Overview:  Thursday, May 15, 2003 (next release 2:00 p.m. on May 22)

Compared with Wednesday, May 7, natural gas spot prices were higher at all locations in the Lower 48 States in trading on May 14.  For the week (Wednesday-Wednesday), prices at the Henry Hub increased 69 cents or roughly 12 percent to $6.16 per MMBtu. The price of the NYMEX futures contract for June delivery at the Henry Hub increased roughly 65 cents per MMBtu or 11 percent since last Wednesday to settle at $6.314 per MMBtu yesterday (May 14).  Natural gas in storage increased to 900 Bcf as of Friday, May 9, which is about 38 percent below the 5-year average.  The spot price for West Texas Intermediate (WTI) crude oil increased $2.97 per barrel or roughly 11 percent since last Wednesday to trade yesterday at $29.21 per barrel or $5.036 per MMBtu.

 

 

 

Prices:

Prices have increased at all market locations since last Wednesday, May 7, as prices climbed more than 40 cents per MMBtu at nearly all market locations.  Contributing factors to the surge in prices likely include cool temperatures in the Northeast driving heating demand, warm temperatures in the Southeast driving cooling demand, continuing concerns about working gas storage levels, rising crude oil prices, and nuclear power outages in Texas, Ohio, and Florida, where natural gas is a principal alternative fuel for electric generation.  Significant price gains were reported in the Northeast, Louisiana, Texas, and Alabama regions where prices climbed from 60 to 70 cents per MMBtu.  These increases returned prices to the relatively high levels that were prevalent late in the heating season this year.  For example, prices at the Henry Hub averaged $6.17 per MMBtu on Wednesday, May 14, which is the highest price since March 11, 2003.  Meanwhile, the largest gains since last Wednesday occurred in the Rocky Mountains, where prices surged more than 70 cents per MMBtu  The largest weekly increase of 96 cents per MMBtu occurred at the Questar market location, which serves parts of Colorado and Utah.  Despite these robust increases, prices in the Rocky Mountains region remain below $5.00 at nearly all market locations.  However, prices remain significantly higher than last year at this time at all market locations, exceeding last year’s level by 53 percent on average with prices at the Henry Hub nearly 65 percent greater than last year at this time.

 

Spot Prices ($ per MMBtu)	Thur.	Fri.	Mon.	Tues.	Wed.
	8-May	9-May	12-May	13-May	14-May
Henry Hub	5.66	5.74	5.90	5.98	6.17
New York	6.11	6.12	6.33	6.44	6.56
Chicago	5.66	5.72	5.97	6.03	6.22
Cal. Comp. Avg,*	5.12	5.16	5.28	5.34	5.53
Futures ($/MMBtu)
Jun delivery	5.772	5.806	5.983	6.308	6.314
Jul delivery	5.845	5.879	6.055	6.398	6.394
*Avg. of NGI's reported avg. prices for:  Malin, PG&E citygate,
and Southern California Border Avg.
Source: NGI's Daily Gas Price Index (http://intelligencepress.com).

 

At the NYMEX, the price of the futures contract for June delivery at the Henry Hub climbed by about 65 cents per MMBtu since Wednesday, May 7, to settle at $6.314 per MMBtu on Wednesday, May 14.  This is the highest that the June contract has been since February 24.  The basis differential between the Henry Hub spot price and the futures contracts for delivery in each month through January 2004 exhibits a pattern of increase for each successive month, up to almost 44 cents.  This price pattern provides suppliers strong incentives to inject gas into storage.  However, the basis differential for each of these contracts has narrowed since last week.  This likely indicates that natural gas demand for heating and cooling is competing for tight natural gas supplies with the demand to inject gas into storage. 

 

Estimated Average Wellhead Prices
	Nov-02	Dec-02	Jan-03	Feb-03	Mar-03	Apr-03
Price ($ per Mcf)	3.59	3.84	4.47	5.45	6.69	4.71
Price ($ per MMBtu)	3.50	3.74	4.36	5.31	6.53	4.59
Note:  The price data in this table are a pre-release of the average wellhead price that will be published in forthcoming issues of the Natural Gas Monthly.  Prices were converted from $ per Mcf to $ per MMBtu using an average heat content of 1,025 Btu per cubic foot as published in Table A2 of the Annual Energy Review 2001.
Source:  Energy Information Administration, Office of Oil and Gas.

                                                           

Storage:

Working gas in storage was 900 Bcf as of Friday, May 9, 2003, according to the EIA Weekly Natural Gas Storage Report.  This is nearly 38 percent below the 5-year average for the report week, and over 47 percent below the level last year for the same week (See Storage Figure).    Working gas in storage was revised upwards by 7 Bcf for the week ended May 2, 2003.  The implied net injection in working gas inventories during the week of May 9 was 72 Bcf, which is roughly 4 percent lower than the 5-year average injection of 75 Bcf for the report week.  Net injections in the East region were 53 Bcf, which is 8 percent greater than the 5-year average.  In contrast, net injections were 1 Bcf or 14 percent below the 5-year average in the Producing region and 6 Bcf or 33 percent below average in the West.  Weather-related demand likely reduced the level of injections during the week.  Cooler than normal temperatures prevailed in Middle Atlantic and New England regions, contributing to lingering heating demand for natural gas (See Temperature Map) (See Deviation Map).  Meanwhile, warmer-than-normal temperatures in the Pacific and South Atlantic regions likely spurred cooling demand for natural gas.  Despite the significant consumption demand for natural gas, the year-on-year storage deficit declined last week, falling 10 Bcf to 807 Bcf.  

        

All Volumes in Bcf	Current Stocks 5/9/03	Estimated Prior 5-Year (1998-2002) Average	Percent Difference from 5 Year Average	Implied Net Change from Last Week	One-Week Prior Stocks 5/2/03
East Region	438	736	-40.5%	53	385*
West Region	198	207	-4.3%	6	192
Producing Region	264	499	-47.1%	13	251
Total Lower 48	900	1,442	-37.6%	72	828*
Source:  Energy Information Administration:  Form EIA-912, "Weekly Underground Natural Gas Storage Report," and the Historical Weekly Storage Estimates Database.  Row and column sums may not equal totals due to independent rounding.  * Revised

 

Other Industry/Market Trends:

U.S. LNG Developments: Several recent international developments concerning liquefied natural gas (LNG) projects underscored the momentum to bring more LNG to the U.S. natural gas market. Atlantic LNG, based in Trinidad and Tobago, said it expects to ship its first LNG cargo from its new Train 3 as soon as the middle of May after production began recently. Construction for the Atlantic LNG expansion, which included the additions of two trains, started in 2000 and cost a total of $1 billion. The Train 2 expansion was completed in August 2002. Each train adds production capacity of approximately 3.3 million metric tones per year (mmtpa), or about 159 Bcf. About 37.5 percent of the combined capacity of the two trains is dedicated to U.S. markets and will be delivered chiefly to the Elba Island, Georgia, terminal and Lake Charles, Louisiana, terminal, according to Atlantic LNG. The remaining 62.5 percent of the production capacity is targeted for markets in Spain. BG Group this week announced plans to ship LNG from an expansion at Nigeria LNG and a new production facility to be based in Equatorial Guinea. BG has signed an agreement with Nigeria LNG for about 2.5 mmtpa (120 Bcf) for 20 years from the addition of two trains at Nigeria LNG, which will be available in late 2005 or early 2006. Through an agreement with Marathon Oil, the operator of the Equatorial Guinea-based liquefaction plant, BG Group would purchase 3.4 mmtpa (163 Bcf) for a period of 17 years beginning in 2007, when the Equatorial Guinea LNG project is expected to begin operation. BG Group, which said it intends to transport much of the LNG to U.S. markets, has an 80-percent share of the rights to the Lake Charles terminal until 2005, after which it has a 100-percent share until 2024.

Natural Gas Summary from the Short-Term Energy Outlook: In the May 2003 Short-Term Energy Outlook, EIA projected that natural gas wellhead prices will remain high relative to historical levels.  In February and March 2003, natural gas wellhead prices were more than double last year’s levels.  Despite considerable declines posted in April 2003, wellhead prices are expected to remain between 42 and 73 percent above last year’s level through each of the remaining months of the refill season.  This will push the average wellhead price to roughly $5.00 per MMBtu in 2003, an increase of about 60 percent over 2002.  This projection is based in part on the expectation of lower volumes of underground gas in storage for 2003 compared with 2002.  Levels of natural gas in underground storage remain low one month into the injection season.  At the end of April, working gas in storage was roughly 789 Bcf, which is about 52 percent below end-of-April 2002 levels and 41 percent below the previous 5-year average.  The exceptionally large shortfall in natural gas storage relative to normal levels continues to place unusually strong upward pressure on near-term gas prices because companies need to obtain large amounts of natural gas to refill storage for the next heating season, which will compete with other uses.  Moreover, if abnormally warm weather prevails this summer, the market demand may surge, particularly in the Western and South Central United States, where natural gas is heavily used for power generation.  Such conditions could cause a mid-year spike in prices to above $6 per MMBtu.

With high natural gas prices, natural gas demand is expected to fall by nearly 1 percent in 2003.   Negative growth this year is likely despite sharply higher weather-related demand during the first quarter of 2003.  Demand for natural gas this summer is expected to fall by 9.2 percent from last summer’s level.  This is largely due to summer weather effects (in the power sector).  Assuming normal weather, cooling degree-days for the refill season will be close to 10 percent below year-ago levels. Demand for natural gas to refill working gas storage in 2003 will be larger than average, which means that price volatility can be expected to continue in these tight market conditions.  Natural gas demand in 2004 is expected to rise as industrial demand recovers from its 2002-2003 lows. 

Dry gas production is expected to increase by 1.4 percent in 2003.  High natural gas prices and sharply higher oil and natural gas field revenues are expected to drive a resurgence in natural gas directed drilling activity this year following a downturn in 2002.  Domestic production growth should continue in 2004 but, given recent experience, the additional drilling might result in increases of less than 2 percent. The prospects for significant reductions in natural gas wellhead prices over the forecast period from the current high levels could hinge on the productivity of the expected upsurge in drilling in terms of expected output. 

 

Short-Term Natural Gas Market Outlook, May 2003
	History			Projections
	Feb-03	Mar-03	Apr-03	May-03	Jun-03	Jul-03
PRICES ($/MMBtu)
Average Wellhead Price	5.31	6.51	4.59	4.18	4.67	4.74
Residential Price	8.18	8.74	9.86	10.25	10.79	11.21
Electric Utilities Price	5.60	6.89	6.89	5.57	6.02	5.89
SUPPLY (Trillion Cubic Feet)
Total Dry Gas Prod	1.48	1.66	1.59	1.64	1.59	1.63
Net Imports	0.30	0.32	0.33	0.33	0.32	0.33
Imports	0.34	0.36	0.36	0.37	0.36	0.38
Exports	0.03	0.04	0.03	0.04	0.04	0.05
Suppl. Gaseous Fuels	0.01	0.01	0.01	0.01	0.00	0.01
Total New Supply	1.790	1.980	1.923	1.979	1.911	1.969
Working Gas in Storage
Opening	1.521	0.838	0.696	0.789	1.129	1.484
Closing	0.838	0.696	0.789	1.129	1.484	1.907
Net Storage Withdrawal	0.683	0.142	-0.093	-0.340	-0.355	-0.423
Total Supply	2.473	2.122	1.830	1.639	1.555	1.547
Balancing Item	-0.058	0.134	0.040	0.034	-0.033	0.016
Total Primary Supply	2.415	2.256	1.870	1.673	1.523	1.562
DEMAND (Trillion Cubic Feet)
Lease & Plant Fuel	0.091	0.104	0.102	0.106	0.102	0.105
Pipeline Use	0.053	0.049	0.040	0.032	0.030	0.033
Delivered to Consumers	2.271	2.102	1.728	1.534	1.390	1.425
Residential	0.824	0.638	0.389	0.239	0.147	0.115
Commercial	0.433	0.363	0.256	0.182	0.141	0.136
Industrial	0.690	0.708	0.669	0.638	0.580	0.542
Electric Power	0.324	0.394	0.414	0.475	0.523	0.632
Total Demand	2.415	2.256	1.870	1.673	1.523	1.562

Source: Energy Information Administration, Short-Term Energy Outlook, May 2003.