The National Association of Publicly Traded Partnerships (NAPTP) recently warned its members that the Obama administration is considering corporate-level taxation of pass-through entities, such as master limited partnerships (MLP). Such a change could have significant consequences for the midstream energy sector where numerous companies are MLPs. The warning came in a confidential memo circulated to NAPTP members, which was leaked to Reuters. NAPTP Executive Director Mary Lyman would not share the memo with NGI but confirmed its distribution. In an e-mail to NGI, Lyman said, “At this point, there is no public proposal yet; we have simply heard that there is a proposal under discussion as part of corporate tax reform that would tax a broad section of pass-through entities, including MLPs — everything with gross receipts over $50 million.” The administration is still considering tax reform options, according to a White House spokeswoman.

Four Republican governors whose coastal areas hold some of the biggest domestic offshore reserves — Texas, Louisiana, Alaska and Mississippi — are urging other coastal governors to join a coalition to ensure that they can play a bigger role in future decisions about oil and gas development. The Outer Continental Shelf Governors Coalition was launched by Texas Gov. Rick Perry, Louisiana Gov. Bobby Jindal, Alaska Gov. Sean Parnell and Mississippi Gov. Haley Barbour. The new coalition, they said, would work to “foster an appropriate dialogue between the coastal states and the [Obama] administration and ensure that future actions are done with adequate state input.”

With a 16% worldwide market share, Russia’s Gazprom remains the “undisputed leader” of global natural gas producers, followed by ExxonMobil Corp., with a 4% share, according to a report by Societe Generale (SG). Gazprom in 2010 managed to increase gas production by 10%, thanks to rising demand in the Former Soviet Union. ExxonMobil also built its gas output last year — by 31% — because of its acquisition of gas shale producer XTO Energy Inc. in late 2009. However, the producer “still produces only a quarter of what Gazprom produces,” noted analysts. Royal Dutch Shell plc and BP plc each captured 3%, while PetroChina International Ltd., Total SA and Chevron Corp. each had a 2% share. U.S. producers ranked included Encana Corp. at 12; Chesapeake Energy Corp. at 14; Devon Energy Corp. at 15; Anadarko Petroleum Corp. at 16; Apache Corp. at 18; and EOG Resources Inc. at 20.

The U.S. Forest Service has withdrawn its decision to not permit oil and natural gas drilling in the Bridger-Teton National Forest in the Wyoming Range. In January U.S. Forest Supervisor Jacqueline A. Buchanan issued a 17-page decision to prohibit drilling on 70 square miles of the affected Wyoming Range (see NGI, Jan. 31). In the reversal, she said a more thorough analysis needed to be conducted. The decision had been appealed by Stanley Energy Inc., Western Energy Alliance, Wold Oil Properties Inc. and the Sublette County, WY, commissioners. The appellants said the decision was inconsistent with the National Forest Management Act, Administrative Procedures Act, the Federal Onshore Oil and Gas Leasing Reform Act, the Endangered Species Act and the National Environmental Policy Act. Those appeals no longer will be processed. Wyoming Rep. Cynthia Lummis and other members of the Congressional Western Caucus also wrote the Forest Service in April asking it to reverse Buchanan’s decision.

A bill (SB 655) that would change the name of the Railroad Commission of Texas (RRC) to the Texas Oil and Gas Commission, as well as make other reforms, was approved by the Texas House of Representatives. The legislation is likely headed for a conference committee with the state Senate, which earlier approved a measure that would make more sweeping changes to the RRC, most notably reconfiguring the body to have one elected commissioner instead of the current three. The one-commissioner proposal is generally opposed by the state’s oil and gas industry (see NGI, April 18). The House measure, which was approved 101 to 43, would retain three elected commissioners; however, it would require sitting RRC commissioners to step down before they seek another elected office. The House measure also would limit fund-raising activities of sitting commissioners and calls for one of the three commissioners to be elected chair of the commission. Both the House and Senate measures would make the regulatory body self-funding from fees on industry, eliminating the RRC’s reliance on the state’s general fund.

The Federal Energy Regulatory Commission approved Questar Pipeline Co.‘s request to extend its southern transmission system, giving shippers access to natural gas supplies in the Uintah Basin of Utah. Questar’s southern transmission system includes the existing ML (Main Line) 104 extension, which comprises about 151 miles of 24-inch diameter pipeline. The certificate order gives Questar Pipeline the go-ahead to extend the ML 104 line by 24.6 miles eastward from Green River to Questar’s Fidlar Compressor Station, essentially completing a loop of the ML 40 line between Green River and Fidlar. The extension would add 160,000 Dth/d of incremental capacity, with 144,000 Dth/d already subscribed under firm agreements, said Questar Pipeline, a subsidiary of Salt Lake City-based Questar Corp. Questar said it negotiated a new agreement with QEP Marketing Co. for 20,000 Dth/d, while three other shippers — Anadarko Energy Services Co., EOG Resources Inc. and El Paso Marketing LP — extended their firm transportation agreements for a total of 94,000 Dth/d. A fifth company, Questar Gas Co., chose to continue as a shipper but at a reduced capacity — 30,000 Dth/d from its existing 50,000 Dth/d. Construction is expected to begin in June, with completion targeted by Nov. 1.The Commission granted Questar Pipeline’s request for a predetermination that it may roll the costs of the extension project, which the pipeline estimated at $46.1 million, into its existing rates in a future Section 4 rate case.

Buoyed by a new gas processing plant and 10 Marcellus Shale wells drilled in the first quarter, Rex Energy Corp. is increasing its capital budget by $26.7 million for the year to support increased drilling activities. Of its new $175.4 million budget, $134 million would pay for 34 gross (22 net) operated and 20 gross (eight net) nonoperated wells in the Marcellus, where the Pennsylvania company holds a majority interest in Butler County leases and a minority interest in other western Pennsylvania properties. The remainder would go to projects in Illinois and the Rockies, where the company also drills. Rex produced nearly 28 MMcfe/d during the first quarter, up 47% from 19 MMcfe/d during the first quarter of 2010. The production was 51% natural gas and 49% liquids. Although Rex generated $23.4 million in operating revenue during the first quarter, up from $16.7 million during the first three months of 2010, the company posted a $7.5 million net loss (minus 17 cents/share), down from a $2 million (5 cents/share) gain in the first quarter of 2010.

Removing a moratorium on new drilling in Pennsylvania state forests is not a priority, the acting secretary of the Department of Conservation and Natural Resources (DCNR) said during recent state Senate confirmation hearings. “The moratorium is still in effect on any additional drilling on forest lands, and we’re not having any discussions about that right now,” Richard Allan told the Pennsylvania Senate Environmental Resources and Energy Committee. “We are looking at protecting the surface impact, and updating our monitoring of the companies that are doing drilling. That is our primary focus right now.” Although 700,000 acres of state forests have been leased for drilling, 800,000 remain unavailable since then-Gov. Ed. Rendell imposed a moratorium last October. The committee unanimously approved Allan’s confirmation.

The Bureau of Land Management (BLM) generated nearly $1 million at an auction from the sale of oil and gas leases on about 13,820 acres in Wyoming. The BLM said receipts totaled $998,089 for 13 parcels comprising 13,821.96 acres. The average bid/acre was $70.57 while the average bid/parcel was $75,035.54. Additionally, the highest bid/acre was $195 and the highest bid/parcel was $218,400, both by Denver-based Contex Energy Co. for a 1,200-acre parcel. By comparison, the minimum price required by the federal government was $2/acre. Successful bidders paid $975,462 for their actual bids but also paid an additional $20,742 in rental payments ($1.50/acre for the first five years, $2/acre in years six through 10), and $1,885 in administrative fees (a one-time fee of $145/parcel). Almost half of the bid and rental receipts will go to the state of Wyoming. The BLM will offer 74 more parcels on Aug. 2 in Cheyenne. The parcels total 83,038.15 acres and are in Big Horn, Campbell, Crook, Hot Springs, Natrona, Niobrara, Park and Washakie counties.

Results from Talisman Energy‘s North American shale plays continue to be positive, but the impact of increased taxes in the United Kingdom and a loss on held-for-trading financial instruments and the timings of liftings led to negative overall earnings in 1Q2011. Shale volumes averaged approximately 450 MMcfe/d in 1Q2011 compared with 110 MMcfe/d in 1Q2010, and shale now accounts for about half of Talisman’s North American natural gas production, the Calgary-based producer said. Talisman has a diverse portfolio of international exploration and production interests, but in North America the company is focused largely on the Montney, Eagle Ford and Marcellus shales. Talisman reported a $326 million (minus 32 cents/share) loss in 1Q2011 compared with a $371 (36 cents/share) profit in 1Q2010, despite a 14% increase in production from ongoing operations. Talisman, which previously used Canadian dollars in its financial reports, switched to U.S. dollars with its 1Q2011 report.

San Diego-based Sempra Energy’s two utilities, Southern California Gas Co. and San Diego Gas, which operate an intrastate gas transmission system in the southern half of California, face the prospect of additional hydrostatic pressure testing on several hundred miles of transmission pipeline to verify past testing to support current operating pressures, according to the California Public Utilities Commission (CPUC) Consumer Protection and Safety Division. The CPUC, in part reacting to Pacific Gas & Electric‘s pipeline explosion in San Bruno, CA, last September, is asking Sempra utilities to validate the maximum allowable operating pressure of each pipeline segment passing through high-consequence, or heavily populated, areas.

Senior Calpine Corp. officials said heavy rainfall in the West is producing potential record hydroelectric supplies that are impacting natural gas-fired power plant operations in California. “Hydroelectric production more than doubled in the first quarter, compared with the same period in 2010,” cutting the amount of hours for running gas-fired plants said Calpine COO Thad Hill. Run hours were down, but profits were higher quarter over quarter on the fewer hours. “We don’t see any long-term implications from this; it was just a matter of extraordinary weather conditions,” Hill said. He expects a return to more “near-normal weather conditions” in 2012-13. For the second quarter and the remainder of this year, Hill said above-normal hydro conditions will continue. A lot of California’s water will run out in the second quarter, Hill said. But he noted that the excess hydro in the Pacific Northwest will continue into the summer and some of that power could come down to California, where Calpine has its large concentration of gas-fired and geothermal power plants.

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