Summary 

The pump was primed for significant energy price effects well before Hurricanes Katrina 

and Rita hit the Gulf Coast production areas in September. The Gulf storms exacerbated already 

tight supply and demand conditions, increasing prices for fuels in the United States further after 

steady upward pressure on prices throughout the summer of 2005. Most of this was due to 

increased electric generation demand for natural gas caused by years of investment in gas-fired 

generation and a significantly warmer-than-average summer. Supply showed some weakness 

despite increasing numbers of active drilling rigs. The result was broadly higher energy prices 

(see Table 1). 

Natural gas prices rose most significantly, but continued to reflect normal historical 

patterns of moving between the prices for residual and distillate fuel oil based on apparent 

scarcity. Prices for electricity also increased due to rising fuel costs and the hot summer. 

Measured in national average cooling degree days (CDDs), the three core summer months (June, 

July, August and September) were 26 percent hotter than in 2004, which was closer to average. 

The higher prices were consistent with the potential for summer price increases noted last spring 

in staff’s 2005 Summer Energy Market Assessment (presented May 4, 2005). 

Then Hurricanes Katrina and Rita shut down many offshore gas platforms, onshore 

refineries and gas processing plants, albeit with different patterns of disruption. Hurricane 

Katrina led to an immediate rise in natural gas prices to as high as $12.69/MMBtu at Henry Hub, 

followed by a decline to $11.03/MMBtu by September 11 as it became clear that damage was 

less severe than initially feared. Hurricane Rita has led to continuing upward price pressures as 

the full extent of damage becomes clear. After prices reached $15.22/MMBtu immediately after 

Rita, Henry Hub was out-of-service until October 4, 2005, removing a key national benchmark 

for natural gas prices during an important period. 

Forward prices for natural gas and electric power have reached record-high levels. New 

York Mercantile Exchange (NYMEX) natural gas futures for January 2006 delivery ended 

September at $13.90/MMBtu at Henry Hub. Further, the NYMEX ClearPort basis swaps for 

New York City delivery reached $8.27/MMBtu on October 3, 2005. Traded forward electric 

price swaps reached over $190/MWh for on-peak January deliveries in New York City and New 

England. 

Table 1 

Summer 2005 Prices of Energy Products 

Spring 2005 

(4/5 - 4/9)

Summer before Hurricanes 

(8/22-8/27)

Summer after Hurricanes 

(9/26-9/30)

 Average Price Average Price

% Change to 

Prior Price Average Price

% Change to 

Prior Price

Natural Gas (Henry Hub*) $7.39 /MMBtu $9.81 /MMBtu 33% $14.10 /MMBtu 44% 

Natural Gas (Transco Zone 6 NY) $7.96 /MMBtu $10.39 /MMBtu 31% $14.90 /MMBtu 43% 

Crude Oil (West Texas) $9.40 /MMBtu $11.42 /MMBtu 21% $11.39 /MMBtu 0% 

Heating Oil (New York) $11.97 /MMBtu $13.33 /MMBtu 11% $15.15 /MMBtu 14% 

Residual Oil (NY .3% Sulfur) $7.47 /MMBtu $9.58 /MMBtu 28% $12.71 /MMBtu 33% 

Coal (Powder River Basin) $26.50 /Ton $30.70 /Ton 16% $33.10 /Ton 8% 

Coal (Central Appalachian) $60.60 /Ton $58.30 /Ton -4% $59.10 /Ton 1% 

* Texas Eastern East Louisiana point substituted for Henry Hub when it was out of service due to flooding. 

Source: Platts Gas Daily and Bloomberg
2

Summer 2005 Energy Price Review: 

Gulf Storms Exacerbate Tight Natural Gas Supplies; 

Already High Prices Driven Higher 

Natural Gas Markets 

Natural gas prices rose throughout the summer, reflecting rising oil prices, unusually high 

demand for gas-fired electric power and lagging gas supply additions. Price increases were not 

uniform across the country (see Figure 1): 

• Natural gas prices rose in the West less than in the East due to relatively cooler weather 

and improved access to newer Wyoming gas supplies through recently expanded pipeline 

systems. 

• Immediately in the wake of the hurricanes, Florida prices rose to the highest levels in the 

nation, reflecting delivery infrastructure disruptions due to the hurricanes themselves. 

• Forward markets implied the likelihood of increasing price differences between 

producing regions and the Northeast, suggesting that market participants are concerned 

about the adequacy of transportation infrastructure to that region for the winter. 

Natural Gas Supply Forces 

Much of the increase in natural gas prices came from tight supplies. Even before the 

hurricanes, the market was responding to declines in domestic production and reduced imports of 

liquefied natural gas (LNG). 

Figure 1 

Price Responses to Gulf Hurricanes Differed by Region 

(August 1 through October 7, 2005) 

5

7

9

11

13

15

17

19

21

4/1 4/15 4/29 5/13 5/27 6/10 6/24 7/8 7/22 8/5 8/19 9/2 9/16 9/30

$/MMBtu

Algonquin

SoCal 

Columbia Gulf

Florida Gas, Zn. 3

Transco Zn. 6

Chicago city-gates

Henry Hub

Columbia Gulf

Note: Due to a force majeure declaration by Sabine Pipeline, operator of the Henry Hub, index publishers have 

not reported after Sept. 25, 2005. 

Source: Staff analysis of Gas Daily data as of Oct. 3, 2005. 
3

Declining Gas Production 

According to Lippman Consulting, domestic production of natural gas has fallen by about 

one percent (389 MMcfd) between the summer of 2003 and the summer of 2005.1

 Production 

has declined despite increases in natural gas exploration and development. The rotary rig count 

rose 30 percent during the same period.2 Cambridge Energy Research Associates (CERA) 

projects that increases in LNG receipts and net pipeline imports will not offset domestic gas 

production declines and natural gas storage withdrawals. CERA forecasts that overall gas supply 

for the United States will fall 0.2 percent for 2005 from 59.62 Bcfd in 2004.3

Summer LNG Imports Declined Despite Higher North American Gas Prices 

The United States imported 45 Bcf (or 13 percent) less LNG during the period from April 

through September in 2005 than in 2004.4 During August prior to Hurricane Katrina, U.S. 

imports were almost 600 MMcfd lower than for the comparable period in 2004. The United 

States competes with other nations for spot LNG shipments, and often higher LNG prices in 

other countries drew away spot supplies. 

Demand Forces 

The summer of 2005 was abnormally hot. The National Climatic Data Center (NCDC) 

reports that during the critical period between June and August, cooling degree days (CDDs) 

increased 26 percent compared to 2004 (see Figure 2).5

Figure 2 

June through August 2005 Was Significantly Hotter than 2004 

41

140

29

259

367

348

220

178

254

310

208

91

0

50

100

150

200

250

300

350

400

Apr May Jun July Aug Sept

2004 CDD

2005 CDD

Source: Staff analysis of National Weather Service, Climate Prediction Center, as of Sept. 30, 2005. 

 1

 Lippman Consulting, Inc., “U.S. Wellhead Production Report,” October 2005. 

2

 Baker Hughes, Inc. 

3

 CERA, Monthly Gas Briefing, “A Band of Uncertainty,” Table 9. Lower-48 Gas Supply/Demand Summary, 

September 20, 2005. Staff analysis of Table 9. 

4

 U.S. Waterborne LNG Report, Sept. 29, 2005. 

5

 National Weather Service, Climatic Prediction Center, on-line degree day statistics. 
4

Figure 3 

Surplus Natural Gas Storage Inventories 

Fell Through Summer 2005 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar

Volume (Bcf)

5-year range 2004-05 2005-06

Source: Staff analysis; derived from EIA Historical Weekly Storage Estimates Database, Weekly Natural Gas Storage 

Report data through the week ending Sept. 30, 2005. 

Starting in June, increased air conditioning demand increased the use of gas-fired electric 

generation. At the end of May, year-to-date net generation by gas-fired generators was 0.4 

percent below the 2004 level; by the end of July, it was 7.1 percent higher. In July, natural gas 

consumption by gas-fired generators was 25 percent higher than in July 2004.6

 

Natural Gas Supply/Demand Balance 

The closest-to-real-time measure of the active balance of supply and demand is natural 

gas inventories in storage. At the beginning of summer 2005, natural gas storage inventories 

were high compared with earlier years. That initial storage surplus dropped throughout the 

summer (see Figure 3). As reported by the Energy Information Administration, effective May 

27, working gas inventories were 1,778 Bcf, or 20.6 percent (304 Bcf) above the five-year 

average.7

 For the week ending September 30, national storage inventories exceeded the fiveyear average by 40 Bcf, or 151 Bcf lower than the comparable week in 2004. Storage 

inventories differ by region, with relatively high inventories in the West and low in the eastern 

consuming areas. Hurricanes Katrina and Rita have reduced (sometimes eliminated) injections 

into production area storage, but the full effects are not yet clear. 

Effects of Hurricanes Katrina and Rita 

Hurricane Katrina resulted in the immediate loss of 8.3 Bcfd of gas production, 

significantly more than Hurricane Ivan in 2004 (see Figure 4 on the next page). About 66 

percent of Gulf production was back on line before Hurricane Rita struck. Hurricane Rita 

increased outages greatly, and recovery has been slower. The hurricanes not only reduced 

 6

 EIA, Monthly Flash Estimates of Electric Power Data, tables 3.1 and 3.2, September 2005 edition. 

7

 EIA, Weekly Natural Gas Storage Reports and staff analysis. 
5

Figure 4 

Hurricanes Katrina and Rita Cut Gulf Production 

More than 2004’s Hurricane Ivan

0

2,000

4,000

6,000

8,000

10,000

1 6 11 16 21 26 31 36 41

Day

MMcf/day

Katrina landfall - 8/29/05

Ivan landfall - 9/15/04

Rita landfall 9/24/05

Source: Staff analysis of MMS data. 

natural gas production but also damaged pipeline and gas processing infrastructure and electric 

power supply along with oil production and refineries. The effects on natural gas markets were 

both to increase prices (and price volatility) and to reduce market activity. 

Price Effects 

Hurricane Katrina produced a sharp increase in prices followed by a moderate decline as 

the industry found that damage was less severe than initially feared. Overall, Henry Hub spot 

prices increased to $12.69/MMBtu.8 The futures contract for September delivery reached a final 

expiration price of $10.85/MMBtu.9 Hurricane Rita again raised daily prices later in September 

as high as $15.22/MMBtu at the Henry Hub before it was closed due to flooding and prices no 

longer published.10 Forward prices have reached very high levels, as we will discuss in a later 

section. 

Trading Operations and Liquidity 

After Katrina hit the Gulf Coast on Monday, August 29, the last trading day for the September 

natural gas futures contract, Henry Hub deliveries were not possible due to physical outages. 

Price volatility increased in the futures markets as traders scrambled to reduce their exposures. 

Physical deliveries under the September contract were the lowest since 1992.11 Again after 

Hurricane Rita, Henry Hub was physically unavailable due to flooding. NYMEX adjusted 

delivery of the September and October natural gas contracts to make up for the Henry Hub 

 8 Gas Daily, Sept. 1, 2005 

9 Gas Daily, Aug. 30, 2005. 

10 Gas Daily, Sept. 23, 2005 

11 Physical deliveries are contemplated under NYMEX’s natural gas futures contract, but are not the norm. Source is a 

staff conversation with CFTC staff. 
6

interruption. Uncertainty engendered by physical outages at Henry Hub appeared to contribute 

to unusually volatile trading on September 28, the last trading day for the October contract. 

The IntercontinentalExchange (ICE) reported that trading volumes at key points such as 

Henry Hub and Transco Station 65 declined markedly with the onset of Hurricane Katrina, but 

then resumed more normal levels. However, trading volumes reported at other Gulf points – 

such as Sonat and Florida Gas Transmission Zone 3 – remain depressed. These points took some 

time to fully recover due to upstream gas processing outages and flow disruptions on 

interconnecting pipelines. Henry Hub resumed trading on ICE on October 7, 2005. 

Electricity Markets 

Overall, electricity prices have been significantly higher in 2005 than in 2004. Through 

early September, year-to-date prices in NYISO averaged $79/MWh versus $59 at the same time 

last year; in PJM, $64 versus $50; at Cinergy, $57 versus $39; and at Palo Verde, $58 versus 

$44.12 

Electricity prices rose through the summer in response to higher demand and higher fuel 

costs. Hot weather prevailed in many regions, especially in the East. From April 1 through midSeptember, CDDs were 39 percent above average in the Mid-Atlantic and 42 percent above 

average in the Northeast. As a result, generation in June, July and August far outpaced recent 

history (see Figure 5) and peak demand set many new records (see Table 2 on the next page). 

 Rising levels of peak demand highlight a continuing need for upgrades to the electric 

infrastructure in some regions, most prominently the Northeast and California. 

Figure 5 

Electric Generation Increased with Heat from June through August, 2005 

US Electrical Output

60,000

70,000

80,000

90,000

100,000

weekly output in GWh

2005 output

range of output,

2000 - 2004

Jan Oct Feb Sep Mar Apr May Nov Dec Jun Jul Aug

Source: Staff analysis of data from Edison Electric Institute, Weekly Electrical Output. Excludes data from Alaska and 

Hawaii.

 12 Prices given are for peak hours (typically Monday through Friday, 7 a.m. through 11 p.m.) Off-peak prices rose 

roughly 50 to 100 percent in the East and Midwest and 10 to 25 percent in the West. 
7

Table 2 

Electric Systems Reached New Demand Peaks in 2005 

Region New Peak 

MW (date)

Previous Peak 

MW (date)

New England (ISO-NE) 26,921 (7/27/05), 26,760 (7/19/05) 25,348 (8/02)

New York (NYISO) 32,075 (7/26/05), 31,741 (7/19/05) 30,982 (8/01)

Mid Atlantic/Central (PJM) 135,000 (7/26/05), 130,574 (7/18/05) [n/a] 

Midwest (MISO) 131,434 (8/3/05), 131,188 (8/2/05) [n/a] 

South Central (SPP) 38,852 (7/22/05), 38,612 (7/21/05) 38,321 (8/03) 

Texas (ERCOT) 60,279 (8/23/05) 60,095 (8/03) 

Southern California (SCE) 21,110 (7/20/05) 20,762 (9/04)

Source: ISO-NE, NYISO, PJM, MISO, SPP, ERCOT, press reports. 

Rising fuel prices, especially for natural gas, contributed to higher electricity prices. Fuel 

costs affected prices most strongly in eastern regions because they have substantial gas- and oilfired generation and higher locational fuel premiums, but electricity prices in all regions ended 

the summer well above year-ago levels (see Figure 6). 

Effects of Hurricanes Katrina and Rita on Electricity 

Hurricane Katrina caused significant electric system damage in Florida and 

unprecedented destruction in Mississippi and Louisiana. Just after landfall on the Gulf Coast, 

2.7 million customers were without power. Hurricane Rita struck Louisiana and Texas and left 

1.5 million customers without power, including about 200,000 not yet restored from Katrina.13

The hurricanes’ effects on natural gas prices flowed through to electric markets, 

especially in the East. For example, in the two weeks after Katrina struck, New England 

bilateral power prices averaged 21 percent higher than the prior two weeks. Western prices also 

rose, but less steeply, reflecting the lower price of gas in the West. 

Figure 6 

Electric Generation Increased with Heat from June through August 2005 

0

20

40

60

80

100

120

140

160

1-Apr 1-May 1-Jun 1-Jul 1-Aug 1-Sep 1-Oct

Day-Ahead Price, $/MWh

PJM

New

York

Entergy

Palo 

2005

2004

Day-Ahead Electricity Prices

2004 and 2005

Source: Platts. Prices through 9/30/05

Source: Staff analysis of Platts Megawatt Daily, PJM, NYISO data. Prices are for peak hours. 

 13 DOE, Office of Electricity Delivery and Energy Reliabiltiy, Gulf Coast Hurricanes Situation Reports, Sept. 22 – 25, 

2005. 
8

Implications for Winter Energy Prices 

Conditions that affected energy markets this summer are likely to continue to affect 

winter markets. Forward prices for key fuels have risen, partly because of concern about storage 

inventories, especially for natural gas. In turn, forward power prices increased to over 

$200/MWh in the Northeast and well over $100/MWh elsewhere before falling slightly in 

October. 

Natural Gas Supply and Futures Prices 

Hurricanes Katrina and Rita will have a lasting effect on natural gas prices. As of 

October 6, more than 6.4 Bcfd of Federal offshore natural gas remained shut-in due to damage to 

wells, platforms, pipelines and gas processing facilities.14 Re-opening processing plants is 

particularly important; 15 facilities constituting 10.1 Bcfd of capacity remain closed as a result of 

the hurricanes.15

Currently, spot prices in the United States are significantly higher than in Europe 

(although winter forward prices are similar), leading some analysts to believe that the United 

States may be able to attract additional LNG imports away from Europe this fall.16 The Lake 

Charles terminal in Louisiana has the capacity to accommodate additional LNG cargoes. While 

the ship-turning basin at Lake Charles was initially littered with hurricane detritus, clean-up was 

quick and the first post-hurricane shipments began to arrive in early October 

Price Implications for Electricity 

Winter power prices may be much higher than last year. Forward power prices for winter 

have risen all summer and are now at historic highs (see Figure 7). 

Figure 7 

January/February 2006 Forward Electricity Prices 

Reflect Fuel Price Expectations for the Winter 

0

50

100

150

200

250

5/31/2005 7/1/2005 8/1/2005 9/1/2005 10/2/2005

$/MWh

Forward Prices for January/February 06

(except as noted) by Trade Date New York City

Mass Hub

Palo

Verde

(1st Q 06)

Entergy

PJM

Source: Platts

 14 Dow Jones News Wire, MMS: Further Improvement in Reported Oil, Gas Output, October 6, 2005 

15 Gas Daily, Oct. 3, 2005 

16 Natural Gas Intelligence, Sept. 12, 2005, 7-8. 
9

Price increases are likely to be greater in the Northeast. A January/February forward 

contract for New England was about $75 higher than one for PJM on September 30; on June 1 

the difference was about $24. This increased differential may reflect regional concerns about 

deliverability of natural gas through the winter. Scarcity premiums for natural gas also may 

cause winter price spikes in the Northeast, as they have for the last three years. Such spikes will 

be more likely (and perhaps higher) if gas supply interruptions remain severe or if winter 

weather is colder than normal. 

Electric power prices in the Northeast will be driven more by natural gas prices than by 

availability of electric generation. Lower winter loads reduce system demands, lower congestion 

costs and make the use of scarcity pricing unlikely. Still, electric price spikes resulting from gas 

price spikes are possible and could be aggravated by strains that extremely cold weather can put 

on the electric systems. The Northeast also faces a continuing need for infrastructure upgrades 

(for example, into southwest Connecticut), without which the transmission system is more 

vulnerable to strain. 

FERC will soon release its Winter Energy Market Assessment, 2005-06, which will 

review prospects for winter prices in more detail. 
10
11

Appendix: 

Summer 2005 Northeastern Electricity Price Issues 

Electric markets in 

New York and New England 

have faced unusual challenges 

during 2005 because of both 

hot weather and particular 

features of their markets. 

New York 

The New York 

Independent System Operator 

(NYISO) used its demand 

curve for reserves for about 12 

percent of the hours in its real 

time market during the 

summer of 2005. It had never 

been used before. These 

administrative price premiums 

apply when operating reserves 

are close to or below required 

levels. The price premiums 

ranged from negligible to 

about $250/MWh.17 

Very high real-time 

market prices were more 

common in 2005 than in 2004 

(see Figure 8). The reserve 

demand curve, higher loads 

and higher overall price levels 

were likely causes. 

 

 17 Reserve demand premiums 

vary by product and location and often 

affect prices for less than one hour, so 

it’s difficult to accurately measure their 

total price effect. 

Figure 8 

Peak Electricity Prices in the New York ISO 

Peak RT Hours, June through August 

0%

10%

20%

30%

40%

50%

60%

70%

Frequency

2004 2005

Zone A

(Western New York)

Zone G 

(Hudson Valley)

0%

10%

20%

30%

40%

50%

60%

70%

Frequency

2004 2005

Zone J 

(New York City)

0%

10%

20%

30%

40%

50%

60%

70%

1 2 3 4 5 6 7 8 9 10 11

Frequency

<0 0 - 25 25 - 

50

50 - 75 75 - 

100

100 - 

125

125 - 

150

150 - 

175

175 - 

200

200 -

225

>225 Price Range

2004 2005

Source: Staff analysis of NY-ISO data. 
New York also saw a few very high or very low real-time prices that resulted from 

software errors. NYISO subsequently corrected these prices. Finally, load forecasting errors 

caused a few high negative prices before the forecast software was adjusted to take into account 

earlier system performance.18

New England 

Real-time prices were high during times of high loads and constrained resources. The 

NEMA/Boston (Northeast Massachusetts plus Boston) zone price reached $1,467/MWh for one 

hour on August 8 when a large generator in the zone went out of service. The NEMA/Boston 

price reached $857/MWh during another hour two days later, in similar circumstances. 

During 2005, congestion and uplift have increased substantially. Connecticut zone 

congestion averaged $7.39/MWh this summer, compared to $1.76 last summer. Congestion in 

the NEMA/Boston zone increased to $4.43 from negative17 cents. 

Uplift costs for dispatching out-of-merit units totaled $200 million through August, 

surpassing the 2004 total of $169 million. Most of the uplift (71 percent) came from the real 

time market. 

 18 Source: NYISO discussions with staff. The real-time market handles about 3 percent of energy market volumes in 

New York. The day-ahead market handles about 50 percent of energy market volumes.