Natural Gas

Overview: Thursday, December 7 (next release 2:00 p.m. on December 14, 2006)

Since Wednesday, November 29, natural gas spot prices decreased more than 25 cents per MMBtu at most market locations in the Lower 48 States although some markets posted price hikes. On Wednesday, December 6, prices at the Henry Hub averaged $7.34 per MMBtu, a decline of 41 cents per MMBtu, or about 5 percent, since the previous Wednesday. The NYMEX futures contract for January delivery at the Henry Hub settled at $7.72 per MMBtu on Wednesday, December 6, falling about $1.14 per MMBtu, or 13 percent, from the settlement price of $8.871 recorded last Wednesday, November 29.Natural gas in storage was 3,406 Bcf as of December 1, which is 9 percent above the 5-year average. The spot price for West Texas Intermediate (WTI) crude oil decreased 25 cents per barrel, or less than 1 percent, on the week (Wednesday-Wednesday) to $62.20 per barrel or $10.72 per MMBtu.

 Prices:

Spot prices decreased at most market locations since last Wednesday, November 29, generally by more than 25 cents per MMBtu, although some markets, principally located in the Northeast region, experienced price hikes. Intraweek trading was characterized by considerable variability as prices recorded significant gains in trading on Thursday, November 30, and Friday, December 1, as cold temperatures contributed to increased heating demand for natural gas. These gains were followed by moderating temperatures and widespread price declines, which more than offset the preceding rally. For the week, the largest price declines occurred principally in the western third of the Lower 48 States where prices fell by more than 50 cents per MMBtu at most market locations with declines averaging 66 cents per MMBtu in California, 98 cents per MMBtu in the Rocky Mountains region, and $1.36 per MMBtu in the Midcontinent region. Elsewhere, price decreases ranged between 25 and 50 cents per MMBtu at most market locations. In the Northeast region, prices fell less than a penny on average, despite posting gains at a majority of market locations in the region. Northeastern markets that recorded price gains included the New York and the Algonquin citygates, where prices increased 13 cents per MMBtu and 15 cents per MMBtu, respectively. Prices remain significantly below levels reported last year at this time, with prices at the Henry Hub $6.46 per MMBtu or nearly 47 percent below last year's level.

 At the NYMEX, prices for the futures contracts for the next 12 months decreased across the board with the 12-month futures strip (January 2007 through December 2007) falling about 65 cents per MMBtu, or about 8 percent, since last Wednesday, November 29. The largest decreases on the 12-month futures strip occurred for contracts for delivery during the remaining heating-season months (January 2007 through March 2007), as prices decreased by about 12 percent on average since last Wednesday, November 29. Averaging $7.77 per MMBtu, the futures contract prices for delivery during the heating season traded at an average premium of about $0.43 per MMBtu to the Henry Hub spot price.Overall, the 12-month futures strip (January 2007 through December 2007) traded at a premium of $0.66 per MMBtu relative to the Henry Hub spot price, averaging $7.996 per MMBtu as of Wednesday, December 6. While futures contracts continue to trade at significant premiums to the Henry Hub spot price, the gap between the futures and the Henry Hub spot prices has narrowed since Wednesday, November 29, with the 3-month strip (January 2007 through March 2007) falling 65 cents. This decline suggests that incentives for suppliers to hold natural gas in storage have decreased somewhat, and larger withdrawals from storage may be expected.

 Recent Natural Gas Market Data

 Storage:

Working gas in storage totaled 3,406 Bcf as of Friday, December 1, which is about 9 percent above the 5-year average inventory level for the report week, according to EIA's Weekly Natural Gas Storage Report (See Storage Figure). As of December 1, stocks exceeded last year's level by 232 Bcf and the 5-year average by 282 Bcf. For the week, the implied net withdrawal of 11 Bcf contrasts with the 5-year average withdrawal of 63 Bcf and last year's injection of 58 Bcf. Warmer-than-normal temperatures that prevailed during the report week in large sections of the country likely contributed to the below-normal withdrawals from working gas stocks as the moderate temperatures would have mitigated heating demand for natural gas. During the report week, heating degree-days in the Lower 48 States were about 28 percent below normal levels.Heating degree-days fell 24 to 55 percent below normal levels in seven of the nine Census divisions. Only the Pacific and Mountain Census divisions had above-normal heating demand with heating degree-days exceeding normal levels by 29 and 8 percent, respectively. (See Temperature Maps)

 Other Market Trends:

EIA Releases Report on Crude Oil, Natural Gas, and Natural Gas Liquids Reserves: The Energy Information Administration (EIA) on December 5, 2006, published the U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report, which presents estimates of proved reserves of crude oil, natural gas, and natural gas liquids as of December 31, 2005, as well as production volumes for the United States by producing States and State subdivisions during 2005. The report also highlights petroleum industry activities that affected oil and natural gas production and proved reserves in 2005. According to the report, proved reserves of dry natural gas in 2005 were 206,385 Bcf, which was 6.2 percent higher than the 2004 estimate of 192,513 Bcf. The 6.2-percent increase was the largest annual increase in natural gas proved reserves since 1970. Reserves additions replaced 164 percent of 2005 dry natural gas production as U.S. natural gas reserves increased for the seventh year in a row. Natural gas reserves additions in the onshore Lower 48 States were large enough to offset a 10 percent decrease in natural gas reserves reported for the Gulf of Mexico Federal Offshore. The majority of natural gas reserves additions in 2005 resulted from extensions of existing gas fields rather than new field or reservoir discoveries. Field extensions were 21,050 Bcf, 16 percent more than in 2004 and 74 percent more than the prior 10-year average (12,101 Bcf). Coalbed methane reserves increased by 8 percent in 2005 and accounted for 10 percent of U.S. dry natural gas reserves. Furthermore, exploratory and developmental natural gas completions increased 27 percent over the 2004 level.

Natural Gas Transportation Update:

• Florida Gas Transmission Company implemented an overage alert day (OAD) for market-area customers on Monday December 4, because of freezing temperatures.The tolerance for negative daily imbalances was set at 25 percent.
• Southern Natural Gas Company announced to their natural gas shippers and poolers that it will most likely implement a type 6 operational flow order (OFO) starting December 7. The pipeline further stated that the OFO may last until Sunday, December 9 and that it can be implemented on a 4-hour notice or less.In addition, owing to system conditions, the pipeline will not be able to accept increases in nominations for interruptible services (ISS) that rely on storage during the evening scheduling cycle for gas day Thursday, December 7. The ISS services affected are ISS withdrawals, withdrawals from contract storage service (firm storage) in excess of firm withdrawal entitlements, and park withdrawals or loans under the park-and-loan service agreement.
• Effective Thursday, December 7, Mississippi River Transmission Corporation (MRT) is implementing a system protection warning (SPW) owing to the cold weather, which will affect MRT deliveries on its main line north of Glendale, Arkansas.Furthermore, firm volumes will be limited to their primary direction of flow. In order to avoid OFOs, shippers who were relying on main line volumes are encouraged to resource supply to MRT's East Line or reduce applicable delivery volumes.
• Colorado Interstate Gas Company announced on December 6 that the Cheyenne Compressor Stations unit that had experienced a major mechanical failure is back in full service. The loss of this unit resulted in a capacity reduction through the station (CYC) of approximately 80 MMcf per day.
• On December 4, 2006, Northwest Pipeline Corporation announced that volumes through the Kemmerer compressor station were scheduled at approximately 700,000 decatherms (Dth), which was above the capacity limit. Northwest is requesting assistance from its customers to voluntarily reduce nominations so that scheduled volumes do not exceed 653,000 Dth per day northbound through the Kemmerer compressor station. In order to avoid an OFO, Northwest will use its limited storage flexibility at Jackson Prairie and Clay Basin to offset possible OFOs at the Kemmerer station by withdrawing gas from Jackson Prairie and injecting gas into Clay Basin. Storage flexibility will only be used to offset OFOs as long as Northwest's Jackson Prairie firm balancing account exceeds 1.2 million Dth.

Short-Term Energy Outlook