Tim Bradner

YEAR IN REVIEW: New production by ConocoPhillips highlights ‘15

ConocoPhilliips had a busy 2015 on the North Slope, completing two new oil projects and planning two others, despite the plunge in crude oil prices. Late in the year the company’s CD-5 project, near the Alpine field on the western Slope, was completed and began production. Earlier in the fall ConocoPhillips completed its Drill Site 2-S in the Kuparuk River field, and it is also now producing. Other projects are in development or are now planned. One being constructed now is an expansion of the West Sak viscous oil project in the Kuparuk field, a project labeled North East West Sak, or NEWS. ConocoPhillips has produced viscous, sometimes called heavy, oil from the West Sak deposit for years, but technical and cost problems have plagued plans to expand the project. On NEWS, the company’s latest plan, new technologies are being employed that will solve some of the earlier problems. A second new project now underway is the $900 million Greater Moose’s Tooth 1 project in the National Petroleum Reserve-Alaska. ConocoPhillips announced this Nov. 18 at the annual Resource Development Council conference in Anchorage, lifting spirits among oil contractors and suppliers in the audience. GMT-1 is a few miles west of CD-5, a drillsite also within NPR-A but near the Colville River boundary with state lands. GMT-1 is expected to peak at 30,000 barrels per day and is to be in production in 2018. Anadarko Petroleum is a minority partner in the project, as it is with CD-5. Mineral rights at GMT-1 are owned jointly by Arctic Slope Regional Corp. and the U.S. Bureau of Land Management, the Interior Department agency that manages the NRA-A. ConocoPhillips and Anadarko are now working on GMT-2, a drill site a few miles furthern into NPR-A. 2. Caelus advances Nuna project Caelus Energy, the Dallas-based independent that now owns and operates the producing offshore Oooguruk field, continued in 2015 with its planning and development of Nuna, a new onshore oil production pad near Oooguruk. A large gravel production pad and access road were constructed for Nuna in early 2015 and engineering work on production facilities continued through the year. Caelus is obligated to have Nuna on production in late 2017 as a condition of an agreement for a temporary reduction of state royalty. The company now plans to construct facilities in the winter of 2016-17 and believes it can meet the deadline for production. Nuna is expected to cost about $1.2 billion to construct and will produce 20,000 to 25,000 barrels per day when operations begin. Caelus also plans additional development work at the Oooguruk field including the treatment of producing wells with large-volume fracturing, a technique aimed at stimulating production in tight rock by injecting fluids and sand at high pressures. Use of large-volume fracturing was very successful on Oooguruk wells last winter, the company has said. In another development for Caelus in 2015 plans were made and equipment was moved, for a strategic offshore exploration well in Smith Bay, northwest of the Colville River delta. The well will be drilled on state-owned submerged lands north of the National Petroleum Reserve-Alaska. The Doyon Drilling “Arctic Fox” rig and other equipment for drilling was moved in the fall to an onshore staging point in NPR-A. As soon as the weather is cold enough construction of an ice island will begin at the well site, which is in shallow water. Two wells are planned to test the prospect. 3. Point Thomson nears production ExxonMobil Corp. continued construction in 2015 on its Point Thomson natural gas condensate project 60 miles east of Prudhoe Bay. The project, with costs at or exceeding $4 billion, is near completion and will begin production of liquid condensates in early 2016. The construction project has been the biggest for the North Slope over the last two years, stimulating employment and business for contractors and suppliers, many of them Alaska based. Although it will initially be a liquids production project, Point Thomson is really intended to produce gas for the large Alaska LNG Project, which is now in the planning and preliminary engineering phase. Production facilities at Point Thomson will initially produce gas with liquid condensates stripped out of the gas, which will then be injected back underground into the producing reservoir. The gas would be “recycled” through the reservoir, being produced and injected repeatedly. As the injected gas, now “lean” after removal of liquids, moves through the underground reservoir rock from injection wells to producing wells, the gas soaks up more liquids, which are stripped off as the gas is produced again. The process will be repeated over and over again. The condensates, at a 10,000 barrels-per-day production rate, will be shipped by pipeline to Prudhoe Bay and Pump Station 1 of the Trans Alaska Pipeline System, where they will be blended with the crude oil being shipped through TAPS. If the Alaska LNG Project is built the production facilities at Point Thompson will be converted to conventional gas production, although facility additions will be needed. Alternatively, if the project does not proceed, the production of liquid condenates can be expanded, possibly to about 30,000 barrels per day. Another option is to convert Point Thomson to gas production and ship the gas to Prudhoe Bay where it can be used to repressure the Prudhoe field and produce more oil. 4. Hilcorp files plan for Liberty offshore Hilcorp Energy filed a development plan for Liberty in late 2015. Liberty is an offshore oil deposit in shallow Beaufort Sea waters northwest of Prudhoe Bay that has long been planned for development by BP but had been shelved for various reasons. If it is developed, Liberty would require construction of an artificial gravel island and a subsea pipeline to shore. Liberty’s oil reserves are estimated at 80 million to 150 million barrels. If developed, the field could produce about 60,000 barrels per day, Hilcorp said in its application. Offshore artificial island construction is a long-established practice for the Beaufort Sea “nearshore,” where waters are very shallow. Three fields are now producing from offshore gravel islands, the Oooguruk field owned by Caelus Energy, the Nikaitchchuk field owned by Eni Oil and Gas, and Northstar, developed by BP and now owned by Hilcorp. Hilcorp purchased a 50 percent interest in Liberty and became the operator of the project when the Texas-based independent acquired four older North Slope fields, including Northstar, from BP in late 2014. Because Liberty is in federally-owned waters five miles offshore, and beyond the state’s three-mile territorial limit, the development plan was filed with the U.S. Bureau of Ocean Energy Management, or BOEM, an agency of the U.S. Interior Department. If it is developed Liberty would be a virtual twin to North Star, an offshore field developed by BP in 2001 and that is now in production. Northstar is northwest of Liberty and roughly north of the Prudhoe Bay field, and six miles offshore. BP considered developing Liberty with a gravel production island some years ago but backed away from the plan after reviewing the company’s experience at Northstar, where there were cost increases and complex issues with regulatory agencies. The company then considered tapping into Liberty’s underground oil reservoir with long-distance, high-angle production wells drilled from shore. Some of the wells would have reached as far as eight miles drilled laterally, and would have been the longest such wells in the world. But this plan was scrapped too. When Hilcorp took over the gravel island plan was resurrected. Although the distances from shore are similar one key difference between Liberty and Northstar is that Liberty is within the belt of barrier islands offshore the North Slope, which will protect the island from the moving Arctic icepack. Northstar, in contrast, faces the open sea and is not protected by barrier islands, so that the island must contend with ice forces causes by the moving pack in winter and summer storms. BP built Northstar strong enough to endure those forces and there have been no problems. Liberty, however, is in a much more benign ice environment, being surrounded in winter by “shore-fast” ice that does not move, in contrast to the polar pack farther offshore. 5. Furie completes first new Inlet platform in 30 years Furie Operating Alaska became the first company to install a new offshore Cook Inlet production platform since the 1980s. Furie began producing gas late in the fall from its Kitchen Lights No. 3 gas well to the production platform and to pipelines to the east side of Cook Inlet. Homer Electric Association, the Kenai Peninsula’s electric utility, is now purchasing gas from Furie. Other production wells will be drilled as its markets expand, Furie says. Development of the Kitchen Lights gas prospect has been a long process for Furie, a Texas-based independent that was formerly Escopta Oil and Gas. Escopeta, under its former president, Danny Davis, identified the gas prospect at Kitchen Lights and worked over several years to bring a jack-up rig to Cook Inlet to drill exploration wells.

Banks warn of impacts for breaking Anchorage LIO lease

Editor's note: This story has been modified from the first version posted online to reflect the owner of the Anchorage office as 716 West Fourth Avenue LLC, of which developer Mark Pfeffer is a member, and to include the correct number of appraisals on the building which was four and not three as originally written. The Alaska Legislature’s 10-year lease on its 64,000-square-foot office building in Anchorage has become a political football, possibly a preview of fireworks to come in the 2016 legislative session. Some legislators are pushing for the state to break its lease on the new building, which was signed with 716 West Fourth Avenue LLC, an Anchorage-based company whose members include developer Mark Pfeffer and longtime building owner Bob Acree. The Legislative Information Office, or LIO, is on 4th Avenue in downtown Anchorage, and includes adjacent parking for the building. “We’re leasing a Cadillac at a time when all we can afford is a Chevrolet,” said Sen. Gary Stevens, R-Kodiak, the current chair of the Legislative Council. The Legislative Council, a House-Senate committee that manages the Legislature’s affairs when not in regular session, will meet and possibly decide the issue Dec. 19. One option being considered is purchasing the building outright from 716 West Fourth Avenue LLC. Pfeffer said he is willing to sell the building for less than $38 million, which includes financing costs for issuing bonds to pay off the existing debt, and making the building owners whole on their investment. Pfeffer briefed the Journal on the project Dec. 14. One concern that has surfaced is the effect of a cancellation on the state’s reputation in the financial community, particularly at a time when national credit rating agencies are watching Alaska closely. Pfeffer also said Dec. 14 that he would pursue legal recourse against the state should the Legislature break the lease. The cost of the project was $44.5 million, including $2.89 million spent to purchase an older building formerly home to Anchor Pub adjacent to the legislative building. The cash equity held by Pfeffer in the building is $9 million. The final tab also included the cost of improvements needed by the Legislature. The lease was signed in September 2013. Critics now argue the $3.3 million annual rental cost is too high, given the state’s current financial condition, and that cheaper space is available. The alternative space the critics, including Stevens, point to is the state-owned Atwood Building on 7th Avenue, which is used by state agencies and the governor. Stevens said there is space in the Atwood Building for legislative offices and that state agencies would not be displaced. However, the state’s financial community is worried over the effect a lease cancellation would have on the state’s overall financial credibility, which is already under stress because of the sharp decline in oil revenues. “We alert you that this action will likely impact the state’s credit worthiness and the cost of borrowing in the future,” wrote Steve Lundgren, president of the Alaska Bankers Association, in a sharply worded letter sent April 8 to budget conference co-chairs Sen. Pete Kelly, R-Fairbanks, and Rep. Mark Neuman, R-Big Lake, when the breaking of the lease was first raised. “Doubts about the state’s willingness to service its obligations will reverberate, and cause lenders and investors to begin a focused reassessment of notes and securities where the source of payment is the state.” The state Senate had voted to not make the payment on the lease, in effect breaking it, in its version of the operating budget. The House budget included the rent payment. The bankers association was strongly opposed, enough a meeting was held on Easter Sunday to vote and draft the letter. The payment was ultimately approved in the final state budget. Lundgren expanded on his comments in an interview with the Journal on Dec. 15. “Our association’s comments do not speak to the issue of the building or the lease but mainly to the statewide impact that could occur on all state leases,” or building space, he said. If an Alaska bank helps finance a building that will be occupied or partly occupied by a state agency, “the institution would look to the strength of that lease. If there is an annual ‘out’ clause in the contract it is like not having a long-term lease at all,” he said. Northrim Bank and Wells Fargo NA participated in the construction loan on the Anchorage LIO; EverBank issued the long-term loan on the building in December 2014. Banks may decide not to lend for the building or, more likely, to raise fees for a risk premium, he said. That would trickle through to the lessee in the form of higher rent. The consequence, if the Legislature were to renege on the 4th Avenue building lease and move to the Atwood Building, the cost of rentals for any agencies would climb because building owners will build in a risk factor for a similar lease cancellation by the state. There may also be broader ripple effects, for example if the state moves to borrow money for state capital projects and to finance future state retirement pensions through bonds as Gov. Bill Walker is proposing. All state obligations and contracts have a “contingent on appropriations” clause, but that authority has rarely been used. Stevens said he recalls it having been used with a lease on an office building in Juneau, although the circumstances of the matter were not described, and also was told the state administration has used it two or three times on other state leases. None of those are as high profile as the new Anchorage building, however. Meanwhile there is also a lawsuit filed by Anchorage attorney Jim Gottstein, owner of an older building adjacent to the new LIO that Gottstein claims was damaged during construction, and that the new lease is illegal. Gottstein claims the rental contract violates a state requirement that rates on lease extensions, which is the way the Legislature chose to structure the deal, must be at least 10 percent under prevailing rates in the market for comparable space. The lease rate is above the prevailing rates, Gottstein said. Pfeffer disputes that and cited several appraisals by Northrim, Wells Fargo — who both appraised the building at $44 million in value — and an independent appraiser, Waronzof and Associates, that was hired to do the analysis under the direction of the Alaska Housing Finance Corp., a state agency with experience in commercial building development. Waronzof estimated the cost of the project at $48.5 million with and estimated rental rate, on comparable space at $3.9 million annually. That is to be compared with $3.38 million to be paid annually under the Legislature’s lease with Pfeffer.  Pam Varni, executive director of the Legislative Affairs Agency, which provides administrative and legal services to the Legislature, signed off on the appraisal in a Sept. 19, 2013, letter to the Budget and Audit Committee. “The annual rental payment (to Pfeffer) will be $281,638 per month or $3,379,658 per year, exceeding the 10 percent reduction in market rental value,” required by law, Varni wrote. “Our annual savings will be $528,341,” in contrast with the comparable lease rate determined by the independent appraiser, she wrote. There is a tangled history to the new legislative office building. The old building, constructed in 1972 was first leased by the Legislature in 1992 from longtime owner Bob Acree. Pfeffer became a partner in the building later. There were multiple extensions of the original lease, including five one-year extensions from 2009-13. The building was aging and one-year lease extensions did not allow for major investments in upgrades. Its one elevator was among the slowest in the state. It was not compliant with Americans with Disabilities Act, lacked secure parking, proper meeting spaces and on-site IT equipment. (Note: This writer was once stuck in the elevator with nine people for three hours, with the emergency phone connected to an answering service in Nebraska.) The Legislature began looking at new options in 2007, one being a rebuilding of the old Anchorage Times building also on 4th Avenue that is owned and used by the Alaska Court system and other a rebuilding and conversion of the state parking garage on 7th Avenue, which is across from the state’s Atwood Building. The state Department of Administration said no to the conversion of the 7th Avenue parking garage, however, and the conversion of the Anchorage Times building also did not proceed, although it is not known why. The former Unocal (then Chevron) building on 9th Avenue was also looked at, but the building was purchased and occupied by NANA, the Kotzebue-based Native development corporation. The Legislative Council then began a long process of Requests for Information, or RFIs, and Requests for Proposals, or RFPs, to solicit information on available space or request actual proposals from building owners. There were 12 of these over the years, Pfeffer said, including “government-to-government” solicitations for space from other state agencies. The requirement was for 35,000 square feet of usable space and dedicating parking. There were 28 responses to the various solicitations with proposed locations on Klatt Road, in south Anchorage, and in east Anchorage. “At that time the Legislative Council also took a vote to indicate a preference for staying downtown,” Pfeffer recalled. By 2013 the building “was getting into rough shape,” he said, but one-year lease extensions did not allow for major investments in upgrades by a building owner. Through all of this no one suggested moving the Legislature into the Atwood Building, Pfeffer said. Council makes call In early 2013 the Legislative Council decided a major decision needed to be made. Rep. Mike Hawker, R-Anchorage, then the council’s chair, was authorized to request proposals for major renovation or even reconstruction from Pfeffer, the building owner. Pfeffer said he responded with three options: “One was essentially new carpeting and paint, which wouldn’t have changed the lease rate; a second was a more extensive renovation and included work on the elevator, which would have added to the rent,” he said. A third option was a full modernization, essentially a new building. In May 2013, the Legislative Council agreed the last option, full modernization and reconstruction, was best, but also put out one more RFI to see if any other space was available. Former Rep. Bill Stoltze, R-Chugiak (now a state senator) was a member of the council and asked that the entire Municipality of Anchorage, from Girdwood to Eklutna and included Stoltze’s Chugiak district, be surveyed. There were two responses, one in a building at 64th and A Street, the Carr-Gottstein building in a South Anchorage industrial area, and a second between Northern Lights Boulevard and Fireweed Lane, on streets where there are large buildings occupied by engineering firms. Both options were rejected by the Legislative Council. In June 2013, the council authorized Hawker to ask Pfeffer to develop a proposal for “full modernization.” This required a scoping out of space needs and uses. Two new elevators were needed as well as meeting rooms on the first floor, so members of the public could have easier access. Security was also to be provided for parking because of safety concerns in the old, unprotected underground parking. There was also to be a facility for emergency power. That was not in the old building. Off-street access by trucks was also needed for the twice-yearly loading and unloading of equipment and files to be moved to the state capitol building in Juneau for annual the legislative session. In the old building the trucks blocked off part of 4th Avenue for loading and unloading. Also, in the old building all of the Legislature’s information technology services were in other locations. All of the “IT” was brought into the new building. Pfeffer developed a proposal for the building incorporating all of these needs including a rough estimate of the annual lease rate, about $3 million a year. A period of cost validation followed, conducted by Alaska Housing Finance Corp. The scoping of needs for the new building was done over an 11-week period from June through August 2013, and involved legislative staff, the Legislative Affairs Agency and others, about 60 being engaged at different times. Hawker was authorized to proceed to execute a contract with Pfeffer in August 2014, but the council also asked if the state could purchase instead of lease the building. Pfeffer said he would be agreeable but the legislators decided to stick with the lease option. The contract was signed in August of 2014, but did not include a sale option clause. Four appraisals were completed on the building. Two were done in 2013 by the banks providing construction financing, Northrim Bank and Wells Fargo, and both came in at $44 million, close to the actual cost. A third appraisal was done by EverBank, which took out the long-term debt on the building, in December 2014. That also came in at about $44 million. The fourth was done for Alaska Housing Finance Corp., which came in at $48.5 million. The reconstruction began in late 2013. It was finished on time and legislators moved into their new offices in December 2014. Decision looms Stevens, who is chair of the Legislative Council, said he hopes the council will make a decision Dec. 19 that will end the political wrangling. He would like to see the committee vote, with finality, to either buy the building from Pfeffer, to stick with the existing lease or to terminate it and move to the Atwood Building. “One concern I have is that with state money getting tighter the very expensive lease in Anchorage will drain funds for the Legislative Information Offices in other parts of the state,” Stevens said.

AGDC, producers approve 2016 spending

Alaska Gov. Bill Walker said he gave the OK Dec. 3 for the state to vote “yes” on continuing work on the Alaska LNG Project after receiving commitments from two North Slope producing companies that they would not withdraw from the project without negotiating to sell their gas. That same day the partners in the project, BP, ConocoPhillips, ExxonMobil and the state, voted to approve a $230 million 2016 budget and work plan to complete preliminary engineering work. The state’s share of that is 25 percent, or about $57 million. BP and ConocoPhillips signed the agreement making the assurances on a withdrawal to Walker Dec. 4, a day after the partners’ vote to approve 2016 spending. ExxonMobil, the third partner in Alaska LNG and the project manager, did not sign on to the agreement. The company did vote to approve the 2016 budget along with the other partners, however. Walker was previously worried that an exit from the project by one of the Slope producers at a critical time could leave the project stranded without enough assurance of throughput for financing and construction. Costs are estimated at $45 billion to $65 billion. In a briefing Dec. 4, Walker said having assurances from two of the three producers is good enough. He said he had spoken by telephone with senior officials at ExxonMobil, the holdout in joining the withdrawal agreement, and was given verbal assurances similar to those from BP and ConocoPhillips.  “Now we know we have gas committed to the project, and this is critical. A piece of pipe without gas is no good,” Walker said. On ExxonMobil, the governor said, “it is still a partner and is continuing to work in good faith,” on the Alaska LNG Project.  The withdrawal agreement between the state, BP and ConocoPhillips was released Dec. 8 and states that good faith efforts to sell gas to the “state or its designee” will be made by either company withdrawing, and that gas would be made available under “mutually agreed commercially reasonable terms.” The agreement states that what is “commercially reasonable” shall be at the sole discretion of each party. It also has a “no liability or damages” section that states no party is required to enter into an agreement and cannot be held liable for any sort of damages to the project, including loss of actual or potential profits. Sources familiar with the exchanges said the phrase “reasonable terms” implies agreement from both buyer and seller on prices and other terms. It is similar to language that now exists in state oil and gas leases under which an oil company lessee has an obligation to develop and sell resources if reasonable terms are offered. This is the “duty to produce” covenant that the governor and Attorney General Craig Richards have often spoken but it has proven difficult to enforce in lawsuits brought in other states involving similar language in leases, the source said. Walker originally pushed for more definitive terms of a potential sale agreement from a withdrawing partner, which might have involved setting a price, but appears to have backed away from this, possibly because of the complexities of the issue and the uncertainties it would have raised for the entire gas project. In his Dec. 4 briefing the governor said the state itself might be willing to buy gas from a withdrawing partner, and then resell it. “This is one option we’re looking at,” Walker said. The state’s gas corporation, the Alaska Gasline Development Corp., has the authority to purchase and sell gas, acting as a gas aggregator, through a subsidiary company formed last fall for that purpose. AGDC’s intent with this, for now, is to buy and sell gas to Alaska communities, its officials told a legislative committee during a special session of the Legislature in November. Legislators on the committee pointed out that the legal charter for the subsidiary appears to be broad enough so that the state could resell gas, as LNG, in international markets. Purchasing gas from a withdrawing partners would be a big financial undertaking for the state that would be on top of the state’s current commitment to finance 25 percent of Alaska LNG Project construction costs that could exceed $50 billion. Alaska now owns 25 percent of the North Slope’s known 35 trillion cubic feet of gas and now owns the same percentage of the Alaska LNG Project after completing the purchase of TransCanada Corp.’s share of the pipeline and North Slope gas conditioning plant. Previously, the state held 25 percent of the large natural gas liquefaction plant at the southern end of an 800-mile pipeline planned to be built from the North Slope. Having bought out TransCanada, the state how holds 25 percent of the pipeline and North Slope gas treatment plant, bringing its share of those into alignment with ownership in the LNG plant and the state’s own gas reserves. Meanwhile, the approval of the 2016 project budget will allow the pre-front end engineering and design, or pre-FEED, to be completed, with a target date by mid-year. Commercial negotiations are meanwhile underway among the partners on several agreements still needed, and these have to be completed before the next step is taken on the technical work, the final engineering or front end engineering and design, or FEED. Steve Butt, the ExxonMobil manager heading the technical work on the Alaska LNG Project, said the latest target date for a decision on FEED is mid-2017. Butt said the project is still on schedule in terms of the original agreements among the companies. There had been hopes previously that the FEED decision could have been made in late 2016. The commercial negotiations include several issues including a complex gas “balancing” agreement among the producers who are part of the Alaska LNG Project which sets out how gas will be made available if there are technical upsets in one of the two fields supplying gas, Prudhoe Bay and Point Thomson. A second important negotiation, on a so-called “governance” agreement, is on the legal and commercial structure for managing the project as it moves through the FEED process to a Final Investment Decision, construction and operation. Currently the commercial structure in place, where ExxonMobil is project operator on behalf of itself and other partners, governs only the pre-FEED work now underway. Eventually a stand-alone operating company similar to Alyeska Pipeline Service Co. might be formed to operate the project in its construction and operation phases, as Alyeska did for the Trans-Alaska Pipeline System. Also pending is a deal to fix the state’s fiscal terms, on royalty and tax, for a period of years, very likely equal to the terms of LNG sales contracts. This will require an amendment to the state constitution that must be voted on by the public in a state general election. The next general election is in November 2016. If the negotiations are not completed in time for the Legislature to approve the amendment by June 24, 2016, the next general election is in 2018, effectively delaying the Alaska LNG Project by two years. The negotiators’ schedule currently calls for the agreements to be completed by spring in time for a special session of the Legislature following the end of the regular session.  If things proceed as planned and the voters approve the amendment, a decision on final engineering, or FEED, in 2017 will allow the partners to make a Final Investment Decision in 2019, after which construction could start. The project could then be in operation in 2025 and could export up to 20 million tons of LNG yearly. Tim Bradner can be reached at [email protected]

Withdrawal agreement would allow state to buy Slope gas

Gov. Bill Walker released the agreement signed Dec. 4 by the state, BP and ConocoPhillips regarding the companies’ willingness to sell North Slope natural gas if either firm withdraws from the Alaska LNG Project. The nine-page agreement states that the sales offer will be made to the State of Alaska if “mutually agreed commercially reasonable terms can be reached between the relevant party (the withdrawing company) and DNR (the state Department of Natural Resources).” In a statement issued Dec. 8, Walker praised the companies for providing the letters: “This agreement ensures that there will be gas for a gasline if either partner withdraws from the project.” However, whether that actually happens depends on whether “commercially reasonable terms” can be agreed on and whether the state would be able to finance such a large transaction before the Alaska LNG Project is built and operating. Still, the fact that the two companies agreed to make the offer to sell gas and to negotiate in good faith, if needed, has given the governor the assurances he felt he needed, even if the letters are not binding. Still, if such a purchase were ever made the costs would be huge. In an analysis, Janek Mayer and Nikos Tsafos, of the firm enalytica, estimated that if the state were to purchase ConocoPhillips’ 22 percent share of the 35 trillion cubic feet of North Slope gas reserves, the cost, at $4 per million British Thermal Units, would be $19.2 billion. If ExxonMobil’s 32 percent share if North Slope gas were purchased, the cost would be $28 billion. ExxonMobil — the project manager for Alaska LNG — was the only one of the three Slope partners to not sign on to the withdrawal agreement. Those would be on top of the $13 billion the state will pay for its 25 percent share of the Alaska LNG Project construction. It might seem implausible that a company’s withdrawal would happen after so much has already invested heavily in the project — nearly $5 billion for all three firms if Point Thomson gas project costs are included. Point Thomson is nearing completion of an initial phase to produce a limited quantity of liquid condensates starting in 2016, but the project is actually intended to be part of the larger gas pipeline and LNG project. But despite sunk costs, things do happen. “Preparing for failure is a fact of life, and Governor Walker is right to be concerned about the possibility that one (or more) producers choose to not pursue Alaska LNG. Several LNG projects have seen partners depart even at late stages of the project development,” consultants Mayer and Tsafos said in a paper presented to the Legislature. Mayer and Tsafos made comments and presented their paper during closing days of a November special session of the Legislature, when word first circulated of Walker’s idea that the state purchase gas from a withdrawing party. The consultants warned against attempting to have a sales agreement actually in place as a contingency, however. “Withdrawal terms are common in most joint-venture agreements; however, there is no clear benefit in securing a detailed sales and purchase commitment from the producers at this stage of the project,” the two consultants said in their analysis. An alternative they suggested is apparently what Walker has done. “The state can explicitly set a framework for such an eventuality (a withdrawal) by creating a process by which the state and a reluctant producer enter into exclusive negotiations, in good faith, for the state or another nominated party to purchase the producer’s gas,” Mayer and Tsafos said. The agreement with BP and ConocoPhillips appears to just commit the parties to good-faith efforts, and nothing more. Walker was still happy, though. “The gas availability agreement is the result of months of negotiations between the state and its partners, and brings the state closer to delivering North Slope gas to the world market and lowering energy costs for Alaskans,” he said in his statement. In a briefing Dec. 5, the governor said, “We no longer will have to worry about (the companies’) competing projects around the world. This is absolute assurance that the gas will be available,” to the Alaska LNG Project. Tim Bradner can be reached at [email protected]

Annual revenue forecast a bleak picture for production take

The state released its annual forecast for state revenue and oil production Dec. 8, and the news wasn’t good. Unrestricted general fund revenues, a measure of funds available for appropriation by the Legislature to support public services, is now forecast at $1.6 billion for fiscal year 2016, the current budget year, compared with $2.26 billion for the last fiscal year that ended June 30. This will likely balloon a projected deficit for the year from $2.7 billion estimated last spring to more than $3 billion. Some good news, however, is that income from Alaska’s investments, mostly the Permanent Fund, will be sharply increased in the current year to $3.77 billion compared with $2.58 billion last year. Within that total, the Permanent Fund’s “realized” earnings — funds received through asset sales, bond interest or rentals, and which are available for appropriation — are estimated at $3.35 billion for this year, up from $2.93 billion last year. The Revenue Department report also listed a gain in the Fund’s unrealized earnings, or its market gains, of $349.8 million, but those are not available for appropriation. Right now the increases in Permanent Fund earnings don’t help the immediate state budget outlook because the Legislature has avoided spending these, preferring to let them accumulate in an earnings reserve account of the Permanent Fund. The annual Permanent Fund Dividend paid to citizens is funded by part of the fund’s annual earnings but the total income far exceeds what is spent on the dividend. A plan to use part of the fund’s annual earnings to help support the state budget is expected to be among new revenue options the Legislature will consider in 2016. The annual dividend is expected to be retained although it may be modified in some way. Other parts of the revenue forecast had more sober news, however. Overall Alaska production from the North Slope declined by about 5.6 percent in the state’s current fiscal year, state revenue Commissioner Randy Hoffbeck said. “While there was a 13.6 percent increase in production from the Cook Inlet, that was not sufficient to offset a 5.6 percent decrease on the North Slope,” Hoffbeck said in a statement. North Slope production is now expected to average 500,200 barrels per day for the current fiscal year, down from 519,500 barrels per day estimated in the forecast made last spring. “We are forecasting North Slope annual production to remain above 500,000 b/d until 2018,” Hoffbeck said. Cook Inlet production is rising, however. Previously estimated at 14,700 barrels per day in the spring forecast, it is now expected to average 17,800 barrels per day for this year, according to the forecast. Meanwhile, a bump up in North Slope production to 504,900 barrels per day is expected in fiscal year 2017 beginning next July 1, due to new projects recently completed or that now under development and soon to be completed. However, Slope output is expected drop again in fiscal year 2018, to 506,600 barrels per day, according to the forecast. The decline in oil revenues has had on other effect, although it is just an accounting measure. Oil revenues are sharply down, which means that the contribution of non-petroleum revenues, small as they are compared to oil, are having a larger impact. This year, 74 percent of Alaska’s revenues are being paid by petroleum taxes and royalties, compared with as much as 90 percent in previous years when oil prices were higher. Meanwhile, the state budget still exceeds revenues by a large measure. The state has been tapping cash reserves to pay hefty budget deficits, which are now exceeding $3 billion a year. The state has sufficient reserves to pay the deficits for three more years, after which earnings of its $55 billion Permanent Fund, an investment fund of past oil income, could be tapped.   Alaska’s forecast of revenues, oil production and operators’ expenditures is done annually, typically in early December, and is updated in the spring, usually in early April. Tim Bradner can be reached at [email protected]

AGDC, partners OK gasline budget; ExxonMobil only producer to not offer withdrawal agreement

The board of the state-owned Alaska Gasline Development Corp. voted unanimously Dec. 3 to approve a $75.6 million expenditure as Alaska’s 25 percent share of final preliminary engineering costs for the Alaska LNG Project. The state is a one-quarter partner in the project with North Slope gas owners BP, ConocoPhillips and ExxonMobil. Later in the day, the project partners voted to approve the total project spending of $230 million for the 2016 preliminary engineering budget. Gov. Bill Walker had said previously that the state’s approval for Alaska LNG’s 2016 budget might be contingent on receiving an acceptable “withdrawn partners” agreement from the three producer partners. Walker said Thursday afternoon that commitments on the agreement had been made by two companies, BP and ConocoPhillips, and that two out of three is good enough. In a press release, Walker thanked BP and ConocoPhillips for committing to sign and make public a “Gas Availability Agreement” for their share of North Slope natural gas. The agreement will allow the project to move forward in the event that either company ends participation in the AK LNG project during the preliminary engineering phase, which is to be concluded in the first half of 2016. “This is an historic milestone in the AK LNG project,” Walker said in a statement. “I am pleased that this agreement will be made public so Alaskans can better understand the project. Ensuring gas will be available to this gasline is a significant step in the right direction. “I thank BP and ConocoPhillips for addressing the state’s concerns by agreeing to continue to negotiate mutually agreed and commercially reasonable terms under which their gas would be made available in the event either company does not proceed beyond pre-FEED. BP and ConocoPhillips have given us the assurances we need to move forward.” There was apparently no letter from the third producer in the partnership, ExxonMobil. The governor did not comment on that. The preliminary engineering, known as pre-front end engineering and design, or pre-FEED, will set the stage for a decision to move to final engineering, front end engineering and design, or FEED, by mid-2017. Commercial agreements between the state and the industry partners must be concluded before the FEED decision is made and negotiations on those are ongoing. Dave Cruz, acting board chairman of AGDC, said the state’s acquisition of TransCanada Corp.’s share of the LNG project made the state’s decision to support the completion of pre-FEED easier because the state would be representing its full one-quarter share on the project management teams rather than having to work through TransCanada on part of that. “We’re now in a great position as a full partner to move this project forward,” Cruz said as the board meeting concluded. Cruz is owner of Cruz Construction, a longtime Alaskan firm.

Citing new projects, explorers urge preservation of tax credits

State oil and gas tax credit incentives are a valuable investment in new oil production and in-state energy security and shouldn’t be trashed, independent explorers are telling state officials and legislators. In the long run they more than repay the state treasury through new royalty and state taxes, too, several companies say. Casey Sullivan, Caelus Energy’s external affairs manager, said his company’s planned $1.2 billion Nuna project on the North Slope will benefit from tax credits and royalty reductions in the near term but will ultimately pay the state treasury an estimated $1.23 billion to $1.32 billion in royalties and taxes. Nuna is expected to begin production in October 2017 and will produce 20,000 barrels per day to 25,000 barrels per day, Sullivan told the Resource Development Council’s annual conference Nov. 19. Caelus is an independent oil and gas company based in Dallas. Benjamin Johnson, president of BlueCrest Energy, a Fort Worth, Texas-based independent, told the RDC conference that his company’s new Cosmopolitan oil project in Cook Inlet is expected to be in production next April and that new gas production could follow by 2018. But those will depend on the state of Alaska not abruptly terminating its oil and gas incentives, particularly for projects now under development and in which investments have been made by companies. Many legislators are looking at the incentive program as a cost and at $500 million a year in direct expenditures by the state in recent years it has weighed heavily on the state budget. “We need to view this as an investment in the future, but we should manage it well,” Johnson told the RDC conference. Sullivan said, “This isn’t free money. We spend money in the economy, and no industry has a greater job-multiplier effect than oil and gas — about 9 to 1,” meaning for every one job in the industry nine other jobs are created indirectly by the spending. Caelus itself has invested massively in its ongoing development and new exploration, employing 900 workers in its North Slope program last winter, Sullivan said. Recent publicity about the program, and some legislators’ calls for ending it, has created financing problems for small companies who are exploring and raising money, he said. “When Alaskans sneeze about oil tax credits, the ripple effects are felt on Wall Street,” Sullivan said. Johnson said the state incentive program may need changes and a range of alternatives are being discussed. For projects in development, like BlueCrest’s Cosmopolitan and Caelus’ Nuna, a low-interest loan or loan guarantee by the state may be just as effective as a cash tax credit, and would have the benefit of not directly taking money from the treasury, Johnson told the RDC. “Loans like this could be low-risk and high return (with a discovered oil and gas deposit) and wouldn’t be cash out of the pocket for the state,” he said. The worst alternative is to end the program and make the termination retroactive, so that tax credits already applied for would be worthless, Johnson said. “Stability of the tax system is vital, and we feel that commitments should be honored for projects (under development) that are low risk, and where benefits can be quantified,” he said. “Changing the program would be fine, but do it in a way that doesn’t immediately affect projects now underway. I would recommend retaining the existing program for a couple of years and then phasing it out.” A particular concern Johnson has is keeping the Spartan Drilling Co. Spartan 151 jack-up rig in Alaska so that it can be used to drill Cook Inlet offshore wells. The rig has been under contract to Furie Operating Alaska for its Kitchen Lights gas project in Cook Inlet but Furie has released the rig now that it is producing. Spartan currently has no customers but is storing the rig in Seward over the winter, hoping for more work next year. BlueCrest hopes to use the Spartan 151 to drill gas production wells at Cosmopolitan in 2016 and 2017 but the gas project can’t proceed until there is more clarity on the state’s intentions on the incentive program. Hilcorp Energy has done an admirable job in developing new Cook Inlet gas for Southcentral Alaska but gas from other new discoveries, like at Furie’s project and BlueCrest’s, is needed to supply regional energy needs until a North Slope gas pipeline can be built, Johnson told the RDC. Gov. Bill Walker put a $500 million cap on current-year expenditures under the incentive program (it was to have cost $700 million) and instructed administration officials to come up with less-costly alternatives. A proposal for a new system is expected to be presented to the Legislature next spring. Options under consideration include an annual cap on tax credit expenditures, a pre-approval process for eligible expenditures as well as some form of direct state financing, or even investment. The state is already making limited investments in the industry through the Alaska Industrial Development and Export Authority, the state’s finance corporation, although these are so far restricted to infrastructure such as roads, pads and process plants, although a company’s acquisition of an offshore jack-up rig was also funded through an investment, which has since been repaid.

Hilcorp looks for cost savings, new reserves

Hillcorp Energy’s Cook Inlet oil production is holding steady at about 14,000 barrels per day and the company is now negotiating with Southcentral regional utilities for extension of natural gas supply contracts, Hilcorp president Greg Lalicker told the Resource Development Council conference Nov. 19. In a briefing on Hilcorp’s activity in Alaska, Lalicker said some new gas supply contracts have been signed out to 2023 and 2024 and others are still being finalized. Hilcorp’s previous supply contracts were through the early part of 2018. Hilcorp’s entry into Cook Inlet in 2012 and 2013 and the company’s aggressive redevelopment of aging gas fields, as well as oil fields, staved off a looming gas shortage facing utilities in the region. Lalicker told the RDC that Hilcorp is investing in new Southcentral gas development with a new exploration well planned to be drilled next spring at the producing small Happy Valley field on the Kenai Peninsula. While Cook Inlet oil production is steady the low price of crude oil is having its effects. Given the high costs of work in the Inlet and low prices, the company can no longer afford certain well workovers and maintenance procedures that Hilcorp has emphasized to sustain and even build per-well oil production rates, Lalicker said. “We just can’t afford to do some of this work,” he said. Still, the company remains focused on oil. “We get to sell it quickly,” Lalicker said, as opposed to gas which is sold to utilities at intervals when there are openings in gas supply contracts. All of Hilcorp’s Cook Inlet oil goes to the Tesoro refinery at Nikiski. Hilcorp has also invested in new 3-D seismic surveys in the mature MacArthur River and Middle Ground Shoal fields in a hunt for new oil. “Parts of these fields have never had 3-D seismic before, so we expect to be able to identify a lot more (oil) targets,” Lalicker said. Three-dimensional seismic is a more intensive and sophisticated method of doing geophysical surveys of underground geologic formations than the older, two-dimensional surveys that were previously done. On the North Slope, Hilcorp has had less luck holding oil production rates steady at three older producing fields acquired from BP last year, the onshore Milne Point and offshore Northstar and Endicott fields. Production has dropped from about 40,000 barrels per day in December 2014, just after Hilcorp took over the fields, to about 36,000 barrels per day in early November, Lalicker said. Hilcorp has only had one year as owner and operator of these fields, however, and the company believes its strategies of seeking efficiencies and then investing will still succeed over several years. Lalicker said big cost reductions have already been achieved in the three producing fields. “When we took over at the end of 2014 we were spending $15.8 million a month operating these fields,” he said. Now, a year later, costs are down to $12.5 million a month. “We don’t focus on eliminating people or services but rather in finding the most efficient ways to do things,” Lalicker said. “It’s a 21 percent cost reduction, but unfortunately the price of what we produce is down 50 percent,” he said. Despite oil prices, Hilcorp is investing in its North Slope assets. The company has been working on producing wells in the Milne Point field with the Nordic-Calista workover rig and plans to bring an additional, new workover drill to the Slope next fall, for more work at Milne Point. A workover rig is one that is mostly designed for repair and major maintenance on producing wells in contrast to larger rigs that are built to mostly drill new wells. Workover rigs can sometimes drill wells, however, although these are typically “sidetracks,” or new wells drilled underground laterally an older producing well. Lalicker said Hilcorp sees potential for new oil from its North Slope fields and particularly Milne Point and the Sag River formation that is there as well as potential oil from tighter rocks and eventually the heavy, large Ugnu deposit. Hilcorp is operator at Milne Point but BP is still a 50 percent owner. Hilcorp is also in a 50-50 partnership with BP at Liberty, an undeveloped offshore oil deposit, but is also the operator there. Liberty is in federal offshore waters and Hilcorp has submitted a development plan to the U.S. Bureau of Ocean Energy Management, which was approved by the federal agency on Sept. 18, triggering a 60-day public review period. The schedule in the application calls for a Record of Decision by the BOEM if the agency grants final approval. If Hilcorp and BP move ahead, engineering would begin in late 2017 and construction would start in 2018. Production would begin in 2020. In its press release BOEM said its Sept. 18 announcement, “does not mean that the Development and Production Plan for Liberty has been or will ultimately be approved; it merely denotes that BOEM has determined that Hilcorp has submitted the information required,” under the agency’s regulations. Public “scoping” meetings on the plan are now being conducted by BOEM to craft an environmental impact statement. Liberty has oil reserves of 80 million to 150 million barrels, according to the BOEM application, which could sustain peak production rates of 60,000 barrels per day to 70,000 barrels per day. Tim Bradner can be reached at [email protected]

Native regional corporations net income rebounded in 2014

Alaska Native corporations continue to grow in financial strength and are increasingly integrated into the state’s economy. In 2014 total revenues by the 12 Alaska Native regional corporations grew over 2013 in line with a five-year average, according to the latest financial reports on regional corporations released Dec. 1 by the ANCSA Regional Association. ANCSA stands for the Alaska Native Claims Settlement Act that passed in 1971 and created the regional and village corporations. The data is compiled and presented annually by the association, which represents the 12 regional corporations. Total revenue for the corporations was $8.57 billion in 2014 compared with $8.49 billion in 2013. Profits in 2014 took a sharp jump for the group, up 98 percent for the group compared with 2013, Kim Reitmeir, the association’s executive director, told the Anchorage Chamber of Commerce Nov. 30. Profits in 2014 were $304.9 million compared with $153.7 million in 2013. The difference is unusual, however, and more a one-year event. Aggregate net income was $389.5 million in 2010. The corporations’ aggregate net income took a dip in 2013 compared with previous years. However, net income for the group was still 11 percent higher in 2014 that the five-year average of net income. “This is a result of management being more focused on getting value for shareholders,” Reitmeir said. Meanwhile, total shareholder equity in the regional corporations, an important measure of the value of the businesses, was also up 8.6 percent in 2014, or about $4 billion compared with $3.8 billion in 2013, she said. Dividends paid to shareholders dropped in 2014 compared with the previous year but that was mainly because of a large one-time dividend paid by one corporation in 2013, Reitmeir said. “Several of our corporations are now paying annual dividends that are larger than the Permanent Fund Dividend. This is something retailers should pay attention to,” she told the chamber. The corporations are also “giving back” a big share of net income, in charitable contributions, support given to nonprofits, scholarships and dividends, which totaled 60 percent of profits in 2014, Reitmeir said. Over five years the average has been 75 percent. Meanwhile, the increasing diversification of the Native corporations is being felt throughout the state’s economy. “It’s difficult to find an industry that Alaska Native corporations are not involved in,” she told the chamber. The corporations have long been engaged in the basic natural resource industries like oil and gas, minerals and timber, but now they are in fields like commercial and residential real estate, financial services and telecommunications and offshore fisheries support. Of strategic importance for Alaska, however, is that the majority of the corporations’ earnings are from outside Alaska, in the form of income on investments and earnings of subsidiaries that operate in the Lower 48 and elsewhere. Some of these are minority 8(a)-designated firms, a U.S. Small Business Administration classification that allows preferences in federal contracting for minority-owned businesses. The regional corporations are now less dependent on 8(a) contracting, however. “The 12 regional corporations have seen a 7 percent decline in 8(a) revenues over the last five years,” Reitmeir said. This is partly due to several of the corporations’ subsidiaries having “grown out,” or graduated, from the minority preference program so that they now fully compete with other companies for private contracts. Several of the regional corporations have also decided to reduce their 8(a) involvement for policy reasons, partly because of criticism of the program from certain people in Congress. Among the regional corporations, one still has 30 percent of its total business operations in the 8(a) field, the largest share for a corporation in 8(a) business, while the corporation with the smallest share has 10 percent of its business operations in 8(a), Reitmeir said. Overall, the regional corporations took in 28.5 percent of their total revenue from 8(a) contracting in 2014 compared to 42.9 percent in 2010. The ANCSA Regional Association compiles and publishes the data to build an understanding of what Native corporations contribute to the economy. The information is incomplete, however, because it does not include data from Native village corporations, several of which are substantial businesses and employers. The regional corporations’ report used to include data from several major village corporations, but this ended, “because there are now many village corporations that are doing very well,” Reitmeir said. Alaska Native corporations were formed in 1971 with the passage by Congress of the Alaska Native Claims Settlement Act, which returned 44 million acres of Alaska’s 365 million acres to Native ownership and paid $965 million in a cash settlement in lieu of lands not returned. “Many people think the $965 million was seed money to get the Native corporations started in business, but it was really a settlement,” and compensation for lands taken, Reitmeir said. The new corporations did use the money to get started in the early 1970s, and while there have been problems and bumps along the road many of the corporations have grown into multi-billion-dollar business enterprises. Passage of the 1971 claims act was also crucial to the development of the state’s economy at the time. The pending Native land claims issue had clouded title to many Alaska lands important for development including a corridor for the 800-mile Trans Alaska Pipeline System then being planned. The federal government wouldn’t grant the pipeline corridor until the claims were settled, which put the oil and gas industry into a political alliance with regional Native groups to get the bill through Congress. It took a second act of Congress to fully approve the oil pipeline, however. In 1973 Congress passed the Alaska Trans-Alaska Pipe Line Authorization Act, which cut through a thicket of environmental lawsuits that were blocking the pipeline. The creation of a large privately-owned land base in Alaska would also boost the economy. Development of mineral resources, oil and gas and timber harvesting has happened since 1971 that wouldn’t have occurred had the lands remained in federal ownership. Reitmeir recalled that many environmental groups worked against the land claims settlement. “They didn’t want these lands going into private ownership,” she told the Anchorage chamber. Tim Bradner can be reached at [email protected]

Tesoro acquires Flint Hills marketing operation

Tesoro will acquire Flint Hills Resources’ fuels marketing and logistics facilities in Alaska, the company announced Nov. 23. The Interior Alaska refinery closed by Flint Hills in April 2014 is not included in the transaction. Tesoro operates a refinery at Nikiski, on the Kenai Peninsula in southern Alaska. “This investment represents our commitment to efficiently and reliably serve customers in the state of Alaska, said Tesoro CEO Greg Goff in a statement. “We have been part of the Alaska community since 1969 and over the last five years we have invested $300 million in our Alaska facilities. We look forward to continuing our operations in the state.” Under the deal Tesoro will acquire Flint Hllls’ wholesale fuel marketing contracts in Alaska, a terminal in Anchorage with 580,000 barrels of storage capacity, truck racks and rail-loading facilities. A 22,500-barrel capacity jet fuel storage facility at the Fairbanks International Airport in the state’s Interior is also included as well as access to rail offloading facilities in Fairbanks that will provide Tesoro better access to the Interior market, according to the company’s statement. The transaction is expected to close in 60 days, Tesoro said. No purchase price was given. Tesoro has been supplying diesel and jet fuel to Flint Hills for that company’s Interior Alaska customers since Flint Hills shut down operations at its refinery at North Pole, east of Fairbanks. “What’s important to us is to be as close to our customers are possible, and this transaction allows us to connect our refinery more efficiently to people we serve in Fairbanks,” through Flint Hills, said Nate Weeks, Tesoro’s vice president for strategy and business development. Tesoro has been investing corporate-wide in infrastructure and logistics in recent years and the new acquisition in Alaska fits that strategy, said Weeks. An important aspect of the purchase is that the former Flint Hills bulk fuel facilities and logistics chain will be open to third parties to use under contract, which is not currently possible with Flint Hills, Weeks said. As an example, a large volume customer could contract to store its fuel in the Anchorage or Fairbanks fuel terminals. Now only Flint Hills-owned products are stored. Tesoro does this at many of its other Lower 48 terminals and even at storage facilities near its Nikiski refinery. “Obviously this is on a space-available basis, but we want to make it available because there is limited fuel storage capacity in the market and we don’t want to appear to be choking off competition by buying more storage capacity,” he said. Flint Hills’ refinery was closed mainly for economic reasons and Flint Hills would like to sell the refinery, the company has said, but buyers are reluctant because of potential liability for soil and groundwater contamination at the site. Flint Hills is currently engaged in a protracted negotiation with Williams Co., a previous owner of the refinery, over cleanup costs. Tesoro’s Nikiski refinery has a capacity to process up to 72,000 barrels per day of crude oil and makes a full range of products including gasoline, jet fuel and ultra-low sulfur diesel. The Nikiski refinery is connected to Anchorage with a 69-mile, 48,000 barrels-per-day pipeline, which gives the company the ability to ship jet fuel to air carrier customers at Ted Stevens Anchorage International Airport by pipeline. The Flint Hills refinery in Fairbanks, in contrast, could make jet fuel and gasoline but not ultra-low sulfur diesel, which put the plant at a competitive disadvantage. Flint Hills also had to ship its jet fuel to Anchorage, to customers at the airport, by rail, which is less efficient than Tesoro can do with its pipeline. At one time Tesoro considered closing its Nikiski refinery because of high costs and supplying Alaska customers from Washington State but the plan was shelved. The Nikiski refinery is now benefitting from a surge of new oil production in Cook Inlet, which allows Tesoro to reduce imports of crude from other regions. The refinery was originally designed to process Cook Inlet crude. Tim Bradner can be reached at [email protected]

ConocoPhillips only successful bidder at federal lease sale

In contrast to a state areawide lease sale held the same day, bidding was very light at a federal U.S. Bureau of Land Management sale in the National Petroleum Reserve-Alaska Nov. 18. NPR-A is the large federal reserve west of state lands on the North Slope,. Only six bids were submitted for six tracts, all by ConocoPhillips. The acreage bid on was adjacent to leases already held by ConocoPhillips and Anadarko Petroleum, a minority partner. In total, BLM netted $788,680 in total high bids in the sale, half of which will be shared with the state of Alaska under terms of a 1975 federal law. ConocoPhillips’ high bid per acre was $31.91, and the highest bid for a lease was $199,760, BLM officials said. The federal sale was area-wide, like the state sale, meaning that all unleased tracts in the area open for bidding were offered. Most of the area open to bids in the sale was of moderate potential for oil and gas discoveries. Lands with higher potential to the north of the lands offered, and nearer the coast, were off-limits to bidding because of the environmental sensitivities of the area, which is a waterfowl breeding area during summer. ConocoPhillips also announced Nov. 18 it would proceed with development of its Greater Moose’s Tooth, or GMT-1 project, in the area near the new leases acquired. The company is also working on a prospective GMT-2 a few miles further into NPR-A from GMT-1. The 23-million-acre NPR-A was created in 1923 by President Warren Harding as a petroleum reserve for the U.S. Navy, although it had no known oil deposits at the time. Designated as Naval Petroleum Reserve No. 4, the region has had several phases of exploration beginning with a Navy-led effort in years following World War II that was followed by a program managed by the U.S. Geological Service. In 1975 the reserve was transferred from the Navy to the U.S. Interior Department and re-designated the National Petroleum Reserve-Alaska. In the 1980s, parts of NPR-A were opened to leasing by private companies and several exploration wells were drilled over the following years. Modest oil and gas discoveries were made in the government-led exploration including a small oil field at Umiat, in the reserve’s southeast, and a gas field at Barrow, which now supplies gas to the community. Federal government geologists now believe the NPR-A has only modest potential for oil discoveries but more substantial prospects for natural gas. Tim Bradner can be reached at [email protected]  

BlueCrest set for April production at Cosmo

BlueCrest Energy will begin oil production next April at its Cosmopolitan project in Cook Inlet and will initially be trucking crude oil to the Tesoro Alaska refinery at Nikiski, company CEO Benjamin Johnson told the Journal. Cosmopolitan is an offshore oil and gas deposit three miles off Anchor Point, on the east side of Cook Inlet, that is owned 100 percent by BlueCrest. Oil will be produced through production wells drilled from shore. BlueCrest, an independent oil and gas company, is based in Fort Worth, Texas. Johnson would give no production or reserve estimates but said previously that the company has expanded previous estimates of oil and gas reserves after new drilling in 2013. “We are not able to disclose reserves but I can tell you that our initial expectations of oil rate start out at several hundred barrels per day from the existing one well and grow to several thousand barrels per day as we drill more wells,” Johnson said. An independent estimate of Cosmopolitan’s reserves done in 2012 and based on previous drilling, estimated the field to hold proved and probable reserves of approximately 55.2 million barrels of oil equivalent. The estimate was based on exploration by Cosmopolitan’s previous owners, Pioneer Natural Resources and ARCO Alaska. The 2013 well drilled by BlueCrest and Buccaneer Energy, then a 25 percent minority partner, confirmed the presence of the gas reservoir overlying the oil and further tested the deeper oil deposit. BlueCrest acquired Buccaneer’s 25 percent share before Buccaneer filed for bankruptcy. Meanwhile, BlueCrest is bringing new equipment to Alaska. “We’ll be bringing a new drill rig to Cook Inlet in January to drill the oil production wells. It will be the largest rig in Alaska,” at 3,000 horsepower and a 1.5-million-pound last load rating, Johnson said. A large rig is needed to drill the high-angle, deviated production wells. Houston-based Oderco Inc., a major manufacturer of drilling rigs, is constructing the rig for BlueCrest, Johnson said. All American Oilfield LLC, an Alaska-based drilling contractor, will operate the rig. “All American has a lot of experience in the Cook Inlet and are well prepared to operate our rig. Many of their workers actually live close to the Anchor Point drill site,” Johnson said. All American is owned by Chugach Alaska Corp., an Alaska Native regional corporation. Onshore facilities to support the drilling and process the crude oil are already installed on a 38-acre pad, Johnson said. “We will be trucking the oil to Tesoro (the company’s refinery near Kenai). Once we have drilled more wells we may look into building a pipeline,” Johnson said. Until then, however, BlueCrest expects the number of oil trucks on the road to be minimal, he said. BlueCrest also plans development of a shallower gas deposit but that will require installation of two gas production platforms with pipelines built to shore, Johnson said. The gas reservoirs are too shallow to tap with high angle production wells from shore, in contrast with the oil reservoir, which is deeper. Gas development is on hold for now, however, until the state clarifies its position on an oil and gas development tax credit program that is now being reviewed, Johnson said. If all goes as planned, however, the drilling of gas production wells will begin in 2016 using Spartan Drilling Co.’s Spartan 151 jack-up rig now in winter storage at Seward, a south Alaska port, Johnson said. Gas production could begin in 2018. BlueCrest is in a partnership with California-based WestPac Midstream on the gas development. WestPac will handle marketing of the gas to Alaska utilities and industrial customers, he said. The gas development schedule is contingent on the state of Alaska not making major changes in its oil and gas development tax program, which is under review by the state. Gov. Bill Walker ordered a review and changes to the program earlier this year because of its growing expense, but also said that some form of state oil and gas development incentives will remain. He deferred payment of some $200 million in credits in the current fiscal year. “If we are able to proceed with the offshore gas development, we expect each platform will produce approximately 35 million cubic feet per day for the first few years before declining in rate. We will start with one platform and then add the second as gas supplies are needed,” Johnson said. Tim Bradner can be reached at [email protected]  

Schedule slipping on pre-FEED work, critical agreements

State officials say they are worried that the schedule for the big Alaska LNG Project could slip because of delays by North Slope producers in reaching key agreements. However, the state itself is contributing to some of the delay, as well as part of the cost increase of the pre-front end engineering and design, or pre-FEED, sources familiar with the project say.  Gov. Bill Walker had hoped to have the agreements earlier this fall in time for legislative approval in a special session of the Legislature held in late October, but that did not happen. The governor did present a proposal that the state buy out the interests of TransCanada Corp. in the project, which lawmakers approved. Several big issues remain, however. “We’re not making progress on the commercial agreements needed and this could be costly to the project timeline,” Alaska Natural Resources Deputy Commissioner Marty Rutherford said in a recent briefing to legislators. The Alaska LNG Project involves an 800-mile, 42-inch pipeline from the North Slope to a large gas liquefaction plant in southern Alaska, along with a large gas treatment plant on the North Slope that would mainly remove carbon dioxide from the produced gas. AGDC is the state corporation that represents Alaska’s 25 percent interest in Alaska LNG Project. The project has been given federal approvals to export up to 20 million tons of LNG yearly. Construction costs are estimated between $45 billion and $65 billion. Frequent changes in the state’s gas negotiating team by Walker have created uncertainty for the industry negotiating partners, the sources said, who asked not to be identified. The governor has made three changes of his lead negotiator since earlier this year. Rutherford, at DNR, was the lead of the gas team until late spring, when Walker requested that Audie Setters, an experienced, retired Chevron LNG official, take over the role. Setters had been working as a consultant for the state. He was replaced in the summer by Rigdon Boykin, a retired California attorney who now lives in South Carolina, and who had worked with the governor in prior years on the Alaska Gasline Port Authority, a group Walker headed. Boykin was sent home to South Carolina by Walker the week of Nov. 9. Boykin’s departure was not announced and no replacement was named but sources told the Journal that key decisions on the negotiations are now being made by three officials: Attorney General Craig Richards, Revenue Commissioner Randy Hoffbeck and Rutherford. Timeline slipping The schedule is slipping in other ways. It looks now that preliminary engineering now underway will not be complete until mid-2016, instead of late 2015 or early 2016 as was hoped earlier. Part of that delay is due to Walker, too. Late in the summer the governor requested the Alaska LNG Project team to reevaluate the use of 48-inch diameter pipe rather than 42-inch pipe. Industry partners had earlier concluded that 42-inch pipe was optimal for shipping the known gas reserves, and that the pipe could be manufactured by several suppliers including steel mills in North America. Walker argued, however, that there will eventually be much more gas found on the North Slope and that building in extra capacity, with bigger pipe, will be more efficient in the long run than handling expansions by building more compressor stations. Industry partners in Alaska LNG agreed, some reluctantly, to the reassessment of the bigger pipe, which is adding $30 million to the pre-FEED cost and delaying its results. The analysis of 48-inch pipe against 42-inch pipe is to be finished by March with the final evaluation to be done by May, according to sources. The decision on the pipe size must be made before the decision to move to front-end engineering and design, or FEED, which is currently estimated to cost the project partners a combined $2 billion, of which the state would be responsible for a quarter, equivalent to its ownership stake. All that means the FEED decision could be delayed to late 2016, Rutherford told legislators in the briefing. However, industry partners in the gas project may also wait to see the outcome of the November 2016 state general election. That’s when voters will decide whether to approve a necessary constitutional amendment to allow the state to enter long-term fiscal agreements with the producers for the gas project. Dan Fauske, CEO of the Alaska Gasline Development Corp., or AGDC, told its board in a briefing Nov. 12 that while the hoped-for schedule is slipping it is still within an overall timeline laid out by the partners, which calls for beginning of FEED no later than July 2017. This could still allow a final investment decision in 2019 and project completion in 2025, which is the current plan. Rutherford said the most critical agreements the governor wants by early December are a gas balancing agreement among North Slope producers BP, ConocoPhillips and ExxonMobil, who are partners with the state in the project, and a separate agreement to cover contingencies over a partner withdrawing from the project, she said. Withdrawal, gas-balancing agreements The partner withdrawal agreement has been requested by Walker, who is concerned that if a partner pulls out of the project it could stymie others in proceeding. Rutherford said the governor is pushing the producers to have the gas balancing and withdrawal agreements by Dec. 4, the date on which the project members are to vote to approve the 2016 budgets for completing the preliminary engineering. “Meeting this goal will be a significant challenge,” Rutherford said. AGDC Operations Vice President Joe Dubler said the balancing agreement is proving to be complex because gas for the project will come from two North Slope fields, Prudhoe Bay and Point Thomson, and there are differing percentages of ownership by the producers. “They’ll get there, but it is taking time,” Dubler said in the Nov. 12 briefing to AGDC’s board. Agreements for withdrawn partners are normal in big projects but Walker wants an added provision that guarantees that the withdrawing party will commit gas to the project, meaning that it would agree to sell to a buyer. That is proving to be very difficult in the negotiations because it essentially involves an agreement to sell gas to an unknown buyer for an unknown price. One option is that the state itself could buy the gas now owned by a withdrawing partner, but that could entail huge financial risks for the state, advisors to the Legislature have warned lawmakers. Dubler told AGDC’s board Nov. 12 that the partners are working hard on an agreement and hope to have it by the governor’s Dec. 4 deadline. Fauske said the Alaska LNG Project partners could vote on the 2016 pre-FEED budget without the withdrawn parties and gas balancing agreements but that the governor prefers to have them done. The state itself will vote on the budget, as a partner. Deadline for amendment looms Meanwhile, Rutherford said a hard deadline the project faces is June 24, 2016. That is the day a proposed constitutional amendment on fiscal terms must be sent to the Division of Elections to appear on the November general election ballot. By that that time Legislature must also have ratified the agreement between the state and North Slope gas producers that will fix state tax and royalty terms for a period of years, presumably the length of long-term contracts to sell Alaska LNG. To be legal, the fiscal agreement will require an amendment to the state constitution. The constitution currently forbids the Legislature approving a guarantee that state taxes won’t change. North Slope gas producers say the fiscal term deal is a “must-have” because of Alaska’s past record of frequently changing state taxes on oil production. However, fiscal terms deal is proving to be another big sticking point in current negotiations, the governor has said in recent briefings. At least one Slope producer is pushing to have it cover taxes on crude oil as well as gas, Walker said. The state is pushing back on that. Assuming the fiscal terms deal agreement is eventually concluded it will have to be ratified by the Legislature next spring, most likely in an April or May special session following the end of state lawmakers’ regular 2016 session. A constitutional amendment requires a two-thirds vote of both the state House and Senate and that must be done by June 20.  “If we don’t meet that the entire project schedule begins to slip,” Rutherford said, because the next general election for ratification of the amendment is November 2018, which would effectively delay the project two years. ASAP update In other developments, managers of AGDC told its board that work is continuing to complete a supplemental environmental impact statement, or SEIS, on the state’s backup pipeline plan, the 36-inch Alaska Stand Alone Project, or ASAP. This is important because while ASAP itself is on hold (it is a backup in case the larger Alaska LNG Project doesn’t go) the work being done for the SEIS and the U.S. Army Corps of Engineers Section 404 wetlands permit is transferable to the larger project. Dave Cruz, an AGDC board member who heads the board’s technical committee, said there are no indications of any delay in the Corps of Engineers issuing the final supplemental EIS, its Record of Decision, as well as the Section 404 permit and other permits by fall 2016, most likely October. A right-of-way across 100 miles of federal lands would also be issued by the U.S. Bureau of Land Management as a part of the other federal documents. “Those permits are transferable to Alaska LNG even though there is a six-inch difference between the 36-inch pipe (of ASAP) and the 42-inch pipe (of Alaska LNG),” Cruz told the board. What’s important is that the physical footprint of the two pipeline projects, including the space needed for construction equipment, are similar, which should be the case for 36-inch or 42-inch pipe, he said. “There’s still some debate on this but it shouldn’t be a problem,” for the regulatory agencies, Cruz said. However, 48-inch pipe may be a different matter, he acknowledged. If 48-inch pipe is decided on and the Federal Energy Regulatory Commission, which is lead agency on the federal EIS for Alaska LNG, decided that the larger pipe represents a “substantial” change, at least some of the work on the 36-inch SEIS won’t be usable. A critical factor, however, is that the routes of the two projects, ASAP and Alaska LNG, have been exactly aligned from Prudhoe Bay to a location in the Matanuska-Susitna Borough where the bigger pipeline would veer off toward a Cook Inlet crossing to the Kenai Peninsula.  ASAP would end in the Mat-Su Borough where it would connect with existing regional pipelines. Meanwhile, AGDC is finishing up other parts of the ASAP project that will be useful to Alaska LNG. This includes a fine-tuning of information gathered to support final engineering on the ASAP project including a c“works package” of equipment needed for construction, AGDC Engineering Vice President Frank Richards told the board that information is available from a Request for Information the state corporation had sent out to vendors for estimates equipment packages. Material sites for construction were also identified. “They have been looking at equipment, parts, camps, pads–those early activities that will need to be done well in advance of construction. There will also be development of material sites and the opening of access roads,” AGDC spokesman Miles Baker said. This information will be useful to the Alaska LNG project, he said. “There may be some differences in equipment due to the differences in pipe size, 36-inch instead of 42-inch, but the civil works side of the project will be roughly the same,” for both ASAP and the larger Alaska LNG Baker said. Moving to 48-inch pipe would require heavier equipment and more updated information, however. “We would have four mainline contractors (on different parts of the 800-mile route) using similar equipment and working simultaneously to build the pipeline, and we need to make sure they are serviced and supplied,” Baker said. Tim Bradner can be reached at [email protected]

Lengthy to-do list remains for Alaska LNG negotiators

There is a long list of commercial issues yet to be resolved in the Alaska LNG Project negotiations but many of these may be combined, so the number of agreements, in the form of contracts, is yet to be determined, sources familiar with the negotiations have told the Journal. At the top of the list are four items important to the state of Alaska, two of which Gov. Bill Walker hopes to see resolved by early December. They are: • Gas balancing agreement: Sometime called a gas supply agreement, which spells out how and when gas will be withdrawn from the two fields supplying Alaska LNG: the Prudhoe Bay and Point Thomson fields. This agreement is between the three Slope producers — ExxonMobil, BP and ConocoPhillips — and is complex because of differing ownership levels at the two fields. ExxonMobil and ConocoPhillips each own about 36 percent of the gas at Prudhoe, and BP another 26 percent. At Point Thomson, ExxonMobil and BP own about 93 percent of the gas and ConocoPhillips less than 5 percent. About 75 percent of the gas for the project is to come from Prudhoe and the remainder from Point Thomson. The gas at Prudhoe, unlike at Point Thomson, is used to enhance oil recovery. • Withdrawn partners agreement: This would spell out terms for a partner withdrawing from the project and clarify how the partner’s gas, as a producer, will still be available for purchase through the project. Other issues pending include: • Fiscal agreement: This would stipulate that state taxes on gas produced for the project would not change over the terms of LNG sales contracts, which could span 20 years to 25 years. Purchasers of the LNG will require this provision, or at least will ask producers to absorb any state tax increase, which the producers will not do. The state constitution currently forbids long-term tax deals, so a constitutional amendment will be needed. Sources have told the Journal that attorneys for the state and the companies are currently debating whether a narrowly-drawn constitutional amendment is possible, such as one that relates to specific contract terms, or whether the amendment will have to be more broadly written. Alaska voters are considered more likely to approve a narrowly-drawn amendment than a broadly-written approval. • Governance agreement: This would provide the long-term framework on how the project would be managed and how costs would be allocated. Decisions have to be made on whether a stand-alone operating entity, such as Alyeska Pipeline Service Co., would be created. This is needed by late 2016, the time that the project would move into final engineering, if that happens. As it has been described the governance agreement would guide the work on final engineering, construction and operations. • Expansion agreement: This is a request by the state, and it involves how a physical expansion of the project, such as if there were more gas to be shipped, would be funded and managed. Sources said this may wind up being rolled into the governance agreement. • PILT, impact payments: It was revealed Sept. 23 that the producers have agreed to pay the state $16.5 billion for property tax obligations and community construction impacts related to the Alaska LNG Project. Revenue Commissioner Randy Hoffbeck made the announcement during a Municipal Advisory Gas Project Review Board meeting in Fairbanks. Of the $16.5 billion sum, $800 million would be for community impact payments during construction. Afterwards, $15.7 billion would be payments in-lieu of tax, or PILT, substituted for property tax payments in project infrastructure and property holdings, according to Hoffbeck. The negotiated $800 million amount is a “fairly firm” number, Hoffbeck said, and would pay for increased public services — police, fire and other first responders — needed in communities along the project corridor that grow from an influx of construction workers. How the massive dollar figures will be allocated amongst the state and the communities affected by the project still needs to be worked out. Whether or not the state’s purchase of TransCanada Corp.’s share of the gas treatment plant and the pipeline — done after the PILT and impact amounts were announced — plays into how much money is distributed is another question Kenai Peninsula Borough Mayor Mike Navarre has raised. The board consists primarily of mayors of local governments along the project route from the North Slope to Nikiski on the Kenai Peninsula. The state commissioners of the Natural Resources, Revenue and Commerce departments also serve on the board. The next Municipal Advisory Gas Project Review Board meeting is scheduled for Dec. 7 in Anchorage. • Contract operator service agreement: This would govern how a company acting as project operator, currently ExxonMobil Corp. in the preliminary engineering now underway, would perform its duties. • Member services agreement: This could be a separate agreement, providing administrative services like independent accounting, to support the contract operator. This could be rolled into the contract operator service agreement. Sources told the Journal that ConocoPhillips has been asked to provide the administrative support function until decisions are made on a possible independent operating company. • Capacity release agreement: This would cover how an owner of capacity in the project, most likely a producer, would release it to other parties if there is spare capacity. The state wants this in place as an assurance to third party access, such as independent explorers. • In-state sales agreement: This is needed to spell out whether and how producers, or the state, will offer gas for in-state sales, such as to utilities. Sources told the Journal that the producers are not keen to supply in-state needs because they would prefer all of their gas go to long-term export customers, and that they would prefer that the state supplies in-state needs with its gas. The state is concerned that if it is the only supplier of in-state gas there will be huge political pressure to sell state gas at a discount. Having producers among the sellers of gas to in-state customers would provide a buffer against these kinds of pressures. • Financing of spur lines and gas conditioning facilities at gas take-off points: The Alaska LNG Project has agreed to at least five of these, but there could be more, as many as 20. The governor is pressing the producer members of Alaska LNG to allow the project to pay for these, including spur pipelines of several miles, such as will be needed to connect the Alaska LNG pipeline to Fairbanks. This is still an issue on the table. The producers thought that Alaska Gas Development Corp., the state gas corporation, was supposed to be responsible for this, which is spelled out in Senate Bill 138, the legislation providing the framework for state participation. So far, AGDC has funded the engineering and design of the “kits,” or facilities, needed at the takeoff points, but there have been no decisions made on where  the points will be except for one near Fairbanks, in the Matanuska-Susitna Borough and on the Kenai Peninsula. Who would fund the takeoff kits and spur lines is also undecided. Tim Bradner can be reached at [email protected] Journal reporter Elwood Brehmer contributed to this article.

Administration will introduce bill to convert Fund earnings

The slide in crude oil prices is continuing, and transforming Alaska’s state finances to revenue sources more predictable and sustainable than oil income has taken on more urgency. Year-to-date prices for North Slope crude oil were at an average of $49.98 per barrel as of Nov. 17. That’s since July 1, the start the current fiscal year, and it is $16 per barrel less than the price of $66.03 per barrel predicted by the state last March and used as the basis for budget planning. Year-over-year production numbers are better, with an increase of about 3.7 percent since the start of the fiscal year through Nov. 15. Daily production in November is averaging about 555,000 barrels per day compared to about 537,000 barrels per day in November 2014. How much the price shortfall will balloon the state budget deficit is uncertain, but a deficit well greater than $3 billion is certain. Is there a better way? State officials have been quietly working since last January on a plan to transform Alaska’s fiscal system and some concepts have been rolled out in recent weeks before legislative and business leaders.  State Attorney General Craig Richards surfaced the concept, still a work-in-progress, in a recent briefing to state legislators and, more recently, to the Alaska business policy group Commonwealth North. The plan, being labeled a “sovereign wealth” fund, would replace oil revenues with earnings from the $53 billion Alaska Permanent Fund. Richards warned, however, that the idea if implemented next year would still leave an estimated $1 billion gap that would require new revenues, most likely new taxes. A preliminary estimate for the idea allows for about $3.1 billion per year to be paid to the general fund from Alaska Permanent Fund earnings, and have about $1 billion paid additionally from other state taxes, for a total of $4.1 billion. This assumes a status-quo state budget of about $5.1 billion in unrestricted general fund spending, leaving the $1 billion remaining gap. However, legislators are likely to reduce the budget to less than $5.1 billion next year. Legislators were briefed on the idea in Juneau during the recently-concluded special session of the Legislature, which had been called to consider Gov. Bill Walker’s idea to buy TransCanada Corp.’s share of the Alaska LNG Project, which lawmakers approved. Members of the administration’s working group have not been identified except that it includes economists from the Department of Revenue and other state agency officials as well as Richards. The administration officials confirmed that there will be a bill introduced for the 2016 session outlining the plan. The concept basically involves bulking up the Permanent Fund by diverting some oil revenues to the Fund that now go to the state general fund. Income earned by the Fund would flow into its Earnings Reserve Account, as it now does. Currently there is about $9 billion in the earnings account. Withdrawals would be made annually from the earnings account by the Legislature to support the state budget, using some as-yet-undetermined formula. The state constitution prohibits spending money from the principal of the Permanent Fund but income that has accumulated in the Earnings Reserve can be appropriated by the Legislature. An important change in the plan is that it would indirectly reduce the amount of money available for the Permanent Fund dividend. If the plan were in place next year the 2016 dividend would be $1,000, about half the 2015 amount, Richards told the legislators. The effect of that would be, indirectly, to put more money into the Permanent Fund, creating more earnings that would support the state budget. John Tichotsky, chief economist in the state Department of Revenue, told members of Commonwealth North’s fiscal task force recently that a major goal of the plan is to take the volatility of oil revenues out of the state general fund, which is now 90 percent dependent on oil, and place it into the Permanent Fund, which can smooth out the volatility because of its sheer size. There would also be a more stable source of revenues for the state general fund. Other key goals include keeping the Permanent Fund on a sustainable basis in terms of its real, or inflation-proofed, value, Tichotsky told the Commonwealth North group. Legislators have voiced few opinions about the plan but some who did speak were cautious. Sen. John Coghill, R-Fairbanks, who is Senate Majority Leader, attended the Juneau briefing and complimented the governor for stepping forward with a plan, but had some mixed views. “I think it’s complicated. It doesn’t really bring in more money, but just rearranges the plumbing,” he said. Coghill’s point was that the same goals can be accomplished in simpler ways that would be more understandable by the public, and possibly more transparent. For example, just appropriating a portion of the Fund’s annual earnings and capping the dividend might achieve the same results. Others who have looked at the concept are intrigued, however. Cheryl Frasca, a former state budget director who chairs Commonwealth North’s fiscal policy task force, is open to the new ideas. “I think it’s an interesting approach for a couple of reasons,” she said. One is the proposal, in the plan, to fund the annual citizen dividend with a percentage of oil royalties rather than earnings from the Permanent Fund, as happens now. “It ties a ‘royalty dividend’ (now the Permanent Fund dividend) directly to oil and gas development instead of Wall Street investment returns,” the current system, she said. “That changes the dynamic of support and creates a constituency that supports future oil and gas development. After all, it’s claimed that it’s ‘our oil.’” A second interesting point, she said, is that it would require a limit on the amount of revenue taken annually from the earnings account, although the mechanism for that is still being developed. “This could be a good tool to control spending. I believe Anchorage’s municipal tax cap (a somewhat similar mechanism) is a very efficient tool that has limited Anchorage’s spending swings over the years,” Frasca said. “This means that if the Legislature wants more money it will have to go to other tax sources,” which will encounter resistance. “Other taxes become the wild card in terms of generating additional revenues to support increased spending. Lots of constituencies protecting sources for these revenues, so it creates a counter-balance against increasing spending,” Frasca said. In a recent talk before the Alaska Miners Association’s annual convention, Northrim BanCorp CEO Joe Beedle said he likes overall concept the Walker administration is advancing. “Whether it’s called an endowment, a sovereign wealth fund or Permanent Fund, I believe the concept is very good,” Beedle said. He also liked the direct connection between the dividend and state oil and gas income, he said. There are other views on that, however. Some see a severing of the connection between the Permanent Fund and the dividends having the effect of reducing citizens’ interest in the Fund and their role as watchdogs on any imprudent investments or a Legislature’s way to “raid” the fund indirectly by using it as loan collateral, which can be done. Linking the dividend to the Permanent Fund performance was central to the idea of the dividend advanced in 1980 by former Gov. Jay Hammond, who saw it as a way of developing safeguards for the Fund. There are also many features of Walker’s fiscal plan that are not yet developed, however, and details are important. Tichotsky, of the Department of Revenue, told Commonwealth’s fiscal task force that a crucial decision yet to be made is whether to use some form of Percent-of-Market-Value, or POMV, formula to annually draw funds for the budget or to develop a fixed yearly payment, perhaps inflation-adjusted. The Percent-of-Market-Value payout method is commonly used by large endowments like those held by universities and large charitable funds. It makes a payment based on the overall market value of the endowment. The payment is typically less than the projected average total earnings, such as a 4 percent payment from earnings averaging 8 percent, with the remaining 4 percent of earnings are retained to adjust for inflation. One problem with the POMV is that, assuming a steady growth of market value, it would tend to automatically increase the amount of revenue available to the Legislature, which would inevitably lead to greater spending. One advantage of the fixed-draw is that this would be a true cap on spending, although there would have to be periodic “reopeners” of the cap to make adjustments, such as for inflation or population growth. Eric Wohforth, co-chair with Frasca of the Commonwealth North task force, said he is concerned about a fixed-draw because any necessary adjustment mechanisms would be complex, difficult for the public and inevitably less transparent. “There’s total transparency to percent-of-market value. Everyone can see what the market value is, so it’s very simple,” Wohlforth said. Wohlforth is an Anchorage attorney and a former Permanent Fund trustee and state Revenue commissioner.

Statoil quits the Alaska Arctic OCS, following Shell’s exit

Norway-based Statoil has quit its Alaska Arctic program in the Chukchi Sea, becoming the second company to officially withdraw from the region.  ConocoPhillips, the remaining holdout among the Chukchi Sea explorers, has not indicated its intentions but said the company’s Arctic offshore plans had been on hold for some time. Earlier this fall Shell announced disappointing results on Chukchi Sea drilling and said it would end its program. Statoil is returning its leases, however, while Shell is retaining its Chukchi holdings, as is ConocoPhillips, although all leases expire in 2020. The U.S. Department of the Interior refused a request by the companies to suspend the clock on the leases. In a statement, Gov. Bill Walker said, “We are disappointed in Statoil’s decision not to pursue further offshore development in the Chukchi, and understand it is largely tied to Shell’s decision to terminate its offshore drilling efforts in Alaska as well. This further emphasizes the need to develop our onshore opportunties, such as the 1002 section of ANWR.” Environmental groups reacted positively. Oceana, which focuses on the offshore, said, “Decisions made by oil companies in the Arctic Ocean are finally starting to make sense. First Shell and now Statoil abandoning offshore leases sends a strong message to decision-makers meeting in Paris next month,” on climate change, said Susan Murray, Ocean’s Deputy Vice President for the Pacific. “Pursuing oil and gas development in the Arctic Ocean is too risky.” Statoil said its leases in the Chukchi Sea are no longer considered competitive. The company also closed its office in Anchorage on Nov. 16, laying off two employees who were still here. Statoil will also drop 16 leases that were 100 percent owned by the company and also a part ownership, with ConocoPhillips, in 50 other leases in the Chukchi Sea.  “Since 2008 we have worked to progress our options in Alaska. Solid work has been carried out, but given the current outlook we could not support continued efforts to mature these opportunities,” Tim Dodson, Statoil’s executive vice president for exploration, said in a statement. Statoil U.S. spokesman Peter Symons said the company is in discussions with ConocoPhillips on the disposition of Statoil’s shares of the 50 jointly-owned leases, in which Statoil holds varying percentages. ConocoPhillips spokeswoman Natalie Lowman, based in Anchorage, said it is possible that if Statoil surrenders its share of leases that portion of ownership would revert to ConocoPhillips, but that the matter is not clear. As for ConocoPhillips’ own position, she said, “Our plans for the Chukchi Sea were on hold prior to Statoil’s announcement and they remain on hold.” Statoil’s last Alaska employees had expected the office closure. “Statoil is a great company but there were just too many obstacles placed in the path of drilling, and low oil prices don’t help,” said Ella Eide, who until Nov. 16 was Statoil’s spokeswoman in Alaska. The company had been gradually winding down its Alaska presence, and its workforce in the state, for some time. Statoil acquired its Arctic offshore leases in the Interior Department’s 2008 OCS lease sale in the Chukchi Sea along with, Shell, ConocoPhillips and Repsol. Statoil and ConocoPhillips began environmental and early planning for drilling but decided to let Shell take the lead in clearing regulatory obstacles and legal challenges. After about $7 billion in expenditures including over $2 billion spent for the OCS leases in 2008, Shell was finally able to drill a well into potential oil formations in 2015, but the results were disappointing. Randall Luthi, president of the National Offshore Industry Association, a trade group, said, “Statoil’s decision to withdraw from the Alaskan Arctic is disappointing yet understandable given current tough economic and regulatory conditions. These are challenging times for the oil and gas industry with continued low commodity prices making for hard choices, and I know this was a difficult one for Statoil.  “The company has a substantial investment in the U.S. Arctic and had hoped to become a producer of both energy and economic growth there for Alaskans and for our nation. Hopefully, another company will step in to fill the void left by Statoil, but given the harsh economic climate and the difficulty obtaining lease extensions, the outlook is rather bleak.” Kara Moriarty, president of the Alaska Oil and Gas Association, said Statoil’s decision is a stark reminder of the importance of regulatory certainty in the oil and gas business. “While lawmakers and policymakers cannot control an oil basin’s geology, they can control permitting and regulatory policies to make the region competitive for exploration and development,” Moriarty said in a statement. “Unfortunately, Alaska is an expensive place to do business, and the federal regulatory environment is known for being difficult and unpredictable. Coupled with oil prices staying stubbornly low and expected to remain so for the foreseeable future, taking huge financial risks in Alaska is just not feasible for most oil companies, even large ones like Statoil and Shell.” The decisions by the two companies to depart will not have a large adverse economic impact on the state, although had Shell had better results and continued with drilling in 2016 it would have generated work for many Alaska-based support companies. There is no effect on state finances either, since it would have been a decade or more before any offshore oil flowed into the Trans-Alaska oil pipeline. Also, oil and gas from federal offshore waters pay no production taxes or royalties to Alaska, although state taxes on onshore property, like pipelines, would have been a benefit.  Offshore production would mainly have helped keep the TAPS pipeline viable by providing more oil. That would lower TAPS’ operating costs, which would have lowered costs for transporting oil produced on state lands. That would have resulted in new revenues to the state.  Tim Bradner can be reached at [email protected]

ConocoPhillips greenlights $900M Greater Moose’s Tooth-1

It was an announcement that lifted spirits at the annual Resource Development Council conference on Nov. 18. ConocoPhillips Alaska President Joe Marushack said his company will proceed with construction of its Greater Moose’s Tooth No. 1 oil project in the National Petroleum Reserve-Alaska. “GMT-1 has been approved for funding. It is expected to cost about $900 million and follows our recent completion of CD-5,” which is also in the NPR-A, Marushack said. The new project will be in production in late 2018 and will produce 30,000 barrels per day at peak, he told the RDC annual conference in Anchorage. The timing likely means that construction activity will begin in 2016, a boost for North Slope contractors and their workers. “We are pleased to have been able to work through key permitting issues with the Corps of Engineers and BLM (Bureau of Land Management) that now allows us to move into the development phase,” he said. GMT-1 is in the northeast NPR-A about seven miles west of the reserve’s eastern boundary with state-owned lands. The producing Alpine field and now the CD-5 project near Alpine are owned 78 percent by ConocoPhillips and 22 percent by Anadarko Petroleum Corp., as is the planned GMT-1. CD-5 began producing ahead of schedule in October, and will have peak production of about 16,000 barrels per day. ConocoPhillips’ Drillsite 2-S in the Kuparuk also began producing and will add about 8,000 barrels per day at peak. GMT-1 will be connected by road and pipelines with CD-5 and the Alpine field. The project has long been in the planning stages and was approved following an extended environmental and regulatory proceeding by the U.S. Bureau of Land Management. Although GMT-1 is within the federal NPR-A, parts of the mineral rights are owned by Arctic Slope Regional Corp., the Alaska Native corporation based in Barrow. ASRC received rights in the reserve as a part of the Alaska Native Claims Settlement Act approved by Congress in 1971. ConocoPhillips is also at work on a planned GMT-2 project a few miles farther west in the NPR-A from GMT-1. The petroleum reserve is a 23-million-acre federal enclave that dominates the western part of the North Slope. It was created in 1923 by President Warren Harding as a future oil reserve for the U.S. Navy, However, after years of exploratio, no commercial oil deposits were found until ConocoPhillips and Anadarko made the discoveries now being developed in the northwest part of the reserve. Marushack also told RDC that ConocoPhillips now has six rigs at work in the North Slope fields it operates, the most since the mid-1980s. The company’s capital budget for 2015 is about $1.4 billion, down slightly from $1.6 billion in 2014. “Our capital budget in Alaska remains strong and the reason is that the projects we do here are what ConocoPhillips does well,” which are large, conventional oil and gas projects, Marushack told the RDC. No capital spending figures for 2016 have been announced.  Journal reporter Elwood Brehmer contributed to this article.

Independents win big acreages in state North Slope lease sale

Some people in industry still have a lot of faith in the North Slope, even with crude oil prices skidding. Independent companies bid aggressively for acreage Dec. 18 in the state’s North Slope “area-wide” sale, acquiring acreage at rock-bottom prices. The bulk of the offers were rock-bottom bids but with the exception of two high bids by Denver-based Armstrong Oil and Gas on tracts near a discovery Armstrong plans to develop with Repsol. Armstrong beat out competing bids by ConocoPhillips, in fact. The Alaska Department of Natural Resources auctioned off 131 tracts on 186,400 acres with high bids totaling $9.51 million. Armstrong was the highest bidder in the sale, offering $1.92 million on two tracts near the Colville River, the area of the Repsol/Armstrong discovery. ConocoPhillips offered the only competing bids in the sale of $160,000 for those two tracts. Two other parts of the North Slope were put up for bid, the “foothills” area of the southern Slope and state offshore acreage in the Beaufort Sea, but drew no bids. About 2.2 million acres of 5.1 million acres in the state’s central North Slope area were up for bid, not including the southern foothills and Beaufort Sea state acreage where there were no bids. In a big surprise, Armstrong Oil and Gas offered $3,007 per acre on the high-bid tracts through its affiliate, 70&140 LLC. The discovery area by Repsol and Armstrong is to the north of the tracts just acquired but the high bids reinforce a belief that the two companies have found a significant new discovery. Repsol, the operator for itself and Armstrong, has filed applications for development permits with federal and state agencies for facilities capable of producing 120,000 barrels per day.  The bulk of the leases sold Nov. 18 were to two small independents bidding together, Accumulate Energy Inc. and Burgandy Xploration LLC in a potential shale oil belt south of the Prudhoe Bay field where 88 Energy, an affiliate of Accumulate, is now drilling an exploration well to test shale prospects. The two companies bid together with Accumulate at 77.5 percent and Burgandy Xploration at 22.5 percent on the leases. The offers were a few cents above the state’s minimum bid of $25 per acre on most of the leases acquired. 88 Energy and another independent, Great Bear Petroleum, are exploring shale oil prospects in a wide area south of the Prudhoe Bay and Kuparuk River fields that are now producing conventional oil. The oil accumulated in the existing North Slope fields originated in deeply-buried shales to the south, which has led Great Bear and 88 Energy to a theory that these could produce oil similar to that now produced in the Eagleford and Bakken plays of the Lower 48 states. Tim Bradner can be reached at [email protected]

Resource heavyweights gather at momentous time for Alaska

It’s November, and time for the big Resource Development Council annual conference. This year, more than any other, huge issues loom for Alaskans including the proposed $50-billion plus North Slope gas pipeline and liquefied gas project and the state’s fiscal troubles, with $3 billion-plus annual deficits. All will be discussed at the conference. RDC is a pro-development advocacy group representing all of Alaska’s industries that touch on use of the state’s rich natural resources. That includes tourism, which relies on an unspoiled wilderness landscape as its prime attraction. Tourism companies work side-by-side with oil and gas, minerals, fisheries and forest products companies in RDC, which demonstrates how these industries are not only compatible but reinforce each other. Organized labor is active in RDC too, because the state’s human resources, its labor force, are critically important. Municipalities are members and participants, too, because what happens in the state’s basic industries, which are mainly resource-driven, affects them. The annual meeting held in November is where all of this comes together, where all the state’s business and political movers and shakers rub shoulders, trade information and frequently move off into side-meetings. If there’s any one place where one can see who drives the state’s economy, this is it. This year’s conference, scheduled for Nov. 18-19 at the Dena’ina Civic and Convention Center in Anchorage, is expected to attract about 1,200, as it has in recent years. Briefings on all the state’s major industries are on the agenda as well as economic trends and updates on key federal and state regulatory issues. Joe Marushack, president of ConocoPhillips Alaska, will discuss his company’s positioning for the future in Alaska; Steve Butt of ExxonMobil, senior project manager of the Alaska LNG Project, will update the conference on the proposed North Slope gas pipeline and LNG export project; Dan Fauske, president of the Alaska Gasline Development Corp., will discuss the state’s role in Alaska LNG, and Kenai Peninsula Borough Mayor Mike Navarre will discuss how his municipality is preparing to deal with a huge construction project, although it is still some years off. There will also be briefings on activities of smaller oil and gas companies, such as BlueCrest Energy with its Cosmopolitan oil project in Cook Inlet; Caelus Energy with a new North Slope oil project, and Hilcorp Energy on that company’s work in redeveloping Cook Inlet oil fields and several mature North Slope fields acquired from BP. Mining companies will also talk about their operations and plans, including Eric Hill, general manager at the Fort Knox gold mine near Fairbanks, and Jan Trigg, community relations manager at the Kensington gold mine near Juneau. RDC’s members include several hundred businesses and groups and a large number of individual members, according to Marleanna Hall, the newly-appointed executive director. As an organization, RDC is unique in a number of ways. There are few, if any, similar organizations in other states that represent diverse interests and with a focus on responsible development of natural resources. Beyond its big annual conference, RDC is known, at least in Anchorage, for its biweekly breakfast meetings that typically feature presentations by business and agency leaders. All of these are posted on RDC’s website, Hall said. The group also offers a unique service to its members by representing them before federal and state agencies on often-complex regulatory and environmental issues. Many of these — endangered species is one example — may or may not have immediate effects on company operations but the potential of disruption is there. Through its engagement with the regulatory agencies RDC makes its members’ views known and also keeps its members informed on regulatory actions. The organization has also takes a leadership role at times in advocating legislative solutions to problems, one example being how state agencies allocated costs to private firms when development permits were applied for. In this case the solution worked out by RDC and its members, a framework on how agency staff costs are allocated, was enacted into law. A recent RDC initiative is with the state Department of Natural Resources’ decision on granting in-stream flow reservations to non-governmental groups. Hall testified in hearings on the issue, which has raised many concerns, and RDC has also submitted detailed comments to the state DNR. In another effort, RDC helped get its members out to support Hilcorp Energy’s planned Liberty offshore project in the Beaufort Sea. The U.S. Bureau of Offshore Energy Management is taking public comments on the application by Hilcorp to do the project. “This is very important because now that Shell has left the Arctic, at least for now, there are opposition groups that are shifting away from Shell to target this proposal,” Hall said. Another past effort was in combating the U.S. Environmental Protection Agency’s new “Waters of the United States” rule, which threatens to sharply expand that federal agency’s role in regulating Alaska development projects. In response to a lawsuit from 13 states including Alaska, a federal judge recently issued an injunction prohibiting the EPA from administering the rule.   The 36th Annual Alaska Resources Conference  November 18-19, 2015 • Dena’ina Civic & Convention Center, Anchorage, Alaska Resource Development Council - Growing Alaska Through Responsible Resource Development. For more information, visit akrdc.org. Wednesday, Nov. 18 7 a.m. Registration/Check-in/ Exhibits Open Eye-Opener Breakfast in Exhibit Area – Sponsored by Wells Fargo 8 a.m. Opening Remarks Ralph Samuels, RDC President, Vice President, Government and Community Relations, Holland America Line Governor Bill Walker (invited) Alaska Economic Trends: 2016 Outlook Neal Fried, Economist, Alaska Department of Labor Alaska Industry 2015 Year in Review and 2016 Outlook Oil & Gas: Kara Moriarty, President and CEO, Alaska Oil and Gas Association Fisheries: Glenn Reed, President, Pacific Seafood Processors Association Forestry: John Sturgeon, President, Koncor Forest Products Mining: Karen Matthias, Managing Consultant, Council of Alaska Producers Tourism: Scott Habberstad, Director of Sales and Community Marketing, Alaska Airlines 10 a.m. Gourmet Break – Sponsored by ConocoPhillips Alaska, Inc. 10:30 a.m. ConocoPhillips Alaska: Positioning for the Future Joe Marushack, President, ConocoPhillips Alaska, Inc. Global LNG Market Update and Framing the Opportunity for Alaska Felipe Arbelaez, Chief Commercial Office, BP Supply & Trading 11:30 a.m. Networking Break Noon Keynote Luncheon: Sponsored by Northrim Bank It’s Still North to the Future: Moving Ahead in the Arctic Wayne Westlake, President and CEO, NANA Regional Corporation Rex Rock Sr., Chairman and President, Arctic Slope Regional Corporation 1:30 p.m. Alaska Can’t Quit Now: Why the Arctic Still Matters Randall Luthi, President, National Ocean Industries Association Marine Freight Transportation: Safety and Environmental Stewardship Charlie Costanzo, Vice President, Pacific Region, American Waterways Operators What Alaskans Need to Know About Federal Overreach Bill Kovacs, Senior Policy Advisor, U.S. Chamber of Commerce 3 p.m. Gourmet Break – Sponsored by Colville, Inc. 3:30 p.m. Pebble vs. EPA: Finally Some Real Progress Tom Collier, CEO, Pebble Partnership Point Thomson: Dawn of a New Era Gina Dickerson, Point Thomson Project Manager, ExxonMobil 4:30 p.m. VIP Networking Reception – Hosted by ExxonMobil open to conference registrants and speakers Thursday, Nov. 19 7 a.m. Exhibits Open Eye-Opener Breakfast in Exhibit Area – Sponsorship Available 8 a.m. Real Solutions to Alaska’s Budget Crunch Cheryl Frasca, Former Director State of Alaska Office of Management and Budget, 2002-2006 Mike Navarre, Mayor, Kenai Peninsula Borough Give the State Some Credit: How Oil Tax Credits Are Changing Alaska’s Investment Game Benjamin Johnson, President, BlueCrest Energy, Inc. Casey Sullivan, Director, State Public Affairs, Caelus Energy Alaska, LLC Hilcorp: Boosting Efficiency and Production in Alaska Greg Lalicker, President, Hilcorp 10 a.m. Gourmet Break – Sponsored by Stoel Rives LLP 10:30 a.m. Communities and Mining: Why it Works Eric Hill, General Manager, Kinross – Fort Knox Mine Jan Trigg, Manager, Community Relations and Government Affairs, Coeur Alaska – Kensington Gold Mine Wayne Hall, Manager, Community and Public Relations, Teck Alaska Incorporated Lance Miller, Vice President, Resources, NANA Regional Corporation 11:30 a.m. Networking Break Noon Keynote Luncheon: Sponsored by Holland America Line Navigating Alaska’s Inside Passage and Policy Linda Springmann, Vice President, Deployment and Tour Marketing, Holland America Line 1:30 p.m. Progress Report on the AKLNG Project Steve Butt, Senior Project Manager, Alaska LNG Project Dan Fauske, President, Alaska Gasline Development Corporation Mike Navarre, Mayor, Kenai Peninsula Borough 3 p.m. Grand Raffle Drawing Send-off Champagne Toast – Sponsored by CLIA Alaska

Draft EIS nearly ready for Donlin, in the works for Chuitna

Mining companies involved with several important projects aren’t ready to press the button on construction just yet, but they are positioning things to be ready to go when metals and commodity prices tick up, as they surely will. One large project being watched closely is Donlin Gold in the mid-Kuskokwim River region west of Anchorage, a potential $6.7 billion surface gold mine. After years of work the U.S. Army Corps of Engineers is expected to publish a draft environmental impact statement, or DEIS, later this month, James Fueg, Donlin Gold’s technical services manager, told the Alaska Miners Association at its annual convention in Anchorage Nov. 5. Publication of the DEIS would be followed by a series of community meetings in the Yukon-Kuskokwim region, including one hearing in Anchorage. If things proceed as hoped, the final EIS would be published in early 2017 following by a Record of Decision later that year. The big question following that is whether the mine will be economic and profitable enough for its developers, Barrick Gold and NovaGold Resources, to commit to spending several billion dollars on construction. Communities in Southwest Alaska have a lot riding on the decision. Calista Corp., the Alaska Native regional corporation for the Y-K delta, is the subsurface minerals owner. The Kuskokwim Corp., a consortium of local village corporations, owns surface lands at the mine site. If Donlin Gold is developed it will be a major employer in the region, now one of the state’s most economically-depressed areas. The prospect itself has 34 million ounces of gold in the measured-and-indicated reserve category, a classification that means companies have a high degree of confidence in the estimate, and another 11 million ounces that are “inferred” resources, or gold estimated to be present but requiring more definition. Chuitna Another large mine project closer to Anchorage that is inching along in its regulatory approvals is the Chuitna coal project, on the west side of Cook Inlet. The mine is planned by PacRim Coal, the owner of coal leases on state-owned lands. Dan Graham, manager of the project, told the Alaska Miners Association convention that the U.S. Army Corps of Engineers expects to have a draft EIS by late April or early May 2016, a milestone in a regulatory process that has taken several years. Graham said the Corps recently completed its internal review of a draft of the document, an important step, and has turned the draft over to other federal and state agencies that are cooperating in the EIS. “We also received our first permit Sept. 25, a minor air quality permit from the state,” Graham told the conference. If the Chuitna project receives final regulatory approval and is approved by its owners for development, construction would require two to three years and the mine itself would have a 25-year production life, Graham said. It is likely that would be extended by new resource additions, which is common with mines. Chuitna has been in the news recently because of an active opposition campaign by environmental groups who protest the company’s plan to mine through a creek that is salmon habitat. Graham said the company plans to create alternative habitat and in any event to restore the habitat along the creek when mining is complete, a procedure that has been used elsewhere in Alaska in disturbed areas. Also, PacRim can work with a decision by the state Department of Natural Resources to award a water rights application to a nongovernmental organization in a lower area of creek outside the mine area, Graham said. The principle of the DNR’s decision, the first award of water rights to an entity other than a government agency, is disturbing as a precedent, he said, but PacRim will ensure that adequate water is flowing through the lower part of the creek. The Chuitna project has had a long and tortured history and not all of the problems and delays can be laid at the feet of government agencies and opposition groups, Graham told the miners. Some of the blame is shared by the company, he said, which made several changes in scope and design. While these are overall improvements, the result has been delays and complications for the regulators, he said. “There are lessons to be learned from this,” Graham said, The state coal leases were originally awarded in 1968 to the Wilson-Bass-Hunt group, who were exploring in Alaska at the time. In the 1980s the Bass-Hunt group, which now owns PacRim Coal (Wilson has dropped out) entered a joint-venture with Diamond-Shamrock. The groups did substantial development work for a large surface coal mine. Major permits were granted in 1987 and an environmental impact statement was approved in 1990. However, the Pacific coal market had meanwhile slumped. Diamond-Shamrock exited the project and Bass-Hunt regrouped to continue working. There were changes in the project design and a relocation of a proposed port, all which meant changes to the permit applications. A major event occurred in 2010, however, when the U.S. Army Corps of Engineers took over as lead agency on a new EIS effort, replacing the Environmental Protection Agency. That was in the ninth year of planning under the revamped development plan, Graham said, and it also meant the Corps had to gear itself up to supervise a major Alaska mining project, which it had previously not done. “We had a situation where we were working with two different lead agencies, and over nine years there were 21 changes in key personnel associated with the project,” Graham said. It took some time, but the Corps rose to the challenge. “They scrambled to get up to speed on coal mine permitting. They were able to bring in specialists from other coal-mining states and to send Alaska personnel outside for training,” he said. The draft EIS is now in its final stages. Long lead times Donlin Gold has had an incubation period almost as long. The mid-Kuskokwim has been a historic placer mining area, which meant that explorers knew it was a good place to look for gold, mainly the lode gold sources of the placers. The gold prospect at Donlin Creek was actually discovered in the 1970s by prospecting crews working with Calista Corp., which had just selected lands under its Alaska Native Claims Settlement Act entitlements. After gold was found, Calista worked to get a mining company interested and after several unsuccessful attempts succeeded in attracting Placer Dome, a mid-sized mining company, for a more extensive exploration. Exploration drilling began in the 1980s and a very large gold resource was defined. However, a plunge in gold prices caused the company to suspend exploration. A small “junior” exploration company, NovaGold Resources, stepped in with a plan to invest and continue exploration in return for a share of the project. Placer Dome accepted, and NovaGold’s work resulted in more gold being located. Eventually the smaller company earned a 50 percent share. Meanwhile, in 2006, Barrick Gold, a major mining company, acquired Placer Dome and took over as operator and as NovaGold’s partner. Barrick poured in more funds for exploration and in 2006 and 2007, at the peak of exploration, the project was spending $2 million a week, Fueg told the AMA. Local hiring and contracting was a priority and even in its exploration phase the project became an economic stimulus for villages in the region. The engineering and design efforts were substantial and an initial capital cost estimate of $4 billion grew to $6.7 billion as the project scope changed, including the addition of a 314-mile 14-inch pipeline from Southcentral Alaska that would bring natural gas to the project. Energy costs were always a major concern and the project team investigated alternatives like wind and peat-fueled power generation along with barging large volumes of diesel up the Kuskokwim River. Finally the gas pipeline was decided on as the most practical alternative. Livengood Another big mine project is making progress, although it has been under the radar for a while. This is International Tower Hills’ Livengood gold project, a potential large surface gold mine on the Elliot Highway 70 miles north of Fairbanks. There are 15 million ounces of measured-and-indicated gold resources, a category in which mining companies have a great deal of confidence, and another 4 million ounces of inferred gold resources, where further exploration is needed. “We are one of North America’s largest known, undeveloped gold resources, and we’re right on a paved, all-weather highway,” said ITH President Tom Irwin. Irwin is a mining veteran who led the development of the Fort Knox mine, and who is also a former state Natural Resources commissioner. If it were developed the Livengood mine would be similar to the Fort Knox gold mine also near Fairbanks but larger, Irwin said. ITH is reworking a plan for a mine the company developed in 2013 but which proved too expensive for current gold prices. The cost estimate was in the range of $2.8 billion to $2.9 billion for a mine that would process 100,000 tons of ore per day. The project team went back to the drawing boards and is now reworking the plan to fit a lower gold price environment. “We’re looking at everything, the ore body, our mining procedure, water management and tailing disposal, and a one-stage as well as two-stage mill. We’re looking at how to optimize value,” Irwin said. Among two areas of focus in the new planning, Irwin said, is a possible acceleration of processing of higher-grade ore, leaving lower-grades until later, a plan also followed at Fort Knox in its initial production. Another area of scrutiny is how to manage water most efficiently and minimize its on-site storage, which would reduce capital costs as well as environmental risks. Energy is a major cost for the mine and ITH is still looking at two options, purchasing power from Golden Valley Electric Association, the Interior power cooperative, or generating power at the mine. If a North Slope natural gas pipeline is built it would pass nearby, and could possibly supply the mine with gas. Meanwhile, metallurgical testing and engineering is still underway to find an optimal mine process, Irwin said. What may emerge is a somewhat smaller, more efficient mine that could be profitable even at today’s gold prices, he said. ITH expects to release its revised mine plan in the first quarter of 2016, Irwin said. Tim Bradner can be reached at [email protected]


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