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Overview (Wednesday, April 2, to Wednesday, April 9)
Released: April 10, 2008
Next release: April 17, 2008
<![if !supportLists]>· <![endif]>Since Wednesday, April 2, natural gas spot prices increased at most markets in the Lower 48 States. Prices at the Henry Hub rose 30 cents per million Btu (MMBtu), or about 3 percent, to $9.89 per MMBtu.
<![if !supportLists]>· <![endif]>At the New York Mercantile Exchange (NYMEX), the futures contract for May delivery at the Henry Hub settled yesterday (April 9) at $10.056 per MMBtu, rising nearly 22 cents or about 2 percent since Wednesday, April 2.
<![if !supportLists]>· <![endif]>Natural gas in storage was 1,234 billion cubic feet (Bcf) as of April 4, which is nearly 2 percent below the 5-year average (2003-2007), following an implied net withdrawal of 14 Bcf.
<![if !supportLists]>· <![endif]>The spot price for West Texas Intermediate (WTI) crude oil increased $6.06 per barrel on the week to $110.89 per barrel or $19.119 per MMBtu.
Natural gas spot prices decreased on the week (Wednesday-Wednesday) at most market locations, with intraweek spot market trading characterized by price decreases through Friday, April 4, and increases beginning on Monday, April 7. The softness in spot prices late last week likely can be attributed to moderating temperatures and softening industrial demand for natural gas over the weekend. While temperatures were relatively mild outside the Upper Rockies, Upper Plains, and parts of the Midwest, other demand/supply factors contributed to the price rally since Monday, April 7. Key demand factors contributing to the price increases included rising crude oil prices, the resumption of industrial load, and injection demand for natural gas. Key supply factors included a major production outage at the Independence Hub in the Gulf of Mexico, and a Colorado State University hurricane report that projects an above-average 2008 hurricane season. Price increases since Monday, April 7, more than offset the declines made in trading heading into last weekend.
On a regional basis, prices rose in all regions outside Florida by about 12 to 38 cents per MMBtu, or about 2 to 4 percent, while prices fell in the Florida region by 15 cents per MMBtu, or 1 percent since Wednesday, April 2. The largest price increases primarily occurred in the producing areas of South Texas, East Texas, and Louisiana, and in the Midcontinent and Midwest regions where heating load remains significant. While prices increased at most market locations outside Florida by more than 12 cents per MMBtu since last Wednesday, April 2, several markets in the Northeast region posted declines, most notably at the Algonquin citygate, which serves the New England region, and at the New York citygate, falling 4 and 3 cents per MMBtu, respectively. Despite these declines, prices increased nearly 15 cents per MMBtu on average in the Northeast region.
Enterprise Products Partners L.P. announced on Wednesday, April 9, that production at the Independence Hub natural gas platform at Mississippi Canyon Block 920 in the deepwater Gulf of Mexico was shut-in as a result of a leak on the Independence Trail export pipeline. The Independence Hub can process approximately 1 Bcf of natural gas capacity per day, which is about 10 percent of the natural gas produced in the Gulf of Mexico. A loss of this magnitude will contribute upward pressure on natural gas prices. The shutin is expected to last between 1 and 4 weeks while the necessary repairs are completed. (For more details, please see the Natural Gas Transportation Update in a later section of this report.)
At the NYMEX, the price of the contract for May 2008 delivery increased 22 cents per MMBtu since last Wednesday, April 2, while futures prices for natural gas delivery through March 2009 posted similar increases, and the contract for April 2009 delivery increased about 7 cents per MMBtu. Prices for the 12-month futures strip (May 2008 through April 2009) averaged $10.438 per MMBtu as of Wednesday, April 9, climbing about 21 cents per MMBtu, or about 2 percent, since last Wednesday, April 2. Contract prices for delivery in successive months in the 12-month strip exhibited a pattern of increasing prices, peaking with the January 2009 contract at $11.115 per MMBtu. Only the April 2009 contract traded at a discount relative to the May 2008 contract.
On Wednesday, April 9, the 12-month futures strip (May 2008 though April 2009) traded at a premium of 55 cents per MMBtu relative to the Henry Hub spot price. Contracts for delivery next winter (December 2008 through March 2009) traded at an average premium of $1.13 per MMBtu relative to the spot price. Price differentials of this magnitude provide suppliers significant incentives to inject natural gas into storage.
Recent Natural Gas Market Data
Working gas in storage decreased to 1,234 Bcf as of Friday, April 4, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). The net withdrawal from working gas storage of 14 Bcf significantly contrasts with the 5-year average net injection of 15 Bcf and last year’s net injection of 33 Bcf for the same report week. These differences likely reflected the heating demand for natural gas as heating degree-days in the Lower 48 States were about 7 percent above normal levels during the report week, and almost 62 percent above the level reported for the same week last year, according to the National Weather Service’s degree-day data (see Temperature Maps and Data). All Census Divisions in the Lower 48 States posted heating degree-days well above last year’s levels, except for the Middle Atlantic and Mountain Census Divisions where heating degree-days were about 2 percent below normal in both regions for the same report week. In the South Atlantic Census Division, heating degree-days were about 31 percent below normal levels; however, cooling degree-days in the region significantly exceed normal levels.
At 1,234 Bcf, working gas in storage is at the lowest level since April 30, 2004, when working gas in storage was 1,227 Bcf. Nevertheless, working gas in storage as of April 4 was significantly above the 1,034 Bcf level reported during the same report week in 2004. As of April 4, working gas stocks were 351 Bcf below the last year’s level and 23 Bcf below the 5-year (2003-2007) average.
Other Market Trends:
Overview of the 2007-2008 Heating Season. The 2007-2008 heating season (November through March) was marked by generally higher natural gas spot and futures prices compared with the 2006-2007 heating season. After beginning the heating season at a record level, underground natural gas storage levels declined relative to last years levels as the weeks progressed and by the end of the heating season fell below the 5-year (2003-2007) average. Temperatures during much of the heating season were warmer than normal, but colder-than-normal temperatures late in the heating season led to net storage withdrawals that were significantly higher than average. The relative decline in storage levels, along with lower volumes of liquefied natural gas (LNG) imports and the record high price of crude oil, exerted upward pressure on natural gas prices. LNG imports totaled about 76 Bcf during the first 3 months of 2008, which is less than half of the nearly 177 Bcf imported during the same period last year. The decrease in LNG imports this year is most likely the result of higher LNG prices abroad, which provided incentives to ship cargoes to Asia and Europe.
The average spot price at the Henry Hub for the 2007-2008 heating season was $8.05 per MMBtu, which is 13 percent higher than the previous heating season’s average price of $7.15 per MMBtu. Despite being higher during the 2007-2008 heating season, the spot price at the Henry Hub was still significantly lower than during the 2005-2006 heating season, when markets were recovering from an active Atlantic hurricane season. During the past (2007-2008) heating season, the Henry Hub spot price peaked at $9.86 per MMBtu on the final day of the season (March 31). Prices in other areas of the Lower 48 States also steadily increased during the heating season, particularly during the months of February and March. For example, prices in the Midwest increased to an average of $8.84 and $9.73 per MMBtu in February and March, respectively. These increases followed price run-ups of $0.13 and $0.78 per MMBtu in December and January, respectively. In the Rocky Mountains, however, the expansion of available pipeline capacity to transport natural gas out of some of its production areas led to more significant price increases. The opening of the Rockies Express pipeline resolved much of the transportation congestion that had previously depressed prices in the region. The regional average price in the Rockies was $8.41 per MMBtu in March, nearly double its November 2007 level of $4.82 per MMBtu.
Temperatures in the Lower 48 States were warmer than normal during the first 3 (November-January) heating season months, albeit by very small percentages. Temperatures in these 3 months were between 1.6 and 3.9 percent warmer than normal, as measured by heating degree-days (HDD). In February and March, however, temperatures were 2.2 and 1.9 percent colder than normal, respectively. Despite the relatively small deviations from normal, temperatures during the 2007-2008 heating season were significantly colder than for the same months in the prior year except for February. Temperatures in remaining months exceeded the prior year’s levels by between 5.4 and 21.5 percent.
Spot price increases in the first 2 months of the 2007-2008 heating season were fairly limited as a result of the moderate temperatures and the abundant volume of natural gas in storage. The heating season started with a record 3,567 Bcf of natural gas in storage, which was 7.2 percent higher than the 5-year average and 3.3 percent higher than the volume at the onset of the 2006-2007 heating season. However, working gas in storage fell below the previous year’s level by mid-December and remained there for the rest of the heating season, eventually falling below the 5-year average at the end of March. The relatively low levels of natural gas remaining in underground storage as of March 31 are the result of higher-than-average net withdrawals. Monthly net withdrawals exceeded the 5-year average net withdrawals in each of the heating season months, resulting in the largest cumulative net drawdown of any heating season except for that of 2002-2003.
EIA Issues Its Short-Term Energy and Summer Fuels Outlook. The Energy Information Administration (EIA) released the latest Short-Term Energy and Summer Fuels Outlook, on April 8, 2008. The report shows that the natural gas price at the Henry Hub averaged $7.17 per thousand cubic feet (Mcf) in 2007 and is expected to reach $8.59 in 2008, and $8.32 in 2009. Higher prices for this year and next are the result of continued strong demand, high oil prices, and the need to inject more natural gas into storage this year than last. During the second and third quarters of 2008, the Henry Hub price is expected to average about $8.44 per Mcf, which represents a 19.8-percent increase from the prior year average of $7.05 per Mcf. Total U.S. dry natural gas production is projected to increase by 2.9 percent in 2008 and 0.2 percent in 2009. In 2008, production is expected to be driven by the development of deepwater supplies as well as production from the Lower 48. However, imports of liquefied natural gas (LNG) are expected to decrease to 680 billion cubic feet (Bcf) in 2008, which represents a 12-percent decline from the record volume in 2007. The decline in U.S. natural gas imports is the result of higher prices in Asia and Western Europe, which compete with the United States for LNG supplies. Natural gas consumption is expected to rise by 1.0 percent in 2008 and by 0.8 percent in 2009. The assumed return to normal temperatures in the remainder of the year is expected to lead to limited growth in residential and commercial demand in 2008, while economic conditions are expected to limit industrial sector growth for the year. In 2009, consumption is projected to decrease slightly in the residential and commercial sectors, with a small increase expected in the industrial sector. Milder summer temperatures are expected to leave natural gas consumption for electricity generation unchanged in 2008, after an increase of more than 10 percent in 2007. Consumption growth of 2.9 percent is expected in the electric power sector in 2009.
EIA Releases Report on Federal Energy Subsidies and Support. According to EIA’s report titled Federal Financial Interventions and Subsidies in Energy Markets 2007, Federal energy subsidies and support to all forms of energy doubled between 1999 and 2007, reaching $16.6 billion for fiscal year 2007. The last EIA report on subsidies, completed in 2000, estimated that subsidies totaled $8.2 billion (in 2007 dollars). Tax expenditures, which are one of four types of subsidies analyzed in the report, have more than tripled since 1999, increasing from $3.2 billion to more than $10.4 billion in 2007. The report, which was completed at the request of Senator Lamar Alexander, shows that electricity subsidies and support per megawatthour varied widely by fuel in 2007. Subsidies for renewables increased from 17 percent of total subsidies and support in 1999 to 29 percent in 2007. Natural gas and petroleum-related subsidies declined as a share of total subsidies primarily as a result of the expiration of the Alternative Fuels Production Tax Credit for the production of unconventional natural gas in 1999, whereas refined coal was the principal beneficiary of this tax expenditure in 2007. Coal-related subsidies, excluding refined coal, experienced a modest decline as a share of total subsidies from 7 percent in 1999 to 6 percent in 2007. Overall, renewable fuels as well as coal-based synfuels that were eligible for the alternative fuels tax credit, received the highest subsidies per unit of generation, ranging between $23 and $30 per megawatthour. At the same time, the smallest subsidies on a per-unit basis were for coal ($0.44), natural gas and petroleum liquids ($0.25), and municipal solid waste ($0.13) per megawatthour of generation.
New Forecast Predicts an Active 2008 Hurricane Season. A new report published by the Colorado State University (CSU) Department of Atmospheric Science predicts a significantly more active hurricane season for 2008 than the average hurricane activity experienced between 1950 and 2000. The report used analog predictors and a new extended-range early-April statistical prediction scheme based on 58 years of data. Based on this analysis, the report states that the current sea surface temperature patterns in the Atlantic Ocean are typically observed before very active seasons, concluding that the probability of a major hurricane landfall in the United States is about 135 percent of the long-period average. At the same time, Atlantic basin net tropical cyclone activity in 2008 is expected to be about 160 percent of the long-term average, while the probability of a Category 3 hurricane making landfall on the U.S. coastline is 69 percent for 2008. The CSU study predicts that there will be 8 hurricanes in 2008, compared with the average of 5.9, as well as 15 named storms, compared with the average of 9.6. Furthermore, 80 named-storm days are predicted for the season (compared with the average of 49.1) and 40 hurricane days (compared with 24.5).
Natural Gas Transportation Update:
<![if !supportLists]>· <![endif]>Florida Gas Transmission Company (FGT) announced that as of April 4, maintenance continued at Compressor Station Number 6, which includes all three units, and was expected to be completed later in the evening. During the work, FGT was expected to schedule up to approximately 150,000 MMBtu per day through Compressor Station Number 6. Normally, FGT schedules up to 300,000 MMBtu per day. FGT also announced that as of April 10 it was performing maintenance at Compressor Station Number 3, which requires both units to be off-line. The outage is expected to last until April 26. During the work, FGT is expected to schedule up to approximately 150,000 MMBtu per day through Compressor Station Number 3. Normally, FGT schedules up to 230,000 MMBtu per day.
<![if !supportLists]>· <![endif]>California Gas Transmission Company issued a customer-specific operational flow order (OFO) for Wednesday, April 9, and a systemwide OFO for April 10, because of low inventory. For both days, the tolerance level was set at 5 percent. Both of the issued OFOs are stage 2 OFOs, with the penalties set at $1.00 per decatherm.
<![if !supportLists]>· <![endif]>Enterprise Product Partners LP reported that the Independence Trail pipeline was shut in on April 9 as a result of a problem to the pipeline’s flex joint that connects the Independence Hub platform to the offtake pipeline. According to the company, the repairs could take from 1 to 4 weeks, but the extent of the damage needs to be assessed by divers before repairs can commence. The joint is located in only 85 feet of water, so the company does not consider the outage a significant problem in resuming transportation. However, since Independence Trail pipeline is the only pipeline that transports natural gas from Independence Hub, a longer-term outage could affect natural gas downstream markets. The Independence Hub is located in approximately 8,000 water depth and produces about 850 million cubic feet of gas per day, accounting for about 12 percent of total regional production.