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Natural gas spot prices across the country surged to record highs this week as yet another Arctic blast of cold arrived, this time reaching as far south as Texas. Prices in the Northeast were the highest in the country at more than $20 per MMBtu for much of the week, but prices also tripled since last Wednesday to $18 and more at production-area trading locations along the Gulf Coast and in Texas. On the week (Wednesday to Wednesday), the spot price at the Henry Hub had a net change of $4.26 per MMBtu to an average of $10.36 yesterday (Wednesday, February 26). The NYMEX contract for March delivery ended its run as the near-month futures contract on Wednesday, settling at just over $9.13 per MMBtu, or $3 higher on the week. As of February 21, natural gas in storage was 1,014 Bcf, or 33.4 percent below the 5-year average for this week. Crude oil prices climbed $1.90 per barrel yesterday to an average of $37.96, or $6.54 per MMBtu, which is near a 12-year high.
Strong space-heating demand combined with limited supply alternatives for a week of sharp price movements, including increases in the price of spot gas at the Henry Hub of more than $5.50 per MMBtu on Monday and Tuesday (February 24-25). After reaching a record high of $18.85 per MMBtu for Tuesday, the Henry Hub price then dropped $8.49 per MMBtu yesterday to $10.36 as forecasters signaled a warming trend into this weekend. Large withdrawals of gas this winter have resulted in lower-than-average inventories with five weeks still left in the traditional heating season. The result has been a tight spot market in which pipeline operators have limited operational flexibility (see Other Market Developments below), and gas buyers resorting to the spot market for incremental supply have faced price shocks. In New England, the spot price for delivery off the Algonquin Gas Transmission pipeline system rose to $31.94 per MMBtu on Tuesday, only to fall to $12.89 yesterday. Price fluctuations were less severe in the Midwest, where the week-high at the Chicago citygate was $18.19 per MMBtu on Tuesday and the net change since last Wednesday was $4.50 after the price fell $8.49 yesterday. Although prices at specific spot markets have climbed to higher levels in the past (over $40 per MMBtu at the Chicago citygate during the 1995-1996 winter, and $37 at New York and $52 in California in December 2000), prices across the country this week were generally the highest on record. (A discussion of the contributing factors behind the record prices is in the Other Markets Developments section.)
At the NYMEX, the futures contract for March delivery at the Henry Hub expired on Wednesday (February 26) at $9.133 per MMBtu, after a week of wild swings in value resulted in a 49-percent increase in its price. During its term as the near-month contract, the March contract generally traded between $5-$6 per MMBtu until Monday’s trading session, when the daily settlement price soared approximately $2.53 to a little less than $9.14. The March contract eventually hit $11.89 per MMBtu in overnight trading (Monday-Tuesday) on NYMEX’s Access platform. The contract traded in wide ranges Tuesday and Wednesday, but its closing prices for the sessions remained somewhat consistent at $9.577 and $9.133, respectively. The April contract settled on Wednesday at $7.39 per MMBtu, which was $1.48 per MMBtu or 25 percent higher on the week. Prices of contracts for later this year trend lower, signaling traders’ expectations that prices of the past week will be unsustainable as winter comes to close. On the week, the 12-month strip, or the average price of gas contracts over the next year, rose a little more than $0.54 per MMBtu to $6.159.
Working gas in storage was 1,014 Bcf or 33.4 percent below the 5-year average for the week ending February 21, according to EIA’s Weekly Natural Gas Storage Report. (See Storage Figure). The implied net withdrawal was 154 Bcf, which is 73 Bcf more than the 5-year average withdrawal of 81 Bcf for the week. In the Mid-Atlantic and New England regions, where major population centers account for much of the country’s space-heating demand, the weather for the week was, respectively, 10 percent and 3 percent colder than normal as measured by heating degree days (HDDs), according to the National Weather Service (See Temperature Map) (See Deviation Map). A trend of warmer-than-normal temperatures in the West this winter continued. In the West, storage inventories remain nearly 9 percent higher than the 5-year average after a 17 Bcf withdrawal this week. However, inventories in the East continued a rapid decline with a 95 Bcf withdrawal and are now 499 Bcf, or almost 42 percent lower than the 5-year average. Although storage inventories in the East have fallen below 500 Bcf by the end of the heating season twice before in the 9 years of weekly data, this is the earliest date when stocks passed that mark. Five weeks remain in the traditional heating season.
Winter (2002-2003) Conditions Have Resulted in Record Price Levels: A number of factors have played major roles in the relatively high gas prices in recent months.
§ Weather: Cold temperatures led to higher demand for heating. Most regions outside the far western portion of the country experienced temperatures that have been much colder than last winter, and also significantly colder than normal in some regions. For example, heating-degree-days (HDDs) in the Middle Atlantic region through February 22, 2003, were almost 8 percent higher than normal and more than 36 percent above last year’s level. HDDs in the entire United States have been 2.5 percent below normal in the United States (although 15 percent higher than last year) because of warm weather in the West (the Pacific and Mountain census regions).
§ Storage: Although working gas inventories entered the heating season at 3,116 billion cubic feet (Bcf) (almost 4 percent larger than the average of the preceding 5 years), high demand resulted in a faster than usual drawdown. Net withdrawals in January, estimated at 859 Bcf, represent the largest volume for this month in 30 years of EIA monthly data. As of February 21, natural gas in storage at 1,014 Bcf was more than 33 percent below the 5-year average.
§ Production: Production for the first 10 months of 2002 was down 2.6 percent from 2001 levels (based on preliminary data). Analysis indicates that the natural gas industry, although producing less, is producing at very high rates of capacity utilization, exceeding 90 percent, as a result of a lower rate of new well completions and the natural decline as producing wells age. Rapid well decline rates increase the continual need for new wells, which have higher production rates than old wells. The completion of new wells is essential to maintain and expand production as relatively new wells provide a disproportionately large share of total production. High production utilization rates tend to result in higher gas prices owing to the increasingly tight market conditions.
§ Imports: Net imports of natural gas were down by 4 percent in the first 10 months of 2002. Total U.S. imports of natural gas in the first 10 months of 2002 were up 80 Bcf or slightly more than 2 percent from 2001 levels, but exports also increased. U.S. imports from Canada, which comprise roughly 94 percent of total imports, increased roughly 3 percent during the first 10 months of 2002. Imports of liquefied natural gas (LNG) provide about 6 percent of total U.S. imports, and they declined 4 percent for the entire year. Exports to other countries were up by 146 Bcf, as additional cross-border pipeline projects, such as the Vector Pipeline, came on line.
In the near-term, conditions are expected to improve as the industry and markets respond to the price signals. Drilling for natural gas projects has increased substantially in recent months. After bottoming out at 591 rigs as of April 5, 2002, rigs drilling for gas prospects have increased to 767 as of February 21, 2003. Additionally, LNG imports may increase if U.S. prices stay high relative to world prices. The Elba Island, GA, LNG facility, reopened for imports late in 2001 and just began to receive regular shipments in 2002. The Cove Point, MD, facility, which is the facility with the largest capacity, is expected to begin operations later this year. At that point, all four existing LNG import terminals (including one at Everett, MA, and another at Lake Charles, LA) will be operational and receiving shipments for the first time since the early 1980s. Capacity for all four facilities is estimated to exceed 800 Bcf per year. Given the expected improvement in supply conditions, the EIA projects the average wellhead gas price at $4.36 per Mcf in 2003 and $4.28 in 2004. At those levels, natural gas prices would be higher than the average for 2001, and after adjustment for inflation, the projected wellhead prices would be comparable to levels seen in the early 1980s.
Pipelines Issue Operational Flow Orders on Storage Contracts: Low storage levels and peak-day conditions this week led to severe pipeline restrictions through much of the country, but particularly in the Mid-Atlantic and New England regions, where temperatures have consistently fallen below normal. In general terms, shippers with firm transportation capacity on Columbia Gas Transmission must fully utilize their firm transportation capacity at receipt points other than storage prior to withdrawing quantities from storage. This is a significant restriction that is intended to protect the integrity of Columbia operations due to low storage levels. Across the Columbia system, no interruptible service is available. Texas Eastern (TETCO) has informed customers that as of March 1, all shippers with firm transportation and storage contracts will have to maximize flow through their transportation contracts before drawing from storage. In its announcement, TETCO said that the reason for the restriction is that, based on current operating conditions, total storage withdrawal capability will decline within five days to less than the total daily contracted firm storage withdrawal rights. Shippers found in violation could be penalized up to$25 per MMBtu.
EIA Administrator Testifies Before Senate Committee: EIA Administrator Guy Caruso discussed current market conditions and both short- and long-term outlooks for natural gas in testimony before the Committee on Energy and Natural Resources of the United States Senate on Tuesday, February 25. Responding to recent widespread concerns about soaring natural gas prices, Caruso pointed out that they might signify that the market is working properly, and that the current “extremely tight” conditions have resulted from consumption having exceeded current supply (production plus net imports) in the past several months coupled with rapidly depleting working gas in storage. Caruso said that the high volatility of prices is likely to continue for the next 12-18 months as the industry mobilizes to increase productive capacity. Over the longer term, EIA expects natural gas consumption to increase at an average annual rate of 1.8 percent through 2025, reaching 35 trillion cubic feet (Tcf). To meet this level of demand, the industry will have to both increase imports and tap new sources of supply. According to Caruso, these would likely include drilling deep and ultra-deep offshore projects in the Gulf of Mexico; development of unconventional production sources such as tight sands, coalbed methane, and shale deposits; and construction of major new pipelines to bring gas from both Alaska and Canada to the Lower 48 States.
Natural gas futures and spot prices soared this week as a late winter Arctic blast boosted space-heating demand and low storage inventories and pipeline restrictions limited buyers’ supply options. After reaching a high of $18.85 per MMBtu on Tuesday, the Henry Hub spot price dropped to $10.36 yesterday, which is still more than quadruple the $2.45 price at the Hub at this time last year. Storage withdrawals for the week ending February 21 totaled 154 Bcf. Inventories for the United States as a whole are now 33.4 percent less the 5-year average.
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