Tim Bradner

Effect of troop cuts may be muted

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

Another round of Slope methane hydrate research planned

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

Shell presses on despite issues with vessel

Shell’s summer Chukchi Sea exploration is facing its share of glitches. The striking of a shallow, uncharted shoal by the ice management vessel Fennica, part of Shell’s support fleet, resulted in hull damage that is sending it back to the Pacific Northwest for repairs. The Fenneca, being guided by a licensed Alaska marine pilot, hit an the uncharted obstacle while departing Dutch Harbor July 3. A temporary patch can be put on in that Aleutians port but a permanent repair must be done at a shipyard and that will be in Vigor Industrial’s Portland, Oregon yard, Shell said. “While we believe interim repairs could be made in Dutch Harbor, our preference is to pursue a conservative course and send it to a shipyard where a permanent fix can be performed. We do not anticipate any impact on our season as we do not require the vessel until August,” Shell spokesman Luke Miller said in a statement. As of July 15 the Fennica is still in Dutch Harbor undergoing the temporarily repair and is expected to depart soon for Portland. The voyage to Portland from Dutch Harbor is expected to about a week. It’s uncertain how long the repairs will take, Miller said. The Fennica must then travel back north to the Bering Sea through the Bering Strait to the Chukchi Sea. The vessel’s presence in the Chukchi Sea is vital because the Fennica is carrying the “capping stack,” a device needed for Shell’s undersea blowout control system. The company cannot drill wells into oil-bearing formations until the Fennica, with the capping stack, is on hand. If the repairs go smoothly the vessel could be back with the fleet in August, which leaves plenty of time for drilling. Until then Shell can drill “top holes,” or partly-complete wells, which it did with one Chukchi Sea exploration well drilled in 2012. Meanwhile, many of Shell’s other vessels are in Dutch Harbor preparing to depart to the Arctic including the two drilling ships, Miller said. More support vessels are departing for the Chukchi Sea and some are already there, making preparations for the arrival of the drilling ships. Greenpeace, the environmental group that dogged Shell’s vessels in Puget Sound, has meanwhile made an appearance in Dutch Harbor, with activists protesting with signs and banners. However, the Esperanza, the Greenpeace vessel that has given the group a capability to take actions to try and impeded Shell, has left Alaska waters and is in California, sources who are tracking the vessel said. Shell faces another major problem, however. A 2013 regulation enacted by the U.S. Fish and Wildlife Service prohibits Shell from having more than one drilling vessel working in the Chukchi Sea within 15 miles of another drilling vessel. Shell is taking two drill vessels to the Arctic, the semi-submersible Polar Pioneer and drillship Noble Discoverer, and has an approved exploration plan with several well locations. However, they are all within an area around the Burger discovery the company hopes to test, and no one location is more than 15 miles from another. The first two well locations on Shell’s list are nine miles apart. The restriction means Shell must drill the wells one at a time. Designating additional well locations more than 15 miles from the approved wells would require a modification to Shell’s approved drilling plan, which would be a complex undertaking that might not be done in time for this year, and which could also open the plan to new legal challenges. “Shell can still drill. They just can’t drill with drill ships within 15 miles of each other,” said Lois Epstein, Arctic coordinator for the Wilderness Society, who is familiar with Shell’s exploration plan. The plan was approved by the U.S. Bureau of Offshore Energy Management, or BOEM, and subsequently OK’d by Interior Secretary Sally Jewell. Epstein said she is perplexed over why Shell designed a drilling plan with wells spaced so closely that was in obvious violation of the Fish and Wildlife Service regulation, which has existed since 2013. The regulation says, “Operators must maintain a minimum spacing of 24 kilometers (15 miles) between all active seismic source vessels and/or drill rigs during exploration activities.” The restriction does not apply to support vessels, the regulation states. “There has apparently been some confusion in the industry that the rule applies only to seismic vessels, but the wording is quite clear, that drilling operations are included,” Epstein said. The purpose of the rule on separation was to prevent increased undersea and surface vessel noise as well as disturbance from aircraft operations that would occur in a concentrated area if drill vessels were working near each other, Epstein said. The U.S. Fish and Wildlife has regulatory jurisdiction over polar bears and walruses, species that are in the Chukchi Sea, and which could be affected by industrial activity. While Shell is dealing with its operational issues a mini-drama continues in a U.S. District Court in Anchorage where Judge Sharon Gleason is weighing Shell’s requests for awarding $57,797 to be paid to Shell by Greenpeace, the environmental group, in compensation for legal fees incurred by Shell. The costs were incurred when the environmental group made filings on an injunction ordered by the court restricting Greenpeace from approaching or attempting to impede Shell’s vessels. Greenpeace was requesting that the injunction be stayed, but then dropped the requests. The legal costs aside, court documents filed by Shell also show a blatant disregard for the injunction in a series of actions by Greenpeace as the semi-submersible Polar Pioneer departed the Port of Seattle June 15. The U.S. Coast Guard arrested 14 activists in that incident. Two days later, at sea, activists working from the Greenpeace ship Esperanza, which had been waiting for Shell in nearby Canadian waters, placed obstacles in the path of tugs towing the rig and, in a highly dangerous move, put swimmers in the water around the moving vessels. “Greenpeace USA has taken matters into it own hands in flat defiance of the (District Court’s) preliminary injunction,” Shell asserted in a June 29 filing. “Greenpeace USA’s conduct contradicts repeated assurances it made to this court and to the Ninth Circuit (Court of Appeals) that it had ‘no plans’ to interfere with Shell.” In earlier hearings on the preliminary injunction in Gleason’s court, Greenpeace USA’s Arctic Campaigner Mary Sweeters told the judge three times, in responses to direct examination by a Greenpeace attorney, that she had no knowledge of any plans by her organization to attempt to block movements of Shell’s vessels. However, on June 15, at least 14 Greenpeace USA directors and employees manned kayaks and motorized boats in an attempt to block the Polar Pioneer in Elliot Bay, near Seattle. In the injunction, Gleason also established a safety zone of 1,000 meters for the Polar Pioneer while it was in transit on the high seas. In defiance of this, Shell said the Esperanza intercepted the Polar Pioneer and its tugs offshore Vancouver Island on the British Columbia coast. Fast-moving rigid-hulled inflatable boats, or RHIBs, were launched from the Esperanza, at least one of them coming dangerously close to the Shell vessels, as documented by photographs taken from the Polar Pioneer that were provided to the Alaska U.S. District Court. “The RHIBs dropped buoys with a tethered banner in front of the tug boats, leaving them no choice given their limited maneuverability to go over the top of it, whereupon the buoys-line banner was then sucked under the pontoons of the Polar Pioneer. After the contraption came up behind the rig, the RHIBs gathered it up, raced back in front of the tugs, and deployed the buoys and banner again. This occurred several times,” the filing by Shell said. And then, in a dangerous move, “the RHIBs also dropped swimmers into the open ocean dangerously close to the drilling rig,” the court filing said. Shell is alleging that it is entitled to legal fees for its work briefing the five motions for a stay of the injunction filed by Greenpeace. The requested order alleges Greenpeace acted in bad faith by always intending to violate the injunction, and bases the argument on the withdrawal of the motions soon after the protesters impeded the Polar Pioneer in Seattle and in Canadian waters. Greenpeace countered in its own filing that it withdrew the motions based on regular legal strategies stemming from Gleason’s refusal to lift the stay, and asserted that it could have accused Shell of acting in bad faith at several points in the case, in particular its refusal to agree on an expedited briefing schedule for some of its motions.

Discussion begins on tax credits

Alaska’s explorer and small producer tax credit program has been capped for this year but the program is still on the books and applications for credits are still being accepted, state Revenue Commissioner Randy Hoffbeck said. There is $500 million in the budget for the program and that’s enough to pay for tax credits that have been applied for, which total about $475 million, the commissioner said. That leaves $25 million for the year, and if more applications come in the companies, mostly small independents, will have to accept an IOU from the state. Gov. Bill Walker trimmed a $700 million appropriation for the credits by $200 million on June 30 when he approved the final fiscal year 2016 state budget. However, the governor said tax credits that have already been applied for would be paid, that the June 30 action should be seen as a “deferral.” The veto affects only part of the state’s tax credit incentive program for the oil and gas industry. Only the program where the state actually purchases the credits from explorers and small producers is being capped. Companies with tax credits still have to option to sell them to a firm that has production tax liability against which the credits can be applied. In this case the state still feels a revenue impact eventually but it is in the form of reduced production tax paid by the producer who purchased the credits and is also delayed. When tax credits are sold, however, they are usually purchased at a discount, for example 90 percent, so the explorer or small producer gets a reduced refund of expenses while the purchaser, for example a larger firm with production, can apply them at full value against tax liability and pocket the difference. It is because of this that the state instituted the straight purchase policy a few years ago because the state treasury feels the same impact either way and a purchase of the tax credits by the state ensures that explorers and small producers get full value in the refund. However, the governor said June 30 that the program as it is currently structured, with the state writing checks, can’t be sustained in tight budget times, and discussions are underway on a more affordable replacement. Hoffbeck said the administration hopes to flesh out several options now being considered and to have a proposal ready for the Legislature next year. “The governor’s action has really gotten people talking,” Hoffbeck said. So far there are three plans on the table, he said. One is a direct state equity investment in a project, such as the Alaska Industrial Development and Export Authority has done with infrastructure to support Brooks Range Petroleum’s small Mustang field development on the North Slope. “We’re talking with AIDEA now on whether the authority could be a conduit for this kind of investment. It would require a good deal more capital than the authority now has available,” Hoffbeck said. Also, current state law does not allow AIDEA to invest “upstream” in oil and gas reserves, but only in the infrastructure needed to produce oil and gas. For example, in the Brooks Range investment AIDEA is a partner in an oil and gas processing plant needed for Mustang as well as the civil support structures like the pad for the plant and an access road. There are separate investment deals for the road and pad, which have been constructed, and the plant, and the agreement provides for AIDEA’s investment to be temporary, with the private partners buying out the authority after the project gets up and running. AIDEA invested in a similar deal in a jack-up rig in Cook Inlet and sold its shares at small profit. The deal facilitated the rig being brought to the Inlet where it drilled exploration wells and made a significant natural gas discovery. The authority sold its stake when the rig was taken out of Alaska. Two other options being considered include some form of long-term financing, at very low interest, as well as a new version of the tax credit program but with pre-approved credits so there is certainty for the companies that the credits will be paid, Hoffbeck said. A new version of the tax credit program would still likely be capped at some level, not as open-ended as the previous one, but it would be more predictable and that is important, the commissioner said. Meanwhile, some legislators have criticized Walker for capping the program. “I couldn’t agree more with the governor that we have to have a realistic budget conversation, but choosing to short the tax credit commitments is not the way to do it,” said Sen. Mike Dunleavy, R-Wasilla, in a formal statement. Dunleavy is co-chair of the Senate Finance Committee. “At a time we’re facing an unprecedented shortfall in revenue, the last thing we want to do is send a chilling message of uncertainty to not just the oil industry but any potential industry looking at Alaska for potential investment,” Dunleavy said. Walker’s unexpected veto of $200 million for the program on June 30 came after months of budget deliberation by the Legislature and the administration, Dunleavy said. Also, the governor had expressed support for Senate Bill 21, which contained changes to the tax credits, and which has overall generated more revenue for the state, Dunleavy said.

City manager says repairs underway on vessel

Shell is being cautious on whether damage to an ice-handling vessel near Dutch Harbor will affect the company’s 2015 Chukchi Sea exploration. The 380-foot Fennica hit a submerged object, possibly World War II debris, while departing July 3 and was returned to port. “Repairs may be possible on site (in Dutch Harbor) but that’s still being determined,” Shell spokesman Luke Miller said. However, Unalaska city manager Don Moore said that the damage can be repaired by a local firm, Resolve Magone Marine Service, and that work has already started on the Fennica at the company’s dock. Meanwhile, a bottom survey was being done July 8 by the National Oceanic and Atmospheric Administration research vessel Fairweather along the route taken by the Fennica, and the survey should identify the obstruction encountered by the vessel, Moore said. A major question is that the Fennica was also equipped to transport and deploy an undersea oil spill containment system Shell is required to have on site. If the vessel cannot be repaired in time for it to get to the Arctic by late July or early August, there could be impacts on Shell’s plans for drilling. The company may have other vessels in its fleet that can deploy the system, which is required to be on hand when drilling vessels drill down into potential hydrocarbon-bearing zones. The company has the option, however, of drilling “top holes,” or partly-drilled wells that do not penetrate the hydrocarbon zones, as it did in 2012. “At this point we do not anticipate any impact on the season but it’s too early to know for sure. Any impact on our season will ultimately depend on the extent of the repairs,” Miller said. On another issue Shell is wrestling with, the company is still considering possible changes in its plan to deal with a U.S. Fish and Wildlife requirement that drilling vessels be at least 15 miles apart while drilling. Shell’s current drill plan has rigs working nine miles apart. “We still intend to accomplish meaningful work in the weeks ahead. That includes drilling in the Chukchi Sea,” Miller said. “We have nearly every permit we need to commence operations this summer and that’s what we intend to do.” Meanwhile, the company’s mobilization is continuing. The semi-submersible Polar Pioneer is in Dutch Harbor while the drillship Noble Discoverer is still en route from Everett, Wash., and is expected to arrive soon, Miller said. “Most of our fleet is now in Dutch Harbor,” Miller said. Four support vessels departed Dutch Harbor July 3 for the Arctic including the Fennica, which turned back after being damaged. Vessels now headed north include the Nordica, also an ice-handling vessel and sister ship to the Fennica, the anchor-handling tug Aiviq and the Harvey Explorer. Meanwhile, the company’s aviation support facilities at Barrow and Wainwright are now operational. Shell’s plan is to have its fleet in the Arctic in late July or early August but local conditions will affect that, Miller said. “Right now the ice conditions are looking good,” at the site of the planned drilling, he said. Shell plans to drill wells at its Burger prospect in the Chukchi, a discovery the company made in the early 1990s when it had previously drilled. The company released the acreage in a 2008 federal Outer Continental Shelf lease sale and was able to return to the site a drill one “top hole,” or partly-completed well, in 2012. Tim Bradner can be reached at [email protected]

Furie nears first production from Kitchen Lights field

Furie Operating Alaska will begin producing natural gas in November from a newly installed production platform at its Kitchen Lights gas discovery in Cook Inlet, the company said. It has been a long haul for the company, which entered Alaska as Escopeta Oil and Gas several years ago. The initial producing rate will be 15 million to 20 million cubic feet per day but that will increase as more customers are lined up, said Bruce Webb, a Furie vice president. The identity of the current customer cannot be disclosed, Webb said. A 10-inch platform-to-shore pipeline now installed and almost complete will have a maximum capacity of shipping 100 million cubic feet per day and Furie’s plans call for second 10-inch pipeline, with equal capacity, when sales contracts allow for expansion. The platform and other production facilities are designed to handle 200 million cubic feet per day, Webb said. “The pipeline is just about complete with a tie-in of the offshore pipeline with the onshore pipeline. Onshore facilities are also almost finished,” he said. At the platform, the pilings are complete and the “top-deck” will soon be installed. The installations are being done with a special pipe-laying barge that is now offshore Kenai. The jack-up rig Spartan 151, under contract to Furie, is also stationed offshore, near the platform and is being used as a floating hotel for workers, Webb said.  Initial production will be from Furie’s Kitchen Lights Unit No. 1 well but two other wells will be brought into production in the first half of 2016, for a total of three wells supplying the contracted sales volumes. Webb said the operation employed up to 400 workers in recent weeks but the workforce is now down to about 250. By the end of the year Furie will have invested about $500 million in its Kitchen Lights development, he said. Furie’s development at Kitchen Lights has a long and complex history. The prospect was initially identified by Furie’s predessor company, Escopeta Oil and Gas, and its president, Danny Davis, an old-school oil exploration wildcatter from Texas. Dwindling production of petroleum from Cook Inlet was becoming a concern but Davis and Escopeta’s geologists believed the Inlet has undiscovered resources, particularly in deeper waters that required a jack-up rig or floating drillship to explore. Escopeta bid in state lease sales and acquired offshore acreage and Davis set about raising funds to bring a jack-up rig to Cook Inlet to drill untested offshore prospects, not only for Escopeta but for others as well. An initial effort to bring a rig north in 2006 failed when Davis’ financing fell apart. A second effort, in 2010, was successful but the federal administration had meanwhile changed and an exemption from the U.S. Jones Act Davis had obtained from the Bush administration to use a foreign heavy-lift ship to move the rig was not renewed by the Obama administration. Davis took a gamble that he could eventually persuade the U.S. Department of Homeland Security, which administers the Jones Act, to renew the exemption, and had the Spartan 151 rig loaded on board a Chinese heavy-lift ship. The rig was then in U.S. Gulf of Mexico waters. Davis continued efforts to get the exemption as the ship rounded Cape Horn and headed north in the Pacific. The rig was actually unloaded in Vancouver, B.C., for maintenance, and U.S.-owned tugs were hired to tow it to Cook Inlet. Even through the journey was broken, so that the Chinese ship moved the rig from a U.S. to Canadian port, the federal government still ruled it a violation of the Jones Act and hit Escopeta with a $15 million fine. Davis, who had pioneered the effort, essentially lost his job as president over the issue, and Escopeta’s investors took the company over, renaming it Furie Operating Alaska. Davis still retains a small royalty in the property, however. Furie used the Spartan 151 rig to drill the first exploration wells at Kitchen Lights and Davis’s foresight was vindicated when a gas discovery was made.

Production off, but price better than forecast

Alaska oil and gas production averaged 502,000 barrels per day in Fiscal Year 2015, the state’s budget year that ended June 30, according to preliminary data compiled by the state Department of Revenue. That is less than the 508,000 barrels per day average predicted in the spring, 2015 production forecast update but Revenue officials expect the average to be adjusted upward in mid-August when the final numbers are calculated, according to Ken Alper, director of the department’s Tax Division. “Historically, our average production adjusts upwards by a few thousand barrels (per day) over the preliminary estimate, so I would be reluctant to read anything into the difference with the spring forecast at this point. We will have final figures in about a month,” Alper said. Meanwhile, the average price paid for North Slope oil was $72.90 per barrel for the fiscal year ending June 30, greater than the estimate of $67.49 per barrel in the spring revenue forecast update, he said. The state finished the 2015 fiscal year with a deficit of $2.7 billion (see story, page 14). “We’re more certain about the preliminary price figures (for the fiscal year average) at this early date. We believe the final average price, once we have all the details, will be within a few cents,” of the preliminary average of $72.90 per barrel, Alper said. The 502,000 barrels per day preliminary estimate for the fiscal year is down from 531,000 barrels per day average of the prior fiscal year, but the Revenue Department is sticking with its earlier forecast that production will increase in the 2016 fiscal year as new North Slope projects now in construction are finished. Two ConocoPhillips projects will be complete and producing by year-end, the CD-5 production pad, a satellite of the Alpine field, and the new Drill Site 2-S in the Kuparuk River field. CD-5 will peak at 16,000 barrels per day and DS 2-S will peak at 9,000 barrels per day, but it is uncertain how fast the production on both will ramp up in early 2016 after startup, ConocoPhillips has said. Meanwhile, a liquid condensate project at Point Thomson, a large gas field east of Prudhoe Bay, will start up in early 2016, several months ahead of a mid-2016 target date set in an agreement with the state of Alaska, ExxonMobil officials told a state legislative committee recently. Condensate production from Point Thomson is estimated at 10,000 barrels per day in the initial phase of the project, ExxonMobil said. Alper said it was too early to assess the effects on fiscal year 2016 state revenues of the production or price averages.

Fiscal year 2016 budget deficit estimated at $3.7 billion

Gov. Bill Walker’s approved fiscal year 2016 state budget will require a draw of $2.7 billion from the state Constitutional Budget Reserve, a ready asset fund, according to state budget director Pat Pitney. The draw on the CBR is lower than the actual deficit of about $3.7 billion because the Legislature opted to transfer $1 billion from the Public Education Fund, a budget reserve used to do advance-funding for school districts. That action will have no effect on school funding, however, because the Legislature will instead appropriate education money next fiscal year as part of the regular budget rather than withdrawing it from the education fund. The CBR balance as of July 1, the start of fiscal year 2016, was $10.1 billion, Pitney said. The draw for the fiscal year will leave the fund at $7.3 billion on July 1, 2016, the start of fiscal year 2017, she said. The just-completed fiscal year 2015 ended with a budget deficit of $2.7 billion, which was covered with funds from the Statutory Budget Reserve that was nearly zeroed out by the draw. At that rate of drawdown, assuming no further budget reductions, no big increase in oil prices and no new revenues, the CBR will be exhausted sometime in fiscal year 2019, which would be in calendar year 2018. David Teal, director of the Legislative Finance Division, said his estimates of the reserve drawdown and CBR depletion is similar to that of the administration’s Office of Management and Budget, which Pitney heads. One issue the administration is now considering, Pitney said, is whether it is prudent to allow the CBR to be completely drained, which would leave only the accumulated earnings of the Permanent Fund, which total several billion dollars, as a cash reserve for emergencies. “We’ll be asking for advice from a lot of people on that,” Pitney said. The governor has said that he intends to propose new revenue measures to state legislators late this year or early next year. Meanwhile, the final figure for total state unrestricted general fund spending in fiscal year 2016 is $4.954 billion, a huge reduction from fiscal year 2015, the budget year ending June 30. That figure includes operations spending, including state agencies, as well as the capital budget, debt service on bonds, and fund transfers. In terms of state operations, which includes agencies, the Legislature cut $343.7 million. The capital budget for fiscal year 2016 totals $116 million in unrestricted general funds, a $489.8 million reduction compared with the previous year capital budget.

Hilcorp acquires additional Inlet oil assets

Hilcorp Alaska will purchase XTO Energy assets in the Middle Ground Shoal of Cook Inlet and is also studying a possible restart of a shut-in platform in the field. Two oil-producing platforms, tank facilities and an office and support facilities at Nikiski, near Kenai, are included in the purchase deal with XTO, the company said in a statement issued July 6. “Hilcorp anticipates making offers to all 31 employees that currently operate the Middle Ground Shoal assets,” spokeswoman Lori Nelson wrote in an email. Meanwhile, Hilcorp is also studying a possible restart of one of two shut-in platforms also in the Middle Ground Shoal field. There were four platforms installed in Middle Ground Shoal, one of the earliest offshore producing fields in Cook Inlet, but only two platforms are still producing.  The purchase announced July 6 includes the operating “A” and “C” platforms, originally built in 1965, which produce about 1,750 barrels of oil per day, Nelson said. XTO is a subsidiary of ExxonMobil Corp. A and C platforms are two remaining producers of four platforms that once produced oil from Middle Ground Shoal. Two other platforms, Baker and Dillon, were shut in several years ago by Chevron Corp., then the owner and operator.  Hilcorp Alaska now owns the Baker and Dillon platforms. Hilcorp purchased Cook Inlet offshore oil platforms formerly owned by Chevron in 2012 and has rejuvenated several platforms after considerable investment. When Hilcorp purchased Chevron’s Cook Inlet oil producing assets in 2012 they were producing 17,000 to 18,000 barrels per day. By late 2014 Hilcorp had built the production back to almost 40,000 barrels per day. The company has been investing about $350 million a year rejuvenating old wells and production facilities, Hilcorp officials have said. The company has been investigating a reactivation and production restart at the shut-in Baker platform but the work was interrupted by a fire in October 2014. “We are focused on reconstruction and repair of the Baker at this time. We don’t anticipate reactivation until sometime next year,” Nelson said. The transaction with XTO will close sometime this fall following approvals of state agencies and regulatory officials, Nelson said.

Walker vetoes exploration tax credits to start 'discussion'

Gov. Bill Walker vetoed $200 million in funding for oil exploration and development tax credits in a budget action on June 30, in effect capping the program at $500 million for state fiscal year 2016 that began July 1. The program was previously budgeted at $700 million. “This has been a tough budget year and no sector, from senior citizens to low-income Alaskans, or oil and gas explorers, is left untouched,” Walker said in a July 1 press conference. The $200 million reduction, made through the governor’s veto authority, was the only noteworthy veto Walker made. State spending will total $4.954 billion in fiscal year 2016, a $1.15 billion reduction from $6.1 billion spent in fiscal year 2015, the budget year that ended June 30. Much of the reduction was in state capital spending, which is a one-time savings. The cut to the oil tax credit incentive program does not end the program but only defers the payments on some tax credits that have been applied for, the governor said. Five hundred million dollars left in the incentive fund is expected to pay the tax credit applications that have been received to date, Walker said. The action affects only tax credits that result in direct payments by the state to companies that are not producing. It does not affect production tax credits allowed to major producing companies. Dawn Patience, spokeswoman for BP, said her company is now paying the minimum state production tax and because of that is not eligible for tax credits. According to its most recent financial report, BP was getting about $51 per barrel for Alaska North Slope crude during the first quarter of 2015 compared to $108 per barrel at the same time in 2014. Also, oil firms producing more than 50,000 barrels per day are also not eligible, which eliminates the current major producers. Major producers do get a per-barrel production tax credit that is applied against the companies’ production tax obligation, but because this is not paid by a state appropriation, as are the explorer and small producers’ tax credits, it is not affected by the governor’s action. Walker said he had to take action because the tax credit payment program is projected to grow and would have been $1.3 billion next year and continue to climb. “It would quickly be the largest cost in the state budget. Clearly, that is not sustainable,” in these lean times of oil revenues, the governor said. The intention is not to end the incentive program but to restructure it, he said. “This is the start of a discussion with the companies on how to do that,” Walker said. Separately, state Revenue Commissioner Randy Hoffbeck said, “It’s not our intention to cut out anyone who has already invested,” in exploration or small fields. “They will get paid. But clearly, at $60-per-barrel oil the program as currently configured can’t be sustained. We have to relook at how we invest.” There will be money available for the bulk of the applications that have come in and the firms who have to accept a deferral of payment do have the option of selling the tax credits to producing companies who do have production tax liability, and where the credits can be used to offset payments. Alternatively, the companies can hold the tax credits until they do develop production and can then apply them, Hoffbeck said. Meanwhile, state statutes set out criteria on who gets paid from the money available. The priority is given as to when the applications are filed on a first-come, first served basis, as well as for companies who face statutory deadlines in using the tax credits, or other deadlines. Casey Sullivan, spokesman for Caelus Energy, a small company now developing Nuna, a new North Slope project, said his company may not be greatly affected, for now. “Historically, we’ve been a small user of the tax credits and for what we have used so far, we hope we’ll be in the first bucket to be paid,” he said. “Still, I think we’ll be looking for guidance from the governor on how the state can assure payments can be made, for future years.” Caelus is currently developing Nuna, an approximately $1.5 billion new production project that is expected to produce between 15,000 to 20,000 barrels per day beginning in 2017. An official with another small independent, asking to remain unidentified for now, said his major concern is that any move that affects tax stability can have immediate impact on potential investors. “People need to know that if they come up here and invest their money they will get a return,” he said. Hoffbeck said the state administration is already mulling ideas for what can replace the tax credits. One approach is a direct state equity investment in a development, or its related infrastructure, such as investments the state’s Alaska Industrial Development and Export Authority has already done with Brooks Range Petroleum, a company now developing the small Mustang field on the Slope. Another idea is to preserve the tax credit structure but with pre-approvals, so the state can better forecast future obligations, he said. Speaking for the oil and gas industry, Alaska Oil and Gas Association president Kara Moriarty said, “We take Governor Walker at his word when he says the state will honor its commitment to pay the oil tax credits, which represents a delay more than a reduction. “The state’s policy of encouraging small or new oil companies to pursue tax credits by spending billions of dollars in Alaska remains wise, and new oil will result from the increased activity. We agree with the governor when he says he wants to see more oil and gas companies operating in Alaska, and we believe credits have already proven to be effective in reaching that goal.”

Feige aims to put welcome mat out for explorers

When producing companies and hopeful oil explorers stop by the state Division of Oil and Gas these days they find the welcome mat laid out by Corri Feige, the division’s new director. Feige took over the division in late April following the departure of Bill Barron, the previous director. For those firms new to the state and particularly small companies, Feige wants to ensure they understand the state’s regulatory landscape and permitting requirements, as she wears the mantle of chief state oil and gas lease administrator. But she also wants to help the companies navigate the system and to succeed. She is going a step further than past oil and gas directors, in fact, by talking with the explorers’ financiers, such as private equity firms, to help pitch Alaska and its prospectivity for new oil and gas finds. In some cases the financiers are calling on Feige. In other cases she takes the initiative and calls them. Investors, typically equity firms, have visited Feige to sound her out on prospective ventures. “I also have been reaching out to them. I want them to understand that there are ways to de-risk projects, and people here (in the Department of Natural Resources) have a lot of experience in doing that and can advise,” she said in an interview. Feige is sensitive to explorers’ concerns because she comes from that side of the industry with a 28-year career as a geophysicist and engineer, on company staffs and in management, and as a consultant. Virtually all of her time has been spent in exploration and development of remote projects, including minerals. However, Feige keeps in mind the regulator side of her job, too. The welcome mat to her office is out, but she won’t be a doormat for companies either. She grew up in Wyoming and has a degree in geophysical engineering from the Montana School of Mines and before coming to Alaska she worked as a geophysicist on exploration programs internationally, in Australia, the tropics, the Canadian Arctic, and South America. She met her husband, Eric, at Aniak, on the upper Kuskowkim River, while working on a minerals exploration project. Eric Feige, a commercial pilot and former state legislator, was operating an air taxi service at the time. A lot of Feige’s recent experience has been with unconventional oil and gas, an area where Alaska has great potential. She worked with Evergreen Resources on that company’s coal-bed methane project in Southcentral Alaska and went back to consulting when Evergreen was purchased by Pioneer Natural Resources and the Alaska coal-bed methane program was closed. She spent time working on Alaska geothermal projects, too, including a drilling program undertaken by Naknek Electric Co., a rural utility, which ultimately proved unsuccessful.  Feige was working with GeoPetro, a consulting company, when it was acquired by Linc Energy, which was investigating a potential unconventional gas project in Southcentral Alaska, underground coal-bed gasification, which led to her joining Linc. When Linc acquired North Slope leases at Umiat, an early, small oil discovery on the North Slope, Feige was tasked with managing the company’s initial exploration. Umiat is a remote site 100 miles west of the Dalton Highway — the nearest infrastructure — and the program proved challenging. “I learned a lot about managing a complex logistics chain with 150 people, a 104-mile snow road and conditions of minus-64 degrees Fahrenheit that lasted for several days,” she said. “This showed me how difficult it can be to manage remote operations and the impact on the cost structure, particularly when you’re completely at the whim of Mother Nature.” This experience, and perspective, is made available to explorers these days when they meet with Feige. After helping get the Umiat project in place Feige went back to work on Linc Energy’s underground coal gasification program, or UCG. This involves a process of controlled combustion in the underground coal seam at produces a synthethis gas, a form of natural gas, which can be used in power generation or in gas-based product manufacturing. Alaska has vast coal resources and the UCG process, which has been proven elsewhere including by Linc Energy, has good potential, but low prices for natural gas is now impeding the industry in North America. “This will have its time,” when economic and technical challenges are overcome, Feige said, just as has happened with shale oil and gas in the Lower 48 states. Many of the small companies calling on Feige these days have questions on the state’s exploration incentives and whether they can be maintained in tight budget times. These are questions that can be put to the Department of Revenue, which manages the incentives. However, Feige’s group at the Oil and Gas Division, and others in the Department of Natural Resources, can advise companies on navigating the state’s land and environmental regulations as well as those with federal agencies like the U.S. Army Corps of Engineers. “I am encouraging everyone to work with our OPMP (Office of Project Management and Permitting) group in the department. There’s a lot of institutional knowledge about the federal regulatory framework with (director) Sara Longan and her group,” Feige said.

Independent consortium plans shale play exploration well

There is more test drilling planned in a potential Alaska shale oil play south of the Prudhoe Bay field on the North Slope. Australia-based 88 Energy LLC and a partner, Houston-based Burgundy Xploration, will drill from a location adjacent to the Dalton Highway 35 miles south of Prudhoe, 88 Energy president David Wall said in an interview. The companies have dubbed their program “Icewine.” 88 Energy has also reached a preliminary agreement with Bank of America Merrill Lynch June 24 to provide $50 million for initial exploration, but Wall said the project is also eligible for State of Alaska tax credit incentives that can pay for as much as 85 percent of exploration costs. Those credits may be altered in the future, however, as Gov. Bill Walker vetoed some $200 million worth of such credits June 30 and called the current credit program for explorers “unsustainable” in light of current low oil prices creating multi-billion dollar state budget deficits. The prime target is the HRZ shale formation, with the Hue shale as another target. The location is about 35 miles south of Prudhoe Bay and south of where Great Bear Petroleum, another small independent, has been testing another shale formations, the Shublik. Both 88 Energy and Great Bear aim to develop production from similar to oil produced in the Bakken and Eagle Ford shale plays in North Dakota and Texas. Paul Basinski, president of Burgundy Xploration, previously identified ConocoPhillips’ shale oil acreage position in the Eagle Ford play in Texas and has extensive experience in the field, Wall said. 88 Energy, based in Perth, Australia, and Burgundy have assembled about 98,000 acres of state of Alaska leases in the area. The companies also plan a 3D seismic program in the area this winter. Negotiations for a drilling rig are in progress and a decision on a rig contract is expected soon, Wall said. The well is planned to be drilled to about 11,400 feet which will require a large rotary rig, but several units are available because Icewine is planned to be drilled in October. That earlier than normal winter exploration on the North Slope, which typically gets underway in December when cold temperatures to freeze the tundra for overland travel. The North Slope rig market tightens up after December. 88 Energy will drill the well from an existing gravel pad adjacent to the Dalton Highway, which means the site is accessible year-around. Wall said geologic analysis of the HRZ shale shows a thermal history that should have formed oil in the shale. Both the Hue and the Shublik, which Great Bear is testing, are known as source rocks for the large producing conventional oil fields further north on the slope. Paul Decker, senior geologist in the state Division of Oil and Gas, said the better and potentially productive parts of the known North Slope shales are in the areas south of Prudhoe Bay and Kuparuk fields on state lands, and where Great Bear, 88 Energy and Burgundy Xploration are exploring. The shale layers thin out to the east, near the Arctic National Wildlife Refuge, and to the west, near the National Petroleum Reserve–Alaska, Decker said. The oil should be in the shale and capable of production but Wall acknowleged that the cost environment of the North Slope is different than North Dakota and Texas, and a larger partner may be needed to develop the different development strategies that may be required. 88 Energy and Burgundy will also explore conventional oil prospects on their leases, just as Great Bear is doing on its acreage to the north, Wall said. Erik Opstad, former principal and general manager at Savant Alaska LLC, has been named general manager for 88 Energy’s Alaska operations, Wall said. Savant owned and operated the small Badami field on the North Slope but recently sold that to another independent, Miller Energy Resources.

Economist: State must shore up finances to support AK LNG

A senior economist with a leading U.S. policy think-tank told an Institute of the North audience June 23 that the state had best get its financial house in order because an instability could undermine the Alaska LNG Project. Alaska has a big opportunity with its proposed large natural gas pipeline and liquefied natural gas export project but there’s a lot of competition in the world of LNG and the success of the Alaska LNG Project is not a sure bet, said Dr. Margo Thorning, vice president and chief economist for the American Council for Capital Formation. The council advises Congress and federal agencies on macro U.S. economic policy including energy. Thorning spoke June 23 at a natural gas outlook conference in Anchorage sponsored by the Institute of the North. In her conference talk, Thorning outlined economic challenges facing Alaska as it grapples with a significant budget deficit, an aging population base and declining oil and gas revenues responsible for nearly 90 percent of the state’s budget.  “Alaska needs to be aware and to think globally. It’s true, you have a lot of natural gas and companies experienced at producing up here, but you have to think about the time it takes to get the gas to market in order to lock in those contracts,” Thorning told the conference. “You have a wonderful opportunity, but it’s very important how you move forward and that you don’t increase uncertainty for the project.” Alaskans should also be wary of talk of a state-sponsored large pipeline as an alternative to the big industry-led project. “There are three major companies involved (in the Alaska LNG Project) and all will have to look at potential cash flow and risk and whether the project is ultimately something they can commit to,” she said. “But if you look at the alternative, you look at countries with state-owned oil and gas companies and you see places that have not been efficient managers of their resources. If I’m the state of Alaska, I’d rather have the management in the hands of the private sector.” Thorning elaborated on this in an interview. “There is uncertainty about the state’s commitment,” she said. This has largely been created by talk of a state-led pipeline that could compete with the larger, industry-led project, she said. This is not a good course for Alaska. State-led energy companies mostly fail, she said. “They tend to under-invest, they do not have access to the latest in technology and there is often graft and corruption. It’s a bad model for Alaska,” she said. Thorning reviewed the state’s current economic situation in the interview, and warned that Alaska could easily go the way of Michigan, a state that enjoyed prosperity and robust manufacturing in the 1960s and 1970s but was complacent and failed to heed international forces undermining auto manufacturing, its key industry. The threat that could undermine Alaska is the unexpected revolution in shale oil and gas in the Lower 48 states and the increasingly fierce competition that is developing in international LNG markets. “What happened in Michigan could happen in Alaska if you’re not far-seeing,” Thorning warned in the interview. “I sense a false feeling of security. You can’t just assume this lifestyle can be sustained. People need to be talking a lot more about this, on television and cable channels. Alaska faces some real challenges.” Alaskans may feel secure, but “your job growth is very slow and your population is aging. The one bright spot is growth in oil and gas jobs. This is a very high-wage industry, and one you should focus on,” she said. New developments like shale oil and gas are transforming the U.S. energy industry and although there are environmental problems, shale producers are solving these, for example by reducing their use of water, Thorning said in the interview. Despite the sharp decline rates in shale wells, and low prices, shale reserves keep going up. The nation now has a 50- to 60-year supply of gas mainly due to shale development, she said. On the LNG export front, the competition is getting fierce. “Australia has four LNG export projects and is building five more. There’s also Malaysia, Qatar and east Africa. China (a major customer) is working on developing its own gas resources and is buying pipeline gas, and may be less of an LNG customer. “The question for Alaska is whether we can get a piece of the market. Can we get our project up and running in time?” Another speaker at the conference, state natural resources Commissioner Mark Myers, said a key to the success of the gas project will be gaining public acceptance for decisions the state will have to make as a partner in the Alaska LNG Project. “This is the third gas line variation, in the last decade, that I’ve worked on. Key to success will be continued public outreach by the state and better educating of the community,” Myers said. “We’re going to ask Alaskans (through the state partnership) to put a lot of money in this project at the same time we have a significant budget deficit. “All the parties will have to align, and one of the challenges with this project has always been the long lead time. And we are being asked to take those risks in an uncertain market, 10 years in advance.  It’s a lot to ask of the Alaska public in the coming years.”

Shell to revamp Chukchi plan after FWS limits drilling

Shell has received one of its final federal permits for 2015 summer exploration in the Chukchi Sea, but with a twist. A Letter of Authorization from the U.S. Fish and Wildlife Service dealing with walruses and polar bears will require drilling vessels to be 15 miles apart if drilling simultaneously. Shell’s initial prospects it hopes to drill first, “Burger V” and Burger “J” are closer than that. The company says it’s too early how the restriction will affect the summer operation. “We still plan to pursue the program outlined in our conditionally approved Exploration Plan. How we go about it may have to be modified based on the conditions outline in the Letter of Authorization, but we plan to make the most out of the time we have” Shell spokesman Luke Miller said. “Our goal is to safely accomplish as much work as we can before the end of the open water season,” he said. Shell may have options in revising its drilling plan. The plan is to use both the semi-submersible Polar Pioneer and drillship Noble Discoverer in drilling prospects around the “Burger” discovery made by Shell in the early 1990s. There are other ways work can be performed within the restrictions. For example, a well can be partly drilled but stopped short of penetrating a potential oil-bearing zone, a procedure Shell used in 2012. The two initial targets for 2015 are different than the partly-drilled “Burger A” well drilled by Shell in 2012, however. Meanwhile, vessels in Shell’s Arctic fleet are continuing to gather at Dutch Harbor, the Aleutians port being used as a staging ground. The Polar Pioneer and Arctic Challenger, a spill containment barge, are at Dutch Harbor along with several other vessels in the fleet. The second drill vessel that will be used, the Noble Discoverer, has left the Port of Everett, in Wash., and is now en route to Dutch Harbor, Miller said. This means all of Shell’s vessels are out of the Pacific Northwest, where some Seattle residents protested against the company’s Arctic plan. Some vessels will begin moving north toward the Arctic soon and one of both of the drill vessels may be moving within a couple of weeks. The plan is to have the fleet in the Arctic by late July or early August so that drilling can begin as soon as conditions allow.

Cook's exploration left lasting impression on Alaska

Editor’s note: This is the conclusion in a series of articles by the Journal of Commerce recognizing the Anchorage Centennial and examining the events and the industries that have shaped Alaska’s largest city. The series is now available as a single special edition of the Journal at centennial events throughout the summer. For Alaskans, the story of Captain James Cook’s exploration of Cook Inlet in search of the Northwest Passage is deeply woven into the history and identity of Anchorage. However, the descendents of the Dena’ina who lived in the area are decidedly ambivalent about the celebration of Cook — after all, they were the original discoverers, a thousand years or more earlier. But Cook and his crew were the first European visitors and their arrival, on Cook’s third voyage to the Pacific, was to have huge significance in the long run, says Jim Barnett, an Anchorage attorney who has become a Cook scholar. At the time the Spanish were exploring Southeast Alaska but had not ventured west of Yakutat, Barnett said. The Russians, meanwhile, were still in the Aleutians. Cook’s two ships, the Discovery and Resolution, had worked their way northwest from what is now Oregon and Puget Sound, along the British Columbia and Alaska coast, hoping to find the long-sought Northwest Passage. They were in Cook Inlet by late May and early June 1778, hoping it would lead to the imagined passageway to Europe. It didn’t, once again, but Cook sent his crew exploring in small boats, which led to the naming of Turnagain Arm, so named because it was a disappointing “turn again” for Cook’s crew (Cook originally called it “River Turnagain”. William Bligh, later of Bounty fame, was a master’s mate in Cook’s crew and led the boat crew exploring what is now Knik Arm, reporting the discovery of a large river at its head (either the Matanuska or Knik Rivers) as well as beautiful mountain scenery to the north, possibly the Alaska Range and even Denali, known to the Lower 48 as Mt. McKinley. Cook’s ships were in the Inlet for just over a week, long enough to establish that this wasn’t the Northwest Passage. While here, though, Cook took time to land at what is now Point Possession on the Kenai Peninsula to proclaim the region for English. That happened on June 1, 1778, where his crew claimed possession of the area in front of dozens of puzzled local residents, the Dena’ina. It was the first significant encounter between Europeans and Dena’ina. The visit to Cook Inlet was part of Cook’s longer exploration of the Alaska coast from which included a stop in Prince William Sound, which Cook named, along with Bligh Reef in the Sound, which was to become famous in 1989 when the tanker Exxon Valdez ran aground on it and spilled millions of gallons of crude oil. Prince William Sound, interestingly, was almost named “Sandwich Sound” by Cook after the Earl of Sandwich in England (and who invented the sandwich as a food item). The Sound was renamed by Cook after Prince William, a scion of the royal family when his journal was published. Leaving Prince William Sound, Cook ventured west along the Alaska coast in subsequent exploration, and after leaving Cook Inlet, he named Bristol Bay and Norton Sound and other features after places and people in England, as was the custom at the time. As he continued his quest for the Northwest Passage Cook entered the Chukchi Sea through the Bering Strait and, amazingly, got as far as Icy Cape, on Alaska’s northwest coast, before being stopped by ice. The two ships were almost trapped by ice off Icy Cape, in fact. Leaving an impression Cook was in the Inlet that carries his name for only a short period, but he left an impression on the Dena’ina who recorded the visit in their oral history. His visits to Alaska, however, were even more significant to the world because they led directly to more visits by British, and later American, ships for trade, and the development of a strong British and American presence as a counterweight to Russian domination. One direct result of Cook’s voyages, for example, was the subsequent detailed charting of the Alaska coast, including Cook Inlet and Prince William Sound and down to Puget Sound, that was ordered by the British Admiralty. The charting expedition was led by George Vancouver, who had been a midshipman on Cook’s crew and was selected to do the coastal charting based in his experience and abilities demonstrated on Cook’s voyages. Vancouver’s charts were of such high quality that they were used widely until the early 20th century, when the U.S. government finally conducted its own marine surveys along the Alaska coast after a series of devastating shipwrecks in Lynn Canal in Southeast Alaska, Barnett said. “His orders were to chart the coast, not the rocks,” Barnett said of Vancouver. Still, “Vancouver’s charts were the accepted maps of the Alaska coast for more than a century, until well past the Alaska purchase,” Barnett said. To their credit, “the British Admiralty published the charts, making them widely available,” even to competitor nations, in the Age of Enlightenment spirit and sense of cultural superiority that shaped British policy at the time, Barnett said. In contrast, “the Spanish were very secretive about their navigational information, to keep competitors away from their territory,” he said. The Russians seemed intent only to pillage. In Britain, however, this was the era of influential “armchair” geographers among the aristocracy and members of the rising merchant community who were intensely curious about unknown regions, particularly the Pacific, Arctic and Antarctic regions. They pushed the Royal Navy to commission Cook’s voyages, and explore he did, not just the Alaska coast but Australia, New Zealand, Antarctica, and Hawaii, where Cook died when he and his crew were attacked by Native Hawaiians just eight months after he had left Cook Inlet. Barnett also said the drawings of Native Americans, and places that Cook’s ships visited including Prince William Sound and the Arctic, by artists John Webber and William Ellis who were with Cook, had a major effect of stimulating scientific curiosity about Alaska in Europe. Native Americans in Prince William Sound, Cook Inlet, the Aleutians and Norton Sound were drawn and painted by Webber. “Cook was the first explorer to make an accurate record of what he saw,” Barnett said. “Because of that we have a pictorial record of what people looked like and what places looked like at the first point of contact,” between Native Americans in Alaska and Europeans. Cook was a close observer of people.  “He realized that the people of Hawaii were Polynesians and he figured out that people in Prince William Sound were Eskimos, distantly related to the Native people of Greenland,” Barnett said. This encouraged Cook to believe he was close to Greenland, just wishful thinking as it turned out, because he soon learned there was no nearby passageway to Europe. Cook himself was “a man of the Enlightenment,” of middle-class origins in England who rose base on his skills to become one of the earliest recruitments in the Royal Navy due to merit, not family connections. His early experience in surveying made him a close observer of his surroundings, leading to his invitation to Webber to join the voyages as official artist. Ellis, another artist, was also a surgeon’s mate on the voyages. After Cook’s death his ships and crew returned to Alaska to continue their work, even returning to the Chukchi Sea and Icy Cape in another effort to penetrate the ice and find a Northwest Passage. Cook’s second-in-command, Charles Clerke, also died on the voyage. Interestingly it was a Virginian, John Gore, one of Cook’s officers who, at the time of the American Revolutionary War, assumed command of the expedition and saw the ships with Cook’s journals and Webber’s drawings and paintings safely back to England. Cooking up a passion As an accomplished amateur historian and long-time president of the Cook Inlet Historical Society, Barnett has a keen interest in promoting more public knowledge of the history of the U.S. west coast and Alaska history precisely because there is so little awareness of it. “When I was growing up in California our sense of history was focused on the east coast,” Barnett said. “We learned about the pilgrims in school but not about why San Francisco had a Spanish name.” When he subsequently moved to Alaska, Barnett was struck by the fact that Alaskans’ sense of their state’s history seemed to start with the American purchase in 1867. There seemed little awareness of anything prior to that, including the Russian colonial story and even Captain Cook, and certainly the Dena’ina. Barnett soon developed a fascination with Cook because his last voyage to Alaska “offered a look into our prehistory, prior to the Russian and American occupation of Alaska.” But while researching Cook, Barnett discovered that even Cook scholars had written little about his final voyage to Alaska because it was so shortly followed by the tragedy of his death in Hawaii. The accounts of Cook’s voyages to the South Pacific were quite detailed, “but we would find only a few paragraphs about the North Pacific voyages, and particularly Alaska.” Barnett’s interest, and the paucity of information about Cook in the North Pacific, inspired him to write, “Captain Cook in Alaska and the North Pacific,” which was published in 2008. That and other efforts by the Cook Inlet Historical Society has now led to the exhibition “Arctic Ambitions: Captain Cook and the Northwest Passage,” a major exhibit on Cook in Alaska that will be at the Anchorage Museum until Sept. 7, 2015. The exhibit, which is cosponsored by the Anchorage Museum, Cook Inlet Historical Society and Washington State History Museum, includes artifacts and reproductions of the most famous of Webber’s illustrations and paintings. An extensive catalogue of “Arctic Ambitions,” on sale at the museum gift shop and online, contains extensive reproductions of photographs and illustrations as well as essays on Cook’s voyages by international scholars and records of contacts with Alaska Natives. The book was co-edited by Barnett and David Nicandri and published by the University of Washington Press. Barnett’s own book is also at the gift shop. After the Arctic Ambitions exhibition closes in Anchorage it will travel to the Washington State History Museum in Tacoma, Wash.

Caelus expands North Slope assets

Caelus Energy LLC has acquired a 75 percent working interest ownership in state-owned offshore Alaskan Beaufort Sea leases held by NordAq Energy, an Alaska independent based in Anchorage. The agreement was to be finalized on June 18, Caelus said in a press release. The company owns and operates the small offshore Oooguruk field on the North Slope, and is also currently engaged in developing a new onshore production pad near that field, Nuna. Caelus acquired the Oooguruk and Nuna assets from Pioneer Natural Resources for $300 million in 2014. The latest acquisition involves an interest in 26 leases covering 117,000 acres in Smith Bay, about 150 miles west of the Prudhoe Bay field on the Slope and offshore from the federal National Petroleum Reserve–Alaska.  NordAq acquired the leases, on what it calls the Tulimaniq prospect, in previous state lease sales. Under the agreement Caelus will become operator, with plans to drill one to two exploration wells this winter, according to the Caelus announcement. “We’re extremely excited. The NordAq Energy team has done a great job of defining the geologic potential in Smith Bay,” said Caelus President and CEO James Mussleman. “Our team is ready to take the helm and get to work on exploring and appraising the Tulimaniq play.” NordAq had planned to drill a well on the prospect last winter but had to delay the project. The company is active in exploring onshore leases in the NPR–A, which are not involved in the Cealus transaction, as well as exploration in the Cook Inlet basin in southern Alaska. One gas discovery made by NordAq in Southcentral Alaska is on the Shadura prospect within the Kenai National Wildlife Refuge, on subsurface lands owned by Cook Inlet Region Inc. The company has not yet developed the discovery, however. NordAq is also exploring on the west side of Cook Inlet.

Gov says amendment needed for gas tax

NIKISKI — Gov. Bill Walker is taking industry partners in the Alaska LNG Project to task for delays in resolving key issues affecting the large North Slope gas initiative. “We have identified a lack of urgency in the parties’ resolution process,” the governor wrote in a June 15 letter to state legislators. In addition, the governor said that the state now believes a constitutional amendment is needed for a long-term fiscal agreement covering tax terms with the North Slope producers. On the negotiations, Walker said in his letter to legislators that, “The methodology that the Alaska LNG team adopted for identifying problems and issues is excellent. However, there does not seem to be much process associated with resolving issues between the parties, and certainly not one with a send of time urgency.” In separate correspondence to senior managers of BP, ConocoPhillips and ExxonMobil, the three North Slope producers who are the state’s partners in the gas project, along with TransCanada Corp., Walker identified a delay among the parties in producing “term sheets” for project enabling contracts by mid-June despite an earlier agreement on the goal. “Despite the efforts of all parties, it is clear we are not on schedule,” the governor wrote to the companies. That letter was sent June 8 and released to legislators, and the public, at a joint meeting of the House and Senate Natural Resources committees in Nikiski on June 16. Walker identified a number of issues in his letter to the companies and offered state officials as facilitators to help the companies bridge differences. Consensus on several complex issues among the companies, and the state, must be concluded soon if a goal for a special legislative session in November to approve gas contracts is to be achieved. Two of the most important agreements include the gas “balancing” contract that governs how gas supplies are to be guaranteed for the pipeline by the producers, which is made more complex by the fact that two fields, Prudhoe Bay and Point Thomson, will supply the gas. A second agreement is needed for “governance,” or how the project partners will organize themselves to share costs and oversight for the upcoming front-end engineering and design phase, or FEED, and, ultimately, construction and operations. The current governance agreement covers only the pre-front-end engineering and design, or pre-FEED, work now underway. A separate issue is the needed deal on state fiscal terms, tax and royalty, between the three producers and the state. In addition, under the current arrangement, the state would conclude a long-term gas transportation agreement with TransCanada Corp. to ship state-owned gas, but Walker is exploring the idea of the state ending the TransCanada arrangement and shipping its own gas through direct state ownership of the pipeline and North Slope gas conditioning plant. Walker is concerned about the pace of negotiations on most of these issues. On the constitutional amendment, the governor said he now believes a state constitutional amendment is necessary for a proposed long-term agreement on tax terms with Slope producers. “The state believes a constitutional amendment will provide the certainty that all parties would like,” Walker wrote in his letter to the producers. Alaska’s constitution prohibits one Legislature from enacting a law that “binds” a future Legislature on taxes, which means that an agreement with producers establishing state taxes for any extended period for the gas project may not be legally possible unless the constitution is amended with language to allow the provision, the governor said. There is no constitutional problem for a long-term agreement over royalty, only taxes. Under the plan now contemplated the state would take both its royalty and tax “in-kind,” or in the form of gas, which would amount to about 25 percent of total slope gas production. The tax portion of this would equate to about 13 percent. However, once the royalty-in-kind and tax-in-kind decisions are made they would be fixed for a duration of several years, under the current plan. At the Nikiski hearing, North Slope producers said their reading of the state constitutional language is that a form of contract could be fashioned that would pass constitutional muster. “BP has looked carefully at this over several years and we believe the language of the constitution is sufficient,” to allow a fiscal agreement enacted by contract, said Dave Van Tuyl, BP’s senior manager on the gas project. The producers have said this before but have also acknowledged that the contract, if developed and approved by the state, would best be legally tested at the state Supreme Court level. A need for a public vote, if decided on, creates a big risk for the project if the public rejects it, and at the legislative meeting the producers say they could see no “plan B” of how a long-term fiscal agreement could be made following a public vote against the idea. “Alaska voters have demonstrated an adversity to amending the constitution. They are also unpredictable. So, if the vote is held and an amendment fails, do you have an alternative path?” asked state Sen. Peter Micciche, R-Kenai. Bill McMahon, ExxonMobil’s senior manager on the gas project, said there appeared to be none. “This is one of the challenges with a vote. If the people say no, it is difficult to think of a recovery plan to provide predictable fiscal terms,” he said. Rep. Andy Josephson, D-Anchorage, said a lot would depend on how the proposal is presented to the public, however. If it is specific, and tied to the gas project, the chance of approval is higher. If it is more generic, there is a possibility of failure. Sen. Lesil McGuire, R-Anchorage, said getting a constitutional amendment through both houses of the Legislature, signed by the governor and on the ballot for the November 2016 state general election is very ambitious. “This is a big deal, and it could affect the project schedule,” she said. McMahon said a November 2016 vote might not affect the schedule, however. “The critical path items for us is the environmental impact statement and the Federal Energy and Regulatory Commission certificate. If we can keep those on schedule, it might not affect the overall plan,” McMahon said. The project participants have set a mid-2016 target date for proceeding into FEED, however, which would be a $1 billion to $1.5 billion commitment. On other matters at the meeting, project managers told lawmakers that work on the or pre-FEED, is on schedule for completion late this year, and that about half of the $500 million budget for that has been expended to date.

AGDC releases 'offtake' plans

The state-owned Alaska Gasline Development Corp. has developed preliminary designs for “offtake” facilities that would allow communities to take natural gas from a large-diameter gas pipeline, if one were built. The designs were presented to AGDC’s board of directors at its June 11 meeting. Under legislation allowing the state to participate in the large Alaska LNG Project, the state has the responsibility to designate up to five gas “offtake” points for communities along the pipeline route, and to assist in developing facilities including lateral pipelines, such as one planned to be built to Fairbanks from the route of the large gas pipeline. So far, offtakes have been designated at points near Fairbanks, a “North Cook Inlet” location (presumably in the Matanuska-Susitna Borough) and a “South Cook Inlet” point, near Nikiski on the Kenai Peninsula. Nikiski is also the location of a planned large gas liquefaction plant for the project, which would produce LNG for export markets. The facilities to extract gas, condition it and transport the gas to communities and condition the gas for home heating or local power generation are not the responsibility of the Alaska LNG Project. AGDC, the state corporation, has been given that responsibility. Preliminary plans for offtake facilities presented to the corporation’s board June 11 include four possible designs. One is a “macro” off-take facility that could handle 80 million cubic feet to 330 million cubic feet per day, and that could cost $37.6 million. A second is a “mini” offtake unit that would handle 20 million cubic feet to 75 million cubic feet per day, and that could cost $28 million. A third is a “micro” offtake facility that would handle 400,000 cubic feet to 2 million cubic feet per day, with an estimated cost of $14.8 million. The fourth is a “nano” unit that would handle 40,000 cubic feet to 250,000 cubic feet per day, and that would cost $13.8 million. Meanwhile, AGDC has also taken a first cut at what the possible in-state demand for gas might be from the North Slope. This is important for the Alaska LNP Project planners to know because they must be able to assure that supplies will be available for LNG export customers. Forecasting this is complicated, however, because it must be assumed that Cook Inlet will continue to produce gas for in-state use. AGDC’s board was told June 11 that the possible in-state demand for North Slope gas might be about 70 billion cubic feet of gas yearly in 2030, five years after the project is to start up, and increasing to about 100 billion cubic feet of gas per year by 2040. The assumption included in the forecast is that Cook Inlet production will decline from its current rate of about 100 billion cubic feet of gas per year to about 44 billion cubic feet of gas per year by 2030 and 25 billion cubic feet of gas per year by 2040, therefore increasing the demand for North Slope gas. This is a “base case” that assumes no large new Cook Inlet discoveries and only one major new industrial customer, the Donlin Gold project. There is also a high demand case, however, that includes possible new mines being developed. State-owned line shelved In another development, the state gas corporation has officially put Gov. Bill Walker’s plan for an expanded state-led gas pipeline on the shelf. “We’ll be holding this in abeyance,” said board chairman John Burns at the meeting. Walker had asked the corporation to pursue engineering studies to expand a smaller gas pipeline plan but the Legislature, in a budget move, took $157 million from AGDC’s budget that would have been used for the work and re-appropriated it to support schools. Staff to the gas corporation had meanwhile prepared estimates for the upsizing engineering costs for the board but did not formally present them given the Legislature’s action. Also, an engineering and design consortium AGDC had hoped to use for the redesign for a scaled-up project, which was under contract for design and engineering for the gas treatment plant for the smaller pipeline, has now been demobilized, the board was told. Remobilizing the team would add to costs of the engineering. For several years AGDC has been working on a plan for a smaller 500 million-cubic feet per day pipeline from the North Slope that would serve as a backup to get gas to Alaska communities in case the large Alaska LNG Project is not built. The engineering and design work on that project, known as the Alaska Stand-Alone Pipeline, or ASAP, is now complete and a supplemental environmental impact statement required because of design changes is due to be complete in 2016. The project is essentially ready to go if it needed. Walker had wanted to increase the scope of ASAP, however, so that it could carry gas volumes similar to those in the larger industry-led project. That unleashed a barrage of criticism, however, from legislators and others that the governor wanted a state-led pipeline in competition with the industry project. Despite that furor, the work on the smaller state pipeline has yielded positive benefits for the larger gas project, in which the state is a 25 percent partner. The routes of both pipeline are now aligned to follow the same rights-of-way, which means that the Alaska LNG Project can benefit from environmental and technical work done by AGDC for its smaller pipeline. “This is a huge benefit for Alaska LNG,” said Dave Cruz, an Alaska contractor and board member of AGDC who chairs the board’s technical review committee. “There has been good science and good data that has been generated, and Alaska LNG has accepted it.” The Legislature had earlier appropriated $305 million for ASAP to do engineering and permitting sufficient to get the smaller project to a construction decision. About $118 million of that has been spent to date, leaving $187 million. That is now reduced by $157 million due to the Legislature’s re-appropriation this spring, however. Meanwhile, $48 million authorized earlier this year for AGDC’s remaining work on ASAP, of which $28 million has been spent to date, is on projects that also benefit the larger pipeline. On work that benefits both projects, Alaska LNG Project pays 80 percent, the AGDC board was told. The state corporation is also undertaking geotechnical work this summer on behalf of the industry-led project, taking advantage of special, streamlined permit authority on state lands given the gas corporation by the Legislature. On work like this that is solely on behalf of Alaska LNG, the consortium reimburses AGDC for 100 percent of its costs, although the state might pay part of that if it involves work at the LNG plant, in which the state is a full 25 percent partner. The state is in a partnership with TransCanada Corp. on the pipeline and North Slope gas conditioning plant.

UA Fairbanks leading way on Arctic research

FAIRBANKS — What may be the world’s biggest conference on Arctic science will be held next March at the University of Alaska Fairbanks. About 800 to 1,000 scientists and government officials from around the world will be gather on UAF’s campus, said Interim Vice Chancellor for Research Larry Hinzman. The meeting — actually dozens of meetings and workshops — will happen over the university’s spring break, which means dormitory space will be available with students temporarily off the campus. The spillover will be a boon for Fairbanks hotels and restaurants. Hinzman took over management of the university’s research programs, though on an interim basis, after Mark Myers, the previous research chancellor, was named by Gov. Bill Walker as commissioner of Natural Resources.  He is a veteran on the university’s research establishment who helped set up UAF’s International Arctic Research Center, one of several research institutes operated by the Fairbanks university. Other institutes include the well-known Geophysical Institute as well as the institutes of Arctic Biology, Arctic Engineering and the School of Fisheries and Ocean Sciences. UAF also operates the new 261-foot research vessel Sikuliaq, which is owned by the National Science Foundation. The Sikuliaq, home-ported in Seward, is in its first year of operations in the Arctic, according to Pete Zerr, UAF’s manager of marine operations. The vessel conducted two research voyages late last year, one to the south Pacific to test remote underwater vehicles and a second northwest of Hawaii in a study of seamounts. Early this spring a test voyage to the ice regions of the Bering Sea was done, Zerr said. This summer the ship will work in the Aleutians and in the Beaufort and Chukchi seas and will conclude with a northern voyage that will extend into November, Zerr said. The 2014 and 2015 voyages were done to support research by the Scripps Institution of Oceanography, based in San Diego, and the Woods Hole Oceanographic Institute in Massachusetts. The U.S. Office of Naval Research is another client for the 2015 season. Hinzman said the UAF scientific gathering next spring illustrates the increasing importance of the university in Arctic and northern studies, with its focus on ocean and terrestrial changes that are occurring because of climate change. This is now more important because the U.S. has assumed, for two years, the chair of the Arctic Council, the eight-nation international body that works to coordinate Arctic policy, including for research, among nations bordering the Arctic Ccean. The Arctic Council will hold a meeting in Fairbanks during the UAF conference and that will include the chairs of working groups and task forces that function under the council as well as six permanent participants, which include two Alaska Native groups, and 32 permanent “observers.” Observers include nations with an interest in the Arctic, like the United Kingdom, that do not border on the Arctic Ocean, as well as other governmental and nongovernmental organizations with an interest in the region. Two other major Arctic scientific meetings will also occur at UAF in the same time, Hinzman said. These include the “Arctic Science Summit,” an annual event held in different northern cities and this year Fairbanks, and the Arctic Observing Summit, an organization that provides coordination and guidance for Arctic observing systems. “The goals in having these two groups meet is to strengthen international Arctic research collaborations, leverage research partnerships and strengthen the Arctic observing systems,” Hinzman said Other, smaller-scale meetings are planning including some Asian polar institutes like the Asian Forum for Polar Science and the Korean Polar Institute, the Canadian Polar Commission and the EU-Polarnet and the European Polar Board. “Many of these research groups have never met each other before,” he said. Many are also little-known outside the corridors of government and research institutions. The U.S. Arctic Research Commission is well known in Alaska because prominent Alaskans have chaired it, currently former Lt. Gov. Fran Ulmer and previously Mead Treadwell, also a former lieutenant governor. However, the U.S. also has the U.S. Polar Research Board and Polar Educators International. UAF, meanwhile, has cemented its role as the leading U.S. Arctic research university and one of the world’s leading scientific research organizations focusing on northern latitude studies. The evidence for this, Hinzman said, is in the number of Arctic-related scientific publications by UAF researchers and the number of citations of its publications.  “UAF leads all other single institutions in the number of publications and the number of citations of its publications,” he said. In the world of research, what is published and cited is important because it reflects the productivity of research teams and the quality of their work in the eyes of peers around the world. The Fairbanks university scored number one in the world in publications and citations between 2009 and 2014, Hinzman said. Arctic-related publications in scientific journals totaled over 700 and citations by other scientists of publications of UAF papers totaled nearly 8,000. In publication citings only, the University of Colorado at Boulder came close behind UAF at almost 7,000 citations. Other prominent universities including Canadian and European institutions were at about half the number of citations for UAF publications. The same was true for the number of scientific publications, about half of UAF’s total, except for the University of Tromso in Norway, which saw about 550 papers published between 2009 and 2014 compared with Alaska’s near-700. UAF research covers a broad range including changes in sea ice cover and shifts in land ecosystems as well as changes affecting Arctic plants and animal life. Permafrost and its gradual warming has a strong focus. The Fairbanks university has also been leading the development of new technologies to aid in research including remote sensing and the use of advanced radars in documenting changes in land forms, vegetation and infrastructure due to shifting permafrost conditions. UAF researchers are also known for their assistance to industry and government agencies. Recently the university has been working with major oil and gas companies like Shell and ExxonMobil on sea ice studies. Forty-plus years ago Arctic engineering researchers at UAF assisted in the construction of the Trans-Alaska Pipeline System in permafrost areas, and in the development of design features that preserved permafrost and the structural integrity of the pipeline.

Walker pitches TransCanada buyout

Gov. Bill Walker is considering ending the state’s relationship with TransCanada Corp. in the big Alaska LNG Project and taking over a full 25 percent share of the project. In an interview June 7 in Fairbanks, Walker said that he is weighing the takeover option along with keeping TransCanada in the consortium under the current structure. Under that arrangement TransCanada would ship state-owned gas though its share of pipeline capacity. A third option Walker is weighing is the state taking a 40 percent share of TransCanada’s interest in the project under the current contract with the state. The state now has a contract with TransCanada that has the pipeline company owning and operating 25 percent of the large North Slope gas treatment plant and the 42-inch, 800-mile pipeline, and with the state itself owning 25 percent of the large liquefied natural gas plant planned for Nikiski. North Slope producers BP, ConocoPhillips and ExxonMobil Corp. would own 75 percent of the overall project. The percentages will be roughly in line with the gas ownership of each participant, except that under the current arrangement the state would have TransCanada as a partner in its share. “TransCanada is a very fine company and I have no problems with their capabilities,” Walker said. However, the state assuming a larger share of ownership of the project may be in its long-term best interests, the governor said. Walker made the comments at a conference on state fiscal issues in Fairbanks. In a related development, Walker has shuffled the state’s management team on gas pipeline negotiations. He named Audie Setters, a 35-year industry veteran manager, as the state’s top manager for gas issues. Marty Rutherford, who formerly filled that role, will remain as deputy commissioner of Natural Resources, the governor said. There was no announcement of the change but in an interview Walker described it as a “transition” that would bring more strength into the state’s negotiating team, while retaining Rutherford’s experience and allowing her to devote more time to Department of Natural Resources matters. Rutherford would presumably remain engaged in key gas issues as they relate to the DNR, such as a pending decision to take royalty gas in-kind and a separate gas-balancing agreement. Walker may face some embarrassing questions about naming Setters to the role, however, because he is a resident of Houston, Texas, although he has been working with the state on gas issues for about a year. Early this year Walker fired a board member of the Alaska Gasline Development Corp. because he lived out of state, also in Houston. On TransCanada, the governor has asked the state Legislature for $108 million to compensate the pipeline company for its expenses to date on the project. Legislators have asked for more details of the governor’s plans, however. Walker did express concern over the added burden of financing a larger state share of the project in view of Alaska’s diminished finances, which are currently stressed by low oil prices and a sharp drop in state revenues. The Heads of Agreement signed by the project participants with former Gov. Sean Parnell set the framework for the preliminary work on the pipeline and LNG plant. The state signed a separate agreement with TransCanada to allow the pipeline company to own a stake in the project. The contract expires in December, although the assumption has been that it would be extended. Walker may opt not to extend the contract, however, leaving the state in full ownership of 25 percent of the pipeline and Slope gas plant along with its share of the LNG project. The project is currently in the pre-Front End Engineering and Design, or pre-FEED, stage, with this phase of work to be wrapped up by early next year. The pre-FEED will include a revised cost estimate, which is currently pegged at $45 billion to $65 billion. The next key decision for the overall project will be moving into full Front-End Engineering and Design, which could occur in mid-2016 and will involve an approximate $2 billion commitment by the parties. Later this year, however, the state must decide on whether to extend its deal with TransCanada, and also finalize a fiscal agreement with North Slope producers covering gas production tax and royalty terms. Negotiations on the fiscal agreement and other pending issues such as a Payment-in-Lieu-of-Taxes, or PILT, on municipal and state property taxes, are currently under way. In an email sent to state legislators May 29 but made available June 9, Walker said, “The agreement with TransCanada allows the state to remove the company as its agent at the end of the pre-FEED. The administration could choose to remove TransCanada at that time, and as late as July 2016. Alaska could then take a direct role in the project at the FEED stage.” TransCanada’s role in the overall project has been somewhat controversial in Alaska. Parnell agreed to bring the pipeline company in as a partner to gain access to the pipeline company’s expertise in large project management and in dealing with the producer partners in capacity management and expansion issues. Another consideration is that the arrangement would have TransCanada finance its share of equity in the project, which would amount to several billion dollars, with its own resources. That would relieve the state from the burden of having the raise the money, if it were to assume the full 25 percent share. On the other hand, under that arrangement the state would not make as much profit from the project. However, the TransCanada deal was also done partly to resolve potential legal issues related to terminating a previous contract the state had with the pipeline company under the Alaska Gasline Inducement Act, or AGIA. Many state legislators, and Walker as a candidate for governor, criticized Parnell’s move, arguing it gave up too much ownership and share of future revenues to the pipeline company. There has also been an assumption that TransCanada, as a part owner, would also play a major role in managing the actual construction of the pipeline, an area where it is widely experienced. However, an industry source close to the project, asking not to be identified, said decisions on which entities would be involved in construction management have not been made. In a response to Walker’s request for funds, state legislative leaders wrote, “Many in the Legislature support the termination of the state’s contract with TransCanada once sufficient financial review and a thorough evaluation of the benefits and risks is undertaken.” The response was in a letter sent June 4 but not released to the public until June 9. It was signed by House Speaker Mike Chenault and Rep. Mike Hawker, R-Anchorage, chair of the Legislative Budget and Audit Committee, and the co-chairs of the House Resources Committee, Reps. Ben Nageak, D-Barrow and Dave Talerico, R-Healy. Lawmakers also asked for details as to how the state can fund a larger commitment to the project: “Our partners, before progressing to FEED, will need to know the state has the ability to fund its FEED commitment, which will be significantly higher if TransCanada is no longer a partner in the venture.”


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