CenterPoint Energy Gas Transmission Co. (CEGT) has entered into two separate firm transportation agreements to transport Chesapeake Energy Corp.'s Haynesville Shale natural gas. CEGT, the interstate pipeline subsidiary of CenterPoint Energy Inc., owns and operates Line CP, a 1.55 Bcf/d pipeline that extends from Carthage, TX, to the Perryville Hub in Louisiana. Under the agreements with Chesapeake Energy Marketing Inc., CEGT will transport gas on both a forward-haul basis to CEGT's Perryville Hub and on a backhaul basis to Carthage. The 27-month backhaul agreement provides for firm transportation volumes to ramp up to 500 MMcf/d. The long-term firm forward-haul agreement provides for 230 MMcf/d of capacity, effective when CEGT's Phase IV Line CP compression expansion goes into service, currently projected for April 2010. CEGT said its application for the Phase IV expansion has been filed with the Federal Energy Regulatory Commission (FERC). To fulfill the forward-haul requirements of the agreement, CEGT said it would add a compressor to each of Line CP's Westdale Compressor Station in Red River Parish, LA, and Vernon Compressor Station in Jackson Parish, LA. The expansion would add 274 MMcf/d of capacity to CEGT's Line CP, bringing the total year-round capacity to more than 1.8 Bcf/d. CEGT previously held an open season for expansion of Line CP's capacity (see NGI, June 30, 2008). It also is evaluating proposals for the remaining 44 MMcf/d capacity in the Phase IV expansion and said it plans to execute definitive service agreements before the project is placed in service in 2010.
Erosion in natural gas and oil prices and continued uncertainty in the markets led onshore producer Penn Virginia Corp. to reduce 2009 capital spending and lower annual production guidance. Capital spending now is set at $210-220 million, compared with $225-250 million announced earlier this year. Penn Virginia expects production to hit 48-50 Bcfe, or 131.5-137 MMcfe/d. It previously set annual output guidance at 51-52 Bcfe. The spending cuts will consist primarily of reduced well completion activity in Mississippi and reduced drilling and completion activity in the Midcontinent region and in South Louisiana. In its Lower Bossier Shale holdings in East Texas, Penn Virginia determined that the Agnor No. 6-H, a recently completed well drilled to test the formation in the outer perimeter of its acreage position in Harrison County, TX, was unsuccessful. However, on the far western side of acreage the Hatley No. 15-H well was completed "and early indications appear positive," the company said. To date Penn Virginia has hedged 71 MMcf/d of gas output, or more than 60% of expected output this year. It also has hedged 500 b/d of crude output, or around 30% of its expected annual volumes.
The coalbed methane (CBM) play in the Atlantic Rim of Wyoming continues to pay dividends for Denver-based Double Eagle Petroleum Corp., which reported a record 230% increase in 4Q2008 production over the same period of 2007. The company, which is 95% weighted to natural gas, set a record for annual production in 2008, ending the year with output totaling 6.7 Bcfe, or 123% higher than the 3.0 Bcfe produced in 2007. Most of last year's gains were from drilling success in the company's Catalina Unit in the Atlantic Rim, some of which it operates, as well as its stake in some nonoperated Pinedale Anticline properties. Double Eagle in 2008 drilled 24 production wells and six injection wells in the Atlantic Rim, and five new wells were on production at year's end. One well was determined to be a dry hole, but the remaining 18 wells are expected to be ready to ramp up by the end of March. At the nonoperated Sun Dog and Doty Mountain units in the Atlantic Rim last year, Double Eagle participated in 65 new production wells, and those are expected to be ready by July. The independent also participated in drilling 24 new wells in the Pinedale Anticline; those wells also are expected to be completed this year. Proved reserves at year-end 2008 were estimated at 88.9 Bcfe, compared with 73.7 Bcfe at the end of 2007. The average price to estimate year-end 2008 proved reserves was $4.51/MMcfe versus $5.99/MMcfe at the end of 2007. This year Double Eagle's capital spending plans range between $10 million and $20 million. Most of the focus will be to enhance output from producing wells in the Atlantic Rim and from drilling new development wells in the Pinedale Anticline and Waltman area of the Wind River Basin. However, the company plans to "continually evaluate the market," and if conditions change, it said it may modify its budget.
In a move intended to focus more attention on unconventional natural gas plays, Calgary's Talisman Energy Canada and affiliate Fortuna LP are selling legacy properties in southeastern Saskatchewan and Daniels County, MT, for C$720 million. The properties are being sold to Crescent Point Resources LP and TOG Partnership, an affiliate of Tristar Oil & Gas Ltd. (see related story). The sale includes 610,000 net acres of land, with nearly three-quarters of the property in Saskatchewan, including fee title lands. The properties have around 8,500 boe/d net production as well as Talisman-owned and -operated infrastructure. An independent, NI-51-101 compliant reserves report by AJM Petroleum Consultants estimated that net to Talisman, the properties' proved reserves total 20.1 MMboe, with proved plus probable reserves estimated at 34.1 MMboe. The sale, expected to close by June 1, is subject to regulatory approval.
Colorado's nonpartisan Office of Legislative Legal Services (OLLS) caused an uproar in the state legislature after it suggested repeal of one of the new rules that will govern future natural gas and oil drilling in the state. The Colorado Oil & Gas Conservation Commission (COGCC) formally approved a revamped rules package for the energy industry in late 2008, and most of the rules are slated to take effect beginning in April and May. Before their enactment, however, several legislators have attempted to dull their impact both because of the downturn in the economy and because of criticism from the energy industry. An opinion by the OLLS led to some maneuvering between opposing groups in the state legislature after the legal services office stated that one of the most controversial rules should be removed. That rule, to require producers to consult with the Colorado Division of Wildlife (DOW) on ways to protect habitat before obtaining a permit to drill, has been hotly contested for months. It was the intent of the legislature "to place the duty to consult on the Division of Wildlife, not on operators," wrote legislative attorney Thomas Morris in his memorandum to the state legislature's Committee on Legal Services. The rule, he said, conflicts with the 2007 statute and should be repealed. Democratic Gov. Bill Ritter, who has long defended the revised rules package, vowed to keep the rules as they are written. And David Neslin, acting director of the COGCC, said the commission is examining ways to make the legal opinion a moot issue.
The Federal Energy Regulatory Commission issued a favorable environmental assessment (EA) to Atmos Pipeline and Storage LLC, an affiliate of of natural gas distribution provider Atmos Energy Corp., to build a nearly 25 Bcf high-deliverability storage facility in Fort Necessity in northeastern Louisiana. The proposed facility would provide about 15 Bcf of working gas capacity and 9.75 Bcf of cushion gas in three newly developed salt caverns in the Fort Necessity Salt Dome, which is located 12 miles south-southwest of the City of Winnsboro in Franklin Parish, LA. In addition to the caverns, the project application -- which was filed at the end of 2008 -- calls for the construction of pipeline and compression facilities (see NGI, Nov. 17, 2008). The storage site would be capable of receiving and injecting gas at a maximum rate of up to 500 MMcf/d and withdrawing and delivering gas at a maximum rate of up to 1.5 Bcf/d, according to the FERC EA. It would interconnect with Tennessee Gas Pipeline, Columbia Gulf Transmission, ANR Pipeline and Regency Energy Partners LP, an intrastate pipeline.
Nevada's two major private-sector electric utilities, now operating as NV Energy for the northern and southern portions of the state, filed their latest rate changes with the Nevada Public Utilities Commission (PUC). Decreases for power and natural gas retail utility rates are being sought in the north, while combined annual fuel cost adjustment and general rate adjustments in the south seek a net $77 million annual electric revenue increase. Reno-based NV Energy's former Sierra Pacific Power Co. filed with the PUC to decrease its electric rates by 2.7% and its natural gas retail rates overall by 4.7%. Like its southern Nevada counterpart, the northern NV Energy utility filed for what are called "deferred energy rates" to adjust for the costs the utility had to pay for fuel supplies during the past 12-month period. In this case, the current electric and gas rates in effect were more than the utility needed to cover its fuel costs. In the south, for the former Nevada Power Co. now operating as Las Vegas-based NV Energy, fuel charges the past 12-month period exceeded the rates it now has in effect. "For 2008, the company's actual fuel costs to generate electricity were higher on average than the costs reflected in current customer rates," a spokesperson said. "This occurred due to a steep run-up in energy prices during the first half of 2008, and the rapid increase in energy prices resulted in a $77 million under-collection in rates." Any changes eventually authorized by the state regulators would be effective Oct. 1, a utility spokesperson said.
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