Quest Resource Corp., which had been concentrating its exploration efforts in the Cherokee Basin of Kansas and Oklahoma, is expanding into the Marcellus Shale after agreeing to buy privately held PetroEdge Resources LLC for $140 million. PetroEdge, whose exploration is focused in the Appalachian Basin across West Virginia, Pennsylvania and New York, controls about 78,000 net acres that hold estimated proved reserves of 99.6 Bcfe. Current output is about 3.3 MMcfe/d. Nearly 67,000 of the net acres are in the heart of the Marcellus Shale play, with nearly 41,000 net acres spread across Ritchie, Wetzel and Lewis counties, WV; 22,000 net acres in Lycoming County, PA; and 3,000 net acres in Steuben County, NY. Quest Resource is said to be the largest producer of natural gas in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma, where it controls about 560,000 net acres. Quest Resource terminated an agreement in May to acquire Pinnacle Gas Resources Inc., which would have given it a position in the Rocky Mountains (see NGI, Oct. 22, 2007), and said it would pursue Marcellus Shale opportunities instead. Combined with its existing acreage and development rights in the Appalachian Basin, Quest Resource said it would own the right to develop 119,000 net acres within the region once the PetroEdge acquisition is completed. Closing is expected by mid-July.

The federal lands of Colorado’s Roan Plateau, long prized for its natural gas riches and wildlife, will be up for auction Aug. 14, the Bureau of Land Management (BLM) said. The BLM, which approved a drilling plan for the plateau in March (see NGI, March 17), said it would offer 46 parcels for lease, which would be around 73,500 acres. The auction would include 31 parcels, or 55,186 acres, on top of the Roan Plateau and on the plateau’s sides that are currently not leased, said BLM. The other 15 parcels in the lease auction cover around 18,300 acres on U.S. Forest Service lands in the Grand Mesa, Uncompahgre and Gunnison national forests. Protests, expected to be filed by environmental and wildlife groups, may be filed through July 30, BLM noted. A protest would require BLM to take another look at the contested parcel(s) and decide whether the reason for the protest is valid. Several of the state’s politicians already have weighed in on the future of the plateau. Gov. Bill Ritter has proposed an alternate plan, and three of the state’s lawmakers — Sen. Ken Salazar, Rep. John Salazar and Rep. Mark Udall — in April introduced legislation calling for phased leasing of federal mineral leases on the plateau and increasing the acreage for areas of critical environmental concern (ACEC), a special area given a higher level of protection, to 39,338 acres (see NGI, April 21). BLM has designated 21,034 acres as ACECs. The Roan Plateau holds enough natural gas to heat four million homes for 20 years, with an estimated 9 Tcf of natural gas that could be pumped from federal lands in the Roan area, according to BLM. Money from leasing and royalties on natural gas sales is expected to generate between $857 million and $1.13 billion over the next 20 years, and Colorado would receive about half of the royalties, an estimated $428-565 million, BLM said.

New Orleans-based McMoRan Exploration Co. plans to seek permission from the Department of Interior‘s Minerals Management Service to drill deeper on the Blackbeard West prospect, located on the Treasure Island play in the Outer Continental Shelf. McMoRan wants to drill to 35,000 feet, an ultra-deep well that would surpass its permitted 33,000-foot depth. The well currently is drilled to 31,943 feet. Former operator ExxonMobil Corp., which spud the well in 2004, encountered higher-than-expected pressure at the site and suspended the operation two years ago (see NGI, Aug. 21, 2006). McMoRan, which specializes in deep drilling in the shallow Gulf of Mexico (GOM), acquired a 32.3% stake last year in the Blackbeard West prospect and is the operator. A consortium of stakeholders holding interests includes Plains Exploration & Production Co. (35%) and Energy XXI Ltd. (20%). McMoRan also said its fourth well was successful at its Flatrock field in the GOM South Marsh Island Block 212. The producer began drilling the prospect in early April and has reached 15,315 feet, it said. Energy analysts consider the Flatrock discovery to potentially be one of the largest ever in the shallow GOM waters. McMoRan already has drilled two successful wells in the Flatrock area. The initial discovery well came online in January at a gross rate of 50 MMcfe/d. The Flatrock No. 2 well was tested at a gross rate of 114 MMcfe/d and is expected to begin production by the end of July, the producer said.

The Wyoming Department of Environmental Quality‘s Industrial Siting Council plans to consider Williams Companies‘ proposal to spend $223 million to expand the processing and natural gas liquid (NGL) production capacities at the Echo Springs processing plant in Carbon County, WY. Wyoming’s siting council reviews the possible social and environmental effects of proposed industrial facilities in the state. Permits from the council are required for any construction project with a final cost of $170 million or more. The Wyoming environmental department contends that its work provides benefits to businesses and indirectly to all of its citizens “by minimizing environmental pollution, enabling responsible economic development and restoring previously polluted and hazardous sites.” Residents and visitors alike “benefit from the quality of life we share in this great state,” the environmental department said on its website. Williams’ proposed expansion would add approximately 350 MMcfe/d of processing capacity and 30,000 b/d of NGL production capacity, roughly doubling the plant’s volumes in both cases. Williams expects to bring the additional capacity on-line during late 2010, subject to all applicable permitting. Once the expansion is complete, the plant’s processing capacity would be 740 MMcfe/d and its NGL production capacity would be 60,000 b/d.

Pacific Gas and Electric Co. (PG&E) has filed with California regulators for a retail electric rate increase of approximately $482 million, or roughly 4.5%, effective Oct. 1. The San Francisco-based utility called the gas prices “skyrocketing” and the hydroelectric situation “lower-than-expected.” The proposed power cost offset increase submitted to the California Public Utilities Commission is designed to be collected during a 15-month period running through December 2009. The proposed increase is strictly limited to recovering the estimated added costs PG&E will face in providing power to its retail customers, the utility emphasized. PG&E said that natural gas wholesale prices have increased by 30% this year and are forecast to remain high in 2009. The utility attributed the gas price spikes to “a tight supply-demand balance” in the U.S. market overall, lower imports of liquefied natural gas and rising crude oil prices that continue to set all-time records. With California’s and the nation’s preference for gas-fired electric generation, higher fuel prices mean higher retail electricity charges, PG&E said. “In 2009, high demand for natural gas — one of the cleanest fossil fuels available to generate electricity — is expected to continue upward pressures on the price of natural gas and in turn lead to further increases in customer electricity rates,” said a PG&E spokesperson. The utility’s electricity costs next year are projected to increase by $340 million, resulting in a “less-then-2% increase” above the rates previously estimated to be effective this October. PG&E said the retail rates also have been impacted by lower supplies of hydroelectric power and increased demand. In the past year, statewide rainfall was about 70% of normal, the utility said.

San Diego-based Sempra Energy‘s two major California utilities remain the foundation for the $11 billion energy holding company, according to Standard & Poor’s Ratings Services (S&P). S&P affirmed the company’s corporate and utility credit ratings. Sempra keeps its “BBB+” corporate rating, and Southern California Gas Co. (SoCalGas) and San Diego Gas and Electric Co. (SDG&E) remain with “A” ratings. At the end of 1Q208, S&P noted that Sempra overall is carrying debt of about $6.2 billion. S&P characterized California’s regulatory climate as “exceptionally supportive of credit quality,” and that fact allows the rating agency to offer the higher ratings on the two utilities, compared to the parent company and its unregulated subsidiaries.”We could lower the ratings or revise the outlook to negative if large capital projects [liquefied natural gas (LNG) terminals, interstate gas pipelines and storage facilities, and independent power generation plants] run over budget and behind schedule and management does not protect credit quality by adjusting its planned share repurchase program,” said S&P analyst William Ferara. S&P sees Sempra’s upside potential as “limited by management’s financial policies,” which it characterized as being designed to protect credit quality at current levels. However, it noted that the approach does not anticipate future debt reduction or risk reduction to improve credit quality in the medium term. The two Sempra utilities represented more than half of the company’s overall 1Q2008 profits.

Standard & Poor’s Ratings Services (S&P) has determined that the credit ratings downgrade of financing insurance giant MBIA Insurance Corp. will not affect the gas supply projects scheduled for California and Tennesee. Involved in separate determinations by S&P were Southern California Public Power Authority (SCPPA), Northern California Gas Authority (NCGA) and the Tennessee Energy Acquisition Corp. (TEAC), which collectively have $3.4 billion in bonds tied to natural gas supply projects for public-sector electricity providers. Goldman Sachs separately guaranteed each of the bond offerings and S&P said the public power financing units’ credit ratings could be revised only if Goldman’s rating was revised. MBIA, which has had its credit rating downgraded and placed on the S&P CreditWatch as negative, is insuring bond dividend payments for each of the deals. S&P said that unaffected by the MBIA downgrades and outlook are TEAC’s $2.2 billion in 2006A bonds; NCGA’s $757 million in bonds; and SCPPA’s $505 million of bonds. The SCPPA and NCGA bonds are tied to billion-dollar long-term natural gas supply prepayments for their public-sector electric utility generation members that are part of the state-chartered joint powers authorities.TEAC, which was established 12 years ago by two municipal utilities in Springfield and Clarksville, TN, has $2.2 billion in gas project revenue bonds tied to its supplier, J. Aron &Co., which is also the supplier in the SCPPA gas prepay deal.

Puget Sound Energy (PSE), the utility of Bellevue, WA-based Puget Energy, will retain key local board members and utility management following completion of the deal to take the company private, it said. The buyout consortium is being led by a North American unit of Australian-based Macquarie Bank Ltd. The deal, which was announced last October, is pending before the Washington Utilities and Transportation Commission (WUTC). Stephen Reynolds will remain as PSE president and CEO, serving on both the utility and holding company boards, which will continue to be chaired by William Ayer, CEO of Alaska Air Group, who has served on the Puget boards since January 2005. When the deal, valued at $7.4 billion, was announced it was estimated that federal and Washington state regulatory approvals of the merger would close by mid-year 2008. The proposed merger has gained approval from Puget shareholders and FERC, and Reynolds has indicated that the WUTC is scheduled to make a decision in September. The investor consortium is led by Macquarie Infrastructure Partners, the Canada Pension Plan Investment Board and British Columbia Investment Management Corp., along with Alberta Investment Management Corp., Macquarie-FSS Infrastructure Trust and Macquarie Capital Group Ltd. Seven other members on the Puget Energy and PSE boards will represent the six-member consortium of investors’ interests. Those persons would be announced following the merger’s final approval by the WUTC.

Piedmont Natural Gas plans to construct, own and operate what would be its fifth peak storage facility within its three-state service area. The Charlotte, NC-based company is evaluating several sites in Robeson County, NC, for a liquefied natural gas (LNG) peak storage facility, the company said. Piedmont said it expects to make a final site selection within weeks. The facility would store up to about 1.25 Bcf and is planned to be in service for the 2012-2013 heating season. Piedmont’s investment is expected to range from $300-350 million. “The Robeson County LNG facility will provide us with needed additional capacity to meet the firm requirements of our growing customer base in the Carolinas,” said Piedmont CEO Thomas E. Skains. The company has two LNG facilities in North Carolina and one in Nashville, TN. Piedmont is also an equity partner in Pine Needle LNG, a joint venture with subsidiaries of Williams, SCANA Corp., Hess Corp. and the Municipal Gas Authority of Georgia. Pine Needle owns and operates an LNG peak storage facility near Greensboro, NC.

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