Tim Bradner

State sees 3.8 percent oil production decline next year

Alaska North Slope oil production is expected to average 689,000 barrels per day this year, a decline of 3.8 percent from last year, state revenue forecasters said in a revenue forecast released in Juneau Dec. 9. For 2010, the department anticipates further production declines to 665,000 barrels per day, the report said. The production decline from existing fields will be partially offset by production coming from new fields. It is anticipated that Nikaitchuq, a new field being developed by Eni Oil and Gas, will begin producing oil in 2009, and Oooguruk, operated by Pioneer Alaska Inc., which began producing in 2008, will see increased production rates, the department said in a press release. Continued development in the Colville River Unit, west of Prudhoe Bay, and ongoing exploration in the National Petroleum Reserve-Alaska and other areas of the state is also expected. The state’s assessment on production is in contrast with more conservative views of producing companies. Doug Suttles, president of BP Exploration (Alaska) Inc., told an Alaska business group Nov. 19 that his company anticipates decline rates of 6 percent to 8 percent in the large producing fields of the North Slope, which provide the bulk of production. On revenues, the state said its fiscal year 2008, which concluded June 30, will go down as a record revenue year for Alaska with estimated general fund revenue totaling nearly $10.8 billion, the report said. Oil revenues contributed 93 percent of the income. The revenue forecast for the current fiscal year was estimated at $6.75 billion, and for 2010 it is estimated at $5.28 billion. In fiscal 2009, oil revenues will contribute 90 percent of the state’s overall revenues, and in 2010 oil will contribute and 88 percent. Non-oil revenues are forecasted to total $700 million in fiscal 2009 and $648 million in 2010. These estimates are down from $780 million in fiscal 2008. But the revenue prediction did not factor in recent oil price trends, which have seen decreases of 40 percent since the estimates were put together. The report assumed oil prices in the range of $62 a barrel through the first half of 2009 and prices averaging $74.21 a barrel through the latter part of the year and early 2010.

Shell asks for rehearing of Ninth Circuit court decision

Shell said it will file a petition with the U.S. Ninth Circuit Court of Appeals Dec. 18 to ask for a rehearing of the court’;s decision to block Alaskan Beaufort Sea drilling. The company also said it will not plan drilling or seismic activity in the area in 2009 because of an injunction against exploration issued by the appeals court. A three-judge panel of the appeals court made the decision against the exploration plan issued by the U.S. Minerals Management Service. “After analyzing the recent opinion of the Ninth Circuit, Shell has decided to file a petition for rehearing to the full court. We believe the MMS performed a complete analysis of our exploration plan. That analysis prompted the agency to properly conclude that any impact from exploration activity in the Beaufort would have minimal impact on marine mammals and subsistence activities,” Shell said in a statement issued Thursday. The company agrees with the dissenting judge that the court has exceeded its field of expertise, and in so doing, ignored the expertise of the federal regulators, the company said. Shell also said in its statement that the court’;s decision places excessive requirements on any future exploration program that could result in unnecessary costs and delays in delivering much-needed energy supplies to the nation. The appeals court denied Shell’;s plan arguing that the company and the MMS had done an inadequate analysis of the effects of drilling on marine mammals, particularly migrating bowhead whales. The MMS had prepared an Environmental Assessment of Shell’;s activity, a more streamlined review than an Environmental Impact Statement, which typically requires two years. The company also said it will defer any plans for drilling or seismic surveys in the Beaufort Sea in 2009 because of the litigation. “The reduced 2009 program means hundreds of jobs associated with support for the operation won’;t materialize,” Shell said in its statement. “This will have a direct effect on Alaska communities. Our current level of investment in Alaska is not sustainable given our inability to drill.”

State signs AGIA license granting TransCanada $500M

Alaska officials signed a state license agreement Dec. 5 giving TransCanada Corp. access to $500 million in state funds to aid its efforts to build a $30 billion-plus natural gas pipeline from northern Alaska to Alberta. As the license was signed, at a ceremony in Fairbanks, energy prices continued to plunge in international and North American markets. Energy analysts predicted significant oversupply of gas and low gas prices for five to six years. Such an oversupply would extend a planned open season solicitation beyond 2010, a critical date when both TransCanada and rival Denali, sponsored by BP and ConocoPhillips. Gov. Sarah Palin was on hand for the signing ceremony, along with TransCanada CEO Hal Kvisle and Vice President Tony Palmer. Alaska Natural Resources Commissioner Tom Irwin and Revenue Commissioner Pat Galvin signed the license, as required by the Alaska Gasline Inducement Act. AGIA is the state law that provides for state funds to be awarded to a company agreeing to certain terms, as TransCanada has done. At the ceremony, Palin praised the company’s record. “TransCanada’s record of delivering projects on time and on budget is unsurpassed in the industry,” the governor said. “Their commercial skill and approach to solving problems will no doubt be of value to us as we continue to take the necessary steps forward on this project.” TransCanada proposes a 4.5 billion cubic feet per day, 48-inch diameter, mostly buried pipeline running 1,715 miles, from a natural gas treatment plant at Prudhoe Bay on the North Slope to the Alberta Hub in Canada. The Alaska section will be approximately 750 miles in length with six compressor stations at startup and five natural gas delivery points in Alaska. “An Alaska pipeline will bring huge economic benefits to the state of Alaska, its people and its producers,” said TransCanada President Kvisle. “And TransCanada is excited by the opportunity to take on this important role.” TransCanada started work earlier this summer using its own funds, doing aerial photography and some engineering work. Having the license means the company will now be reimbursed for 50 percent of its expenses until a planned open season in 2010. The reimbursement rate will increase to 80 percent if the open season fails to attract enough gas shipping contracts, and TransCanada continues work on the project. The state grant is for a maximum $500 million. A spokesman for the rival Denali pipeline group said the license award to TransCanada doesn’t affect its work program. “Denali is moving ahead outside the state’s AGIA framework. We welcome competition, but we believe Denali has the best chance of delivering a successful Alaska gas pipeline project,” said Denali spokesman Dave MacDowell. “Our owners have always said they are open to any involvement of any party who can add value and take on some of the risks association with the project.” Denali began work this summer on field studies to prepare for an open season also planned for 2010. The company will spend $600 million of its owners’ funds in preparation for the open season. The deepening economic recession is raising new concerns over whether the giant project will be able to attract the needed shipping contracts. Even if the U.S. economy recovers from its current economic recession, natural gas markets not be particularly robust in 2010. There’s also a lot of new competition. Jen Snyder, head of North American gas research for Wood Mackenzie Ltd., a leading consulting firm, told an energy conference in Houston that new shale gas plays in the continental U.S. could be producing enough new gas to keep gas markets in an oversupply situation. Snyder said there would be significant amounts of gas made available at $5.50 per million British Thermal Units from shale gas plays. Competition for the electric power market will also be coming from new coal-fired power plants and wind-power projects, she said, as well as imported liquefied natural gas.

Meet Alaska's corrosion cops

  Allison Iversen, coordinator of the Petroleum Systems Integrity Office, Division of Natural Resources, works from the Atwood Building in downtown Anchorage. Photo/Rob Stapleton/AJOC     When oil spilled from corrosion-weakened Prudhoe Bay field pipelines in 2006 then-Gov. Frank Murkowski vowed quick and tough action on what were widely viewed as lapses in industry maintenance of facilities vital to the state’s treasury and economy. In the heat of the moment, Murkowski ordered aggressive state inspections of field pipelines and production facilities not covered by federal pipeline regulators. Alaska would become the first oil-producing state to introduce comprehensive government inspection and regulation of “upstream” production facilities. The new inspection bureaucracy Murkowski contemplated sent shivers through industry managers. There were visions of state inspectors crawling through processing plants and offshore platforms writing tickets. Two and a half years later, there’s a different ending to this story. BP has largely completed a reconstruction of its damaged Prudhoe Bay pipelines and has done a major overhaul of internal quality management procedures. Murkowski’s vision of state inspectors playing tough cop has been softened into a more pragmatic and effective approach. That has largely been the work of Gov. Sarah Palin and Natural Resources Commissioner Tom Irwin, who have reputations for being tough on the industry. In this case, though, Palin and Irwin quickly ordered the scaling down of Murkowski’s plans for the large inspection organization just after the new administration took shape in early 2007. BP’s efforts to repair its pipelines were well underway, Prudhoe Bay had resumed full production, and the political furor had died down. The new administration’s approach was more level-headed. Alaska Division of Oil and Gas Director Kevin Banks was put in charge of the new, streamlined Petroleum Systems Integrity Office, or PSIO. The division is part of the Department of Natural Resources. DNR has the responsibility of managing state-owned lands and oil and gas leases, and has broad legal authority to protect the state’s interests and the integrity of facilities that produce state-owned resources. Banks made it clear from the outset that his mission was to cooperate with industry in encouraging good maintenance and management practices, to get people to start working together and sharing “lessons learned,” and to play tough cop only as a last resort. With these marching orders, Allison Iversen, the Petroleum Systems Integrity Office’s coordinator, says the core missions of the new PSIO are first, “to break people out of their silos” to share information, starting with state agencies; and, secondly, to educate other agencies on the benefits of quality management programs. “The end goal is efficient and effective oversight of the petroleum industry,” she said. Iversen is an attorney by training, and was deputy state director of the Joint Pipeline Office before coming to head the PSIO. She has recruited two veterans to help her, Dan Rice and Michael Engblom-Bradley. Rice is a veteran engineer with years of experience at the Joint Pipeline Office and the state Department of Transportation. Engblom-Bradley was with Alyeska Pipeline Service Co. and was in charge of Trans-Alaska Pipeline System quality management programs. He joined the PSIO last February. The agency is about to add two more engineers and two natural resources specialists, Iversen said. The PSIO’s task is complicated because the industry is already regulated heavily by several agencies and a significant problem is that there is often little coordination or communication between agencies. There are gaps in oversight as well as overlaps. Pipelines, loading terminals and tankers have long been subject to federal and state regulation, and producing wells, in Alaska and other states, are inspected by state agencies like the Alaska Oil and Gas Conservation Commission. But field pipelines and oil and gas processing facilities have largely been left to industry, although the state fire marshall and the Departments of Labor and Environmental Conservation have oversight in certain areas. Following the 2006 Prudhoe Bay spills, federal pipeline safety agencies extended their authority to in-field crude oil pipelines, like the ones that spilled oil, but no agency had overall responsibility for the networks of flow lines and major field processing plants. That was the problem with the Prudhoe Bay field pipelines. The allegation, still in dispute, was that BP and ARCO Alaska, which previously operated the eastern side of the field, had trimmed maintenance spending when oil prices collapsed in the late 1990s. Because there was a gap in regulatory oversight, there was no government agency looking over the companies’ shoulders to make sure the maintenance was being done. Problems still occur. A recent rupture of gas in a gas-lift line in the Prudhoe Bay field caught BP and the state by surprise. It was apparently caused by external corrosion and it required two production pads to be shut down while BP made repairs and did inspections.     Dan Rice, Allison Iverson and Michael Engblom-Bradley examine a map of proposed oil and gas drilling locations above the Brooks Range on the North Slope. The three are leading the state’s efforts on pipeline corrosion control. Photo/Rob Stapleton/AJOC     Things could have been worse. Luckily, no fire or injuries happened. BP’s well and pad shutdown systems worked as expected, too. Still, it was a signal problems are out there, Iversen said. Meanwhile, the development of the PSIO is taken in measured steps. “You have to earn the respect of people with something like this. You don’t just issue press releases and blindside people,” Iversen said. The first objective is a comprehensive gap analysis now underway. Rice has done a paper study of gaps in authority among agencies, but a request for proposals has just been issued for a consultant to do a more comprehensive analysis of how different state agencies are actually using their authority. “Most agencies have broad authority but they are all constrained by budgets and personnel,” Iversen said. The goal is to see if it’s possible for agencies to coordinate and communicate better to provide cost-effective oversight, she said. “We hope to have this completed in six months, but because we’re working with many other agencies we’re also dependent on their timelines,” Iversen said. One simple idea, although it’s expensive, would be to have a state office in Deadhorse, near Prudhoe Bay, for all agencies to share. Working in the same office would facilitate communication. Another PSIO objective is to encourage the use of quality management systems not only in industry but also by the state. The agency sponsored a major conference on quality management in Anchorage Dec. 9 and 10, which included industry but was also aimed at state agencies. The conference featured experts in the field both from the public and private sector. “Our goal is to have state personnel get a better understanding of what quality management is. Most people in the agencies do not use quality management principles,” Engblom-Bradley said. Even veteran industry managers often lack a clear understanding of what quality management really is, he said. “Too often, people think it’s just making sure the machinery is being oiled properly,” he said. “It’s much broader than that. It’s really about leadership to ensure productivity, safety and protection of the environment. Without a good management system those things don’t happen.” Dan Rice said PSIO won’t demand companies use uniform quality management systems, but just that they have one and that it is followed. Meanwhile, the Department of Environmental Conservation has a separate, but related, initiative underway. It is a major petroleum infrastructure risk-assessment project. Iversen said the two efforts are intended to complement each other because DEC shares certain types of regulatory authority with DNR over producing oil fields. “Until we fully understand where the highest risks to the state are, we can’t know which gaps to fill or overlaps to delete,” Iversen said. “The PSIO needs the risk assessment to determine what next steps are appropriate once we identify the gaps and overlaps.” When it is complete, DEC’s risk assessment may be the largest and most comprehensive of its kind in the world. Risk assessments have been done for major parts of the state’s petroleum industry - the Trans-Alaska Pipeline System, for example - but there has never been anything that covers such a large geographic area or so many complex systems. Doyon-Emerald, a consulting company, was retained by DEC to do the study, said Ira Rosen, DEC’s manager for the project. An initial phase involving consultations with industry, agency and public stakeholders is complete and the contractor is now in phase two, developing a method to actually do the analysis, Rosen said. The methodology will be reviewed with stakeholders when it is complete. The final phase is obtaining information and development of the model to be used. The end result will be a risk profile of all of the petroleum production and transportation systems in the state, from the North Slope to Cook Inlet, Rosen said.

North Slope is busy despite plunge in oil prices

Activity levels are expected to be brisk on the North Slope this winter, despite the recent plunge of oil prices to levels not seen in years. The plunge has steepened in the last two weeks, but much of this winter’s drilling and construction was planned months or even years ago, and much of it will go forward, the operating companies say. The major operators are warning, however, that next year will be slower as companies adjust their plans to lower oil prices. One positive sign is that BP has increased its planned 2009 capital spending to about $1.2 billion, a 30 percent increase over the current year capital budget of $900 million. The increase essentially covers four long lead-time projects the company has underway, including a heavy oil test development, the start of work on BP’s planned Liberty offshore field, and the company’s share of the Point Thomson development being led by ExxonMobil Corp. and the Denali gas pipeline project being done with ConocoPhillips. The Point Thomson project hinges on whether the Point Thomson leaseowners - ExxonMobil, BP, Chevron and ConocoPhillips - can resolve a contentious dispute with the state over past lease obligations at Point Thomson. The state is attempting to cancel the Point Thomson leases and had blocked a key permit for an ice road that would allow ExxonMobil to move a drill rig to Point Thomson, which is 60 miles east of Prudhoe Bay. The remaining $900 million of BP’s capital budget covers ongoing development work in producing fields on the North Slope, mainly in the Prudhoe Bay field B, where BP is operator, and Kuparuk River field operated by ConocoPhillips, but where BP has a major interest. The deteriorating economic environment has had some casualties in BP’s plans, however. The company announced it will suspend work on a natural gas processing plant planned for Z Pad on the west side of Prudhoe Bay. The company said it will also reduce its development drilling by about 10 percent in 2009 and will operate one less drilling rig next year. BP said its actions were prompted as much by state taxes as falling prices, particularly a limit on tax deductions for capital investments in the Prudhoe Bay and Kuparuk, the two large producing fields. Capital budget plans for ConocoPhillips, the other major North Slope operating company, are not yet known. The company usually announces its plans in December. Other work is underway on the Slope, including the drilling of development wells by Eni Oil and Gas Inc. for its Nikaitchuq offshore field, and Pioneer Natural Resources’ continued drilling of production wells at Oooguruk, another small offshore field near where Eni is drilling. Pioneer is drilling Oooguruk offshore from an artificial island built to support producing wells and facilities. Eni is drilling several wells planned for Nikaitchuq from an onshore pad and will build an offshore gravel island in a second phase of the project. Winter exploration activity is proceeding as planned. Much of the exploration will be near the existing fields or near discoveries. ConocoPhillips will drill two exploration wells in the northeast National Petroleum Reserve-Alaska as previously announced, near the Moose’s Tooth area, where small discoveries have been made. Savant, an independent company, will drill a well east of Prudhoe Bay near BP’s small Badami field. Independent Ultra Star will drill a well near Prudhoe. Brooks Range Petroleum, the operating company for a group of independents, also has winter drilling plans near the large producing fields. Two major exploration efforts in more areas of the slope include Anadarko’s drilling for natural gas in the foothills region southwest of Prudhoe Bay, where the company plans to complete a well started last year, drill a new delineation well near where Anadarko drilled last year at Gubik, a known gas discovery, and a new test well a new miles west in the National Petroleum Reserve. Chevron Corp. will also continue with its multi-year exploration in the White Hills region south of Prudhoe Bay. Chevron began its program in the White Hills last year.

Southcentral Alaska's gas situation is grim and getting worse

Southcentral Alaska’s natural gas situation is getting grim. The large producing fields in the region are being depleted faster than expected. While there is still plenty of gas left in producing gas fields, producing companies and utilities are concerned about the “deliverability” of the fields, or the capability of the aging wells to produce enough on cold winter days to meet peak demands. “Gas deliverability from the four largest fields in the Cook Inlet Basin has declined significantly in the last three years,” Steve Wright, Chevron Corp.’s Alaska asset manager, told the Resource Development Council Nov. 19. “These four fields - Beluga River, North Cook Inlet, McArthur River field and Kenai field - were capable of delivering up to 14 billion cubic feet per month in January 2004. At present, they are capable of producing only 9 billion cubic feet per month.” The four fields produce about 65 percent of the natural gas production in Southcentral Alaska. The concern over deliverability was a major factor in Chevron’s decision to reduce the amount of gas it will supply in its contracts with Enstar Natural Gas Co. from 2012 to 2016. “We could not document that we would have adequate deliverability to have met this commitment,” Wright said. The heat and power in Southcentral Alaska communities won’t get turned off, however. ConocoPhillips and Marathon Oil, the owners of the liquefied natural gas plant near Kenai, have pledged to backstop utilities if gas deliverability is insufficient on cold days. Still, the underlying problem of declining reserves is getting worse, and exploration results in recent years have been modest. “Gas exploration has not been successful. Chevron has operated six exploration wells in recent years and have had only modest success,” Wright told the RDC council. There is good potential in the region, but the problem is that many areas with prospective geology have substantial surface occupancy issues, he said, which limits explorers’ access. Production has actually dipped below what the state Department of Natural Resources has estimated would be possible from remaining proved gas reserves in the Cook Inlet Basin, he said. The industry isn’t sitting on its hands, however. Chevron and other Cook Inlet operators are making substantial investments. Two years ago Chevron announced a $400 million program to refurbish aging oil production platforms in Cook Inlet and to stimulate new gas production. The company is carrying out that program, Wright said. Marathon and ConocoPhillips have made separate commitments to drill new gas wells in an agreement with the state related to a two-year extension of a liquefied natural gas export license for the Kenai-area plant the two companies own. “Our hope is that new drilling in the Beluga and Ninilchik fields will stem the decline, but we see no scenario where the decline is eliminated,” Wright said. Chevron itself has spent $200 million over the last years in its new drilling program, which include oil as well as gas. Chevron has invested in projects in seven gas fields and two oil fields. Results of the drilling are generally positive, but there were disappointments as well, Wright said. “A few of our wells far exceeded expectations, some came close to what we had forecast, but a couple were expensive but poor producers,” he told the RDC. “There is a lot of stratigraphic variability in Cook Inlet. The risks and uncertainties there are not average.” The company still expects to spend $100 million to $200 million over the next three to five years on projects, but plans are always subject to change. Given the downward shift in oil prices, “we are currently reassessing our opportunity catalogue,” Wright said. Natural gas projects in the last year have included two new gas development wells in the Happy Valley gas field on the Kenai Peninsula, the installation of a new production pad and the testing of a new “fracture” technology to stimulate production, and three new gas wells and a compressor to boost deliverability of gas in the Ninikchik gas field, where Chevron owns 40 percent (Marathon Oil is the majority owner, at 60 percent, and operator). Other projects included two new gas wells and a workover in the Beluga River gas field, and two new production wells and the addition of compressor capability on the Steelhead platform, which produces gas. On the oil side, Chevron has drilled two new wells in the Granite Point field from the Anna platform. These wells did not meet expectations, Wright said. Chevron also drilled one new well and two well maintenance jobs in the Swanson River oil field, and performed six well maintenance jobs in the McArthur River field. “Gas-lift” wells, which use natural gas to lift crude oil up producing wells, were also converted to down-hole electric pumps to bring the oil up. This has the effect of freeing up gas supplies, Wright said.

Belts tighten on Alaska's North Slope

  A Carlile Transportation truck driver tightens a load of pipe from a storage yard at Prudhoe Bay that was headed for the Alpine Field early last year. Producers are tightening their belts as oil prices drop worldwide. File Photo/Rob Stapleton/AJOC     Belts are tightening on Alaska’s North Slope. After several years of hectic activity, the plunge in oil prices is sending a chill through the state’s oil patch. BP Exploration (Alaska) Inc. president Doug Suttles said his company will suspend work on a $120 million gas processing plant planned for the western part of the Prudhoe Bay oil field and will reduce its drilling by about 10 percent next year. ConocoPhillips’ Alaska president Jim Bowles warned that “things will get tougher next year” as oil producers struggle with high costs and high state taxes but sharply lower oil prices. Pioneer Natural Resources Corp. said it would delay a delineation well planned for its Cosmopolitan offshore oil project in Cook Inlet from 2009 until 2010, which effectively delays plans to put the field into production, said Pioneer’s Alaska manager, Ken Sheffield. Cosmopolitan is three miles offshore from Anchor Point on the Kenai Peninsula. Suttles, Bowles and Sheffield addressed the Resource Development Council’s annual conference in Anchorage, Nov. 17 and 18 along with other industry officials. In addition to the project deferrals, however, people at the RDC conference were worried about the state of Alaska’s effort to stop ExxonMobil’s drilling planned this winter at Point Thomson, east of Prudhoe Bay. ExxonMobil plans to begin drilling in February in the first stage of a $1.3 million condensate production and gas cycling plan, but the state Department of Natural Resources blocked a permit giving permission for the company to build an ice road to move the drill rig 60 miles from Prudhoe Bay to Point Thomson. Though some projects are delayed, other work is proceeding, and the lights won’t be turned out at Prudhoe Bay anytime soon. Suttles told the conference his company is proceeding with its plan to develop the $1.2 billion Liberty offshore field, with site preparation work starting this winter. BP is also continuing with a test program to develop heavy oil deposits. Three new test wells are being drilled into the Ugnu heavy oil formation by BP as part of a long-term test of a new production technology. Eni Oil and Gas will continue its development of the Nikaitchuq offshore field, an oil deposit in shallow waters two to three miles north of the Beaufort Sea coast. Drilling of the first production well for the Nikaitchuq started this month at a drill pad near Oliktok Point, northwest of Prudhoe Bay. Eni hopes to have the field in production by the end of 2009. Bowles said ConocoPhillips plans two exploration wells this winter near previous discoveries in the National Petroleum Reserve-Alaska. UltraStar, a small independent, plans an exploration well north of the Prudhoe Bay field. Anadarko Petroleum Corp. plans to complete a test well and drill two others in a search for natural gas in the foothills region of the southern North Slope. Chevron Corp. will continue a multi-year exploration drilling program in the White Hills region, south of Prudhoe Bay. In other projects, BP will also complete its construction of new Prudhoe Bay field pipelines this winter, concluding a two-year project, Suttles said. ConocoPhillips hopes move toward development of the CD-5 production area in the Alpine field in the Colville Delta, west of the Kuparuk River field. Bowles said the company is putting a priority on resolving permitting problems on a river crossing that will give access to CD-5. The river crossing has become bogged down in local controversy. People in the village of Nuiqsuit, which is nearby, have objected to the company’s plan to cross a channel of the Colville River to develop the CD-5 site. Bowles said the crossing is important to plans for developing substantial new resources in the area as well as discoveries ConocoPhillips and its partner, Anadarko Petroleum, have made farther to the west in NPR-A. As for the projects being deferred, Suttles and Bowles said their two companies are being squeezed by high costs, high taxes and now declining oil prices. The projects themselves aren’t affected by short-term price volatility, they said, but declines in prices do mean there’s less cash available to fund new projects. Suttles said costs on the North Slope have increased at rates of 15 percent to 20 percent over the past two years. Both Suttles and Bowles said that the state’s new production tax, and mainly a cap on deductions of costs from the big Prudhoe and Kuparuk River fields, have hurt the economics of marginal projects like the gas processing plant at Z Pad. Last year BP cancelled another west-end Prudhoe project, the $1 billion “I-pad,” a 50-well production pad. Bowles said another casualty of the state’s new tax law, a new refining unit to make ultra-low sulfur diesel fuel on the North Slope for use by the producing companies and contractors, had to be cancelled. Federal rules are requiring the use of ultra-low sulfur diesel in diesel engines in trucks and heavy equipment on a phased-in schedule and the fuel will be required to be used on the North Slope in 2010. The companies had planned to modify a small diesel-refining unit to make the diesel on the slope, but state tax rules make the project uneconomic. The only alternative now is to transport the diesel by road from the Tesoro refinery near Kenai, which has the capability to make the fuel. “What this means is that 25 million to 30 million gallons of ultra-low sulfur diesel will have to be hauled to the North Slope up the Dalton Highway beginning in 2010. This is expected to add $100 million in new operating costs,” Bowles told the RDC conference. Suttles said the North Slope is declining at rates of 6 percent to 8 percent annually. “If those rates continue, by 2020 there will be about 200,000 barrels per day moving through the Trans-Alaska Pipeline System, about a third of what the pipeline is handling today,” he said. That’s about the time a natural gas pipeline is expected to be in operation, but Alaskans shouldn’t think that gas could entirely replace oil in providing revenues to the state treasury. “Four billion cubic feet of gas is the energy equivalent of about half of today’s oil production,” he said. “Gas is not enough,” Suttles said. “It’s important we continue to develop new oil resources, like heavy oil and oil from offshore,” he said. New conventional oil will be needed to blend with heavy oil that is too thick to flow through the pipeline by itself. The squabble over Point Thomson development, which led the state DNR to refuse an ice road permit, involves a long-standing dispute over past work obligations between the state and Point Thomson leaseowners, which include BP, Chevron, ConocoPhillips and ExxonMobil, which is the operator. If the ice road permit isn’t issued in November the companies may not be able to build the ice road in time to move the rig to the field. If the drilling is delayed, the companies may not be able to meet their timetable to have Point Thomson in production by 2014. Ironically, the root of the dispute is the claim by the DNR that ExxonMobil and its partners haven’t been diligent in efforts to develop the field. The DNR is now attempting the cancel the leases. There’s wide agreement within industry and even other states agencies that canceling the leases will set Point Thomson development back 10 years to 15 years.

Fairbanks man receives first state ADS-B loan

The first state loan application for the equipage of new aviation technology, referred to as NexGen, has been approved and the equipment installed in a Fairbanks-based aircraft. The Alaska Avionics Loan Program, introduced in a bill by Gov. Sarah Palin in January 2008, qualified its first applicant for the installation of Automatic Dependent Surveillance-Broadcast, or ADS-B, equipment. Fairbanks resident Gary Hunt has the technology in his amphibious Lake Buccaneer aircraft. ADS-B is a situational awareness technology that displays on a cockpit screen other aircraft, as well as the terrain in the area. It offers a moving map display, weather and terrain avoidance features, as well as in-flight messaging capability. It was previously called the Capstone Safety Program. This Federal Aviation Administration-sponsored program was tested in Southwest Alaska, and was credited with a significant and immediate drop in the number of aircraft accidents. The equipment effectively replaces radar with a real-time digital tracking of aircraft. The state-sponsored loan program was intended to spur the usage of a mechanism to finance the safety equipment. “This is a fabulous program, and the application is a piece of cake,” said Hunt, a retired FAA safety inspector and commercial pilot. Statewide aviation officials, dubbed the Capstone Statewide Agreement Implementation Committee, along with the FAA signed a memorandum of agreement in 2007 saying that the state would gather $34 million and would receive $493 million in services and infrastructure improvements from the federal agency once a quota of Alaska aircraft are equipped. Palin signed Senate Bill 249, which provides the rules for the low-interest revolving loan program, on May 3 at the 11th annual Alaska State Trade Show and Conference. Those in the aviation industry were slow to apply, however. Some point to the high fuel costs, which cuts into their extra funds to buy new equipment. Current Alaska cost estimates range from $14,000 to $18,500 per aircraft for installation and the hardware. Hunt, who spent $34,000, has installed the full suite of ADS-B equipment to qualify his privately owned aircraft for instrument flying. Hunt paid for the equipment and installation before applying for the loan, and now has the option of being reimbursed. Hunt’s aircraft was equipped by Fairbanks-based avionics service and installation business Air Com. “They ordered it and I paid for everything in advance, except the GDL-90 (a universal access transceiver), which I had them order after the loan was approved,” said Hunt. The $14,000 GDL90 unit is now on order, and was expected to arrive in Fairbanks in mid-November. Hunt approached state lending officials as they were soliciting loan applicants at the Aviation North Expo, held in Fairbanks Oct. 16-18. “I talked to Geoff Whistler at ANE, took the paperwork home and filled in the squares,” said Hunt. “I brought it back the next handed it in and got the loan approval the next week.” Whistler said that the department worked with Legislative Affairs officials to keep the application and credit process simple. “We have worked very hard to keep this a simple and straight forward as possible,” said Whistler, who works with the Alaska Division of Investments. Hunt is bullish on the equipment and says, “its air traffic avoidance at its best,” and that other aircraft owners should install it. “Really this is so easy to get, the state has done a great job pulling this together,” said Hunt. “We have to get more aircraft equipped to get ADS-B compliant. The state needs the infrastructure improvements that will come with our compliance.” The $5 million revolving loan program offers 4 percent interest over 10 years. It is being administered by the Alaska Division of Investments. The agency also has approved applications from Era Aviation for its Dash 8 aircraft, said Whistler, the lending manager. “Really you have to credit the governor for seeing this through,” Whistler said. “She put the full weight of the governor’s office, pushed this through, rallied across political lines, and achieved this in a record period of time.” ADS-B is touted as the replacement for radar in less congested areas of the U.S. and for use in rural and Third World locations.

State denies permit for Point Thomson ice road

The state of Alaska on Nov. 14 denied a key permit to ExxonMobil for an ice road needed for drilling it plans in the disputed Point Thomson gas and condensate field on the North Slope, upping the ante in a contentious dispute between leaseholders at Point Thomson and the state Department of Natural Resources. A statement on the agency’s decision was posted on DNR’s Web site. ExxonMobil said Nov. 17 that it has yet to receive a letter from DNR giving formal notification of the decision. Other state and federal agencies have given their approvals for the ice road, the company said. The company says it will keep working on the project in hopes of resolving a dispute with the state. The dispute with the state involves past work obligations at Point Thomson. The state alleges ExxonMobil reneged on commitments and has moved to cancel leases. The issue is now in the Alaska courts, and settlement talks are underway between the companies and the state. “We have the right to conduct drilling activities under terms of the leases. The Point Thomson working interest owners are proceeding with the project and the drilling plan while we attempt to resolve the dispute with the state,” company spokeswoman Margaret Ross said. ExxonMobil, the operator at Point Thomson, needs a state permit to build a 50-mile ice road east from Prudhoe Bay to move a drill rig to the field. Work on the ice road needs to begin in begin in November to allow the rig to be moved in time for drilling to start in late January or early February. If the rig move cannot be done on schedule, it may delay the project because of seasonal constraints in moving equipment on the North Slope. Heavy equipment can only be moved by land during the winter on the Slope. The Point Thomson leaseowners, which include BP, Chevron and ConocoPhillips as well as ExxonMobil and a number of minority owners, are planning a $1.3 billion gas cycling condensate production project in the field, which is undeveloped. The well planned in January is the first of five production wells needed for the project, which is to produce 10,000 barrels per day of liquid condensates beginning in 2014. In a press release issued Nov. 17 the state called the company’s effort to get the permit “an effort to force a solution” in the current negotiations over the dispute. “ExxonMobil has been aware for many months that the state did not approve its drilling plan. Although ExxonMobil has challenged the state’s decisions in court, it is not in the state’s best interests to allow them to proceed until a court determines whether or not the state’s actions were proper,” the press release said. Ross said ExxonMobil believes the leases are still valid. An estimated 9 trillion cubic feet of natural gas and 200 million barrels of condensates have been discovered at Point Thomson in exploration drilling during the 1970s and 1980s. The field has not been developed to date because of lack of a gas pipeline and technical questions over whether liquid condensates can be produced in a gas cycling project. The current project planned by the companies is intended to resolve the technical questions, ExxonMobil has said in previous briefings. Point Thomson reservoir pressures are high, at 10,200 pounds per square inch, which complicates any development, the company has said.

Big jack-up rig may be heading to Cook Inlet

Pacific Energy Resources Ltd. has notified the state of Alaska that it has signed a contract for a heavy-lift vessel to move the Blake 151 jack-up rig to Cook Inlet to drill offshore exploration wells. The company hopes to have the rig in place for the 2009 summer drilling season. The contract for the rig was signed with Blake Offshore LLC earlier this year but getting a suitable vessel to move the rig from the Gulf of Mexico has taken the company longer than expected, said Kevin Banks, director of the Alaska Division of Oil and Gas. The state is considering an extension of Pacific Energy’s Corsair Unit in Cook Inlet, and the contract to bring the jack-up rig to the inlet is a condition to the extension, Banks said. The division is examining the contract and will make a decision to approve the unit extension in a few days. Pacific Energy will share the costs of bringing the rig north with Renaissance Alaska LLC, another independent company with leases in Cook Inlet. Renaissance would use the rig to drill its Northern Lights prospect, an offshore area in the inlet where there are confirmed showings of oil from old exploration wells, said Mark Landt, a Renaissance official. Banks said companies have found several prospects for oil and gas in Cook Inlet with the benefit of new technologies, like three-dimension seismic, that were not available to the industry in early rounds of exploration in the 1960s and 1970s. Exploration has been stymied, however, by the lack of suitable drilling equipment capable of drilling in areas too far to drill with extended-reach wells from shore. Cook Inlet is a mature producing area with three decades of production, but state geologists believe the area has not been sufficiently explored, Banks said. Pacific Energy, Renaissance and other independents have been working for several years on plans to share costs to get a jack-up rig to Alaska. A key obstacle was the U.S. Jones Act, a federal law that requires shipments between U.S. ports to be done with American-built vessels. There are no U.S.-built heavy-lift vessels capable of carrying a jack-up rig, however. The problem was solved last year when Alaska U.S. Sen. Ted Stevens secured a one-time exemption from the Jones Act for a foreign-built heavy-lift vessel to move the Blake 151 to Alaska.

Apprehension, caution among Alaska miners at meeting

  Steve DeMolen with NC machinery shows Stan Peters, a heavy equipment operator at the Donlin Creek mine, a simulator that teaches drivers how to operate the new Caterpillar M series grader. Photo/Rob Stapleton/AJOC     There was an air of apprehension among the 600-plus Alaska miners who gathered Nov. 5 in Anchorage for the Alaska Miners Association’s annual convention. The state’s minerals industry is at a high plateau - production revenues and development and exploration spending surpassed $4 billion last year, a record - but there are new worries that the world financial crises will cause this to unravel by cutting funds for development and new exploration. Miners are an optimistic lot, though. One sign of that is the record number of exhibitors signed up for the miners’ association convention trade show this year, a signal of confidence among suppliers and contractors, said Steve Borell, the association’s executive director. There were warning notes, however. “Those of us who managed to save some cash should survive, but not all of us will be here next year,” at the 2009 convention, said speaker Greg Beischer of Millrock Resources Inc. In the current downturn, share prices of small and large mining companies have dived, and as many as 50 percent of the small “junior” mining companies, who finance their exploration through equity offerings on Canadian stock exchanges, could be casualties of the recession. Even big companies aren’t immune. Anglo American and Teck are cutting back, although those companies’ Alaska projects haven’t been affected so far. Others at the convention shrugged off the bad financial news as just another dip in a cyclical minerals industry. “I’ve been in this business for 30 years and I’ve seen all this before,” said Don Stevens, of Stevens Exploration, an Anchorage-based geologic consulting firm. “The companies that don’t survive are those that are poorly managed. Companies that are well managed and that have retained some cash will get through this.” Rick van Neuwenhuyse, president of NovaGold Resources, even sees positives. “It means costs will come down,” he said. Construction cost inflation has doubled the cost of developing new mines in the past two to three years, van Neuwenhuyse said. He welcomes lower fuel prices and a cooling-off in markets for steel and other construction materials. If companies have the cash, there are some real deals out there, van Neuwenhuyse said. In a downturn, properties can be acquired on the cheap. In fact, van Neuwenhuyse started NovaGold just that way a decade ago. The company acquired most of its assets during period of gold price slumps, he said. That includes the company’s holdings in the large Donlin Creek gold project near the Kuskokwim River, where it is now a 50 percent partner with major miner Barrick Gold. NovaGold acquired the Alaska Gold Co. property in Nome as well as Rock Creek during period of price slumps. Rock Creek has just started producing gold. The pain is mostly felt among companies working in industrial metals like copper and zinc, where a falloff in industrial activity has caused prices to dip sharply. Copper prices have dropped from $3.50 per pound to $1.75 per pound in a short time. With prices like that, companies with new copper projects must have courage. “It costs $2 to produce a new pound of copper,” van Neuwenhuyse said. Gold prices are holding up better, although they have dropped too. Companies with gold projects are considered to be better positioned, Beischer and other speakers at the convention said. Joe Beedle, executive vice president of Northrim Bank, told the convention he expects the national recession to be extended and deep, although Alaska’s economy has been largely spared so far. The shakeout in the world mining industry has some positives, however, because high-cost mines are being closed and capacity is being taken out of the market. Beedle agreed with van Neuwenhuyse that costs will drop, a positive, and that the downturn may blunt some of the effectiveness of environmental extremists. But on the global level, there will be consolidations and big mining companies will get bigger. Even companies with liquidity may not spend and many projects will be put on hold or go into cold storage, Beedle said. Minerals companies do have some advantages over firms in other industries, Beedle said, because they are used to projecting costs, profitability and schedules in a uniform manner and working with a financial community, mostly Canadian, that is experienced in mining. The Canada connection is important because 70 percent of the financing for Alaska mining projects comes from that country. Large Canadian banks that work with the mining industry, such as the Royal Bank of Canada, did not acquire risky assets as did large U.S. financial institutions, and are thus better off now than their U.S. counterparts, Beedle said. “Banks like these know the mining industry and they are patient capital,” meaning lenders will look to the long term on their financing, not demanding quick returns. “However, expect them to be at the table with you in making decisions, and they are tough,” Beedle said. “The better you are able to project your costs and revenues, the easier it will be to get financing.” But that can be a tough order in the current unsettled environment. “The challenge for us is to determine what long-term metal price we should use,” van Neuwenhuyse said. There are other problems that add to the woes, like currency swings, van Neuwenhuyse said. This is particularly important for Canadian-based mining companies, which include most of the firms exploring in Alaska. “We’ve seen currency swings of 35 percent,” van Neuwenhuyse said. Some of NovaGold’s own projects and those of other companies based in Canada have to deal with these problems. Like Beedle, van Neuwenhuyse does not see a speedy recovery of the economy. “They’ll sort this out (the world’s financial and government leaders) but the only way out is to inflate the economy. To do that, they’ll have to print massive amounts of money.” The miners’ association’s annual convention is mainly an opportunity for the state’s mineral industry to get together to compare notes and technical reviews of exploration projects. Updates on current projects underway are a staple of the convention, and companies aren’t shy about sharing accounts of bumps they have encountered. Among several projects featured, NovaGold’s new Rock Creek project, located 10 miles north of Nome, has just started operations and is expected to reach its expected full rate of production by mid-2009. Company President van Neuwenhuyse said he is optimistic that new resources around the existing mine as well as nearby satellite gold deposits will at least double the mine life beyond the five years of production expected with current gold reserves. An unusually heavy snowfall last winter and a rapid meltoff in late spring complicated the final stages of construction, presenting real challenges in managing the meltwater runoff, van Neuwenhuyse said. Rock Creek also encountered increases in construction costs and now that production has finally started, declining gold prices, van Neuwenhuyse said. Steve Teller, of Mystery Creek Resources Inc., said his company is continuing to work on the small, high-grade Nixon Fork mine northeast of McGrath, which Mystery Creek produced recently until encountering unexpected problems with the complex underground ore body. Basically the company encountered voids, or open spaces, in the limestone formation where the modeling had predicted veins of ore, a disappointing discovery. Mystery Creek is continuing to examine and explore the ore body, though, and Teller believes the mine will be back in production. The multi-metal ore is of high quality and the company believes there is substantial potential there, Teller said. Karsten Eden, of Silverado Gold Mines Inc., described his company’s exploration program at the Nolan Creek Mine near Bettles, on the south flank of the Brooks Range. Nolan Creek is a historic placer producing area and Silverado produced placer gold there in the past, but in recent years has focused on attempting the find the lode gold source of the placer gold, Eden said. Silverado believes it has now accomplished that. A small underground mine at Nolan Creek is in the planning stages. Among large projects, exploration drilling and development work at the large Donlin Creek gold project near the Kuskokwim River is nearing completion. The project will soon shift into the permit stage, which is expected to take two to three years, van Neuwenhuyse said. NovaGold is a 50 percent owner of Donlin Creek. The project still appears to be attractive. At the large Red Dog Mine in Northwest Alaska, TeckCominco’s activities are focused on permitting an expansion of the mine to a new pit, Jim Kulas, the company’s environmental manager, told the conference. The company has about a year and a half of production left at its present pit and would expand to mine an adjacent ore body if the government approvals come through, Kulas said.

100 renewable energy projects head for final review

State officials are in the final stages of reviewing renewable energy projects eligible for $100 million in state funding and expect to make final recommendations to a legislative committee Dec. 7, state energy director Steve Haagenson told a state energy task force Nov. 10. If the projects recommended by the Alaska Energy Authority, Haagenson’s group, are followed by the Legislative Budget and Audit Committee, which has authority to approve them, the $100 million will most likely be dispersed in the first quarter of 2009, according to Karsten Rodvick, spokesman for the AEA. House Bill 162, passed by the Legislature in the 2008 session, set up a $250 million state renewable energy grant program, with the current $100 million funding as the first year increment, and requires the audit committee to approve the first round of renewable energy projects. Subsequent rounds of funding must be approved by the entire Legislature. Haagenson told the Alaska Renewable Energy Task Force that 112 proposals were received at the Oct. 8 deadline for a “round one” solicitation for projects that were well defined and more or less ready for final engineering or construction. About 12 applicants were eliminated, leaving about 100 for the final round of scrutiny by the AEA, Haagenson said. Only part of those will make the final cut to be recommended by the AEA because the amount of money being requested is over four times the $100 million being offered. All of the final applications will be given to the legislative committee, but it’s likely the legislators will follow the agency’s recommendations in the final approvals. Meanwhile, a second set of project applications were also solicited in a “round two,” for projects that needed more time for definition and development. The deadline for those was Nov. 10. By the end of the day, 110 applications had been received by the AEA, some that involved more than one renewable energy project, according to Rodvick. Round two projects will undergo the same screening as round one projects, but only $50 million is likely to be available under House Bill 162 and even that must be appropriated by legislators next spring as part of the fiscal year 2010 state budget. Meanwhile, the energy agency is still planning an early December rollout for a statewide energy plan. Haagenson told the renewable energy task force Nov. 10 that a core part of the energy plan will be community plans with a catalog of options available to local residents for reducing fuel use along with an estimated cost of implementing each option. The agency is now scrambling to get the cost information completed before the December deadline, he said. Two uncertainties the AEA has had to deal with in preparing the plan was knowing how much fuel was being used in each community, which would give the agency an idea of the amount that can be displaced by a new energy source, and a price to assume for the cost of the fuel. For the cost of oil, the AEA wound up using $110 per barrel as an expected long-term price, an amount recommended by University of Alaska economists. Determining the amount of fuel used has been a struggle, however. The AEA wound up hiring University of Alaska researchers Steve Colt and Nick Symomiak to do a fuel-use survey. Colt told the energy task force Dec. 10 that while the amount of diesel used for power generation in rural communities is known with precision because of state Power Cost Equalization payments, oil used for space heating and transportation could only be roughly estimated using a combination of methods. The figure Symomiak and Colt finally arrived at was approximately 737 gallons of fuel oil per year for heating and 548 gallons per year for each job in the community. The combination of those two multiplied by the number of households and number of jobs gave an estimate that the two economists believed was roughly accurate. “We’re not looking for a perfect set of data at this point, but something that is in the ballpark,” Colt said. “This is very high level. We could be off 20 percent.” Haagenson said a rough estimate was adequate for the AEA’s initial task of planning strategies for reducing fuel use, but as communities begin actually looking at projects a more detailed and accurate figure for local fuel use will be needed. Rep. Anna Fairclough, chair of the task force, said she was uncomfortable with possible inaccuracies in the fuel-use data at a time when legislators will be asked to approve more funding for energy projects. Rep. Bill Thomas, R-Haines, another legislative task force member, said it may not be worth a lot of expenditure if the accuracy can be improved only marginally, but that he and other alternative energy advocates will need good ammunition to counter efforts to reappropriate the funds identified for energy projects. “Oil prices are taking a dip now, but they’ll be back up,” Thomas said. Thomas said the AEA should solicit the help of the Alaska Municipal League, the state Chamber of Commerce and school districts in assembling more accurate data on local fuel use. “If they want our help (with energy appropriations) they’d better help us,” get the data needed, he said. Another task force member, Sen. Joe Thomas, D-Fairbanks, said some of his Interior Alaska constituents volunteered that they typically use about 1,200 gallons of fuel oil per year for heating, which is not far off the rough estimates Colt and Symomiak made for rural communities. He said fuel oil distributors could be persuaded to volunteer figures for average household delivery, which would provide a useful set of data. Colt told the task force that Southcentral Alaska households served by Enstar Natural Gas Co. typically use about 200,000 cubic feet of natural gas per household per year, which on an energy unit basis is the equivalent of about 1,200 gallons of fuel oil.

BP pipe rupture caused by external corrosion

A preliminary investigation into the Sept. 29 rupture of an eight-inch high-pressure pipeline on the North Slope points to external corrosion as a likely cause, BP and state officials say. The pipe was carrying carrying gas to a Prudhoe Bay field production pad. Allison Iverson, director of the state Petroleum Systems Intergrity Office, said BP’s initial investigation indicated the presence of external corrosion, but other factors may have also been involved. Iverson said the state is working with BP on reviewing maintenance and operations procedures for flow lines serving production pads in the Prudhoe field. “Fortunately no one was hurt and there was no fire, but this could have been a very serious incident,” Iverson said. The gas line was operating at 1,600 pounds per square inch and was carrying gas to be used in gas-lift equipment in the producing wells. BP spokesman Steve Rinehart said no one was near the pipe when it ruptured but there were workers on the pad at the time. “Our safety systems worked as intended, including pressure-sensitive automatic valves. The pad operator notified the central field controllers, who shut down the facility,” Rinehart said. A preliminary report on the incident showed the presence of external corrosion on the pipe where insulation had been removed and water had accumulated, Rinehart said, but there may be other factors, such as problems in metallurgy, which are still being investigated. BP is now carrying out inspections of other flow lines in the field where similar circumstances may be present. Two Prudhoe production pads, Y Pad and P Pad, remain shut down as the investigation continues and repair work is done, BP spokesman Steve Rinehart said. About 5,000 barrels per day of production is affected by the shutdown, he said. Iverson said oilfield flow lines are under the regulatory jurisdiction of the state PSIO, a division within the state Department of Natural Resources. Federal pipeline safety regulators have jurisdiction over larger field pipelines that carry crude oil from processing facilities to the Trans-Alaska Pipeline System. However, federal regulators are providing technical assistance to the state under an agreement between state and federal agencies, Iverson said. BP is meanwhile continuing a project to replace major field crude oil pipelines that were damaged by internal corrosion and taken out of service in 2006. Rinehart said construction of four pipeline sections is complete and two segments are in operation with the other two expected to go into service by the end of the year.

Ten groups pay $9 million for on/offshore lease sale on North Slope

The state of Alaska auctioned off new leases on the North Slope Oct. 22, bringing bonus bids of $9.1 million into the state treasury. Some 32 offshore tracts and 60 onshore tracts brought bids from 10 different bidding groups in the sale. The state offers acreage annually in regularly schedule areawide sales, which typically include all unleased state lands in a given region. The October sale included unleased North Slope onshore and Beaufort Sea offshore acreage within the state’s three-mile territorial limit. Other areawide sales are held at different times of the year in the Cook Inlet basin in southern Alaska and the Bristol Bay region in Southwest Alaska. Kevin Banks, director of the state Division of Oil and Gas, said the Oct. 22 North Slope sale results signaled a continued interest in oil and gas exploration. Tracts that received bids were generally around existing prospects and areas of unleased acreage between and around existing producing units, Banks said. Many bids were for tracts around the Colville River delta and offshore. The tract receiving the highest bid, $305.87 per acre by Pioneer Natural Resources, is adjacent to the Oooguruk Unit, which contains the Kuparuk and Jurassic oil-producing sandstone reservoirs. Leases recently taken out of the Badami Unit, east of Prudhoe Bay, also received bids. One tract near the Niakuk unit, which produces from the Kuparuk formation, was bid on by a consortium of major producers: BP, ConocoPhillips, Exxon and Chevron. The majority of bids were by a new entrant, “70 & 148 LLC” (the latitude and longitude coordinates for Prudhoe Bay), which successfully bid on 19 Beaufort Sea tracts and 48 North Slope tracts. “Many tracts offered in the sale were relinquished to the state in the ordinary course of our management of oil and gas lands,” Banks said, meaning they had been previously leased and returned to the state. The fact that different companies bid on the previously leased acreage is encouraging, Banks said. “I believe that new entrants in the Alaska oil and gas industry are motivated to try new concepts to develop prospects that may have been overlooked,” he said. “The economy of Alaska is enhanced when these newcomers can join those active companies already here as part of a vibrant, diversified petroleum industry.” Half of the bonus bids received Oct. 22, approximately $4.55 million, will be deposited in the permanent fund account.

Legal price-gouging going on says state attorney

  Pumping gas into his pickup truck at an Anchorage gas station Oct. 28, Bristol Beaujean, 29, pays more for gas in Alaska than his friends in the Lower 48. Photo/Rob Stapleton/AJOC     Alaska legislators say they’ll consider gasoline price-regulation or other actions, including state investment in a refinery, if refiners in Alaska don’t lower gasoline prices. “We’re under tremendous pressure from our constituents to do something,” Rep. Jay Ramras, R-Fairbanks, said in a legislative hearing Oct. 23. Gasoline prices are dropping fast across the nation as crude oil prices fall, but they remain high in Alaska. Ramras chairs the House Judiciary Committee, which held hearings on the fuel price issue in Anchorage. At the hearing the state’s lead attorney in an investigation on fuel prices told legislators that gasoline prices in Anchorage were as much as 90 cents a gallon higher than Seattle this summer and fall. On Oct. 24 regular gasoline sold for $3.51 per gallon in some Anchorage retail stations. On the same day gasoline prices averaged $3.08 per gallon in Seattle and $2.92 per gallon nationwide. Prices were higher in small communities outside Anchorage. In Cordova, gasoline was selling for $4.93 per gallon. Residents of Kake, in Southeast Alaska, were paying $5.50 per gallon. Ed Sniffen, head of the Department of Law’s consumer protection division and lead investigator in the gasoline price inquiry, said he can find no explanation for the large price difference between Seattle and Alaska. “Spreads like that raises anti-trust red flags,” Sniffen told the Judiciary Committee. It is possible that there is no illegal market activity and that the extended lag in price reductions results simply from the structure of the market, Sniffen said. He called it a “duopoly,” or market domination by two suppliers. Two refineries supply gasoline in Alaska. Tesoro Corp. is the state’s main supplier, operating from its refinery near Kenai. Flint Hills Resources, a Koch Industries subsidiary, supplies gasoline to Interior Alaska markets from its refinery near Fairbanks. Two other small refineries operated by PetroStar Inc., an Alaska company, make only jet fuel and diesel. All of Alaska’s fuel requirements except in the Southeast panhandle region are supplied by Tesoro and Flint Hills. Southeast Alaska is supplied by refineries in the Pacific Northwest. Tesoro declined to appear before the committee, but Sniffen said he and other state investigators met with company officials in Anchorage on Oct. 22. Tesoro was cooperative in providing information, but Sniffen said he was unable to tell legislators what was discussed because of confidentiality agreements. Flint Hills’ Alaska public affairs manager Jeff Cook did appear before the committee but told legislators he couldn’t answer detailed questions because of the investigation. Cook said Flint Hills supplies only 15 percent of the state’s gasoline market and all of that is in Interior Alaska. He also said new federal and state environmental requirements on fuels have imposed costs on the company’s refinery, with an additional result that it is unable to produce as much gasoline as it did previously. Ramras asked Econ One Inc., a consulting firm working for the state Department of Law, to analyze the effects of several legislative options, including price controls. Other lawmakers aren’t enthused about controls. “Price controls can be very dangerous. The answer is to increase competition,” Rep. Bob Lynn, an Anchorage Republican, said in the meeting. Rep. Les Gara, an Anchorage Democrat, said he favors either price regulation or a major state investment in one of two refineries serving Alaska so state officials will have a way to influence markets. “If the state owns 51 percent of one of the refineries, we could decide to take a lower margin at certain times as a way of influencing behavior of the other refiner,” Gara has said. These ideas would obviously require a great deal more discussion, but Gara expects several legislators to introduce bills next spring. There may be an opportunity for state investment in the Flint Hills refinery. The company is studying options for the plant, including selling it, because of poor financial performance. One of the problems is a high premium charged by the state for state-owned royalty oil supplied to Flint Hills. Sniffen also told the legislative committee the state could act to induce new competition. When such a large price spread between regional markets exists, competitors typically rush new supply into that market to take advantage of higher prices. That isn’t happening in Alaska, Sniffen said, possibly because the gasoline market is small and the existing suppliers control storage and distribution. “There might not be enough of an incentive for an entrepreneur to get into the market,” Sniffen said. Barry Pulliam, an economist with Econ One, agreed with Sniffen. “In small markets the normal price discipline, the opportunity for competitors to bring product in from elsewhere, is often missing,” he said. “It’s a complex question but it’s often difficult to get people to do it.” Hawaii’s situation is similar to Alaska’s in that the state is remote and has two refineries, and the market is relatively small. The price spread for gasoline between Hawaii and the West Coast is almost as high as in Alaska, Pulliam said. California provided an example of what can happen when the opportunity to import competing supply is missing. When the state of California imposed standards for gasoline formulation for environmental reasons, the price differences between California and Texas, for example, at times reached 50 cents to 60 cents per gallon even though it only cost 8 to 12 cents per gallon to transport fuel from the U.S. Gulf Coast to California. Because California imposed the special fuel standards and it wasn’t made elsewhere, there was a supply restriction. Ramras said the state could invest in bulk fuel tanks at Anchorage’s port, which could then be leased to a competitor bringing gasoline to the state. Sniffen said Alaska’s toolbox to influence refiners is limited absent discovery of antitrust or illegal collusion, because the state doesn’t have a price-gouging law. Refiners are free to charge whatever they think the market will bear. “In theory, there is nothing preventing them from charging $10 per gallon,” he said. But price-gouging laws in other states, which could serve as a model for Alaska, are typically linked to a natural disaster, such as a hurricane, and not to high crude oil prices. In those cases the state or other government entity must declare an emergency, which gives it powers to impose penalties if a marketer hikes prices unusually high compared with price levels prior to the event that triggered the emergency. An alternative is for the Legislature to bring gasoline under state utility regulation that now covers telecommunications, electricity and natural gas sales, Sniffen said. “That would work. It’s a proven procedure,” he said. The pitfalls with this are in the extended time needed for regulatory proceedings, he said. Ramras said an option he wants to consider is to require refiners to maintain a certain spread between Anchorage and Seattle wholesale prices when crude oil prices exceed $100 per barrel, and to apply penalties if the spread exceeds those limits. Sniffen said Flint Hills and Tesoro face challenges with their refineries. Flint Hills operates a topping plant near Fairbanks that can only make certain products from crude oil. Most of the output is jet fuel sold to airlines flying into international airports in Anchorage and Fairbanks. Flint Hills is capable of making only limited quantities of gasoline and diesel. The refinery is also dependent on state-owned royalty oil delivered through the trans-Alaska oil pipeline, for which it pays a premium. Tesoro’s refinery near Kenai is designed to process light crude oil from Cook Inlet fields, but that supply is supplemented with crude oil from the North Slope and elsewhere. The refinery also has limited options for selling its residual oil, which amounts to about a third of production, and takes a loss on this, Sniffen told legislators. Ramras said he doesn’t want to “demonize” the refineries because he recognizes the problems they face. “Both of these plants are not models of efficiency,” he said. Sniffen cautioned legislators on price controls because of possible unexpected effects. “In the worst case, one of the two refineries could close, leaving you worse off. There could also be effects on supply reliability,” if the state moved aggressively to control margins. “Contracts for delivery to remote communities could be affected, for example.”

Despite energy turmoil, gas pipe work proceeds

  ConocoPhillips President Jim Bowles and BP’s Alaska President David Suttles discuss the Denali pipeline project at a briefing earlier this year. Work on both the Denali and the TransCanada pipeline projects are underway. File Photo/Rob Stapleton/AJOC     Two competing groups working on a $30 billion-plus Alaska natural gas pipeline planning aren’t fazed by current economic problems and plummeting energy prices, at least not yet. U.S. spot market prices for gas reached $6 per thousand cubic feet on Oct. 27. That’s less than half what they were in recent weeks. Major energy projects that will span decades aren’t influenced by short-term market prices, but there are critical times when attitudes and perceptions in financial markets can have an impact. For the Alaska pipeline that could come in 2010, when both TransCanada Corp. and the Denali pipeline group, owned by BP and ConocoPhillips, plan open seasons to solicit customers. Gas shippers, either producers or downstream buyers of gas, will be asked to sign take-or-pay shipping commitments worth in excess of $100 billion. If economic conditions are still sour, executives of even these major companies may blink before signing the checks. That could delay the project or kill it - again. The U.S. gas price volatility reminds many in Alaska of what happened to the last proposed gas pipeline project, called the Alaska Natural Gas Transportation System, which was moving at full steam in the early 1980s until the North American gas market dropped out from under it. Memories of that are still fresh at TransCanada because Foothills Pipe Lines, now a part of TransCanada, was part of the ANGTS consortium that spent about $1 billion in environmental, engineering and permitting work before the plug was pulled on the project. Denali and TransCanada will have spent almost $750 million by the time the companies have their open seasons in 2010. For now, however, it’s full steam ahead for both projects. TransCanada Corp. and the competing Denali pipeline group, which is owned by two North Slope producers, are moving ahead with engineering and cost studies, and both still plan open seasons in 2010 to solicit customers for their projects. TransCanada has yet to formally receive its state license under the Alaska Gasline Inducement Act, but the company is doing work even though it won’t be partly reimbursed by the state under the AGIA license, company Vice President Tony Palmer said. The license is awarded 90 days after its signing by Gov. Sarah Palin, which will put the date at about Nov. 25, Palmer said. Meanwhile, the Denali pipeline company is analyzing data gathered during field work this summer and is doing a limited field program this winter to gather geotechnical data by drilling, company spokesman Dave MacDowell said. The geotechnical program means Denali will now be keeping its Tok field office open year-round. A major summer program is planned for 2009. Palmer said TransCanada has completed aerial photography along the pipeline route from the North Slope to the Canada border and from Delta to Valdez. The company is also doing aerial surveys of the pipeline route through Canada, he said. “We have mobilized our project team and plan to solicit comments on a proposed engineering planning contract for the gas treatment plant soon, which will be followed by a formal request for proposals later this year,” Palmer said. The gas plant, to be in Prudhoe Bay, is a major project on its own, and is expected to cost about $2 billion. The plant will condition the raw gas that is produced for the pipeline, mainly by removing carbon dioxide, water and impurities. An engineering planning contract for the pipeline itself will be let early next year. “The pipeline is much more straightforward for us,” Palmer said, because of TransCanada’s experience in pipeline building. The pipeline company is also close to making an announcement of where it will locate its Alaska office, Palmer said. It will be either in Anchorage or Fairbanks. Palmer couldn’t say how big the office will be or how many people it will support. MacDowell said Denali’s staff is still supported by two temporary offices in Anchorage, but that the company will be announcing the location of a larger, centralized office soon. Denali is also beginning work on studies of infrastructure needed to support pipeline construction, in-state gas needs and workforce development, MacDowell said. As for the current clouded economic outlook, Palmer said TransCanada doesn’t think a recession would affect his project if the economy downturn is relatively short, say a year or a two. “There could even be a window of opportunity,” he said, if it cools recently overheated oil equipment and materials markets and creates a more level headed environment in which to conduct cost estimates. Still, any lock-in on prices won’t occur for years until after a project has been sanctioned by the company and U.S. and Canadian agencies, Palmer said. But if the slowdown lasts several years, Palmer acknowledged it could affect TransCanada’s hopes to nail down customers for capacity for its project. Meanwhile, TransCanada’s competitor, the Denali gas consortium owned by BP and ConocoPhillips, says it is too busy with preliminary engineering and cost estimates and to worry about a recession. “We’re focusing on the things we can control, like the work necessary to conduct an open season in 2010,” MacDowell said. “That remains our objective and we can’t be distracted by volatile market conditions playing out at present.” TransCanada hopes to begin its open season in March 2010 and to conclude it by July 2010, Palmer said. Denali will have its open season later that same year, according to its president, Bud Fackrell. The Denali group is budgeting its preparations for the open season at $600 million, of which $40 million has been already spent on the 2008 summer program. TransCanada has estimated its work to prepare for the open season at about $184 million. Half of that will be reimbursed by the state under the AGIA license agreement. There is no question that ultimately only one pipeline will be built, and that a consortium of pipeline companies and producers will build it. The disagreement is over who will control the project, the producers or TransCanada. Most Alaskans believe Denali has a leg up over TransCanada because BP and ConocoPhillips have gas reserves on the Slope that total about half what is needed for the project, and which the two companies would presumably ship through a pipeline they own. However, a third major owner of North Slope gas reserves, ExxonMobil Corp., has yet to decide how it will market its gas. Another major gas owner, Chevron Corp., also has made no decision. TransCanada owns no gas but it has been in the gas pipeline business a long time and hopes to convince the gas owners, or potential downstream purchasers of gas, to purchase capacity in its system. The pipeline company says it can build a pipeline for less than the producers’ group would spend. The state of Alaska is pushing for TransCanada, believing that a pipeline controlled by an independent company would prevent a gas monopoly on the North Slope, since the producers already own most of the producing fields and existing infrastructure. TransCanada hopes the state’s support will ultimately give it an advantage in attracting gas shipping commitments from the producing companies. AGIA carries with it the state’s promise to make an agreement on tax terms for any producers that commit gas to TransCanada. Alaska state officials, such as Revenue Commissioner Pat Galvin, have said that if the producers want a deal with the state on taxes the way to it is through TransCanada. The producers argue that the deal TransCanada struck, an agreement under the state’s Alaska Gasline Inducement Act to abide by special pipeline terms, may ultimately become an albatross for the pipeline company. BP and ConocoPhillips say they can’t accept some of the terms under AGIA, and that this will prevent TransCanada from being brought into the Denali consortium or prevent the producers from joining TransCanada. To resolve this, the state Legislature may have to soften AGIA’s terms and also make a tax deal available for gas to any pipeline, not just TransCanada’s.

Pebble mine construction now estimated at $6 billion

  Pebble Partnership CEO John Shively and spokesman Sean McGee. Photos/Tim Bradner, Margaret Bauman/AJOC     Construction costs for the proposed Pebble mine have topped $6 billion, the president of the company that would develop the project told the Alaska Support Industry Alliance Oct. 9. Costs have been pushed up by inflation that is affecting all major industrial projects, as well as the increasing complexity of the project. It is $1 billion higher than was estimated last year and about three times the initial estimate made when mining companies began serious work on Pebble. Pebble is a copper-gold-molybdenum deposit located about 18 miles north of Illiama. If a mine were developed, it would be one of the largest of its kind in the world. John Shively, CEO of the Pebble Partnership, the mine development company, told the Alliance that the project also requires a 95-mile road to a new port that would be built on the west side of Cook Inlet. The mine would also need a pipeline to carry a slurry, a mixture of ore and water, from the mine to the port and a second pipeline to return recycled water from the slurry back to the mine for re-use. A small pipeline may also be needed to ship diesel fuel for mine equipment, he said. The Pebble Partnership, formed to develop the mine, is owned 50 percent by major mining company Anglo American Mines and mine developer Northern Dynasty Minerals. Mining company Rio Tinto owns some 20 percent of Northern Dynasty Minerals. Shively told the Alliance that the electricity requirements for the mine have now been estimated at 600 megawatts to 700 megawatts, an amount of power that would provide enough new baseload demand to build substantial new generation capacity for the state’s railbelt power grid. Shively said power for the project may be generated elsewhere, most likely on the east side of Cook Inlet, and sent to the mine through long-distance transmission lines, including a submarine cable crossing the inlet. The amount of power required could provide enough new baseload electricity demand to justify substantial generation capacity additions in the main railbelt power grid and benefit the entire system, he said. “This could help justify a bullet line to bring gas from the North Slope, or a major geothermal project,” such as one being discussed near Mount Spurr, west of Anchorage, Shively said. However, until that happens the company is also considering short-term options, including gas-fired power generation using imported liquefied natural gas, he said. Substantial work is continuing at Pebble this year, with a goal for the company to file permit applications with government agencies in late 2009 or early 2010. About $140 million is being spent this year on drilling, engineering and environmental work, Shively said. The project employed 200 to 240 people at periods of peak activity this year. Many of the workers were hired from communities near the project or in the Bristol Bay region. I   (Right) Workers ready pipe to collect drill samples at the Pebble mine in this file photo. Shively said construction costs to ready the Pebble mine for production will be $6 billion. Photos/Tim Bradner, Margaret Bauman/AJOC     n another development, a third and deeper ore body has been discovered at Pebble, but it will not be tested further, at least for now, because the project already has sufficient ore. “Our constraint is not resources,” Shively said. The challenge is how and where to store waste rock after minerals are extracted from the existing ore reserves. “The tailings containment facilities will be the constraint in how much we can mine,” he said. Some 99 percent of what is mined will remain, with only about 1 percent extracted as metals. Although large quantities of ore have been identified, it is still not known if a mine at Pebble can pass muster with state and federal permitting agencies and be economically developed, Shively said. The new ore body is about 7,000-foot deep into the ground. It was found through one of the deep test holes drilled into Pebble East, one of the two previously known ore bodies that is itself at the 1,500-foot depth. Further testing of the deep ore will be difficult with the mobile, lightweight drill rigs now being used for test drilling at Pebble, Shively said. However, it appears to be of a higher grade similar to that of Pebble East. Pebble West, the other deposit that was initially explored, is a shallow, low-grade deposit that is located virtually at the surface. The initial plan was to develop Pebble as an open-pit mine when only Pebble West was known, but when the deeper, richer Pebble East was discovered, the plan changed to envision an underground mine combined with a surface mine. Shively said there is enough ore at Pebble to conduct mining for 50 to 80 years. At Pebble West, 569 million tons of ore have been identified in the “measured and indicated” category, a measurement of resources determined by closely spaced drill holes to demonstrate continuity of mineralization in the ore body, and another 143 million tons in the “inferred” category, an estimate based on more widely spaced test holes. The quality of the ore was 7 percent copper-gold equivalent in both estimates. Copper-gold equivalent is a way of combing the values of all metals in the mine into one measurement. In Pebble East about 1.52 million tons or ore have been identified as “inferred resources” as of February 2008. Results of the 2008 drilling had not yet been included in the figures.

Doyon Ltd. has stakes in most of Alaska's key industries

  This 2008 photo shows the Doyon Ltd. sign, with the corporation’s headquarters building in the background. Doyon is the Alaska Native regional corporation for Interior Alaska. The organization has business stakes in several of the state’s key industries. Photo/Melissa Campbell/AJOC     From oil drilling to catering, security, utilities, engineering services, minerals, oil and gas, utilities, tourism and more, Fairbanks-based Doyon Ltd. has a stake in them all. Doyon is the Alaska Native regional corporation for Interior Alaska and is widely diversified, like many of the Native corporations formed by the 1971 Alaska Native Claims Settlement Act. Doyon seems in a class by itself, however. In sheer geography, it is the largest of the Native corporations, stretching across a vast area of Alaska’s Interior from the Canadian border in the east almost to Norton Sound in the west, and from the continental divides of the Brooks Range in the north to the Alaska Range in the south. It has the biggest landholding of any of the Native corporations, at 12.5 million acres. This also makes Doyon one of the largest private landowners in North America. The corporation is also solidly profitable. Both net and gross revenues are headed in the right direction - up. Phillips said he expects that profits and revenues will be up for the corporation’s most recent financial year when the final review of results is completed. Because of its land ownership, Doyon has a huge stake in natural resources and, consequently, resource-based industries. Doyon Drilling Inc., for example, is one of the state’s leading oil drilling companies, operating eight highly sophisticated drill rigs on Alaska’s North Slope. A ninth rig, designed to drill shallow heavy oil wells, will be added to Doyon Drilling’s rig fleet next year. Doyon is one of the state’s major employers. Its companies employ about 3,000 people with 90 percent of these in Alaska. The corporation has a number of new initiatives underway this year. One of the most significant is the startup of Doyon Utilities, a joint venture formed with local utility Fairbanks Water and Sewer to operate power plants and utilities on three U.S. Army installations in the state; at Fort Wainwright, Fort Richardson and Fort Greely. “This is a 50-year contract with total revenues of $4 billion over its life, but it will wind up saving the military $800 million,” Phillips said. Much of the savings will be in new efficiencies in the plants due to investments in upgrades the partners will make. About $70 million is being invested in modernization this year, in the first life of the contract, Phillips said. Doyon Universal Services LLC was awarded an extension of its contract with Alyeska Pipeline Service Co. to provide facility management, security and catering services. The company is also providing support this year for the Denali pipeline group, the natural gas pipeline initiative by BP and ConocoPhillips. This is a long-standing joint venture between the regional corporation and Universal Services. The joint venture is now doing business outside Alaska, including at a Tesoro Petroleum refinery in Washington state. The joint venture hopes to use its oil and gas industry experience to pick up new business in the oil-producing states of Colorado and Wyoming. Doyon Government Group, an 8(a) contracting company formed in 2003, has picked up support contracts on military bases in Washington state and Hawaii, and hopes to be working soon on similar contracts for other federal agencies. Many Native corporations have subsidiaries recognized as minority-owned contractors under section 8(a) of the federal small business assistance programs. Two of Doyon’s technical services ventures, DoyonEmerald and Doyon Industrial Group, a joint venture with Associated Pipelines of Houston, are also working for the Denali pipeline group. The work included geotechnical surveys on the pipeline route through the eastern Interior. “We expect to be working with TransCanada next year too,” Phillips said. Despite that fact that Denali and TransCanada are competitors in pursuing gas pipeline projects, “there would not be a conflict, but we would obviously build a ’fire-wall’ between the groups working on the projects.” Similar surveys may be done on the northern part of the pipeline route next summer, and possibly in Canada as well. Doyon Industrial Group is also working in the producing oil fields on the North Slope on pipeline maintenance work. Doyon also has Doyon Tourism Inc., which operates lodges in the Denali National Park area, and is also in Doyon-Aramark, a joint venture operating tour buses in the national park. It is in development of its lands, however, that Doyon sees its future. “We see some real opportunities related to natural resources to create sustainable development for our villages, in terms of jobs, infrastructure and local tax base,” Phillips said. Doyon has been engaged for several years in a long-term exploration program in the Nenana Basin west of Fairbanks, where there is potential for both oil and gas. The same is true for the Yukon Flats basin further north, where Doyon owns substantial lands and hopes to fill out its holdings with acreage acquired in a land-exchange with the U.S. Fish and Wildlife Service. There are several initiatives related to minerals, too. The most promising is in the Fortymile area of the eastern Interior, where Full Metals Minerals, a minerals exploration company, is exploring zinc, silver and lead prospects with showings of high-grade ore on Doyon-owned lands. Full Metals had a drilling program this year to acquire 50,000 feet of core sample and will substantially expand the drilling program next year. The mining company has signed an agreement with Doyon giving it rights to explore on 88,675 acres of Doyon-owned lands. “We’re very pleased that Full Metals is hiring locally and within the state, and is even taking people for training down to their ’drill school’ in Vancouver, B.C.,” said Jim Mery. Phillips said people have been hired from communities like Northway and Tok that are near the project area, but also from as far away as the Yukon-Kuskokwim. Mery said it’s too early to know if a mine could be developed or if it would be a surface or underground mine, or both. “It’s just not one prospect, either. There is a 30-mile district of mineralization with several prospects. There are both state and Doyon lands but the project is being initiated on Doyon lands. We see this as a long-term, multi-generational opportunity,” Mery said. Full Metals is also working with BHP Billiton, a major mining company, on copper-gold prospects on areas south of the prospect on Doyon lands. Doyon has lands in the area but is not part of that project. The corporation is also working with FreeGold Ventures on gold prospects south of McGrath. One prospect there, Vinasale, is an established gold discovery where about 1 million ounces of gold resources have been found. “It is low-grade. We need to find some high-grade” resource to allow a mine to get started, Mery said.

Oil industry leaders offer update on Sakhalin work

YUZHNO-SAKHALINSK, Russia - A major Sakhalin oil and gas project being led by ExxonMobil Corp. has achieved its first major goal - recovery of initial capital costs - and is now gearing up for a significant expansion. Recovery of capital costs is a key milestone in Sakhalin I’s project agreement with the Russian government because it triggers and expansion of revenues paid to the federal government and the local Sakhalin Oblast regional government, James Taylor, president of ExxonMobil’s Russian subsidiary, said during an oil and gas conference in Sakhalin Oct. 3 and 4. Sakhalin I has been producing oil and gas since October 2005, with oil being shipped to export markets from an oil terminal on the Tartar Strait, which separates Sakhalin Island from Russia’s mainland. Natural gas also produced is sold to communities on the Russian mainland, Taylor told the 12th Sakhalin Oil and Gas Conference. Meanwhile, construction is essentially complete on Sakhalin II, a second major project on Sakhalin being led by Shell Oil and Gazprom, Russia’s state-owned gas company. The project is set to begin year-round oil exports later this year and exports of liquefied natural gas, or LNG, in early 2009, said Ian Craig, president of Sakhalin Energy Investment Co. Sakhalin Energy is the company managing the Sakhalin II project. The LNG plant was built at Prigorodnoye, the port city on Sakhalin’s southern coast. It is one of the world’s largest LNG projects. Sakhalin is emerging as one of the world’s major new oil and gas producing areas. ExxonMobil and Shell, with their Russian, Japanese and Indian partners, have established the initial infrastructure and now other discoveries are being made, mainly by Russian-owned state companies. One of these, Roseneft, announced another major gas and condensate discovery at the Sakhalin conference Oct. 3. Craig said Sakhalin Energy would begin filling a newly completed 800-kilometer oil pipeline later this month from the offshore Molipaq platform, one of three platforms in the project. Molipaq, which was brought to Sakhalin from the Alaska Beaufort Sea, has been producing oil and loading directly to tankers during ice-free months since 1999. “Oil from the Molipaq platform will be introduced into the northern section of the (onshore) pipeline system later this month,” Craig told the Sakhalin conference. “At this point the offshore export of oil will cease.” It will take several weeks for oil from Molipaq and Piltun-Astokhskoye-B, a second platform nearing completion, to fill the newly completed Trans-Sakhalin oil pipeline, he said. Delivery of gas to a gas pipeline from the two platforms, as well as LUN-A, a third platform, is also on schedule, Craig said. Two pipelines, one for gas and the second for oil, were built alongside each other from the producing fields, in the northern part of the island, to the LNG plant and export terminals in the south. The target is for the first LNG deliveries to be made in early 2009. As for the pipelines, Craig told the conference that pipeline crossings of 19 areas of high seismic activity have been completed, and remaining pipeline commissioning is underway. Each of the crossings had to be tailored to conditions at the sites. In the seismic crossings, the pipelines were provided with elbows to minimize stresses and add strength, and were surrounded by light, crushable material in the trenches to facilitate movement in an earthquake. Craig also said SEIC has made good progress on restoration of the pipeline right-of-way under an environmental action plan agreed on with Russian governmental agencies. “The reinstatement work will be substantially completed before the onset of winter, but we do expect some follow up work in 2009 and beyond as it takes some time for rehabilitation measures to become fully established,” Craig said. Meanwhile, drilling of new production wells is underway on both the Piltun-Astokhskoye-B and LUN-A. Wells for injection of drilling mud and cuttings back into underground reservoirs have been completed on both platforms and the drilling of the first oil production well is now underway on the Piltun-Astokhskoye-B platform, Craig told the conference. On the LUNA-A platform, two gas production wells have been substantially completed, but gas production will not begin until the platform and onshore processing facility is ready to accept the gas, which is expected to be in November, Craig said. Two more gas wells will be drilled at the LUN-A platform and the combined production from four wells on the platform should be sufficient for starting up production of liquefied natural gas in early 2009, he said. Craig also said condensates from the gas will be separated and mixed with crude oil. “The gas condensate will eventually become a significant proportion of our liquids production,” eventually reaching about a third of the liquids volume, he said. Sakhalin Energy is now in the final phase of commissioning the second LNG production unit. The first train, or unit, was commissioned last May with liquefied gas imported from other areas, including the Alaska LNG plant near Kenai. On the Sakhalin I project, Taylor told the conference that ExxonMobil plans to begin drilling in the Odoptu field in 2009 and will have construction underway this winter on a 50-mile pipeline from Odoptu to Chayvo, the Sakhalin I field currently producing. Odoptu is the second of three fields in the Sakhalin I project and is about 80 miles north of Chayvo, the first field to be developed. An oil field construction subsidiary of CH2M-Hill is managing pipeline construction in a joint venture with Russian partners, and CH2M-Hill’s Anchorage office is in charge of the pipeline. A number of Alaskans are working on the project. Pipeline construction is expected to be completed by March and the system should be tested in late spring. Taylor said ExxonMobil is also now moving the large Yastrub drill rig from the Chayvo field to Odoptu. Yastrub is a specialized rig, one of the world’s largest, built for the long extended-reach wells needed in both Chayvo and Odoptu. Constructed and operated by Parker Drilling Co., Yastrub weighs 5,000 tons. The rig has been broken down into truck-sized units and is being moved in 340 trips by truck over local roads to the Odoptu field. Although Odoptu is an offshore field, there will be no offshore platform, unlike at Chayvo. All of Odoptu’s production wells will be drilled from shore through extended-reach drilling. At the Chayvo field, some production wells were drilled from shore and from a single offshore platform, the Orlan. A third Sakhalin I field scheduled for development, Arkutun-Dagi, is in deeper water and will require a platform and pipeline to shore. Arkutun-Dagi construction is tentatively planned for 2010 and 2011. Taylor told the conference that Arkutun-Dagi and Odoptu will help offset the decline in oil production from Chayvo, which is now producing about 190,000 barrels per day, down from its peak of 250,000 barrels per day in 2007. The fields will also make more gas available for either exports or domestic sales. Taylor said that, to date, the Russian federal government has received $1.1 billion in taxes and shared production value, but Russia will receive about $50 billion in total over the life of the project. Sakhalin Oblast has received about $200 million in shared revenues with an additional $100 million paid to the Sakhalin Oblast Development Fund, Taylor said. Another $60 million will be paid in to the Sakhalin Oblast as additional phases of the Sakhalin I project start up, he told the conference. Since the start of the Chayvo field the Sakhalin I project has produced and exported 157 million barrels of crude oil through the De-Kastri export terminal on the Tartar Strait, Taylor said. There have been 200 tanker sailings and never a missed shipment because of weather of ice conditions, he said. Also, about 105 billion cubic feet of gas from the Chayvo field has been produced and sold to customers in Khabarovsk Krai, on the Russian mainland. The company’s customers there include a metallurgical factory, an aircraft plant, utilities serving several communities and several medium and small-sized businesses, he said. ExxonMobil’s Russian subsidiary, Neftegas Ltd., is the operator of the Sakhalin I project. Partners include Sakhalin Oil and Gas Development Ltd., a Japanese consortium; two affiliates of the Russian state-owned Rosneft, RN-Astra and Sakhalinmoreneftegas-Shelf; and ONGC Videsh Ltd., owned by the Indian state. Reserves at Sakhalin I are estimated at 2.3 billion barrels of oil and 17.1 trillion cubic feet of natural gas.

Loss of partner, political obstacles prompted BG bid drop

BG Group told Alaska legislators Feb. 2 that it had planned to submit a bid for an Alaska liquefied natural gas project in the state of Alaska’s recent solicitation for gas project proposals, but pulled back out of concerns for political risks and when a pipeline company partner pulled out of a proposed joint venture at the last minute. In a related development, former Alaska governor and U.S. Interior Secretary Walter Hickel told the state Senate Resources Committee the state should hold a second round of solicitations for proposals under its Alaska Gasoline Inducement Act and that results of the first round should be scrapped. In a prepared statement read by a spokesman, Hickel said a pipeline and LNG plant could become a “common carrier” for Arctic resources delivered to several nations. David Keane, vice president of BG North America, also told the resources committee Feb. 2 that political risks weighed heavily in BG’s decision to forego submitting a bid, mainly opposition voiced by Alaska’s congressional delegation to North Slope gas being exported. BG is a major U.K.-based energy company with extensive experience in liquefied natural gas trading. The company is now exploring for gas on the North Slope in partnership with Anadarko Petroleum Corp. The state received five proposals Nov. 30 under its solicitation but on Jan. 4 said only one met the terms of the request for applications, a proposal by TransCanada Corp. for an all-land pipeline from the North Slope to Alberta. Hickel is a strong supporter of an LNG project. Keane said BG believes the highest-value market for Alaska gas is Asia rather than the continental U.S. LNG sales will return better value for North Slope gas because gas is priced in parity with crude oil in Asia but against other gas in continental U.S. markets, Keane told legislators. “Asia-Pacific is the natural market for North Slope gas,” Keane said. BG also believes there are not enough proven gas reserves on the North Slope to support a large all-land pipeline that would deliver 4.5 billion cubic feet per day. TransCanada has proposed a large pipeline project, as has ConocoPhillips in a separate proposal. BG believes there are enough proven reserves, however, to support a smaller 2.7 billion cubic feet per day project, which is enough to support an LNG project. BG’s plan was to build the project in two phases, a pipeline to southern Alaska to an LNG project in the first phase, and a second phase pipeline branching off from the first to deliver gas through Canada to the continental U.S. when more gas reserves are discovered. BG’s plan was to build the pipeline oversized, with a 48-inch diameter, from the North Slope to Delta Junction in Interior Alaska, Keane said. This would have extra capacity for eventual shipments through a pipeline to Canada. The pipeline from Delta south to the LNG plant in Valdez would be 42 inches in diameter, he said. BG’s plans had called for a three-train LNG plant in Valdez. The pipeline part of the project was estimated to cost $13.5 billion in 2007 dollars. The entire project, including the LNG plant, was pegged at $22 billion, Keane said. The company was concerned with potential delays and the effect those would have on construction costs and tariffs for transporting gas, Keane said. The gas reserve uncertainties are widely acknowledged. The 35 trillion cubic feet of proven reserves on the Slope are enough to supply a large continental U.S. pipeline like that proposed by TransCanada or ConocoPhillips for 18 to 20 years, but another 15 tcf of gas will have to be found to supply long-term needs for the pipeline. North Slope producers as well as TransCanada are confident additional gas will be found, however, because much of the North Slope is gas prone and most potential gas prospects are unexplored. On political objections to an LNG project, Keane said there were political risks with Alaska gas being transported through Canada, “which may or may not ultimately go to the U.S.,” Keane said. In previous presentations in Alaska, BG has said LNG exports to Asia could be balanced by imports of LNG to the U.S. from Atlantic Basin LNG projects. BG has substantial experience in LNG trading and could handle such swaps, Keane said. In addition to concerns over political opposition to LNG exports from Congress, Keane said BG was worried because the pipeline portion of its LNG project could fall under the Regulatory Commission of Alaska jurisdiction rather than the Federal Energy Regulatory Commission. BG worries that state regulators might tilt decisions in the state’s interest, which is for low tariffs, at the expense of a pipeline company.

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