Sunday, August 28, 2011

BOEMRE issues revised EIS for Chukchi Sea

By Tim Bradner
Alaska Journal of Commerce

The U.S. Bureau of Ocean Energy Management, Regulation and Enforcement has issued the final supplemental environmental impact statement for the Chukchi Sea OCS Sale 193.

A lawsuit over the EIS is still pending in court, however, and the new document must be cleared by the court for the companies that bid on and won Chukchi Sea leases to finally have clear title to them. The sale was held in February 2008, and netted more than $2 billion on bonus bids, mostly from Shell. ConocoPhillips, Statoil and Repsol also bid.

A court decision on the case could come in October, a source close to the litigation said.

The environmental impact statement for the 2008 sale was challenged by a coalition of environmental and Alaska Native groups and was sent back to the agency for changes by a U.S. Federal District Court in Alaska in July, 2010.

An earlier version of the SEIS to correct the legal deficiencies was prepared in late 2010, but BOEMRE in early 2011 decided on further changes, to include a hypothetical "very large oil spill" scenario and developed a second SEIS that has now been issued in its final version.

Shell officials were pleased by the action.

"Last summer, an Alaska Federal District Court found the environmental impact statement that supported Chukchi Lease Sale 193 lacked certain information from the BOEMRE," said company spokesman Curtis Smith. "The agency has now provided additional information. We remain hopeful the BOEMRE will approve Shell's Chukchi plan of exploration as soon as possible after Secretary Salazar issues the record of decision."

The final document included a very large oil spill scenario, where a well "blowout" occurs that could spill 61,000 barrels of oil per day and last 74 days, spilling a total of 2.1 million barrels. This is a hypothetical spill, however, and is not the "worst case" spill scenario that an explorer would be required to prepare for at a specific exploration location, a BOEMRE official in Anchorage said. That scenario would be tailored to the geologic and environmental conditions at the site, the official said.

BOEMRE held two rounds of hearings in Alaska communities with the 2010 and 2011 versions of the SEIS.

"We have worked diligently to address the District Court's concerns in a thorough and comprehensive manner," said BOEMRE director Michael Bromwich. "This will insure that decisions related to this lease sale will be made in a careful, balanced manner using the best scientific information available."

Shell, ConocoPhillips and Statoil are planning exploration wells in the Chukchi Sea and some federal permits have been issued in draft form by federal agencies. Shell and ConocoPhillips hope to drill exploration wells in the Chukchi Sea in 2013 but have previously said that legal issues surrounding the original lease sale must be resolved.

Republished with the permission of the Alaska Journal of Commerce. Tim Bradner can be reached at tim.bradner@alaskajournal.com.

State O&G division scolds Escopeta

By Tim Bradner
Alaska Journal of Commerce

The Spartan 151's deck, heliport and two of its independently adjustable 150-foot legs are at left in this photo. Photo/M. Scott Moon/Peninsula Clarion
Escopeta Oil and Gas Co. is negotiating a possible fine with the U.S. Department of Homeland Security over a violation of the U.S. Jones Act that occurred when the company moved the Spartan Drilling Co. Blake 151 jack-up rig recently from the U.S. Gulf Coast to Cook Inlet.

"There are discussions under way but nothing has been determined," Escopeta spokesman Steve Sutherlin said.

The Blake 151 is now being prepared for final state inspections by the Alaska Oil and Gas Conservation Commission, Sutherlin said. Drilling is expected to begin within days.

The Jones Act violation occurred after Escopeta used a Chinese heavy-lift vessel to move the Blake 151 part of the way to Alaska. The rig was moved from the Gulf Coast to Vancouver, B.C., with the Chinese vessel, where it was offloaded to allow work to be done on the rig. The subsequent tow from British Columbia to Alaska's Cook Inlet was done with U.S.-built tugs supplied by Foss Maritime, a U.S. company.

The Jones Act requires cargoes moved between U.S. ports to be in American-built and -operated vessels even if the voyage is broken with a stop at a foreign port, as occurred with the Blake 151 movement.

The resulting uproar over the rig movement, with letters of complaint being written to Homeland Security Secretary Janet Napolitano by several U.S. senators as well as U.S. shipping groups, resulted in Escopeta President Danny Davis stepping down from his position, Davis has acknowledged.

The U.S. Customs and Border Protection, which is part of the Department of Homeland Security, has jurisdiction over Jones Act administration.

In a related development, Alaska's state oil and gas director, Bill Barron, chastised the company for moving the Blake 151 into location in upper Cook Inlet and lowering the legs on the jack-up rig to the ocean bottom without completing sea bottom site surveys required by the state.

"Our concern is with the company's operational practices, not the condition of the rig," Barron said.

Barron wrote Escopeta a sternly worded letter intended to put the company on notice that, "these are not acceptable practices," he said, referring to the company's action in moving the rig without having all of the authorizations.

No penalty against Escopeta is contemplated at this time, Barron said. The state just wants the company to adhere to all rules, he said.

"The last thing we need is a major incident in Cook Inlet," with and oil and gas operator, Barron said.

In his letter to Escopeta's current president, Edward Oliver, Barrow said, "While the division is pleased to see a jack-up rig arrive in the state, I am gravely concerned about what I perceive to be Escopeta's apparent disregard for regulatory requirements."

In the letter, Barron cited Escopeta's action to ship the Blake 151 rig to Alaska without having obtained a Jones Act waiver as well as the company's decision to move the rig to the final location without first having U.S. Army Corps of Engineers permit. However, a Corps of Engineers spokeswoman in Anchorage said the company is now in compliance with its requirements. U.S. Coast Guard rules are also being complied with, a Coast Guard spokesman said.

Escopeta had sought a waiver of the Jones Act arguing that no U.S.-built vessel was available at the time that could have moved the Blake 151 safely through rough seas around the tip of South America. The government had granted Escopeta a waiver in 2006, but financing for the rig fell through and when Escopeta put its deal back together in late 2010, the department would not grant another waiver, citing the lack of a U.S. security justification needed for Jones Act waiver.

Alaska U.S. Sen. Mark Begich said in an interview Aug. 22 that the U.S. Department of Energy, which made the energy security determination for Homeland Security both in 2010 and 2006, has not explained reasons for changing its position. Begich and other members of Alaska's congressional delegation had interceded on Escopeta's behalf with Napolitano, although the effort to get the waiver was unsuccessful.

"They would never have stopped the rig being unloaded. Napolitano was always supportive of our efforts to get more exploration in Cook Inlet, particularly for natural gas, which we need," Begich said.

Begich said a penalty is now being negotiated between the Department of Homeland Security and Escopeta, and that he has asked the department for a "modest" penalty.

"A violation of the Jones Act has occurred but we don't want the penalty to bankrupt the company," Begich said.

Jones Act penalties are at least partly based on the value of the cargo being transported, in this case of value of the Blake 151 jack-up rig.

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Republished with the permission of the Alaska Journal of Commerce. Tim Bradner can be reached at tim.bradner@alaskajournal.com.

Friday, August 26, 2011

Division looks at potential for multiple permitting with unit plan

Alan Bailey

Faced with continuing precipitous declines in oil production both from Alaska’s North Slope and from Cook Inlet, Alaska’s Division of Oil and Gas is pursuing various avenues to encourage new oil exploration and development, William Barron, division director, told the Anchorage Chamber of Commerce Make it Monday Forum on Aug. 22.

Permitting restructure

The division is actively looking to restructure the permitting of oil and gas projects, Barron said. And one possibility is the authorization of the permits for multiple activities within a company’s unit plan of development, as part of plan authorization.
“If we can do that, then people will have an assurance of their ability to go forward rather than always permitting the same task over and over,” he said.

Typically, a plan of operation involves several projects and covers a period of three to five years. The division has to approve the overall plan, but individual projects within the plan separately require a series of individual permits. Barron told Petroleum News in an Aug. 21 email that the division has not yet taken its thoughts on “plan permitting” beyond the conceptual stage, and that the complete scope of the concept and the specifics of what, if any, statutory or regulatory changes might be involved have yet to be worked out. The idea would be to look out further in time than has tended to be the custom, to secure as many permits as possible, based on the plan of operations, he said.

The division is also working on the creation of a statewide information clearing house for permit information and other critical information associated with oil and gas activities and with geothermal work, Barron told the Chamber of Commerce audience.

“The idea here is to try to have a little bit more transparency and a bit more openness across the board for anybody who’s trying to do work, to understand what’s been done,” he said.

Barron also said that the division is looking at the possibility of introducing bonding for restoration at the end of the useful life of oil and gas facilities, asking questions about what the abandonment liabilities might be and what the state and landowners might want left at a site after facility decommissioning.

Unconventional oil & gas

The division’s resource evaluation group is in the process of building on its knowledge of unconventional oil and gas, while the division’s commercial group is, among other things, working on issues relating to shale oil, Barron said.
The units section is updating division regulations to promote oil and gas development while protecting state interest, he said.

“You can lease land all day long but if you don’t do exploration and if you don’t bring it to production the only thing the state gains is basically the bonus (bid) and the rental from the lease,” Barron said.

One issue that this section is addressing is the encouragement of exploration and development during the regular term of a lease, to reduce the tendency for a business to apply for unit formation at the end of a lease term, to allow exploration to take place after the lease would have otherwise expired, he said.

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Republished with the permission of the Petroleum News













Alaska grapples with rural energy puzzle; Resource-rich state joins federal government, private sector in seeking w

Rose Ragsdale
For Alaska-Washington Connection

Alaska has enormous quantities of untapped or under-utilized energy resources, including some of the highest concentrations of fossil and renewable energy resources on earth. In addition to vast oil and natural gas resources, primarily located on the North Slope and in Cook Inlet, the state has proven coal reserves that rank as the fourth-largest fossil energy resource in the world. Nature also bestowed significant undeveloped geothermal resources in the volcanic art of the Aleutian Islands, abundant untapped hydropower, wind, and biomass resources, and the majority of the tidal and wave power potential in the United States.

Yet rural communities throughout Alaska are chronically burdened with economy-stifling high energy costs. When oil prices spiked to $144 per barrel in July 2008 before plummeting to under $50 per barrel by December 2008, many Alaska villages where winter fuel must be purchased before fall freeze-up suffered a severe shock and extraordinary economic hardship. For those communities, there was no potential relief until the following spring.

While no year since has been as bad, Rex Wilhelm, president and CEO of Alaska Commercial Co., said his company, which owns and operates grocery and general merchandise stores in at 27 rural Alaska communities, keeps a close watch on oil prices.

“We’re very conscious of the price of oil and the dependence on it in our markets,” Wilhelm said. “We purchase fuel from the local vendor like everyone else.”

Alaska Commercial Co. also pays fuel surcharge on the goods shipped to its stores when oil prices are high. “We’ve had some relief in recent weeks, but with oil at $90 per barrel, it’s still very high on the freight rates,” Wilhelm said. High energy prices affect everything in rural Alaska, he added.

Investments in energy savings

In recent years, the Alaska Energy Authority, the Denali Commission and the Alaska Center for Energy and Power have spearheaded a mammoth investment of millions of dollars into everything from upgrades of bulk fuel storage tanks to renewable and emerging energy research projects. Alaska Gov. Sean Parnell signed into law a $2.8 billion capital budget in June that includes $1 billion for energy projects.
Along with the efforts of a wide variety of private sector stakeholders and even schoolchildren, these initiatives are paying off as rural communities report energy cost savings, ranging up to 30 percent.

This is good news because the State of Alaska has a goal of deriving half its power from renewable energy sources by 2025.

But it is the “low-hanging fruit” of energy efficiency programs such as weatherization and heating system upgrades that is making the biggest strides in cutting rural heating and fuel bills, said Denali Daniels, senior program manager of the Denali Commission’s energy program. Parnell earmarked a total of $101.5 million for weatherization and home energy rebates in the FY12 capital budget.

“It’s a question of how do we get the biggest bang for our buck,” she said.

Thus the Commission focuses mainly on project planning and design rather than construction.

“We’d rather spend $50,000 for a planning grant on a project that doesn’t move forward than spend $5 million on construction of a plant that shouldn’t have ever been built,” Daniels said.

Currently, the Energy Authority’s Alternative Energy and Energy Efficiency program manages and funds more than 125 projects and initiatives totaling $188 million in state and federal funding. The projects seek to lower the cost of power and heat to Alaska communities, while maintaining system safety and reliability.

Private initiatives pay off

NANA Regional Corporation, the Alaska Native regional corporation for Northwest Alaska, is working to solve Alaska’s rural energy puzzle through partnerships with regional, state and federal entities on a variety of renewable energy projects, including hydropower, wind, biomass and alternative fuels development.
“We are actively engaged with our regional partners as well, like the Northwest

Arctic Borough, Kotzebue Electric Authority and Alaska Village Electric Cooperative on wind development in the communities of Deering, Buckland, Noorvik, Kivalina, Kotzebue and the communities of the Upper Kobuk,” said NANA spokeswoman Shelly Wozniak.

Beginning in August, NANA, in conjunction with RurAL CAP, is implementing the highly regarded Energy Wise Program. The program engages rural Alaska communities in behavior change practices resulting in energy efficiency and energy conservation.

In FY 2010, Energy Wise was responsible for reducing electrical and home-heating costs for residents in 32 Alaska villages, and for training 160 rural Alaskans who were employed for 6-8 weeks. The program also conducted energy fairs in 32 communities; provided energy use assessments, education and low-cost, efficiency upgrades for 2,000 homes; and educated 7,500 rural Alaskans on energy efficiency and energy conservation strategies.

NANA is the first private organization to fund a regional rollout of the Energy Wise Program, committing $860,000 for six communities in the NANA region in 2011. With the price of fuel climbing, NANA said the Energy Wise Program will help the Northwest Alaska region conserve energy and save money as its communities get ready for winter.

To offset its higher energy costs, Alaska Commercial Co. is investing millions of dollars in lighting and refrigeration equipment upgrades during the next five years, including spending one-third of its capital budget on new refrigeration cases.

In addition, the company is rerouting the heat by-product from equipment such as compressors into its stores to reduce its consumption of heating oil. It also recently entered a joint venture with the City of McGrath in which the heat by-product of the community’s power plant is piped into the AC Store next door.

Alaska Commercial also worked hard at improving the flow of goods to its stores, which factors into its energy costs. This included opening the large warehouse at the Port of Tacoma in 2010 as a major distribution center which allows it to buy certain items in bulk and leverage less-costly waterborne transportation to ship larger quantities of shelf-stable items when rates are low and pass the savings on to customers.

A number of transportation companies that serve the Alaska market, including Bowhead Transport Co. and NorthStar Gas, also have invested in new equipment to improve fleet efficiency and offset the high cost of fuel. NorthStar Gas, for example, recently purchased a new barge, the “Cuaneq.”

Renewable energy that works

“The challenge for Alaska will be developing renewable energy systems that can be successfully integrated with existing diesel systems, because public perceptions aside, fossil fuels such as natural gas and propane supplies from the North Slope, will remain an important part of the energy equation for the foreseeable future,” Daniels said.
Among the possibilities, hydroelectric power is exceedingly attractive. It is the least expensive form of power in Alaska by 15 percent and the least expensive form of heat by a factor of 3.5 to 1, according to the Alaska Energy Authority.

Researchers say Southeast has adequate hydroelectric potential to serve all of its needs for decades to come if an intertie system existed to transport power to the region’s high-use areas. Without a regional electrical grid, isolated load centers likely will continue to rely on high-cost diesel generation to meet immediate needs.

Alaska’s FY12 capital budget provided $28.5 million for a project at Blue Lake near Sitka and $8 million for one at Whitman Lake near Ketchikan.

Other regions of Alaska also have potential for hydroelectric generation.

A new major hydro project – a dam project on the upper Susitna River won $65.7 million in state funds in this year’s capital budget, while a project on Chikuminik Lake in the Yukon-Kuskokwim Region of western Alaska also secured $10 million in state funding.

Among other renewable energy sources, wind is proving to be a viable opportunity for many small Alaska communities.

Building wind systems is costly, but once in place, the cost of wind is stable, while diesel fuel prices are volatile, according to University of Alaska Anchorage. In a preliminary analysis of wind-diesel systems in Alaska, produced by the Institute for Social and Economic Research, they note that there are already more than a dozen wind-diesel systems generating electricity in remote areas of western Alaska, and only three wind systems, in Kotzebue, Wales, and Saint Paul Island, have been operating for more than a few years. Some 10 projects were under construction in the spring of 2010, while another 23 projects were in feasibility studies or negotiating contracts to begin work.

Alaska Village Electric Cooperative, for example, has about 30 100-kilowatt wind turbines currently in operation and six more 65-kilowatt units scheduled to be operational by fall, serving a total13 villages in western Alaska. The cost of recently built wind systems average about 14 cents per kilowatt-hour, or the energy-equivalent of diesel priced at about $1.90 a gallon, according to ISER. Diesel prices reported by many rural utilities in 2009 ranged from $4 to $5 a gallon.

The U.S. Department of Energy is introducing wind energy to the nation’s small communities through its “Wind for Schools Program,” an effort that Lynden Transport, Alaska Marine Lines, Alaska Hovercraft and Lynden Air Cargo is supporting in Alaska with an offer to provide in-kind assistance to transport wind turbines and towers to 14 communities in Alaska. For example, Alaska Marine Lines recently transported the components of a wind turbine to Sitka’s Mt. Edgecumbe School.

Emerging energy technologies

Researchers at the Alaska Center for Energy and Power in Fairbanks estimated in 2010 that Alaska’s vast geography also holds about 40 percent of the country’s potential river energy, and thus, perfect settings for small-scale hydrokinetic technology – turbines designed to harness kinetic energy from oceans, bays and rivers. Micro-hydropower systems usually generate up to 100 kilowatts of electricity and are mostly used by homeowners and small business owners. Run-of-the- river hydroelectricity is ideal for streams or rivers with a minimum dry weather flow. Such systems also could help trim rural Alaska’s dependence on heating oil and diesel fuel.
NANA is engaged in micro-hydro and run-of-river hydropower pre-engineering development efforts that have potential in Shungnak, Kobuk and Ambler.

Federal regulators are reviewing plans for a submerged, in-river power turbine near Nenana in a pilot project that energy researchers and the developer think could help rural Alaska communities. Two other small in-river turbines are being tested near the Interior communities of Ruby and Eagle.

Among other emerging energy technologies currently being studied in rural Alaska include energy storage batteries and solar hot water systems by Kotzebue Electric Association; a wood pellet-fired boiler by Sealaska Corp at its headquarters in Juneau, Organic Rankine cycle waste heat recovery by the Tanana Chiefs Conference; high penetration hybrid power system by the University of Alaska Fairbanks; psychrophiles (cold-weather-loving microbes) for generating heating gas by the Cordova Electric Cooperative; seawater heat pump system by the Alaska SeaLife Center; wind-diesel hybrid power system (controls and communication) in Wales, Alaska by Kotzebue Electric Association, and Nenana hydrokinetic project by Ocean Renewable Power Co/UAF.

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Republished with the permission of the Petroleum News










Friday, August 19, 2011

Australian company to supply gas to Enstar

By Tim Bradner
Alaska Journal of Commerce


Buccaneer Energy Ltd., an Australian independent oil and gas company, has signed a contract to sell up to 15 million cubic feet per day of natural gas from the company's new Kenai wells in Southcentral Alaska to the Alaska Pipeline Co. and Enstar Natural Gas Co., Buccaneer said Aug. 15 in a press release.

Gas deliveries from Buccaneer's wells, on the Kenai Peninsula, will begin in April 2012, when the Cook Inlet Natural Gas Storage Facility being developed by SEMCO and Mid-American Energy Holdings is completed. The new gas storage facility is near Buccaneer's discovery well, Kenai Loop No. 1.

The sales price agreed on is an average of $6.03 per thousand cubic feet, a blend of $5.96 per thousand cubic feet for deliveries during the spring, summer and fall, from March through November, and $7.06 per thousand cubic feet for winter deliveries, from December through February. In the 2010-2011 winter period Enstar paid an average of $9 per thousand cubic feet for peaking gas purchased through its auction.

Buccaneer has also agreed to make additional gas available to Enstar during an auction process the utility operates during the winter to meet peaking needs.

Buccaneer drilled the well earlier this year and announced a gas discovery with estimated reserves of 40 billion cubic feet. Drilling on a second well is expected to begin within two weeks, company officials told local community leaders in a briefing.

Under the contract Buccaneer has committed to drill a third production well in late 2013.

The Kenai Loop gas field is approximately one and a half miles from the existing Cannery Loop gas field on the Kenai Peninsula. Cannery Loop is operated by Marathon Oil Co.

"This is major milestone for Buccaneer," company spokesman Dean Gallegos said. "This gas contract represents the first contract executed by Enstar to supply its capacity in the new gas storage faculty. Southcentral Alaska suffers from a shortage of natural gas, and the problem is expected to deteriorate over the next two to three years. Buccaneer looks forward to playing a major role in helping alleviate this shortage."

Buccaneer also has plans to move a jack-up rig from Asia to Cook Inlet later this year or in early 2012 to drill offshore prospects in Cook Inlet.

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Republished with the permission of the Alaska Journal of Commerce. Tim Bradner can be reached at tim.bradner@alaskajournal.com.

Legislators queasy over big bucks committed to gaslines

By Tim Bradner
Alaska Journal of Commerce


Alaska legislators are getting queasy over three quarters of a billion dollars the state will have committed to help fund North Slope natural gas pipeline projects. Lawmakers voted to approve the money, but there are no guarantees yet the state will get anything.

"We're being asked to approve substantial appropriations for both a 48-inch pipeline proposed by TransCanada and ExxonMobil and a separate 24-inch pipeline the state itself is pursuing, but we have very little information as to whether either will come to anything," said Sen. Bill Wielechowski, D-Anchorage, during two days of oversight hearings on the two pipeline initiatives held Aug. 15 and Aug. 16.

Legislators are also frustrated with plans for the 24-inch pipeline to charge consumers in Interior Alaska for the cost of a plant to take off and re-inject natural gas liquids at the gas takeoff point west of Fairbanks while the benefits of the gas liquids would be in Southcentral Alaska. The charge helps push the price for gas delivered to Fairbanks through the pipeline above the price for gas to the Anchorage area.

There are also concerns that recent gas discoveries and renewed exploration for gas in Cook Inlet, a plan by utilities to install facilities to import liquefied natural gas, or LNG, and a recently-announced plan by Golden Valley Electric Association and Flint Hills Resources to truck LNG from the North Slope to Fairbanks, could result in "stranded" investments by utilities in those facilities if a gas pipeline is built.

The money is a big worry, though. The state will fund $500 million of TransCanada's and ExxonMobil's expenses for engineering and permits for a planned $40 billion 1,700-mile, 48-inch natural gas pipeline from the North Slope to Alberta, and about $400 million for work on an alternative 737-mile, 24-inch pipeline from the North Slope to Southcentral Alaska that is seen as an alternative for the state if the large pipeline is seriously delayed. The 24-inch pipeline is estimated to cost $7.6 billion.

TransCanada vice president Tony Palmer told the legislators Aug. 16 his company is still negotiating with potential shippers who submitted bids for capacity in the 48-inch pipeline during a 2010 open season, and has recently offered improvements in terms in an attempt to nail down commitments.

Palmer said he could not provide details to legislators on the negotiations or the identities of potential shippers. Under a contract with the state, which provides for the cost-reimbursement, Trans-Canada and ExxonMobil are committed working toward a Federal Energy Regulatory Commission certificate despite the failure so far to secure shipping contracts.

However, some information has been provided to the state administration on the status of negotiations, Palmer said. TransCanada's contract with the state under the Alaska Gasline Inducement Act, or AGIA, provides for certain information to be shared under conditions of confidentiality, he said.

Wielechowski asked if legislators could be given briefings if they signed confidentiality agreements. Palmer said he would not permit that because the AGIA contract makes no provision for legislators to have the information and because of a previous bad experience TransCanada has had with legislators signing confidentiality agreements.

When TransCanada was negotiating several years ago with the state for a gas pipeline license under the Stranded Gas Act legislators signed agreements to get access to TransCanada's proposal to the state, which was confidential. Later, during public hearings, one lawmaker waved the package around, although it was in a large brown envelope, Palmer said. The legislator did not release the information but the experience left a sour taste, Palmer said.

On the state-sponsored 24-inch pipeline Dan Fauske, CEO of the state-owned Alaska Natural Gas Development Corp., the state corporation formed to plan the project, said that an open season planned in 2013 would answer questions on whether gas shippers believe the project is viable. "We have been pleasantly surprised by the interest in the project so far from potential owners and industrial customers for gas," Fauske said.

Fauske said AGDC is proceeding with preparations for an open season to be held in early 2013 and hopes to have commitments from shippers by the end of that year. The project is limited to 500 million cubic feet a day, however, as a condition of the state's agreement with TransCanada on the large pipeline, said Fauske.

The state would fund about $400 million in engineering and permitting for the project through the 2013 open season and then seek proposals from firms to build and own the project, or alternatively to build and operate the pipeline with the state retaining ownership, Fauske said.

Joe Dubler, vice president and chief financial officer of the AGDC, said letters of interest have been received from four companies interested in building and owning. Two of the firms said they can do the project without substantial state financial guarantees, he said. The identities of the interested firms could not be revealed, Dubler said.

Fauske also said there is also interest from potential industrial customers, which are necessary because utilities in Alaska can only purchase about 250 million cubic feet of gas daily, about half the planned throughput of the 24-inch pipeline. There were indications of interest for up to 500 million cubic feet, or mcf, per day for industrial use, although this would exceed the throughput allowed under the TransCanada agreement, Fauske said.

The AGDC has spent about $30 million to date on preliminary engineering and another $240 million will be spent this year and next in more detailed engineering and work on environmental permits to prepare for the 2013 open season, Fauske said. An additional $130 million is needed to do detailed engineering if the open season is successful, but some of this could be paid by a firm interested in owning the project, he said.

If a private firm takes the project over after the open season the expected tariff for moving gas to Southcentral Alaska is estimated at $9.63 per thousand cubic feet, or mcf, but if the state owns and finances the project itself the tariff could drop $1.00 to $1.20 per mcf because the state would not earn a return on an investor's equity and would obtain better financing terms than a private company because of Alaska's strong financial position, Dubler said.

Legislators said the best option for getting gas to Southcentral Alaska is if the 48-inch pipeline is built and a 24-inch spur line is built across 350 miles from Interior to Southcentral Alaska.

"We expect a Draft Environmental Impact Statement to be issued in late August or early September, and for the final EIS to be published early next spring," Fauske told the legislators.

There are concerns from legislators, however, about the economic viability of the 24-inch pipeline because of the 500 million mcf limit in the TransCanada agreement, particularly as to whether there would be enough gas or gas liquids shipped to entice industrial customers to the project. On idustrial customers, Fauske said AGDC has examined liquefied natural gas export sales as the best potential option although sales of natural gas liquids and a gas-to-liquids option were also studied.

Sen. Joe Paskan, D-Fairbanks, who chaired the hearings, asked whether a private company could take the project over and expand the project to ship more than 500 million cubic feet per day. Dave Haugen, the project manager, said this is possible and that there could be proposals for larger throughputs and larger diameters put forth in the 2013 open season.

The planning done so far indicates that as much as 1 billion cubic feet per day could be moved through the 24-inch pipeline if additional compression were added. However, customers could propose larger diameters in the open season, too.

"We could consider a 30-inch or 36-inch pipeline. Anything is negotiable," Haugen said. "The engineering information we have developed is the property of the state," and could be transferred to a private developer.

However, moving more than 500 million cubic feet a day could still violate the state's contract with TransCanada, attorneys for the ADGC said. Palmer, of Trans-Canada, said the 500 million limit was agreed on as an allowable offtake for use in Alaska so that the pipeline could could be assured there would be enough gas from the North Slope, about 4 billion mcf per day, to make its larger project viable.

On the charge to Fairbanks consumers for the natural gas liquids plant, Fauske said the AGDC would have preferred to roll this cost into the overall tariff for moving gas, but that Regulatory Commission of Alaska rules prohibit that. The gas liquids plant is required because of the technical requirements of a planned connection with a 12-inch spur pipeline from the 24-inch pipeline west of Fairbanks to the Interior city.

Rules of the RCA require that consumers who "benefit" from a facility, in this case the pipeline connection, also pay the full cost. Rep. Paul Seaton, R-Homer, said this still seemed unfair.

"Fairbanks is being charged for costs related to natural gas liquids that results in a $1 per mcf high cost for the community," Seaton said.

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Republished with the permission of the Alaska Journal of Commerce Tim Bradner can be reached at

tim.bradner@alaskajournal.com.

Three in a row; Enstar files new Buccaneer, Aurora & Cook Inlet Energy gas contracts

Alan Bailey
Petroleum News

Southcentral Alaska gas utility Enstar Natural Gas Co. has submitted three new gas supply contracts to the Regulatory Commission of Alaska for approval. One of the contracts, for gas from Buccaneer Energy’s newly discovered Kenai Loop gas field on the Kenai Peninsula, commits firm gas supplies after Cook Inlet Natural Gas Storage Alaska’s new Kenai Peninsula gas storage facility goes into operation in 2012.

The other two contracts, with Aurora Gas and Cook Inlet Energy, will enable those companies to help bolster Enstar’s peak winter gas supplies by participating in the gas bidding system that Enstar pioneered in the winter of 2010-11 — Enstar has insufficient contracted, guaranteed gas supplies to meet projected peak winter demand and has instigated the bidding system to obtain gas to fill shortages on a day-to-day basis.

A provision in the Buccaneer contract will also enable Buccaneer to participate in the bidding process as soon as RCA approves that contract.

Gas for storage
However, the primary purpose of the Buccaneer contract will be to ensure sufficient gas supplies to meet Enstar’s contracted use of the CINGSA storage facility, Enstar spokesman John Sims told Petroleum News Aug. 15. Enstar plans to pull gas from the CINGSA facility during periods of high winter demand, starting in the winter of 2012-13, to ensure that gas can be flowed fast enough to meet gas consumers’ peak needs.

According to Enstar’s tariff filing, the Buccaneer contract for guaranteed gas supplies from 2012 involves pricing indexed to the New York Mercantile Exchange gas futures, but with a minimum gas price of $5.71 per thousand cubic feet between March and November of each year, and a minimum price of $7.06 per thousand cubic feet between December and February. The maximum price at any time of the year would be $10 per thousand cubic feet. These floor and ceiling prices would be adjusted for inflation, starting in 2012. Based on projections of Nymex futures, Enstar anticipates the weighted average cost of gas purchased under the contract to rise from $5.89 per thousand cubic feet in 2012 to $6.16 per thousand cubic feet in 2014.

The pricing terms appear similar to those in earlier Enstar supply contracts with Marathon, approved by RCA in May 2010, and with Anchor Point Energy, approved by RCA in November 2009. Those earlier contracts both had inflation-adjusted price floors and ceilings of $6.85 and $9.70 year round. Anchor Point Energy is selling gas from the Armstrong Cook Inlet-operated North Fork gas field in the southern Kenai Peninsula.

However, Sims said that based on a comparison of the price floors between March and November, the Buccaneer contract pricing should work out a bit lower than that for the Anchor Point Energy contract.

Up to 31.5 bcf
The Buccaneer contract requires the delivery of a total of 12 billion cubic feet of gas to Enstar, with an option to increase that total volume to 31.5 bcf, with these volumes likely taking until 2018 to deliver, Enstar says. The contract requires Buccaneer to complete the drilling of two new wells at Kenai Loop, one well by Nov. 1 this year and the other well by Nov. 1, 2013.

According to a Buccaneer press release, Buccaneer will initially deliver gas from Kenai Loop at the rate of 5 million cubic feet per day in 2012, with an option to increase that rate to 15 million cubic feet per day after six months, depending on progress with the drilling of new wells.

Although the Buccaneer contract for firm gas supplies will help fill a looming gap in Enstar’s annual gas supply needs, Enstar’s customers will still likely face supply shortfalls, starting at 5.9 bcf in 2013 and growing to 18.9 bcf in 2018, in the absence of further gas supply contracts, Enstar says. On the other hand, the storage of Buccaneer’s gas in the CINGSA facility should stave off any shortfall in the rate of delivery of winter gas until 2018.

And Enstar presumably hopes that the recent startup of new Cook Inlet gas exploration will further bolster its supplies. The new contracts and recent enthusiasm by small independent gas explorers operating in the Cook Inlet basin appear to reflect the impact of incentives for gas exploration that the Alaska Legislature has enacted, Sims said.

Bidding system
Meantime, with insufficient gas under firm contract to meet potential delivery needs in the winter of 2011-12, before CINGSA comes online, Enstar will be operating its day-to-day bidding system, to try to fill any supply shortfalls as necessary.

None of the contractual arrangements for gas supplies through the bidding process guarantee to make gas available but do allow qualified gas producers to bid to deliver to Enstar any gas that they have available for immediate sale. Enstar’s three new contracts add Buccaneer, Aurora Gas and Cook Inlet Energy to the list of qualified producers, thus increasing the likelihood of finding any necessary short-term supplies — Enstar already has contracted arrangements for the potential purchase of “non-firm” gas from Unocal, Marathon, ConocoPhillips and Anchor Point Energy.

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Republished with the permission of the Petroleum News

ANWR plan leans to wilderness expansion; public comment open

—Wesley Loy

The federal rollout of a draft management plan that could lead to huge new sections of the Arctic National Wildlife Refuge being designated “wilderness,” including the potentially oil-rich coastal plain, drew immediate disdain from top Alaska politicians.

The U.S. Fish and Wildlife Service, which acts as landlord for ANWR, is wasting time and money reviewing whether to make more of the refuge wilderness, said Sen. Mark Begich, a Democrat.

“I’ll fight every step of the way any effort by federal bureaucrats to close off this enormous source of oil and gas by slapping it with more wilderness designation,” he said.

Oil and gas exploration and development already is prohibited in ANWR, but a wilderness designation could harden that policy.

U.S. Sen. Lisa Murkowski, the top-ranking Republican on the Senate Energy and Natural Resources Committee, argued the Fish and Wildlife Service lacks authority under ANILCA, the Alaska National Interest Lands Conservation Act of 1980, to even study designating more wilderness in the state.

“Instead of trying to lock up our resources, we should be developing them as part of a balanced energy plan that creates jobs and bolsters our failing economy,” Murkowski said. “There’s a tremendous amount of money buried in the ground in Alaska, and it’s time to withdraw it.”

Alaska’s Republican governor, Sean Parnell, also objected to the draft 15-year management plan for ANWR.

“This is another unfortunate effort by the Obama Administration to prevent Americans from developing Alaska’s vast resources for the benefit of the country,” Parnell said.

Conservation groups encouraged
Conservation groups, as well as a group representing indigenous Gwich’in people, hailed the prospect of expanding wilderness within ANWR, the protection of which has long been a top priority for the environmental community.

“We are encouraged that the Fish and Wildlife Service is considering Wilderness recommendations for the coastal plain, the biological heart of the Arctic Refuge,” said Dan Ritzman, Alaska regional director for the Sierra Club. “For decades Americans from all walks of life have asked for permanent protection for these critical lands and waters and now they have the opportunity to move this one step closer to reality.”

“The Arctic Refuge is one of the country’s most treasured, pristine places, and as of yet remains unspoiled by widespread industrial scale oil and gas operations,” said Jamie Rappaport Clark, executive vice president of Defenders of Wildlife. “The Fish and Wildlife Service should seize the opportunity to strengthen protection for the refuge and its diversity of wildlife against the threat of Big Oil and pursue a wilderness recommendation.”

“Since President Eisenhower established the Arctic Refuge in 1960, our nation has acted to embrace the bold wilderness vision of the refuge’s founders and to protect it from oil and gas interests. In the face of climate change and a renewed push to develop the Arctic for oil and gas, our country’s leaders should support the wishes of Americans by taking the necessary steps to permanently protect the Arctic Refuge’s coastal plain — a globally significant, vital homeland and birthing ground for millions of birds, polar bears and caribou, as well as a critical subsistence resource,” said Nicole Whittington-Evans, Alaska director for The Wilderness Society.

‘Preliminarily recommended’
It’s far from assured that more ANWR acreage will be designated wilderness. Such a measure would need to clear several approvals before winning the ultimate OK from Congress.

The Fish and Wildlife Service in April 2010 began work to revise what’s known as the “comprehensive conservation plan” for ANWR. The original plan was signed into effect in 1988, and the service says it’s time to freshen it up.

Already, the service has conducted a scoping process, which generated more than 94,000 comments from individuals and organizations.

Out of that has come the new draft comprehensive conservation plan, which the service announced on Aug. 12.

“The draft plan contains six alternatives for long-term management, ranging from the continuation of current practices to the designation of three geographic areas (including the Arctic Refuge coastal plain) for potential inclusion within the National Wilderness Preservation System, and the potential designation of four additional Wild and Scenic Rivers on the refuge,” an agency press release said.

The draft plan does not identify a preferred alternative, saying all options remain under “active consideration.”

But it appears that sentiment within the Fish and Wildlife Service favors establishing new wilderness areas within ANWR.

Located in the extreme northeast corner of Alaska, the remote refuge takes in 19.3 million acres — nearly the size of South Carolina. About 40 percent of ANWR already is designated wilderness.

The draft plan — specifically Appendix H, the “wilderness review” — indicates three huge new chunks of ANWR are “preliminarily recommended for wilderness designation.”

These include the coastal plain at 1.6 million acres; a southern ANWR area known as the Porcupine Plateau at 4.4 million acres; and the western Brooks Range area at 5.7 million acres.

All told, practically all of ANWR would be wilderness if these three areas were designated as such, with only relatively small areas near villages remaining non-wilderness.

No oil, gas alternatives
The Fish and Wildlife Service is inviting public comments on the draft plan through Nov. 15. The agency plans to hold public hearings around the state, including one in Anchorage on Sept. 21 and another in Fairbanks on Oct. 19.

The plan and details on how to submit comments are online at http://arctic.fws.gov/ccp.htm.

The agency aims to issue its “record of decision” by the end of 2012.

“If the final plan recommends additional Wilderness and/or Wild and Scenic River designations, the recommendation(s) would require approval by the Director of the Fish and Wildlife Service, the Secretary of the Interior, and the President,” the agency press release said. “The President would then submit the recommendation to Congress, which alone has the authority to make final decisions on any proposed Wilderness or Wild and Scenic River designations.”

Although comments received during the scoping process overwhelmingly concerned the coastal plain and the question of oil and gas activity, the Fish and Wildlife Service chose not to include plan alternatives to allow oil and gas leasing or 3-D seismic shoots in ANWR, which the U.S. Geological Survey in 1999 estimated could hold several billion barrels of oil.

The governor’s office criticized the service for excluding industry alternatives, calling that decision “inconsistent with existing federal law.”

But nothing in the statutory mission of the National Wildlife Refuge System requires the service to consider or propose development scenarios for oil and gas or other natural resources, the agency said. Anyway, the service added, Congress has reserved the authority to make final decisions on oil and gas development in ANWR.

As for criticism that its wilderness review violates the “no more” clauses in ANILCA, the service argues to the contrary, saying the review is just a “tool” to make sure ANWR is being managed right.

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Republished with the permission of the Petroleum News.

Thursday, August 18, 2011

State reaches deal with ExxonMobil on Point Thomson lawsuit

By Tim Bradner
Alaska Journal of Commerce

The state has reached a tentative agreement with Exxon Mobil Corp. in the lengthy and contentious lawsuit over the Point Thomson unit of the North Slope, a natural gas and gas condensate field 60 miles east of Prudhoe Bay.

State Natural Resources Commissioner Dan Sullivan said ExxonMobil, operator of the unit, is now discussing proposed terms of the settlement with other Point Thomson owners, mostly BP and Chevron, who are also involved in the litigation. Terms of the settlement are still confidential, Sullivan said.

Sullivan spoke at a legislative hearing on natural gas issues Aug. 15. Legislators asked how soon information on the settlement would ne available.

"Our interest is that it would be soon. Those discussions are under way now, but we are not driving the timeline anymore," Sullivan said.

"We're aware of the state's testimony on Aug. 15 at the legislative committee hearings," said ExxonMobil spokesman David Eglinton. "We remain committed to working with Governor (Sean) Parnell's administration and the other working interest owners to finalize a settlement. Settling Point Thomson litigation and securing necessary local, state and federal permits is imperative to maintain the pace of Point Thomson development."

Point Thomson is a large gas discovery with an estimated 8 eight trillion cubic feet of gas reserves and an estimated 200 million barrels of condensates, a natural gas liquid, and additional conventional crude oil. Gas reserves at Point Thomson are a critical part of the 36 trillion cubic feet of gas that has been identified on the North Slope, and which would support a planned $40 billion North Slope gas pipeline.

Despite the ongoing lawsuit, ExxonMobil and the state worked out an interim agreement where the companies would retain ownership of some leases in the unit with the rest still disputed. In return, the companies agreed to develop a $1.3 billion gas cycles and condensate production project that would produce 10,000 barrels a day of condensate liquids. Those would be shipped by pipeline to Pump Station 1 on the Trans-Alaska Pipeline System.

The dispute with the state has a long history. Point Thomson gas was first discovered in the 1970s but not developed because of the lack of a pipeline and a way to market the gas. Over the years the state gas pushed ExxonMobil, BP and Chevron to do an interim development project based on liquid condensates in the field along with small oil accumulations that are nearby. In the late 1990s ExxonMobil developed a plan for a gas cycling and 70,000 barrels a day condensate production project and spent considerable sums in project definition and permitting before shelving the project as uneconomic.

A dispute over that decision and ExxonMobil's reluctance to additional work led the state threaten to terminate the leases, which is finally did so in 2007. Subsequent lawsuits filed by ExxonMobil, BP and Chevron has kept the issue in the courts since then.

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Republished with the permission of the Alaska Journal of Commerce

Mary Ann Pease's testimony to Senate Resources - August 17, 2011


Good Afternoon, my name is Mary Ann Pease and I am the owner of MAP Consulting. Over the past decade, I have been involved in various aspects of oil, energy and gas consulting services for a whole host of companies. Most recently my efforts have focused on the Propane Project for ANGDA. This project is timely and could be an attractive alternative for many rural communities today.

ANGDA developed a *Alaska Propane Consortium* approach to promoting and advancing the concept of shipping Propane from the North Slope prior to and with a gas pipeline. We have held 2 major forums and conferences here in Anchorage and another in Fairbanks. North Slope propane is readily availableon the North Slope and with the proper commercial arrangement with the Producers, the private sector could start delivering propane today as an attractive alternative to diesel… The concept is to start small with existing propane facilities and then work with the private sector to build the necessary storage and deliveryinfrastructure to support distribution to Interior and rural Alaska.

I have also worked with ROUSH CleanTech, who has been working with the Propane Education & Research Council (PERC)and Ford Motor Company since 2006 to develop liquid propane autogas fuel systems for a variety of Ford vehicles.As a matter of fact, 2 of these ROUSH propane fuel injected FORD 250 trucks are being driven in Alaska today by the SOA fleet services, several companies that have a presence on the North Slope, as well as the Fleet services companies supporting North Slope Activities.There is definitely a sense that fleet service conversion to propane is a viable option (compared to trucking ULSD North), especiallygiven the resource available on the North Slope today. There is an opportunity for a substantial cost saving for fleet vehicles on the North Slope and also attractive savings for rural communities depending on the logistics involved. Propane also offers environmental advantages as a cleaner burning fuel and much lower maintenance costs for equipment.

I have participated in the In-state bullet line project on behalf of the Pacific Propane Gas Association (which was founded in 1961) and represents propane marketers and related businesses throughout Alaska, Hawaii, Oregon and Washington. PPGA maintains its core principles of education, safety and training to promote high standards of practice in the propane industry and to help its members compete in the energy marketplace. The Pacific Propane Gas Assoc. has been an active participant in the Alaska Propane Consortium and propane advancement throughout our state and nationwide.

The cost of trucking propane from the North Slope and then utilizing barges with ISO containers to delivery points along the river communities is a very timely and commercially viable project. Deliveries could start today versus 10-20 years out and is not dependent upon propane imported from Canada.

CONCLUSION:

I encourage the legislature to support all efforts to continue participation in options related to propane conversion for Interior and Rural communities, many of which will never see any benefits from a gas line for their home heating needs. Similar to the development of the storage and infrastructure for diesel, there is an opportunity to build out storage for this very viable alternative that could be utilized for home heating and cooking in many communities. I have been working closely with the Northwest Arctic Borough and the energy coordinator- Ingemar Mattiasson – can document the demand, need and cost savings from propane even today – and that is using propane from Prince Rupert rather than our North Slope!

Friday, August 12, 2011

State: Additional Cook Inlet investments could find new gas

By Tim Bradner
Alaska Journal of Commerce

An investment of $1 billion to $2 billion by natural gas producers in additional drilling in gas fields in Southcentral Alaska could meet projected gas supply shortages in the region until 2018 or 2020, possibly eliminating the need for local utilities to import liquefied natural gas.

A recent study by the state Division of Oil and Gas shows that if producers drill eight new production wells per year in the four largest gas fields in Cook Inlet Basin, the fields will produce sufficient new gas to meet the current 90 million cubic feet per day demand in the region at a cost of $10 million to $20 million per well with an additional $100 million investment in compression.

"This study considers what we think it will take, in terms of revenue, to get producers to produce additional gas we believe is in these fields, although we can't say the price that the field operators will feel is acceptable to make the investment," said Joe Balash, deputy commissioner in the state Department of Natural Resources, in the briefing.

ConocoPhillips, Marathon Oil Co. and Chevron Corp. are operators at the four fields included in the study.

The region's utilities, however, are skeptical that investments by producers will actually be made, and are proceeding with plans to have imported LNG available in Cook Inlet within three years.

"We can't take a chance. Our estimates show a supply gas in the region as early as 2014," said Jim Posey, general manager of Anchorage's city-owned Municipal Power & Light, one of several utilities in negotiations with potential LNG suppliers.

Despite what the state study said, Cook Inlet producers are actually drilling about half the new wells needed to sustain current production levels, Posey said. Four new development wells are planned for 2011.

The study by the Division of Oil and Gas examines gas reserves the state believes remain in the four largest gas fields, which include the Beluga, Ninilchik, North Cook Inlet and the McArthur River Grayling gas sands based on data that is public and some that is confidential, and relies on known costs for drilling and compression.

Balash said the state study included only the large producing fields and did not include new gas found though exploration, such as a recent 10 billion-cubic-foot gas discovery made by Buccaneer Energy LLC, an independent, on the Kenai Peninsula.

The study indicates that producers could earn a 20 percent internal rate of return in 2018 at a gas price below $6 per thousand cubic feet (mcf), a price that is about what producers are selling most gas produced in Cook Inlet, and a 15 percent rate of return on a gas price below $5 per mcf.

However, another assessment made in the study is that the net present value of many of the investments in wells will be modest, which could discourage some companies, particularly larger companies, from exploring, Balash said.

"It's quite possible that smaller projects could have quite good rates of return and yet have small net present values. This kind of investment might be very attractive for a small independent and less attractive for a larger company," said Jeff Dykstra, a commercial analyst in the state oil and gas division and one of the authors of the gas study.

Independent companies are in fact showing much more interest in Cook Inlet than are large companies such as the current producers.

"Most companies use several financial indicators in assessing possible investments including rate or return and net present value as well as their cash-flow needs," Bill Barron, director of the state oil and gas division, said in the briefing. Whether an investment will be made depends on a company's internal investment threshold, Barron said.

Information in the study will be used by state legislators next year as they consider additional funds needed for planning a possible $7.9 billion, 24-inch gas pipeline that could be built by the state from the North Slope. The 24-inch pipeline, which could bring gas from the slope to southern Alaska by 2019, is being considered as an alternative if a large 48-inch Alaska gas pipeline is seriously delayed.

Balash said the division will do a second increment to its Cook Inlet gas study taking into consideration a new estimate of technically-recoverable gas resources released by the U.S. Geological Survey. The USGS estimated that Cook Inlet could hold as much as 19 trillion cubic feet of conventional and unconventional gas resources, more than twice the amount of conventional gas discovered so far.

"We will try to determine a minimum economic field size that would allow some of these new resources to be developed," Balash said.

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Republished with the permission of the Anchorage Journal of Commerce.



Flint Hills, GVEA announce plan for LNG trucking

By Tim Bradner
Alaska Journal of Commerce

Flint Hills Resources and Golden Valley Electric Association of Fairbanks have begun engineering on a natural gas liquefaction plant at Prudhoe Bay on the North Slope and plan to build the facility in time for deliveries in 2014, Flint Hills and GVEA announced.

The project would involve trucking of LNG from the North Slope to Fairbanks on the Dalton Highway. Flint Hills, a Koch Industries subsidiary, operates a refinery at North Pole, near Fairbanks. Golden Valley is the regional electric cooperative for Interior Alaska.

The venture is not connected, at this time, with a similar LNG project being pursued by Fairbanks Natural Gas LLC, a small private gas utility operating in Fairbanks. FNG has site preparation under way for its proposed plant but said it needs contracts with large customers like Flint Hills and GVEA for its project to proceed.

GVEA spokeswoman Corinne Bradish said a decision was made to proceed in a partnership with Flint Hills and not the local gas utility, at least at this time, because the two-party deal would result in lower costs of LNG delivered to Fairbanks.

"Several years ago GVEA announced that it was considering a deal with Fairbanks Natural Gas. However, we ultimately decided to pursue a partnership with Flint Hills because it delivers gas at cost. The expense of liquefying, trucking and regasification operations would be shared and neither party would profit from these activities. That means lower costs to our customers," Bradish said.

Meanwhile, the LNG proposal will require approvals by the Regulatory Commission of Alaska, which will have to approve Golden Valley's passing its share of costs for engineering and building the LNG plant at Prudhoe Bay and a regasification plant near Fairbanks on to Interior Alaska ratepayers.

The cost is estimated at $180 million but that will be refined as engineering continues. Fairbanks Natural Gas LLC, the small gas utility that now serves Fairbanks with LNG trucked from Southcentral Alaska, is studying a similar North Slope LNG trucking plan and has estimated costs at $160 million.

The two companies said they have secured a gas supply contract with a North Slope producer but declined to identify the company. For its project, Fairbanks Natural Gas has a contract with Exxon Mobil Corp., one of three major North Slope producers.

Flint Hills and Golden Valley did not release cost estimates for the project. Fairbanks Natural Gas has estimated that its project, which would be similar, would cost about $160 million for the LNG plant on the North Slope and the regasification plant near Fairbanks.

Meanwhile, Fairbanks Natural Gas has work is underway this summer to expand a six-acre pad at Deadhorse, the industry service area adjacent to Prudhoe Bay. The company has also a right-of-way application filed with the state Department of Natural Resources for a 3.8-mile, eight-inch pipeline from Flow Station 1 in the Prudhoe Bay field to the site of the LNG plant.

While FNG is not a part of the joint Flint Hills-Golden Valley deal now, that could change, said Brian Newton, Golden Valley's president. FNG has assets that could be contributed, such as its pad and lease at Deadhorse and the pending pipeline right-of-way, as well as engineering and planning it has done to date.

Newton said the nature of the Flint Hills-Golden Valley venture has yet to be defined. Engineering work being done now is with resources internal to both partners (Flint Hills has experience with LNG elsewhere), Newton said, but a third-party engineering contractor will be retained soon.

At that time a cost-sharing arrangement will have to be worked out. A key part of the current deal, according to the press release from the two parties, is the concept of, "at cost," gas delivered to both, meaning no profit. Under this arrangement Golden Valley would contribute its share of capital and would share operating costs. Fairbanks Natural Gas now serves about 1,100 commercial and residential customers in Fairbanks and trucks LNG about 400 miles from a small liquefaction plant in Southcentral Alaska, in the Matansuka-Susitna Borough north of Anchorage, its president Dan Britton said.

The company has operated since 1998 and now purchases gas from Aurora Gas LLC, an independent Cook Inlet gas producer. On average FNG ships about three truckloads per day of LNG to Fairbanks, but this varies from one to two truckloads daily in summer and four to five truckloads daily in winter, Britton said.

Currently, the constraints in gas supply from Cook Inlet limits the ability of the Fairbanks utility to take on new customers and prompted the company to pursue trucking LNG from the North Slope, Britton said.

Oil is also used widely for heating parts of Fairbanks not now served by Fairbanks Natural Gas, and the cost of home heating has become a serious economic problem for the community, Fairbanks North Star Borough Mayor Luke Hopkins said. Also, the inability of FNG to expand service has caused delays in new retail expansion in Fairbanks because large out-of-state firms planning new stores prefer not to use oil for space heating because of the expense and liabilities associated with construction of underground fuel storage.

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Republished with the permission of the Alaska Journal of Commerce. Tim Bradner can be reached at tim.bradner@alaskajournal.com.



Doyon plans new Interior gas exploration effort in Nenana Basin

By Tim Bradner
Alaska Journal of Commerce

Doyon Ltd., the Interior Alaska Native regional corporation, is planning new seismic work this winter in the northern part of the Nenana Basin, an Interior Alaska basin about 60 miles west of Fairbanks that is considered gas prone but also has oil potential.

About 120 miles of two-dimensional seismic is planned for this winter, according to Jim Mery, Doyon's vice president for lands. The seismic will set the stage for a possible exploration well drilled in the area, he said. It would be the second test well drilled in the Nenana Basin in recent years.

Doyon is an Alaska Native development corporation with about 11 million acres of surface and subsurface land holdings in Interior Alaska. The Nenana Basin project is on state-owned lands held under an exploration license, a form of state lease. The license area includes 483,000 acres of general state lands and an additional 9,500 acres of lands owned by the Alaska Mental Health Trust Authority, a state agency that leases its lands to support mental health programs.

Mery said Doyon plans to press ahead with exploration in spite of an announcement by Golden Valley Electric Association, the regional electric utility, and Flint Hills Resources, operator of a refinery near Fairbanks, that they will pursue a project to truck liquefied natural gas from the North Slope.

The Fairbanks area is a near-term market for any gas discovered in the Nenana Basin, although a 60-mile pipeline would be needed to bring the gas to the Interior city.

On the other hand, a plan by the state of Alaska to pursue a 24-inch pipeline built from the North Slope to Southcentral Alaska would have its line pass through the Nenana Basin near where Doyon plans exploration. If gas is discovered, and if the pipeline is built, Doyon could ship its gas to Southcentral Alaska through the pipeline.

"There are a lot of moving parts to the pipeline and natural gas picture, and our decision is to move ahead with our plans," Mery said.

Doyon and three partners drilled a well two years ago in the southern part of the basin with mixed results. No gas was found but there were indications that hydrocarbons were present in the region. Doyon's partners in the Nenana Basin exploration have been Arctic Slope Regional Corp., another Native development corporation with holdings on the North Slope, and Usibelli Energy LLC, an affiliate of Usibelli Mines, which operates a coalmine near Healy, also in Interior Alaska.

Mery said this winter's program will involve the first seismic done in the northern part of the Nenana Basin, which is believed to hold the deepest part of the basin, with sedimentary rocks possibly as deep as 16,000 feet.

State geologists have said the basin exhibits somewhat similar geology to the prolific Cook Inlet basin in southern Alaska and is generally considered prospective for natural gas. A geologic assessment of the basin indicated the possibility of 3 trillion cubic feet of technically recoverable thermogenic gas in the basin, with the possibility of additional biogenic gas. There were two earlier exploration wells drilled, by Unocal in 1962 and ARCO in 1984, but the wells were drilled at the far southern, and shallowest, part of the basin and were unsuccessful.

A key advantage of Nenana Basin gas for the state's 24-inch pipeline is that a 500 million cubic feet per day limit that applies to the state project because of its contract with TransCanada Corp. does not apply to gas found in Interior Alaska and shipped through the pipeline, said Dan Fauske, president of the Alaska Gasline Development Corp., the state corporation planning the 24-inch pipeline.

The state's 24-inch pipeline could move 500 million cubic feet per day from the North Slope to comply with the TransCanada contract and any gas from the Nenana Basin could be above that amount, Fauske told legislators in recent briefing.

TransCanada and ExxonMobil Corp. are planning a 48-inch pipeline built from the North Slope to Canada and are working with incentives offered by the state. As a part of the agreement the state is limited in helping a competing pipeline that would ship more than 500 million cubic feet per day from the slope.

The 500 million cubic feet per day limit is a source of frustration to many state legislators because it limits the development of industrial customers who would need more than the gas that could be delivered under the limit. Industrial customers are needed for the 24-inch pipeline build to Southcentral Alaska to be economically viable.

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Republished with the permission of the Alaska Journal of Commerce. Tim Bradner can be reached at tim.bradner@alaskajournal.com.

Escopeta's jack-up rig arrives in Cook Inlet, set to drill

By Tim Bradner
Alaska Journal of Commerce

The Spartan Drilling Co. Blake 151 jack-up rig lies at anchor in Kachemak Bay Aug. 8. The Polar Explorer, one of three Foss Maritime tugboats that towed it from Vancouver, B.C., to Homer, is to the left. The rig left Vancouver July 19 and arrived about 5 p.m. Aug. 7 in Kachemak Bay. Photo/Michael Armstrong/ Homer News Spartan Drilling Co.'s Blake 151 jack-up rig arrived Aug. 7 in Cook Inlet and cleared U.S. Customs before proceeding to an exploration location in upper Cook Inlet Aug. 10, a spokesman for Escopeta Oil and Gas Co. said.

The rig waited briefly in Kachemak Bay near Homer, Escopeta spokesman Steve Sutherland said in an interview.

"We [held] in Kachemak Bay until we clear customs and finalize some matters with the state Department of Natural Resources. We expect to be moving the rig to the drilling location in the Kitchen Light Unit," Sutherland said.

Escopeta has most of the permits it needs from the state. "Escopeta has an approved plan of operations from Department of Natural Resources," agency spokeswoman Elizebeth Bluemink said. "We plan an informal inspection after they arrive at the drill site but we don't have any pending DNR permits. What's still pending will come from other agencies, the AOGCC (Alaska Oil and Gas Conservation Commission) drilling permit, for example."

"We approved the plan of operations in July. The plan covers drilling related activities and not the transit period to get to the drill site," Bluemink said.

Escopeta is the main leaseholder in the Kitchen Lights Unit and will be operator of the exploration well.

If the rig moves to the location and successfully spuds the well it will qualify for a special state exploration incentive that will pay up to 100 percent of the first $25 million of costs of the first exploration well drilled with a jack-up rig in Cook Inlet. Wells drilled by the same rig are eligible for follow-on incentives for the second and third exploration wells, of 90 percent of costs up to $22.5 million on the second well and 80 percent f the first $20 million for the third well.

However, the wells must be drilled for different companies.

The Blake 151 was towed from Vancouver, B.C. To Cook Inlet by three Foss Maritime Co. tugs. The rig was in Vancouver for several weeks undergoing modifications after being moved to the west Canadian city from the U.S. Gulf of Mexico by a Chinese heavy-left vessel.

The rig movement from the gulf was controversial because Escopeta's original plan was to move it directly to Cook Inlet after obtaining a waiver of the U.S. Jones Act from the Department of Homeland Security.

The rig was diverted to Canada after Homeland Security Secretary Janet Napolitano turned down the waiver request. U.S. Shipping interests who work to protect the Jones Act had urged Napolitano to turn down the waiver.

The Jones Act requires shipments of cargo between U.S. Ports to be made with American-built ships. Escoptea hired the Chinese heavy-lift ship because no U.S. Vessels were capable of moving the rig safely around the tip of South America, where there are rough seas, company president Danny Davis said earlier.

U.S. shipping groups are pushing for a penalty to be imposed on Escopta for a Jones Act violation.

"We expect the customs to issue a significant fine once the rig has completed its transit and positioned for duty in Cook Inlet," said Richard Berkowitz, Director of the Transportation Institute, a Seattle-based maritime industry association.

Even with the rig's voyage on a Chinese heavy-lift vessel terminated in Vancouver, B.C., a Jones Act violation has occurred, Berkowitz said.

Meanwhile, a second jack-up rig may soon be headed to Cook Inlet. Buccaneer Energy, an Australian company, is purchasing a heavy jack-up rig in Asia for drilling in Cook Inlet waters and elsewhere in coastal Alaska. That rig may be moved to Alaska this winter or by early spring.

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Republished with permission from the Alaska Journal of Commerce. Tim Bradner can be reached at tim.bradner@alaskajournal.com.

Monday, August 8, 2011

Friday, August 5, 2011

Shutdown over, DOT anticipates quick approval for Deadhorse project

By Andrew Jensen
Alaska Journal of Commerce

Update: This story has been modified from the version in our print edition that went to press Aug. 3 to reflect the end of the FAA shutdown Aug. 5.

After nearly every flight at one of the busiest airports in Alaska, maintenance crews check for displaced pavement and other debris.

They would have been patching the runway at Deadhorse Airport until 2013 without the end of a partial shutdown of the Federal Aviation Administration that ended Aug. 5.

Now that the FAA is set to re-open Aug. 8, state Department of Transportation and Public Facilities Statewide Aviation Director Roger Maggard anticipates a quick approval for the project.

"The FAA was ready to give us the grant right before they were furloughed,"

Maggard said Aug. 5.

The $21 million project to repave the runway serving Prudhoe Bay and the Alaska oil industry was one of hundreds of projects around the country on hold as the U.S. House and Senate fought over rural airport subsidies and union voting rules.

After Congress made an 11th-hour deal to raise the national debt limit, the House left Washington, D.C., without a resolution to the FAA shutdown that led to the furlough of 4,000 workers, including 79 in Alaska, and idled as many as 35,000 construction workers performing airport improvement projects funded by federal grants.

Using a parliamentary maneuver that required just two senators for unanimous consent, the Senate adopted the House version of a short-term reauthorization for the FAA to end the shutdown.

The timing for the Deadhorse project required the release of grant funding by early August in order to complete work needed for the taxiway to serve as a temporary runway.

Runway lights, approach lights and GPS instrumentation all needed to be in place on the taxiway parallel to the main runway no later than Oct. 1, which is the last day a special FAA aircraft could make it to Deadhorse for a flight check.

Without the grant funding available, the taxiway wouldn't have been ready by Oct. 1 and the flight coordinates couldn't be published by the FAA in time for the 2012 construction season.

Ryan Anderson, design chief for the Northern Region of the Alaska Department of Transportation and Public Facilities, said it will take an entire summer to repave the runway and work had to begin by May 31, 2012.

If the temporary runway wasn't available in 2012, the soonest the main runway could be repaved was 2013.

Sen. Mark Begich called the situation "outrageous" Aug. 1.

"I am pleased that an agreement was reached which will put 4,000 furloughed employees back to work." Begich said in a statement Aug. 4. "It will also get millions of dollars worth of airport construction projects, employing 70,000 construction workers, back on track."

Other projects in Alaska stopped mid-stream during the shutdown will be able to resume.

Stop work orders were issued by the FAA for an $843,816 runway lighting and rehabilitation project in Bethel and for a $563,000 seismic modernization contract for the air traffic control tower at Ted Stevens International Airport in Anchorage. The FAA is spending $20 million to upgrade air traffic control towers in earthquake prone areas.

Ahtna Inc., an Alaska Native regional corporation, is performing the Bethel project; the seismic work at Stevens Airport is being done by Jacobs Engineering of Pasadena, Calif.

Because the FAA couldn't collect passenger taxes and fuel charges during the shutdown, the agency lost out on $30 million per day in revenue, which will add up to some $350 million from the time it shut down July 22 until Aug. 8. That is almost as much as the $400 million in savings over 10 years from the proposed cuts to essential air service, or EAS, subsidies to rural airports.

The lost revenue will also bleed the trust fund that pays for projects like Deadhorse, and by displacing funding from fiscal year 2011 to 2012 or beyond, other scheduled projects figure to delay or lose out on grants.

Bids will be taken for three weeks starting Aug. 17 for a $5 million to $10 million project to improve the runway safety area at Cold Bay. Maggard said he believes the state can get FAA funding this fiscal year for the Cold Bay project.

A similar scenario exists for a $2.6 million rehabilitation, paving and lighting project in Homer. The project is almost ready to advertise for bids, but the state needs authorization from the FAA to post the contract. Maggard said the state will coordinate with the FAA on advertising the project, and that it would "probably" try to secure a grant this fiscal year.

Rep. Don Young said Aug. 2 the Senate could end the shutdown by passing the House version of the bill, a solution that ended up being adopted two days later to accept the last-minute rider attached by Mica targeting EAS subsidies that would have affected airports in Senate Commerce, Science and Transportation Chairman Jay Rockefeller's home state of West Virginia.

Mica inserted the cuts in an effort to force concessions from the Democrat majority in the Senate on regulations revised in 2010 that would make it easier for airline employees to unionize.

Sen. Lisa Murkowski said the dispute got "personal" between Mica and Rockefeller with the FAA caught in the middle.

This is the 21st short-term FAA reauthorization passed since 2007. The latest is good through Sept. 16, two weeks before the end of the fiscal year.

Where the FAA situation ranks in terms of priorities for the Congress when it returns remains to be seen — especially with the continuing resolution funding the government set to expire at the end of the fiscal year Sept. 30 and setting the stage for more budget brinksmanship.

Young noted that Congress hasn't actually completed its budget work for 10 years and Murkowski said Washington, D.C., needs to clean up its act.

"I think it speaks to the fact that we have got to figure out how we return to regular business around the Senate and getting back to ensuring that a budget is introduced so we can operate off it, and ensuring the appropriations committee is able to do the work it needs to do," she said. "We have seen far to clearly how a series of continuing resolutions, year after year after year, hurts us as a nation. It doesn't allow for efficiency.

"It is just not the way to be doing business."

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Republished with the permission of the Alaska Journal of Commerce. Andrew Jensen can be reached at andrew.jensen@alaskajournal.com.

Inlet producer jostled; Field ops unaffected as Miller, Alaska subsidiary deal with stock drop, lawsuits

Wesley Loy
For Petroleum News

Cook Inlet Energy LLC and its Tennessee-based parent, Miller Energy Resources Inc., have enjoyed considerable success since becoming an Alaska oil and gas producer in late 2009.

They grabbed a package of west Cook Inlet assets out of bankruptcy, restored a number of shut-in wells to production, and brought the offshore Osprey platform back to life. Along the way, Miller’s stock price went from a few pennies to a few dollars.

In recent days, however, the good fortune has seemed to turn a bit for Miller and Cook Inlet Energy.

Miller has reported that some of its recent financial filings with the U.S. Securities and Exchange Commission “should not be relied upon,” and must be corrected.

The company’s shares, traded on the New York Stock Exchange, have taken a beating, in part due to a negative online article about Miller. The stock closed Aug. 3 at $3.46 a share. Through most of July the stock traded well above $7.

Aside from these troubles, Miller and Cook Inlet Energy have been hit with two federal lawsuits, one involving Cook Inlet Energy’s former chief financial officer, who was fired.

All these issues stand in contrast to what previously had been a stream of positive news from Miller and Cook Inlet Energy as they advanced their Alaska operations.

‘Full steam ahead’

David Hall, Cook Inlet Energy chief executive, told Petroleum News on Aug. 3 the recent run of difficulties hasn’t hindered the company’s operations in the field.
Assembly continues in Houston on a $17.9 million rig for use on the Osprey platform, Hall said. It’s expected to be in Alaska and working this coming winter.

“We’ve got our heads down and nothing has changed,” he said. “We’re moving full steam ahead. Production is still flowing.”

Cook Inlet Energy operates the West McArthur River oil field as well as Osprey, which sits in the Redoubt unit. The company, with Miller’s backing, acquired the assets in December 2009. The previous owner was California-based Pacific Energy Resources Ltd., which had filed for bankruptcy.

At the time, Miller said it paid about $4.5 million for Alaska reserves valued at more than $325 million.

Since the purchase, Hall and Cook Inlet Energy have set about reviving shut-in wells and making plans for further drilling.

In an “open letter to shareholders” issued Aug. 1, Miller Energy indicated it has four Alaska wells producing around 1,450 barrels of oil equivalent per day. These include the West McArthur 5 and 6 wells, which averaged a collective 847 barrels per day in June, and the recently activated RU-1 and RU-7 wells on the Osprey platform, which averaged 371 and 239 barrels respectively during their first 30 days of production.

CEO refutes ‘attack blog’

Scott M. Boruff, Miller Energy’s chief executive, wrote the open letter to explain some recent SEC filings, and to respond to what he called a disturbing “attack blog” seeking to discredit the company for the benefit of short sellers. Short selling is a technique that can profit an investor who bets correctly that a stock’s price will fall.
On Aug. 1, Miller Energy filed a Form 8-K “current report” with the SEC explaining that some previously filed financial statements, including its Form 10-K annual report filed July 29, contained errors and would be revised as soon as possible. The company added it didn’t expect any “material changes” to its overall financial situation.

Boruff’s open letter also sought to defend Miller’s valuation of its Alaska assets.

On July 28, a website called The Street Sweeper posted a long article highly critical of Miller Energy, questioning the “hefty valuation” the company placed on the assets, and its involvement in a number of lawsuits.

The article had a disclosure at the end saying The Street Sweeper, “through its members,” in late June began establishing a short position in Miller Energy, and that it “expects to profit on future declines in the stock.”

In his open letter, Boruff wrote that “Miller became the target of a short selling blog that hoped to profit from discrediting our company.”

He said his company takes “a conservative approach” to its valuation and production data.

“In order to provide an accurate valuation of our Alaskan subsidiary, we have consulted extensively with independent third parties in order to fairly and reliably value those assets,” Boruff wrote.

In conjunction with a recent financing deal, he said, an “independent reserve engineer approved by our lenders” conducted a review and the valuation was “consistent with” the company’s current reserve report.

Boruff added that “not a single member of our board of directors or senior management has sold a single share of Miller stock since the Alaskan acquisition.”

Two East Coast law firms known for bringing class actions put out press releases on Aug. 1 and 2 announcing they were “investigating” Miller Energy for possible securities violations.

Two lawsuits

As for the implication that Miller Energy is “riddled with lawsuits,” Boruff wrote that “any company our size will be subject to lawsuits in the ordinary course of its business.”
He continued: “Miller is currently being sued by two parties and believes that both lawsuits are without merit.”

In one suit, filed May 6 in federal court for the Eastern District of Tennessee, Troy D. Stafford is suing Miller claiming he was wrongly fired and was denied pay, severance and rights to company stock. All told, he is seeking damages totaling at least $3.47 million.

When the Alaska assets were acquired in 2009, Stafford was part of the deal as Cook Inlet Energy’s chief financial officer.

Miller Energy, in its recently filed annual report, vowed to defend the lawsuit vigorously, saying: “We believe that we had appropriate cause to fire Mr. Stafford.”

A second suit was brought against Miller Energy and Cook Inlet Energy on June 15 in the federal court for the Eastern District of Pennsylvania. The plaintiff, VAI Inc., says it is a Wayne, Pa., financial adviser and consultant that “devoted nearly all of its efforts, time and resources over a six-month period in 2009” to connect Cook Inlet Energy with Miller and help them acquire “those extraordinarily valuable oil and gas assets in the Cook Inlet region of Alaska.”

Despite this help, VAI contends the defendants breached a contract by failing to pay it “warrants for 1,750,000 shares of Miller stock exercisable over a four-year period at $.01 per share.”

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Republished with the permission of the Petroleum News

Central Mac buzz grows; ConocoPhillips says it is focused more on liquids; speculation on Husky oil find

Gary Park
For Petroleum News


ConocoPhillips has done more than anyone so far to explain its interest in July’s blockbuster land sale in the Central Mackenzie Valley of the Northwest Territories that attracted successful bids from four industry majors, all of them anchor-field gas owners in the Mackenzie Gas Project.

But the spotlight is squarely fixed on Husky Energy, which laid out C$376 million for two parcels totaling about 533,600 acres — by far the bulk of the C$534 million in winning bids, which lends weight to those who think Husky may have struck pay dirt and gained the attention of the industry majors in the process.

Clayton Reasor, vice president, corporate and investor relations, told a second-quarter conference call that ConocoPhillips is targeting a Canol shale play.

“The unconventional that we are going after will be more from a liquids perspective than from a gas perspective,” he said.

ConocoPhillips made a work commitment of C$66.7 million for a parcel of about 216,000 acres adjacent to Husky’s sales-leading bids of C$188 million each for two parcels of about 216,800 acres each.

Husky said it is attracted by the prospective nature of the land, which is 50 miles from the existing Enbridge pipeline which transports 34,900 barrels per day of light oil from Norman Wells to Zama in northwest Alberta.

Asked by an analyst why Husky paid twice as much on a per-acre basis as other bidders for similar properties, Husky Chief Operating Officer Rob Peabody said his company has actively explored the Central Mackenzie Valley for more than a decade and has been involved in two discoveries.

Husky’s existing exploration leases in the region include a significant discovery license for the 2004 Summit Creek B-44 natural gas and light oil discovery well drilled into two Devonian-age reservoirs. It also operates a lease over Tulita District Land Corp. freehold parcels. The Summit Creek well operated by Husky tested at 20 million cubic feet per day of gas and 6,300 bpd of oil.

In 2007, Husky, with a 75 percent stake, and International Frontier Resources, with 25 percent, bid C$4.89 million in work expenditures to secure a license farther south.

In 2004 (with a 29.48 percent working interest), Husky was part of a joint venture with Northrock Resources (32.5 percent interest) which bid work commitments of C$24.8 million for a 224,000-acre parcel about 55 miles south of Norman Wells. Other partners were EOG Resources Canada 26.4 percent, Pacific Rodera Energy, 6.62 percent and International Frontier, 5 percent.

In 2008, Husky, as operator with a 75 percent working interest, drilled the Dahadinni B-20 well to a total depth of almost 8,000 feet, logged and abandoned the well as a dry hole. The Northern Oil and Gas Directorate reported that the parcel was surrendered in 2010.

Complement existing portfolio

Peabody said Husky believes the new properties complement existing portfolio in the Central Mackenzie Valley, while its spending commitment is what it will cost to “assess the lease and hopefully move forward.”
Imperial Oil (69.6 percent owned by ExxonMobil) and ExxonMobil’s wholly owned Canadian subsidiary made a combined commitment of C$43 million, divided equally between two parcels totaling 444,000 acres.

Imperial offered no further insight in its second-quarter earnings report beyond noting that the licenses are in the Summit Creek area, while Shell Canada has not commented on the thinking behind its combined bids of C$43.4 million for three parcels totaling 498,000 acres.

The latest spending spree on leases, coming amid an uncertain outlook for the Mackenzie Gas Project, has stirred speculation that Husky may have made a substantial oil find in the Central Mackenzie Valley close to Imperial’s 1920 Norman Wells discovery estimated to have held 630 million barrels of original oil in place, but which is now operating well short of its 45,000 bpd capacity.

Henry Sykes, president of MGM Energy, which partnered with 6362 NWT Ltd. to make made work commitments of C$5 million for three Central Mackenzie Valley licenses totaling 254,000 gross acres, and Pat Boswell, chief executive officer of International Frontier, are among those who think the target is narrowing to a liquids-rich shale play.

Boswell ruefully conceded to Petroleum News that his company had lost out to the “big boys” in the bidding and said it will now have to review its next moves in the region.

He said that “sooner or later somebody is going to find another Norman Wells” in the area.

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Republished with the permission of the Petroleum News