Overview:  Thursday, June 10 (next release 2:00 p.m. on June 17)

Since Wednesday, June 2, natural gas spot prices have decreased at virtually all market locations in the Lower 48 States.  For the week (Wednesday-Wednesday), prices at the Henry Hub decreased 46 cents or about 7 percent to $6.05 per MMBtu.  Yesterday (June 9), the price of the NYMEX futures contract for July delivery at the Henry Hub settled at $6.082 per MMBtu, decreasing roughly 44 cents or nearly 7 percent since last Wednesday.  Natural gas in storage was 1,666 Bcf as of June 4, which is 0.2 percent below the 5-year average.  The spot price for West Texas Intermediate (WTI) crude oil fell $2.36 per barrel or nearly 6 percent on the week to $37.60 per barrel or $6.48 per MMBtu.

 

 

Prices:

Widespread moderate temperatures and falling crude oil prices contributed to price declines of 31 to 87 cents per MMBtu at virtually all market locations in the Lower 48 States since last Wednesday, June 2.  The steepest declines occurred principally west of the Rockies, where prices fell more than 70 cents per MMBtu at most markets, with the largest declines in California.  The lack of temperature-driven demand also caused operational difficulties, with a number of pipelines in the West issuing either high inventory OFOs or critical notices in response to high linepack on their systems.  East of the Rockies, price decreases were widespread with declines ranging between 40 and 60 cents per MMBtu at most markets.  These declines were more pronounced in the central regions of the Lower 48 States with declines averaging between 50 and 60 cents per MMBtu in the Midcontinent, Midwest, and Texas regions.  In Louisiana and east of the Mississippi, prices fell less than 50 cents.  With these widespread declines, prices have fallen below last year’s levels by as much as 39 cents per MMBtu.  For example, prices at the southern California border are 39 cents or nearly 7 percent below last year’s level, while prices at the Henry Hubare 20 cents or 3 percent below last year’s level.

 

 

At the NYMEX, the price of the futures contract for July delivery at the Henry Hub decreased about 44 cents per MMBtu or nearly 7 percent since last Wednesday to $6.082 per MMBtu.  The prices of the futures contracts for delivery in each of the following 6 months fell about 33 to 42 cents or about 5 to 6 percent from last Wednesday’s level.  With the spot price declining at a faster rate than futures price, the differentials between the spot price and the futures price increased over last week’s level.  The prices of the futures contracts for each month through the remaining months of 2004 exceed the Henry Hub spot price by 3 to 57 cents per MMBtu.  January and February 2005 contracts traded at 70 and 65 cents, respectively, above the spot price yesterday (June 9).  With the futures strip through next winter now trading at a significant premium to the Henry Hub spot price, suppliers have increased economic incentives to inject gas into storage.

 

Recent Natural Gas Market Data

 

Estimated Average Wellhead Prices
	Nov-03	Dec-03	Jan-04	Feb-04	Mar-04	Apr-04
Price ($ per Mcf)	4.34	5.08	5.53	5.15	4.97	5.20
Price ($ per MMBtu)	4.22	4.94	5.38	5.01	4.83	5.06
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 1,027 Btu per cubic foot as published in Table A4 of the Annual Energy Review 2002.
Source:  Energy Information Administration, Office of Oil and Gas.

 

Storage:

Working gas in storage was 1,666 Bcf as of Friday, June 4, 2004, according to the EIA Weekly Natural Gas Storage Report (See Storage Figure). This is about 0.2 percent below the 5-year average for the report week.  The implied net injection during the report week was 102 Bcf, marking the first time during the current injection season that the implied net change exceeded 100 Bcf.  At 102 Bcf, net injections were about 6 percent above the 5-year average net addition of 96 Bcf for the week and about 18 percent below the injection of 125 Bcf reported for the same week last year.  Moderating temperatures during the week ended June 5 likely contributed to the higher-than-average rate of injections as temperatures in most regions of the Lower 48 States were cooler than normal. (See Temperature Map) (See Deviations Map) 

 

 

Other Market Trends:

Long-Term Decline in Alberta’s Gas Production and Exports: The Alberta Energy and Utilities Board (EUB) released a report on June 3, 2004, stating that natural gas production fell by 2.5 percent in 2003, which marks a decline for the second year in a row. Despite a 46 percent increase in drilling (12,000 successful drills in 2003 compared with 8,210 drills in 2002), the declining production trend is expected to continue through the end of the forecast period in 2013. One of the reasons for the decline in production cited by the EUB is that the new pools are smaller and are exhibiting lower initial production rates, as well as steeper decline rates. As the demand for natural gas increases in Alberta and production declines, the volume available for export will decline. The Gas Resources Preservation Act prescribes that Alberta’s core consumption requirements need to be met over the long-term before exports will be permitted. The EUB issues export permits only for gas considered to be surplus to the needs of core customers for 15 years. It is estimated that Alberta’s demand will amount to 46 percent of production in 2013. At the end of 2003, Alberta’s remaining established reserves of natural gas stood at 40 Tcf after 4.8 Tcf was produced during the year. This reserves figure included an estimated 34 Bcf of coalbed methane (CBM) reserves. CBM production is expected to grow in the coming years, reflecting its potential as an alternative source to conventional gas. Alberta is the largest source of U.S. natural gas imports.

 

Natural Gas Summary from the Short-Term Energy Outlook:

EIA projects that natural gas prices will continue at high levels through the rest of 2004 (Short-Term Energy Outlook, June 2004). Wellhead prices are expected to average $5.74 per MMBtu in the summer months (June–August) and $6.00 per MMBtu in the fourth quarter, while composite spot prices will likely stay well above $6.00 through December. Spot prices averaged about $5.35 per MMBtu in the first quarter of the year but have been above $6.00 since the beginning of May, as strong demand for natural gas coupled with high petroleum prices has led to higher gas prices despite nearly normal storage inventory levels. Storage stocks at the end of May were less than 1 percent below the 5-year average and 23 percent higher than last year at this time. Overall in 2004, spot prices will likely average about $6.05 per MMBtu, which is 13 percent higher than the 2003 average. In 2005, prices are expected to decrease only slightly as production gains are expected to be relatively low.

Natural gas production is estimated to have increased by approximately 0.6 percent in 2003.  Growth of about 0.9 percent in 2004 is expected as new natural gas well completions, which totaled an estimated 20,000 in 2003, remain high at more than 24,000 wells per year for the next 2 years. Because of apparently high decline rates from existing wells, these high drilling rates are not expected to yield more than modest net gains in U.S. production. Natural gas demand is expected to increase by about 1.4 percent in 2004, owing to increasing economic growth, the lack of fuel-switching options given the high cost of oil, and the continuing rise in electricity demand. Demand growth in 2005 is expected to be minimal (0.2 percent) as some of the current pressure on natural gas in the electric power sector eases and relative coal and fuel oil spot prices decline somewhat.

 

Short-Term Natural Gas Market Outlook, June 2004
	History			Projections
	Mar-04	Apr-04	May-04	Jun-04	Jul-04	Aug-04
PRICES ($/MMBtu)
Average Wellhead Price	4.84	5.06	5.21	5.48	5.76	5.92
Residential Price	9.07	9.88	10.71	11.79	12.43	12.83
Electric Utilities Price	5.14	5.51	5.69	5.98	6.17	6.28
SUPPLY (Trillion Cubic Feet)
Total Dry Gas Production	1.634	1.568	1.619	1.564	1.624	1.628
Net Imports	0.250	0.237	0.259	0.248	0.264	0.265
Imports	0.315	0.313	0.317	0.304	0.323	0.327
Exports	0.065	0.057	0.057	0.056	0.060	0.062
Suppl. Gaseous Fuels	0.005	0.004	0.005	0.005	0.006	0.006
Total New Supply	1.889	1.809	1.883	1.817	1.894	1.898
Working Gas in Storage
Opening	1.163	1.028	1.227	1.601	1.993	2.305
Closing	1.028	1.227	1.601	1.993	2.305	2.602
Net Storage Withdrawal	0.135	-0.199	-0.374	-0.392	-0.312	-0.297
Total Supply	2.024	1.610	1.509	1.425	1.582	1.601
Balancing Item	0.116	0.148	0.052	0.009	0.012	-0.005
Total Primary Supply	2.140	1.758	1.561	1.434	1.593	1.596
DEMAND (Trillion Cubic Feet)
Lease & Plant Fuel	0.096	0.092	0.095	0.093	0.096	0.096
Pipeline Use	0.063	0.051	0.047	0.045	0.047	0.047
Delivered to Consumers	1.981	1.615	1.419	1.297	1.450	1.452
Residential	0.608	0.400	0.236	0.155	0.126	0.117
Commercial	0.357	0.246	0.180	0.142	0.138	0.134
Industrial	0.661	0.609	0.550	0.506	0.553	0.564
Electric Power	0.355	0.359	0.454	0.494	0.634	0.638
Total Demand	2.140	1.758	1.561	1.434	1.593	1.596

 

Source:  Energy Information Administration, Short-Term Energy Outlook, June 2004.