Overview:  Thursday, April 12, 2007 (next release 2:00 p.m. on April 19, 2007)

Unseasonably cold temperatures in most regions of the country led to increases of both spot and futures prices since Wednesday, April 4. On the week (Wednesday-Wednesday, April 4-11) the Henry Hub spot price increased 50 cents per MMBtu, or about 6.7 percent, to $7.96. At the New York Mercantile Exchange (NYMEX), the futures contract for May delivery increased 34 cents per MMBtu to a daily settlement of $7.855 yesterday (April 11). The first weekly report of the traditional injection season brought natural gas volumes in underground storage to 1,592 Bcf as of Friday, April 6, which is 28.4 percent above the 5-year average inventory for the report week. The spot price for the West Texas Intermediate (WTI) crude oil decreased $2.42 per barrel to $61.98 per barrel or $10.69 per MMBtu. 

 

 

Prices:

Winter-like temperatures in the northern half of the Lower 48 States and in the Rockies, and several operational flow orders in the West, all contributed to higher spot prices this week at virtually all market locations. Since last Wednesday (April 4), prices in the major producing areas along the Gulf Coast increased between 21 and 64 cents. Prices in the Northeast on average increased by 43 cents, or 5 percent, to a regional price of $8.79 per MMBtu. The price in the New York City area off Transcontinental Gas Pipe Line (Transco Zone 6) ended trading yesterday at $8.99 per MMBtu, reflecting a total gain for the week of 25 cents per MMBtu or about 3 percent. Although market locations in the Rockies recorded the highest weekly increases that averaged $1.21 per MMBtu or 25.3 percent, prices in this region remain the lowest in the Lower 48 States, trading yesterday at $6.61 per MMBtu. The weekly increase in the Rockies reflects the impact of space heating demand in the region as well as in its downstream markets.

 

 

 

NYMEX futures prices for delivery months through November 2008 all increased this week, despite the arrival of the traditional injection season and an above-average volume of natural gas in underground storage. The current level of gas in storage likely would limit the demand for injections through the refill season. The return of winter-like temperatures across much of the Lower 48 States overshadowed the favorable supply picture.  The near-month contract increased on the week by 34 cents per MMBtu, or 4.5 percent, as it settled yesterday at $7.855 per MMBtu. On Tuesday, April 10, the May futures contract reached $7.869 per MMBtu, the highest daily settlement price for the near-month contract since February 8, when the near-month contract settled at $7.871 per MMBtu. Yesterday’s price for the May contract was nearly $1 higher than the May 2006 contract price a year ago. The June 2007 contract increased 35 cents on the week to $7.999 per MMBtu yesterday, decreasing slightly from the day before when it reached its highest daily settlement price since December 1, 2006. Prices for the remaining summer months all increased by about 5 percent on the week, despite the report issued by the National Weather Service, which stated that the stream flows in the Northwest will be near 100 percent of normal from April through September. The additional water supply is expected to support hydroelectric power generation and mitigate the need for natural gas-fired power generation.  This decrement to natural gas demand would free up some gas supply for the Midwest and the Northeast, and also for injection into underground storage.  The 12-month strip, which is the average price for futures contracts over the next 12 months, closed yesterday at $8.80 per MMBtu, an increase of 31 cents or about 4 percent since last Wednesday.

 

Overview of 2006-2007 Heating Season: The average spot price at the Henry Hub for the 2006-2007 heating season (November through March) was $7.15 per MMBtu, which is more than 23 percent less than the previous heating season’s (2005-2006) average price.  However, it exceeded the 2004-2005 heating season average price of $6.38 per MMBtu by about 12 percent. Although below last year’s level, the average price is high relative to history, despite higher natural gas production in 2006 than 2005. This winter, the Henry Hub spot price peaked in February at $9.10 because of colder than normal temperatures.  Prices during February also were elevated in many major natural gas consumption areas in the Lower 48 States. During February, prices in the Northeast increased to as high as $40.03 per MMBtu as a result of capacity constraints in the area, while prices at the Chicago citygate and in Florida reached $9.88 and $9.27 per MMBtu, respectively, for the month. Most other market locations in the Lower 48 States recorded price ranges for the month between $6 and $9 per MMBtu. Overall, average prices during the 2006-2007 heating season were more than $2 below those of the previous heating season.

    

Henry Hub spot prices generally reflected temperatures in the Lower 48 States. The highest monthly average spot price was recorded during February, which was the only month during the 2006-2007 heating season that recorded below-normal temperatures.  Gas-customer-weighted heating degree-days (HDD) during February 2006, as reported by the National Weather Service, were 16.4 percent above normal but more than 18 percent lower than the HDDs recorded in the previous year. On the whole, however, temperatures during the 2006-2007 heating season were warmer than normal and relatively warm temperatures were widespread.  In 3 out of the 5 winter months, all nine Census Divisions recorded temperatures that were warmer than normal. Overall, HDDs in the Lower 48 States were about 8 percent lower than normal, but about 1 percent higher than the number of HDDs during the same 5-month period a year prior.

 

Spot price increases were also limited during the 2006-2007 heating season by the relatively large volume of natural gas in underground storage. At the beginning of the 2006-2007 heating season (November 1), working gas in underground storage was 3,452 Bcf, which was 258 Bcf or 8.1 percent higher than the volumes at the onset of the 2005-2006 heating season. Working gas in storage remained above both the 5-year average and the previous year’s level through much of the heating season. Although temperatures began January well above normal, they increased in each of the following 5 weeks, resulting in very high draw-downs during January and February. In January and February, total net withdrawals were 691 and 719 Bcf, which were 8 and 34 percent, respectively, above the 5-year average withdrawals for these months. In fact, the 719-Bcf withdrawal was a record for February. The net withdrawal for the 2006-2007 heating season totaled 1,880 Bcf, which is 5 percent below the 5-year average net withdrawal of 1,972 Bcf. The heating season ended with the second-highest volume of natural gas remaining in underground storage since the end-of-March volume of 1,911 Bcf in 1991. 

 

Recent Natural Gas Market Data

 

Estimated Average Wellhead Prices
	Oct-06	Nov-06	Dec-06	Jan-07	Feb-07	Mar-07
Price ($ per Mcf)	5.03	6.43	6.65	5.92	6.66	6.59
Price ($ per MMBtu)	4.90	6.26	6.48	5.76	6.48	6.42
Note: 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 underground storage was 1,592 Bcf as of April 6, which is 28.4 percent above the 5-year average inventory level for the report week (see Storage Figure). According to the first Weekly Natural Gas Storage Report of the 2007 injection season the implied change for the week was a net injection of 23 Bcf, which is higher than both the 5-year average net injection of 8 Bcf and last year’s net injection of 19 Bcf. Inventories currently stand 352 Bcf above the 5-year average inventory level of 1,240 Bcf, but 119 Bcf below last year’s 1,711-Bcf volume.  The latest heating degree-day statistics published by the National Weather Service for the report week ending Thursday, April 5, indicated that temperatures were above normal, thus reducing weather-related natural gas demand to support injections into storage (see Temperature Maps).  Of the nine Census Divisions, only New England had greater-than-normal heating degree-days (HDD), where they were 10 percent above normal and significantly above last year’s level.  HDDs were at least 10 percent below normal in all other regions except the West North Central, and 19 percent less than normal for the Nation as a whole. 

 

 

Other Market Trends:

EIA’s Short-Term Energy and Summer Fuels Outlook for Natural Gas:  The Energy Information Administration (EIA) expects that natural gas prices at the Henry Hub will average about $7.64 per thousand cubic feet (Mcf) this summer (April–September 2007) according to the agency’s Short-Term Energy and Summer Fuels Outlook, released April 10, 2007.  The summer 2007 average price represents a 17.7 percent increase from the summer 2006 average of $6.49 per Mcf, reflecting concerns about potential extreme weather conditions and rising prices in the oil market.  The increases in prices this summer are expected to lead to an increase of 12.8 percent in the annual average, which is expected to be $7.83 per Mcf in 2007.  Total U.S. dry natural gas production is projected to increase by 1.4 percent in 2007 and 1.3 percent in 2008, driven by increases in onshore lower-48 production.  Imports of liquefied natural gas (LNG) are expected to increase to 750 billion cubic feet (Bcf) in 2007, which is 170 Bcf more than in 2006.  This number could rise if natural gas demand outside the United States is lower than expected.  LNG imports are projected to surpass 1 trillion cubic feet (Tcf) in 2008.  Working gas in storage is expected to remain above the 5-year average for 2002-2006 throughout 2007 and 2008.  Natural gas consumption is expected to rise to 22.4 Tcf in 2007, which is about 2.5 percent more than 2006.  This estimate includes a projected increase of 8.4 percent in residential consumption over 2006 levels, but a 1.0 percent decrease in electric power sector consumption.  The assumed return to normal temperatures results in higher heating degree-days and a cooler summer compared with 2006, which are the main drivers for this projection.  Total natural gas consumption is expected to increase another 1.7 percent to 22.78 Tcf in 2008.  Consumption in both the residential and electric power sectors is expected to grow in 2008 by 2.3 percent and 1.6 percent, respectively.

EIA Reports the Major Assumptions to Annual Energy Outlook 2007:  The EIA presented a report on April 11, 2007, detailing the major assumptions used in the National Energy Modeling System (NEMS) to generate the projections in the Annual Energy Outlook 2007 and perform policy analyses requested by the White House, U.S. Congress, Department of Energy officials, and other government agencies.  The Annual Energy Outlook 2007, which was published in February, provides a long-term projection to 2030 of domestic energy markets.  The report titled, Assumptions to the Annual Energy Outlook 2007, describes general features of the NEMS structure, assumptions concerning energy markets, and the key input data and parameters that are the most significant to the model results.  NEMS comprises 12 modules that represent the individual supply, demand, and conversion sectors of domestic energy markets in addition to international and macroeconomic modules, plus an integrating module.  The Oil and Gas Supply Module, for example, captures the interrelationships among the conventional and unconventional oil and natural gas supply sources, and analyzes cash flow and profitability to compute investment and drilling for each of the supply sources.  The model is based on data regarding crude oil and natural gas costs and operations, the domestic recoverable resource base, and foreign sources of natural gas.  Key assumptions include legislation and regulations, technology, and alternative growth.

 

Natural Gas Transportation Update: 

·         El Paso Corporation conducted an inspection at the Bondad Station B in La Plata County, Colorado, from Tuesday through Thursday this week.  During the inspection, capacity was scheduled to be reduced from a base capacity of 746 MMcf per day to 440 MMcf per day on Tuesday, 380 MMcf per day on Wednesday, and 120 MMcf per day on Thursday.

·         El Paso Corporation reduced capacity at the Mojave Topock Station on Tuesday, April 3, from a base of 500 MMcf per day to 170 MMcf per day for mandated testing.

·         Pacific Gas and Electric Company issued a system-wide Stage 2 high-inventory operational flow order (OFO) for the California Gas Transmission system on Friday, April 6.  Penalties were $1 per decatherm for exceeding a 13 percent daily imbalance. The OFO was not extended beyond Friday.

·         Southern California Gas Company reduced available border delivery capacity at Wheeler Ridge, California, starting on Tuesday, April 3, from 880 MMcf per day to 100 MMcf per day because of maintenance.

·         Southern California Gas Company declared a high-linepack OFO on Saturday and Sunday, April 7 and 8.  The OFO included a 10 percent tolerance for positive daily imbalances.

·         ANR Pipeline Company (ANR) is conducting engine maintenance at the St. John Compressor Station in Indiana, which will reduce capacity at the St. John facility by 115 MMcf per day through April 19 and by 40 MMcf per day from April 20 through May 11.  Based on current nominations, it is likely that curtailment of interruptible and firm secondary nominations will occur.

 

 

 

 Short-Term Energy Outlook