Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

REPORT ON THE NATURAL GAS PRICE SPIKE

 OF FEBRUARY 2003

STAFF INVESTIGATING TEAM

FEDERAL ENERGY REGULATORY COMMISSION

JULY 23, 2003

In late February 2003, United States production-area prices for natural gas rose sharply 

and quickly in response to physical market conditions leading to low supply and high demand for 

a short time. These conditions influenced prices across the North American continent. In 

addition, some Northeastern and Midwestern consuming areas faced additional price increases 

because of limits on the industry’s physical capacity to deliver sufficient natural gas to meet 

elevated customer demand due to a cold front. Deliveries were limited, in part, due to low 

storage inventories. Similar natural gas price spikes are possible when episodes of cold weather 

occur at times when storage inventories are limited. 

The Federal Energy Regulatory Commission assigned an investigating team (the Team) 

to analyze the situation, and to coordinate as needed with the Commodity Futures Trading 

Commission (CFTC) on their analysis.

The Team’s detailed analysis of a large sample of thousands of physical natural gas 

transactions and subsequent interviews with various market participants yielded no evidence of 

market manipulation. The many physical and financial markets that together constitute the larger 

North American natural gas market appeared to operate effectively through the spike. Prices in 

these markets rose in apparent response to underlying supply and demand conditions, and in a 

manner consistent with those conditions.

Natural gas markets in the last week of February 2003 consisted of relatively few buyers 

and sellers, too few of which were engaged in active trading. While less robust markets increase 

the possibility that these markets may not respond adequately under stress, market thinness and 

concentration are evidence of the potential for inefficient prices or manipulation, not evidence of 

those problems. Increased numbers of active traders in these markets would improve liquidity 

and reduce concentration and a rebound of the energy trading industry would probably improve 

performance.
July 23, 2003 Page 2

Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

THE FEBRUARY PRICE SPIKE 

During the week of February 24, 2003, natural gas prices for physical next-day delivery 

across the country spiked – effectively tripling in certain regions. Figure 1 below shows price 

behavior around that time for production areas (Henry Hub, Louisiana), consuming areas

(Chicago, New York City at Transco Zone 6, and West Texas at Waha) and futures markets 

(delivery for the next month at Henry Hub).

Prices changed the most on February 24 when Henry Hub next-day prices ranged from 

$8.00 to $16.00/MMBtu. 1 The following day, February 25, Henry Hub prices reached an alltime high of $22.00/MMBtu with a reported mid-point price of $18.60/MMBtu. Other 

production area prices reached similar highs. 

Prices for New York City momentarily reached $40.00/MMBtu and finished the day on 

February 25 in the upper $20.00/MMBtu range. Chicago prices rose on February 25 in

alignment with production area prices and then spiked again on February 28.

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Futures Next Month (Henry Hub)

Production Area Next Day Physical

(Henry Hub)

West Texas Next Day Physical (Waha)

Chicago Next Day Physical

New York Next Day Physical (Transco

Zone 6 New York)

Figure 1: Spiking Natural Gas Prices Were National in Scope

Sources: NYMEX for futures settlement prices and Gas Daily next day physical prices

 

1 Unless otherwise identified, daily physical market prices are reported from Gas Daily during that period.
July 23, 2003 Page 3

Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

The futures price for the March 2003 contract reacted in the same direction during the 

spike, but did not rise as far.

2 The reaction of the futures market in the same direction at the 

same time shows how closely the physical day-ahead and financial monthly markets are linked. 

The smaller effect on futures prices indicates that traders saw the spike as the short-term 

phenomenon it turned out to be and understood that price pressures were likely to moderate 

during the following months.

The next section of this report shows that natural gas markets were under great stress 

during late February 2003, primarily because cold weather significantly increased demand and 

reduced storage inventories. The following section reports on our examination of a large portion

of the market behavior during the period and finds no evidence of market manipulation. At the 

end, the study summarizes findings.

Figure 1 underscores the fact that the price spike was short, national in scope, and 

affected different regions differently. To understand the reason for the price spike, we need to 

consider the national and regional factors that led to it.

DEMAND, SUPPLY AND PHYSICAL FACTORS

National factors explain the basic pattern of the price spike.

At the national level, important demand and supply factors included:

ß A Cold Front. A cold front drove down temperatures across much of the eastern half of 

the United States during that last week of February. At the same time, forecasters 

expected cold weather into early March. The eastern United States represents a large 

proportion of overall natural gas demand. This cold weather and the associated heating 

needs raised demand to high levels – not the highest of the winter but high for late winter.

ß Sustained Cold Weather and its Effects. The cold weather in late February came at the 

end of an unusually cold winter in the eastern half of the United States, as shown in 

Figure 2. As a result, as shown in Figure 3, storage inventories in production and eastern 

consuming areas were much lower than normal after heavy winter withdrawals – 42 

percent lower than the late February 5-year average of 1,446 billion cubic feet. In 

general, low inventories lead to low pressure in storage reservoirs, reducing the amount 

of natural gas they can deliver on any day. This effect cut the supply available to meet

the kind of peak demands faced that week.

ß Well Freeze-Offs. The cold front penetrated producing areas, particularly in the Midcontinent, freezing-off some wells. Well freeze-offs shut off production until they could

be fixed, reducing supply availability temporarily.

 

2

 This report includes analysis of some natural gas futures and options trading data from the New York Mercantile 

Exchange (NYMEX). This information was provided to the Commission by the CFTC. This report is, however, 

solely the product of the Commission’s Investigating Team and does not represent the analysis of the CFTC or its 

staff.
July 23, 2003 Page 4

Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

Figure 2: Cold Weather Drove Winter Natural Gas Demand

(Average February 2003 Temperature by State Compared to the Last 108 Average February Temperatures)

Source: National Oceanographic and Atmospheric Administration

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5-year range

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2001-02

Storage inventories declined from 

5-year highs in October 2002 to 

5-year lows by the end of February

Figure 3: National Storage Inventories Were at the Low End of the

5-Year Range during the Price Spike

Source: American Gas Association (before May 2002) and

Energy Information Administration (since May 2002)
July 23, 2003 Page 5

Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

Overall, the nation faced high, short-term demand for natural gas at the same time as 

there was a reduced ability to deliver natural gas. The result was predictable: higher nationwide 

prices for a short period until weather patterns moderated. Similar conditions have led to less 

severe price spikes in the past. Similar conditions could create price spikes in the future. 

Additional price increases occurred regionally due to pipeline and storage limits. 

Certain regions, including the Northeast, the Midwest, and West Texas, saw larger price

increases than in producing regions. Others, such as California and the West, saw no additional 

price increases. 

To examine these regional differences, the Team collected pipeline-specific capacity use 

information. In addition, the Team conducted follow-up interviews with representatives of 

interstate pipelines serving the Northeast and the Midwest, electric generators, local distribution 

companies, and state agencies. Based on this information, the Team found no evidence of 

manipulation of pipeline or storage capacity in order to affect regional prices. In summary, the 

Team found: 

Northeast. Prices increased more in the Northeast than nationally because of physical 

delivery limitations. The Team verified that pipelines serving the region were full 

between producing and consuming areas. Many had to issue special instructions (known 

as Operational Flow Orders or OFOs) limiting how customers could use the systems. To 

illustrate these effects in the Northeast, we will review prices for New York City. Figure 

4 shows how cold New York was each day of the price spike3, the daily price of natural 

gas, and the timing of major OFOs. Pipelines were not as full between major storage 

fields and consuming areas as they had been earlier in the winter, because of the reduced 

ability of storage fields to deliver.

4

 Indeed, several storage field operators imposed 

constraints on customer use of storage for that reason. 

Prices do not exactly track heating degree days, because at some point when heating 

degree days go up (it gets cold), pipeline delivery capacity reaches a limit. At that point 

in markets, the price rises to reduce demand. We see this effect on Figure 4 in particular 

in New York on February 25, 2003.

Some market participants reported to the Team that the higher demand in the Northeast 

described above had driven many buyers into the spot market, thus forcing up the price. 

ß Midwest. Broadly, issues in the Midwest were similar to the Northeast. Like Figure 4, 

Figure 5 shows how cold Chicago was each day of the price spike, the daily price of 

natural gas, and the timing of major OFOs. As in the Northeast, operational failures 

limited pipelines’ ability to serve the market during the critical period. 

 

3

 Measured in heating degree days – the number of degrees below 65 degrees Fahrenheit

4

 In effect, most natural gas storage operates much like a balloon. When it empties, there is less pressure. 

Consequently, it produces less on any day or hour than when it is full.
July 23, 2003 Page 6

Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

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Consolidated Edison OFO Feb. 

24 to Feb. 28, previously issued 

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since Feb. 10, Dominion ongoing FTNN OFO 

and Conform to Schedule OFO since Feb. 

10, Texas Eastern customer specific storage 

OFOs from January to March

Transco System OFO Feb. 25, 

Pre-OFO notice on Feb. 24

Difference Between 

Transco Zone 6 NY and 

Henry Hub Prices

New York

Heating Degree

Days

Figure 4: Timing of Weather and OFOs Affecting the New York

Natural Gas Market during the Price Spike

Source: Gas Daily and wunderground.com

ß West Texas. Prices also increased more in West Texas than at Henry Hub. This increase

resulted directly from local well freeze-offs and high electricity demand within Texas. 

As a result, market participants reported that many generators could not meet ERCOT’s5

call for more power because they could not buy natural gas in the spot market.6

ß California and the West. Weather in the west was relatively mild compared to the 

eastern United States. As a result, infrastructure did not limit delivery and force up 

natural gas prices. Western price movements followed closely supply area movements.

7

 

5

 The Electric Reliability Council of Texas

6

 For further information regarding effects of the Price Spike in Texas, see “Market and Reliability Issue Related to 

Extreme Weather Event on February 24-26, 2003,” Project Number 25937 of the Public Utility Commission of 

Texas, Market Oversight Division, May 19, 2003.

7

 For further information regarding effects of the Price Spike in California, see “Natural Gas Market Price Report,” 

California Energy Commission and the California Public Utilities Commission, March 28, 2003 with monthly 

updates including the latest on July 1, 2003.
July 23, 2003 Page 7

Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

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Restrictive Flow 

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Chicago City Gate and 

Henry Hub Price

Chicago Heating 

Degree Days

Mar. 2 and 3 NGPL OFO 

and storage limitations 

Feb. 22 NGPL issues OFO 

warning, Foothills outage

Figure 5: Timing of OFOs Affecting the Mid-western Markets during the Price Spike

Source: Gas Daily and wunderground.com

In general, the Team found that natural gas price movements across the United States and 

regionally appeared to behave as expected given the prevailing supply, demand and regional 

capacity limitations. However, the Team decided that it was necessary to examine specific 

market behaviors to assure market participants and others that markets performed effectively. 

The next section will discuss that analysis.
July 23, 2003 Page 8

Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

MARKET BEHAVIOR

In addition to fundamental (supply, demand and delivery constraints) factors, the Team

examined an extensive sample of transaction data to determine whether trader behavior

exacerbated the price spike. In particular, the Team analyzed transactions executed in physical 

and some financial natural gas markets during late February to look for evidence that any trader

might have engaged in behavior designed to manipulate prices.

The Team was unable to analyze all natural gas transactions because these markets are 

not traded in centralized exchanges, so there is no central repository for information about 

natural gas transactions. To collect a reasonable sample of transactions, the Commission

subpoenaed sixteen over-the-counter natural gas brokers, including both “voice” brokers and 

electronic trading facilities like the Intercontinental Exchange (ICE), for information related to 

all natural gas trades, bids and offers during the week of the spike. 

The resulting data set included over 10,000 trades and over 100,000 bids and offers for 

both physical and financial natural gas products for more than 100 locations across the United 

States. Based on strong anecdotal evidence, the Team believes the data set represents more than 

half of next day physical trades, the most relevant product markets given the short-term, 

fundamentals-driven nature of the spike.

8

 Transactions not included in the sample include deals 

done directly between traders and NYMEX transactions. 

Detailed analysis of this transaction sample showed no signs of market manipulation. 

Analysis of the sample data included, but was not limited to assessments of trader activity levels, 

effectiveness of the way certain markets relate to one another, actual patterns of trading and 

human intelligence. We will consider each of these tests in some detail.

Trader activity tests show some thinness and concentration. 

When markets have too few active participants, or when a few participants have a 

disproportionate share of the activity, then they are at higher risk of not functioning well. We 

call markets with these characteristics “illiquid” and “concentrated.” Liquid markets are ones 

where a trader can easily buy or sell at a prevailing price with relatively low transaction costs, 

and are characterized as having many participants, many of whom are actively trading.

Physical natural gas markets, because they are so fragmented by geographical location 

and by timing of delivery (e.g., daily, monthly, longer-term), often face problems with liquidity. 

The Team’s analysis supports this conclusion.

 

8

 In the April 24, 2003 Staff Conference on Natural Gas Price Formation, Chuck Vice, Senior Vice President and 

Chief Operating Officer of ICE asserted that he believed that ICE handled 70% of day-ahead physical natural gas 

transactions (p. 33 of the transcript). The investigating team interviews with traders confirmed opinions that ICE 

represents between 50% and 70% of their day-ahead physical natural gas transactions. Additionally, in the June 24, 

2003 Technical Conference on Natural Gas Price Formation, three trading panelists confirmed that transactions with 

ICE and voice brokers are “representative” of this market (pp. 239-249 of the transcript).
July 23, 2003 Page 9

Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

Concentration Ratio

of 4 Largest

ICE Market Number of Number of Volume Buyers Sellers

Location Traders Sales (MMBtus) (Volume %) (Volume %)

Production Area:

Henry Hub 32 76 1,069,733 56.7 48.9

New York:

Transco Zone 6 New York 14 15 104,533 81.0 68.6

Chicago:

NGPL, NICOR 22 41 440,017 71.3 55.4

PGLC 17 22 257,650 67.9 66.4

West Texas:

El Paso Keystone 15 16 176,083 69.7 70.5

Waha 10 15 180,700 88.6 81.1

California:

PG&E Citygate 16 28 497,317 78.9 65.9

PGT Malin 12 13 173,217 82.6 69.7

Table 1: Average Daily Next Day Physical Natural Gas Trading Activity 

as Sampled on ICE Over the Week of the Price Spike 

(February 21 through February 28, 2003)

Table 1 shows trading statistics on ICE for physical day-ahead natural gas markets in the 

geographical locations discussed above for the period from February 21 through 28, 2003. The 

most actively traded location reported in the table is Henry Hub, with an average of 32 traders 

that executed 76 transactions for over a billion cubic feet of natural gas each day of that period. 

Of the daily average of 32 traders, the largest four buyers averaged almost 57 percent of the 

natural gas purchased, the largest four sellers 49 percent of volumes sold.9 (Other locations, 

particularly in production areas, were as actively traded.) 

Liquidity and concentration measures for the regional markets are less robust than Henry 

Hub. However, numbers of traders and transactions are not significantly different than normal as 

measured using averages noted by ICE for the first four months of 2003. Recently, ICE through 

its 10X subsidiary has begun to publish the data related to number of traders and trades, and 

volumes along with volume-weighted average prices for these markets on a daily basis.

By definition, because Table 1 was generated using a sample of the market – albeit a 

large sample – Table 1 understates trading activity and may overstate concentration somewhat. 

In addition, there are no direct comparisons to these physical natural gas markets to use as

benchmarks.

10

 Also, concentration ratios are evidence of the potential for inefficient prices or 

manipulation, not necessarily evidence of those problems. Still, increased numbers of active 

 

9

 This study uses a four trader concentration measure to emulate, as closely as possible, concentration ratios used in 

the CFTC’s weekly Commitment of Traders reports. However, the CFTC’s measure is of open interest, which is not 

the same as volumes sold. Our measure of trading concentration cannot be directly compared – underscoring the 

difference between the structure of physical and futures markets.

10 NYMEX natural gas futures as of February 25, 2003 had 176 traders with open interests for all 72 months traded. 

Concentration in the futures market is measured not by numbers of trades, but by open interests (size of positions 

held) at the end of the week. Using that alternate measure, on February 25, 2003, natural gas futures had 4 trader 

concentrations of 19.4% for net sellers and 26.6% for net buyers as reported in that week’s “Commitment of Traders 

Report.”
July 23, 2003 Page 10

Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

traders in these markets would improve liquidity and reduce concentration and a rebound of the 

energy trading industry would probably improve performance. The next three analyses of

market relationships, trading behavior and human intelligence are more direct evidence.

Markets appear to have related to one another effectively. 

Minute-by-minute comparison of transactions through voice brokers and on ICE for 

various physical natural gas markets tracked each other consistently through the last week of 

February. The Team considered these relationships over time, geographically, and between 

look-alike products.

As demonstrated previously in Figure 1, prices in the futures market for March delivery 

to Henry Hub changed less than in the Henry Hub physical next-day market. During the entire 

week of February 24, there was a substantial difference between these two markets. Though

lower than the day-ahead physical high price, March futures hit an all-time high price of

$11.899/MMBtu during early morning electronic trading on February 25, 2003. Figure 6 shows 

that the March futures price reached that high for only one trade, and traded above

$10.00/MMBtu for only a few hours in overnight electronic trading.

The fundamentals-driven rise in the short-term physical market did not have as a great

dollar effect on the futures market for the March 2003 contract because traders did not expect 

the price pressures to persist. Indeed, within two or three weeks, physical market prices returned 

to its historical relationship with futures prices. A short-term premium of physical markets to 

futures prices makes sense given the nature of the spike.

Figure 6: March NYMEX Natural Gas Futures Trading Reached a Brief $11.899/MMbtu

High in Before-Hours Trading in the Morning of February 25.

Source: NYMEX from nymex.com
July 23, 2003 Page 11

Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

To assess geographic relationships in more detail, the Team analyzed the price and timing 

of short-term fixed price physical and financial transactions at 23 trading locations in the Gulf 

Coast near Henry Hub on February 24. Figure 7 on the next page shows that transactions in all 

these markets reacted similarly throughout the day. 

Because these 23 locations are relatively close to one another physically (near the 

Louisiana Gulf Coast), trading in those areas tends to fall in a relatively close band. Erratic 

relationships could have been evidence of a number of factors including capacity constraints in 

the area or manipulation of pipelines, storage, or markets. None of these erratic relationships 

were found.

The Team performed the same analysis on five Northeast trading locations, and Figure 8

shows a similar result. Together, Figures 7 and 8 show similar timing for price movements 

between the production and this consumption region as well, though the movements were 

different in magnitude as discussed in the regional assessment of fundamentals above.

Finally, to test for similar behavior in similar products, the Team compared minute-byminute prices for March 2003 and April 2003 natural gas futures against monthly swaps traded 

on ICE and designed to function much like futures. The prices for both products tracked each 

other closely, showing the strong link between those markets.

In all cases, trading in comparable markets behaved as expected. Because of the shortterm, physical nature of the pressure on prices, prices in shorter-term markets spiked higher than 

in longer-term markets, with an apparent premium on physical delivery. Geographically, prices 

moved disproportionately to the rest of the country where capacity constraints applied. 

This collection of observations indicates that markets appeared to have related to one 

another relatively effectively, not creating large, apparent, unused opportunities to make money 

by trading between two markets.

Analyzed patterns of trading did not offer evidence of manipulation. 

Reviewing actual patterns of trading is the most direct way to search for potential

manipulation. For this study, the Team performed overlapping, detailed reviews of the sample 

information described above. In its extensive analysis of the transaction sample, described 

below, the team found no evidence of market manipulation.

The first steps of the analysis included construction of minute-by-minute timelines of 

trading in the most significant markets making use of 16,488 sample transactions and the 

138,446 sample unconsummated bids and offers (from ICE) in various physical and financial 

natural gas markets covering key locations across the overall United States natural gas pipeline 

delivery system. 

These timelines were used for detailed examinations of trading patterns, identifying times 

when prices of transactions changed most abruptly and identifying the traders most active during 

those periods. The activities of those traders was reviewed both in the context of the overall 

market, and individually in order to develop theories regarding their strategies. Multiple analysts 

reviewed these data using different analytic tools and approaches to increase the likelihood of 

finding suspicious patterns. These analysts periodically compared their overlapping findings to 

coordinate the analysis.
July 23, 2003 Page 12

Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

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Figure 7: Natural Gas Prices in Gulf Coast Markets near Henry Hub Traded Together

Closely on the Day of the Largest Price Movement During the Price Spike

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Price ($ per MMBtu)

Figure 8: Natural Gas Prices in Northeastern Markets near New York City Traded

Together Closely on the Day of the Largest Price Movement During the Price Spike
July 23, 2003 Page 13

Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

Analysts searched for patterns within products, for specific traders, and for product-trader 

combinations. The additional markets analyzed were chosen based on prices, size, liquidity and 

concentration. Specific company bids, offers, and trades reviewed were chosen based on size, 

number, unusual timing, and potential price-leading behavior among other considerations. 

The first set of markets examined were those trading products for the next day physical 

and balance of month “swing swaps” for February. 11 A total of 6,520 next-day physical and 

balance of month swing swap transactions were grouped by delivery points into specific

geographical regions. Each region was charted by day to focus on the relationships between the 

delivery points (as discussed above) and then the regions were compared to each other on a daily 

basis for trading from February 21 to 28. Using these timelines, Team analysts identified and 

reviewed low and high prices each day as well as periods of sharp price increases and declines. 

A second set of timelines were created for those companies that executed a significant 

volume of the transactions in each geographic region. These timelines were reviewed for patterns 

that would indicate that a particular trader was “leading” prices during sharp price increases or 

declines. No significant situation involving “leading” of prices was identified. 

A third set of timelines was created to compare March 2003 and April 2003 swaps 

settling against the NYMEX expiration price and executed through voice and online brokers tied 

to March 2003 and April 2003 natural gas futures.12 In these timelines, prices corresponded 

closely. A final set of timelines examined plotted prices for next day physical delivery versus 

March futures transactions (compared on a daily basis in Figure 1). The February next day 

physical price was found to trade at a premium to the March 2003 futures contract for the 

fundamental reasons described earlier.

Within each individual company’s activities, analysts looked for patterns of trades in one 

product which seemed inconsistent with their trades in another product. Additionally, the 

counterparties within each transaction were checked to see if they had consistently transacted 

with one another and if there were patterns within the trades between pairs of counterparties. 

The Team was able to identify behaviors reflective of a wide range of company-specific 

business strategies. These included evidence of various gradations of strategy from

straightforward supply procurement and sales activity through more active trading of positions. 

Subsequently, the Team held detailed follow-up interviews with eight of the most active traders 

in order to verify the Team’s theories regarding their strategies and identify other trading activity 

outside the sample. 

In its extensive review of the transaction sample described above, the team found no 

evidence of market manipulation.

 

11 Because trading that week was at the end of the month of February 2003, balance of the month products 

overlapped the timing of the price spike as well as the next day delivery market. “Swing swaps” are financial 

hedges that relate directly to prices in the next day physical market.

12 “Swaps” are financial products that, in effect, trade one price for another, with a payment made based on that 

difference. For example, the buyer of a swap might agree to pay the difference between a fixed price and a price 

determined later in a market.
July 23, 2003 Page 14

Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

No additional evidence of manipulation was found from Hotline calls or trader interviews. 

The Commission Hotline13 was monitored for calls regarding manipulation during the

February price spike. The Team also explored price spike market conditions in interviews with 

large buyers and sellers. 

One contact was made with Hotline staff expressing concern about the price spike, but 

the caller did not provide material information regarding market manipulation.

Interviewed industry participants did refer to a widening of the difference between where, 

from moment to moment, offers to sell and offers to buy would stand – known as the “bid/ask 

spread.” The size of this difference reflects many things including the competitive pressures on 

the markets, the level of liquidity and the mix of trading companies’ relative credit strength. A 

widening of bid/ask spreads was consistent with the forces on the markets at the time. No trader 

interviewed indicated that this was crucial problem.

 

13 Call toll free at 888-889-8030, locally at 202-502-8390 or email at hotline@ferc.gov. 
July 23, 2003 Page 15

Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

FINDINGS

After rising steadily last winter, natural gas prices in various physical and financial

markets spiked in the United States in late February, reaching a peak of $22.00/MMBtu for 

physical day-ahead delivery in producing areas on February 25, and topping $30.00/MMBtu in 

some Northeastern and Midwestern consuming areas. This study summarizes the Federal

Energy Regulatory Commission’s investigating team’s analysis of the February price spike, 

examining both market fundamentals and the behavior by energy traders in key markets.

The Team concludes that:

ß United States production-area prices spiked as a result of short-term conditions leading to

low supply and high demand. These conditions affected prices continent-wide. In 

particular, a cold front over the Eastern half of the United States significantly increased 

natural gas demand at the same time that gas deliverability declined due to low, latewinter storage inventories that reduced the ability to withdraw natural gas from storage 

and from some cold-weather well freeze-offs.

ß Some Northeastern and Midwestern consuming areas faced additional price increases 

because of a limited ability to deliver natural gas to customers in these areas. The Team

verified that pipelines from producing areas were full and storage withdrawals in market 

areas were inadequate to meet the additional demand, so that natural market dynamics 

should have caused these price increases.

ß Similar natural gas price spikes have occurred historically when episodes of cold weather 

occur at times when storage inventories are limited. Adequate storage inventory levels 

entering the coming winter would reduce the likelihood of price spikes in early 2004.

ß Detailed analysis of a large sample of physical and financial natural gas transactions that 

week found no evidence of market manipulation. Extensive interviews with large traders

– both buyers and sellers in that week – likewise provided no evidence of market 

manipulation.

ß The many physical and financial markets that together constitute the larger natural gas 

market appeared to operate effectively through the spike. Prices in these markets rose, 

but in apparent response to underlying supply and demand conditions and in ways the 

Team would have expected.

ß Natural gas markets in the last week of February 2003 consisted of relatively few buyers 

and sellers, too few of which were engaged in active trading. While less robust markets 

increase the possibility that these markets may not respond adequately under stress, 

market thinness and concentration are evidence of the potential for inefficient prices or 

manipulation, not evidence of those problems. Increased numbers of active traders in 

these markets would improve liquidity and reduce concentration and a rebound of the 

energy trading industry would probably improve performance.
July 23, 2003 Page 16

Report of the Natural Gas Price Spike of February 2003 FERC Staff Investigating Team

CONTRIBUTORS

Major Contributors to the Investigating Team included:

 Lee-Ken Choo, Team Leader

 Darrell Blakeway

 Robert Flanders

 Ted Gerarden

 Steve Harvey

 Rafael Martinez

 Kara Mucha

Thomas Pinkston

Demetrios Pulas

Marvin Rosenberg

John Roddy

Ann Vanture

Charles Whitmore