More than three months after Hurricane Ike severed a natural gas pipeline that was part of the company’s High Island Offshore System (HIOS), Enterprise Products Partners LP said repairs have been completed and the company has been given permission to resume full service on HIOS. The 42-inch diameter segment of the HIOS system — which transports gas from fields in the western Gulf of Mexico — was severed approximately 130 feet under water during Ike in September. Since then, gas volumes into the system have been limited to certain receipt points upstream of the break and required third-party pipeline systems for delivery to onshore facilities. Enterprise said federal regulators, after approving Enterprise’s inspection and start-up procedures, authorized the partnership to resume full service. The pipeline has the capacity to transport up to 1.8 Bcf/d. HIOS, which is owned by an affiliate of Enterprise, consists of a 291-mile pipeline system that transports gas from fields in the Galveston, Garden Banks, West Cameron, High Island and East Breaks areas of the Gulf of Mexico to third-party pipeline systems. HIOS also includes eight pipeline junction and service platforms.

Hundreds of royalty owners in the Piceance Basin of Garfield, CO, may benefit from a proposed partial settlement of a class action lawsuit brought against Williams Production RMT. Parachute, CO, royalty owners Ivo, Sidney and Ruth Lindauer, and Diamond Minerals LLC in Sept. 2006 filed the lawsuit against Williams and predecessor owner Barrett Resources Corp. (Lindauer et al. v. Williams Production RMT Co., Case No. 2006 CV 317). The plaintiffs alleged that Williams had underpaid royalties and some overriding royalties in several ways that included improperly calculating a netback value and failing to account fully for the proceeds received from the sale of the gas and products extracted from the gas. In its response Williams asserted that it had properly calculated and paid royalties, properly accounted for the gas and other products sold and had taken deductions permitted by the leases held by the plaintiffs. Williams said it had made ad valorem tax refunds for the production years 2002 and 2003 and was in the process of determining refunds for 2004 because the 2004 taxes were not due and paid until 2006. Garfield County’s Ninth Judicial District Judge Denise Lynch approved the partial settlement, and she has scheduled a fairness hearing for March 20. In the settlement Williams did not admit to wrongdoing or to the legitimacy of the claims of the plaintiffs. The court case and related documents are available at www.fleeson.com.

The Wisconsin Public Service Commission (PSC) kept electric rates unchanged and decreased retail natural gas rates for two utilities — Wisconsin Public Service Corp. (WPS) and Wisconsin Power & Light (WP&L) — effective Jan. 1. Shortly before the PSC action on electric and gas rates, WP&L parent company Alliant Energy Corp. filed a settlement that agreed to keep electric charges flat and decrease natural gas retail rates by about $4 million annually. As part of the deal, WP&L also received approval to file a full 2010 test year rate case in 2009 instead of being limited to a “reopener” as specified in its original rate filing. Wisconsin’s three-member commission said WPS natural gas customers will have a decrease of about $3 million annually overall, or less than half of 1%, and as a result, those customers should average about $7 in annual savings. For the WP&L gas customers, the rate drop will be about 1.14%, or $4 million, with an average annual savings of about $15/customer.

Williams‘ Transcontinental Gas Pipe Line (Transco) has placed the first phase of its Sentinel expansion into service, increasing firm capacity into the northeastern U.S. by 40,000 Dth/d. Sentinel has been years in the making. The Sentinel expansion is being constructed in two phases. Phase 2 will provide an additional 102,000 Dth/d and is expected to be placed into service by November 2009. The entire project is designed to increase Transco’s firm capacity by 142,000 Dth/d. Phase 1 included the addition of approximately four miles of 42-inch diameter pipe in Northampton and Monroe counties, PA, in addition to compressor station upgrades at Transco Station 195 in Delta, PA. Phase 2 will include the addition or replacement of 14 miles of pipeline at various locations in Pennsylvania and New Jersey.

The Pacific Northwest’s week-long below-freezing temperatures just before the holidays pushed Bellevue, WA-based Puget Sound Energy (PSE) to another record natural gas sendout Dec.19, surpassing a record the utility set earlier in the month. PSE said natural gas demand hit 780,000 MMBtu on Dec. 19, compared to 755,881 MMBtu Dec. 16. The Dec. 19 peak electricity usage for PSE was 4,772 MW at 6 p.m., short of the record set Dec. 15 of 4,906 MW, which exceeded a power demand marker that had stood for a decade at the combination utility. The utility began alerting customers before Dec. 20-21 weekend that the severe cold snap means that their utility bills will be higher, so they should try to use energy wisely, particularly during the peak periods of customer demand — 6:30-9 a.m. and 4-7:30 p.m. PSE reminded customers that there are several programs to help qualifying households pay their higher monthly energy bills, and said its natural gas and electricity infrastructure was holding up very well under the severe weather conditions.

FERC denied the rehearing requests of two New York regulators for late intervention in a proceeding involving Broadwater Energy LLC‘s proposed liquefied natural gas (LNG) terminal and associated pipeline facilities, which the agency approved in March. Both the New York State Department of State (NYDOS) and New York State Department of Environmental Conservation (NYSDEC) filed requests to intervene in the case in April of last year, more than two years after intervention requests were due at FERC. In a September order, the Commission denied the rehearing requests of several parties, including NYDOS’ and NYSDEC’s requests for late intervention. The latest order denies the New York State agencies’ requests for rehearing of the September order. NYSDOS is a cooperating agency in the Broadwater case. It sought late intervention last April — about a week after it determined that the Broadwater LNG project was inconsistent with the New York Coastal Management Program. Broadwater Energy, a partnership of Shell Oil and TransCanada Corp., has asked the U.S. Department of Commerce to overturn New York regulators’ opposition to the construction of the proposed LNG terminal and pipeline facilities to be located in New York waters of Long Island Sound (see NGI, July 14, 2008). The NYSDEC, which issues water permits, has not awarded a water quality certification for the Broadwater project to date. The proposed Broadwater offshore terminal would have an average sendout capacity of 1 Bcf/d and peak sendout of 1.25 Bcf/d. Broadwater Energy would operate the facility, while Shell would own the capacity and supply the LNG. The project, which is targeted for service in December 2010, would cost approximately $700 million to build.

FERC granted Guardian Pipeline LLC‘s request to commence service on the Guardian Expansion and Extension Project (G-II) in eastern Wisconsin. The Guardian G-II expansion consists of 119.2 miles of 12-inch and 30-inch diameter pipeline extending from Ixonia, WI, to Green Bay, WI, and 78,000 hp of compression and associated facilities. The $261 million project is expected to result in an incremental 537,200 Dth/d of firm capacity on Guardian’s existing G-1 system from Joliet, IL, to Ixonia, and 437,200 Dth/d of new firm capacity from Ixonia to Green Bay. The approval came a little over a year after FERC issued a certificate for Guardian Pipeline to expand its system to meet growing demand in the region, which currently is served by only the constrained ANR Pipeline (see NGI, Dec. 24, 2007). Guardian had initially expected to place the facilities in service on Nov. 1, 2008. Guardian, which is owned by ONEOK Partners LP, has executed precedent agreements with three local distribution companies for an initial term of 15 years, including Wisconsin Gas LLC for 90,105 Dth/d, Wisconsin Electric Power Co. for 201,656 Dth/d and Wisconsin Public Service Corp. for 205,2455 Dth/d.

Houston-based Western Gas Partners LP closed its $210 million purchase of all or parts of various Powder River Basin processing and gathering infrastructure from Anadarko Petroleum Corp., which previously formed Western and eventually spun it off. Some of the purchase involves percentage interests in the Anadarko assets. The sale includes 100% interest in the Hilight processing plant, a 50% interest in the Newcastle processing facility and gathering system, and a 14.81% interest in the Fort Union gas gathering and treatment system. The midstream assets are all located in the Powder River Basin in Wyoming. A combination of debt and equity was used by Western to make the purchase. It received a five-year $175 million note from Anadarko and issued some 2.55 million common shares to Anadarko at a price of approximately $13.69/partnership unit. With the completion of this deal, Western said Anadarko now owns 63% of the common and subordinated units and 2% of the partner interest in the company. Western was originally created by Anadarko to own, operate, acquire and develop midstream energy assets. The company now holds assets in East and West Texas, the Rocky Mountains and the Midcontinent, providing gathering, compressing, treating, processing and transporting services for natural gas held by Anadarko, other producers and shippers.

Colombia’s Ecopetrol and Norway’s StatoilHydro ASA agreed to jointly drill three exploratory wells over the next two years in the deep waters of the U.S. Gulf of Mexico (GOM). The farm-in agreement would give Ecopetrol, Colombia’s largest company, a 20-30% stake in the prospects. Ecopetrol already operates in the GOM as a joint partner on the deepwater K2 Unit with Royal Dutch Shell plc, ENI, BP plc and Anadarko Petroleum Corp. Anadarko operates the K2 Unit, and in 2007 it sold part of its stake to undisclosed parties for $1.2 billion (see NGI, March 19, 2007). Daily production from the K2 Unit in 2007 averaged 37,100 boe/d from six wells, according to Anadarko. Ecopetrol and StatoilHydro did not detail where the exploration wells would be drilled. However, StatoilHydro has a big presence in the U.S. deepwater. In early 2008 the Norwegian producer expanded its stake in one of the largest GOM discoveries, Kaskida, which is located on Keathley Canyon Block 292 in the Lower Tertiary formation. StatoilHydro, considered a leader in deepwater technology, has stakes in 415 blocks in the GOM, and it operates 195 of them. It also agreed to purchase one billion cubic meters a year of liquefied natural gas from 2009 to 2014 from the Cove Point receiving terminal (see NGI, March 10, 2008). Ecopetrol’s initial investment with StatoilHydro could exceed $160 million, the companies said. In addition, the two producers agreed to undertake a process for “maturing” several projects in the GOM over the next seven years.

Boardwalk Pipeline Partners LP subsidiaries Gulf Crossing Pipeline Co. LLC and Gulf South Pipeline Co. LP asked FERC for authorization to place their 42-inch diameter Mississippi Loop in service. In a letter to FERC, the companies said that the tie-in points and hydrostatic testing is complete and they estimated that the Mississippi Loop facilities would be purged and packed by Dec. 29. The 17.8 miles of pipeline loop between Hinds County, MS and Simpson County, MS, is part of the Gulf Crossing Pipeline project. Gulf Crossing expects to place in service during the first quarter of 2009 the 356.3-mile, 42-inch diameter pipeline and associated compression facilities (100,734 hp) extending from Sherman, TX, to an interconnect with affiliate Gulf South Pipeline’s Tallulah Compressor Station in Madison Parish, LA. It also proposes to lease up to 165,000 Dth/d of upstream capacity on the Oklahoma intrastate pipeline system of Enogex and up to 1.4 Bcf/d of capacity on Gulf South from Tallulah to an interconnect with Transcontinental Gas Pipe Line‘s Station 85 in Choctaw County, AL, located at the terminus of Gulf South’s 116-mile Southeast Expansion Project [CP07-398, CP07-401]. Some shippers are challenging the leasing of the Enogex capacity (see NGI, Oct. 29, 2007). The companies said they expect the project to provide up to 1.732 Bcf/d of capacity. Devon Energy Corp., Enterprise Products Partners LP and Crosstex Energy LP are among the companies that have already committed to transportation capacity on the proposed line. FERC approved MarkWest Pioneer LLC‘s proposal to build the 24-inch diameter Arkoma Connector Pipeline, which would extend from the outlet of an affiliate’s existing treating plant in northeast Oklahoma 50 miles in a southeasterly direction to near Bennington, OK, where it would interconnect with the proposed Midcontinent Express and Gulf Crossing pipeline systems (see NGI, Nov. 17, 2008). MarkWest’s interstate natural gas pipeline would allow producers in the Woodford Shale area of Oklahoma to interconnect with the Midcontinent Express and Gulf Crossing pipeline systems for delivery of their gas to eastern markets.

El Paso Corp. reported “significant” progress in selling several noncore assets, with agreements completed or nearly finalized that altogether should net the company close to $275 million. Subsidiary El Paso Exploration & Production Co. agreed to sell two natural gas producing properties to undisclosed buyers for a total of $77 million. One property being sold is located in the San Juan Basin in northwestern New Mexico; it was acquired by El Paso in 2007 when it purchased Peoples Energy. Properties in the Shongaloo and Spring Hill fields, which are located along the Louisiana/Arkansas border, also are being sold to undisclosed buyers. The properties to be sold contain total proved reserves estimated at 40 Bcfe, with current production of 15 MMcf/d. The sales, with an effective date of Dec. 1, are scheduled to be completed by the end of January. El Paso also executed an agreement to sell its stake in the Porto Velho power generation facility in Brazil for $178 million. The sale, which should close by the end of March, would complete the company’s exit from the power business in Brazil. Sales proceeds are expected to be paid with up to $100 million in cash, with the balance paid by a note from the unnamed buyer. In addition, the Houston-based operator received $20 million from the completed sale of its legacy fuel oil terminal in South Boston, MA.

The mix of regulators on the five-member Arizona Corporation Commission (ACC) is changing with the new year following the election of three new commissioners to replace members whose terms expired at the end of 2008. After several years of an entirely Republican ACC there now will be two Democrats on the regulatory panel. The ACC is nonpartisan but the commissioners run for election under their party affiliation. All three of the new members have been elected state or local officials in the past. They are Sandra Kennedy, Paul Newman and Bob Stump, replacing outgoing Commissioners Mike Gleason, the current ACC chairman, Bill Mundell and Jeff Hatch-Miller, both of whom had served as chairman of the regulatory panel. Commissioners Kris Mayes and Gary Pierce continue on the ACC. In a statewide ballot measure in 2000, Arizona adopted a five-member regulatory commission with a limit of two four-year terms for each commissioner. They serve staggered terms.

Oregon Gov. Ted Kulongoski signed an executive order creating the Oregon Energy Planning Council to sort through a complex set of strategies involving new natural gas sources, more renewable-based electricity and a greater reliance on energy efficiency and conservation. The chair of the newly appointed 11-member council will be an Oregon State University engineering professor Ron Adams and will include senior top executives from the region’s major private- and public-sector utilities. For example, the top administrator at the federal Bonneville Power Administration, Steve Wright, was named to the panel. Kulongoski charged the new advisory body with “providing proactive analysis, advice and assistance on energy planning.” His move comes within weeks of a Dec. 3 Oregon Business Plan meeting in which it was said liquefied natural gas (LNG) should continue to be an option. Oregon is considering three separate proposals to site LNG receiving terminals. It also comes after the governor’s own energy summit held last August. Under the executive order, the planning council is charged with providing a report to the governor and the state legislature before the end of 2010. The ultimate report by the council will include updated information on the state’s current energy use and supply.

Recently released natural gas forecasts from federal and California government energy agencies late last year caused an avowed opponent of U.S. liquefied natural gas (LNG) imports, Ratepayers for Affordable Clean Energy (RACE), to re-energize its campaign with a new promotional blast just before the holidays, contending that the West Coast doesn’t need LNG. RACE cited U.S. Energy Information Administration (EIA) projections for a decline in natural gas imports overall during the next 22 years, dropping from 16% of the gas burned in the lower 48 states currently to 3% by 2030. EIA’s assumption is the difference will be made up by increased domestic gas production, said the LNG opponents, quoting the 2009 Annual Energy Outlook from the U.S. Department of Energy. Similarly, RACE highlighted a recent joint California Public Utilities Commission (CPUC) and California Energy Commission (CEC) report predicting gas demand in the state will stay essentially flat through 2030. Economic declines, renewable energy and efficiency growth and ultimately greenhouse gas (GHG) emission controls all were cited in the joint CPUC-CEC staff report as pushing down natural gas demand in the near term in California and further pushing back the need for LNG imports. The report was developed for a Dec. 8 joint meeting of the two state energy agencies to update the state’s Energy Action Plan. The state report said that one indicator of the dramatic increase in domestic U.S. gas supplies and dampening of demand is the fact Sempra Energy now has told the CEC it does not expect any meaningful shipments of LNG to its new Costa Azul receiving terminal along the Pacific Coast of North Baja California, Mexico, until late this year. A Sempra spokesperson subsequently clarified that projection for NGI, saying the company expects shipments late in the third quarter of 2009 at the West Coast terminal.

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