The Federal Energy Regulatory Commission gave Arlington Storage Co. the green light to begin service at its Thomas Corners Storage Field in southern New York state on an interim basis. The Thomas Corners field, a converted natural gas production field in Bath, NY, has a total working capacity of approximately 7 Bcf, along with maximum withdrawal and injection capabilities of 140 MMcf/d and 70 MMcf/d, respectively. In May 2008 Arlington Storage said it sold all the available capacity in its storage project. The storage field, which FERC approved in late 2008, interconnects with Tennessee Gas Pipeline’s Line 400 and Columbia Gas Transmission’s A-5 line, which accesses the Millennium Pipeline (see NGI, Dec. 22, 2008). Inergy acquired Arlington Storage in late 2007.

Transcontinental Gas Pipe Line (Transco) and Florida Gas Transmission (FGT) have filed an application with the Federal Energy Regulatory Commission to build a pipeline to connect Transco’s Mobile Bay Lateral with a liquefied natural gas (LNG) import terminal being developed in Pascagoula, MS. Known as the “Pascagoula Expansion,” the project calls for the construction of 15.5 miles of 26-inch diameter pipeline connecting Gulf LNG Energy LLC’s Clean Energy terminal to the Mobile Bay Lateral. It would have the capacity to deliver approximately 810,000 Dth/d and would be located in portions of Mobile County, AL, and Jackson County, MS, at the Bayou Casotte portion of the Port of Pascagoula. The connecting pipeline is being jointly developed by Transco, a Williams pipeline, and FGT with each party holding an undivided interest. The 1.5 Bcf/d Gulf LNG Clean Energy import terminal, which was approved by FERC in February 2007, is targeted for service in fall 2011 (see NGI, Feb. 19, 2007).

AGL Resources subsidiary Jefferson Island Storage & Hub LLC (JISH) has negotiated a tentative agreement with Louisiana officials, which if approved would resolve the pending lawsuit between the parties over a disputed Lake Peigneur mineral lease that would allow the company to expand its existing natural gas storage facility. A public hearing on the subject is to be held by the Louisiana Department of Natural Resources on Sept. 24. The state’s mineral board must approve the agreement in order for it to be valid, and a decision could come as early as this fall. Located near the Henry Hub, JISH currently consists of two salt dome storage caverns with 7.5 Bcf of working gas capacity, along with capacities of 720,000 MMBtu/d for withdrawal and 360,000 MMBtu/d for injection. In 2006 Louisiana’s then-Gov. Kathleen Blanco pulled the company’s lease and halted the expansion following several missed royalty payments to the state, and local concerns about possible contamination of Lake Peigneur and the aquifer that provides water to the local community (see NGI, Sept. 11, 2006). On Nov. 21, 1980, the 1,300-acre lake collapsed after a drilling rig operated by Texaco punctured a salt dome that was being used for salt mining by Diamond Crystal Salt Mine. Once the salt dome was penetrated, lake water began to drain into the salt dome, forming a giant whirlpool that sucked down the drilling rig, 11 barges, 1.5 billion gallons of lake water, 70 acres of a nearby botanical garden, a parking lot, and reversed the flow of the Delcambre canal, temporarily creating the biggest waterfall in Louisiana.

The Commodity Futures Trading Commission (CFTC) and the United Kingdom’s Financial Services Authority (FSA) have agreed to strengthen cross border supervision of energy futures markets. At the same time the CFTC extended the new rules to ICE Futures Europe. The CFTC said it and the FSA would immediately work toward implementing strengthened surveillance over linked energy contracts including, where appropriate, through: (1) enhanced direct access rights to trade execution and audit trail data; (2) mutual on-site visits of exchange operators; (3) sharing exchange regulations and notices; (4) sharing disciplinary notices; and (5) the framework to consider the coordinating emergency action. At the same time the conditions were extended to apply to ICE Futures Europe as part of a revised “No Action” letter under which the overseas exchange is allowed to offer trading terminals in the U.S.

In preparation for the upcoming winter season, NiSource Gas Transmission & Storage (NGT&S) unit Columbia Gulf Transmission is holding an open season for capacity to deliver gas to Texas Eastern Transmission LP in St. Landry Parish, LA, the pipeline said. NGT&S is considering modifying or constructing new assets to facilitate the delivery of up to 176,000 Dth/d to Texas Eastern, with an anticipated in-service date of Nov. 1. Columbia Gulf is soliciting binding offers for firm contracts sourced from receipt points on the Columbia Gulf mainline near Delhi, LA, and delivered to the Texas Eastern St. Landry interconnect. A bid package is at Bids are due by noon CDT Sept. 9. For information contact Joshua Gibbon at (713) 267-4718 or at

Energy Transfer Partners LP (ETP), three affiliates and Federal Energy Regulatory Commission enforcement litigation staff have submitted a proposed settlement that resolves all claims that ETP manipulated physical natural gas prices at key Texas trading points from late 2003 to 2005. The settling parties, which also included Energy Transfer Co., ETC Marketing Ltd. and Houston Pipe Line Co., have asked that the joint offer of settlement be deemed uncontested, certified by an administrative law judge (ALJ) and submitted to FERC for approval. FERC has the option to approve or reject the proposed settlement in full or in part. Given the “sensitive information” in the offer of settlement, the parties asked that the agreement be treated as confidential — only until FERC approves the agreement “in its entirety without modification.” In July 2007 FERC accused ETP and affiliates of manipulating physical natural gas prices at the Houston Ship Channel (HSC) and Waha trading hub on various dates from December 2003 through December 2005 (see NGI, July 30, 2007). FERC proposed potential civil penalties for ETP totaling $82 million — $79 million for the alleged manipulations at the HSC and $3 million for the alleged manipulations at Waha and Permian trading hubs. FERC also proposed disgorgement of $69.9 million, plus interest, in unjust profits. In March FERC approved a joint offer of settlement filed by its enforcement staff and ETP’s Oasis Pipeline and affiliates, which essentially closed the enforcement case against the companies without levying any financial penalties (see NGI, March 2).

A subsidiary of Plains All American Pipeline LP (PAA) will pay $220 million for Vulcan Capital‘s 50% interest in PAA Natural Gas Storage, the companies said. The purchase price includes $90 million cash, 1.9 million PAA common units valued at $90 million and deferred contingent cash consideration up to $40 million. The transaction will give PAA 100% of the natural gas storage business and related operating entities, which will be accounted for on a consolidated basis. At closing, PAA will repay the joint venture’s outstanding project finance debt using joint venture cash and borrowings under its revolving credit facility. As of June 30 the joint venture had approximately $450 million of debt and approximately $52 million of cash. PAA management intends to recommend to its board of directors an increase in the partnership’s quarterly distribution level to 92 cents/unit effective with the November 2009 distribution.

Chief Oil & Gas LLC, which was the No. 2 natural gas producer in the Barnett Shale until it sold its leasehold three years ago, is taking on Canada’s Enerplus Resources Fund to help develop half a million acres in the Marcellus Shale. Enerplus agreed to pay $406 million ($3,500/acre) to acquire a 30% stake in 552,000 acres (gross) held by Chief affiliates and a limited partnership managed by Tug Hill Inc. The transaction would give Enerplus an average 21.5% nonoperated working interest in about 116,000 net acres. Privately held Chief would continue to operate the properties, and as part of the transaction, midstream services would be provided by affiliate Chief Gathering LLC. Most of the leasehold interest held by Chief and Tug Hill is in the northeast and southwest portions of Pennsylvania, with some spillover into West Virginia and Maryland. In the past two years Chief has drilled 31 Marcellus Shale wells, 10 vertical and 21 horizontal. Total gross production from the first wells placed into production is 8.7 MMcfe/d. Three drilling rigs now are contracted, but under the enhanced development plan, seven more rigs would be added to the play by 2012.

The Minerals Management Service (MMS) took in 76% less in high bid money during its Western Gulf of Mexico (GOM) lease sale held in August than it did during a sale of drilling rights off the coast of Texas last year, which agency officials attributed to lagging natural gas prices, less participation by independent producers and an “undercurrent” of litigation. Lease Sale 210 received high bids of $115.4 million, significantly less than the $487.2 million in high bids from Lease Sale 207 in the western GOM in 2008. The highest bid ($28.1 million) was by BP Exploration and Production for Block 96 in Keathley Canyon. Total bids were $145.2 million, compared to more than $600 in last year’s Lease Sale 207. Twenty-seven producers participated in Lease Sale 210, submitting 189 bids on 162 blocks covering 924,486 acres. One of the areas offshore Texas that drew significant attention was Alaminos Canyon, where Chevron U.S.A., BP Exploration, Focus Exploration and ConocoPhillips bid for acreage. BP Exploration gobbled up most of the leases that were offered in the Keathley Canyon area. Substantial interest also was seen in the East Breaks area, particularly by ConocoPhillips and BP Exploration. Estimates are the lease sale could result in the production of 242-423 million bbl of oil and 1.64-2.64 Tcf of natural gas.

Calgary-based Crescent Point will spend close to C$924 million in three transactions to build a substantial position in southern Saskatchewan. With the three acquisitions, the company lifted its 2009 year-end production guidance by 16%. In the largest transaction, Crescent Point agreed to acquire privately held Wave Energy Ltd. for C$665 million. Wave is said to be the largest leaseholder in the Lower Shaunavon Formation in southwest Saskatchewan with a leasehold of more than 150 net sections of land, including 132 net sections that are undeveloped. Crescent Point also closed one agreement and entered into a second worth a total of C$258.2 million cash to acquire property in southeast and southwest Saskatchewan from undisclosed sellers.

The Federal Energy Regulatory Commission issued a certificate to Southern Natural Gas pipeline to expand its system to provide more natural gas to a power generator in Georgia. The South System Expansion III (SSEIII Project) would provide up to 375,000 Dth/d of firm capacity for Southern Company Services Inc. (SCS) to serve affiliate Georgia Power Co.’s proposed expansion of its Plant Jack McDonough electric generation facilities near Atlanta. The Commission also approved Southeast Supply Header’s (SESH) and Southern Natural Gas’ application to expand Southern’s capacity on the jointly held portion of SESH’s pipeline system. The first 117.19 miles of the SESH pipeline are owned by SESH and Southern. The proposed joint pipeline expansion (JPE Phase II) would increase Southern’s capacity on that segment to 500,000 Dth/d from 140,000 Dth/d. The SSEIII expansion, along with the JPE II project, is designed to cater to Georgia Power’s plans to add two 840 MW natural gas-fueled generators at its Jack McDonough facility in Cobb County, GA. Georgia Power proposes to retire its two coal-fired units totaling 540 MW of capacity and replace them with the gas-fueled units. Southern and SCS have entered into a long-term firm precedent agreement to provide the 375,000 Dth/d in gas to the power plant in three phases, beginning in January 2011 through May 2032.

Progress Energy Carolinas plans to shutter three coal-fired generating units near Goldsboro, NC, and build 950 MW of gas-fired combined-cycle generation at the site as their replacement. The company is relying on a streamlined certification process for the new gas units recently enacted by the state legislature. As proposed, the new plant would increase the amount of electricity that can be produced at the site by about 550 MW. The company filed for a certificate of public convenience and necessity from the North Carolina Utilities Commission, seeking approval to build the gas-fired unit, which would replace the 397 MW of coal-fired generation at the H.F. Lee Plant in Wayne County, NC. The project represents an investment of about $900 million and is expected to be in service in early 2013. The project also will involve construction of a natural gas pipeline to fuel the new generating units. The pipeline, plans for which have not been completed, would provide the additional benefits of extending large-volume gas supply more deeply into eastern North Carolina, Progress said.

The Bureau of Land Management’s (BLM) quarterly oil and natural gas lease sale held in Utah in August went off without a hitch, netting $1.07 million in bonus bids to develop acreage in the central and northeastern parts of the state. BLM said it sold 27 of the 37 parcels that were offered, totaling 34,648 acres of federal land overseen by its Filmore, Moab, Price and Vernal field offices. In addition to the bonus bids, the sale generated $51,984 in rental fees and $3,780 in administrative fees, for a total of $1.129 million in total revenues from the lease sale. Douglas Chasel of Salt Lake City submitted the highest total bid per acre — $925 on parcel 72 containing 320 acres overseen by the Vernal field office — as well as the highest total bid per parcel — $296,000 on parcel 72. Given Utah’s record for disputed leases sales, the leases offered in Tuesday’s auction “were heavily screened and went through a very long check list,” said BLM spokeswoman Megan Crandall. Only one protest was filed — by the Theodore Roosevelt Conservation Partnership — and it was subsequently denied, she noted. The Interior Department still is conducting its review of 77 parcels in Utah, which were auctioned last December and then subsequently withdrawn in February 2009, (see NGI, June 15). It recommends that reinstatement of certain leases may be appropriate following the review.

Colorado Republican Senate Minority Leader Josh Penry, who has indicated his plans to run for governor in 2010, and fellow Republican state Rep. Cory Gardner have asked the Colorado Oil and Gas Conservation Commission (COGCC) to extend the allowed time to hold a natural gas and oil drilling permit to provide “long-term certainty” for companies willing to invest in the state. In an open letter to COGCC Executive Director Dave Neslin, the assemblymen requested an extension to two years from one year in the state’s application for permit to drill (APD) program, with an option to extend the permit for an additional year beyond that. Referring to a recent survey of oil and gas executives who ranked Colorado as the “least attractive state for oil and gas investment” (see NGI, June 29), Penry and Gardner said they would “continue to oppose, and work to repair significant aspects of the new oil and gas rules” adopted by the state earlier this year. If COGCC decides to reject the request, the lawmakers said “it is our intention to take legislative action this coming session to address this situation.” Neslin, a Gov. Bill Ritter appointee, has said he supports extending the state permit period to mirror BLM permits, which for federal lands are valid for two years.

The California Public Utilities Commission (CPUC) plans to study the potential impact of electric vehicles (EV) on the state’s major energy utilities and the electric and natural gas infrastructures. The CPUC would examine what tradeoffs may need be made to ensure energy infrastructure reliability and climate change goals. CPUC President Michael Peevey said regulators’ first order of business will be to address rate design that promotes alternative vehicle use. The California Energy Commission (CEC) also said it plans to spend $100 million in 2010-2011 under a mandate from 2007 state law AB 118 to help reduce gasoline-powered transportation. In its 2008-09 and 2009-10 investment plans, which totaled $176 million, the CEC allocated $46 million for EVs, $43 million for natural gas vehicles, $40 million for hydrogen, $12 million for ethanol, $6 million for renewable diesel/biodiesel and $2 million for propane.

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