FERC issued a favorable environmental review of MarkWest Pioneer LLC's proposal to build a natural gas pipeline that would allow producers in the Woodford Shale area of Oklahoma to interconnect with the Midcontinent Express Pipeline, which is currently under construction. "Approval of the proposed project, with appropriate mitigating measures, would not constitute a major federal action significantly affecting the quality of the human environment," FERC staff said in the environmental assessment on the project [CP05-404]. Denver-based MarkWest Pioneer's proposed Arkoma Connector Pipeline would extend approximately 50 miles from an interconnect with the company's gathering system in the Woodford Shale production area in southeastern Oklahoma to an interconnect with Midcontinent Express in Bennington, OK. The project also calls for the construction of approximately 19,500 hp of total compression at two compressor stations and associated facilities in Coal, Atoka and Bryan counties in Oklahoma. The proposed Arkoma Connector would have the capability to deliver 638,000 Dth/d out of the Woodford Shale area to the Bennington area. The pipeline is scheduled to begin operation in the second quarter of 2009, subject to FERC approval. MarkWest held a binding open season through April 21 for capacity on the Arkoma Connector (see NGI, March 24).
Chesapeake Energy Corp. has taken steps to spin off a subsidiary to hold its midstream natural gas assets -- and allow it to build pipeline infrastructure in some of its productive shale plays. The Oklahoma City-based producer in November indicated it wanted to launch a master limited partnership (MLP) to hold midstream assets (see NGI, Nov. 12, 2007). Chesapeake requested permission from those holding more than $2 billion of the company's outstanding senior notes due between 2013 and 2016 to allow the debt to be carried in a new subsidiary. Chesapeake now is restricted from carrying debt for the parent company in the notes due in that period, the Securities and Exchange Commission Form 8-K filing indicated. Following the solicitation, which is scheduled to be completed by Friday (Aug. 22), "Chesapeake intends to transfer certain of its midstream assets to a newly formed group of subsidiaries and designate such subsidiaries as unrestricted subsidiaries under each of the indentures," the filing stated. Chesapeake's spin-off, either as an MLP or privately held subsidiary, initially is expected to hold existing assets in the Barnett Shale, the Fayetteville Shale and within the Midcontinent.
Houston-based EV Energy Partners LP (EVEP) agreed to pay multiple sellers a combined $202.7 million for a set of natural gas-weighted properties in the San Juan Basin, Midcontinent, Texas and West Virginia. Estimated total proved reserves are 88 Bcfe, and daily production is averaging 12.9 MMcfe/d. More than 440 producing wells are included, and the properties are 94% proved developed. The assets combined are 58% weighted to gas, 18% to oil and 24% to natural gas liquids (NGL). In the first transaction, EVEP agreed to pay EnerVest Ltd. $142.1 million to acquire some San Juan Basin assets, in which EnerVest holds a 77% average working stake. Proved reserves are estimated at 65.5 Bcfe, and 85% are proved developed. Current production averages 9.1 MMcfe/d, weighted 58% to gas. The West Virginia assets, also to be acquired from EnerVest for $5.8 million, include proved reserves estimated at 2.3 Bcfe. Current production from 86 wells averages 380 Mcfe/d. Production is 100% weighted to gas and 75% is operated. The Midcontinent package. which EVEP agreed to acquire from EnCap Investments LP for $38.8 million, includes properties in Oklahoma, the Texas Panhandle and Kansas. Proved reserves are estimated at 13.7 Bcfe and are 100% proved developed. Average production from 128 producing wells is 2.8 MMcfe/d, weighted 78% to gas. An undisclosed seller also agreed to sell a 100% operated leasehold located in Eastland County, TX, for $16 million. Estimated proved reserves are 6.5 Bcfe; the properties are 72% proved developed. Current output from 58 wells averages 600 Mcfe/d, which is 90% weighted to oil. EVEP expects to close the transactions by mid-September.
Canadian Superior Energy reported a second "significant" natural gas discovery offshore Trinidad that it said could produce at a rate of 200 MMcf/d. The resource potential was estimated at up to 2 Tcf. Canadian Superior took control of the Intrepid Block, located about 60 miles off the east coast of Trinidad, about three years ago. The latest gas find was in the Bounty test well, which was drilled to about 17,300 feet. Initial tests indicate that the Bounty is "one of the best natural gas wells offshore Trinidad," said Chairman Greg Noval. The discovery would be the second natural gas discovery Canadian Superior and its partners have made from the Intrepid Block this year, he noted. Victory, the first well, was tested earlier this year and estimated to contain up to 1.1 Tcf of gas reserves with flow from two formations of about 150 MMcf/d (see NGI, Jan. 21). Canadian Superior holds a 45% working stake in the Intrepid Block and is the operator. BG International Ltd., a subsidiary of BG Group plc, holds a 30% working interest and Challenger Energy Corp. holds the remaining 25% stake. Challenger is 20% owned by Noval and his wife.
Inergy subsidiary Inergy Midstream LLC has agreed to buy 100% of the membership interest in US Salt LLC, a mining and salt production company in Schuyler County, NY, between Inergy's Stagecoach and Steuben County natural gas storage facilities. US Salt produces food-grade salt products and bulk salt for chemical feedstock. The deal will bring Inergy usable salt cavern capacity for gas storage. After receiving necessary regulatory approvals, Inergy expects to immediately begin developing approximately 5 Bcf of available salt cavern capacity and have that capacity operational in fall 2010. The transaction provides Inergy with "a long-term pipeline of high-return storage development projects in the heart of the Northeast natural gas distribution infrastructure," said Inergy CEO John Sherman. "In addition, this transaction is yet another example of the successful execution on our plan to build an integrated natural gas storage and transportation hub in the Northeast." The solution mining process used by US Salt creates salt caverns that can be developed into gas storage capacity, and US Salt operations are near Empire Connector Pipeline, New York State Electric and Gas' intrastate pipeline network, Millennium Pipeline, Teppco's liquefied petroleum gas pipeline and storage system and Inergy's own Thomas Corners project, the company said. Inergy expects to immediately market the facilities in an open season. Inergy said it will spend about $191 million to acquire US Salt and develop the initial 5 Bcf of storage. The acquisition will be funded with a combination of borrowings from Inergy's revolving credit facility and Inergy LP common units issued directly to US Salt. Inergy expects to generate earnings before interest, taxes, depreciation and amortization from the combined salt production and gas storage operations of approximately $28.5 million on a run rate basis by the end of fiscal 2010. The acquisition is expected to close by the end of August, Inergy said.
North America's first liquefied natural gas (LNG) transshipment and storage terminal proposed for Grassy Point at the head of Placentia Bay in Newfoundland and Labrador has been found not to be a threat to the environment if appropriate mitigation measures are taken. Canadian Environment Minister John Baird made the finding and referred the project back to Transport Canada and Fisheries and Oceans Canada. Project backer Newfoundland LNG is a joint venture of North Atlantic Pipeline Partners LP and LNG Partners LLC. It filed plans for the project with federal and provincial regulators in late 2006. The project would include eight 160,000-cubic-meter storage tanks, three jetties with berthing facilities capable of mooring 265,000-cubic-meter LNG cargo ships, and a tugboat basin along one of North America's deepest ice-free ports. It would not include LNG regasification facilities. The project, which is intended to accommodate up to 400 vessels per year, was slated to begin construction in summer 2007, but construction was delayed and is expected to begin late this year or in early 2009. Newfoundland LNG said it believes the province offers "unique and strategic geographical advantages," particularly for LNG suppliers in the North Sea and Barents Sea regions but also for suppliers in the Persian Gulf. For more information on the project, go to www.newfoundlandlng.com. A copy of the environmental assessment decision statement is available on the Canadian Environmental Assessment Registry at www.ceaa.gc.ca, reference number 07-03-26546.
Dallas-based oil and natural gas company Gulf Onshore Inc. has formed a Pennsylvania operating company to target opportunities in the natural gas-rich Marcellus Shale region. Newly formed Shale Gas Operating Ltd. plans to seek authority from the Pennsylvania Department of Environmental Protection's Bureau of Oil and Gas Management to operate oil and natural gas wells in the state, Gulf Onshore said. Gulf Onshore said it has been in talks with agents of two property owners, with a combined 3,200 acres in northern Pennsylvania, to develop these properties. There are various estimates of the potential of the Marcellus Shale region which extends through the Appalachian Basin from Tennessee to southern New York. The U.S. Geological Survey in 2002 estimated that the Marcellus contained approximately 1.9 Tcf. Pennsylvania State University's Terry Engelder pegged the Marcellus reserves at 168 Tcf, but his figures are unconfirmed (see NGI, April 7). Gulf Onshore holds interest in four producing wells in Texas and interests in several oil and gas leases in Throckmorton and Shackleford counties, TX. The company was formerly known as Brighton Oil & Gas. It changed its named to Gulf Onshore in April.
The U.S. Department of Energy (DOE) and its Southwest Regional Partnership (SWP) are testing a way to permanently store carbon dioxide (CO2) and simultaneously recover natural gas in a large coalbed methane (CBM) area in the San Juan Basin of New Mexico. In a six-month demonstration, the SWP plans to inject up to 35,000 tons of CO2 in the basin near Navajo City, NM. Unlike other enhanced CBM recovery projects, the demonstration could show how to permanently store the greenhouse gas through geologic carbon sequestration. Many coalbeds in the United States are saturated with methane but the gas is difficult to extract because methane chemically binds to coal. CO2 also has a tendency to bind to coal. Injecting CO2 into the coalbed essentially would displace the methane and make the gas easier to produce, according to the DOE. The San Juan Basin was selected because the coals are considered exceptionally permeable, at least compared with other regional coalbeds, with "favorable geology, high methane content, available CO2 from nearby power plants, low capital and operating costs, and well developed natural gas and CO2 pipelines," the DOE noted.
Peak-day shortfalls on two pipeline laterals of Intermountain Gas could occur in 2011 and 2012, according to a current supply-demand analyses in an integrated resource plan (IRP) filed with the Idaho Public Utilities Commission (PUC). Boise, ID-based Intermountain experienced 5% growth in its residential and commercial customer groups last year and now serves more than 300,000 customers in southern Idaho. The utility estimates that future growth will average about 4% annually. Industrial load consumes 43% of its total annual sendout. "Many of the company's customers are served directly off the Williams Northwest Gas Pipeline coming into Idaho from Wyoming generally following the Snake River in southern Idaho," the PUC said. Intermountain owns several laterals coming off the main Williams interstate pipeline, and two of the three largest laterals are where the utility sees possible problems during peak-demand periods in the future.Without adding a new compressor station by 2011 on one lateral -- Sun Valley -- the utility could experience "natural gas delivery deficits on some days of peak use," the IRP said. Similarly, there could be shortfalls on another lateral -- Canyon County -- because of a current bottleneck. Intermountain is considering adding a parallel pipeline in the area to boost capacity. The PUC said the utility's resource plan anticipates continued "steady" growth during the next five years that ultimately it feels is manageable. The PUC will will take comments on the utility's IRP through Sept. 4.
Sioux Falls, SD-based NorthWestern Energy Corp. announced a change at the top with CEO Michael Hanson, 49, resigning and former Montana Public Service Commission (PSC) member Bob Rowe, 53, being named to replace him. NorthWestern's three-state utility operations increasingly have been dominated by its Montana distribution and transmission holdings. Hanson will remain in a consulting role at the utility holding company, but no other plans for his future endeavors were given, nor any reason for his sudden departure from a position he has held the last three years, covering most of the period since the company emerged from Chapter 11 bankruptcy protection in November 2004. NorthWestern Chairman E. Linn Draper touted Hanson's "leadership and significant contributions" and emphasized that he thought Rowe was an "excellent leader to carry on." Draper said the former Montana regulator was well known to the board and the company's management team. A company spokesperson said there were no other changes contemplated in the NorthWestern management team.
The review of Avista Utilities natural gas and electric rate increase settlement begins later in August, and public hearings are expected to be completed in September, the Idaho Public Utilities Commission (PUC) announced. Spokane, WA-based Avista said that an all-party settlement was reached in the case, which was originally filed in early April. If approved, the new rates would be effective Oct. 1. Stakeholders, including PUC staff, agreed to increases in electric and gas utility rates averaging 11.98% and 4.7%, respectively. This compares to Avista's original filing seeking increases of 16.7% and 5.8% for electric and gas utility retail customers, respectively. The PUC said the settlement attempts to cut about $9 million from Avista's original requested annual revenue requirement, lowering it to $23.16 million.
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