Natural Gas: Analysis of Changes in Market Price (18-DEC-02,
GAO-03-46).
During the winter of 2000-2001, the wholesale price of natural
gas peaked at a level four times greater than its usual level.
Responding to the congressional interest and concern caused by
these high prices, GAO undertook a study to address the (1)
factors that influence natural gas price volatility and the high
prices of 2000-2001; (2) federal government's role in ensuring
that natural gas prices are determined in a competitive, informed
marketplace; and (3) choices available to gas utility companies
that want to mitigate the effects of price spikes on their
residential customers. GAO surveyed a nationwide sample of gas
utilities and staff of state utility regulatory agencies.
-------------------------Indexing Terms-------------------------
REPORTNUM: GAO-03-46
ACCNO: A05736
TITLE: Natural Gas: Analysis of Changes in Market Price
DATE: 12/18/2002
SUBJECT: Natural gas
Natural gas prices
Price regulation
Prices and pricing
Public utilities
Utility rates
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GAO-03-46
Report to Congressional Committees and Members of Congress
United States General Accounting Office
GAO
December 2002 NATURAL GAS Analysis of Changes in Market Price
GAO- 03- 46
Price spikes occur periodically in natural gas markets because supplies
cannot quickly adjust to demand changes. In 2000- 2001 for example,
natural gas supplies were constrained and demand skyrocketed, leading to
the perfect environment for the price spike shown below. While market
forces make natural gas prices susceptible to price volatility,
investigations are underway to determine if natural gas prices were
manipulated in the Western United States during the winter of 2000- 2001.
Federal agencies face major challenges in ensuring that natural gas prices
are determined in a competitive and informed marketplace. The Federal
Energy Regulatory Commission lacks an adequate regulatory and oversight
approach and is reviewing its statutory authority and market monitoring
tools. The Commodity Futures Trading Commission does not have regulatory
authority for over- the- counter derivatives markets. It does have
antimanipulation authority and is currently investigating what role, if
any, these markets played in the natural gas price spike of 2000- 2001.
Finally, the Energy Information Administration has an outdated natural gas
data collection program, but has made efforts to reassess its data needs
to provide more useful information.
Gas utility companies can protect their residential customers against
price spikes such as the one that occurred in 2000- 2001. For example,
using various hedging techniques, utilities can lock in prices for future
gas purchases. Continuing volatility in natural gas prices, especially the
price spike of 2000- 2001, has increased the importance of price stability
for gas utility companies. Agencies that commented on this report
generally agreed with its conclusions.
Natural Gas Wholesale Prices (adjusted to 2001 dollars)
NATURAL GAS
Analysis of Changes in Market Price
www. gao. gov/ cgi- bin/ getrpt? GAO- 03- 46. To view the full report,
including the scope and methodology, click on the link above. For more
information, contact Jim Wells at (202) 512- 3841. Highlights of GAO- 03-
46, a report to
congressional committees and members of Congress.
December 2002
During the winter of 2000- 2001, the wholesale price of natural gas peaked
at a level four times greater than its usual level. Responding to the
congressional interest and concern caused by these high prices, GAO
undertook a study to address the (1) factors that influence natural gas
price volatility and the high prices of 2000- 2001; (2) federal
government*s role in ensuring that natural gas prices are determined in a
competitive, informed marketplace; and (3) choices available to gas
utility companies that want to mitigate the effects of price spikes on
their residential customers. GAO surveyed a nationwide sample of gas
utilities and staff of state utility regulatory agencies.
Page i GAO- 03- 46 Analysis of Changes in Natural Gas Prices Letter 1
Results in Brief 5 Background 7 Market Forces Contributed to the Natural
Gas Price Spike in 2000-
2001, but Price Manipulation Has Not Been Ruled Out 13 Federal Government
Faces Challenges in Ensuring a Competitive
and Informed Natural Gas Marketplace 27 Consumers Can Be Protected against
Price Spikes 35 Conclusions 44 Agency Comments 45
Appendix I Objectives, Scope, and Methodology 49
Appendix II Results of Investor- Owned and Municipally Owned Utility
Survey 52
Appendix III Additional Results of Investor- Owned and Municipally Owned
Utility Survey 69
Appendix IV Results of State Regulatory Agency Survey 72
Appendix V Additional Results of State Regulatory Agency Survey 79
Appendix VI Comments from the Federal Energy Regulatory Commission 85
Appendix VII Comments from the Energy Information Administration 88
Contents
Page ii GAO- 03- 46 Analysis of Changes in Natural Gas Prices Appendix
VIII GAO Contacts and Staff Acknowledgments 90
Tables
Table 1: Results of a Hypothetical Gas Utility (GU- H) Hedging Gas
Purchases Versus Relying on Spot Market Prices for Winters 1990 through
2001 38 Table 2: Percentage of Gas Utility Companies That Reported Using
Hedging Techniques in Gas Purchases for 2000- 2001 43 Table 3: Changes in
Utilities* Use of Hedging Techniques since
Winter of 2000- 2001 43 Table 4: State Regulatory Agency Policy Concerning
Gas Cost
Stabilization Tools 44 Table 5: Gas Utilities* Planned Use of Hedging for
Residential
Customers 69 Table 6: Gas Utilities* Actual Use of Hedging for Residential
Customers during the Winters of 2000- 2001 and 2001- 2002 70 Table 7: Gas
Utilities* Planned and Actual Volumes of Natural Gas
Purchased during the Winter Heating Season for Residential Customers 70
Table 8: Use of Natural Gas Storage Among Utilities (on Average
over the Past 5 Years) 71 Table 9: State Regulatory Agency Regulation of
Hedging
Techniques Used by Utilities for Natural Gas Purchases 79 Table 10: State
Regulatory Agency Oversight of Gas Utilities 81
Figures
Figure 1: Natural Gas Wholesale Prices Per mmBtu, Adjusted to 2001 Dollars
2 Figure 2: U. S. Natural Gas Usage by Sectors, 2000 8 Figure 3: Principal
Components of Residential Natural Gas Price
during Winter Heating Season 11 Figure 4: Available Gas in Storage at the
Beginning of the Winter
Heating Season, November 1976- November 2000 14 Figure 5: Number of Gas
Rigs in Operation and Gas Prices 16 Figure 6: Monthly Average Number of
Natural Gas Rigs in Use,
1993* 2001 17 Figure 7: Mean Temperatures in the Continental United States
for
December 2000, in Degrees Fahrenheit 18
Page iii GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Figure 8: Comparison of Price Impacts of Elastic Supply and Inelastic
Supply 24 Figure 9: Comparison of Price Impacts of Elastic and Inelastic
Supply and Demand 25 Figure 10: Comparison of Hedged and Unhedged Gas
Prices for
Hypothetical Gas Utility 40 Figure 11: Percentage of Gas Utilities That
Hedged None of Their
Winter Gas Supply for Residential Customers, 1995- 2002 42
Abbreviations:
AGA American Gas Association APGA American Public Gas Association bcf
billion cubic feet CEA Commodity Exchange Act CFMA Commodity Futures
Modernization Act CFTC Commodity Futures Trading Commission DOJ Department
of Justice DRI Data Resources, Incorporated EIA Energy Information
Administration FERC Federal Energy Regulatory Commission FTC Federal Trade
Commission GU- H Hypothetical gas utility mmBtu million British thermal
units NARUC National Association of Regulatory Utility Commissioners NYMEX
New York Mercantile Exchange OMOI Office of Market Oversight and
Investigation OTC over- the- counter SEC Securities and Exchange
Commission tcf trillion cubic feet
Page 1 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
December 18, 2002 Congressional Committees and Members of Congress Natural
gas is an essential energy source in this country that has many
applications, including heating more than 59 million homes and 5 million
businesses, powering industrial and agricultural production, and
generating a substantial amount of the nation*s peak electricity needs.
During the winter of 2000- 2001, the wholesale price of natural gas peaked
at a level almost four times greater than the average price since 1993.
Figure 1 reflects this price spike in relation to natural gas prices over
the period from 1993 through 2001.
United States General Accounting Office Washington, DC 20548
Page 2 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Figure 1: Natural Gas Wholesale Prices Per mmBtu, Adjusted to 2001 Dollars
Note: A million British thermal units (mmBtu) is a measure of energy
content commonly used to quantify amounts of natural gas. It is
approximately the equivalent of 1,000 cubic feet of gas.
One extraordinary aspect of this price spike was its prolonged duration,
with prices remaining at high levels for a year. This period of high gas
prices raised concerns among industry and government officials as to
whether they would see the relatively low prices of the past any time in
the near future. Although the 2000- 2001 price spike was the longest
experienced since federal wholesale price controls were removed in 1993,
it did not mark the record high price for natural gas. This record high
occurred on February 2, 1996, when the price was 46 percent higher than
the peak price of the 2000- 2001 winter.
Page 3 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
The dramatic and prolonged price spike of 2000- 2001, coupled with
increased gas usage, affected all facets of the American economy. Millions
of residential customers who purchase natural gas from local utility
companies saw the costs of heating their homes increase significantly from
the previous winter*s costs. Nationwide, the average residential
customer*s total gas heating costs for the winter months increased from
$380 to $624, and in some locations the increase was even greater. In
addition, some companies significantly curtailed their production of
products such as fertilizer because of the increased price.
Over the past 25 years, the wholesale natural gas supply market has
evolved from a highly regulated market to a largely deregulated market,
where prices are mainly driven by supply and demand. Before implementation
of the Natural Gas Policy Act of 1978, which began deregulation of
wholesale natural gas prices, the federal government controlled the prices
that natural gas producers could charge for the gas they sold through
interstate commerce. Under this regulatory approach, producers located
natural gas reserves, drilled wells, gathered the gas, and sold it at
federally controlled prices to interstate pipeline companies. After
purchasing the natural gas, pipeline companies generally transported and
sold the gas to local distribution or gas utility companies. These
companies, under the oversight of state or local regulatory agencies, then
sold and delivered the gas to their ultimate consumers, such as
homeowners.
In today*s deregulated market the federal government does not control the
price of natural gas. Producers still locate and gather natural gas, but
they now sell the gas at market- driven prices to a variety of companies,
including marketers, broker/ trader intermediaries, and a variety of
consumers. Furthermore, the various players in the market may in turn sell
gas back and forth several times before it is actually delivered to the
ultimate consumers. In addition, several types of natural gas derivatives,
which are contracts whose market value is derived from the price of the
gas itself, can be bought and sold through numerous sources by entities
that are interested in protecting themselves against increases in the
price of natural gas. Derivatives markets* which include federally-
regulated exchanges like the New York Mercantile Exchange (NYMEX) and
offexchange, over- the- counter (OTC) markets, which are generally not
subject to federal regulatory oversight* become important because
derivative prices typically move in parallel with the actual physical or
cash
Page 4 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
market. These derivatives include natural gas futures and options. 1 Thus,
there are a variety of different types of gas buying and selling
arrangements that can be quite involved.
Overall, since the removal of federal price controls, the price of natural
gas has decreased but yet has become more volatile. In one extreme
example, the wholesale price of gas increased by 286 percent and then
decreased by 71 percent over a 4- day trading period in 1996. A
deregulated market also provides a new challenge to three key federal
agencies that do not control the fundamental nature and operation of the
natural gas market, but are charged with ensuring the existence of a
competitive and informed natural gas market that is not subject to fraud
or price manipulation. The Federal Energy Regulatory Commission (FERC) has
responsibility for ensuring *just and reasonable rates* for the interstate
transportation of natural gas, certain sales for resale of natural gas,
and the wholesale price of electricity sold in interstate commerce. In
addition, the Commodity Futures Trading Commission*s (CFTC) mission
includes fostering transparent, competitive, and financially sound
commodity futures and options markets. Finally, the Energy Information
Administration (EIA) is responsible for providing energy information that
promotes sound policymaking, efficient markets, and public understanding.
In addition to the challenges faced by these federal agencies, gas utility
companies, operating under state or local regulatory bodies, are
challenged in their efforts to mitigate the effects of price spikes on
their customers.
In this context, this report addresses the (1) factors that influence
natural gas price volatility and, in particular, the high prices that
occurred during the winter of 2000* 2001; (2) federal government*s role in
ensuring that natural gas prices are determined in a competitive and
informed marketplace; and (3) choices available to gas utility companies
that want to mitigate the effects of price spikes on their residential
consumers. We are addressing this report to congressional committees of
jurisdiction and to individual members that expressed concerns to us about
natural gas price spikes. The complete list of addressees appears at the
end of this letter.
1 A futures contract is an agreement to buy or sell a commodity for
delivery in the future at a price, or according to a pricing formula, that
is determined at initiation of the contract. An obligation under a futures
contract may be fulfilled without actual delivery of the commodity by, for
example, an offsetting transaction or cash settlement. An option gives the
buyer the right, but not the obligation, to buy or sell a commodity at a
specific price on or before a specific date.
Page 5 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
In addressing these issues, we examined government and industry price data
to determine how and why natural gas prices have behaved since 1993, when
federal wholesale price controls were removed. We also reviewed the
oversight responsibilities of agencies and their efforts to monitor and
collect information on the natural gas market. Finally, we surveyed a
sample of gas utility companies to learn what actions these companies had
taken or were planning to take to mitigate the effects of future spikes in
the price of natural gas. The survey included 112 utilities that are
members of the American Gas Association (AGA), which generally represents
larger investor- owned gas utility companies, and 21 additional large
utilities. These companies tend to have large customer bases, and
collectively they distribute locally about 90 percent of the natural gas
delivered by gas utilities in this country. The survey also included a
sample of 342 of 906 smaller, municipally owned gas utilities that are
represented by the American Public Gas Association (APGA). The municipally
owned utilities generally serve fewer customers than the investor- owned
companies. We received responses from 68 percent of the 133 larger
utilities surveyed and 52 percent of the sampled smaller utilities.
However, this response rate was not sufficient to generalize the results
of our survey to all gas utility companies; therefore, we reported the
results of only those that responded. In addition to the gas utility
company survey, we also surveyed state regulatory agencies in the 48
contiguous states and the District of Colombia to determine how they
oversee the purchasing and pricing of natural gas by the utility companies
under their jurisdiction. We achieved a 100- percent response rate. A
detailed description of our objectives, scope, and methodology is
contained in appendix I. Appendixes II and III provide details on the gas
utility companies* responses to our surveys. Appendix IV contains the
state regulatory agency survey and appendix V provides details on the
state regulatory agencies* responses to our survey.
Price volatility is a natural condition of natural gas markets because
natural gas supplies cannot quickly adjust to demand changes, leading to
periodic supply and demand imbalances. In 2000- 2001 for example, natural
gas supplies, constrained by unusually low storage levels and the
inability to quickly increase production levels, combined with
skyrocketing demand associated with extremely cold weather and strong
economic growth to create the perfect environment for the price spike that
occurred. The lack of timely and accurate data about the overall natural
gas market adds to the uncertainty about supply and demand conditions,
further exacerbating price volatility. While market forces make natural
gas prices inherently susceptible to volatility, there are some
indications that natural Results in Brief
Page 6 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
gas prices may have also been manipulated in the Western part of the
country during the winter of 2000- 2001. A number of investigations are
underway aimed at determining whether such manipulation occurred and until
they are complete, it is not possible to definitely establish whether and
how much prices paid by consumers were affected.
The federal government faces major challenges in meeting its role to
ensure that natural gas prices are the result of supply and demand factors
in a competitive and informed marketplace. As we have recently reported,
FERC* the agency responsible for ensuring wholesale natural gas prices,
sold and transported through interstate commerce, are just and reasonable*
lacks an adequate regulatory and oversight approach to meet this role.
FERC is still using legal authorities to regulate an evolving, competitive
market that were enacted when the wholesale natural gas supply market was
regulated. In addition, FERC*s market oversight initiatives have been
ineffective, serving more to educate staff about new markets than to
produce effective oversight. As a result, FERC has been slow to react to
charges of possible market manipulation and lacks assurances that
wholesale natural gas prices are just and reasonable. FERC recognizes that
it previously lacked an adequate regulatory and oversight approach and is
reviewing its statutory authority and market monitoring tools. Recently,
FERC has taken positive steps by creating a new monitoring office to
better understand energy markets. In addition, CTFC* the federal agency
responsible for fostering competitive commodity futures markets* does not
have general regulatory authority over trading in the OTC derivatives
markets. CFTC does have antimanipulation authority and is currently
investigating what role, if any, that these markets may have played in the
natural gas price spike of 2000- 2001. These investigations could lead to
enforcement actions or highlight the need for legislative changes.
Finally, EIA* the agency responsible for providing energy information that
promotes efficient natural gas markets and public understanding* has an
outdated natural gas data collection program. Most elements of EIA*s
current natural gas collection program have been in place for more than 20
years, when the more regulated natural gas market was much less
competitive and complicated. As a result, EIA*s ability to provide
information that promotes understanding of the market price of natural gas
has declined significantly. EIA recognizes this limitation and has made
efforts to reassess its information needs to provide more useful market
information.
Although the price of natural gas is volatile and significant price spikes
can occur, gas utility companies have various means of protecting their
residential customers against price spikes such as the one that occurred
in
Page 7 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
2000- 2001. For example, through storage, fixed- price buying
arrangements, and derivatives, utilities can hedge against the risk of
price spikes by locking in prices for future gas purchases. The goal of
hedging is to ensure stable prices, which are not necessarily the lowest
possible prices: stable prices locked in for the future may be lower or
higher than future market prices. However, continued volatility in market
prices, most recently with the price spike of 2000- 2001, has increased
the importance of price stability for gas utility companies that serve
residential customers and the state regulatory agencies that oversee this
service. As a result, gas utility companies have increased their use of
hedging. For example, 20 percent of the large and 32 percent of the small
gas utilities responding to our survey reported that before the price
spike of 2000- 2001 they had not planned to hedge any of their gas supply.
Consequently, their customers had to pay the prevailing market prices. In
contrast, 90 percent of all the utility companies responding to our survey
reported that they had decided to hedge some portion of their gas supply
before the next winter (2001- 2002).
This report does not contain any recommendations. However, in our recent
report discussing FERC*s oversight of new energy markets, we did make a
number of recommendations to FERC on ways to improve its oversight of
competitive energy markets. We also suggested that the Congress might want
to review FERC*s legal authorities to determine whether revisions are
needed to respond to the changing competitive energy markets.
Natural gas is a crucial source of energy in the United States. It is used
in five sectors: residential, commercial, industrial, electric generation,
and transportation. The United States used about 23.5 trillion cubic feet
(tcf) of natural gas in 2000. Figure 2 shows the percentages of total gas
usage by each of the five sectors. Background
Page 8 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Figure 2: U. S. Natural Gas Usage by Sectors, 2000
EIA expects the country*s consumption of natural gas will increase to 33.8
tcf per year by 2020. More than half of this increase is predicted to come
from gas- fired electric generation. Eighty- four percent of the natural
gas used in the United States is produced domestically, 15 percent comes
from Canada, and about 1 percent comes from other countries. Almost 8,000
companies produce natural gas from wells located in 37 states and
offshore. The producing companies range in size from small, family- owned
businesses to large international corporations. According to the
Independent Petroleum Association of America, small companies, most of
which employ fewer than 20 people, produced 65 percent of the natural gas
consumed by Americans in 2001.
Over the years, the natural gas market has undergone major changes, and it
is still growing and evolving. However, perhaps the most significant
change in the gas market* the transition from a regulated to a competitive
natural gas market* has already occurred. Under the regulated market,
producers sold their gas directly to interstate pipeline companies at
prices set by federal regulation. Although this system ensured stable
prices, it also caused severe gas supply shortages. These shortages
occurred because, with artificially low prices, producers had no incentive
to increase production and consumers had no reason to curtail their
demand.
Page 9 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Ultimately, the gas shortages led to delivery curtailments during cold
winters for many customers in the northern United States.
Responding to these supply problems, the Congress passed the Natural Gas
Policy Act of 1978, 2 which began the phased deregulation of natural gas
producer prices. This act established a pricing arrangement that
encouraged increased production of natural gas, but producer price
deregulation was not completed until after passage of the Natural Gas
Wellhead Decontrol Act of 1989. This act mandated that federal controls
over natural gas wholesale prices end by 1993, allowing the price to be
set freely in the marketplace. In addition, FERC issued a series of orders
during the 1980s and early 1990s to address the inability of natural gas
users to gain access through the pipeline systems to competitive natural
gas suppliers. The two most notable were Order 436 and Order 636. Order
436, issued in 1985, instituted open- access, nondiscriminatory pipeline
transportation. In 1992, Order 636 was issued requiring pipeline companies
to completely separate or *unbundle* their transportation, storage, and
sales services. As a result, natural gas as a commodity was separated from
gas transportation. Pipeline companies were required to treat other
parties wishing to use the pipeline to transport natural gas the same as
they would their own affiliated sales services. These laws and regulatory
changes led to the competitive and more complex natural gas market that
exists today.
In today*s market, instead of selling natural gas strictly to the pipeline
companies, producers now sell their gas to a variety of purchasers located
across the United States. With the removal of federal price controls,
producers* prices are determined in the marketplace. Natural gas is bought
and sold at many different locations, to numerous parties, and under
different sales and transportation arrangements. Numerous entities,
including utilities and marketers, can buy, sell, re- buy and re- sell gas
in a variety of ways.
The prices paid for natural gas can vary among the different buying
arrangements. For example, before deregulation, many gas utilities* supply
contracts were long- term* often for 20 years or more* with little
variability in price. As deregulation unfolded in the 1980s, gas utilities
attempted to obtain better gas prices for their customers by developing a
portfolio of long- term and short- term supply contracts and purchasing
2 P. L. No. 101- 60 (1978).
Page 10 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
some gas on the spot market. 3 However, while generally lower on average
than previously regulated prices, the prices for short- term gas supply
contracts and purchases on the spot market can be highly volatile. As
shown in figure 1, several prices spikes occurred over the 9- year period
ending in 2001, but with one exception, during 2000- 2001, the price of
natural gas quickly returned to previous levels.
Natural gas prices also vary depending on location because of the
importance of factors such as proximity to gas production, pipeline
capacity, and local supply and demand conditions. In addition, prices vary
depending upon the step in the natural gas distribution process during
which the gas is sold. Wholesale natural gas prices reflect the basic
costs for the commodity itself and are reported daily at a number of
production market centers throughout the country. Unless otherwise
specified, the wholesale prices cited in this report are for gas at the
Henry Hub, a natural gas market center located in Louisiana. The Henry Hub
is one of the largest gas market centers in the United States and often
serves as a benchmark for wholesale natural gas prices across the country.
City gate prices are the prices at which gas is delivered from an
interstate pipeline to a utility or large consumer. These prices are
higher than wholesale prices because they reflect transportation costs in
addition to commodity cost. Finally, the retail prices paid by residential
and other small- end users are typically the highest gas prices because
these customers must pay for not only the gas itself, but also the costs
of transporting the gas to their city and the utility company*s costs for
providing full service delivery. Full service is more expensive because it
requires a utility company to meet customers* full requirements, which can
vary significantly depending on the weather. State regulatory agencies,
such as public utility commissions, usually regulate the retail gas prices
charged by generally larger, investorowned gas utility companies, and
local bodies, such as city councils, usually regulate the prices charged
by generally smaller, municipally owned companies. Figure 3 shows the cost
components for the residential price of natural gas.
3 Spot market (sometimes referred to as the cash or physical market)
prices are the current cash prices at which natural gas is sold at the
various market locations.
Page 11 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Figure 3: Principal Components of Residential Natural Gas Price during
Winter Heating Season
Another development in the deregulated natural gas market is the use of
natural gas derivatives* financial tools for managing risk that are based
on natural gas prices. NYMEX introduced natural gas derivatives, in the
form of futures and options contracts in 1990 and 1992, respectively.
Using these derivatives, gas utilities, along with electric power
generators, other large industries, and gas marketers, can hedge against
price risk by locking in or setting an upper limit on the prices they will
pay for future gas purchases. In the 1990s, the development of electronic
trading systems and the Internet added another layer of complexity to the
natural gas market. At that time, natural gas derivatives began to be
bought and sold in the offexchange OTC markets, such as the
Intercontinental Exchange and the former EnronOnline. These OTC markets
expanded both the terms (the
Page 12 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
size, maturity, and price) and types (OTC markets introduced swaps 4 ) of
hedging instruments available to natural gas marketplace participants.
Although the federal government has deregulated natural gas producer
prices, three key agencies still maintain some role in ensuring that a
competitive and informed natural gas market exists. FERC was established
in 1977 as a successor to the Federal Power Commission and has
responsibility for ensuring *just and reasonable rates* for the interstate
transportation of natural gas, certain sales for resale of natural gas,
and the wholesale price of electricity sold in interstate commerce. CFTC*s
mission is, in part, to oversee the nation*s commodity futures and options
markets, including natural gas markets, and to protect market users and
the public from fraud, manipulation, and abusive practices. Finally, EIA
is responsible for providing energy information (including natural gas) to
meet the requirements of government, industry and the public that promotes
sound policymaking, efficient markets, and public understanding. EIA was
established by the Congress in 1977 and is charged with providing
unbiased, professional analyses of energy issues and does not advocate
policy. EIA*s role is as a depository for energy information and it has no
direct influence on natural gas prices or policy. However, the data that
the EIA collects are used to address significant energy industry issues.
EIA*s natural gas data collection program is part of its National Energy
Information System, a system created by the Federal Energy Administration
Act of 1974, as amended, to help fulfill the agency*s mandate to collect
data that adequately describes the energy marketplace. According to EIA,
adequate evaluation of the industry requires production, processing,
transmission, distribution, storage, marketing, consumption, and price
data.
The Securities and Exchange Commission (SEC), the Department of Justice
(DOJ), and the Federal Trade Commission (FTC) also play roles in
maintaining competitive energy markets through their regulation of firms
participating in these markets. SEC administers and enforces federal
securities laws to protect investors and to maintain fair, honest, and
efficient markets. DOJ investigates and prosecutes illegal activities such
as
4 A commodity swap, including an energy swap, is typically between two
parties who each promise to make a series of payments to the other, of
which at least one series is based on a commodity price, such as the price
of an energy product. For example, an airline might agree to make fixed
cash payments on particular dates over a certain period and to receive
from the counter party on those same dates payments that are based on an
index of oil prices. This would enable the airline to hedge against
volatility in its fuel costs.
Page 13 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
price fixing, insider trading, and wire fraud. Both agencies have ongoing
investigations into the financial activities of energy companies. DOJ also
enforces the Sherman Antitrust Act, which prohibits all contracts,
combinations and conspiracies that unreasonably restrain interstate and
foreign trade. FTC shares authority with DOJ under section 7 of the
Clayton Act to prohibit mergers or acquisitions that may substantially
lessen competition or tend to create a monopoly. In addition, section 5 of
the Federal Trade Commission Act prohibits *unfair methods of competition*
and *unfair or deceptive acts or practices,* thus giving FTC
responsibilities in both the antitrust and consumer protection areas.
Available market evidence suggests that the inability of gas supplies to
meet surging demands contributed to the natural gas price spike that
occurred in 2000- 2001. Specifically, natural gas supplies were
constrained because of unusually low storage levels and the inability to
quickly increase production levels. At the same time, demand during 2000-
2001 was high because of extremely cold weather in the beginning of the
winter and continuing strong economic growth. The price spike of 2000-
2001 is consistent with the overall volatile nature of natural gas prices,
which is driven by the short- term inelasticity of supply and demand that
neither quickly nor easily adjusts to meet changes in the natural gas
market. In addition, a lack of timely and accurate data about the overall
natural gas market can create uncertainty about supply and demand
conditions and further exacerbate price volatility. As a result, the
combination of inelastic supply and demand means that shifts in natural
gas supply or demand, real or perceived, can and are likely in the future
to continue to cause volatility in the price of natural gas. While these
market factors result in an inherent susceptibility to price volatility,
there are indications that market manipulation may have occurred as well
in the winter of 2000- 2001. Several federal investigations looking into
the possibility of such price manipulation in the natural gas market are
currently ongoing. However, because these investigations are ongoing, a
final determination of whether natural gas prices were manipulated, and if
so, where and to what extent prices were further affected, has not yet
been determined. Market Forces
Contributed to the Natural Gas Price Spike in 2000- 2001, but Price
Manipulation Has Not Been Ruled Out
Page 14 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Based on our analysis of EIA data and interviews with EIA and other energy
analysts, constrained natural gas supplies, caused by unusually low levels
of gas in storage on the part of gas utilities and gas marketers, and the
considerable time required for gas from new production to reach the
marketplace, contributed to the increases in natural gas prices in
20002001. 5
EIA data show that as of November 1, 2000, the volume of natural gas in
storage was at the lowest level recorded for the beginning of a winter
heating season since 1976 6 : only 2,732 billion cubic feet (bcf). In 4 of
5 months during the 2000- 2001 winter heating season, the volumes of
natural gas in storage were at record low levels. And at the end of March
2001, the volume of gas in storage dropped to 742 bcf, the lowest level
ever recorded by EIA, or 36 percent below the level in March 2000.
Figure 4: Available Gas in Storage at the Beginning of the Winter Heating
Season, November 1976- November 2000
5 In general, gas supplies were not significantly hindered by transmission
or pipeline capacity constraints. However, EIA reported that although the
use of natural gas pipeline capacity rose to high levels (90 to 100
percent in many locations), the movement of gas from production areas to
end- use markets encountered few problems, except in some fastgrowing
market areas, such as California, Florida, and New York. In California,
for example, according to the California Energy Commission, insufficient
capacity within the state and on the interstate El Paso pipeline system
both contributed to the high price of natural gas in the fall and winter
of 2000.
6 The winter heating season is typically defined as November 1 through
March 31. Natural Gas Supplies Were
Constrained because of Low Storage Levels and Delays in Newly Produced Gas
Reaching the Market
Page 15 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
These low storage levels resulted primarily because wholesale gas prices
from April through September 2000 were higher than normal, climbing from
around $3 to over $5 per mmBtu. According to EIA, these prices caused some
storage users to postpone buying gas to inject into storage in the hope
that prices would eventually decrease before the winter. However, instead
of decreasing, gas prices generally stayed high and the volume of gas
placed into storage for the winter heating season did not reach normal
levels. According to industry experts, natural gas prices were high in the
summer of 2000 because of the increased use of natural gas for electric
generation. The increased demand for electric generation was compounded by
the warmer- than- normal weather in the South and West, which increased
the demand for gas- fired electricity to run air conditioning units. In
addition, some companies and marketers that had put gas into storage
earlier in the year reportedly sold it for profit when gas prices
increased later that year, further depleting the already low storage
reserves. In late September and October 2000, the industry did put more
gas into storage at rates higher than the previous 5- year average for
this period to prepare for the coming heating season; however, this late
surge of injections of gas into storage did not bring storage volumes up
to their usual levels.
Adding to the supply constraints caused by low storage levels was the fact
that producers could not quickly increase their production levels to meet
the increasing demand for natural gas. During the winter of 2000- 2001,
almost all of the gas that could be produced from existing natural gas
wells was being produced and sent into the marketplace. According to EIA
analysts, when over 90 percent of the maximum possible gas productive
capacity from wells is being utilized, the natural gas market is at
greater risk for price spikes. Data supplied by EIA show that this was
true during the winter of 2000- 2001, when the nation*s natural gas
utilization rate was above 90 percent and reached levels close to 100
percent in certain areas of the country. Therefore, new gas production was
needed to respond to increased demand, but this new production could not
be developed fast enough to keep prices from rising.
Prior to 2000, drilling activity was lower as supply was sufficient and
prices were lower. However, in response to the higher prices in 2000,
natural gas producers took action to increase their production by
increasing the number of new gas wells they drilled. As shown in figure 5,
the number of drilling rigs began increasing in the April to May 2000 time
frame, when gas prices first rose above $3 per mmBtu and continued to
increase for more than a year. However, the number of drilling rigs in
operation stopped increasing around July 2001, when gas prices again fell
Page 16 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
below $3 and producers no longer had the economic incentive to increase
production.
Figure 5: Number of Gas Rigs in Operation and Gas Prices
Although the number of new natural gas wells being drilled in 2001
decreased when gas prices decreased, the monthly average number of rigs in
use that year was the highest recorded since natural gas prices were
deregulated in 1993. Figure 6 compares the number of natural gas rigs in
operation for the years 1993 through 2001.
Page 17 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Figure 6: Monthly Average Number of Natural Gas Rigs in Use, 1993* 2001
The effect of this increased drilling activity was not immediately felt in
the supply of natural gas available in the marketplace because there is a
lag time of 6 to 18 months before gas produced from new wells reaches the
market. Furthermore, according to EIA, there is an inherent delay between
gas price changes and changes in drilling activity. Gas prices began to
increase around May 2000 and peaked around January 2001, but rig counts
did not peak until July 2001 (see fig. 5). Therefore, the increased
drilling in 2000 and 2001 did not result in an immediate increase in the
production of natural gas, and the new production that did occur did not
reach the marketplace in time to respond to the growing demand and slow
the rising prices. Moreover, industry officials told us that the typical
delay associated with getting newly produced gas to the marketplace was
exacerbated by the low number of gas drilling rigs that were in operation
before the price increase in 2000. According to these officials, low
natural gas prices beginning in late 1998 and continuing through 1999 had
caused producers to greatly reduce the number of drilling rigs in
operation. In fact, as figure 6 shows, the number of natural gas drilling
rigs operating in 1999 averaged only 496 per month and hit an almost 4-
year low in April when the average number of operating rigs dropped to
371. Therefore, natural gas producers faced more than a normal delay in
increasing their natural gas drilling activity because of limited
equipment availability.
Page 18 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
At the same time the country was facing constrained gas supplies, a
surging increase in demand, caused chiefly by cold weather and a strong
economy, also contributed to the increases in natural gas prices in the
winter of 2000- 2001. Nationwide, extremely cold weather early in the
winter heating season was a key reason for the peak in natural gas demand.
This increased demand came primarily from the residential and commercial
customers who use natural gas for heating. According to data from the
National Climatic Data Center, November 2000 was the coldest November
recorded for almost 90 years, with temperatures below normal or much below
normal across most of the country. In December 2000, temperatures
continued to remain cold, with 40 of the 48 contiguous states showing
temperatures below or much below normal (see fig. 7).
Figure 7: Mean Temperatures in the Continental United States for December
2000, in Degrees Fahrenheit
Natural Gas Demand Increased because of Cold Weather and the Strong
Economy
Page 19 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
According to EIA data, these frigid temperatures caused record natural gas
withdrawals from storage in November 2000, followed by the highest level
of withdrawals in 11 years for the month of December. These relatively
large withdrawals, coupled with the low storage levels at the beginning of
the winter heating season, caused some people in the natural gas industry
to believe that storage levels in some areas would not be sufficient to
last through the winter if the cold weather continued. In fact, gas
supplies did not run out because the high gas prices motivated some
consumers to reduce consumption or use substitute fuels when possible,
especially in the industrial and electric generation sectors. In addition,
gas supplies did not run out because the weather was milder during the
rest of the winter. However, even with this eventual decrease in demand,
by the end of the winter heating season on March 31, 2001, the volume of
natural gas in storage was at its lowest level since EIA began its
complete monthly data series beginning in September 1975.
In addition, continuing economic growth throughout the 1990s and into 2000
expanded the potential demand for natural gas and contributed to the price
spike that occurred in 2000- 2001. This growth occurred in major sectors
of natural gas consumption: residential, commercial, industrial, and
electric generation. The strong economy during the 1990s had boosted new
home construction, and most of these homes were heated with natural gas.
Housing data that we reviewed show that from 1991 to 1999, two- thirds of
the new homes and more than one- half of the new multifamily buildings
constructed were heated with natural gas. Further, many of these new
houses tended to be larger, thus increasing the potential for high natural
gas consumption during colder weather. The number of commercial gas
customers also increased from 4.6 million in 1995 to 5.1 million in 2000,
while natural gas consumption in this sector rose by 6 percent. Gas
consumption in the industrial sector remained high, although it has
decreased slightly since 1997 in part because of more efficient equipment.
Because of its clean burning properties, natural gas is now the preferred
source of energy for most new electric generation capacity. Gas- fired
electric generation facilities accounted for only about 23 percent of
natural gas consumption in the United States in 2001, but account for a
greater percentage during the summer, when electricity demand goes up
because of the use of air conditioning.
Page 20 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Natural gas price volatility, as occurred during the winter of 2000- 2001,
is driven by inelastic supply and demand, which means neither can quickly
nor easily adjust to meet changes in the natural gas market. The supply of
gas from new production wells cannot quickly increase to meet higher
demand because of the lag time required to get the newly produced gas into
the marketplace. Similarly, the demand for natural gas does not quickly
drop in response to higher prices: some consumers do not have easy access
to alternative fuels, so their demand does not decrease significantly even
when natural gas prices increase. In addition, a lack of timely and
accurate data about the overall natural gas market can create uncertainty
about supply and demand conditions and further exacerbate price
volatility. As a result, the combination of inelastic supply and demand
means that small shifts in natural gas supply or demand, real or
perceived, can and are likely to continue to cause relatively large
fluctuations in the price of natural gas.
The inelastic nature of natural gas means that supply is slow to respond
to price changes in the marketplace. The immediate supply of natural gas
primarily comprises gas coming from production that goes straight into the
market and gas placed into storage during the warmer summer season for use
during the winter heating season. On the production side, there is a
significant delay from the time drilling begins to the time when newly
produced gas enters the marketplace. Developing additional supplies from
new wells and building the new infrastructure required to deliver the
newly produced gas to market* such as gas processing plants and pipelines*
can take considerable time. The amount of time required to get new gas to
the market depends on several factors, including the location of the
natural gas well. For example, natural gas industry sources told us that
gas coming from new wells drilled in areas with established reserves that
are not deep in the ground takes about 6 months to reach the market.
However, it takes much longer for gas being extracted from very deep
wells, from new fields, or from offshore wells to reach the marketplace.
In addition, gas extracted from a new field often cannot reach the
marketplace until a pipeline segment and/ or gathering line is
constructed, and this requires even more time. Thus, new gas production
often cannot be brought into the marketplace quickly enough to meet
increases in demand. In addition, the amount of natural gas available from
storage to meet increasing demands is limited. According to industry
officials, natural gas is generally purchased and injected into storage
during the 7- month period from April through October. This gas is then
withdrawn from storage for heating and other use during the winter heating
season running from November through March. Once the injection season is
over, the amount of gas in storage is typically set. Thus, when people in
the gas Natural Gas Market Supply
and Demand Characteristics Cause Price Spikes
Natural Gas Supply Is Inelastic, and Information Is Limited
Page 21 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
industry become concerned that the available supply of gas will not be
sufficient to last through the winter heating season, a significant price
spike can occur, as it did in 1996 and again in 2000- 2001, when the
amounts of gas in storage were at low levels.
Compounding the limited ability of production to respond quickly and the
limited gas in storage is the lack of comprehensive and timely information
on these market characteristics. This uncertainty can make it difficult
for market participants to determine when shifts in supply are occurring,
leading to increased and frequent speculation that may ultimately increase
price volatility because of perceived shifts in supply. According to EIA,
the agency*s monthly production data are subject to problems of accuracy
and timeliness. First, the forms used to report production data vary from
state to state and often do not include all information requested by EIA.
Therefore, EIA must estimate marketed production from whatever data
elements are submitted, information in state publications and web sites,
the trade press, or prior year data. Also, EIA data is collected through
an optional survey. If a state does not comply with information requests,
the federal government has no authority to require it to provide
information. In addition, monthly production data for a certain year are,
for some states, available to EIA only in the late summer of the following
year, leading to inherent delays in reporting. Late or incomplete reports
from the states to EIA are common.
Incorrect information concerning storage can also greatly affect the
market. As discussed above, because timely production information is not
available, storage data have become a widely used indicator to estimate
the supply of natural gas. When this information is incorrect, it can
increase volatility in the natural gas market. For example, when AGA
reported on August 15, 2001, that injections for the week ended Friday,
August 10 totaled a record low of 3 bcf, the September futures contract
daily settlement price jumped by 12 percent from the previous day.
Analysts had predicted that injections for that week would range from 45
to 70 bcf. Later, AGA discovered that it had received erroneous data from
an entity included in its survey and issued a corrected gas storage report
on August 22 showing that gas injection during the week ending August 10,
2001, was 50 bcf. As a result, the September futures contract price on
August 22 decreased by more than 10 percent from the day before. On
October 12, 2001, AGA announced that in 2002 it would stop providing
weekly reports on the volume of natural gas in underground storage. AGA
said that it was discontinuing its reporting of storage data primarily
because the staff time required to conduct the gas storage survey drained
staff resources that could be redirected to programs more
Page 22 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
beneficial to its members. Shortly after the AGA announcement, the
Secretary of the Department of Energy announced that because of the
importance of natural gas storage data in forecasting winter gas prices
and demand, EIA would begin providing this data in a weekly report.
The demand for natural gas is inelastic to varying degrees among major gas
consuming sectors: residential, commercial, industrial, and electric
generation. Demand from residential and commercial customers is perhaps
the most inelastic because heat is generally a necessity, not a luxury.
Those consumers that heat their homes and businesses with natural gas will
require a certain level of heat even if gas prices are quite high.
Furthermore, they cannot easily respond to high natural gas prices in the
short run by switching to a more economic fuel source for heat. In
addition, many of these customers do not know beforehand that they are
paying higher gas prices because they are customarily billed later for gas
they are currently using.
Industrial natural gas demand is more elastic than demand from residential
and commercial customers. For example, some industrial customers have the
ability to switch from natural gas to other fuels when natural gas prices
rise. However, many do not have this capability and others have limited
fuel switching capability. As natural gas prices rise, some industrial
customers may choose to reduce their operations and sell the gas they had
under contract to the highest bidder. When natural gas prices rose
significantly in 2000- 2001, this option was more profitable for certain
industrial users than if they had continued their operations using natural
gas at higher- than- normal prices. Natural gas demand for electric
generation may now be more elastic, but according to industry experts it
is becoming more inelastic. Previously, many of these users had facilities
that could use either natural gas or an alternate fuel, such as oil,
depending on which energy source was less expensive. However, natural gas
prices were low throughout the 1990s, so many electric generation
facilities decided to use natural gas as their only source of energy, thus
increasing their dependency on natural gas. The demand for natural gas in
the electric generation sector is growing faster than in any other sector
and if EIA*s projections for gas- fired electricity are realized, this
sector will likely have a significant effect on future natural gas prices.
EIA projects that the demand for natural gas in the electric generation
sector will grow at an annual rate of 4.5 percent, and by 2020 the demand
will have risen to 10.3 tcf of gas, accounting for 30 percent of the
natural gas used annually in this country. In addition, industry analysts
told us that because of the high demand for gas- fired electricity in some
markets, some electric Natural Gas Demand Is
Inelastic, and Information Is Limited
Page 23 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
generating facilities are willing to pay premium prices for the natural
gas needed to produce this electricity.
As with gas supply data, some aspects of natural gas demand information
are also limited, making it difficult for the market to see real changes
in demand. The resulting increased speculation about perceived shifts in
demand can also exacerbate price volatility. According to EIA, the growth
and restructuring of the natural gas industry have made it more difficult
to collect data concerning natural gas demand. For example, changes in
certain regulatory requirements have led to the elimination of information
that EIA needs to ensure the quality and completeness of its data. In
addition, firms providing natural gas delivery do not always know the
intended use for the gas they are delivering. For example, a gas supplier
could deliver gas to a city building that contains both residential
apartments and retail space. The supplier has no way to know what
percentage of the gas delivered is used for what purpose and therefore
cannot determine in what usage sector the gas should be reported. In the
electric generation sector, the importance of nonutility generators,
including independent power producers and cogenerators, is growing. In the
past, EIA has included these entities in the statistics it develops for
industrial or commercial users of natural gas sectors, thereby
underreporting the amount of gas used to generate electricity. However,
EIA is implementing a better approach to measure and report the amount of
natural gas used for electric generation by nonutility generators. Also,
EIA recently changed how it estimates and presents data on the fuels used
to produce electricity. The purpose of this change is to improve data
quality, ensure that data are reported consistently throughout EIA
publications, and provide users with a better understanding of how fuels
are consumed.
Any market with inelastic supply and demand characteristics* as is the
case in the natural gas market* is more susceptible to significant price
fluctuations than a more elastic market: in an inelastic market,
relatively small shifts in supply or demand can result in significant
price changes. Natural gas supply is relatively fixed in the short term;
it is limited to available storage and current production and cannot be
quickly increased to meet increased demand. Thus, an increase in demand
will result in a greater increase in price than if the supply were more
elastic. Basically, in the perfectly inelastic supply market, more demand
competes for the same level of supply, driving prices higher than they
would go if supply were more readily available* more elastic. Figure 8
illustrates this example by comparing the smaller price increase in a
market with elastic supply (panel A) with the larger price increase in a
market with perfectly inelastic Short- term Inelasticity Means
Small Shifts in Supply or Demand Can Lead to Significant Price
Fluctuations
Page 24 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
supply (panel B) when faced with the same increased level of demand.
Figure 9 goes farther, illustrating this difference for a market with both
inelastic supply and demand* as is the case with the natural gas market.
Figure 9 compares the smaller price increase in a market with both elastic
supply and demand (panel A) with the larger price increase in a market
with inelastic supply and demand (panel B) when demand increases and
supply decreases.
Figure 8: Comparison of Price Impacts of Elastic Supply and Inelastic
Supply
Note: In panel A, assume we have a good with elastic supply; elastic
supply is represented by a supply line whose upward slope is relatively
not very steep. Initially, the price and quantity settle at P a
0 and quantity Q0 as determined by the intersection of supply S a and
demand D0 . Next, assume that demand increases, as depicted by an outward
shift in the demand line to D1 . Because supply is somewhat elastic,
additional supply is made available to meet the increased demand, albeit
at a higher price P a
1 . The increase in price is represented by P a *the difference between P
a 1 and P a
0 . However, in an inelastic supply situation, the supply response is
weaker. A more limited quantity is supplied to the market to meet the
increased demand, resulting in a steeper rise in price than in the more
elastic case. Graphically, this inelasticity is represented by a supply
line that is much steeper than the elastic supply line. Taking an extreme
example, assume that supply is totally inelastic* that is, supply is fixed
no matter what the demand* as depicted in panel B with a vertical supply
line, S b . The initial price and quantity are the same as in panel A.
Given the fixed supply, in order to meet the same increase in demand to D1
, the price would have to increase to P b
1 to *choke off* the excess demand. The increase in price from P b
0 to P b 1 for the inelastic supply case, as represented by P b , is
significantly higher than the increase in price in the elastic supply
case, P a .
Page 25 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Figure 9: Comparison of Price Impacts of Elastic and Inelastic Supply and
Demand
Note: To provide a more complete picture, figure 9 compares a market with
elastic supply and demand with a market with inelastic supply and demand*
like the natural gas market* to further illustrate the greater price
response to shifts in inelastic supply and demand. The elastic supply and
demand market (panel A) has a relatively less steep supply and demand
lines, while the inelastic supply and demand market (panel B) is
characterized by much steeper supply and demand lines. The primary
observation is the difference in the price response to changes in supply
and demand in the elastic market in panel A (P a
0 vs P a 1 ) compared with the price response in the inelastic market in
panel B (P b
0 vs P b 1 ). In both examples, supply drops as depicted by an inward
shift from S0 to S1 . In the gas market, this drop could be due, for
example, to an accident that disrupts a major pipeline. Also, in both
examples, demand rises, as depicted by an outward shift from D0 to D1 . In
the gas market, this could be the result of an unusually cold winter snap.
We have constructed both examples in such a way as to leave the quantity
of the commodity unchanged at Q0 . As can be seen, in the market with
elastic supply and demand, the decline in supply and the rise in demand
result in a relatively small price increase ( P a ). However, in the
market with inelastic supply and demand, the increase in price due to the
supply and demand shifts is considerably larger ( P b ).
On February 13, 2002, FERC commissioners directed staff to undertake a
fact- finding investigation into whether any entity, including Enron
Corporation, manipulated short- term prices in electric energy or natural
gas markets in the West or otherwise exercised undue influence over
wholesale electric prices in the West, for the period January 1, 2000,
forward. On March 5, 2002, FERC staff issued an information request to
companies that sold energy in the West during this period to report on
Evidence of Natural Gas
Market Manipulation Found, but Federal Investigations Still Ongoing
Page 26 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
their capacity and energy sales transactions. On May 6, 2002, counsel for
Enron released several memos to FERC staff that indicated the company had
actively worked at manipulating California*s wholesale electric power
markets. On May 8, 2002, FERC issued an *Admit or Deny* order requiring
other companies to either admit or deny they engaged in strategies that
might have inflated market prices during California*s energy crisis of
2000- 2001. A May 22, 2002, FERC order further expanded the investigation
by requesting that natural gas sellers in both the West and Texas provide
information on *wash trading.* 7 In an initial staff report issued August
13, 2002, FERC found indications that several companies, including Enron,
may have manipulated spot prices upward for natural gas delivered to
California during 2000- 2001. 8 FERC staff reported that during the months
October 2000 to July 2001, the correlation of spot prices for natural gas
at the California delivery points with prices at producing basins in the
Southwest and the Rockies and Henry Hub was abnormally low. FERC staff
found that published natural gas price data are susceptible to
manipulation and cannot be independently validated. The staff report noted
that the lack of formal verification opens the door for entities to
deliberately misreport information in order to manipulate prices and/ or
volumes for both electricity and natural gas. The staff report concluded
that in the absence of some form of double- checking, such misreporting is
likely to be undetected in the reporting process and uncorrected when
prices are published. FERC staff also found that Enron*s trading
strategies, described in internal Enron memos, used false information in
an attempt to manipulate prices. The FERC staff report stated that while
the exact economic impact of Enron*s trading strategies remains difficult
to determine, the Enron trading strategies have adversely affected the
confidence of the markets (electric and natural gas) far beyond their
dollar impact on spot prices. Based on the staff report, FERC ordered
formal investigations into instances of possible misconduct by Avista
Corporation and Avista Energy, Inc., El Paso Electric Company, and three
Enron
7 Wash trading, also know as *round- trip trading,* is defined in the
natural gas market as *the sale of natural gas together with a
simultaneous or pre- arranged purchase of the same product at or near the
same price.* It gives the appearance of trading when no bona fide,
competitive trade has occurred. The practice creates the false impression
that an energy firm sold more power or natural gas than it actually
controlled and may inflate the price of the commodity to the extent that
the artificial and higher price created by the wash trade is used as a
basis for pricing.
8 Initial Report on Company- Specific Separate Proceedings and Generic
Reevaluations: Published Natural Gas Price Data; and Enron Trading
Strategies (FERC, Aug. 13, 2002).
Page 27 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
corporate affiliates* Enron Power Marketing, Inc., Enron Capital and Trade
Resources Corporation, and Portland General Electric Corporation.
In addition to the FERC investigation, on September 23, 2002, a FERC
administrative law judge found that El Paso Natural Gas Company exercised
market power during the 2000- 2001 winter heating season by withholding
substantial volumes of pipeline capacity to its California delivery
points, thereby tightening natural gas supply to the state and increasing
its price. The California Public Utilities Commission originally brought
the case, filing a complaint with FERC in 2000. The judge recommended that
FERC commissioners institute penalty procedures. The Commission will
review the judge*s recommended decision. In addition to the FERC
investigations, CFTC Chairman James E. Newsome confirmed during
congressional testimony in March 2002 and again at a press conference in
May 2002 that CFTC had began an investigation into various energy trading
schemes, including possible wash trading, in gas and power futures
markets. However, consistent with CFTC policy on ongoing investigations,
CFTC could not tell us about the scope or reporting deadlines of its
investigation.
FERC, CFTC, and EIA play front- line roles in promoting a competitive
natural gas marketplace by monitoring business activities and deterring
anticompetitive actions that could undermine these markets, and obtaining
information and analyzing trends in the industry that are used by
decisionmakers in both industry and government. However, regulatory gaps
and outdated data collection efforts have impeded effective federal
oversight of the natural gas marketplace to ensure competition and limited
its ability to provide market information. As we have recently reported,
FERC has not adequately revised its regulatory and oversight approach to
respond to the transition to competitive energy markets. As a result, it
has been slow to react to charges of possible market manipulation and
lacks assurances that wholesale natural gas and electricity prices are
just and reasonable. We note, however, that FERC has recently take actions
to correct this with the formation of the Office of Market Oversight and
Investigation (OMOI). In addition, CTFC* the federal agency responsible
for fostering competitive commodity futures markets* generally does not
have regulatory authority over trading in the OTC derivatives markets.
Finally, EIA recognizes that most elements of its natural gas data
collection program were set in place more than 20 years ago, well before
deregulation spawned a host of new entities and markets that influence
natural gas prices. EIA recognizes that its ability to provide information
that promotes understanding of the market price of natural gas has Federal
Government
Faces Challenges in Ensuring a Competitive and Informed Natural Gas
Marketplace
Page 28 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
declined significantly and is currently reevaluating its data collection
needs.
Under federal law, FERC is responsible for regulating the terms,
conditions, and rates for interstate transportation by natural gas
pipelines and public utilities to ensure that wholesale prices for natural
gas and electricity, sold and transported in interstate commerce, are
*just and reasonable.* However, FERC jurisdiction over sales for resale is
limited to domestic gas sold by pipelines, local distribution companies,
and their affiliates. The Commission does not prescribe prices for these
commodity sales. As energy markets deregulate, FERC has concluded that its
approach to ensuring just and reasonable prices needs to change: from one
of reviewing individual companies* rate requests and supporting cost data
to one of proactively monitoring energy markets to ensure that they are
working well to produce competitive prices. However, we reported in June
2002 9 that FERC has not yet adequately revised its approach to regulating
and overseeing the nation*s natural gas and electric power industries. The
problems we identified include the following:
FERC is using legal authorities to regulate competitive markets that
were enacted when the energy industries were regulated monopolies. For
instance, FERC generally does not have the authority to levy meaningful
civil penalties. While this authority may not have been necessary when
energy industries were regulated monopolies, it is important, in today*s
market, if FERC is to deter anticompetitive behavior or violations of
market rules by market participants. FERC*s oversight initiatives have
been incomplete or ineffective. FERC
initiatives to monitor competitive markets have served more to help
educate FERC*s staff about the new markets than produce effective
oversight. Additional market data available to staff have not been used to
initiate an enforcement action or to confirm or refute a problem
identified elsewhere in the agency. FERC*s organizational structure
limits its ability to monitor competitive
markets because it diffuses its market oversight function, making it more
difficult to provide the communication, focus, and management attention
needed to successfully implement a new regulatory and oversight approach.
9 Energy Markets: Concerted Actions Needed by FERC to Confront Challenges
That Impede Effective Oversight (GAO- 02- 656, June 14, 2002). FERC Faces
Challenges
That Impede Effective Oversight
Page 29 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
FERC must overcome significant human capital challenges, such as
recruitment and retention of qualified staff.
We concluded that absent an effective regulatory and oversight approach,
FERC lacks assurance that today*s energy markets are producing interstate
wholesale natural gas and electricity prices that are just and reasonable.
FERC*s response to the natural gas price spikes during the winter of 2000-
2001 highlighted the challenges it faces in providing market oversight.
Because FERC did not have a system in place to monitor natural gas spot
markets, it was slow in responding to charges of possible market
manipulation. For example, the investigation into whether Enron
Corporation or others manipulated short- term prices in electric energy or
natural gas markets in the West for the period January 1, 2000, forward
did not begin until February 2002, and remains incomplete almost 2 years
after natural gas prices first spiked. According to FERC, this
investigation should be completed by the first quarter of 2003. Further,
this investigation was largely reactive to complaints and accusations of
improper behavior by energy companies such as Enron, and relies heavily on
requests for information from various energy companies. For example, the
investigation had to rely on energy companies to report back to FERC,
through information requests or *Admit or Deny* orders on whether they had
engaged in any behavior that might have inflated market prices.
Our previous report recommended that FERC take actions to ensure that it
can effectively carry out its responsibilities for overseeing interstate
wholesale natural gas and electricity markets, such as updating its
strategic plan for overseeing energy markets and developing a training
action plan for staff involved or potentially involved in carrying out
FERC*s market oversight functions. We also suggested that the Congress
might wish to convene public hearings to review FERC*s authorization
legislation and determine, in consultation with FERC Commissioners,
whether FERC*s authorities needed to be revised in the light of the
changing energy markets. We also suggested that the Congress might want to
consider providing FERC with the appropriate range of authorities to levy
civil penalties against market participants that engage in anticompetitive
behavior and violate market rules. FERC agreed with the conclusions of our
report and noted that its internal restructuring to support its new market
oversight role has not kept pace with the speed of energy industry
restructuring. Specifically, FERC stated that it needs additional
statutory authority* in particular, the ability to assess a meaningful
range of penalties for violations of the law or FERC rules. To address
organizational problems, FERC created a new Office of Market Oversight and
Investigation whose purpose is to oversee and assess the
Page 30 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
fair and efficient operations of energy markets. OMOI reports directly to
FERC*s Chairman and its responsibilities include understanding energy
markets and risk management, measuring market performance, investigating
compliance violations, and analyzing market data. According to FERC, a
multidisciplinary team of 120 people will staff OMOI and 89 of them have
been hired.
In addition to the statutory and organizational problems that limit its
oversight of energy markets, FERC is in the early stages of assessing what
information it needs to have in order to monitor and regulate competitive
markets for wholesale electricity, and to ensure that open access natural
gas transportation and electric transmission services are provided fairly
and efficiently, without the exploitation of market power. In September
2001, FERC formed a Comprehensive Information Assessment Team to survey
its current data collections to ensure they meet FERC*s traditional and
future information needs. The team*s goal is to assess and propose changes
to FERC*s reporting requirements in order to improve FERC*s monitoring of
competitive markets and performance of traditional regulatory duties.
In addition to these problems, current FERC regulations governing the
conduct of natural gas pipeline companies with affiliates are outdated.
Because these regulations were set in place in 1988, significant changes
have occurred in the natural gas marketplace, such as unbundling, capacity
release, growth of e- commerce, and market growth and consolidation, that
have expanded the number and types of pipeline affiliates. FERC*s current
affiliate regulations do not address the potential exercise of market
power through sharing information among pipeline companies and their
affiliates because the regulations exclude nonmarketing affiliates, local
distribution companies, and affiliated producers and gatherers. FERC
issued a Notice of Proposed Rulemaking in September 2001, which puts forth
new affiliate standards that would apply uniformly to natural gas pipeline
companies by extending standards of conduct to relationships between the
transmission providers, and all affiliates.
CFTC*s regulatory oversight of natural gas derivatives varies among
natural gas derivatives markets. CFTC was created in 1974 to oversee the
nation*s commodity futures and options markets and has a twofold mission:
to foster transparent, competitive, and financially sound markets, and to
protect market users and the public from fraud, manipulation, and abusive
practices in those markets. NYMEX* the largest exchange that trades
natural gas derivatives* is a federally designated contract market CFTC
Regulatory Oversight
Varies Among Markets
Page 31 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
that is fully regulated by CFTC. CFTC staff routinely monitored trading
and price relationships in the NYMEX natural gas contracts and found no
reason to take enforcement action during the 2000- 2001 natural gas price
spike. There are numerous off- exchange, or OTC, derivatives markets that
trade substantial volumes of natural gas derivatives and that are
generally not subject to CFTC regulations. 10 CFTC is currently conducting
an investigation into whether wash trading or other price- manipulative
misconduct occurred in the OTC or spot markets during the price spike
period. However, until CFTC*s investigation is complete, it is unknown,
what role, if any, these markets may have played in the 2000- 2001 natural
gas price spike, or what, if any, enforcement or other actions may result.
NYMEX reported that the average daily contract amount 11 of its
derivatives trades for all of 2001 was $13 billion. As a federally
designated contract market, NYMEX must file all terms and conditions of
traded contracts and contract changes with CFTC. CFTC reviews exchange
rules to ensure that listed contracts are not readily susceptible to
manipulation; oversees the registration of participants on the exchange;
and requires daily reporting of key market and trader position information
such as position size, trading volume, open interest, 12 and prices. NYMEX
participants are subject to CFTC*s antifraud and antimanipulation
provisions, including prohibitions on wash trading. In addition, NYMEX is
required to conduct market surveillance and enforce minimum financial
requirements for its members. Also, because NYMEX acts as a clearinghouse,
13 it protects all participants against counterparty credit risk, which is
the risk of failure by
10 The Commodity Exchange Act (CEA) excludes certain types of derivatives
entirely from the CFTC*s jurisdiction, such as off- exchange swaps between
certain qualifying parties (called *eligible contract participants*) that
are based on broad economic measures like interest rates or stock indices
beyond the control of the parties. The act exempts certain other types of
derivatives from much, but not all, of the CFTC*s jurisdiction, such as
electronically- executed multilateral transactions in energy or metals
commodities among certain qualifying commercial enterprises (called
*eligible commercial entities*), over which the CFTC retains antifraud and
antimanipulation authority.
11 Contract amount is a measure of the volume of certain derivatives (such
as futures and options) that is based on the value of the underlying
contract. 12 Open interest is the total number of futures contracts long
or short in a delivery month or market that have been entered into and not
yet liquidated by an offsetting transaction or fulfilled by delivery.
13 A clearinghouse is an institution that acts as the buyer to every
seller and the seller to every buyer, thereby guaranteeing performance on
a contract.
Page 32 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
a contract counterparty to settle the contract by paying funds as they
become due as a result of the trade.
For NYMEX natural gas contracts, CFTC market surveillance staff told us
they found no market problems that required CFTC intervention during the
winter of 2000- 2001. Surveillance staff told us that because no unusual
problems or excessive speculative positions were identified during this
period using the customary daily surveillance tools and procedures, no
special reports were prepared by CFTC pertaining to the price spike. Based
on its monitoring, CFTC concluded that NYMEX natural gas contracts behaved
normally during this period and that natural gas futures prices, though
high, were driven by supply and demand. Because of the high prices and
price volatility during this period, the natural gas futures market was
discussed at 18 of the Commission*s weekly surveillance briefings in
September 2000 through March 2001, which represented a high frequency for
the commodity.
Natural gas OTC markets are structured differently than NYMEX and
generally are not subject to CFTC regulation. Natural gas OTC derivatives
can be traded on multilateral basis (typically on an electronic trading
facility in which multiple buyers and sellers participate) or on a
bilateral, or principal- to- principal basis, which may also be through an
electronic trading facility. Unlike exchange- traded derivatives, the
maturity dates, quantities, and delivery points for the commodities
underlying the derivatives offered in the OTC markets are negotiable among
participants and are not subject to CFTC review and approval. The
Commodity Futures Modernization Act (CFMA) of 2000 provided a series of
exclusions and exemptions that removed these markets from most of CFTC*s
regulatory authority. Therefore, these markets typically are not subject
to daily monitoring by CFTC. However, CFTC can take action to address the
use of OTC transactions in natural gas derivatives, other than swaps, to
manipulate the underlying commodity and, depending on the parties to the
transactions, the Commission can take action to prevent or address fraud.
14 Also, CFTC has authority to investigate manipulation of commodity
prices. Finally, participants in the OTC derivatives markets generally
bear counterparty credit risk, but a clearinghouse function is
14 Nonswap bi- lateral natural gas OTC transactions between eligible
commercial entities are subject to provisions in the CEA prohibiting
manipulation. Such transactions involving participants that do not qualify
as eligible commercial entities are also subject to CEA antifraud
provisions. Multilateral natural gas derivatives traded on an electronic
exchange are subject to both the antimanipulation and antifraud
provisions.
Page 33 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
legally permitted. For example, the Intercontinental Exchange, an OTC
multilateral energy derivatives trading facility, has a clearing service.
NYMEX also clears OTC energy derivatives.
During the natural gas price spike of 2000- 2001, CFTC, consistent with
its lack of general regulatory authority, did not monitor or assess
activity in the OTC markets. However, during congressional testimony in
March 2002, CFTC Chairman Newsome confirmed that CFTC was among the
federal agencies investigating Enron. Subsequently, in May 2002,
responding to widely publicized concerns about wash trading in gas and
power markets, Chairman Newsome stated that CFTC was investigating various
energy trading schemes, including possible wash trading, in these markets.
However, CFTC, consistent with agency policy, would not discuss the nature
or extent of its ongoing investigations. As a result, the scope of its
investigations and the authority upon which they are being undertaken is
unknown.
Further, it remains unclear what information CFTC may rely upon,
conclusions it may draw, or enforcement or other actions it may take in
relationship to the role the OTC markets may have played, if any, in the
natural gas price spike of 2000- 2001. However, in October 2002, the CFTC
Chairman said that the agency*s investigations, in addition to leading to
formal actions, might reveal facts that cause CFTC to revisit its rules or
to suggest legislative changes.
EIA* the federal agency responsible for analyzing energy price movements*
reports that its ability to understand the market price of natural gas has
declined significantly, largely because most elements of its data
collection program for the industry were set in place before the
industry*s restructuring. Most elements of EIA*s natural gas data
collection program have been in place for more than 20 years, when
pipelines and local distribution companies owned the natural gas in their
custody and knew its purchase and sales price. In that environment, EIA
designed its data collection program to survey a relatively small number
of firms to obtain a complete picture of the industry. Today, pipeline and
distribution companies do not know the prices of the gas they transport
for others, and most industrial and commercial gas is priced in unreported
private deals. In addition, entities that did not exist a decade ago*
marketers, independent storage facilities, spot markets, and futures
markets* are central to the operation of the industry. Because of these
changes in the industry, the data collected under EIA*s outdated approach
have come to describe only a portion of the industry. EIA Is Trying to
Modernize
Outdated Data Collection Program
Page 34 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
EIA has recognized that its collection of data on prices and volumes needs
to be timelier because the natural gas market is no longer based solely on
long- term contracts. With some exceptions, EIA*s current natural gas data
collection program remains basically an annual effort to obtain
comprehensive information on natural gas volumes and prices. Monthly data
series are less complete and the largest monthly survey is a sample survey
selected from respondents to the core annual survey. In response to the
problems in data coverage and quality, EIA began a review in 1998, called
the Next Generation Natural Gas Initiative, to assess the effect of
industry restructuring and shifting customer needs on its future natural
gas information program. This review includes efforts to identify data
quality problems in EIA*s current price and volume series as well as
requirements for new kinds of data. After a period of public comment in
March of this year, EIA submitted a proposal to the Office of Management
and Budget for its review that would update EIA*s natural gas data
collection program package. EIA expects OMB to make final approval of
changes to EIA*s information program in December 2002, so that the changes
take effect in January 2003.
In addition, EIA has recently began to provide more real time market
information that traders and other gas industry analysts use as an
indicator of both supply and demand. On May 9, 2002, EIA began releasing
weekly estimates of natural gas in underground storage for the United
States and three regions of the United States* a key predictor of future
natural gas price movements. EIA began this weekly estimate because AGA
discontinued its own estimate of natural gas in storage, with its final
weekly report dated May 1, 2002. EIA has also undertaken efforts to better
understand derivatives markets. In February 2002, the Secretary of Energy
directed EIA to report on, among other things, how derivatives are being
used and to discuss the impediments to the development of energy risk
management tools. A draft EIA report, scheduled for release in December
2002, states that, when properly used, derivatives are generally
beneficial in managing risk. EIA concluded that all available evidence
indicates that the oil industry in particular, and the natural gas
industry to a lesser extent, has successfully used derivatives to manage
risk. However, EIA found that continuing problems with the reporting of
natural gas price data and with pipeline transmission costs might be
denying the benefits of derivatives to many potential users.
Page 35 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Residential customers who rely on natural gas to heat their homes are
especially vulnerable to price spikes because they may have limited
ability to switch to alternate fuels for heating their homes or to obtain
gas from sources other than the gas utility companies. Therefore, when the
gas utilities pay higher wholesale prices for natural gas, residential
customers usually see their heating costs increase as well. This is true
because a majority of gas utility companies, under state or local
regulatory oversight, pass their gas costs on to their customers. However,
utility companies can use various techniques to protect or hedge against
the risk of rising natural gas costs by locking in the prices they will
pay for gas purchased for residential customers. Hedging does not,
however, ensure that a utility company will pay the lowest possible price
for future natural gas purchases: it simply provides stable gas prices and
protection against price spikes such as the one that occurred in 2000-
2001. Hedging may result in the utility company paying natural gas prices
that are higher or lower than the prevailing market price. In the 5 years
prior to the recent price spike, between 20 percent of the small and 45
percent of the large gas utility companies responding to our survey
reported that they did not hedge any of their natural gas purchases.
Further, industry data that we reviewed showed that prior to and during
the winter of 2000- 2001, many gas utility companies were relying more on
shorter- term contracts and the more expensive spot market for the gas
they were purchasing to satisfy customer needs throughout the winter
heating season. As a result, a significant number of gas utilities likely
had to pay higher prevailing market prices when they purchased the natural
gas needed to satisfy their customers* needs in 2000- 2001, and these
higher prices were likely passed on to their customers. This recent price
spike increased the importance of price stability for those gas utilities
that serve residential customers and the regulatory agencies that oversee
this service. As a result of the 2000- 2001 price spike, gas utilities
have increased their use of hedging when buying natural gas. Ninety
percent of the utilities responding to our survey reported that after the
price spike they made plans to hedge some portion of their gas supply for
the winter of 2001- 2002.
Gas utilities can use several hedging techniques to stabilize their gas
supply costs and thereby protect their customers against the unpredictable
price behavior of natural gas. Hedging techniques include both physical
and financial tools. Physical tools, which are widely used by gas
utilities, include the following:
Storage of gas for future use can provide a hedge against the effects of
price volatility. According to industry officials, many gas utility
companies Consumers Can Be
Protected against Price Spikes
Various Tools Are Available to Protect against Rising Gas Prices
Page 36 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
have traditionally purchased a portion of their gas supply during the
warmer summer months when prices are lower and stored the gas for use
during the winter heating season when prices are typically higher.
However, there are costs associated with storing natural gas and, because
it is stored underground in geologic formations, such as salt caverns, and
in depleted oil and gas wells located in 30 states, not all gas utility
companies can take advantage of this tool. Fixed price contracts, or
forward contracting arrangements, can also
provide a hedge against price volatility. Under such an arrangement, a
utility agrees to take delivery of a set amount of natural gas at a
specified time, price, and location. However, the buyer must pay the
contract price even if the market price at the time of purchase is lower.
For those gas utility companies that cannot or do not want to rely on
physical hedges, various derivatives can also provide protection against
increasing gas prices. Derivatives are contracts whose value is linked to,
or derived from, the price of the gas itself. There are costs associated
with using all derivatives, but most of the state regulatory agencies we
surveyed allow gas utilities to recover these costs through their gas
rates. Derivatives include natural gas futures, options, and swaps.
Futures contracts that are traded on regulated exchanges, such as NYMEX
generally are standardized. A gas utility that purchases a futures
contract or an options contract through NYMEX is protected against
counterparty credit risk. Simply stated, the financial performance of both
the buyer and the seller of futures and options are guaranteed by the
exchange. A natural gas futures contract may be purchased to lock in a
future price for up to 72 months in the future and natural gas options can
be used to guarantee prices in increments of $0.05 per mmBtu for various
time periods. For example, a purchaser of a futures contract traded on
NYMEX makes a legal commitment to take delivery of 10, 000 mmBtu of gas at
the Henry Hub in Louisiana on a specified date in the future. However,
hedgers who buy futures contracts usually do not take delivery of the gas.
According to a NYMEX official, less than 1 percent of the gas futures
contracts traded on the exchange result in physical delivery of the
commodity. Instead, those holding futures typically sell the contracts
through NYMEX before the contractual date of delivery at the going market
price. Then, whatever profit or loss accrues from this transaction offsets
the change in natural gas prices from the time they bought the contract to
when they buy gas for delivery. For example, in March a gas utility
company wishing to hedge against a possible future price increase buys a
futures contract for gas to be delivered in January at $4.60. If the
January cash price later increases to $5.15, the company can buy its gas
on the spot market for $5.15 and sell
Page 37 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
the futures contract on NYMEX for $5.15 thereby accruing a gain of $. 55
on the futures contract and a net gas cost of $4.60. If, however, the
January cash price drops to $4. 25, the company could buy its gas at this
price, sell the futures contract at $4.25 and take a loss of $0.35. But,
the company*s net gas cost would still be $4.60. Options, which can be
bought for a premium on NYMEX or in the OTC
markets, give a utility the right, but not the obligation, to buy or sell
natural gas at a certain price at some time in the future. Some analysts
believe that purchasing options is the best way for gas utility companies
to hedge against possible price increases, because the utility holding an
option is protected against possible increases in the price of gas, but at
the same time has the ability to participate in any downward changes in
price. Swaps generally provide more flexibility to users than do
exchange- traded
futures because their terms can often be individually negotiated, such as
for different amounts of gas and for different delivery points. However,
natural gas swaps are traditionally traded in the OTC markets, and these
markets often do not provide the same level of protection against credit
exposure as NYMEX.
A gas utility company that follows a hedging strategy is not guaranteed
that it will pay the lowest price for natural gas. In fact, minimizing
price volatility through hedging and minimizing gas costs (beating the
market) are two entirely different objectives. A hedging strategy for a
gas purchaser aims at gaining more certainty with respect to future costs,
or avoiding exposure to large price fluctuations in the future that could
come from total reliance on spot market prices. This is a different
strategy from one that tries to secure the lowest possible prices in the
future. Neither strategy is costless, and parties that use them risk that
their effective costs, after the fact, may be higher than those of
alternative strategies.
To show how a hedging strategy can result in prices that are lower or
higher than spot market prices, we conducted an analysis based on a
hypothetical utility and actual spot and futures gas prices.
We constructed a hypothetical gas utility, GU- H, whose gas use patterns
mirror, on a smaller scale, the pattern of residential gas consumption in
the United States from 1990 through 2001. We modeled GU- H so that its gas
requirements each month are equal to about 2.5 percent of residential gas
consumption in the United States. This makes GU- H a fairly large gas
utility. Hedging Does Not
Guarantee the Lowest Possible Gas Prices
Page 38 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
We assumed that GU- H follows a hedging strategy whereby it purchases
NYMEX gas futures contracts for the months of November through March* the
months for which it has the highest gas requirements during the year. We
assumed GU- H purchases the same amount of NYMEX contracts for
each month of the winter season every year, based on its estimate of
*baseload* for that month. We assumed that its baseload estimate is equal
to the lowest amount of gas used for that month from 1990 through 2001.
For example, the lowest amount of gas GU- H used during the month of
January was in 1992 at slightly under 20 bcf, so we assumed that GU- H
hedges this amount for the month of January each year. We assumed GU- H
effectively *locks- in* prices for the coming November
through March by purchasing NYMEX gas futures contracts on the first
trading day in April of each year. For example, on April 3, 2000, GU- H
purchased NYMEX gas contracts for the months of November and December 2000
and January through March of 2001. We assumed a transactions cost for
the NYMEX contracts based on
conversations with NYMEX officials. This cost was added to the hedged cost
of gas, but it is relatively small. We assumed that monthly amounts of
natural gas used above the baseload
amounts covered by the futures contracts were bought on the spot market at
a price indexed to a monthly average spot price at the Henry Hub,
effectively resulting in zero transmission costs, another simplifying
assumption.
Given the above, we compared the cost of GU- H*s gas purchases for the
winter months of November through March with and without a hedging
strategy. Without hedging, GU- H purchases all its gas requirements on the
spot market at the monthly spot price. Table 1 summarizes the results of
our analysis with respect to GU- H*s gas purchase costs from the 1990-
1991 winter through the 2001- 2002 winter.
Table 1: Results of a Hypothetical Gas Utility (GU- H) Hedging Gas
Purchases Versus Relying on Spot Market Prices for Winters 1990 through
2001
Dollars in millions
Winter Heating Season (November through March) 90- 91 91- 92 92- 93 93- 94
94- 95 95- 96 96- 97 97- 98 98- 99 99- 00 00- 01 01- 02
Unhedged gas costs $136.8 $120.6 $175.2 $202.1 $122.5 $270.4 $275.3 $205.6
$152.2 $201 $644.3 $192.1 Hedged gas costs 155.1 156.4 153.5 193.9 179.4
196.1 209.6 195.7 214.3 195.2 368.7 412.7 Hedging gain (loss) (18.3)
(35.8) 21.7 8. 2 (56.9) 74.3 65.7 9. 9 (62.1) 5.8 275.6 (220.6)
Source: GAO analysis of EIA, NYMEX, and other data.
Page 39 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
As the table shows, GU- H*s hedging strategy would have resulted in net
savings over the spot market price in gas purchase costs for some winter
seasons and losses for others. For the winter of 2000- 2001, the savings
would have been unusually large* over $275 million* because spot market
prices turned out to be far higher than NYMEX futures prices. However, the
very opposite would have been the case in the winter of 2001- 2002, when
GU- H*s losses would have been over $220 million.
We also calculated the effective monthly prices for the winter months with
and without hedging. Interestingly, over the 11- year period, the overall
average price paid for gas under the two scenarios was virtually the same,
at about $2.56 per mmBtu for the unhedged case and $2.57 per mmBtu for the
hedged case. 15 However, the level of volatility was greater for the
unhedged case. According to one commonly used measure of deviation from
averages (standard deviation), the hedged case resulted in considerably
less exposure to price volatility than the unhedged case. A measure of
dispersion from the average price was about $1.41 for the unhedged case
and only about $0.97 for the hedged case. Figure 10 shows a comparison of
hedged and unhedged gas prices for a hypothetical gas utility.
15 These are simple averages in the sense that they are not *weighted* by
the quantities of gas purchased/ delivered for the individual months.
Page 40 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Figure 10: Comparison of Hedged and Unhedged Gas Prices for Hypothetical
Gas Utility
Note: Figure 10 plots average prices for November through March for the
hypothetical gas utility GU- H.
Following the price spike in 2000- 2001, many gas utilities took steps to
protect themselves and their customers against a repeat of the soaring
prices that marked that period. According to our survey, since the natural
gas price spike in 2000- 2001, many gas utilities have increased their
focus on achieving stable prices for their customers. In fact, 87 percent
of the small utilities and 74 percent of the large utilities responding to
our survey reported this goal is very important or extremely important to
them. Previously, only 72 percent of the small utilities and 48 percent of
the large utilities thought that stable prices were very important or
extremely important. In addition, the efforts of utilities to provide more
stable prices Prices in 2000- 2001
Prompted Gas Utilities and State Regulatory Agencies to Act to Mitigate
Future Price Spikes
Page 41 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
for their customers have received more support from state regulatory
agencies. For example, state regulatory officials from 29 of the 48
agencies that we spoke with told us that they consider it very important
or extremely important for gas utility companies to work toward achieving
stable prices for their residential customers. Before the gas price spike
in 2000- 2001, only 14 agencies surveyed had considered this goal to be
very important or extremely important.
Consistent with the increased importance of stable prices, many gas
utilities increased the percentage of their gas supply that they hedged
after the winter price spike of 2000- 2001. During the 2000- 2001 winter,
20 percent of the large utilities and 32 percent of the small utilities
that responded to our survey did not hedge any of their winter gas supply
for residential customers. As a result, these utilities had to pay the
prevailing high spot market prices for gas, resulting in higher bills for
their customers. In contrast, during the 2001- 2002 winter, only 10
percent of these utilities did not hedge any of their winter gas supply
for residential customers. About 63 percent of the large utilities and 81
percent of the small utilities that responded to our survey reported that
they hedged at least one- half of their winter gas supply during 2001-
2002. In comparison, during the previous year, about 44 percent of the
large utilities and 56 percent of the small utilities hedged at least one-
half of their gas supply. In addition, a recent survey of 52 companies
completed by AGA found that a majority of them planned to increase their
use of hedging techniques to protect at least part of their gas supply
portfolios from future price spikes. According to an AGA official, the
extreme price volatility experienced during the winter of 2000- 2001 made
it clear to many gas utilities that hedging a portion of their gas supply
helped to shield their customers from dramatic increases in natural gas
prices. As figure 11 shows, since 1995, the number of utilities that do
not hedge any of their gas supply for residential customers has steadily
decreased.
Page 42 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Figure 11: Percentage of Gas Utilities That Hedged None of Their Winter
Gas Supply for Residential Customers, 1995- 2002
Many gas utility companies continued to use fixed price contracting and
storage as the primary tools for stabilizing their gas acquisition costs.
However, some gas utilities also used derivatives, including futures,
options, and swaps, as a way of stabilizing their gas costs. Table 2 shows
that the gas utility companies that responded to our survey used physical
hedging tools much more than derivatives, and large utilities reported
much higher use of financial hedging techniques than small utilities.
Page 43 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Table 2: Percentage of Gas Utility Companies That Reported Using Hedging
Techniques in Gas Purchases for 2000- 2001
Hedging techniques Large utilities
(percentage) Small utilities
(percentage)
Physical tools Storage 84 49 Fixed price contracts 56 65 Financial tools
Futures 35 24 Options 36 4 Swaps 28 5
Source: GAO analysis of survey data.
Overall, 57 percent of the large gas utility companies and 47 percent of
the small gas utility companies responding to our survey reported that
they had increased their use of one or more hedging techniques since the
2000- 2001 winter. Table 3 shows the specific changes in the use of
different hedging techniques among the utility companies. More details on
the gas utilities* responses to our survey questions can be found in
appendixes II and III.
Table 3: Changes in Utilities* Use of Hedging Techniques since Winter of
2000- 2001 Percentage using hedging technique Percentage not currently
using hedging technique Use has increased Use has remained
the same Use has decreased Plan to use in the next 12
months Do not plan to use in the next 12 months
Large utilities Physical tools Storage 13 72 0 2 13
Fixed price contracts 42 36 2 5 14
Financial tools Futures 23 29 2 8 38
Options 20 30 5 9 36
Swaps 18 30 1 7 43
Small utilities Physical tools Storage 9 510 3 37
Fixed price contracts 34 42 4 6 15
Financial tools Futures 22 19 1 5 52
Options 5 132 5 75
Swap 3 171 1 79
Source: GAO analysis of survey data.
Page 44 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
According to our survey of state regulatory agencies, most allow the gas
utilities under their jurisdiction to use hedging techniques when they
purchase gas for their residential customers. However, despite an
increasing openness to the idea of hedging tools, these regulatory
agencies favored the use of physical hedging tools over financial tools.
Table 4 reflects the positions of state regulatory agencies on the use of
hedging tools by the gas utilities they regulate.
Table 4: State Regulatory Agency Policy Concerning Gas Cost Stabilization
Tools Cost stabilization tool
Number of state agencies allowing use of
the tool Number of state
agencies not allowing use of
the tool Does not apply a No response
Physical tools Storage 45 0 3 0 Fixed price contracts 45 0 3 0 Financial
tools
Futures 42 1 5 0 Options 40 3 5 0 Swaps 36 1 10 1
Note: We surveyed the 48 continental states and the District of Columbia.
The Nebraska Public Service Commission declined to respond because natural
gas is regulated on a local level and the Commission handles only pipeline
disputes. a Either the tool is not available in a certain area or the
agency has not addressed the tool in its policy.
Source: GAO analysis of survey data.
In general, state regulatory agencies that allow gas utilities to use
hedging tools do not restrict the amount of gas purchased through use of
these tools. In addition, a large percentage of the gas utilities
responding to our survey reported that their regulatory agency allows them
to recover all costs associated with hedging. And, while 90 percent of the
utilities regulated by state agencies reported being subject to prudence
audits of their gas- buying strategy, only 7 percent have had costs
associated with gas purchases disallowed by an agency because of such an
audit. More details concerning the state regulatory officials* responses
to our survey questions are shown in appendixes IV and V.
Although the federal government is not a direct regulator of natural gas
prices, it has an interest in promoting a competitive and informed natural
gas marketplace that protects the public from unnecessary price
volatility. The principal tools available to federal agencies to promote a
competitive natural gas marketplace and protect the public from price
volatility Conclusions
Page 45 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
include monitoring for anticompetitive behavior; taking appropriate
enforcement actions where necessary; and providing decision- makers in
industry and government with sound, up to date, natural gas marketplace
information, such as short- term price movements and long- term demand and
supply trends. However, at this date, the federal government faces major
challenges in meeting its role of ensuring that natural gas prices are
determined by supply and demand factors in a competitive and informed
marketplace.
We had previously recommended that FERC take actions to update its
strategic plan and to develop an action plan for overseeing energy
markets, so that it could more effectively carry out its responsibilities
for overseeing interstate wholesale natural gas and electricity markets.
We continue to believe these steps are important and are encouraged that
FERC is beginning actions to address this recommendation. FERC recognizes
that it needs to improve its market oversight and is reviewing its
statutory authority and market monitoring tools. In addition, we suggested
and continue to believe that the Congress might wish to convene public
hearings to review FERC*s authorizing legislation and determine, in
consultation with FERC Commissioners, whether FERC*s authorities need to
be revised in light of the changing energy markets. Of particular concern
would be any changes needed to support FERC*s new Office of Market
Oversight and Investigation. CFTC, consistent with its authority, did not
monitor activity in the OTC markets during the winter of 2000- 2001, but
it is continuing its investigation into whether OTC energy derivatives
markets were manipulated during this period. Findings from these
investigations may lead to enforcement actions and may also highlight the
need for changes in federal oversight. Finally, EIA has recognized the
need to collect more accurate and timely data on the natural gas market
and has begun taking steps to update its data collection program for
natural gas. We support these efforts and believe it is important that the
agency continue to refine its efforts to provide more timely natural gas
market data and focus on implementing changes to its natural gas data
collection program as soon as possible.
We provided FERC, EIA, and CFTC with a draft of this report for review and
comment. FERC generally agreed with our conclusions (see app. VI), and
noted that it previously lacked an adequate regulatory and oversight
approach to monitor a restructured natural gas industry. FERC stated that
with the creation of its Office of Market Oversight and Investigation it
has taken the steps needed to oversee and assess the fair and efficient
operation of electric power and natural gas markets. In addition to its
Agency Comments
Page 46 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
letter, FERC provided us with technical changes to our draft, which we
incorporated into the final report as appropriate. EIA generally agreed
with our conclusions (see app. VII), and noted that it recognized the need
to collect more accurate and timely data on the natural gas market and has
begun taking steps to update its data collection program for natural gas.
In addition to its letter, EIA provided us with technical changes to our
draft, which we incorporated into the final report as appropriate. CFTC
did not provide us a formal letter, but met with us to provide us with
technical changes, which we incorporated into the report as appropriate.
It also generally agreed to our conclusions.
Copies of this report will also be sent to the FERC Chairman, the CFTC
Chairman, the DOE Secretary, and other interested parties. We will make
copies available to others upon request. In addition, the report will be
available at no charge at GAO*s Web site at http: www. gao. gov.
Questions about this report should be directed to me at (202) 512- 3841.
Key contributors to this report are listed in appendix VIII.
Jim Wells Director, Natural Resources
and Environment
Page 47 GAO- 03- 46 Analysis of Changes in Natural Gas Prices List of
Addressees
The Honorable Jeff Bingaman Chairman The Honorable Frank Murkowski Ranking
Minority Member Committee on Energy and Natural Resources United States
Senate
The Honorable Joseph I. Lieberman Chairman The Honorable Fred Thompson
Ranking Minority Member Committee on Governmental Affairs United States
Senate
The Honorable Tom Harkin The Honorable Fred Thompson United States Senate
The Honorable W. J. *Billy* Tauzin Chairman The Honorable John D. Dingell
Ranking Minority Member Committee on Energy and Commerce House of
Representatives
The Honorable Dan Burton Chairman The Honorable Henry A. Waxman Ranking
Minority Member Committee on Government Reform House of Representatives
The Honorable Spencer Bachus The Honorable Ed Bryant The Honorable Bob
Clement The Honorable Bud Cramer The Honorable Bob Etheridge The Honorable
Bart Gordon The Honorable Edward J. Markey The Honorable Janice D.
Schakowsky The Honorable John M. Spratt, Jr. The Honorable John Tanner
Page 48 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
The Honorable Mike Thompson The Honorable Zach Wamp House of
Representatives
Appendix I: Objectives, Scope, and Methodology
Page 49 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
In our study of the natural gas market, we addressed (1) the factors that
influence price volatility and, in particular, the high prices that
occurred during the winter of 2000- 2001; (2) the federal government*s
role in ensuring that natural gas prices are determined in a competitive
and informed marketplace; and (3) choices available to gas utility
companies that want to mitigate the effects of future price spikes on
their residential gas customers.
To address these objectives, we reviewed pertinent documents and obtained
information and views from a wide range of officials in both government
and the private sector. Our review encompassed the entire natural gas
market from the wellhead, where gas is produced and first valued, to the
end- user. We obtained information and views from federal, state, and
local agencies and from natural gas industry officials through a variety
of means, including interviews and surveys. We interviewed analysts from
the Department of Energy*s Energy Information Administration (EIA), the
Federal Energy Regulatory Commission (FERC), the Commodity Futures Trading
Commission (CFTC), the New York Mercantile Exchange (NYMEX), companies
involved in over- the- counter gas markets, such as the Intercontinental
Exchange, and state utility regulatory commissions, to obtain their views
on the factors that influence natural gas prices. We also discussed
natural gas prices with representatives from various industry
organizations, including the American Gas Association (AGA), the American
Public Gas Association (APGA), the National Association of Regulatory
Utility Commissioners (NARUC), the National Association of State Utility
Consumer Advocates, the Natural Gas Supply Association, the Independent
Petroleum Association of America, and the Interstate Natural Gas
Association of America. Finally, we spoke with various individuals who
work in the natural gas industry, including experts working at production
companies, gas marketing companies, and gas utilities.
In addition to our interviews, we obtained and analyzed natural gas price
data supplied by the EIA, Data Resources, Incorporated (DRI), and NYMEX.
The EIA provided wholesale gas prices, city gate prices, and enduser
prices by customer class and by state, while the DRI database provided
prices for the Henry Hub spot market prices and NYMEX officials provided
prices for NYMEX natural gas futures contracts. Our analyses focused on
how gas prices have behaved since 1993, when natural gas wholesale prices
became fully deregulated. We also collected and analyzed data on factors
that influence natural gas supply and demand, such as production, storage,
consumption, weather, and gas- fired electric generation, as well as data
on natural gas derivatives trading. Appendix I: Objectives, Scope, and
Methodology
Appendix I: Objectives, Scope, and Methodology
Page 50 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Because residential customers usually have limited ability to switch to
alternate fuels and few choices concerning who will supply their natural
gas, we concentrated on determining how high prices affected this group of
end users and what gas utilities can do to protect them from future price
spikes.
We also reviewed laws and regulations pertaining to CFTC*s, EIA*s, and
FERC*s responsibilities for monitoring and providing information about the
natural gas market. In addition, we identified key changes in natural gas
regulation and in the development of the natural gas market that changed
how gas prices are established. We also examined pertinent CFTC, EIA, and
FERC documents, including annual reports and filings, staff research
papers, fact sheets, reports, and congressional testimonies.
We surveyed a sample of both investor- owned and municipally- owned gas
utility companies to determine how they acquire their natural gas and what
actions they have taken or plan to take to mitigate the effects of future
price spikes. We identified our sample primarily from the lists of member
utilities belonging to the AGA and the APGA. The AGA generally represents
larger, investor- owned gas utilities; whereas, the APGA generally
represents smaller, municipal gas utility companies. Since some companies
were members of both organizations, we adjusted our sample by removing
duplicates from the APGA list. We also included in our survey four large
gas utility companies, which were identified by AGA staff as major
utilities that are not members of their organization. Thus, our overall
population consisted of all gas utility companies in the United States
that were members of either the AGA or APGA, plus four additional
companies.
We sent survey questionnaires to the 112 gas utilities on AGA*s membership
list, plus the 4 large investor- owned utilities that are not members of
the AGA. In addition, we selected 17 large municipal utilities from APGA*s
members list of 923 utilities for inclusion in our survey. Each of these
17 companies reported that it serves more than 20, 000 customers. Thus,
the first group of gas utilities we surveyed, referred to as the AGA
group, consisted of 133 companies that serve large customer bases and
deliver a large majority of the total volume of natural gas sold in this
country. According to AGA, their members plus four additional large
companies account for more than 90 percent of the natural gas delivered by
gas utilities annually in the United States. We then selected a
statistical sample from the remaining 906 (923* 17) municipally- owned gas
utilities found on the APGA members list. Our sample consisted of 342
municipal utilities, which provided 95 percent confidence intervals of +5
percentage
Appendix I: Objectives, Scope, and Methodology
Page 51 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
points. Thus, our second group of gas utilities, referred to as the APGA
group, consisted of 342 municipal companies that tend to have smaller
customer bases. Before mailing our survey questionnaire to the two groups,
we pretested it at six utility companies across the country that serve a
range of customers. During these visits, we administered the survey and
asked the utility staff to fill out the survey as if they had received it
in the mail. After completing the survey, we interviewed the respondents
to ensure that (1) the questions were clear and unambiguous, (2) the terms
we used were precise, (3) the questionnaire did not place an undue burden
on the staff completing it, and (4) the questionnaire was independent and
unbiased.
We did not receive a high enough response rate to our survey of gas
utility companies to allow us to generalize the results of our analysis to
all gas utilities located in the United States. We did, however, receive
responses from 90 or 68 percent of the 133 companies in the first group
(AGA list) and 179 responses or 52 percent of the 342 companies in the
second group (APGA list). Because we cannot generalize the results of our
survey, we have reported the results from the two groups* large utilities
(AGA) and small utilities (APGA)* separately.
We also surveyed staff from the utility regulatory agencies of the 48
contiguous states and the District of Colombia. We did not include Alaska
and Hawaii in our survey, as these states are unique in their use of
natural gas because their geographic locations separate them from the rest
of the country*s natural gas infrastructure. We pretested our
questionnaire with the regulatory agencies in Maryland, New Mexico, and
the District of Columbia and then completed a structured interview with
staff from the 48 states and the District of Colombia. However, because
the Nebraska Public Service Commission does not regulate gas utility
companies (such regulation occurs at the local government level), we
exempted this state from our analysis of regulatory agencies. To identify
the most qualified person within the agencies to contact, we obtained a
list from NARUC, whose members include the governmental agencies that are
engaged in the regulation of utilities and carriers of telecommunications,
energy, and water. In cases where NARUC was unable to provide a contact,
we called the agency directly.
We performed our review from June 2001 through September 2002 in
accordance with generally accepted government auditing standards. However,
we were unable to assess the accuracy of the natural gas prices and other
information provided by the EIA or the DRI database, as no resources exist
to verify this data.
Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
Page 52 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
We mailed a questionnaire to 475 from a population of 1,039 gas utilities
in the continental United States. The questionnaire, reprinted below,
contained 33 questions covering the utility*s basic characteristics, gas
purchasing strategy for residential customers, use of hedging tools, and
regulatory framework.
In the following results we provide statistics for our two sampling
groups. We identified these groups primarily from the lists of member
utilities belonging to AGA and APGA. The first group consists primarily of
AGA members, which are generally large, investor- owned gas utilities.
This group also includes four large investor- owned utilities identified
by AGA staff as the investor- owned utilities that did not belong to their
organization, as well as the 17 companies on the APGA list that reported
serving more than 20,000 natural gas customers. For simplicity, in the
results we refer to this group as AGA. The second group consists of a
sample of the APGA mailing list, which tend to be small, municipally owned
gas utilities. In the results we refer to this group as APGA. We received
responses from 269 utilities; 90 from AGA members for a response rate of
68 percent and 179 from APGA members for a response rate of 52 percent.
For most of the questions of the reprinted survey, we identified the
percent of utilities that marked each box to each question. For other
questions, we included tables of the responses in appendix III and
referred the reader to these tables. For the questions on population, we
included the mean, median and range of responses. Also, several gas
utilities did not respond to each question, so some questions have fewer
total respondents than others. We included the number of respondents to
each question, with N referring to the total number of respondents that
answered a question and n referring to the number of respondents that
indicated a certain answer to a question. Appendix II: Results of
Investor- Owned and
Municipally Owned Utility Survey
Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
Page 53 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
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Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
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Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
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Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
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Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
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Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
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Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
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Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
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Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
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Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
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Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
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Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
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Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
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Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
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Appendix II: Results of Investor- Owned and Municipally Owned Utility
Survey
Page 68 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Appendix III: Additional Results of InvestorOwned and Municipally Owned
Utility Survey
Page 69 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
The tables in this appendix list results from our survey of 269 gas
utilities that could not be displayed in the body of the survey. Table 5
identifies the percentage of the residential customers* gas supply that
gas utilities planned to hedge during the winters of 1995- 1996 through
2001- 2002. It is likely that fewer utilities answered for earlier years
because some companies do not keep records for many years. Table 6
identifies the percentage of the residential customers* gas supply that
gas utilities actually hedged during the winters of 2000- 2001 and 2001-
2002. Table 7 identifies the volumes that gas utilities planned to
purchase and actually purchased for residential customers in the winters
of 1999- 2000 through 2001- 2002. These volumes cannot be directly
compared in some cases because the number of respondents may differ.
However, as shown in appendix II, differences between planned and actual
gas purchases were in large part due to changes in weather. Finally, table
8 identifies how much of utilities* gas supply came from storage on
average over the last 5 years.
Table 5: Gas Utilities* Planned Use of Hedging for Residential Customers
AGA Percentage of natural gas supply utilities planned to hedge during the
winter heating season
1995- 1996 (N= 44)
1996- 1997 (N= 43)
1997- 1998 (N= 45)
1998- 1999 (N= 48)
1999- 2000 (N= 81)
2000- 2001 (N= 84)
2001- 2002 (N= 86)
0 39 35 27 23 212010 1 to 49 43 49 42 42 38 36 27 50 to 99 14 12 24 29 32
37 52 100 5 5 7 6 9710
APGA Percentage of natural gas supply utilities planned to hedge during
the winter heating season
1995- 1996 (N= 88)
1996- 1997 (N= 89)
1997- 1998 (N= 93)
1998- 1999 (N= 96)
1999- 2000 (N= 159)
2000- 2001 (N= 159)
2001- 2002 (N= 159)
0 45 42 41 36 313210 1 t o 4 9 7 7 6 914129 50 to 99 20 24 24 30 28 31 46
100 27 28 29 24 28 25 35
Source: GAO.
Appendix III: Additional Results of InvestorOwned and Municipally Owned
Utility Survey
Appendix III: Additional Results of InvestorOwned and Municipally Owned
Utility Survey
Page 70 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Table 6: Gas Utilities* Actual Use of Hedging for Residential Customers
during the Winters of 2000- 2001 and 2001- 2002
AGA Percentage of natural gas supply utilities actually hedged
2000- 2001 (N= 85)
2001- 2002 (N= 46)
0 189 1 to 49 44 26 50 to 99 31 57 100 8 9
APGA Percentage of natural gas supply utilities actually hedged
2000- 2001 (N= 161)
2001- 2002 (N= 86)
0 3012 1 to 49 16 12 50 to 99 29 38 100 25 38
Source: GAO.
Table 7: Gas Utilities* Planned and Actual Volumes of Natural Gas
Purchased during the Winter Heating Season for Residential Customers
AGA Median Range N=
Planned volumes 1999- 2000 4,373,786 46,647- 200,000,000 73 2000- 2001
4,229,400 49,127- 210,000,000 73 2001- 2002 4,940,969 46,800- 220,000,000
73 Actual volumes
1999- 2000 3,652,357 46,647- 193,000,000 73 2000- 2001 4,865,541 49,127-
228,000,000 73
APGA Median Range N=
Planned volumes 1999- 2000 97,708 5, 100- 154,000,000 118 2000- 2001
100,000 6, 200- 145,000,000 122 2001- 2002 100,000 6, 000- 125,000,000 127
Actual volumes
1999- 2000 95,000 5, 000- 145,000,000 137 2000- 2001 95,000 5, 820-
125,000,000 141 Source: GAO.
Appendix III: Additional Results of InvestorOwned and Municipally Owned
Utility Survey
Page 71 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Table 8: Use of Natural Gas Storage Among Utilities (on Average over the
Past 5 Years)
Percentage of gas supply for residential customers in storage
AGA N= 79
APGA N= 146
0 1553 1 to 25 37 27 26 to 50 42 13 51 to 100 6 8
Source: GAO.
Appendix IV: Results of State Regulatory Agency Survey
Page 72 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
We surveyed staff specializing in natural gas regulation from the state
regulatory agencies, which are usually known as public utility commissions
or public service commissions, that oversee gas utilities. We contacted
the agencies of the 48 contiguous states and the District of Colombia in a
series of structured telephone interviews. However, because the Nebraska
Public Service Commission does not regulate gas utility companies (such
regulation occurs at the local government level), we exempted this state
from our analysis of regulatory agencies. Therefore we received responses
from a total of 48 state regulatory agencies.
For each question in the reprinted survey, we identified the number of
state regulatory agencies that indicated each response. A few commissions
did not respond to all of the questions, so some questions have fewer
total respondents than others. In addition, certain questions are
presented in greater detail in appendix V. Appendix IV: Results of State
Regulatory
Agency Survey
Appendix IV: Results of State Regulatory Agency Survey
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Appendix IV: Results of State Regulatory Agency Survey
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Appendix IV: Results of State Regulatory Agency Survey
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Appendix IV: Results of State Regulatory Agency Survey
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Appendix IV: Results of State Regulatory Agency Survey
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Appendix IV: Results of State Regulatory Agency Survey
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Appendix V: Additional Results of State Regulatory Agency Survey
Page 79 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
This appendix provides selected results from our survey of regulatory
agencies located in the 48 contiguous states and the District of Columbia.
Table 9 shows what hedging tools the state and the District of Columbia
regulatory agencies allow or do not allow gas utilities under their
jurisdiction to use when purchasing natural gas for their residential
customers. Table 10 shows the various approaches the regulatory agencies
use in their oversight of gas utilities.
Table 9: State Regulatory Agency Regulation of Hedging Techniques Used by
Utilities for Natural Gas Purchases State regulatory agency Storage Fixed
price
contracts Futures Options Swaps Weather derivatives
Alabama Public Service Commission Allows Allows Allows Allows Allows Does
not allow Arizona Corporation Commission N/ A a Allows N/ A N/ A N/ A N/ A
Arkansas Public Service Commission Allows Allows Allows Allows Allows N/ A
California Public Utility Commission Allows Allows Allows Allows Allows N/
A Colorado Department of Regulatory Agencies, Public Utility Commission
Allows Allows Allows Allows Allows N/ A Connecticut Department of Public
Utility Control Allows N/ A N/ A N/ A N/ A N/ A Delaware Public Service
Commission Allows Allows Allows Allows Allows Allows District of Columbia
Public Service Commission
Allows Allows Allows Allows N/ A N/ A Florida Public Service Commission N/
A Allows Allows Allows Allows N/ A Georgia Public Service Commission
Allows Allows Allows Does not allow Does not allow Does not allow Idaho
Public Utilities Allows Allows Allows Allows Allows Allows Illinois
Commerce Commission Allows Allows Allows Allows Allows Allows Indiana
Utility Regulatory Commission Allows Allows Allows Allows Allows Allows
Kansas Corporation Commission Allows Allows Allows Allows Allows Allows
Kentucky Public Service Commission Allows Allows Allows Allows Allows N/ A
Louisiana Public Service Commission Allows Allows Allows Allows Allows
Allows Maine Public Utility Commission Allows Allows Allows Allows Allows
Allows Maryland Public Service Commission Allows Allows Allows Allows
Allows Allows
Appendix V: Additional Results of State Regulatory Agency Survey
Appendix V: Additional Results of State Regulatory Agency Survey
Page 80 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
State regulatory agency Storage Fixed price
contracts Futures Options Swaps Weather derivatives
Massachusetts Department of Public Utilities
Allows N/ A N/ A N/ A N/ A N/ A Michigan Public Service Commission Allows
Allows Allows Allows N/ A N/ A Minnesota Public Utility Commission Allows
Allows Allows Allows N/ A N/ A Mississippi Public Utilities Staff Allows
Allows Allows Allows Allows Does not allow Missouri Public Service
Commission Allows Allows Allows Allows N/ A N/ A Montana Public Service
Commission Allows Allows Does not allow Does not N/ A Allows Nebraska
Public Service Commission No response No response No response No response
No response No response Nevada Public Utilities Commission Allows Allows
Allows Allows Allows Allows North Carolina Department of Commerce
Utilities Commission
Allows Allows Allows Allows Allows Allows North Dakota Public Service
Commission Allows Allows Allows Allows Allows Allows New Hampshire Public
Utilities Commission Allows Allows Allows Allows Allows Allows New Jersey
Board of Public Utilities Allows Allows Allows Does not allow Allows
Allows New Mexico Public Regulatory Commission Allows Allows Allows Allows
Allows Allows New York Public Service Commission Allows Allows Allows
Allows Allows Allows Ohio Public Utility Commission Allows Allows Allows
Allows Allows Allows Oklahoma Corporation Commission, Public Utility
Division
Allows Allows N/ A N/ A N/ A N/ A Oregon Public Utility Commission Allows
Allows Allows Allows Allows N/ A Pennsylvania Public Utility Commission
Allows Allows Allows Allows Allows N/ A Rhode Island Public Utility
Commission Allows Allows Allows Allows Allows Does not allow South
Carolina Public Service Commission Allows Allows Allow Allows No response
No response South Dakota Public Utilities Commission Allows Allows Allows
Allows Allows Allows Tennessee Regulatory Authority, Energy and Water
Division
Allows Allows Allows Allows Allows N/ A
Appendix V: Additional Results of State Regulatory Agency Survey
Page 81 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
State regulatory agency Storage Fixed price
contracts Futures Options Swaps Weather derivatives
Texas Railroad Commission N/ A N/ A N/ A N/ A N/ A N/ A Utah Public
Service Commission Allows Allows Allows Allows Allows Allows Vermont
Public Service Board Allows Allows Allows Allows Allows Allows Virginia
State Corporation Commission
Allows Allows Allows Allows Allows N/ A Washington Utilities and
Transportation Commission
Allows Allows Allows Allows Allows N/ A West Virginia Public Service
Commission Allows Allows Allows Allows Allows N/ A Wisconsin Public
Service Commission Allows Allows Allows Allows Allows N/ A Wyoming Public
Service Commission Allows Allows Allows Allows Allows Allows
a Either the regulatory agency has not addressed this technique in its
policy or procedures or the technique is not available. Source: GAO.
Table 10: State Regulatory Agency Oversight of Gas Utilities Regulatory
agency
Regulatory approval of buying strategy required
Utilities seek approval of buying strategy but not required
Regulator limits Use of financial derivatives Regulator conducts
prudence audits Since 1995
regulator has disallowed utility gas commodity costs
Alabama Public Service Commission
No No No No No Arizona Corporation Commission
No No No Yes No Arkansas Public Service Commission
No Yes No Yes No California Public Utility Commission No No Yes Yes Yes
Colorado Department of Regulatory Agencies, Public Utility Commission
No No No Yes No Connecticut Department of Public Utility Control
No No No Yes Yes
Appendix V: Additional Results of State Regulatory Agency Survey
Page 82 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Regulatory agency
Regulatory approval of buying strategy required
Utilities seek approval of buying strategy but not required
Regulator limits Use of financial derivatives Regulator conducts
prudence audits Since 1995
regulator has disallowed utility gas commodity costs
Delaware Public Service Commission
No No Yes Yes No District of Columbia Public Service Commission
No No Yes Yes No Florida Public Service Commission
Yes No No Yes No Georgia Public Service Commission
Yes No Yes Yes No Idaho Public Utilities Commission
No Yes No Yes No Illinois Commerce Commission No No No Yes Yes Indiana
Utility Regulatory Commission
No Yes No Yes Yes Iowa Utilities Board No No Yes Yes No Kansas Corporation
Commission
No No No No No Kentucky Public Service Commission
No No Yes No No Louisiana Public Service Commission
No Yes No Yes No Maine Public Utility Commission No No No No No Maryland
Public Service Commission
No No Yes Yes No Massachusetts Dept. of Public Utilities
Yes No No Yes No Michigan Public Service Commission
Yes No Yes Yes Yes Minnesota Public Utility Commission No No Yes Yes No
Mississippi Public Utilities Staff No Yes Yes Yes No
Appendix V: Additional Results of State Regulatory Agency Survey
Page 83 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Regulatory agency
Regulatory approval of buying strategy required
Utilities seek approval of buying strategy but not required
Regulator limits Use of financial derivatives Regulator conducts
prudence audits Since 1995
regulator has disallowed utility gas commodity costs
Missouri Public Service Commission
No No No Yes Yes Montana Public Service Commission
No No No Yes No Nebraska Public Service Commission
No response No response No response No response No response Nevada Public
Utilities Commission
No Yes No Yes No North Carolina Department of Commerce, Utilities
Commission
No Yes No Yes Yes North Dakota Public Service Commission
No Yes No Yes No New Hampshire Public Utilities Commission
Yes No No Yes Yes New Jersey Board of Public Utilities Yes No No Yes No
New Mexico Public Regulatory Commission
No No No Yes No New York Public Service Commission
No Yes No Yes No Ohio Public Utility Commission No No No Yes No Oklahoma
Corporation Commission, Public Utility Division
No No No Yes Yes Oregon Public Utility Commission No Yes Yes Yes No
Pennsylvania Public Utility Commission
Yes No Yes Yes Yes Rhode Island Public Utility Commission
No Yes No Yes Yes South Carolina Public Service Yes No Yes Yes No
Appendix V: Additional Results of State Regulatory Agency Survey
Page 84 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Regulatory agency
Regulatory approval of buying strategy required
Utilities seek approval of buying strategy but not required
Regulator limits Use of financial derivatives Regulator conducts
prudence audits Since 1995
regulator has disallowed utility gas commodity costs
Commission South Dakota Public Utilities Commission
No No No No No Tennessee Regulatory Authority, Energy and Water Division
No No Yes Yes Yes Texas Railroad Commission No No No Yes Yes Utah Public
Service Commission
No Yes No Yes No Vermont Public Service Board No Yes No Yes Yes Virginia
State Corporation Commission
Yes No No No No Washington Utilities and Transportation Commission
No Yes No Yes No West Virginia Public Service Commission
No No No Yes No Wisconsin Public Service Commission
Yes No Yes Yes No Wyoming Public Service Commission
No Yes No Yes No Source: GAO.
Appendix VI: Comments from the Federal Energy Regulatory Commission
Page 85 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Appendix VI: Comments from the Federal Energy Regulatory Commission
Appendix VI: Comments from the Federal Energy Regulatory Commission
Page 86 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Appendix VI: Comments from the Federal Energy Regulatory Commission
Page 87 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Appendix VII: Comments from the Energy Information Administration Page 88
GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Appendix VII: Comments from the Energy Information Administration
Appendix VII: Comments from the Energy Information Administration Page 89
GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Appendix VIII: GAO Contacts and Staff Acknowledgments
Page 90 GAO- 03- 46 Analysis of Changes in Natural Gas Prices
Jim Wells (202) 512- 3841 Mark Gaffigan (202) 512- 3168
In addition to those named above, James Cooksey, James Rose, Daren
Sweeney, Timothy Minelli, Diane Berry, Philip Farah, Luann Moy, Mark
Ramage, Barbara Timmerman, and Nancy Crothers made key contributions to
this report. Appendix VIII: GAO Contacts and Staff
Acknowledgments GAO Contacts Acknowledgments
(360091)
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