Led by increases of 9% (0.37 Bcf/d) in the Federal Offshore Gulf of Mexico and 1.9% (0.37 Bcf/d) in other states, natural gas production in the Lower 48 states increased 1.4% (0.96 Bcf/d) in October compared with the previous month, according to the Energy Information Administration (EIA). The increases were partially explained by wells coming back online that had been shut-in due to Tropical Storm Lee and drilling activity in the Marcellus Shale play, according to EIA’s Monthly Natural Gas Production Report. Offshore production, which has also have suffered from the moratorium on drilling there that followed the blowout of BP plc’s Macondo well (see see NGI, April 26, 2010), remains well below year-ago levels. Gross production from the Federal Offshore Gulf of Mexico was 4.49 Bcf/d in October, a nearly 25% decline from 5.95 Bcf/d in the year-ago period, according to EIA. Overall, U.S. production climbed 1.3% (1.05 Bcf/d) in October from September to 80.10 Bcf/d and were up 6.4% (4.85 Bcf/d) from the year-ago period, according to EIA. Wyoming posted a gain of 2.9% (0.19 Bcf/d); Alaska climbed 1.0% (0.09 Bcf/d); Texas was up 0.5% (0.12 Bcf/d); and Oklahoma remained unchanged at 5.37%. At the same time, Louisiana experienced a 0.7% decline (minus 0.06 Bcf/d) and New Mexico posted a decline of 0.8% (0.03 Bcf/d).

The federal government has conditionally approved Shell Gulf of Mexico Inc.‘s revised exploration plan proposing to drill up to six exploration wells in Alaska’s Chukchi Sea beginning in the 2012 drilling season. But before it can move forward with exploratory drilling in the Chukchi Sea, the Houston-based producer must satisfy the conditions of the Bureau of Ocean Energy Management’s (BOEM) approval, as well as obtain approvals from the Bureau of Safety and Environmental Enforcement (BSEE) regarding the oil spill response plan and well-specific applications for permit to drill. In addition, Shell must obtain necessary permits from the Environmental Protection Agency, U.S. Fish & Wildlife Service and National Marine Fisheries Service.

Texas Eastern Transmission LP (Tetco), American Electric Power and Chesapeake Energy Marketing Inc. are proceeding with the Ohio Pipeline Energy Network (OPEN), an expansion of the Tetco pipeline system to connect Marcellus and Utica shale gas supplies in Ohio to existing markets. The OPEN project involves 70 miles of new pipelines adding 1 Bcf/d of capacity to serve local distribution companies, industrial users and power generation. The group plans to hold a binding open season in the first quarter and plans to bring the system into operation by November 2014. Although the route of the pipeline is still under discussion, it likely would start in Carroll County and run south to the Tetco mainline. The project is expected to cost $500 million, but could grow depending on the interest.

Quicksilver Resources Inc. and Kohlberg Kravis Roberts & Co. LP (KKR) plan to jointly construct and operate natural gas midstream services to support producers operating in Canada’s Horn River Basin. Fort Worth, TX-based Quicksilver, which would operate the facilities, agreed to dedicate current and future production from its Horn River acreage to the partnership. It also contributed an existing 20-mile, 20-inch gathering line and compression facilities, as well as 10-year contracts for gas deliveries into those facilities to create the joint venture. KKR paid $125 million to Quicksilver in exchange for a half-stake. Under the agreement KKR would carry Quicksilver’s future development costs for the initial treating facility in exchange for preferential distributions to KKR. The facility is expected to lower Quicksilver’s costs to get its produced gas to market by about 80 cents/Mcf, the company said. The area of mutual interest established for the midstream business covers about 30 million potential acres in the Horn River, Liard and Cordova basins, which would include third-party transportation and processing infrastructure, as well as agreements.

D’Lo Gas Storage LLC (DGS) has filed an application to build a facility in the D’Lo Salt Dome underground salt formation in south-central Mississippi [CP12-39]. The Louisiana-based company, which is 100% owned by D’Lo Holdings LLC, proposes to construct three caverns with a combined working gas capacity of 24 Bcf, and pipeline interconnections to existing interstate and intrastate pipelines in Mississippi’s Simpson and Rankin counties. The connections would be with Boardwalk Pipeline, Kinder Morgan Midcontinent Express Pipeline, Southern Natural Gas, Southcross Pipeline and Gulf South Pipeline. DGS has asked the Federal Energy Regulatory Commission to issue a final order by July so it can begin construction by next winter. Storage services could be available in late 2014. An open season is planned in March.

The Federal Energy Regulatory Commission has issued a favorable environmental assessment to Sabine Pass Liquefaction LLC to build facilities to liquefy and export natural gas at the existing Sabine Pass liquefied natural gas (LNG) import terminal in Cameron Parish, LA [CP11-72]. The liquefaction project would be capable of processing an average of 2.6 Bcf/d of pipeline-quality natural gas from the Creole Trail Pipeline, which interconnects with the Sabine Pass terminal. It would have the ability to export approximately 16 million metric tons of LNG annually via tankers. Sabine Pass Liquefaction and the Sabine Pass terminal are subsidiaries of Houston-based Cheniere Energy Partners LP. The project is being designed and permitted for up to four modular LNG trains, each with a nominal capacity of about 4.5 million metric tons per year. The liquefaction project is expected to be constructed in phases, with each LNG train commencing operations about six to nine months after the previous train (see related story).

The National Oceanic and Atmospheric Administration (NOAA) published a draft environmental impact statement describing how offshore oil and natural gas activities in the U.S. Beaufort and Chukchi seas could affect marine mammals and the Alaska Native communities that depend on them for subsistence. Measures to lessen potential effects of oil and gas activity also are examined in the document. Among other things the draft document looks at measures NOAA could adopt over the next five years as it issues incidental take authorizations under the Marine Mammal Protection Act in the area. In addition it would contribute to decisions made by the Department of the Interior‘s Bureau of Ocean Energy Management (BOEM) on issuing permits for seismic surveys. Officials with the NOAA and the BOEM plan to travel to eight North Slope communities to hold public hearings in late January and February. The times and locations of the public hearings in Barrow, Kaktovik, Kivalina, Kotzebue, Nuiqsut, Point Hope, Point Lay and Wainwright are to be announced in the Federal Register.

Pennsylvania Gov. Tom Corbett signed a bill giving state regulators authority over gathering lines. The Pennsylvania Public Utility Commission (PUC) is the “state agent” of the U.S. Pipeline and Hazardous Materials Safety Administration, a designation shared by the regulatory body in every natural gas producing state except Alaska. With the authority the PUC may inspect and investigate pipelines that are not public utilities. Because the law only allows the PUC to enforce federal regulations, it does not give the agency oversight over pipelines in sparsely populated corners of the state, known as “Class I” gathering lines. But the law does allow the PUC to hire at least 12 additional inspectors to ease the increased workload, with the positions paid for by a combination of federal funds and industry fees.

The Jordan Cove liquefied natural gas (LNG) project in Oregon won approval by the state’s Department of State Lands to develop an access channel and multi-purpose vessel slip on the North Spit of Coos Bay, boosting the hopes of the Port of Coos Bay, which is an supporter of the project for its potential job creation and value to the port’s resurgence. The LNG project, including its Federal Energy Regulatory Commission-certified 230-mile transmission pipeline, still has state and local air and water permitting to complete. Under the state land permit, the slip at Coos Bay will accommodate two berthing areas, one for Jordan Cove LNG, and a second for other cargo traffic.

Mexico’s state-owned petroleum company, Petroleos Mexicanos (Pemex) plans to accept bids for a new round of private exploration and production (E&P) contracts in early January. Pemex said the E&P contracts up for bids are for work in six of its mature fields. Four of the fields are onshore (Altamira, Panuco, San Andres and Tierra Blanca) while two are offshore in the shallow waters of the Gulf of Mexico (Arenque and Atun). Pemex said the contracts would be awarded in June.

Southwestern Energy Co. said it will spend slightly less in 2012 in the Fayetteville Shale while it nearly doubles spending in the Marcellus Shale in Pennsylvania. Overall, Southwestern’s 2012 capital program is pegged at $2.3 billion, up from about $2.1 billion in 2011. Production is expected to climb about 15% from this 2011. In the Marcellus Shale Southwestern has increased its acreage position to 181,500 net acres in northeastern Pennsylvania. The company plans to begin 2012 drilling with two operated rigs and end the year with four operated rigs and plans to participate in 80-85 gross wells, all of which will be operated. In the Fayetteville it plans to participate in 580-590 gross wells, 490-500 of which will be operated. About 475-480 Bcf of targeted gas production is expected to come from the Fayetteville Shale, up from 433-435 Bcf in 2011. About 60-65 Bcf of 2012 targeted gas production is projected to come from the Marcellus, up from 20-22 Bcf in 2011. Fayetteville spending is forecast to be $1.25 billion in 2012, down from a projected $1.32 billion in 2011. Spending in Appalachia is forecast to be $530 million, up from a projected $290 million in 2011.

Denver-based Petroleum Development Corp. (PDC) is selling its Permian Basin assets to Concho Resources Inc. for about $175 million to focus on the Wattenberg Field in Colorado, the Marcellus Shale in West Virginia and the Utica Shale in Ohio. The deal is expected to close in 1Q2012. PDC’s capital budget for 2012 is expected to be $284 million and includes $198 million of development spending, 85% of which will be invested in the Wattenberg Field for an expanded horizontal Niobrara drilling program, refractures and recompletions, and nonoperated projects, and $86 million for investment in acquisitions, exploration, leasehold and miscellaneous expenditures.

Recent production test results from the first two horizontal wells completed in the Tuscaloosa Marine Shale (TMS) in Louisiana have been encouraging and there is likely more good news to come, according to the Louisiana Department of Natural Resources (DNR) Secretary Scott Angelle. He noted that Devon Energy Corp. reported an initial test of 120 b/d in its first completed horizontal TMS well in East Feliciana Parish. Indigo Minerals, with a well in Rapides Parish, reported an initial test of 540 b/d. Indigo calls the play the “Louisiana Eagle Ford.” The Eagle Ford play is best known in Texas, but in Louisiana, the Eagle Ford and the Tuscaloosa Marine Shale are considered part of the same overall trend.

Copano Energy LLC and Magellan Midstream Partners LP have formed of a joint venture (JV) to deliver Eagle Ford Shale condensate to Corpus Christi, TX. The JV plans to make use of new and existing pipeline infrastructure. Double Eagle Pipeline LLC would construct and own about 140 miles of pipeline to connect an existing 50-mile pipeline segment owned by Copano to Karnes, Live Oak, McMullen and LaSalle counties in Texas. The system will enable delivery of condensate to Magellan’s terminal in Corpus Christi. The initial capacity of the pipeline is to be 100,000 b/d. Double Eagle also will construct a new truck unloading facility along the pipeline near Three Rivers, TX, for deliveries of condensate destined for Corpus Christi.

The number of fatalities stemming from natural gas pipeline accidents in 2010 more than doubled to 21 from nine in the prior year, according to estimates released by the National Transportation Safety Board (NTSB). Natural gas pipelines accounted for all but one of the total 22 pipeline deaths in 2010, the NTSB said. One death was attributed to hazardous liquid line last year. In contrast the NTSB reported a total of 13 pipeline-related fatalities in 2009. The natural gas pipeline rupture in San Bruno, CA, which killed eight people and was investigated by the NTSB (see NGI, Oct. 18, 2010), contributed to the rise in pipeline fatalities in 2010, the board said. The five fatalities from a pipeline explosion in Allentown, PA, were not included in the NTSB count since the blast occurred in early 2011 (see NGI, Feb. 14, 2011).

New Environmental Protection Agency (EPA) rules have prompted Corona Power LLC to switch most of the coal-burning generation at its 400 MW Sunbury generation facility in Shamokin Dam, PA, to gas-fired generation. The company plans to replace five of its six coal-fired boilers with two natural gas-fired combustion turbines by 2015, according to an air quality plan approval application filed with the Pennsylvania Department of Environmental Protection (DEP). According to the application, the repowering of the plant will increase the amount of electricity that it can generate from 381 MW to 689 MW. The decision to switch fuels at the 62-year-old facility was driven by new EPA regulations that would require coal-fired power plants to lower emissions in coming years, and the cost of burning coal, a plant official told the Danville News. Corona Power bought the Sunbury facility from WPS Resources Corp. for $30.4 million in 2006 (see Daily GPI, July 11, 2006).

Rapid City, SD-based Black Hills Corp. said its utility operations in Colorado is firing up commercial operations of two new baseload gas-fired generation plants near the Pueblo, CO, airport. Separate units of Black Hills Energy‘s operations will own and operate the $227 million, 180 MW Black Hills Energy, Colorado Electric plant; and a $260 million, 200 MW Black Hills Colorado IPP plant. The power from both facilities will replace a power purchase agreement with Xcel Energy that expires at the end of this year. The plants have completed most pre-commercial operations testing. With the two new plants, Black Hills Energy-Colorado Electric will have replaced 75% of its resource capacity at one time, under a mandate from the Colorado Public Utilities Commission.

Judge Shira A. Scheindin of the U.S. District Court for the Southern District of New York preliminarily approved a $77.1 million class-action settlement to resolve claims against Amaranth Advisors LLC, a hedge fund that collapsed in September 2006 after suffering $6 billion in market losses due to wrong-headed bets in natural gas futures [Amaranth Natural Gas Commodities Litigation 1:07-Civ.-6377]. The judge ordered Amaranth to pay the settlement amount in two parts — $72.4 million and $4.7 million. A hearing on final approval of the deal is scheduled for March 27. In August 2009 the Federal Energy Regulatory Commission (FERC) and the Commodity Futures Trading Commission entered into separate settlements requiring Amaranth Advisors and affiliates to pay a total of $7.5 million in penalties to settle the claims that they manipulated or attempted to manipulate natural gas futures prices (see NGI, Aug. 17, 2009). Amaranth, seven affiliates and former trader Matthew Donohoe — the parties to the FERC settlement — were accused of manipulating or attempting to manipulate the New York Mercantile Exchange natural gas futures contract, which settles at the Henry Hub and has a direct bearing on physical gas prices over which FERC has jurisdiction. Former Amaranth gas trader Brian Hunter was not part of the FERC agreement. FERC has imposed a $30 million penalty on Hunter. The U.S. Court of Appeals for the District of Columbia recently agreed to review the FERC penalty order (see NGI, Dec. 19, 2011).

Louisiana Attorney General Buddy Caldwell has filed a civil lawsuit against the Department of Interior (DOI) over the federal government’s redrawing of Gulf of Mexico (GOM) boundaries that determine how states receive mineral royalties. The redrawn GOM boundaries would require Louisiana to share $2.81 million in royalty revenue collected since 1986 with neighboring Texas and Mississippi, Caldwell said. In changing the boundaries of the Gulf Coast states’ GOM Outer Continental Shelf (OCS) zones, DOI failed to follow the legal mandates of the Administrative Procedures Act, the Outer Continental Shelf Lands Act (OCSLA), the Submerged Lands Act and the Federal Debt Collection Act, according to the lawsuit, which was filed in U.S. District Court for the District of Columbia. DOI’s change in defining the boundaries of the zones and its substantive changes in the allocation of revenues from the zones was “arbitrary and capricious,” according to the lawsuit.

Centaurus Energy Master Fund LP, a Houston-based energy hedge fund that was founded by John D. Arnold after the collapse of Enron Corp., was fined $75,000 by the New York Mercantile Exchange (Nymex) for violating position limits in natural gas trading. The business conduct committee found that on Jan. 26 Centaurus violated position limits by establishing an aggregate intraday peak position that exceeded the “do not increase” order by 0.11%. This was Centaurus’ fourth position limit rule violation in a 24-month period and further violated a previous order by [the] Business Conduct Committee to cease and desist from violating exchange orders, said CME Group, which owns Nymex and a number of other exchanges. Centaurus neither admitted nor denied the position limit rule violations.

Keystone Midstream Services LLC has received permit approval to build the Bluestone cryogenic gas processing plant in Butler County, PA, according to upstream partner Rex Energy Corp. The partners expect to bring the 50 MMcf/d facility online in May. Keystone Midstream also recently got permits to build the Voll Compressor Station at its existing Sarsen plant. That would expand the Butler County facility to 40 MMcf/d from its current capacity of 34 MMcf/d as soon as February. Butler County, located north of Pittsburgh in the wet-gas corridor of the Marcellus, is attracting more interest than activity right now. The Pennsylvania Department of Environmental Protection had issued 133 drilling permits in the county through November, compared to 73 from the same period in 2010.

Excelerate Energy LP has a contract to develop a floating liquefied natural gas (LNG) regasification facility off the southern coast of Puerto Rico for the Puerto Rico Electric Power Authority. Aguirre GasPort, to be around four miles off the southern coast, would provide fuel to the Central Aguirre Power Plant using one of Excelerate’s 150,900-cubic meter floating storage and regasification vessels. The facility would operate year-round and would be Excelerate’s seventh floating LNG import facility. The facility requires authorization from the Federal Energy Regulatory Commission and is subject to a public environmental review and analysis under the National Environmental Policy Act.

For the second time since its ordinance banning hydraulic fracturing was ruled illegal, the Morgantown, WV, city council has voted 4-3 to keep the illegal ban on the books. The issue was also tabled by the city council on Nov. 1 by a 6-1 vote. Morgantown enacted the ban over fears that operations at two Marcellus Shale gas wells owned by Northeast Natural Energy could foul the Monongahela River and the city’s municipal water intake (see NGI, June 27, 2011; June 13, 2011). The wells, located in the Morgantown Industrial Park, are about 2,000 feet from the river and an additional 1,500 feet from the intake. Monongalia County Circuit Court Judge Susan Tucker struck down the city’s ordinance, which banned fracking within the city and an adjacent one-mile buffer zone, on the grounds that the state Department of Environmental Protection has exclusive dominion over the regulation of natural gas drilling (see NGI, Aug. 29, 2011).

A bill to expand natural gas use in Maine is in committee and could be up for a vote in the state legislature when it convenes on Wednesday (Jan. 4). But a proposal to build a natural gas pipeline could be in jeopardy after residents of one community along the route say they are opposed to granting tax breaks for the gas line. Under bill LD 1644, also known as “An Act to Expand the Availability of Natural Gas to Maine Residents,” the Finance Authority of Maine (FAME) would be authorized to issue bonds for natural gas pipeline projects in the state. Applicants would receive FAME approval if they commit to financing at least 25% of the project’s cost. LD 1644, which also sets minimum and maximum capital reserve requirements, was referred to the Committee on Energy, Utilities and Technology on Dec. 21. The primary beneficiary of the bill’s passage could be the Kennebec Valley Gas Co., which has received regulatory approval to build a $70 million, 80-mile natural gas pipeline from Richmond to Madison, ME, in the state’s Kennebec Valley. The pipeline would interconnect with the Maritimes & Northeast Pipeline.

Victory Energy Corp. said a carbonite formation well in southeastern New Mexico it holds an interest in has been successfully re-entered, five years after being plugged, and is now completed and producing oil and natural gas. Newport Beach, CA-based Victory acquired an interest (10% working, 7.5% net revenue) in the Uno Mas No. 1 well through a partnership with Aurora Energy Partners. The well in Lea County, NM is targeting the Mississippian Detrital carbonite formation. Victory identified the well’s operator as Midland, TX-based V-F Petroleum Inc. (VF), but other interest holders were not disclosed and flow rate data was not released, pending public regulatory filings by VF.

The Research Partnership to Secure Energy for America (RPSEA) is seeking requests for proposals (RFP) for its Small Producer Program and its Unconventional Resources Program. Sugar Land, TX-based RPSEA said it expects to award about $10 million in five to 12 awards in the Small Producer Program and about $35 million in eight to 15 awards for oil and natural gas research and development projects in its Unconventional Resources Program. “The projects to be selected under the 2011 Small Producer Program will focus on unlocking the potential for domestic hydrocarbon resources by enhancing production within existing surface footprints from mature fields, where up to two-thirds of original oil in place is left behind,” RPSEA said. Proposals are due by 4 p.m. CST Feb. 27. “The projects to be selected under the 2011 Unconventional Resources Program will focus on the challenge to safely and responsibly extract the abundant resource of domestic natural gas that lies within our grasp, primarily in gas shales and also tight sands,” RPSEA said. Proposals are due by 4 p.m. CST March 6, 2012. Information is available at the RPSEA website.

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