OAO Rosneft has given BP plc until Monday (May 16) to negotiate an acceptable alternative to their historic share swap agreement announced in January. The “groundbreaking strategic alliance” to explore Russia’s largely unexplored Arctic region, considered key to BP CEO Bob Dudley’s plan to right the company, would give state-controlled Rosneft around 5% of BP’s ordinary voting shares in exchange for BP receiving 9.5% of Rosneft shares (see NGI, Jan. 17). However, BP already had joint venture (JV) exploration agreements with Alfa-Access-Renova (AAR), a Russian oligarch consortium, in TNK-BP. The group of Russian billionaires disputed the Rosneft alliance, and in March an arbitration tribunal extended an injunction of the agreement (see NGI, March 28). AAR in essence won its case before the tribunal, which said it would allow BP to move forward with the Rosneft share swap only if it agreed to cede its Arctic JV to TNK-BP.

The heads of the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corp. (NERC) are combining their investigations of the causes and aftermath of the natural gas end-use customer shutoffs and natural gas and electric infrastructure freeze-ups in the midst of a severe winter temperature drop in late January and early February in the Southwestern states. Various state and federal probes have been launched since the extreme cold in the Southwest (Feb.1-3) which caused well freeze-offs and compressor failures resulting from weather-driven power outages. The cold eventually curtailed gas deliveries to thousands of customers in New Mexico, Arizona and Southern California supplied through El Paso Natural Gas and Transwestern Pipeline (see NGI, Feb. 23). FERC and NERC have been sharing information but conducting separate inquiries into the matter, but all of that will change, and the respective staffs will issue a joint report. The combined findings and recommendations will be presented to FERC and the Board of Trustees for NERC.

A joint venture formed by Houston-based Southern Union and BG LNG Services LLC, a subsidiary of BG Group plc, has filed an application with the Department of Energy (DOE) to export liquefied natural gas (LNG). In its filing with the DOE, the joint venture is seeking “long-term authorization to export domestically sourced liquefied natural gas from [Southern Union’s] liquefied natural gas import facility in Lake Charles, LA,” he said. Before it can export LNG, the company will have to construct liquefaction facilities, according to Southern Union. The joint venture seeks to export 2 Bcf/d over a 25-year period, beginning on the earlier of the date of the first export or 10 years from the approval of the application. The announcement came more than a year after Southern Union received approval from the Federal Energy Regulatory Commission to place into service its Trunkline LNG Infrastructure Enhancement Project (see NGI, March 22, 2010).

The Federal Energy Regulatory Commission has given Golden Pass LNG Terminal LLC the green light to place into service its Phase II import terminal operations. Phase II commissioning activities and performance tests of its liquefied natural gas (LNG) terminal were completed in late April, according to the Houston-based company. This phase entailed the cooling down of three LNG holding tanks, as well as the commissioning of pipeline and associated infrastructure facilities within the terminal, a spokesman said. The terminal’s Phase I commissioning and performance tests were completed in early March. This phase, which began last October, included the commissioning of two LNG holding tanks. With the commissioning phases now completed, Golden Pass has the capability to send out up to 2.5 Bcf/d of regasified LNG. The $1 billion terminal, which is considered one of the largest in the world, is located in Sabine Pass, TX, just south of Port Arthur. It opened in 2010 after three years of construction. The terminal is owned 70% by Qatar Petroleum International, the international arm of Qatar Petroleum, with the remainder owned by ExxonMobil Corp. and ConocoPhillips.

The Federal Energy Regulatory Commission issued a favorable environmental assessment (EA) of Equitrans LP’s Sunrise Pipeline project [CP11-68] to expand its natural gas pipeline system that would deliver Marcellus Shale gas to markets in the Mid-Atlantic and Northeast regions. The Sunrise project calls for the construction of facilities in Greene County, PA, and Wetzel County, WV, including 44.4 miles of small-diameter pipeline; one new compressor station in Jefferson Township in Greene County; five interconnect sites; and other facilities. The project would increase Equitrans’ capacity to the Mid-Atlantic and Northeast by about 313,560 Dth/d, according to the FERC notice. Pending approval by FERC, Pittsburgh-based Equitrans said it expects to begin construction of the Sunrise line this summer, with in-service targeted for the summer of 2012.

Algonquin Power & Utilities Corp. (APUC) affiliate Liberty Energy Utilities Co. will pay about $124 million for Atmos Energy Corp.‘s regulated gas distribution assets in Missouri, Iowa and Illinois, the companies said. The transaction is subject to conditions including state and federal regulatory approval and is expected to occur in 2012. Liberty intends to make offers of continuing employment to all current employees, according to Ontario-based APUC. The utilities provide local distribution service to about 57,000 gas customers in Missouri, 23,000 in Illinois and 4,000 in Iowa. Atmos said the customers are predominantly residential and commercial and represent less than 3% of its three million natural gas customers. The deal will reduce the number of states in which Atmos operates from 12 to nine, with about 80% of its remaining utility operations in Texas, Louisiana and Mississippi.

State Sen. Jim Brewster, a Democrat from southwest Pennsylvania, plans to introduce a 7% tax on natural gas extraction to fund education, environmental programs and local infrastructure projects. Brewster said his proposal, yet to be introduced, would be modeled on a bill that passed the House in late 2010 but stalled in the Senate and ultimately died after the midterm elections (see NGI, Oct. 25, 2010). The primary difference, Brewster said, is that his bill would fund education cuts proposed in the current budget, and would offer tax credits to operators that hire locally and invest in community projects. Brewster estimates his proposal would raise $280 million per year, half going to education and the remainder split between environmental protection programs, including a special emergency account, and local governments. Brewster also plans to introduce legislation creating a mandatory training program for well-site workers.

The Interior Department approved a deepwater Gulf of Mexico supplemental exploration plan (SEP) for Shell Offshore Inc. following the completion of a site-specific environmental assessment for deepwater oil and natural gas exploration. Interior’s Bureau of Ocean Energy Management, Regulation and Enforcement (BOEM) said it found no evidence that Shell Offshore’s proposed actions would significantly affect the quality of the human environment. As a result, the agency determined that an environmental impact statement was not required and issued a “finding of no significant impact,” which allowed the exploration plan to be approved. Shell Offshore’s SEP, which augments the original exploration plan submitted prior to the Deepwater Horizon rig explosion, includes five new proposed exploratory wells in approximately 7,160 to 7,259 feet of water, as well as three previously approved wells about 72 miles offshore Louisiana.

Shell Oil Co. and some of its affiliates have agreed to pay the United States $2.2 million to resolve claims that they violated the False Claims Act by underpaying royalties owed on natural gas produced from federal leases. It is the latest settlement in a long-running whistle-blower case and resolves claims that the Shell companies improperly deducted from royalty values the cost of boosting gas to pipeline pressures and improperly reported processed gas as unprocessed gas to reduce royalties. The settlement arises from a lawsuit filed by Harrold Wright under the False Claims Act (see NGI, Jan. 4, 2010). The case is U.S. ex rel. Wright v. Chevron USA Inc. et al., 5:03-CV-264.

Linn Energy LLC plans to acquire a 40% interest in oil and gas properties from two privately held companies — Tulsa-based Panther Energy Co. LLC and Perryton, TX-based Red Willow Mid-Continent LLC — as it looks to expand in the Anadarko Basin and capitalize on Panther’s expertise in horizontal drilling. The deal is valued at $220 million on land totaling 140,000 gross acres (44,000 net acres) in the liquids-rich Cleveland play. The properties are in Ochiltree and Lipscomb counties, TX, in the Texas Panhandle, and in neighboring Ellis County, OK. Net production from the properties is estimated at about 2,700 boe/d from about 170 producing wells, while proved reserves are about 10 million boe (45% oil and 37% proved developed). The Southern Ute Growth Fund is the majority owner and funding partner of Panther and the parent company of Red Willow. The deal is expected to close by June 1.

EQT Corp. is selling its Big Sandy Pipeline in eastern Kentucky to Spectra Energy Partners LP for $390 million in cash. Most of the sale proceeds are targeted for Marcellus and Huron shale development. Big Sandy, a 70-mile-long, 20-inch diameter gas pipeline, entered service in 2008 (see NGI, April 18, 2008) and has capacity of 171,000 Dth/d. The transaction is expected to close during the third quarter of 2011. EQT said it will use most of the pipeline sale proceeds to develop its 520,000 Marcellus acres, including associated midstream gathering; and to develop its Huron reserves.

DCP Midstream LLC plans to build a 110 MMcf/d gas processing plant and high-pressure gathering system in Weld County, CO, to augment its position in the Denver-Julesburg (DJ) Basin. The $270 million LaSalle plant will include capability to service producers in the Niobrara Shale in the north and west of DCP’s existing footprint. It is scheduled to be in service in mid-2013, the Denver-based company said. The plant is being funded through DCP Midstream’s existing debt facilities and operating cash. DCP Midstream, which is a 50-50 joint venture of Spectra Energy and ConocoPhillips, currently owns and operates seven processing plants with a combined capacity of 400 MMcf/d in the DJ Basin.

California Assemblyman Bob Wieckowski, chairman of the lower house’s Environmental Safety and Toxic Materials Committee, has introduced a bill (AB 591) seeking to require public disclosure of any chemicals used in oil/gas hydraulic fracturing (fracking). Environmental groups in the state are supporting the bill as a means of providing more transparency in the energy production sector. Wieckowski said new technologies and drilling practices, such as fracking, now allow oil companies to access previously unavailable oil/gas reserves in California. AB 591 passed its first legislative hurdle in late April, clearing an initial committee vote by 5-3. Wieckowski said tight gas sands in Northern California and “the richest oil shale deposits in the United States” are located in Central and Southern California. Backers of the legislation also point to California’s ranking as the fourth largest oil/gas producer in the United States.

Spokane, WA-based Avista Corp. is sitting atop snowpack and water levels more than 150% of normal, setting up the prospect for abundant hydroelectric supplies and less-than-normal natural gas-fired electric generation for its combination utility Avista Utilities. As a result, revenues were up and fuel costs down for the first quarter, Avista reported in a quarterly earnings conference call. Avista reported increased quarter-over-quarter net income with 1Q2011 profits of $41.9 million, or 73 cents/diluted share, compared with $28.8 million, or 52 cents/diluted share, for the same period last year. In response to a question from analysts on the abundant hydro pushing down the price of natural gas, CEO Scott Morris said demand for gas in the region right now is “much lower” than normal. “Certainly with the amount of snowpack and runoff that we expect this spring you are going to see most or all of the gas plants shut off so there is some definite supply-demand impact,” he said.

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