Elwood Brehmer

Mallott rejects salmon habitat ballot initiative

Lt. Gov. Byron Mallott denied an application on Sept. 12 to put a voter initiative on the 2018 statewide ballot that would have tightened the state’s permitting requirements for development projects with the potential to impact salmon streams. Assistant Attorney General Elizabeth Bakalar wrote a Sept. 6 letter to Mallott recommending he not certify the initiative because it would strip the Legislature of its power to allocate resources — in this case salmon habitat — and thus violate the Alaska Constitution. The lieutenant governor’s primary responsibility in Alaska is to manage state elections. The “salmon habitat initiative” pushed by the nonprofit Stand for Salmon, which is chaired by Cook Inlet commercial fisherman Mike Wood, met all but one of the four criteria the Department of Law uses to evaluate ballot initiatives, according to Bakalar. She noted that the Alaska Supreme Court has generally ruled broadly to allow citizen initiatives unless there is no debate the proposal in question is unconstitutional. “An initiative us unobjectionable as long as it grants the Legislature sufficient discretion in executing the initiative’s purpose. But an initiative that controls the use of public assets such that it essentially usurps the Legislature’s resource allocation role runs afoul of Article XI, Section 7 (of the Alaska Constitution),” Bakalar wrote. “17FSH2 (its technical title) clearly limits the Legislature’s ability to decide how to allocate anadromous streams among competing uses. The initiative contains restrictions and directives that would require the commissioner to reject permits for resource development or public projects in favor of fish habitat.” Specifically, it would have overhauled Title 16, the state’s permitting law for salmon streams, by establishing two tiers of development permits that could be issued by the Department of Fish and Game commissioner. “Minor” habitat permits could be issued quickly and generally for projects deemed to have an insignificant impact on salmon waters. “Major” permits for larger projects such as mines, dams and anything determined to potentially have a significant impact on salmon-bearing waters would require the project sponsor to prove the project would not damage salmon habitat. Additionally, the project sponsor would have to prove that impacted waters are not salmon habitat during any stage of the fish life cycle if the waters are connected to proven salmon habitat in any way but not yet listed in the state’s Anadromous Waters Catalog. Currently, Title 16 directs the Fish and Game commissioner to issue a development permit as long as a project provides “proper protection of fish and game.” The initiative sponsors contend that is far too vague and an update is needed to just define what “proper protection” means. The Department of Law deemed an earlier iteration of the initiative as a means to allocate resources and prohibit projects such as the Pebble and Chuitna mines and Susitna-Watana dam, which the initiative sponsors have opposed. Stand for Salmon wrote in a formal statement that Gov. Bill Walker’s administration has chosen to “play politics” and defer to the short-term gains of Outside mining companies instead of supporting the fish Alaskans depend on. “The decision to deny us our constitutional right as Alaskans to gather signatures and put this issue before voters is stunning, particularly from a governor who once promised to support fish first policies,” the group wrote. “Instead, Governor Walker and Lt. Governor Mallott have done next to nothing to uphold their promises to Alaskans who depend on salmon for jobs, culture, recreation and way of life. “The merits of our application should have been based purely on the law. Yet, the relentless lobbying and pressuring from corporate representatives and lawyers seemed to carry more weight than the integrity of the public process.” Opponents to the initiative have said Title 16 is working as it is and the proof is that Alaska has not had an environmental disaster related to projects under the law’s jurisdiction. Wood, one of the sponsors, said in a previous interview with the Journal that the state has simply been “lucky” that it has avoided such a disaster, noting most of the large mines and other projects in Alaska are well away from salmon rivers. Bakalar wrote in a June 30 letter to the sponsors that a previous version of the initiative would have also allocated resources without the Legislature’s consent. The initiative was then reworded in an attempt pass legal muster, but the revisions apparently didn’t go far enough. “Despite the altered language, we remain concerned that 17FSH2 would, theoretically and/or in practice, categorically prohibit certain mines, dams, roadways, gaslines, and/or pipelines,” Bakalar wrote Sept. 6. “In doing so, the measure would effectively set state waters aside for the specific purpose of protecting anadromous fish and wildlife habitat ‘in such a manner that is executable, mandatory, and reasonably definite with no further legislative action,’ while leaving insufficient discretion to the Legislature or its delegated executives to use that resource in another way.” She also noted the letter should not be viewed as an opinion to whether the initiative is good public policy or not, but is simply a legal opinion on its constitutionality. To that end, the public policy could still be changed via House Bill 199, sponsored by Rep. Louise Stutes, R-Kodiak. The bill largely mirrors the language of the initiative and if passed, would be the Legislature deciding to allocate and prioritize water resources for salmon. Board of Fisheries Chair John Jensen also wrote in a Jan. 19 letter to House and Senate leaders that there is nothing in current state laws or regulations defining what is a proper protection. The Kenai Peninsula Borough Assembly also unanimously passed a resolution about a year ago supporting an update to Title 16 to further protect fish habitat. Wood said HB 199 would be the ideal vehicle for changing Title 16, as it could be amended to include input from development proponents and thus be more agreeable to more Alaskans, but added that the initiative was the group’s way of showing how serious it is about getting the law changed. The sponsors have 30 days to appeal Mallott’s ruling and Stand for Salmon said it is currently evaluating its next move. Elwood Brehmer can be reached at [email protected]

Ballot measure would give greater say to ADFG

Alaska fishing groups concerned about the impacts that large-scale development projects could have on salmon habitat are pushing to reform the state’s permitting requirements through a voter initiative on the 2018 ballot. The initiative would primarily establish a two-tiered permitting structure for projects with the potential to impact salmon-bearing waters. It would give the Department of Fish and Game commissioner the authority to issue broad approval for projects deemed “minor,” but also require proponents of larger projects to prove they would not have a significant adverse impact on salmon habitat. Additionally, it would require project advocates to prove to Fish and Game that the area of the water body the development could damage is not used by salmon sometime in their life cycle if the water is connected to one known to have salmon. The initiative was sponsored by Cook Inlet commercial fisherman Mike Wood, Bristol Bay lodge owner Brian Kraft and Gayla Hoseth of Bristol Bay Native Association. Lt. Gov. Byron Mallott will decide whether to certify the initiative by Sept. 12. In an interview, Wood said it is not intended to stop development projects, but rather to simply update the state’s protections for salmon as the Board of Fisheries requested. Current law directs the Fish and Game commissioner to approve fish habitat permits if a project is deemed to provide “the proper protection for fish and game.” Board of Fisheries Chair John Jensen wrote in a Jan. 19 letter to House and Senate leaders that there is nothing in current state laws or regulations defining what is a proper protection. “Additional guidance is warranted for the protection of fish, to set clear expectations for permit applicants and to reduce uncertainty in predevelopment planning costs,” Jensen wrote. “To strengthen ADF&G’s implementation enforcement of the permitting program, the Legislature may want to consider creating enforceable standards in statute to protect fish habitat, and to guide and create a more certain permitting system.” The Board of Fisheries letter was spurred by public pressure to amend Title 16, the state’s general laws relating to Fish and Game, according to Jensen. To that end, the initiative, which would rewrite state law, is mirrored after House Bill 199 sponsored by Rep. Louise Stutes, R-Kodiak. “We don’t want to stop (development); we want to make sure that the permitting process is rigorous so that we don’t destroy the fish habitat that we need to get the returns that are so important to the Alaska economy,” Wood said. The Alaska Constitution was written with a huge amount of thought toward salmon resources and the effort is to get back to that mindset in the state, he added. “It’s gotten a little blown out of proportion because this won’t stop things; it’s just trying to elevate the level of accountability back to where we believe it began at statehood. Over the years the regulations have been whittled away from administration to administration,” Wood said. Initiative opponents have cited federal laws, such as the Clean Water Act and National Environmental Policy Act that guides the environmental impact statement process as additional adequate salmon habitat protections; meaning an update to Title 16 is unnecessary. “I think there was a time when we thought we could have faith in the feds, the EPA, to have those standards and I think now we’re seeing that we can’t and it’s just part of the state having a greater say in its own outcome to have those high (permitting) standards,” Wood said. Wood characterized Alaska as simply “lucky” it hasn’t seen a large-scale manmade disaster of late similar to the 2014 Mount Polley mine tailings dam failure in British Columbia. He noted many of the state’s largest mines and other developments are in the Interior region or otherwise away from major salmon-bearing watersheds. The Department of Law deemed an earlier iteration of the initiative as a means to allocate resources and prohibit projects such as the Pebble and Chuitna mines and Susitna-Watana dam, which the initiative sponsors have opposed. A June 30 Department of Law letter to the sponsors outlined the provisions in the first draft of the initiative that would not pass legal muster. Assistant Attorney General Elizabeth Bakalar emphasized in an interview that the letter was in large part a response to industry concerns about the initiative that the department heard and is the same type of opinion state attorneys issue on any ballot measure — just earlier. She commented that the department isn’t likely to issue “courtesy” opinions in the future because this one has been incorrectly perceived as the state helping the petitioners. However, it could just as easily be seen as a way to calm development industry concerns by clarifying ahead of time that the initiative would not be ratified. “It’s just a heads up; do with it what you will,” Bakalar said. Wood said small changes were made to the latest version to hopefully meet the Department of Law standards. He acknowledged that the preferable vehicle to address salmon habitat protections would be through HB 199, which could be amended to include input from development proponents, but characterized the ballot proposal as a “belt and suspenders” approach to the issue. The Resource Development Council and other pro-development groups stressed in testimony on HB 199 that reforming the state’s habitat permit requirements is a solution searching for a problem. “The intent to safeguard Alaska’s salmon fisheries is an objective we share and it is why we support Alaska’s existing rigorous and science-based regulatory system,” wrote a coalition including the Alaska Chamber, Southeast Conference and the Anchorage and Fairbanks economic development corporations in an April letter to legislators. “As a coalition that includes urban and rural Alaskans and businesses and associations representing tens of thousands of jobs for our state’s citizens, we cannot overstate how important it is to have consistent regulator and permitting processes.” They continued to contend that HB 199 or the initiative would likely cause delays to smaller community projects like wastewater facility upgrades or airport expansions while worsening the state’s fiscal crisis by slowing or stopping economic development without any true benefits to fish habitat. Alaska Native corporations such as Cook Inlet Region Inc., Calista Corp. and Doyon Ltd. have opposed the measures, while Native tribal organizations such as the Tanana Chiefs Conference and the Native Village of Eklutna support it. The Kenai Peninsula Borough Assembly unanimously approved a resolution in September 2016 supporting an update to Title 16 to further protect fish habitat. A 2014 state ballot measure requiring legislative approval for a large mine in Bristol Bay — which Pebble argues is a blatant violation of the Alaska Constitution — was billed as a way to protect the region’s salmon and passed with 66 percent support among Alaska voters. It was supported by 72 percent of voters in Bristol Bay and greater southwest Alaska, according to Division of Election results. Elwood Brehmer can be reached at [email protected]

Railbelt utilities make progress to pool resources

Leaders of Alaska’s largest electric utilities hope to have a green light from state regulators to form new infrastructure management companies in a little more than a year. A collection of officials from the six Railbelt region utilities told the Regulatory Commission of Alaska at a late August meeting that they are collectively working toward internally approving the joint formation of a transmission company, or transco, by the end of the year. That would allow the utilities to submit the plan to the RCA early in 2018 and possibly have it approved by the end of next year. Proponents of the new jointly owned company believe pooling transmission lines and the resources is the best way to spread the costs of large infrastructure projects and assure the benefits from them reach as many of the region’s residents as possible. The RCA strongly ordered the utilities to investigate forming a transco in 2015, stating the cooperatives had not collaborated enough to maximize efficiencies and economies of scale in delivering power to their ratepayers. Covering an area from Fairbanks to Homer — home to about 80 percent of Alaskans — managers at some of the utilities had previously been hesitant about forming a transco, as it means giving up control of the utility-owned transmission lines that can provide revenue from wheeling tariffs. They generally acknowledge a transco would be of at least some benefit, but also emphasize their cooperatives’ bylaws require them to do what’s best for their ratepayers and investing in a transco could mean spending on projects that provide the greatest aid to others. The transco would be a partnership between the utilities and Wisconsin-based American Transmission Co., a transco formed after its state’s Legislature passed a law mandating Wisconsin utilities to do so. American Transmission Co. has pitched its experience in operating a transco to the Alaska utilities and the positives of forming one in Alaska, where long lengths of expensive transmission lines are needed to serve relatively small populations. The Alaska Energy Authority just finalized a study that says more than $880 million of substations, new lines, and other improvements are needed to optimize Railbelt electric generation and distribution. The utilities have consistently downplayed the need for such large-scale spending, contending a less expensive, more targeted investments would give the greatest benefits for money spent. ATC Business Development Manager Eric Myers told the RCA that his company knows it must earn a right to participate in the Alaska transco. “(In Wisconsin) every company was doing what was best within his or her jurisdiction to meet its customers’ needs. But the interconnections were a little weak, and economics and reliability suffered as a result.” Myers said. Fairbanks-area Golden Valley Electric Association CEO Cory Borgeson and Matanuska Electric Association General Manager Tony Izzo both said the utilities need to form an independent system operator, or ISO, as well to similarly manage power transactions between utilities down to a minute-by-minute basis. MEA, Anchorage Municipal Light and Power and Chugach Electric Association entered into their own ISO-like power pooling agreement in January. They estimate pooling their generation resources to maximize efficiencies could save their ratepayers between $12 million and $16 million per year. Much of the savings comes in the form of less fuel, which in Southcentral Alaska means less burning of natural gas. Chris Rose the executive director of the Anchorage nonprofit Renewable Energy Alaska Project, also testified to the RCA that an ISO is as much of a necessity as a transco is. “We do not want to find ourselves in a situation where a transco is formed, the parties declare victory, and the momentum to do anything further dies out. New transmission assets may increase the ability of the Railbelt to economically dispatch electrons and add more nonfuel renewable energy to the grid,” Rose said. The utilities’ leaders said a governance model assuring maximum local control of the transco is a priority and remains something the utilities must finish. They also have to finalize the operating agreements and methods for allocating transmission costs before taking the plans to their boards for approval. The RCA has scheduled a meeting Sep. 27 for further updates on the progress of the utilities’ work. Elwood Brehmer can be reached at [email protected]

State rejects Point Thomson expansion plan

The Alaska Division of Oil and Gas has denied ExxonMobil’s plan to expand the Point Thomson North Slope gas project because it doesn’t live up to a prior settlement between the state and the company, according to Director Chantal Walsh. In a detailed six-page letter dated Aug. 29, Walsh wrote to ExxonMobil Alaska Vice President Cory Quarles that the Point Thomson Expansion Project Planning Plan of Development, or POD, is far too vague and offers no commitment that the company will live up to the 2012 Point Thomson Settlement Agreement. Separate from but related to the Expansion Project POD, the division parsed out and approved the Initial Production System POD despite the company not meeting production expectations of natural gas condensates at Point Thomson because of technical challenges. ExxonMobil submitted a single Point Thomson POD to the state on June 30, but division officials determined it contained two PODs because the 2012 settlement does not spell out what the company must do with its current infrastructure at the large eastern Slope gas field after this year. The settlement does, however, direct the company to start expanding production at Point Thomson by 2019 under one of several scenarios. PODs are submitted annually by the unit operator company for every oil and gas unit in the state. They detail the company’s work plan for the coming year. The plans are generally adhered to but not strictly enforced by the state if unforeseen factors, such as changes to a project’s economics from external market forces or technical challenges, arise, Walsh noted. But in the unique case of Point Thomson, development is prescribed by the settlement, which the Division of Oil and Gas considers to be a contract with the state, meaning its terms must be upheld regardless of extenuating circumstances, according to Walsh. The Point Thomson Settlement, reached under former Gov. Sean Parnell, ended years of litigation between the state and the company in which the state argued ExxonMobil had not fulfilled its responsibility to develop the leases it held for many years. It also set a course for ExxonMobil to develop Point Thomson and start production by May 2016. The field was discovered in 1977. ExxonMobil, which operates Point Thomson, and BP, its primary working interest owner partner, spent roughly $4 billion developing the gas field since 2012. Production started in late April 2016. Gov. Bill Walker, who’d lost to Parnell in the Republican primary in the 2010 governor’s race, promptly sued the state over the settlement in 2012 on the grounds that the settlement over state assets was reached in private negotiations and was not in the best interest of Alaska residents. He withdrew his appeal to the Alaska Supreme Court in February 2015 shortly after taking office. Last year Walker’s administration deemed the Prudhoe Bay Unit POD incomplete until BP, as unit operator, and the state reached an agreement that the company would provide more information on its efforts to further the Alaska LNG Project in future PODs. ExxonMobil outlined its plans to move gas from Point Thomson and inject it into the Prudhoe Bay oil and gas pool as a way to further enhance oil recovery from the large oil field. The reinjection of gas produced during oil production efforts at Prudhoe has been a primary driver behind BP’s ability to extract more than 30 percent more oil — currently about 12.5 billion barrels in total — from the massive field than was expected when it came into production 40 years ago. Production facilities at Point Thomson would first be expanded to handle production of more than 50,000 barrels per day of the diesel-like condensates and 920 million cubic feet per day of gas. The current Point Thomson facilities have a production capacity of about 10,000 barrels of condensates and 200 million cubic feet of gas per day. Moving gas to Prudhoe is one of the options for expanding Point Thomson under the settlement in the event major gas sales — the Alaska LNG Project — was not sanctioned by mid-2016. While the Alaska Gasline Development Corp. continues to advance the gasline project, it is still uncertain if it will be built. With an estimated 8 trillion cubic feet of natural gas, Point Thomson holds about a quarter of the gas needed to feed a large gasline; the rest is in the Prudhoe Bay pool. Point Thomson is one of the highest pressure producing gas fields on Earth, at about 10,000 pounds per square-inch. A positive of the reservoir pressure is that it makes separating the condensates, or natural gas liquids, from the gas much easier. According to ExxonMobil officials, the liquids essentially “fall out” of the gas once the pressure is relieved. Those liquids are then fed into the Trans-Alaska Pipeline System. The natural gas has so far been reinjected into the Point Thomson reservoir. Getting the gas from Point Thomson to Prudhoe would require construction of a 62.5-mile, 32-inch diameter gas pipeline between the fields and production would be ramped up with the drilling of three new wells, according to the plan of development. The two wells now used for gas injection would also be converted to production. Specifically, Walsh points to the wording the company used in its Expansion POD to justify her ruling. The POD states that before expansion planning can proceed, the working interest owner companies at Point Thomson and Prudhoe must sign a commercial agreement and fund the work, and according to Walsh, ExxonMobil confirmed that in a technical meeting with division officials. Company representatives said further that it had “not even approached the Prudhoe working interest owners to begin these discussion, but surmised that the Prudhoe working interest owners were aware of the need for an agreement,” Walsh recalled in her letter. She noted that BP, ExxonMobil and ConocoPhillips collectively own 99 percent of both fields — Chevron holds 1.6 percent of Prudhoe — and therefore Exxon was, in part, waiting to negotiate with itself. ExxonMobil corporate spokesman Aaron Stryk wrote in an email that, “We have been, and continue to be, in full compliance with the Point Thomson Settlement Agreement. We are aware of the letter from the Department of Natural Resources, but have not yet reviewed the letter, so we are unable to comment.” Walsh further emphasized that the need for a commercial agreement is not part of the settlement and the lack of one should not prevent Exxon from continuing expansion planning. “The POD conditions all FEED (front-end engineering and design) work — the work that the Settlement Agreement requires the Point Thomson Unit WIOs to conduct during this POD period — on whether the WIOs decide to fund the work. Exxon prefaces its discussion of FEED by stating, ‘if funded FEED would progress…’ and then proceeds to refer to activities it ‘would’ do, rather than activities it will do,” Walsh wrote. “The division questioned Exxon about this language to determine if it was intentional or merely inartful wording. Exxon confirmed at the technical meeting that the WIOs did not intend to proceed with any Expansion Project Planning work unless they both decide to fund the work and enter a commercial agreement for Prudhoe Bay Unit injection. Again, the division understands the importance of the commercial agreement, but it is not an impediment to complying with the Settlement Agreement.” She continued: “This proposed POD would allow the WIOs to decide that they would rather not pay for planning, and then Exxon would perform no work. This proposed POD would also allow the WIOs to not enter an agreement with themselves for Prudhoe Bay Unit injection, and then Exxon would perform no work.” Walsh additionally contended that the plan does not comply with the settlement because it is far too vague to be an adequate POD. The Settlement Agreement requires the plan to include the number of wells, their locations and other plans for completion of expansion, while Exxon simply stated it would drill three new wells on the Central Point Thomson pad, without identifying the wells’ targets or completion plans, she wrote. Similarly, it states Exxon expects to file for permits to do the work with little more detail. “Scheduling time to apply for permits is not a plan for acquiring them,” Walsh wrote. She summarized her displeasure with the company by writing that the “POD fails to paint even the most impressionistic picture of what Exxon will do over the next year and a half to engineer and permit an expansion project.” “The proposed Expansion Project Planning POD fails to provide for Exxon to fulfill this contractual obligation. The proposed POD includes conditions that would give the Point Thomson Unit WIOs control to avoid doing any planning work, effectively nullifying this portion of the Settlement Agreement,” Walsh concluded. Appeals to Oil and Gas POD rulings usually go to the Department of Natural Resources Commissioner; however, the Settlement Agreement nullifies the administrative appeal and sends Point Thomson disputes directly to the Alaska Superior Court, according to Walsh. ExxonMobil has until Oct. 13 to submit a revised Point Thomson Expansion POD. Production challenges ExxonMobil met its first big deadline at Point Thomson by starting condensate production and natural gas cycling in April 2016. Since then, however, the company has had difficulty meeting the 10,000 barrels per day of condensates production threshold called for in the 2012 Settlement Agreement with the state. ExxonMobil noted in its proposed Point Thomson POD that production exceeded 10,000 barrels of condensate and 200 million cubic feet of natural gas on Dec. 20, 2016. Yet, Walsh wrote the company has not met its obligation because production levels have fluctuated wildly in the year-plus since the project came online. According to Alaska Oil and Gas Conservation Commission data, Point Thomson produced 47,972 barrels of natural gas condensates in April 2016, but that fell to just 7,903 barrels for the entire month of May. Production was then ramped back up to hit 213,845 barrels in December, to average about 7,000 barrels per day for the month. Production then peaked in January with a daily average of 7,634 barrels, but fell again in June to a total of 8,400 barrels for the month, or just 280 barrels per day. In July, Point Thomson produced an average of 1,738 barrels per day of natural gas condensates. The production fluctuations stem from problems ExxonMobil has had with the gas compressor it uses to reinject the natural gas back into the reservoir, according to Walsh’s letter. “During the technical meeting, Exxon provided additional detail about the compressor and its design flaws and difficulties in relation to this reservoir. By Exxon’s account, it was conducting maintenance or repairs on the compressor during periods when production ceased or decreased,” she wrote. The company also acknowledged a requirement to pursue, but has not identified work, to “debottleneck” the Initial Production System, as it is directed to in the Settlement Agreement, Walsh noted. Finally, ExxonMobil has not advanced permitting for an East Pad and associated wells at Point Thomson — another requirement of the deal — beyond what it had done at the time the settlement was reached, she continued. Walsh wrote that the Oil and Gas Division is “hopeful” the company can resolve the technical issues with the IPS and sustain production at 10,000 barrels per day and the division appreciates its consideration of debottlenecking work. “While the division remains concerned about the future of the IPS, the proposed POD does generally provide for continued production, which is a benefit to the state. Unitized production like this generally conserves resources, minimizes environmental impacts, and prevents waste,” Walsh summarized. “The proposed POD does not create additional impacts to the land. Thus, despite the division’s continued concerns, the division hereby approves the IPS POD for the period Sept. 30, 2017, through December 31, 2019.” Elwood Brehmer can be reached at [email protected]

Coast Guard commandant keeps up push for icebreakers

U.S. Coast Guard Commandant Adm. Paul Zukunft has one very clear message: the country needs more icebreakers. Zukunft reiterated that point time and again during an Aug. 24 speech to members of the Alaska policy nonprofit Commonwealth North in Anchorage. He recalled a conversation he had with then-National Security Advisor Susan Rice when Rice asked him what President Barack Obama should highlight shortly before the president’s extended trip to Alaska in late August 2015. “I said (to Rice) we are an Arctic nation. We have not made the right investments and we do not have the strategic assets to be an Arctic nation and that translates to icebreakers and that’s almost exactly what President Obama said when he came up here,” Zukunft said. “Fast forward — it’s Jan. 20, 2017, and I’m sitting next to President Trump and as they’re parading by he says, ‘So, you got everything you need?’ I said, ‘I don’t. The last administration, they made a statement but they didn’t show me the money. I need icebreakers.’ (Trump said) ‘How many?’ ‘Six.’ ‘You got it.’ “You never miss an opportunity,” Zukunft quipped. It’s well documented in Alaska that the U.S. has “one-and-a-half” operable icebreakers. That is, the heavy icebreaker Polar Star and the medium icebreaker Healy, which are in the Coast Guard’s fleet. A sister ship to the Polar Star, the Polar Sea remains inactive after an engine failure in 2010. Zukunft noted Russia’s current fleet of 41 icebreakers to emphasize how far behind he feels the U.S. is in preparing for increased military and commercial activity in the Arctic as sea ice continues to retreat — a message Alaska’s congressional delegation stresses as well. “We are the only military service that’s truly focused on what’s happening in the Arctic and what happens in the Arctic does not happen in isolation,” Zukunft said. He added that Russia is on track to deliver two more cruise missile-equipped icebreakers in 2020. “I’m not real comfortable with them right on our back step coming through the Bering Strait and operating in this domain when we have nothing to counter it with,” he said. The Coast Guard’s 2017 budget included a $150 million request to fund a new medium icebreaker, which Zukunft characterized as a “down payment” on the vessel expected to cost about $780 million, according to an Aug. 15 Congressional Research Service report on the progress of adding to the country’s icebreaking fleet. For years it was estimated that new heavy icebreakers would cost in the neighborhood of $1 billion each, but those estimates have been revised down as the benefits of lessons learned through construction of the initial vessel and ordering multiple icebreakers from the same shipyard are further examined. The CRS report now estimates the first heavy icebreaker will cost about $980 million to build, but by the fourth that price tag would go down to about $690 million for an average per-vessel cost of about $790 million. That is on par with the cost for a single new medium icebreaker. Zukunft said the Coast Guard is working with five shipyards on an accelerated timeline to get the first icebreaker by 2023, but how it will be fully funded is still unclear. “We have great bipartisan support but who is going to write the check?” he said, adding that aside from Russia and China, the United States’ economy is larger than that of the other 18 nations with icebreakers combined. The Obama administration first proposed a high-level funding plan for new icebreakers in 2013 that has not been advanced outside of small appropriations. “Our GDP (gross domestic product) is at least five times that of Russia and we’re telling ourselves we can’t afford it,” Zukunft continued. “Now this is just an issue of political will and not having the strategic forbearance to say this is an investment that we must have.” He also advocated for the U.S. finally signing onto the United Nations Law of the Sea treaty, which lays out the broad ground rules for what nations control off their coasts and how they interact in international waters. Not signing onto the Law of the Sea, which was opened in 1982, leaves the U.S. little say as other nations further study and potentially exploit the Arctic waters that are opening, he said. “We are in the same club as Yemen; we are in the Star Wars bar of misfits of countries that have not ratified the Law of the Sea convention,” Zukunft said. ^ Elwood Brehmer can be reached at [email protected]

Court rules on PFD veto lawsuit

JUNEAU — The Alaska Supreme Court ruled that Gov. Bill Walker acted within his authority in reducing the amount set aside for checks to state residents from Alaska’s oil-wealth fund last year. The decision, released Aug. 25, affirms a lower court decision that sided with the state in the dispute over Alaska Permanent Fund dividends. The high court decided that the legislature’s use of fund income is subject to normal appropriation and veto processes. It says Walker validly exercised his veto authority when reducing the amount available for dividends last year. The case was brought by Democratic state Sen. Bill Wielechowski and two former legislators. Wielechowski said he is “bitterly disappointed” by the court’s ruling. Walker called it “by far” the most difficult decision he’s made as governor. They had argued that the Alaska Permanent Fund Corp. was required by law to make available nearly $1.4 billion from the fund’s earnings reserve for dividends, despite Walker’s veto. The case was heard before the Supreme Court on June 20. The court determined the “narrow question” it had to answer was whether the constitutional amendment that created the Fund and dedicated 25 percent of all state resource royalties to feed it also exempted the use of the Fund’s income from the anti-dedication clause, according to the ruling. “The answer cannot be found by weighing the merits of the dividend program or by examining the statutory dividend formula,” the justices wrote. Wielechowski’s group argued in part that Walker overstepped his authority by crossing out the reference to the dividend formula statute in the budget in addition to replacing the original estimated $1.36 billion collective dividend payment with $695 million. The Alaska governor has the authority to veto appropriations, but not existing laws. In its discussion of the ruling, the court noted it ruled in a 1982 case that the anti-dedication clause of the Alaska Constitution “prohibits the dedication of any source of revenue” without a constitutional exception. The crafters of the state Constitution believed dedicated funds to be a “fiscal evil,” according to the ruling, because they took control necessary to manage state finances away from the governor and Legislature. “No party suggests that Permanent Fund income (distributed for dividends) is not state revenue,” the ruling states. “Our starting point must therefore be that the anti-dedication clause prohibits the dedication of Permanent Fund income unless the 1976 constitutional amendment exempted not only the dedication of enumerated revenues into the Permanent fund but also — as Wielechowski argues — the Legislature’s potential future, unspecified dedication of revenues out of the Permanent Fund.” Attorney General Jahna Lindemuth thanked the state’s attorneys that argued the case in a Friday Department of Law release. “I know this was not a decision Gov. Walker took lightly, but I’m glad we have more clarity around the use of Permanent Fund earnings as we continue to try and resolve the state’s fiscal crisis,” she said. Walker announced that he roughly halved the dividend appropriation among other vetoes in June 2016 on what he called “a day of reckoning” to drive home his message to legislators and the public that drastic changes to state finances need to be made to resolve Alaska’s ongoing multibillion-dollar budget deficits. This year, the Legislature itself ignored the statutory dividend formula and set an arbitrary dividend appropriation to pay dividends of $1,100 per Alaskan, a compromise amount based on what dividends would be under the differing versions of Walker’s Permanent Fund restructure bill passed by the House and Senate. To Wielechowski’s arguments, the court concluded that a plain reading of the Permanent Fund amendment, which states that income from the fund will go to the General Fund, “unless otherwise provided by law,” does not amount to a dedication. The Fund clause in the Constitution directs the Fund’s income to be deposited for appropriation, but it does not give the Legislature the authority to dedicate that income, according to the court. “Interpreting the 1976 constitutional amendment to allow dedications of Permanent Fund income would create an anti-dedication clause exception that would swallow the rule,” the justices concluded.

Rodell reflects on Fund at $60B milestone

The Permanent Fund is many things to many Alaskans. It’s the State of Alaska’s way of transforming finite resources into potentially perpetual wealth. It’s the source of undoubtedly one of the most popular government programs ever envisioned, the Permanent Fund Dividend. It’s always a reliable topic for lively debate. At more than $60 billion, it’s currently worth about $83,000 per Alaskan. To Alaska Permanent Fund Corp. CEO Angela Rodell, it’s also beautiful. “When you think about the forward thinking and political will it took to set this up, it’s stunning. All too often I hear about the things that we’re not proud of in Alaska,” Rodell said during an hour-long interview with the Journal on Aug. 23. “Yet this one we got really right. This is something I think we should all be tremendously proud of and understand.” The understanding part is key, according to Rodell, particularly as the Legislature and Gov. Bill Walker debate whether the Fund should also be a funder of government. She said Alaskans, even some legislators, regularly refer to her organization as the “Permanent Dividend Division” or the “Permanent Dividend Fund,” referencing the corporation’s longtime sole purpose as far as much of the public is concerned: to produce the annual dividend checks distributed by the Revenue Department each October. On one level, the misconceptions about the Fund are understandable. Since 1976, when voters passed a constitutional amendment establishing the Permanent Fund, it has been cared for in relative anonymity. In 1980, the Legislature directed the corporation to start spinning off dividends based on the length of each Alaskan’s residency. The U.S. Supreme Court promptly nixed the idea of rewarding Alaskans based on their time served and in 1982 the Legislature approved the Permanent Fund Dividend formula that stands today. The PFD is half of the average annual net income generated by the Fund over the five most recent state fiscal years divided amongst all eligible residents. To date, the Fund supported more than 18.4 million dividend checks totaling about $21.1 billion. It was started with an initial deposit of $734,000 in oil royalties on Feb. 28, 1977. Continuous mineral royalty deposits and prudent management have grown the fund to $60.9 billion today. During the 2017 fiscal year that ended June 30, the Fund grew by more than $7 billion thanks to corporate managers achieving a 12.6 percent return on its investments. Rodell described the strong returns as a “nice recovery” after turbulence in financial markets through much of 2016 limited the Fund to about 1 percent growth. The 12.6 percent return was led by a roughly 20 percent return on the $26.1 billion of the Fund invested in public equities, or stocks. Rodell acknowledged that a market correction is all but assured given U.S. public markets continue to set records almost daily. “We know because history tells us there will be a correction. When and where — how much — is anyone’s guess. We don’t have any more insight into that than anyone else,” she said, noting that is why the Fund has an ever-more diversified portfolio. Rodell said the staff regularly run scenarios of various possible market downturns to evaluate how they could impact the Fund. Time of transition Rodell took the helm at the APFC in October 2015 just a couple months before Walker took a big political leap and proposed employing the Fund’s earning power to help alleviate what was then a roughly $4 billion budget deficit. Walker’s original bill would have drastically re-plumbed state finances to funnel most revenue through the Permanent Fund to fully harness that earning power and spin off about $3.2 billion to pay for government services. The governor has since endorsed a simpler percent of market value, or POMV, draw from the Fund’s Earnings Reserve Account each year, a plan his administration devised alongside Senate Republicans early in 2016. While the Democrat-led House and Republican-dominated Senate both passed similar version of Walker’s POMV bill earlier this year, the politically disparate leadership in the bodies have yet to compromise on the contingencies each has placed on doing something that was unheard of just a couple years ago, as Rodell and others have noted. Both House and Senate POMV plans would result in a smaller dividend check from the current statutory formula. Neither Walker nor former Gov. Sean Parnell ever mentioned turning to the Fund’s earnings to fix the deficit in the 2014 gubernatorial race, with Walker explicitly rejecting the idea of touching the PFD. However, less than three years later, it feels inevitable. Rodell was Revenue commissioner and a Permanent Fund trustee in Parnell’s administration. And though the Legislature is on the precipice of tapping the Fund for government — something it has resisted for 40 years — Rodell said it is being done properly, even if the politics is messy. “I think having a structural plan in place that is either POMV or a capped dollar amount draw really sort of helps everybody plan for some sort of distribution of the Earnings Reserve Account to the extent that (legislators) decide that’s the direction they want to go,” she said. Like the General Fund, the Earnings Reserve has always been accessible by majority votes in the House and Senate along with the governor’s approval. Additionally, the Alaska Supreme Court ruled Aug. 25 that the dividend is just another state appropriation that the governor has veto power over despite the best efforts of Sen. Bill Wielechowski and former state Sens. Clem Tillion and Rick Halford, who served in the Legislature when the dividend program was established. The bipartisan trio and some others in the Legislature have also supported the idea of enshrining the current dividend formula in the state Constitution to protect it from actions like Walker’s veto to halve the PFD appropriation in 2016 and the Legislature’s move this year to arbitrarily set dividends at $1,100 per Alaskan. Both moves resulted in PFD payments that were about half of what they would have been under the statutory formula. The $1,100 amount was a compromise between the dividends the House and Senate’s Permanent Fund POMV bills would provide for; the Senate’s was set at $1,000 with a 5.25 percent draw and the House’s at $1,200 with a 4.75 percent draw. Those bills would generate about $2.5 billion for government and dividends combined. Three times between 2000 and 2004, the Permanent Fund Corp. Board of Trustees passed resolutions in support of a POMV draw from the Fund of up to 5 percent after inflation; that was the last time lawmakers mulled employing the Fund to reduce deficits. Soaring oil prices and tax revenue soon pushed deficit worries aside. With all that as background, Rodell again stressed the importance of broadening knowledge about the Fund and its namesake corporation among both lawmakers and the general public. “For a long time nobody paid any attention because our purpose was to pay an amount over to (Revenue) to pay dividends, so you didn’t have a constituency that really cared,” she said. “Everybody cares about their dividend; they don’t really care how you get to the dividend or what it takes to generate that dividend. “I think in order for people to understand exactly what they’re being asked to make decisions about, whether it’s voters deciding the dividend or whatever it is, they need to understand what the Permanent Fund and the corporation is.” Fund 101 If the Fund is going to be expected to support part of the state’s budget each year, the first shift has to be mentally separating the Earnings Reserve that holds the Fund’s net income from its principal, according to Rodell. Together, the accounts make up what has always been known as the entirety of the Fund. Rodell admitted she often slips up, referring to the Fund as “$60 billion” to the Journal, instead of parsing out the $47 billion principal, or corpus, and the nearly $13 billion Earnings Reserve. The accounts are usually rhetorically lumped together in part because they are invested together. Stocks, for example, are purchased by the corporation with a pro-rated amount of the corpus and the Earnings Reserve. However, 100 percent of the income earned off that stock when it is sold is deposited into the Earnings Reserve, which is why inflation-proofing the corpus of the Fund is critical, Rodell said. The Legislature has not transferred money from the Earnings Reserve to the corpus for inflation proofing in the last two state budgets in an effort to build up the Earnings Reserve before starting to draw on it. It’s a decision Rodell appreciates, but it doesn’t make fighting the value degradation of the Fund any less important. In fiscal year 2016, it would’ve only taken about $47 million to counteract inflation — about 0.12 percent of the corpus value. But in 2017, that jumped to more than $500 million, according to Rodell. “If we’re not putting anything back into the corpus we still have that same $39 billion we had in the nominal value of the royalties contributed over the years; that’s all we have to invest,” she said. Rodell objects to the premise that the ongoing mineral royalty payments offset inflation. First, with current lower oil prices and much less production than the state has seen historically, last year’s royalty injection into the Fund of about $225 million isn’t even half of what was needed to offset inflation. Additionally, using royalties in-lieu of inflation proofing transfers does a disservice to young Alaskans, Rodell contended. “I would argue the royalty payment is the nonrenewable resource turning into a renewable resource. It shouldn’t even be considered a hedge against inflation by any stretch,” she said. “We’re still harvesting that nonrenewable resource and future generations should get the benefit of what we’re harvesting today and that’s the royalty payment.” Along with deferring inflation proofing, legislators also disregarded laws directing up to 50 percent of royalty revenue from some state leases to be deposited into the Fund. The Constitution requires a minimum of 25 percent of all resource royalties be used to grow the Permanent Fund and the Legislature has funneled the other 75 percent of royalty revenue into the General Fund of late in an effort to shrink the deficit. “There are a number of statutes that have been ignored without a plan being put in place. That concerns me,” Rodell said. Gov. Walker’s Permanent Fund restructure bills also reverted to the 25 percent royalty minimum and the POMV bills would only start to inflation-proof the Fund once the value of the Earnings Reserve is greater than four times the previous year’s draw. Any excess cash beyond the four-fold threshold would automatically be injected into the corpus. Budget battles While the realities of the state’s fiscal situation are putting pressures on the Fund, the Legislature’s ever-increasing inability to timely pass a budget is starting to weigh on the Alaska Permanent Fund Corp., as it is an arm of the state Revenue Department. Rodell recalled that the budget fight in 2015 drew into May, but the Legislature passed a receipts budget allowing self-sustaining state operations to stay open in the event of a government shutdown. The corporation’s budget comes out of the Earnings Reserve. By 2016, a budget deal was reached just days before the dreaded “pink slips” had to go out to state workers on June 1, but there was no receipt authority granted prior. In 2017, the budget battle lasted until a week before a government shutdown. At one point during the month, the Senate had passed a bill to use about $2 billion in Fund earnings while the House passed a budget to spend $5 billion. The eventual compromise ended up filling the deficit from the Constitutional Budget Reserve and dividends were funded as usual from the Earnings Reserve. “This year, they’re fine with sending out pink slips, but we’re not actually going to shut down state government. What do you think happens next year? I don’t care that it’s an election year,” she commented, adding that people in the Lower 48 are taking notice. “I’ve got headhunters watching this and calling my staff, calling me, saying, ‘Hey Angela, do you really want to keep working for the State of Alaska? I’ve got a great job in the Lower 48 for you.’ My (chief investment officer) got calls; we all got calls,” Rodell said. “Now the good news is we’re also residents of Alaska; we love Alaska, but how many more times are we going to do this?” “I don’t think there’s a single legislator out there that has any interest in seeing us shut off the lights and close our doors, not one, but we’re part of the bigger budget battles that happen.” To that, Rodell said the corporation Board of Trustees will likely decide at its late September meeting in Juneau whether or not the corporation will seek a change to state law to forward fund the corporation or otherwise remove it from the annual budget debates. She also characterized trying to adequately compensate the world-class finance professionals managing investments on the scale of the Permanent Fund requires as “a real challenge,” noting the Revenue commissioner faces the same obstacles with Treasury Division officials. Keeping up with compensation Because the APFC is technically an arm of the state, its salaries are viewed through the lens of what’s fair compensation for state government workers, Rodell said. “We got caught this year again in a debate of ‘no one’s getting merit increases.’ They cut $169,000 from our budget request I had built in for merit increases but we made $7 billion,” she commented, emphasizing that she does not advocate for Wall Street-like compensation at the APFC. Thankfully, the opportunity to work on the Permanent Fund — the United States’ premier sovereign wealth fund — in a place like Juneau usually sells itself, according to Rodell. She said investment types from worldwide hubs such as Singapore and London apply to move to Juneau to be a part of Alaska’s Fund. She described it as a “really crazy unique experience,” noting that the U.S. Treasury looks to the APFC to be its “eyes, ears, voice in the international camp. We participate in the International Forum of Sovereign Wealth Funds that was created by the World Bank and the IMF (in 2009); we are a leader in that organization.” Former CEO Mike Burns helped craft the Santiago Principles of transparency and good governance for sovereign wealth funds after the 2008-09 financial crisis, Rodell pointed out. “We have trillion-dollar funds — the staff come to Juneau and learn how we do things because they like the results that they see; they appreciate the transparency we create,” she said. “We bring a bit of a ‘halo effect’ we call it, to certain investments when we participate and I was not aware of that international reputation until I got into this job and started going outside.” She continued, “Knowing that we are voice in the international finance community — I think people would be really stunned by that. Now, whether or not people think that’s a role for us to play or not I don’t care. The fact is we can’t get away from it. “We have access to some of the most amazing, brightest thought leaders around the world and that’s a function of our size. It’s why I could recruit a chief investment officer the caliber of Russell Read.” Read joined the APFC in May 2016. He has also served as CIO for CalPERS, the $330 billion California state pension fund, among other positions, and holds master’s degrees from the University of Chicago and Stanford University as well as a Ph.D. in political economy from Stanford. Being able to participate on the global scale from a small town like Juneau offers other benefits, such as a work-life balance that is lost in the mega cities, Rodell added. “We save 170 hours in commuting time alone that you get back from New York if you come to Juneau. There’s no commuting time in Juneau,” she said with a laugh. The four-hour time difference between New York and Juneau can be a challenge but is not always a deterrent, according to Rodell. Investing internationally requires odd hours and one knows that going in. “If you’re a fixed income trader and you’re sitting at your desk when the markets open at 5:30 in the morning; you’re done by 1 o’clock in the afternoon,” she noted. “You know what that means in the summer in Alaska?” It’s changing times for nearly everyone in Alaska and Rodell said she doesn’t want to see the state’s biggest asset fall by the wayside or be pulled apart by competing pressures. She summed her thoughts up by reciting a question posed at a recent conference she attended. “Fifty years from now, what do you think your grandchildren will wish you had invested in today?” Rodell recalled. “My answer was the Permanent Fund because I worry that we’re not thinking about the Fund itself anymore; that we’re taking the Fund for granted in some ways and that it will be this perpetual ongoing resource.” ^ Elwood Brehmer can be reached at [email protected]

State to take on permitting for transportation projects; Cooper Landing bypass reconsidered

The Alaska and federal Transportation departments have inked a deal allowing the state to assume permitting responsibility on federally funded projects, which should speed environmental reviews and save government money, according to the agencies’ leaders. The memorandum of understanding, or MOU, will shift environmental assessment and environmental impact statement drafting from U.S. DOT sub-agencies to the state Department of Transportation and remove duplicative federal processes and “interagency squabbling,” DOT Secretary Elaine Chao said during a Thursday afternoon press conference in Anchorage. Alaska Transportation Commissioner Marc Luiken said the agreement will hopefully save money on large projects by spending less on studies — leaving more for construction. “We see the opportunity to accelerate project delivery,” Luiken said at the briefing. The State of Alaska will still follow the National Environmental Policy Act processes with oversight from its federal counterparts, but will issue its own decisions at the end of the reviews. “Every federal regulation, every federal law still has to be abided by, but we’re just the lead agency,” Luiken added. The standard 90-10 federal-state split on funding for large highway and airport projects still applies regardless of who is leading the studies, so the state will not be adding cost burdens, he clarified. Sen. Dan Sullivan, long an ardent critic of the layered federal regulatory process for construction projects, said it should provide more jobs for Alaskans by allowing more important infrastructure projects to move forward. “It’s a new era of state and federal cooperation,” Sullivan said. The MOU will be published in the Federal Register Friday and likely take effect in late October after a public comment period. Chao stressed the agreement as a way to add jobs to a state in a recession. “Infrastructure feeds economic development,” she said. Cooper Landing bypass The trio used the long-studied and proposed Sterling Highway bypass around the narrow, windy section of highway through Cooper Landing as a prime example of what can happen when multiple federal agencies are left to work on a major road project. However, they also announced the U.S. Fish and Wildlife Service, an Interior Department agency, has agreed to consider a swap with Cook Inlet Region Inc. of Kenai National Wildlife Refuge acreage for some of the Alaska Native corporation’s property that could facilitate the bypass route many Alaska leaders want. A spokesman for CIRI could not immediately be reach for comment on the proposal. The first draft EIS for rerouting the Sterling Highway around Cooper Landing was completed in 1982 but did not lead to construction. A second draft was published in 1994 before again stalling, according to the Alaska DOT’s website on the project. Publication of a final EIS this year left the state at odds with the Federal Highway Administration, which chose a route different than that preferred by many on the Kenai Peninsula and Gov. Bill Walker’s administration and the congressional delegation. The $250 million “G South” alternative selected by FHWA would add a third bridge over the Kenai River in the area and therefore not mitigate risks to the river from accidents such as tanker spills that the more northerly $205 million Juneau Creek option would, they contend. The Juneau Creek route would also use less of the existing highway corridor. In July, Walker, Sen. Lisa Murkowski, Sullivan and Rep. Don Young sent a letter to Chao and the Secretaries of Interior and Agriculture urging them to have their agencies rethink the alternatives. Walker commended Chao for agreeing to relook at the Cooper Landing bypass options in a statement from his office. “It is critical to the safety and health of both Alaskan motorists and our world-class salmon fisheries that this complicated project move forward,” the governor said. “The current road alignment does not meet current highway standards, is congested, and due to its proximity to the river has an increased risk of spills that would harm salmon in the Kenai and Russian rivers. I thank Secretary Chao for allowing all options for this project to be considered.” The Interior and Agriculture departments had allegedly been hesitant to sign off on the Juneau Creek option, as it would send the highway through additional Chugach National Forest and Kenai National Wildlife Refuge lands.   Elwood Brehmer can be reached at [email protected]

Rare Alaska hearing probes causes for plane crashes

Why, in the technological age, are airworthy planes still being flown into the ground in Alaska? That was the omnipresent question at the National Transportation Safety Board’s Aug. 17 hearing in Anchorage to further its investigation into the crash of Hageland Aviation Flight 3153 on Oct. 2, 2016, just outside of the Western Alaska village of Togiak. The Hageland Cessna 208 Caravan was en route to Togiak from the nearby village of Quinhagak with a load of mail and one passenger when it crashed high on a mountainside about 12 miles from Togiak, according to representatives from the commuter airline. The controlled flight into terrain, or CFIT, crash killed the passenger and both pilots on impact. While the number of CFIT accidents in Alaska has generally decreased over the last decade-plus, NTSB officials said leading up to the rare field hearing that they really shouldn’t be happening anymore at all. Board member Earl Weener stated in a press release that the board traveled to Alaska because most of the witnesses the agency wanted to hear from are here. However, the NTSB has investigated countless aviation accidents in the state over the years and the inquiry into the Togiak crash was the first investigative hearing the board has held outside of Washington, D.C., in nearly 20 years. It was the first in Alaska since the 1989 Exxon Valdez oil spill. Weener, who ran the hearing, noted at its outset that the hearing was “strictly a fact-finding mission.” “The board does not find fault or blame,” he said. Federal Aviation Administration officials and Hageland leaders testifying under oath before the board stressed throughout the intense, nine-hour day of inquiry that two age-old Alaska themes are often at the root of CFIT crashes in the state: much of rural Alaska still lacks needed infrastructure to give pilots the information they need — in this case for weather reporting and communications —and the daring, “bush pilot culture” is still pervasive amongst the state’s aviators. According to FAA data, the number of CFIT accidents in Alaska has gone from eight in 2002 and nine in 2003, to an average of four per year by 2016. The number of CFIT accidents — fatal and nonfatal — involving commuter and flight service operators known as Part 135 has gone from five in 2002 to four in 2004 and has been one or two per year since 2006. The overall average would be lower if not for a recent spike in incidents that prompted Alaska FAA Flight Standards Manager Clint Wease to issue a letter in May 2016 to Part 135 operations. According to Wease at the time, CFIT accidents involving Part 135 aircraft in the year before the letter had led to 24 fatalities or serious injuries. “Many of these CFIT accidents have occurred in aircraft with advanced avionics, which were capable of instrument flight and operated by experienced pilots,” Wease wrote. His first of several recommendations in the letter was for pilots to operate under instrument flight rules, or IFR, whenever possible. Hageland Operations Manager Luke Hickerson said in his testimony to the NTSB that about two-thirds of the airports the airline serves don’t have all of the equipment necessary to conduct IFR flights. According to Hickerson, Hageland has about 7,600 possible “city pairs” in its flight network and its pilots perform roughly 150,000 takeoffs and landings per year on about 55,000 flights. Erin Witt, Hageland’s chief pilot, estimated that up to 15 percent of the airports the company flies to have no communication capabilities at all. Hageland serves the numerous villages in the Yukon-Kuskokwim region of the state on behalf of its larger sister airline Ravn Alaska. The communications challenges are often compounded by the fact that the area regularly has low cloud ceilings that are sometimes at less than 1,000 feet, Hageland pilots testified. Flying an IFR route allows a pilot to fly through and above cloud cover, almost eliminating the risk of CFIT accidents. “I would love to operate a fleet of IFR aircraft” and fly by instruments all of the time, Witt said. The alternative is flying below the ceiling under visual flight rules, or flying VFR. Lacking weather reporting from official equipment such as National Oceanic and Atmospheric Administration automated weather observing systems, or AWOS, common at larger airports, Hageland pilots regularly use FAA weather cameras and call trusted sources in the villages such as state Department of Transportation workers at the airports for current conditions before take-off and, when possible, during a flight, Hickerson said. The FAA maintains a network of more than 230 weather cameras in Alaska at airports and high-risk points. While they are viewed by small commercial operators across the state, the cameras are geared towards general aviation and information they provide cannot be used as a formal weather report by a commercial pilot. When questioned by NTSB investigators why a pilot would rely on unofficial weather information, Hickerson responded by saying the pilots are “going from nothing and making something.” Hageland pilot Natoshia Burdick, who was the safety pilot on a flight about five minutes behind Flight 3153, noted in testimony that a pilot flying in the Yukon-Kuskokwim area is required to get near-immediate clearance from air traffic control in Bethel when requesting to fly IFR and the tower is not always reachable. “It’s a whole lot easier with the infrastructure that’s out there to go VFR,” Burdick said. Additionally, pilots on IFR-capable routes may still have to fly below the clouds because many of the village airports do not have de-icing equipment, according to Hickerson. Flying through clouds and at higher altitudes greatly increases the likelihood that ice will form on the aircraft and when a plane that has flown through icing conditions it cannot take back off without being sprayed down with a glycol solution. Hageland has developed its own small, portable de-icing sprayer that can be kept in the small aircraft it flies, but with only about five gallons of fluid its usefulness is limited, company representatives testified. Hickerson said there are reasons CFITs were a serious problem in the Lower 48 up until about 40 years ago. “I think the technology and infrastructure advancements that have been made in the continental U.S. need to be made here,” he told the NTSB. Deputy NTSB Director of Aviation Safety John DeLisi said the agency has recommended mandating CFIT avoidance training for all Part 135 pilots — it isn’t currently — while also seeming to commiserate somewhat with the Hageland witnesses. “It would be great to have that infrastructure and we’re going to do our job to make that point,” DeLisi said in response to Hickerson. FAA Alaska Region Administrator Kerry Long, who has held the position for about three years, said in an interview that he believes he and his staff have made progress of late in getting key agency personnel from the Lower 48 to visit Alaska and recognize the challenges the aviation industry faces in the state. Long said a pending report commissioned by the FAA from the RTCA — an aviation technology nonprofit —should highlight Alaska issues for decision-makers in Washington, D.C. He called the lack of weather and navigational infrastructure in parts of Alaska “a pressing issue.” “We believe that we have developed approaches that have made people more interested in coming up here as well as providing the information in forms that people understand better and this particular RTCA report will fit in with the recommendations that get made to the agency as a whole,” Long said. He noted the FAA’s funding has been flat for several years as a result of Congress repeatedly passing continuing budget resolutions, which challenges the agencies ability to install new equipment. “We can ask for it; we can push for it; we can do everything we can but if we can’t deliver we have to try harder,” he added. Alaska Air Carriers Association Executive Director Jane Dale wrote in an email that despite the facts that 82 percent of Alaska communities are only accessible by air and the FAA encourages Alaska carriers to fly IFR, the state lags in AWOS stations and working ground-based navigational equipment. “Infrastructure supporting IFR and VFR flights in Alaska is and has been the association’s number one priority for years,” Dale wrote. “This includes improving the availability of weather information in rural Alaska, proactive investment in aviation infrastructure and maintaining the existing infrastructure.” Flight 3153 crash Despite the apparent consensus among industry and government regulators at the hearing that Alaska’s aviation infrastructure is insufficient; it does not explain the Togiak accident. The Quinhagak-Togiak route is IFR capable. Burdick, a pilot on the trailing Hageland flight that detoured around the mountain before being notified of the crash, said agents at the company’s Operations Control Center led by Hickerson recommended flying IFR that day, but the Flight 3153 pilot chose not to. Little explains the crash of the flight that had a pilot-in-command to fly the Cessna and a safety pilot tasked with — as the title implies — being a redundant safety check. Hageland’s right-seat safety pilots are trained to clearly and directly voice any concerns they have with weather conditions or decisions made by the pilot-in-command, the company’s NTSB witnesses testified. Burdick said when news of the crash made its way to their plane, she and her pilot-in-command attempted to locate the crash site but the 2,500-foot mountain was obscured by clouds below the broader ceiling. The NTSB may yet find a definitive reason for the Hageland tragedy, but Hickerson and FAA officials said audacious attitudes are still far too prevalent among Alaska pilots, creating a wholly unnecessary danger, particularly among commercial pilots. Hageland’s operational control agents at the center in Palmer discuss the circumstances surrounding each flight with the pilot before approving, or releasing it, Hickerson said. An operations manager is involved if any disagreement arises between the pilot and the agent. He emphasized that the operations center is completely removed from the business side of the company. “There is not pressure on the OCC to ever release a flight,” he said. The OCC has cancelled more than 3,500 flights since the start of 2016 and turned another 600-plus around due to deteriorating weather, according to Hageland leaders. Culture shift Hickerson stressed that “safe, legal, and best practice” is what drives Hageland Aviation. “It’s a lot easier to write rules and regulations than it is to change hearts and minds and that’s what we’re trying to do right now,” Hickerson said. He continued: “The idea of turning around 10 years ago was unheard of and shamed not only by other pilots buy by companies as well.” Wease generally agreed in his testimony, saying a series of Hageland incidents in the 2012-13 timeframe pushed the FAA to uncover what he described as a “poor pilot culture,” that he believes has since been corrected. The company CEO starts each ground school with a talk to prospective pilots highlighting Hageland’s safety culture, Hickerson said, to illustrate it is truly companywide. He said the company looks for reckless behavior “in every aspect of pilots’ lives,” because risks don’t announce themselves. “You’ve got to listen for the whispers in the system,” Hickerson said. Dale, of the Alaska Air Carriers Association, said the industry group does not agree with the belief that there is still an unsafe pilot culture in the state. Alaska operators “work hard to ensure a culture of safety,” according to Dale. She again cited a lack of needed equipment in some areas of the state, noting some of the current AWOS and navigational infrastructure is often out of service. Witt said pilots applying to fly for Hageland are screened with questions related to their decision-making and risk tolerances and about 10 percent of applicants are denied solely on those answers. To that, FAA Alaska Certificate Office Manager Deke Abbott, who spent most of his career in aviation Outside, said he was taken aback by the adventurous nature of many Alaska pilots. “We push the airplanes to get where we’re going,” Abbott said to the board, adding that when a pilot makes a decision, the consequences of that decision are ultimately solely the pilot’s responsibility. “We’re trying to change a 100-year culture,” he concluded. Elwood Brehmer can be reached at [email protected]

Permanent Fund Corp. earns 12.6% in FY17

While the State of Alaska is still mired in a damaging cycle of multibillion-dollar budget deficits, it’s hard to imagine a scenario in which its biggest financial asset could be doing better. The Alaska Permanent Fund Corp. achieved a 12.57 percent return on its namesake Fund during the 2017 fiscal year that ended June 30. The Permanent Fund ended the year with a record value of $59.8 billion. The corpus, or principal, of the Permanent Fund is constitutionally prohibited from being spent; however, the Fund’s Earnings Reserve Account is available for appropriation and it ended fiscal 2017 with more than $12.8 billion of Fund income. Of that, more than $10.8 billion was available realized earnings. More than $3.2 billion in statutory net income was added to the Earnings Reserve in 2017. Historically, the Fund’s investment income has been only been distributed as dividends to Alaska residents based on a statutory formula. In the weeks since the end of the state fiscal year, the Fund has continued to grow to more than $60.6 billion as of Aug. 21, according to the corporation’s unaudited results. Permanent Fund Board of Trustees Chair Bill Moran said in an APFC release that the “high mark is a testament to the Alaskans who had the foresight to create the Fund, the leaders of yesterday and today who have maintained the integrity of the Fund and the dedicated professionals of the Alaska Permanent Fund Corp. who have attentively invested the Fund.” CEO Angela Rodell said the Permanent Fund has gained international recognition “as a model for converting a non-renewable (oil) resource into a renewable financial resource.” The strong 2017 results counter fiscal 2016 when volatile public financial markets kept Fund growth at a modest 1.35 percent. Gov. Bill Walker’s administration and many legislators have pegged a long-term return average of 6.9 percent as a foundational assumption for starting to spin off about 5 percent of the Fund’s annual value to support government services and continue to pay out annual dividends in the $1,000 to $1,200 range. Doing so could sustainably provide up to about $1.8 billion per year to reduce the state’s deficits, they contend. The below-average 2016 put the Fund’s three-year return average below the 6.9 percent target at 6.18 percent, but the corporation’s active management still greatly out produced passive benchmark investments of 60 percent stocks, 30 percent bonds and 10 percent real estate and inflation-protected securities that would have returned 3.37 percent over that time. Over the previous five years the corporation’s management has produced an 8.94 percent return, compared to a projected passive return of 7.10 percent. The 2017 performance was led by a roughly 20 percent return on the $26.1 billion of the Fund invested in public equities, or stocks. For rough comparison, the Dow Jones Industrial Average closed Aug. 22 up 18.19 percent over the previous 12 months. Another nearly $7 billion invested in private equities returned 20.98 percent and the Fund’s $5.5 billion of real estate investments earned 4.45 percent, according to the corporation’s June performance report. Infrastructure and private credit investments averaged roughly 9 percent paybacks, while $11.7 billion in fixed income assets naturally yielded more modest returns. Elwood Brehmer can be reached at [email protected]

Draft EIS released for Liberty offshore project

A long-anticipated North Slope oil project took a big step forward Aug. 18 when the federal Bureau of Ocean Energy Management released the draft environmental impact statement for Hilcorp Energy’s proposed offshore Liberty development. Houston-based Hilcorp and its partners in Liberty — BP and Arctic Slope Regional Corp. subsidiary ASRC Exploration LLC — are planning to construct a 24-acre gravel island in the federally-controlled shallow waters about six miles offshore and just east of Deadhorse in the Beaufort Sea. The island would allow Hilcorp as the project operator to access the up to 330 million barrels of light crude the companies believe are in place. With 16 wells, Hilcorp expects it could recover 41 percent to 48 percent of the oil in place. Peak production could hit up to 70,000 barrels per day a couple years after initial production, according to the company’s Alaska leaders. Liberty would produce for 15 to 20 years based on the current reserve estimates. The oil would be moved to the Trans-Alaska Pipeline System, or TAPS, through a 12-inch diameter pipeline that would tie in to the eastern Slope Badami transport line. About 5.6 miles of the roughly 7-mile Liberty pipeline would be a subsea line, buried and installed during the winter. The subsea portion of the 12-inch pipeline would also be contained within a 16-inch pipe, drawing on a technique used at other North Slope manmade island oil developments. With a 24-acre seafloor footprint, the island, in 19 feet of water, would have a working surface of 9.3 acres, according to the 1,270-page draft EIS. Hilcorp has pointed to the four large existing North Slope oil development islands — Endicott, Spy, Oooguruk and Northstar — as strong evidence that Liberty can be done safely. “Not only have similar proposals of the Liberty project been vetted and approved before, but gravel-based energy facilities have a proven record of safe operations, with some in production for over a decade in the Beaufort Sea,” Hilcorp Alaska Senior Vice President Dave Wilkins said in a joint release. “We are eager to work with the communities across the North Slope and our partners throughout the state to develop a project that will greatly benefit Alaska and bring greater domestic energy security to the country.” ASRC Lands and Natural Resources Vice President Richard Glenn said Liberty is the kind of project the company has determined is important for its region and “through local participation we can ensure that the needs and issues of our communities and shareholders are addressed.” Hilcorp is majority owner and operator of the Northstar and Endicott fields, after purchasing BP’s interests in them in a 2014 deal that also gave it a 50 percent interest in Liberty. BP subsequently sold 10 percent of its stake in Liberty to ASRC Exploration. BP purchased Liberty from Shell in 1996 after Shell discovered the prospect with four exploration wells in the mid-1980s. BP first planned to build an island to develop Liberty but put those plans on hold in 2001 to further study the project, according to the draft EIS. In 2005 the London-based oil major proposed drilling ultra-extended-reach wells from onshore to eliminate the need for an island and minimize the project’s impacts on Alaska Native subsistence whaling hunts in the area. That plan was scrapped in 2012 and Hilcorp subsequently took over the project in 2014. Gov. Bill Walker submitted a letter to BOEM in October 2015 supporting Hilcorp’s plan during the public comment period to determine the scope of the EIS. Walker wrote that the oil produced from Liberty would help extend the life and increase the operational efficiency of TAPS. Liberty would indeed be a boost to TAPS, but it would not do much for the state treasury because it is in federal waters. BOEM estimates the project would generate nearly $1.5 billion in federal lease and royalty payments — in 2015 dollars — over its operating life. The State of Alaska’s share of that revenue would be about $400 million, with another $15 million generated in state corporate income taxes and $3 million in state property taxes from the onshore facilities. The North Slope Borough would receive about $35 million in estimated property taxes from Liberty. BOEM’s alternatives to Hilcorp’s proposal include moving the island 1 to 1.5 miles to avoid the densest area of the “Boulder Patch,” an area of the seabed with small boulder substrate that “supports the richest and most diverse biological communities in the Beaufort Sea,” the draft EIS states. Moving the island 1.5 miles into state waters would lengthen the wellbores necessary to reach the oil reservoir by 3,300 feet to a length of 17,200 feet, according to BOEM. Another option the agency is considering would move the oil processing facilities to the manmade Endicott Island that Hilcorp operates about eight miles to the northeast of Liberty. Moving Liberty oil processing to Endicott was suggested after EIS scoping period comments asserted doing so would minimize impacts to marine life and subsistence harvests around Liberty by reducing noise and vibrations from the island, according to BOEM. Kuukpik Corp., the Alaska Native village corporation for the North Slope village of Nuiqsut wrote in a 34-page March 2016 letter submitted to BOEM as public comments that the EIS should closely examine the impacts of abandoning the pipeline and leaving the island in place once production from Liberty has ceased. While Kuukpik President Isaac Nukapigak wrote the company neither supports nor objects to Liberty, it would eventually like to see the island area restored. “Leaving the island to slowly drift apart would almost certainly cause navigation hazards in this critical travel corridor in the short-term at least,” Nukapigak wrote. Doing so would expose the Boulder Patch to artificial debris, he contended. “The only apparent justification for failing to remove this island is to cut costs. If there’s not more to it than cost savings (Hilcorp) should be required to remove the gravel that it wants to dump in this marine environment,” he continued. He concluded his letter by noting that Kuukpik is concerned about the impacts the building a gravel island in what is an important whaling area for North Slope Alaska Natives would have, urging BOEM “to proceed slowly and methodically” to ensure the agency’s review of Hilcorp’s proposal is as complete as possible. Kuukpik shareholders are also shareholders in ASRC, which holds the 10 percent interest in Liberty through its exploration subsidiary. The possibility of drilling into the Liberty oil reservoir from onshore was not advanced and given only cursory consideration because it would require drilling wells that would be nearly a mile longer than the current world record wellbore of 40,602 feet, the draft EIS states.

State unemployment rate hits five-year high

Alaska seasonally adjusted unemployment rate hit 7 percent in July according to the state Labor Department. It’s the highest the unemployment rate the state has seen in nearly five years since it was at 7.1 percent in October 2012. The rate was up 0.2 percentage points from June, up 0.5 for the year and up 0.3 from July of last year. By comparison, the national adjusted unemployment rate was 4.3 percent in July. The not-seasonally adjusted unemployment rate was 6.6 percent in July, down 0.4 percent from June, which is common. Economists try to account for seasonal employment demand swings with the adjusted rate to better show month-to-month employment trends. Alaska’s busy fishing and tourism industries make lower unadjusted rates a common occurrence during the summer months. The upward trend in unemployment was spurred by the estimated loss of 7,500 jobs over the past year — a 2.1 percent decline in jobs statewide since July 2016, according to the Labor Department. “Preliminary estimates show job losses spread across most industries, although the deepest losses remain concentrated in industries closely tied to oil and gas,” an Aug. 18 Labor release states. Alaska lost about 1,500 direct oil and gas jobs over the past year, another 1,200 construction jobs and about 1,000 jobs each in the professional and business services and state government sectors. Job growth in the state since July 2016 has been limited to health care, local government and federal government positions. Those sectors have each grown by about 1.4 percent over the past year, according to Labor figures. Overall, Alaska is down about 8,900 jobs, or 2.6 percent, this year from its 2015 statewide employment peak. The 330,000-job average through July is comparable to full-year employment in 2011. Alaska economists have generally said they expect the current two-year recession to relax in 2018 before the state eventually resumes small job growth in following years. Statewide direct oil and gas employment peaked in 2015, averaging just less than 14,200 jobs for the year before significant layoffs began. Alaska has averaged 10,600 oil and gas jobs so far in 2017, a 25 percent decline from the 2015 employment. The oil price decline of 2014-15 has hit Alaska contractors especially hard as North Slope oil companies have pulled back spending on large projects. Doubling down on that has been the virtual elimination of state-funded capital projects in the annual state budget as government oil revenues have dwindled as well. Alaska spent more than $1.8 billion in discretionary general funds in the 2013 fiscal year capital budget. That was down to $120 million in the 2018 capital budget passed last month — nearly all of which was for the state’s 10 percent match to federal funds for highway and airport projects. Construction employment has fallen from a near-term peak of averaging 17,800 jobs in 2014 to average about 15,100 jobs through the first seven months of 2017, according to preliminary Labor numbers. Alaska construction employment was at its greatest over the last 15 years in 2005 with 19,100 jobs. State government employment peaked in 2014 at an average of 26,500 jobs, including University of Alaska positions. This year, the State of Alaska has so far averaged 23,900 workers, which is about a 10 percent decline from 2014. Elwood Brehmer can be reached at [email protected]

RCA asks state telecoms for broadband coverage plans

State utility regulators are doing their best to live up to a legislative directive to examine broadband coverage in Alaska and providers’ future plans despite not having any authority to do so. The Regulatory Commission of Alaska issued an Aug. 9 request for companies providing broadband service in the state to answer any or all of two dozen questions the commission has about the current status of broadband infrastructure and what the state could do to help expand coverage, among other things. The seven-page request also asks for a contact list of broadband internet service providers in Alaska and inquires about communities where broadband is available and at what download speeds from those internet providers. While the RCA has regulatory jurisdiction over a broad range of public service-providing entities including gas, electric, telecom and wastewater utilities and pipelines, it does not in any way regulate the broadband industry in Alaska. The 2018 fiscal year state operating budget passed in late June under the threat of a government shutdown contains intent language ordering the RCA to draft an analysis of the state’s broadband situation for the House and Senate Finance committees and the Legislative Finance Division by Dec. 1 of this year. To that end, RCA spokeswoman Grace Salazar wrote in an email that the commission will do everything it can to comply with the Legislature’s intent but learning about the status of broadband in Alaska “is going to require a high level of cooperation from the telecommunications industry.” Rep. David Guttenberg, D-Fairbanks, a House Finance Committee member who pushed to have the broadband paragraph added to the budget, said in a House Majority coalition release that he’s convinced the RCA’s report will illustrate that Alaska needs more competition in the broadband sector to lower costs and improve service. “I am confident the effort by the RCA to document the coverage gaps in Alaska will provide lawmakers, regulators and providers with the needed information to make the right decisions to ensure Alaskans can use broadband as a tool to help start a small business, connect with people from across the globe, and enjoy all that is available online,” Guttenberg said. While the RCA is asking for some information as basic as maps detailing where coverage is offered and infrastructure is located, Alaska Telephone Association Executive Director Christine O’Connor said the commission is also requesting granular data and some information that could be competitively sensitive. Her members, primarily rural Alaska telephone and internet providers but also the state’s largest such as GCI and Alaska Communications, are trying to figure out what information they have, how quickly it can be provided and at what cost, according to O’Connor. “Broadband service is the priority for all ATA member companies and we support all efforts to provide broadband for Alaskans. It is important to us to help policymakers advance that goal wherever possible, while also balancing judicious use of limited resources which should be directed to broadband infrastructure and service whenever possible,” she wrote in an email. The RCA is asking for responses by Sept. 8. Some of GCI’s competitors and smaller, local rural internet providers have filed objections with the Federal Communications Commission to the pending purchase of GCI by the Colorado-based telecom investment firm Liberty Interactive Corp. for $1.2 billion. They contend GCI — the dominant Alaska telecom — has used federal subsidies to build a monopoly and control broadband access and pricing across the state. GCI counters that building out broadband infrastructure in rural Alaska is exceedingly expensive and it has been the only company willing to match the available federal funds with its own significant investments to do so. The company has stated it used $250 million of its capital to build the $300 million TERRA broadband network. Alaska Communications plans to respond to the RCA’s request, according to a spokeswoman for the company. GCI spokeswoman Heather Handyside said the company is reviewing the request and determining how to respond. Elwood Brehmer can be reached at [email protected]

ConocoPhillips accepts state terms to obtain leases

ConocoPhillips has agreed to comply with a long list contingencies demanded by Natural Resources Commissioner Andy Mack to allow the company to control a prized parcel of North Slope oil acreage. ConocoPhillips Alaska Land Manager John Schell Jr. wrote to Mack in a brief Aug. 11 letter that the company accepts DNR’s terms to expand the Colville River Unit to include 9,100 acres of the now-defunct Tofkat Unit. Mack sent a 21-page decision to the company Aug. 1, which lays out a strict drilling and payment schedule the oil major must meet in order to retain control of the area. In it, he required ConocoPhillips to drill an oil exploration well into the Nanushuk geologic formation by May 31, 2018, and make a total of $7 million in payments to DNR. The $7 million is in lieu of the money the department could expect to receive in winning bids if the area were to be put up for bid in the state’s annual North Slope lease sale. Further, ConocoPhillips must also decide by Aug. 15, 2018, if it wants to continue exploration and commit to drilling another well by June 2020. It operates the large Colville River oil field, commonly known as Alpine. While a relatively small area in North Slope terms, the 22 former Tofkat leases are adjacent to the southern edge of the Colville Unit and also close to the Armstrong Energy’s massive Nanushuk oil discovery in the Pikka Unit just to the east. It’s a highly prospective area. ConocoPhillips held the acreage in the early 2000s but had to give it back to the state after failing to meet drilling requirements. If the company misses any of the benchmarks or decides to give up on exploring the area it will immediately relinquish the leases back to the state, according to Mack’s ruling. The decision, with the hefty legal title of, “Colville River Unit: Reconsideration of the Denial of the Fifth Expansion of the Unit Area with Modifications Under Which Approval will be Granted,” gave ConocoPhillips until Aug. 14 to decide whether or not it would comply; it was made public Aug. 3. Schell wrote that the company doesn’t agree with all of Mack’s assertions and therefore accepts only the drilling and payment requirement portion of the decision, but continued that, “it is not necessary to resolve or address those disagreements at this time and CPAI (ConocoPhillips Alaska Inc.) reserves its rights accordingly. The important thing is that CPAI agrees to the modifications in the decision and is prepared to move forward consistent with those modifications. “CPAI appreciates you taking time to reconsider your prior decision. In CPAI’s view this outcome will benefit all stakeholders and represents the best opportunity for this area to be timely developed in a safe and environmentally responsible manner. CPAI looks forward to proceeding towards this goal in collaboration with the State of Alaska, Arctic Slope Regional Corp., local communities and other interested stakeholders.” In prior correspondence ConocoPhillips accused Mack of violating the company’s due process and making decisions based on an incomplete record. Mack, in his Aug. 1 decision, roundly dismissed the allegations, calling them “troubling” and “unfounded.” ConocoPhillips spokeswoman Natalie Lowman wrote in an email to the Journal that the company plans to “work with the State, ASRC, Kuukpik Corp. and the community of Nuiqsut to drill an exploration well in 2018.” ASRC is a joint holder in subsurface rights to the leases with the state, while Kuukpik Corp., the Native corporation for the Village of Nuiqsut, holds surface access rights. Nuiqsut is located in the contested area. Mack’s most recent decision came after ConocoPhillips requested he reconsider a February order to require the company drill an exploration well in the area and make a $2.5 million payment before June or relinquish it back to the state; a tight timeline particularly considering any well would have to be drilled on an ice pad. The challenging schedule was the result of the company telling DNR last December it would not be drilling an exploration well in the area because residents of Nuiqsut — less than three miles downwind from the proposed drill site — were concerned exhaust from the diesel-powered drilling rig would make its way into the community during the several weeks of continuous drilling. Last November, Mack overturned a prior 2016 decision by former Division of Oil and Gas Director Corri Feige denying Brooks Range Petroleum Corp.’s attempt to transfer the former Tofkat leases to ConocoPhillips. Feige believed it was in the state’s best interest to put them back up for bid, as Brooks Range’s title to the leases was about to expire. Mack allowed ConocoPhillips to obtain the area after the company told DNR it would drill last winter. ASRC has supported ConocoPhillips gaining control of the area and a spokesman for the North Slope Native regional corporation told the Journal while ConocoPhillips was deliberating that ASRC will be discussing any potential concerns with the residents of the village, who are its shareholders as well. Kuukpik CEO Lanston Chinn said his company, in representing Nuiqsut, continues to seek a balanced approach towards all oil and gas activities. Mack said in an interview that any residual issues between the ConocoPhillips and the Native corporations were matters between private parties that the state would not be involved in. Drilling NEWS Unrelated to the high drama over the Colville River Unit, ConocoPhillips announced Aug. 11 that it had commenced drilling at its 1H NEWS project in the Kuparuk River oil field. The project is a nine-acre addition to the existing Kuparuk 1H drill site and includes four lateral production wells to access previously challenging viscous oil and another 15 injection wells. NEWS is an acronym for Northeast West Sak; the company is drilling into the West Sak oil reservoir in the greater Kuparuk field. According to ConocoPhillips, the $460 million 1H NEWS project should produce up to 8,000 barrels per day at peak and first oil is expected later this year. ConocoPhillips is also progressing its Greater Moose’s Tooth greenfield oil projects in the National Petroleum Reserve-Alaska to the east of Kuparuk. The two GMT projects are expected to each produce up to about 30,000 barrels of oil per day at peak production in the next few years. Elwood Brehmer can be reached at [email protected]

AGDC reports progress in attracting interest to gasline

One piece at a time, the Alaska Gasline Development Corp. is putting its plan to sell the $40 billion Alaska LNG Project into action. The state-owned group currently has a preliminary capacity solicitation for potential customers of the LNG export plan to express their interest in it open through Aug. 31. The “open house” of sorts is geared towards natural gas producers so AGDC can gauge the interest in reserving capacity on the proposed project’s gas pipeline and liquefaction tolling system, corporation officials have said. Accordingly, AGDC has also set up a data room for potential customers to examine the technical design and environmental information on the project the state, BP, ConocoPhillips and ExxonMobil collectively spent about $600 million over three years compiling. The companies transferred that mountain of data to AGDC at the start of the year after depressed oil and LNG markets put in question their ability to continue investing the Alaska LNG and the project’s long-term profit margin. Gov. Bill Walker, the primary proponent of a state-led Alaska LNG Project plan, believes the state can provide benefits to the project the producers can’t that will make it financially viable. A broadly skeptical Legislature has basically given him 2017 to prove it. While the capacity solicitation is meant to mostly gauge upstream interest in the project, AGDC Commercial Vice President Lieza Wilcox said during the corporation’s Aug. 10 board meeting that 17 confidentiality agreements have been signed with companies in six potential LNG markets. The corporation is now meeting with those companies to further inform them about the Alaska LNG Project, she said. After signing the confidentiality agreements the companies “want to walk alongside this train to see if it’s moving,” Wilcox described. She noted a confidentiality agreement is the first step in courting Asian LNG buyers. It is typically followed by a non-binding memorandum of understanding — which AGDC signed with the massive Korea Gas Corp. in late June — or letter of intent and then a heads of agreement, hopefully leading up to a firm contract. AGDC is also reviewing draft letters of intent with 13 parties from multiple countries, according to Wilcox. “I get reminded at almost every meeting what a serious step that (MOU/LOI) is for the companies,” she commented to the board. Tax questions AGDC notched a noteworthy victory in July when it secured an opinion from the Internal Revenue Service that it indeed is a tax-exempt political subdivision of the State of Alaska in the eyes of the federal government. But what exactly does that mean for the Alaska LNG Project? AGDC President Keith Meyer said in response to questions from board Vice Chair Hugh Short that the tax-exempt status is indeed a significant positive for the corporation, but not the missing link that will make the planned megaproject a sure-fire go. Short is a co-founder and CEO of the Anchorage-based and Arctic-focused investment firm Pt Capital. Meyer first clarified that the ruling extends only to AGDC, not to the Alaska LNG Project it is sponsoring. “If we brought a third party into that equity (investment) structure, we can’t extend the (tax) benefits to the third party but we still retain them,” he said. A private equity investor in the Alaska LNG Project would still be subject to federal taxes on any profits that investment would return. However, that may not extend to all Alaska LNG investments as a result of the IRS opinion, depending on how the many billions of dollars worth of financing for the project is ultimately structured. Being a political arm of the state — and holding the IRS ruling confirming as much — also allows AGDC raise debt by selling tax-exempt bonds. As a result, the buyers of any bonds sold by the corporation to fund the project would not have to pay federal taxes on the interest revenue they generate. AGDC estimates the Alaska LNG Project could initially generate $1 billion-plus in annual cash flow growing to more than $2 billion after about 20 years until the debt is paid off. Once debt-free in about 2045, it could produce upwards of $5 billion in cash to investors annually and be sold for up to $50 billion, Meyer said. He has repeatedly pointed to a very high-level, prospective scenario in which construction of the roughly $40 billion project is paid for with a combination of roughly 75 percent debt and 25 percent equity investments. The equity investments would likely garner about an 8 percent return and the debt 5 percent, for a 5.8 percent average cost of capital, according to Meyer. The State of Alaska would not be liable for any debt AGDC takes on to fund the project, Meyer has also stressed, as the bonds or other debt would be backed by the long-term “take or pay” contracts the corporation would secure from Alaska LNG customers. AGDC is encouraging Alaska firms to invest in the project and Senate Bill 138 — the law that established the framework for the state’s participation in Alaska LNG — requires the corporation to allow individual Alaskans to buy into the project as well. Private equity holders would have to manage their Alaska LNG investment into their overall holdings and tax position, but would have a “potential reduced return relative to AGDC for the exact same investment because of the tax impact — to the extent they have a tax impact,” Meyer acknowledged. Short said private equity investors in the project would likely require a higher return threshold to offset the federal taxes they would have to pay on the returns. “I think it’s a little optimistic to think taxable entities are going to invest alongside us and accept a lower rate of return and accept that’s how it’s going to be,” Short said. He suggested offering a different class of stock, blended return rates or simply factoring higher investment returns into a slightly higher tariff to use the pipeline and LNG plant if need be to satisfy potential investors’ requirements. Meyer responded by saying AGDC will offer benefits to different classes of investors with higher returns to some, particularly early investors in the project. He said those late to the game will probably have to accept lower rates because those investments should be subject to less risk as the project progresses, noting AGDC is considering many of these issues in drafting its financing plan. “It’s just a benefit, but when we’re talking about competing against very competitive projects globally, every cent counts,” Short summarized. Elwood Brehmer can be reached at [email protected]

Anchorage, railroad settle federal funding fight

The Municipality of Anchorage and Alaska Railroad Corp. appear to be back on good terms. Railroad CEO Bill O’Leary said in an Aug. 9 interview that the state-owned railroad reached an agreement last week with Anchorage Mayor Ethan Berkowitz’s administration to settle a multi-year dispute over how annual federal transportation grant funds are split between the two and get millions of dollars flowing into Alaska again. The formula funds will be split as they always have been for fiscal years 2016-2018, O’Leary said, which is a positive for the railroad that receives the lion’s share of the funding. The deal also includes an understanding that the railroad will sell the city a parcel of land next to the Port of Anchorage for $1.5 million. Berkowitz said the 20.2-acre property is “a critical piece” of land that will help the city progress its much-needed overhaul and modernization of port infrastructure. The standoff that started in 2016 had left more than $23 million with the feds — roughly $15 million for the railroad and $8 million for Anchorage under the earned split — for last year and the first half of 2017, as the FTA would not release the money without the split letter. As a result, O’Leary said the mayor instead wanted a 50-50 split, which the railroad simply could not agree to. Not getting just more than $11 million in expected 5307 funds in 2016 pushed the railroad into a $4.4 million loss for the year, according to O’Leary; the first annual loss it posted since 1999. Both Berkowitz and O’Leary described the agreement as a “win-win” in separate interviews. “Each one of our organizations had issues we were able to resolve here,” Berkowitz said. “By combining those two (the federal funds and land sale), we were able to do it in a way that solved both problems.” The Municipality of Anchorage is leasing the property in question and buying it outright will save Anchorage taxpayers over the long-term, Berkowitz stressed. He also thanked Gov. Bill Walker for helping resolve the issue. Walker's spokesman Jonathon Taylor said the governor simply brought the two sides together for discussions. Neither the mayor’s office nor the railroad were able to provide the lease rate in time for this article. O’Leary said the land sale “kind of served as the catalyst to move forward” with the overall settlement. In late March Alaska Railroad officials told the Journal Berkowitz was refusing to sign a joint letter with the railroad to be sent to the Federal Transit Administration showing the agency each approved of how the pool of federal cash would be split. Specifically, the “split letter” is for the FTA’s Section 5307 Urbanized Area Funding program meant to support public transit operations across the country. The two entities must settle on how the funds are apportioned because the Municipality of Anchorage, which has bus service, and the state-owned Alaska Railroad, which has year-round scheduled passenger service, are the two public transportation entities in the city. While the whole pot of Section 5307 funds is meant to benefit public transportation in Anchorage in general, its total amount is determined by formulas that tally how much is generated by the municipality’s People Mover bus line and how much the railroad generates. Those formulas are based on route and passenger ridership miles for bus service, and similarly revenue track and route miles for the railroad, as well as population density in the areas served by each. The letter is the Federal Transit Administration’s way of providing local control over how the money is spent. Berkowitz contended the railroad, which had historically generated and received about two-thirds of the Section 5307 formula funds, was getting the money on technicalities. While the Alaska Railroad does indeed offer daily scheduled service in the city — qualifying it for the money — the railroad does not provide the commuter service the city’s bus system does and the funds are intended for, he argued. The Alaska Railroad’s passenger service is primarily tailored to tourists on sightseeing trips and Alaska residents wanting to make longer trips to other cities or to remote cabins or homes along the tracks. The railroad has looked into commuter service in Southcentral, but it has never been deemed financially feasible. When the dispute first surfaced in April when the railroad released its annual results, talks had stopped but the name-calling had started. Berkowitz said in an interview then that railroad leaders were negotiating like “bullies” and with “petulance,” also accusing an unnamed railroad official of calling him “a terrorist” for standing up for his city. Alaska’s congressional delegation quietly sent letters to the FTA during the dispute asking if federal Transportation officials had the authority to settle it. Letters from Sen. Lisa Murkowski and Dan Sullivan did not choose sides, but did highlight how the funds were split previously. Rep. Don Young sided with the railroad in a June 2016 letter to Berkowitz, writing that he only did so because a new split separate from how the funds are generated could kill support in Congress for future FTA funds to Alaska. Alaska’s delegation has long had to fight to keep up federal support for the state-owned railroad because it does not operate as a traditional Lower 48 commuter service provider. The Alaska Railroad is the only full-service passenger and freight train corporation in the country. It does not receive state support for its operations, but various federal grants can account for up to about 30 percent of its operating revenue in any given year. The railroad has fallen on hard times in recent years as its freight business, which was once primarily from coal exports and the now-closed Flint Hills oil refinery in North Pole, has declined precipitously. Low oil prices have also slowed North Slope spending and correspondingly led to fewer equipment and material hauls on the rails for oil and gas projects. Now that a deal has been reached, the remarks from each side are much more measured. “We were able to get this land on terms that are attractive,” Berkowitz said. “The railroad is going through difficult financial times. The split, as configured, was very important to them.” He added that continuing the existing funding apportionment through 2018 allows the city and railroad to “find other ways of supporting each other” in the interim. Berkowitz’s first term as Anchorage mayor runs through June 2018. O’Leary noted that because the railroad is owned by the state, the property sale will have to be approved by the Legislature and railroad officials will be in Juneau next spring to make that happen. “I think this is a good thing for the municipality and the railroad to put behind us,” O’Leary said. Elwood Brehmer can be reached at [email protected]

BLM seeks input on opening entire NPR-A to leasing

The Bureau of Land Management wants to know if any more of the nearly 23 million-acre National Petroleum Reserve-Alaska should be open to development of its namesake resource. The Interior Department agency that oversees the NPR-A on the western North Slope is soliciting interest in the roughly 11 million acres former President Barack Obama’s administration made off limits to oil and gas leasing in 2013, according to an Aug. 7 press release from BLM’s Anchorage office. “Offering all tracts for nomination is in response to (Interior Secretary Ryan Zinke’s) order and will jump-start Alaskan energy production in the National Petroleum Reserve in Alaska,” acting Assistant Interior Secretary for Lands and Mineral Management Katharine MacGregor said in a formal statement. Zinke signed a secretarial order May 31 to initiate possible revisions to the 2013 NPR-A Integrated Activity Plan and update the oil and gas resource estimates for the NPR-A and the Arctic National Wildlife Refuge while at the Alaska Oil and Gas Association’s annual conference in Anchorage. MacGregor further said in her statement that the information gained from the solicitation will aid the department’s review of the current NPR-A land management policies “while protecting surface resources.” “Oil and gas lease sales help strengthen American energy independence, promote domestic energy production and support local job growth,” she said. MacGregor was appointed by Zinke in April to be the deputy assistant secretary for land and mineral management. She is in the acting assistant secretary position as the department awaits Senate confirmation of former Alaska Natural Resources Commissioner Joe Balash, who Zinke appointed to the post in July. BLM regularly asks for nominations on its annual fall NPR-A lease sales and the recent solicitation includes the 900 oil and gas tracts over the 10.3 million acres of the reserve that are open to leasing. Currently, companies hold 189 leases covering 1.37 million acres in the NPR-A, according to BLM. Industry interest in the NPR-A leases has waxed and waned over the years as federal land management policies have shifted and evidence of available oil and gas resources has evolved. The fact that only the far eastern fringe of the NPR-A has any oil and gas infrastructure has also made industry movement into the vast area very incremental. ConocoPhillips, in partnership with ARCO, is the only company to push entitrely into the federal area with its mid-sized Greater Moose’s Tooth oil projects currently under development and projected to total 60,000 barrels per day if both come online. The 2013 NPR-A land management plan prohibits leasing in much of the northeast part of the reserve to protect the Teshekpuk Lake caribou herd and waterfowl that breed in the area. State Department of Natural Resource Commissioner Andy Mack has said the state is also interested in protecting the Teshekpuk caribou — an important subsistence resource for residents of nearby villages — but that can be done while also strategically opening certain areas to leasing that are currently off limits. The December 2016 NPR-A lease sale drew a large amount of interest — again, primarily from ConocoPhillips — garnering $18 million in high bids on 613,000 acres mostly on its eastern edge. ConocoPhillips followed up its bidding activity with the January announcement of its Willow oil discovery in the eastern NPR-A, which the company estimates could hold 300 million barrels of recoverable oil with peak production of up to 100,000 barrels per day possible. Additionally, small independent Caelus Energy’s potentially massive Smith Bay oil find is in near shore state waters adjacent to northeast NPR-A lands currently off limits to leasing. Caelus estimates the prospect contains more than 6 billion barrels of oil in place. Elwood Brehmer can be reached at [email protected]

State gasline corp. gets favorable ruling from IRS

The Alaska Gasline Development Corp. has cleared another of many hurdles in its effort to monetize the state’s North Slope natural gas resources. The state-owned corporation announced Tuesday morning it qualifies as a federally tax-exempt political subdivision of the State of Alaska, according to a ruling it received from the Internal Revenue Service. AGDC President Keith Meyer said in a press release that the ruling will give the organization “significant maneuvering room” in how it can shape the financing structure for the $40 billion LNG export proposal. “This is great news for the corporation and the Alaska LNG Project. Receiving a favorable tax ruling from the IRS was one of the expectations of the transition of the Alaska LNG Project to state leadership,” Meyer said. Being labeled a “political subdivision” of the state means potential profits to the corporation from the project will not be subject to federal income taxes and AGDC can issue tax-exempt debt, according to the Tuesday release. Those prospective benefits were selling points to legislators skeptical of Gov. Bill Walker’s push to continue the project under state leadership. Under the previous project structure, which had BP, ConocoPhillips and ExxonMobil as equity partners with the state equal to their respective natural gas holdings, the companies concluded a flooded global LNG market and correspondingly low prices for the commodity would not allow the project to return profits at levels needed to make their investments worthwhile. As a result, the major North Slope producers suggested either slowing the design phase of the project until market conditions improved or handing it to the state to see if AGDC could make it work with the state’s tools. Meyer has said the Alaska LNG Project — with multibillion-dollar gas treatment and LNG plants on the North Slope and Kenai Peninsula and an 800-mile buried gas pipeline connecting the two — would be primarily debt-financed on the back of customer commitments and would not obligate the State of Alaska to repayments if it went sour. A copy of the five-page letter dated July 18 states AGDC is a political subdivision of the State of Alaska and therefore does not have to file a federal tax return. It does not specify whether or not partnering with private firms on the project, or partial private investment in Alaska LNG, would impact the project’s tax status. In setting the facts the opinion is based on, the letter asserts AGDC stated it may enter into “arm’s-length” natural gas or LNG sale contracts and tolling arrangements with private entities. About a year ago an executive from the global energy industry consulting firm Wood Mackenzie said during legislative hearings that a project not subject to federal taxes under a state-owned gas tolling model as proposed by AGDC could be competitive at current energy market prices; however its ultimate success would be dependent upon a number of other factors as well. Wood Mackenzie’s Dave Barrowman estimated the previous equity-owner model with high returns for the producers would require contracts with Asian buyers for LNG priced to at least $12 per million British thermal unit, or mmBtu. A traditional third-party owned tolling structure with lower investment returns could be profitable at approximately $7 per mmBtu and a state-owned, tax-free project could be economic selling LNG at $6 per mmBtu, according to Barrowman. His assumptions were made on wholesale natural gas being sold into the project at about $2 per mmBtu. The three Slope gas owners have all said they would sell gas into the project on mutually agreeable commercial terms. Tax attorneys testified in the same hearings that while AGDC could be considered a political subdivision of the state, actually capturing tax-exempt status could be more problematic. The corporation could be required to demonstrate other sovereign powers to be recognized by the IRS as above federal taxes beyond just being state-owned, they testified. To that end, AGDC holds the state’s eminent domain powers, according to the IRS opinion. The municipally-controlled Alaska Gasline Port Authority, formerly led by Walker, also received a similar political subdivision determination from the IRS in 1999 but was unable to advance a gasline. ^ Elwood Brehmer can be reached at [email protected]

State gives conditions for ConocoPhillips to explore Tofkat leases

ConocoPhillips is on the clock again for North Slope leases it gave up years ago and has spent the better part of the last two trying to get back. Department of Natural Resources Commissioner Andy Mack issued a decision Aug. 3 giving the oil major another shot at a relatively small piece of sought-after acreage tucked between the company’s large Colville River field and Armstrong Energy’s massive and ever-growing Nanushuk oil discovery. The catch is ConocoPhillips has until Aug. 14 to agree to Mack’s decision, which comes with a long list of contingencies. In February, Mack reversed his previous ruling and denied ConocoPhillips’ application to have 22 leases totaling about 9,100 acres in the now-defunct Tofkat Unit transferred from small independent Brooks Range Petroleum Corp. Mack’s February reversal was due to ConocoPhillips not drilling an exploration well in the acreage this past winter as it had told DNR it would as a condition for approving the transfer. ConocoPhillips Alaska officials appealed the decision, contending they did not drill because residents of the Native Village of Nuiqsut — located inside the area in question — were concerned about diesel exhaust from the drilling rig drifting into the community, which is just a few miles from the chosen exploration site. The rig would have been working continuously for several weeks about three miles in the direction of the prevailing winds from the village. As a result, Nuiqsut residents asked the company to look for a new place to drill. The oil company has a longstanding surface use agreement with Kuukpik Corp. that predates the current iteration of ConocoPhillips — a company that is today the result of multiple mergers of other large oil and gas companies. Kuukpik is the Alaska Native village corporation for Nuiqsut that owns surface rights around the village. Thus, by honoring the residents’ request, ConocoPhillips appeared to be reneging on its commitment to DNR, which is obligated to do its part to ensure the potential oil resource is developed. The company also argued Mack’s decision did not accurately recount discussions between it and DNR and he did not give the company a fair hearing before making the ruling. Mack stated in the document released Aug. 3 that the “due process arguments are unfounded” and bluntly rebutted several other claims by ConocoPhillips raised throughout the lengthy process. “While ConocoPhillips Alaska’s request for reconsideration (to the February decision) largely consists of legal and policy arguments that are mostly unfounded and thus did not factor into the commissioner’s reconsideration, because these arguments were raised and are somewhat troubling, DNR is providing responses to those arguments,” he wrote. DNR is not obligated to provide the company a hearing before issuing such a decision either through the Colville River Unit agreement or department regulations, according to Mack. He wrote further that ConocoPhillips’ claim that he made his February decision based on an incomplete record is erroneous because it is the applicant’s duty to support its request. The company also contradicted itself in documents it submitted to the department; citing meetings between officials in one instance and claiming Mack did not discuss his concerns with its application in another, he continued. “If there were additional or different facts that ConocoPhillips Alaska wanted the commissioner to consider, ConocoPhillips Alaska could have amended its application to provide those facts,” Mack wrote. Brooks Range Petroleum was unable to develop the area because it could not secure a land access agreement with Kuukpik Corp. The state and Arctic Slope Regional Corp. share subsurface rights, but the state holds ultimate decision-making authority if it consults with ASRC, a key part of a 1991 court settlement to resolve a court dispute. To that end, a DNR release that accompanied the decision states that ASRC will also have to agree to the terms of the decision if oil exploration of the area is to progress. “It’s important for the State of Alaska to find common ground with our oil industry partners and local stakeholders as we work to bring much-need oil to the trans-Alaska pipeline,” Gov. Bill Walker said in the DNR release. “To get the full benefit of the decision, at least 80 percent of the hires must be Alaskan. ConocoPhillips has a strong record of training and hiring Alaskans. Because jobs in Alaska should go to Alaskans, my team and I will continue to ensure strong local hire provisions on this and other projects.” Kuukpik CEO Lanston Chinn said the corporation, in representing Nuiqsut, continues “to seek a fair and balanced approach towards any oil and gas activity.” Similarly, ASRC spokesman Ty Hardt wrote in an email that the company will be discussing any potential concerns with the residents of the village, who are its shareholders as well. Mack said in an interview that the state certainly values the concerns of Nuiqsut residents, but it will continue to focus on advancing its interests regarding the former Tofkat area as any potential remaining issues between Kuukpik and ConocoPhillips regarding the location of drilling activity is a matter between two private parties. According to DNR, ASRC must also approve of the decision as a joint resource owner in the area. “We have executive rights under the (1991) decision, but they are certainly a resource owner in every sense and we view them as a really important partner in this process and when we go to make decisions about units which are affected by the settlement decision, ASRC is also an entity that approves those unit decisions,” Mack said. “This is applied across almost every decision we’ve made with the Colville River Unit since its inception.” ASRC objected to DNR’s prior attempts under former Commissioner Marty Rutherford to put the leases in question up for bid in a lease sale, alleging the state had not fulfilled its responsibilities to consult with the Native corporation on the issue. In late June 2016 ASRC subsequently informed the department it would transfer its share in the leases to ConocoPhillips regardless of what the state decided. ConocoPhillips held the acreage in the early 2000s but had to give it back to the state after failing to meet drilling requirements. (At the time, ConocoPhillips referred to the area as Titania, a fairy queen character in William Shakespeare’s play “A Midsummer Night’s Dream.” Subsequently, Tofkat is an acronym for: The Opportunity Formerly Known As Titania.) Mack’s most recent ruling gives ConocoPhillips the opportunity to add the Tofkat area to the Colville River Unit if it drills a well into the Nanushuk formation by May 31, 2018. If the company drills the well and wants to keep pursuing the prospect it will have to make a $3 million bid replacement payment to DNR by Aug. 15, 2018, in-lieu of the money the state would potentially get for putting the leases up for sale. ConocoPhillips would additionally have to commit to drilling a second well by the spring of 2020. If the company decides to further develop the area after 2020 and bring it to production, ConocoPhillips would need to make another $4 million bid replacement or employ at least 15 percent North Slope residents and 80 percent Alaskans on the project. Achieving the Alaska hire requirements would cut the $4 million bid replacement to $3.5 million. The total payment amount of up to $7 million was based on the winning bids for recently leased acreage nearby, which went for between about $1,000 and $3,500 per acre, according to the decision document. Mack wrote that $7 million is appropriate for the size of the area, particularly when a deduction for ConocoPhillips’ ability to hopefully bring it into production quicker than a new lessee is factored in from the state’s perspective. Failing to meet any of the aforementioned requirements, or deciding not to develop the leases, would terminate the Colville River expansion and the company would return the leases to the state, per Mack’s decision. ConocoPhillips spokeswoman Natalie Lowman said the company is reviewing the document and she couldn’t comment further at this time. Mack’s February ruling gave ConocoPhillips the option to make good on its promise and still drill the well last winter, which included putting up a $2.5 million performance bond that DNR would return upon completion, but that was also a tight timeline on which to drill from an ice pad before spring. ConocoPhillips did not agree to those terms and instead filed a request for reconsideration. A prior 2016 ruling from former Oil and Gas Division Director Corri Feige denied the lease transfer on the grounds that it was in the state’s best interest to put the acreage up for bid in a lease sale, start fresh and gain potentially millions of dollars in bid revenue. Mack eventually overruled Feige on the premise ConocoPhillips would be drilling early in 2017. ^ Elwood Brehmer can be reached at [email protected]

Unpaid credits lead to pause in BlueCrest drilling

BlueCrest Energy Inc. is preparing to pause drilling work at its Cook Inlet oil development because the State of Alaska owes the company about $75 million in refundable tax credits, but CEO Benjamin Johnson said he hopes the hiatus will be short-lived. Fort Worth, Texas-based BlueCrest is the sole owner and operator of the Cosmopolitan oil project on the edge of the Inlet near Anchor Point on the Kenai Peninsula. The company is currently drilling a lengthy production well, which is close to done and should be ready to flow oil sometime in September, Johnson said. Once that well is done and mechanical repairs are made to the first well BlueCrest finished drilling early this year, the company will be forced to suspend drilling operations until alternative financing can be secured. That will impact the roughly 300 BlueCrest and contract drilling employees that are currently working at the site, according to Johnson, but he hopes only temporarily. “We were hoping we could squeak by and make it without any additional tax credits; we’re working to try and avert that (drilling stoppage),” he said in an interview. “Hopefully in the best case we’re pausing briefly, only for a month or two, on the drilling. It might be longer; we just don’t know.” The state has paid BlueCrest $27 million in tax credits since the company purchased the project in 2012, but the company now holds about $75 million in refundable credit certificates and expects to earn another $15 million for eligible drilling and development work done at Cosmo before July 1, Johnson added. The Legislature passed House Bill 111 July 15 with a retroactive effective date to end the North Slope and Cook Inlet oil and gas tax credit programs July 1. Gov. Bill Walker signed HB 111 into law July 27. With drilling work and production facilities, Cosmopolitan is about a $525 million project overall, he said further, meaning the company has invested about $400 million of private capital. Walker has taken significant heat from industry representatives and many Republicans in the Legislature for vetoing a total of $630 million of tax credit payments in 2015 and 2016, contending the state could not afford to spend the money and further drain savings dwindling from years of ongoing budget deficits in the $3 billion range. The governor has also said repeatedly he would be willing to start paying off the obligation as soon as the Legislature passes a plan to resolve the deficits and put the state on more solid financial footing. However, it was some of those same Republicans in the Senate that proposed the immediate end to the program. And this year the Legislature appropriated just $77 million — the statutory minimum — to pay down the $700 million-plus obligation. Walker sponsored legislation passed last year to phase out the credits in Cook Inlet over several years, but HB 111 finished off the program sooner. Also because of unpaid tax credits, , BlueCrest also received modifications last December to a $30 million loan it took out with the state-owned Alaska Industrial Development and Export Authority for its powerful drilling rig with a 30,000-foot reach. The AIDEA board of directors unanimously approved the minor loan changes. Johnson said his company will have no problem making the monthly payments on the loan, noting the rig — presumed to be the largest onshore drill in the state — has a value far exceeding the loan amount; AIDEA also has exclusive title to the rig, according to loan documents, which cost about $40 million to build and get to Alaska. BlueCrest and other companies holding oil tax credits could sell their certificates at a reduced rate to the large North Slope producers that could use them against their own production taxes, but the viability of that market is unclear, particularly given low oil prices have dramatically cut down on producers’ state net profits-based production taxes. While his company is trying to move ahead on further drilling with or without the credits, Johnson said they were imperative in drilling the company’s first $45 million offshore well in 2013 that proved up the Cosmo field. The above ground portion of BlueCrest’s Cosmopolitan project is onshore; however the angled oil wells are aimed at an oil pool that is about three miles offshore and 7,000 feet underneath Cook Inlet. BlueCrest is currently producing less than 200 barrels of oil per day from a previous exploration well drilled by ConocoPhillips in 2001. That well has mechanical plugs that have prevented additional oil flow, according to Johnson. The well completed early this year also needs repair after a service company’s part broke, he said, and that work should be done fairly quickly with the rig after the current drilling is finished. When the two new oil wells come online Johnson said they should each exceed the 1,000 barrels per day of production the company originally expected. He is clearly excited about Cosmo’s potential, saying there is enough oil to continuously drill there for at least seven years. “We’ve drilled all the way across the reservoir and we have confirmed that literally every inch of it is productive — is good rock, has oil saturation — so it’s just a matter of getting these wells to flow the oil out,” Johnson said. “There are many hundreds of millions of barrels of oil in the ground, absolutely confirmed. The question is what percentage of that do we get and how fast will it come.” The Cosmopolitan field also contains a large natural gas cap, but limited local demand and shifting state tax policy have delayed BlueCrest’s plans to develop it via an offshore platform, company officials have also said. Elwood Brehmer can be reached at [email protected]


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