Tim Bradner

Chukchi SEIS approved, Shell on track for 2015

The U.S. Interior Department published a long-awaited Record of Decision March 31 on a contested 2008 Arctic offshore lease sale that had blocked Shell’s exploration plans on leases it purchased. Meanwhile, Shell has started moving vessels into place for its hoped-for summer 2015 Arctic drilling. Greenpeace, the environmental group, announced March 26 it is trailing the semi-submersible drilling vessel Polar Pioneer after it left Southeast Asia in route for North American waters. Shell confirmed April 1 the rig is being moved. The Interior Department’s record of decision, or ROD, gave formal approval to a supplemental environmental impact statement, or SEIS, published in February by the U.S. Bureau of Ocean Energy Management. The revised environmental document corrected a defect in the environmental study for the 2008 lease sale over which environmental groups sued. Federal courts agreed the 2008 environmental impact document needed revision, and the U.S. BOEM opted to pursue the SEIS as a remedy. Completion of the process allows the BOEM to begin processing applications by Shell for permits to drill on its leases in the Chukchi Sea. Shell spokeswoman Meg Baldino said the company has submitted a revised exploration plan that would replace one submitted last August. BOEM will not release details of the plan until it is reviewed, however. Meanwhile, the federal courts had given the agency authority to review the previous plan informally. Shell is hoping for “conditional approval” of its plan by the end of April, but BOEM would still need to do an environmental analysis of the plan, which may spark more protests from environmental groups. “Basically, the Record of Decision reaffirms Lease Sale 193 (held in 2008) and clears the way for the BOEM to conclude its review and make a decision on our Revised Chukchi Sea Exploration Plan,” Baldino said in a statement. “As you know, that plan remains contingent on achieving the necessary permits, legal certainty and our own determination that we are prepared to explore safely and responsibly.” Meanwhile, the U.S. Bureau of Safety and Environmental Performance, a sister agency to the BOEM within Interior, is still working on finalizing new special drilling rules for the Arctic, but Shell need not wait until these are issued, BSEE officials have said. Most provisions in the new rules have already been agreed to by Shell and would be incorporated into permits. Shell drilled one partially-complete well in the Chukchi in 2012 along with a partially-complete well in the Beaufort Sea where the company also holds leases. U.S. Interior Secretary Sally Jewell said the revised document reflects a balanced and thoughtful approach to Arctic exploration by the government. “The Arctic is an important component of the administration’s national energy strategy,” Jewell said in a statement. “This unique, sensitive and often challenging environment requires effective oversight to ensure all activities are conducted safely and responsibly,” she said. Environmental groups criticized the action. “It is unconscionable that the federal government is willing to risk the health and safety of the people and wildlife that live near and within the Chukchi Sea for Shell’s reckless pursuit of oil,” said Marissa Knodel, Earth Climate Campaigner for the Friends of the Earth. “Shell’s dismal record of safety violations and accidents, coupled with the inability to clean up or contain oil in the remote and dangerous Arctic waters, equals a disaster waiting to happen.” Shell paid more than $2 billion for its leases in the Chukchi Sea in 2008 but has been unable to completely drill an exploration well because of legal and regulatory hurdles. Overall the company has spent more than $5 billion on its Arctic program. Although its actual Arctic drilling went off without incident, Shell’s 2012 exploration season was beset by mishaps, including the failure to get either its spill containment barge or its containment dome to pass inspection, which prevented it from being able to drill to oil-bearing depths. While in port in Dutch Harbor, the Noble Discoverer drill rig drifted to shore and the contractor operating the rig was later fined more than $12 million for safety and environmental violations. The season was capped by the conical drill rig Kulluk losing its tow during a storm in the Gulf of Alaska on New Year’s Eve, running aground off Kodiak and resulting in a total loss. The Noble Discoverer is returning to the Chukchi the summer along with the Polar Pioneer to replace the Kulluk to complete the well started in 2012 and to drill additional wells. A key goal for the summer is to complete the evaluation of the Burger prospect, a deposit of oil and gas ironically discovered by Shell in 1991 in the company’s earlier Chukchi Sea drilling. Burger appeared to be a large gas discovery and at the time there were no plans for a large gas pipeline from northern Alaska. Shell dropped its Chukchi Sea federal leases in the 1990s but returned in the 2008 lease sale and reacquired leases on Burger. Subsequent evaluation using tools not available earlier, such as 3-D seismic, led the company to believe the region has substantial oil resources that can be produced. Drilling must be done to confirm that, however.

Caelus plans fracking technology with a twist

When Caelus Energy begins development of its Nuna project on the North Slope it will employ technologies borrowed from the Lower 48 shale oil industry, but with a twist. The company plans to use large-scale hydraulic fracturing on its oil production wells, though not to the degree used in the North Dakota Bakken and the Texas Eagleford shale producing regions. The new twist is that injection wells will be fractured, too. Nuna will be producing from a tight-rock formation known as the Torok which has not previously supported commercial production, state officials have said. Fracturing with high-pressure liquids will break open the tight rock to let oil flow, but the fracture on the injection wells will allow fluids to be injected and to circulate, to push oil in the reservoir. Fluid injection, mostly water, is commonly used on the North Slope to push oil in the porous underground reservoirs toward production wells. The fracturing will enable the process to work in the tighter rock, however. Caelus’ experiments with the process and how well it works will be published, with technical information made available to the public under an agreement between the company and the state Division of Oil and Gas. That will allow other companies to benefit from Caelus’ experience with the process. The provision is part of Caelus’ agreement with the state for a temporary reduction of state royalty from 12.5 percent to 5 percent. Pioneer Natural Resources, Caelus’ predecessor at Nuna and the nearby Oooguruk field, which Caelus also purchased last year when it bought Nuna, tested the large-scale fracturing early last year on four new Oooguruk production wells. “We were very pleased with the results,” in production, compared to what the wells would have produced without the fracturing, said Caelus spokesman Casey Sullivan. About 2 million pounds of proppant material were used in the fracturing jobs, about a third of what is often used in very large Lower 48 fracturing, he said. While the Oooguruk fractures were done in a different producing reservoir than those to be done at Nuna, the Nuiqsut formation, Pioneer also tested the procedure on one of the two evaluation wells drilled at Nuna where production tests were done. That test showed the procedure also worked in the Torok formation. State officials said new technologies that can be applied to the Torok are important because the formation is widespread across the west-central North Slope, and with a great deal of potential recoverable oil.

Legislature gets to work on Medicaid reform, expansion

JUNEAU — Legislators are getting down to business on reforming the state’s bloated Medicaid system. A committee in the state House took up Gov. Bill Walker’s bill to expand, but also reform, Medicaid, while a Senate committee took up a bill by Sen. Pete Kelly, R-Fairbanks, to reform, but not expand, the program. Walker’s bill is House Bill 148. Kelly’s is Senate Bill 74. The proposals for reform are similar in many respects in the bill. Sen. Bert Stedman, R-Sitka, chair of the Senate Health and Social Services Committee, said he expects reform elements of the two bills to be combined. It’s too early to say whether Medicaid expansion has a chance. It is being opposed by Republicans in the House. Kelly considered adding it to his bill but changed his mind, sensing the votes weren’t there in the Senate, at least yet. There are other differences between Walker’s and Kelly’s bills aside from Medicaid expansion. The governor proposes a tax on health care providers, which most states have. Kelly’s bill does not have a tax. Kelly also proposes a feasibility study of selling major state-operated facilities like the Pioneers Homes and Alaska Psychiatric Institute and certain juvenile treatment facilities. The senator also proposes a voluntary program of Health Savings Accounts for Medicaid recipients funded with a portion of recipients’ Permanent Fund Dividends and also sets out aggressive deadlines for reforms to be in place. Walker’s bill has no provision for Health Savings Accounts and does not have hard deadlines. However, the governor’s bill would also make changes to financial audit procedures, streamlining these, to ease a burden health providers now have with increasing numbers of audits being required under the federal Affordable Care Act. Kelly’s bill would save $1.01 million next year with annual savings increasing to $17.9 million per year in 2021, according to a fiscal analysis of the bill. Some form of overhaul of the state’s $1.8 billion-per-year Medicaid program is likely because it is still growing and given the state’s current fiscal situation it cannot be sustained. “Growth in Medicaid has accounted for 22 percent of the total unrestricted general fund increases over the last 10 years,” Kelly said. “The current and former state administrations have testified that the Medicaid program, as it stands, is not sustainable. Low oil prices and billions of dollars in revenue shortfalls have forced us to change how we do business.” Changes are also likely to have substantial effects, positive and negative, on the state’s health care industry because they would introduce concepts like managed care aimed at reducing excessive use of hospital emergency rooms, as well as “payment reform,” to include changes in billing procedures but also the rates health care providers are paid, Kelly said. Another issue that is sure to surface is the range of optional services paid in Alaska’s Medicaid program that are beyond the mandatory services required to be paid by the federal government. States are allowed to add services as options to mandatory services required by the federal government, but Alaska’s range of optional services is among the most generous in the nation. Almost a third of Alaska’s annual outlays for Medicaid are for optional services, according to a recent study of the state budget published by Commonwealth North, an Anchorage-based public policy group. Meanwhile, there are already proposals in the House to make amendments to Walker’s bill, said Rep. Paul Seaton, R-Homer, who chairs the House Health and Social Services Committee, which began hearings on the governor’s expansion proposal March 24. Seaton said amendments to the bill will be considered in a March 28 meeting of the committee. In the Senate, Stedman said his committee will take up Walker’s bill March 30, and will meanwhile continue work on Kelly’s SB 74. Kelly told the Senate committee March 24 that the managed care part of his proposal would be done in a demonstration project with children enrolled in Denali KidCare — the state’s Medicaid program for children — because they are an easily identified population within the program. The goal is to have care that is coordinated by one physician group to avoid inappropriate use of emergency rooms, “self-referrals” to highly priced specialists, and the use of brand-name drugs when less expensive generics are available and just as effective, Kelly said. Another goal is “steerage,” to direct Alaska Natives on Medicaid to Tribal health facilities where the federal government reimburses the state at 100 percent of the cost instead of 50 percent if care were given at a non-Tribal facility, Kelly said. “Payment reform,” another goal, would lead to negotiated rates for providers rather than straight “fee-for-service” payments, Kelly said. Most states have changed their payment procedures for Medicaid, as has Medicare, the federal heath program for senior citizens, but the changes have not been made in Medicaid in Alaska, he said. One aspect of payment reform is that payment services can be contracted through health insurance companies so that the recipient can carry a standard insurance company card rather than a Medicaid card, which may carry a stigma. SB 74 would also direct the state health and social service department to expand telemedicine, matching telemedicine programs developed by Tribal health consortiums in the state. “The Alaska Native Tribal Health Consortium found that telemedicine averted the need for travel in 40 percent of the cases where telemedicine was used. ANTHC is leading the use of telemedicine and should be built on,” Kelly said. Department of Health and Social Services Commissioner Val Davidson told the Senate committee that the department has already initiated several reform steps including the identification of 5,000 “super-users” of emergency rooms among Medicaid recipients. “We’re already matching people up with case managers,” to steer people to primary care physicians in a coordinated program for “the right care at the right time, and at the right price,” Davidson said, echoing the phrase often used by her predecessor, former Health and Social Services Commissioner Bill Streur. This is a form of managed care, and Davidson said the department hopes to have 2,000 people of the 5,000 super-users under coordinated care soon. The program was kicked off in December and January. “At first Medicaid recipients were nervous about the intrusive aspects but now they welcome it when someone calls to make sure appointments are being set up and the right prescriptions are being obtained,” Davidson said. “They like it that someone cares.” Davidson said what’s contemplated in Alaska is not the formalized managed care through Managed Care Organizations, or MCOs, that are common in Lower 48 states, but not in Alaska, but rather informal managed, or coordinated, care. Of course the Legislature may wish to allow MCOs in Alaska, Davidson said.

ConocoPhillips moves ahead with Slope project at Kuparuk

ConocoPhillips announced it is proceeding with another North Slope oil project despite the sharp slump in prices. The company said March 23 it will develop a $460 million viscous oil expansion project in the Kuparuk River field on the Slope. The 1H Northeast West Sak, or NEWS, project will add 8,000 barrels per day to Kuparuk field production at peak production, ConocoPhillips said in its announcement. Production of technically-difficult viscous oil has been underway for years on the Slope but field operators have been working on ways to improve efficiency and expand production. ConocoPhillips has been producing the West Sak viscous oil in the Kuparuk field, while BP has been producing similar viscous oil from the Schrader Bluff deposit in the nearby Milne Point field. Hilcorp took over operations at Milne Point last fall after it purchased 50 percent of the field from BP. Viscous oil is thicker and colder than the conventional oil found on the North Slope. It lies in geologic formations above the conventional oil reservoirs and is cooler and more difficult to produce than the conventional oil. “The 1-H NEWS development (at West Sak) is one of the key projects we announced after passage of oil tax reform,” by the state of Alaska in 2013, ConocoPhillips’ Alaska President Trond-Erik Johansen said. “The positive investment climate created by tax reform was an important factor in our decision to move ahead with this project.” The project has been considered for years but is now formally approved. It includes a 9.3-acre extension to the existing Drill Site 1-H in the Kuparuk field and installation of surface facilities to support four new production and 15 injection wells, the company said. Construction will begin later this year with first production expected in 2017, ConocoPhillips said in its announcement. The company also has two other new North Slope oil projects under construction, the CD 5 project near the Alpine field and a new Kuparuk field Drillsite 2-S. Both will be completed and in production late this year. CD 5 will produce about 16,000 barrels per day at peak production while Drillsite 2-S will add about 8,000 barrels per day to production. Another ConocoPhillips project still in the planning stage is Greater Moose’s Tooth No. 1 in the National Petroleum Reserve-Alaska, which is administered by the U.S. Bureau of Land Management. The company is still working on permits issues with federal agencies, and ConocoPhillips has yet to approve the project, which will cost about $900 million and would produce about 30,000 barrels per day. The new work planned by ConocoPhillips will be reassuring to oilfield services contractors rattled by reports last week of contractor layoffs on some ConocoPhillips projects. KTUU TV Channel 2 in Anchorage reported March 17 that 75 employees of ASRC Energy Services, a major North Slope contractor, had been released from their work in the Kuparuk River field, which is operated by ConocoPhillips. ASRC Energy later confirmed, in a press release, that “recent changes in our market have resulted in the company restructuring its North Slope operations to be more efficient and productive in a new and highly competitive business environment.”

Caelus sanctions Nuna development

Caelus Energy has given formal approval for its new $1.5 billion Nuna oil project on the North Slope and has started construction, the company confirmed Friday. A letter notifying the state Department of Natural Resources of the approval was sent to the agency March 10 to satisfy a requirement of a temporary state royalty modification for the Nuna project. Gravel mining and hauling for a 2.5-mile access road and 22-acre drillsite began Jan. 25, Caelus Vice President Pat Foley told state Deputy Natural Resources Commissioner Marty Rutherford in the letter. The road and pad are to be finished this winter, with construction of production facilities planned for next year, company spokesman Casey Sullivan said in an interview. The company has signed authorizations for $480 million in expenditures to date and is preparing additional expenditure authorizations for an additional $800 million, according to the letter. Nuna is to be producing in 2017 and is expected to reach peak production rates between 15,000 barrels per day and 20,000 barrels per day. There have been reports that Caelus had cut back some activities related to Nuna and Sullivan confirmed that some facility fabrication work has been rescheduled. Overall, the project is on track, he said. Any reported slowdown of North Slope work causes discomfort in the support contractor community. Earlier this week KTUU Channel 2 in Anchorage reported that 75 employees of ASRC Energy Services, a major North Slope contractor, had been released from their work in the Kuparuk River field, which is operated by ConocoPhillips.  ASRC Energy later confirmed, in a press release, that “recent changes in our market have resulted in the company restructuring its North Slope operations to be more efficient and productive in a new and highly competitive business environment.” Caelus is pushing Nuna along, however. “Our Nuna development has been fully sanctioned, construction activities have commenced and we are safely on track to satisfy all of the milestones required in the Jan. 20 royalty modification,” agreement with the state, Foley said in the letter to Rutherford.

AGDC board adopts 'to-do' list for Walker's state-led pipeline

There may still be uncertainties about Gov. Bill Walker’s expectations for a larger state-led gas pipeline, but the board of the Alaska Gasline Development Corp. has adopted a cautious, step-by-step strategy for investigating an expanded project. AGDC has currently developed the state-led Alaska Stand Alone Gas Pipeline, or ASAP, as a fallback to get North Slope natural gas to Alaska communities in case a large industry-led gas project falters. ASAP is now designed to move 500 million cubic feet of gas daily. The Legislature authorized AGDC to pursue the backup plan in House Bill 4, passed in 2013, and added further guidelines in 2014 in Senate Bill 138, which also authorizes the state to partner with industry in the larger Alaska LNG Project. The governor announced Feb. 19 that he wants the ASAP project “upsized” to more than 2 billion cubic feet per day capacity, to become more economically viable as an option for the state. Private companies now engaged in the Alaska LNG Project, in which the state is a 25 percent partner, are now worried that the governor may intend his project to become a competing project. AGDC’s board is now working to dampen those concerns. At the corporation’s March 12 board of directors meeting, its chair, Fairbanks attorney John Burns, laid out a strategy for expansion that requires maintaining the state’s partnership with industry in the larger project, including the sharing of confidential data, with a goal of gaining the partners’ consent in AGDC’s expansion of its plan as a backup.  “The key is to maintain the alignment (with industry partners) and not duplicate the work effort or be competitive,” Burns said. “We need the concurrence of our (private) joint-venture partners,” an expansion plan. At the same time, AGDC needs to have an economically viable alternative in ASAP if the large project does not go, he said. The board directed AGDC’s staff to develop, in two weeks, rough costs and a lists of tasks for two increased volume scenarios, one that would move 1.4 billion to 1.6 billion cubic feet of gas per day, and a second that would move 2.4 billion to 2.6 billion cubic feet of gas daily. The project does not include a natural gas liquefaction, or LNG, plant. The larger industry-led project has an LNG plant with land already acquired for it in Nikiski, however.   Lack of gas Meanwhile, in a separate forum, state officials identified a critical challenge facing a state-led pipeline: The state has no access to natural gas without North Slope oil and gas operators producing their own gas at the same time. Department of Natural Resources Deputy Commissioner Marty Rutherford told the House Resources Committee March 13 that the state would receive a royalty share of gas production, but not before the other companies. “There is no ’overlift,’” provision, Rutherford said, which would allow the state to takes its gas before the producing companies. AGDC President Dan Fauske also appeared at the House Resources Committee meeting and, speaking separately, agreed with Rutherford. “The state has no gas,” to sell before the producers have their gas, he said. Also, AGDC will not sell state royalty gas even when it is produced. State law reserves that duty to the Department of Natural Resources, although DNR can contract with AGDC to sell the state gas on its behalf, as a marketing entity. (The large Alaska LNG Project agreement also provides the state with an option to contract with individual producing companies to sell state gas as LNG). The March 13 House Resources meeting was tense, but it had its lighter moments. Fauske was pressed about who is in charge of the ASAP project, the governor or the corporation’s board, and about him personally being named as “point person” by the governor for the project. Fauske said he learned about this while buying a sandwich at a fast-food restaurant and listening on his iPhone to the governor’s press conference when the expansion plan was announced. Fauske is well-liked in the Legislature but members of the Resources committee pressed the issue. “Who is the captain of this boat, the governor?” asked Rep. Bob Herron, D-Bethel. Rep. Mike Hawker, R-Anchorage, asked, “You were personally named as the governor’s point person on this. Are you?” “I take direction from the (AGDC) board,” Fauske said. “The governor appoints the board but legally it is the board’s responsibility,” to direct the project, he said, drawing laughter from the committee by adding, “I’m not trying to weasel out of answering the question, Rep. Hawker, but, well, maybe I am.” Hawker asked about the suspension of the ASAP environmental impact statement, or EIS, process by the U.S. Army Corps of Engineers due to the governor’s announcement of an upsizing of ASAP. “Could this have effects on the (larger) Alaska LNG Project? If the governor ramps up a competing project could it cast doubt, in the federal agencies, on whether Alaska LNG will proceed?” Hawker asked. That could cause them to slow down work on Alaska LNG regulatory proceedings. Fauske said he would not be surprised to see concerns raised by other agencies. “It could happen,” he told the legislators. At the March 12 AGDC board meeting, member Dave Cruz said people should recognize the proper relationship between an independent pipeline like ASAP and the producers if the state pipeline were to be built. “These producers are not our competitors. They are our customers,” Cruz said. “We will ship their gas, whether under ASAP or (the state’s 25 percent share) of Alaska LNG,” Cruz said. “They own the gas,” he said, or most of it. The pipeline is a transportation entity, like a railroad. “We provide a service,” to producers, Cruz said. “If we can offer a better and faster service through ASAP the producers could decide to ship their gas with us,” he said.   Engineering challenges AGDC’s staff explained to the board that expansion of volume through the pipeline itself can be achieved using the 36-inch pipe with the strength of steel in the current ASAP design, although additional compression of gas will be needed, presumably with compressor stations added. There is no compressor station along the pipeline in the current design. The second, higher volume could be achieved using a heavier-strength steel, and also with compressor stations.  The goal is a “Class 3” design estimate, what would be considered the pre-front-end engineering and design, or pre-FEED, level of the project. Design work has currently been completed for the smaller project to a “Class 2” level, or full front-end engineering and design. The estimates for the pipe changes and compression can be ready within two weeks, but a big gap is that it will not include design and engineering changes for the gas treatment plant, or GTP, at Prudhoe Bay, Cruz said. “We have not vetted the change in the GTP which would require a total reengineering,” Cruz said. “That will be a lot bigger of an exercise and will take longer than two weeks.” Cruz is president of Cruz Construction, a long-time Alaskan construction company. Rick Halford, one of three new board members appointed to AGDC by the governor, said he would be more comfortable doing the scale-up study in smaller bites. “The GTP is a huge issue,” Halford said. Step one of a GTP plant redesign, Cruz said, is knowing the specifications of the gas the producing companies can deliver because that will influence what process AGDC would select for the larger treatment plant. The current plant design uses one technology that may not be efficient in a scaled-up facility. A different technology may be required. “I wouldn’t want to wade into this before deciding which model (technology) to use,” Cruz told fellow board members. Also, the current design assumes that only Prudhoe Bay gas will be used. An expansion would require gas also produced at Point Thomson, which has a different chemical composition. Designing a larger plant to handle the different gas compositions adds complications. As for the scale-up scenarios, AGDC Engineering Vice President Frank Richards told the board that the normal procedure with pipeline planning is to work with the market to define the volume needed. “Here we are looking at what can (technically) be done,” he said. Halford, a former state senator and Senate President, warned that the project should be driven by the economics. “This seems to be designed to fit politics,” he said. Burns expressed reservations, too. “This question we are asking is whether it is possible to upsize, but what other information is needed? Without the market you are limited,” he told other board members. Halford also asked if the assumption of in-state gas demand of 250 million cubic feet per day is net of existing Cook Inlet production, which is now about 100 million cubic feet per day. Richards said that a 2010 study on in-state demand by Northern Economics, an Anchorage consulting firm, done for TransCanada Corp., is now being updated for the Alaska LNG Project. The earlier study showed that the actual demand for gas within the state could be less than 250 million cubic feet per day if continued Cook Inlet gas production is assumed. There could be other new demand for gas, however. Agrium Corp. is studying a possible restart of its fertilizer plant near Kenai, and could be a large industrial customer. Likewise, if Donlin Gold builds its large gold mine in the mid-Kuskokwim River region, the company could also become a new gas customer. Oh the other hand, there is uncertainty on how much gas might be needed in Fairbanks given the shutdown of the Flint Hills refinery and Golden Valley Electric Association’s startup of the 50-megawatt Healy 2 coal-fired power plant. The rule-of-thumb has been that Interior region demand might be 50 million cubic feet of gas per day, but it could also be far less. However, if the gas price is Fairbanks is affordable Flint Hills might restart its refinery and other industrial customers could develop, such as a large gold mine being planned at Livengood, north of Fairbanks.

AGDC needs spending freeze lifted

The first new jobs created by Gov. Bill Walker’s new gas pipeline plan may well be in California, it appears. Following the governor’s directions, the state-owned Alaska Gasline Development Corp. has initiated a study of costs to do engineering to scale-up a state-backed North Slope natural gas pipeline, the Alaska Stand-Alone Gas Pipeline. The state pipeline is now planned with a capacity to move 500 million cubic feet per day. The governor wants to increase it to as much as 2.6 billion cubic feet per day. AGDC’s board of directors approved the new study March 12. It is contingent, however, on Walker’s lifting of an earlier administrative order freezing AGDC’s unspent funds as a spending-restraint action. To do the cost study, AGDC will have to rely on engineering and design contractors with offices in California who have just completed final engineering on a smaller gas pipeline designed as a backup to get gas from the slope to Alaska communities in case the large industry-led project does not move forward. At the peak of the engineering effort on the smaller gas project there were 130 engineers at work in California for Fluor Corp.-WorleyParsons Ltd. joint-venture Arctic Solutions. Engineering companies CH2M Hill and Michael Baker Jr. are also working for AGDC. Walker’s plan has meanwhile unsettled companies now engaged in a larger North Slope gas pipeline and LNG project with the state as a 25 percent partner. BP, ConocoPhillips, ExxonMobil Corp., and TransCanada are the state’s partners in the large Alaska LNG Project. The industry partners now worry that the governor is developing a competing project, raising uncertainty about which approach the state will really support, the partnership with industry or a state-controlled gas project. “Things have been a little strained lately, since the governor’s announcement (in a newspaper op-ed on Feb. 18),” AGDC President Dan Fauske told the corporation’s  board March 12 meeting. “There are some strains in the relationship (between the state and the industry partners) but we think we can work through this.” AGDC board Chair John Burns said it is critical that the state maintain its current good relationship with industry partners in the Alaska LNG Project, “but we do have to maintain a viable alternative,” with the state-led ASAP project in case the large initiative falters. However, AGDC Commercial Vice President Joe Dubler warned the board that moving to a larger project may violate terms of agreements between AGDC and its industry partners over the sharing of confidential information. Those agreements, which are themselves confidential, refer to the 500 million cubic feet per day capacity of the state-led pipeline. Dubler said there are provisions that the agreements can be altered, however. Meanwhile, the possible new direction for the state has caused federal regulatory agencies to take a step back from a pending revised environmental impact statement, or EIS. ADGC Vice President of Engineering Frank Richards told the board that the U.S. Army Corps of Engineers notified the state corporation March 2 that it was suspending work on the EIS until there is more clarity on the future of the project. In a related development, legislative leaders, who are also anxious to maintain smooth relations within the gas partnership have introduced a bill in the Legislature limiting the ability of Walker to spend money to develop a competing project. The legislation was introduced March 2 by House Speaker Mike Chenault and seven other House members. It is expected to move out of the House Resources Committee March 13 or 14, according to Rep. Ben Nageak, D-Barrow, co-chair of the committee. For now, AGDC’s board has directed its staff to develop cost estimates and actions needed for preliminary engineering of larger state pipeline. Richards said an estimate for the costs of engineering for additional compression and the thicker pipe needed to move more gas will be available, but that estimates for reengineering on a gas treatment plant on the North Slope will take longer. Final design and engineering of the gas treatment plant and pipeline were completed for the smaller 500 million cubic feet per day capacity pipeline in January and AGDC must now see whether engineering and design contractors who worked on that are still available to estimate costs for the resized project, Richards told the board. The smaller pipeline is estimated to cost $10 billion. A larger project would cost much more, but how much more is unknown until preliminary engineering is done. The re-scoping would also see the state pipeline extended 12 miles to tidewater at Cook Inlet from its present terminus at a connection with the Enstar Natural Gas Co. regional gas distribution system in the Matanuska Susitna Borough north of Anchorage. At present the state pipeline has no LNG plant component. That could be added or the state could partner with a third party LNG developer.  A big unknown on how far the governor will be able to take his new plan is how much engineering AGDC can do for the $150 million the state corporation has on hand from previous appropriations by the Legislature. The estimates now being developed will answer that. If the funds are insufficient to develop enough engineering for a firm cost estimate Walker will have to go back to the Legislature for more money. Given the current sour state of relations between the governor and lawmakers, further appropriations of state funds seem unlikely, particularly given the state’s deteriorated financial position due to lower oil production tax and royalty revenue. Alaska is projected to run a combined $7 billion to $7.5 billion in deficits for the current and next fiscal years, and legislators are having to make sharp cuts to state agencies and education funding.

Walker introduces legislation to expand Medicaid

Bowing to legislators’ requests, Gov. Bill Walker introduced legislation March 17 setting out a broad framework for reform of the state-managed Medicaid program and also expanding the program to provide health coverage to an estimated 40,000 uninsured Alaskans. Earlier in the week, Sen. Pete Kelly, R-Fairbanks, introduced Senate Bill 74, setting out several provisions for reform of Medicaid but without an expansion of coverage. The governor previously sought to expand Medicaid under an administrative procedure through the operating budget but the Legislature balked at giving the Department of Health and Social Services the authority to receive federal funds and instead asked Walker to submit a bill that outlined steps to be taken to reform the program. Medicaid is a state-federal program that provides health coverage to families at or below the federal poverty level and disabled individuals. The program is managed by the state and funded about 50-50 by the state and federal government. This year the Medicaid budget is about $1.7 billion with about half of the funds, or $850 million, coming from the state general fund. Expansion of the program to provide coverage to Alaskans up to 138 percent of the Federal Poverty Level, or to an annual income of $20,344 for an individual, with the federal government picking up most of the tab as allowed under the federal Affordable Care Act. However, states must approve an expansion under a U.S. Supreme Court decision, and in Alaska former Gov. Sean Parnell had refused the expansion, citing concerns over future costs. Walker, while on the campaign trail, made Medicaid expansion a priority, but now he must convince the Republican-led Legislature to go along with the plan. Expansion is good for Alaska, the governor said March 17 in a press conference. “First, it will improve Alaskans’ health by providing medical coverage to 40,000 Alaskans who do not now have medical coverage; second, it’s good for our economy. It will bring $146 million in new federal funds next year and this will be ongoing; third, it’s good for the state general fund. We pay out a lot of money for health care that we will not have to pay. We’ll replace state funds with federal funds; fourth, it will be a catalyst for reform,” Walker said. “The Legislature has asked for this (legislation) and we are responding.” The immediate effect of an expansion would be to offset $6.5 million to $7 million in state funds now paid out, mainly for prisoners’ health care, that would be replaced by federal funds. Walker said by not having Medicaid expansion in place the state is missing out on $400,000 a day in federal funds. “Think about $146 million a year. That’s about the size of our state capital budget for next year. It’s a big deal. But it provides a lot of coverage for people, and it will also create about 4,000 jobs,” he said. Walker said governors in other states who have expanded Medicaid told him that all the initial estimates of benefits and economic impact proved to be low once the expansion programs were up and running. A possible tax on health care providers is included in the proposal but the details of that still need to be hammered out in talks with health providers, and separate legislation will be needed. Most states have taxes on health care providers but Alaska does not. A tax of up to 6 percent on hospitals is allowed under federal law. Under the current corporate tax rate budget director Pat Pitney said increased activity under Medicaid expansion would bring in about $1.6 million per year. Walker also dealt in the press conference with a concern raised by opponents of expansion in the Legislature that if the state expanded the program and the federal government later reneged on its commitment to fund at least 90 percent of costs in future years, the state could not withdraw and would be stuck with picking up the tab. A letter obtained from the U.S. Secretary of Health and Human Services said the state can, in fact, withdraw. “It won’t lock us in,” Walker said. Department of Health and Social Services Commissioner Val Davidson said the governor’s bill contains language that terminates the expansion if the federal contribution drops below 90 percent. Davidson said at the March 17 press conference that two key initiatives possible under an expansion will save the state a lot of money. “We will be able work with our Tribal health provider partners to maximize federal payments for Alaska Native medical care. We see potential savings of up to $80 million to $100 million a year under this,” Davidson said. A second initiative would maximize the federal share for certain home and community-based health services now mainly state-funded. Approval for this must come from the federal Center for Medicaid Services but there are potential savings of $24 million a year possible, although it will take two to three years to see most of these savings, she said. There are also opportunities for expansion of telehealth services, which would improve service in remote communities and lower costs, mainly by reducing travel. These ideas aren’t new, the commissioner said. Legislative committees have been briefed on the proposals several times this spring, she said. Davidson said her department has issued a Request for Proposals for a consulting firm to help identify other reform and cost-saving measures. Responses to the RFP, which is being funded by the Alaska Mental Health Trust, are due March 20, she said. Davidson said an important improvement the legislation will also accomplish will be to streamline the current Medicaid audit procedures which are cumbersome and difficult for both the state and health providers and growing more so under new federal requirements. Kelly’s SB 74 directs the Health and Social Services Department to develop a reform program by regulation similar to the authority for reform measures given in the governor’s bill, but the reforms would apply to the existing, not an expanded, Medicaid program. The intent of the reforms would be to steer Medicaid recipients away from using very high-cost health care like hospital emergency rooms and toward lower-cost primary care providers. Kelly’s bill also contains authorization for the department to set up voluntary Health Savings Accounts for Medicaid recipients to help pay for any out-of-pocket costs and for these to be funded, on a voluntary basis, with funds drawn from a recipients Permanent Fund dividend. The Fairbanks senator had originally contemplated including a Medicaid expansion in his bill but changed his mind when he saw a lack of support for the expansion in the Senate, Kelly said. Reform must come before expansion, Kelly and other legislators have said.

Key decisions due at end of March for Shell

A key federal decision is shaping up for Shell at the end of this month. The U.S. Bureau of Ocean Energy Management, or BOEM, expects to issue a final decision by March 31 on a revised environmental impact statement of the Chukchi Sea 2008 Outer Continental Shelf lease sale that has been contested in court by environmental groups, the director of the agency said March 13. Abigail Hopper, director of the BOEM, said a Record of Decision on a revised supplemental environmental impact statement, or SEIS, is to be issued. That will enable the agency to begin its formal review of a plan submitted by Shell for 2015 summer exploration in the Chukchi Sea, she said. Hopper also said Shell will likely not have to submit a revised oil spill containment and cleanup plan developed in 2012 and approved by the BOEM. That plan was reviewed and approved again in 2014, she said. “However, we are reviewing it again to see if any changes might be needed,” she said. Although a decision in late March puts Shell on a tight timetable, the company hopes to get its drill fleet to the Arctic in time for the open-water drill season. “We are planning to drill in Alaska in 2015,dependent of course on successful permitting, clearing any legal obstacles and our own determination that we are prepared to explore safely and successfully,” Shell spokeswoman Meg Baldino said. “We look forward to a ROD (record of decision).” Shell plans to bring two drill vessels, a drillship and a semi-submersible drilling vessel, to the Chukchi Sea this summer along with a flotilla of support vessels. In a related development, Brian Salerno, director of the U.S. Bureau of Safety and Environmental Enforcement, or BSEE, said his agency is still in a public review period for proposed special Arctic OCS drilling rules, but the rule is expected to be finalized and published in final form soon. Salerno joined Hopper in a meeting with Alaska reporters March 13 after spending a week in Alaska meeting with state and local officials, and interested groups, on the new Arctic rule. The public comment period for the rule, now in draft form, closes April 27. Shell drilled two partially-complete Arctic exploration wells in 2012, one in the Chukchi Sea and one in the Beaufort Sea, but did not return to the Arctic in 2013 and 2014 after being blocked by federal court order. That was over a lawsuit brought by environmental groups who contested the estimated probable size of a discovery in the Chukchi Sea in the environmental impact statement prepared for the lease sale in 2008. U.S. District Court Judge Ralph Beistline ordered the BOEM to reconsider the estimate, which was that 1 billion barrels might be discovered. The agency initiated a supplemental EIS, revising the estimate upward. That process will conclude with the issuing of the ROD on March 31. Salerno and Hopper said the proposed Arctic drilling rule mainly puts into regulations provisions Shell had agreed to in 2012 as conditions to its permits, such as having a stand-by rig in the region to assist in a Deepwater-Horizon-type emergency, and having an undersea well blowout capping system and oil retrieval and storage facility on hand. “There are a lot of similarities in the draft rule compared with the 2012 permit requirements but the difference is that these are now being codified so they apply to all operators, not just Shell,” he said. “The existing drilling rules apply to the OCS anywhere, but we now recognized that conditions in the Arctic are far different than the Gulf of Mexico. This rule says you bring what you need with you,” such as a backup drill rig for a relief well. However, the rule doesn’t mean the backup rig can’t also be drilling another well, which Shell plans to do in 2015, or that a rig working for one operator can’t be considered the backup rig for another company in an emergency, Salerno said. One difference is that Arctic operators will have to submit “holistic” operations plans that include not just drilling but all elements, including transportation, from the start of the project to the completion. One of the most important “lessons learned” from Shell’s 2012 experience was that Shell had no integrated plan, he said. A post-season review by the U.S. Department of the Interior on Shell’s 2012 drilling season, “showed that not all elements of the operations were synchronized. The need for better coordination, such as between the company and contractors, was one of the lessons learned in 2012,” Salerno said. That may have contributed to management decisions leading to the loss of the Kulluk drill ship when it lost its tow and ran aground off Kodiak Island in a Gulf of Alaska storm in late 2012, he said. Hopper said the integrated operations plan is not something that will have to be approved by the BOEM but having one will be required. “It will allow the company to receive feedback at an early stage,” if potential problems are seen, she said. Salerno said the Arctic drilling rule will not be overly “prescriptive,” meaning that it not specify in detail the equipment to be used. “We will specify that specific types of equipment are needed,” such as spill capping and containment systems, he said. There will still be flexibility to propose new solutions and technology. “We don’t want to shut the door on innovation. We want to be open to it,” he said. However, the agency will want to be involved in monitoring when new technologies are tested, Salerno said.

Production to decline 4.1% this year

North Slope production is declining again after producing companies managed to stem the drop in output last year, according to data from the state Department of Revenue. For the last half of 2014, production averaged 487,864 barrels per day compared with an average of 520,557 barrels per day for the same period of 2013, a 6.3 percent decline. These are confirmed production numbers, according to Cherie Nienhuis, an analyst with the Revenue Department’s Tax Division. January and February production data is still preliminary, but those figures show the year-over-year trend continuing, with 2015 production compared with January and February of 2014. John Tichotsky, the state’s chief economist, said the decline was expected because of an unusually intense summer maintenance schedule for North Slope production plants last summer, which depressed production during the July- September period. Tichotsky said the state has forecast an average of 509,000 barrels per day for fiscal year 2015, which ends June 30, or a 4.1 percent decline from fiscal year 2014. So far the production trend appears on track to achieve  that forecast. “We don’t see anything so far that would change our assumptions,” he said. “Oil prices have changed but we have not yet seen any changes in the level of drilling, well-maintenance or overall investment by the industry. “We think we’re on target,” he said, but the April forecast may lower the volumes a bit, however. With that work completed and the onset of cold weather, which improves efficiency of the processing plants, production performance has improved, Tichotsky said. The production data shows that. For the July through September period, North Slope output was 10.2 percent below the same period of 2013 at an average of 437,273 barrels per day, or 49,807 fewer barrels per day. However, the decline eased to 2.8 percent in the October-December 2014 period to an average of 538,456 barrels per day, a decline of 15,578 barrels per day from the same period in 2013. January’s preliminary data, based on the Revenue Department’s daily production reports, showed production averaging 530,209 barrels per day, or 30,755 barrels per day less than January 2014; February averaged 513,694 barrels per day, or 19,604 fewer than February 2014. A revised state revenue and production forecast will be released by the department on April 3 but Tichotsky said he doesn’t expect any big change from the previous estimate made in December. The forecast annual average of 509,000 barrels per day for fiscal year 2015 made last December is less than the 531,000 barrels per day actual average for fiscal years 2013 and 2014 due mainly to changes in the timing of industry investment in field projects, Tichotsky said. However, the Revenue Department is predicting that production will increase by 4.1 percent to about 530,000 barrels per day for each of the next two fiscal years, or essentially the same production as in fiscal years 2013 and 2014. New liquids to replace declining production will come from three projects now in construction including the Point Thomson field expected to start up in 2016 and three ConocoPhillips projects: the CD-5 production pad near the Alpine field, Kuparuk 2-S, a new production pad in the Kuparuk River field, both to be producing by the end of this year. The expected production increase is included in the state’s revenue forecast along with a gradual improvement in crude oil prices. Tichotsky said the state is really focused on keeping production greater than 500,000 barrels per day because less than that level, and particularly in winter, operating problems can occur with the Trans-Alaska Pipeline System. TAPS was originally designed to move 2 million barrels per day and is now operating at one fourth of that capacity. “At this point we expect to be above 500,000 barrels per day, on average, for the next several years,” Tichotsky said.

AGDC board approves study for larger gasline, but needs spending freeze lifted

The first new jobs created by Gov. Bill Walker’s new gas pipeline plan may well be in California, it appears. Following the governor’s directions, the state-owned Alaska Gasline Development Corp. has initiated a study of costs to do engineering to scale-up a state-backed North Slope natural gas pipeline, the Alaska Stand-Alone Gas Pipeline. The state pipeline is now planned with a capacity to move 500 million cubic feet per day. The governor wants to increase it to as much as 2.6 billion cubic feet per day. AGDC’s board approved the new study Thursday. It is contingent, however, on Walker’s lifting of an earlier administrative order freezing AGDC’s unspent funds as a spending-restraint action. To do the cost study, AGDC will have to rely on engineering and design contractors with offices in California who have just completed final engineering on a smaller gas pipeline designed as a backup to get gas from the slope to Alaska communities in case the large industry-led project does not move forward. At the peak of the engineering effort on the smaller gas project there were 130 engineers at work in California for Fluor Corp.-WorleyParsons Ltd. joint-venture Arctic Solutions. Engineering companies CH2M Hill and Michael Baker Jr. are also working for AGDC. Walker’s plan has meanwhile unsettled companies now engaged in a larger North Slope gas pipeline and LNG project with the state as a 25 percent partner. BP, ConocoPhillips, ExxonMobil Corp., and TransCanada are the state’s partners in the large Alaska LNG Project. The industry partners now worry that the governor is developing a competing project, raising uncertainty about which approach the state will really support, the partnership with industry or a state-controlled gas project. “Things have been a little strained lately, since the governor’s announcement (in a newspaper op-ed on Feb. 18),” AGDC President Dan Fauske told the corporation’s  board Thursday’s meeting. “There are some strains in the relationship (between the state and the industry partners) but we think we can work through this.” AGDC board Chair John Burns said it is critical that the state maintain its current good relationship with industry partners in the Alaska LNG Project, “but we do have to maintain a viable alternative,” with the state-led ASAP project in case the large initiative falters. However, AGDC Commercial Vice President Joe Dubler warned the board that moving to a larger project may violate terms of agreements between AGDC and its industry partners over the sharing of confidential information. Those agreements, which are themselves confidential, refer to the 500 million cubic feet per day capacity of the state-led pipeline. Dubler said there are provisions that the agreements can be altered, however. Meanwhile, the possible new direction for the state has caused federal regulatory agencies to take a step back from a pending revised environmental impact statement, or EIS. ADGC Vice President of Engineering Frank Richards told the board that the U.S. Army Corps of Engineers notified the state corporation March 2 that it was suspending work on the EIS until there is more clarity on the future of the project. In a related development, legislative leaders, who are also anxious to maintain smooth relations within the gas partnership have introduced a bill in the Legislature limiting the ability of Walker to spend money to develop a competing project. The legislation was introduced March 2 by House Speaker Mike Chenault and seven other House members. It is expected to move out of the House Resources Committee March 13 or 14, according to Rep. Ben Nageak, D-Barrow, co-chair of the committee. For now, AGDC’s board has directed its staff to develop cost estimates and actions needed for preliminary engineering of larger state pipeline. Richards said an estimate for the costs of engineering for additional compression and the thicker pipe needed to move more gas will be available, but that estimates for reengineering on a gas treatment plant on the North Slope will take longer. Final design and engineering of the gas treatment plant and pipeline were completed for the smaller 500 million cubic feet per day capacity pipeline in January and AGDC must now see whether engineering and design contractors who worked on that are still available to estimate costs for the resized project, Richards told the board. The smaller pipeline is estimated to cost $10 billion. A larger project would cost much more, but how much more is unknown until preliminary engineering is done. The re-scoping would also see the state pipeline extended 12 miles to tidewater at Cook Inlet from its present terminus at a connection with the Enstar Natural Gas Co. regional gas distribution system in the Matanuska Susitna Borough north of Anchorage. At present the state pipeline has no LNG plant component. That could be added or the state could partner with a third party LNG developer.  A big unknown on how far the governor will be able to take his new plan is how much engineering AGDC can do for the $150 million the state corporation has on hand from previous appropriations by the Legislature. The estimates now being developed will answer that. If the funds are insufficient to develop enough engineering for a firm cost estimate Walker will have to go back to the Legislature for more money. Given the current sour state of relations between the governor and lawmakers, further appropriations of state funds seem unlikely, particularly given the state’s deteriorated financial position due to lower oil production tax and royalty revenue. Alaska is projected to run a combined $7 billion to $7.5 billion in deficits for the current and next fiscal years, and legislators are having to make sharp cuts to state agencies and education funding.

State estimates $150B to treasury if ANWR ever opened

Alaskans have long believed oil discovered in the coastal plain of the Arctic National Wildlife Refuge could help keep the Trans-Alaska Pipeline System operating and also replenish the state treasury. It may be a pipe dream because the federal government shows no sign of opening the coastal plain to further exploration and Congressional approval is required for any exploratory drilling or leasing. Interior Secretary Sally Jewell, who denied the State of Alaska’s proposal for new seismic exploration of the ANWR coastal plain and is awaiting the outcome of a court case challenging that decision, wants to make it wilderness, a permanent lockup. But what if? What if there were exploration, and discoveries? How much oil could there be? State officials told legislators in February the revenue to the state treasury could total more than $150 billion over 50 years. ANWR’s coastal plain, in the eastern North Slope, is thought by geologists to have the best potential for major discoveries of any unexplored onshore area of the U.S. Major oil fields have been discovered in the central North Slope, including the very large Prudhoe Bay and Kuparuk River fields. There is potential for further discoveries in this area but they are expected to be smaller. The southern North Slope, and the huge 23-million-acre National Petroleum Reserve–Alaska on the western Slope, are generally thought by geologists to be prone to natural gas discoveries although some oil will almost certainly also be found. The most informed estimate on ANWR’s coastal plain area came from the U.S. Geological Survey in 1998, which made a “mean” estimate of 7.7 billion barrels of recoverable oil that could be discovered. “Mean” is basically mid-way between high and low estimates. Whether oil is really there isn’t known for sure. The USGS worked with data from 1,180 miles of two-dimensional seismic program conducted between 1983 and 1985, plus what is known about the regional geology. The only exploration well drilled in ANWR, in a 91,000-acre in-holding of private lands owned by Kakovik Inupiat Corp. and Arctic Slope Regional Corp., was drilled in the early 1980s by BP and Chevron Corp., and the results are still secret. No matter what the drilling showed, development of even these private lands are blocked unless Congress decides to open the rest of the costal refuge. Still, state legislators in Juneau want to know what Alaskans may be missing out on. In mid-February, the House Resources Committee asked the state departments of Natural Resources and Revenue to develop the most plausible oil discovery and production scenarios based on that is known, and to derive state revenue estimates from those. The two agencies presented their results to the committee on Feb. 12. Paul Decker, acting director of DNR’s Division of Oil and Gas, described ANWR’s regional geology in the so-called “1002” area, a coastal plain area named for the section of the law in which Congress designated for additional study of petroleum resources in the Alaska National Interest Lands and Conservation Act of 1980, the federal law that created the refuge. Decker said the best prospects for discovery are in the western third of the coastal plain, which state geologists believe to hold the most oil potential. Of the 7.7 billion barrels of resources estimated to be in the 1002 area, 6.4 billion barrels are expected to be in the western third. That is about five times the oil potential of the eastern two-thirds of the coastal plain. “The northwestern one-third of the coastal plain is geologically simpler and more favorable to hosting oil accumulations,” Decker told the committee. The area is also adjacent to state lands across the Canning River where companies have made discoveries at Point Thomson (gas, liquid condensate, and oil), and Sourdough (oil). Oil has also been discovered offshore the 1002 area, with the Kuvlum well in 1993 and “Hammerhead” (where Shell is exploring) in 1985. Geologists in the division did further analysis, predicting that most of the accumulations that might be discovered would be in the 32 million-barrel range to 256-million-barrel range, but accumulations of 1 billion barrels were also possible. Based on that analysis, the Department of Revenue developed possible production and oil royalty and tax estimates. Ken Alper, director of the Tax Division, presented the conclusions, assisted by Dan Stickel, assistant chief economist. The scenario presented by Alper and Stickel would have permission granted by Congress to explore in 2016 and leases issues between 2017 and 2019. Exploration would begin in 2019, with the first field located in 2022, and with its development beginning that same year. First production would be in 2026. From that point on, the scenario foresees one new field discovered and brought into production every two years so that there would be 25 fields in total developed by 2074. The assumed size of discoveries vary along the lines of the estimates by the Division of Oil and Gas but most of the new fields would be between 64 million barrels and 512 million barrels of recoverable resources. All prices and costs in the modeling assumed 2015 constant dollars and an oil price of $110 per barrel along the lines of the Revenue Department’s very long-range price forecast (a $90 per barrel case was also considered, however). The modeling assumes no gas being developed, although surely there would be gas discovered also. Given these assumptions in the modeling, a “base case” of 7.1 billion barrels of oil developed and produced until 2075 would bring $150.9 billion to the state treasury, although the number could be higher, or lower, depending on the amount of oil found. The production profile in the base case was about 560,000 barrels per day, with a high case, with more oil discovered, of 760,000 barrels per day and a low case, with less oil discovered, or 350,000 barrels per day. The required investment by industry would reach $5.75 billion per year in the development, pre-production phase, with continuing investment all through the operating lives of the fields. Because of tax credits in the current state production tax the state treasury would not begin to experience income net of the tax credits until 2030 or 2031, but revenues would then increase rapidly to a peak of about $4.9 billion per year in 2045. Revenues would the taper off gradually, but even by 2075, the end of the period modeled, there would still be $3.3 billion per year net to the state treasury.

Exploration payrolls down as producing mines add jobs

Minerals employment and industry spending dropped in 2014 compared with 2013 and 2012 but the decline is attributed mostly to sharp declines in expenditures for exploration. The state’s larger producing mines added jobs in all three years, according to the latest minerals industry economic report by McDowell Group. The report was recently released by the Alaska Miners Association. McDowell Group is a Juneau-based economic research firm.  The latest report shows 4,400 employed in mining in Alaska in total during 2014, down from 4,600 in 2013 and 4,800 in 2012. Payroll is also down, to $620 million in 2014 from $630 million in 2013 and $650 million in 2012. However, payments to local governments, in taxes and in-lieu-of-tax payments, rose in 2014 relative 2013, to $17.4 million paid in 2014 compared with $17 million in 2013. Payments to municipalities totaled $21 million in 2012. The totals include all jobs related to mining including exploration, metals and coal production activities and gravel mining. Counter to the overall trend, the state’s six larger producing mines have been adding jobs mostly due to increased production and new development work in the mines. For example, the Fort Knox gold mine near Fairbanks, a surface mine, employed 650 in 2014, up from 630 in 2013 and 548 in 2012. The Greens Creek Mine near Juneau, an underground multi-metals mine, employed 415 in 2014, 400 in 2013 and 390 in 2012; the Kensington Mine, an underground gold mine also near Juneau, employed 320 in 2014, 306 in 2013 and 300 in 2012; Pogo, another underground gold mine near Delta east of Fairbanks, employed 320 in both 2013 and 2014 (data for Pogo for 2012 was inconsistent in the McDowell reports); the Red Dog lead-zinc mine north of Kotzenue, a surface mine, employed 610 in 2014, 639 in 2013 and 604 in 2012. The Usibelli mine near Healy, Alaska’s only coal mine, employed 140 in both 2014 and 2013, and 124 in 2012. All of the state’s producing mines are doing well, but there has been a sharp drop in exploration spending over three years caused mainly by declines in metals prices, the recent weakening in China, a strong importer, and continued economic weakness in Japan and Europe. Exploration spending dropped to $67 million in 2014, down from $180 million in 2013 and $275 million in 2012, according to the McDowell report. Exploration spending is a barometer for the mineral industry’s future because it results in new discoveries, a few of which typically become producing mines. Mines tend to have long lives, typically several decades, once they get into production but eventually the ore is depleted and new projects need to be coming into the pipeline, which is a result of continued exploration. In terms of immediate impact, the falloff in exploration tends to affect a number of smaller support companies including air taxi firms, camp and logistics service operators and a variety of technical-support firms such as laboratories. Meanwhile, work is continuing on eight new mine development projects that are a result of discoveries made decades ago. Seven of these are far enough along in development planning that estimates of new jobs in production can be made. Those seven would add 3,615 permanent jobs if all are developed. These include: • The large Donlin Gold project near Crooked Creek, in the mid-Kuskokwim River region, which could employ as much as 1,400 production workers. Donlin Gold would be a large surface mine and it is now in an advanced stage of environmental impact statement work for its project after which a decision on construction could be made. • Pebble, near Iliamna southwest of Anchorage. Although it is snarled in controversy and attempts by the U.S. Environmental Protection Agency to foreclose development, the large Pebble gold/copper/molybdenum project could create 1,000 production jobs. It would be a surface mine initially and possib ly an underground mine in later years to tap deep mineral resources. Pebble has done extensive exploration and is at an advanced stage of engineering and mine planning. However, the company is seeking to resolve legal issues brought by the EPA’s attempt to foreclose mining before permits can be filed for development. Both Donlin Gold and Pebble are in two of the most economically-depressed regions of the state where jobs are badly needed. • Livengood gold project — North of Fairbanks, International Tower Hills is continuing development planning on the large Livengood gold project, a surface mine which could create 450 production jobs if it is developed. The company is now developing a new mine plan to reduce costs. • PacRim Coal, near Anchorage — The company is working on development of the Chuitna coal project on the west side of Cook Inlet, about 50 miles west of Anchorage. The project is now at an advanced stage of permitting. Chuitna would be a surface mine and it would create 300 to 350 production jobs if the mine is built. • Wishbone Hill — North of Palmer, in the Matanuska-Susitna Borough, Usibelli Mine Inc. is working on development of the Wishbone Hill coal deposit. If developed it would create 75 to 125 production jobs. • Niblack and Bokan Mountain — In southeast Alaska two new mining projects are in advanced stages of development planning on southern Prince of Wales Island, near Ketchikan. Niblack would be a multi-metals underground mine. If developed Niblack could create 200 production jobs. The second, Bokan Mountain, is a potential rare earths mine, also underground. If constructed it could employ 190. An eighth minerals development project, for which the McDowell Group report did not include potential jobs, is the Upper Kobuk Minerals Project, a joint-venture of NovaCopper Inc., an exploration company, and NANA Regional Corp., the regional Native development corporation in northwest Alaska, which is also a large landowner. This includes two projects, both significant copper discoveries, that are relatively near each other in the western Brooks Range, the Arctic deposit in the Ambler mining district and Bornite, on the upper Kobuk River. Both are in advanced stages of exploration and development plans have been done for Arctic. The region is remote, however, and surface infrastructure would have to be built to the area before mines could be developed. The State of Alaska is working on a plan for a minerals access road to the region from the Dalton Highway, which transects the central Brooks Range, but the project is on hold at the order of Gov. Bill Walker.

Walker outburst further strains relations with legislators

Gov. Bill Walker’s temper tantrum against House leaders in a March 2 press conference has brought his relations with the House, and quite likely the Senate, to a frigid level, posing a threat to the governor’s major initiative, an expansion of Medicaid. Medicaid expansion was already in trouble in the House, but the sour relationship has almost certainly doomed any chance of it happening this session. Health and Social Services Commissioner Val Davidson had hoped to get the expansion underway July 1. Walker’s blast at the House was over a bill introduced in that body March 2 that would limit the administration in developing a state-owned gas pipeline until it is known that a large gas project, in which the state is a 25 percent partner, will not advance. On Feb. 27, a House Finance subcommittee stripped the Department of Health and Social Services budget of its authority to receive new federal Medicaid funds under an expansion of the program. House leaders, including House Finance co-chair Rep. Mark Neuman, R-Big Lake, also urged the governor to introduce a bill authorizing the Medicaid expansion. In the Senate, Senate Finance Committee co-chair Sen. Pete Kelly, R-Fairbanks, is reported to be working on a Medicaid bill that will link expansion of the program with reforms. Bringing in a bill to effect the expansion will almost certainly put any enactment over until the 2016 session because committee hearings will be needed in both House and Senate and the 2015 session is past the halfway mark to adjournment, scheduled for the 90th day, or April 20. Davidson has told legislative committees that her department is already working on reforms that would save money but Kelly is reported to be considering further steps. Those could include changes in the amounts of reimbursement allowed to health care providers, even under the existing program. Under Medicaid, which is now funded 50-50 between the state and federal governments, states set the levels of reimbursement, or payment, to medical providers, and Alaska’s reimbursement levels are more generous than many other states. The health care community has made Medicaid expansion a priority because it would extend health coverage to several thousand low-income Alaskans who do not have medical coverage because they are caught in a gap between minimum income requirements of federally-subsidized health insurance under the Affordable Care Act and the maximum income requirement of the existing Medicaid program, which is administered by the state. The gap was created when former Gov. Sean Parnell did not expand Medicaid as permitted under the federal law. Expanding Medicaid would raise the maximum allowable earnings limit, bringing those caught in the gap under coverage. Hospitals in the state strongly support the expansion because it would reduce the number of uninsured patients they care for and losses they incur in writeoffs. The Alaska Native community also supports it because it would strengthen the finances of rural Tribal health care organizations by allowing them to bill Medicaid for health services to Native people in Tribal facilities. On other issues, Finance committees in the House and Senate continue work on the state budget, which is being cut this year due to sharply-reduced revenues from oil. House Finance subcommittees turned in their recommendations to the full House Finance Committee Feb. 28 reducing spending for all agencies. In many cases the subcommittees went beyond Walker’s recommendations, reducing spending even more. The House committee held public hearings on the recommendations this past week. Meanwhile Senate Finance subcommittees are beginning their reviews of agency budgets and will consider the House subcommittees’ recommendations although they have not yet been formally accepted by the House. Time zones, Interior Energy Project On another issues, Alaska may soon be on track to return to multiple time zones. Sen. Anna MacKinnon’s Senate Bill 6, ending daylight saving time changes statewide in Alaska, has been changed, the senator said. The bill’s new version, as it was reported out of the Senate Finance Committee March 3, will authorize the governor to petition the U.S. Department of Transportation to hold hearings in Alaska on whether Alaska should return to multiple time zones, such as allowing Southeast Alaska to be on Pacific time, which it was until 1983 when Alaska’s five time zones were consolidated, and to allow northwest and western Alaska to be one or more hours earlier than Southeast, Interior Alaska and Southcentral time. If the U.S. DOT does not act on that and leaves Alaska Standard Time in place, SB 6 would end the switch to daylight saving time for Alaskans as of Jan. 1, 2017. In a March 2 briefing by Senate leaders, MacKinnon released a poll of 4,000 Alaskans that showed 78 percent in favor of going off daylight savings time changes. “Every region, including Southeast, showed strong support for eliminating the time change,” MacKinnon said in the briefing. Even business operators responding to the poll support the elimination of daylight saving time, she said. The main resistence for the proposal in the Senate has come from Sen. Dennis Egan, D-Juneau, who says many of his constituents and the regional tourism industry prefer longer periods of light in the evenings that wouldn’t be possible with daylight saving time. “For us, it means it gets dark at 9 p.m.,” when the spring time-change comes, Egan said March 4. One tourism operator said the shorter evening hours could cut as much as 30 percent of revenues from evening sightseeing flights and other activities for tourists that are an add-on to cruise ship trips. Before Alaska’s time zones were unified in 1983, Southeast Alaska was on Pacific time even though geographically it would be an hour earlier, as it is now, because the Southeast panhandle is farther west than the Pacific Northwest. In those days Anchorage and the Interior were two hours different than Southeast and three hours off Seatttle, with Nome and Kotzebue one more hour earlier, or three hours off Southeast and hours off Seattle. In those days Yakutat, between Southeast and Southcentral, was Alaska’s only community on Yukon time, which was then one hour earlier than Juneau and one hour later than Anchorage. Now Yukon is on Pacific time, which means clocks in Whitehorse, Y.T. are set an hour later than Skagway, Haines and Juneau, which are directly south but across the Alaska border. Sen. Donny Olson, D-Nome, said he supports the elimination of daylight saving time because it will enhance safety, creating more light for air taxi operators for example. “You can see where you’re trying to land,” he said. Olson is a pilot and former air taxi operator. On other issues, energy legislation is active in the state House. The House Energy Committee, co-chaired by Rep. Liz Vazquez, R-Anchorage, and Rep. Jim Colver, R-Palmer, has reported out House Bill 105, which changes existing state law to allow the Interior Energy Project, the state-backed plan to get more natural gas to Fairbanks, to purchase liquefied natural gas, or LNG, from any region, meaning Southcentral Alaska, instead of just the North Slope. Previously the Alaska Industrial Development and Export Authority, the state development corporation, has worked with an investor, MWH Global, on a North Slope LNG plant with the liquefied gas trucked down the Dalton Highway. Costs on that plan turned out higher than expected. In order for AIDEA to switch the project so LNG can be purchased from Southcentral a change in the law is needed, which HB 105 accomplishes. Hilcorp Energy and WesPac Midstream would like to supply gas or LNG to the Interior through the AIDEA project. The bill also expands and updates AIDEA’s limits for all of its project and program financing. The bill is now in the House Resources Committee but has long way to go in the House, with referrals also to the Labor and Commerce and Finance Committees. A similar bill in the Senate, Senate Bill 50, is in the Senate energy committee and has seen no action. It has two other committee referrals there, to the Resources and Finance committees. Meanwhile, a bill dealing with electricity and utilities’ purchases of power from independent power producers is also before the House Energy Committee, where it has become controversial. Rep. Tammie Wilson, R-North Pole, is the sponsor of HB 78, which would provide a standard for utilities in purchasing power from independent producers. A wind power operator in Delta, Mike Craft, has been attempting to expand his project and sell more power to Golden Valley Electric Cooperative, the Interior power co-op, but has been blocked by GVEA’s position in what the price should be. Craft argues that utilities in Alaska should be required to base the price for purchased power on their highest-cost unit that would be shut down if lower-cost power, such as wind power, was purchased. Craft argues GVEA should shut down or curtail operations at its oil-fired plant at North Pole if he can supply wind power from Delta for less. However, GVEA and other utilities say that existing law and regulations allow them to offer a price based on their average cost among all sources of power, which in GVEA’s case would allow low-cost coal power and hydro to be averaged into the formula. This brings down the price at which the co-op would buy power for from an independent producer. Craft said it is too low. Purchases of power from independent power producers is common in all other states and the price is set at the highest “avoided cost.” Alaska is alone among the state in allowing utilities to base their offers on the average cost. Wilson argues the practice is basically anti-competitive, allowing the regulated utilities a monopoly on power production, except for the state-owned Bradley Lake hydro plant, by keeping out competition from independent producers like Craft. Utilities have pushed back against HB 78, however, arguing that the bill indirectly imposes other costs of them. Hearings continued on the bill March 3 in the House committee.

Alaska LNG Project partners discuss progress

Things were going well for the large Alaska LNG Project as of Feb. 18. North Slope producers and the president of Alaska Gasline Development Corp., the state-owned gas company, presented an update on the Alaska LNG Project to the Senate Resources Committee. Steady progress was being made in negotiations of key agreements needed in 2015, which would set the stage for a critical decision in 2016 on proceeding to detailed engineering, the group said. None of the state officials at the hearing, including Dan Fauske, president of AGDC; Randy Hoffbeck, Commissioner of Revenue; Donna Keppers, Deputy Commissioner of Revenue, or Marty Rutherford, Deputy Commissioner of Natural Resources, dropped a hint at the bombshell their boss, Gov. Bill Walker, would drop the next day, Feb. 19, in a newspaper op-ed column. Walker announced in the column that he would seek to expand the state-backed smaller gas pipeline to a size that could compete with the Alaska LNG Project, in which the state is a 25 percent partner. It is not known if the state officials at the hearing were aware of what the governor would announce, however. On the day of the presentation everything seemed upbeat for the bigger project. The producer companies at the table had no clue what was coming. Opening the presentation, Dave Van Tuyl, BP’s Alaska regional manager, said the teams working on the project, including the state’s team, were making steady progress. “The right parties are aligned,” Van Tuyl said. “We have a lot of work to do but we’re on a track for a 2016 decision to move to FEED,” or Front-End Engineering and Design, a major step for the project because it will involve a considerable investment of more than $2 billion for the parties involved. ConocoPhillips’ Darren Meznarich, the company’s Project Integration Manager for Alaska North Slope Gas, said the agreements now being negotiated include commercial and fiscal issues, including a gas supply agreement among the parties including the state to cover instances of production upsets or other supply interruptions; a “governance” agreement that spells out how decisions are to be made, and recommendations to the Legislature on an agreement that will ensure state stable fiscal terms for the producers. “ConocoPhillips would invest according to our share of the gas, but once we make the investment we must be assured that we will receive our share of LNG,” he said. ExxonMobil Senior Commercial Advisor Bill McMahon told the committee a lot of progress has been made over the last year including the Legislature’s passage of Senate Bill 138, which laid out the framework for the state’s participation with the North Slope producers and TransCanada Corp. “From where we sit today there are still challenges but we are moving forward,” McMahon said, Vincent Lee, of TransCanada, said his company and the state are working separately on an agreement for the state to ship its royalty and tax share of gas through TransCanada’s portion of the gas pipeline and North Slope gas treatment plant. The state royalty and production tax would be taken “in-kind” or as gas under the agreement, although the state must initiate a formal process to take the in-kind share sometime this spring. Lee said TransCanada and the state are due to sign the contract in late 2015. Like many of the other agreements, such as the fiscal terms, this will require legislative approval. In his presentation to the committee, Fauske, the president of AGDC, said things were going well in the relations between the state corporation and the private parties in the Alaska LNG Project. “We are sharing (confidential) data and ADGC has undertaken certain work on behalf of the Alaska LNG Project to avoid duplicated efforts,” Fauske said. Van Tuyl, of BP, said there were certain elements outside the control of the project teams such as the efforts of the state and municipalities along the pipeline route to agree on an alternate plan for property taxes, in a Payment-in-Lieu-of-Tax, or PILT, agreement, but said the state was making good progress with a Municipal Advisory Group, or MAG, of mayors formed to negotiate a PILT. Revenue Commissioner Randy Hoffbeck said the MAG was unable to come to an agreement by late December, as was hoped, but are now considering a plan they are likely to accept. The agreement has to be ratified by the Legislature and the hope was that this might happen in 2015, but that now appears less certain, Hoffbeck told the committee. In a comment, Rep. Mike Hawker, R-Anchorage, said that benchmarks for agreements are important but that the negotiating teams should be wary of letting the project be schedule-driven, which can lead to costly problems later if decisions are made in haste. “There are major benchmarks in 2016, such as the FEED decision, and minor benchmarks in 2015, such as the PILT. We were hoping to receive the majority of these agreements in August (in time to prepare for a special session of lawmakers) but my sense now is that we should not presume that this will happen,” Hawker said. “I do know that you’re working hard to get us to the FEED decision in 2016.” Rutherford and Keppers were also upbeat in their remarks to the legislators. Rutherford, newly returned to the DNR (she held the same position previously) said she signed a confidentiality agreement in December so as to be briefed on the progress by the state’s negotiating teams. “I was impressed by the quality of the work that was being done,” she said. Keppers, previously an audit master and deputy commissioner at the Revenue Department, said he had worked on governance and tax issues on the project teams under the previous administration, but is now exposed to the full spectrum of issues. “I was part of the detailed work (previously) but I now can see the global picture,” she said. “The schedule is aggressive, but this is an exciting project to work on.” On the municipal tax issue, Hoffbeck told the committee that the PILT is an important issue for the state as well as the municipalities. “It’s not just a municipal issue. The state will have 40 percent or more of these (property tax revenues),” he said. “It’s a big issue for the project. On a $60 billion project the 20-mil state property tax amounts to $1.2 billion a year and the state collects 40 percent of that.”

State geologists raise estimates for Inlet gas

State geologists have now increased the amount of natural gas they believe can be economically produced from known fields in Cook Inlet. The state Division of Oil and Gas concluded, in a recent study, that there may be 440 billion cubic feet more gas in the Inlet’s gas fields than previously estimated. About 1.1 trillion cubic feet of recoverable gas reserves were estimated in a 2009 resource assessment by the division, and the new figure is about 1.54 trillion cubic feet of gas, according to Paul Decker, acting director of the state Division of Oil and Gas. Decker presented the estimates in a briefing to an energy task force of Commonwealth North, an Anchorage-based business and public policy group. The estimates are derived from data available to the public from a handful of the Inlet’s larger producing gas fields and do not include resources that could be added from three recent gas discoveries where the estimated volumes are still confidential, Decker said. It’s not known, however, whether the new estimates mean there’s enough gas in the Inlet to supply future utility needs, a possible restart of the Agrium fertilizer plant near Kenai and possibly supplying gas to Fairbanks. That will probably take continued exploration and investment in the producing fields, Decker said. Gas from the North Slope will still be needed someday, he said. The increase in estimated reserves is good news, though, because just a few years ago the regional utilities were seriously worried about depleted supply from the region’s gas fields. Imports of liquefied natural gas were being studied as a short-term solution. What turned things around was the entry of Hilcorp Energy into Cook Inlet and that company’s investment and aggressive redevelopment of the Inlet’s older fields, Decker said. The apparent shortage also stimulated state geologists to reassess what they knew about the Inlet. Both the 2009 resource estimate and a 2013 update of that assessment included estimates from 28 fields that are known in the Inlet, and a more detailed look at three of the larger fields in the 2013 update. In the 2014 update, there was a more detailed look at four additional gas fields, for a total of seven, of the 28 fields surveyed in 2009. Meanwhile, there is one new producing field added in the Inlet since 2009. It is the small onshore Kenai Loop field that was discovered and developed by Buccaneer Resources. Buccaneer went bankrupt due to unrelated financial issues but Kenai Loop is still producing. The field is now owned by another company, AIX. If the new discoveries are developed, additional reserves would be added in Cook Inlet. Decker said the three new discoveries include one by Furie Operating LLC, at its “Kitchen Lights” find in upper Cook Inlet; BlueCrest Energy LLC at the “Cosmopolitan” offshore deposit near Anchor Point, and NordAq Energy LLC’s “Shadura” onshore gas discovery on the Kenai Peninsula. Resource estimates by Furie are not public but the production facilities planned by the company, to be installed this summer, will have a capacity to produce 80 million cubic feet of gas per day or 30 billion cubic feet per year, Decker said. Production facilities and wells planned at Cosmopolitan, where installation is hoped to be done in 2016 and 2017, will be capable of handling 22 billion cubic feet of gas per year, he said. Production potential at the Shadura onshore discovery is confidential, but the deposit is within the Kenai National Wildlife Refuge, which means that permitting for development would be complicated. The subsurface mineral rights are held by Cook Inlet Region Inc. but surface production facilities must adhere to regulations of the refuge. “We believe a tremendous amount of new gas can be discovered in the Inlet,” but it will be found in smaller deposits, Decker said. “Most of the large structures have been drilled,” in the initial exploration of the Inlet, Decker said. These were the large anticline structures easily seen with the type of 1960s-era two-dimensional seismic exploration imaging technology used when the Inlet was first explored. Modern three-dimensional seismic now in use is capable of spotting smaller structural traps, he said, and more complex stratigraphic reservoirs. To date about eight trillion cubic feet of gas has been produced from the Inlet, Decker told Commonwealth North. The Inlet produces about 115 billion cubic feet of gas yearly including some “associated” gas produced with oil, according to Division of Oil and Gas data. Electric utilities in Southcentral Alaska and Enstar Natural Gas Co., the regional gas utility, consume about 90 billion cubic feet of gas yearly, and the remaining gas is used as fuel on oil and gas production platforms and by Tesoro, which owns a refinery at Nikiski. “The 90 billion cubic feet a year of demand does not include potential gas demand if the Agrium plant were to restart, or if gas were provided to the Donlin Creek mine,” if that gold project were developed, Decker said. It also does not include 4 or 5 billion cubic feet of gas that might be shipped to Fairbanks as liquefied natural gas, which is now being discussed. If other potential demand in the Interior were included, the demand for LNG might reach 8 billion cubic feet per year.

Interior Dept. releases proposed Arctic drilling rules

The U.S. Interior Department issued its long-awaited special Arctic drilling rules Friday. The proposed rule will be held for a 60-day public review period before being finalized, the department said in its announcement. “The proposed Arctic-specific regulations released today focus solely on offshore exploration drilling operations within the Beaufort and Chukchi Sea OCS planning areas,” the agency said. “The proposed regulations codify requirements that all Arctic offshore operators and their contractors are appropriately prepared for Arctic conditions and that operators have prepared an integrated operations plan that details all phases of the exploration program for purposes of advance planning and risk assessment,” the announcement said. “Exploration operators would be required to have region-specific oil spill response plans, have prompt access to source control and containment equipment, and have available a separate relief rig to timely drill a relief well in the event of a loss of well control.” Many of these requirements were conditions Shell had agreed to voluntarily in its 2012 Arctic exploration program, but they are now being codified into regulations that will apply to all companies exploring in the Arctic. The U.S. Bureau of Safety and Environmental Enforcement, or BSEE, an agency of the Interior Department, developed the proposed rules. Shell said it is still studying the actual language of the draft rules. Company spokeswoman Meg Baldino said, “The paramount concern in all of our operations is safety and environmental protection. We support regulations that further these imperatives in the Arctic, provided they are clear, consistent and well-reasoned.  “While we review the draft Arctic Regulations put forward by the Department of Interior, we will continue to work with federal agencies, the State of Alaska, local communities, and contractors to develop a 2015 drilling program that achieves the highest technical, operational, safety and environmental standards.” In the announcement, Interior Secretary Sally Jewell said, “The Arctic has substantial oil and gas potential and the U.S. has a long-standing interest in the orderly development of these resources, which includes establishing high standards for the protection of this critical ecosystem, the surrounding communities, and the subsistence needs and cultural protection of Alaska Natives.” Release of the proposed rule is one more step in clearing regulatory obstacles confronting Shell as it plans to resume exploration in summer, 2015. In a related development, the Bureau of Ocean Energy Management recently released a final supplemental environmental impact statement to correct a defect in the environmental assessment on the 2008 OCS lease sale held by the Interior Department.

BLM awards $10M contract for NPR-A legacy well cleanup

The U.S. Bureau of Land Management has let a $10 million contract to Marsh Creek LLC to remediate abandoned oil wells drilled decades ago at Umiat in the National Petroleum Reserve-Alaska. This is the first phase of what will be a $50-million program to clean old well sites in the federal reserve, BLM’s Alaska manager, Bud Cribley, said in an interview. The agency is tapping $50 million made available through efforts by Alaska U.S. Sen. Lisa Murkowski. “We’ll be starting work as soon as possible. We had previously let a contract for work on one well (before the $50 million became available) but now we want to ‘piggyback’ on the contractor’s mobilization to do work on more than one well,” Cribley said. Umiat is a support facility in the far southeast part of the reserve near the Colville River that is the boundary of the NPR-A. Early exploration of what was then the Naval Petroleum Reserve No. 4 was carried out by the U.S. Navy in the 1940s and early 1950s. Later, after the reserve was transferred to the U.S. Interior Department in 1975, drilling and core holes were done by the U.S. Geological Survey. Many of the government-drilled wells were left in an unsafe condition, however. BLM, which administers the renamed National Petroleum Reserve–Alaska, has been working for years to clean up the wells with increments of funding, the latest of which is the $50 million Murkowski was able to get. BLM Alaska spokeswoman Lesli Ellis-Wouters, said, “We are plugging Umiat wells 1, 3, and 11 via an interagency agreement with the U.S. Army Corps of Engineers. The Corps has awarded the contract to Marsh Creek LLC. “In addition to the well plugging, Marsh Creek will remove the old wellheads from Umiat wells 4, 8, and 10. Total cost of this project including mobilization and demobilization is approximately $10 million. Mobilization is slated to begin March 1.” Crumbley said BLM has identified 18 old wells as presenting the most risk and hazard. The $50 million should be appropriate to clean those, he said, but a lot will depend on how contractors mobilize equipment, he said. If a rig and crew can mobilize to do several wells in one area it will save money. The U.S. Navy drilled 91 exploration wells and geologic test holes between 1943 and 1952, according to information made available by BLM. Exploration resumed when Congress transferred the reserve to the Interior Department, and another 28 wells were drilled by the USGS. In 2004, BLM plugged four wells in the Umiat area, well numbers 3,4,8 and 10, but only surface plugs were set. “Site conditions limited the plugging options due to equipment stuck in the well,” BLM said in a presentation on the problem. Beginning in 2005, BLM initiated an emergency program to plug and remediate four wells at the Beaufort Sea coast where coastal erosion was resulting in pollution being released to the ocean. The cleanup, which involved plugging the wells as well as remediating old “reserve” pits, where waste oil was stored, cost $52 million. The wells were “JW Dalton”, East Teshekpuk, Atigaru and Drew Point. Overall since 2002, 18 wells were plugged by BLM, at a cost of $80 million. Of wells remaining to be plugged, many are clustered in the Barrow area, with some of these done by the North Slope Borough. Others are clustered in the Simpson Lagoon area east of Barrow. Others are in the Umiat area in the far southeast NPR-A.

Leaders rally against Army force reductions

Community leaders in Anchorage and Fairbanks are rolling out the red carpet for a Pentagon team visiting Alaska that is considering possible reductions of Army troops at Joint Base Elmendorf-Richardson in Anchorage and Fort Wainwright in Fairbanks. The visitors will be in Anchorage Feb. 23 and in Fairbanks Feb. 24. The loss of a major combat unit at either base could be severe, said Bill Popp, president of Anchorage Economic Development Corp. “The loss of a brigade at JBER could total 5,000 troops and 9,000 dependents, a total loss of 14,000 population, which is 4.5 percent of Anchorage’s overall population,” Popp said. The Army payroll in Anchorage is over half-a-billion dollars yearly with additional Army civilian worker payroll, according to AEDC data. Jim Dodson, CEO of Fairbanks Economic Development Corp., said the impact on that community could be even more severe because it is smaller than Anchorage. “We see a potential of losing 5,800 troops plus dependents, which could mean a total loss of 14,000 population. That’s a big deal for us,” Dodson said. The military accounts for 30 percent of employment in the Fairbanks region and 35 percent of total wages, he said. Popp said the Army has committed to reducing its strength by 120,000 soldiers by 2017 under the “Army 2020 Force Structure Realignment,” which grew out of the 2011 Budget Control Act. Reductions of units at 30 U.S. Army installations are being considered. AEDC and other community organizations are organizing what is hoped to be a big community turnout at the “listening session” being held by the visiting Army delegation at the Dena’ina Civic and Convention Center on Feb. 23. Earlier in the day the visitors will tour JBER facilities, hear about the economic importance of the military at a luncheon, also at the Dena’ina, and tour local university, school and medical facilities later in the day. The luncheon is being sponsored by the Anchorage and Eagle River Chambers of Commerce as well as the Alaska Chamber, Popp said. Popp believes Anchorage has a pretty good story to tell. “The criteria we will be judged on includes the strategic importance of the installations,” he said. In this, Alaska’s geographic position in relation to Asia may be a strength. “They will also be looking at how supportive the community is to the military and the quality of schools, the university and regional medical facilities to provide treatment in addition to that given on base, and to the general quality of life,” Popp said. The visiting delegation will also be interested on how strong the local veterans community is. “They will see this as an indicator of how favorable the community is to the military,” he said. To this end, the event organizers are recruiting veterans to ride along with the visitors in buses, acting as hosts, as they move from one location to the next, Popp said. Part of Alaska’s story on veterans are many special state-funded veterans’ benefits in education, home loans and land purchases as well as municipal property tax exemptions. There are also free hunting and fishing licenses for resident veterans with service-related disabilities, along with free camping in state parks and one-year free passes on state ferries. The Alaska Railroad also offers a 20 percent discount to veterans and active military, and employers who hire veterans are eligible for special tax credits. As good as Alaska’s story is, however, leaders in 30 other communities may also have compelling stories, Popp warned. In a community near one Army installation in Kansas, 2,000 showed up at a listening session, he said. Organizing the reception in Anchorage has been a scramble since local leaders got only four weeks’ notice of the visit. The Army’s decisions will be made soon, too, Popp said, if the reductions are to be in place in 2017. Dodson said Fairbanks community leaders and residents will turn out at a similar listening session at the Carlson Center Feb. 24. Earlier in the day the visiting Army officials will be given a tour of the community and the University of Alaska Fairbanks campus. “What’s really important is what is said at the listening session because that is what is recorded and transmitted to the Secretary of the Army,” Dodson said. Information gathered earlier, during the tours, is helpful, but what really counts is what is recorded, he said. JBER, Fort Wainwright and Eielson Air Force Base have survived previous rounds of reductions, both Dodson and Popp said, but this one is different because it is a congressionally-mandated reduction that is on a fast track. Meanwhile, Dodson is hopeful about Fort Wainwright and other Alaska installations. During the most recent Base Realignment and Closure Commission, or BRAC, process the Alaska bases were ranked for their viability and the strategic nature of their mission. “Fort Wainwright was ranked as the Army’s No. 1 post for maneuverability,” a reference to the extensive ground training areas near the base, he said. Also, recent geopolitical issues like the emerging military power of China, Russia’s reestablishment of Arctic military bases and the growing importance of the Arctic as a military arena, continue to make Alaska bases strategically important, Dodson said. Popp said the proximity of infrastructure to the Alaska bases, such as the Alaska Railroad and the Port of Anchorage for transporting heavy equipment and major airfield runways for quick deployment are also important.

Sharp questions in opening hearings for Medicaid plan

Medicaid expansion is taking on a partisan edge in Juneau, to no surprise. Hearings on the plan by Gov. Bill Walker opened Feb. 16 in a House Finance subcommittee. Department of Health and Social Services Commissioner Valerie Davidson made the case for expansion, citing improved health care for Alaskans, lower near-term costs to the state budget, and lower costs for many employers if workers have better access to health care. Republican Reps. Dan Saddler, R-Eagle River, and Tammie Wilson, R-North Pole, were the lead skeptics in the debate, asking pointed questions mainly over long-term state cost worries. Rep. Bryce Edgmon, D-Dillingham, a strong supporter of expansion, complained the subcommittee was spending too much time on negatives in the far future with little discussion of near-term benefits like cost reductions in the departments of Corrections and Health and Social Services, where federal funds would replace state dollars now being spent on health care. Rep. Les Gara, D-Anchorage, said, “I’ve never heard of Alaskans turning down 90 percent federal funding for a program. We wouldn’t dare do that for highways,” also 90 percent federally-funded. Davidson handled it all with grace and poise. “We all want Alaskans to be as healthy as possible and contributing to the economy, but without improved access to heath care many can’t work and can’t hunt and fish. Medicaid expansion will reduce the number of Alaskans without health insurance by half, from about 20 percent of our population to 10 percent,” Davidson said. “We know our mortality rates will drop. A recent study by Harvard showed that for every 830 individuals gaining health coverage, one death per year is prevented. That means there would be 30 fewer deaths per year in Alaska with expansion, according to the Harvard study.” Also, Medicare expansion and Medicaid “reform,” a restructuring of services in both the current and proposed expanded program, go hand-in-hand, the commissioner said. The department already has several reform initiatives underway aimed at lowering costs and these will be continued and expanded, she said. Davidson acknowledged that changes to even the present program are needed. The Department of Health and Social Services budget is $2.7 billion per year and Medicaid is $1.7 billion of that, although the federal government is picking up 50 percent of Medicaid costs. “The current Medicaid program is not sustainable,” and reforms are needed, she said. “Efficiencies, improvements and innovations are critical to bend the cost curve.” That prompted Wilson to ask whether the expansion should be done if the current program can’t be sustained. Davidson said reforms are needed for both the current program and an expansion but there are still many benefits from the expansion. Saddler posed a question about the possibility that the federal government may someday shirk its promise to pay 90 percent of the cost of the expansion, leaving Alaska stuck with the tab. “Does that concern you?” he asked Davidson. Davidson replied, “We must plan for the future but we must also live for today.” She pointed to the federal government paying 90 percent of major state highway and airport projects with no guarantees this level of funding will continue. “We still maintain our roads and runways, and we use them. Having roads and runways allows our businesses to continue. We need to think of health care in a similar way, like infrastructure. We can build roads and highways but unless we have healthy people our economy will be thwarted,” she said. “There are a whole range of programs where we are heavily dependent on the federal government. We can’t spend all of our time worrying about the feds. We have bigger problems.” Medicaid expansion will also bring near-term economic benefits from the infusion of new federal funds, she said. “We will see $145 million in (fiscal year) 2016, increasing to $224 million per year in 2021. That’s a billion dollars of new federal money in six years,” Davidson said. Expansion will also reduce uncompensated care paid out by Alaska hospitals, which amounted to $90 million in 2011, Davidson said. Federal law requires hospitals to treat all who appear at emergency rooms regardless of ability to pay, and the losses hospitals incur wind up being spread through the rates paid by all others using the facilities. “Arizona saw a 30 percent drop in hospital uncompensated care within six months of expanding Medicaid. We know we will see a reduction here, although we don’t know how fast it will occur,” Davidson said. Edgmon said the biggest immediate benefit he sees in expansion will be in making continuing treatment, for alcohol and substance abuse for example, available to prisoners once they are released. “There is no treatment available now, and these people return home to the same environments they left,” he said. The likelihood of their returning to prison is high, he said. Committee members questioned Davidson about other aspects of the expansion. Rep. Tammie Wilson, R-North Pole, said she worries whether the state’s health care workforce will be able to accommodate an expansion of medical services. Wilson said she has constituents now who find it difficult to get certain types of service. Several legislators had questions about the level of payment by the state to health providers under Medicaid, at rates higher than most other states. Health and Social Services Deputy Commissioner Jon Sherwood said Medicaid is paid in Alaska at rates, on average, about 130 percent of what Medicare pays. However, Medicare, the federal health program for senior citizens, pays at about 70 percent, on average, the usual and customary rates charged by Alaska health care providers, Sherwood said. If Medicaid is 30 percent above that it brings the Medicaid rate near parity with health providers’ typical charges. Sherwood appeared with Davidson at the House Finance subcommittee meeting. In other states, Medicare rates are closer to what providers typically charge and Medicaid rates are below that, so that in many states, for general physician services, senior citizens are treated by most providers while some Medicaid patients are turned away because of insufficient reimbursement. In Alaska the situation is the reverse. Alaska seniors in larger cities like Anchorage have difficulty seeing physicians because of the low Medicare reimbursement. Because the Alaska reimbursement for Medicaid is higher, those patients are accepted by most care providers. Rep. Cathy Munoz, R-Juneau, asked Davidson and Sherwood to provide a comparison between Alaska and other states on Medicaid reimbursement. Medicaid reform efforts already underway would be expanded along with an expansion of the overall program, Davidson said. She identified several initiatives: One is to reduce “super-users” of hospital emergency rooms by those now covered by Medicaid, by people who don’t have access or don’t choose to use primary or other care providers. “We have identified about 5,000 ‘super-users’ of emergency rooms and this is costing our program about $29 million yearly,” Davidson said. The department has now initiated a program, so far voluntary for patients, to receive counseling and assistance in lining up care providers other than the emergency rooms. This has the potential of saving $7 million per year near-term, she said. The department is considering making it mandatory for Medicaid recipients, although that would require adoption of new regulations. A bigger potential savings, $15 million per year, could come from new initiatives to reduce fraud, waste and abuse of the system by providers, she said. There have particularly been problems among personal care attendants licensed, and paid, by the department. In these cases the department is focusing on closer scrutiny of billed hours and billed locations. “We know there are 24 hours in a day. If we see excessive hours being billed, we want to take a look. Also, if we see services billed at more than one location, and even more than one community, it’s a red flag,” Davidson said. Another savings, about $24 million per year, involves an expansion of community-based services so that state dollars are replaced by federal funds. These require obtaining waivers, or permission, from the federal Center for Medicaid Services, a process that can take two to three years, she said. Yet another initiative is a “medical home” plan where patients are assigned to a single care provider, such as a clinic, for coordinated care. This would have patients received almost all care in one place rather than going, ad hoc, to several locations, which drives up costs. A pilot program for this is underway with the Alaska Primary Care Association, Davidson said. Studies show that it could save between $78,000 and $165,000 per 1,000 patients enrolled in Medicaid being served in such a coordinated fashion. Another savings, about $15 million per year, could come through closer coordination with Tribal health providers to ensure that Alaska Natives who are eligible for Medicare enroll in the program. The federal government will now pick up 100 percent of those costs if the Alaska Natives receive care in Tribal health facilities, Davidson said. The state now pays 50 percent of those costs, she said. The department will also be looking closely at reform efforts underway in other states. Colorado, Minnesota and Vermont are now experimenting with various alternative payment strategies aimed at lowering costs, and lessons can be learned from those states, Davidson said.

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