December 1997 Vol. 218 No. 12  Production

Robert E. Snyder,  Editor

Gas pipeline, Norwegian developments, high-cost electricity

Westcoast Energy Inc. announced that its subsidiary Westcoast Energy (U.S.) Inc. has joined with CMS Energy Corp. subsidiary CMS Gas Transmission and Storage (CMS) to participate as an equity partner in the TriState Pipeline Project. Westcoast will acquire a 33-1/3% ownership; CMS will hold 66-2/3%.

TriState will provide new natural gas transportation service from the Chicago area to Michigan and Ontario province, and through connecting pipelines to eastern U.S. markets. The project will have a market capacity of 300 MMcfd and will be expandable, depending on market response, to more than 1 Bcfd. Depending on volumes required, project cost is expected to be in the range of $250 million to $530 million. Bids for transportation capacity were opened November 5 to Dec. 10, 1997.

The TriState line will originate near Joliet, Illinois, with interconnections with Natural Gas Pipeline Co. of America, the proposed Northern Border extension, and Alliance and Viking Voyageur pipelines. From Joliet, the line will proceed northeasterly through northern Indiana to the Consumers Energy gas system near White Pigeon, Michigan. From that point, it will incrementally expand the Consumers Energy system so that Canadian and U.S. gas may be delivered to multiple Michigan markets and as far east as the Dawn market hub in Ontario. From Dawn, gas can be delivered to Canadian and eastern U.S. markets via connection pipelines.

Transportation bottlenecks to eastern markets have typically cut the price bonuses gas producers in certain western areas have access to during winter marketing seasons, a situation that has slowed gas-well drilling in several Northern U.S. and Canadian areas.

New Norwegian developments. Statoil's Status Weekly newsletter of October 30 notes development plans for three fields and a new oil find. The operator says joint development of Glitne and Theta West oil fields in the Sleipner producing area is planned, with production starting in October 2000 at the earliest. A plan for development and operation (PDO) could be submitted to Norwegian authorities within a year.

Glitne, which lies about 40 km NW of Sleipner A gas/condensate platform, contains some 50-60 million bo. Located about eight km north of Sleipner A, Theta West's reserves remain to be clarified. Various development solutions are under consideration, including a wellhead platform on Theta West and an oil processing facility on Sleipner A, as well as a stand-alone solution based on a platform with processing capability. Glitne lies in 110-m water, Theta West in 85-90 m.

A PDO for the new Huldra field is to be submitted by Statoil in December. Located in Blocks 30/2 and 30/3 near Oseberg and Troll, Huldra contains an estimated 19.1 Bcf gas and 45 MMbo. The licensees want gas to be piped to Statoil's treatment plant at Kollsnes near Bergen, with condensate sent to Veslefrikk B platform. Norway's Gas Supply committee will assess this proposal and make a recommendation before year-end.

Six producers are planned. The main drilling option is to use a jackup rig, if one can be found. The proposed development comprises an unmanned wellhead platform. Field partners are: Norske Conoco, Total Norge, PetroCanada and Svenska Petroleum Exploration.

And an oil find has been made by Statoil in the Lunde formation east of its Gullfaks South satellite. Drilled as a combined exploration and production well in Block 34/10, the discovery well found a vertical oil/gas column of some 700 m, a record for this part of the North Sea. More appraisal drilling will be needed to determine the extent of this find, which represents a substantial supplement for Gullfaks South, which has previously been estimated to contain about 225 MM bbl recoverable oil/condensate.

$2.5 billion/year for renewable electricity. The U.S. Natural Gas Supply Association in Washington, DC, has received and distributed a copy of a memo to the Office of Management and Budget from the Alliance for Competitive Energy (ACE). This memo describes a calculation, under which, if a federal mandate were legislated that requires 4.5% of all U.S. kilowatt hours of electric power be generated from renewable sources by 2005, the additional cost would be $2.5 billion per year from that date on. This equates to a 1% increase in the price of all U.S. electric power from 2005.

This memo, authored by Mr. Randall E. Davis of ACE offers a credible development of the calculation which sheds a lot of light on the low cost of electricity generated by the "premier generation technology" of combined-cycle gas-fired generation (CCGG) at 3 cents to 5 cents/kwh, and spot coal-fired power at an even lower 2 cents/kwh.

These are compared to "renewable resources," which, for this study, are considered to include geothermal, wood, wood waste, other biomass, solar thermal, solar photovoltaic and wind power-excluded by language of the proposed legislation are hydropower, municipal solid waste and fuel cells. The cost of wind power is pegged at 7 cents/kwh, from analysis described in the memo. The memo notes that various electric restructuring bills require 4, 10, 12 or 20% of U.S. kwhs to be generated from "renewable resources" by varying dates early in the next century. The assumption is made that the mandate requires at least 4.5% by 2005.

In Davis' conclusion, he uses EIA's estimates of renewable electrical power in 2005 at 80.5 billion kwh, or 2.4% of the total U.S. supply of 3,363 kwh. Raising this to 4.5% by mandate would require an additional 70.5 billion kwh, which would cost an additional 3.5 cents/kwh (7 cents for wind power vs. 3.5 cents for CCGG) or $2.5 billion-just over 1% of the total annual U.S. power bill. NGSA says this analysis will be used in its continuing fight against congressional proposals to mandate use of renewable energy. NGSA's contact fax and e-mail are: 202 326 9334 and clegates@ngsa.org.

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