US natural gas in storage was declined by 23 Bcf to 3,814 Bcf as of Friday, November 26, 2010, according to Energy Information Administration (“EIA”) report today. This puts inventory at 23 Bcf less then the same time last year, and 347 Bcf above the 5-year average. Analysts polled expected a draw down of 26 Bcf to 30 Bcf.
Jay Levine of Energjay LLC said that the government report should spark movement in the price Thursday but the effect will be limited until a long-term withdrawal trend is established. Levine is quoted in the Wall Street Journal;
“Any report, including today’s, is generally only good for a knee-jerk reaction since the market will very likely go on its merry way as if the report didn’t even exist.”
The following is the text of the weekly natural gas update as released by the U.S. Department of Energy in Washington D.C.:
Following the Thanksgiving Day holiday weekend, prices moved up significantly this week as wintry weather moved into much of the country. The most severe weather to date this season is increasing space-heating demand from nearly coast to coast and as far south as Florida. During the report week (November 24- December 1), the Henry Hub spot price increased $0.39 to $4.21 per million Btu (MMBtu).
At the New York Mercantile Exchange (NYMEX), futures prices decreased during the report week in response to indications of warmer weather in the outlook and amid reports of growth in supply. The futures contract for January 2011 delivery decreased by $0.12 per MMBtu on the week to $4.27 per MMBtu.
On the Wednesday before Thanksgiving, the December 2010 contract expired at $4.27 per MMBtu, having increased nearly 40 cents, or 10.2 percent, since its first day of trading as the near-month contract.
As of Friday, November 26, working gas in underground storage was 3,814 billion cubic feet (Bcf), which is 10.0 percent above the 5-year (2005-2009) average.
As a strong cold-weather mass entered much of the lower 48 States this report week (November 24-December 1), natural gas demand for space heating increased significantly. Compared with the prior week, U.S. natural gas demand increased about 8 percent to as high as 87 Bcf, according to BENTEK Energy, LLC. Combined demand in the residential and commercial sectors increased 21 percent from the end of the prior report week to 44 Bcf for on Wednesday, December 1. This higher demand led to widespread increases in prices that generally ranged between 5 and 15 percent east of the Mississippi River, but were considerably less in the West. The Henry Hub price increased on the week by $0.39 per MMBtu, or 10.2 percent, while prices at other markets in the Gulf of Mexico Producing region showed similar increases, albeit slightly lower. With wintry weather reaching as far south as Florida, the interstate natural gas pipeline serving the State yesterday alerted shippers of the need to balance supplies in order to meet higher demand (See Transportation Notes below). The spot price there finished trading yesterday at $4.84 per MMBtu, increasing 30 cents from the previous day. This early cold spell has resulted in a strengthening in prices from earlier in the fall. For example, the Henry Hub price yesterday was 79 cents per MMBtu, or 23 percent, higher than the price a month prior. Nonetheless, prices are still roughly the same or slightly below their levels this time last year. On December 1, 2009, the Henry Hub price was $4.30 per MMBtu, or about 2.1 percent above yesterday’s average of $4.21.
Price increases in the Northeast were among the highest in the country, with prices at a number of markets in the region ending the report week above $5 per MMBtu. Nonetheless, several market centers in the Northeast region posted declines of close to $0.50 per MMBtu, or more than 10 percent on the week. The uneven pattern in pricing has occurred throughout the last month as pipeline enhancements and new supply sources to the region have resulted in changing pricing dynamics between market centers. For delivery in Zone 6 (New York) off Transcontinental Gas Pipe Line, the price yesterday (December 1) averaged $5.00 per MMBtu, which was $0.71 more than the price the previous Wednesday. In trading yesterday, the Transco Zone 6 price was $0.79 per MMBtu higher than the Henry Hub, a significant increase from the prior week’s average differential of $0.42 per MMBtu. The closely- watched difference in the Northeast price over Gulf of Mexico regional prices tends to fluctuate severely during the winter. Interstate pipelines have limited flexibility to transport non- firm supplies between the two markets because of colder weather and the associated increase in space-heating demand in the Northeast, causing differences in local supply and demand conditions to develop. However, it is expected that the price differential between the regions will be minimized this winter following pipeline enhancements and new supply growth in the Northeast region. The price for deliveries to Transco Zone 6 in January 2011, for example, is currently at about $2.36 per MMBtu over the Henry Hub price in trading on the Intercontinental Exchange, while last year at this time the premium was about $3.80.
Further to the west, week-to-week price increases were significantly lower, and decreases were reported at several markets in the Rockies and California, as the coldest weather from the current cold front moved out of the region. At Rockies trading locations, price increases were generally less than 5 percent. The price for supplies on Kern River Pipeline in Utah (for delivery into California) increased just $0.11 to $4.01 per MMBtu. Yesterday’s price of $3.96 per MMBtu for natural gas off of Colorado Interstate Pipeline Company (the lowest price in the country) represented an increase of $0.06 per MMBtu on the week.
U.S. pipeline imports from Canada were significantly higher during the report week in comparison with the prior week, likely resulting from increased withdrawals from storage in Canada to meet heating demand in the United States. According to BENTEK, which monitors flows on the continental pipeline network, U.S imports from Canada during the report week increased 15 percent relative to the prior week to 7.0 Bcf per day. However, liquefied natural gas (LNG) imports (as measured by sendout from regasification terminals) averaged just 0.5 Bcf per day during this report week, which was over 21.1 percent lower than the prior week. Both Canadian and LNG imports have been significantly lower than the prior year, likely as a result of continuing supply strength from domestic drilling, particularly in shale formations in the lower 48 States. Pipeline and LNG imports during the report week were, respectively, 2.2 percent and 44.4 percent lower than last year at this time.
At the NYMEX, the price of the near-month contract (for January 2011 delivery) decreased $0.12 during the report week to $4.269 per MMBtu. With the weather outlook for much of the country indicating moderate temperatures will likely return at least temporarily, the price of the January contract decreased in three of four trading sessions during the report week (there was no trading on Thursday, November 25, owing to the Thanksgiving Day holiday). The January 2011 contract is now priced about $1.55 per MMBtu lower than the final expiration price of $5.81 for the January 2010 contract. Downward price pressure also appears related to recent increases in natural gas supplies, as described by the Energy Information Administration (EIA) in a report released this week (See Other Market Trends below). At the end of trading yesterday, the 12-month strip, which is the average for natural gas futures contracts over the next year, was priced at $4.41 per MMBtu, a decrease of about $0.10 per MMBtu, or less than 2.2 percent, since last Wednesday.
The price of the December 2010 contract increased significantly with the arrival of colder weather in the final two weeks of trading as the near-month contract. Before its final settlement at $4.27 per MMBtu on Wednesday, November 24, the contract increased in five of the prior eight trading sessions for a net increase of 47 cents. This is 98 cents per MMBtu higher or 30 percent more than the expiration price of the November 2010 contract. It is also the highest final price for a NYMEX futures contract since the expiration of the August contract at $4.77 per MMBtu on July 28, 2010. Nonetheless, the December 2010 contract’s final price was 22 cents per MMBtu less than the expiration price of $4.49 for the December 2009 contract and $2.62 less than the expiration price of $6.89 for the December 2008 contract.
Working natural gas in storage fell to 3,814 Bcf as of Friday, November 26, according to EIA Weekly Natural Gas Storage Report. The net draw of 23 Bcf is less than the 5-year average draw of 36 Bcf for the report week, but it stands in stark contrast to last year’s late build of 2 Bcf. The Producing region storage levels are now 45 Bcf above last year’s level, while the East region is 40 Bcf below last year’s level. Working gas stocks in the West region are 28 Bcf below last year.
Typically the East region sees the largest draws when the weather turns cold. This is the result of the East having higher storage levels and more heating consumption during the winter. The trend did not hold this week due to weather impacts, with the West being abnormally cold. The West drew more than the East, and the Producing region actually saw a significant build despite a draw for the lower 48 States as a whole.
Temperatures were slightly above average in the lower 48 States during the week ending November 25, but regions saw major variations.*The National Weather Service’s degree-day data show that the average temperature in the lower 48 States last week averaged 45.3 degrees, 1.7 degrees above normal, but 3.0 degrees below last year. The Pacific and Mountain regions were 7.0 and 2.9 degrees below average, respectively. That accounts for the 49 percent more heating degree-days than normal in the Pacific region. In contrast, much of the southern portion of the country experienced relatively warm weather with the West South Central region standing out at nearly 10 degrees warmer than normal and a 57 percent decrease in heating degree-days.
Other Market Trends
Shale Development Helps Boost Proved Natural Gas Reserves to Highest Level since 1971. Natural gas proved reserves are at their highest level since 1971, according to EIA Summary: US Crude Oil, Natural Gas, and Natural Gas Liquid Reserves, 2009, http://www.eia.gov/oil_gas/natural_gas/data_publications/crude_o il_natural_gas_reserves/cr.html, which was released November 30, 2010. Proved reserves of wet natural gas (including natural gas liquids) rose by 11 percent to 284 trillion cubic feet (Tcf). Development of natural gas in shale formations drove the increase. Increasing 9.2 Tcf, Louisiana had the largest increase in proved reserves of any State. This was largely due to development of the Haynesville Shale. Arkansas and Pennsylvania (areas of major growth in the Fayetteville and Marcellus Shales) added 5.2 Tcf and 3.4 Tcf, respectively. Proved reserves are those volumes of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. EIA’s estimates of proved reserves are based on an annual survey of about 1,200 domestic oil and gas well operators.
Production Rises and Prices Fall in September. EIA released the November Natural Gas Monthly http://www.eia.gov/oil_gas/natural_gas/data_publications/natural _gas_monthly/ngm.html, which includes data through September 2010. Natural gas wellhead prices averaged $3.89 per MMBtu in September, a decrease of about 10 percent from the previous month’s level of $4.34 per MMBtu. Despite the price decline, marketed production increased from 62.6 Bcf per day in August to 63.2 Bcf per day in September. At the same time last year, marketed production of natural gas was 58.8 Bcf per day. September 2010 production recorded the highest monthly level since February 1973. Consumption fell month over month, from 60.5 Bcf per day in August to 54.1 Bcf per day in September, largely attributable to a 25 percent decline in use of natural gas for electric power generation. Heating degree-days in September declined to 196 from 356 in August.
Natural Gas Transportation Update
Two new pipelines began full-service on December 1. ETC Tiger Pipeline, with a projected 2 Bcf per day capacity, commences at an interconnect with Houston Pipeline Company in Panola County, Texas, and terminates at the Perryville Hub in Richland Parish, Louisiana. According to the company, ETC Tiger Pipeline will move natural gas from the Haynesville Shale, Bossier Sands and Fort Worth Basin production areas to end markets in the Midwest and Northeast via deliveries to seven interstate pipelines. Similarly, the Fayetteville Express pipeline, a joint venture between Kinder Morgan Energy Partners, LP, and Energy Transfer Partners, adds nearly 2 Bcf per day of capacity. Originating in Conway County, Arkansas, the pipeline terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. This pipeline will help move Fayetteville Shale produced gas to the end markets of the Midwest and Northeast via connections with four interstate pipelines.
Forecasted below-freezing temperatures in Florida prompted Florida Gas Transmission (FGT) to issue an Overage Alert Day for the gas day of December 2. FGT notified their customers in the FGT market area that there will be a 25 percent tolerance for negative daily imbalances. Weather-driven demand is also impacting pipelines in the Northeast. On December 1, Algonquin Gas Transmission, LLC, issued a system-wide imbalance warning until further notice. Additionally, Algonquin is requiring all power plant operators on the system to provide information mandated by Federal Energy Regulatory Commission Order No. 698 until further notice. Information required includes the hourly consumption profiles of directly connected power generation facilities.
Northwest Pipeline, GP (Northwest), has issued a notice stating that during the Pocatello compressor maintenance in Bannock County, Idaho, from December 1 though 15, the operational capacity at the Kemmerer compressor station in Lincoln County, Wyoming, will be limited to 675,000 Dekatherms per day. Since the primary firm scheduled quantities through the Kemmerer compressor station currently exceed this capacity, Northwest issued a Recall Advisory and declared an Operational Flow Order (OFO) as of gas day December 1 until further notice. This notice will affect shippers who have an OFO obligation (contract- specific, realignment and/or must-flow) through the Kemmerer compressor station.