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Excelerate Energy confirmed that its Explorer liquefied natural gas (LNG) tanker began offloading regasified LNG at the Northeast Gateway LNG terminal offshore Boston. A blockage in Algonquin Gas Transmission's HubLine gas pipeline had prevented the offloading since the tanker arrived in January. Algonquin said its pipeline was back in service on the previous Monday. The cargo is the terminal's second, an Excelerate spokesman told NGI. The first cargo was received in May 2008. The spokesman said he did not know when the next cargo was expected. Northeast Gateway consists of two submerged buoys that attach to specialized ships capable of regasifying LNG on board and sending it into a subsea pipeline. The HubLine system runs under the ocean floor across Massachusetts Bay and connects to the New England natural gas grid.

The Texas Senate passed two bills relating to natural gas production in the Barnett Shale. Both were sponsored by Sen. Wendy Davis (D-Fort Worth). SB 686 would allow gas pipelines to be placed in Texas Department of Transportation right-of-way, giving pipeline companies more placement options and thereby reducing the number of eminent domain cases pursued to place pipelines. SB 752 would restrict the placement of injection wells for the disposal of contaminated drilling wastewater by limiting the geologic formations for which the Texas Railroad Commission can issue a disposal well permit in Tarrant County. SB 686 and SB 752 will now go to the Texas House where companion bills are being offered by Rep. Rob Orr and Rep. Kelly Hancock, respectively.

Because the Wabash River has remained above flood stage since early April, Rockies Express (REX) now projects it will commence REX-East service to the four delivery points in Illinois that are upstream of the Wabash in mid-May. "We anticipate service to the NGPL, Ameren, Trunkline and Midwestern delivery points in Illinois to commence in mid-May 2009 with the addition of the PEPL [Panhandle Eastern Pipeline] delivery point (Putnam County, IN) in late May," the pipeline said in an informational posting. "The Illinois River horizontal directional drill (HDD) has progressed to an advanced reaming stage and it is anticipated that we will complete reaming in the next few days." The Wabash was expected to remain at flood stage through last weekend, REX said, noting that activities would resume once the river recedes below flood stage. REX affirmed its previously projected in-service dates for Lebanon, OH, of June 15 and Clarington, OH, of Nov. 1. Earlier this month REX said it had experienced delays with two remaining horizontal directional drills and projected it would begin interim service on REX-East in mid-May (see NGI, April 13). In March the pipeline said service on the segment would begin in late April or early May (see NGI, March 30). Information is available at www.rexpipeline.com under "Rockies Express-East" and "Informational Posting."

TransCanada Corp. filed at FERC seeking pre-filing status for its proposed Alaska Pipeline Project. The pipeline said pre-filing status would "enhance the exchange of information with Commission staff and assist in the coordination of agency activities for this significant infrastructure project." TransCanada holds the state concession under the Alaska Gasline Inducement Act (AGIA) to construct a pipeline from the North Slope to carry gas to Lower 48 markets. Pursuing a competing project are BP and ConocoPhillips, which have proposed the Denali pipeline outside of the AGIA framework. The Denali partners already have secured pre-filing status at the Federal Energy Regulatory Commission (see NGI, June 30, 2008). The future of both projects is in doubt due to the shifting nature of North American gas markets. Robust production from established and emerging gas shale plays has pushed gas prices down to levels that make a major North Slope pipeline uneconomic. Additionally, the North American market is poised to receive additional imports of liquefied natural gas (LNG) as the global market for LNG has weakened and supplies are ramping up. In the meantime, Alaska's Southcentral region is in need of new gas supplies for which the state has been considering in-state gasline projects (see NGI, April 6).

Houston-based Apache Corp. is reducing its global workforce to "reflect current activity levels," a spokesman said. The move follows job cuts announced publicly by other energy companies in the past few months (see NGI, April 20; March 30; March 2a; March 2b). "Because lower commodity prices mean lower cash flow and capital budgets, we have reduced our employee ranks...," Apache's Bill Mintz, director of public affairs, told NGI. "These actions will reduce Apache's worldwide employee count by 6% since the first of the year." About 200 positions are affected, he said. The planned reductions have been "substantially completed," but Mintz said he could not provide details on what types of employees are being laid off nor could he say where the reductions were taking place.

New Orleans-based McMoRan Exploration Co. posted a quarterly loss for the first three months of the year, which it blamed partly on lower natural gas and oil prices and partly on lower production. Some of its gas-weighted output remains shut in because of third-party facility outages following last September's hurricanes in the Gulf of Mexico (GOM). The independent, which focuses on deep gas prospects offshore, reported a loss in 1Q2009 of $63.2 million (minus 90 cents/share), compared with earnings of $32 million (46 cents) in 1Q2008. Continuing operations reported losses of $59.5 million, which included a $39 million loss (minus 55 cents/share) in impairment charges for certain fields to reduce their net carrying value to fair value. and $16.2 million (minus 23 cents) for exploration wells determined to be noncommercial. In addition, McMoRan's results were impacted by an $18 million mark-to-market gain on hedging contracts an $18.7 million gain associated with its share of insurance proceeds related to the September 2008 hurricanes. Gas and oil output in the quarter averaged only 198 MMcfe/d net, compared with 294 MMcfe/d for the same period a year ago. An estimated 45 MMcfe/d of McMoRan's production continues to be constrained by outages at third-party facilities. Based on "recent" information from operators of these facilities, McMoRan estimates production will average 215 MMcfe/d for the year. To ensure it can continue to fund its exploration, McMoRan said it "may pursue additional partner arrangements to further reduce capital expenditures."

In a move that would create a $595 million combined energy company serving 200,000 customers in three states, Chesapeake Utilities Corp. (CPK) and Florida Public Utilities Co. (FPU) agreed to merge FPU with a CPK subsidiary. Under terms of the all-stock transaction, holders of FPU common stock will receive 0.405 shares of CPK common stock in exchange for each outstanding FPU share. Based on the average of CPK's closing stock price on the 15 trading days prior to April 15, the transaction has an approximate value of $12.20/FPU share. The companies said they expect the transaction to be earnings neutral or slightly accretive in 2010 and meaningfully accretive in 2011. The merger is intended to qualify as a tax-free reorganization and is subject to approval by shareholders of both companies. The merger has already been approved by both companies' boards of directors. It must be approved by federal and state regulatory authorities, including the Delaware Public Service Commission and the Maryland Public Service Commission. The companies anticipate closing of the transaction during the fourth quarter. At the close of the merger FPU would become a wholly owned subsidiary of CPK and would initially continue to operate as a separate business unit. Over time, FPU and Central Florida Gas -- a division of CPK -- would integrate their operations, conducting business under the name Florida Public Utilities. CPK CEO John Schimkaitis would become chairman and CEO of the new Florida Public Utilities. Current FPU CEO Jack English would be retained as a consultant for up to 24 months following the merger and two members of the current FPU board of directors would join the CPK board. The company created by the merger would have approximately 117,000 natural gas customers, 31,000 electric customers and 48,000 propane customers in Delaware, Maryland and Florida. CPK and FPU reported $291.4 million and $168.5 million in revenues, respectively, and $13.6 million and $3.5 million in net income, respectively, for 2008.

Lower natural gas prices have prompted Questar Gas to ask the Public Service Commission of Utah (PSC) to approve an immediate $50 million one-time rebate to its customers. If approved, the rebate will reduce the typical customer's May natural gas bill by $40-$45, Questar said. Twice a year Questar and the PSC use third-party forecasts of natural gas prices to estimate how much the utility's rates should be adjusted to cover anticipated costs of buying natural gas for its customers. In November Questar cut natural gas rates by $63 million (5.3%); in March the utility cut rates another $157 million (16%). Citing the weakness of the economy, Questar said it wanted to pass the lower fuel costs on to its customers ahead of the scheduled autumn rate adjustment.

Minneapolis-based Xcel Energy's Colorado utility retail natural gas bills in May should be 38% lower than this month overall -- 39% lower for residential customers and 45% lower for small businesses than they were last May. The commodity rate in May 2008 was three times higher than what is projected for this May, Xcel said. With expected warmer weather driving down gas use, typical May 2008 bills were a little more than $42, which would be 39%, or $16.50 more than the projected bills for next month, adjusted for expected average current use of 31 therms, Xcel said. Warmer weather also is expected to result in a 40% decrease in use in May for typical small business customers when compared to this month. Bills in May could decrease 38% to just a little more than $113, compared to average bills this month for the same customers of $183, using on average more than 100 more therms. Xcel has proposed revised commodity prices to the Colorado Public Utilities Commission (PUC) for residential and small business customers, projecting a 10% drop next month to 28.96 cents/therm, compared to the current price of 32.21 cents/therm. By comparison, last May the price was 84.52 cents/therm. The change reflects anticipated natural gas prices and impact on customer bills for this May, Xcel said. If approved by the PUC, the new natural gas commodity price would take effect Friday (May 1).

The Idaho Public Utilities Commission (PUC) will hold a series of public hearings in various parts of the state served by Spokane, WA-based Avista Utilities to gain public input on Avista's proposed general rate increases of $2.7 million for natural gas and $31.2 million for electricity utility customers, or 3% and 12.8%, respectively, the PUC announced April 17. In late January Avista asked the PUC for a net electric rate increase and a natural gas hike. The request for electric retail rates was a 12.8% rate hike to be offset by a 5% reduction in the current power cost adjustment. Avista serves 121,000 electric and 93,000 gas customers in Idaho. The PUC subsequently suspended the rate request and began an assessment. The PUC has scheduled workshops for May 12-13 in Sandpoint and Lewiston, ID. More hearings are scheduled for June 16-17 in Moscow and Coeur d'Alene, ID. Technical hearings will begin June 29 and will continue for up to three days, according to a PUC spokesperson. Written comments from customers will be accepted through July 1. Commission staff and intervenors in the case must file written testimony by May 29 and any rebuttal testimony by June 19.

Six coastal states will share nearly half a billion dollars from offshore oil and natural gas revenues in fiscal years (FY) 2009 and 2010 to help restore and protect coastal wetlands, wildlife habitat and marine areas, Interior Secretary Ken Salazar said. Four Gulf Coast states, Alaska and California will share a total of $242.5 million in each fiscal year for a total of $485 million, with $315.2 million going directly to the states and $169.6 million earmarked for coastal political subdivisions, according to Interior. Louisiana will receive the lion's share of the money -- $121 million in each fiscal year. It is followed by Alaska ($37.5 million per year in FY 2009 and 2010); Texas ($35.6 million per year); Mississippi ($23.8 million annually); Alabama ($19.7 million per year); and California ($5 million per year). The Energy Policy Act of 2005 authorized that funds be distributed to states adjacent to Outer Continental Shelf oil- and gas-producing areas to mitigate the impacts of energy development on marine and coastal areas.

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