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Oklahoma City-based Quest Resource Corp. (QRCP) has completed its purchase of privately held PetroEdge Resources for $142 million, which will give Quest 78,000 net acres of Appalachian Basin acreage with estimated proved reserves of 99.6 Bcfe. PetroEdge's current net production was around 3.2 MMcfe/d. Simultaneous with the close, QRCP sold some of its producing wells, with estimated proved developed reserves of 32.9 Bcfe, and all of the current net production to its partnership, Quest Energy Partners LP, for $72 million. QRCP owns 100% of the general partner and a 57% limited partner interest in Quest Energy Partners. About 70,600 of the new leasehold is in the Marcellus Shale, including 41,200 net acres in Ritchie, Wetzel and Lewis counties of West Virginia and 22,200 net acres in Lycoming County, PA. Together with its existing acreage and development rights, QRCP would own the right to develop 122,600 net acres within the fairway of the Marcellus Shale and 7,300 net acres outside the fairway.

Using horizontal drilling techniques that have led to phenomenal success onshore in North America, BP plc plans to spend $1.5 billion to tap a hard-to-reach offshore reservoir in the Arctic waters of the Beaufort Sea. BP's Liberty project is buried beneath thousands of feet of rock on the Outer Continental Shelf about six miles off Alaska's northern coast. The project's remote location has stymied efforts by the London-based major to develop the field. However, refinements in drilling technology, including well bores that can pierce up to eight miles of shales and siltstone, now make the project viable. The reservoir is expected to yield about 100 million boe beginning in 2011. Included in the development costs is a specialized Arctic drilling rig to be built by Parker Drilling Co., as well as construction of several well bores centered on a man-made concrete island built earlier by BP. The extended-reach drilling plan is expected to yield a smaller environmental footprint and eliminate the need for offshore pipes in the frigid Beaufort waters.

FERC denied rehearing of a November 2007 order on remand in which it declared a portion of Transcontinental Gas Pipe Line's (Transco) pipeline network located onshore and offshore Louisiana to be transmission in nature and thus subject to agency jurisdiction. The case has a long, circuitous history at the Federal Energy Regulatory Commission (FERC) and in the courts. In August 2001 FERC ruled that the Transco facilities in question were unregulated, exempt gathering and could be spun down to affiliate Williams Gas Processing-Gulf Coast Co. However, the Commission reversed the order in April 2005, finding that Transco's facilities downstream of an interconnection with Jupiter Energy Corp. were transmission subject to FERC jurisdiction (see NGI, April 25, 2005). Transco challenged the decision in the U.S. Court of Appeals for the District of Columbia Circuit, which in December 2006 vacated the order and remanded it to FERC (see NGI, Dec. 25, 2006). In the latest order denying rehearing, FERC said it found that jurisdictional transmission was the primary function of Transco's 12.43-mile long, 24-inch diameter offshore lateral that receives gas from Jupiter Energy's facilities in Vermilion Block 22 and transports it to shore, where it enters Transco's other jurisdictional transmission facilities. The Commission held that the 12.43-mile offshore segment at issue was really part of what was one continuous 37-mile, 24-inch diameter pipeline, of which 24.63 miles were located onshore [CP01-368, CP01-369].

FERC approved Caledonia Energy Partners LLC's (CEP) proposal to expand to 16.9 Bcf its 11.7 Bcf storage facility located in Monroe and Lowndes counties in northeast Mississippi. The expansion is expected to increase maximum daily withdrawal capability to 477 MMcf/d from the current 330 MMcf/d. Caledonia proposed constructing and operating facilities in two phases in order to expand the Caledonia Field storage facility. In the first phase the company will develop the County Line Field, a depleted production reservoir approximately two miles northeast of the Caledonia Field, as an additional field capable of storing approximately 1.6 Bcf of working gas. Caledonia plans to construct one injection and withdrawal well with two horizontal lateral sections and about 1.8 miles of eight-inch diameter pipeline to connect the County Line Field to the Caledonia Field. In the second phase, Caledonia plans to install 10,000 hp of compression in a new compressor building within the existing compression station at the Caledonia Field. The Caledonia Field is fully subscribed for firm service through 2010. The facility directly interconnects with Tennessee Gas Pipeline's 500 Leg, which delivers 2 Bcf/d to markets in the Northeast, Southeast and Ohio Valley regions. The Caledonia storage facility went into service last year (see NGI, May 7, 2007). At start-up, the facility had an initial maximum withdrawal capacity of 330 MMcf/d and a maximum injection capability of 260 MMcf/d. FERC gave environmental clearance for CEP to convert what was then a nearly depleted natural gas reservoir into the Caledonia storage facility more than three years ago (see NGI, Feb. 14, 2005). Houston-based Enstor Inc., a unit of Spain's Iberdrola SA, said in May it would buy CEP from Tenaska Power Fund LP and other owners.

Westport, CT-based NGS Energy LP subsidiary Tres Palacios Gas Storage LLC said construction on its Matagorda County, TX, gas storage project is going according to plan and it has completed mechanical integrity testing (MIT) on the first of three caverns at the southeast Texas site. Facility construction has been under way since November when the project received approvals from the Federal Energy Regulatory Commission (see NGI, Sept. 24, 2007). The successful MIT is a milestone and is the penultimate step prior to placing the cavern into operation, the company said. The final step, which the company is expected to seek this week, requires FERC authorization to place facilities in service. This final approval, expected by the end of July, would enable Tres Palacios to begin cavern dewatering and commence firm storage operations on Sept. 1. The Tres Palacios facility would be interconnected with 10 interstate and intrastate pipelines, including: Florida Gas, Transco (near Station 30), Tennessee, NGPL, CTGS (Transco/Tennessee), HPL, TETCO, Enterprise Texas, Enterprise Texas Intrastate and Kinder Morgan Tejas. The project has been authorized to inject up to 1 Bcf/d and withdrawal up to 2.5 Bcf/d and when all three caverns are placed into service will offer 36 Bcf of working capacity. The company plans to hold a binding open season for firm capacity remaining at the facility beginning on July 28. For information, contact Mark McConnell at (203) 557-1000.

With mandated wildlife restrictions lifted, Denver-based Double Eagle Petroleum Co. has launched its Atlantic Rim drilling program in the Catalina Unit in Wyoming. Infrastructure construction has begun with drilling will follow, Double Eagle stated. The company has three drilling rigs contracted and on-site. In this phase of its program, Double Eagle expects to add 24 new producing wells, additional injection wells and expects to finalize the feasibility for the water treatment facility, said Chairman Richard Dole. "The additional injection wells will allow us to put on production the 10 wells already drilled but shut-in due to current water injection limitations," he said.

Fort Worth, TX-based XTO Energy Inc. has completed its acquisition of producing properties from Headington Oil Co. for $1.05 billion in cash and 11.7 million shares of XTO common stock for total consideration of $1.8 billion. The purchase includes 352,000 net acres of Bakken Shale leasehold in Montana and North Dakota. In addition, XTO agreed in separate transactions with undisclosed parties to acquire another 100,000 net undeveloped acres in the play and 400 boe/d of production for $115 million. "With these deals XTO now becomes a leading operator in perhaps the largest oil resource play in the nation, with more than 450,000 net acres," said President Keith A. Hutton. "Given the opportunities in the Bakken through horizontal drilling, multiple stimulations and enhanced recovery, we anticipate the potential for even more."

Chaparral Energy Inc., for 20 years a privately held producer, is moving to the public arena with an agreement to acquire natural gas producer Edge Petroleum Corp. in an all-stock transaction. Combined proved reserves would be 1.15 Tcfe, 56% weighted to crude oil and 67% proved developed. Edge, which is 86% weighted to natural gas, put itself on the market late last year (see NGI, Dec. 24, 2007). The Houston-based independent, which was formed in 1983, focuses its operations along the onshore Gulf Coast, primarily in South Texas. Edge also has substantial stakes in other gas-heavy plays across the United States, including stakes in Arkansas' Fayetteville Shale, Mississippi, Louisiana and southeast New Mexico. Combined production for Chaparral and Edge in the first three months of 2008 was 172 MMcfe/d. The combined proved reserves would be tilted toward the Midcontinent (66%), with another 17% of the reserves on the Gulf Coast, 10% in the Permian Basin and 7% in other onshore basins. Present value of the combined proved reserves at the end of 2007 was $3.3 billion. The reserve-to-production ratio combined is about 18.3 years. Chaparral CEO Mark Fischer would be chairman of the combined company; Chaparral's Joseph Evans would continue as CFO. The company's headquarters would remain in Oklahoma City; Edge's Houston office would serve as a regional office.

Range Resources Corp. has increased its leasehold in the Marcellus Shale by 20% to 850,000 net acres (1.4 million gross) and said it plans to drill 40 horizontal wells in the play by the end of this year. About 60% of Range's leasehold is located in the southwestern part of the play, mostly Pennsylvania; the remaining 40% is in the northeastern part of the play. Range plans to develop its Pennsylvania acreage first because the pipeline infrastructure is "better developed" there, it said. Range and MarkWest Energy Partners LP in June agreed to develop infrastructure in the area, and Range noted that work is under way on three infrastructure projects. Range said it has secured firm transportation capacity for 150 MMcf/d and "is holding discussions to expand this capacity as the play develops." Gas-in-place in Range's core holdings is estimated to range from 70 Bcf to 150 Bcf per section, and Range revised upward its estimate of the unrisked reserve potential of its leasehold position to 15-22 Tcfe.

A union dispute over proposed pension fund changes at Nevada Power Co. upstaged a Nevada Public Utilities Commission (PUC) meeting with consumers in Las Vegas. The meeting had been called to discuss the prospects of higher natural gas prices and their impact on retail utility electric rates for Nevada Power and the other Sierra Pacific Resources' utility, Sierra Pacific Power Co. Regulators called the session also to explain a potentially confusing situation for the immediate future in which retail electricity rates have been lowered due to deferred rate adjustments. Both PUC and Nevada Power utility representatives tried to explain the situation at the workshop while the major of the attendees were utility employee union members who were more concerned about the utility's effort to allegedly cut worker pension benefits by up to 70%. The thrust of the PUC's message was that even though Nevada Power retail rates are set to drop a little more than 5% beginning Oct. 1, the decrease will be short lived because natural gas prices for Nevada are expected to soar this winter. The PUC tried to stress that so far consumers have been shielded from wholesale gas price hikes, but that will end this winter. Members of the International Brotherhood of Electrical Workers Local 396 flooded the public meeting to state their opposition to the utility's proposed pension changes. As a result, for the first time in 18 years a bitter labor dispute threatened the reliability of future electricity supplies in the air conditioning-dependent Southern Nevada region, one of the fastest growing areas in the nation, according to the Las Vegas Review-Journal.

NorthWestern Energy Corp., the South Dakota-based energy holding company, said that the U.S. Bankruptcy Court for the District of Delaware has approved its settlement with Magten Asset Management, Law Debenture Trust Company of New York and holders of quarterly income preferred securities, marking the end of the last major disputed claim in its 2003 Chapter 11 proceeding. Under the agreement, a payment of $23 million will be allocated between Magten, Law Debenture and holders of the preferred securities. The $23 million will be paid out of a disputed claims reserve that was established after the company filed for bankruptcy protection in September 2003. NorthWestern CEO Michael Hanson said the $23 million settlement was the last major claim related to his company's bankruptcy case, from which it emerged in late 2004. At the time of the emergence, NorthWestern said a total of 4,409,100 shares, or 13.5% of the new common stock, was being held in reserve pending resolution of contingent or otherwise unliquidated claims. Hanson said NorthWestern will be reimbursed for $4 million in legal fees and expenses under a separate agreement. After the distributions under the settlement agreement have been completed, there will be a supplemental distribution of all of the remaining assets in the disputed claims reserve to unsecured creditors and debt holders in Class 7 and Class 9 under the company's reorganization plan approved by the court and creditors when it emerged from Chapter 11, other than the holders of the quarterly income preferred securities (QUIPS). The value of the supplemental distribution to each of these unsecured creditors and debt holders is not presently known, NorthWestern said.

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