Alaska Journal of Commerce

New and bigger taxes, reduced PFD in gov’s plan

(Editor's note: This story has been updated to include remarks from legislators as they become available.)   Ready or not Alaskans, here comes reality: higher taxes, more of them and a smaller dividend. Gov. Bill Walker unveiled his long-range fiscal plan for the state Dec. 9, which includes a personal income tax as well raising nearly every state industry tax in the face of yearly budget deficits approaching $3.5 billion. The Legislature will have its say when it convenes in January, but under the Walker administration’s proposal, the State of Alaska would adopt federal code for its income tax and levy the tax at 6 percent of ones federal liability. That equates to about 1.5 percent of an individual’s annual income. An income tax allows the state to capture revenue from nonresident workers — about 20 percent of Alaska’s workforce, according to the state Labor Department — as well as profits from S-corporations and partnership businesses. The relatively small income tax would generate an estimated $200 million for the state every year. Withholdings would begin in January 2017. Alaska has not had an income tax since 1980, and three attempts to reinstate a tax during the fiscal disaster of the late-1980s all failed. Along with the income tax, Walker formally proposed shifting how the state manages its money towards a “sovereign wealth fund” model, an idea first floated by the administration in late October during a presentation to the Legislature by Attorney General Craig Richards. The concept would stabilize state revenue by filtering it through the Permanent Fund, thus allowing the money to make an investment return, before lawmakers could spend it. More specifically, the Walker administration’s plan would put half of the state’s resource royalty revenue and all of its oil and gas production tax income into the Permanent Fund each year. The earnings, or investment return, made by the fund would then be allotted to the Permanent Fund Earnings Reserve account and spent to run state government. The state could sustainably draw $3.2 billion from the Earnings Reserve each year under the plan. That projection holds up under 97 percent of scenarios and is based on roughly $50 per barrel oil, according to the administration. Permanent Fund Dividend checks, which have historically come from the Earnings Reserve, would then come from the remaining 50 percent of annual resource royalties. Alaskans would no longer get a Permanent Fund Dividend; rather they would get a resource royalty dividend, pegged to be about $1,000 in the coming years. A $3 billion infusion from the Constitutional Budget Reserve, or CBR, account into the Earnings Reserve would be needed to jumpstart the plan, according to the administration. The CBR currently holds about $9.1 billion, while the Earnings Reserve will hold about $6.5 billion at the end of fiscal 2016, according to Alaska Permanent Fund Corp. projections. The Permanent Fund held $51.3 billion in total assets at the end of the third quarter. That money cannot be accessed by the Legislature without a constitutional amendment. The Earnings Reserve can be spent with a simple majority vote. The whole plan is based on continuing status quo unrestricted state spending in the $5 billion range. The fiscal plan “keeps the Permanent Fund permanent,” Walker said while unveiling his proposal. Combining a small, progressive income tax with a smaller dividend, which is an impact to all Alaskans, is an imperfect way to spread the burden of now directly paying for government services across all residents, while minimizing the impact on low-income Alaskans, the administration says. Walker’s proposed taxes and fiscal plan will all be vetted, dissected and reflected upon during the upcoming legislative session. Any action will have to be approved by the Legislature. “This is a work-in-progress; this isn’t an edict or a mandate,” Walker said. “The main message is that we have to fix the problem.” Doing nothing — not really an option — would require the state to draw $33 billion from savings, money the state does not have, over the coming years while dividend checks would disappear in about 2020, the administration says. A large natural gas pipeline, which would generate billions in revenue annually, cannot itself save the state’s finances and is still far from a certainty. How quickly things change. Less than a year-and-a-half ago Alaska North Slope crude was selling for $101 per barrel. On Dec. 7, the price for Alaska oil fell below $40 per barrel for the first time since February 2009. The second half of this year is the first time oil prices have consistently held below $50 per barrel since the end of 2004. Alaska’s state revenue history looks much the same. The Department of Revenue’s annual fall revenue forecast released Dec. 8 projects Alaska will take in just less than $1.6 billion in unrestricted general fund revenue in the current 2016 fiscal year. That would be the lowest income level for unrestricted funds the state has seen since oil was below $20 per barrel in 1999. Just a few years ago in 2013 the state took in nearly $7 billion of discretionary income; a year prior that number was $9.5 billion. The problem this time is declining North Slope oil production will not allow the state to refill its coffers once oil prices rebound, whenever that may be. As a result, the state must wholly shift its financial structure. Further government spending cuts totaling $100 million are proposed in the governor’s operating budget, Office of Management and Budget Director Pat Pitney said at a press briefing Dec. 9. Unrestricted government spending has fallen by nearly $1 billion over the last couple years. Additionally, about 600 state employees have been laid off as a result of those budget cuts. Senate President Sen. Kevin Meyer, R-Anchorage, said he has not had a chance to fully review the administration’s proposal, but his initial reaction is that the spending cuts do not go far enough. “A $100 million reduction (proposed by the governor) is not acceptable to our Senate Majority if we’re asking for $400 million in new taxes on Alaskans,” Meyer said. The majority caucus will be meeting soon to iron out priorities, but Meyer said a likely target for Senate Republicans is a 5 percent to 10 percent reduction. House Speaker Rep. Mike Chenault, R-Nikiski, said he disagrees with the governor over not proposing a state sales tax. There are problems with how it would relate with municipal sales taxes, even in his own Kenai Peninsula Borough, the Speaker said, “but I still think a sales tax is a fair tax across the state, although it won’t be liked in rural Alaska.” Chenault added that he is concerned about the administrative costs associated with implementing new taxes. Walker said a sales tax was considered but not chosen based on the disproportionate impact on rural Alaska, where higher costs of goods would generate a higher sales tax. House and Senate Democrats commended Walker for not ignoring the state's fiscal bind in formal statements, but said the governor's plan pushes the burden of paying for government onto low-income Alaskans. "The oil companies, and the wealthiest Alaskans will be thrilled with this proposal because three-fourths of what the government takes will come from hard-working Alaskans, many of whom rely on their Permanent Fund checks to cover the basics," Anchorage Democrat Sen. Bill Wielechowski said. "The whole plan is skewed to have the least impact on the rich and powerful, while dumping the burden on those who can least afford it. This is a reverse Robin Hood plan that robs from those wo need, and spares the rich." Oil and gas tax credits — brought into the limelight by Walker’s partial deferment of $200 million of the the state’s $700 million refundable credit obligation in the current year’s operating budget — would be transformed into a loan program, with interest rates tied at least partially to what percentage of a project’s workforce is Alaskan. That would be a drastic shift away from the current refundable credit system, which pays, particularly small producers, dollar-for-dollar on many exploration and development capital expenses. Industry representatives have pushed back on major changes to the state’s oil and gas tax credit program, and a report released Dec. 1 by the Senate Majority urged against wholesale changes to the program, fearing a sudden retraction from the industry in the state when low oil prices are already challenging bottom lines. The Alaska Oil and Gas Association panned Walker’s plan to change the tax credit program. “At a time of low oil prices, now is not the time for the state to increase taxes or reduce incentives to the oil and gas industry in Alaska,” said AOGA President Kara Moriarty in a statement. “Unfortunately, Governor Walker is proposing to do both. We support the governor’s goal to put more oil into TAPS. However, increasing taxes and removing important incentives will not lead to more production.” Moriarty noted that prices have now slid to less than $40 per barrel and cited fiscal year 2014 figures of $46.42 per barrel for transportation, operating and capital costs. The administration’s tax plan would also harden the oil production tax floor for legacy oil from large producers to prevent operating losses from eliminating a company’s tax obligation, a recommendation made by the Senate Oil and Gas Tax Credit Working Group report, but also bump the floor up from 4 percent to 5 percent. The oil and gas tax credit changes would not necessarily generate much revenue, but rather would save the state upwards of $500 million per year that it is currently spending. “There’s no one that won’t be impacted in some way by what we’re going to propose,” Walker said. “I guarantee, everybody in Alaska will find something about this plan they don’t care for.” State motor vehicle fuel taxes —the lowest in the nation at 8 cents per gallon— would be doubled to 16 cents; the marine fuel tax would also double to 10 cents per gallon; and the 3.2 cents per gallon aviation fuel tax would go to 10 cents. Those increases would raise $45 million, according to Walker administration projections. Most other major industry taxes would be raised between 1 percent and 2 percent to generate another $12-$20 million annually from the tourism, fishing and mining industries, the administration says. A change to tourism taxes would eliminate a deduction that has allowed cruise companies to deduct local head tax payments from their state obligations, primarily in Juneau and Ketchikan. Additional sin taxes would include a 10 cents per drink alcohol tax to collect $40 million and a $1 per pack increase to tobacco products and e-cigarettes. The regulated marijuana trade — new in fiscal 2017 — should generate about $12 million in its first year, according to the Revenue Department. Elwood Brehmer can be reached at [email protected]

AGDC, producers approve 2016 spending

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

Cook Inlet fish meeting to stay in Anchorage

The 2017 Upper Cook Inlet meeting of the Alaska Board of Fisheries will be held in Anchorage, as planned and as usual. The board made the call by a 5-2 vote at the tail end of its Bristol Bay finfish meeting, also in Anchorage. Only two board members, commercial fishermen Sue Jeffrey and Fritz Johnson, voted in favor of a proposal moving the meeting from Anchorage to Kenai Peninsula, where the board hasn’t held an Upper Cook Inlet meeting since the last millennium.  “Maybe next time,” said member John Jensen of Petersburg, drawing an outraged cry from the audience. “Why maybe?” called John McCombs, a Peninsula fisherman and board member of United Cook Inlet Drifters Association. Board director Glenn Haight and others quietly warned McCombs to be quiet while member Sue Jeffrey began making her comments, “hopefully without feeling threatened,” she added. “Threatening” was the exact term Jensen used to characterize the Upper Cook Inlet meeting issue after the matter had closed. “I’m glad to have it behind us,” he said. Member Robert Mumford said he had no compunction against moving the meeting to the Peninsula, but ended up voting against the move, not wanting to “upset the apple cart.” Mumford hinted that he felt pressured.  “I feel like we’re in the middle of a soccer game, and at least I’m the ball,” said Mumford. Walker appointed Mumford to the board in May following the failed appointments of Roland Maw and Robert Ruffner. Mumford has not yet been confirmed by the Legislature. Board members listed fears of influence peddling, political perceptions, security, convenience, and fairness. Jensen said the board goes through pains to make meeting agendas so stakeholders can time their visits to the 14-day meeting. The board’s consensus was that Anchorage, at the center of the Upper Cook Inlet area, is the logical choice. “If we’re going to be fair to the majority of users, it’s having a meeting in Anchorage,” said Jensen. “The user groups don’t have to spend that much time up here. If they have to come for one part of the meeting, they know where it is.” Peninsula residents have long argued that the board process is too complex and nuanced to go for only one day, and that the process is therefore skewed against those who can’t make the trip. Ed Schmitt, the chairman of the Kenai Area Fishermen’s Coalition’s board, said the vote is a blow to the Kenai Peninsula. Two weeks in Anchorage is prohibitively expensive for those without large financial interest in meeting outcomes, so many people who use the fisheries are not heard, he said. “The community is centered around the Kenai River,” Schmitt said. “It’s in our back yard. It’s what we use. It’s a very frustrating process for the people who are most affected by it.” A potential meeting relocation has been in spotlight since November, when two letters supporting a meeting relocation made their way to the board, including one from Gov. Bill Walker. The board had scheduled the meeting for Anchorage last year, and voiced resentment at being made to consider it again. The Bristol Bay meeting, board members said, suffered from the “distraction” of the Upper Cook Inlet relocation issue. “All this went on during another region’s meeting,” said board member Orville Huntington. “I don’t think it’s fair to the people of Bristol Bay.” Walker wrote a letter to the board Oct. 21, asking it to consider changing the location and promising to attend if it were held on the Peninsula. “There has been much attention given to the controversies surrounding the Cook Inlet fisheries, and I feel we should attempt to improve the communication and exchanges among the many interested parties,” wrote Walker. “Holding a meeting on the Peninsula, possibly Soldotna, may show a willingness to consider points of view from local residents who may not have been able to participate over the past five board cycles.” After Walker’s letter, public officials flooded the Board of Fisheries with written comments either supporting or condemning a meeting relocation. Mat-Su Sens. Mike Dunleavy and Bill Stoltze jointly scorned Walker’s “rather forceful letter,” accusing him of “inappropriate” commercial fishing favoritism. “It appears to (our constituents) that you continue to receive bad advice and provide preferential treatment to one user group, commercial fisheries,” the letter states, “to the potential detriment of tens of thousands of Alaskans that participate in recreational and personal use fisheries.” A second letter offered the board financial benefits, which some board members later equated with a corrupting bidding process. In a Nov. 16 letter, Kenai Peninsula Borough and City of Kenai mayors Mike Navarre and Pat Porter, and Soldotna Mayor Pete Sprague offered the board over $60,000 in service savings by volunteering local venues, transportation, and coffee service. “In my opinion, this is a procurement issue,” said member Reed Morisky, a lodge owner. “We’re on a slippery slope here. I don’t recall a public notice saying that offers would be entertained for free venues and free coffee. The board meeting becomes a low bid situation, I think it pollutes the process.” Peninsula residents said they are down, but not out, and already looking to the board cycle beyond 2017. Rick Koch, the city manager for the city of Kenai, said he was disappointed in the decision but not intending to give up. “I’m disappointed, obviously,” he said. “My focus and the focus of others will shift in 2020 to the UCI meeting as well as being able to take advantage of the work session that will be held down here in 2016.” Peninsula Clarion reporter Elizabeth Earl contributed to this report. DJ Summers can be reached at [email protected] Elizabeth Earl can be reached at [email protected]

Donlin environmental impact statement released

Twenty years in the making, the first draft of an environmental impact statement for the Donlin Gold mine proposed for Western Alaska was released Nov. 30. “It’s still a long path ahead of us, a lot of challenges ahead of us, but (the EIS) is a significant milestone,” Donlin Gold General Manager Stan Foo told the Resource Development Council of Alaska Dec. 3. Early resource definition work at the site began in 1995. A true mega-project, Donlin Gold’s $6.7 billion plan calls for a conventional open-pit mine 1.5 miles across and up to 1,200 feet deep about 10 miles north of the village of Crooked Creek in the Upper Kuskokwim River drainage. A tailings facility, large power plant, workers’ camp and 5,000-foot airstrip would accompany the mine. Also supporting the mine operation would be 315-mile, 14-inch diameter natural gas pipeline originating on the west side of Cook Inlet that is needed to fuel the 227 megawatt capacity power plant. To the south and east, a 30-mile road would connect the mine to a new barge port on the Kuskokwim. Further down the Kuskokwim, port cargo landing facilities would be expanded in Bethel, and new diesel storage tanks would be needed Dutch Harbor. In all, the direct supply chain in Donlin’s proposal from Cook Inlet to Dutch Harbor would cover approximately 1,050 miles. Donlin Gold is a joint venture between Barrick Gold Corp. and NovaGold Resources Inc. The natural gas pipeline would initially be only about half full as the average load of the power plant will be about 150 megawatts, according to Foo, leaving potential capacity for natural gas that could be used by local communities to offset high-cost, diesel-sourced heat and power. Assuming the cost of using Donlin’s pipeline and developing natural gas infrastructure in the region would be the responsibility of a third-party developer, Foo said. He said the scope of the Donlin project meant compiling a stock of information rarely matched in scale, much like the project proposal. The draft EIS, which is primarily shared in electronic form, would surpass 7,000 printed pages, he surmised. The mine itself would produce more than 33 million ounces of gold from about 500 million tons of ore over an initial 27-year operating life, or more than 1 million ounces per year. It would process 59,000 tons of ore per day, according to the draft EIS prepared by the U.S. Army Corps of Engineers. “Very few mines in the world produce more than 1 million ounces of gold each year,” Foo said. However, gold prices will need to improve between now and the time Donlin decides whether or not it plans to move forward with construction. Foo said the mine would not be feasible at today’s gold prices of less than $1,100 per ounce. The tailings storage facility, which would be the first full-lined facility in Alaska, he said, would cover approximately 2,300 acres. During three to four years of construction, the mine would employ about 3,000 workers; once in operation the workforce would average about 800 employees. Calista Corp., the regional Alaska Native corporation, holds subsurface mineral rights for the mine. The Kuskokwim Corp., the area village corporation, holds surface rights. Both have been “very supportive of the project,” Foo said. Donlin Gold submitted its EIS application to the Corps in July 2012. A final EIS and subsequent record of decision are expected in mid- to late 2017. The draft EIS examines five project alternatives beyond Donlin Gold’s preferred alternative and the requisite no-action alternative. Of those, three would change the project in an effort to reduce barge traffic — specifically diesel barges — on the Kuskokwim River, which area residents rely heavily on for travel and subsistence salmon harvests. The reduced barging options include using liquefied natural gas-powered equipment at the mine, thus reducing the need for diesel fuel; constructing an 18-inch diesel pipeline from Cook Inlet to the mine, which would replace the natural gas line; and moving the port site from Jungjuk Creek 69 miles downstream to Birch Tree Crossing to reduce the distance freight and diesel would travel on the Kuskokwim. An alternative that would use a dry stack method of tailings storage instead of the tailings pond and dam proposed by Donlin would avoid the risk of a tailings dam failure. The tailings under this option would be dewatered in a filter plant and saturated into a compactable cake material, according to the draft EIS. That material would then be spread into thin layers with bulldozers in a dry stack tailings area. The last alternative would shift the natural gas pipeline route slightly through the South Fork Kuskokwim valley. Comments on the draft EIS can be submitted to the Corps through April 30.

$305B transportation bill grows annual outlays for Alaska

President Barack Obama signed into law the nation’s first long-term transportation funding bill in more than a decade on Dec. 4. The $305 billion Fixing America’s Surface Transportation, or FAST, Act provides five years of funding aimed at improving rail, road and marine infrastructure. It passed both the House and Senate by wide margins the day prior to being signed by the president. All three members of Alaska’s congressional delegation supported the legislation. Alaska is poised to receive more than $2.6 billion over the life of the FAST Act, with yearly allotment increases. The state took $483.9 million from the federal government for surface transportation programs in federal fiscal year 2015, which ended Sept. 30. In 2016, that figure jumps to $508.6 million; by the end of the FAST Act in 2020 it is $555.3 million, according to a release from Sen. Dan Sullivan’s office. Passage of the five-year bill gives funding certainty needed to make infrastructure investments in Alaska, Sullivan said. “The bill also includes reforms to our permitting system, which will help cut through project-killing red tape and streamline regulatory burdens,” he said in a formal statement. “This bill amounts to a big win for Alaska as it will allow us to not only address our infrastructure needs, but also promote and sustain economic growth throughout the state.” The legislation establishes a council of relevant federal permitting agencies tasked with determining best practices and modeling timelines for evaluation of major transportation projects in an effort to speed up federal regulatory approval, according to a conference committee summary. A pilot program will also allow up to five states to substitute their own environmental regulations in place of the National Environmental Policy Act, or NEPA, given the states’ laws and regulations are at least as stringent as those in NEPA. The FAST Act is a win for Alaska, as Sullivan noted, at least when it comes to dollars per Alaskan. A large, young state with limited transportation infrastructure, the $2.6 billion equates to more than $3,500 per Alaskan, while the rest of the country averages $956 per citizen. “We all recognize that Alaska is in the midst of a budget crisis, so being able to rely on federal funding for critical infrastructure projects, whether it be on roads, bridges, or ferries, is key to our state,” Sen. Lisa Murkowski said in a release. Murkowski served on the conference committee that resolved the final transportation bill. Rep. Don Young noted in a statement from his office that the last long-term surface transportation bill, SAFETEA-LU, was legislation he authored as chair of the House Transportation and Infrastructure Committee in 2005. He said the FAST Act is “far from perfect,” but, like Sullivan, added it makes several important reforms to streamline federal permitting. “The success of any state’s economy directly depends on their ability to move people and products safely and efficiently,” Young said. “That is especially true in a developing and geographically unique state like ours, which is why I worked so hard to secure numerous provision specifically beneficial to Alaskans — including $31 million annually for the Alaska Railroad, ample funding for our ferry program, and significant increases for the Tribal Transportation Program.” An error in the funding formula in the 2012 MAP-21 transportation bill that cost the Alaska Railroad Corp. $3 million per year is corrected in the FAST Act, which also grew the pool of passenger railroad formula funding. In all, the Alaska Railroad will get a $5 million increase in federal funding annually, according to a railroad spokesman. Railroads across the country will also have the opportunity to compete for $199 million in federal grants to aid implementation of the federally mandated Positive Train Control safety system, which is expected to cost the Alaska Railroad nearly $160 million by the time it is fully in place in 2018. The state-owned Alaska Railroad has spent more than $70 million to install Positive Train Control over several years and the Legislature authorized it to sell bonds earlier this year to further the work. Railroad spokesman Tim Sullivan said the railroad will likely apply for federal assistance, but added how that would play into the current PTC funding plan is still unclear. The previous year-end deadline for railroads to have Positive Train Control in place was pushed back to 2018 in a separate piece of legislation passed earlier this fall. The Alaska Marine Highway System, hit hard by state operating budget cuts, gets a little more for its capital improvement program. The state ferry system will receive $18.6 million annually for major work on its vessels, which equates to a $2.4 million increase over the five years of the FAST Act. Earlier versions of surface transportation legislation changed the funding formula for state ferry programs, which could have lessened Alaska’s take and caused concern in the Alaska Department of Transportation. The Tribal Transportation Program — $450 million per year under the MAP-21 extensions — will get an additional $15 million in 2016 and $10 million more in the following four years. A new federal freight program designed to fund freight-related highway improvements will send $80 million Alaska’s way over the duration of the legislation as well. As Alaska and other states legalize the sale of marijuana for recreational use, the FAST Act requires a feasibility study be done to investigate impairment standards for drivers under the influence of marijuana, according to a House Transportation briefing.

State working on flatfish tax fix to capture foregone revenue

A state tax rate glitch let groundfish trawlers off the hook for more than $10 million of fishery taxes in the last half decade, and there’s no concrete fix just yet. The fishery resource landing tax taxes groundfish based on ex-vessel price. Processors turn flatfish caught as bycatch into low-value fishmeal, so the only known ex-vessel price for certain flatfish species is artificially low. Nine species have this price uncertainty, but most flatfish volume comes from yellowfin sole and Atka mackerel. By only having an ex-vessel value based on the price paid for bycatch turned into fishmeal, the state has no idea what the ex-vessel value is for the direct flatfish fishery that has annual harvests measured in hundreds of thousands of metric tons. According to state research estimates, the state has lost out on $1.8 million to $2.5 million per year, or more than $10 million over the last five years. Researchers haven’t yet looked back further due to paucity of data, but the fishery resource landing tax has existed since 1994. Lori Swanson, assistant executive director of groundfish trawler group Groundfish Forum, did not say whether the industry knew it had been underpaying since the tax’s birth. “They pay what the state tells them to pay,” she said. The state doesn’t really know The Department of Revenue, however, hasn’t been calculating a realistic view of fleet’s tax rate, and is only starting to rework the system. The state began this tax specifically for factory trawlers and catcher-processors, but overlooked a systemic flaw from the beginning. “It’s actually two things,” said Kurt Iverson, a research analyst with the Alaska Department of Fish and Game. “First, a very small amount of the total harvest is in the (Commercial Operator’s Annual Report), and on top of that, that harvest is not representative of a true ex-vessel valuation because it’s coming in as bycatch.” Anna Kim, the Department of Revenue chief of revenue operations, said she can’t speculate why the issue went for so long without being noticed. Iverson said the problem isn’t intentional. The Department of Revenue simply attached the tax to shoreside sales, which don’t happen for some species.  “There’s nothing wrong, just an artifact of data,” Iverson said. “How do you get at the price when very little ever crosses the dock as a shoreside sale?” The federally managed Exclusive Economic Zone sits from three to 200 miles off the coast. Groundfish — which includes pollock, Pacific cod and flatfish — makes the bulk of the volume pulled from the federal waters off Alaska’s coast, and is instrumental in making Alaska the most voluminous and valuable fishing region in the nation. All fish landed at an Alaska port owe some kind of tax, even if caught in federal waters. The fishery resource landing tax retroactively tallies federal fishermen’s haul before it was processed and taxes the unprocessed value, using unprocessed volume and the price at which it sold from fisherman to processor, or ex-vessel price. Flatfish are caught in bulk by bottom trawlers, mainly by what’s known as the Amendment 80 fleet based in Seattle (the name derives from the amendment to the Bering Sea Aleutian Islands fishery management plan that rationalized the bottom trawl fleet by assigning harvest quotas). These trawlers are catcher-processors; they process flatfish right on the boat. Catcher-processor flatfish don’t make the handoff from fisherman to shoreside processor, so the only ex-vessel price is when harvest actually crosses the dock. Flatfish only make a shoreside sale as bycatch. Trawlers offload loads of pollock or cod and happen to have some yellowfin sole or Atka mackerel in the net. Pollock or cod processors can’t do anything with it besides grind it up for fishmeal, and so they only pay fishmeal prices of just pennies per pound. Commercial fishermen fill out Commercial Operator’s Annual Reports, or COAR reports, that detail who sold what, and at which price and volume. According to COAR reports, processors paid an average of two cents per pound for yellowfin sole in 2014, and only a penny per pound in 2013. Atka mackerel must have had more shoreside action to raise its price from fishmeal, but still came in very low at 10 cents per pound in 2014 and two cents per pound in 2013. At this price, even flatfish caught by the hundreds of thousands of metric tons, doesn’t add up to much in the state coffers. The tax Alaska fisheries management aims to safeguard coastal communities, and its taxes do too. “I think (the Commercial Fisheries Division of ADFG) is really concerned about a lot of money leaving the state,” said Kim. The state enacted the tax in 1993 to be effective the next year. Immediately, the American Factory Trawler Association challenged the tax as unconstitutional. It withdrew the challenge in 1997, and the state declared it constitutional anyway for good measure. The list of allowable tax credits is coastal Alaska’s wish list; donations for vocational schools and two or four-year colleges, annual intercollegiate sports tournaments, Alaska Native cultural or heritage programs, and in 2011 a very specific allowance for a “facility in the state that qualifies as a coastal ecosystem learning center under the Coastal American Partnership.” The state splits the income 50-50 with the municipality and borough where the landings occurred. If landed outside a municipality, the Alaska Department of Commerce, Community and Economic Development doles out half the taxes through an allocation program. Iverson reviewed ex-vessel prices for the past five years and made a range of estimates for how short the state had taxed. He arrived at over $10 million, between $1.8 and $2.5 million per year. Iverson hasn’t yet gone back another 15 years, and isn’t sure the records are around to do so. With a $3 billion-dollar deficit, $10 million or even a potential $40 million of forgone revenue might seem like short change, but it makes a large percentage of the narrow-based fishery resource landings tax. After credits cut over a million dollar from the total, 2013 and 2014 collected $13.4 and $12.6 million. The uncollected amount is between 13 percent and 20 percent of the total tax. But it’s trying The Department of Revenue knows it needs a more complete tax rate, but getting one is laborious. Kim and Iverson, and their respective departments, are working together to come up with a better metric for flatfish. The priority, she said, is making sure people know the rate’s origin. “It’s not as simple as just taking whatever the highest (listed ex-vessel) price is,” said Kim. “If we do something outside what we’ve normally done, we need to plainly explain why we chose a certain price.” Groundfish industry simply wants “a seat at the table” when coming up with a new formula. Swanson said the industry is waiting to provide what information the state needs. She said she doesn’t know how ADFG derives COAR ex-vessel prices, and wouldn’t know how to make a shoreside equivalent in the absence of reliable ex-vessel data. “There’s just no good way of making a comparable value to shoreside sales,” Swanson said. “I’m sure economists have a way of addressing this, but I’m not an economist.” The state might normally fill in spotty information with federal research, but in this case the feds are no better off. Federal reports from the National Marine Fisheries Service have had equal trouble nailing down an ex-vessel price for flatfish species, according to Iverson. “The federal government has struggled with the same problem when it tries to estimate the value of those fish,” said Iverson. “For groundfish, they produce an economic (Stock Assessment and Fisheries Evaluation report), and they gather as much economic information as they can. When they boil it down to the ex-vessel value, they’ve struggled.” The department could link the value to something other than ex-vessel price, but would have to make regulatory changes to do so. Swanson said linking the fishery value to wholesale price wouldn’t work, either. Between federal reports and COAR reports, ADFG and the Department of Revenue have to find a more realistic price. In Kim’s eyes, the complexities of fisheries management makes some proposals seem “convoluted,” but Iverson said he’s trying to loop enough extra data into the formula to compensate for COAR ex-vessel prices. “I proposed giving them not only the COAR, but in addition getting them data from fish tickets, and from the COAR production side,” said Iverson. “I’ll give them data from fish tickets as well. You’d be able to put those numbers side by side and see how much the value was.” Iverson also said taxes could be derived from processed value, perhaps, or calculated under any one of hundred different ways. With any luck, Iverson hopes 2016 could see a more complete tax plan for trawlers. “The governor’s budget is coming out soon,” Iverson said. “We’re shooting for that to come up with something.” DJ Summers can be reached at [email protected]

Board of Fisheries rejects permit stacking for Bristol Bay

One permit, one person will still be the norm for Bristol Bay. The Alaska Board of Fisheries voted against a fistful of proposals that would have allowed a single person to hold multiple Bristol Bay permits. Taking care of the coastal communities, the board said, trumps the business sense of reinvestment and increased efficiency. “There’ll be fewer people able to participate,” said board member Fritz Johnson, a Dillingham resident and commercial fisherman in Bristol Bay. “It’s a rational business decision, but I think the board needs to take a view of this...based on what’s best for coastal communities and what’s best for the resource.” Half a dozen proposals submitted by the public offered variations of permit stacking options for driftnet and setnet operations, under which fishermen could hold and fish two permits under the same name and/or the same vessel in the case of drift permits. The board voted unanimously against each. Bristol Bay fishermen in attendance were evenly divided on permit stacking, which the board allowed in the area in 2009 but with a sunset clause for 2012. Opponents said permit stacking would consolidate the fishery into fewer hands, echoing concerns over crab fishery rationalization a decade prior. Bristol Bay set and drift net permits cost $38,600 and $150,500 in June 2015, respectively. Those without the capital to buy a second permit will be pushed out of the fishery by bigger bankrolls. Permit values would rise, opponents said. “This is just going to make the rich richer and the poor poorer,” said Robin Samuelson, Dillingham resident and former chief executive officer of the Bristol Bay Economic Development Corp., or BBEDC. According to Commercial Fisheries Entry Commission data, the value of a Bristol Bay driftnet permit dropped from an average $89,800 in 2008 to $78,300 in 2009. Between 2009-2012, the value peaked at $160,600 in August 2011. This price was matched or exceeded in the winter months of 2014 up until May 2015, with a high of $169,900 in March 2015. For a Bristol Bay setnet permit, the price peaked in dual permit allowance years at $42,500 in September 2012. The next highest price afterward was $41,800 in April 2015. Fishing is the Bristol Bay watershed’s primary source of employment, but many Bristol Bay permits are owned by Alaskans from other areas or Outsiders who come into the Bay only to fish in summer. Norm Van Vactor, who replaced Samuelson as BBEDC CEO in 2012, said permit stacking would drain permits away from his organization’s 30 villages, 17 of which filed similarly worded letters of opposition to permit stacking proposals. “One of the single largest issues we have is the continued loss of permits by watershed residents,” said Van Vactor. “Permit stacking was an experiment that exacerbated this issue.” Proponents viewed the practice as a wise investment for savvy fishermen, and a necessary one. Bristol Bay fishermen received half their usual price per pound in 2015, a market situation that will be slow to change due to a complicated array of international and domestic factors. Fishing several permits’ worth of sockeye could cut into the losses. “We’re all looking at an economic crisis,” said Abe Williams, president of the Bristol Bay Regional Seafood Development Association. “We have a condition of market that is going to require us to do some innovative thinking. Let’s cut through the rhetoric of the haves and the have-nots, of the rich getting richer and the poor getting poorer. That’s nothing but emotional rhetoric.” In the end, the board agreed with Samuelson and Van Vactor. Members recalled consolidating the crab fishery when it was first put on a quota system, and feared a similar result in Bristol Bay. Permit stacking doesn’t “align with original legislation” that emphasizes equal access to resources for Alaskans. Members said they agree that permit stacking is indeed a wise business practice, but in the board’s eyes its main concern is protecting communities. “I understand the business aspect,” said member Reed Morisky. “It would make some businesses more viable. But it would also make other businesses more marginal.” “I do think permit stacking is not a tool we should use at this time. With this particular proposal, it allows the 977 permits to be in the hands of 488 people,” said member Sue Jeffrey. “ Our job is to allow fair access to all people, not just in the watershed. Reducing the number of permits by half is not good public policy.” Currently, dual permit use is allowed in Upper Cook Inlet. Driftnetters may have two permits fished by their respective users from the same vessel and setnetters are allowed to hold two permits. At the 2014 Upper Cook Inlet Board of Fisheries meeting, Tom Kluberton, now the board’s chair, said the board has no business going back and forth on fishing regulations from year to year. “I think it’s just wrong for this board to tumble these business plans over every three years,” he said. “We walk in, we put a regulation in place, come back three years later and tip it upside down…I just find that I can’t buy into that. I can’t put an individual, a family, any group through that much instability in their business for some benefit that’s perceived by some.”

Interior gas project finalists narrowed to two

Interior residents will have to wait a little longer to hear who their new supplier of natural gas will be, but the Alaska Industrial Development and Export Authority has narrowed its project partner options to two: Spectrum LNG and Salix Inc. AIDEA Interior Energy Project manager Bob Shefchik said during the authority’s Dec. 3 board meeting — when a private Interior Energy Project partner recommendation was expected — that pushing the decision back about six weeks to late January would allow the project evaluation team to more thoroughly vet the best and final offers from Salix and Spectrum. The final offers by five project finalists were submitted in late October and Salix and Spectrum quickly separated themselves from the other proposals, Shefchik said. AIDEA’s project evaluation team then reached a consensus that more time was needed to fully vet the finalists’ cost projections to make sure the best plan is chosen. Specifically, he said the evaluation team will further review commercial and financial terms of the plans Salix and Spectrum have put together, as well as fully cross-examining the capital and operating cost projections that will weigh heavily on the success of the project. “To some extent this is work that would have gone on had even one been selected,” Shefchik said. “We doubled our workload to make sure we’re doing it with two to bring (the AIDEA board) the best project with the best information.” The delay should not have much impact on the timeline of the project. Spectrum has touted an ability to get natural gas to Fairbanks early in 2017, while Salix has said it could be ready for production by January 2018. While the race to supply Interior Alaska with liquefied natural gas is too close to call, the leading companies have plans coming from opposite ends of Alaska. Salix Inc., a subsidiary of the Pacific Northwest utility company Avista Corp., is proposing a Southcentral LNG plant with an initial liquefaction tolling fee of $2.87 per thousand cubic feet, or mcf, of natural gas. Costs for wholesale gas, trucking to Fairbanks, regasification of the LNG and final distribution to customers would still have to be added to the tolling fee. The goal of the Interior Energy Project is to supply Fairbanks residents with natural gas at a final, burner tip price of roughly $15 per mcf, which is the energy equivalent of fuel oil at about $2 per gallon. Salix would finance its Southcentral plant, pegged at $68 million, with a $30 million appropriation from AIDEA, a $28 million low-interest loan from the authority and $10 million of its own equity. Spectrum LNG vied to participate in the first go-round of the project early in 2014, but with a different financing plan for its North Slope LNG plant. This time, the Tulsa, Okla.-based company is proposing a North Slope LNG plant that would produce LNG — wholesale gas cost included — for $5.06 per mcf, leaving a $10 gap available for trucking and distribution costs to still meet project goals. Spectrum CEO Ray Latchem estimated trucking costs from the North Slope at about $5 per mcf during a Nov. 4 town hall meeting in Fairbanks. AIDEA has said regasification of the LNG and distribution to customers should cost between $4 and $5 per mcf. Spectrum would pay for its plant, estimated to cost about $85 million, also through a $30 million grant from AIDEA, a $50 million low-interest loan and a $5 million equity investment. The loans and grants proposed to finance LNG plant construction in each plan would come from the $332.5 million state grant-loan-bond package approved by the Legislature in 2013 for the Interior Energy Project. Shefchik said the expectations for capital costs on the Slope are more positive than the first attempt of the project, which was doomed by high plant construction costs. Wholesale natural gas on the North Slope costs roughly half to one-third of what it does currently from Cook Inlet; however, working on the Slope also includes higher capital, operating and trucking costs, which keep Cook Inlet options competitive. Spectrum leadership helped develop Fairbanks Natural Gas’ LNG supply chain in the late 1990s. The company currently operates a small LNG plant in Arizona that supplies LNG for vehicle use. By going with Salix or Spectrum — LNG plants only — AIDEA steered away from more complex plans by others in the group of five project finalists that wrapped gas supply, liquefaction and delivery to the Interior in an “all-in-one” price. Phoenix Clean Fuels, a consortium of seven companies including Crowley LNG, General Electric Oil and Gas and Alaska utility company TDX Power, had proposed delivering North Slope-sourced LNG to the Interior at $10.60 once the project was up and running for several years. Phoenix Clean Fuels reached its price estimate partially on the back of a trucking cost of $3.86 per mcf, significantly less expensive than other projections to get LNG down the Dalton Highway. Irvine, Calif.-based WesPac Midstream LLC claimed it could deliver Cook Inlet-sourced LNG to Fairbanks for $12.25 in its plan summary released in September. That price, which would strain the project once distribution costs were added, was based on an assumption that feedstock, or wholesale, gas would be about $1.20 per mcf lower than the forecasted market in 2018. WesPac owns the working interest in natural gas from the small Cook Inlet Cosmopolitan field being developed by BlueCrest Energy Inc. and has said it will continue to pursue a Southcentral LNG plant whether it partners with AIDEA on the Interior Energy Project or not. Hilcorp Energy, which owns most of the Cook Inlet gas supply, had proposed three options through its LNG subsidiary Harvest Alaska LLC: an LNG plant, a gas supply and plant and its own bundled, delivered option. Harvests privately financed options forecasted the most expensive LNG prices of all the Interior Energy Project finalists. Elwood Brehmer can be reached at [email protected]

Withdrawal agreement would allow state to buy Slope gas

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

Annual revenue forecast a bleak picture for production take

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

Marijuana board reverses itself on residency

In an emergency meeting, the Marijuana Control Board voted unanimously on Dec. 1 to reinstate a stricter residency requirement for marijuana business licensees, following Permanent Fund Dividend rules instead of voter registration rules. The board also tried to loosen rules to allow more access to Outside money, but public process rules will hold that discussion until the board’s next meeting in February 2016. The regulatory package will now move to Lt. Gov. Byron Mallot for approval pending a review by the Department of Law to make sure the regulations follow statute. “This amendment essentially changes the residency requirements back to what were in the draft regulations,” board chairman Bruce Schulte said. This requirement plus the definitions of financial investment satisfies the demands of some in the local cannabis industry and the board’s legal advisers, who respectively fear “Big Marijuana” investors and federal money laundering charges, but frightens others about their prospects in a small market with limited capital. “I’m very disappointed in the inability to seek Outside investments,” said Tina Smith, chief operations officer for Midnight Greenery. “This is going to severely limit the number of licensees (applications) in February. It’s required that you already have a very significant amount of capital to even submit a license that has a chance of opening.” The adopted regulations require a marijuana licensee to be an Alaska resident by Permanent Fund Dividend definitions. Under these rules, non-Alaskans must maintain a physical presence and Alaska address for a calendar year and not maintain residency in any other state. Because of financial regulations, this effectively bars all transparent Outside financial contributions in the Alaska marijuana industry. According to regulations, no one can hold “direct or indirect” financial stake in an Alaska marijuana business without being listed as a licensee. The board’s action follows a last minute amendment at its Nov. 20 meeting that opened the Alaska cannabis market to more Outside presence than stakeholders were comfortable with, and overburdened the board’s small staff. Alaskans declared it the death knell for small Alaska marijuana businesses, and board members regretted the hasty amendment as too slack. That amendment loosened residency requirements to voter registration standards, which only require an Alaska address and a 30-day wait. Outside investors could theoretically become residents without leaving their current state, and board staff would have to verify that licensees have filled all the requirements. “In an effort to meet some of the suggested changes,” Schulte said, “the board may have inadvertently put staff in a position where they wouldn’t be able to execute the regulations.” After the board returned to PFD rules on Dec. 1, board member Brandon Emmett proposed an amendment that would “expand the pool of investment resources” and allow 12.5 percent Outside financial stake or ownership in Alaska marijuana businesses. However, the board had not requested public comment for this change or announced its presence on the meeting agenda. Assistant Attorney General Harriet Milks said the board could not consider the motion without the proper public input, and Emmett withdrew the motion. “I think the most important action today is to sign this and get it off to the lieutenant governor,” said board member Marc Springer. “We can talk about this in February.” The combination of residency requirements and total investment prohibitions are a step in the wrong direction, according to Outside industry figures, who share the same concerns as Smith. “That’s going to be a real problem,” said Kris Krane, former executive director for the National Organization for the Reform of Marijuana Law. “I’m sympathetic to the idea they don’t want outsiders dominating the state’s industry. But these are really expensive businesses to set up. You’d be hard-pressed to find a medium-scale cultivation operation for less than a million bucks. Some of the bigger ones are three, four million. There’s just not that much money in Alaska. How are you going to fund all that?” In other states, marijuana policy makers have bounced back and forth between different residency requirements, trying to fine tune the balance between locals who want to roadblock out of state competitors while still allowing a path for investment dollars. In Oregon, a bipartisan group of state representatives has publicly opposed the two-year residency requirement and 51 percent Oregon ownership regulation proposed in that state. “Our own thinking on these issues has evolved over time,” wrote a group of legislators to the Oregon Liquor Control Commission, which oversees marijuana regulation. “We now believe that broad residency requirements and significant limits on outside investment could do more harm than good.” Vincent Sliwoski, an attorney with Harris Moure, a Seattle firm specializing in corporate law including regulated substances, said strict residency requirements fail to keep outsiders outside. Well-financed investors find legal loopholes. “All residency requirements do is make people find ways around them, then you get people like me,” said Sliwoski. “They’re basically creating a bunch of hoops to jump though. This sort of trade protectionist policy isn’t helpful.” DJ Summers can be reached at [email protected]

Interior aurora tourism continues to grow in new markets

(Editor's note: This story was updated to reflect an accurate number of Japan Airlines charter flights for this aurora season — from two to three —  after a scheduling change by the airline.)   Don’t say “winter” to Deb Hickok. The Explore Fairbanks CEO is not in denial of the chilling temperatures and dark mornings yet to come. Rather, in the style of any good marketer, she will tell you the Golden Heart City has two seasons: summer and aurora. “The aurora is really the big thing in Fairbanks,” Hickok said. It’s hard to argue with her stance. About a 30-minute drive north of Fairbanks just off the Steese Highway is Aurora Borealis Lodge, one of a select few accommodations in Alaska that is closed during summer. Aurora Borealis Lodge opens Aug. 16 each year and shutters — for the summer — April 12. “Basically, we designed our season around when we have darkness,” lodge co-owner Mok Kumagai said. Kumagai’s foray into aurora-centric tourism began in 2003 as a tour operator out of Fairbanks. That year he was open for two months and served about 100 customers, he said. By 2008, demand had grown enough for Kumagai and his business partner Logan Ricketts to open the lodge, which can host up to 35 guests. “All of a sudden there was an increased demand for places that could hold 30 or so people at a time,” Kumagai said. That roughly coincides with Japan Airlines’ first winter, err, aurora, charter flights direct from the island country. The first three aurora charters from Japan flew in 2004. By 2007, Japan Airlines had dedicated 16 flights to Fairbanks for aurora spotters. The non-summer charters peaked in 2011 with 19 flights. Most charter itineraries include at least five nights in Fairbanks, giving guests a fair shot to find clear skies. Those guests are spending money, too. The average Outside traveler to Alaska spends about $950 once in the state; international travelers shell out more than $1,600; and Japanese travelers eclipse $2,000, according to the state Commerce Department. In recent years, Kumagai has had upwards of 5,000 aurora tour customers in addition to a full lodge most of the season. This aurora season Japan Airlines has only three charters scheduled —a consequence of reorganization within the airline after it filed for bankruptcy — not for lack of demand, Hickok said. Those travelers that would have taken the charter will simply have to find another way to Alaska. Explore Fairbanks lists 15 lodges and tour companies offering customers a chance to see Alaska’s renowned northern lights. Many of those businesses have opened — or decided to stay open in winter — within the last 10 years. In the first few years of the business virtually all of Kumagai’s customers were Japanese. Being a native of Japan himself, he has a theory as to why aurora viewing is such a popular vacation theme amongst his brethren, and it’s not a popular myth about the mystical powers of the aurora. “You may have heard that it brings good luck to conceive a child under the northern lights; that’s completely wrong by the way,” Kumagai clarified. “It’s really a fascination with nature (among Japanese tourists). It’s similar to wanting to go see Old Faithful geyser in Yellowstone or Machu Picchu in Peru — this fascination with the wonders of the world, the aurora being one of them.” Rather than sitcoms or dramas, Kumagai said travel shows were the primetime must-watch television in Japan when he was growing up, which exemplifies the urge to see the world in the country. Ralf Dobrovolny opened 1st Alaska Outdoor School in Fairbanks in 2003. A year-round excursion provider, 1st Alaska offers Denali and Arctic adventures in the summer and mushing and aurora viewing the rest of the year. Once a niche to go along with summer business, Dobrovolny said the aurora season now makes up about 70 percent of his annual business activity. Northern Alaska Tour Co. has offered a suite of Arctic trips for 25 years. Co-owner Matt Atkinson said Northern Alaska began its aurora tours 10 years ago and “the last five to six years it’s just been gaining momentum.” The aurora’s popularity is evidenced by the distinct terms that have been generated to describe it. At Northern Alaska Tour Co. there are aurora viewers, those that are actively taking the northern lights. Aurora watchers are on guard for the slightest light activity and aurora hunters or chasers are those traversing Alaska to find a break in the nighttime clouds. While the Japanese may have been the first on the Alaska aurora bandwagon, they aren’t the only group on it anymore. The first China Airlines aurora charter, direct from Taiwan, was scheduled to land in Fairbanks Dec. 4. It is the first of three charters the carrier has planned to Fairbanks before the end of the year, and they all sold out, Hickok said. Chinese students going to college in the U.S. are a subsection of the aurora visitor market Atkinson said has caught him by surprise over the last couple years. “These kids are wired; they’re going on Weibo, which is basically Chinese Twitter. Then there’s Trip Advisor and these things so they’re very connected,” Atkinson said. That technological connectivity will hopefully help cultivate the concept aurora viewing in Alaska across China through good old word of mouth, he hopes. Dobrovolny agrees. “I am convinced that in the next few years we will see a huge impact on our winter business — on winter tourism — from the Chinese market,” Dobrovolny said. The European market is also starting to catch on, Dobrovolny added. He just better not let Hickok hear him using the “W” word.

IPHC staff presents 2016 halibut harvest recommendations

The International Pacific Halibut Commission’s scientific staff released its recommendations for the 2016 harvest Dec. 1, including the first natural bump the Central Bering Sea, or Area 4CDE, has seen in 10 years, as well as an overall increase from recent recommendations. The international commission sets the direct commercial halibut removals in U.S. and Canadian waters of the Pacific Ocean, incorporating the allocations for sport removals and halibut bycatch that are set by the North Pacific Fishery Management Council. The commission will decide on the final allocations at its meeting in January 2016. The suggested harvest limit, or blue line, for 2016 is 26.56 million pounds, 20.32 million of which are reserved for Alaska waters. This is 9 percent lower than the adopted harvest limit in 2015, but higher than the blue lines from 2014 and 2015 at 25.22 million pounds and 24.45 million pounds, respectively. Most regulatory areas have an increased blue line harvest limit from both the 2015 blue line harvest limit. Three areas have a blue line limit greater than the actual 2015 allocation. One notable exception is Area 3A, or the Central Gulf of Alaska, which has the largest amount of removals from directed catch, sport harvest and bycatch. The blue line recommendation for 3A in 2016 is 9.37 million pounds compared to 10.1 million pounds in 2015. IPHC scientists recommend the “blue line” harvest quotas at the interim meeting each year; the six commissioners (three each from the U.S. and Canada) then vote at the annual meeting each January to choose the limits. The IPHC can choose to set the quotas greater or less than the blue line recommendation. Last year, the British Columbia coast had a blue line recommendation of 5.22 million pounds, but the IPHC ultimately adopted a harvest limit of 7.06 million pounds for the area. Overall, the IPHC chose a total commercial harvest of 29.2 million pounds in 2015 compared to the blue line recommendation of 26.5 million pounds. Area 4CDE is seeing an increase in 2016, with a blue line harvest level of 1.44 million pounds. The increase should be cause for some relief in the Central Bering Sea, where declining halibut allocations have taken their toll on the fishery-dependent Pribilof Island economies. The blue line in 2015 was just more than a half-million pounds, or a 60 percent cut from 1.285 million pounds in 2014, and a 73 percent cut from 1.93 million pounds in 2013. Only an emergency order from U.S. Department of Commerce officials got the adopted harvest in 2015 up to 1.285 million pounds, which fishermen say is the bare minimum they need to sustain their livelihood. Halibut quotas shrank considerably from 2004-2014 until stabilizing in the last two seasons. In 2004, the coastwide Pacific halibut catch limit was 76.5 million pounds. By 2014, that had been cut 64 percent to 27.5 million pounds. On Jan. 30, 2015, the commission set the quotas for commercial and charter halibut industries at 29.2 million pounds total coastwide catch, 22 million pounds of which went to Alaska waters. The following are the blue line harvest limits compared to last year’s: • Area 2A (Northern California to Washington): 1.02 million pounds, up from 750,000 in 2015. The adopted allocation was set at • Area 2B (British Columbia): 5.22 million pounds, up from 4.96 million pounds in 2015. • Area 2C (Southeast Alaska): 4.63 million pounds, up from 4.30 million pounds in 2015. • Area 3A (Central Gulf of Alaska): 9.37 million pounds, down from 10.1 million pounds in 2014. • Area 3B (Western Gulf of Alaska): 2.67 million pounds, up from 2.46 million pounds in 2015. • Area 4A (Alaska Peninsula): 1.3 million pounds, down from 1.39 million pounds in 2015. • Area 4B (Aleutian Islands): 910,000 pounds, up from 730,000 in 2015. • Area 4CDE (Bering Sea); 1.44 million pounds, up from 520,000 in 2015. DJ Summers can be reached at [email protected]

Citing new projects, explorers urge preservation of tax credits

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

Alaska, British Columbia sign transboundary MOU

Gov. Bill Walker and British Columbia Premier Christy Clark signed a Memorandum of Understanding Nov. 25 committing to cooperation on transboundary issues, particularly related to concerns in Southeast over mines on the Canadian side of the border. The MOU will create a Bilateral Working Group on the Protection of Transboundary Waters that will facilitate the exchange of best practices, marine safety, workforce development, transportation links and joint visitor industry promotion. It will also explore other areas for cooperation such as natural resource development, fisheries, trade and investment and climate change adaptation. The neighboring U.S. state and Canadian province will work together on water quality monitoring, scientific information exchanges, resource sharing and facilitating access to information and soliciting input from First Nations, Alaska Native Tribes, and other stakeholders. Lt. Gov. Byron Mallott will lead the Alaska side of the working group and the Minister of Environment and Minister of Energy and Mines will lead the BC side. “As our next door neighbor, Canada plays a significant role in many Alaska industries, including trade, transportation, and tourism,” Walker said. “This MOU underscores that connection, and I thank British Columbia Premier Clark for her support and cooperation in advancing this important relationship “As we work to improve our state’s economy, it is important that we actively reach out and foster good relationships with our trading partners and neighbors with whom we share so much in common.” In an interview with the Journal, British Columbia Minister of Energy and Mines Bill Bennett said the MOU signifies a “change in how we do business” between Alaska and BC. “How we were doing business was the state and province cooperated on mine approvals and permitting that takes place in British Columbia that has potential to impact Alaska,” he said. “But there wasn’t very much public awareness of that relationship and it was incredibly difficult for Tribes and conservation groups and fishing groups to get information on our processes. “We realized that was a shortcoming of our approach and Alaska realized they needed to communicate more with Alaskans on the opportunities the state has to be involved in our process. It’s a matter of opening our doors to acquiring information and making it easier. We’re adding to the opportunities for them to be involved. “This is sealing the deal by having the two leaders sign a deal that says ‘we’re going to do a better job on issues between the jurisdictions.’” There was initially some confusion among the Southeast stakeholders who have been pushing for action on transboundary issues. They had been presented the draft of a statement of cooperation on Nov. 16 by Mallott and told they had two weeks to provide comments to the state. After the announcement, Salmon Beyond Borders, a coalition of Southeast stakeholders representing Tribes, fishing and conservation groups, released statements blasting the timing of the signing and the nonbinding nature of the agreement. A spokesperson from the governor’s office clarified to the Journal that the MOU signed Nov. 25 was not the one presented to the stakeholders for comment Nov. 16, and that the comment period has been extended to Dec. 11. The MOU signed Wednesday is the “umbrella agreement,” Bennett said, which creates the working group that will facilitate the access and cooperation between the two jurisdictions. Southeast stakeholders have repeatedly called for the involvement of the International Joint Commission, which regulates disputes under the Boundary Waters Treaty of 1909. “Since day one, the fishing industry has called on the state and Congress to secure legally binding agreements between the U.S. and Canada with substantial habitat protection and mitigation requirements to ensure the state’s interests are protected,” said Dale Kelley, Executive Director of the Alaska Trollers Association, in the Salmon Beyond Borders press release. “Alaska has instead signed non-binding agreements with British Columbia that offer no visible means of holding Canada, or the mining companies, accountable for mitigating our losses should accidents like the one at Mt. Polley occur in the region.” Kelley was referring to the Mount Polley mine tailings disaster on Aug. 4, 2014, that spilled millions of gallons of mine waste into the Cariboo region of British Columbia, polluting several lakes and watersheds. Concerns over mine waste polluting Alaska watersheds have been elevated by several proposed cross-border mines, particularly the proposed KSM mine near the Unuk River watershed that will also require a large tailings dam structure; there is also ongoing acid rock drainage flowing into a tributary of the Taku River from the abandoned Talsequah Chief Mine. R. Brent Murphy, vice president of environmental affairs for Seabridge, the owners of the proposed KSM mine, wrote in an emailed statement that, “Seabridge wants to clarify that our proposed TMF (tailings mine facility) associated with the KSM Project is not situated in the Unuk watershed or a watershed that drains into Alaska, contrary to the assertions of those who are the most vocal with regards to transboundary development. Our TMF will be situated within the Nass watershed, a watershed that drains entirely into Canadian waters.” Murphy also wrote that naturally occurring acid rock drainage is currently occurring in a Unuk tributary. “We also want to highlight that the water quality within the Unuk River is currently being impacted by naturally occurring acid rock drainage originating from the exposure of the Mitchell Deposit within the head waters of Mitchell Creek (which is a tributary of the Unuk River),” he wrote. “This naturally occurring acid rock drainage results in naturally elevated concentrations of many metals within the river, including copper, iron and zinc. These elevated concentrations have been identified during our extensive baseline sampling of the Upper Unuk River and associated watersheds, which has been ongoing since 2008.” After Bennett visited the Talsequah site in August, government agencies issued a letter to the owners of the mine Nov. 10 that they have 90 days to come up with a plan to stop the acid rock drainage. Although the drainage has been ongoing for years, tests by several government agencies have found that fish in the Tulsequah River are not being affected by the discharge. Regarding the Tulsequah mine, Bennett said the company has told the province it will have a plan to improve the site but that it will stop short of reopening the water treatment plant because the small exploration company doesn’t have the financing. “We think we have some opportunities here to have the company improve the site,” he said. “The best thing would be to develop the site, create cash flow for the company that can open the treatment plant, operate the mine, then close the site, remediate the site, and stop the leaching. That would all be paid for by company as opposed to the public. “That’s what BC has been trying to see happen for 20 years.” He said the fact no harmful effects have been measured by agencies on either side of the border affects how the province is approaching the mine, but that could change if damage was being done. “If the scientists in Alaska and British Columbia were saying that the drainage was harming the water, harming the fish, we’d obviously have a different reaction,” he said. “I think we should do more study, more monitoring, to make sure about the impacts. “If it was determined that there is a negative impact, I think BC would have to take more dramatic action and we’d be responsible for that site. The government would probably have to take it over. I don’t see it happening any time soon, but I acknowledge that it’s a possibility in the future.” Bennett also said there is a “fundamental misunderstanding” of what role the International Joint Commission, or IJC, could play on Alaska-BC transboundary issues. As sub-national jurisdictions, Alaska and BC cannot sign legally binding documents, and the IJC could only get involved if both the U.S. and Canada agreed to it, and if there was a complete breakdown in communications between the nations. He noted that there is a “tremendous amount of pressure on both jurisdictions” related to preserving watersheds from mining impacts and the signing of the MOU is a strong public commitment to working together. “It’s there for the world to see,” he said. “It’s shortsighted to say it won’t impact BC or Alaska.” Andrew Jensen can be reached at [email protected]

North Pacific council to talk halibut rules, groundfish quotas

The North Pacific Fishery Management Council will meet in Anchorage Dec. 9-15 at the Hilton to hash out sport halibut measures for 2016 in addition to setting groundfish harvest limits. Groundfish — which includes pollock, Pacific cod and flatfish — makes the bulk of the volume pulled from the federal waters off Alaska’s coast. Harvest quotas totaling two million metric tons of those species are set each year in the Bering Sea and Aleutian Islands fisheries. The council also will adopt charter halibut rules for 2016, which can include size, bag and annual limits for sport anglers to keep them within their overall allocation. The bottom trawlers who prosecute the groundfish fisheries will be on the lookout for restrictive total allowable catch, or TAC, having taken some cuts last year and taken bycatch cap reductions earlier in 2015. Halibut avoidance is a high priority for council, and groundfish trawlers take the vast majority of halibut that is bycatch. To start off the meeting, the Amendment 80 cooperatives of bottom trawl catcher-processors will report on what progress they’ve made reducing halibut bycatch on their own. Lori Swanson, assistant executive director of industry group Groundfish Forum, said her fleet has managed to cut its overall bycatch by several hundred tons in 2015 using voluntary measure like intrafleet communication, deck sorting, and halibut excluder devices. Halibut management sorely needs an overhaul, according to policy makers. Clashes between directed halibut fisheries, the groundfish trawlers who use halibut as bycatch, and the younger guided angler industry are spurring the council to review a new halibut management framework that takes a more nuanced and proactive role in the fishery. In summary, the framework tries to identify what data the council needs to best manage halibut, and the best way to get and share it. First and foremost is how to bridge the knowledge gap between the two biggest halibut authorities. The North Pacific council oversees all federal fisheries from three to 200 miles off the coast. It only manages the sport removals and halibut bycatch, mostly concentrated in the groundfish fisheries. The U.S.-Canadian International Pacific Halibut Commission manages the directed halibut fisheries. Unlike the council’s stationary bycatch limits, the commission’s halibut quotas shift with legally harvestable halibut biomass. Directed halibut limits have shrunk along with declining biomass, while bycatch limits largely remained unchanged until reductions for the Gulf of Alaska passed in 2012 and new reductions for the Bering Sea passed earlier this year. As a result, more halibut are taken and wasted as bycatch than by the actual halibut fishery, disenfranchising small boat halibut fishermen in fishery-dependent communities. The council reduced bycatch limits in June, but the cuts were less than the Bering Sea halibut fishermen say they needed. Learning from each other’s methodology will factor heavily into the new framework. Right now, the council’s only formal communication with the commission is a yearly management report. Informal information sharing and collaboration are common, but not required. The proposed framework makes is clear there is no plan to merge the two bodies, but would like to create a system of recommendations from one to another, along with the possibility of regularly scheduled meetings in some kind of joint protocol board. Along with inter-body meetings, stakeholders have requested the council create some kind of advisory system that addresses not only biological issues but also economic and social issues. As fishery-dependent communities in the Bering Sea have little other economic driver besides commercial fishing, they believe more thought should go into allocations than just what is biologically acceptable. Potentially, this could mean a new system where a stakeholder group makes recommendations prior to the regular council process. Even arriving at what is “biologically acceptable” needs revision. The framework says the industry needs a host of new science to better inform both the North Pacific council and the international commission. “I think everybody recognizes the need for better science,” Swanson said. “There’s a lot of conjecture about what the impact of Bering Sea bycatch is, and it drives decisions behind not-so-solid science.” The new framework will identify council priorities, including migration studies of halibut spawned in the Bering Sea, the rate at which discarded bycatch fish die, and the disparity between U.S. and Canadian abundance survey techniques. To get to more concrete numbers, the council will review the efficacy and frequency of tagging studies for Bering Sea halibut, deck sorting mortality rates, observer coverage rates, and environmental impact studies. Among other research priorities, the North Pacific council will review a discussion paper on a possible abundance-based halibut bycatch management scheme similar to the commission’s. Earlier this year the council heard a presentation from Steve Martell, a fisheries biologist working for the commission regarding the possibility, and identified process as a possibility.  Halibut sportfishing captains want restructuring in their fleet as well. As biomass has declined, charter operators have seen their slice of the halibut pie shrink, too. They have no sector-wide method to purchase unused allocation from the commercial fleets who use the fish as bycatch, and are asking for a remedy. The council will hold an initial review of Recreational Quota Entities, which would potentially hold commercial halibut quota share on behalf of guided recreational halibut anglers under a “willing seller and willing buyer” approach. This would allow looser charter restrictions while still staying within halibut allocations. The proposed program would differ from current Guided Angler Fish system in that charter operators could purchase, rather than simply lease, quota from commercial users. The program would also be sector-wide rather than individual; purchased quota would be held in a common pool for all charter vessels to draw from as needed to stay within their allocation. The council will review several different options on how many RQEs to establish and in which areas, what kind of transfers will be allowed, and the broader economic impacts of RQEs on the commercial and charter fleets. Halibut quota isn’t cheap, and the charter industry will have to determine how they purchase the quota in the first place.

Tongass EIS proposes transition to young-growth harvest

The future of timber management in the Tongass National Forest in Southeast Alaska is beginning to take shape. On Nov. 20, the U.S. Forest Service released the first draft of an environmental impact statement, or EIS, needed to amend the Tongass Land and Resource Management Plan with five alternatives for managing the federal forest that dominates the region. At nearly 17 million acres, the Tongass is the nation’s largest national forest and encompasses about 90 percent of Southeast Alaska. An emphasis to shift away from harvest of the forest’s old growth hemlock, spruce and cedar is evident in the Forest Service’s preferred EIS option. Alternative 5 would phase out old-growth timber harvest over 15 years and would not allow any harvest — young- or old-growth — in roadless areas defined by the 2001 Roadless Rule. Old-growth harvest that would be allowed in previously designated areas would be limited to commercial thinning or 10-acre openings, with removal of no more than 35 percent of available timber. A 200-foot “no-cut buffer” from the shoreline inland would be instituted along beach and estuary areas open to harvest. The preferred alternative was a unanimous recommendation from the Tongass Advisory Committee, according to a release from the Tongass office of the Forest Service. The 15-member Tongass Advisory Committee was formed in early 2014 to steer the direction of the latest management plan. It is comprised of three members each from five stakeholder groups: Alaska Native tribes and corporations, conservation organizations, government, the timber industry and other commercial users. In July 2013, U.S. Department of Agriculture Secretary Tom Vilsack issued a memo directing Tongass management to be more ecologically, socially and economically sustainable, while accelerating the transition to predominantly young-growth timber harvest by the region’s remaining timber industry. Other alternatives would allow harvest of any-age timber in inventoried roadless areas that were developed before the Roadless Rule took effect in 2001 and during the period that the Tongass received an exemption from the executive order. Additional options would limit young-growth harvest as well. According to the Forest Service, less than 10 percent of old-growth habitat in the Tongass has been converted to young-growth; however that percentage is much higher for some types of old-growth habitat, such as lowland and large tree areas. The Alaska Forest Association, which represents the state’s timber and sawmill industry, is quick to point out that under the current management plan, for each acre scheduled for future timber harvest there are 24 acres managed for uses other than logging in the Tongass. Timber harvest in the forest has declined by more than 90 percent since enactment of the Roadless Rule in 2001 — prohibiting further development of many National Forest lands. At its peak in the 1980s the timber industry supported nearly 4,000 jobs in Southeast. Today, there are about 300 timber-related jobs in the region, according to the state Labor Department. Emily Ferry, deputy director for the Southeast Alaska Conservation Council said the Forest Service’s preferred alternative steers away from logging in the “salmon strongholds” the organization has sought to protect. “It has been a long-term goal of ours to make sure those salmon strongholds aren’t cut and at first blush (the Forest Service) isn’t planning to log those areas,” Ferry said. She noted at the same time a worry about continuing to harvest old-growth timber, which just perpetuates the classic controversy surrounding the timber industry in the Tongass, Ferry said. Alaska Forest Association Executive Director Owen Graham said current young-growth stands in the Tongass simply aren’t mature enough to be useful to the region’s sawmills designed to cut larger trees. “We always planned to transition (to young-growth harvest) but we wanted to do it so sawmills could start cutting the products they do now out of the larger logs,” Graham said. “By continuing the old-growth harvesting now we would build more acres of young-growth so that once the mills transition into the young-growth they can sustain it.” By allowing young-growth stands to mature another 30 years, the board feet available per acre would double, he said, which would also reduce the footprint made by harvesting a given amount of timber. Most young-growth trees in the Tongass today are suitable only for low-grade construction lumber and the distance from the Lower 48 market puts Alaska mills at a competitive disadvantage, Graham said. The market for exporting raw logs to Asia has grown, but that means the value-added manufacturing opportunity drawn from lumber is lost, a concern shared by Ferry and Graham. “We are not making the most of each board foot when we cut a round log, an unprocessed log, and send it to Asia,” Ferry said. Finding a way to quickly transition to young-growth timber harvest and still maximize the value of the lumber is imperative, she said, because no one in Alaska is benefiting from the current Tongass timber situation. Elwood Brehmer can be reached at [email protected]

Hilcorp looks for cost savings, new reserves

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

Native regional corporations net income rebounded in 2014

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

Fauske resigns as AGDC president

The melodrama that has become the Alaska Gasline Development Corp. continued Nov. 21 with the sudden resignation of president Dan Fauske. Fauske stepped down one day after Gov. Bill Walker removed John Burns and Commerce Commissioner Chris Hladick from the Alaska Gasline Development Corp., or AGDC, board. Burns, who served as board chair, is a former Alaska attorney general. AGDC is the state entity tasked with representing the State of Alaska in the $45 billion-plus Alaska LNG Project — the large North Slope natural gas export effort with BP, ConocoPhillips and ExxonMobil. Walker appointed former Fairbanks North Star Borough Mayor Luke Hopkins and Transportation Commissioner Marc Luiken to replace Burns and Hladick. Fauske tendered his resignation in a letter dated Nov. 20 that was made public just prior to a special AGDC board meeting the morning of Nov. 21. He wrote that he is proud of his time as president of the corporation, but did not expand on specific reasons for his departure. “As an (Alaskan) for many years, I strongly desire that a natural gas pipeline project will come to pass,” Fauske wrote. “In that pursuit, I wish the governor and this board of directors success. I believe that a successful project will benefit Alaskans for many years into the future and will be a source of economic prosperity for the state.” His resignation will officially take effect Jan. 1, however, Fauske indicated he will take accrued personal leave until then. During a press briefing following the board meeting Walker commended Fauske for his work with AGDC in bringing the Alaska LNG Project to its current point and said Fauske offered to help move the project along in any way he could during a conversation the two had Friday. The governor said changes to the state’s gasline team are meant to bring “alignment” to the group. He also said that while he didn’t directly ask for Fauske’s resignation, he expressed his wish to the corporation that a change in leadership be made. “We need a person in that (AGDC president) position that has done many, many pipeline projects,” Walker said. Prior to leading AGDC, Fauske headed the Alaska Housing Finance Corp., or AHFC, for many years. AHFC first worked on the state-led Alaska Stand Alone Pipeline project known as ASAP, a contingency project to get North Slope natural gas to Alaskans if a commercial project with the producers doesn’t materialize. Fauske transitioned to AGDC when it was formed in 2013 to focus on natural gas projects. Fauske said in a recent interview with the Journal that he was displeased with proposed AGDC confidentiality regulations — drafted by the Attorney General’s office and strongly opposed by the producers — because they would make contracts the corporation entered into public and could compromise the state’s bargaining position and ability to work with third party vendors, according to Fauske. The governor also said he met with the leaders of the House and Senate Resources committees earlier in the week to discuss how the administration and the Legislature can work more collaboratively to bring the project along. The coming year will be a big test for the project, as all four parties will need to decide if they want to make significant investments in front-end engineering and design, or FEED, for the project, a multi-year commitment to bring it to a final investment decision. Alaskans will also likely have to decide if they are willing to amend the state Constitution to allow long-term contracts to be signed with the producers. Senate Resources Committee chair Sen. Cathy Giessel, R-Anchorage, said in an interview following Fauske’s announcement his departure is a “significant loss” for the state because of his experience in finance and that she is concerned with the recent loss of experience in positions of leadership for a project crucial to the economic future of Alaska. What, if anything, the shakeup at AGDC means for the direction of the Alaska LNG Project remains to be seen. “Continuity, consistency, stability, predictability, those are the key words these companies (BP, ConocoPhillips and ExxonMobil) look for, not only in tax policy but also in personnel,” from the State of Alaska, Giessel said. She added that Burns provided consistency on the board through its changes and offered “exemplary” service to the state. The AGDC board unanimously approved acting board chair Dave Cruz to also act as corporation president until an interim AGDC president is named. That topic will be addressed at the next board meeting scheduled for Dec. 3. Cruz said in a formal statement that Fauske did an “incredible job” building the state organization from its infancy. “Under (Fauske’s) leadership, Alaska has made more progress on a natural gas pipeline than every before,” Cruz said. “I want to personally thank him for his dedication to this incredibly important project and for his years of service to the State of Alaska. He will be missed.” Since taking office nearly a year ago, Walker has now replaced six of the seven AGDC board positions. In January, he began reshaping the board by removing three members appointed by former Gov. Sean Parnell, citing transparency issues. At the time he ordered the new board members not to sign confidentiality agreements that, prior to the Walker administration, all AGDC board members and employees were required to sign. Cruz, owner of Cruz Construction Inc., an oilfield contracter, is the only board remaining board member to have signed AGDC’s confidentiality agreement. Walker called the resolving the issue of what’s confidential a “fine line” and said he is assessing the concerns of all parties on the issue, but added that Alaskans need to be kept abreast of the agreements the state is entering into if they are going to be asked to change the state’s Constitution. “We don’t want to hinder the project in any way,” the governor said. “We’ll find that line.” As for former AGDC chair Burns, Walker said he holds Burns in the highest regard and removing him from the board does not in any way reflect the relationship the two have. “I don’t think we’ve seen the last of John Burns in this project,” he said. He also noted that Commerce Commissioner Hladick already serves on more than 20 different boards and DOT, the state’s infrastructure agency, will have a large role in the project moving forward. Not to be lost in the buzz surrounding the latest AGDC leadership changes is the fact that the state now officially owns TransCanda Corp.’s share of the Alaska LNG Project. The AGDC board passed a resolution to authorize a $64.6 million payment to TransCanada and accept the company’s share of the midstream portion of the project. That follows the Legislature’s approval of the state’s purchase TransCanada’s 25 percent share of the North Slope gas treatment plant and the 800-mile pipeline in the special session completed earlier this month. Approval of AGDC’s fiscal year 2017 work plan and budget was delayed until the Dec. 3 meeting, apparently at the request of Walker. He said at the briefing it was premature for the state to commit funding work before getting formal commitment from the producers that gas will be made available to the project if one or more of them pulls out. The governor and the producers settled on a Dec. 4 date for withdrawal agreements in late October. Elwood Brehmer can be reached at [email protected]

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