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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Administration has an outdated natural gas data collection program, but 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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