Shareholders of AGL Resources and Nicor Inc. have approved a merger that would create the nation’s largest gas-only distributor with a rate base of $3.8 billion that encompasses seven regulated gas distribution companies serving 4.5 million customers in Illinois, Georgia, New Jersey, Virginia, Florida, Tennessee and Maryland. The merger was announced in December (see NGI, Dec. 13, 2010). Nicor would merge with an AGL subsidiary in a deal with an enterprise value of $3.1 billion, including equity of $2.4 billion. Corporate headquarters would be in Atlanta with gas distribution headquarters in Naperville, IL. The merger must still be approved by the Illinois Commerce Commission, which regulates Nicor and establishes rates. The deal is expected to close by the end of the year.

Federal Energy Regulatory Commission Chief Judge Curtis Wagner Jr. has ordered Stingray Pipeline Co. LLC, which is seeking a large increase in its pipeline transportation rates, to continue settlement talks with its shippers [RP11-1957]. The next settlement conference will be Sept. 14. Stingray has proposed an across-the-board increase in its transportation rates of up to 500% in an attempt to make up for the load lost to locally delivered shale natural gas (see NGI, May 23). Stingray operates in the Gulf of Mexico and comes ashore in Louisiana, where it interconnects with several downstream pipelines — ANR Pipeline, Natural Gas Pipeline Co. of America and Tennessee Gas Pipeline. Stingray is one of several interstate gas pipelines that are filing Section 4 rate hikes for the first time in several years due to changing flow patterns on their systems brought on by the development of shale gas.

The Federal Energy Regulatory Commission (FERC) granted Duke Energy Indiana certificates authorizing it to construct and operate a pipeline across the border from Kentucky to Indiana to move natural gas to a coal-fired plant that Duke previously agreed to convert to gas-fired boilers. The Gallagher Station Pipeline Project includes plans to build 19.5 miles of 20-inch diameter pipeline extending from an interconnection with Texas Gas Transmission‘s mainline facilities near Kosmosdale, KY, across the Ohio River to Duke’s R. Gallagher Generating Station in Floyd County, IN. The pipeline would be used to deliver gas owned by Duke solely to its units at Gallagher station, and is therefore exempt from FERC’s open-access regulations and other reporting requirements. But Duke will not proceed with the project if it gets regulatory approval to instead acquire a stake in the gas-fired Vermillion Generating station in Vermillion County, IN.

SM Energy Co. has agreed with undisclosed buyers to divest a portion of its Eagle Ford Shale position for cash proceeds of about $225 million. The Denver-based producer is selling about 15,400 net acres in a detached block of acreage composed of all of its operated acreage in LaSalle County, TX, as well as an immaterial portion of adjacent operated acreage in Dimmit County, TX. As of year-end 2010, there was an immaterial amount of proved reserves booked for this acreage, the company said. Buyers would be entitled to about 12% of the takeaway capacity associated with SM Energy’s agreement with Eagle Ford Gathering LLC, a joint venture of Kinder Morgan Energy Partners LP and Copano Energy LLC (see NGI, July 12, 2010). The sale is expected to close in August and is subject to customary price adjustments, closing conditions and fees.

The Interior Department’s Bureau of Ocean Energy Management, Regulation and Enforcement (BOEM) has increased its inspection force for oil and natural gas rigs in the Gulf of Mexico (GOM) by more than 40% since April 2010, according to the agency. BOEM currently has 79 inspectors operating in the GOM compared with 56 inspectors on April 20, 2010, at the time of the Marcondo well blowout, and is in the process of hiring five more inspectors, an agency spokesman said. “As more inspectors are hired, we will be deploying multi-disciplinary inspection teams instead of individual inspectors, providing broader oversight to ensure that offshore operators are complying with federal regulations and conducting their operations in a safe and environmentally responsible manner,” said BOEM Director Michael R. Bromwich. In addition to on-the-job training, BOEM recently established the National Offshore Training Center and has developed the agency’s first formal training curriculum, which has been piloted with new BOEM inspectors.

The Pearl gas-to-liquids (GTL) plant in Ras Laffan Industrial City in the state of Qatar has sold its first commercial shipment of GTL gasoil, partners in the project Qatar Petroleum and Royal Dutch Shell plc said. Pearl GTL is claimed to be the largest energy project ever launched in the state of Qatar. The sale marks the start of production of GTL products when Qatar and Shell, which is the operator of the plant, begin to receive revenue from the project. In March gas began flowing through a subsea pipeline offshore Qatar into Pearl GTL. Production is expected to ramp up over the coming months. A second train is expected to start up before the end of 2011, and the plant is expected to reach full capacity by the middle of 2012.

The Louisiana Department of Environmental Quality (DEQ) must modify permitting for the discharge of produced water and other offshore oil and gas industry waste to the Gulf of Mexico to ensure “that the environmental costs of discharging produced water directly into the territorial seas of Louisiana are being minimized or avoided as much as possible…” an appeals court said. The decision by the Louisiana State Court of Appeal First Circuit upheld the position of the Louisiana Environmental Action Network that DEQ failed to protect the public from pollution and possible radiation poisoning when it issued oil and gas permits for exploration without proper monitoring of the impact on territorial waters, the group said.

The Federal Energy Regulatory Commission (FERC) has rejected the application of Turtle Bayou Gas Storage Co. LLC to build a salt dome gas storage facility and associated pipeline facilities northeast of Houston [CP10-481]. Turtle Bayou proposed to construct the two-cavern, 12 Bcf storage facility in Chambers and Liberty counties, as well as pipeline facilities that would extend from the storage facility to Natural Gas Pipeline Co. of America and Texas Eastern Transmission. The storage project would be capable of injecting gas at a maximum rate of up to 300 MMcf/d and withdrawing gas at a maximum rate of 600 MMcf/d, with the capability of cycling the capacity six times per year. Turtle Bayou is 100% owned by The Cornelia Lacey Wright Testamentary Trust, ASTO Overbrook Land LLC, The Pittman Charitable Trust, Entrust Administration of the Southeast FBO James Standridge IRA, and Entrust Administration of the Southeast FBO Vaughn P. Stough IRA.

In Georgia’s retail natural gas market about 15% of customers switched suppliers over the last year, and over the next 12 months another 15% will be in play, according to J.D. Power and Associates 2011 Georgia Retail Gas Provider Satisfaction Study. “Although Georgia has a mature retail gas market, the fact that nearly one-third of customers are switching providers — or contemplating switching — indicates ample opportunity for improving customer satisfaction,” said Chris Oberle, senior director of the energy practice at J.D. Power. “There is a clear connection between high levels of satisfaction and increased customer loyalty, both of which are essential for any Georgia gas retailer that wants to retain and grow its customer base.”

The proposed Jordan Cove liquefied natural gas (LNG) terminal and related pipeline project in Oregon are moving through required permitting processes, project manager Bob Braddock said. Braddock responded to calls by the Western Environmental Law Center (WELC) for the Federal Energy Regulatory Commission to conduct a supplemental environmental review of the Oregon project or else terminate it. Braddock said that Jordan Cove backers were “thinking about” the export option, but no firm decisions have been made yet. WELC contends that moving to an export facility would be a “clear significant change” in the project’s fundamental purpose, warranting at least supplemental National Environmental Policy Act analysis, “if not outright termination of the Jordan Cove” terminal project and an associated pipeline certificate.

State lawmakers in West Virginia have created a bipartisan 10-member panel to discuss and seek a consensus over Marcellus Shale regulatory reform.State Sen. Douglas Facemire (D-Braxton) told NGI that he has been asked to chair the panel, informally called the Marcellus Study Subcommittee, by Acting Senate President Jeffrey Kessler (D-Marshall). The subcommittee idea was formed during a meeting Wednesday of the Interim Joint Committee on Government and Finance (IJCGF). Meanwhile, early indications are that Democratic Gov. Earl Ray Tomblin may call a special session of the West Virginia Legislature sometime this summer to discuss redistricting, but Marcellus issues might not be on the agenda. The next 60-day regular session of the legislature is scheduled to begin on Jan. 11, 2012 and conclude on March 10, 2012. The legislature adjourned sine die on March 18.

As it works to craft best practices for hydraulic fracturing (hydrofracking), the U.S. Department of Energy (DOE) recently hosted a rare meeting in Washington — Washington, PA, not Washington, DC. The hearing marked the first time the Secretary of Energy Advisory Board Natural Gas Subcommittee (SEAB) has left the capitol to hear from stakeholders in Marcellus Shale country (see NGI, May 9). Hundreds attended the event to speak for and against hydrofracking. Proponents argued that the federal government should leave regulation to the states, while critics argued that hydrofracking should be kept on hold until it’s impacts are studied further. The SEAB subcommittee previously held a two-day hearing in Washington (see NGI, June 13).

Wyoming officials postponed making proposed changes to the way the state calculates royalty payments on oil and gas extracted from state lands. The State Board of Land Commissioners had been scheduled to make the first changes in the state royalty program in 30 years. The board, which includes Gov. Matt Mead and the state’s other four statewide elected officials, is to take up the issue again Aug. 4. The board has been considering extensive updates to the standard state oil and gas lease agreement since last year; it was last updated in the early 1980s. Changes would include more detailed oversight of the production costs the state allows industry to deduct from royalty payments.

Mountainview Energy Ltd. has acquired 4,566 net leasehold acres of Montana state lands in the south Alberta Bakken Shale play for approximately $340,000, an average price of $85/acre. The deal includes 1,381 acres in Pondera County, 1,905 acres in Teton County and 1,280 acres in Toole County. The acquisition brings the company’s total position in the shale play to approximately 75,000 net acres. Mountainview is focused on exploration, production and development of the Bakken and Three Forks shales in the Williston Basin and the south Alberta Bakken shale play.

Goodrich Petroleum Corp. has purchased leases totaling about 74,000 net acres in the Tuscaloosa Marine Shale (TMS) oil trend in Louisiana and Mississippi for an average $175 per net acre. The Houston-based company anticipates development to begin in early 2012. Geologists believe the TMS may to contain up to 7 billion bbl of oil and up to 3.5 Tcfe. The play covers 2.7 million acres in Amite, Pike and Wilkinson counties in Mississippi; and Avoyelles, Concordia, East Baton Rouge, East Feliciana, Livingston, St. Helena, Tangipahoa, Washington and West Feliciana parishes in Louisiana.

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