1

Federal Energy Regulatory Commission

Winter 2005 Winter 2005 - 2006

Energy Market Update Energy Market Update

Item No.: A Item No.: A-3

February 16, 2006 February 16, 2006

Good morning Mr. Chairman and Commissioners Brownell and Kelly.

I’d like to review U.S. energy market conditions as we near the end of the 2005/06 heating 

season, review prospects for the gas market, and finally, spend a little time discussing recent 

staff research of electric generation investment patterns in 2005. At that point, Jeff Wright 

will take over to discuss LNG activity and storage and pipeline infrastructure investment 

efforts.
2

Gas Prices at Summer Gas Prices at Summer 

Levels With Mild Winter Levels With Mild Winter 

Source:

Intercontinental

Exchange

Natural Gas Prices (MMBtu)

$-

$5.00

$10.00

$15.00

$20.00

Katrina

Rita

M-05 J-05 J-05 A-05 S-05 O-05 N-05 D-05 J-06 F-06

Since we last reviewed natural gas market conditions on January 19, prices for gas in the 

United States have continued to moderate, dropping to about $7.30 per million British 

thermal units (or MMBtu) in trading Wednesday for gas delivered today at Henry Hub, 

Louisiana. That price represents less than half of what it was at its recent high during a 

period of post-hurricane cold weather last December 13. The last time we saw a price this 

low was in trading on July 1, 2005. The current price is about a dollar higher than in midFebruary 2005. 

The price differences between the eastern and western parts of the United States that I 

pointed out in December have largely disappeared. These differences were related both to 

facilities outages and to the location of disrupted Gulf production, that tends to be better 

connected to the east. With the continued improvement in Gulf production and prevailing 

market conditions I will discuss next, the market rationale for east/west differences appears 

to be gone. 
3

Record Mild January Record Mild January 

Reduced Demand Reduced Demand

Source:

National Oceanic and 

Atmospheric Administration

Record 

Warmest

Much Above 

Normal

Above 

Normal

Temperature

1=Coldest Year 

112=Warmest Year

The weather in January was extraordinary. There is no other word for it. January was the 

warmest in the full 112 years tracked by the National Oceanic and Atmospheric 

Administration or NOAA. Temperatures averaged 81⁄2 degrees above norms. This map, 

produced by NOAA, shows how widespread the warm weather was. Fifteen states in the 

northern Plains, Great Lakes and Midwest, shown in red on the map, had their warmest 

January in 112 years. NOAA identified an additional 26 states as above average, shown in 

orange. The “coolest” state in January was Arizona, which nevertheless had its 21st 

warmest January in 112 years. 

NOAA scientists estimate that residential energy needs in January were 20 percent less than 

under normal temperatures. Consistent with that estimate, figures released by the Federal 

Reserve yesterday indicate that natural gas deliveries fell 15.0 percent from December to 

January.

This record warm spell followed the 9th warmest November and a roughly average 

December. In all, this winter’s extraordinary weather and the resulting weak energy 

demand has resulted in gas market conditions we certainly couldn’t have predicted in the 

Fall.
4

Storage Now Above Storage Now Above 

5-Year Highs Year Highs

5-year 

range

2004-05

2005-06

Source:

Energy Information

Administration

Storage Inventory (Bcf) 1,000

2,000

3,000

0

A M J J A S O N D J F M

Months

For example, storage inventories for natural gas last week reached above the previous 5-

year range. Inventories last week were 649 billion cubic feet (or Bcf) above the 5-year 

average – almost 38percent. Today’s report of a 102 Bcf withdrawal was right at 

expectations, resulting in continued high inventories.

Instead of being short of supply, the industry now faces the task of getting enough gas out of 

storage by the end of March, considered the end of the heating season. For physical 

operations reasons, inventories for most storage facilities have to fall to certain levels to 

maintain their integrity. As of today, even historically strong withdrawals for the rest of the 

season could easily result in record high inventory levels on April 1.

This is a remarkable story. After starting the winter in a strong inventory position but with 

real concerns as to the availability of supply from the Gulf for the winter, our literally 1-in100 chance warm weather has resulted in a current surplus of gas inventory. We bet, as a 

country, on mild weather, and we hit the jackpot.

I noted last month the “kink” in withdrawals you can see on the graph in mid-December, 

where the red line had been moving down the middle of the 5-year range, but then appeared 

to turn and has now reached slightly above the band. At that time, we observed less gas 

being withdrawn from storage per heating degree day than we’ve seen in the past. We now 

think that there are three basic reasons for this.

Continued on next page
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Continued

First, as I’ve already indicated, the weather for the last week of December and through 

January was so mild that it didn’t function like a winter month, more like a “shoulder 

period” (or mild fall or spring) month. Consequently, demand was reduced even more than 

a less extreme variantion of temperature would predict.

Second, reductions in demand may have been the result of decisions by customers to change 

their behavior – what I’ll call a “demand response.” We’ve noticed anecdotal evidence of a 

demand response to the high prices of the early winter in the form of more attention to, for 

example, lowering thermostats and taking other energy-saving actions. Almost certainly, 

high November and December gas bills changed customer behaviors. In addition, the 

Department of Energy and many state and local authorities have made significant efforts 

this winter to encourage conservation. 

Third, high prices are likely to have had a supply effect as well. Evidence for a supply 

response is also anecdotal, but compelling. For example, rig counts surged recently to 

record highs not seen since the early 1980s.

More directly, Bentek Energy, consultants who follow pipeline flow information closely, 

released a report last week titled “Gas Market Fundamentals” that reports their insights into 

supply trends. To quote their findings, Continental U.S. production is dramatically 

responding to the current high price environment. . . . Basins having the greatest increases 

are Ft. Worth (17 percent), Uinta-Piceance (16 percent), E. Texas (11 percent), Arkla (10 

percent), Raton (9 percent) and Wind River (6 percent). . . . Were it not for the hurricanes, 

U.S. production would have increased by 2.7 percent over 2004. The basins Bentek

identifies as showing growth are significantly smaller than the Gulf Coast production, but 

their combined effects are material. Storage inventories are the most immediate signal we 

receive of supply/demand balance issues in U. S. natural gas markets. However, storage 

inventories do not identify the relative contributions of what forces are at play – they could 

be demand- or supply-related, or both. When the Energy Information Administration’s 

detailed statistics on consumption and production patterns are compiled and released later 

this year, we will study them to detail the relative influences of supply and demand 

responses. 
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Factors Influencing Factors Influencing 

Gas Markets in 2006 Gas Markets in 2006

 Extreme effects on supply Extreme effects on supply 

(hurricanes) and demand (hurricanes) and demand 

(January weather) (January weather)

 Apparent responses to price by Apparent responses to price by 

both supply and demand both supply and demand

 Anticipation of oil prices and Anticipation of oil prices and 

summer weather summer weather

Several factors appear to be influencing where the U.S. natural gas markets are likely to 

head next. The first is the history of extreme weather disruptions in the recent past –

hurricanes and mild winter weather – resulting in an initially strong storage position. The 

second may be long-lived responses to historical and future prices by customers and

producers. A last set of drivers at play include expectations about the price of oil and the 

possible effects of summer weather. Remember that last summer was warmer-than-average, 

and that oil prices are still rather high – just recently creeping below the $60 per barrel 

range. Last month I showed how high oil prices create something of a floor for gas prices. 

At this point, we are watching to see whether that floor will hold in the face of extremely 

high storage inventories and possible demand and supply responses to price.

One way of assessing current expectations of energy prices is to examine futures prices. 

Futures are in no sense a predictor of future prices because futures prices include other 

forms of value than just expected supply and demand. Still, their patterns reflect current 

expectations of buyers, sellers and others interested in energy markets. Currently, futures 

are indicating an expectation that prices today are about as low as they are likely to be for 

the remainder of the decade. Winter futures prices are in the $10.00/MMBtu range while 

summer futures, including this summer, are higher than the current spot price. 
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Electric Generation Growth Electric Generation Growth 

Was Strong in 2005 Was Strong in 2005

EEI Weekly Output US 2000-2005 

lower 48 states

GWh output

55,000

65,000

75,000

85,000

95,000

13 26 39 52

5 year range

2000-2004

2005 output

Source:

Edison 

Electric 

Institute

One reason for the expected continued strength in future gas prices may be the increasing 

demand for natural gas in electric generation. The Edison Electric Institute’s data regarding 

U.S. generation over the year in 2005 is graphed here in blue and compared to the 5 year 

historic range shaded in yellow. With hot summer temperatures, we see that 2005 electric 

generation was often higher last year than in the previous 5 years. In addition, while overall 

electric generation was up, generation from natural gas grew even more. According to 

available full-year data from EIA for the 5 years ending in 2004, the overall increase in 

electric generation grew at an average of 1.5 percent per year while electric generation from 

natural gas increased at an average rate of 5.1 percent per year for the same period. Another 

summer of strong electric demand growth for natural gas, like last year, may be a factor in 

current futures prices.

This relationship between electric and gas markets is becoming increasingly important. 

Consequently, as we consider this important relationship and begin to look forward to next 

summer, I’d like to shift the focus a little, and review some recent information developed by 

staff looking at generation investment trends.
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Generation Additions Generation Additions 

Declined Again in 2005 Declined Again in 2005

Source:

Staff analysis of 

data from EIA, 

Platts’ POWERDat, 

AWEA and various 

ISOs 2002 2003 2004 2005

2002-2005 Capacity Additions 

0

20,000

40,000

60,000

80,000

Summer Capacity 

To develop these generation addition figures, staff used data from a variety of sources 

including EIA, Platts’ POWERdat, the American Wind Energy Association, and the various 

RTOs and ISOs. Staff verified all the figures from the various sources in the assessment 

and eliminated any that it could not verify. As a result, estimates will differ. EIA reports 13 

gigawatts (GW) of additions, less than the staff analysis. Platts reports more, about 19 GW. 

In addition, staff figures do not take account of retirements or repowerings. However, 

staff’s methodology is consistent across the analysis presented.

According to our study, additions to U.S. generation capacity in 2005 totaled approximately 

17 GW, down 25 percent from the prior year and down 75 percent from 2002. 2002 saw the 

most generation additions in U.S. history. So, to put 2005 additions into a larger context, 

though lower than the previous 5 years, 17 GW represented more generation added than in 

14 of the previous 20 years. Current plans indicate that additions in 2006 are likely to be 

roughly half the 2005 level.

Several trends were interesting. The first is that the generation additions were slightly more 

diversified in 2005, with 84percent burning gas as opposed to 96 percent in 2004. Coal 

remained steady at 2percent, and wind increased significantly from 1percent in 2004 to 14 

percent in 2005. The wind increases were certainly related to the extension of federal tax 

credits and the expansion of state fuel diversity initiatives. Clearly, gas is and likely will 

continue to be a dominant fuel for new generation for some time. Although there has been 

increased discussion of coal and nuclear generation in the recent past, the lead times for 

these investments are long, and generation using these fuels did not make big showings in 

2005. 
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Generation Investment Generation Investment 

Dominated by Utilities Dominated by Utilities

Source:

Staff analysis of data 

from EIA, Platts’ 

POWERDat, AWEA 

and various RTOs

MUNI/COOP

IPP

IOU

IOU Affiliate

2005 Regional Capacity

Additions by Sponsor Type

Summer Capacity 6,000

0

2,000

4,000

California

ERCOT

Midwest

Northwest

NYISO

PJM

Southeast

Southwest

SPP

New

England

This graph shows both the geographic diversity and the ownership breakdown of generation 

investments. Let’s start with geography. The biggest area for investment was in the 

Southeast, mainly in Florida, which faces some congestion. California and the Midwest not 

only saw relatively high levels of investment, but also showed substantial increases over 

2004 levels, with California investment more than tripling and Midwest investment almost 

doubling. New England had no additions we could identify, and PJM’s were small, mainly 

renewables. I should note that the staff analysis and PJM differ on the timing of one 750 

megawatt plant. We counted it in 2004, as has EIA. PJM counts it in 2005. Overall, about 

one third of all additions appear to have been made in areas that are constrained and face 

transmission congestion, particularly California, Wisconsin and downstate New York. The 

breakdown in investors is also of interest. In total, municipals and cooperatives added a 

little less than 4 GW, just slightly less than in 2004. Investor-owned utilities, identified as 

IOUs on the graph, added 7 GW of the capacity in 2005, almost tripling their 2004 

investments. Their affiliates added a little over 2 GW, a little more than a third of what they 

added in 2004. Finally, independent power producers, shown as IPPs on the graph, added 

more than 4 GW, down from over 7 GW in 2004. Geographically, there were differing 

patterns. In the Southwest, for example, virtually all generation added was by munis, coops 

and investor-owned utilities. The most investment by independents was in California, the 

Southwest, Texas (or ERCOT) and the Midwest. We expect generation additions to decline 

again in 2006 and an increasing proportion of development efforts to focus on baseload coal 

and nuclear as well in renewables. Regional trends in investment and trends in investor 

type are not so clear. With that, I’d like to turn it over to Jeff.
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U.S. LNG Imports U.S. LNG Imports 

Decline Slightly Decline Slightly

0

100

200

300

400

500

600

700

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Bcf per year

Source:

DOE/OFE, 

EIA

At the last Commission meeting I gave a preliminary recap of US LNG activity in 2005. 

Since that time the Office of Fossil Energy at the Department of Energy has finalized the 

LNG information for 2005. DOE reports that during 2005 the United States imported 275 

cargoes of LNG totaling 631.3 Bcf. This is a 3 percent reduction in LNG imports from 

2004 levels. LNG supplied about 3 percent of the U.S. gas supply, assuming total 2005 

demand of 22 Tcf. The weighted average price per Mmbtu for the imported LNG was $7.82 

which compares favorably with the Henry Hub price, which averaged $9 per Mmbtu for 

2005, according to the Energy Information Administration.
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U.S. LNG Imports U.S. LNG Imports 

Dominated by Trinidad Dominated by Trinidad

0

100

200

300

400

500

Trinidad

Algeria

Egypt

Malaysia

Nigeria

Qatar

Oman

Bcf per year

Source:

DOE/OFE

About 70 percent, or almost 430 Bcf of LNG, came from Trinidad, our largest supplier. 

Approximately 62 Bcf originated in Algeria and nearly 50 Bcf was imported from Egypt. 

These three countries accounted for 86 percent of 2005 LNG imports to the U.S. 
12

U.S. Imports U.S. Imports 

Predominantly Short Predominantly Short-term

0

50

100

150

200

250

Cove

Point

Everett

Elba

Island

Lake

Charles Gulf

Gateway

Bcf per year

Short 

Term

Long 

Term

Source:

DOE/OFE

The busiest U.S. regasification terminal was the Cove Point facility in Maryland, which 

received 222 Bcf, or 35 percent of the total imported LNG. And, it should be noted, all of 

the volumes it received were under short-term authorization. The least active terminal was 

the offshore Gulf Gateway which, after opening in March 2005, received only two cargoes.

Let me explain that the Office of Fossil Energy at the Department of Energy approves LNG 

imports either on a long-term basis (greater than 2 years) or on a short-term basis. Shortterm authorizations are blanket authorizations which do not require a contract to be 

provided. However, the length of the contract underlying the authorization – whether short 

or long-term – is not necessarily relevant to whether LNG shipments are required under the 

contract to be delivered to the United States. Just because a supplier has a long-term 

contract provides access to a terminal to import LNG does not mean they are necessarily 

committed to using that terminal if the economic value of the cargo is higher elsewhere. 

For example, in January, long-term contract holder BP diverted a cargo that originated in 

Trinidad to Japan. The cargo was initially destined for Cove Point but went to Japan 

because of a rumored $13/MMBtu price from Kendai Electric – higher than prices available 

in the United States. Because of the mild weather and relatively lower prices in January that 

Steve just discussed, receipts of LNG in the United States reached their lowest monthly 

level since April 2003.

Nearly 70 percent of the LNG imports into the United States in 2005 were under DOE’s

short-term blanket authorization. For the last three months of 2005 – the period when the 

DOE began tracking spot deliveries – 27 percent of U.S. LNG imports were spot deliveries.
13

U.S. LNG Terminals U.S. LNG Terminals

Approved by FERC Approved by FERC-2005

1 3 2

1.Corpus Christi, TX 2.6 

Bcfd (Cheniere LNG)

2.Corpus Christi, TX 1.0 

Bcfd (Vista Del Sol -

ExxonMobile

3.Sabine, TX 1.0 Bcfd

(Golden Pass – ExxonMobile)

4.Fall River, MA 0.8 Bcfd

(Weaver’s Cove Energy/Hess 

LNG

5.Corpus Christi, TX

1.0 Bcfd (Ingleside Energy –

Occidental Energy Ventures)

Source:

FERC 

In 2005, the Commission authorized five LNG regasification terminals with a combined 6.4 

Bcf per day of deliverability. Four of these terminals would be located in the State of 

Texas. Construction on 9.2 Bcf per day of deliverability is currently occurring at five sites 

– the first three sites listed on this slide as well as the Cameron LNG site in Louisiana and 

the Freeport site in Texas. On February 1st, service commenced at the expanded facilities at 

the existing Elba Island facility in Georgia. Besides substantially increasing its storage 

capacity, Elba Island’s maximum sendout capability nearly doubled to over 1.2 Bcf per day. 

Elba Island’s latest expansion proposal, which will increase its deliverability by another 1 

Bcf per day is now in the prefiling phase at the commission. To compliment this increase in 

LNG receiving capacity, the Commission has been taking actions on other gas projects 

necessary to support downstream delivery of the additional gas supply. In 2005, the 

Commission approved 20 major pipeline projects totaling 870 miles of pipe with an 

associated capacity of about 12.3 Bcf per day. 7.5 Bcf per day of this capacity is linked to 

facilities to take regasified LNG away from the approved terminals. The Commission also 

approved nine storage projects in 2005 with a total storage capacity of about 110 Bcf and 

daily deliverability of 3.2 Bcf. Four of those projects were in the gulf area, ostensibly to 

store regasified LNG. These four projects accounted for over half of the approved capacity 

and two-thirds of the daily deliverability. That concludes our presentation. Steve and I 

would be happy to answer any questions you may have.