A coalition of 20 Senate Democrats has called on Vice President Joe Biden to make sure a provision stripping major oil and natural gas producers of an estimated $21 billion in tax breaks over the next decade is included in any deficit-reduction package negotiated with Republicans.The coalition led by Sen. Robert Menendez (D-NJ) made the request in a letter to Biden, who is representing the administration in efforts to reach a deficit-cutting deal with Republicans, The Hill reported. On May 17 “a majority of the Senate voted for legislation to close these loopholes for the Big Five oil companies, and this mandate cannot be ignored,” the group told the vice president. While 52 senators, including three Republicans, voted for the bill to repeal the tax breaks, the measure was blocked because the majority failed to get the 60 votes needed to advance the bill. The bill, sponsored by Menendez, sought to revoke the tax breaks for Chevron Corp., BP plc, Royal Dutch Shell plc, ConocoPhillips and ExxonMobil Corp. Following the bill’s defeat, Senate Majority Leader Harry Reid (D-NV) said he expected the legislation to resurface.
Regency Energy Partners LP said it will spend about $450 million to construct a wellhead gathering system and other infrastructure in order to serve an undisclosed producer in the Eagle Ford Shale with gas and condensate gathering. Known as the EF Expansion, the infrastructure will be owned and operated by Regency and will tie into its existing gathering system. Regency has also purchased existing midstream assets in the Eagle Ford that it will own and operate as part of the EF Expansion. Once the project is finished, Regency’s entire South Texas system will be capable of gathering, compressing, treating and transporting up to 1 Bcf/d of natural gas and 26,500 b/d of condensate to downstream outlets.
The Pennsylvania Department of Environmental Protection is proposing revisions to laws governing gas development in the state that would restrict drilling near water supplies, increase bonding amounts and toughen penalties for violations. The recommended changes to the state Oil and Gas Act would require companies to track hydraulic fracturing wastewater from “cradle to grave” at high volume wells, widen the set backs from drilling around water supplies and increase the parameters where an operator is held liable when the cause of contamination event is uncertain, similar to the recommendations of two environmental groups (see Shale Daily, May 13). The changes would have to be approved by the Pennsylvania General Assembly before they could be implemented (see Shale Daily, April 11; March 29).
The University of Texas at Arlington (UT Arlington) and 1st Resource Group Inc. of Fort Worth, TX, are collaborating to commercialize a process to convert natural gas to synthetic fuel at a cost they said is “lower than current market rates.” UT Arlington researchers have designed a portable conversion unit that transforms natural gas from the field for use as clean-burning synthetic fuels. 1st Resource has partnered with Fort Worth-based UMED Holdings Inc. to aid in commercializing the patent-pending process. 1st Resource said it plans to deploy conversion units in domestic and international gas fields to yield synthetic jet fuels and diesel. The application is expected to be particularly useful in stranded gas fields, on sites where gas must be vented or flared and when it is not economically viable to move gas to a pipeline due to adverse market conditions, the researchers said.
Montana’s Department of Natural Resources and Conservation (DNRC) is considering new rules to regulate hydraulic fracturing (hydrofracking) activities in the state and has scheduled a public hearing on proposed rules for June 15. Montana’s proposed rules “are reasonably necessary in order to address safety issues associated with techniques used for oil and gas well completions,” the DNRC said in its hearing notice. “These techniques include hydraulic fracturing, which has become more prevalent throughout the United States in recent years.” DNRC would require producers/operators to include “processes, anticipated volumes and types of materials planned for use” in frack jobs in well permit applications. For wildcat or exploratory wells, written approval for fracking would need to be obtained in advance of well stimulation by at least 24 hours.
Aux Sable Liquid Products LP unit Sable NGL LLC is buying the Stanley Condensate Recovery Plant and Prairie Rose Pipeline from a unit of EOG Resources Inc., the company said. The Prairie Rose Pipeline connects the Stanley Plant to the Alliance Pipeline, which delivers high energy dense phase gas to Aux Sable’s Channahon, IL, plant for processing. The purchase agreement calls for the US$185 million transaction to close in July. The Stanley Plant began operation in February 2010 and will have capacity of 80 MMcf/d when an ongoing expansion is completed this month. The plant removes the heavier hydrocarbon compounds while leaving the majority of natural gas liquids (NGL) in rich gas delivered into the Prairie Rose Pipeline.
Wood Mackenzie natural gas analyst Jen Snyder said in a recent issue of the Electric Power Research Institute‘s quarterly journal that the power generation sector should watch developments in the wholesale gas market because the upstream sector can handle big swings upward in demand, but not at today’s paltry forward curve prices for natural gas. Wood Mackenzie’s North American gas research team is “extremely bullish” on shale gas; it doesn’t argue with forecasters who say there is now a 100-year supply of gas in North America, Snyder said. “However, the pace at which this market grows is extremely important, including not just incremental power generation capacity additions, but also retiring older capacity.”
Apache Canada Ltd. has dropped out of a joint venture (JV) with Corridor Resources because it said poor results from two natural gas test wells in New Brunswick’s emerging Frederick Brook Shale did not justify spending more. Corridor, a junior producer based in Halifax, NS, said Apache would not commit an additional C$100 million required to further test and appraise the shale deposit in the Moncton Basin, which is in the southeastern part of New Brunswick. Under a farmout and option contract negotiated with Corridor, Apache Canada agreed to spend up to C$25 million to evaluate the commercial potential of gas in the formation (see NGI, Dec. 14, 2009). The appraisal, completed on June 1, gave Apache the option to drill more test wells and construct a gas pipeline to Corridor’s gas plant at the McCully Field near Sussex, NB.
Cardinal Gas Storage Partners LLC is paying about $148 million to acquire Monroe Gas Storage Co. LLC and an option on development rights to an adjacent depleted gas reservoir from High Sierra Monroe LLC, a unit of High Sierra Energy LP and other shareholders. Monroe, with 12 Bcf of working capacity in service, is a high-deliverability reservoir in northeast Mississippi that has been in operation since 2009. The facility has potential to add up to 12 Bcf of working capacity through expansion of the existing facility and development of the option on the adjacent field. Monroe has two pipeline interconnects through a separate east and west header system to Tennessee Gas Pipeline and Texas Eastern Transmission.
To fund increased drilling in core areas of the Marcellus Shale and Piceance Basin, Antero Resources has added $126 million to its capital budget for 2011. The Denver-based driller said the revised capital budget, which now totals $685 million, allocates $519 million for drilling and completion, $86 million to construct gathering pipelines and facilities, and $80 million to acquire more land. Of the $126 million increase to the budget, more than half (53%) is for drilling, with more than one-third (35%) to be spent on gathering pipeline expansion and 12% to acquire more acreage. Most of the new spending is to add gathering infrastructure and increase acreage in the Marcellus.
California regulators have agreed to shut two natural gas-fired electric generation units along the Southern California coast to help develop a gas-fired facility inland in eastern Los Angeles County. The action involves AES Corp. and Edison Mission Energy (EME). AES transferred ownership of its Units 3 and 4 at its 900 MW gas-fired Huntington Beach complex to EME, with an agreement for AES to lease back the units. Subsequently, EME and AES agreed to close the two units, with a combined 450 MW of capacity, in late 2012. The two units would give EME required emissions credits to build a 500 MW gas-fired combined-cycle plant, Walnut Creek Energy Park, in the City of Industry, about 30 miles east of downtown Los Angeles. The project has been held up, pending resolution of the emissions credits.
A bill to reduce haze in Colorado (HB 1291), considered a priority by the state’s oil and gas industry, has been approved by the Colorado General Assembly. The Colorado Oil and Gas Association (COGA) praised the bill’s passage. Xcel Energy’s Public Service Company of Colorado, said the bill was procedural to help implement a haze mitigation plan in the state’s landmark Clean Air, Clean Jobs Act (HB 1365), which was enacted in 2010 with broad-based support from the energy industry because it would require some coal plants to be shuttered and more gas-fired power generation.
Gastar Exploration Ltd. hopes to take part in 21 wells in the Marcellus Shale this year, including 14 as operator. The Houston-based company holds 103,500 gross (73,600 net) acres across two areas, the 19,000-net acre Marcellus West and the 54,600-net acre Marcellus East. At Marcellus West, Gastar and joint venture partner Atinum Marcellus I LLC plan to drill at least 12 horizontal wells this year and 24 horizontal wells in both 2012 and 2013 on their existing acreage (see NGI, Sept. 27, 2010). The companies are also looking into acquiring leases in Ohio and New York in addition to their existing holdings in West Virginia and Pennsylvania, according to recent financial filings.
The total value of minerals produced in Wyoming last year was up 23% year over year, hitting $15.5 billion, according to Gov. Matt Mead. Last year’s value was second only to 2008 in Wyoming’s history of collectively valuing its oil, natural gas, coal, bentonite, trona and uranium production each year. In 2010 the production in each of those areas increased in value, compared with 2009, Mead said. The taxable value of natural gas was up by 30% and oil jumped 34%. The other sectors increased by widely varying amounts, with surface coal and trona increasing 6% and 7%, respectively, while uranium and bentonite jumped year over year by 44% and 89%, respectively.
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