ExxonMobil Corp. boosted its proven reserves in 2008 by 1.5 billion boe, more than replacing the amount of oil and natural gas it produced. The Irving, TX-based major said reserves added totaled 103% of the resources it produced last year. ExxonMobil had 22.8 billion boe of reserves at year-end 2008, split evenly between natural gas and oil. Excluding asset sales, the producer replaced 110% of its output. Using the Dec. 31, 2008 oil and gas prices required by the Securities and Exchange Commission to make reserves calculations, ExxonMobil replaced 136% of its output, the company said. Prices from a single day, it said, are not useful for making long-term investment decisions. At the end of 2008, ExxonMobil's proved reserves base increased to 22.8 billion boe. The company's reserves life, at current production rates, is 15.3 years. The portion of proved reserves already developed was estimated at 62%.

Repsol YPF SA agreed to buy all of the gas production from EnCana Corp.'s Deep Panuke field offshore Halifax, NS. The gas will be delivered to markets in Eastern Canada and the northeastern United States. The deal is for the life of the field, estimated to be eight to 18 years. Initial production is expected to be about 200 MMcf/d, which will ramp up to 300 MMcf/d. Production is slated to begin from Deep Panuke late next year (see NGI, May 12, 2008). The gas will be carried by The Maritimes & Northeast Pipeline. Repsol views the region to be served with Deep Panuke gas as a 3.5 Bcf/d market, of which the company hopes to capture 20%. The EnCana board approved the Deep Panuke project in 2007 after federal regulators gave the go-ahead on the company's development plan (see NGI, Oct. 29, 2007). Last year Repsol Energy Canada Ltd. was approved for a 25-year license to import liquefied natural gas (LNG) at the Canaport LNG Terminal at Mispec Point near Saint John, NB, and a separate 25-year license to export regasified LNG to the U.S. Northeast by Canada's National Energy Board (see NGI, Sept. 8, 2008). The Canaport terminal, a project of Repsol and Irving Oil Ltd., is expected to receive its first delivery of LNG from Repsol by May.

A binding open season is being held through March 20 by Energy Transfer Partners LP (ETP) to solicit market interest in the Tiger Pipeline, a 180-mile, 42-inch diameter interstate system that would carry growing natural gas supplies from the Haynesville Shale. The pipeline is expected to have an initial throughput capacity of at least 1.25 Bcf/d, but it may be increased to 2 Bcf/d based on the open season. ETP already has a 15-year commitment from Chesapeake Energy Marketing Inc. for firm transportation capacity of 1 Bcf/d. ETP and the Chesapeake Energy Corp. subsidiary launched plans to build the pipe in January (see NGI, Feb. 2). The Tiger Pipeline would connect to ETP's dual 42-inch diameter pipe system near Carthage, TX, and extend through East Texas and northwestern Louisiana, terminating near Delhi, LA. Interconnects would be available with "at least seven interstate pipelines at various points in Louisiana," ETP said. Depending on regulatory approvals, the pipe could be in service in the first half of 2011. When completed, the pipe would provide takeaway capacity from the increasingly constrained Carthage Hub area in East Texas, which receives gas from several producing basins in Texas, including the Barnett Shale, Deep Bossier Sands and the Permian Basin. ETP subsidiary ETC Tiger Pipeline LLC is conducting the bid process for customers that want contract terms of at least 10 years. For information contact Luke Fletcher at (210) 403-6492, luke.fletcher@energytransfer.com; or Lee Hanse at (210) 403-6455, lee.hanse@energytransfer.com. Information is also available at www.energytransfer.com.

The Peoples Gas Light and Coke Co. and North Shore Gas Co., both Integrys Energy Group Inc. utilities, are seeking rate hikes from the Illinois Commerce Commission to take effect next year, in part to cover bad debt expense for gas commodity charges. Currently Peoples and North Shore have authorized returns on equity of 10.19% and 9.99%, respectively, and a 56% equity ratio for both companies. New rates, if approved, would go into effect in 2010. Peoples would see a revenue increase of about $162.9 million, or about 10%. North Shore would see a revenue increase of nearly $22 million, or about 6%. Each would have a return on equity of 12%. Both the Peoples and North Shore filings are based on a 2010 forward-looking test year and include riders for the gas cost component of bad debt expense. In addition, the Peoples proposal includes a rider for the accelerated replacement of its cast iron main system. The companies are seeking recovery of the increasing costs of maintaining an aging infrastructure and also proposing to accelerate infrastructure replacement. They are also seeking recovery of other cost increases, such as employee and retiree health care and pension benefits.

Sempra Energy's two major California utilities and Xcel Energy's Colorado utility have issued projections that their retail natural gas charges will be lowered by about 20% in March. Xcel said retail bills in March should be 19-20% lower than in February and 20-21% lower than in March last year. Sempra's Southern California Gas Co. (SoCalGas) announced that its customers can expect see their monthly bills 20% lower this winter than last year, with bills averaging $70-80/month, compared with $89/month last year. Sempra's San Diego Gas and Electric Co. (SDG&E) also expects winter heating bills to be down 20%, averaging $50-60/month, compared with $67/month last year. Xcel said its commodity price proposed to the Colorado Public Utilities Commission for residential and small business will decrease 8% in March to 0.4676 cents/therm from a current price of 0.5064 cents/therm. Xcel's price last March was 0.7039 cents/therm, or 50% higher than what is proposed for next month. Xcel asked Colorado regulators to allow new rates to take effect March 1.

Sen. Lisa Murkowski (R-AK) said she plans to introduce legislation that would allow directional drilling for oil and natural gas resources below Alaska's Arctic National Wildlife Refuge (ANWR). Murkowski said current directional drilling technology would only permit about 10% of the refuge's estimated oil resources and 80% of its natural gas to be produced, but future subsurface oil technology may substantially increase those percentages. She said drilling from state lands would allow oil production to begin sooner. In addition, she noted that Congress approved the "no surface occupancy" precedent to develop a wilderness area when it approved the Wyoming Range Legacy Act of 2007, the first bill to permit underground oil development from beneath a wilderness area. President Obama has said in the past that he is opposed to exploration and production of ANWR.

The energy industry likely will compete for freshwater resources across the globe as water becomes more strategically significant, the World Economic Forum and Cambridge Energy Research Associates (CERA) reported. Water's role in energy production and the new risks and opportunities are growing in significance, said the authors of "Thirsty Energy: Water and Energy in the 21st Century." Solutions that join needs for local water use and local energy use have to be found to optimize both of the resources across the globe, the study concluded. Agriculture is the world's largest water user, representing 70% of freshwater withdrawn worldwide. The energy sector uses only about 8% of the world freshwater, "but this number can be as high as 40% in developed countries," the study noted. "By comparison, water consumption for energy in the United States is about 5%, compared to 85% for agriculture." The report is available at www.2.cera.com/docs/WEF_Fall2008_CERA.pdf.

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