Toronto-based Enbridge Gas Distribution has received approval from the Ontario Energy Board to adjust the gas supply cost portion of its rates effective Thursday (July 1). The regulated gas utility said the impact of the charges would vary based on the amount of gas used and whether customers buy their natural gas from the utility or a gas marketer. Enbridge delivers gas to about 1.7 million customers in its franchise area. Of those customers, about 60% buy their gas supply from the utility, and the other 40% buy their gas supply directly from marketers. The utility’s gas supply charge, the actual cost of the gas without mark-up, will increase 16%. The new residential gas supply price will be C28.6 cents per cubic meter, up from C24.07 cents. For a typical residential customer who buys gas from the utility, this represents an annual increase of C$122, Enbridge said. Customers who buy their gas from a marketer will continue to pay the price specified in their contract with that marketer. Enbridge said its delivery charge for all customers — whether they buy from the utility or a marketer — also will increase “slightly,” attributable to higher costs for natural gas storage, which are included in the delivery charge. For a typical residential customer, the annual increase to the delivery charge will be approximately C$4.

State of Washington regulators last week announced that they unanimously approved a rate settlement with Portland, OR-based Northwest Natural Gas Corp. that includes an average 6.5% residential rate increase, effective July 1. The decision affects the gas utility’s 54,000 residential and business customers in the southwestern part of the state. Northwest Natural reached a settlement agreement on the rate increase last month with commission staff, the Public Counsel division of the state attorney general’s office, Industrial Gas Users and the Citizens Utility Alliance. The Washington Utilities and Transportation Commission okayed the settlement that authorized $3.5 million in added revenue for the utility. Northwest had originally asked for a $7.9 million increase last November. Residential customers on average face about an added $2 on their monthly gas bills. Commercial customers face an average 6.8% rate hike, or $40 more each month.

Range Resources said it completed the purchase of the 50% of Great Lakes Energy Partners LLC that it did not previously own for $200 million plus the assumption of $68 million of Great Lakes bank debt and the retirement of $27 million of oil and gas commodity hedges. Great Lakes, a 50/50 joint venture between Range and Akron, OH-based FirstEnergy Corp., was formed in 1999 to hold their Appalachian oil and gas properties. Range estimates that it is acquiring 255 Bcfe of net proved reserves in the transaction — Great Lakes has a total of about 500 Bcfe of reserves. The purchase will add 35 MMcfe/d to Range’s production, increase its leasehold position by 664,000 net acres and bring it full control of 5,100 miles of gas gathering systems, having a throughput of more than 100 MMcfe/d. The deal makes Range the third largest Appalchian producer. The acquisition increases Range’s proved reserves by 30% to more than 900 Bcfe and increased its production by 20% to more than 210 MMcfe/d. The purchase cost equates to $1.09/Mcfe of proved reserves after the allocation of $12 million of the purchase price to undeveloped leasehold and gathering systems. Range’s production growth target for the second half of 2004 has been increased to 32-34%. A preliminary production growth target of 12-15% has been set for 2005, assuming no further acquisitions.

Cheniere Energy Inc. has selected Mitsubishi Heavy Industries (MHI) and Matrix Service as the liquefied natural gas (LNG) tank subcontractors for both its Sabine Pass & Corpus Christi LNG receiving terminals. The work will entail engineering and construction of three 160,000 cubic meter single containment storage tanks at each site. Final negotiations with MHI/Matrix are expected to be complete in the next few weeks. Construction of the LNG receiving terminals is expected to start during the first quarter of 2005, subject to receipt of construction permits by the end of 2004. Cheniere filed applications with the Federal Energy Regulatory Commission on Dec. 22, 2003, for permits to site, construct and operate LNG receiving terminals near Sabine Pass, LA, and Corpus Christi, TX. Each facility is designed to have an initial natural gas processing capacity of 2.6 Bcf/d. “FERC recently granted the permit for the first project we started in Freeport, TX,” noted Cheniere CEO Charif Souki. “With all of Freeport’s 1.5 Bcf/d of capacity spoken for, it is urgent for the local and national economies that we move rapidly on our current projects in Sabine Pass and Corpus Christi to deliver an additional 5.2 Bcf/d of import capacity.”

The Sacramento Valley in California was touted Wednesday as an E&P hot spot by a Tucson, AZ-based Fidelis Energy Inc., which announced that its first exploration well tested at 12 MMcf/d from a 1,000-acre tract on the North Franklin Project. It taps the so-called Winters Formation, a new discovery on a ranch about 25 miles south of the state capital in Sacramento County. A Bakersfield, CA-based operator, Archer Exploration, has been exploring the area for about two years and began the first well in this formation a month ago with $500,000 backing from publicly held Fidelis Energy, according to a spokesperson for the firm. Fidelis said it will drill up to five additional wells in the area. According to Fidelis’ announcement, gas samples acquired during the recent flow test “produced a 94% pure result (with a 940 Btu content to the gas). In addition, reservoir engineers report that Fidelis can expect excellent deliverability under producing conditions. “Given the casing pressure was increasing at the end of the testing period, the resulting absolute open flow rate of 12 MMcf/d is a conservative calculation.”

Houston-based Enterprise Products Partners LP and GulfTerra Energy Partners LP have scheduled a special meeting of their common unitholders on July 29 to vote on the approval of a merger between the two partnerships. The two announced their merger late last year, which, when approved, will form the second largest publicly traded energy partnership in the United States (see Daily GPI, Dec. 16, 2003). The new partnership will be worth about $13 billion, with the jointly owned affiliates of Enterprise and El Paso Corp. each owning a 50% stake. Enterprise’s registration statement on Form S-4, including the joint proxy statement/prospectus for the special meeting, was declared effective by the Securities and Exchange Commission, and the proxy statement was to be mailed to the unitholders of both companies.

Houston-based Meridian Resource Corp. said an electric log analysis reflects “apparent gas pay” in two separate sands, the Cris “I” and the Big hum sand intervals at its Biloxi Marshlands No. 24-1 well at the Oars Deep prospect area. The well was recently tested from the Cris “I” sand interval, the deeper of the two sand intervals, through 12 feet of perforations between a gross pay interval of 9,600 feet and 9,642 feet at a stabilized gross daily flow rate of 8.3 MMcf/d through a 22/64-inch choke. Flowing tubing pressure was measured at 2,674 psi and shut-in tubing pressure was measured at 3,032 psi. The well was placed on production on June 18, at 5.7 MMcf/d through a 13/64-inch choke with a flowing tubing pressure of 2,900 psi. The company owns a 92% working interest in the well.

Fitch Ratings has revised Occidental Petroleum‘s Outlook to Positive. Currently, Fitch rates the producer’s senior unsecured debt and bank revolver “BBB+” and its commercial paper “F2.” The change in Outlook affects approximately $4 billion in publicly traded debt securities. The revision, said Fitch, reflects Occidental’s growing production and reserves coupled with continued debt reduction that has occurred over the past year. The company increased production 6.2% in 2003 to 547,000 boe/d from 515,000 boe/d in 2002, and “it is likely to increase it again by slightly over 5% in 2004 to approximately 575,000 boe/d.” Analysts said expectations are for continued growth in production and reserves that is currently being funded by relatively modest capital spending levels. Operationally, the company has replaced reserves at economic costs over the past few years, said Fitch, with organic reserve replacement averaging 124% over the past three-year period at a finding and development cost of $4.78/boe. The company’s reserve replacement over the same time period averaged 156% at a finding, development, and acquisition cost of $4.54/boe. Also, over the past several months, the company has reduced debt by another $400-500 million.

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