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|Residential Natural Gas Prices: What Consumers Should Know|
|An Assessment of Prices of Natural Gas Futures Contracts As A Predictor of Realized Spot Prices at the Henry Hub|
|Overview of U.S. Legislation and Regulations Affecting Offshore Natural Gas and Oil Activity|
|Changes in U.S. Natural Gas Transportation Infrastructure in 2004|
|Major Legislative and Regulatory Actions (1935 - 2004)|
|U.S. LNG Markets and Uses: June 2004|
|Natural Gas Restructuring|
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Overview: Thursday, May 17, 2007 (next release 2:00 p.m. on May 24, 2007)
Natural gas spot and futures prices increased slightly this week (Wednesday-Wednesday, May 9-16), despite the usual lull in demand during this shoulder period between the winter heating and summer cooling seasons. The upward price trend likely resulted from a variety of factors, including rising prices for competing petroleum products (as evidenced by an increase in the underlying crude oil price). Additionally, concerns over current and future supplies do not appear to have eased. The official start of the hurricane season is imminent, and the first named tropical storm appeared this week. However, imports of liquefied natural gas (LNG) have increased markedly in the past few months. On the week, the Henry Hub spot price increased 16 cents per MMBtu, or 2 percent, to $7.62. At the New York Mercantile Exchange (NYMEX), the contract for June delivery increased 17.0 cents per MMBtu on the week to a daily settlement of $7.890 yesterday (May 16). EIA’s Weekly Natural Gas Storage Report today reported natural gas storage supplies of 1,842 Bcf as of Friday, May 11, reflecting an implied net injection of 95 Bcf. This level of working gas in underground storage is 20.6 percent above the 5-year average inventory for this time of year. The spot price for West Texas Intermediate (WTI) crude oil increased $1.03 per barrel on the week to $62.57 per barrel, or $10.79 per MMBtu.
Although moderate temperatures characterized the weather picture for most of the Lower 48 States, summer-like heat moved into the South and with intensity into the Southwest. Hotter weather was at least partially responsible for the largest 1-day price movement this report week, which occurred during trading on Monday, May 14, as several spot markets had increases of more than 50 cents per MMBtu. For example, at the Waha market in West Texas, the average price increased to $7.71 per MMBtu, 58 cents higher than in the previous trading session. However, for the most part, prices were generally stable during the week and even decreased in three of the five trading sessions at most market locations. For the week, prices at production-area trading locations along the Gulf Coast in Louisiana generally increased between 9 and 30 cents per MMBtu. The Henry Hub spot price climbed to $7.62 per MMBtu, which is 16 cents higher than last Wednesday’s price. Two large price decreases on the week occurred at market locations in the Rocky Mountain region. The price at the El Paso Bondad and El Paso non-Bondad pools dropped 73 cents and 65 cents per MMBtu, respectively. This decline resulted from the closure of El Paso Natural Gas Company’s San Juan Crossover capacity, essentially eliminating a key outlet to Southwest markets. Still, prices at the Bondad and non-Bondad markets off the El Paso pipeline finished the week above $6 per MMBtu, considerably higher than some other points in the Rockies. For example, the price off Colorado Interstate Transmission gained 7 cents on the week, but remained below $4 per MMBtu yesterday at an average price of $3.89 per MMBtu. In contrast to this price level, prices in many Northeast markets still exceed $8 per MMBtu, despite the dropoff in demand with the end of winter. Off Transcontinental Gas Pipe Line in New York City, the average price yesterday was $8.21 per MMBtu, or 18 cents higher on the week.
At the NYMEX, the price of the futures contract for June delivery increased in four of five trading sessions this week, resulting in a net increase of 17 cents per MMBtu (to $7.890). All futures contracts through the end of the next heating season also increased on the week (albeit in lesser amounts). As a result, the price of the 12-month strip, or the average price for contracts over the next year, climbed 13.6 cents per MMBtu, or 1.6 percent, to $8.819. The price of the near-month contract is $1.638 per MMBtu higher than last year’s price at this time (on May 16, 2006, the June 2006 contract settled at $6.252 per MMBtu). At this time last year, the difference between the Henry Hub price and the price for the NYMEX contract for delivery the following January (the month that is normally the highest price in the 12-month strip) had widened to $5.201 per MMBtu, a spread that was highly unusual. The corresponding spread this year is still atypically high, but is narrower at $2.375 per MMBtu. Currently, the January 2008 contract is priced at $9.995 per MMBtu. The increases at the NYMEX this week (as well as the increasing price in successive months through next January) reflect an uncertainty in the market, as the possibility of an active hurricane season and a tight supply/demand balance may have a significant impact on the futures prices during the coming summer months and beyond.
Recent Natural Gas Market Data
Working gas in underground storage was 1,842 Bcf as of May 11, which is 20.6 percent above the 5-year average inventory level for the report week, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). The implied net injection for the week was 95 Bcf, or 23 percent higher than the 5-year average net injection of 77 Bcf, and 5 Bcf or 6 percent higher than last year’s net injection of 90 Bcf. As a result, current inventory levels now are 315 Bcf higher than the 5-year average (2002-2006). Net injections for the past 3 weeks have exceeded volumes for the comparable period of last year, so the volume of gas in storage is 225 Bcf below the level at this time last year, which is down from the difference of 276 Bcf as of April 20. The latest heating and cooling degree-day statistics published by the National Weather Service for the period roughly coinciding with the week covered by this storage report show that weather-related gas demand was minimal relative to the peak periods in the summer and winter, limiting heating- or cooling-load demand (see Temperature Maps). For the United States as a whole, heating degree-days (HDDs) were lower than normal and below last year’s. As for cooling degree days (CDD), some Census Divisions showed large percentage differences from normal, but the actual CDD levels were relatively low compared with summer levels and therefore do not represent significant cooling demand.
Other Market Trends:
Overview of Canadian Natural Gas Markets in 2006: The National Energy Board (NEB), Canada’s independent federal agency responsible for regulating parts of Canada’s energy industry, released a report on May 10, 2007, describing Canadian energy trends and markets in 2006. According to Canadian Energy Overview 2006, Canadian natural gas production averaged 17.1 billion cubic feet (Bcf) per day in 2006, which was roughly equal to production in 2005. This was largely a function of drilling activity that reached record highs during the first half of the year, but declined significantly in the second half of the year, leaving the total number of new gas wells completed in 2006 slightly below 2005 levels. Canadian natural gas consumption in 2006 was 8 Bcf per day, which is about 46 percent of Canadian production and about 1.2 percent less than consumption in 2005. This decrease relative to the previous year mainly reflects mild winter temperatures as more than one-third of Canadian natural gas consumption is directed toward residential and commercial uses, primarily space and water heating. High and volatile prices also may have moderated natural gas consumption in 2006, although prices for natural gas were lower than the record highs in late 2005. Natural gas gross exports from Canada to the United States were about 9.6 Bcf per day in 2006, which was about 16 percent of estimated U.S. consumption. This is about 4.8 percent less than in 2005, a year when more natural gas was needed to offset U.S. natural gas supply losses from hurricanes. Because of lower export volumes and prices compared with 2005 levels, Canadian revenues from gas exports decreased about 24 percent in 2006. The NEB report also describes trends in crude oil, natural gas liquids, and electricity markets as well as the energy industry’s role in the Canadian economy. In 2006, the energy industry accounted for almost 6 percent of Canada’s Gross Domestic Product and 22 percent of the total value of Canadian exports.
Natural Gas Transportation Update: