The proposed route and two alternative routes for Spectra Energy Corp.‘s proposed Texas Eastern Transmission (Tetco) natural gas pipeline bisect a “very complicated” 66-acre property in Bayonne, NJ, owned by Texaco Downstream Properties Inc. (TDP) and should be realigned, the Chevron affiliate said in a Federal Energy Regulatory Commission filing. The site, which was previously a lubricant blending facility and light products terminal, “is well along in the approval process” to be redeveloped into a residential development, according to TDP. Chevron requested that the pipeline route be realigned, “preferably off the property, but at a minimum to an area on the property that does not interfere with the ongoing remediation, the unique physical characteristics of the property or the planned redevelopment of the site.” Chevron and Spectra both say they are working together to try to resolve the issue. The project calls for Tetco to build a 16-mile, 30-inch diameter extension from Tetco’s pipeline in Staten Island, NY, through Bayonne and Jersey City in New Jersey to a Consolidated Edison plant in Manhattan, as well as expand Spectra’s Algonquin Gas Transmission system (see NGI, Jan. 4). The proposed facilities would be capable of transporting up to 800 MMcf/d of Marcellus Shale gas to the region and are targeted for service in the fourth quarter of 2013.

The Federal Energy Regulatory Commission has approved Petal Gas Storage LLC‘s proposal to convert an existing salt-brine storage cavern within the Petal Salt Dome east of Hattiesburg, MS, for use as a salt dome natural gas storage cavern, and to construct necessary pipeline facilities to connect the cavern with existing Petal storage operations. The Cavern No. 12A Conversion Project has a proposed storage capacity of 8.2 Bcf, including 5 Bcf of working gas and 3.2 Bcf of cushion gas. The storage facility would interconnect with Petal’s existing gas storage facilities through an approximately 1,525 foot long, 16 inch diameter pipeline. Petal, which is a subsidiary of Enterprise Products Partners, had requested FERC approval of its application by June so that it could begin construction in July in order to meet expected requests for injection in the fall of 2011.

Icon NGS LLC is holding a 30‐day, nonbinding open season through Sept. 23 for its Tallulah Gas Storage (TGS) project in northeastern Louisiana about 15 miles east of the Delhi Hub and adjacent to the west‐to‐east pipelines connecting supply to and from the Delhi Hub. The project is to be composed of three high‐deliverability, multi‐cycle salt caverns with working gas capacity of 8 Bcf per cavern for a total of 24 Bcf. The project will be designed to inject 900 MMcf/d and withdraw up to 1,575 MMcf/d. The in‐service date for the initial 8 Bcf cavern is targeted for September 2013, to be followed by caverns 2 and 3 in September 2014 and September 2015, respectively. The open season is offering up to 24 Bcf of storage with the first cavern scheduled to begin service in September 2013. More information is available at www.tallulahgas.com.

Changes proposed by Sempra LNG unit Cameron LNG LLC to its liquefied natural gas terminal in Cameron Parish, LA, to allow for the export of LNG do not meet the threshold to be considered “new construction,” according to U.S. Coast Guard Captain J.J. Plunkett, captain of the port for Port Arthur, TX. As the changes do not constitute new construction, Plunkett said they do not require a letter of intent under the Code of Federal Regulations. In a letter to Cameron filed with the Federal Energy Regulatory Commission, Plunkett wrote, “The waterway impacts associated with export operations at the Cameron LNG terminal should not change or exceed those envisioned in the original environmental impact statement, environmental assessment, and waterway suitability assessment.” The terminal is on the Calcasieu Channel, 18 miles from the Gulf of Mexico in Hackberry, LA, and is owned 100% by Sempra Energy. Commercial operation began in July 2009.

New Pennsylvania wastewater treatment rules, which apply to gas drillers in the Marcellus Shale, are now in effect, the state’s Department of Environmental Protection said. The new permitted limit for discharges of wastewater from gas drilling is 500 milligrams per liter (mg/l) of TDS and 250 mg/l for chlorides (see NGI, June 28). All new and expanding facilities that treat gas well wastewater must now meet these discharge limits. The rules cleared a state Senate review earlier this year. The final rules became effective upon publication in the Pennsylvania Bulletin, which contains the full text of the rules at www.pabulletin.com, page 4835.

Sempra Energy unit Sempra Pipelines & Storage said the first of two caverns at its Mississippi Hub gas storage facility has entered service. Located at the Bond Salt Dome in Simpson County, MS, the facility is accessible to the shale basins of East Texas and Louisiana, traditional gas supplies in the Gulf of Mexico and along the U.S. Gulf Coast, as well as liquefied natural gas imports. The first cavern is designed to provide up to 10-cycle service on 7.5 Bcf of working capacity. Pipeline interconnects will include Southern Natural Gas, Southeast Supply Header and Transcontinental Gas Pipeline. A second cavern, which will add 7.5 Bcf of working capacity, is under construction and is slated for completion in the second quarter of 2012.

Natural gas utilities will need to achieve annual savings of 6% by 2020 under a new set of rules approved by the Arizona Corporation Commission (ACC). The state regulators want the utilities to greatly expand their energy efficiency programs and measure their effectiveness against percentage savings on retail energy sales each calendar year. The utilities can apply both demand-side management (DSM) and renewable energy resource technology (RET) programs. One-third each of the annual savings can come from energy-efficient building codes and energy efficiency appliance standards, respectively, under the ACC’s new rules. The utilities also can count the savings from individual residential and business customers that adopt various efficiency practices and technologies to driven down their energy use. Finally, the ACC will allow the utilities to count the savings coming from RET projects that displace gas use by customers. Starting in June 2011 and in every year ending in an odd number, utilities will be required to file an implementation plan with the ACC, describing how they intend to meet the standard for the next two calendar years. The initial implementation plan will be due within 30 days of the effective date of the new rules.

British Columbia (BC) collected more than C$98 million in bonus bids in its August natural gas and oil lease sale, officials said. For the year the province said bids have totaled C$760 million. The sale on offered 81 parcels covering 34,349 hectares in northeast British Columbia, where the prospective Horn River and Montney shales are located. The auction resulted in 68 parcels being sold covering 31,052 hectares. The average price per hectare in the latest sale was about C$3,160. The next BC auction is scheduled for Sept. 22, when the province will offer 71 parcels covering 35,197 hectares.

Denver-based independent SM Energy Co. said it plans to raise “at least $300-500 million” by selling nonstrategic assets or through joint venture (JV) agreements over the next year. Among the assets on the list for potential sale or for a JV agreement are 43,000 net acres in the Marcellus Shale, the producer said. Bank of America Merrill Lynch has been engaged to market the acreage, which is in the Pennsylvania counties of McKean and Potter. SM Energy, formerly St. Mary Land & Exploration Co., said its second Marcellus well in McKean County, the Potato Creek 3H, began producing to sales in early August at a “facility-constrained” initial gas production rate of more than 7 MMcfe/d. Albrecht & Associates also was engaged to market a set of undisclosed noncore, “primarily proved developed” properties, “with a goal of completing a transaction by the end of 2010,” the producer said. Current production associated with the package is 13 MMcfe/d.

Abraxas Petroleum Corp. and Blue Stone Oil & Gas LLC have signed a joint venture (JV) agreement to develop the Eagle Ford Shale play in South Texas. San Antonio-based Abraxas will contribute 8,333 net acres in the Eagle Ford Shale to the JV — to be called Blue Eagle Energy LLC — and will receive a $25 million equity interest in the JV, while Denver-based Blue Stone will contribute a total of $75 million in cash for a 75% equity interest in the JV. Blue Eagle Energy’s subject area will encompass 12 counties across the Eagle Ford Shale for expected future acreage acquisitions. Abraxas will operate the JV’s wells and Blue Stone will manage its day-to-day business affairs.

Louisiana’s efforts to guide natural gas drillers to alternative water sources and to track the sources of water used in drilling operations are helping to protect groundwater resources in the state’s northwestern Haynesville Shale area, according to a report from the Louisiana Ground Water Resources Program (LGWRP). Nearly 80% of water used for drilling operations in Louisiana’s Haynesville Shale now comes from surface water sources, according to LGWRP. An LGWRP study found that 1.5 billion gallons of surface water was used in the operations of more than 420 wells drilled in northwest Louisiana between Oct. 2009 and July 2010, LGWRP staffers told the state’s Ground Water Resources Commission (GWRC). The state’s commissioner of conservation first advised operators in the Haynesville Shale to seek surface water or other alternatives to groundwater for hydraulic fracturing needs in 2008.

Rapid City, SD-based Black Hills Corp. announced that its natural gas utility operating in Nebraska was granted an $8.7 million general rate increase by the state Public Service Commission (PSC). The new rates are effective Wednesday (Sept. 1) for Black Hills Energy. The decision on the rate hike request, which was filed late last year, also authorized a return on equity of 10.1% for Black Hills Energy, along with structuring the utility’s capital structure at 52% equity. Under the Nebraska PSC process, Black Hills implemented a $12.1 million, or 6.5%, interim increase last March 1. Since the new rates will be lower than the interim hike now in effect, customers will receive refunds for the difference between the two rates. The utility will file a specified refund plan to the PSC before implementing the refund. Under the new rates, following any refunds, the typical Black Hills retail residential customer is looking at a monthly increase of almost $4; typical commercial customers will see an increase of nearly $2/month. For large industrial customers, the increases will vary depending on the rate class and volumes and type of natural gas use. The rate increase also included a PSC-authorized change in the fixed monthly customer charges. Residential monthly charges will be set at $13.50, and the commercial fixed monthly charge will become $18.50.

Black Hills Corp.’s natural gas utility operations in five states — Colorado, Iowa, Kansas, Nebraska and Wyoming — are switching customers of Black Hills Energy to smart meters. The installation of new Itron advanced gas meters began earlier this month. The utility is banking on Itron’s “ChoiceConnect” technology to provide flexibility in collecting advanced meter data from up to 330,000 of the meters in its states with gas distribution operations. Expected to be spread over a three-year installation period, not all the utility’s customers will get the new meters because as a rural-based operation there are groups of customers that are to widely dispersed to make it uneconomic for remote reading of meters in their geographical areas.

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