Natural Gas
Analysis of Changes in Market Price Gao ID: GAO-03-46 December 18, 2002During 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.
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 Finally, the Energy Information Administration has an outdated natural gas data collection program, but has made efforts to reassess its data needs to provide more useful information.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.
GAO-03-46, Natural Gas: Analysis of Changes in Market Price
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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:
GAO Highlights:
Highlights of GAO-03-46, a report to congressional committees and
members of
Congress.
December 2002:
Natural Gas:
Analysis of Changes in Market Price:
Why GAO Did This Study:
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.
What GAO Found:
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.
Figure: Natural Gas Wholesale Prices (adjusted to 2001 dollars)
[See PDF for image]
[End of figure]
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.
Contents:
Letter:
Results in Brief:
Background:
Market Forces Contributed to the Natural Gas Price Spike in 2000-2001,
but Price Manipulation Has Not Been Ruled Out:
Federal Government Faces Challenges in Ensuring a Competitive and
Informed Natural Gas Marketplace:
Consumers Can Be Protected against Price Spikes:
Conclusions:
Agency Comments:
Appendix I: Objectives, Scope, and Methodology:
Appendix II: Results of Investor-Owned and Municipally Owned Utility
Survey:
Appendix III: Additional Results of Investor-Owned and
Municipally Owned Utility Survey:
Appendix IV: Results of State Regulatory Agency Survey:
Appendix V: Additional Results of State Regulatory Agency
Survey:
Appendix VI: Comments from the Federal Energy Regulatory Commission:
Appendix VII: Comments from the Energy Information
Administration:
Appendix VIII: GAO Contacts and Staff Acknowledgments:
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:
Table 2: Percentage of Gas Utility Companies That Reported Using
Hedging Techniques in Gas Purchases for 2000-2001:
Table 3: Changes in Utilities‘ Use of Hedging Techniques since Winter
of 2000-2001:
Table 4: State Regulatory Agency Policy Concerning Gas Cost
Stabilization Tools:
Table 5: Gas Utilities‘ Planned Use of Hedging for Residential
Customers:
Table 6: Gas Utilities‘ Actual Use of Hedging for Residential Customers
during the Winters of 2000-2001 and 2001-2002:
Table 7: Gas Utilities‘ Planned and Actual Volumes of Natural Gas
Purchased during the Winter Heating Season for Residential Customers:
Table 8: Use of Natural Gas Storage Among Utilities (on Average over
the Past 5 Years):
Table 9: State Regulatory Agency Regulation of Hedging Techniques Used
by Utilities for Natural Gas Purchases:
Table 10: State Regulatory Agency Oversight of Gas Utilities:
Figures:
Figure 1: Natural Gas Wholesale Prices Per mmBtu, Adjusted to 2001
Dollars:
Figure 2: U.S. Natural Gas Usage by Sectors, 2000:
Figure 3: Principal Components of Residential Natural Gas Price during
Winter Heating Season:
Figure 4: Available Gas in Storage at the Beginning of the Winter
Heating Season, November 1976-November 2000:
Figure 5: Number of Gas Rigs in Operation and Gas Prices:
Figure 6: Monthly Average Number of Natural Gas Rigs in Use, 1993-2001:
Figure 7: Mean Temperatures in the Continental United States for
December 2000, in Degrees Fahrenheit:
Figure 8: Comparison of Price Impacts of Elastic Supply and Inelastic
Supply:
Figure 9: Comparison of Price Impacts of Elastic and Inelastic Supply
and Demand:
Figure 10: Comparison of Hedged and Unhedged Gas Prices for
Hypothetical Gas Utility:
Figure 11: Percentage of Gas Utilities That Hedged None of Their Winter
Gas Supply for Residential Customers, 1995-2002:
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:
Letter:
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.
Figure 1: Natural Gas Wholesale Prices Per mmBtu, Adjusted to 2001
Dollars:
[See PDF for image]
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.
[End of figure]
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.
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 off-exchange, 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 market. These derivatives
include natural gas futures and options.[Footnote 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.
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.
Results in Brief:
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 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 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.
Background:
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.
Figure 2: U.S. Natural Gas Usage by Sectors, 2000:
[See PDF for image]
[End of figure]
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. 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,[Footnote 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 some gas on the spot market.[Footnote 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, investor-owned 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.
Figure 3: Principal Components of Residential Natural Gas Price during
Winter Heating Season:
[See PDF for image]
[End of figure]
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 off-exchange
OTC markets, such as the Intercontinental Exchange and the former
EnronOnline. These OTC markets expanded both the terms (the size,
maturity, and price) and types (OTC markets introduced swaps[Footnote
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 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.
Market Forces Contributed to the Natural Gas Price Spike in 2000-2001,
but Price Manipulation Has Not Been Ruled Out:
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.
Natural Gas Supplies Were Constrained because of Low Storage Levels and
Delays in Newly Produced Gas Reaching the Market:
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 2000-2001.[Footnote 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[Footnote 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:
[See PDF for image]
[End of figure]
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 below $3 and producers no longer had the economic
incentive to increase production.
Figure 5: Number of Gas Rigs in Operation and Gas Prices:
[See PDF for image]
[End of figure]
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.
Figure 6: Monthly Average Number of Natural Gas Rigs in Use, 1993-2001:
[See PDF for image]
[End of figure]
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.
Natural Gas Demand Increased because of Cold Weather and the Strong
Economy:
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:
[See PDF for image]
[End of figure]
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.
Natural Gas Market Supply and Demand Characteristics Cause Price
Spikes:
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.
Natural Gas Supply Is Inelastic, and Information Is Limited:
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 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 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.
Natural Gas Demand Is Inelastic, and Information Is Limited:
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 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.
Short-term Inelasticity Means Small Shifts in Supply or Demand Can Lead
to Significant Price Fluctuations:
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 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:
[See PDF for image]
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 PA0 and
quantity Q0 as determined by the intersection of supply SAand 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 Pa1. The increase in price is represented by
DPP--the difference between Pa1 and Pa0. 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, Sb. 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 Pb1 to ’choke off“ the excess
demand. The increase in price from Pb0 to Pb1 for the inelastic supply
case, as represented by DPP, is significantly higher than the increase
in price in the elastic supply case, DPP.
[End of figure]
Figure 9: Comparison of Price Impacts of Elastic and Inelastic Supply
and Demand:
[See PDF for image]
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 (PA0 vs PA1)
compared with the price response in the inelastic market in panel B
(PB0 vs PB1). 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 (DPA).
However, in the market with inelastic supply and demand, the increase
in price due to the supply and demand shifts is considerably larger
(DPB).
[End of figure]
Evidence of Natural Gas Market Manipulation Found, but Federal
Investigations Still Ongoing:
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 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.“[Footnote 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.[Footnote 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 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.
Federal Government Faces Challenges in Ensuring a Competitive and
Informed Natural Gas Marketplace:
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 declined significantly and is currently reevaluating
its data collection needs.
FERC Faces Challenges That Impede Effective Oversight:
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[Footnote
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.
* 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 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 Regulatory Oversight Varies Among Markets:
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 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.[Footnote 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[Footnote 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,[Footnote 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,[Footnote 13] it
protects all participants against counterparty credit risk, which is
the risk of failure by 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.[Footnote 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 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 Is Trying to Modernize Outdated Data Collection Program:
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 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.
Consumers Can Be Protected against Price Spikes:
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.
Various Tools Are Available to Protect against Rising Gas Prices:
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 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 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.
Hedging Does Not Guarantee the Lowest Possible Gas Prices:
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.
* 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.
Unhedged gas costs; Winter Heating Season (November through March): 90-
91: $136.8; Winter Heating Season (November through March): 91-92:
$120.6; Winter Heating Season (November through March): 92-93: $175.2;
Winter Heating Season (November through March): 93-94: $202.1; Winter
Heating Season (November through March): 94-95: $122.5; Winter Heating
Season (November through March): 95-96: $270.4; Winter Heating Season
(November through March): 96-97: $275.3; Winter Heating Season
(November through March): 97-98: $205.6; Winter Heating Season
(November through March): 98-99: $152.2; Winter Heating Season
(November through March): 99-00: $201; Winter Heating Season (November
through March): 00-01: $644.3; Winter Heating Season (November through
March): 01-02: $192.1.
Hedged gas costs; Winter Heating Season (November through March): 90-
91: 155.1; Winter Heating Season (November through March): 91-92:
156.4; Winter Heating Season (November through March): 92-93: 153.5;
Winter Heating Season (November through March): 93-94: 193.9; Winter
Heating Season (November through March): 94-95: 179.4; Winter Heating
Season (November through March): 95-96: 196.1; Winter Heating Season
(November through March): 96-97: 209.6; Winter Heating Season (November
through March): 97-98: 195.7; Winter Heating Season (November through
March): 98-99: 214.3; Winter Heating Season (November through March):
99-00: 195.2; Winter Heating Season (November through March): 00-01:
368.7; Winter Heating Season (November through March): 01-02: 412.7.
Hedging gain (loss); Winter Heating Season (November through March):
90-91: (18.3); Winter Heating Season (November through March): 91-92:
(35.8); Winter Heating Season (November through March): 92-93: 21.7;
Winter Heating Season (November through March): 93-94: 8.2; Winter
Heating Season (November through March): 94-95: (56.9); Winter Heating
Season (November through March): 95-96: 74.3; Winter Heating Season
(November through March): 96-97: 65.7; Winter Heating Season (November
through March): 97-98: 9.9; Winter Heating Season (November through
March): 98-99: (62.1); Winter Heating Season (November through March):
99-00: 5.8; Winter Heating Season (November through March): 00-01:
275.6; Winter Heating Season (November through March): 01-02: (220.6).
Source: GAO analysis of EIA, NYMEX, and other data.
[End of table]
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.[Footnote 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.
Figure 10: Comparison of Hedged and Unhedged Gas Prices for
Hypothetical Gas Utility:
[See PDF for image]
Note: Figure 10 plots average prices for November through March for the
hypothetical gas utility GU-H.
[End of figure]
Prices in 2000-2001 Prompted Gas Utilities and State Regulatory
Agencies to Act to Mitigate Future Price Spikes:
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 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.
Figure 11: Percentage of Gas Utilities That Hedged None of Their Winter
Gas Supply for Residential Customers, 1995-2002:
[See PDF for image]
[End of figure]
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.
Table 2: Percentage of Gas Utility Companies That Reported Using
Hedging Techniques in Gas Purchases for 2000-2001:
Hedging techniques: Physical tools.
Hedging techniques: Storage; Large utilities: 84; Small utilities: 49.
Hedging techniques: Fixed price contracts; Large utilities: 56; Small
utilities: 65.
Hedging techniques: Financial tools; Large utilities: [Empty]; Small
utilities: [Empty].
Hedging techniques: Futures; Large utilities: 35; Small utilities: 24.
Hedging techniques: Options; Large utilities: 36; Small utilities: 4.
Hedging techniques: Swaps; Large utilities: 28; Small utilities: 5.
Source: GAO analysis of survey data.
[End of table]
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:
[See PDF for image]
Source: GAO analysis of survey data.
[End of table]
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: Physical tools.
Cost stabilization tool: Storage; Number of state agencies
allowing use of the tool: 45; Number of state agencies not allowing use
of
the tool: 0; Does not apply[A]: 3; No response: 0.
Cost stabilization tool: Fixed price contracts; Number of state
agencies
allowing use of the tool: 45; Number of state agencies not allowing use
of
the tool: 0; Does not apply[A]: 3; No response: 0.
Cost stabilization tool: Financial tools; Number of state agencies
allowing use of the tool: [Empty]; Number of state agencies not
allowing use of
the tool: [Empty]; Does not apply[A]: [Empty]; No response: [Empty].
Cost stabilization tool: Futures; Number of state agencies
allowing use of the tool: 42; Number of state agencies not allowing use
of
the tool: 1; Does not apply[A]: 5; No response: 0.
Cost stabilization tool: Options; Number of state agencies
allowing use of the tool: 40; Number of state agencies not allowing use
of
the tool: 3; Does not apply[A]: 5; No response: 0.
Cost stabilization tool: Swaps; Number of state agencies
allowing use of the tool: 36; Number of state agencies not allowing use
of
the tool: 1; Does not apply[A]: 10; No response: 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.
[End of table]
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.
Conclusions:
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 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.
Agency Comments:
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 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:
Signed by Jim Wells:
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
The Honorable Mike Thompson
The Honorable Zach Wamp
House of Representatives:
[End of section]
Appendix I: Objectives, Scope, and Methodology:
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
end-user 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. 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 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.
[End of section]
Appendix II: Results of Investor-Owned and Municipally Owned Utility
Survey:
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.
[See PDF for image]
[End of section]
Appendix III: Additional Results of Investor-Owned and Municipally
Owned
Utility Survey:
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:
[See PDF for image]
Source: GAO.
[End of table]
Table 6: Gas Utilities‘ Actual Use of Hedging for Residential Customers
during the Winters of 2000-2001 and 2001-2002:
[See PDF for image]
Source: GAO.
[End of table]
Table 7: Gas Utilities‘ Planned and Actual Volumes of Natural Gas
Purchased during the Winter Heating Season for Residential Customers:
[See PDF for image]
Source: GAO.
[End of table]
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: 0; AGA:
15; APGA: 53.
Percentage of gas supply for residential customers in storage: 1 to 25;
AGA: 37; APGA: 27.
Percentage of gas supply for residential customers in storage: 26 to
50; AGA: 42; APGA: 13.
Percentage of gas supply for residential customers in storage: 51 to
100; AGA: 6; APGA: 8.
Source: GAO.
[End of table]
[End of section]
Appendix IV: Results of State Regulatory Agency Survey:
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.
[See PDF for image]
[End of section]
Appendix V: Additional Results of State Regulatory Agency Survey:
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: Alabama Public Service Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: Does not allow.
State regulatory agency: Arizona Corporation Commission; Storage: N/
A[A]; Fixed price contracts: Allows; Futures: N/A; Options: N/A; Swaps:
N/A; Weather derivatives: N/A.
State regulatory agency: Arkansas Public Service Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: N/A.
State regulatory agency: California Public Utility Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: N/A.
State regulatory agency: Colorado Department of Regulatory Agencies,
Public Utility Commission; Storage: Allows; Fixed price contracts:
Allows; Futures: Allows; Options: Allows; Swaps: Allows; Weather
derivatives: N/A.
State regulatory agency: Connecticut Department of Public Utility
Control; Storage: Allows; Fixed price contracts: N/A; Futures: N/A;
Options: N/A; Swaps: N/A; Weather derivatives: N/A.
State regulatory agency: Delaware Public Service Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: Allows.
State regulatory agency: District of Columbia Public Service
Commission; Storage: Allows; Fixed price contracts: Allows; Futures:
Allows; Options: Allows; Swaps: N/A; Weather derivatives: N/A.
State regulatory agency: Florida Public Service Commission; Storage: N/
A; Fixed price contracts: Allows; Futures: Allows; Options: Allows;
Swaps: Allows; Weather derivatives: N/A.
State regulatory agency: Georgia Public Service Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options: Does
not allow; Swaps: Does not allow; Weather derivatives: Does not allow.
State regulatory agency: Idaho Public Utilities; Storage: Allows; Fixed
price contracts: Allows; Futures: Allows; Options: Allows; Swaps:
Allows; Weather derivatives: Allows.
State regulatory agency: Illinois Commerce Commission; Storage: Allows;
Fixed price contracts: Allows; Futures: Allows; Options: Allows; Swaps:
Allows; Weather derivatives: Allows.
State regulatory agency: Indiana Utility Regulatory Commission;
Storage: Allows; Fixed price contracts: Allows; Futures: Allows;
Options: Allows; Swaps: Allows; Weather derivatives: Allows.
State regulatory agency: Kansas Corporation Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: Allows.
State regulatory agency: Kentucky Public Service Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: N/A.
State regulatory agency: Louisiana Public Service Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: Allows.
State regulatory agency: Maine Public Utility Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: Allows.
State regulatory agency: Maryland Public Service Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: Allows.
State regulatory agency: Massachusetts Department of Public Utilities;
Storage: Allows; Fixed price contracts: N/A; Futures: N/A; Options: N/
A; Swaps: N/A; Weather derivatives: N/A.
State regulatory agency: Michigan Public Service Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: N/A; Weather derivatives: N/A.
State regulatory agency: Minnesota Public Utility Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: N/A; Weather derivatives: N/A.
State regulatory agency: Mississippi Public Utilities Staff; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: Does not allow.
State regulatory agency: Missouri Public Service Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: N/A; Weather derivatives: N/A.
State regulatory agency: Montana Public Service Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Does not allow;
Options: Does not; Swaps: N/A; Weather derivatives: Allows.
State regulatory agency: Nebraska Public Service Commission; Storage:
No response; Fixed price contracts: No response; Futures: No response;
Options: No response; Swaps: No response; Weather derivatives: No
response.
State regulatory agency: Nevada Public Utilities Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: Allows.
State regulatory agency: North Carolina Department of Commerce
Utilities Commission; Storage: Allows; Fixed price contracts: Allows;
Futures: Allows; Options: Allows; Swaps: Allows; Weather derivatives:
Allows.
State regulatory agency: North Dakota Public Service Commission;
Storage: Allows; Fixed price contracts: Allows; Futures: Allows;
Options: Allows; Swaps: Allows; Weather derivatives: Allows.
State regulatory agency: New Hampshire Public Utilities Commission;
Storage: Allows; Fixed price contracts: Allows; Futures: Allows;
Options: Allows; Swaps: Allows; Weather derivatives: Allows.
State regulatory agency: New Jersey Board of Public Utilities; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options: Does
not allow; Swaps: Allows; Weather derivatives: Allows.
State regulatory agency: New Mexico Public Regulatory Commission;
Storage: Allows; Fixed price contracts: Allows; Futures: Allows;
Options: Allows; Swaps: Allows; Weather derivatives: Allows.
State regulatory agency: New York Public Service Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: Allows.
State regulatory agency: Ohio Public Utility Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: Allows.
State regulatory agency: Oklahoma; Corporation Commission, Public
Utility Division; Storage: Allows; Fixed price contracts: Allows;
Futures: N/A; Options: N/A; Swaps: N/A; Weather derivatives: N/A.
State regulatory agency: Oregon Public Utility Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: N/A.
State regulatory agency: Pennsylvania Public Utility Commission;
Storage: Allows; Fixed price contracts: Allows; Futures: Allows;
Options: Allows; Swaps: Allows; Weather derivatives: N/A.
State regulatory agency: Rhode Island Public Utility Commission;
Storage: Allows; Fixed price contracts: Allows; Futures: Allows;
Options: Allows; Swaps: Allows; Weather derivatives: Does not allow.
State regulatory agency: South Carolina Public Service Commission;
Storage: Allows; Fixed price contracts: Allows; Futures: Allow;
Options: Allows; Swaps: No response; Weather derivatives: No response.
State regulatory agency: South Dakota Public Utilities Commission;
Storage: Allows; Fixed price contracts: Allows; Futures: Allows;
Options: Allows; Swaps: Allows; Weather derivatives: Allows.
State regulatory agency: Tennessee Regulatory Authority, Energy and
Water Division; Storage: Allows; Fixed price contracts: Allows;
Futures: Allows; Options: Allows; Swaps: Allows; Weather derivatives:
N/A.
State regulatory agency: Texas Railroad Commission; Storage: N/A; Fixed
price contracts: N/A; Futures: N/A; Options: N/A; Swaps: N/A; Weather
derivatives: N/A.
State regulatory agency: Utah Public Service Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: Allows.
State regulatory agency: Vermont Public Service Board; Storage: Allows;
Fixed price contracts: Allows; Futures: Allows; Options: Allows; Swaps:
Allows; Weather derivatives: Allows.
State regulatory agency: Virginia State Corporation Commission;
Storage: Allows; Fixed price contracts: Allows; Futures: Allows;
Options: Allows; Swaps: Allows; Weather derivatives: N/A.
State regulatory agency: Washington Utilities and Transportation
Commission; Storage: Allows; Fixed price contracts: Allows; Futures:
Allows; Options: Allows; Swaps: Allows; Weather derivatives: N/A.
State regulatory agency: West Virginia Public Service Commission;
Storage: Allows; Fixed price contracts: Allows; Futures: Allows;
Options: Allows; Swaps: Allows; Weather derivatives: N/A.
State regulatory agency: Wisconsin Public Service Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: N/A.
State regulatory agency: Wyoming Public Service Commission; Storage:
Allows; Fixed price contracts: Allows; Futures: Allows; Options:
Allows; Swaps: Allows; Weather derivatives: Allows.
[A] Either the regulatory agency has not addressed this technique in
its policy or procedures or the technique is not available.
Source: GAO.
[End of table]
Table 10: State Regulatory Agency Oversight of Gas Utilities:
Regulatory agency: Alabama Public Service Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: No; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Arizona Corporation Commission; Regulatory approval
of buying strategy required: No; Utilities seek approval of buying
strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Arkansas Public Service Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: Yes; Regulator limits Use of
financial derivatives: No; Regulator conducts prudence audits: Yes;
Since 1995 regulator has disallowed utility gas commodity costs: No.
Regulatory agency: California Public Utility Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: Yes; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: Yes.
Regulatory agency: Colorado Department of Regulatory Agencies, Public
Utility Commission; Regulatory approval of buying strategy required:
No; Utilities seek approval of buying strategy but not required: No;
Regulator limits Use of financial derivatives: No; Regulator conducts
prudence audits: Yes; Since 1995 regulator has disallowed utility gas
commodity costs: No.
Regulatory agency: Connecticut Department of Public Utility Control;
Regulatory approval of buying strategy required: No; Utilities seek
approval of buying strategy but not required: No; Regulator limits Use
of financial derivatives: No; Regulator conducts prudence audits: Yes;
Since 1995 regulator has disallowed utility gas commodity costs: Yes.
Regulatory agency: Delaware Public Service Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: Yes; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: District of Columbia Public Service Commission;
Regulatory approval of buying strategy required: No; Utilities seek
approval of buying strategy but not required: No; Regulator limits Use
of financial derivatives: Yes; Regulator conducts prudence audits: Yes;
Since 1995 regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Florida Public Service Commission; Regulatory
approval of buying strategy required: Yes; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Georgia Public Service Commission; Regulatory
approval of buying strategy required: Yes; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: Yes; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Idaho Public Utilities Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: Yes; Regulator limits Use of
financial derivatives: No; Regulator conducts prudence audits: Yes;
Since 1995 regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Illinois Commerce Commission; Regulatory approval of
buying strategy required: No; Utilities seek approval of buying
strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: Yes.
Regulatory agency: Indiana Utility Regulatory Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: Yes; Regulator limits Use of
financial derivatives: No; Regulator conducts prudence audits: Yes;
Since 1995 regulator has disallowed utility gas commodity costs: Yes.
Regulatory agency: Iowa Utilities Board; Regulatory approval of buying
strategy required: No; Utilities seek approval of buying strategy but
not required: No; Regulator limits Use of financial derivatives: Yes;
Regulator conducts prudence audits: Yes; Since 1995 regulator has
disallowed utility gas commodity costs: No.
Regulatory agency: Kansas Corporation Commission; Regulatory approval
of buying strategy required: No; Utilities seek approval of buying
strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: No; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Kentucky Public Service Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: Yes; Regulator conducts prudence audits: No; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Louisiana Public Service Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: Yes; Regulator limits Use of
financial derivatives: No; Regulator conducts prudence audits: Yes;
Since 1995 regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Maine Public Utility Commission; Regulatory approval
of buying strategy required: No; Utilities seek approval of buying
strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: No; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Maryland Public Service Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: Yes; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Massachusetts Dept. of Public Utilities; Regulatory
approval of buying strategy required: Yes; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Michigan Public Service Commission; Regulatory
approval of buying strategy required: Yes; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: Yes; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: Yes.
Regulatory agency: Minnesota Public Utility Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: Yes; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Mississippi Public Utilities Staff; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: Yes; Regulator limits Use of
financial derivatives: Yes; Regulator conducts prudence audits: Yes;
Since 1995 regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Missouri Public Service Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: Yes.
Regulatory agency: Montana Public Service Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Nebraska Public Service Commission; Regulatory
approval of buying strategy required: No response; Utilities seek
approval of buying strategy but not required: No response; Regulator
limits Use of financial derivatives: No response; Regulator conducts
prudence audits: No response; Since 1995 regulator has disallowed
utility gas commodity costs: No response.
Regulatory agency: Nevada Public Utilities Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: Yes; Regulator limits Use of
financial derivatives: No; Regulator conducts prudence audits: Yes;
Since 1995 regulator has disallowed utility gas commodity costs: No.
Regulatory agency: North Carolina Department of Commerce, Utilities
Commission; Regulatory approval of buying strategy required: No;
Utilities seek approval of buying strategy but not required: Yes;
Regulator limits Use of financial derivatives: No; Regulator conducts
prudence audits: Yes; Since 1995 regulator has disallowed utility gas
commodity costs: Yes.
Regulatory agency: North Dakota Public Service Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: Yes; Regulator limits Use of
financial derivatives: No; Regulator conducts prudence audits: Yes;
Since 1995 regulator has disallowed utility gas commodity costs: No.
Regulatory agency: New Hampshire Public Utilities Commission;
Regulatory approval of buying strategy required: Yes; Utilities seek
approval of buying strategy but not required: No; Regulator limits Use
of financial derivatives: No; Regulator conducts prudence audits: Yes;
Since 1995 regulator has disallowed utility gas commodity costs: Yes.
Regulatory agency: New Jersey Board of Public Utilities; Regulatory
approval of buying strategy required: Yes; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: New Mexico Public Regulatory Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: New York Public Service Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: Yes; Regulator limits Use of
financial derivatives: No; Regulator conducts prudence audits: Yes;
Since 1995 regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Ohio Public Utility Commission; Regulatory approval
of buying strategy required: No; Utilities seek approval of buying
strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Oklahoma Corporation Commission, Public Utility
Division; Regulatory approval of buying strategy required: No;
Utilities seek approval of buying strategy but not required: No;
Regulator limits Use of financial derivatives: No; Regulator conducts
prudence audits: Yes; Since 1995 regulator has disallowed utility gas
commodity costs: Yes.
Regulatory agency: Oregon Public Utility Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: Yes; Regulator limits Use of
financial derivatives: Yes; Regulator conducts prudence audits: Yes;
Since 1995 regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Pennsylvania Public Utility Commission; Regulatory
approval of buying strategy required: Yes; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: Yes; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: Yes.
Regulatory agency: Rhode Island Public Utility Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: Yes; Regulator limits Use of
financial derivatives: No; Regulator conducts prudence audits: Yes;
Since 1995 regulator has disallowed utility gas commodity costs: Yes.
Regulatory agency: South Carolina Public Service Commission; Regulatory
approval of buying strategy required: Yes; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: Yes; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: South Dakota Public Utilities Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: No; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Tennessee Regulatory Authority, Energy and Water
Division; Regulatory approval of buying strategy required: No;
Utilities seek approval of buying strategy but not required: No;
Regulator limits Use of financial derivatives: Yes; Regulator conducts
prudence audits: Yes; Since 1995 regulator has disallowed utility gas
commodity costs: Yes.
Regulatory agency: Texas Railroad Commission; Regulatory approval of
buying strategy required: No; Utilities seek approval of buying
strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: Yes.
Regulatory agency: Utah Public Service Commission; Regulatory approval
of buying strategy required: No; Utilities seek approval of buying
strategy but not required: Yes; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Vermont Public Service Board; Regulatory approval of
buying strategy required: No; Utilities seek approval of buying
strategy but not required: Yes; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: Yes.
Regulatory agency: Virginia State Corporation Commission; Regulatory
approval of buying strategy required: Yes; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: No; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Washington Utilities and Transportation Commission;
Regulatory approval of buying strategy required: No; Utilities seek
approval of buying strategy but not required: Yes; Regulator limits Use
of financial derivatives: No; Regulator conducts prudence audits: Yes;
Since 1995 regulator has disallowed utility gas commodity costs: No.
Regulatory agency: West Virginia Public Service Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: No; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Wisconsin Public Service Commission; Regulatory
approval of buying strategy required: Yes; Utilities seek approval of
buying strategy but not required: No; Regulator limits Use of financial
derivatives: Yes; Regulator conducts prudence audits: Yes; Since 1995
regulator has disallowed utility gas commodity costs: No.
Regulatory agency: Wyoming Public Service Commission; Regulatory
approval of buying strategy required: No; Utilities seek approval of
buying strategy but not required: Yes; Regulator limits Use of
financial derivatives: No; Regulator conducts prudence audits: Yes;
Since 1995 regulator has disallowed utility gas commodity costs: No.
Source: GAO.
[End of table]
[End of section]
Appendix VI: Comments from the Federal Energy Regulatory Commission:
FEDERAL ENERGY REGULATORY COMMISSION WASHINGTON, DC 20426:
November 15, 2002:
OFFICE OF THE CHAIRMAN:
Mr. Jim Wells:
Director, Natural Resources and Environment United States General
Accounting Office 441 G St., NW, Room 2T23:
Washington, DC 20548:
Re: GAO Draft Report Entitled Natural Gas Analysis of Changes in Market
Price:
Dear Mr. Wells:
Thank you for your November 7, 2002 letter enclosing your draft report
of Natural Gas: Analysis of Changes in Market Price. I appreciate the
opportunity to comment on this report and congratulate you on your
effort.
In general, I agree with the conclusions of your report. As the report
indicates, FERC previously lacked an adequate regulatory and oversight
approach to monitor a restructured natural gas industry.
With the creation of OMOI, FERC has taken the steps needed to oversee
and assess the fair and efficient operations of electric power and
natural gas markets. OMOI‘s job will be to understand energy markets
and risk management, measure market performance, and analyze market
data with an eye to recommending market improvements, investigate
compliance violations, and where necessary, pursue enforcement actions.
In fact, a major undertaking this year by OMOI will be the assessment
of the data we already collect with the goal of fine-tuning the data we
need to monitor electric power and natural gas markets effectively.
I have a few specific comments to clarify several points in this
report, especially relating to our jurisdictional authority.
The draft report may lead the reader to misunderstand the scope of
FERC‘s authority to oversee wholesale natural gas markets. On page 35,
the draft accurately states that FERC is responsible for the regulation
of terms, conditions, and rates for the transportation of natural gas,
but has limited jurisdiction over sales for resale, and no jurisdiction
over producer prices of natural gas. However, on pages 4 and 14, the
reader is given the impression that FERC has much broader authority and
responsibility. We suggest that the summary statements of FERC‘s
responsibility and authority on pages 4 and 14 be revised to reflect
the limited nature of our authority as described on page 35.
In my November 12, 2002 testimony to the Senate Committee on
Governmental Affairs, I stated, ’[t]he Commission also has jurisdiction
over transportation and sales for resale of natural gas. However,
FERC‘s jurisdiction over sales for resale is limited to domestic gas
sold by pipelines, local distribution companies, and their affiliates
(including energy marketers). Consistent with Congressional intent, the
Commission does not prescribe prices for these commodity sales.“:
Therefore, we suggest revising the text on page 4 to state:
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.
On page 14 we suggest the following:
FERC was established in 1977 as a successor to the Federal Power
Commission and is the principal agency responsible for overseeing the
interstate natural gas grid which underpins the natural gas market.
The draft report provides an out-of-date picture of FERC‘s efforts to
refocus and retool its oversight of competitive energy markets. On page
35, the draft report discusses the formation of the Office of Market
Oversight and Investigation to oversee and assess the operation of
energy market. However, the discussion on page 32 fails to give the
agency credit for this effort.
We suggest revising the page 32 discussion to read:
As we have recently reported, FERC has not adequately revised its
regulatory and oversight approach to respond to the transition to
competitive energy markets. We note, however, that FERC has recently
taken actions to correct this with the formation of the Office of
Market Oversight and Investigation (OMOI).
Thank you for your insights into the causes of volatility in natural
gas markets.I appreciate the hard work your staff put into this report
and hope it will enable us to focus our market oversight and data
collection. Again, I appreciate the opportunity to comment on your
report.
Best regards,
Pat Wood, III:
Chairman:
Signed by Pat Wood, III:
[End of section]
Appendix VII: Comments from the Energy Information Administration:
Department of Energy Washington, DC 20585:
Mr. Jim Wells:
Director, Natural Resources and Environment:
U.S. General Accounting Office 441G Street, NW Washington, D.C. 20548:
NOV 18 2002:
Dear Mr. Wells:
The Energy Information Administration (EIA) has reviewed your draft
report, Analysis of Changes in Natural Gas Prices (GAO-03-46) and
generally agrees with your findings and conclusions. EIA does recognize
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. EIA appreciates your support for these efforts and
understands that 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, as you recommend.
As you noted, EIA recently began its first weekly data release for
natural gas - the Weekly Natural Gas Storage Report. While this
significantly improves the timeliness of the overall natural gas data
program, EIA would like to call your attention to a number of efforts
recently completed or scheduled for completion by summer 2003 to
further improve natural gas data quality and timeliness. These include:
*Change in natural gas data sources and concepts - EIA has changed the
definition of the industrial and electric power end-use sectors in
natural gas reports to use data collected from electric power
generators rather than gas delivery agents to represent consumption by
electricity generators. This has improved the completeness and accuracy
of natural gas consumption series in annual reports and will be
implemented in monthly reports in 2003.
*Redesign of survey forms - EIA received OMB approval in November 2002
for implementation in 2003 of revised survey forms with updated
industry terms. *Redesign of survey processing system - EIA is
converting the largest monthly and annual survey forms during 2003 to a
new processing system that will support improved data quality and
nonresponse tracking.
*Improvement in price series coverage - Starting with January 2003
data, EIA will incorporate price data from a recently implemented
survey of gas marketers to improve the quality of residential and
commercial prices in 5 large States.
In addition, EIA is studying further changes to its natural gas data
collection program to determine their feasibility and potential
resource requirements. These include:
*Development of a new approach to natural gas production data
collection - EIA is exploring alternatives to the present voluntary
survey of States, including collecting components of natural gas
production directly from producers. *Development of a new approach to
industrial price estimation - EIA explored a Bureau of the Census-
related survey collection approach for this series but after learning
the cost ($0.75 --$1.00 million) is now exploring estimation
alternatives using EIA electricity generator data.
*Development of a new monthly survey of liquefied natural gas (LNG)
inventories, injections, and withdrawals --EIA does not collect monthly
data about U.S. LNG operations. Because LNG‘s role in short-term
natural gas supply is increasing, EIA is studying options for new
information about LNG supplies. -:
*More frequent reviews of natural gas industry changes - EIA plans to
investigate and react to changes in industry participants and
operations more frequently in the future to assure accurate, complete
reporting of industry activities:
EIA expects to complete its assessments of the merit and resource
requirements for the projects described above in 2003. Undoubtedly the
changes will require additional resources for development and for
ongoing program operations. Whatever the outcome of our analysis of
these specific new projects, because natural gas represents a quarter
of the U.S. energy supply and is essential to U.S. consumers and
businesses, EIA is committed to updating and improving the natural gas
collection program to the extent of our ability and resources.
Thank you for the opportunity to comment on this report.
Sincerely,
Guy F. Caruso
Administrator:
Signed by Guy F. Caruso:
[End of section]
Appendix VIII: GAO Contacts and Staff Acknowledgments:
GAO Contacts:
Jim Wells (202) 512-3841:
Mark Gaffigan (202) 512-3168:
Acknowledgments:
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.
FOOTNOTES
[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.
[2] P.L. No. 101-60 (1978).
[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.
[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.
[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 fast-growing 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.
[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).
[9] Energy Markets: Concerted Actions Needed by FERC to Confront
Challenges That Impede Effective Oversight (GAO-02-656, June 14, 2002).
[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.
[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.
[15] These are simple averages in the sense that they are not
’weighted“ by the quantities of gas purchased/delivered for the
individual months.
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