lands available and tax incentives – and conservation measures.
And the impact of price on demand has not come to its full effect. The combination
of increased production and price-induced conservation might balance supply and
demand at a more comfortable price level.
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Natural Gas Industry Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wellhead Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-Distance Pipeline Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . .
Local Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current Price Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Gas Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Gas Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Domestic Reserves and Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Other Supply Options
General Policy Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
List of Figures
Figure 1. Natural Gas Consumption Imports and Production, 1973 - 2000 . . . . 5
Figure 2. Natural Gas Wells by Year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
List of Tables
Table 1. Natural Gas prices by Customer Class, 1995 to 2000
Table 2. Gas Consumption by Sector (tcf) - 1985 and 1999 Compared . . . . . . .
Table 3. Natural Gas Used to Generate Electric Power, 1989 and 1999 . . . . . .
Natural Gas Prices: Overview of Market
Factors and Policy Options
Natural gas prices have risen sharply during the past year, following a 15-year
period of adequate supply and relatively low prices. That extended period of low
prices followed a severe price spike during the late 1970s and early 1980s, when
natural gas was thought to be such a finite resource that the federal government began
restricting its use. The high prices of the early 1980s led to increased supply and
reduced demand, causing prices to fall. Low prices and plentiful supply persisted
through the late 1990s, despite growing demand for gas-fired electric power
During the 1990s, the total supply of natural gas from U.S. production and
imports grew steadily until 1996. Domestic production declined by about 5% between
1996 and 1999, and imports – chiefly from Canada – do not appear to have risen
enough to completely make up the difference. Despite the slightly lower apparent
supply and underlying demand that may well be growing, prices remained stable until
2000. An imbalance between “normal weather” supply and demand, with
accompanying price increases, may have been postponed by rising imports and warm
winter weather during the late 1990s.
By the second half of 2000, however, steadily growing gas demand by new gasfired power plants began to consume the gas supply left over from the warm winter.
Much of the supply that might have gone into storage for the current winter was
burned. As winter 2000-2001 approached, power demand remained strong and prices
began to rise sharply.
How much will prices rise? Late-month 2000 data have not yet been tabulated.
Many consumers are using gas acquired by distributors in 2000, at what amounts to
last year’s prices. Spot market transactions at very high prices are known to have
taken place, but so far they represent incremental purchases. The question becomes
how long will it take for the average price of flowing gas to catch up with the spot
market’s price leadership. And what might the average price of flowing gas be as the
peak winter season winds down?
This report describes the market factors that are influencing the current natural
gas situation, outlines the structure of the natural gas industry, and discusses policy
options for Congress. New sources of supply will be important in bringing prices
down in the long term, but not for winter 2000-01. How quickly such supplies can be
brought on line is difficult to predict. Demand-side options – especially priceinduced conservation – may also help in the long run.
Natural Gas Industry Structure
Natural gas is purchased by residential consumers in a manner different from that
of larger industrial and commercial users. Nearly all homeowners buy gas from a
state-regulated local distribution company (LDC), while larger customers generally
purchase gas directly from producers or wholesale marketers. For a typical residential
or small commercial consumer, gas bills consist of three components: the wellhead
price, the long-distance transportation cost, and local distribution costs, which are
discussed below in turn.
Most large industrial and commercial gas users and electric power generators
buy gas from producers or market makers and arrange pipeline transportation
themselves. They may be located adjacent to a long-haul pipeline route, own a
connecting pipeline, or have an arrangement for delivery via an LDC.
Natural gas producers find reserves, drill wells, and produce and gather the gas
and put it in marketable condition. Producers’ prices are determined in the
marketplace by the interaction of supply and demand. Federal price controls existed
for a number of years, but for the most part ended in 1985. The small amount of gas
that remained under controls was deregulated in 1989.
Producers sell gas to a variety of ultimate consumers as well as broker/trader
intermediaries, gas "clearing houses," and other entities playing a market maker role.
Gas ultimately sold to consumers moves under a variety of contractual arrangements
that fall into two broad categories. Gas may be sold under contract in which amounts,
duration, and prices are specifically spelled out. Or gas may be sold on the spot
market, where the owner auctions a package of gas at a specific location for the price
prevailing at that time and place. There are numerous trading centers at various
pipeline system nodes around the nation, and during times of market volatility they
can be the scenes of frenetic trading activity for gas that is promptly available.
Most gas moves under contract of one sort or another. But contracts are either
finite in duration or provide for periodic price adjustment to reflect market conditions.
It is the exception rather than the rule for a gas contract to provide below market
prices for a sustained period.
Long-Distance Pipeline Transportation
Long-distance pipeline transporters are the next step from gas field to consumer.
Under Federal Energy Regulatory Commission (FERC) Order 636, most pipeline
rates are set based on competitive forces in the marketplace. While rates are not
regulated directly, FERC reviews the filed tariffs of pipeline companies to ensure that
they are "just and reasonable" as well as nondiscriminatory. In the exceptional case
of pipeline systems without competition, FERC may set rates, using a traditional
public utility accounting regulatory format.
Buyers and sellers arrange for pipeline capacity to transport their gas to market;
the purchaser pays the pipeline its transport tariff. Gas buyers may also contract for
ancillary services – such as storage (often pipeline owned) – en route.
In some transactions, pipelines deliver gas to customers located directly along
the pipeline right of way or near enough to a customer-owned pipeline. In other cases,
gas is delivered to a local distribution utility from the long-haul pipeline dropoff point
(often referred to as the city gate).
The local distribution company (LDC) operates an intrastate utility – regulated
by the state public utility commission – that delivers gas from the city gate to
residential, commercial, and industrial users along its route. It usually purchases gas
for resale to residential consumers. Generally speaking, non-residential LDC
customers may also buy gas – not just transportation of gas they have bought on their
own – from the LDC; for some, this is an attractive alternative to procuring gas
supply and arranging transport on their own.
An LDC's rates and tariffs are formulated by the state regulatory body to recover
the gas utility’s operating and capital costs and its gas acquisition costs, and to earn
a return on capital invested in plant and equipment. Gas acquisition cost recovery is
typically handled through a mechanism called the purchased gas adjustment (PGA)
clause, which passes through increased (or decreased) gas acquisition costs to gas
customers. During times of rapidly rising gas prices, the PGA can become a focal
point of consumer concern, as it has this winter.
Current Price Trends
The last half of 2000 and the beginning of 2001 have seen a sharp escalation in
gas prices. Residential prices have caused a great deal of concern among residential
customers. According to the U.S. Energy Information Administration (EIA),
residential gas prices have risen from an average of $6.51 per mcf in December 1999
to $9.04 on January 4, 2001, an increase of 39%. Higher prices – coupled with higher
consumption due to colder winter weather – have resulted in much higher heating
bills. EIA's breakdown of recent residential gas prices shows that only 35% ($3.16)
of the $9.04 average price is for the gas itself, and 47% ($4.25) for LDC tariffs. The
remaining 18% ($1.63) is for long haul-transport.1
But these data may lag fast-moving developments in gas markets. Today's prices
– for which bills have not yet been mailed – may be higher than they were a few
weeks ago. Spot market reports from nodal trading points around the country have
commodity prices – without distribution or substantial transport costs – in the $8.00
to $10.00 per mcf range. Very short-term readings have been as high as $39.00 at the
New York city gate on December 29, 2000; other trades at pipeline systems have
EIA, Natural Gas Status Report, January 18, 2001
recorded similar, transitory pricing situations. Southern California – where gas
demand is especially high because of electric power needs – has also experienced such
Table 1 shows producer gas prices at the wellhead as well as prices for other
consumer classes. Because year 2000 data are year-to-date as of September, and do
not reflect substantial late-year price increases, these data are historical and may
understate current gas prices.
Table 1. Natural Gas prices by Customer Class, 1995 to 2000
Source: EIA Natural Gas Monthly, Table 4.
These data do show 5 years of price stability, running through 1999; they do not
show a preparatory price ramp to the current situation. Even year 2000 data do not
fully encompass real-time pricing. For all users, each month’s gas bill represents
completely new and unexpected pricing.
U.S. natural gas consumption trends have changed direction dramatically since
1973. Figure 1 traces a 25% decline in consumption from 1973's 22.0 trillion cubic
feet (tcf) to a bottom of 16.2 tcf in 1986. The downtrend in gas consumption then
reversed, with rising consumption reaching its historic (1973) peak in 1996 and 1997.
Between 1986 and 1996/7, consumption increased 5.8 tcf (36%). Virtually half of
increased demand was supplied by imported gas, which rose by 2.8 tcf between 1986
and 1997. During 1998 and 1999, gas consumption declined slightly from its highest
levels, a likely result of warm winter weather.
Figure 1. Natural Gas Consumption Imports and Production, 1973 - 2000
Table 2 shows an overview of gas demand in the main consuming sectors, contrasting
use in 1985 with 1999's consumption and identifying the high growth sectors since the
recovery of gas demand. Of special note is the 3.4 tcf increase in industrial consumption,
because it includes the fast growing non-utility power generating industry.
Table 2. Gas Consumption by Sector (tcf) - 1985 and 1999 Compared
Source: EIA, Natural Gas Annual, 1999, and author’s calculations.
In 1989, DOE began to account for gas consumed to generate electricity as a separate
item so that all gas used to generate electric power would be shown in the same data series.
Table 3 shows the growth of non-utility (unregulated) and utility gas-fired power plant
Table 3. Natural Gas Used to Generate Electric Power, 1989 and 1999
Source: EIA, Natural Gas Monthly, Tables 4.5 and 7.6
Between 1989 and 1999, gas used in power production in unregulated and utility plants
grew from 4.0 tcf to 5.9 tcf, a jump of 1.9 tcf. By 1999, independent power producers’
consumption accounted for 47% of the gas used to produce electric power. Further EIA data
for the first 9 months of 2000 show that independent power producers’ gas use was 37%
higher than the comparable 1999 period.
High rates of growth for unregulated power generators’ gas consumption are an
important consideration in evaluating future gas demand. Many firms have built combinedcycle gas turbine plants during the past 6 or 7 years and they have come on line just in time
to supply increased electric demand. A primary source of electricity to meet growing power
demand, these plants’ call on natural gas supplies will likely grow in the next several years.
In fact, EIA data show that gas fired power production – including the output of cogenerators
– provided 17% of total-kilowatt hours produced in 1999; in 2005 it is forecast to have
grown by 42%, providing 22% of the nation’s electricity. 2
While consuming a sizable part of U.S. gas supply, natural gas-fired generation has a
number of benefits. Among them is the fact that gas-fired plants can be constructed faster than
other power facilities, an advantage in this time of power shortages. Additionally, gas plants
have environmental advantages, especially when compared to the alternative of coal plants.
They produce fewer emissions of both pollutants and greenhouse gases.
Most U.S. natural gas supply comes from domestic sources, either from on-shore wells
or the outer continental shelf. In addition to domestic production, the United States imports
nearly 16% of its current gas supply by pipeline from Canada and liquefied natural gas (LNG)
from Algeria and Trinidad. Growing international trade in LNG could point toward a future
world market for natural gas, as currently exists for crude oil.
EIA, Annual Energy Outlook, 2001. Table 8A
Domestic Reserves and Production
Increased demand has steered the policy debate toward discussion of proven reserves
and what sort of incremental demand might be supported by the nation's resource base.
Proven gas reserves have held steady between 1989 and 1999, starting and ending the period
at 167 trillion cubic feet,3 an amount equivalent to slightly less than 9 years of production.
EIA contends there is much more gas to be found in the United States, and that those
discoveries will sustain the current level of proven reserves and support output for many
years. It estimates that technically recoverable resources amount to 1,279 tcf (the equivalent
of 58 years of consumption at current rates) in the lower 48 states and Alaska.4
While gas may be produced in conjunction with crude from oil wells, gas largely comes
from gas-only wells. Figure 2 shows the trend in the number of gas wells drilled since 1973.
Figure 2. Natural Gas Wells by Year
(thousands of wells)
EIA, U.S Crude Oil, Natural Gas and Natural Gas Liquids Reserves, 1999. Annual Report,
Drilling activity picked up after 1973 as gas prices rose and remained high until oil and gas
prices dropped in 1985. Gas drilling did not pick up again until the mid-1990s. Despite a
setback in 1999, drilling remained strong through 2000, with higher prices driving the number
of wells back to pre-1985 levels. The number of active rigs drilling for gas increased from 496
in 1999 to 706 for the first 11 months of 2000.
With gas well drilling headed back up to levels not seen for 15 years, it would seem as
if there were adequate incentives and enough attractive prospective territory to foster a high
level of drilling activity. Given that the amount of drilling in the last half of 2000 was twice
that of the first half of 1999, much of the increased gas supply resulting from those efforts
should be available on markets sometime during 2001.
Other Supply Options
Other potential sources of increased supply include additional LNG imports and
production of Alaskan gas. LNG imports are already growing, sparked by higher prices.
There are four receiving facilities in the United States, located at Boston MA, Cove Point,
MD, Elba Island, GA, and Lake Charles, LA. Cove Point and Elba Island are currently
mothballed. Most current interest centers on Elba Island and Lake Charles. Cove Point is
reportedly attempting to start up in 2002, but details are sketchy.
Platt's Oilgram News reports that El Paso Energy is currently seeking approval to reopen
the facility in Georgia, which has been shuttered since 1980.5 The terminal was included in
the purchase of SONAT by El Paso in 1999. Were FERC to fast-track the regulatory process,
El Paso claims that it could be receiving spot cargoes by year-end; the plant is scheduled to
receive its first imported gas from Trinidad in 2002. El Paso has also applied to FERC to
Trunkline, operator at Lake Charles, has expressed interest in expansion also, having
been able to procure spot cargoes from Qatar, Algeria, Nigeria, Australia, Oman and Abu
Dhabi. With world LNG trade in its early stages, it seems as if recent energy market
conditions have given the infant industry a boost.
One potential barrier to early startups is a possible shortage of LNG carriers. Worldwide
interest in LNG is so strong that the current fleet, which includes many aging vessels, is
Alaskan natural gas could be a longer-term supply option. Construction of a gas
transport system to bring Alaskan gas to the lower 48 states would take several years once
a decision were made to move forward. Substantial proven reserves are said to exist in and
around the Prudhoe Bay field that produces a large share of Alaska's North Slope (ANS)
crude. These reserves are currently classified as non-commercial because the gas cannot be
transported to markets.
On September 18, 2000, the Senate Energy Committee held oversight hearings on
alternative routes to bring the stranded gas to market. While formal proposals have not been
Platt’s Oilgram News, U.S. LNG Operators Look to Grab Bigger Piece of Market,
December 27, 2000.
announced by the firms owning production rights to ANS gas, three routes have been
discussed. Two would go overland, crossing Canada and intersecting with its gas pipeline
system. These plans would bring Alaskan – and perhaps more Canadian – gas to the U.S.
upper Midwest. Also under discussion is an LNG route along the Trans-Alaska Pipeline
System right of way that would bring gas to liquefaction facilities at the port of Valdez for
ocean transport to the West Coast ports or abroad.
The Alaska gas proposals need FERC approval, a right of way across federal lands, and
approval of Canadian governmental bodies if the transit Canada. Congress may be called upon
to pass legislation granting a right of way, as was done with for the TransAlaska Oil pipeline
System, when it enacted the Trans Alaska Pipeline Act of 1973.
In addition to these hurdles, any Alaska gas project viability would depend on gas prices
remaining high in end-user markets.
General Policy Options
Up to this point, gas price hikes are just beginning to flow through to many end users,
and the full impact of this winter’s higher prices has not been fully realized. As the end of
January 2001 approaches, and gas bills covering a period of cold winter weather arrive, the
intensity of public concern felt will increase and the policy debate will likely heat up.
Increasing intensity in the policy discussion will likely identify more policy options – and more
tightly focus the details of those being discussed – to deal with what could become a crisis.
But at this writing, there are scant options under discussion for dealing with the gas price
problem in the near-term.
Looking toward what might be debated in this Congress, the one short-term option that
may receive legislative attention is additional funding for the Low Income Home Energy
Assistance Program (LIHEAP),6 which may be needed because of both higher energy prices
and cold weather. Whether further incentives to drill for gas–inherently longer term measures
– are considered may be affected by strong response in the number of gas wells being drilled
to date. It may well be that such an initiative is considered later in the debate.
In a similar vein, Congress may debate opening federal lands not now available for
exploration. These could include areas on-shore in the lower 48-States, as well as Alaska,
possibly the Arctic National Wildlife Refuge (ANWR), and off-shore areas not now available
for leasing. Alaskan gas supply requires construction of a transport system, crossing federal
and possibly Canadian land.
Additionally, the Department of Interior will begin work on the next 5-year plan for
leasing on the outer continental shelf (OCS). It will be receiving input – and revisiting
leasing policy – regarding which tracts should be made available for exploration during 2003
For more information see CRS Report 94-211: The Low-Income Home Energy Assistance
Program(LIHEAP), by Melinda Gish. Updated January 8, 2001
The LNG option may also be addressed. Among the policy options are fast-tracking
regulatory approval for the refurbishing and expansion of the four existing facilities. A related
issue is the construction of new, specialized LNG vessels, perhaps by U.S. shipyards.
Finally, measures regarding conservation, electric power plant gas use and gas producer
issues such as a windfall profit tax at the wellhead could figure in the policy discussion.
In closing this policy summary, it should not be overlooked that the confluence of market
forces may well resolve the gas price problem. There is some chance that more production
will result – perhaps by next winter – from the step-up in drilling. Taken together with price
induced conservation and some extra imports, this might be sufficient to balance supply and
demand at a more comfortable price level.