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Millennium Pipeline Co. LLC remains on schedule to complete the 182-mile-long, 30-inch diameter natural gas pipeline across New York's Southern Tier and lower Hudson Valley by November, the company said. More than 90% of the pipeline is expected to be installed within or next to existing pipeline rights-of-way. Millennium, which would transport up to 525,400 Dth/d when it goes in service, is the centerpiece of a $1 billion investment in new energy infrastructure that includes new facilities by Empire Pipeline, Algonquin Gas Transmission and Iroquois Gas Transmission. The pipeline is anchored by National Grid, Consolidated Edison of New York, Central Hudson Gas and Electric Corp. and Columbia Gas Transmission Corp. Millennium is jointly owned by affiliates of NiSource Inc., National Grid and DTE Energy. Construction on the pipeline was begun last year with the installation of 12 miles of pipeline, mostly in New York's Orange and Rockland counties (see NGI, May 12). Most of the mainline pipeline installation work, however, is scheduled to be completed this year to meet the targeted November in-service date. Some land restoration and environmental monitoring work is expected to extend into 2009 and beyond, Millennium said. More than 2,000 workers -- many of them hired locally -- were to be involved in the construction project. Houston-based U.S. Pipeline Inc. is the pipeline contractor, and Precision Pipeline LLC of Eau Claire, WI, is installing horizontal directional drill crossings below selected rivers, streams and roadways.

Ozark Gas Transmission LLC, an affiliate of Tulsa, OK-based Atlas Pipeline Mid-Continent LLC, is proposing to build a new pipeline to transport natural gas from the developing Fayetteville Shale area in Arkansas. The project calls for the construction of approximately 160 miles of at least 36-inch diameter pipeline from White County, AR, in the North-Central part of the state to proposed interconnects with Trunkline Gas Co. and Texas Gas Transmission near Dyersburg, TN, in the northwest portion of the state, as well as 20,000 horsepower of compression facilities. The proposed pipeline would have initial capacity of up to 700,000 Dth/d, with the ability to expand up to 1.2 million Dth/d, according to Ozark Gas. Construction is expected to be completed as early as Nov. 1, 2010. A nonbinding open season on the $400 million-plus project was held through May 15. Ozark Gas Transmission, an interstate pipeline, operates 565 miles of gas transmission pipeline in Oklahoma, Arkansas and Missouri. It interconnects with both intrastate and interstate pipelines, including Oklahoma Natural Gas, Enogex, Texas Eastern Transmission, Natural Gas Pipeline Co. of America, Mississippi River Transmission, Atmos, Arkansas Western Gas and Arkansas Oklahoma Gas. Ozark Gas also operates 365 miles of gas gathering pipeline in Oklahoma and Arkansas.

FERC has issued a certificate for CenterPoint Energy Gas Transmission Co.'s (CEGT) proposal to build a pipeline and additional compression to serve a power plant in Arkansas and other shippers. In light of the fact that the project should have no negative impact on existing customers, has not been protested by other pipelines in the CEGT market area and should have minimal effects on landowners, "we find approval of CEGT's proposal to be in the public convenience and necessity," FERC said in the order [CP08-69]. The project, known at the Tontitown Project, calls for the construction of an approximately 16-mile, 24-inch diameter pipeline in Logan and Franklin counties, AR. The pipeline will loop CEGT's existing Line OM-1. In addition, a 10,310-horsepower Poteau compressor station is proposed to be constructed on CEGT's parallel Lines O and O-1-O near the city of Poteau in Le Flore County, OK. The proposed pipeline and compression facilities are expected to add approximately 132 MMcf/d of incremental capacity to CEGT's system, the majority of which (90 MMcf/d) will be used to serve the electric generation requirements of Southwestern Electric Power Co.'s power plant in Tontitown, AR. The uncontracted capacity will be posted and made available to existing shippers, according to CEGT. The estimated cost of the project is $52.3 million. The Commission granted CEGT's request to roll the project costs into its system rates in a future general Section 4 rate proceeding, absent any material change in circumstances.

For the third month in a row, Double Eagle Petroleum Co. broke a record for natural gas production at its Catalina Unit, an emerging coalbed methane play located in the Atlantic Rim of Wyoming. Total gross production from 40 wells in the unit was on pace in May to exceed 510 MMcf, or 18.8 MMcf/d, which would be 237% higher than gas output in May 2007, Double Eagle stated last week. Net output from May 1 through last Wednesday surpassed 310.0 MMcf, or 11.1 MMcf/d, which was 150% higher than the same period a year ago. Average daily production through Wednesday was 414 Mcf/d gross, with net average daily production of 250 Mcf/d. "We are extremely pleased to continue to see excellent results from our newly drilled Catalina," said Chairman Richard Dole. "In 2008 we have been able to realize significant production for this project and hope to continue creating value growth from this and other areas for several years to come." The production data was compiled from Double Eagle's original 14 Cow Creek wells in the unit and 26 of 33 new wells drilled last year. Another 24 wells are expected to be drilled in the play beginning in July. The Denver-based independent also increased its production and reserves forecasts from interests in nonoperated production areas of the Pinedale Anticline in Wyoming, as well as a nonoperated interests in the Sun Dog and Doty Mountain units of the Atlantic Rim. "The new Pinedale wells and the encouraging outlook for the Sun Dog and Doty Mountain units position the company for a strong second quarter and remainder of 2008," said Dole.

FERC approved two stipulation and consent agreements that ordered Duquesne Light Co. and Otter Tail Power Co. to pay a combined $1.8 million in either civil penalties, disgorged profits or to implement a comprehensive regulatory compliance plan. The Duquesne Light order resolved an investigation into violations of the FERC's cost-allocation procedures, the electric quarterly report filing requirement and the standards of conduct (IN07-27]. Specifically, the order said employees of the Pittsburgh-based utility failed to keep track of their time-performing functions for affiliates; a small Duquesne generating affiliate failed to file required electric quarterly reports from 2002 to 2006; cited several instances of Open Access Same-Time Information System posting violations; and identified several violations of the independent functioning and information-sharing requirements related to Duquesne's provider of last resort responsibility, as well as several other violations of the information-sharing rules. Duquesne Light admitted it committed the acts in question, but neither admitted nor denied that the acts constituted violations of the rules. Nevertheless, it agreed to pay a $250,000 civil penalty, keep track of employees' time-performing functions for affiliates and to spend at least $1 million to develop and implement a comprehensive regulatory compliance plan. The Otter Tail order resolved alleged network transmission violations of the Open-Access Transmission and Energy Markets Tariff of the Midwest Independent Transmission System Operator (Midwest ISO). Otter Tail, based in Fergus Falls, MN, acknowledged that it committed the acts, which predated the Energy Policy Act of 2005, but neither admitted nor denied that the acts constituted violations of the tariff [IN08-6]. However, it agreed to disgorge profits of $546,832 plus interest. Enforcement staff said it did not seek to impose a compliance monitoring plan on Otter Tail because now that the Midwest ISO's Day 2 market is operational, its member utilities no longer schedule transmission within the system. Otter Tail provides electricity and energy services to a quarter million customers in Minnesota, North Dakota and South Dakota.

Noting it has made some "minor tweaks" to its portfolio of public-sector bond financing packages, the Southern California Public Power Authority (SCPPA) executive director said that none of the authority's renewable and other energy projects currently being pursued have been affected by the subprime mortgage market meltdown that continues to adversely affect some of its counterparties. Standard & Poor's Ratings Services (S&P) reiterated double-A level credit ratings for SCPPA. S&P reaffirmed the SCPPA ratings as it moved May 21 to place a "negative" outlook on American International Group Inc. and one of its subsidiaries, which provides interest payment assurances on hundreds of millions, if not billions, of dollars of project financing bonds that SCPPA sells on behalf of its dozen public-sector utilities in Southern California. The rating outlook impacts SCPPA's gas supplier in some long-term pre-paid natural gas supply deals for its members. The rating on SCPPA's pre-pay gas deal is tied to J. Aron & Co., the supplier, and Goldman Sachs guarantees J. Aron's obligations under the pre-paid SCPPA deal, S&P said. "The insurance companies are taking a bath right now," said Bill Carnahan, SCPPA executive director. "What used to be like the 'Good Housekeeping Seal of Approval' has gotten so it doesn't mean anything anymore. As a result we don't get the lower interest rates, so what we're doing on variable interest bonds being held to counteract our interest rates on existing bonds going up a little bit is to switch from variable to fixed interest rates." Wall Street's mess tied to the expansion of banks and insurance companies into buying too big a share in the subprime industry has nothing directly to with the utility business, Carnahan said. "Our credit is based on the ratings of our members, and they are all fine."

Spectra Energy has launched an open season to solicit participation in the expansion of raw natural gas transmission capacity in the Fort Nelson area of northeast British Columbia, where the gas-rich Horn River Basin is located. Spectra in February proposed expanding its gas gathering system to accommodate growing production in the Grizzly Valley area of the province (see NGI, Feb. 18). The proposed project would be part of a third phase of expansion related to the company's Pine River facility to allow more incremental raw gas to flow to its Pine River Gas Plant near Chetwynd, BC. "Given producer expectations for Horn River Basin shale gas development and production, we are holding this open season to evaluate the need for additional raw gas transmission services connected with our existing Fort Nelson processing plant," said Duane Rae, vice president, field services, Spectra Energy Transmission West. Spectra also has launched plans to build a large-scale integrated carbon capture and storage project near the Fort Nelson plant. The project would be a partnership between Spectra and the BC provincial government, which provided a $3.4 million grant to fund an initial feasibility plan. Interested parties must submit a nomination form before the open season closes at 4 p.m. MDT on June 13. To obtain a nomination form or more information, contact Doug Deeprose at (403) 699-1735 or

Chevron Corp. has shelved plans to sell its natural gas storage operations in British Columbia because the offered bids didn't match the asset's worth, the oil major said. Chevron said it received several offers for its Aitken Creek storage facility after it was put up for sale late last year. The facility is estimated to be worth around C$1 billion. It holds gas for pipeline delivery to southern British Columbia and to the Lower 48 states. The Aitken Creek facility has capacity to hold 71 Bcf and it is expandable. It now is the largest gas storage facility in the province, connected to Spectra Energy's pipeline system.

The success of a horizontal test well in the emerging Lower Bossier Shale in Harrison County, TX, is expected to ramp-up at an initial rate of 10-15 MMcf/d once there is sufficient takeaway capacity from the region, Penn Virginia Corp. (PVA) said. The producer said it completed its first horizontal well test on the Fogle #5-H, in which it has a 100% stake, which targeted the Bossier formation in East Texas. The well had an initial production rate of 8 MMcf/d with a flowing casing pressure of 5,000 pounds, and the well reached a total vertical depth of 11,378 feet with a 3,861-foot lateral. According to PVA, the well is connected to existing infrastructure, but sales have been limited to about 5 MMcf/d because of pipeline capacity constraints. Once there is additional takeaway capacity, which is expected by July, PVA said the well's initial production rate could double or even triple to a rate of 10-15 MMcf/d. CEO James Dearlove said test well "exceeded our expectations." PVA has around 53,000 net acres in East Texas. Through the rest of the year, PVA plans to try to expand its acreage in the leasehold. Based on the results of its vertical tests and the latest success from the horizontal well, PVA said it now expects to drill at least five additional horizontal Bossier Shale wells through the rest of the year.

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