Tim Bradner

State pessimistic about gasline session

PALMER — The president of the state-own gas development corporation told state legislators Sept. 9 that Gov. Bill Walker is unlikely to call a special legislative session to ratify Alaska LNG Project agreements unless progress is made quickly on several key issues. Walker must issue a call for a special session 30 days in advance and the clock is ticking on that deadline for a special session in mid-to-late October, which had been the governor’s hope. No agreement on the key outstanding issues were announced as of Sept. 15. In a gloomy assessment of the negotiations, Dan Fauske, CEO of the state-owned Alaska Gasline Development Corp, told a combined meeting of the House and Senate Resources committes that, “The state (negotiating) team is very concerned about the lack of progress on many of the key commercial and fiscal issues.” The two committees met to hear a scheduled quarterly update on the big gas project from the Alaska LNG Project management team as well as the North Slope producers and state officials who are now engaged in negotiations on the needed agreement for the project. Fauske read a prepared statement to the legislators. “The process we are currently involved in assumes that all parties are equally motivated in getting a project built as quickly as possible within reasonable engineering and design constraints,” he said. “This may have been an unreasonable assumption given the different alternatives and economic considerations of each party. In the state gas team’s opinion, the progression (of negotiations on agreements) will not allow them to be completed in time for a special session this fall.” Industry members of the LNG management team, who were sitting at the table alongside Fauske for the briefing, had not seen the administration’s statement or been made aware of its tone prior to Fauske reading it to the legislators. Fauske said he had been asked to keep the statement confidential until the meeting. Key unresolved issues were identified: Negotiations on a critical “gas balancing,” which assures gas supply to the LNG project if there is a production upset, “are at a virtual standstill with little progress amongst all parties having been made the last several months,” Fauske said. Darren Meznaarich, a ConocoPhillips manager representing his company on the gas team, said the gas supply agreement is critical to his company’s participation. “A tax stability agreement, historically referred to as a fiscal agreement, has yet to be agreed, and there is little common ground between the parties,” Fauske told the legislators. The companies and the state are now in agreement that an amendment to the state constitution is needed to allow the fiscal agreement to be legal. The amendment must be approved by a two-thirds legislative vote in a special session or the 2016 regular session if it is to be placed before voters in the 2016 November general election, as the Constitution requires. Before the constitutional amendment can be considered by legislators, an agreement on the fiscal terms is needed. If the November 2016 election is missed the next time it can be moved will be November 2018, which effectively delays Alaska LNG for two years. Two other items unresolved include a “withdrawn parties” agreement that would allow the project to proceed, “without interruption or delay” if one party fails to agree to move forward, has yet to be reached, Fauske said. The other item important to the state, an agreement on project “milestones,” involving a firm schedule, is also not settled, Fauske said. Two legislators on the Senate committee, Sen. Cathy Giessel, R-Anchorage, who co-chaired the meeting, and Sen. Anna MacKinnon, R-Eagle River, said blame for lack of progress isn’t entirely industry’s fault. The state administration has failed to show progress on two key matters that are entirely within the state’s control, Giessel said. One is a formal decision by the state to take its royalty and taxes on gas “in kind,” or in the form of gas, she said. A second, pointed out by MacKinnon, is a “Payment-in-Lieu-of-Tax,” or PILT, agreement with municipalities to cover property taxes on the big project. MacKinnon said the PILT was to have been completed earlier this summer. Meznarich, of ConocoPhillips, said the delayed “RIK” (royalty-in-kind) decision by the Department of Natural Resources has been made complicated because it requires certain commercial agreements to have been made among the producers, and those are still being worked out. On the PILT, Fauske said that conceptual agreement on a plan for property taxes has been reached between the administration and the companies, who are the taxpayers, but details on it cannot be released until it is reviewed by the affected local governments who are members of a municipal advisory group to the project. The group is scheduled to meet with municipal officials Sept. 23 in Fairbanks and if they approve, the details will be released, Fauske said. The PILT deal will include a structure for construction impact payments to municipalities, a matter of particular importance to the Kenai Peninsula Borough where the large LNG plant will be constructed. Legislators also scolded the administration over frequent changes in the leadership of the negotiations. Rep. Mike Hawker, R-Anchorage, said he has asked for an organization chart of the state negotiating team to show who is responsible for what and has never received one. Giessel said her last knowledge of the state’s leader in the negotiations was Deputy Natural Resources Commissioner Marty Rutherford. Rutherford, who was at the table with Fauske and producer company officials, said Walker asked her to step aside from that role last March. Walker then appointed Audie Setters, a retired Chevron Corp. executive with substantial LNG experience, as lead negotiator. In a June interview the governor said he wanted someone with more LNG experience heading the team. However, the legislators were told Sept. 9 that Rigdon Boykin, an attorney from South Caroline who is an old confidante of the governor’s, is now leading the negotiations, although Setters is also involved along with Rutherford and Donna Keppers, Deputy Commissioner of the Department of Revenue. At the hearing Hawker asked if Boykin had ever negotiated large LNG projects and Boykin, who stepped to the table, acknowledged that he had not, although he has been involved in negotiations on large electrical-generation projects. Boykin worked with Walker earlier when the governor headed the Alaska Gasline Port Authority, a Valdez municipal group working on a gas project.

Courts allow Medicaid expansion to proceed

State officials processed 356 new applications for Medicaid Sept. 1, the first day of an expansion of the program, and another 27 individuals were approved for health care under the expansion. “It was a very good day, with a lot of hard work by many folks, especially in the field. We also saw a significant increase in phone volume at 5 p.m. directly related to Medicaid expansion inquiries,” said Dawnell Smith, spokeswoman for the Department of Health and Social Services. About 40,000 Alaskans became newly eligible for Medicaid Sept. 1 after the Alaska Supreme Court acted a day earlier, refusing to temporarily block the state from expanding the health care program. Jeremiah Campbell, a spokesman for Republican leaders in the state House, said a lawsuit filed to stop the expansion will continue in court, however. More information on the new legal steps will be available later in the week, he said. The court rulings were a big win for Gov. Bill Walker, however, who made commitments to expand Medicaid when running for office last year and then expanded the program administratively earlier this summer after the Legislature refused to pass a bill the governor introduced, although Walker had initially proposed an administrative expansion through his operating budget. The governor praised the Supreme Court ruling, which followed a Superior Court’s refusal to issue a temporary restraining order that Republican state legislators were seeking. “The ruling brings final assurance that thousands of working Alaskans will have access to health care. Medicaid expansion will save the state more than $100 million over the first six years, and save Alaskan lives,” Walker said in a statement. The governor also committed, in the statement, to working with the Legislature on reforms to the program. The Legislative Council, acting on behalf of lawmakers, sued to stop expansion. The council, comprised of House and Senate legislators, voted 10-1 in August to sue Walker over his plans. Walker has said nearly 20,000 working Alaskans will have access to health care under expansion. State-commissioned estimates released earlier this year indicate that nearly 42,000 Alaskans would be eligible for coverage under expanded Medicaid the first year and about 20,000 would enroll. Evergreen Economics, an Oregon-based health care consulting firm, had made the estimates in a report to the state last February. Indications so far are that Evergreen’s estimates will hold firm for this year, said Sean O’Brien, director of the department’s Division of Public Assistance.  In his decision against a restraining order or injunction Aug. 28, Anchorage Superior Court Judge Frank Pfiffner said the Legislative Council had not presented evidence that there would be irreparable harm, one of the conditions for a restraining order, if the expansion were allowed to begin Sept. 1. Pfiffner was also not convinced that the plaintiff legislators have a good chance of ultimately prevailing in the lawsuit, which is another condition for a restraining order. In a court hearing Aug. 27 Pfiffner said, “In several legal opinions the Legislature’s own attorneys told the Legislative Council that it is likely to lose this case.” The Legislative Council opinions actually said the matter was unclear. The legal issue is an interpretation of a U.S. Supreme Court decision as to whether the expansion is an “option” for the state, under which legislative approval is needed, or whether it is mandatory under the federal Affordable Care Act, in which case Walker can do the expansion administratively. On the question of harm, state Department of Law attorneys challenged the plaintiffs that expanding Medicaid, and then voiding the expansion if the case is ultimately lost, constitutes harm. “There has been no showing that there will be harm done,” by the expansion, said Dario Borgheson, an attorney with the Department of Law who was representing the Walker administration. “On the contrary, there will be real benefits given to people. Some people will get health care. It might save lives, and the state won’t have to spend money to care, to prison inmates for example, that would be paid by the federal government if the expansion is allowed.” So far, the online portal being used for applications by the Department of Health and Social Services is functioning well, said O’Brien, which handles Medicaid applications. “Our system is fully functioning so applications are being processed,” he said. Meanwhile, $1.5 million was allocated by the Alaska Mental Health Trust Authority to pay the required state 50 percent portion of administrative costs of the expansion, but state officials acknowledged there is no other money available if the current year’s cost exceeds $3 million, which is the state’s $1.5 million and the same amount paid by the federal government. “There is not another pot of funds available,” O’Brien said. However, the funds allocated are expected to cover costs, he said. “The majority of administrative costs are personnel costs to process enrollment applications and payments to providers which have increased staffing. If the enrollment is higher (than expected) we will consider our options for additional administrative or electronic processing efficiencies. We do not anticipate requesting additional funding from the Mental Health Trust.”

Skagway set to embark on $23M Yukon Gateway Project

Skagway will begin work later this year on its long-planned Yukon Gateway Project, a $23 million redevelopment of the historic city’s port and its aging facilities that will broaden Skagway’s role as a transportation “gateway” to Canada’s landlocked, but mineral-rich, Yukon Territory. The long-run plan is a project that would cost about $80 million when fully developed. What’s envisioned now, however, are replacements of docks and shore facilities, a deepening and widening of the port, which is currently constricted, and a cleanup of contamination that has been accumulating for decades from shipments of mine ore concentrates, according to Chad Gubala, the city’s consultant on the project. The contamination has become a real worry. An estimated 80 tons of lead have been found in submerged soils of the port as well as mercury and other contaminants, which now constitute a human health hazard. Contaminated submerged soils will be removed as a part of the port project but a new concern is that there are now indications of new copper contamination and it is most likely seeping from onshore, possibly from land near the state-owned Skagway Ore Terminal. Meanwhile, a pending vote of Skagway citizens on accepting a new uplands lease for the White Pass & Yukon Route Railroad, or WPYR, a historic railway now operated for tourism, could affect the project. The new lease is more compact than the existing lease, will provide higher payments to the city and impose tighter requirements on the company for environmental remediation. There are positives for both the city and WPYR, however. The company’s lease will expire in few years anyway and it will help it with its long-range planning to have the question settled now. But any issue placed before voters is always unpredictable. A special election on the lease is set for Oct. 7. If voters reject the lease the municipality will still be able to go ahead with parts of the project but it would be better under a new lease. The municipality will have direct control sooner of more of the land now controlled by WPYR under the proposed new, smaller lease. Meanwhile, Skagway’s prospects will be brightened with the Yukon Gateway project. When it is finished the aged and structurally-weak docks and wharves will be replaced with modern structures, and the port will be deepened and widened so there will be enough room to simultaneously accommodate two cruise ships, including one of the new supersized vessels built to carry almost 4,000 passengers, and a large industrial ship, like an ore ship or bulk carrier, Gubala said. Modernizing and expanding the port infrastructure will also facilitate expanded year-around general cargo transport service to Yukon, up the Klondike Highway, which will reduce the territory’s current heavy dependence on goods moved long distances by truck up the Alaska Highway from British Columbia and Alberta. “This shift away from high-cost and high-carbon truck transportation will cut user costs, reduce highway reconstruction (in the Yukon) and significantly reduce the use of diesel fuel, thereby lowering carbon and other emissions,” the city said in a statement on the project. Yukon Gateway would also broaden services to Skagway’s two current economic mainstays, tourism and the shipping of ore, but also foster new opportunities building a larger year-around economy if Yukon Territory grows economically. The territory has a strong mining industry, although it is now affected by the commodities slump, as well as good oil and gas prospects. Skagway is Yukon’s traditional outlet to the sea, but its port is now limited, which puts limits on future growth, Gubala said. Skagway itself wants to be less dependent on mining, which is highly cyclical, as well as cruise tourism, which is heavily seasonal, he said. On the project at hand, the municipality will publish a Request for Proposals for demolition and environmental remediation this fall, after the vote on the WPYR lease, with the intention of having work underway by the end of the year on phase one, Gubala said.  Phase one is expected to take a year or year and a half. Phase two will include the harbor widening and deepening, and the dredging planned for that will also remove submerged contaminants, after which reconstruction and expansion of docks and wharves will be done. The project will also put enhanced environmental controls in place for any residual contamination, Gubala said. Bringing more of the uplands under direct municipal control is a benefit of the shrunken railroad lease. This will result in better coordination of subsequent development as well as environmental oversight through a Skagway port authority that will be created following the project. Despite the ambitious goals, however, there are complications for Skagway. One is that geotechnical boring conducted last January discovered unstable submerged soils that will require the injection of sand to improve stability, Gubala said. That will add costs. The second issue that has emerged recently is the indication of contamination in the water of copper and other metals apparently coming from adjacent shorelands, including the Skagway Ore Terminal owned by the Alaska Industrial Development and Export Authority. Bruce Wanstall, with the state Department of Environmental Conservation’s contaminated sites program, said it is too early blame AIDEA or anyone else for the copper contamination, or even that it is from a continuing source. Studies done to date do not trace the actual migration path of the pollution, and more work needs to be done. It would seem logical that the pollution likely came from the ore terminal because copper ores have been loaded on ships since 2006, when shipments of ore from the Yukon expanded, but whether the copper is now leaching from onshore contaminated soil or has been in the offshore soils for years is unknown, Wanstall said. Windblown ore dust could have been the agent causing the migration, as well as contaminated rainwater runoff, he said. Upland site leaseholders as PetroMarine, a bulk fuel operator, have secured DEC permits and have successful mitigation measures in place, Wanstall said, but AIDEA has not secured DEC permits for the ore terminal. The issue is still being discussed, he said.

Injunction sought against unilateral expansion

Superior Court Judge Erin B. Marston must decide by Aug 31 whether to halt the enrollment of new Medicaid recipients under Gov. Bill Walker’s expansion of the program. In a lawsuit filed Aug. 24, the Legislative Council, acting mainly under direction of Republican House and Senate leaders, asked for an injunction blocking the governor’s Sept. 1 start of Medicaid enrollment. Medicaid is a state-federal program that provides health care to low-income Alaskans. Under the current program only low-income women and children and the disabled with incomes at the Alaska-adjusted federal poverty level, are eligible. The services are paid for by the state and federal government on roughly a 50-50 basis. However, the federal Affordable Care Act allows for the program to be expanded to include all individuals under 65 with incomes up to 38 percent above the federal poverty level. Walker campaigned for governor with a promise to expand Medicaid, but Republican legislative leaders blocked legislation allowing the expansion. If the program is expanded it will extend health care coverage to a group of about 40,000 Alaskans, with an estimated 19,000 expected to enroll. Walker ordered an administrative expansion of the program, which he argues he has the authority to do. That prompted legislative leaders to file the lawsuit to block the expansion. Walker argues existing law gives him authority to order the expansion because the federal law makes Medicaid coverage required, or mandatory, for low-income people including those to be newly-covered. Legislators argue with this, saying the expansion is optional, which means that it requires legislative approval. The lawsuit will basically hinge on an interpretation of a U.S. Supreme Court ruling that new people to be enrolled for health care represents an “optional” population or whether the terms of the federal Affordable Care Act make the coverage “mandatory.” If the “optional” interpretation is upheld, Walker must seek legislative approval before expanding Medicaid under current state law. If the expansion is ruled “mandatory,” then legislative approval is not required and Walker’s decision is on secure ground. The question is not clear cut. Legal opinions have been prepared in Alaska, but now that the issue is headed for court a judge will ultimately decide. Two opinions by the state Department of Law say Walker is on secure ground. Two prepared by the Legislature’s attorneys say the governor is probably secure, but that there are uncertainties. Optional vs. mandatory The lawsuit will hinge on a state court’s interpretation of the U.S. Supreme Court’s decision in National Federation of Independent Business v. Sebelius, which struck down requirement that states must expand Medicaid or lose all federal funding, and left the decision up to governors and Legislatures. In making the case that the expansion is “optional”, and requiring legislative approval, State Sen. John Coghill, R-North Pole, said the U.S. Supreme Court, in Sebelius, “declared that the additional group of able-bodied, childless adults is an optional group and that states have a genuine choice as to whether to expand Medicaid to include that population. “That being the case, state statute requires legislative approval for any new additional groups. The governor may not expand unilaterally,” Coghill said. However, Rep. Andy Josephson, D-Anchorage, who is an attorney, says that Sebelius doesn’t say that. “I believe Sen. Coghill is wrong,” he said, citing part of the majority decision where Chief Justice John Roberts described provisions of the federal Affordable Care Act on Medicaid expansion as “required” of states, or mandatory. According to Josephson’s interpretation of the Sebelius decision, the expansion remains mandatory even though the financial penalty was struck down. In only two states — Ohio and Kentucky — have governors expanded Medicaid without legislative approval, and both of those states grant such a power to the executive branch. Josephson said Walker may be on weak legal ground on other parts of his decision to expand Medicaid, such as in the appropriations area, but on “mandatory” or “optional” argument the governor is on firmer ground. There is disagreement on this. Attorneys who filed the lawsuit on behalf of the plaintiffs, the Legislative Council, have selected their own citation of from the Sebelius decision and Justice Roberts to bolster their case. The decision also refers to states having a “choice” to participate in Medicaid expansion, which argues for the optional interpretation, according to the complaint filed by the Legislative Council. Legislative attorneys, meanwhile, said the issue is not clear cut. In a legal opinion written last Nov. 26, attorney Jean Mischel of the Legislative Affairs Agency’s Division of Legal Services, wrote, “Although the ACA (Affordable Care Act) expressly mandates coverage for newly-eligible individuals (the expansion group) coverage for those individuals is not clearly required of coverage since the penalty (provision of the ACA) has been judicially amended,” by the U.S. Supreme Court. “Therefore, it is unclear whether the newly-eligible individuals would be automatically covered under current state law if the Legislature took no action and if (then Gov.-elect) Walker accepted the federal funding for expansion.” Mischel also explained that, “state law provides that all residents of the state for whom federal law requires coverage are also eligible for coverage in the state. State law also provides for optional coverage for individuals who meet eligibility criteria, including varying income levels and conditions.” Opponents of expansion point to the varying income criteria that can be used for optional groups under Alaska law as reinforcing the claim that the expansion group, which is eligible under an income provision, meets the criteria of an “optional” group, and therefore requiring legislative approval. In its complaint filed Aug. 24, the Legislative Council also cited a March 6 letter from U.S. Heath and Human Services Secretary Sylvia Burwell to Walker that stated, “There is no requirement for the state to maintain coverage for the new adult group.” Arguments that the court intended to leave intact the mandatory aspects of the ACA for the expansion population point to the fact that Sebelius, as it related to Medicaid expansion, dealt mainly with funding issues. The decision struck down the provision of the ACA that cuts all funding for Medicaid for states that did not expand Medicaid. The decision on the Alaska lawsuit will rest mainly on how Alaska judges interpret the U.S. Supreme Court decision in Sebelius, and whether can be interpreted that expansion is optional or mandatory. A second legislative legal opinion, by attorney Megan Wallace, written July 31, reaches similar conclusions to Mischel on the main points of the dispute, that there is some uncertainty as to how Sebelius can be interpreted, but it also supports Walker’s argument that he has authority under existing law and under language of the 2016 fiscal year budget act approved by legislators to accept new federal money. In his opinion Wallace quoted existing state law, which “authorizes the governor to increase…an appropriation item based on additional federal or other program receipts not specifically appropriated by the full Legislature.” The statute requires the governor to submit his plan to receive new federal Medicaid funds to the Legislative Budget and Audit Committee, which Walker has done in this case. This is a frequent occurrence, in practice, and the Legislature typically includes language in the budget act to allow receipt and use of new federal funds, and did so in the fiscal year 2016 budget bill, the opinion said. Wallace noted in his opinion, however, that the procedure only allows an increase of an existing appropriation by legislators, not a new appropriation. A question,  is whether the existing appropriation item in the budget, for “Medicaid services,” is broad enough to meet the criteria of expanding an “existing” program, or whether receiving federal funds for the additional Medicaid expansion population constitutes a “new” expansion, requiring a approved appropriation. This will be an issue before the courts, too. The budget also included language that stated: “no money appropriated in this appropriation may be expended for services to persons” who are eligible under the expanded language of the Affordable Care Act. What may weigh into the court’s decision on this is a previous 2001 state Supreme Court decision, Legislative Council vs. Knowles, dealt with a somewhat similar issue regarding a change in budget language for an appropriation to the Alaska Seafood Marketing Institute. Under his veto authority, “The governor can delete and take away (funding), but the Constitution does not give the governor power to add or divert for other purposes the appropriations enacted by the Legislature,” the court’s decision in that case said. In the Legislature’s lawsuit the Legislative Council argues that existing statutes and the state Constitution give the Legislature the sole authority to decide who is eligible under the state-run Medicaid program, and under a subsection of the statute sets out how the Legislature approves the additions of optional groups. The letter to Walker from Burwell stated that, “Alaska may take up the Medicaid coverage expansion, and then later drop it at state option.” Further, the governor’s own bill introduced to expand Medicaid, introduced on March 17 after legislators asked the governor to introduce a bill, added the Medicaid expansion population as an “optional group” under the existing state statute. The Legislature did not pass the bill, however. Reappropriation or transfer? The Legislative Council also challenged the governor’s use of $1.6 million from the Alaska Mental Health Trust Authority to help cover implementation costs of the Medicaid expansion. Appropriations to the authority must be used to benefit mental health recipients, the complaint said, and its reallocation to the health and social services department to pay administrative costs for Medicaid expansion amounts to a reappropriation, which only the Legislature can do, the complaint said. Jeff Jesse, executive director of the Mental Health Trust Authority, of MHTA, said the authority’s budget procedures allow this kind of funding transfer and that similar transfers to other state agencies to support services to mental health clients, including the health and social services department and the Department of Corrections, have been done for years. The Legislature appropriates funds to the trust authority, but the services are actually provided by other agencies, Jesse said, so the authority transfers funds under a “Mental Health Trust Authority Receipt,” or MHTRA, procedure. “Various departments use trust authority funds through MHTRAs under the ‘receipt authority’ given by the Legislature,” to receive federal funds or money from sources other than a general fund appropriation, Jesse said. “It’s just like an agency receiving a federal grant.” The agency follows a procedure to notify the Legislative Budget and Audit Committee of the receipt, similar to the way the committee was notified about the receipt of federal funding for the expansion population. Former Health and Social Services Commissioner Bill Streur, in an affidavit filed to support the Legislative Council’s lawsuit, said, “the purpose of the MHTA trust fund is to provide funding for a comprehensive statewide mental health treatment system. Many beneficiaries of the trust authority system are currently eligible for significant state assistance from other sources. There will be only incidental benefit to the current beneficiaries (of the trust) from expanding Medicaid.” Streur declared that because trust funds ($1.5 million this year) are being diverted to help establish a program that will serve people who do not require mental health treatment, the effect is to drain funds that support service to those who do need that help. Streur also argued that the administrative costs will increase over time — the $1.5 million is just to help the startup — and that the federal law requires states to pay for half of the overhead for enrolling the newly eligible group. Jesse argues with Streur’s point that the money helps people not in need of mental health services. He has long been an ardent supporter of the expansion because state funds to support many services mental health trust beneficiaries need are not available — drug and alcohol counseling for released prisoners, for example — and the new federal money will make them available, reducing the reincarceration rates using the released prisoners example. Also, “the cuts in state funding for many health and social services have made us (the authority) more and more dependent on Medicaid,” Jesse said, so the new federal money will in effect replace state dollars from a treasury under increasing strains.

Large premium increases approved for individual policies

The Alaska Division of Insurance has approved significant 2016 health insurance rate increases for individual and family policies issued by two companies selling health coverage. A much smaller increase of 4 percent was approved for policies covering small groups of 50 to 250. For the individual and family policies, a 2016 increase of 39.6 percent has been approved for Moda Health and a 38.7 percent increase was approved for Premera Blue Cross Blue Shield of Alaska, according to Lori Wing-Heier, the state insurance director. The increases were approved Aug. 25. They apply to only the individuals and family “metallic” policies (referring to the gold, silver and bronze levels of coverage) sold through the federal health insurance exchange established by the federal Affordable Care Act and where federal subsidiaries support the premium costs of some policy-owners. Premera’s costs are mainly from a small group of policyholders with individual and family plans, and Moda has experienced similar results. “Between Jan. 1 and June 30, 2015, we had more than $11.2 million in medical claims generated by only 37 Alaska members on individual (health) plans under the federal Affordable Care Act. This is out of a total of $45 million in claims generated by the entire membership pool,” Premera spokeswoman Melanie Coon said. Premera’s claims costs overall accelerated between the first and second quarter. In the first quarter, between Jan. 1 and March 30, Premera incurred costs of  $4.1 million in claims by the 37, of a total of $10.6 million in total claims by individual and family policy owners. In 2014, Premera lost $9 million serving the individual policyholders, and a similar loss of $9 million was projected for 2015 based on claims cost data in the first three months. It is too early to update the estimated 2016 loss based on recent cost data, Coon said. “The bottom line is that we see another year of significant losses. It’s not getting any better,” she said. “We have seen a significant influx of new members with exceptionally high medical costs buying plans. These members have significant medical conditions such as chronic heart failure, various types of cancer and other high cost conditions. That’s having a unique impact given the size of Alaska’s individual market.” A driving factor is the small size of the pool, so that high costs for a small number of people have substantial impacts on losses because there are fewer policy owners overall paying into the pool. Premera has not seen such increases for its Alaska group policies, where there are more enrolled people over which costs can be spread, Coon said. Also, the individual and family insurance markets in Washington and Oregion, where Premera also markets, have not seen large increases because there are larger numbers of people in the pools. The rate increases for 2016 are based on the 2014 cost and loss data and the first six months of 2015, Wing-Heier said. Costs escalated sharply for individual and family policies as an apparent result of Alaskans with significant health problems dropping out of the state-established ACHIA insurance pool, where premiums are high, and purchasing individual and family metallic plans through the federal exchange, where premiums are much lower because of federal subsidies, Wing-Heier said. The ACHIA (Alaska Comprehensive Health Insurance Association) program, which has operated for several years, involves “re-insurance,” where Alaskans with medical complications who could not get ordinary insurance could join the ACHIA pool. Insurance coverage cannot be denied and costs are subsidized through fees paid by all companies selling health insurance in the state. The premiums paid by the insured individuals were high but at least insurance was made available, Wing-Heier said. When the Affordable Care Act exchanges went into operation in 2014 many of the individuals in ACHIA opted to drop out and purchase coverage through the exchange, where it also could not be denied under the new federal law. The migration from ACHIA to the ACA metallic plans seems validated by the reductions of people covered under ACHIA, which have dropped from 542 individuals in 2012 to 211 who are currently covered, Wing-Heier said.

Slope output dips on scheduled maintenance

North Slope production dipped sharply in late August due to production facility and pipeline maintenance temporary shutdowns, but is now returning to more normal mid-summer levels. In the large Prudhoe Bay field, which accounts for about half of total Slope oil production, Gathering Station 1 and Flow Station 1 in the field have been down for scheduled maintenance “turnarounds,” BP spokeswoman Dawn Patience said. Work has been underway since June and will continue to mid-September, she said. BP is the operator of the field. Prudhoe production dropped below typical summer output of 250,000 barrels per day in mid-August and dipped to 36,313 barrels on Aug. 21, according to state Department of Revenue production data. “The turnaround times vary but are staggered to take advantage of other temporary facility or pipeline shutdowns and the milder Arctic climate,” during summer, Patience said. “These temporary facility shutdowns allow workers to safely work around pipes, flares and other equipment. The work is planned to minimize production impacts as much as possible.” In another development, ConocoPhillips spokeswoman Natalie Lowman said the Alpine field was shut down for maintenance Aug. 20 and that production resumed Aug. 25. Alpine production typically averages 45,000 barrels per day in summer but dropped to 1,275 barrels Aug. 21 and one barrel per day on Aug. 22 and 23, with output ramping up to 9,503 barrels Aug. 24. The facility work was also scheduled to coincide with a 36-hour maintenance shutdown planned for the Trans-Alaska Pipeline System on Aug. 21 and 22. The TAPS shutdown is the last long-duration suspension of operations for the summer, according to Alyeska spokeswoman Michelle Egan. Short-term suspensions are planned but those will not affect production, she said. Production overall through Aug. 24 of 413,111 barrels per day is up from the August 2014 average of 395,728 barrels per day, the Revenue Department data indicates. Summer production on the Slope is typically lower than winter output because production facilities perform somewhat less efficiently in warmer temperatures in summer and at peak efficiency, and output, during the cold winter season.

Shell exploration drilling advances at Burger J

Shell is keeping a tight lid on information about its Chukchi Sea drilling for now. The semi-submersible Polar Explorer is at work drilling the first well in Shell’s 2015 program, Burger J, and a weekly report issued Aug. 25 by the U.S. Bureau of Safety and Environmental Enforcement, or BSEE, indicated that a shallow casing string has been installed and cemented into place on the well. This is an initial “string” of casing that is typically installed once the “mud-line cellar” excavation is completed, a step Shell reported earlier. “Casing” refers to heavy steel pipe installed in the well through which the actual drilling tools are operated and drilling “mud,” or fluid, is circulated to keep up pressures at the bottom and to remove rock cuttings from drilling. The casing is cemented into the formation to add strength to the well, which increases safety. As the Polar Pioneer works, a second drill vessel, the Noble Discoverer, is moored nearby at a second well location, Burger V. Federal rules require two drill ships to be in the vicinity in case a problem occurs on a well and assistance to the rig drilling the well is required. Rules also prohibit the second rig, in this case the Noble Discoverer, from drilling while the first rig, the Polar Pioneer is operating. Rigs operating simultaneously in the Chuchi Sea must be at least 15 miles apart, to minimize noise effects on marine mammals and other wildlife, under U.S. Fish and Wildlife Service regulations. Shell has applied for permission to drill up to five exploration wells in its initial Beaufort Sea program but only two wells, Burger J and Burger V, would be drilled this year, under the approvals that have been given. Shell drilled a partly-complete exploration well in 2012, Burger A, but chose not to return to that specific location this year. The Burger prospect is a more-or-less confirmed discovery about 60 miles off the northwest Alaska coast. Shell drilled the first wells there in 1990 and 1991 and made the initial discovery, but at the time it was believed to me mainly gas and, although seemingly large, uneconomic in such a remote location and with no gas pipeline likely. Shell returned in recent years, did a reevaluation with modern seismic and other exploration tools, and bid to reacquire the leases at Burger in the federal outer continental lease sale held in 2008. It is still not known if there is also significant oil at Burger in addition to gas, and if so whether there is enough to justify the huge costs of constructing offshore production facilities, 60 miles of pipelines to shore and more pipeline across the National Petroleum Reserve-Alaska to the Trans-Alaska Pipeline System. However, Shell and federal officials have high hopes that significant quantities of oil and gas can eventually be found and developed in the Chukchi Sea. ConocoPhillips, Statoil and Repsol also acquired acreage but Shell has taken the lead in exploration.

Cooperate, don't lead on AK LNG, says economist

A leading U.S. economist says a large natural gas pipeline project is vital to the state’s economic future and that the state should cooperate with experienced large companies in developing the project rather than attempting a plan for the state to lead the project. The Alaska LNG Project could diversify the state’s revenue sources and strengthen its finances, said Margo Thorning, chief economist for the American Council for Capital Formation, a Washington, D.C.-based think tank, in a briefing following the Aug. 12 release of a white paper by the council on liquefied natural gas export projects. “Alaska needs to have more eggs in its basket than oil, and the forecasts for oil price recovery are not rosy,” Thorning said in the briefing. She cited a recent forecast by the World Bank that oil prices could remain in the $70 per barrel range, in real prices, through 2025. “Who knows how long prices will stay at current levels, which are below $60 per barrel?” she asked. In the paper, Thorning wrote, “While the oil reserves are still ample, they are finite. Extracting the remaining North Slope oil is likely to be more difficult and expensive in the coming years. This raises questions about how long Alaska can rely on petroleum as its chief source of revenue. “Ten years from now it is possible that technologies, such as gas injection, could begin to reach the upper limits of their ability to extract oil from Prudhoe Bay. The field has already yielded far more oil than was expected when it was discovered in 1967.” In the long run, having a major gas project will give the state something other than oil as a major revenue source, she said. Gas production will also help support extraction of the remaining oil in the North Slope’s producing fields and spur exploration for gas, which will ultimately result in more oil discoveries, too. Thorning also had a warning in her paper, however. Large energy projects led by governments have a history of failure. Alaska’s project, which is the largest infrastructure project in North America, is best left to the private sector to lead, she said. However, discussions within the state administration to have the state take a larger, even lead, role in the project could raise new uncertainties. Under a plan previously agreed to with major North Slope producers, Alaska would have a 25 percent share of the Alaska LNG Project with BP Exploration, ConocoPhillips and ExxonMobil having similar, almost equal shares, but with industry leading the project. The plan also includes TransCanada, an experienced pipeline company, as the state’s partner in its 25 percent share. Gov. Bill Walker would like to increase the state’s share, possibly to as much as 51 percent, so that it would have a larger role in managing the project. Earlier this year Walker also proposed increasing the scale of a small state-led backup pipeline plan to one that could compete with Alaska LNG Project, but the Legislature refused to provide money for this. Thorning suggested that the state administration’s desire for more control could raise new uncertainties and might damage the project, currently estimated to cost between $45 billion to $65 billion to build. “State-run energy projects are not very successful,” Thorning said in a briefing on the council’s paper. “There is a tendency for governments to under-invest. It is preferable to have the private sector managing the project if there are companies available who are willing to put shareholders’ dollars at risk. Why would you risk public dollars when private companies are willing to put their capital at risk?” Uncertainty over the administration’s position on the gas project is now raising new questions, she wrote in the council’s paper, “The Global Race for Liquefied Natural Gas: Commercializing Alaska’s Natural Gas.” “The administration announced plans (last spring) to create a team to review the Alaska LNG Project for 45 days. As of this report the administration has not yet released any information about the review’s conclusions,” Thorning wrote in the paper. The 45-day deadline has long expired and the uncertainties caused by lack of information on the review has increased the odds that many state legislators will engage the administration in a “tug-of-war” over needs for the project laid out in a Heads of Agreement signed between the companies and the state and endorsed by the Legislature in 2014 through Senate Bill 138, Thorning wrote. Uncertainty is the enemy of large infrastructure projects; it could erode big advantages held by the Alaska LNG Project, one of which is that three large, experienced companies are involved that have a history of successfully completing large projects. Academic studies by the Aspen Institute and Stanford University, Thorning wrote, show a strong negative correlation between uncertainty and capital investment by corporations, and that uncertainty raises the cost of “risk premiums” companies will include in their economic and financial analyses of projects. Despite all that, Alaska is well positioned to take advantage of a growing demand for liquefied natural gas in Asian markets, Thorning wrote in the paper. Shipping distances to Asia are closer than Australia and the Persian Gulf, or the U.S. Gulf of Mexico, she noted. However, western Canada is emerging as a potential competitor to Alaska that will enjoy some of the advantages of Alaska, Thorning wrote in her paper. Meanwhile, the state of Alaska will badly need the new revenues and large gas pipeline and LNG export project will provide, as well as the stimulus having a market for natural gas will provide to the existing North Slope oil and gas industry, Thorning wrote. The state’s economy is slowing due mainly to the collapse is oil prices, with almost no job growth seen in 2015 compared with gains of nearly 5,000 jobs per year between 2010 and 2012 when oil prices were high, she wrote. Continued strong oil and gas employment is one bright spot in the state’s economy, with a projected increase of 1.4 percent in 2015, Thorning wrote. That offsets declines in other parts of the workforce, such as government. Also, population growth may have peaked, for now. The latest population estimates, for 2014, show a slight decline from 2013, and it is the first time in 25 years that Alaska’s population showed a decline, however small. “A declining population means fewer workers contributing the state’s Gross Domestic Product,” Thorning wrote. She also cited the aging of the population, and workforce, as shown in Alaska Department of Labor and Workforce Development data.

Doyon Ltd. plans third test well in Nenana Basin for 2016

Despite the slump in crude oil prices an Alaska Native corporation is pushing ahead with a multi-year exploration program in the Nenana Basin in Interior Alaska and will drill a third test well in 2016, Doyon Ltd. CEO Aaron Schutt said Aug. 13. Doyon will drill the Toghotthele No. 1 test well near where two earlier tests were drilled, in a area about 60 miles southwest of Fairbanks. The corporation is the first to conduct a sustained exploration program in large undeveloped basins in the state’s Interior. Commercial oil and gas discoveries in Alaska have been so far made only in Cook Inlet and on the North Slope. The Interior basins were long believed to be mainly gas-prone by state geologists but Doyon’s exploration has confirmed the presence of oil as well as gas in the Nenana Basin, as well as indications of oil as well as gas in the large Yukon Flats basin further north, where Doyon is also exploring. Doyon is drilling the well with its own funds, although the state’s exploration incentive program could provide assistance. The corporation drilled the second well itself, also with the benefit of the incentives, but had partners on the first well. The corporation drilled two wells previously in the Nenana Basin with significant shows of oil and gas. Several seismic programs have also been conducted, the most recent in late 2014, Schutt said. Doyon holds 400,000 acres of state oil and gas leases and owns another 200,000 acres itself. The corporation is one of the largest private landowners in the U.S. with about 12 million acres of surface and subsurface lands, mostly in Interior Alaska. Besides exploring on mainly state-owned lands in the Nenana Basin, Doyon is also exploring on its own lands in the Yukon Flats, a large sedimentary basin along the Yukon River north of Fairbanks. Doyon’s exploration in the Nenana Basin began in 2005. The corporation believes it is now closing in on a target with good prospects. A primary goal of the overall program is oil but the basin is also known to be gas-charged and there are high hopes for a commercial gas deposit might be found at the third well.   “We are excited to begin the next phase of our exploration program,” in the Nenana Basin, Schutt said. “Building on promising results from each of our earlier programs, we have substantially reduced exploration risks to a point that we estimate the chance developable (commercial) gas at one in two, and one in five for oil.” According to a statement issued with the well announcement, “The results (to date) show an active hydrocarbon system throughout the basin with source rocks that produce oil and gas, world-class reservoir rocks, abundant traps, and rock types that should seal oil the traps. “The Nunivak #2 well in 2013, while not commercial, encountered thick sections of natural gas-charged reservoir rocks. Analysis of Nunivak #2 gas also demonstrated the presence of ‘wet’ hydrocarbon fractions including propane.” The “Arctic Fox” drill rig, which is owned and operated by subsidiary Doyon Drilling, will be used to drill the well. Toghotthele No. 1 will be drilled about seven miles west of Nenana and two miles north of the existing Totchaket Road that was built by Doyon for its earlier exploration. New road construction to the new site will be done this winter and the well itself will be drilled in the summer because of the year-around access to the site. Doyon’s prospects are a few miles west of existing major infrastructure like the Parks Highway, the Fairbanks-Anchorage electric intertie and the route of a proposed large diameter natural gas pipeline.

LNG purchase denied after Hilcorp rejects new terms

Alaska Attorney General Craig Richards has rejected the proposed purchase by Harvest Alaska of a small liquefied natural gas plant at Point MacKenzie, and the action is drawing criticism as well as praise. In a July 7 letter to Harvest, a subsidiary of Hilcorp Energy, Richards proposed changes in the LNG sales contract reached in November 2014 with Fairbanks Natural Gas, the existing plant owner that also operates a small gas utility serving about 1,100 business and residential customers in Fairbanks. Hilcorp rejected the proposed changes in a July 17 letter, telling the attorney general it wanted to stick to the original contract terms because the purchase already had a small profit margin. Based on that, Richards informed Harvest in an Aug. 3 letter that he would not approve the sale of the plant. In an Aug. 6 statement, Hilcorp said it was disappointed in the attorney general’s decision. “We believe the purchase and sale agreement originally struck in November 2014 (with Fairbanks Natural Gas) was both reasonable and fair,” Harvest Alaska President Sean Kolassa said. Assistant Attorney General Ed Sniffen, who led the negotiations with Harvest, said the state’s proposals were aimed at protecting Interior consumers who would be paying for the LNG from the plant. “There was no requirement in the (proposed contract to buy the plant) that Harvest would drop its price for LNG if Cook Inlet gas prices were to decrease. The Fairbanks gas utility would have no other options for gas. They would be stuck at the price,” in the contract, Sniffen said. In the July 7 letter, the state was proposing that some form of pricing index be agreed to, but Harvest wanted to stick to its original contract terms, Sniffen said. Lori Nelson, a spokesperson for Hilcorp Energy, the parent company of Harvest, said the state’s proposal removes any potential gains for the company. “The attorney general suggested terms to place risk on Hilcorp (and Harvest) and to remove any performance incentive should we execute well and improve plant efficiency,” Nelson said in a statement. However, Fairbanks North Star Borough Mayor Luke Hopkins supports the attorney general’s position. “We’re very satisfied with the decision. It protects Fairbanks ratepayers,” Hopkins said in an interview. The mayor is unhappy with other aspects, he said, mainly in that the future of the plant, which would supply energy to the Interior, is in ownership limbo. The plant is now owned by Pentex, the parent of Interior gas utility Fairbanks Natural Gas Co. The Alaska Industrial Development and Export Authority, the state economic development corporation, has approved a $53-million purchase of Pentex and when the sale goes through the LNG plant, operated under subsidiary Titan, would belong to the state corporation. “It will be interesting to see what AIDEA does with this,” Hopkins said. Many in the state’s business community are weighing in on the side of Hilcorp and Harvest, however. Alaska State Chamber president Rachael Petro said her organization, “believes it unwise to use scarce state funds (through AIDEA) to invest in projects when private sector investment is available. “We are discouraged that the attorney general rejected private sector investment in the Titan LNG plant particularly from a business that has a successful track record. Hilcorp has built a solid, credible and successful track record in Alaska through its Cook Inlet and North Slope investments.” AIDEA’s board of directors approved a $53-million purchase of Pentex in order to supply natural gas to the Interior after a previous attempt tied to North Slope gas turned out to be uneconomic. The sticking point between the state and Harvest Alaska appears to have been Richards’ proposal that Harvest essentially adopt a “cost-based pricing” system. In the July 7 letter from the state to Harvest, state attorneys wrote, “We are considering whether Harvest should be required to develop a price for processing natural gas into LNG for expansion capacity, and offer processing services at this price to AIDEA and other Cook Inlet gas producers. “This processing or tolling fee would allow AIDEA to negotiate with other gas producers for its supply on LNG in the event that it would like to expand beyond the base volumes under an LNG supply contract. “Separating out the processing fee will allow the utilization of a market index, as discussed above, for developing a pricing formula that considers the cost of gas, cost of processing and the cost of transportation. Calculating a processing fee can be done using a cost analysis from the previous RCA (Regulatory Commission of Alaska) dockets.” The Harvest contract agreed to by Fairbanks Natural Gas set a price that would be a ceiling for the LNG supplied under that 10-year contract, but the attorney general also proposed a mechanism for periodic downward adjustments to the price that reflected any drop in Cook Inlet gas prices. The attorney general also proposed that Harvest divest the transportation component — the LNG trailers and trucks that carry liquefied gas to Fairbanks — so that LNG would be sold at the gate of the plant. Harvest wrote July 17 that it objected to the state’s proposal to base periodic downward adjustments on a Cook Inlet gas price index that would be part of a cost-based pricing system, and also said its existing proposals allowed for downward price adjustments, regardless of operating costs, “should LNG be offered at a more attractive price from credible source,” the company wrote in its letter. “Because of the substantial risks associated with finding and developing gas reserves, the operation costs of operating the plant and transporting LNG, and the slim margin already incorporated in the deal, we simply cannot accept the additional market risk.” Hilcorp has become the dominant natural gas player in Cook Inlet supplying Southcentral utilities after acquiring the former assets of Chevron and Marathon in 2012 and 2013, respectively. Sniffen said Hilcorp’s strong position in Cook Inlet gas production raised anti-trust concerns over the LNG plant purchase. “Harvest would be the only plant supplying the gas utilities in Fairbanks, unless Fairbanks can find other sources of supply,” Sniffen said. The ConocoPhillips LNG plant would be an unlikely competitor, he said, because of the longer trucking distances from Nikiski or the costs of moving LNG containers by barge to Port MacKenzie. A possible North Slope gas pipeline is at least 10 years away from operations, if it proceeds. The state’s goal was to put the Fairbanks utilities in a position to take advantage if more favorable gas supply conditions develop in Cook Inlet, even offered by other producers, and to be able to process the gas in the Harvest plant under a “tolling arrangement,” where the plant owner would charge a processing fee. Doing this, however, would move the plant toward a “cost-based pricing” system similar to what would be required if the plant were subject to utility regulation under the Regulatory Commission of Alaska. “They were not interested in that,” Sniffen said.

Fennica rejoins fleet, Shell seeks to drill for oil

Shell is continuing its drilling program in the Chukchi Sea. The company completed a “mud-line” cellar at its Burger J well location the weekend of Aug. 8, and the ice management vessel Fennica was to arrive on site on Aug. 12, federal agency and company officials said. Without the Fennica and its cargo of a capping-stack device to be deployed in the event of a well blowout, Shell only has permits to work on “top holes,” or the upper part of a well and with no penetration of potential oil-bearing zones. With the Fennica now on site, the company has applied for modifications of its drilling permits so that it can drill deeper after the upper part of the well is finished and a blow-out preventer is installed. Guy Hayes, spokesman for the U.S. Bureau of Safety and Environmental Enforcement’s Alaska region, said no estimate can be given on how long it may take to process Shell’s request for permit modifications. “We’re going through the applications in detail now,” Hayes said. Shell’s semi-submersible drilling vessel Polar Pioneer is working at the Burger J location. Another drill vessel, the Noble Discoverer, a drillship, is moored at a second well location, Burger V, where Shell also hopes to drill this summer. Shell may drill just one well at a time, although the second drillship can be kept nearby and ready to drill when the first vessel finishes a well. Federal rules prohibit simultaneous drilling by drill vessels within 15 miles, and Shell’s planned well locations, for this year, are nine miles apart. The wells are grouped around the Burger discovery made originally by Shell in the early 1990s. In 2012 Shell was able to drill a partly-complete well, Burger “A” at the site of the earlier discovery. Company spokeswoman Meg Baldino has previously said Shell chose not to return to Burger A this season because it believes a better picture of the potential reservoir can be gained by drilling at nearby locations identified as Burger J and V in the company’s drill plan. The Fennica was delayed arriving in the Chukchi Sea when it developed a hull crack after striking a previously uncharted obstacle on departing Dutch Harbor July 3. The vessel was sent to a Portland, Ore., shipyard for repairs and then returned to Alaska waters. Shell has permits to drill two wells. The company can operate in the Chukchi Sea into the fall, most likely late September. “Our plan is to make as much use of the time that we have in theatre before the ice arrives in (fall) 2015. Whatever we don’t accomplish in the summer ahead we are fully prepared to finish in 2016,” Baldino said in the statement. Shell’s hopes are high for a significant discovery in the Chukchi Sea after having spent more than $6 billion since the leases were acquired in a federal Outer Continental Shelf lease sale in 2008. ConocoPhillips, Statoil and Repsol also acquired leases in the sale but are letting Shell take the lead in exploration to gauge the ability of federal agencies to work with Arctic OCS exploration. Government geologists believe the Chukchi Sea has prime potential for major oil and gas discoveries and Shell’s first discovery at Burger in the early 1990s was significant but at the time was believed to be mainly a gas discovery. Now, with the benefit of improvements in seismic and other exploration technology the company, and the government, believes there is oil present as well as gas. However, the prospect is 70 miles offshore, requiring a pipeline to shore and construction of an additional 350-mile onshore pipeline across the National Petroleum Reserve–Alaska to the Trans-Alaska Pipeline System.  If a discovery is made at Burger it will have to be large enough to support of the cost of the support platform, long-distance pipelines and other facilities. Shell executives have said that it will be 15 years, at the earliest, before any Chukchi oil can flow into TAPS. At current prices of about $50 per barrel the project would not be economic, but it becomes profitable at prices greater than $70 per barrel.

Attorney General denies LNG plant sale

Alaska Attorney General Craig Richards has rejected the proposed purchase by Harvest Alaska of a small liquefied natural gas plant at Port MacKenzie. In a July 7 letter to Harvest, a subsidiary of Hilcorp Energy, Richards proposed changes in the LNG sales contract reached in November 2014 with Fairbanks Natural Gas, the existing plant owner that also operates a small gas utility serving about 1,100 business and residential customers in Fairbanks. Hilcorp rejected the proposed changes in a July 17 letter, telling the attorney general it wanted to stick to the original contract terms because the purchase already had a small profit margin. Based on that, Richards informed Harvest in an Aug. 3 letter that he would not approve the sale of the plant. In an Aug. 6 statement, Hilcorp said it was disappointed in the attorney general’s decision. “We believe the purchase and sale agreement originally struck in November 2014 (with Fairbanks Natural Gas) was both reasonable and fair,” Harvest Alaska president Sean Kolassa said. The Alaska Industrial Development and Export Authority, or AIDEA, board of directors has approved a $53-million purchase of Pentex, the parent company of Fairbanks Natural Gas Co., in order to supply natural gas to the Interior after a previous attempt tied to North Slope gas turned out to be uneconomic. The sticking point between the state and Harvest Alaska appears to have been Richards’ proposal that Harvest essentially adopt a “cost-based pricing” system. In the July 7 letter from the state to Harvest, state attorneys wrote, “We are considering whether Harvest should be required to develop a price for processing natural gas into LNG for expansion capacity, and offer processing services at this price to AIDEA and other Cook Inlet gas producers. “This processing or tolling fee would allow AIDEA to negotiate with other gas producers for its supply on LNG in the event that it would like to expand beyond the base volumes under an LNG supply contract. “Separating out the processing fee will allow the utilization of a market index, as discussed above, for developing a pricing formula that considers the cost of gas, cost of processing and the cost of transportation. Calculating a processing fee can be done using a cost analysis from the previous RCA (Regulatory Commission of Alaska) dockets.” The Harvest contract agreed to by Fairbanks Natural Gas set a price that would be a ceiling for the LNG supplied under that 10-year contract, but the attorney general also proposed a mechanism for periodic downward adjustments to the price that reflected any drop in Cook Inlet gas prices. The attorney general also proposed that Harvest divest the transportation component — the LNG trailers and trucks that carry liquefied gas to Fairbanks — so that LNG would be sold at the gate of the plant. Harvest wrote July 17 that it objected to the state’s proposal to base periodic downward adjustments on a Cook Inlet gas price index that would be part of a cost-based pricing system, and also said its existing proposals allowed for downward price adjustments, regardless of operating costs, “should LNG be offered at a more attractive price from credible source,” the company wrote in its letter. “Because of the substantial risks associated with finding and developing gas reserves, the operation costs of operating the plant and transporting LNG, and the slim margin already incorporated in the deal, we simply cannot accept the additional market risk.” Hilcorp has become the dominant natural gas player in Cook Inlet supplying Southcentral utilities after acquiring the former assets of Chevron and Marathon in 2012 and 2013, respectively.

Premera files for 4.4% increase in small group plans

Premera Blue Cross Blue Shield, the dominant firm in the state’s health insurance market, has filed for a relatively modest 4.4 percent increase for its small group plans in 2016, which is down from the 5.26 percent increase filed last year for 2015. The 2016 increase is only proposed and has not yet been approved by the state Division of Insurance, Premera spokeswoman Melanie Coon said. The modest increase in small group premiums contracts sharply with a major 37.8 percent increase requested for individual health insurance policies sold through the federal Affordable Care Act exchange for Alaska, but the individual insurance market has been affected by unusual factors, Coon said. Those are mainly high costs experienced when individuals with health problems moving out of the state-sponsored high-risk pool where premiums are subsidized by all insurance companies selling health policies in Alaska, to the “metallic” individual plans (gold, silver, bronze) sold through the Affordable Care Act federal exchange. Premera and other companies selling individual policies are working with the Division of Insurance on possible solutions for those problems, Coon said. Rates for 2016 on Premera’s large groups (100 employees or more) aren’t yet known because those contracts are renewed through the year and are not part of the programs through the ACA exchange. For 2015 to date, the large group increases have averaged 9 percent, Coon said, “but because these don’t use the metallic system it’s not an apples-to-apples comparison to the small groups.” Meanwhile, the modest rise in premiums for group plans this year is a success story that reflects efforts of Alaska employers to control health costs, and that is at least partly related to the aggressive adoption by employers of wellness programs to promote health among their workers, Coon said. Alaska is leading other Pacific Northwest states in the number of employers promoting wellness programs to control health care costs, and in fact may also be leading the nation, she said. Premera Blue Cross and Blue Shield also sells in Washington state and in Oregon under another company in the Premera group, LifeWise Health Plan of Oregon, so the company has good comparative data on employer wellness initiatives and preventative care, Coon said. If that is good news, some not-so-good news is that Alaska is lags in another key health indicator, preventative checkups for adults and vaccinations for children. That is matter of concern to Premera, Coon said, because checkups and vaccinations result in better health and ultimately lower health insurance costs for employers. The company has another campaign underway for that, however, the “Checkup Challenge.” Meanwhile, “Our Alaska market has definitely been the leader for the rest of Premera as it relates to embedded wellness products,” or wellness programs encouraged by employers, Coon said. “Other markets are starting to catch up in engagement (of wellness) but they lag behind Alaska,” she said. That’s because wellness initiatives got started here earlier but also because the program have embraced by Alaska employers who were moving aggressively to control health costs, she said. Premera promotes the programs with its customers and offers discounts of up to 7 percent to 10 percent on group health premium costs depending on how many employees sign up for the wellness initiatives.  Groups that are not affiliated with an Affordable Care Act plan, those sold in an ACA insurance exchange, can get up to a 10 percent discount. Groups in one of the ACA metallic plans can get up to 7 percent off on premiums, she said. “Currently we serve more than 1,000 employer groups in Alaska and approximately 25 percent of these participate in the wellness program,” Coon said. This amounts to about 30 percent of the total number of employees in the plans, she said. Premera is now stepping up its initiatives with a new program launched in July: the “Activity Challenge.” Until now Premera’s wellness programs have been focused more on promoting periodic health screening and checkups, with biometric screening, blood pressure and weight monitoring, but the new initiative is aimed at promoting more physical activity, which has been shown by data to be linked to improved health, Coon said.  “Physical activity is the fastest and most proven way to improve one’s health and health outcomes,” Coon said, and encouraging activity among employees can be a key driver for employers to manage their health costs. To promote this Premera is now offering “Fit Bit Zip” tracking devices to large group employees and the program may eventually expand to small group plans. “These are wearable trackers that clip onto clothing and tracks steps, distance, calories burned and active minutes. People can sync their Fit Bits wirelessly to their computers or smart phones to see all their activity stats and chart their progress,” Coon said. Premera’s “Activity Challenge” campaign allow employees in large group plans to earn points by having their physical activity tracked on the Fit Bit, and logging their activity through “EveryMove,” an online application that compiles the data from the tracking device and can transmit tothe employee’s iPhone or computer. In the contest, “if employees log 750 points in a month, or 30 minutes of activity five times a week, they get to keep the Fit Bit device and earn a $100 Visa gift card,” Coon said. The activity data remains confidential to the participant but EveryMove does keep track for Premera of how many employees are participating and when enough activity has occurred to get the incentive card. The challenge goes through September. On the checkup and vaccination front, the Alaska statistics are not so good, Coon said. Nearly half of employees covered by Premera’s policies in Alaska have had no preventative care in the last two years. Also, 35 percent of children in the 19-month through 35-month age group have not had the recommended vaccinations for children. Because Premera is a the largest insurer in the Alaska market, in health insurance, the statistics on preventative care and vaccinations may reflect the situation across the broader Alaska population, however. To improve this, Premera has launched yet another initiative, its “Checkup Challenge,” also with a gift card incentive, this one a $200 Amazon gift card. A key difference is that this incentive is available to all Alaskans, not just those covered under Premera’s plans, Coon said. However, the card is awarded through a weekly drawing among people who sign up with Premera for the Check Up Challenge.  “You don’t have to be a member of Premera to participate. Even if you’re a nonmember we’ll pay for the gift card,” she said. A plus for Premera is that the campaign gets people to the company’s website, which in the long run could result in more business for the company. Premera is also looking to improve preventative care in Washington and Oregon where it also has a checkup initiative and a gift card, but Alaska is getting special emphasis. “We have not seen the staggering low numbers of checkups and vaccinations in those markets like Alaska,” Coon said.

ConocoPhillips overcoming viscous oil challenges

Producers have wrestled for three decades with technical problems on how to produce a vast resource of “viscous,” or lower-quality, oil on the North Slope. Viscous oil is thicker than conventional crude oil and does not flow as easily. It is not heavy oil, although it is sometimes called that. There is true heavy oil on the Slope too, in the large Ugnu deposit. Viscous oil is somewhat deeper and warmer than Ugnu, and less challenging. The Ugnu heavy oil cannot yet be commercially developed, but ConocoPhillips and BP Exploration Alaska, the two major North Slope producers, are now producing viscous oil. Problems have impeded past plans to increase that production, but the companies are now working through those challenges. Using new techniques, ConocoPhillips plans to increase its production of viscous oil from the West Sak project, a part of the Kuparuk field, from about 15,000 barrels per day to 23,000 barrels per day with an expansion project now underway. The $500 million I-H North East West Sak project, or IH-NEWS, is due to be complete by the end of this year and will add 8,000 barrels per day, at peak production, to the current West Sak viscous oil production of about 15,000 barrels per day, according to Mike Driscoll, ConocoPhillips’ manager for the West Sak expansion. Potential viscous oil resources on the North Slope are large, with an estimated 5.5 billion to 7.4 billion barrels of oil in place in parts of the Kuparuk River, Milne Point and Prudhoe Bay fields where viscous oil is being developed, according to state geologists. Oil-in-place is the oil physically in the reservoir rock. Not included in these estimates are substantial viscous oil resources in the western part of the Kuparuk field that are not now targeted for development because they are shallower and cooler, which makes them more difficult to produce than the resource now being tapped, Driscoll said. While the oil-in-place resource is large, the important number is the estimated recovery, or the amount that can be economically produced from the in-place resource. At West Sak, that is estimated at 15 percent to 20 percent in the parts of West Sak now developed, and which represents the better reservoir areas, Driscoll said. In comparison, oil recovery is much better in conventional fields, typically 40 percent, and even higher in high-quality reservoirs such as Prudhoe Bay, where recovery may eventually exceed 50 percent. Viscous oil is essentially conventional oil that has seeped up to shallower levels compared with the large conventional producing fields on the Slope like the Prudhoe Bay and Kuparuk fields, Driscoll said. Because it is shallower, it is cooler and thus thicker and more difficult to flow, he said. Also, at shallower depths bacterial action has eroded some of the lighter ends of the crude, making it somewhat heavier. West Sak crude is ranked typically at 18 to 20 degrees API while the conventional North Slope oil is higher, with Prudhoe Bay oil ranked about 29 degrees API and oil from the Alpine field in the high 30s. (API is the American Petroleum Institute measurement for how heavy or light the oil is; lower numbers are heavier and higher numbers are lighter.) Producing companies began efforts to produce the viscous oil in the 1980s but those were plagued with difficulties. In 2004, ConocoPhillips and BP announced a West Sak expansion aimed at boosting output to 45,000 barrels per day by 2007. The goal was never reached, however. Output was stuck at about 15,000 barrels per day and has remained there since.  “The sand is the number one problem,” at West Sak, Driscoll said. It breaks loose in the unconsolidated reservoir rock at West Sak and, entering wells, it can damage pumps and other machinery. It is also related to a second problem: how to increase daily production rates of wells while keeping the sand out, he said. Another serious challenge has been waterflood “breakthroughs,” where water breaks a channel through unconsolidated producing sands. These started happening as producers stepped up waterflood injection in efforts to get well-rates up, and as water broke through the loose reservoir rock it diminished and effectively ended the benefits of injecting water to enhance production. “These were not good news events,” said Driscoll. ConocoPhillips addressed this by injecting a polymer into the holes, sealing them. This has been successful. Waterflood breakthroughs, called “Matrix Bypass Events” by ConocoPhillips, have been cut by about a third since the technique was introduced two years ago, Driscoll said. The company also successfully employed a fine-mesh screen inserted into an open hole section of the well that is now reducing sand coming into producing wells. Previous efforts to keep sand out with screens or gravel “packs” also impeded the oil flow. The new screening technique slows and stops sand inflow but does not impede the oil, Driscoll said. In the earlier years ARCO Alaska (now ConocoPhillips) was the most aggressive in experimenting with West Sak viscous oil because of the size of the in-place oil resource is larger in the Kuparuk field. Prior to its merger with Phillips, Conoco, on its own, was able to get production from wells it drilled in Milne Point, a field adjacent to Kuparuk, where the viscous oil is deeper and warmer, which make it easier to flow. In Milne Point and Prudhoe the deposit is called Shrader Bluff but it is the same geologic formation as at West Sak Conoco’s Milne Point wells typically flowed in the range of 250 barrels per day, which were not economic on the North Slope. ARCO had similar rates with its early wells. The well-rate problems were overcome to some extent when ARCO and BP, which purchased Milne Point from Conoco in the early 1990s, began drilling multilateral wells with horizontal production well segments. Multi-lateral wells involve several underground production wells, or legs, drilled off one vertical well to the surface. These allowed the combined flows from several long horizontal production legs to achieve higher per-day rates in the West Sak. Some multilateral wells achieved rates of 3,000 barrels per day, Driscoll said. The wells planned at IH-NEWS will be multilaterals with up to five producing legs. Driscoll hopes 1H-NEWS is only the first increment, and that nearby undeveloped West Sak reservoir sections that can be added, over time. There is also future potential in a large area further to the west in Kuparuk, now called “Western West Sak,” that has large in-place resources but is also shallower and cooler, and with even more challenges because of those factors. But it represents a big opportunity for the future as companies work out technical problems.

BP and ExxonMobil seek more Prudhoe gas

BP and ExxonMobil, two of the three major Prudhoe Bay field owners, have applied to the Alaska Oil and Gas Conservation Commission for an increase in the allowable volume of natural gas that can be produced and sold from the North Slope field. The AOGCC, a quasi-judicial state regulatory commission with oversight of oil and gas production practices, has set a public hearing date of Aug. 27. In 1977, the commission set a limit on Prudhoe Bay gas offtake of 2.7 billion cubic feet of gas per day, but BP and ExxonMobil, citing new reservoir studies, have now asked for permission to increase the rate to 4.1 billion cubic feet per day to supply a planned gas pipeline and LNG export project. By law the AOGCC is required to seek maximum recovery of hydrocarbon fluids and must ensure that too rapid a withdrawal of gas from the Prudhoe reservoir will not result in an unreasonable loss of long-term oil recovery. Prudhoe Bay holds about 24 trillion cubic feet of natural gas in addition to about 12 billion barrels of remaining oil, although not all of the oil can be produced. Prudhoe has already produced about 12.2 billion barrels since operations began in 1977. If the Alaska LNG Project is built, the field will supply the bulk of the gas, at least in the near term, while additional gas will come from the Point Thomson gas field 60 miles east of Prudhoe Bay. A separate application to the AOGCC for gas offtake from the Point Thomson field is expected later. ConocoPhillips, which is also a major lease owner at Prudhoe Bay, was not included in the application made by to the AOGCC by the two other companies. ConocoPhillips spokeswoman Natalie Lowman said her company has been working with BP and ExxonMobil on the offtake issue. “We are not aware they intended to make a unilateral filing,” she said in a statement. Lowman said ConocoPhillips will have more to say on the matter at the AOGCC hearing. BP spokeswoman Dawn Patience said her company could not comment on the matter and that there would be more discussion in the hearing in late August. About 8 billion cubic feet of gas is now produced along with oil at Prudhoe but the majority of that injected back underground to maintain pressure in the reservoir to aid oil production. Natural gas liquids, or NGLs, produced with the gas are also mixed with crude oil and shipped to market in the Trans-Alaska Pipeline System, while other NGLs are used to make a miscible injectant fluid that is used in Enhanced Oil Recovery on the slope. The AOGCC’s concern is that if some of the produced gas, in this case up to half, is shipped to markets via pipeline, there will be less gas injected and less support for pressure in the reservoir. That could result in loss of oil. In their application to the commission, BP and ExxonMobil said the loss of oil recovery would be mitigated by steps including injection of carbon dioxide in an enhanced oil recovery project. Prudhoe Bay gas contains about 12 percent CO2, which must be extracted from gas before it can be shipped by pipeline to an LNG plant planned to be built in southern Alaska. That process will make large quantities of CO2 available on the North Slope to aid oil recovery. In the Aug. 27 hearing, the two producers will present evidence showing that the loss of oil recovery can be minimized. “In accordance with good oil field engineering practices, at various stages of field development the Prudhoe Bay field owners have evaluated the potential effects of Prudhoe Bay major gas sales on oil production and hydrocarbon recovery. Gas production from Prudhoe Bay (to date) has been used for extraction of miscible injectant, manufacture of natural gas liquids, pressure maintenance and enhanced oil recovery,” wrote Dave Lachance, BP’s vice president for reservoir development, in the application. About 75 percent of the 3.5 billion cubic feet/day of gas supply needed for the Alaska LNG Project, or about 2.7 billion cubic feet/day, is expected to come from Prudhoe Bay. About 25 percent of supply for Alaska LNG will from other sources, Lachance wrote in the application. This would be mainly from Point Thomson. About 600 million cubic feet per day will be needed to fuel field operations on the North Slope and for local gas sales to contractors, raising the average daily offtake requirement, including the fuel needs, to 3.3 billion cubic feet per day. However, a contingency must be built in to account for potential interruptions in gas supply from other fields. To include that contingency, BP and ExxonMobil have requested authorization for up to 4.1 billion cubic feet per day to cover shortfalls if they occur, according to BP’s application. Overall, the Alaska LNG Project will result in the production of an additional 3.8 billion barrels of “oil equivalent,” from Prudhoe Bay, the application said. Oil equivalent is a measure of production that reflects crude oil and natural gas together with the gas covered to the equivalent of liquid barrels of the same energy content as oil. One barrel of oil is equal to about 6,000 cubic feet of natural gas. The CO2 injection will play an important part in producing oil that remains in the reservoir, according to BP’s application, In 1979, after it was discovered, Prudhoe Bay was estimated to be able to produce about 9.6 billion barrels of about 23 billion barrels of oil in place in the reservoir rock, but the oil recovery has improved substantially due to a variety of steps including use of the existing gas production for pressure maintenance and to make the miscible injectant for enhanced oil recovery, BP said in the application.

Shell rigs poised to drill in Chukchi prospects

Shell’s two drilling vessels are in the Chukchi Sea and ready to drill, Shell and federal agency sources said July 29. Meanwhile, environmental groups are staging their usual stunts in Portland, Ore., where a Shell-leased ice management vessel was sent for repairs. Shell spokeswoman Meg Baldino said July 29 that both drill vessels are in the Chukchi Sea and that the semi-submersible Polar Pioneer is now connected to its anchor chains at the “Burger J” well location with preparations to drill underway. Meanwhile, the Noble Discoverer, a drillship, is moored at the Burger V well location. A bulletin issued July 28 by the U.S. Bureau of Offshore Energy Enforcement, or BSEE, confirmed the status of the two drillships. “Shell currently has multiple support vessels at the Burger Prospect in the Chukchi Sea and others staged nearby or in transit in preparation for drilling activities,” BSEE said in its update. “The ice management vessel Fennica is being repaired in Oregon.” The Fennica, which is also carrying a “capping stack” needed to control an undersea blowout, was damaged by an uncharted shoal while leaving Dutch Harbor July 3 and has been sent to a Vigor Industries shipyard in Portland for repairs. BSEE has given Shell permission to drill “top holes,” at Burger, or the upper parts of wells that do not penetrate potential oil-bearing formations, until the Fennica gets to the Arctic with the capping stack after its repairs. Shell must also drill just one well at a time, although the second drillship can be kept nearby and ready to drill when the first vessel finishes a well. Federal rules prohibit simultaneous drilling by vessels within 15 miles, and Shell’s planned well locations, for this year, are nine miles apart. Baldino said weather conditions in the drilling area were moderate with some slush ice, but no heavy ice. Shell has been given permission to operate until near the end of the open-water season in the Chukchi, which means it will be able to conduct drilling through August and possibly into September depending on conditions. In Portland, the Associated Press reported that Greenpeace USA activists have rappelled off the city’s tallest bridge and are now dangling in midair in an attempt to block the ice management vessel Fennica from leaving after its repairs are complete. Greenpeace USA director Annie Leonard said the protesters have enough water and food to last for several days and can hoist themselves to allow other marine traffic to pass. Thirteen protesters were dangling from St. Johns Bridge while 13 more were on the bridge itself serving as lookouts, the Associated Press reported. Shell, which won a court injunction barring Greenpeace USA activists from interfering with its rigs and support vessels, stated in a July court filing that it intends to file a motion seeking a contempt order against the activist group from repeatedly violating the injunction. Shell is also seeking reimbursement for attorney fees from Greenpeace related to its responses to several stay motions seeking to lift the injunction, arguing that the group filed them in bad faith with the intention to violate the injunction if it wasn’t granted a stay.

Hilcorp to resume heavy oil tests at Milne Point field

Hilcorp Energy hopes to take a new look at a massive heavy oil accumulation in the Milne Point field of the North Slope, where Hilcorp is the field operator and a 50 percent-owner with partner BP. The company is considering a restart of a test production program from the Ugnu formation that was operated by BP for several years but then suspended in 2013, Hilcorp spokeswoman Lori Nelson confirmed. BP conducted a four-well production test in the Ugnu formation, and achieved a rate of 600 barrels per day in some tests. Two vertical wells and two horizontal test production wells were operated by BP, but Hilcorp is considering resuming the test with one well, Nelson said. The tests were considered a technical success by BP in that new technologies being experimented with, mainly a Cold Heavy Oil Production System, or CHOPS, showed increased daily production rates, but there were also mechanical problems. BP shut down the wells to address those but then never restarted the program. Sources familiar with the program said BP was also shifting its Alaska priorities, and resources, to commercialization of stranded North Slope gas at the time. “We’re very interested but we also have potential conventional oil projects on our plate at Milne Point,” Nelson said. A custom-built grind-and-inject facility in Milne Point, which disposes of waste rock underground, would also have to be restarted for the program, she said. Alaska Natural Resources Commissioner Mark Myers said his agency is pleased at Hilcorp’s aggressive stance in tackling new Slope projects. “It’s exciting to see them this engaged and grabbing opportunities,” Myers said. North Slope producers have looked at ways heavy oil might be produced for years, investigating techniques like in-situ heating to warm the oil. One promising approach that BP pursued was CHOPS, a technique borrowed from Alberta where it is used to produce heavy oil.  CHOPS involves an auger device that rotates in the well, bringing the oil and sand from the shallow producing formation, to the surface. Unlike viscous oil production also done on the North Slope, and where operators work to keep sand out of a well (the sand can damage pumps), an inflow of sand into an Ugnu well is encouraged in the CHOPS approach. With CHOPS, as sand falls out of the rock into the well bore it opens up channels, or “wormholes” in the rock, enhancing the flow of oil fluids. As more sand is extracted, the wormhole network expands in the reservoir. The idea worked in Alberta and BP’s tests showed it can work on the North Slope. A key operational problem pointed up in BP’s test was that CHOPS, as a mechanical procedure (using the auger), requires frequent maintenance. This is affordable in Alberta where there is a well-developed industry support sector, sources familiar with the program said. However, it is less affordable on the North Slope where costs for drill rigs and other equipment are high, the sources said. A lower-cost approach to drilling and maintaining wells will be needed for heavy oil production to succeed, the sources said. There are other challenges, too, among them that heavy oil would be discounted in sales because of its lower quality. Its value would be adjusted downward in the Trans-Alaska Pipeline System Quality Bank, a mechanism used by TAPS shippers to adjust for quality differences in crude oil value in the pipeline. Ugnu oil is 10 to 15 degrees API gravity compared with 29 API gravity or better for North Slope conventional “light” oil. Another problem is that the Ugnu oil won’t flow by itself in a pipeline and must be mixed with conventional “light” oil on almost a one-to-one ratio. All this has given heavy oil a bit of a bad reputation. “The resource is considered high cost and low return, but this need not be true,” said one person knowledgeable with Ugnu deposit. “This assumes you use existing equipment, such as drilling rigs, under the contracts that exist today on the Slope. If you do that you will get high costs and low return.” CHOPS showed that daily well rates could be boosted, but to operate the wells on a commercial basis new types of lower-cost drill rigs must be developed, which might be possible because the Ugnu is very shallow, and ways of maintaining the wells for lower costs must be found. The potential resource is huge, however. “The oil-in-place estimate of heavy oil in the Ugnu deposit ranges up to 21 billion barrels, of which 5 to 10 percent is considered technically (but not yet economically) recoverable,” said Paul Decker, a senior geologist with Alaska’s Division of Oil and Gas.  The deposit is shallow and extends across areas of the Prudhoe Bay and Kuparuk River fields as well as Milne Point, Decker said. Some of it is actually frozen in the permafrost layer that underlies much of the North Slope, he said. Ugnu’s oil originated in the same places that the conventional “light” oil on the North Slope, the large shale formations south of the Prudhoe Bay and Kuparuk River fields. Over millions of years, oil seeped out of the shale “source rocks” and migrated upward, and northward, along faults and other pathways through the rocks, Decker said. Some of it was trapped at deeper levels in the large sandstone formations that are now the producing conventional oil fields, and some kept migrating to shallower levels, where temperatures were cooler, and became the “viscous” oil deposits that were also found and which are producing today, such as the West Sak formation in the Kuparuk field. Some of the migrating oil missed both the deeper and shallower traps and kept seeping upward to even shallower, cooler levels, to accumulate in what is now the Ugnu deposit beneath the permafrost. Over the years a lot of ideas have been considered for Ugnu including ways of warming the oil in-situ, or in the underground formation, so that it will flow. Steam injection, for example, is used to lighten and produce heavy oil in other places. The concern for steam injection on the North Slope is that injecting the steam from the surface will also warm the permafrost and thaw it, an undesirable outcome. Also, the cost of producing the steam at the surface would be a consideration. Other ideas have been toyed with including placing electrical heating devices underground. Those would create cost barriers too, however. So far the CHOPs approach of augering the oil and sand mixture to the surface appears to be the most workable course, and one that Hilcorp would like to continue pursuing.

ConocoPhillips puts Inlet fields up for sale

ConocoPhillips is getting out of the natural gas production business in Cook Inlet. The company has put its Inlet gas assets up for sale and plans to open a data room for prospective buyers. However, the company’s liquefied natural gas plant at Nikiski is not included in the assets for sale, company spokeswoman Amy Burnett said.   Included in the offering are the North Cook Inlet field, which has historically been the main supplier of gas to the LNG plant, although most of the gas to the plant to support ConocoPhillips’ LNG exports now comes from other producers, Burnett said. Also to be sold is ConocoPhillips’ interest in the Beluga gas field, where the company is also the field operator. ConocoPhillips is one-third owner in the Beluga field. Other owners are Hillcorp Energy and the Municipality of Anchorage. “While historically significant to the company’s investment in Alaska, the North Cook Inlet and Beluga River units are mature fields that are no longer considered core to Alaska operations. The focus will be on the company’s current North Slope operations, including the Alaska LNG project,” according to a ConocoPhillips press release. “ConocoPhillips believes the North Cook Inlet and Beluga River units are important assets that offer good opportunities for the right buyer. Development of a data room for the sale is in progress, and is expected to open in early August.” Larry Persily, oil and gas advisor to the Kenai Peninsula Borough, said he wasn’t surprised that ConocoPhillips would shed older, mature properties in order to focus on new opportunities. What is more interesting is who might purchase the assets, he said. A logical interested party would be Hilcorp Energy, which has expanded aggressively in Cook Inlet after purchasing Chevron Corp. and Marathon Oil properties in 2012 and 2013, Persily said. Other potential buyers could include Enstar Natural Gas Co., the regional natural gas utility, or other, out-of-state firms reported to be now investigating opportunities to supply gas to Interior Alaska. However, Hilcorp is already the largest owner of natural gas in Cook Inlet and the major supplier to regional utilities. “Purchasing ConocoPhillips’ holdings would give them overwhelming dominance that the State of Alaska may object to,” Persily said. Ownership in the Beluga gas field is now split between Hilcorp Energy, the Municipality of Anchorage and ConocoPhillips owning one-third each. If Hilcorp were to buy ConocoPhillips’ holdings in Beluga it would own two-thirds of that field, which supplies gas to regional utilities. That may be of concern to the utilities and to the state. The Department of Natural Resources must approve any transfer of state leases at the North Cook Inlet and Beluga fields. There is precedent for the state moving to block a company’s acquisition of oil and gas resources to be in a dominant position. In 1990, former Gov. Tony Knowles objected to BP’s acquisition of ARCO Alaska’s assets in on the North Slope, which led to ARCO’s sale to Phillips Petroleum, now ConocoPhillips. A small Japanese consortium now planning a medium-sized LNG plant at Point MacKenzie, Resources Energy Inc., has also been looking to acquire a Cook Inlet gas supply and may be a potential purchaser. A significant factor any prospective purchaser will have to consider is the liability that would be assumed in future removal of the Tyonek platform, which now supports the North Cook Inlet field gas operations. The state will likely insist that liability for the eventual platform removal and environmental remediation be accepted as part of a purchase deal, mainly so the state itself doesn’t get stuck with the costs. Estimates for removal of a Cook Inlet platform range to $50 million, according to sources familiar with the issue.

Effect of troop cuts may be muted

The U.S. Army’s decision to reduce personnel at Joint Base Elmendorf-Richardson by 2,600 troops sent shock waves through Anchorage when the announcement came July 9. However, after several days of thinking through the implications, community leaders and some economists think the actual effects of the reduction will be relatively light. “Do we like this decision? No. It is the end of the world? No,” said Bill Popp, president of Anchorage Economic Development Corp. Jonathan King, president of Northern Economics, an Anchorage-based consulting firm, said his initial assessment is that the economic effects will be felt to some degree, but muted by geography. “If you own a barbershop on Muldoon Road in northeast Anchorage you’ll feel an effect. If you live in south Anchorage you won’t feel it at all,” King said. His estimate of job losses, including direct and indirect, is 4,500. University of Alaska Anchorage economist Scott Goldsmith arrived at a higher estimate of job losses, 6,000, by factoring in rising pay for Alaska military personnel in recent years, which would increase the “multiplier” effect in the economy of reduced payroll, as well as rough estimates of civilian defense employees. Both he and King said their estimates were rough, however. Popp said the fact that the reduction will take place over two years will soften the effects. It will give people time to plan and make adjustments, he said. King said the reduction, if it really happens, will reduce the amounts the number of military personnel at JBER by about one-fourth. However, it’s tricky to calculate the economic effects of that. For example, while a substantial number of soldiers live off base, both owning and renting homes, the military doesn’t say where they live, in Anchorage, Eagle River or the Matanuska-Susitna Borough. Popp said the anecdotal evidence is that many military living in the Mat-Su tend to own homes rather than rent, which is made more possible by recent Defense Department policies to not rotate married personnel and families as frequently as single soldiers. Military homeowners, in Mat-Su or elsewhere, would also be more likely to want to remain in Southcentral Alaska and to seek jobs with private employers, Popp said. King said his data indicates that the loss of the 2,600 soldiers will include 1,400 spouses and 2,600 children. The impact on schools depends on where the military families live, which isn’t known, he said. The effect may be so spread out across the region so that it will hardly be noticed. “Depending on the schools, I can see some of this as reducing overcrowding in classes,” King said. The amount and effect of the loss of local spending by military families is also hard to judge, he said. The total military payroll at JBER is estimated at about $142 million per year but a lot of this spending — how much is unknown — occurs on base. These are dollars that never touch the regional economy in a significant way. King said his back-of-the-envelope estimate is that military payroll spending in the regional economy might be reduced by 10 percent to 15 percent. However, Popp said the loss of military payroll has to be viewed in context of the entire economy. “Anchorage’s total payroll, including the military, was $8.58 billion in 2014. This will be a very small fraction of that,” he said. JBER also spends about $135 million per year on private contract services for various support functions, but how this would be affected by the troop reduction is also unknown, for now. On-base housing services, which accounts for a good portion of it, will be largely unaffected because there is a waiting list for housing on JBER, Popp said. Much of the contract spending will be on support of other infrastructure, and these kind of expenditures change more gradually because a base like JBER has a lot of fixed costs. Finally, it isn’t for certain that the cut will happen in the end, although the Army seems committed. “We’re considering options that could result in these cuts to JBER being avoided,” said Matt Felling, spokesman for Alaska U.S. Sen. Lisa Murkowski. Felling wouldn’t elaborate on pathways being investigated to accomplish that, and also cautioned against false expectations being raised. He also said the Army could be under pressure to make more cuts nationwide if sequestration kicks back in during 2017. The reductions being made now are part of a plan by President Barack Obama and the Defense Department and not sequestration, Felling said. The plan now being followed is to reduce the Army by 120,000 soldiers, from a recent peak of 570,000 to 450,000. Congress has meanwhile given the Pentagon a two-year reprieve from sequestration to allow lawmakers to make changes in the overall national budget. However, if sequestration resumes in 2017, the Army’s overall forces would be reduced from 450,000 to 420,000 soldiers by 2019, according to information provided by the Army to the congressional offices. If those reductions occur the Alaska Army posts may see more reductions.

Another round of Slope methane hydrate research planned

Another test of methane hydrates on the North Slope, a potential huge new gas resource, is being planned. State officials are in discussions with the U.S. Department of Energy and the Japan Oil, Gas and Metals National Corp., or JOGMC on possible joint-sponsorship, and talks are planned with North Slope producers about potential sites for a test within one of the operating units on the Slope, Commissioner of Natural Resources Mark Myers said. A technical evaluation of different sites is now underway, Myers said. Drilling within an existing industry unit is preferable for cost reasons but sites on nearby unleased state lands set aside for hydrate research are also being evaluated; those are lacking in infrastructure and less is known about the potential for hydrate accumulations, however. Myers, a former head of the U.S. Geological Survey and Alaska Oil and Gas Division director, has long been intrigued with the possibility of that hydrates could eventually be a huge new energy resource. He now sits on the U.S. Department of Energy’s hydrates advisory board. Both the DOE and the U.S. Geological Survey have been extensively engaged in hydrates work, Myers said. The DOE advisory board’s recommendations for continued work focuses on not only as hydrates as a potential energy resource, but also as a hazard (drillers can unexpectedly drill into a hydrate, causing shallow gas blowouts) and the contribution that hydrate melting, mainly offshore, and release of methane, a potent greenhouse gas, could be making in global climate change. JOGMC, a Japanese industry group that participated in previous North Slope hydrates work and has also been engaged in hydrates research offshore Japan, may take part in helping fund a new slope test. The cost of the well could reach $30 million.  Hydrates are crystalline structures of ice and methane, the main component of natural gas, which form at shallow depths under certain temperature and pressure conditions. They are known to exist offshore in many parts of the world including offshore Japan, India, the U.S. Gulf of Mexico, and in permafrost areas of the Arctic. On the North Slope they have formed beneath and in some cases within, the permafrost, or the permanently-frozen soil and rock that underlies much of the Slope. Hydrates can hold large amounts of methane. The U.S. Geological Survey has estimated that about 84 trillion cubic feet of methane could be technically produced from hydrate-prone permafrost areas of the North Slope. In another study, 12 trillion cubic feet of methane capable of being technically produced were estimated to be in hydrates in the immediate central North Slope area, in the Prudhoe Bay, Milne Point and Kuparuk River fields. The challenge is finding ways to produce the methane from the hydrates, a problem government and industry scientists have focused on in recent years. As it turns out, the North Slope is an ideal laboratory for research and tests because of the presence of infrastructure like roads, which lowers costs compared with working in roadless areas like Canada’s Mackenzie River delta, where hydrates have also been found. The Arctic onshore hydrates are also in sandstone formations, which would be technically easier to produce from than the fine-grained sediments in which offshore hydrates are often found. High stakes There are big stakes in this, Myers believes. If the methane can be produced economically it would add a huge new gas resource to backstop a planned North Slope natural gas pipeline, he has said. At present, the known and proven conventional natural gas reserves of the slope, estimated at about 35 trillion cubic feet, or tcf, are enough to keep the planned Alaska LNG Project at capacity for about 15 years. After that, additional gas supplies will have to be available, state officials have said. While there are large potential and undiscovered conventional gas resources on the Slope — 100 tcf is an estimate often cited — methane from hydrates could almost double that if technical problems can be overcome. So far there have been three hydrate test wells on the North Slope and one in Canada, in the MacKenzie Delta, with each test advancing scientists’ understanding of hydrates and how the methane might be produced. The test being discussed now would be the first long-term production test, possibly lasting 18 months to 24 months, Myers said.  The Canadian test, at the Mallik well in 2007, drilled into a hydrate and showed that methane could be produced, although it was a short, six-day test. At Prudhoe Bay, an early test by Anadarko Petroleum to do a hydrate production test was unsuccessful when the company did not find the hydrate where it was thought to be. Industry participation There is learning from failure, however, and scientists reworked their research and developed new seismic techniques to more effectively locate hydrates. That was successful and hydrate were successfully located in the Milne Point field, then operated by BP, where that company drilled a second test in 2007, the Mt. Elbert well. Hydrate cores were successfully extracted for research. In 2011 ConocoPhillips operated a third hydrate test on the slope in the Prudhoe Bay field, Ignik Sikumni No. 1, which involved an actual production test that was done for 30 days. ConocoPhillips tested two possible production techniques at Ignik Sikumni, one involving the gradual depressurization of the hydrate, which allows the hydrate to thaw and the methane to escape (but also potentially destabilizing, or melting, the hydrate) and a second technique involving the substitution of carbon dioxide for the methane in the hydrate, a technique aimed at preserving the structure of the hydrate. In the chemical “exchange” of CO2 for methane, the methane could be produced and the hydrate could be kept intact, in its frozen state, by injecting the C02. Keeping the hydrate intact can be important because thawing the hydrate could create side-effects, like subsidence at the surface where the hydrate is shallow, which most are. The CO2-methane “displacement” technique also has an advantage of creating a potential for permanent sequestration of C02 in the frozen hydrate. CO2 is a “greenhouse” gas that scientists say contributes to global warming. If a natural North Slope gas pipeline is built the C02 in the conventional natural gas on the slope, constituting about one-eighth of the Prudhoe Bay gas resource, will have to be extracted there and uses for it, or places to put it, will have to be found. ConocoPhillips’ test was encouraging for both techniques but its duration was not long enough to answer a lot of other questions. A big question is whether a “freeze-back” might occur as a hydrate is depressured that could plug up the hydrate, preventing a flow of methane, according to Paul Decker, a senior geologist in the state Division of Oil and Gas. Myers said several sites for the possible upcoming test are under consideration, including locations within the Prudhoe Bay and Milne Point units, where hydrates are known to occur, as well as on nearby tracts of unleased state lands where hydrates are possible but have not been confirmed. The test would likely cost less if done within one of the industry units because infrastructure would be available. However, permission from the unit operators, the producing companies, would have to be obtained, and the test would have to be planned so that it does not impair operations in the unit, Myers said. There is also the element of geologic risk, that the hydrate might not be there, which would be lower for a test well in Prudhoe Bay or Milne Point where the presence of hydrates has been confirmed. So far there have been some positive reactions from Prudhoe Bay unit owners, Myers said. Discussions have been held with ExxonMobil, one owner of Prudhoe Bay, which was positive, he said. Talks with BP and ConocoPhillips, the other major owners, are scheduled. There are four or five possible sites for a hydrate test in Prudhoe Bay and at least two sites in Milne Point, but permission there would have to come from Hilcorp Energy, now half owner and the operator of that field. Myers said a long-term production test is important for a number of reasons. “It would give us a chance to understand the physics and chemistry (of the hydrate) and what to see happens to the permeability in the sands (the small spaces that allow gas fluids to flow) and how a sandstone reservoir would really perform,” he said. “The modeling that has been done (based on previous shorter tests) has been encouraging but we need to validate the modeling.” Meanwhile, people ask why the government should provide funding for research like this and why industry isn’t leading. Industry has contributed and even led projects in the past, but the very long lead-time for the development of a brand new resource like methane from hydrates can make it difficult for companies who typically have shorter-term strategies, particularly in an environment like today’s. “Most people see any commercialization of hydrate production as several decades out,” Myers said. But there can be surprises. The U.S. Department of Energy and U.S. Geological Survey did a lot of the initial research into coal-bed methane, or gas from coal seams, as well as producing gas, and oil, from shales. Once the basic science was understood industry moved quickly to commercialize the potential, Myers said. Hydrate methane production could happen faster than people now believe, he said. Offshore hydrates will take longer to test and someday produce because costs will be higher. Hydrates are known offshore Japan and in the U.S. Gulf of Mexico but in waters depths of 6,000 feet or so, which means offshore drilling equipment must be used. Chevron Corp. led a testing program to locate hydrates in the Gulf of Mexico but although hydrates were found in sand formations, which would in theory make good reservoirs, no cores were taken and Chevron has since dropped out of the program, according to Ray Boswell, head of the U.S. DOE’s hydrates program. Overall, the results were encouraging enough that the University of Texas has stepped in to work with the U.S. DOE to continue the program, the extraction of cores being the next step, Boswell said. In another development, JOGMC, the Japanese consortium, led its own hydrate test drilling program offshore Japan, drilled a well and conducted a short-term production test, Boswell said. The results were again encouraging enough that Japan’s government, which funded the tests, is likely to approve more work. JOGMC has participated in past North Slope tests, and may do so again, because what is learned in a long-term production test can be applied offshore Japan, Boswell said.

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