Elwood Brehmer

Walker looks to Legislature to finally use Fund to fix budget gap

A paramount year is shaping up for Alaska. The state is on the precipice of turning to the Permanent Fund for government revenue in addition to its previous sole outlays for dividend payments. The fate of the Alaska LNG Project will likely be known by the year’s end. Another battle is brewing between conservation and development interests, this time over salmon habitat protections. And it’s an election year. Gov. Bill Walker discussed a few of the year’s pressing topics in a Dec. 22 interview with the Journal. For the first time, Walker’s fiscal year 2019 budget proposal released Dec. 15 includes a 5.25 percent of market value, or POMV, draw from the Earnings Reserve of the Permanent Fund to fill the lion’s share of the deficit expected to be roughly $2.5 billion. The POMV provision is written as a compromise to the Earnings Reserve draw formulas in versions of Senate Bill 26 from the House and Senate, which are awaiting a conference committee resolution after being approved by the bodies last spring, according to Walker. The governor said he is comfortable using the one-time draw language in the operating budget bill as a fallback funding mechanism in the event the Legislature does not approve a long-term formula draw. “What we did is about the best we could get out of (SB) 26,” Walker said, noting the POMV structure avoids the undisciplined “ad hoc” draw from the Fund that he has persistently warned against. The 5.25 percent draw on the value of the Fund reflects the Senate’s larger draw amount (the House used 4.75 percent), while the $818 million dividend appropriation from it — enough for about $1,200 per Alaskan — is closer to the PFD approved by the House. “We’re meeting the intent of what we had introduced and hopefully it will be wrapped up this year,” he added. The Constitutional Budget Reserve is on course to hold about $2.6 billion on June 30 at the end of fiscal year 2018, according to the Office of Management and Budget. That could be enough to cover another deficit year but it would leave the state with no financial wiggle room. And with little argument from legislators that the state needs at least $1 billion in accessible savings for cash management and emergencies, it appears the Permanent Fund will finally be employed to pay for part of government in the coming legislative session, something Walker has been pushing for since late 2015. Walker said he’s saddened the state has had to spend roughly $14 billion from its once bountiful savings accounts to cover budget deficits since 2013 while politics has delayed what is becoming inevitable. Echoing numerous Alaska economists, he said he believes the length and severity of the state’s recession has been self-inflicted by inaction from the Legislature. The state’s credit rating has also been downgraded several times from the once top AAA to now the third-lowest among all states. “I had certainly hoped that early on they would recognize that we need to make adjustments and be done with it. In my opinion we don’t have to be where we are,” Walker said. He continued to say that waiting to utilize the Fund as a revenue source has “created this fear of uncertainty that is felt all the way from car dealerships to homebuyers and on. That’s the part that’s disappointing to me. We didn’t have to be in this recession as long as we have been.” Alaska is starting the third calendar year of the current recession with the highest unemployment rate in the country at 7.2 percent, according to the state Labor Department. The lack of savings could also end up impacting how much, if any, the state can directly invest in the $43 billion Alaska LNG Project. That’s because under the Alaska Gasline Development Corp.’s financing outline for the massive gasline project, about 75 percent of the cost would be funded with debt underwritten by customer contracts. The remaining 25 percent, or about $11 billion, would be filled by equity investors, which could include the State of Alaska. AGDC projects the state would take in about $250 million per year from the project without an equity investment but that’s a much smaller revenue stream than the multibillion dollars per year of revenue to state coffers once envisioned. However, that does not account for the layered benefits the project could bring to the state’s economy aside from basic government revenue such as jobs and cheaper energy. Without savings to rely on, there does not seem to be a direct way for the state to buy into the project. Walker said it’s probably a little early in the project’s development to single out a way for the state to invest in Alaska LNG as a final investment decision is not expected for about a year, but said the state could sell its equity share or use debt to fund it. “It really will be defined as the project is put together,” he said. “It depends on where we are financially as a state.” That said, the governor also noted the state has public retirement funds of more than $25 billion that could find the project to be a sound investment. Having the state invest in some fashion could take risk out of the project and help assure other potential investors that it will be seen through, indirectly helping its economics, according to Walker. Yet, he does not expect state investment managers to accept a lower return from Alaska LNG just to get the state’s participation. “If they’re going to get a regulated return somewhere in the Lower 48 and they can get the same return in Alaska I would hope they would bet on their home team a bit,” Walker said. And while interested groups on both sides wait to see how the Alaska Supreme Court will handle the Stand for Salmon ballot initiative, Walker said he doesn’t like the idea of using the initiative process, which he described as “a fairly blunt instrument,” to make policy changes. The initiative is aimed at strengthening state salmon habitat protections and giving the Department of Fish and Game more authority to limit the impacts development projects could have on that habitat. Lt. Gov. Byron Mallott originally rejected the proposed initiative based on an opinion from the Department of Law that it would direct state water resources to fish habitat, taking that resource allocation authority away from the Legislature and thus violate the state constitution. After a successful appeal by the petitioners got Mallott’s ruling overturned in Superior Court in October, the state subsequently appealed to the Supreme Court, which has not revealed when it will handle the matter. If the high court upholds the lower court ruling, it could appear on the upcoming 2018 ballot. Sponsors are currently gathering signatures to qualify for the ballot. Walker said the initiative is too broad in its scope and it could hamper nearly every area of project development in the state, which would include the Alaska LNG Project. “I think when you’re making definitions that impact development of projects in Alaska and you do that through the initiative process — I was very concerned about that,” he said. “I would like there to be a discussion back and forth; hearings in the appropriate hearing rooms in Juneau and various folks being able to weigh in.” House Bill 199, currently in the House Fisheries Committee, mirrors the initiative language, but Democrat House Speaker Bryce Edgmon has said he does not see it passing this year, or its current form, given the consternation the initiative has caused. Elwood Brehmer can be reached at [email protected]

New plays add 8.7B barrels to NPR-A oil estimate

And back the pendulum swings. U.S. Geological Survey again officially believes it is likely the National Petroleum Reserve-Alaska holds billions of barrels of recoverable oil, according to its updated resource assessment released Dec. 22. Specifically, the federal geologists estimate the mean undiscovered conventional and recoverable oil resource in the 23 million-acre NPR-A and adjacent state and private lands to be more than 8.8 billion barrels, with a 95 percent chance there is at least 1.7 billion barrels in place and a 5 percent probability the area holds more than 21.8 billion barrels of oil. Interior Secretary Ryan Zinke, who ordered the updated assessment while on a trip to Alaska last May, said it is a big step towards what has become his catchphrase of sorts, “American energy dominance.” “Thanks to the incredible work of scientist at the USGS and (the Bureau of Ocean Energy Management), we know what’s available and what our potential is,” Zinke said in a formal statement. “New discoveries have changed our geologic knowledge of the area and these assessments show that the North Slope will remain an important energy hub for decades to come in order to meet the energy needs of our nation.” BOEM, which manages oil and gas activity in federal waters, contributed data from nearby offshore areas to the resource estimate, according to an Interior Department release. The members of Alaska’s congressional delegation similarly said the new numbers are good news for the state and prove now is a prudent time to invest in Arctic energy development. “Just as we have always known, this assessment shows that the NPR-A has significant potential and will remain a big part of our energy future,” said Sen. Lisa Murkowski, who chairs the Senate Energy and Natural Resources Committee. “I thank Secretary Zinke for traveling to this area with me earlier this year, for directing USGS to update its resource assessment and for working with Alaskans on a better plan for responsible development.” While the Republican delegation insists the new NPR-A oil estimate is further proof the industry should be encouraged to explore the state-sized area, the assessment is the latest in a series in which oil projections have varied wildly. A 2002 assessment, completed after what is now ConocoPhillips discovered the large Alpine oil field on state and Native corporation lands near the eastern edge of the NPR-A, put the mean undiscovered oil resource at 10.6 billion barrels, with a 95 percent probability of there being at least 6.7 billion barrels available. Current USGS Senior Research Geologist David Houseknecht has said the 2002 estimate was based on the presumption that the oil charge in the Alpine formation stretched far to the west across much of the NPR-A. Houseknecht led or participated in the drafting of similar assessments of the NPR-A in 2002 and 2010 and the Arctic National Wildlife Refuge coastal plain in 1998, and is well regarded by many geologists who have studied the North Slope. However, subsequent exploration efforts revealed the oil quickly turned to natural gas pools, putting a damper on industry’s excitement at the time. The fizzled Alpine play in part led to a drastically reduced mean estimate of just 896 million barrels in the 2010 NPR-A assessment. “Recent activities in NPR-A, including extensive 3D seismic surveys, six federal lease sales totaling more than $250 million in bonus bids, and completion of more than 30 exploration wells on federal and Native lands, indicate in key formations more gas than oil and poorer reservoir quality than anticipated,” the 2010 assessment states. “In the absence of a gas pipeline from Alaska, exploration has waned and several petroleum companies have relinquished assets in the NPR-A.” What hasn’t changed much is the belief there is a massive amount of natural gas beneath the western North Slope. The most recent assessment contains the smallest mean estimate for gas quantities at 39.2 trillion cubic feet, which is slightly more than the 35 trillion cubic feet of known gas reserves at Prudhoe Bay and Point Thomson that would supply a large gasline and LNG export project. The big change on the oil side has been the Brookian revelations in and around the NPR-A. The large Nanushuk formation discoveries by the Armstrong Energy-Repsol partnership on state lands just to the east and ConocoPhillips’ Willow find within the reserve together total more than 1.5 billion barrels of confirmed and recoverable oil, according to the companies. Additionally, Caelus Energy’s Torok formation oil prospect at Smith Bay — in state waters of the Beaufort Sea just offshore from the NPR-A — holds roughly 6 billion barrels of oil, the company estimates. The Nanushuk and Torok sand formations are part of the Brookian geologic sequence and generally hold oil pools in more subtle stratigraphic traps that until recently have largely been overlooked. Slope geologists say advanced 3D seismic has made it easier to identify the traps. Nearly all of the 8.7 billion barrels of oil added to the new mean assessment are expected to come from the Nanushuk and Torok formations. Houseknecht said during a November presentation in Anchorage that the companies focusing on the Brookian plays have mostly been forthcoming with proprietary seismic and drilling results, which helped greatly in drafting the assessment. Zinke’s order did not include funding for the agencies to gather new data. An updated resource assessment for the newly-available ANWR coastal plain, also part of the Interior directive, should be on its way soon as well. However, Houseknecht and others have noted that the lack of any new geologic information for the costal plain will make it difficult for scientists to make drastic improvements on the latest ANWR assessment, done in 1998. That one estimates a mean undiscovered resource of 7.6 billion barrels and was done mostly using data collected in the mid-1980s. More than 7 billion barrels of the new oil estimate is expected to be in the northeast corner of the NPR-A, most of which was closed to oil and gas leasing by the Bureau of Land Management in the 2013 NPR-A Integrated Activity Plan. The area was put off limits to industry to protect subsistence activities and critical habitat for the Teshepuk Lake caribou herd. Environmental groups speculated when Zinke directed the assessment that it would be used as justification to open the protected area to industry. The BLM — now overseen by former Alaska Natural Resources Commissioner and current Assistant Interior Secretary Joe Balash — offered up all of the areas open to leasing in the NPR-A in its Dec. 6 lease sale. Regardless of the changes to the speculative assessments, ConocoPhillips has been plugging away on its Greater Mooses Tooth projects to the south of the currently set aside Teshepuk Lake area in the reserve. GMT-1, which the company is building this winter, is expected to start producing oil late next fall. It would be the first production on true NPR-A lands. The company’s CD-5 development started producing in 2015 but is on Native corporation in-holdings within the reserve boundary. The GMT-2 project, now in permitting, is planned to come online in a few years. Each of the roughly $1 billion projects is expected to produce about 30,000 barrels per day at its peak. ^

Pebble finally files for permits

The Pebble Limited Partnership has long been criticized for many things, but as of Dec. 22 that list no longer includes failure to file for environmental permits. Pebble and its Vancouver-based parent company Northern Dynasty Minerals filed for a Clean Water Act Section 404 wetlands fill permit with the U.S. Army Corps of Engineers. Alaska Army Corps officials said Dec. 21 that the wetlands fill permit application detailing the types and volumes of fill material the project will use and the area of wetlands it is expected to cover would first be subject to a 15-day completeness review. If the wetlands application is deemed complete the Corps will then issue a public notice saying as much and — given the size of the project — issue a subsequent determination that the project needs to go through the full, multi-year environmental impact statement process. Northern Dynasty leaders said early in 2017 they planned to start permitting for the wildly controversial project by the end of the year, a promise that was met with understandable skepticism. They made good on it with nine days to spare. Pebble Partnership and its ownership groups, which have varied over the years, had consistently been faulted for making numerous claims dating back to 2005 that they would soon start the environmental reviews. The permitting process is also seen as one way to eventually provide closure for those on each side of the contentious debate over whether the world-scale mine proposed at the headwaters of a world-scale salmon fishery is appropriate. “For the Pebble team, this day has been a long time in the making and is the result of a tremendous amount of hard work,” Pebble CEO Tom Collier said. “We have listened to our stakeholders, supporters and skeptics, and are presenting a much smaller mine with enhanced environmental safeguards. Since I have been with the project, my main focus has been to initiate the permitting process so that Pebble can be fairly and objectively evaluated by the independent experts hired by the Corp of Engineers.” In 2014, the Environmental Protection Agency proposed blocking Pebble based on a larger mine concept outlined in financial disclosure filings by Northern Dynasty. Shortly thereafter Pebble Partnership sued the EPA, claiming the agency’s actions were made on a biased, anti-mine premise and that it illegally colluded with opponents of the project. That suit was settled in May and because the EPA is currently evaluating public comments on whether to lift the proposed determination that would prohibit the project. With a total mine facilities footprint of 5.4 square miles, the new plan is less than half the overall size contemplated by the EPA but still larger than the 4.2-square mile footprint the agency said could be acceptable. In statements issued shortly after Pebble’s announcement, opposition groups said the permit filing changes little, other than renewing determination to stop the project. “It took Pebble Limited Partnership 12 years just to file the paperwork asking the Army Corps to look at this project,” Bristol Bay Economic Development Corp. CEO Norm Van Vactor said. “The bar is set very low, indeed, if merely filing an application is cause for celebration. Bristol Bay fishermen file paperwork for their permits every single year, without fanfare. And here in Bristol Bay, we will choose our sustainable commercial fishery that generates thousands of jobs over a short-term development project.” A few days earlier on Dec. 18, Northern Dynasty issued a statement saying it is close to finalizing a deal with fellow Canadian mining firm First Quantum Minerals for investment in Pebble. Northern Dynasty is the sole owner of Pebble after previous partners Anglo American and Rio Tinto walked away from the controversial copper and gold project several years ago. In the case of Anglo American, the company ended its partnership on the project in 2013 after spending $541 million on exploration. Since then, company officials have acknowledged the need for a large investment partner to fund Pebble’s development. Under the terms released of the preliminary deal, First Quantum would contribute $150 million to Pebble over up to six years with a $1.35 billion option to buy a 50 percent stake in the project. In a Dec. 21 interview Collier said he expects to have the partnership finalized by the middle of next year. Collier said his company doesn’t yet have a solid cost estimate for the scaled-back mine plan he unveiled in October, but that would materialize as permitting plays out. Elwood Brehmer can be reached at [email protected]

Major Alaska resource projects face crucial year in 2018

The upcoming year will be a telling year for several of Alaska’s prospective development projects, starting with the biggest: the $40 billion-plus Alaska LNG Project. That’s not to say the state-owned Alaska Gasline Development Corp. did not produce any accomplishments in 2017. After taking control of the LNG export effort to start the year, AGDC promptly submitted its environmental impact statement application — nearly 60,000 pages of scientific and socioeconomic information — in April. Agency officials believe it to be the largest single EIS filing in the history of the National Environmental Policy Act review process. AGDC leaders have stressed their desire for Federal Energy Regulatory Commission, or FERC, to have a final EIS published by the end of the year, with a record of decision following shortly thereafter. Getting the EIS done in the next year would go a long way towards keeping AGDC on schedule for the early 2019 final investment decision that corporation President Keith Meyer says is critical to hitting the available Asian market window for LNG deliveries to start in 2024 or 2025. Meyer and his team point to the size of the filing as evidence of its thoroughness, which should help the federal regulators expedite their evaluation. AGDC officials and Gov. Bill Walker also note the Trump administration’s support of the project and several actions the administration has taken to speed federal permitting for infrastructure development. While FERC is known to process permit applications quicker than most other regulatory agencies, the EIS schedule that AGDC had requested be published by Dec. 15 at the latest still isn’t public; FERC continues asking the corporation for additional information, or follow-up questions, on its application. As a result, it’s still anyone’s guess as to when the first draft EIS, which comes with a 45-day public review and comment period, will be published. Similar timing questions remain on the commercial side of the Alaska LNG Project as well. The highly publicized, touted and critiqued joint development agreement Meyer and Walker signed with three giant Chinese corporations interested in partnering on Alaska LNG Nov. 9 in Beijing calls for the sides to have a framework agreement in place by the end of May 2018. The concept is that AGDC would essentially trade 75 percent of the project’s capacity, up to 20 million tons of LNG per year, to Sinopec in exchange for 75 percent of the project’s financing from the Bank of China and the China Investment Corp. That outline would then be turned into a firm contract in the second half of the year. The nonbinding joint development agreement expires Dec. 31, 2018. Sinopec is one of the world’s largest oil and gas companies. It, and the financial firms are nationalized companies owned by the Chinese government. The status of other nonbinding Alaska LNG memorandums of understanding signed in 2017 with Korea Gas Corp., Tokyo Gas Corp. and PetroVietnam Gas Corp. is less clear because AGDC, citing commercial sensitivity, has kept their contents confidential. The Alaska LNG Project will also undoubtedly play a leading role in the 2018 gubernatorial election. Walker will highlight the state’s stewardship of the project — the regulatory achievements and customer interest. If it appears to be moving well his opponents will acknowledge his progress but claim to alternative or cheaper development plans that will return more money for the state. And if the project struggles in the coming months they will call for its stoppage or outright demise, repeating in some form the question: “Why is the state still spending the gasline when BP, ConocoPhillips and ExxonMobil decided not to?” To that end, AGDC has not asked for any new state money in fiscal year 2019. The governor’s 2020 state budget proposal will be out on Dec. 15 of next year. Oil projects North Slope production is expected to keep climbing in 2018, with state officials estimating an average of 533,000 barrels per day for the fiscal year that runs through June 30. Additionally, the status of the two biggest oil projects on the North Slope should become clearer in the coming year. Armstrong Energy’s 1.2 billion-plus barrels Nanushuk prospect will be handed over to Australian-based Oil Search, as part of an up to $850 million buyout announced last fall. The companies’ leaders said in an interview following the announcement that the deal is a way to continue expeditious development of Nanushuk, estimated to be upwards of $5 billion, which is too large for the exploration-focused Armstrong to manage. The Army Corps of Engineers released its draft EIS for the project in September and a final evaluation is forthcoming. First oil from Nanushuk is expected in the early 2020s. Similarly, a final EIS is the next big step for the long-discussed Liberty offshore oil project. Designed as a manmade island development in the near shore federal waters of the Beaufort Sea, Hilcorp Energy estimates Liberty could produce up to 70,000 barrels of oil per day, following in the path of other successful North Slope artificial island projects currently in production. Nearby and onshore, Hilcorp is continuing to build out Milne Point, one of the fields it bought into as part of a $1.25 billion deal with BP in 2014. The company recently drilled 10 wells at Milne Point that are just starting to come online, according to Hilcorp Alaska leaders, and plans to start drilling another 50 to 70 wells next fall and try a polymer flood project to ultimately produce between 30 million and 50 million barrels of oil from Milne Point. In Cook Inlet, Hilcorp is also in the midst of spending $75 million to convert a cross-Inlet natural gas pipeline to an oil carrier, a project it plans to finish in about a year, company officials have said. With other requisite work to adjust gas and oil flow on the west side of the Inlet, the project will allow Hilcorp to close the Drift River oil tank farm, which has been a lingering environmental concern to many because of its location at the base of Mt. Redoubt, an active volcano that most recently erupted in 2009 and caused flooding at the facility. The oil transport line will also reduce oil tanker traffic in the Inlet. Mining While each of Pebble Limited Partnership’s activities will continue to dominate headlines, the fate of another massive mine proposal to the north should be known a lot sooner. A final EIS for the Donlin Gold megaproject in the upper Kuskokwim River valley is expected early in 2018. As planned by the company, Donlin would produce about 1.1 million ounces of gold per year over a 27-year mine life for a total of about 33 million ounces of the precious metal. The mine site, on lands owned by The Kuskokwim Corp. and Calista Corp., the area village and regional Native corporations, respectively, would also include a fully lined, 2,300-acre tailings facility to store the processed ore. Support infrastructure would include a 315-mile, 14-inch diameter natural gas pipeline originating on the west side of Cook Inlet needed to supply fuel to the 227-megawatt capacity power plant at the mine site. The pipeline has also been viewed as a first, indirect step to getting lower cost natural gas to numerous villages in Western Alaska that currently rely on fuel oil their primary heat and electricity sources. A 30-mile road would connect the mine to a new barge port on the Kuskokwim. Further down the Kuskokwim, port cargo facilities would be expanded in Bethel, and new diesel storage tanks would be needed Dutch Harbor to supply fuel for equipment at the mine. Regardless of Donlin’s fortunes in permitting, Donlin Gold leaders acknowledge the project is more sensitive to gold prices than even other Alaska prospects simply because of its associated infrastructure costs. Company officials have said the project would not be economic at gold prices of about $1,100 per ounce. Gold currently sells for about $1,280 per ounce in spot trading. On Pebble, 2018 is likely to be largely a wait-and-see year. Folks on all sides of the mine debate will see if Pebble’s owner, Northern Dynasty Minerals, can finalize the framework investment deal it announced with fellow Canadian mining firm First Quantum Minerals. First Quantum said in a release it is doing its due diligence to review the project and its potential investments — $150 million to support permitting or $1.35 billion for 50 percent of Pebble — while Northern Dynasty admits it can’t develop the project itself. On the permitting side, Pebble’s Dec. 22 wetlands fill permit application with the Corps of Engineers, which will trigger an EIS, kicked off what is sure to be a three to five-year, or more, review. Pebble CEO Tom Collier said in an interview that the company believes its thorough background study work means the EIS can be done in three years, but Corps officials note the average EIS time for a project the size of Pebble is four to five years. Pebble would undoubtedly like to get the EIS done before the next presidential election in the event a new administration might try to put more restrictions on development. As for revoking its prior proposed Clean Water Act Section 404(c) prohibition on Pebble, the Environmental Protection Agency is reviewing the mountains of comments it received on the policy change, spurred by its court settlement with the Pebble Partnership. The EPA’s tally is not yet known, but Pebble opponents claim more than 750,000 comments were submitted in support of stopping the project. What the EPA will do with the proposed reversal of its original proposal is also unknown. The agency could make a political statement and finalize its move to revoke the Obama administration’s proposed mine veto or, since no substantive action was taken against Pebble, simply leave it in limbo and let the permitting process play out. Salmon habitat initiative The Stand for Salmon citizen-driven ballot initiative to significantly tighten the state’s salmon habitat permitting laws is sure to be 2018’s version of Alaska’s omnipresent development versus conservation debate. That is, if the state Supreme Court allows it to be. The state Department of Law, at the behest of Lt. Gov. Byron Mallott, appealed an October Superior Court ruling to uphold the initiative and that appeal is currently before the Supreme Court. There is no indication as to when the court may or may not hear and rule on the case. Mallott originally rejected the proposed initiative based on Law’s opinion that it would direct state water resources to fish habitat, taking that resource allocation authority away from the Legislature and thus violate the state constitution. The petitioners are currently hustling to gather the roughly 32,000 signatures they need from voters by mid-January to get it on the 2018 ballot while everyone waits to hear from the Supreme Court. If the initiative is upheld in court, it is likely to galvanize Alaska’s development proponent groups, which have already formed their own counter-measure campaign, Stand for Alaska, to raise money to fight the initiative. Opponents contend the proposal, aimed to give the Department of Fish and Game more authority in permitting large projects, would make even many small developments unworkable and cost-prohibitive. Stand for Salmon leaders counter that they are just pushing the reforms requested by the Board of Fish in January 2017 to update the state’s vague and decades-old salmon habitat protection statute. Gov. Bill Walker opposes the initiative, saying its scope is far too broad, and if upheld in court it will be another topic amongst gubernatorial candidates. And even if the petitioners don’t gather the signatures they need in time for the 2018 ballots, that just means it could resurface in 2020 — again, assuming the Supreme Court stays with the lower court ruling. Elwood Brehmer can be reached at [email protected]

State changes course, approves Pt. Thomson plan on “new information”

State Natural Resources officials approved ExxonMobil’s long-term plan of development to grow the Point Thomson gas field Friday after getting a letter from the companies Alaska leaders that caused the state to change course, according to the approval documents. The approval comes despite Division of Oil and Gas Director Chantal Walsh first resoundingly rejecting the plan Aug. 29, contending at the time it contained too many “ifs” and “woulds,” depending on economics and its partners’ decisions and allowed Exxon to back out of its 2012 Point Thomson settlement with the state that bound it to develop the long-awaited project. The conditional language indicated Exxon was not committed to expanding natural gas and condensate production despite the state’s assertion the 2012 settlement was a contract that bound the company to do the work. 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 in its June 30 development plan — the one first rejected. Walsh wrote in the Friday approval document that the Oct. 12 letter from Exxon — considered by the state to be a revision to the original plan — lays out a plan for the company to advance expansion in five areas, including negotiating agreements with the Prudhoe Bay operators, engineering, permitting and other unspecified work. In rebutting Exxon’s claim that the Point Thomson work is contingent on agreements with the Prudhoe Bay working interest owners, she noted in her August rejection letter that the Prudhoe owners, BP, ConocoPhillips and Exxon, are the same companies in charge of Point Thomson, meaning they would be negotiating with themselves. ConocoPhillips relinquished its 5 percent stake in Point Thomson to the field’s other owners earlier this year. DNR and Exxon officials also had an Oct. 9 meeting, according to Exxon’s letter. A press release from Gov. Bill Walker’s office called the plan approval “a positive step to achieve major gas sales and increase oil production. Point Thomson holds roughly 25 percent of the gas that could feed the Alaska LNG Project. “Our approval of the Point Thomson to Prudhoe Bay pipeline plan adds to the momentum of the Alaska LNG Project and demonstrates the commitment of the Point Thomson working interest owners into (the) Alaska Gasline Development Corp.’s 800-mile pipeline,” Walker said in a formal statement. However, Walsh also made it clear in the approval that the state expects the expansion project to move forward regardless of extenuating circumstances. “If the Point Thomson Unit working interest owners do not fund the planning work or enter a commercial agreement with the Prudhoe Bay working interest owners, those events will not in any way absolve Exxon from fulfilling its obligation to complete the planning work promised in the revised planning POD,” she wrote. 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. 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.   Elwood Brehmer can be reached at [email protected]

Anchorage utilities, mayor announce $1B consolidation deal

Anchorage’s mayor and electric utilities will ask the city’s voters to approve a $1 billion deal that would consolidate the two utilities and save ratepayers “hundreds of millions of dollars” over many years, according to utility officials. Mayor Ethan Berkowitz and the leaders of Chugach Electric Association and Municipal Light and Power held a joint press briefing Thursday morning to announce their plan for Chugach to buy city-owned ML&P for roughly the $1 billion figure. “It will benefit taxpayers over the long haul and in the short haul. It will benefit ratepayers. It also does a lot for the municipality in terms of stabilizing our revenue picture moving ahead, which is very critical in terms of making sure that our economy is on a firm footing regardless of what happens at the state level,” Berkowitz said. The prospect of a single electric utility in Anchorage has long been discussed; Chugach CEO Lee Thibert said this is the third time it has been analyzed in his 30-year career with the cooperative. The presumption has been that the duplicative overhead needed to run two utilities in a city with a current population of about 300,000 is unnecessary. “There’s lots of things that are very identical with the two organizations and it just makes sense to put this all together,” Thibert said. City-owned ML&P services Downtown and Midtown Anchorage, as well as Joint-Base Elmendorf Richardson. Chugach, a member-owned cooperative utility, covers the remaining majority of the city and small portions of the northern Kenai Peninsula Borough. Because the municipality owns ML&P selling it requires voter approval, Berkowitz will ask the Anchorage Assembly to put a proposition on the April 2018 municipal ballot to allow the sale. The Chugach Board of Directors will also vote on the sale and, as a result of nearly all of Chugach’s member-customers being Anchorage residents, they will get their say through the city vote as well. What Anchorage residents will think of the plan is unclear, but the utility officials said they haven’t heard from anyone who thinks it is a bad idea. If approved by voters, the Regulatory Commission of Alaska would then have its say, an approval process that can take up to six months. That likely puts a final closing date sometime in very early 2019, Thibert said. He estimated the aforementioned savings would be wrought over 30 to 40 years by basically by having one of everything an electric utility needs instead of two — likewise for repetitive operational activities. Industry experts have said the six Railbelt utilities from Fairbanks to Homer have about as many customers as an average Lower 48 utility, albeit over a comparatively vast geographical region.  “Obviously when you put to organizations together you get efficiencies that generate revenue that you wouldn’t get otherwise; it’s a reduction in cost so you can maintain the rate levels the way they are and (decrease rates) over time.” Thibert added. ML&P General Manager Mark Johnston said the rates the utilities charge are usually very similar. “We kind of trade back and forth who’s number one and who’s number two in best rates,” he commented. It was stressed at the press briefing that no layoffs will be associated with the deal, should it go through. Thibert said Chugach would whittle the combined workforce through attrition and reorganization, noting each utility currently has a fair amount of vacant positions. Specifically, Chugach would take on $695 million of debt, make incremental payments to the city totaling about $170 million and continue making the municipal utility service assessment payments, which are essentially ML&P’s payments to the city in-lieu of property taxes, according to Thibert. He also noted that current low interest rates lessening Chugach's borrowing costs make the deal all the more appealing now. Berkowitz said it would allow the city to pay down about $525 million in debt and make additional contributions to its trust fund. Part of debt Chugach would take on would cover a $170 million direct payment to the Municipality of Anchorage, while the rest would be assuming ML&P’s outstanding obligations. They said a series of meetings held by the Anchorage Economic Development Corp. last spring examining how to lower electric rates helped restart the consolidation conversation. At those meetings, a national utility consultant said merging the utilities is the single biggest step that could be taken to capture savings. Subsequent to that the Anchorage Assembly passed a resolution in June encouraging the utilities to examine a merger. Berkowitz said it quickly became clear a straight merger wasn’t feasible because of the inherent challenges in blending a member-owned cooperative with a government-owned utility so discussions evolved into what it would take for Chugach to buy ML&P. The deal, while not expected, is almost a natural evolution considering the multiple ways Chugach and ML&P have partnered in recent years. In January, Chugach, ML&P and adjacent Matanuska Electric Association announced a voluntary power pooling agreement through which the three will trade power down to the hour based on demand requirements. Pooling demand and generating capacity allows the utilities to more fully capture the fuel savings and other operational efficiencies provided by the new generation plants each has put into service since 2013. In 2016 they bought into the Cook Inlet Beluga River natural gas field to gain a reliably priced long-term fuel supply. The two also jointly own the west Anchorage Southcentral Power Project generation plant built in 2013.   Elwood Brehmer can be reached at [email protected]

Pebble Partnership to finally file permit application

The Pebble Limited Partnership has long been criticized for many things, but as of Friday that list will no longer include failure to file for environmental permits. Pebble and its Vancouver-based parent company Northern Dynasty Minerals announced Thursday their plans to file for a Clean Water Act Section 404 wetlands fill permit with the U.S. Army Corps of Engineers on Friday, Dec. 22. Northern Dynasty leaders said early in the year they planned to start permitting for the wildly controversial project by the end of the year, a promise that was met with understandable skepticism. They will have made good on it with nine days to spare. Pebble Partnership and its ownership groups, which have varied over the years, had consistently been faulted for making numerous claims dating back to 2005 that they would soon start the environmental reviews. The permitting process is also seen as one way to eventually provide closure for those on each side of the contentious debate over whether the world-scale mine proposed at the headwaters of a world-scale salmon fishery is appropriate. “For the Pebble team, this day has been a long time in the making and is the result of a tremendous amount of hard work,” Pebble CEO Tom Collier said. “We have listened to our stakeholders, supporters and skeptics, and are presenting a much smaller mine with enhanced environmental safeguards. Since I have been with the project, my main focus has been to initiate the permitting process so that Pebble can be fairly and objectively evaluated by the independent experts hired by the Corp of Engineers.” In 2014, the Environmental Protection Agency proposed blocking Pebble based on a larger mine concept outlined in financial disclosure filings by Northern Dynasty. Shortly thereafter Pebble Partnership sued the EPA, claiming the agency’s actions were made on a biased, anti-mine premise and that it illegally colluded with opponents of the project. That suit was settled in May and since the EPA is currently evaluating public comments on whether to lift the proposed determination that would prohibit the project. With a total mine facilities footprint of 5.4 square miles, the new plan is less than half the overall size contemplated by the EPA but still larger than the 4.2-square mile footprint the agency said could be acceptable. In statements issued shortly after Pebble’s announcement, opposition groups said the permit filing changes little, other than renewing determination to stop the project. “It took Pebble Limited Partnership 12 years just to file the paperwork asking the Army Corps to look at this project,” Bristol Bay Economic Development Corp. CEO Norm Van Vactor said. “The bar is set very low, indeed, if merely filing an application is cause for celebration. Bristol Bay fishermen file paperwork for their permits every single year, without fanfare. And here in Bristol Bay, we will choose our sustainable commercial fishery that generates thousands of jobs over a short-term development project.” Earlier in the week on Tuesday, Northern Dynasty issued a statement saying it is close to finalizing a deal with fellow Canadian mining firm First Quantum Minerals for investment in Pebble. Northern Dynasty is the sole owner of Pebble after previous partners Anglo American and Rio Tinto walked away from the controversial copper and gold project several years ago. In the case of Anglo American, the company ended its partnership on the project in 2013 after spending $541 million on exploration. Since then, company officials have acknowledged the need for a large investment partner to fund Pebble’s development. Under the terms released of the preliminary deal, First Quantum would contribute $150 million to Pebble over up to six years with a $1.35 billion option to buy a 50 percent stake in the project. In a Thursday interview Collier said he expects to have the partnership finalized by the middle of next year. Collier said his company doesn’t yet have a solid cost estimate for the scaled-back mine plan he unveiled in October, but that would materialize as permitting plays out. Alaska Army Corps officials said Thursday that the wetlands fill permit application detailing the types and volumes of fill material the project will use and the area of wetlands it is expected to cover would first be subject to a 15-day completeness review. If the wetlands application is deemed complete the Corps will then issue a public notice saying as much and — given the size of the project — issue a subsequent determination that the project needs to go through the full, multi-year environmental impact statement process. Look for updates to this story in an upcoming issue of the Journal. Elwood Brehmer can be reached at [email protected]

Tax overhaul, ANWR heads to Trump’s desk

When President Donald Trump signs the federal tax overhaul into law the coastal plain of the Arctic National Wildlife Refuge will be open to the oil industry. Most Alaskans are happy about it, some aren’t. In the Lower 48 the public seems more split on the issue, if not slightly against it. After 37 years of debate, what more is there to say? The members of Alaska’s congressional delegation, who got the last words on ANWR in Congress when the tax bill passed, wanted to add a little more in a Wednesday morning press briefing with Alaska reporters. “This is a pretty historic day,” Sen. Lisa Murkowski said, and in recognition of it being winter solstice, she added opening ANWR is an “opportunity for Alaskans that will bring many bright days for Alaska.” Rep. Don Young, noting it’s the 14th time he’s shepherded ANWR legislation through the House, compared it to the day in 1973 when Vice President Spiro Agnew cast the tie-breaking vote in the split Senate to authorize construction of the Trans-Alaska Pipeline System. He also gushed about his colleagues in the delegation. “The work these two senators put in is awesome,” Young said. Sen. Dan Sullivan said the ANWR victory should provide a psychological boost to Alaskans struggling through a two-year recession. In a broader sense, Sullivan also said the tax vote is proof that “elections have consequences,” as tax reform is something Republicans in Congress have been pushing for seemingly as long as the Alaska delegation has been stumping for ANWR. Young said the delegation got commitments from House Speaker Paul Ryan and Senate Majority Leader Mitch McConnell early in the year that opening the coastal plain would be a priority in Congress. Murkowski said technological advancements allowing more oil to be extracted via a smaller footprint and the industry’s diligent environmental practices on state lands on the North Slope helped overcome old arguments about how oil activity would damage the fragile Arctic ecosystem. “We heard the same tired rhetoric that we’re going to turn this into an industrial wasteland,” she said. “The way that we operate up there is second to none.” The ANWR rider directs the Interior Department to hold two oil and gas lease sales of at least 400,000 acres each in the coastal plain within the next 10 years, but it authorizes total development of just 2,000 acres in the 1.5 million acre area, the delegation again stressed. Sullivan went a step further, calling opposition arguments “dishonest” and saying, despite claims the oil industry spent millions of dollars supporting the effort, it was actually Outside environmental groups that spent money on the debate. “This was a grassroots effort; it was the three of us and Alaskans that came to testify, that was it,” Sullivan said. “People were tired of the stale talking points by (Washington Democrat Senator) Maria Cantwell and others.” Young went all the way, calling anyone who criticized the plan to drill for oil in the wildlife refuge “very stupid.” Young has also said recently that current oil estimates in the refuge are probably close to 20 billion barrels of available oil. The most recent U.S. Geological Survey assessment of the oil and gas underneath the coastal plain, done in 1998, put the mean oil estimate at 7.6 billion barrels for the coastal plain-1002 area. The USGS additionally estimated there is a 5 percent probability the area holds nearly 12 billion barrels of technically recoverable oil, which says noting of the economics of extracting it. With the political battle for ANWR all but over — at least until Democrats eventually regain control in Washington — now comes the legal fight. Environmental groups will assuredly sue Interior at every turn to at least delay the lease sales. The law mandates Interior hold the lease sales after going through a lengthy National Environmental Policy Act review. It’s unclear what happens if the conclusions of the environmental study don’t support development. What appetite the industry will have for exploring in ANWR given the strong emotions it evokes from much of the public is also unknown. That leads to questions about whether the 800,000-plus acres to be offered in lease sales can generate the $1 billion in federal revenue that’s expected — which is actually $2 billion because the State of Alaska gets half of all revenue from ANWR, per the legislation. Murkowski acknowledged “it will likely be a decade-plus” before ANWR oil production starts, but said the state has waited 37 years and can wait a little longer. “Now we at least have the opportunity we haven’t had,” she said. Elwood Brehmer can be reached at [email protected]

YEAR IN REVIEW: Pebble promises permit application after hurdles fall

This was the first good year in a long time for Pebble Limited Partnership and its owner Northern Dynasty Minerals and equally as bad a year for those trying to stop the massive mining project. After months of talks, the Environmental Protection Agency and Pebble Partnership settled a lawsuit in May that the company filed against the agency in 2014. The suit claimed the EPA, under the Obama administration, was biased in its drafting of the Bristol Bay Watershed Assessment and colluded with anti-mine scientists to reach the conclusion that a large, open-pit mine would cause too much damage to the region’s fisheries. The 1,000-plus page assessment was the basis for the EPA’s 2014 attempt to use its Clean Water Act authority to ostensibly prohibit development of Pebble. Per the settlement, the EPA is in the process of withdrawing its Clean Water Act 404(c) proposed determination and Pebble has 30 months and counting from the time of the May 12 agreement to file for the project’s federal permits. However, Pebble also agreed that the watershed assessment, the only official scientific document examining the potential impacts of the project, would remain valid. The EPA under the Trump administration is just not invoking it any longer. In early October Pebble released a new, smaller mine plan than original concepts that entails a reduced overall footprint and fewer roads to reach it by way of a ferry across giant Iliamna Lake. Pebble executives left open the possibility of expanding the mine after initial development and noted that would require a separate permitting process of its own. They also proposed setting up a corporation to distribute revenue from the mine to local Native village corporations and directly to area residents once it is in production. Most recently on Dec. 18, Northern Dynasty and fellow Canadian mining company First Quantum Minerals announced the framework of an investment deal in which First Quantum could put $150 million into the project over up to six years. The first $37.5 million would go towards permitting costs but First Quantum is still evaluating whether or not to finalize the potential investment, according to its press release about the deal. It could also buy a 50 percent stake in the project for $1.35 billion, according to Northern Dynasty. The parent company to Pebble has said it will need a large investment partner to help fund development and wants to secure one by the end of the year. Additionally, Pebble leaders have said they plan to file environmental permit applications by the end of 2017, which is coming soon. (Editor's note: This story has been changed to correctly state that the EPA is in the process of withdrawing its 404(c) proposal, but has not done so yet.) No. 2: Habitat initiative heads to Supreme Court Three Alaskans from Bristol Bay and Talkeetna filed a proposed ballot initiative to overhaul the state’s anadromous fish habitat permitting requirements and another fight over what are acceptable rules for development in and around salmon habitat has predictably followed. Proponents contend the “Stand for Salmon” initiative would give the Department of Fish and Game much-needed enforcement authority over unlawful salmon habitat disruption, which they say it currently lacks. They further note the state actually has no formal permitting structure for development in salmon habitat; rather, just a couple vague lines of statute that direct the department to authorize projects that provide “proper protection of fish and game.” In a June 30 letter to the sponsors, the Department of Law deemed the first iteration of the initiative an unconstitutional allocation of resources and would prohibit projects such as the Pebble and Chuitna mines and Susitna-Watana dam, which the initiative sponsors have opposed. After the sponsors revised the initiative, Lt. Gov. Byron Mallott still rejected it based on the opinion of Law Department attorneys and wrote that the measure “essentially usurps the Legislature’s resource allocation role.” He has insisted the state’s position is based on the constitutional implications and has nothing to do with the politics. In an interesting twist, Elizabeth Bakalar, the assistant attorney general assigned to the matter, said the June 30 letter was in large part a response to industry concerns about the initiative that the department heard. It is the same type of opinion state attorneys issue on any ballot measure, except earlier, she said. 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 certified. The petitioners appealed to the Superior Court and Oct. 9 Judge Mark Rindner overturned Mallott’s decision, meaning the initiative could be put on the 2018 ballot. The state Supreme Court has instructed lower courts interpret initiatives broadly to give voters a say whenever possible, Rindner noted in his order. The state appealed Rindner’s ruling to the Supreme Court Oct. 25. The high court has since been quiet about its path forward and in the meantime the sponsors are gathering the required signatures to place it on the 2018 general election ballot. No. 3: NANA rebound High zinc prices made it a much better year for NANA Regional Corp. NANA, the Native regional corporation for Northwest Alaska, owns the Red Dog Mine — one of the largest zinc mines on Earth — that is operated by Vancouver-based Teck Resources Ltd. In September, Teck said it expects production from Red Dog to be between 525,000 and 550,000 metric tonnes this year. Output in that range would be about 10 percent above prior production forecasts. Zinc sold on spot markets for between 80 cents and about $1 per pound for several years before dipping to 70 cents per pound in early 2016. Since, the corrosion-resistant metal commonly used in steel coatings has steadily increased in value to its current spot price of about $1.45 per pound. NANA CEO Wayne Westlake said Red Dog’s increased revenue of late has largely made up for the recent decline in 7(i) distributions brought on by $50 oil. He noted that the resource development payments — required to be shared among the 12 Native regional corporations, with NANA a major contributor for its mineral royalties — are often one of few private cash flows going into rural Alaska communities. While the oil price depression hit Native corporations through revenue sharing, NANA is also among the group of corporations that is heavily invested in the business side of Alaska’s oil and gas, with seven subsidiary firms working on the support services side of the industry in Alaska, Colorado and the Gulf Coast. About 40 percent of NANA’s revenues come from the oil and gas sector in some fashion, according to company leaders. That led to NANA absorbing a $109 million loss in 2016 and its business operations company, NANA Development Corp., also had its credit rating downgraded last year as a result of its oil business struggles. No. 4: Ambler Road permitting begins with AIDEA in lead Development of the Ambler Mining District road project is now in federal hands. The Bureau of Land Management issued a Federal Register notice Feb. 28 requesting public input regarding what topics the agency should consider in drafting the environmental impact statement, or EIS, for the mining access road. Early environmental and financial study work for the proposed gravel road running west from the Dalton Highway for 211 miles to the remote Ambler Mining District has to this point been led by the state Department of Transportation and more recently the Alaska Industrial Development and Export Authority. The Ambler Mining District stretches for about 75 miles along the southern flank of the Brooks Range in the upper Kobuk River drainage. It has long been identified as an area of great potential for copper, zinc and precious metals but access issues have largely inhibited development. Vancouver-based Trilogy Metals Inc., formerly NovaCopper, is one company that has been busy exploring multiple prospects in the region. According to Trilogy, its well-defined Arctic deposit in the Ambler district likely holds about 2.3 billion pounds of zinc, more than 1.7 billion pounds of copper, 40 million ounces of silver and a small amount of gold. No. 5: Southeast exploration Alaska Mental Health Trust Land Office officials keep plugging away at their heavy mineral prospect on the Gulf Coast near Yakutat. In October, the Mental Health Trust Authority Board of Trustees approved $3 million more for exploration at the Icy Cape prospect in 2018. The prospect is a long stretch of coastline about 75 miles northwest of Yakutat in Southeast Alaska owned by the trust at the entrance of Icy Bay that appears to hold world-class deposits of several heavy minerals. The entirety of the area is roughly 48,000 acres and stretches for more than 30 miles along the Gulf of Alaska coast. Trust Land Office leaders have stressed that they are still in the preliminary exploration phase of evaluating the prospect but early drilling samples from the broad delta at the point of the cape indicate the ore there could be up to 40 percent heavy minerals. Overall, an average of 26 percent of the sands are heavy minerals, according to the Trust Land Office reports. The minerals of value in the “ore” — which is mostly old beach sands — are roughly equal portions of epidote and garnet in the areas of highest concentration with small amounts of zircon and even gold. Epidote and zircon are semiprecious gemstones. Garnet has also been used as a gemstone for hundreds of years, but more recently the hard mineral has been put to use as an industrial abrasive on sandpapers and in sandblasting applications. It is also used in water filtration; garnet’s small pores allow for the passage of liquid while catching some contaminants. If developed, the Trust property would be the only source for garnets on the West Coast, Land Office officials have said.

YEAR IN REVIEW: Port project, King Cove, Alaska-Virgin merger

Anchorage municipal attorneys settled half of their tangled litigation over the long-failed Port of Anchorage expansion project but it was more of the same for port officials trying to drum up hundreds of millions of dollars for the scaled back but badly needed modernization plan. In less than a week starting Jan. 26, municipal attorneys filed documents in U.S. District Court of Alaska announcing settlements with four defendants — CH2M, GeoEngineers Inc., Integrated Concepts and Research Corp., and PND Engineers Inc. — stemming from the lawsuit filed in early 2013 seeking damages for the failed construction project. The municipality started resolving the case in June 2016 when it settled with MKB Constructors, a construction company that partnered with Quality Asphalt Pavement to install the PND’s proprietary Open Cell Sheet Pile dock design, which was at the heart of the court dispute. Work on the project — started way back in 2003 — was halted in 2010 and never resumed after extensive damage to installed sheet pile was discovered. In total, the Municipality of Anchorage settled the port lawsuit against the contractors for $19.35 million. The legal battle now turns to Federal Claims Court, where the city is also suing the U.S. Maritime Administration, claiming its management incompetence over the project led to the construction problems. The city is seeking upward of $300 million in that case but it is progressing very slowly. Port officials are moving ahead with the new plan to replace the existing docks, but that is expected to cost roughly $700 million. They are hopeful phase one — mostly a new fuel and cement terminal — of the five-part project can be done with the $127 million left from the first project. Without the new docks the port has about 10 more years before the steel sleeves now being installed to patch the corroding dock supports start rusting away themselves and begin to limit operations, they say. And that’s if an earthquake doesn’t knock it offline sooner. In June, a cruise ship was docking at the port when a 57,000-pound fender fell off the dock because the steel supports gave way due to corrosion. Luckily, that was the worst of it. As a result the city is examining all options to pay for the new project since state support has to date been nil. That could even include selling the to port to private investors if someone else is looking for a $700 million burden, however slim that prospect might be, according to Port Director Steve Ribuffo. In a ceremonial attempt to drum up funding support the Anchorage Assembly changed its name to the Port of Alaska on Oct. 24, a gesture intended to emphasize the importance of the ailing infrastructure to all of Alaska, not just its largest city. Gov. Bill Walker included $40 million, with a requisite municipal match, from the state for the port in his $1.4 billion plan to address the state’s backlog of infrastructure maintenance — a start — but that has many political hurdles to overcome. No. 2: King Cove road revived Proponents of a road from King Cove to Cold Bay feel renewed hope under discussions with Interior Secretary Ryan Zinke’s administration for a different land swap than was proposed in the past. Discussions involve setting up a federal lands appraisal process on 200 to 300 acres owned by the King Cove Corp. that could be swapped with the federal government for land to complete the road with an 11-mile connection through the Izembek National Wildlife Refuge to reach Cold Bay and its all-weather airport. Under previous administrations since 1997, the community has struck out at attempts to gain the road. At issue is the wildlife refuge designation and its habitat for 98 percent of the Pacific black brant goose worldwide population, according to the Interior Department. Alaska’s congressional delegation and several Alaska governors have pushed for the road between the small, isolated communities, as it would link King Cove to the large runway at Cold Bay and provide a safer route to Anchorage for those in urgent need of medical care in a region known for treacherous weather. In June the Alaska Department of Transportation began survey work to identify the least impactful route for the road through the refuge, which took a few weeks. By July the U.S. House passed standalone legislation with bipartisan support approving the land swap. The Alaska DOT estimates the road will cost about $30 million, which will likely be paid for by the state. Sens. Dan Sullivan and Lisa Murkowski are likely to pick the legislation effort back up in the New Year after the major tax and budget issues are resolved in Congress. No. 3: Alaska-Virgin merger materializes The parent company to Alaska Airlines, Horizon Air and now Virgin America started the year by reporting a $911 million profit in 2016, a seventh consecutive year of record earnings. However, the rest of the year was a little more turbulent for the growing company trying to compete with the industry’s giants. Profitability was not the issue; Air Group continued to report solid financials but its airline’s trademark service started to suffer. Alaska Airlines has long been the top on-time domestic carrier, but since bringing Virgin America into the fold in the fourth quarter of last year those numbers have fallen. Through September, 82 percent of Alaska Airlines flights arrived on time, which is down 6.5 percent year-over-year. For Virgin America-flagged flights the numbers are worse. Just more than 67 percent of Virgin flights have been on-schedule this year, a decrease of 9.3 percent. Additionally, Horizon Air continues to face the same problems retaining pilots as many regional carriers across the country, an issue that forced the airline to curb its schedule in August and September, Air Group CEO Brad Tilden acknowledged in October. Also in October, company officials said after a roughly four-year experiment, Horizon will stop its service in Alaska next March. The regional carrier has been operating flights for Alaska between Fairbanks, Anchorage and Kodiak. Horizon’s routes in the state will be picked back up by Alaska Airlines Boeing 737s. Alaska Airlines is also spending about $100 million upgrading its rural Alaska terminals and is working on a new $40 million hangar at Ted Stevens Anchorage International Airport to accommodate its newer, larger 737s. No. 4: DOT MOU The Alaska and federal Transportation departments inked a deal in August 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, shifts environmental assessment and environmental impact statement drafting from U.S. DOT sub-agencies to the state Department of Transportation and removes duplicative federal processes and “interagency squabbling,” DOT Secretary Elaine Chao said during a trip to Alaska. 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. 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, Alaska DOT Commissioner Marc Luiken said at the time. No. 5: Railroad, MOA fight over funding In April, the Alaska Railroad issued its 2016 financials and reported a $7.4 million loss, the railroad’s first annual loss since 1999, and blamed it on Anchorage Mayor Ethan Berkowitz. That’s because Berkowitz refused to sign a letter agreeing to split federal transportation funds between the railroad and the city; the mayor said the railroad was getting the money on technicalities and the city could better use it for the true public transportation operations as the feds intended. 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 Federal Transportation Administration would not release the money without the split letter. However, by August the sides agreed to resume the historical funding split, with a property sale driving the resolution. Berkowitz said the 20.2-acre railroad property, to be sold to the city for $1.5 million, is “a critical piece” of land that will help the city progress its much-needed overhaul and modernization of port infrastructure. 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.

YEAR IN REVIEW: Credit program scrapped; Slope discoveries expand

It took six months of debate but the Alaska Legislature ended the state’s refundable oil and gas tax credit program in July — something all sides agreed needed to happen from the get-go. The lengthy debate mostly centered on the House Majority’s push to link a production tax overhaul and increase to the tax credit legislation. The version of House Bill 111 that Gov. Bill Walker ended up signing was much more what Senate Republicans wanted without the tax changes; it ended the 35 percent net operating loss credit for small North Slope operators and expedited the credit phase-out plan passed for Cook Inlet in 2016. The Department of Revenue estimates repealing the cashable credits will save the state roughly $150 million per year over the long-term; however, House Majority members noted that the bill simply swaps what would have been a cash expense into less future tax revenue as companies can still apply the credits as tax deductions against their production taxes. The House coalition did score a victory in that the bill included a provision that allows companies to hold deductions at full value for seven years, after which the value decreases by 10 percent per year. The “downlift” provision is intended to spur development activity by limiting how long the maximum value of the tax deductions can be realized. Lesser used exploration credits for Interior Alaska — mostly used by Native corporations — and refinery and LNG storage credits were not cut in HB 111, but those generally sunset in 2020 or 2021. No. 2: Oil Search buys into Nanushuk Responsibility for Alaska’s largest oil prospect is going to change hands for the second time in three years in 2018 as a result of an $850 million deal between Armstrong Energy and Alaska newcomer Oil Search. Australia-based Oil Search announced the terms of its agreement with Armstrong Oct. 31. Under the deal, Oil Search will get a 25.5 percent stake in the Pikka Unit — which is operated by Armstrong and holds the 1.2 billion barrel-plus Nanushuk oil prospect — and a 37.5 percent interest in the “Horseshoe” leases to the south. Armstrong currently operates the Pikka Unit for its partners Denver-based GMT and Spanish major Repsol. Armstrong is also in the midst of the environmental impact statement process to develop the Nanushuk field, which could produce up to 120,000 barrels of oil per day. The same formation in the National Petroleum Reserve-Alaska is where ConocoPhillips announced a discovery in January it dubbed “Willow” it estimates could produce 100,000 barrels per day. Oil Search has its primary operations in Papua New Guinea and will take over as operator of Pikka from Armstrong on June 1, 2018, according to a company release. The company also has until June 30, 2019, to buy the rest of Armstrong’s and GMT’s interests in the prospects for another $450 million. Oil Search executives said in an interview with the Journal they expect to exercise the $450 million option. Repsol and Oil Search are partners in oil and gas projects in Papua New Guinea. Armstrong took the operator position at Pikka from Repsol in late 2015. The companies first partnered to explore the state lands between ConocoPhillips’ very large Kuparuk and Colville River fields in 2011. Armstrong CEO Bill Armstrong said developing Nanushuk just became too large of a task for his small exploration company, but he plans to continue exploring on the Slope. Armstrong subsequently was an active bidder in the state’s North Slope lease sale held Dec. 6. No. 3: Tofkat tangle Prized oil and gas leases surrounding the Native village of Nuiqsut got a new owner in mid-August after ConocoPhillips agreed to comply with DNR Commissioner Andy Mack’s list of contingencies for gaining control of the 9,100 acres. The leases are now part of Conoco’s large Colville River oil 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. The company was first awarded the leases — this go-round — in November 2016 after a series of decisions to put the leases back up for bid by former DNR officials were reversed by Mack. ConocoPhillips chose not to drill an exploration well on the leases last winter because of concerns from Nuiqsut residents about exhaust from the diesel-powered drilling rig that would have been running continuously for several weeks about three miles from the village, the company said. Mack took umbrage with the decision because the lease transfer was granted on the condition Conoco would drill the well. Small oil company Brooks Range Petroleum Corp. held the leases for years but applied to transfer them to ConocoPhillips early in 2016 because it couldn’t secure an access agreement from Kuukpik Corp., which jointly holds surface rights to the area with the state, and in turn explore the area. ConocoPhillips held the acreage in the early 2000s but had to give it back to the state after failing to meet drilling requirements. 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. 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.No. 4: Arctic OCS projects advance 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. 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. 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. To the west of the Liberty prospect Italian major Eni is undertaking a unique offshore exploration program. Eni, which produces about 20,000 barrels per day from the Nikaitchuq field off of Oliktok Point, is in the midst of commencing a two-well exploration plan to reach potential oil deposits. The first roughly 35,000-foot well will be drilled from its manmade Spy Island drill site in state waters off of Oliktok Point into formations beneath federal waters further offshore. The company has previously drilled several wells up to 25,000 feet on its state leases, according to an Eni Alaska spokesman. If successful, Eni plans to drill a second, similar exploration well next winter. The company currently believes the offshore reservoir it’s targeting could double the 180 million barrels of reserves the Nikaitchuq field originally held when it started producing in 2011. No. 5: State lease sale record Interest was again high among oil and gas lease bidders for state acreage on the North Slope in Dec. 6 lease sales but that was not the case for the federally controlled National Petroleum Reserve-Alaska. Winning bidders spent $21.2 million for 216,000 acres of state land and water across 119 lease tracts. The vast majority of that, $19.9 million, was for 179,000 onshore acres and the remaining $1.2 million was for 37,000 acres of state-owned, near shore waters of the Beaufort Sea. It was the third-most spent to win state lease bids in the past 20 years, Division of Oil and Gas Director Chantal Walsh said. According to DNR, the average winning bid of $110 per acre was the largest since the current area wide lease sale format began in 1998. Spanish major Repsol, which holds a 49 percent stake in the large and in-permitting Nanushuk oil project, dominated the onshore Slope sale, spending up to $293 per acre in some bids to win 45 tracts. Much of that acreage is in the few tracts south of the Pikka Unit that holds the Nanushuk project that were not leased and open for bidding. Despite offering all 10.3 million acres available for leasing, the Bureau of Land Management received only seven bids for 80,000 acres in the NPR-A, all of which came from ConocoPhillips. Last year’s NPR-A sale netted more than $18 million in high bids for 613,000 acres, mostly from ConocoPhillips, which has led the foray into the vast undeveloped area. No. 6: Point Thomson plan dispute Division of Oil and Gas officials rejected ExxonMobil’s plan to expand the Point Thomson North Slope gas project in late August because it doesn’t live up to a prior settlement between the state and the company, according to Director Chantal Walsh. 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. Walsh wrote a six-page letter to ExxonMobil Alaska leaders contending the Point Thomson Expansion Project Plan of Development is far too vague and offers no commitment that the company will live up to the 2012 Point Thomson Settlement Agreement. 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 in the plan, but stopped short of committing to do so. 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. For its part, ExxonMobil responded in an October letter to DNR Commissioner Andy Mack insisting it is in compliance with the settlement and has said it can’t compel its partners in either field to move forward with the expansion plan. Walsh noted Exxon’s Point Thomson and Prudhoe partners are the same companies, meaning they would largely be negotiating with themselves. A further ruling from DNR is expected soon.

Pebble prospect owners might have new investor

The owners of the Pebble project are one step closer to securing the investment partner that will be key to advancing the contentious mine, according to Dec. 18 announcements. Vancouver-based Northern Dynasty Minerals Ltd. has inked what a company press release characterizes as a “framework agreement” with fellow Canadian mining company First Quantum Minerals Ltd. “The option agreement contemplates an option payment of $150 million (U.S.) staged over four years which option will entitle First Quantum to acquire the right to earn a 50 percent interest in the Pebble Limited Partnership for $1.35 billion,” a Northern Dynasty release stated. First Quantum can also extend the option and make the payments over an additional two years, according to the company. Northern Dynasty is the sole owner of Pebble after previous partners, Anglo American and Rio Tinto walked away from the controversial copper and gold project several years ago. Northern Dynasty leaders have said they will start filing environmental permit applications for Pebble by the end of the year. At the same time, they have acknowledged the company needs a new partner to help fund permitting and development. “We have made good progress in the partnering process and are very pleased to be in advanced-stage discussions with First Quantum, an industry leader in mine development and management,” Northern Dynasty CEO Ron Thiessen said in a formal statement. As soon as the agreement is finalized, First Quantum will make a $37.5 million payment to Northern Dynasty to fund permitting, according to a company release. First Quantum operates six mines worldwide primarily producing gold, copper and zinc. Thiessen added that Northern Dynasty will initiate state and federal permitting “in the very near term.” According to a release from First Quantum the company is still conducting a due diligence review of the potential partnership and will finalize the agreement contingent upon a favorable review. First Quantum CEO Philip Pascall said his company remains primarily focused on advancing a copper project in Panama, but Pebble could provide long-term growth for the mine developer. “We are well aware of the environmental and social sensitivity of (the Pebble) project and will utilize the lengthy option period to apply our extensive project development and operating expertise to ensure that this project can be developed with the support of stakeholders,” Pascall said further. Opposition stakeholders from the Bristol Bay region quickly responded with statements that they will continue to fight Pebble development and First Quantum should follow Northern Dynasty’s ex-partners and stay out of the project. “An overwhelming majority of Bristol Bay residents — fearful of the threat large-scale mining poses to their livelihoods and their way of life — are strongly against the Pebble project,” House Speaker Bryce Edgmon, D-Dillingham, said. “As their representative in the state House, it is my clear responsibility to oppose development of the proposed Pebble mine and the unacceptable risks it represents for the Bristol Bay watershed and the many communities I serve. A new investor in Northern Dynasty’s venture does nothing to change that.” The Pebble Limited Partnership unveiled high-level plans in early October for a smaller Pebble mine aimed at lessening the project’s environmental impacts and appeasing skeptics. Pebble CEO Tom Collier said the company might eventually look to expand the project but noted that would require another thorough permitting examination. A Northern Dynasty investor presentation from earlier this year states the company estimates the Pebble prospect holds 1.9 percent of all the gold ever mined in recorded history. Elwood Brehmer can be reached at [email protected]

Gov’s budget aimed at economic recovery

Gov. Bill Walker’s budget proposal released Dec. 15 focuses on paying down growing state obligations and bolstering Alaska’s economy, actions which administration officials say should in the long run help address the ongoing budget deficits. Overall spending from Unrestricted General Funds, known as UGF, in the governor’s fiscal year 2019 budget is $4.7 billion, down 1.7 percent from 2018. State agency spending is up about 1 percent due to $34 million in response to higher crime rates. That money will go to additional public safety spending to pay for more prosecutors, rural State Trooper positions and growth in drug treatment programs. An additional $27.2 million is needed to cover increased Medicaid formula costs. Walker said the two years of economic recession have pushed more out-of-work individuals to utilize the safety net and is a large contributor to the cost growth. The $4.7 billion total also includes an increase of $82 million for state retirement liabilities and flat funding for K-12 education and the University of Alaska. Accompanying legislative proposals start with bonding to end the state’s oil and gas tax credit obligation, which administration officials estimate will require $900 million to fully pay off over the next couple years. In July, the Legislature passed a bill ending the refundable tax credits for small companies working in Cook Inlet and on the North Slope, but after three years of the state not paying the credits as they came due — first via governor vetoes and then a minimum payment by the Legislature — the sizable debt still needs to be paid. Revenue Commissioner Sheldon Fisher said the state would sell subject to appropriation bonds to fund the payments and offer the credits at a discount of up to 10 percent, reflecting the decline in net present value companies would absorb if the state continued to pay the statutory minimum credit amount each year and prolong the payments for many years. Department officials expect the state can borrow the money for less than 6 percent interest over 10 years. Fisher said his agency, in coordination with the Department of Natural Resources, could also work to lower the discount rate for companies with production through negotiating a slightly higher royalty rate on their leases. It’s a proposal he believes will be well-received after discussions with industry representatives. “We believe the discount we will offer these companies will be significantly less than their cost of capital,” Fisher said. While the state has technically followed the tax credit statutes by appropriating less than $100 million in the past couple years, the break in precedent from paying them in full each year has hurt Alaska’s credibility in the oil and finance industries, officials acknowledge. Lacking the payments has also kept small companies from leveraging the credit funds for larger private investments to pursue work in the state. Another bill, dubbed the Alaska Economic Recovery Act, would allocate $800 million over three years from the governor’s 1.5 percent payroll tax that will sunset in 2021 to fund state deferred maintenance projects. The administration estimates the state has roughly $1.8 billion worth of backlogged projects from school and university building repairs to cleaning up contaminated sites and road projects. With local and federal matches for some other projects, including funding for the much-needed Port of Anchorage rehabilitation, the package would be a $1.4 billion infusion to the state’s construction industry. “We have the highest unemployment, I believe, in the nation and we need to put Alaskans back to work. We need to fix that part of our economy,” Walker said in a press briefing on the budget. Alaska’s unemployment rate was 7.2 percent in October, compared to 4.1 percent nationally. Walker added that the relatively small size of the more than 60 projects planned to receive funding means small, local contractors across the state will get most of the work. The tax, introduced in the October special session, would sunset at the end of 2021 after the three-year construction program. Walker first proposed bonding for capital projects every two years as part of his overall plan to balance the budget two years ago. However, with the fiscal situation much the same — and the state continuing to run annual deficits of more than $2.5 billion — the state’s ability to take on additional debt remains limited, according to the administration. Senate Majority Republicans have blocked attempts by the governor and the Democrat-led House Majority to pass an income tax the past two years, contending government spending needs to be cut further before adding taxes to a strained economy. Walker said he believes the sunset clause and committing the revenue to growing one of the industries hit hardest by the recession should change Republicans’ thinking on the tax. “They thought it would grow government; it doesn’t. They thought it would go on forever; it doesn’t,” he commented. House Finance co-chair Rep. Paul Seaton, R-Homer, commended the governor for holding education spending steady in a caucus release and Senate Minority Leader Berta Gardner similarly praised the plan to add public safety resources. However, Gardner said she is skeptical that Alaskans will be comfortable with a tax to fund infrastructure projects while at the same time prioritizing the oil tax credit payments. The rest of the capital budget is much as it has been for three years now; “very, very austere” is how Office of Management and Budget Director Pat Pitney described it. At about $150 million, the basic capital budget funds the state’s 10 percent match to more than $1 billion of federal transportation program funds and supplies several small state energy efficiency and housing programs. Permanent Fund The governor’s budget appropriates $818 million for Permanent Fund Dividends — enough for about $1,200 per Alaskan. The PFD total is 30 percent of the 5.25 percent of market value, or POMV, draw from the fund that is in Senate Bill 26, the Fund reform bill that passed the House and Senate last spring and awaits conference committee reconciliation. Administration officials said the 30 percent for dividends is simply a compromise to the 25 percent in the Senate version of the bill and 33 percent in the House’s SB 26. The remainder of the roughly $2.7 billion planned draw from the Earnings Reserve Account of the $61 billion Permanent Fund would go towards closing the deficit. In the event SB 26 is not reconciled and dies in the Legislature, the governor’s budget includes the POMV formula language to draw from the Permanent Fund based on the bill. Either way, the state will likely pull about $800 million from the dwindling Constitutional Budget Reserve to close the rest of the expected fiscal 2019 budget gap. “The wait-and-see program that some in the Legislature have adopted has cost us $14 billion,” Walker said, with most of that savings amount coming from the CBR over the past four years. The administration, after a request from the Alaska Permanent Fund Board of Trustees, also included a nearly $2.4 billion inflation-proofing transfer from the Earnings Reserve to the corpus of the Fund. The Legislature has not inflation-proofed the corpus for three years, which APFC CEO Angela Rodell told the Journal is a growing concern for the corporation. Budget process reforms Walker also said he will submit legislation to move the state to a biennial budgeting format as well as stop legislator pay and per diem if budgets are not passed in the standard 90-day special session. For three years the Legislature has blown past the 90-day regular session and the 120-day constitutional session limit without passing a budget. Similarly, the proposal would cut the governor’s pay if the budget plan is not released by the Dec. 15 deadline; however, that is rarely an issue. “There’s no question the process is broken that we use in Alaska for budgeting,” Walker emphasized. “It’s just a terrible way to run a state.” Legislators have generally been open to the idea of a two-year budget cycle, in which they would focus on the budget in the first year of a two-year Legislature and, after making true-ups, focus on policy issues in year two. The large budget deficits of late have made seemingly every appropriation contentious in recent years, dragging out budget debates and tainting negotiations on other issues as well. The budget delays have forced state agencies to issue “pink slips” notifying workers of a potential government shutdown and associated layoffs. It has also caused confusion among state ferry officials, commercial fishery managers and others in industries that have significant state oversight as to what exactly would happen to private businesses in the event of a government shutdown. While he has declined to comment on many legislative proposals and preferred to push legislation from behind the scenes during session, Walker said he would aggressively pursue the pay and per diem restriction this year. He called it “silliness” to use the budget as a negotiating tool with respect to other issues at hand during the legislative session. “There has to be consequences for what you do and you don’t do,” Walker said. “(Delaying the budget) is expensive, it’s demoralizing and it gives us another sign of instability as a state.” Elwood Brehmer can be reached at [email protected]

House majority won’t push income tax again

Legislative leaders from both parties claimed success when reviewing 2017 despite achieving little to solve the state’s most pressing issue: ongoing multibillion-dollar budget deficits. Democrat House Speaker Bryce Edgmon and Republican Senate President Pete Kelly spoke about the year’s legislative sessions and their expectations for the upcoming session that starts Jan. 16 to a Dec. 13 lunch gathering of the policy analyst group Commonwealth North in Anchorage. Edgmon said his House Majority coalition met each of its four major goals during the prolonged 2017 sessions: the House made “surgical cuts” to the operating budget; ended the refundable oil and gas tax credit program for Cook Inlet and North Slope work; passed legislation to enact a percent of market value, or POMV, draw from the Earnings Reserve of the Permanent Fund; and approved an income tax. “Amid all the acrimony and endless special sessions we did get some work done,” he said, noting the passage of bills to allow ridesharing companies in the state, address the federal REAL ID mandate and the state’s opiod addiction epidemic that Gov. Bill Walker signed, among others. With control of the House for the first time more than 20 years, Edgmon added the Democrats strengthened personal relationships with Senate Republicans, which could prove beneficial in 2018. “The point of it is we took action,” he said, acknowledging the caucus was aware not everything it passed would become law. Similarly, Kelly noted the Republican-dominated Senate made good on plans to cut the operating budget by roughly $300 million in its version of the budget; approved a revised state spending cap; passed the Permanent Fund POMV legislation; and voted down the House’s income tax, thereby protecting the private sector, he said. The only budget-directed bill to reach the governor’s desk was House Bill 111, which ended the oil tax credits. It reduces future state obligations but does little to fix the immediate budget gap. Meanwhile, the Legislature spent a record 211 days in session this year; prolonged budget battles pushed the state to within nine days of a government shutdown; the $2.7 billion fiscal year 2018 budget deficit was again filled with savings from the dwindling Constitutional Budget Reserve; and ratings agencies further downgraded Alaska’s creditworthiness. Looking ahead, Edgmon said his caucus is still focused on fixing the state’s budget in the standard 90-day session if at all possible. He also said the House Majority “heard the message loud and clear” from the Senate and will not push for an income tax again this year. The Senate gaveled out from the special session Walker called this fall without taking up his latest proposal for an income tax. Rather, the House will shift its focus to separating education funding from the annual operating budget, overhauling how the Alaska Marine Highway System is managed and paid for, and continue to push for a new, “non-regressive revenue source” for the state that doesn’t disproportionately impact rural Alaska, according to Edgmon. “We can’t simply cut people’s dividends in half and then use the Earnings Reserve to fill the gap — which doesn’t really fill the gap,” he said. The Office of Management and Budget’s 10-year forecast recognizes inflation but only reflects the costs the state is currently covering with its $4.3 billion unrestricted general fund budget, he stressed. Alaska’s last three capital budgets have mostly been cut to include only mandatory items and the minimum 10 percent state match to formula-driven federal funds for transportation programs crippling the construction industry while the deferred maintenance bill on state facilities has grown to about $1.8 billion. Additionally, Edgmon noted there are still no plans to expedite how the state will pay down its leftover $700 million oil tax obligation, stabilize education funding or handle potential cuts to federal assistance. On top of Edgmon’s unfunded list, state employee retirement payments — $163 million this year — will again grow to over $400 million by 2022, according to OMB. Economists have said long-term the state likely needs to add roughly $1 billion per year to its current annual deficit amounts because of the issues it has put off addressing. Kelly said the Senate Majority will stay focused on cutting the budget, protecting the private sector and getting the Permanent Fund bill to the finish line. “The Senate is going to come from a starting position that we’re in a recession,” he said, contending the state can find its way through its current fiscal issues without new taxes that could further damage the economy. “We can’t make decisions about the long-term future of the state based on what’s hitting us right now.” Alaska crude prices are back above $60 per barrel and there are at least five significant North Slope oil prospects that could grow production beyond the incremental increases of the past couple years, he stressed. Kelly said it’s a “pretty safe assumption to say we’re going to have 300,000 to 500,000 (additional) barrels per day flowing in 2021.” However, getting there would mean those projects would have to meet or beat in-service schedules and high-end production estimates. As a result, with further budget cuts and the addition of $2.1 billion and growing of Permanent Fund revenue each year the state can live off its reserves and have a balanced budget by 2023, according to Kelly. He said further that the Walker administration has lacked the innovative ideas needed to reform government and instead, along with House Democrats, has just said government needs more money. Kelly touted his Medicaid reform bill passed in 2016, which could save the state up to $400 million over six years. The bill got strong bipartisan support and directs agencies to study more structural changes to how chronic health issues are managed and how the state administers its own health care and insurance programs. The expected savings come largely from taking advantage of federal health care laws that give states opportunities to secure more federal funding for existing programs. Revenue forecast up The Department of Revenue issued the official Fall 2017 Revenue Sources Book Dec. 12 with a revelation that the state will have $247 million more than first thought. That should cut the current-year deficit to roughly $2.5 billion. The downside is that the new money is short-lived; it’s coming from unexpected back production tax payments made after the preliminary fall forecast was released in late October, according to a department release. The $247 million will bump fiscal year 2018 unrestricted revenue up to over $2.1 billion, but the department predicts it will fall back to $2 billion in 2019 and gradually grow to $2.8 billion by 2027. Elwood Brehmer can be reached at [email protected]

‘Aggressive’ timeline for AK LNG needs one year for permitting

State gasline officials have made headway of late with potential buyers and investors in the Alaska LNG Project, but progress on the regulatory side has been harder to come by. The Alaska Gasline Development Corp. filed an environmental impact statement application with the Federal Energy Regulatory Commission, or FERC, for the $43 billion project in mid-April. At nearly 60,000 pages, AGDC leaders said they believed it to be the largest EIS filing in the history of the National Environmental Policy Act process, which became the federal permitting standard in 1970. The size of the EIS filing could end up being a mixed blessing for the project. The 13 exhaustive resource reports that comprise the bulk of the material are the end product of the $600 million the state, BP, ConocoPhillips and ExxonMobil spent evaluating the project during the preliminary front-end engineering and design, or pre-FEED, period, when the companies were equity partners with the state. That arrangement ended last year as the producers handed off the lead role to the state as global LNG prices bottomed out. AGDC emphasizes that the massive filing illustrates the comprehensive nature of the pre-FEED work and limits regulators’ needs for supplemental information; that should help speed the EIS along. President Keith Meyer is targeting a final investment decision on the Alaska LNG Project by early 2019, and, as a result, a record of decision on the EIS by the end of 2018, which he acknowledges is “aggressive.” However, whether AGDC’s regulatory timeline is feasible is still an unanswered question simply because of the project’s size and the need for statutory public comment periods. Also, the municipally-owned Alaska Gasline Port Authority has urged FERC to evaluate routing the Alaska LNG Project to Valdez as opposed to AGDC’s planned Nikiski terminus, but how much consideration the request will receive and how that could affect the EIS timing is also unknown. FERC is generally regarded as one of the most expeditious federal agencies when it comes producing environmental permits but has yet to publish a schedule — which is fungible regardless — for the EIS. Meyer said AGDC can still sign the many binding commercial agreements it needs for the project before FERC issues its record of decision; those agreements would just need clauses indicating they are contingent on a favorable decision from regulators. “If we don’t (get a decision in time) we can deal with it,” he said. AGDC regulatory Vice President Frank Richards wrote a letter to FERC commissioners Nov. 16 requesting, among other things, that the commission publish the Alaska LNG schedule by Dec. 15. AGDC leaders originally hoped FERC’s timeline would be published sooner. “The issuance of a schedule will provide valuable assurance to the market that the regulatory process, and particularly commission review of Alaska LNG, is on track and consistent with Alaska LNG’s (2025) targeted in-service date,” Richards wrote. He said during the corporation’s Dec. 7 board meeting that AGDC is hopeful a final EIS is published by mid-2018 to stay on its desired timeline. Meyer and Richards have stressed the support the project has received from Trump Administration and actions the White House and federal agencies have taken to streamline infrastructure permitting, but to get there it seems FERC would really have to get moving soon. EIS public scoping meetings to determine what all regulators should evaluate were held in late 2015 under the former ExxonMobil-led project structure. The next major step under a standard EIS development would be for FERC to issue a preliminary draft EIS for cooperating federal agencies to review and comment on. Subsequent to that, the resulting draft EIS would be issued, initiating a public comment period of at least 45 days — on very large or contentious projects it is often longer — and associated public meetings. FERC would then respond to the appropriate comments and incorporate them into the final EIS publication, after which a minimum 30-day waiting period must be held before a record of decision on the project is reached. Richards also asked FERC to publish the schedule before getting responses to all of its questions in his Nov. 16 letter, noting the commission could adjust the schedule if AGDC is too slow in responding to stay on track. His team has responded to 584 of FERC’s 801 questions and requests for additional data stemming from the application filed in April as of the Dec. 7 meeting, Richards said. AGDC was waiting for questions on the last of the 13 resource reports at that time as well. Additionally, he urged FERC to adopt or otherwise incorporate the supplemental EIS that the U.S. Army Corps of Engineers is in the midst of finalizing for the smaller $10 billion Alaska Standalone Pipeline, or ASAP, project and defer to the Corps on wetlands issues. “The Alaska District of the Corps of Engineers has regulated the construction of infrastructure projects through Alaska’s continuous and discontinuous permafrost for many decades, and construction planning in Alaska has centered on the application of the Corp of Engineers’ guidance,” Richards wrote. He continued: “The commission should rely on the experience and expertise of the Alaska District of the Corps of Engineers and require a duplicative demonstration justifying a waiver of the Office of Energy Projects’ wetlands procedures. If not waived, these procedures will have a significant impact on project construction planning, schedule and cost.” Such a waiver would lift wetlands construction and mitigation requirements from FERC’s Office of Energy Projects that are more restrictive than those the Alaska District of the Corps uses, according to Richards. AGDC notes the pipeline corridors for Alaska LNG and ASAP are virtually identical and therefore evaluation of the route does not need to be duplicated. The primary differences in the two pipelines is the line for the ASAP project, meant for in-state gas use, is 36 inches versus the 42-inch Alaska LNG pipe and would stop near Big Lake in the Matanuska-Susitna Borough. The Alaska LNG line would continue south, cross beneath Cook Inlet and end at the LNG plant in Nikiski. Experts have said EIS for the Alaska LNG is basically three separate evaluations in one document; one each for the North Slope Gas treatment plant, the pipeline and the Nikiski plant. ASAP decision delayed While AGDC wants FERC to use the Corps’ ASAP work, the Corps added public meetings to the supplemental EIS for ASAP and thus has pushed back its schedule for issuing a decision on the backup gasline project to July, according to Richards. Prior to the adjustment AGDC had been expecting a final supplemental EIS in December with a record of decision in March. In late 2012, the Corps approved an EIS for a smaller version of ASAP with a 24-inch pipeline but when the state upped the size of the proposed gasline to 36 inches, the Corps determined differences between the in-state plans — changes to the gas conditioning modules, a North Slope barge dock, pipeline route and a smaller overall footprint with fewer pipeline compressor stations — necessitated an SEIS. The draft SEIS was once expected to be out in mid-2015 but wasn’t published until July of this year. Yukon designation pulled In an unsurprising move, the Environmental Protection Agency’s Region 10 has dropped its push to designate the Yukon River an aquatic resource of national importance, or ARNI, as it relates to the ASAP project. EPA Region 10 officials wrote a letter to the U.S. Army Corps of Engineers Alaska District in late August detailing the agency’s concerns with AGDC’s approach to building the ASAP project through wetlands in the Yukon watershed. Roughly half of the 737-mile pipeline corridor is through the massive river drainage. They did not feel AGDC’s compensatory mitigation plan for filling wetlands in the Yukon drainage was sufficient. Gov. Bill Walker responded with an early October letter to EPA Administrator Scott Pruitt contending Alaska’s wetlands — 43 percent of the state’s acreage — are so vast “it would not be practicable, nor environmentally justifiable, for this project to mitigate for all wetland impacts along the entire pipeline route.” Region 10 officials did not send the Corps a second letter as called for under the 1992 agreement between the agencies that established the process for designating an ANRI, rendering the issue moot, according to Richards. Also, Walker’s former Commerce Commissioner Chris Hladick took over as Region 10 administrator earlier this month after being appointed to the post by Pruitt in October. Elwood Brehmer can be reached at [email protected]

AIDEA approves deal with gas utility for Interior Energy Project

The Interior Energy Project is finally on its way to Fairbanks. After nearly five years of analysis, negotiations, debate and a wholesale route change, the Alaska Industrial Development and Export Authority on Dec. 7 transferred control of the project to the Interior Gas Utility. The IGU is owned by the Fairbanks-North Star Borough and will take over the plan to expand natural gas use in the area. Transfer of the unfinished project mostly means handing off the responsibility to fulfill the $331.2 million development plan the two organizations jointly crafted to complete the IEP. It also includes the $54 million sale of Pentex Alaska Natural Gas Co., which, through Fairbanks Natural Gas and its other subsidiaries, is already trucking Cook Inlet-sourced LNG to supply its group of customers in the core of Fairbanks; the IEP builds on that model. The AIDEA board of directors previously approved the IEP plan and Pentex sale Oct. 26, but technical changes to the finance agreement meant the AIDEA leaders had to approve the amended document again. The Interior Gas Utility board approved the deal Dec. 5. The two first signed a memorandum of understanding establishing the framework of the deal about a year ago. While the MOU first set a deal deadline date of March 31, 2017, it was extended to allow negotiations to continue and give AIDEA project officials time to secure a new gas supply contract needed to support the other aspects of the plan. AIDEA announced success on the gas contract in September. “This represents the culmination of nearly a year of in-depth due diligence and negotiations between ADIEA and IGU. AIDEA welcomes this approval of the sale and financing package that we anticipate will create a unified, locally controlled gas utility for the Interior by next spring,” AIDEA board chair Dana Pruhs said in a formal statement. The Regulatory Commission of Alaska must still approve the agreement by May 31, at which point AIDEA and IGU can officially close the deal. Until then, AIDEA’s lead IEP manager Gene Therriault said the authority will continue to advance the plan under the terms of the MOU while getting concurrence from IGU on all decisions. When the deal closes the authority will resume its more normal role as a financier and loan administrator, Therriault said, adding, “AIDEA will be involved (in the IEP) if and when IGU needs to access bonds.” Additional gas is expected to start flowing from the expanded LNG trucking plan sometime in 2020. AIDEA and Gov. Bill Walker absorbed criticism from some Republican lawmakers in the state when the authority worked out a deal to buy Pentex from its private investors in January 2015. Critics argued it was inappropriate for a state entity to buy the one private utility that had managed to do what the IEP proponents wanted — albeit on a smaller scale and at a higher cost to customers — and ostensibly killed the prospect of a private sector-generated solution to Fairbanks’ energy problems. However, AIDEA leaders contended the move was intended to facilitate consolidation of Fairbanks Natural Gas and IGU to avoid duplicative costs and achieve the operational efficiencies possible through running one utility versus two in a relatively small service area. Some also noted the call for a private solution to Fairbanks’ energy needs had gone unanswered for decades and AIDEA’s purchase of Pentex was the state’s attempt to fix what was for years a problem of high-cost fuel oil and has morphed into primarily an air quality quandary. Fairbanks Natural Gas CEO Dan Britton has long said his utility repeatedly tried to expand its service but could not secure a long-term gas supply contract from Inlet producers to do so. In 2013, leaders of the utilities sparred in front of the RCA over service territory rights for the areas surrounding FNG’s existing business in the core of Fairbanks. The RCA ultimately sided with IGU; setting up the scenario where two gas utilities would operate in the Fairbanks area. Also in the spring of 2013, the Legislature approved a $332.5 million package of grants, loans and bond financing to spur the IEP and tasked AIDEA with managing it. The legislation included a requirement for North Slope-sourced natural gas. At the time there were fears of a gas shortage in Cook Inlet, which drove gas prices higher and left no gas available for the Interior at a viable price. Through much of 2013-14, AIDEA evaluated the feasibility of a North Slope LNG plant to capture potential savings afforded the IEP by cheaper Slope feedstock natural gas. However, the high cost of building on the Slope forced AIDEA to scrap the plan late in 2014 and falling oil prices — a mixed blessing for the project — gave Fairbanks-area residents a reprieve from high fuel oil prices and project leaders additional time to review alternatives. They eventually turned south for a solution as the Southcentral natural gas market stabilized into 2015 and lawmakers agreed to open the IEP financing legislation to an Inlet-sourced option. The pending deal between ADIEA and IGU is the culmination of the second try at the IEP. The structure of the financing exemplifies the complex nature of the project and the unavoidably challenging economics it must overcome. Anatomy of the deal IGU will buy Pentex for the $54 million AIDEA spent on the utility company in 2015, but the purchase also includes the interest ADIEA is required by law to recoup on its in-house investments. Therefore, the final price will be closer to $59.6 million, according to the financing agreement. AIDEA bought Pentex with funds from its own Revolving Fund and did not use the state IEP funds it was given management of in 2013. Currently a start-up utility with no customers or revenue, IGU will use $42.4 million of state IEP grants and other low-interest project loans, which AIDEA now holds and will supply the utility, to buy Pentex. Buying the working utility will also give IGU a revenue stream it can leverage to finance the gas supply and distribution infrastructure buildout set forth in the agreement. The infrastructure financing will also come from the state through AIDEA in the form of about $83 million in Sustainable Energy Transmission Supply Fund loans and $150 million of state-backed bonds. The 50-year loans will be used more as an active line of credit IGU can call upon when needed and defers interest and payments for 15 years after which a 0.25 percent interest rate kicks in. According to AIDEA, IGU can also defer principle payments on the SETS loans if future gas demand doesn’t meet expectations. AIDEA leaders have also been criticized for continuing ahead with a project that needs such favorable financing terms to work. While lower oil prices eased heating fuel prices for Interior consumers, it also meant lowering expectations about how many residents and businesses would make the personal investments needed to convert from fuel oil to natural gas heating systems. It should also be noted that AIDEA — with it expertise in financing and investing in projects above managing them — is complying with its directive from the Legislature in keeping the IEP alive. Doyon offers gas alternative On Nov. 28, Doyon Ltd., the Alaska Native corporation for the Interior region, announced via press release its plans for next summer to drill another oil and gas exploration well in the Nenana area it has been exploring for a decade. A significant gas find near Nenana could be a long-term energy solution for Fairbanks because it is only about 60 miles from the city. Doyon leaders noted as much in their press release, calling it “unfortunate timing” for IGU and AIDEA to commit to their IEP plan. Doing so straps IGU to the $46 million Southcentral LNG plant expansion, $52 million Fairbanks LNG storage and regasification facilities and associated LNG tankers and trucks at least until the state loans on the infrastructure are paid off decades later, Doyon Natural Resources Vice President Jim Mery said in an interview. That, in turn, discourages IGU from buying gas from other sources in the future that could include a North Slope gasline or Nenana if a discovery is made, he said. An AIDEA spokesman noted the gas supply contract recently inked with Hilcorp only runs through 2020 at the request of IGU leadership on the hope the utility can secure a more favorable contract once the is system proven and in place. Doyon has drilled three exploration wells in the Nenana basin with mixed results. While the company is targeting oil first, a 2013 well hit substantial zones of gas-saturated reservoir rock and if not for a faulty geologic trap could have been a commercial find, according to Doyon leaders. Most recently, a well drilled in the summer of 2016 was unsuccessful. IGU General Manager Jomo Stewart said in an interview that the utility wants Doyon to be successful; he emphasized the notion that the LNG trucking portion of the IEP is a placeholder until another gas source is available. “This was always envisioned as a starter project meant to get more gas here. You’re building infrastructure so people could access gas, but then create the utilization of that infrastructure through expanded deliveries of gas,” Stewart said. More than $140 million of planned expenses in the overall project are for gas distribution infrastructure — street-level gaslines for residents and businesses to tie into — regardless of supply source, according to the financing document. Stewart also said the refined designs of today’s small LNG plants makes them mobile enough to be relocated to where they are needed most. “It’s not as simple as backing up tractor-trailers, unbolting and driving away, but it is modular enough that it could be relocated,” he described. “Under a large volume scenario, particularly via pipeline, the expectation is that you could be able to take this LNG facility — you would move it to Fairbanks — the gas to the consumer would go directly into the pipelines that feed the consumer, but you would also have a line that would go to this LNG facility and you would use this LNG facility as peaking capacity and (gas) security.” It could also be used in conjunction with the 5.2 million-gallon LNG storage tank planned for Fairbanks to supply other road system communities that are out of economic reach of a large gasline, Stewart noted, in much the same way the smaller Southcentral plant is currently used for Fairbanks. AIDEA leaders have discussed the possibility of such a scenario, but it is still a hypothetical one. Finally, Stewart said the IEP plan, even if the infrastructure stays put, only feeds the most densely populated areas of Fairbanks and North Pole and additional gas from any source could supply many more customers in the region. Elwood Brehmer can be reached at [email protected]

AGDC gets interest from Tokyo, questions from lawmakers

Legislators got their first chance to publicly question Alaska Gasline Development Corp. officials about a recent agreement with Chinese companies to advance an LNG export project during a Dec. 4 hearing. Meanwhile, AGDC executives in Japan were busy putting the finishing touches on the state-owned corporation’s latest pact to cooperate on developing the $43 billion Alaska LNG Project with potential customers. Shortly after AGDC President Keith Meyer told the House Resources Committee and other legislators in attendance that his team was close to signing a letter of intent with Tokyo Gas Co., the corporation issued a release announcing just that. “Tokyo Gas and Alaska have a special relationship in LNG and I was pleased to host (company President Michiaki) Hirose for meetings and a project update in Juneau this past August to help continue that kinship,” Gov. Bill Walker said in an official statement. The Japanese utility, with more than 11 million customers, was itself a customer to ConocoPhillips’ Kenai LNG plant, which first exported to Japan in 1969. The plant has seen little use in recent years as down prices globally have challenged the competitiveness of Cook Inlet-sourced LNG. “Alaska is a trusted source of LNG. For more than 40 years Tokyo Gas Co. Ltd. received shipments of LNG from Alaska. As the closest source of North American LNG to Japan, with a shipping time of as little as seven days point to point, Alaska LNG is naturally an economic and reliable source of LNG for Tokyo Gas Co. Ltd.,” Hirose said, reiterating AGDC talking points, in the release. The letter of intent is for the sale and purchase of LNG but it also includes a commitment by Tokyo Gas to look at other ways to support the Alaska LNG Project, according to AGDC. Corporation leaders have stressed the distinctions between how its different agreements with potential gas customers and project investors are characterized, highlighting the fact that the Asian utilities and companies AGDC has targeted follow a prescribed schedule in the courtship and very rarely back out from a letter of intent. Spokeswoman Rosetta Alcantra wrote in an email that the Tokyo letter sets the basic principles for the two to “collaborate on exploration of potential purchase of LNG from AGDC; and to evaluate other opportunities to advance Alaska LNG.” That includes potential upstream investment. It is a nonbinding agreement. How the letter differs from the joint development agreement signed Nov. 9 with three giant nationalized Chinese companies or memorandums of understanding with PetroVietnam Gas Corp. and Korea Gas Corp. is unclear. Walker and Meyer said in a press call after announcing the China development agreement that it went beyond the significance of a letter of intent because it involves all parties needed to put the project together — Sinopec, the gas buyer; the Bank of China, a project lender; and the China Investment Corp., an equity investor. The joint development agreement, released by Walker’s office, is a nonbinding document that expires Dec. 31, 2018. AGDC has kept the other letters of intent and memorandums of understanding confidential, citing business considerations in the highly competitive LNG industry. The Legislature afforded AGDC the right to keep its deals private in the 2013 legislation that made it a standalone entity. AGDC was originally a branch of the Alaska Housing Finance Corp. Questions on price, dealing with China Legislators’ questions in the Dec. 4 hearing largely focused on Chinese involvement in the Alaska LNG Project should the joint development agreement come to fruition and whether the North Slope producers are on board with the state’s expectations for the project. AGDC’s Meyer has long said Gulf Coast LNG projects are Alaska’s primary competitors in Asian import markets because of the continued low cost of Lower 48 Henry Hub indexed feedstock natural gas and political pressures that have killed LNG export plans in Canada and Oregon. LNG can be produced and delivered to Asia from Texas and Louisiana for about $8 per million British thermal units, or mmBtu, the standard unit measurement in the industry, according to AGDC. That is assuming a generally static Henry Hub price of roughly $3 per thousand cubic feet, or mcf, of raw gas. One mmBtu of LNG is roughly equivalent to 1 mcf of unprocessed natural gas. Meyer said liquefaction, shipping and other costs total about $5 per mmBtu to deliver Gulf LNG for a minimum customer cost of $8 per unit. While Alaska’s proximity to East Asia makes LNG shipping costs from the state about one-third of that from the Gulf Coast and colder temperatures improve liquefaction efficiency — meaning less gas must be burned to produce the LNG — the cost of the 800-mile pipeline off the Slope is the big cost snag. AGDC estimates the 42-inch pipeline will cost about $8 billion in the larger $43 billion project. As a result, the bundled costs to deliver Slope-sourced LNG to any of AGDC’s prospective customers is about $7 per mmBtu, leaving a $1 netback to the producers for their gas if the project is to compete, Meyer described. He acknowledged the $1 per mcf price is what’s “left over” after accounting for other costs if trying to meet the $8 delivered price threshold, but added the method to arrive at the wholesale gas price is more common in the industry than not. The Lower 48, where gas exported as LNG is priced based on a market index, is the exception, he added. “All these producers deal with a netback throughout the world,” Meyer said. “It’s the standard.” Anchorage Republican Rep. Lance Pruitt asked whether BP, ConocoPhillips and ExxonMobil were on board with the $1 per mcf for gas. Meyer said the producers have not committed to the plan but haven’t rejected it either in preliminary discussions. The $1 per thousand cubic feet price equates to about $1 billion per year for gas, given the project would process about 1 trillion cubic feet per year at full production. “I think we’re going to find that $1 billion a year upstream, compared to nothing, looks pretty good,” Meyer commented. LNG contracts have historically been linked to the price of oil and he said Alaska LNG deals could as well if both sides are comfortable with market volatility. Pruitt and other legislators also noted the state would get about 25 percent of each $1 through its royalty and presumed taxes on the gas. ConocoPhillips still supports the Alaska LNG Project and is in negotiations with AGDC but pricing and numerous other terms have yet to be finalized, according spokeswoman Natalie Lowman. ConocoPhillips Alaska leaders have said the company would prefer to sell its North Slope gas reserves into the Alaska LNG infrastructure and not take a larger role in the state-led project. Similarly, BP spokeswoman Dawn Patience said via email that the company looks forward to better understanding the role of gas owners, such as BP, in AGDC’s customer agreements. Also, AGDC and BP have extended an agreement for the producer to assist the state corporation in developing the project, she added. That agreement, signed about a year ago, is set to expire Dec. 31. Rep. Dan Saddler, R-Eagle River, questioned China’s possible involvement beyond financing and buying LNG, asking if Sinopec would get construction jobs on the project. Meyer said the oil and gas giant won’t have majority involvement, noting some labor will have to come from outside of Alaska simply because the state does not have the workforce to fill the 10,000-plus jobs that will be available. A large construction management firm will oversee the 800 miles of work but smaller Alaska subcontractors will certainly get a lot of work, he said. “I would expect Alaska contractors to have a degree of priority,” he added. Saddler and Palmer Republican Rep. DeLena Johnson also wanted to know if the administration is comfortable working with a communist regime with a long history of human rights violations. “On a moral basis, does it bother you to be dealing with China?” Saddler asked. For his part, Meyer reminded legislators that the country is already the state’s largest export customer; it bought 27 percent of Alaska’s $4.4 billion of exports last year. About half of it was seafood. “This is an extension of that relationship,” he said. Meyer has emphasized the LNG would help China move off of coal as well. He also said the LNG trade could be a tool to improve the country’s geopolitical position because it’s a critical commodity. Pruitt said he’s not concerned about partnering with China but is worried about “what seems like China coming in and letting them own our state.” Meyer stressed that there is no scenario under which the Chinese will have majority ownership in the project; AGDC is looking for up to 25 percent equity investment. “They’ll be a good customer, a good partner, but they’re not going to have a controlling interest,” he said. Pruitt and Saddler sit on the House Finance Committee but were invited to participate in the Resources meeting. Elwood Brehmer can be reached at [email protected]

ANWR clears Senate, Young named to conference panel

The northern edge of the Arctic National Wildlife Refuge is almost open for business after some late maneuvering by Sen. Lisa Murkowski. With the inclusion of Murkowski’s provision to open the ANWR coastal plain to oil exploration in the Senate’s tax reform bill, the Alaska congressional delegation is as close as it has ever been to what would be a landmark victory for the Republicans. In statements following the Senate’s Dec. 2 early morning vote, they described it as a way to jumpstart Alaska’s economy and improve national security by producing more oil domestically. However, it took some last-minute technical adjustments to specific language in the ANWR legislation to keep it viable, which also led to Murkowski having to do an about-face on a longstanding policy stance. The issue arose during initial Senate floor debate on the tax bill Nov. 30, when the Senate parliamentarian deemed the language relating to the regulatory steps needed before holding an ANWR lease sale required consideration from the Environment and Public Works Committee and not just the Energy and Natural Resources Committee chaired by Murkowski. Specifically, the original language directed the Interior Secretary to manage ANWR lease sales under the 1976 Naval Petroleum Reserves Production Act — the law that transferred what is now the 23 million-acre National Petroleum Reserve-Alaska from the Navy to Interior — and follow the requisite regulations. Because an environmental impact statement is required to put together a management plan and hold lease sales in the NPR-A, the decision to lease the coastal plain should’ve also gone through Environment and Public Works, the parliamentarian concluded. Murkowski’s Energy and Natural Resources Committee had been the only non-Budget committee tasked with reviewing her proposal to generate at least $1 billion in deficit-reducing revenue over the next 10 years. The Budget Committee’s directive to find the $1 billion was a nod to Murkowski to introduce the ANWR option as part of the tax bill that needed only a simply majority vote and not meet the filibuster-proof, 60-vote threshold standard for non-budget legislation. The revised language broadened the ANWR management guidelines away from the indirect National Environmental Policy Act reference to “a manner similar to” how NPR-A sales are managed, but Sen. Dan Sullivan said in Dec. 1 press briefing that the technical correction doesn’t eliminate the NEPA process prior to holding ANWR lease sales. In floor debate, Murkowski said the extensive oil production on nearby state lands is proof that Arctic oil development can be done with minimal environmental impact, a point proponents of opening the coastal plain have often made. “Environment and local wildlife will always be a concern, that’s why we didn’t waive NEPA,” she said. Democrats argued that Murkowski’s legislation ostensibly renders environmental reviews of ANWR leasing meaningless because it states the Interior secretary “shall” hold two lease sales, each offering at least 400,000 acres of the 1.5 million-acre coastal plain, regardless of what the reviews conclude. The technical wording change did, though, create uncertainty over what exactly the regulatory process would entail and whether the lease sales would still generate the $1 billion. To offset that, a 5 million-barrel sale from the Strategic Petroleum Reserve authorized in the Energy Committee rider was upped to 7 million barrels on the Senate floor. A Strategic Petroleum Reserve oil sale — something Murkowski had previously been steadfastly against — was first approved in the Energy Committee Nov. 15 as an add-on amendment by Louisiana Republican Sen. Bill Cassidy. He asked for the oil sale amendment to offset his proposal to appropriate $300 million more to Gulf states through the Land and Water Conservation Fund in 2020 and 2021. Murkowski voted for the amendment, which passed out of her committee on a party-line vote, saying the increased revenue to states would help them mitigate the impacts of offshore oil and gas activity. The Land and Water Conservation money is derived from offshore lease revenue and Cassidy said the extra $300 million would go back into restoring damaged coastline. His amendment capped the oil sale at either 5 million barrels or no more than $325 million in revenue. When the Senate voted on the tax bill, the sale limits had been increased to 7 million barrels or up to $600 million to the Treasury; however, Cassidy’s Land and Water Conservation Fund appropriation did not grow. In 2015 Murkowski opposed a Strategic Reserve sale to help pay for a federal highway bill. A Senate Energy Committee press release at the time stated: “Murkowski has long cautioned against calls to sell crude oil from the reserve to pay for unrelated legislative initiatives” because she considers it a “vital national security asset.” Spokeswomen for Murkowski did not respond to questions regarding her stance on the oil sales from the SPR. The ANWR provision isn’t home free quite yet, as it was not in the House version of the tax bill. Therefore it must be approved in a conference committee, which is expected to resolve the differences in the House and Senate bills before the holiday break. Rep. Don Young, picked by House Speaker Paul Ryan Dec. 4 to sit on the tax bill conference committee, said in a statement that there is still a lot of work left for the delegation in its effort to maximize Alaska’s energy resources but he is looking forward to securing a final victory on ANWR. “It’s been over 40 years since this battle began — a generations-long battle that is finally coming to a head,” Young commented. “I thank Speaker Ryan and the House leadership for recognizing my role in this important debate and for entrusting me to be part of the effort to craft an agreement that will positively improve the lives of Alaskans and Americans for generations to come.” While Republicans hold a 240-194 majority in the House, 12 of them sent a letter on Nov. 30 to Ryan and Senate Majority Leader Mitch McConnell pleading for the refuge’s protection. They cite legacy bipartisan support for leaving ANWR intact since Republican President Dwight Eisenhower established its predecessor area in 1960. The Republicans further note the oil under the coastal plain is not worth the troubles likely to accompany it. The U.S. Geological Survey’s mean estimate for oil in the coastal plain is about 7 billion barrels of technically recoverable reserves. In May, Interior Secretary Ryan Zinke ordered the USGS to update the rough 1998 estimate. “If proven, the estimated reserves in this region would represent a small percentage of the oil produced worldwide,” the House Republicans wrote. “Moreover, the likelihood that lawsuits would accompany any development is high. Business-savvy oil companies are more likely to turn to the National Petroleum Reserve, a 23.5 million (acre) area in northwest Alaska specifically allocated for energy development, which is closer to infrastructure and significantly less controversial.” The letter concludes with the representatives stating that on behalf of their constituents they “look forward to working with (Ryan and McConnell) to maintain this longstanding balance that protects and preserves the refuge’s incredible natural resources and wildlife habitat and allows for responsible American energy development elsewhere.” Native corporations, CDQ provisions The final Senate tax bill would also included a deduction for Alaska Native corporations, but an amendment for Western Alaska fishing groups did not make it. Under the bill, Alaska Native corporations would be allowed to deduct either cash payments made into settlement trusts or the market value amount of land contributed to such a trust in the year the contribution was made. The legal and financial implications of putting Native lands into trusts have generally not been an issue until recently as it hasn’t been a common practice. Over the last couple years the Alaska Department of Law in Gov. Bill Walker’s administration has worked to clarify the process for putting Tribal lands in the state into trust status to provide an avenue for Alaska Native Tribes wishing to do so. Nonprofit Bering Sea fishing groups, on the other hand, did not get the clarification they were looking for in the tax overhaul. The six Community Development Quota groups established in 1992 by the North Pacific Fishery Management Council were hopeful the Alaska delegation would be able to add a provision noting the income received from their subsidiary companies is tax-exempt. The CDQ program was intended to be a way to increase local ownership in Bering Sea fisheries. Collectively, the six nonprofit CDQ groups representing 65 communities within 50 miles of the Bering Sea coast receive 10 percent of the annual total allowable catch in most of the fisheries. The profits derived from the harvest quota the groups own is supposed to be invested into economic development programs in their regions. Norm Van Vactor, CEO of Bristol Bay Economic Development Corp., said he is disappointed the tax-exempt language didn’t make the Senate bill, but added that the delegation has assured the groups it is a priority they will keep working. “Everything we do flows back to our communities, so we stressed to (Murkowski) that this provision would be very helpful towards securing our future,” Van Vactor said. The Aleutian Pribilof Island Community Development Association got a private letter ruling from the Internal Revenue Service in 2014 stating subsidiary income derived from fish harvests is not taxable, but BBEDC has taken a more conservative stance and thus has led the push to get the clarification in law, according to Van Vactor. Being on solid tax ground would make it easier for the groups to purchase additional shares of quota from individual quota holders getting out of fishing and turn that into more community investment without the worry about tax implications, he said. “We just want real clarity that our understanding is in fact what the IRS intends because we don’t want to do anything at all that at a later date might come under scrutiny or jeopardize the investments that we might otherwise make,” Van Vactor described. Elwood Brehmer can be reached at [email protected]

Ahtna subsidiary gets reduction in huge fine at Tolsona well

(Editor's note: This story has been updated to include a response by Ahtna Inc.) State regulators substantially reduced the penalty issued to an Ahtna Inc. drilling subsidiary to $92,000 in a final order issued Wednesday morning after company leaders admitted to the gas well violations and rectified them. The Alaska Oil and Gas Conservation Commission initially imposed a fine of $380,000 on Tolsona Oil and Gas Exploration LLC in late May for the company’s prolonged failures to install pressure gauges on its natural gas exploration well, monitor the well casing pressure and to even respond to repeated demands by the commission to do so. The wholly-owned Ahtna subsidiary spudded the Tolsona-1 well near Glennallen in September 2016, but technical challenges with the 5,500-foot well led the drilling to take about 54 days, according to Ahtna, about twice as long as originally expected. By mid-December, the company was preparing to suspend the well when pressure began to build between inner well casings. Tolsona notified the AOGCC of the issue, bled the pressure and the commission required the company to monitor the pressure for four weeks, according to the order. In January, the commission further required Tolsona to install a pressure gauge on an outer well casing and similarly report monthly pressure readings. The company said in February it would meet the requirement. However, Tolsona officials did not follow through with the pressure reports or return subsequent emails and phone calls from the commission. That led the AOGCC to issue a proposed enforcement action in mid-April, to which the company again didn’t respond. As a result, the AOGCC issued the $380,000 proposed penalty May 24. The Alaska Oil and Gas Conservation Commission is a technical state regulatory body responsible for oversight of subsurface oil and gas activity. Ahtna did not dispute the commission’s timeline of events during a Sept. 12 hearing on the matter. Tom Maloney, CEO of Ahtna and Tolsona, said at the time that the company manager responsible for the project never relayed issues to him, despite the fact that the two communicated daily. According to the documents, Maloney called the commission May 25 and said the company had not received the enforcement notice and the commission sent copies to him. Tolsona installed the outer pressure gauge June 1. Maloney apologized to the three-member commission at the Sept. 12 hearing for the company’s errors and said an internal investigation revealed problems in its communication chain, which have been rectified. Brewster Jamieson, an attorney for Ahtna, also said at the hearing that because the company was not “simply blowing the commission off” and leaders didn’t know about the problems the fines were excessive also not in line with similar previous cases. The original fines were $10,000 for not installing the pressure gauge and another $10,000 for not submitting the first pressure report in March. Additional fines of $5,000 per day were levied for each of the 50 days the gauge wasn’t in place before the April enforcement notice and $5,000 per day for each day the pressure report was past due. The final $92,000 penalty includes both the $10,000 fines for the initial violations but the accumulating daily penalties were reduced from $5,000 to $1,000 per day. “Tolsona’s demonstrable disregard for regulatory compliance precludes any finding that it acted in good faith,” the final order states. “The unmonitored over-pressured annulus is deemed a serious violation which poses a serious and significant risk to public health. Although there was no injury to the public, the seriousness of the violation, the absence of any effort by Tolsona to correct the violation and the need to deter such behavior weigh strongly in the penalty imposed. “However, the steps Tolsona has taken to ensure compliance with AOGCC regulations on future work, and Tolsona’s statement that it plans to plug and abandon the Tolsona-1 well, warrant reduction of the proposed civil penalties.” The company has 30 days to appeal the ruling to the Alaska Superior Court but issued a statement Thursday morning saying it "appreciates the substanital reduction in penalties from the AOGCC and does not plan to appeal the penalty." "We are proud that the Tolsona project delivered a perfect safety record, provided a boost to the local and statewide economy, created new employement opportunities for Ahtna shareholders and Alaskans, and that we were able to reach and evaluate the targeted zone," the Ahtna statement continues. "We are actively pursuing additional gas exploraiotn opportunities with operators on Ahtna lands in the Copper River basin." Elwood Brehmer can be reached at [email protected]

Doyon keeps up Nenana drilling; touts gas alternative to Cook Inlet

Doyon Ltd. is sticking with its oil and gas exploration program near Nenana. Despite past challenges, the Interior Alaska Native regional corporation announced Nov. 28 that it plans to drill another exploration well in the frontier basin west of Fairbanks next summer. The Totchaket-1 well will be drilled based on the results of a 64 square-mile 3D seismic program shot early this year, according to a Doyon release. Company leaders think their years of exploration around Nenana are close to paying off. “We are especially excited about the recent seismic results because for the first time in this basin we see trapped hydrocarbons,” Doyon CEO Aaron Schutt said in a formal statement. “This could be a game-changer.” Doyon has drilled three exploration wells in recent years on the roughly 240,000 acres of state leases it holds in the area and conducted several seismic shoots. The Native corporation also owns land around Nenana. The results of that drilling have mixed. A well drilled in 2016 did not turn out to be successful, but one drilled in 2013 hit several hundred feet of natural gas-saturated sandstone, according to company officials. If not for a faulty geologic trap, Doyon believes it could’ve produced up to 180 billion cubic feet of gas, or bcf, from the formation and potentially supplied the Fairbanks market for decades. Doyon Vice President Jim Mery said the trap was full of water and the gas in place was under pressured as a result of the fault. “We think the building blocks have been there and that’s why we’ve kept at it. We learn from every project and it informs us as to what we should do next,” Mery said. The Totchaket well will be drilled to 12,500 feet and be about 20 miles north of Nenana and on the east side of the Tanana River, according to Doyon. Prior drilling was done closer to Nenana and west of the Tanana. “Although our primary target is oil, our gas prospects are greater, so it is unfortunate timing to see the Interior Gas Utility ready now to commit to a course of action with (the Alaska Industrial Development and Export Authority) which will tie Fairbanks for at least a generation to imported LNG by truck at much less favorable price projections,” Mery said in the release. He added that by committing to the Interior Energy Project plan to expand natural gas distribution in Fairbanks, the borough-owned utility would kill “the option for use of future Nenana gas as well as foreclosing future opportunities to tap into any North Slope gas export line.” AIDEA spokesman Karsten Rodvik said via email that after the three-year gas supply contract the authority reached with Hilcorp for the project earlier this year expires, IGU can purchase gas from any source. That contract, which kicks in Jan. 1, is included in the $331 million package for IGU to purchase Fairbanks Natural Gas and finance gas infrastructure build out in the Fairbanks area with low-interest state loans, bonds and grant money. IGU leaders have expressed concerns with some of the finer points of the financing terms in the tentative deal with AIDEA, but the start-up utility board is expected to make a decision on it soon. Since its inception in 2013, the Interior Energy Project has been intended as an interim solution to Fairbanks’ high energy costs until a gasline from the North Slope is built. While high fuel oil costs subsided along with oil prices in late 2014 — which has also challenged the economics of the IEP by reducing the incentive for residents to switch to gas — getting more natural gas to the city would also help improve its at-times dangerously poor winter air quality. Mery said in an interview that the gas contract is not the issue; rather, it’s the investment in the LNG supply chain — expanding the Mat-Su LNG plant, tankers and LNG storage in Fairbanks — that will tie the utility to Cook Inlet-sourced gas for years. “Once that entity commits to hundreds of million of dollars of debt they’re wedded to that project. How can they abandon that project to buy cheaper gas? Somebody has to pay for those assets that have been acquired,” he said. “We’re just saying there might be another option; there might be a better option in the relative near term. We’re just throwing that out for the public to consider.” IEP leaders have discussed the possibility of using the LNG supply chain to fuel other communities on the road system if another gas supply for the Fairbanks area is found, but their primary focus has been on getting the project up and running first. Mery has said in the past Doyon could start supplying natural gas about three years after a commercially viable discovery is made. On its current schedule, additional gas is expected to start flowing from the IEP in 2020. IGU leaders could not be reached for comment in time for this story. Mery noted Doyon would have to beat fuel oil prices with its natural gas if it is successful, which the company thinks it can do. Elwood Brehmer can be reached at [email protected]

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