The Georgia Public Service Commission has approved a plan to establish a provider of last resort (POLR) to allow natural gas customers disconnected for non-payment to reconnect their service. The commission chose Florida-based marketer Infinite Energy Inc. as the POLR, overcoming what was thought to be strong support for the frontrunners, considered to be Atlanta Gas Light, Georgia Natural Gas Services and Scana Energy. In a vote of 3-2, with Commissioners Lauren “Bubba” McDonald Jr. and Stan Wise voting “no,” the PSC’s proposal would have customers paying a $150 deposit to be reconnected. However, the customers would not have to make payments on any past due balances owed to other marketers before being reconnected. Customers would pay 10 cents above Infinite’s current market rate and be charged a $11.95 monthly customer service charge for the service. The GPSC last week also approved new electricity rates for Georgia Power Co., resulting in a $354 million reduction in the company’s revenues over the next three years. The ruling came despite the utility’s request for a rate hike totaling $103 million in additional revenues over the next five years. The reduction represents a decrease of about $1.40 for the average residential customer’s monthly bill. The commission vote was 4-1, with Commissioner Robert Baker voting no. Had the GPSC approved the rate increase over five years, residential rates would have increased by 1.2% per year on average.

Devon Energy entered into additional hedging transactions, covering its first quarter 2002 natural gas production. It entered into fixed-price physical delivery contracts covering an additional 116,400 MMBtu/d in the United States at an average price of $2.65/MMBtu, and in Canada, the company entered into fixed-price physical delivery contracts covering an additional 118,400 MMBtu/d of gas at an average price of $2.46. Devon said it currently has downside price protection in place for about one-half of its expected first quarter 2002 gas production at an average price of $2.94. For the full year 2002, Devon has downside price protection in place for 39% of its expected gas production at an average price of $3.02. On the oil side, Devon has downside price protection in place for 53,200 b/d in 2002 at an average price of $22.34/bbl, That represents 55% of Devon’s expected 2002 oil production.

Canada’s National Energy Board approved an application from Petro-Canada to construct a natural gas pipeline from the Medicine Hat, AB, area to Burstall, SK. The 44-mile, 10 inch diameter line will extend from existing natural gas production properties located in the Medicine Hat area to TransCanada PipeLines’ system near Burstall. The pipeline will have a design capacity to transport 53 MMcf/d of gas. About 35 miles of the pipeline route follows existing corridors. The Medicine Hat Pipeline is proposed to be in-service in January 2003 and the estimated capital cost is $10.1 million.

Boston-based NSTAR, Massachusetts’ largest combined utility, has asked state regulators to reduce its gas adjustment cost by 17% to 43.5 cents/therm effective Jan. 1, 2002. If approved, NSTAR’s gas adjustment cost will have dropped by 67.5 cents/therm for the year or by more than 60%. The utility’s requested reduction would lower natural gas costs by about 9.1 cents/therm during the January through April 2002 period, NSTAR said. This would mean a savings of about $13.11/month for NSTAR customers who heat with natural gas, and a savings of $1.54/month for non-heating gas customers, it estimated. In its filing to the Massachusetts Department of Telecommunications and Energy (DTE), NSTAR said the requested decrease was in response to lower natural gas prices. The utility said it anticipates its gas costs will fall by almost $15 million through the end of next April. NSTAR has asked the DTE for expedited approval of its filing so it can begin passing the savings on to its gas customers immediately. The latest DTE filing marks the fourth time this year that NSTAR has cut its gas adjustment costs to pass along the lower gas costs to its customers, according to the utility. At the start of the year, NSTAR’s gas adjustment cost stood at $1.11/therm. The gas adjustment cost, which is directly passed through to customers, includes the cost of the gas commodity and the cost of delivery of the gas. DTE already has approved a reduction for NSTAR in the default service price of electricity that is expected to save customers more than $11/month starting Jan. 1. The utility also has asked regulators to approve a cut in the Standard Offer Service price of electricity, which could save the average customer about $6/month effective Jan. 1. NSTAR serves about 1.3 million electric and natural gas customers throughout Massachusetts.

Calgary-based Gemini Corp. said Wednesday that its new natural gas processing facility in Burstall, SK, has successfully commenced operations. “This is significant because it is the first custom gas processing facility to be designed, constructed, owned and operated by the corporation,” said Carl Johnson, CEO. “We will continue to pursue similar projects, including those outside the oil and gas sector, since we believe that this type of service has strong growth potential and could represent an important part of the corporation’s future operations.” The initial design capacity of the plant is 3.8 MMcf/d with provision to expand to 7 MMcf/d. The cost was approximately $1 million and it should generate revenues of $3.6 million over the next 10 years, the company estimated. The anticipated life of this project is in excess of 15 years based on estimates of recoverable reserves in the immediate area. Gemini supplies engineering, project management, fabrication and construction, custom contract operating services and electrical and instrumentation services in Canada and internationally, predominantly to the oil and gas industry.

Plains Resources Inc. reported that it has filed a Form 8-K with the SEC to provide operating and financial guidance for the first quarter of 2002 as well as for the full year 2002. “The 2002 capital plan provides for flexibility to allow the company to pursue accretive and strategic acquisition opportunities as well as repurchasing our common stock and subordinated notes or purchasing the common units of Plains All American Pipeline LP,” said Jim Flores, chairman of Plains Resources. The company said its upstream plans call for capital expenditures of approximately $75-77 million in 2002 as compared to $135 million in 2001. The new level of capital spending is expected to generate a 2-4% increase in production volumes from the 2001 level and a 13-15% growth rate over 2000 levels.

Dallas-based EXCO Resources Inc. reported that Addison Energy Inc., a wholly owned subsidiary of EXCO, has completed the previously announced acquisition of some Alberta oil and natural gas assets from an independent Canadian producer. No seller was named by the company. As of Dec. 1, total proved reserves net to EXCO’s interest included approximately 3.0 million barrels of oil and natural gas liquids (NGL), and 21.4 Bcf of natural gas. The company listed net daily production in September at approximately 675 barrels of oil and NGLs, and 4,305 Mcf of gas from the acquired properties. The transaction became effective on Dec. 18. The purchase price was approximately $33.8 million (C$53.6 million), funded with cash and bank debt from Addison’s Canadian credit facility. “These properties complement one of our existing core areas in west central Alberta,” said Doug Miller, EXCO’s CEO. “This acquisition will increase our reserves in Canada by approximately 70% and increase our production in Canada by approximately 60%.” EXCO is an oil and gas acquisition, exploitation, development and production company with principal operations in Texas, Louisiana, Mississippi and Alberta.

Denver-based MarkWest Hydrocarbon Inc. has acquired an Alberta gathering system for C$3.1 million (US$2.0 million). The purchase includes six miles of pipelines and compression facilities that currently gather 5,500 Mcf/d. MarkWest plans to expand the system to 10,000 Mcf/d by early 2002. The new addition in southeastern Alberta is located in the Bantry field, where MarkWest already has wells and drilling locations. The system, bought from an undisclosed seller, together with a second connecting gathering system currently under construction by MarkWest, will serve seven townships and allow connection of new gas wells to the sales line as the company continues its aggressive exploitation program in what it called a “very productive and rapidly growing field.” The new system, said MarkWest, is part of a larger strategy of building a gathering system that is anticipated to grow to a capacity of 35 MMcf/d by year-end 2002, “allowing our exploration and production segment and third-party volumes to grow smoothly in tandem, as we execute our game plan for rapid ramp-up of natural gas production.” The midstream gathering system and related facilities will require 2001-2002 capital expenditures of about US$7 million, including this acquisition.

Energy Exploration Technologies (NXT) said that pipeline construction would commence in the first week of the new year to connect the company’s Poblano-area natural gas wells in Sublette County, WY to existing transmission lines in the vicinity of the Jonah gas field. Mountain Gas Resources Inc., a subsidiary of Western Gas Resources Inc., informed NXT that all Bureau of Land Management (BLM) permits have been approved and construction is set to proceed. The 11-mile pipeline will connect and subsequently take away the production from the Poblano Federal 1-28 and Juel Spring 3-2 wells (NXT 22.5% working interest). NXT said it expects to begin producing gas from these wells into the pipeline by February 2002, at which time it will report on flow rates. The company added that it also has interests in two gas wells adjacent to the pipeline that will be completed and tied in if flow rates from the first two wells are encouraging. Elsewhere in the Green River Basin, NXT’s U.S. joint venture partner, CamWest Exploration LLC, has informed it that the drilling of the first well on the Antelope Tail prospect (22.5% NXT working interest) will be postponed until the second quarter of 2002 due to BLM-mandated environmental restrictions. Completion of the BLM’s prairie dog population distribution study is expected in January or February 2002, at which time a drilling permit for Antelope Tail should be issued, NXT said. Due to a spring moratorium, the company said it expects to begin drilling the field in June 2002.

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