Overview (Wednesday, February 27, to Wednesday, March 5)
Released: March 6, 2008
Next release: March 13, 2008
<![if !supportLists]>· <![endif]>Since Wednesday, February 27, natural gas prices increased on both the spot and futures markets. There were a few scattered exceptions to the increases, but these were mostly confined to the Northeast.
<![if !supportLists]>· <![endif]>The spot price at the Henry Hub increased 16 cents per million Btu (MMBtu) or 1.7 percent on the week, averaging $9.37 per MMBtu yesterday, the highest price since January 2006.
<![if !supportLists]>· <![endif]>Boosted by record-high crude oil prices and declining working gas in storage, the prices of natural gas futures contracts increased on the week, reaching levels not seen in the market in more than 2 years. The price of the futures contract for April 2008 delivery increased 68 cents per MMBtu to $9.741.
<![if !supportLists]>· <![endif]>Natural gas in storage was 1,484 Bcf as of February 29, which is 4 percent above the 5-year average.
<![if !supportLists]>· <![endif]>The spot price for West Texas Intermediate (WTI) crude oil increased $4.86 per barrel to a new record-high price of $104.45 per barrel or $18.01 per MMBtu.
Cold weather that blanketed much of the country, with the exception of the Northeast, as well as the high crude oil prices, led to price increases at nearly all natural gas spot market locations. Spot price increases in the Lower 48 States ranged mostly between 20 and 50 cents per MMBtu, although several trading locations in the Rocky Mountains recorded increases of up to 62 cents per MMBtu. As of yesterday, the average regional price in the Rockies was $8.69 per MMBtu, the lowest regional price in the Lower 48 States.
The Henry Hub spot price increased 16 cents on the week to $9.37 per MMBtu. While the weekly price increase at the Henry Hub was comparatively low, yesterday’s price was the highest for this location since January 3, 2006, when the Henry Hub spot price reached $9.91 per MMBtu.
Warmer weather in the Northeast during the report week led to spot prices that were significantly below prices on Wednesday, February 27. In this region, price decreases averaged $3 per MMBtu or 19 percent, although several trading locations, including Algonquin, Iroquois, and Transco Zone 6 (both New York and non-New York delivery), recorded price declines that exceeded $4 and reached as high as $8.02 per MMBtu. Despite these sizeable decreases, 10 out of 13 locations in the Northeast traded at $10 or more per MMBtu yesterday, and the Northeast had the highest regional spot prices in the Lower 48 States.
Boosted by rising crude oil prices and declining working gas in storage, the NYMEX futures contract for April delivery at the Henry Hub settled yesterday, March 5, at $9.741 per MMBtu, after increasing 68 cents or 7.5 percent on the week. Yesterday’s settlement price for the April 2008 contract was the highest near-month settlement price since the February 2006 contract settled at $10.197 per MMBtu on January 4, 2006. During the first week of trading as the near-month contract, the price of the April 2008 contract increased in three out of five trading sessions.
Prices for contracts in the other refill season months of 2008 increased across the board with the May-through-October futures strip gaining about 65 cents per MMBtu, or about 7 percent since last Wednesday. As of yesterday, the price of the refill-season-contract strip (April-October) was $9.871 per MMBtu. With storage levels likely to finish the current heating season below last year’s levels, demand for gas for underground storage injections between April and October is expected to exceed that of last year. The current higher prices for future deliveries reflect the expected tightness in the natural gas market over the next 6 months, which results from the significant volume of natural gas that will be required for storage injection.
Recent Natural Gas Market Data
Working gas in storage decreased to 1,484 Bcf as of Friday, February 29, according to the EIA Weekly Natural Gas Storage Report (see Storage Figure). Storage inventories are currently 4.4 percent above the 5-year average, but about 10 percent below last year’s storage level at this time. The implied net withdrawal of 135 Bcf is 22 percent more than the 5-year average withdrawal of 111 Bcf and about 36 percent higher than last year’s withdrawal of 99 Bcf. With the latest net withdrawal of 135 Bcf, this year’s natural gas volume in storage already has dipped below last year’s low of 1,511 Bcf, which was reported for the week ending March 23, 2007.
The East and Producing regions recorded net withdrawals that were 24 and 64 percent, respectively, higher than the 5-year average withdrawals for the week. The relatively large drawdowns of gas reflect the impact of the unusually cold temperatures during the week, which kept demand for heating relatively high. For the week ending February 28, temperatures were 13.3 percent colder than normal and about 10 percent colder than last year, according to degree-day data published by the National Weather Service. All of the Census Divisions, with the exception of the Mountain and Pacific Census Divisions, experienced temperatures that were colder than normal (see Temperature Maps and Data). The Census Divisions with large population centers that consume large volumes of natural gas for space heating, such as the East North Central and Middle Atlantic, recorded temperatures that were between 10 and 22 percent colder than normal.
Below-average net withdrawals of 7 Bcf occurred in the West region as temperatures were at or warmer than normal. The relatively small withdrawal reduced the difference between current and last year’s volumes in the region. However, as of last Friday, the 189 Bcf being stored in the West region was still 11.7 percent below the 5-year average for the region.
Other Market Trends:
Gross Natural Gas Production in Texas Exceeds 20 Bcf per Day. In December 2007 gross withdrawals of natural gas in Texas hit their highest production level since the data series began in 1991. Gross withdrawals reached 20.2 Bcf per day in December, which was about 14.5 percent higher than the year-ago production volume of 17.6 Bcf per day. Texas recorded an 11.2-percent increase in annual gross production in 2007 compared with 2006, reaching 6.9 Tcf (18.9 Bcf per day) in 2007. Factors contributing to the increased production include increased drilling activity and continued success from unconventional resources. While the State is considered a mature producing area, exploration and production of unconventional gas resources, such as the Barnett Shale in northeastern Texas, play a major role in natural gas production. Production from unconventional resources, including coalbed methane, tight sands, and gas shales, make up the largest portion of production in the onshore Lower 48 States. According to EIA’s Annual Energy Outlook 2008, unconventional resources are projected to account for 8.73 Tcf or 57.5 percent of total Lower 48 onshore production in 2007.
Since January 2005, Texas gross withdrawals have exhibited a generally increasing trend, with the exception of a significant dip in September 2005 that resulted from the production disruption associated with hurricanes Katrina and Rita. As a result, State gross production fell to 15.6 Bcf per day in September 2005, a 4.1-percent decline from the preceding month’s level, but it returned to pre-hurricane levels by October 2005 (16.4 Bcf per day). Texas annual gross production totaled 5.8 Tcf (16.0 Bcf per day) in 2005, followed by 6.2 Tcf (16.9 Bcf per day in 2006.
Drilling activity in Texas increased during this time, when the average number of oil and gas rigs drilling climbed 21 and 22 percent in 2005 and 2006, respectively. The rate of increase in rigs in Texas hit a peak in early 2007, from which it declined and then leveled off during the final 8 months of the year. The average rig count in Texas grew about 1 percent between 2006 and 2007. According to Baker Hughes, Incorporated, the weekly average number of rigs drilling in Texas was 748 in 2007, which was on average 2 rigs more per week than in 2006.
For more information on the latest natural gas data, see the February 2008 edition of the Natural Gas Monthly. Additional data on gross natural gas production can be found in the Form EIA-914 Monthly Natural Gas Production Report.
EIA Releases Updated Report on Imports and Exports. The Energy Information Administration (EIA) has released a special report titled U.S. Natural Gas Imports and Exports: 2006, which examines recent trends in U.S. international trade of natural gas. In 2006, when U.S. natural gas consumption and prices decreased, international supplies of natural gas to the United States also fell. The United States imported natural gas from six different countries and exported natural gas to three countries. In 2006, net imports to the United States totaled 3,462 Bcf, a decrease of 150 Bcf, or 4.2 percent, from the previous year, and net U.S. exports to Mexico and Japan declined by 5 Bcf. As in years past, the U.S. imports came primarily via pipeline from Canada (85.8 percent of total imports). However, import volumes from Canada fell by 110 Bcf to 3,590 Bcf. The average price for all U.S. imports declined to $6.72 per million British thermal units or $6.88 per thousand cubic feet). Imports of liquefied natural gas (LNG) declined 7.6 percent from the 2005 level to 584 Bcf. Although LNG imports declined during 2006, the industry continued with plans to expand infrastructure in the United States in anticipation of bringing LNG from a variety of countries. The report includes extensive historical tables with natural gas import and export data through 2006 for both pipeline and LNG trade.
EIA Releases Revised Annual Energy Outlook 2008. The Energy Information Administration (EIA) on March 4 released a revised Annual Energy Outlook 2008 (AEO2008) reference case. The revised analysis replaces the early release version issued shortly before the December 2007 enactment of the Energy Independence and Security Act of 2007 (EISA2007) and includes the impact of that enactment. In the AEO2008 reference case, real world crude oil prices (defined as the price of light, low-sulfur crude oil delivered in Cushing, Oklahoma, in 2006 dollars) decline gradually from current levels to $57 per barrel in 2016 ($68 per barrel in nominal dollars), thereafter rising to $70 per barrel. The real wellhead price of natural gas (in 2006 dollars) is expected to decline from current levels through 2016, as new supplies enter the market. After 2016, real natural gas prices rise to $6.56 per thousand cubic feet in 2030. The higher prices reflect an increase in production costs and the higher oil prices.
Total consumption of natural gas is projected to increase from 21.7 trillion cubic feet (Tcf) in 2006 to 23.9 Tcf in 2016, then decline to 22.7 Tcf in 2030. Under current laws and regulations, natural gas is expected to lose market share to coal in the electric power sector as a result of continued increase in natural gas prices in the latter half of the projection and slower growth in electricity demand.
Total domestic natural gas production, including supplemental natural gas supplies, increases from 18.6 Tcf in 2006 to a projected 20.1 Tcf in 2022 before declining to 19.6 Tcf in 2030. While onshore conventional production is expected to decline steadily, lower-48 offshore production peaks in 2017. Lower-48 production of unconventional natural gas, particularly gas from shale, is expected to be a key contributor to growth in U.S. natural gas supplies, increasing from 8.5 Tcf in 2006 to 9.5 Tcf in 2030. The Alaska natural gas pipeline is expected to be completed in 2020, later than previously anticipated, because of delays in the resolution of issues between Alaska’s State Government and industry participants.
Net pipeline imports of natural gas in the AEO2008 reference case fall from 2.9 Tcf in 2006 to a projected 0.3 Tcf in 2030, reflecting both resource depletion in Alberta and Canada’s growing domestic demand. Total net imports of liquefied natural gas (LNG) to the United States are expected to increase from 0.5 Tcf in 2006 to 2.8 Tcf in 2030. The future direction of the global LNG market, with many new international players entering LNG markets and strong competition for available supply, is one of the key uncertainties in the AEO2008 reference case.
The complete AEO2008, which EIA will release in April, includes a large number of alternative cases intended to examine uncertainties surrounding the projections.
Natural Gas Transportation Update:
<![if !supportLists]>· <![endif]>Mississippi River Transmission Corporation (MRT) issued a system protection warning (SPW) March 4 and until further notice. The warning was issued as a result of forecasted cold weather. During the SPW, MRT will not schedule volumes that might result in a daily short position. If actual deliveries exceed scheduled volumes, shippers may be required to add supply or reduce their takes from MRT.
<![if !supportLists]>· <![endif]>Trunkline Gas Company announced that on March 4 and 5, it will be inspecting the Quicksand Creek Lateral in southwestern Louisiana for corrosion and defects, a procedure known as “pigging.” During that time, four meters will be shut in.
<![if !supportLists]>· <![endif]>Questar Pipeline Company announced that it will be performing a required water washing of all three units at its Oak Spring compressor station in Carbon County, Utah. To facilitate the work, the main line 104 capacity will be reduced to 400,000 decatherms (Dth) per day for gas day March 18 and to 290,000 Dth per day for March 19 and 20.
<![if !supportLists]>· <![endif]>TransColorado Pipeline between the TransColorado/REX Love Ranch interconnect and Greasewood Compressor Station (Segment 180) in northwestern Colorado has been temporarily shut in and isolated for emergency repairs. Consequently, some pipeline interconnects have been shut in until further notice. TransColorado is working with point operators and does not anticipate any impact to shippers.