Elwood Brehmer

Audit concludes Mental Health Trust improperly invested $44M

A legislative audit has concluded the Alaska Mental Health Trust Authority invested nearly $45 million in real estate developments over nine years in violation of state law and a court settlement that direct how the authority’s assets are managed. The audit, dated Feb. 8 but released earlier this month by the Legislative Budget and Audit Committee, asserts the $44.4 million instead should have been transferred to the Alaska Permanent Fund Corp. for management within its $65 billion portfolio. Legislative Auditor Kris Curtis emphasized in the 126-page report that the authority’s “board of trustees’ actions appear to be well-intentioned, driven by a desire to maximize revenue for use by beneficiaries” of the authority. Nevertheless, Budget and Audit Committee chair Sen. Bert Stedman, R-Sitka, wants everyone in leadership roles at the authority to resign. “In my opinion there is a cultural issue that exists within the Mental Health structure and I think the entire board along with (CEO) Mike Abbott should submit their resignations,” the typically measured Stedman said in an interview. The Alaska Mental Health Trust Authority is an independent, state-owned corporation that utilizes its assets to better the lives of its beneficiaries, who are Alaskans with mental health and addiction challenges. Stedman said the seven trustees — appointed by the governor and confirmed by the Legislature — could re-apply to the board after resigning, at which point the applications would be considered in the light of the audit report. “You can’t hide behind your mission and claim that your breach of the trust settlement is therefore just. That is laughable,” Stedman said. A 1994 legal settlement and corresponding legislation directed the state to allocate $200 million for the Mental Health Trust. That money, along with one-time revenues from development activities on Trust land — land sales, oil, gas and mineral extraction and 85 percent of timber sale proceeds — was to be handed over to the Permanent Fund Corp., which comingles the Trust assets with its Fund investments. From state fiscal years 2009-2017 the Mental Health Trust Authority invested $39.5 million in seven commercial real estate properties in Anchorage, Cordova and the Lower 48 through the Trust Land Office, which is tasked with managing the authority’s roughly 1 million acres of land holdings in the state. Six of the properties were mortgaged and, according to the audit, portions of those proceeds were used for further real estate investments. Another $4.9 million was used for land development work mostly intended for beneficiary programs, the audit states. The authority can use recurring revenue from land leases or easements more liberally. The $44.4 million came from such one-time revenue streams. For his part, Abbott noted that he has only been with the authority since November and most of the activity discussed on the audit was prior to his appointment by the board. Abbott said in an interview that he has no intention of resigning and he was aware of the audit while going through the hiring process last year. He also said he has not spoken with Stedman about the issues. “I haven’t heard anything yet that made me doubt the motivation of the trustees or their or the staff’s commitment to doing right by the beneficiaries,” Abbott said. “That doesn’t mean that some of what they did wasn’t wrong but I haven’t heard anything that I felt uncomfortable with regarding motivation or intent or anything like that.” He described the real estate purchases as “the Trust investing in itself.” Those investments generated several million dollars more than if the money had been transferred to the Permanent Fund Corp., Abbott added. According to the audit, the seven properties had a collective market value of $98.2 million as of June 30, 2017, with mortgage balances totaling $47.3 million and equity of $50.8 million. “Regardless of if you over-perform or underperform, it’s not that relevant,” Stedman said. “You’re outside your investment policy and that’s not acceptable; so that’s a weak excuse.” A letter dated May 1 by authority board chair Mary Jane Michael responding to a draft version of the audit thanks the auditors for recognizing the trustees’ intentions in making the real estate investments, but also states the board continues to believe its investment choices were appropriate and have grown the amount of spendable income available to the Trust. The board will examine the some of the recommendations made in the audit and if they are deemed to be in the best interest of the beneficiaries they will be implemented, according to Michael. The recommendations made in the audit that the board will consider are to stop investing in commercial real estate through the Trust Land Office and discuss with Permanent Fund officials on how the current real estate holdings can be transferred to the Fund managers. Further, the trustees should fund future program-related investments via the Trust’s income account and reconstitute the Permanent Fund Corp. with the principal funds used on the investments to date. Michael wrote in her response that the trustees would work to revise its asset and resource management policies to incorporate best practices and help the authority comply with state investment laws, as well as implement procedures to ensure the authority complies with state open meetings laws. Those actions were additional recommendations made in the final audit. The authority has paused similar investments and is in talks with Permanent Fund officials on whether or not there is a way for the corporation to manage the authority’s real estate holdings, Abbott said. The audit also concludes that draft legislation considered by the authority board in March 2017 to change its authorizing statutes likely would have been in violation of the 1994 settlement. “Based on the verbatim minutes transcript (of a March 24, 2017 meeting), the proposed legislation was narrowly developed to answer questions in the request for this audit,” the report states. “At the heard of this draft bill was the idea that trustees would have discretion to manage land principal proceeds outside of the (Permanent Fund Corp.).” Stedman called the trustees “indignant” in their management of the assets and their inability to follow the settlement. “They deviated from their investment policy, sometimes for several years, and then backed up and changed their policy. They tried to do a similar thing with the Legislature this year by submitting legislation to basically try to legalize what they were doing and that is questionable at best,” Stedman said. He added that the bicameral Budget and Audit Committee would be formulating its own response to the authority over the coming weeks. And while Stedman insists statute trumps regulation in the hierarchy of operating mandates, Abbott highlighted that upward of five years ago Department of Natural Resources and Law officials wrote and approved a batch of regulations permitting the authority to make the investments that it did, noting those regulations were only finalized after a process that included public notices and opportunities for comment. “The trustees believed that their obligation to the beneficiaries and the sort of different authorities they were working under suggested that they had the authority to make the investment choices that they did. It certainly was not a rogue interpretation that the trustees were making,” Abbott said. He said further that if going forward there is agreement that the authority should not have the ability to make its own investments with Trust principal, that should be clarified and the authority’s behavior will change accordingly. Elwood Brehmer can be reached at [email protected]  

State seeks input on plan for $8.1M in VW settlement funds

The Alaska Energy Authority is asking for ideas about how to spend $8.1 million the state received as part of the 2016 legal settlement stemming from Volkswagen’s use of emissions “defeat devices” in many of its late model diesel cars. The $8.1 million is Alaska’s share of nearly $2.9 billion the German vehicle manufacturer was required to put into trusts to fund mitigation of nitrogen oxides, or NOx, emissions from diesel engines of all sorts nationwide. Nearly $54.5 million was allocated to a trust for federally recognized Tribes nationwide and the rest was allocated to states based on the number of vehicles sold in each state that were equipped with the emissions control defeaters between 2009-2016. In Alaska there were 1,450 such vehicles, which emitted about 10.5 tons of NOx, according to AEA Environmental Manager Betsy McGregor. Nationwide, almost 600,000 vehicles and their owners were affected. VW was also required to spend roughly $10 billion to buy back the vehicles with the devices that purposefully gave readings indicating the cars and SUVs were emitting lower amounts of NOx than was actually the case when tested for emissions outputs. “The vehicles were more (fuel) efficient and more powerful but they released thousands of tons of NOx beyond EPA standards,” McGregor said during a June 4 public meeting in Anchorage. AEA also held meetings in Fairbanks and Juneau to inform the public about its plans and solicit feedback. High concentrations of nitrogen oxides can aggravate respiratory ailments, such as asthma and long-term exposure can lead to the development of respiratory diseases and increase one’s susceptibility to respiratory infections. The particulate emissions can also contribute to the formation of acid rain. The car company was further required to invest $1.2 billion over 10 years to support increased use of zero emissions vehicles in the U.S. Specifically, AEA is asking for feedback on the Proposed Draft Beneficiary Mitigation Plan the agency put together since January — its early ideas on how to spend the money. The agency is trying to use the limited money in the most cost-effective manner, McGregor said, and wants the public’s help in doing so. Currently, the mitigation plan calls for 58 percent of the $8.1 million to be allocated over up to 10 years through competitive grants open to any applicants. That $4.7 million is open to anyone wishing to replace or repower generally pre-2009 model diesel freight trucks, buses, ferries, tugboats or other equipment and vehicles with cleaner burning engines. McGregor emphasized that grant applications must meet a litany of specific criteria to be eligible for the trust funds largely because they are available as a result of a court settlement. Another 12 percent, or $1 million would be available for government-sponsored projects to repower or replace older diesel vehicles or equipment. The final 30 percent of the $8.1 million would be split evenly between federal Diesel Emissions Reduction Act projects, which are primarily diesel powerhouse replacements in rural Alaska, according to McGregor, and projects to add electric vehicle infrastructure in the state. McGregor said AEA officials want the electric vehicle funds to go to coordinated efforts that would help strategically place charging stations along the road system, for instance. “We don’t want a shotgun approach. We want them to be strategically located,” she added. In some cases applications could be given preference depending on the air quality and amount of NOx historically released in a given area. The formal public comment period on the mitigation plan runs from May 1 to July 1 and McGregor said AEA hopes to issue requests for applications in late summer or early fall. “We expect to be funding projects by the end of the year,” she said. The proposed draft plan and additional information is available on AEA’s website, www.akenergyauthority.org. ^ Elwood Brehmer can be reached at [email protected]

AIDEA revises Mustang investment to spur production

Brooks Range Petroleum Corp. has the go-ahead from state regulators and funders to scale back its Mustang development in order to get the long-delayed North Slope oil project into production sooner. On May 31 the Alaska Industrial Development and Export Authority board of directors unanimously approved a pair of resolutions that shift the authority from being an investor-owner in Mustang infrastructure to a lender for Brooks Range’s parent company, Caracol Petroleum LLC. AIDEA will sell its interest in the holding companies — Mustang Operations Center-1 LLC and Mustang Road LLC — that were set up under the original deal for the project’s processing facilities and the five-mile gravel road and pad needed to access the site. Specifically, AIDEA will finance the purchase by Caracol of MOC-1 for $52.5 million and its membership in the road and pad company for $8.5 million plus enough to cover the authority’s investment costs, according to a memo accompanying the resolutions. The loans will be amortized over the time the project is producing oil. The authority will also get options in Alpha Energy Holdings Ltd., which is Caracol’s parent company. AIDEA Executive Director John Springsteen said prior to board approval of the terms that continuing to support the Mustang project is consistent with the authority’s economic development mission and with the state’s broader goal of getting more independent companies to develop oil projects on the North Slope. Fairbanks businessman and board member Bernie Karl, owner of the popular Chena Hot Springs Resort, suggested AIDEA has “bent over backwards” for Brooks Range and authority staff should’ve insisted on a stake in the project’s oil production in exchange for its financing help, but voted in favor of the plan. “The best time to plant a tree is 30 years ago. The second best time is today,” Karl remarked. “Today we are planting a tree.” Deputy Commerce Commissioner and board member Fred Parady said helping Brooks Range reach sustained production will ultimately provide the company and its owners the cash flow needed to meet their obligations as well as move the state forward with a new North Slope development. Mustang is in the small Southern Miluveach Unit on the southwest edge of the large Kuparuk River Unit. It’s estimated to hold 33 million barrels of proven and probable light oil reserves, according Brooks Range. Peak production estimates for the field have been in the range of 15,000 barrels per day. Full development was initially pegged at $580 million, but now is estimated at greater than $750 million, according to AIDEA. It is expected to generate $230 million in state royalties over the 20-year production period. “The true way to monetize this investment is to make it produce and I think it moves us much further down the road of achieving that objective,” Parady said. AIDEA leaders have been debating nearly continuously over how to handle years of delays in the project. The authority first invested $20 million of the $27 million needed to build a five-mile road to Mustang and a 19-acre pad for production and processing facilities in December 2012. At the time Brooks Range leaders said they hoped to have Mustang in production by late 2014. The gravel road and pad — in which AIDEA is an 80 percent owner — were finished in April 2013. In April 2014, AIDEA committed another $50 million equity investment in the $225 million Mustang oil processing facility. Brooks Range Chief Operating Officer Bart Armfield said at the time that the project would start production in late 2015 and likely peak in 2017. In February 2016 management for the authority and Brooks Range agreed to put Mustang in “warm standby” as oil prices in the $30 per barrel range hampered the ability to secure other financing options. Company leaders subsequently told state officials in regulatory filings that Mustang would produce in late 2017, but apparent financing problems ended that prospect. Armfield, now president of Brooks Range, told the Journal in January that the company is also owed more than $40 million in tax credits from the state. The AIDEA memo states that discussions with other potential financiers “made it clear that long-term, third-party financing will only be available for MOC-1 and the (Southern Miluveach Unit) with a definitive demonstration of the capacity/capability of the Mustang field.” Last June AIDEA invested another $2.5 million in MOC-1 to help maintain installed equipment and secure the original investment. On May 31 the AIDEA board also approved a $1 million line of credit to MOC-1 from the Economic Development Account of the authority’s Revolving Fund as “bridge financing” to continue work on the project, according to a second memo from the authority. Brooks Range has less than $200,000 remaining from the $2.5 million that has gone to operational costs such as storage fees and taxes, the memo states further. Repayment of the credit line is to be included in the loan for the transfer of the MOC-1 assets from AIDEA to Caracol. On May 7 the state Division of Oil and Gas approved changes to Brooks Ranges’ plan of operations for the Southern Miluveach Unit and Mustang that the company hopes will finally get the project off the ground. The company plans to install a turnkey “early production facility” with the capacity to produce up to 6,000 barrels of oil per day, which will be trucked to nearby facilities for processing, the filings with Oil and Gas state. Armfield said the company is working to finalize a contract for the early production facility, but declined to comment much further, saying the company would be able to provide more information about its work in the near future. Last fall Brooks Range conducted a flow test of the North Tarn 1-A well on the Mustang pad that produced peak oil flows averaging nearly 1,300 barrels of crude per day with only small amounts of water, according to a company statement at the time. Based on that flow test, Brooks Range leaders developed a new plan around the smaller, early production facility that could have it producing roughly 2,000 barrels per day in the first quarter of 2019 and up to 5,000 barrels per day by the end of the year. According to the AIDEA loan documents, Brooks Range will drill laterals off of existing wells this year to access the oil. Elwood Brehmer can be reached at [email protected]

Gasline corp. withdraws loan application to AIDEA

Editor's note: This story has been updated with the withdrawal of the loan application described in the original story, which follows below. State gasline officials have pulled their loan application with the state’s development bank, Alaska Gasline Development Corp. spokesman Jesse Carlstrom told the Journal Thursday. AGDC’s loan application, discussed during an executive session of the Alaska Industrial Development and Export Authority’s May 31 board of directors meeting, was not to directly finance a portion of the $43 billion Alaska LNG Project the corporation is pursuing. “It was a small loan to explore ways to provide in-state gas to Alaskans,” Carlstrom said. Corporation officials previously would not acknowledge that the application, listed on AIDEA’s May 31 board meeting agenda simply as an “LNG loan” was from AGDC. The application was withdrawn just prior to the Wednesday morning online publication of a Journal story outlining the loan, according to Carlstrom. He declined to comment on the loan amount, citing commercial sensitivity. An AIDEA spokesman previously noted that if the finance authority’s board ever took formal action on the loan its details would have been made public at that time. AGDC officials denied a public records request for the loan application documents June 7, citing "information or trade secrets" that "would cause commercial or competitive harm or damage" to the corporation. AIDEA has not responded to a request for documents sent between the two this year. Both state-owned organizations under the Department of Commerce, Community and Economic Development. AGDC President Keith Meyer has repeatedly emphasized a desire to disperse LNG shipments to remote Alaska communities wherever possible alongside the large LNG tanker shipments to Asian buyers that would be the economic driver of the proposed LNG export plan. Original story Alaska Gasline Development Corp. leaders are asking the state’s development bank for help in financing the Alaska LNG Project, but neither side is willing to say as much. Multiple sources within the state confirmed AGDC has applied for a loan from the Alaska Industrial Development and Export Authority to fund work on the $43 billion LNG export plan; however, when asked if the state-owned gasline corporation had sought help from its fellow state-owned financing authority, an AGDC spokesman provided neither a “yes” or a “no.” “AGDC is actively developing financial and business arrangements that are beneficial to moving the Alaska LNG Project forward,” spokesman Jesse Carlstrom wrote in an email. “Due to the confidentiality and competitive nature of these efforts, AGDC cannot publicly disclose any information at this time.” The agenda for the May 31 AIDEA Board of Directors meeting listed an “LNG loan” as one of the topics the seven-member board would be discussing in an executive session. AIDEA spokesman Karsten Rodvik said the authority had received a loan application to finance an LNG project and authority staff was in the early stages of reviewing the application. “It was just a quick briefing and heads up on a loan that could come before them (for approval) someday,” Rodvik said. He added that it was discussed behind closed doors because of a confidentiality statute that precludes disclosing potentially sensitive information of the authority’s prospective business partners. It is common practice for public bodies to discuss legal, business or personnel matters in an executive session to prevent information that could potentially damage a business deal, for instance, if it became public, but the general topics that are going to be discussed in an executive session must be disclosed. However, in the case of AIDEA and AGDC, both are public entities under the Department of Commerce, Community and Economic Development and their financials are public information. AIDEA officials denied a June 1 records request for the documents related to the “LNG loan” citing the authority’s confidentiality statute, but noted the documents would be made public if the board ever took action on the application. Subsequent records requests submitted June 4 to AIDEA and AGDC seeking documents sent between the two this year are outstanding. The amount AGDC is requesting and under what loan structure is unknown at this point. AIDEA regularly participates with private banks and credit unions in loans for real estate developments. The authority has several loan programs and also invests in energy projects but it is typically required to — unless directed via legislative policy — to achieve commercial returns on its investments, which also often require significant collateral. AIDEA had a net position of more than $1.3 billion at the end of fiscal year 2017, according to its annual report. And while AGDC leaders have made good on their promise over the last two years to not request additional funding from the Legislature while the state continues to run sizable deficits, legislators further challenged them by not granting the agency the ability to accept third-party investments in Alaska LNG in the state budget passed May 12. Enough legislators are concerned that authorizing AGDC to accept outside funds would ostensibly be signing away the Legislature’s control over the project — that of the purse string — and the request was pulled from the budget. The corporation took over control of the project in January 2017 with $106 million remaining from prior gasline appropriations and expects to have $52.5 million at the start of the 2019 fiscal year July 1. An austerity program instituted by AGDC leaders when they took over the project has helped them under-spend on their budget by $35.7 million since. As a result, the corporation should be able to continue operating on its existing funds through June 2019, according to AGDC Finance Manager Philip Sullivan. However, lacking a substantial injection of new money could potentially challenge the ability of the corporation to stay on its desired schedule, which is to have a final investment decision in early 2020. Prior to that AGDC will need to hire at least one, likely multiple, large engineering, procurement and construction firms to manage the massive build-out as well as complete the costly environmental impact statement for the project that is currently being reviewed by the Federal Energy Regulatory Commission. Elwood Brehmer can be reached at [email protected]

Gov, challengers square off for support at oil and gas conference debate

Two challengers for governor took their swings at the incumbent during the Alaska Oil and Gas Association’s gubernatorial debate on May 31 yet the mood was generally light and there was even a fair amount of laughter. But then again, it is still early in the campaign and the full field wasn’t yet set as former U.S. Senator and Anchorage Mayor Mark Begich entered the race on June 1, sending Walker out of the Democrat primary and into an independent bid for reelection with running mate Lt. Gov. Byron Mallott. Later that day, former Lt. Gov. Mead Treadwell also announced he was entering the GOP primary. Journal Managing Editor Andrew Jensen moderated the hour-long debate that focused on oil and gas production, government regulation, the Alaska LNG Project and a few non-related topics submitted from the audience and those watching on Facebook Live. Republican hopefuls Scott Hawkins, an Anchorage businessman, and former state Sen. Mike Dunleavy of Wasilla also stressed continued budget cuts and the prospect of growing the state’s resource development economy by making permitting more efficient. Walker noted the reduction in future deficits via the passage of his landmark legislation to employ a 5 percent structured annual draw on the Earnings Reserve Account of the Permanent Fund and his efforts to lobby federal officials on behalf of ConocoPhillips regarding the company’s North Slope projects. “We closed 80 percent of the fiscal gap. That’s a significant step for the future of (the oil) industry and the future of this state,” Walker said in his opening remarks, adding that he ran for governor in 2010 and 2014 on a resource development platform. Dunleavy and Hawkins are vying for the Republican nomination. Gubernatorial candidate and longtime Republican Kenai Peninsula Rep. Mike Chenault was unexpectedly absent from the debate and announced late Thursday night he is withdrawing from the race. Dunleavy and Hawkins also questioned the role Chinese state-owned companies might play in the $43 billion Alaska LNG Project if it is built. In November Gov. Bill Walker and Alaska Gasline Development Corp. President Keith Meyer signed a nonbinding framework agreement to have oil and gas giant Sinopec buy LNG from the project with the Bank of China and China Investment Corp., the country’s sovereign wealth fund, financing up to 75 percent of the project’s cost. The deal also leaves open the prospect of Sinopec having engineering and construction roles in the project. Dunleavy said he voted for gasline legislation in 2014 that made the state a partner in the project with BP, ConocoPhillips and ExxonMobil, but he questioned how Walker’s administration has handled it now that the state is leading the gasline effort. “I don’t have faith in the administration that they’re going to be able to pull it off,” Dunleavy said of Alaska LNG. He added that if the state is not cautious in negotiating contracts with the nationalized Chinese companies “they’ll tie us in knots.” Hawkins said it is very important for the private sector to lead construction and management of the gasline. Walker responded that China is already Alaska’s largest trading partner, buying much of the state’s seafood, minerals and timber. “When we start drawing lines and saying ‘you can invest, you can’t invest,’ I think that’s a dangerous road to go down,” the governor said. Hawkins, the former CEO of the Anchorage Economic Development Corp. and the owner and founder of Advanced Supply Chain International, a logistics firm, contended the state has a “toxic reputation on Wall St.” because Walker vetoed full payment of oil and gas tax credit certificates in 2015 and 2016. The vetoes, totaling $630 million — and followed by the Legislature’s statutory minimum tax credit appropriation in 2017 — caused small explorers and producers that took out loans underpinned by the credits to default on their payments, ostensibly leading to a credit freeze on the industry in the state. Hawkins called the credits a “tremendously successful” program. He said the credits, which in some instances had the state fund more than two-thirds of oil and gas projects, were probably overly generous but he would be open to a similar program in the future. In response to a question regarding whether the state’s royalty share of North Slope gas should be sold to in-state consumers at a discount to maximize the public benefit if the gasline is built, Hawkins said it would need to be sold at market rates. “Generally, it’s a bad idea to subsidize things,” he added. Walker noted that his administration led the push to pass House Bill 331 this year, allowing the Department of Revenue to sell bonds to pay off the nearly $1 billion outstanding credit obligation once the Legislature passed a long-term solution to the state’s deficit. HB 331 requires the companies to accept a discount of up to 10 percent on the value of the certificates they hold to prevent the state from incurring additional interest costs. A lawsuit has been filed against the administration challenging the constitutionality of the tax credit bonds, as well. Walker hasn’t signed the bill yet. Hawkins also expressed concern over the Alaska Industrial Development Authority’s strategy for getting more natural gas to the Fairbanks area since Walker took office. AIDEA purchased Fairbanks Natural Gas for $52 million in 2015, a deal that set the stage for consolidating the area’s gas utilities, which Interior Energy Project leaders believe will result on operational efficiencies, economies of scale and ultimately lower gas prices to consumers. He said the project is important but it’s become “too government driven.” Dunleavy called it a “work in progress,” while Walker highlighted that regardless of the economic challenges of the project brought on by lower oil prices it is a fundamental way to improve air quality in Fairbanks, which is often the worst in the country during the winter months. ^ Elwood Brehmer can be reached at [email protected]ournal.com.

Explore Fairbanks signs deal on gov’s China trade trip

Alaska travel industry leaders have long been trying to establish a presence in China, and Explore Fairbanks now has its proverbial foot in the door. The lead promoters of the Golden Heart City announced May 25 that a day prior they inked a deal with East West Marketing Corp. to represent them in the largest, mostly untapped visitor market on the planet. Explore Fairbanks CEO Deb Hickok signed the contract in Beijing while part of Gov. Bill Walker’s 12-day “Opportunity Alaska” trade mission to the country which wrapped up May 30. “This contractual relationship between Explore Fairbanks and East West marks another quantum leap for tourism from China to Alaska and for cultural exchange among our citizens,” Walker said in an Explore Fairbanks release. Walker said prior to the trip that the trade mission was largely spurred by China President Xi Jinping’s extended layover in Anchorage on his way home from a meeting with President Donald Trump in April 2017. That same meeting laid the initial groundwork for the ongoing partnership between three large Chinese companies and the Alaska Gasline Development Corp. to collaborate on the Alaska LNG Project, according to Walker. Explore Fairbanks Tourism Director Scott McCrea said in an interview that the tourism arrangement will not only help Explore Fairbanks make traditional business connections with tour operators, travel agents and the like in the country’s top cities, but will also give the Alaska organization a presence on Chinese social media platforms such as WeChat and Sina Weibo, the Chinese version of Twitter. “We think here in the U.S. that we’re tied into our social media — within China I think it’s even more so, and it’s very difficult for us here in the U.S. to know now to use it properly without someone who, one, speaks the language, but is familiar with how to use those platforms to reach out, not just to travel trade (businesses) but to consumers as well,” McCrea commented. The arrangement will also build on the business missions to China that Explore Fairbanks has coordinated with Visit Anchorage and other travel trade companies, such as the Alaska Railroad over the past three years, according to McCrea. Explore Fairbanks officials will certainly welcome visitors traveling to the Interior at any time and for any reason, but in particular they hope partnering with East West Marketing can help raise awareness among Chinese travelers that Fairbanks is the premier place on Earth to see the northern lights. “The Chinese visitor mix is changing and a majority of tourists are now fully independent travelers and seeking unique personal travel experiences,” East West Marketing CEO Alina Xiang said in an Explore Fairbanks release. “Fairbanks offers visitors a fascinating opportunity to experience the northern lights and create a lasting travel memory.” Aurora viewing is the driver behind the direct charter flights that Japan Airlines has operated for about 15 years out of that country to Fairbanks, McCrea noted, and the goal is to eventually establish a similar network in China, he said. China Airlines has flown charters from Taiwan to Fairbanks for three years, but a direct link from China to Alaska has yet to be established. “Without question, for us in Fairbanks, (the aurora) is pretty much the main attraction,” McCrea said. “That’s a big part of our marketing message within China is to promote ourselves as an aurora destination and trying to help position ourselves over other aurora destinations that we know are attracting other Chinese visitors” such as Iceland, Norway and Canada, he added. “These are places that have pretty robust marketing budgets that we can’t quite match, but having this on-the-ground representation is certainly going to help us compete better with those other places.” Elwood Brehmer can be reached at [email protected]

Pebble files revisions to mining plan

Pebble Limited Partnership has made changes to its mine plan that would slow its mining rate but increase its ore processing while potentially lessening the project’s environmental impact, according to a document filed with the Corps of Engineers May 11. The Corps published the five-page overview of the plan changes on the project EIS website May 21. The revisions would cut the peak mining rate from 90 million tons of ore per year to 75 million tons; at the same time the milling rate would grow from 160,000 tons per day in the original plan submitted to the Corps to 180,000 tons per day. Pebble had planned to stockpile up to 330 million tons of low-grade ore mined during the first 14 years for processing in the latter years of the initial 20-year mine. The mining-milling adjustments mean the project would now mine roughly 1.5 billion tons of material — with about 200 million tons of that being waste rock — up from the original plan of 1.2 billion tons. From that, annual production should increase by about 10 percent to 660,000 tons of copper-gold concentrate and 16,500 tons of molybdenum concentrate. Mining more material means the pit dimensions “will increase slightly” from the 6,500 feet long; 5,500 feet wide and up to 1,750 feet deep mine contemplated in the plan submitted in December, according to the five-page summary of the changes. The specific changes to the pit dimensions are not detailed. The onsite power plant will also need to grow from 230 megawatts to 270 megawatts of capacity to accommodate the increased mill throughput, according to Pebble. By not storing the potential acid-generating low-grade ore Pebble will not have to treat runoff water from the stockpile, the document notes. Further changes are also being made to the tailings storage facility. Originally, Pebble designed a single storage facility with two segments, one for bulk tailings and another to hold pyritic tailings. The updated plan includes separating the bulk and pyritic storage areas and moving the bulk tailings storage about 2,000 feet south to incorporate more of the existing terrain into the tailings dam construction, according to Pebble. Oxidization of pyritic tailings can lead to acid rock drainage depending on the amount of sulphur in the tailings. A new, lined pyritic tailings storage facility located closer to the pit will also house potentially acid-generating mine waste during operations. That waste will then be moved into the pit when the mine is closed, allowing the harmful waste to be permanently stored under water and below ground level. The tailings storage changes also eliminates the need for perpetual water treatment of the pyritic tailings and storing the material below-ground also removes all risk of downstream impacts related to a pyritic tailings storage facility failure, Pebble notes. The original plan for two water management ponds has also been changed to a single, much larger lined pond built using rock fill similar to how the tailings storage dams will be built. Pebble spokesman Mike Heatwole wrote via email that the changes were made to enhance the overall project and make environmental improvements to the plan. Milling the low-grade ore throughout the project versus waiting until the end makes for a more efficient mining process, while the other adjustments will help during mine closure, according to Heatwole. He said Pebble couldn’t discuss how the changes impact the project’s economics until the company publishes its preliminary economic assessment, which is expected later this year. Heatwole added that the project’s wetlands impact — pegged at 3,190 acres in the original submittal — has not been fully quantified but Pebble doesn’t expect it to change significantly. Corps of Engineers Project Manager Shane McCoy said as of May 24 Pebble had not submitted engineering designs of the proposed changes, but agency officials expected to get more detailed documents on the new plans soon. “Everything that they have proposed to date is a reduction in the proposed impacts to aquatic resources or navigable waters, so the Corps does not believe these are major changes other than the fact that it’s a reduction in scope,” McCoy said. Finally, Pebble has concluded after further study of its shipping plan that it no longer needs a deepwater port. The company is now proposing to shuttle concentrate containers with barges from the Amakdedori port site to bulk freighter vessels that could moor at two locations 12 and 18 miles offshore from west Cook Inlet port. Consumable materials and fuel would go directly to the port on barges without being lightered, according to Pebble. Cargo is lightered to reduce a vessel’s draft, making the individual portions of the overall bulk shipment lighter to allow for travel in shallower water. Keeping the bulk freighters offshore will end the need for channel dredging and storing up to 20 million cubic yards of dredged material at the port. Pebble is also evaluating the possibility of a “high-tide only” access port to further reduce dredging requirements, according to the outline document. Elwood Brehmer can be reached at [email protected]

Railbelt utilities continue work toward unified structure

Leaders of the largest Alaska electric utilities are inching closer to finalizing an overhaul of how the state’s primary power grid is managed despite continued skepticism from within the group regarding the necessity of the changes. The collection of officials from the state’s Railbelt electric utilities told the Regulatory Commission of Alaska May 23 that they are about six months behind schedule but are hopeful they can reach final decisions on forming a Railbelt transmission company. Known in the industry as a transco, the company would be a transmission-only utility aimed at simplifying the tariff structure in the Railbelt and investing in long-haul electric infrastructure upgrades. The Railbelt region includes the service areas of six electric utilities from Fairbanks to the Kenai Peninsula. Chugach Electric Association CEO Lee Thibert said the formation of a transco, when joined with a proposed Railbelt Reliability Council, would help consolidate expertise currently spread amongst the utilities that face the challenge of attracting qualified technical personnel. “If we can pull these like functions together — the more we can do that and spread the cost of doing it once rather than six ways — I think we’re better off,” Thibert told the RCA commissioners. “That’s going to take a lot of planning and a lot of effort but I think we’re headed in the right direction.” A major selling point of a transco has been the prospect of a single Railbelt transmission tariff to eliminate “rate pancaking” for producers needing to cross multiple service areas to get power to a buyer. Independent power producers have argued the stacked transmission tariffs are an economic barrier to developing low-cost renewable energy in the state’s most populated region. Partially because ownership of the transmission lines is fragmented to each utility’s service area, a utility that owns a segment of transmission and thus is on the hook for it may not be the entity to benefit from an upgrade or new line altogether — therefore eliminating the willingness to invest. Last August, the utility general mangers and CEOs told the RCA they planned to develop a transco business plan towards the end of 2017 and file for a certificate of public convenience and necessity, or CPCN, which is essentially a business license for a regulated utility, in the first half of this year. On May 23, they informed the RCA that they have now targeted the end of the year for having established a governing board to make the final decisions needed to form a transco and subsequently apply for a CPCN. Eric Myers, a business development manager for Milwaukee-based American Transmission Co., said the group has a few tasks to analyze and negotiate through before it can come back and ask the RCA for approval. He described the transco as “essentially a collaboration through service agreements,” meaning the transmission network would continue to be serviced by the utilities that own and maintain the given segments of it today. “(It) is both an efficient and effective way to transfer both those skills and knowledge to make sure the network continues to be reliably maintained,” Myers said. In December 2014, American Transmission Co., or ATC, a transmission-only utility, inquired about the possibility of developing a Railbelt transmission company to spur investment in the system. The utilities ultimately signed a memorandum of understanding with ATC to investigate the feasibility of a Railbelt transco. ATC has experience with the transco model and would provide access to capital through its Lower 48 investors. Subsequently, in June 2015, the RCA demanded the Railbelt utilities move to establish a united electric system. In a letter to legislative leadership, the commission stated it would seek the authority to mandate the utilities to take action if they failed to heed the warning on their own. Myers said discussion regarding a system-wide transmission rates and tariff structures are still ongoing, as are talks about equity participation in future transmission investments. However, he said most topics are down to just a couple alternatives. “We’re not out beating the bushes for alternatives at this point,” Myers commented. “We’re down to the point of figuring out what final ingredients are going to go into this recipe.” The Railbelt Reliability Council would, as its name implies, set a single standard of reliability metrics for the myriad of mechanical and infrastructure pieces that make up a complex electric grid stretching over extremely challenging terrain and environments. The council would also act as an enforcement arm of the system to ensure open-access to the network and that the benefits of economic dispatch — using as much of the lowest-cost power as possible across the system — are realized. The transco would use the reliability standards as an independent benchmark to determine whether or not a given transmission infrastructure project is appropriate, according to Myers. A draft version of a study examining how to establish the council concluded that its board of directors should balance the interests of the utilities and non-utility stakeholders such as independent power producers . The study was commissioned by the Alaska Railbelt Cooperative Transmission and Electric Co., or ARCTEC, and was conducted by Georgia-based GDS Associates, an engineering and consulting firm. It was published May 11. The GDS study also suggests the council be staffed lean, starting with just five employees including an executive director, a finance official, an information officer, an engineer and an administrative professional. It lays out a starting annual budget of just more than $1.5 million. “You need to be efficient and effective in how you implement the RRC because we’re tapping the same pool of resources to get that work done,” Myers said. Chris Rose, the founder and executive director of the nonprofit Renewable Energy Alaska Project known as REAP, said during public testimony to the RCA that such an independent system operator needs to be established in concert with a transco because region-wide planning is a primary aspect to improving the overall power system. Rose, along with smaller, mostly renewable power producers in the region have pushed the RCA and the utilities to form an independent system operator on the belief it would greatly aid in economic dispatch, which, in the Railbelt, generally means giving Fairbanks’ Golden Valley Electric Association more low-cost power options to choose from. Disconnected from the natural gas supply of Southcentral, Golden Valley relies on diesel or fuel oil-fired generation for the lion’s share of its generation capacity. “I don’t want the public or anyone else to think that we didn’t at Golden Valley yesterday call around to find out who the cheapest generator is and buy as much of that power as possible,” CEO Cory Borgeson stressed. “So to the extent that we can kind of perfect that, we have a more efficient market in the dispatch and better coordination is what this is about, but there is economic dispatch going on.” MEA chief still skeptical Matanuska Electric Association General Manager Tony Izzo said he is still skeptical of the near-term necessity of a transco; he instead insists that the utilities set up the reliability council or a system operator in some form and measure what materializes before revisiting the transmission issue. MEA officials believe the real value to ratepayers will come through system-wide economic dispatch and not infrastructure investments. “I’ve looked at a number of capital work plans over the next three to five years and I don’t see a project that is region-wide that meets the cost-benefit test,” Izzo said, noting if state or federal funding were available some transmission projects could be viable for broader economic development purposes. He emphasized that the wheeling tariff must not distort economic dispatch decisions and also needs to provide for equitable cost sharing across the system, which could be a challenge. Izzo and prior MEA leaders have dismissed studies commissioned by the Alaska Energy Authority that contend the Railbelt needs upwards of $885 million of transmission upgrades over the next decade-plus to provide unlimited access to lowest-cost power and fully realize the benefits of economic dispatch. In January 2017, MEA, Chugach Electric and Anchorage Municipal Light and Power signed an agreement to pool their generation resources in an effort to maximize the benefits of the new, more efficient gas-fired power plants each has brought online in the last five years. They contend the voluntary, or loose, power pool will save their ratepayers up to $16 million per year simply by burning less fuel. “I support the transco construct completely; I believe it is something the Railbelt needs. My difference is I’m questioning when we need it and in what order,” Izzo said. He suggested following up on the transco plan a year or so after the Railbelt Reliability Council is formed, adding he wants to see what impacts the possible Chugach-ML&P merger approved to advance by Anchorage voters in the April municipal election could have on the immediate need for a transco. However, Izzo said that MEA would not stand in the way of a transco if the other utilities continue to push forward. ML&P General Manager Mark Johnston contended the reliability council and transmission organization are co-dependent in that the transco needs the operating standards set by the council, which needs the transco as its “boots on the ground” to implement the best economic dispatch. Chugach’s Thibert said that the delta in generation fuel prices between Fairbanks and Southcentral is what will ultimately determine the viability of transmission projects and a large part of the debate over what is needed boils down to how long one wants to plan — for years or for decades. The utilities’ leaders said AEA, which owns 170 miles of transmission lines between Willow and Healy, would be best situated with a long-term planning role in the council. AEA spokeswoman Katie Conway said in a response to questions that the state-owned authority agrees that “a stakeholder-driven, consumer-oriented single operator entity that includes AEA as a board member and active participant is a good idea and is what’s needed in the Railbelt.” She said further that authority officials think any new organization should focus on merit order dispatch as a high priority. “We are pleased with the general progress and direction of the conversation so far and look forward to continuing to participate to bring this idea to a meaningful conclusion — one that results in reduced costs to ratepayers across the state,” Conway concluded. AEA officials point to the fact that the current Kenai Peninsula transmission system, which is a single line between Soldotna and Anchorage, limits the availability of Bradley Lake power when the hydro plant is operated at above 65 megawatts, or just more than half of its capacity. Located across Kachemak Bay from Homer, the Bradley Lake hydro project is also owned by AEA. The oldest part of the line was built originally in 1961 to move power from the small Cooper Lake hydro plant near Cooper Landing to Anchorage, according to the study. It’s that inability to maximize the use of Bradley Lake whenever the utilities want it — at about 4 cents per kilowatt-hour; the hydro plant is the cheapest power source in the region — that limits its usefulness. Additionally, AEA is pursuing a $50 million project to divert part of nearby Battle Creek into the Bradley Lake system, which would increase Bradley’s generation capacity by about 10 percent. Myers said ATC and the utilities would provide monthly updates to the RCA going forward. Commissioner Bob Pickett said the RCA would likely draft a report for the Legislature on the utilities’ progress in carrying out the commission’s 2015 directive sometime near the end of the year. Elwood Brehmer can be reached at [email protected]

Pebble owner loses potential major investor

The company spearheading the Pebble mine is again long on mineral prospects but short on cash after another major potential funder turned away from the project, according to a release from Northern Dynasty Minerals Ltd. Vancouver-based Northern Dynasty Minerals, the sole parent company to Pebble Limited Partnership, issued a statement early May 25 acknowledging that its framework investment agreement with First Quantum Minerals has been terminated. In December, the two Canadian mining firms announced they had reached an option agreement under which First Quantum made an initial $37.5 million payment to Northern Dynasty with plans to make three more similar payments totaling $150 million over four years. At the end of that period First Quantum would’ve had the option to buy a 50 percent stake in Pebble Limited Partnership for $1.35 billion. First Quantum operates six primarily copper, gold and zinc mines worldwide. The pre-development Pebble prospect is Northern Dynasty’s sole project. The initial $150 million was intended to fund the permitting process for Pebble, while the subsequent major investment would have helped develop the mine and its extensive support infrastructure. First Quantum was originally supposed to decide whether or not it would invest in Pebble beyond the $37.5 million payment by April 6, according to the framework agreement. The companies first pushed that deadline back to April 30 and later to May 31. Groups opposing Pebble quickly began pressuring funds with investments in First Quantum to divest their interests in the company if it were to get involved in the Pebble project long-term. Those same groups were able to spend Memorial Day weekend celebrating Northern Dynasty’s announcement. “Today is a victory for Bristol Bay’s tribes,” United Tribes of Bristol Bay President Robert Heyano said in a prepared statement. “Our voices are being heard everywhere from our villages to the boardroom at First Quantum. Quyana (thank you) to First Quantum for listening to reason and divesting from this toxic project. No project is worth more than a culture or a way of life. It’s fitting that this announcement comes right on the cusp of fishing season, where Bristol Bay will once again harvest millions of salmon for the world.” Pebble Partnership leaders have long acknowledged they need to secure another major investor partner before the mine can be built, so what the revelation means for the future of Pebble and Northern Dynasty is unclear. Pebble CEO Tom Collier downplayed the significance of failing to reach an agreement with First Quantum in a formal statement following the Northern Dynasty announcement. Collier said he is continuing on with “business as usual” because he is confident the junior mining company will secure the funding it needs to complete the project’s environmental impact statement. “Pebble remains one of the nation’s most important undeveloped mineral resources. It is on state land and is an important economic asset for Alaska,” he said. “Our project is well defined and we are going to continue communicating with Alaskans about why we believe in the opportunity it represents.” A spokesperson for First Quantum could not be reached for comment. Northern Dynasty held $27.9 million Canadian, or roughly $21 million U.S., in cash on March 31, according to its first quarter financial report issued May 15. At the same time, it had also accrued $13.5 million Canadian in near-term liabilities and total liabilities of $68.7 million Canadian. Northern Dynasty stock closed trading May 25 on domestic markets at 47 cents per share, down 33 percent from its prior closing price of 70 cents per share. The company is also traded on the Toronto Stock Exchange. London-based mining major Anglo American withdrew from Pebble in 2013 after spending more than $540 million exploring the copper and gold deposit. In 2014, fellow British mining firm Rio Tinto donated its 19 percent ownership in Northern Dynasty to the Alaska Community Foundation and the Bristol Bay Native Corp. Education Foundation. Bristol Bay Native Corp. has helped lead the fight against Pebble. BBNC President Jason Metrokin said First Quantum “ultimately came to the right conclusion about the Pebble project”. “I commend First Quantum for exiting the Pebble project,” Metrokin added. “As we have said repeatedly since formally opposing the proposed mine nine years ago, Pebble mine is the wrong mine in the wrong place. The people of Bristol bay and the majority of Alaskans will not trade salmon for gold.” In early April, a group of 50 conservation and outdoor recreation companies and organizations sent a joint letter to First Quantum leaders imploring them to stay out of the Pebble project. Further, a group of Alaska Native leaders from the Bristol Bay-area traveled to First Quantum’s May 3 shareholder meeting in Toronto to deliver a similar message. California Treasurer John Chiang, a trustee to the state’s $360 billion-plus Public Employees’ and Teachers’ Retirement systems, sent a letter to First Quantum leaders Jan. 29 urging them to stay out of the Pebble project because CalPERS officials believe sustainable business practices are fundamental to long-term value growth for shareholders. According to Chiang, the Pebble project would risk the sustainability of fisheries in the Bristol Bay region as well as the fund’s investment in First Quantum. At the time, CalPERS held 4.3 million shares of First Quantum amounting to 0.62 percent of outstanding stock in the company as well as bonds in First Quantum with a maturity value of $2.3 million. Additionally, Environmental Protection Agency Administrator Scott Pruitt, generally seen as a bane to conservation advocates, issued a surprising statement Jan. 26 expressing his “serious concerns” about the impacts of mining activity in the Bristol Bay watershed. As a result, Pruitt said the EPA would not finalize its proposed withdrawal of the 2014 proposed determination to prohibit a large mine in the Bristol Bay region through its Clean Water Act Section 404(c) authority. Pruitt stressed that his decision would not impact Pebble’s environmental review under the National Environmental Policy Act, or NEPA, but it kept a cloud of uncertainty over the project that Pruitt was expected to remove. Pebble Limited Partnership filed its wetlands fill permit application with the U.S. Army Corps of Engineers Dec. 22. The initial application outlined plans to fill 3,190 acres of wetlands at the mine site. While not specific to any mine plan — a point Pebble and parent company Northern Dynasty minerals have stressed — the Bristol Bay Watershed assessment published by EPA in 2014 concluded a mine that would fill more than about 1,100 acres would be too damaging to fish habitat to allow. ^ Elwood Brehmer can be reached at [email protected]

88 Energy to reenter Icewine well to test production capacity

88 Energy is getting ready to test the production capacity of its latest North Slope exploration well as it evaluates seismic data that could lead to more drilling. The small Australian independent explorer plans to reenter the Icewine-2 well on June 11. After pressure gauges are retrieved from down the wellbore, the company will employ a nitrogen lift to recover up to 4,000 barrels of drilling and other fluids from the reservoir before production tests begin, according to a May 21 release on its upcoming operations. The nitrogen gas displaces the down hole fluids and allows them to be removed so, ideally, oil can begin flowing naturally after the process is complete. 88 estimates the work will take 10 to 14 days, after which time the well will continue to be flowed to test its drawdown pressure and decline rate. 88 Energy holds rights to roughly 475,000 acres of contiguous state leases south of the developed area of the North Slope. It also holds a 100 percent interest in about 15,500 acres south of the Point Thomson gas field and adjacent to the western edge of the Arctic National Wildlife Refuge. BP drilled the Yukon Gold-1 well in the area in 1994 and hit oil at several depths of the 12,800-foot well but did not develop it, according to 88 Energy. The company is working from the Franklin Bluffs drilling pad, about 35 miles south of existing North Slope fields, where it drilled the Icewine-1 well in late 2015. Its location adjacent to the Dalton Highway-trans-Alaska pipeline corridor makes it accessible year-round, a rare feature among Slope exploration projects that often require ice roads and winter-only drilling on undeveloped land. The Icewine-2 well, drilled in early 2017, is focused on appraising the unconventional oil resource in the HRZ shale, which 88 Energy describes as “a prolific source rock” in the Brookian geologic formation. The Brookian sequence of formations contains the shallow Nanushuk formation and the Torok sands, which have been the source of multiple large oil discoveries by Armstrong Energy, ConocoPhillips and Caelus Energy in recent years. The belief is the HRZ shale holds similar potential to the Nanushuk and Torok plays if it can be effectively fracked. Additionally, the company is processing 3-D seismic data it acquired this winter over nearly 180 square miles on its large swath of acreage west of the Dalton Highway. 88 Managing Directory David Wall said via email the seismic information will inform company leaders about where their next exploration wells could be drilled. In February the state Division of Oil and Gas approved permits for the company to drill two exploration wells roughly 25 miles west of the Franklin Bluffs pad near the Kuparuk River. The company had older, 2-D seismic over the area but did not feel it was sufficient to support base a drilling campaign on, according to Wall. Evaluation of the 3-D data should be done in midsummer, according to the May 21 release. He said 88 leaders are confident that with the new data and drilling permits in hand they will be able to raise money for further exploratory drilling. New seismic data from the company’s Yukon Gold leases should be available late in the year, as well. ^ Elwood Brehmer can be reached at [email protected]

NANA strengthens in-state business holdings

NANA Development Corp. has bought back into Alaska after a challenging financial period pushed the company to sell several of its subsidiaries. Vice President of Operations Eric Billingsley said in an interview that the Alaska Native corporation pulled the Alaska branches of WHPacific Inc. and GIS Alaska back under its umbrella after selling the Outside offices of the companies. The moves are part of NANA’s broader overhaul of its business model to focus its commercial sector on growth in the state. NANA Development Corp. is the business arm of NANA Regional Corp., which is the Alaska Native corporation for the northwest region of the state. The former Anchorage office of WHPacific has been renamed Kuna Engineering and GIS Alaska’s fabrication facility in Big Lake is now again known as NANA Construction. “We’re glad to have these companies back operating inside of NANA,” Billingsley said. He called the 27-acre Big Lake tract the best fabrication facility in the state given its large size and location, which allows truckers hauling materials to and finished products from the facility to avoid the congested areas of Anchorage and Wasilla. Leaders of the parent company have been encouraged by the gradual but consistent increase in oil prices — now to the mid-$70s per barrel compared to less than $50 per barrel a year ago — as well as recent oil discoveries by ConocoPhillips and other companies exploring on the Slope as indicators Alaska’s oil patch is set to resume growth. “We believe in the state. We believe in the opportunities going forward and we want to continue to prove the services across the gamut to everyone involved, not just to oil and gas but to broad-based commercial businesses as well,” Billingsley said. Kuna Engineering currently has 37 employees and NANA Construction has a workforce of about 190, according to NANA spokeswoman Amy Hastings. She wrote in an email that employment at NANA Construction should remain steady for the foreseeable future and Kuna’s workforce could increase slightly given its work with Teck Resources. The Kuna Engineering team over the years has come to provide a large portion of the engineering work Teck needs at the Red Dog mine, according to Billingsley. Teck operates the Red Dog zinc mine north of Kotzebue, which is located on NANA Regional land. Last year Teck announced that a prospect it had been exploring on state land about 7 miles northwest of Red Dog could be another world-class zinc deposit near what is already a world scale zinc mine if further exploration drilling proves out the resource estimates. Red Dog is one of the largest zinc mines on Earth. Teck is also in the midst of a $110 million upgrade to Red Dog’s mill to increase its production capacity by about 15 percent. Increased zinc prices have helped NANA Development rebound from several tough financial years, according to company leaders. NANA Development, which has roughly 15,000 employees through its subsidiary companies, is also heavily involved in the federal contracting sector. In 2016, the company’s losses in the oil services sector of $61.5 million were part of an overall net loss of $109 million, according to the corporation’s annual report. The corporation absorbed losses in 2014 and 2015 as well. It sold NANA Oilfield Services to shipping and logistics giant Saltchuk in 2016 and also saw Moody’s downgrade $300 million of its corporate debt, citing deterioration in its core businesses, namely oil and gas. NANA sold off WHPacific’s Lower 48 offices last year after holding the company for many years prior. It purchased Grand Isle Shipyard Inc., or GIS, in 2011. GIS was focused on oil and gas support in the Gulf Coast region, according to a NANA release at that time. GIS was then merged with NANA Construction. NANA also operates NMS, a camp services and facilities management firm, and NANA WorleyParsons, an engineering and project management company. Both are significant support service providers on the North Slope. Billingsley said he thinks NANA is in a unique position as a resource owner and an active participant in the resource industry through its support service companies. Keeping businesses like Kuna and NANA Construction also help the parent company and resource owner ensure that development costs are reasonable, according to Billingsley. “There is a suite of services Teck needs to operate the mine and we have the skills and the opportunities to take advantage of those and contract those; so those dollars stay with NANA and we’re also able to provide wages and opportunities for our shareholders,” he said. Billingsley noted that NANA has provisions in its agreements with Teck about using its support companies, but typically doesn’t leverage those provisions. “We want the economically preferable provider and if we’re not, we need to reevaluate some decisions,” he commented. In addition to supporting Teck at Red Dog, Kuna is engaged in rural development work, such as alternative energy projects for Alaska villages. “Really, we believe in Alaska, so all the pieces that weren’t Alaska we just let go,” Billingsley said. Elwood Brehmer can be reached at [email protected]

Successful Slope season stirs optimism at DNR

Alaska’s top resource managers believe a successful exploration season could signal the dawn of a renaissance on the North Slope. Department of Natural Resources Commissioner Andy Mack said that ConocoPhillips going “six-for-six” and finding commercial quantities of oil in all of the exploration wells it drilled last winter is not only encouraging for the company, but for the long-term future of the state as well. “I think what we see is the success rate of drilling wells in the Arctic is really high based on modern technology, really good seismic data, the fact that they’re starting to hone in on the Nanushuk formation. It’s incredibly good news for Alaska,” Mack emphasized in an interview. He pointed specifically to the Putu-2 well drilled near the Native Village of Nuiqsut as strong evidence that those technologies can be combined with targeted measures to reduce the above-ground impacts of exploratory drilling to result in the ability to search for and produce oil from areas that otherwise would face resistance for one reason or another. The Putu-2 well was spudded in February about three miles northeast of Nuiqsut, which sits on the edge of the Colville River delta, and is on the western edge of established Slope oil infrastructure. The area is also just south of the highly prospective Pikka Unit that Armstrong Energy is set to transfer to Papua New Guinea-based Oil Search in June. Spanish oil and gas major Repsol also holds a 49 percent stake in Pikka, according to the state Division of Oil and Gas. Armstrong estimates the Pikka Unit holds roughly 1.2 billion barrels of recoverable oil and could produce upwards of 120,000 barrels of oil per day once fully developed from the shallow and conventional but underexplored Nanushuk oil formation. A development plan for Pikka is currently being reviewed by the U.S. Army Corps of Engineers through the environmental impact statement process. First oil from Pikka is tentatively scheduled for 2023. “It’s hard to overestimate the value of what we see in the Pikka Unit specifically, in the Colville (area) generally, in the NPR-A, and they were able to drill those wells fairly close to the Village of Nuiqsut,” Mack said. “They did so with the support of the borough, with the support of the community — and we understand that’s not 100 percent — but it was a very safe operation and we think it will open the door to more development and similar operations like the one that we saw this winter.” ConocoPhillips first planned to drill the Putu well in early 2017. That exploration plan was a driving force behind Mack overturning his predecessor’s decision and transferring all 9,100 acres in and around Nuiqsut, and once part of the now defunct Tofkat Unit, from the small independent Brooks Range Petroleum Corp. to ConocoPhillips. However, those plans caught the attention of Nuiqsut residents, who became concerned that, among other things, exhaust from a traditionally diesel-powered drilling rig, which would be running continuously for more than two months, would ride the prevailing winds into the community. Kuukpik Corp. is the Native village corporation for Nuiqsut and holds title to about 147,000 acres on the Slope. It jointly holds surface rights along with the state to the Putu acreage, which the Department of Natural Resources awarded to ConocoPhillips in November 2016. The company has also taken on the role of being a public voice for the community of about 400 residents that it answers to. While a relatively small area in North Slope terms, the acreage around Nuiqsut is seen as a potentially rich piece of property given it is adjacent to the Pikka Unit as well as ConocoPhillips’ established Colville River Unit just to the north. ConocoPhillips held the acreage in the early 2000s but had to give it back to the state after failing to meet drilling requirements. Brooks Range also held the leases for years but was unable to secure an access agreement with Kuukpik, according to documents previously submitted to the state. ConocoPhillips Alaska leaders went as far as to state publicly even before drilling commenced that the Putu prospect could someday produce 20,000 barrels per day, a signal of confidence from the usually conservative, publicly traded oil company. Similar estimates were applied to the Stony Hill well, which the company also drilled last winter to the south of Nuiqsut. ConocoPhillips cited the concerns coming out of Nuiqsut as its reasons for deferring the exploration program, a move DNR officials were not happy with because the acreage was awarded to the company on the premise it would drill quickly. Mack eventually agreed to allow ConocoPhillips to keep the leases in August 2017 as long as the company committed to drill the Putu well when it did and pay the state up to $7 million in two installments by August 2020 if the decision is made to bring the area into production. Nuiqsut residents and Kuukpik Corp. focused their requirements on making the drilling as inconspicuous as possible. The drill site was moved about a half-mile farther from the village than initially planned, along with numerous other impact mitigation measures. The drilling rig, owned by Kuukpik, was electrified instead of diesel-fired. It was powered by six 975-horsepower, low-emissions diesel generators set about a mile north of the ice drilling pad. Exhaust scrubbers installed on the generators make them as much as 90 percent cleaner than the traditional drill rigs by capturing much of the sulfur and other particulate matter found in diesel exhaust before it is emitted, according to Kuukpik CEO Lanston Chinn. Multiple sensor stations monitoring for air, water and noise pollution originating from the Putu pad were also installed around Nuiqsut, in addition to other efforts aimed at reclamation procedures and lessening the impacts of gas flaring. Chinn said prior to the drilling that he believed the mitigation measures set a new standard for exploratory drilling, if not Slope-wide, at least on Kuukpik land near Nuiqsut. “They did a great job of executing the plan,” Mack said of ConocoPhillips’ work at Putu. Chinn concurred in a brief interview after the drilling was complete, noting, “There weren’t really any complaints to speak of” coming from Nuiqsut residents. He said further drilling proposals to delineate the Nanushuk formation in the area would be handled on a case-by-case basis. ConocoPhillips has until Aug. 15 to decide whether or not to make a $3 million lease bid-replacement payment to DNR in accordance with Mack’s August 2017 ruling. Mack said the company has not yet made the payment, “but we have every reason to believe from the announcements that we’ve had and heard and our observations that what we’ve proposed has worked.” The $3 million payment equates to a lease sale bid of roughly $320 per acre for the area known to be highly prospective. ConocoPhillips spent up to $111 per acre to win leases in the same general area in the state’s December 2016 North Slope sealed-bid lease sale. However, that payment would only allow the company to keep the area until 2020 and would also commit ConocoPhillips to drilling another well into the Nanushuk within the next two years. Further, the company has until Aug. 14, 2020, to make another $4 million bid-replacement payment if it wants to keep the acreage long-term for development. ConocoPhillips spokeswoman Amy Burnett said via email that the results from the exploration season were promising but the company still had extensive information to review prior to making any decisions about its plans for the 2018-19 winter Slope work season. She also noted that any development of Putu could be done with directional drilling from gravel pads farther away from the village. Mack said state officials would also keep an open dialogue with Nuiqsut residents about what can be done to ensure development around their village does not disrupt their way of life. “What we’re seeing is companies are better than ever at executing extended reach drilling and the actual production facility for the same area that was explored this winter — we have more flexibility, Mack said. “We’re going to continue to have that discussion about subsistence and quality of life and the things that are happening in that village. What I would envision happening is when (ConocoPhillips) gets to the production phase they’re going to be able to place permanent facilities that will not be as close as the exploration project this winter and still effectively produce.” Chinn said it is premature to speculate about permanent Putu development and Kuukpik leaders would discuss the relevant issues with ConocoPhillips when the time comes. More success in NPR-A While the apparent success at Putu is a win for the state given the complex history of exploration challenges in the area, ConocoPhillips also drilled three wells to the west, in the National-Petroleum Reserve-Alaska. Those wells were drilled to better delineate its Willow discovery — another Nanushuk prospect — which was first announced in January 2017. Preliminary estimates from the company put Willow at about 300 million barrels of recoverable oil, with production potential reaching 100,000 barrels per day. Alaska oil experts believe the Nanushuk formation, which for decades hid in plain sight, is largely a western Slope phenomenon; it quickly peters out to the east of the Colville Delta. However, 3-D seismic data indicates the oil-bearing formation could be prolific in the NPR-A, leading the state officials to keep pushing the Bureau of Land Management to revise its management plan for the reserve. Last May, while on a trip to Alaska, Interior Secretary Ryan Zinke issued an order directing the U.S. Geological Survey to update its oil and gas resource estimates for the reserve. That mean estimate, released in December, projects the NPR-A and nearby areas hold upwards of 8.8 billion barrels of oil predominantly in the previously overlooked Nanushuk formation. The previous resource assessment done in 2010 estimated the NPR-A held just 896 million barrels of technically recoverable oil. 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. Mack said the Gov. Bill Walker and his administration would like to see BLM “rebalance the plan.” “We would look forward to a conversation about really defining what areas have (oil and gas) potential in what is the northeast NPR-A and what areas need to be protected,” Mack said. “This is a petroleum reserve. We would take our lead and be listening very carefully to the North Slope Borough, for instance.” State officials have also discussed the issue with area Native corporations and tribes, according to Mack. “Plans are always informed by new information,” he added. While federal land, oil and gas production from the NPR-A — expected to officially commence for the first time late this year with the startup of ConocoPhillips’ Greater Mooses Tooth-1 project — is subject to state taxes. The State of Alaska also receives half of federal royalty and lease sale revenue generated from the NPR-A. Mack said that the administration has made its feelings clear to Zinke, but also noted the NPR-A plan is one of several things the state is advocating to Interior for just in the North Slope region. “There’s an issue of how much we can get done in a short amount of time,” he said. ^ Elwood Brehmer can be reached at [email protected]

Lower costs, federal tax cut boost producers’ share of profits

For at least one quarter, the total taxes paid by Alaska’s largest oil producer appear to contradict a longstanding argument against raising them, but ConocoPhillips maintains that the results jive with its previous statements to the Legislature. Alaska oil industry advocates have fought attempts to raise North Slope oil production tax in part by insisting that “total government take,” an all-in calculation of combined taxes, royalties and fees paid to the state and federal governments, consistently exceeds the share of profits large companies are allowed to keep on the oil they produce at all prices. That claim has generally applied to the three major producers of BP, ConocoPhillips and ExxonMobil, which own the Prudhoe Bay, Kuparuk and Alpine oil fields that provide the lion’s share of North Slope production. More recently Hilcorp has joined those three as a large producer by state taxing standards with more than 50,000 barrels of production per day. ConocoPhillips reported net income of $445 million in the first quarter, while paying $400 million to governments — $298 million to the State of Alaska in royalties, property, income and production taxes, and $102 million in federal corporate income taxes — for a government take of 47 percent while the company correspondingly kept 53 percent of its taxable revenue. Before a one-time $79 million special item expense related to a Trans-Alaska Pipeline System tariff settlement, the company had $524 million in net earnings from Alaska. The company, Alaska’s largest oil producer, is required to break out its Alaska operations in its regular corporate financial reporting to the Securities and Exchange Commission because its activities in the state account for significant segment of its worldwide business. ConocoPhillips Alaska representatives emphasized that total government take is still greater than what the company retained based on its first quarter 2018 earnings. Spokeswoman Amy Burnett wrote in an email that on a net cash flow basis, which has been the basis of its presentations over the years to the Legislature, the company kept $367 million during the first quarter, or 48 percent of its total net cash flow of $767 million. The end net cash flow is calculated, according to Burnett, by adding back a $185 million depreciation expense on the company’s assets to the $445 million profit before deducting $263 million in capital expenditures for the quarter to arrive at the $367 million figure. Alaska Tax Division Director Ken Alper said total government take should generally be in the “low 50s range” at recent prices, but noted that “if you’re in a low 50s paradigm it doesn’t take that much to get further into a high 40s paradigm.” However, on the most basic level, “If in fact they’re now below 50 percent in the first quarter that’s going to be a hard admission for them because their reports are always caveated with how much taxes they pay.” Alper said that the changes in the numbers are driven by lower company costs and federal tax reform, which cut the top corporate tax rate from 35 percent to 21 percent as of Jan. 1. Before the federal corporate tax rate cut, the state share was larger than the producer share at all prices. The federal tax cut now puts the producer share larger than the state’s at prices up to $85 per barrel. Total take The complex state production tax is geared to support small companies and those producing oil from new developments while capturing revenue from the owners of the large, aforementioned legacy fields. ConocoPhillips Alaska leaders asserted in an April 2017 presentation to the House Finance Committee about a proposal to increase production taxes that the company’s share of taxable revenue peaked at 38 percent at oil prices between $70 to $80 per barrel. The company’s share shrank to 15 percent at roughly $45 per barrel and quickly became negative at prices of about $40 per barrel when costs outpaced revenue and the company began losing money on each barrel it produced. Companies and supporters of the current system note the royalty and gross tax require the producers to pay hundreds of millions each quarter during such exceptionally low price periods when they are losing money on each barrel of oil they produce. Burnett stressed, as others in the industry have, that the state’s tax and royalty levels must remain competitive with other regimes around the world so the producers will continue to invest in Alaska’s high-cost North Slope. BP paid $464 million to the state in 2016 when it lost $358 million in Alaska overall, with operating expenses combined with low prices more than erasing the $85 million North Slope upstream profit, according to BP Alaska Region President Janet Weiss. ConocoPhillips paid $492 million to the state in 2016 when it made $319 million here but lost $3.6 billion companywide. State royalties of 12.5 percent to 16.6 percent, depending on the leases where the oil is produced, and the gross 4 percent minimum production tax are collected regardless of a company’s profitability. During its April 2017 presentation at the Legislature, ConocoPhillips estimated the federal government would take 20 percent to 21 percent of the taxable revenue while the state would collect the remaining 41 percent to 42 percent in the $70 to $80 per barrel price band. More recently, during a Jan. 29 House Resources Committee meeting on another oil tax increase bill, company representatives showed a similar slide indicating a company’s would “take” peak at 48 percent when oil prices averaged $65 per barrel when the state got 39 percent and the feds took 13 percent. The chart also shows a large producer is likely profitable at lower prices as well, with the company not going into the red until $35 per barrel oil and still retaining 23 percent of taxable earnings at $40 per barrel prices. While the federal corporate tax calculation is seemingly a simple one — 21 percent of a company’s net earnings after state taxes and royalties are deducted — federal tax credits and depletion allowances mean companies are likely to not always pay the full rate, which would lower the government’s share from the high-level charts ConocoPhillips Alaska leaders used in their testimony to the Legislature, according to Alper. BP reports less-specific Alaska results to the SEC in its public annual reports and ExxonMobil, which discloses very little on any matter as its general practice, does not need to disclose its Alaska financials. BP netted $830 million in upstream Alaska profits, according to its 2017 annual report published in late March — on the back of $3.2 billion in operating revenue — is due to a roughly $500 million federal corporate tax accounting benefit stemming from the tax reform Congress passed in December. BP Alaska held a deferred tax liability of nearly $1.3 billion in 2016; that liability fell to $838 million in 2017, according to the report. A BP spokeswoman referred further questions about the company’s taxes in the state to the annual report. Gross versus net ‘crossover price’ The major producers were not eligible for the state’s now-scrapped North Slope refundable tax credit program, but they can purchase un-refunded credits from small companies to reduce their own production tax liability — potentially at steep discounts. The Department of Revenue estimates roughly $100 million of credits will be sold to the large producers over the next several years. Alaska’s oil price-linked production tax is structured to act as a progressive net profits tax at higher market prices and as a gross tax that ensures the state makes some revenue at lower prices. Whichever calculation between the net profits calculation, with the per-barrel credit that grows at low prices, and the simpler 4 percent gross tax is the one the state applies to tax North Slope oil. Currently, that “crossover” price, where the applied tax switches from the gross to the net tax calculation, is currently at about $65 per barrel based on the latest aggregated data reported to the state by the producers, according to Alper. The crossover price has been falling in recent years as companies have cut costs to while prices have been mostly less than $70 since late 2014 and bottomed at $26 in January 2016. In fiscal year 2015, North Slope operators deducted on average $43.60 in lease expenditures per barrel from the net taxable value of their produced oil, according to the Revenue Department. Today, those lease expenditures have fallen to about $25 per barrel, according to Revenue Department estimates. As a result, the state’s take is at its smallest percentage in relation to the profitability of the oil when near the gross-net crossover price as was the case in the first quarter. ConocoPhillips reported an average realized price of $68 per barrel in the first quarter on its Alaska oil. “There has been more efficiency in the industry and that has made them money but that has also made us money because it lowers the breakeven price of a barrel of oil,” Alper said during January testimony to the House Resources Committee. Unrestricted state petroleum revenue is expected to total $1.8 billion in the current 2018 fiscal year, with $654 million of that coming from oil and gas production taxes and the remaining majority coming from property and corporate taxes and royalties, according to the Revenue Department’s Spring 2018 Revenue Forecast. The state took in $876 million of discretionary petroleum-derived revenue in 2017 and the forecast is for $1.6 billion in unrestricted petroleum revenue in 2019. Supporters of the current system point to the increases in production even amid lower prices from 2015-17 as proof the tax regime is working for both the companies and the state. Alper said in an interview that the numbers between the companies would differ at least slightly because each has different spending patterns, noting ConocoPhillips is generally spending more than the other majors on capital expenditures as it is working to evaluate and develop several large prospects at once. ConocoPhillips drilled six separate exploration and appraisal wells this past winter, its busiest season in 15 years. Members of the Democrat-led House Majority Coalition have cited Department of Revenue reports that the effective production tax rate since 2015 has been as low as at any point in the state’s history as a reason to reform the current tax structure. The average tax rate during the last phase the state relied on a gross production tax prior to 2006 was as low as 6.4 percent in 2004 but generally higher. The economic limit factor, or ELF, tax rates varied depending on the field it was produced from. Alper added that the state paid $50 million in production tax true-ups in April on 2017 tax payments because of “migrating” per-barrel credits that companies can earn in one month and apply to another during years when oil price fluctuations push the tax between the gross and net systems. A similar situation occurred when prices collapsed in the latter half of 2014 and pushed the Walker administration to propose changes that would limit the ability of companies to use “migrating” per-barrel credits. As a result, just a few months of prices above the crossover point does not necessarily lead to additional state revenue, according to Alper. “I think the issue for the people interested in re-engaging in oil taxes is (government take) used to be deeper into the 60s and even into the 70s,” he said. Anchorage Democrat Sens. Berta Gardner and Bill Wielechowski cited a Legislative Research Division memo in a May 4 press release that states Alaska is ConocoPhillips’ most profitable region worldwide “by a wide margin.” “As this state continues to deflect billions of dollars in oil revenues in the form of per-barrel credits, the burden to balance the budget and provide necessary services is solely, and erroneously, forced upon working Alaskans,” Gardner said. “This is not about one company making significant profits. It’s about providing a balance to fixing our economic situation, and it takes all of us to achieve that.” The $445 million first quarter profit in the state, which is after the $79 million TAPS tariff special item deduction, was 39 percent of the company’s overall profit of $1.1 billion despite Alaska accounting for just 15 percent of its global oil and gas production. Further, ConocoPhillips netted an average of $26.18 per barrel of oil equivalent in Alaska during the period, compared to a $10.06 net per barrel average globally. Elwood Brehmer can be reached at [email protected]

As AGDC makes deals, details remain confidential

Those leading the state’s effort to commercialize its North Slope natural gas resources have touted recent agreements with key potential players in the $43 billion Alaska LNG Project as proof the project is viable and ever closer to coming to fruition, but what is in those agreements and how it impacts the state remains largely unknown. Gov. Bill Walker and Alaska Gasline Development Corp. President Keith Meyer signed the Nov. 9 joint development agreement, or JDA, with the government-owned Chinese mega corporations of Sinopec, an oil and gas company, the Bank of China and China Investment Corp. While a nonbinding agreement meant to set the framework for further negotiations, Walker and Meyer have characterized it as a watershed agreement because — in addition to being signed in front of the leaders of both countries — it brought entities into the fold that could finance a majority of the project in exchange for purchasing most of its end product, liquefied natural gas. Specifically, the JDA outlines the prospect of Sinopec signing up for up to 75 percent of the project’s liquefaction capacity with the Bank of China and China Investment Corp., the country’s sovereign wealth fund, providing a corresponding level of debt and equity financing to fund it. It also sets a soft May 31 deadline for the parties to have better defined the roles of each before finalizing those roles with binding deals later this year, as it notes Sinopec could also potentially participate in engineering, constructing or managing the project. It expires Dec. 31. As envisioned, the Alaska LNG Project would produce 20 million tons of LNG per year at full production, but Meyer has said the project could be built in phases if the market, financing or gas supply prevents full up-front development. Other, similar nonbinding agreements with potential Asian LNG buyers Korea Gas Corp., or Kogas, PetroVietnam Gas Corp. and Tokyo Gas have been announced ahead of and after the China JDA, but the details of those deals remain sealed. Walker said at the time that he insisted the JDA be made public despite objections from Chinese officials. On March 27, AGDC announced it had secured two of the world’s largest banks, again, the Bank of China, and Goldman Sachs, to assist the state-owned corporation in raising multiple rounds of debt and equity investment for the project. AGDC officials denied records requests for the memorandums with the other potential LNG purchasers and the contracts with the Bank of China and Goldman Sachs, citing the commercially sensitive information the documents contain. Spokeswoman Rosetta Alcantra wrote in a prepared statement that “Both Goldman Sachs and Bank of China will serve as AGDC’s financing arrangers, underwriters and placement agents for Alaska LNG. Bank of China will focus on raising funds from Chinese sources and Goldman Sachs will focus on U.S. and other international investors.” Additionally, Alcantra wrote, “The two companies will be paid a reasonable fee for services provided. Additionally, they will receive a success fee upon procuring necessary financing for Alaska LNG.”. The Legislature provided the public corporation exceptionally broad authority to withhold documents and information for commercial reasons in Senate Bill 138, the legislation that established an operational path for AGDC to participate in the prior, producer-led iteration of the project, and passed with broad bipartisan support in 2014. However, AGDC has released other contracts it has signed to media outlets, including agreements with Washington, D.C.-based consultants providing services as liaisons between Congress and the Trump administration. In an interview following the Bank of China-Goldman Sachs announcement, Meyer said the corporation works hard to be as transparent as possible through its board of directors meetings and legislative hearings in which AGDC officials testify and update the Legislature on Alaska LNG progress. “We’re dealing with public money and the money is to get a project done and we’re operating in a very, very competitive arena and we’ve got to recognize that. We’ve got to recognize that we’re somewhat handicapped because of this need to be so public,” Meyer said. “We’ve got people who can take pot shots at us in the public arena — having all of our commercial agreements out there posted on the internet by the press. We’ve got to recognize there’s some justification for that, no doubt, but at the same time it hinders us in this very, very competitive landscape and it’s getting increasingly competitive.” Working as a public entity in the closed-door oil and gas realm where success is measured in billions of dollars, Meyer said he welcomes the critiques and comments from Alaskans in positions of power or the public at-large and wants to be responsive whenever possible. “It pains me to get a request for information and not be able to comply. In spite of what you may have been led to believe we’re trying to be as transparent as we can at every turn,” he said. AGDC leaders have been willing to conduct interviews when their schedules allow. Additionally, Meyer noted he instituted a strict policy of following best business practices when he took the helm at the corporation in June 2016. “To me, and I’ve told the folks here, we’ve got to make decisions based on business fundamentals and they’ve got to be scrutinized on that basis. We don’t do a single thing here that has a political motive or has some appearance of something like that. It is strictly focused on execution. We’re trying to build America’s largest energy export project; that’s what we’re focused on; that’s what we’re doing and we’re fighting lots of people bigger than ourselves,” he said. The bank contracts have been withheld at the request of the banks, which didn’t even want their deals with AGDC shared between the two, according to Meyer. He further stressed that when it comes time to spend significant amounts of state money — during a time when the state is running budget deficits — the commitments the corporation makes will be “quite open.” “In terms of the banker deals, those guys get paid when they bring in third party money, not Alaska money; they don’t get paid for Alaska money,” said Meyer, who added they won’t get paid with State of Alaska money, either. “They get paid with a slice of the third party funds they bring in. If they don’t bring in funds there’s no slice that they get.” Most recently, AGDC announced May 7 it had inked a binding agreement with BP on the primary terms of a gas sales contract including price and volume to supply the Alaska LNG Project. As expected and generally understood, the key terms of that deal are confidential given — beyond BP’s desire that they remain classified permanently — AGDC would not want to compromise the similar negotiations it is still in with ConocoPhillips and ExxonMobil. Meyer and Walker said in separate interviews that the gas supply terms, which presumably commit AGDC to buy BP’s produced gas just before it enters the project’s North Slope gas treatment plant, are likely to be made public eventually, but neither could say exactly when. Legislators who have followed AGDC’s progress closely said they are most concerned about the project’s netback to the state treasury and how that might be impacted by the gas supply agreements. Anchorage Democrat and House Resources co-chair Rep. Andy Josephson said he expects AGDC will be required to disclose the terms of the major commitments it makes closer to when the corporation is ready to make its final investment decision, but he wouldn’t want those disclosures to run afoul of any agreements to the contrary. AGDC has pegged its final investment decision for early 2020 to coincide with when the Federal Energy Regulatory Commission has said it will rule on the Alaska LNG environmental impact statement. Meyer has said the state should expect at least $250 million per year in revenue from the project based on high-level financial modeling, while some legislators are wondering what happened to consultant reports that pegged the state’s annual income from Alaska LNG in the billions of dollars when the producer companies were directly involved in the project prior to 2017. A major change in the revenue estimate is largely to due global natural gas and LNG spot market prices that were twice as high in 2014 as they are currently, with delivered LNG prices to Asia now in the $7 per thousand cubic feet range, according to FERC. Senate Resources chair Sen. Cathy Giessel, R-Anchorage, said she appreciates why the gas sale terms are kept close to the vest, but said she wants to know how those terms relate to oil and gas taxes in addition to also having questions about state revenue from Alaska LNG. “What if the state of Alaska during this (project) raises production taxes? Will those added tax liabilities by passed on to AGDC or the LNG buyer?” she questioned. Giessel is the only legislator to have signed a confidentiality agreement with AGDC to review sensitive documents, but she did so prior to the state entity taking control of the project in early 2017 and said it’s her understanding that agreement is not valid for the current iteration of Alaska LNG and the documents produced to support it. She also noted the state taking over the project is not what the Legislature agreed to when it passed SB 138 and may not have given AGDC such broad authority to withhold information. “I believe had we ever envisioned it becoming a state-led project like this we would have structured it differently,” Giessel said. “In (Meyer’s) hands is the sole authority to commit the state and its resources for decades.” ^ Elwood Brehmer can be reached at [email protected]

Final budget deletes receipt authority for state gasline corp.

The Legislature left plenty of items in Gov. Bill Walker’s budget and added to others, but it took out a key provision in the Alaska Gasline Development Corp.’s effort to bring the Alaska LNG Project to fruition. Lawmakers pulled language allowing the gasline agency to accept outside funds from investors, known as receipt authority, for the $43 billion project in the 2018 and 2019 fiscal years. AGDC President Keith Meyer said in a statement to the Journal that he and his team look forward to working with the Legislature on the important aspects of the project as it advances. But lacking a substantial injection of new money could potentially challenge the ability of the corporation to stay on its desired schedule. AGDC leaders expect to have $52.5 million at the start of the 2019 state fiscal year that starts July 1, according to documents from its May 10 board of directors meeting. The state-owned corporation took over control of the Alaska LNG Project in January 2017 with $106 million remaining from prior gasline appropriations. An austerity program instituted by AGDC leaders at that time has helped them under-spend on their budget by $35.7 million since, Finance Manager Philip Sullivan said at the meeting. As a result, the corporation should be able to continue operating on its existing funds through June 2019, according to Sullivan. Senate Resources chair Sen. Cathy Giessel said in an interview that she believes AGDC can continue to advance the project’s environmental impact statement being drafted by the Federal Energy Regulatory Commission. Senate Republicans by and large have been the most skeptical legislators about the administration’s plan for the state-led gasline. FERC is expected to issue a record of decision on the project in March 2020. Meyer said May 10 — before the final operating budget was passed — that the corporation would soon initiate work drafting contracts for engineering, procurement and construction, or EPC, management firms to finish designing and build the project. The different aspects of the complex project — a North Slope gas treatment plant, 807 miles of buried, 42-inch pipeline, a very large LNG plant and marine terminal — will likely require multiple firms with varying areas of expertise to complete, according to Meyer. He has said AGDC has been in discussions with EPC firms for some time. Additionally, AGDC will soon be getting ready for an equity offering, Meyer said May 10. Giessel said she wouldn’t expect the corporation to secure EPC firms with its remaining funding, adding that third-party receipt authority shouldn’t be confused with financing for the corporation. “AGDC has plenty of revenue to continue on with the FERC process,” she said. “That’s what they need to focus on.” With AGDC seeking non-recourse debt and equity to finance the vast majority of Alaska LNG from banks and third-party investors, many legislators are concerned granting the corporation the ability to accept those funds would be ceding most of lawmakers’ oversight of the project. Giessel said AGDC leaders have yet to answer questions regarding how much equity ownership the state will have to give up and for how substantial an investment return among others. “These questions have to be answered before the Legislature gives up its appropriation authority on this project,” she said. The Legislature could revisit funding the project when it convenes next January if AGDC can provide more details on it, Giessel suggested. AGDC spokesman Jesse Carlstrom wrote that as corporation officials work with Goldman Sachs and Bank of China to arrange third party funding they will continue to keep legislators informed on all aspects of the project. “AGDC understands Alaska’s lawmakers are committed to making decisions that are in the best interest of all Alaskans,” Carlstrom said via email. “Throughout the remainder of 2018 and into 2019, AGDC will continue to present the Legislature with the information lawmakers need to make appropriate decisions for the responsible development of Alaska’s vast amounts of proven, stranded, North Slope natural gas.” The House originally limited the receipt authority to $1 billion per year rather than the open-ended language in Walker’s budget. However, some in the Legislature were still concerned the administration could use a procedural maneuver to request unlimited receipt authority through the Legislative Budget and Audit Committee outside of the regular session — a request the Legislature would have no authority to deny. Giessel also noted the Legislature did approve AGDC to use $12 million previously committed to the smaller, in-state Alaska Standalone Pipeline, or ASAP, project for the larger Alaska LNG export plan as the corporation had previously requested. House Resources co-chair Rep. Andy Josephson, D-Anchorage, said he shares AGDC’s concerns about the appearance of the Legislature’s hesitancy to support the project. “Markets and investors may be squeamish that we wont even agree to accept someone else’s money,” Josephson said. “I’ve been told it puts AGDC in a light they don’t want to be in.” He said Walker could call a special session to resolve the matter if he feels it warrants such an action, but Walker said after the session ended May 13 he had no intention to do so for any reason. Josephson noted further that if the Legislature would have acted before this year to implement a fiscal plan and drastically reduce the multibillion-dollar budget deficits it covered with the state’s savings for four years, lawmakers would have more flexibility to control the project. “With $10 billion in savings we could’ve done it ourselves,” Josephson added. Elwood Brehmer can be reached at [email protected]

Former UA Regent sues state over tax credit bonding plan

(Editor's note: This story has been updated from its orginal version to include comments from Eric Forrer, who filed the lawsuit, and his attorney Joseph Geldhof.) Questions regarding the constitutionality of the Walker administration’s plan to pay off the state’s $800 million-plus oil and gas tax credit obligation will likely be answered sooner than later. Former University of Alaska Regent Eric Forrer filed suit against the administration May 14 in Juneau Superior Court, just two days after the Legislature passed House Bill 331 authorizing the Department of Revenue to sell bonds to pay the credits. The lawsuit, filed in Juneau Superior Court, alleges the bond sale would commit the state to debt outside of the restrictions the Alaska Constitution puts on the Legislature’s ability to incur financial liabilities. Administration officials, including Attorney General Jahna Lindemuth, contend the plan is legal because the 10-year bonds would be “subject to appropriation” by the Legislature, which the bond buyers would be aware of, and therefore would not legally bind the state to make the annual debt payments. Department of Revenue officials testified in hearings on the matter that the arrangement has been used in the past to fund other projects. However, Forrer’s complaint argues that “Failure by future legislatures to make funds available to repay the ‘subject to appropriation’ bond scheme contained in HB 331 will have a negative impact on the credit rating of the State of Alaska,” just as not repaying more traditional general obligation bonds would. “The implied promise in HB 331 that future Alaska legislatures will make appropriations to satisfy the ‘subject to appropriation’ bond scheme contained in the legislation essentially amounts to an impermissible dedication of funds contrary to the Alaska Constitution,” the complaint continues. The state Constitution generally limits the Legislature from bonding for debt to general obligation, or GO, bonds for capital projects, veterans’ housing and state emergencies. In most cases the voters must approve the GO bond proposals before the bonds are sold. State corporations can also sell revenue bonds, but those are usually linked to a corresponding income stream and only obligate the corporation to make payments, not the State of Alaska as a whole. Legislative Legal Division attorneys in an April 13 opinion questioned whether the Alaska Tax Bond Corp. that HB 331 authorizes Revenue Commissioner Sheldon Fisher to set up would truly have a revenue stream that could pass legal muster given it would rely on annual legislative appropriations to fund the debt payments. Sen. Bill Wielechowski, D-Anchorage, raised the potential constitutionality issues in the first hearing on the plan in February. Fisher said in testimony on the bill that the department planned to sell roughly $800 million in bonds sometime in late July or August and another, much smaller bond sale would be needed in a couple years to pay off the remaining credits that companies have earned but not yet claimed from the state. The Walker administration hopes that paying off the credits in a lump sum would restart investment by small producers and explorers in Alaska’s oil and gas fields that has been slowed by three years of less-than-full credit payment amounts while the Legislature and the administration debated how to resolve the state’s large budget deficits, according to Fisher and supporters of the plan in the Legislature. The 72-year-old Forrer said in an interview that he filed the lawsuit in the public's interest, adding that "atta boys are pouring in over the transom" since it became public. It's clear the state owes the credit money, he said, but noted it has also lived up to the law by making annual appropriations in line with the statute that spells out the calculation for the oil-price driven minimum credit payment formula in the past two budgets. "The pressure point is coming, we presume, from the banks and the oil companies holding credits," Forrer said. He suggested the Legislature and the Walker administration should have put the bonds up to a vote of the people, as is required for GO bonds, and that they should've expected a court challenge in the absence of additional measures to quell the constitutionality questions surrounding the plan. An amendment to HB 331 by Rep. Scott Kawasaki, D-Fairbanks, that called for a public advisory vote on the bonds was rejected during debate on the House floor. Questions to the Department of Revenue regarding how the suit might impact the bond sale were responded to by the Department of Law. Spokeswoman Maria Bahr said the Revenue Department will review the issue with its legal counsel and, as is general practice, the Law Department would not comment further on the active litigation. One matter state attorneys will likely analyze is whether or not the issue is “ripe” for a challenge given Walker has yet to sign HB 331 into law. The complaint notes that given it is the administration’s bill “the likelihood that HB 331 will become law is as certain as anything can be in the political context.” Forrer's attorney Joseph Geldhof acknowldeged there is a pottntial ripeness issue in filing the suit before HB 331 is officially the law of the land, but said they wanted to give Walker an opportunity to veto the bill and call the Legislature into a special session to address at least this year's credit payments. He said there is "a strong moral obligation" for the state to pay the tax credits, but turning that into a debt that could impact the state's credit rating is not the proper, or legal, way to do it. The suit also alleges a provision in the bill attempting to limit legal challenges to a period within 45 days after approval of a resolution to authorize a bond sale is an unconstitutional restriction on citizens’ abilities to seek judicial review. The provision was added to the bill by the Legislature after the constitutionality issues were raised. "It shows we're running the state like a clubhouse gang and not a real state," Geldhof said. The administration has 40 days to respond to the complaint. Elwood Brehmer can be reached at [email protected]

Hilcorp again lone bidder in Cook Inlet sale

For the second consecutive year Hilcorp Energy had free rein over the state’s annual Cook Inlet oil and gas lease sale. The Houston-based independent producer was again the only company to bid on tracts in the basin, which was revealed Wednesday morning when Division of Oil and Gas officials opened the bids. Hilcorp, the dominant natural gas supplier in the Inlet, spent about $298,000 on eight lease tracts over 16,636 acres, according to the preliminary results tallied by the division. Its bids ranged from $16 to $25 per acre. Most of the leases are on the southern Kenai Peninsula in the Anchor Point area near the onshore Nikolaevsk and Deep Creek units. Those units are mostly gas plays, according to Oil and Gas Director Chantal Walsh, but the company also bought two tracts near BlueCrest Energy’s Cosmopolitan development on the shores of the Peninsula. The near shore Cosmopolitan unit holds both oil and gas, but BlueCrest has focused on developing the oil resource first. Hilcorp also acquired two more leases between the offshore Trading Bay and Kitchen Lights units in the middle Inlet, which is another area with both oil and gas potential. “We’re excited that Hilcorp is still exploring in Cook Inlet,” Walsh said after the sale. In 2017 Hilcorp spent $3.95 million on 20 tracts over both state and federal acreage in the basin. The state’s 2016 Inlet lease sale drew no bids and industry representatives said that was due in large part to the state Legislature debating whether or not to end its oil and gas tax credit program for work in the basin at the time, which it did. Companies used the credits to offset their exploration and development costs. There is also limited interest in Inlet natural gas, as production from the basin supplies the relatively small demand from Southcentral gas and electric utilities and low global LNG prices have killed the economics of exporting Inlet gas. The plans for the Donlin and Pebble mine projects in Western Alaska include piping Inlet-sourced gas to the mines as feedstock for their on-site power plants. Those projects, as well as the possible reopening of the former Agrium, now Nutrien, fertilizer plant in Nikiski could provide new gas demand and trigger more gas development in the basin, but those plans are all uncertain and at least several years away. Elwood Brehmer can be reached at [email protected]

House approves tax credit bonds in split vote

Tangible action in Juneau is ramping up as the session winds down in the final week before legislators bump up against the 121-day constitutional limit. Amidst passing one of the most momentous pieces of legislation in the state’s history May 8 to use the earnings of the Permanent Fund for government services, the Legislature continued to plug away at the other big bill from this year’s session: the Walker administration’s plan to sell bonds to pay off the state’s $800 million-plus oil and gas tax credit obligation. House Bill 331 didn’t gain traction until late into the session but it has been moving along promptly in the past several weeks. It is largely seen as a substantial piece of end-of-session budget negotiations. The House passed its version of HB 331 May 3 on a 22-16 vote that split members of both the Democrat-led majority and Republican minority. The lion’s share of concern with the bill among those who voted against it related to questions about its constitutionality raised by Sen. Bill Wielechowski, D-Anchorage, about Senate Bill 176, its companion legislation . Others voting against the plan argued it would pit the need to make the debt payments against other funding priorities like education and public safety. HB 331 would create the Alaska Tax Credit Certificate Bond Corp. within the Department of Revenue to sell the bonds and pass the proceeds of the sales on to the bondholders, of which there are 37, according to Deputy Revenue Commissioner Mike Barnhill. The bonds would be “subject to appropriation,” meaning the revenue to pay for them would be contingent upon the Legislature appropriating money to pay the debt service each year. The legislation would also require credit holders to accept up to a 10 percent discount on the amount they’re owed to cover the cost of the state’s borrowing and avoid spending additional state money on the all-but defunct tax credit program. Credit holders could also opt for a lesser discount rate in the 5 percent range if they agree with the Department of Natural Resources to negotiate a higher state royalty in future oil and gas production or commit to reinvest a portion of the payment back in Alaska projects. The bonds would be paid off over 10 years. The annual debt payments would be up to $115 million, according to the Revenue Department, and would be smaller than the largest projected payments the state would make paying off the debt under the current statutory formula. Another roughly $200 million bond sale will likely be needed in a couple years to pay off a few remaining credits that are expected to be claimed before the remaining LNG storage and Interior basin credits sunset in 2020, according to Revenue officials, bringing the total bond amount to about $1 billion. Wielechowski, with the support of an April 13 opinion from Legislative Legal Services attorneys, contends the plan could violate the state Constitution, which generally restricts the Legislature from taking on debt outside of voter-approved general obligation bonds for capital projects and times of emergency. The administration, backed by its own legal opinion from Attorney General Jahna Lindemuth, argues the “subject to appropriation” nature of the debt makes it constitutional because it requires annual approval of the debt payments by the Legislature. And while failing to service the debt would undoubtedly damage the state’s credibility among financial markets, there would be no legal requirement to make the payments. The House Finance Committee attempted to address the possibility of a legal challenge by adding a provision to HB 331 requiring any challenges be made within 45 days of a bond sale, the first of which is expected to happen in late summer if the bill becomes law, according to Revenue officials. Additionally, Fairbanks Democrat Rep. Scott Kawasaki pushed an amendment during floor debate to hold a public advisory vote before the bonds are sold in an attempt to mirror the vote needed to sell general obligation bonds. “I think at the very least we owe it to the people of Alaska when we’re passing such large legislation with such a large fiscal impact that will be seen 10 to 15 years to come that we have an advisory vote basically to assert that it is something the people would like to see,” Kawasaki argued on the House floor. The amendment failed 10-28. House Resources co-chair Rep. Andy Josephson, D-Anchorage, suggested that not passing the bill and paying the credits to the small companies that have earned them could lead those companies to sell the credits to the large producers at a steep discount and further “basin control” on the North Slope by the major producers, which was one of the primary things the credit program aimed to change. Eagle River Republican Rep. Dan Saddler said the bonds would provide a predictable payment plan for the Legislature that in recent years has not known what the credit obligation would be in any given year until the Revenue Department published its Spring Revenue Forecast. This year the statutory minimum credit payment would be $184 million, according to the administration. The interest-only debt payment would be $27 million. “These credits are a cloud hanging over our economy and this allows us to clear those clouds up. It’s a practical business deal,” Saddler said in floor debate. A May 1 financial analysis of the plan by former Department of Natural Resources commercial analyst and economist Ed King found that back loading the debt payments, as is Revenue’s plan, could save the state nearly $680 million compared to following the statutory formula repayment schedule that would require payments of nearly $400 million in the next two fiscal years. That’s because it would leave investment return-bearing money in the Permanent Fund Earnings Reserve longer and allow that money to grow. King is the principal at King Economics Group. However, that assumes the Permanent Fund’s investments continue to earn strong returns over that time, and that the legislature does not spend down the savings. Revenue Commissioner Sheldon Fisher has said repeatedly that the administration back loaded the debt payments to give the state several years to get on better financial footing before having to make $100 million-plus annual payments to service the bonds. As of early May 9, HB 311 was in the Senate Finance Committee awaiting amendments from the committee before heading to the Senate floor for a vote. Elwood Brehmer can be reached at [email protected]

Fund value increases in 3Q

The $64 billion Alaska Permanent Fund again earned strong returns in the third quarter of the state fiscal year and going forward its performance is likely going to be scrutinized like never before. Fund managers saw their investments grow by 8.86 percent in the quarter. The Permanent Fund ended the quarter up $4.8 billion for fiscal year 2018 at $64.6 billion, according to a quarterly report released May 2. The Permanent Fund is up 7.65 percent over the prior three years and 8.35 percent over the last five. All of those figures are better than the corporation’s passive index benchmark by at least 1.5 percent. On May 8, the Alaska Legislature quickly and quietly took the long anticipated step of passing legislation to utilize a 5.25 percent of market value draw from the Fund to support government and pay dividends. How much will go to either long-term is still unclear. It is a move the APFC Board of Trustees has advocated for to provide stability in the expectations of Fund managers for long-term investment strategies. The draw in fiscal year 2019, which starts July 1, is expected to be about $2.7 billion. And while the POMV has a nameplate of 5.25 percent, it is done on a five-year look back of the Fund’s average value over that time. That will make it an effective 4.35 percent draw, legislators noted. Those draws will come out of the Earnings Reserve Account, which held $15 billion in net income and $2.6 billion in unrealized gains as of March 31. At 41 percent of the Fund’s total assets, the corporation’s $26.8 billion public equities portfolio returned 11.42 percent fiscal year-to-date, 16.31 percent over the past year and 8.65 percent over the previous three years. The $7.6 billion of private equity and special opportunities investments have done exceptionally well, returning 18.94 percent over the past nine months and 22 percent over the past five years. The success is due in part to the Fund’s co-investment program of 23 investments averaging $46 million each and has netted a 64 percent internal rate of return since it was started five years ago, according to the report. Elwood Brehmer can be reached at [email protected]

Legislature approves draw from Permanent Fund

It took three years, eight iterations of legislation and countless hours of debate filled with both meaningful questioning and pandering rhetoric, but the Legislature was finally able to send the centerpiece of a fiscal plan to Gov. Bill Walker Tuesday afternoon by employing one of the oldest adages known to mankind: keep it simple. A House and Senate conference committee on Senate Bill 26 introduced and passed a bare-bones version of the legislation to establish a percent of market value, or POMV, draw from the Earnings Reserve Account of the $65 billion Permanent Fund in a seven-minute meeting Tuesday morning. By 2 p.m. it had passed the House and Senate on 23-17 and 13-6 votes, respectively. Sen. Anna MacKinnon, R-Eagle River, who has led the push in the Legislature for utilizing the earning power of the Permanent Fund to greatly reduce the state’s ongoing budget deficits, called the day “a historic moment in Alaska’s future” during the brief committee hearing. “Today, (May 8) legislators from across the political spectrum came together for a historic vote to protect Alaska’s Permanent Fund. This bill stabilizes our revenue stream, providing reliable funding for Alaskans who rely every day on state troopers, educators, and health care providers,” MacKinnon further said after the votes. Democrat House leaders noted the approved version of SB 26 is closer to what the Republican-led Senate passed last year, but noted it will help ensure the prosperity of the Fund into the future by discouraging ad hoc appropriations from the Fund that the Alaska Permanent Fund Corp. cannot plan for. “Last year our coalition took charge and responded to the fiscal crisis and ongoing recession. We passed a comprehensive fiscal plan to the Senate that included a POMV draw as part of a larger plan but not the only part of the plan. We felt our plan was fairer because we didn’t want to burden one group over another,” said House Majority Leader Chris Tuck, D-Anchorage, referring to the House inclusion of an income tax to raise about $700 million in addition to the POMV draw. “However, our plan was rejected, which is why many of us voted against SB 26 today. Despite our differences on this bill, today’s vote was an example of lawmakers voting their conscience. The Alaska House Majority Coalition is a nonbinding caucus and today was a good example of that.” Tuck voted against the bill. House Speaker Bryce Edgmon voted for it. The vote similarly split the House Republican caucus as well as members of both parties in the Senate. Walker said in a statement from his office called SB 26 “landmark legislation” that goes a long way towards ensuring the perpetuity of the Fund and the dividend program as well. “By stabilizing revenues, we secure Permanent Fund dividends for our children and grandchildren, and ensure services provided by the Alaska State Troopers, road maintenance crews and teachers will continue for generations,” Walker said. “SB 26 lays the foundation for our economy to grow and prosper. It provides for efficient investment of the Permanent Fund, improves the state’s position in financial markets, and perhaps most importantly, allows Alaskans to be fully confident in the future of their households and their communities.” Alaska Permanent Fund Corp. CEO Angela Rodell joined Walker in commending the Legislature for passing the framework of a structured draw from the Permanent Fund, which aligns with what the corporation’s board of trustees has long advocated. “SB 26 is an important milestone for the Permanent Fund and (the) APFC,” she said. “It gives us the target we have been asking for in order to craft our investment strategy and will ensure the Fund is a resource Alaskans can rely on now and in the future.” While each body passed a version of SB 26 last year, it languished on the sideline of budget debates for more than a year as the contrasting contingencies put on a POMV draw by the House and Senate made it a particularly touchy subject. The House called tied a $600 million-plus income tax and oil production tax increases to a Fund draw and directed one-third of the amount to PFDs. On the other hand, the Senate insisted upon a spending cap and lowered the draw dollar-for-dollar as oil revenues increased to ensure the state did not end up with excess money available to grow the budget in high revenue years. The Senate also set PFDs at 25 percent of the larger POMV draw. The SB 26 about to become law does none of that. It sets a 5.25 percent of market value draw for three years, which drops to 5 percent per year thereafter. It also explicitly states the Legislature shall not appropriate money from the Earnings Reserve in excess of the yearly POMV amount. That’s it. No spending cap, tax talk or dividend split — the last of which will surely elevate PFD politics in the coming years, but at least the budget deficit will be a lot smaller. Legislators supporting the bill also stressed that the draw amount is based on a five-year rolling average of the Fund’s value, which will make the effective 2019 fiscal year draw on July 1 closer to 4.35 percent. Such a rolling average “look back” is common among endowment draws to mitigate the effects of any single year of very high earnings or very high losses. The upcoming 2019 fiscal year draw is pegged at roughly $2.7 billion, which, with the $1,600 per Alaskan PFD established in the operating budget, should leave the state with a deficit of roughly $500 million to $600 million. Without SB 26, the deficit would be in the $2.2 billion range. Anchorage Democrat Rep. Les Gara acknowledged the current SB 26 is far from the fiscal solution he hoped for but noted it is the biggest piece to ending the five-year run of billion-dollar plus deficits that have drained $14 billion from state savings accounts. “Even if it’s not the first thing I would’ve done to solve the fiscal gap I have to do it because the budget deficit is a math problem and this is part of dealing with that math problem,” Gara said on the House floor. He also noted that not addressing the PFD in SB 26 means the entirety of the POMV draw could go towards dividends in high revenue years, however unlikely that is to happen. A $2.7 billion draw would equate to PFDs in the $4,300 per person range this year, Gara added. Sen. Bill Wielechowski, D-Anchorage, said in floor debate that leaving the existing formula in place — that was disregarded by Walker and the Legislature in 2016 and 2017, respectively — means the Legislature will continue to bypass the PFD in law in favor of providing more cash to government agencies. “One statute will inevitably be violated and my prediction is it will probably be that statute that provides for a full dividend,” Wielechowski said. “In fact, that’s what’s happening this year, in this budget. That’s what’s happened the last two years.” Wielechowski is among a bipartisan group of lawmakers that has pushed to put the PFD in the Alaska Constitution. He also challenged Walker’s 2016 veto of half of the PFD all the way to the Supreme Court before losing the case. That case established the precedent that Walker’s veto authority (used in 2016) and the Legislature’s appropriating authority (used to set an $1,100 dividend in 2017) — both enshrined in the state constitution — are superior to any law subsequently passed, including the PFD formula. Staunch conservative Rep. David Eastman, R-Wasilla, argued SB 26 reverses the Legislature’s historic priorities by putting government funding ahead of the PFD and inflation proofing the Fund. “By enshrining this in statute we are putting the value and the longevity and the survivability of the Permanent Fund in third place,” Eastman said. Retiring Juneau Democrat Rep. Sam Kito, who voted against it, said he simply doesn’t trust the Legislature will follow SB 26 any more closely than it has followed the PFD formula or any of the other business and fiscal principles and laws it has bypassed in recent years. With the passage of SB 26, the major items left for the last week of the current session before the Legislature bumps up against its 121-day constitutional limit are the operating budget, which appears close to being resolved, and the capital budget, which should not be controversial. A bill authorizing the sale of bonds to immediately pay off the nearly $1 billion backlog of oil tax credits is also pending. Elwood Brehmer can be reached at [email protected]


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