Just days after Enron Corp. ended a bid to sell Portland General to Sierra Pacific Resources Corp., Scottish Power Plc apparently decided to fling in an offer for the Oregon-based power utility. The West Coast utility would be a fit geographically with Scot Power’s PacifiCorp, which is headquartered in Portland and operates in six U.S. states. Enron would have received $2 billion from Sierra Pacific, which also would have assumed $1 billion in debt. That deal was first set up in late 1999 but started to fall apart as West Coast power problems continued (see NGI, Nov. 15, 1999). Terms for a Scot Power deal were not disclosed. Portland General has about 700,000 customers and has 2,000 MW of generating capacity. Scot Power’s PacifiCorp is now paying about $1 million a day for buy-in costs that resulted when one of its generators failed in the power crisis. For the past two years, the share price of Scot Power has registered 5% United Kingdom sector underperformance.
According to a stipulation and agreement between the Maryland Office of the People’s Counsel and Baltimore Gas & Electric, BGE must change its gas purchasing practices and buy between 10% and 20% of its winter gas supply under fixed-price agreements. The settlement was filed with the Maryland Public Service Commission last week. The switch to fixed-price contracts was a revision to BGE’s market gas commodity price procedure, which establishes the commodity portion of retail gas prices. BGE sets commodity prices based on monthly reported gas prices in spot markets. Under the agreement, BGE will buy 10-20% of its winter supplies between April and September under fixed-price deals. Gas purchased under the fixed price agreements will not be subject to sharing mechanisms or prudence reviews. “The volatility of natural gas spot prices hurt residential customers in Maryland this past winter,” said Peoples Counsel Michael J. Travieso. “This settlement will bring some diversity to BGE’s supply portfolio and help moderate the effects of unstable spot prices on consumer bills. Customers will benefit from more predictable gas costs.” The settlement also reduces what consumers must pay for BGE to reserve future gas supplies from $1.625 per year to $300,000.
Southern Company and the Orlando Public Utilities Commission (OUC) have received preliminary approval to build a 633 MW gas-fired generation facility. The Florida Public Service Commission signed off on a certificate of need filed by Southern, OUC and two other partners — the Kissimmee Utility Authority and Florida Municipal Power Agency. The project now goes to the Florida Department of Environmental Protection, then to the Florida governor and cabinet for final approvals. The four partners had signed a contract earlier that will see Southern build the combined-cycle generation unit at OUC’s Curtis H. Stanton Energy Center. Construction could begin as soon as this fall, with operation by 2003. It is Southern’s first step in expanding outside its service area. The company has targeted what it calls the “Super Southeast” for expansion, which not only includes the areas it currently services — Alabama, Georgia, northwest Florida and southeastern Mississippi — but also a broader region covering eight to 10 states across the Southeast. “The South is the single fastest-growing retail and wholesale energy market in the nation,” said Paul Bowers, president of Southern Company Generation and Energy Marketing. “We intend to play a large part in serving that growth by providing energy that is affordable, reliable and cleaner than ever.”
Duke Energy North America announced the sale of its ownership interest in Duke Energy McClain to NRG Energy. Duke Energy McClain is the holder of a 77% interest in the McClain energy generating facility, a 500 MW merchant power facility under construction in Oklahoma. Terms of the transaction were not disclosed. The McClain facility is a combined-cycle, natural gas-fired merchant generation facility located near Newcastle, OK. Construction of the facility began in March 2000, with commercial operations set to begin this summer. Duke Energy McClain closed on the sale of a 23% interest in the facility to the Oklahoma Municipal Power Authority in March 2001. The sale of the McClain facility is expected to close in the third quarter of 2001.
A new study by John S. Herold Inc. found that despite a 150% increase in capital spending to $50.7 billion, reserve replacement costs dropped a dramatic 8% to 4.73/boe last year. Reserve replacement rates set all time records, with U.S. E&P companies replacing 272% of oil production and 251% of gas production, the firm said in its report, “The Herold 34th Annual Reserve Replacement Cost Analysis–Top 50 U.S. Companies.” The $30 billion jump in capital spending was fueled by a $20 billion increase in proved acquisitions and a $10 billion spurt in finding and development expenditures. BP was the biggest U.S. spender ($12.7 billion), followed by Phillips Petroleum ($6.7 billion) and Anadarko Petroleum ($6 billion). U.S. gas reserves rose 17% to 102 Tcf, said Nicholas D. Cacchione, Herold senior vice president and director of research. “Record reserve replacement rates were due not only to strong acquisition activity but also to drillbit additions.” The Herold 50 replaced its natural gas production through the drillbit for the first time in at least five years and replaced 163% of oil production through drilling. Despite the torrent of spending, U.S. reserve replacement costs fell to a 5-year low. Finding and development costs dropped to $5.17/boe while proved acquisition costs slipped to $4.38/boe. The only “blemish” was a 15% uptick in production costs to $4.14/boe, due largely to higher price sensitive production taxes, Herold said. For information about Herold’s study, call (203) 847-3344 or email firstname.lastname@example.org.
Pacific Gas and Electric Co. announced that due to a decrease in wholesale natural gas prices, and a decline in usage, the average residential gas bill in May is expected to decrease as much as 42% from April bills, to $47. The new rates will take effect May 7. The average residential customer uses 30 therms a month in the summer season (May-October) and 70 therms a month in winter (November-April). The anticipated drop in usage accounts for most of the significant decrease expected in monthly bills. However, the actual cost of gas is also declining in May. The procurement cost will be $0.78 per therm, compared with $0.84 per therm in April, a decrease of more than 9%. The delivery charge that customers pay the PG&E utility has not increased, and will not change.
Husky Energy Inc. and Avid Oil & Gas announced that a Husky subsidiary will offer to acquire all remaining shares of Avid not currently held by Husky for about C$94 million. Husky currently owns approximately 38% of Avid as a result of the acquisition of Renaissance Energy in August 2000. Under the terms of the agreement, Husky will acquire all remaining Class A shares (14.6 million) of Avid at C$5.85/share and all of Class B shares (843,000) at $10/share. The offer represents a 23% premium over Avid’s 30-day average closing price of the Class A shares prior to announcement. Avid’s operations are in the Provost region, West Central and the Peace River Arch of Alberta. Key properties include Thompson Lake, Pine Creek, Edson, Bigoray, Gordondale, Fourth and Hines Creek. Avid currently produces 5,800 boe/d and has 11.6 million boe of proved reserves, as well as 100,000 net acres of undeveloped acreage.
Canadian 88 Energy Corp. closed a previously announced sale of assets in the Waterton and Caroline areas of Alberta to Hunt Oil for C$176 million. Net proceeds from this sale will be used to reduce the company’s debt which currently stands at C$200 million. Canadian Superior Energy Inc., which launched an unsolicited takeover bid for Canadian 88 last week, has instigated litigation involving a portion of the Waterton assets in the Hunt Oil transaction. Meanwhile, Canadian 88’s board and team of advisers continue to evaluate alternatives to boost shareholder value.
Ocean Energy completed its $118 million purchase of the of the Texas and Louisiana oil and gas assets of EnSight Resources. “This niche acquisition gives us quality properties at an attractive price with no appreciable impact on our balance sheet,” said John Schiller, executive vice president of operations. “We strengthen our North American natural gas portfolio with exploitation upside and solid economic returns. Most of these assets are situated in East Texas and North Louisiana where Ocean has an excellent operating position and base of technical expertise.” The assets add total estimated proved reserves of 101 Bcfe, of which 88% is natural gas. Ocean estimates that total reserve potential exceeds 150 Bcfe.
Phillips Petroleum said its net income, excluding special items, rose to $504 million, or $1.96 per share, up from $271 million, or $1.06 per share, in the year-earlier period. Revenues rose to $4.9 billion from $4.8 billion a year ago. Wall Street expected the company to earn between $1.85 and $2.25 a share, with a mean of $1.92. The company warned earlier this month that it would fall short of a consensus estimate which stood at $2.19 a share at the time.
Halliburton said a subsidiary has signed an agreement to acquire Magic Earth Inc., a leading 3-D visualization and interpretation technology company with broad applications in the area of data mining. Adding Magic Earth will further enhance Halliburton’s suite of integrated software solutions for the energy industry and grow its information products and services business, the company said. Magic Earth’s technology provides a “quantum improvement in oil and gas exploration by revolutionizing the 3-D seismic interpretation workflow process,” Halliburton said. Under the agreement, Halliburton will acquire Magic Earth in a stock-for-stock transaction valued at $100 million. “In order to capture value early in the reservoir life cycle, our customers continue to need improved speed in their workflows,” said Dave Lesar, CEO of Halliburton. “The acquisition and integration of Magic Earth’s software with the Landmark data infrastructure and other leading software tools will provide best-in-class solutions unparalleled in the industry. This strategic acquisition is not expected to be dilutive to earnings in 2001, and is expected to be accretive next year.”
CMS Energy’s first-quarter earnings rose 45% on higher sales and increased sales margins, beating analysts’ estimates. CMS reported earnings of $109 million or 85 cents a share. In 2000, CMS earned $75 million and 65 cents a share in the first quarter, including the one-time accounting charge of 5 cents a share. Wall Street expected CMS to earn 78 cents/share. CMS said, however, it expects lower than expected earnings for the rest of the year because of asset sales. Operating earnings were up 16% to $131 million from non-utility businesses, up 19% to $93 million from gas and liquefied natural gas transmission and processing, up 225% to $13 million from oil and gas exploration and production operations, up 41% to $24 million from independent power production, up 133% to $7 million from marketing and trading, and up 12% to $200 million from the electric and gas utility businesses of Consumers Energy.
Units of Exelon and Peoples Energy announced that they will jointly develop and operate a 350 MW, natural gas-fired peaker electric plant on Chicago’s southeast side. The plant will provide electricity to the city in periods of high electric demand. Exelon’s wholesale power marketing division, Power Team, will market the energy output of the plant for its affiliate Exelon Generation. Peoples Energy Resources, a subsidiary of Peoples Energy, will provide fuel procurement. The plant will operate only during periods of peak electricity use and emergencies to help ensure reliability of the local and regional electricity supply. Also, eight General Electric turbines, equipped with dry, low NOx burner coal technology to reduce emissions, will be installed. Construction of the plant will take about 10 months and it is targeted to begin operations in late spring 2002.
Chicago-based Peoples Energy took on a little larger Texas flavor, announcing that it has almost doubled its current proved reserve base and investment in exploration and production by buying 100% of the interests in 28 oil and natural gas producing wells onshore in South Texas for $120 million. About 91% of the leaseholds are natural gas. In its move to build natural gas reserves, CEO Richard E. Terry said the South Texas acquisition helped Peoples make “significant progress toward our long-term goal of becoming a top-50 owner of natural gas reserves. By increasing our operations in the Gulf Coast region, we strengthen our business and enhance our ability to diversify on growth opportunities.” The new properties include interests in approximately 11,500 gross acres (8,900 net) of developed and undeveloped oil and gas leaseholds, which will be operated by Peoples Energy Production, the production unit. The transaction increases Peoples’ total proved reserves to approximately 130 Bcfe as of March 30, 2001, with current net production approximately 55 MMcfe/d.
NiSource Inc. reported first quarter 2001 net income of $188.8 million ($0.92 per share), compared to $79.6 million ($0.64 per share) posted during the first quarter 2000. However, the company warned that its results could not be directly compared due to the acquisition of Columbia Energy Group, which was completed on Nov. 1, 2000. “The first-quarter results demonstrate the accretive value of the strategic combination of NiSource-Columbia, and we continue to be on track to meet analyst expectations for 2001,” said Gary L. Neale, NiSource CEO. As previously stated, because of the seasonal nature of the gas business, which accounts for a greater portion of NiSource’s business since the Columbia acquisition, it is expected that the first- and fourth-quarter results will be stronger, and the second- and third-quarter results weaker when compared to NiSource’s historical performance, assuming normal weather patterns. Reflecting the addition of Columbia’s five natural gas distribution subsidiaries, the company’s operating income for gas distribution sky-rocketed from $191.1 million during the first quarter 2000, to $288.1 million for the quarter ended March 31, 2001.
The number of wind generation projects submitted in response to a Bonneville Power Administration (BPA) request for proposals has taken the agency by surprise, with a much higher level of interest in the alternative form of energy than originally anticipated by BPA. “I thought developers would be far enough along with their projects to submit maybe 1,000 MW of projects, but the 25 proposals added up to about 2,600 MW,” said George Darr, BPA’s renewable power resource program manager. And that’s not all. Darr pointed out that if room for expansion included in the proposals is also thrown into the mix, that raises the total to over 4,000 MW of wind power on the sites. Most of the proposed sites are in Oregon, which has 10 projects, and Washington State, with eight sites. The rest are distributed among Idaho, Montana, Wyoming and Canada. BPA will examine the projects in terms of cost, how well they can be integrated into the Northwest power grid and other factors. The agency will select the most promising proposals by the end of May and then begin contract negotiations with developers. Darr hopes to have the first of the projects on line in late 2002 or early 2003. Because wind speed varies, the 2,600 MW capacity of the proposals will likely translate into about 850 MW of power on average.
Continuing to report a trail of red ink, PG&E Corp. last week said its first-quarter results turned up a $951 million, or $2.62 per share, loss, driven by a $1.1 billion (after tax) cost of wholesale power by Pacific Gas and Electric Co.in unreimbursed power costs and power purchases. Before the charge for the uncovered power costs, PG&E net income from operations in the first quarter was $243 million, or 67 cents per diluted share, compared to $284 million (78 cents/share) in the same period last year. The utility contributed $192 million, or 53 cents-per-share, and the PG&E National Energy Group (NEG) produced $54 million in net income, or 15 cents/share — essentially the same as last year’s first quarter ($56 million, 15 cents per share). PG&E CEO Robert Glynn expressed disappointment that the state’s energy situation “continues to have such a negative impact on our reported financial results,” adding that the company hopes its April 6 Chapter 11 bankruptcy filing ultimately will “restore shareholder value associated with our strong operating results.” He and Tom Boren, the head of NEG, maintained that the bankruptcy, however, is not stopping the nonutility businesses from moving ahead with major capital projects, for which some of the financing will be announced in the near future.
Eastern Canada, New York state and New England should all have adequate electricity supplies this summer, according to a set of comprehensive reliability assessments unveiled by the Northeast Power Coordinating Council (NPCC) last week, although the NPCC did raise a red flag related to New York’s ability to handle periods of extreme demand for power. The NPCC said that New York state, as a whole, should have an adequate supply of electricity, but warned that the state could require significant amounts of electricity to be imported during peak demand periods. The council said that reliability in the state would be enhanced by reducing dependence upon external resources with more installed generation within New York. NPCC’s summer outlook for New England is more favorable. The council said that several new power plants have come online in the region since last summer and additional capacity, sufficient to meet the needs of a million homes, is scheduled to become available by June. This additional capacity will offer increased reserves and a higher reliability than past summers. Turning to Canada, the NPCC said that Quebec and the Maritime Provinces, which experience their highest electricity demand in the winter, are expected to have ample resources throughout this summer. For Ontario, resources and operating reserves are sufficient to meet their expected demand in the summer months.
Idaho Power last week received the go-ahead from state regulators to immediately start recovering $168.3 million of the $227.4 million requested by the utility in its annual power cost adjustment. But any decision related to the remaining $59.1 million of Idaho Power’s request won’t come until after the Idaho Public Utilities Commission (IPUC) completes an investigation into several areas, including the activities of the utility’s non-regulated trading arm. Of the $168.3 million approved by the IPUC, $126.2 million is for excess power supply costs Idaho Power incurred over the past year. The remainder is anticipated costs the company expects to incur from purchasing power over the next 12 months. Those estimates are based, in part, on expected Snake River stream flows and storage and on anticipated wholesale power costs over the next year. The rate increase took effect last Tuesday, as requested by Idaho Power.
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