Elwood Brehmer

ConocoPhillips posts seventh straight quarterly profit

Lower global LNG and natural gas prices took a small bite out of ConocoPhillips’ profits, but the major producer still generated a healthy profit of nearly $1.6 billion in the second quarter. Company executives released the quarterly earnings report July 30. Chairman and CEO Ryan Lance said in a statement accompanying the report that the period was the seventh consecutive quarter the company was able to generate free cash flow and pay for capital investments, share buybacks and dividends out of cash from operations while meeting its operational and financial targets. “ConocoPhillips has embraced an approach to our cyclical industry that we believe will deliver superior returns and create value across a range of commodity prices,” Lance said. “This quarter represents a continuation of strong performance on our business model that prioritizes financial returns, discipline, resilience with upside and shareholder distributions.” The companywide profit was generated from more than $8.3 billion in revenue and translated into earnings of $1.40 per share. ConocoPhillips stock closed trading July 30 at $59.56 per share, up 4.2 percent from the pre-earnings report start to the day. Lance added that company leaders will present a plan detailing their ability to continue the strong returns over the long term at a November investor meeting. ConocoPhillips had achieved profits greater than $1.8 billion for three quarters in a row before the $1.6 billion second quarter net. ConocoPhillips’ total realized price for all of the oil and natural gas it sold during the first half of the year was $50.55 per barrel of oil equivalent, compared to $52.37 in the first six months of 2018, according to the report. The company also continued to realize strong returns from its North Slope Alaska operations, which netted a $462 million profit during the period. However, several special item costs “predominately related to non-cash adjustments for certain state and federal tax adjustments” totaling $81 million resulted in $381 million in adjusted quarterly earnings for ConocoPhillips’ Alaska business segment, spokeswoman Natalie Lowman wrote in an email. ConocoPhillips paid $278 million in State of Alaska taxes and royalties during the quarter as well, according to Lowman. She added that the company has reinvested all of its adjusted Alaska earnings totaling $765 million so far in 2019 back into projects in the state. ConocoPhillips Alaska spent $370 million on capital investments during the quarter. The second quarter also marked the end to one of the company’s largest Alaska exploration seasons, in which eight exploration wells were drilled and tested, Lowman wrote via email. A slide presentation accompanying the earnings report states ConocoPhillips had “encouraging” results from the wells drilled at its North Slope Willow and Narwhal prospects, but the company has not released additional information on the exploration results. ConocoPhillips also announced a deal to purchase the mid-sized Nuna prospect on the North Slope from small independent Caelus Energy, but a purchase price has not yet been disclosed. The $462 million Alaska profit accounted for 29 percent of ConocoPhillips global earnings for the quarter, while the company’s production from the state — dominated by high-value oil — accounted for 16 percent of its total combined oil and gas production. Alaska has also accounted for 23 percent of the company’s overall year-to-date capital spend of $3.4 billion. Elwood Brehmer can be reached at [email protected]

EPA rescinds proposed action to stop Pebble mine

A July 30 announcement from the Environmental Protection Agency means it won’t stand in the way of Pebble Partnership receiving the key federal permit it needs to construct what has become one of the most controversial development projects in the country. EPA Region 10 Administrator Chris Hladick on July 30 signed a 28-page notice at the direction of agency leaders that formally removes the agency’s proposed “preemptive veto” that loomed over the Pebble mine project since it was initiated under former President Barack Obama’s administration in 2014. In an interview Pebble CEO Tom Collier said, “This is a good day for Pebble. It’s a day I wish had happened much sooner, but it’s a good day for Pebble.” The EPA retains its power to eventually prohibit the Pebble mine project under the Clean Water Act. Hladick also wrote that the EPA has other avenues to scrutinize the project such as the 404(q) process, which “elevates” the environmental analysis of projects the EPA believes could have significant environmental impacts through a longstanding agreement the EPA has with the Corps of Engineers. Traditionally, the 404(q) has been used before any final actions regarding a wetlands permit are made, according to Hladick. “EPA believes these processes should be exhausted prior to EPA deciding, based upon all information that has and will be further developed, to use its Section 404(c) authority,” he wrote. Collier added he doesn’t see why the EPA would use the 404(q) and potentially go back to a 404(c) veto in roughly a year — when the Pebble EIS is scheduled to be done — after rescinding it now. Formal statements from Pebble and its parent company, Vancouver-based Northern Dynasty Minerals Ltd., thanked Gov. Michael J. Dunleavy for pushing President Donald Trump’s administration to rescind the proposed restriction. Dunleavy has avoided taking a formal stance on the hotly contested project, but said the EPA’s unusual actions to preclude its development send a bad signal to prospective investors in other projects across Alaska. The Pebble deposit is on State of Alaska land. Hladick is a former commissioner of the Alaska Department of Commerce, Community and Economic Development under former Gov. Bill Walker, who opposed the Pebble mine, and has served as manager to several local governments across Alaska, including the City of Dillingham, a commercial fishing hub in the Bristol Bay region. Pebble’s opponents, which include conservation groups, area fishing lodges, Bristol Bay tribes and Bristol Bay Native Corp., said in statements that the EPA’s latest action disregards the agency’s namesake responsibility, insisting the mine would endanger the salmon area residents rely on for jobs and subsistence harvests. BBNC President Jason Metrokin stressed that the move is inconsistent with the comments EPA Region 10 officials sent to the U.S. Army Corps of Engineers July 1 on the Pebble draft environmental impact statement. Those lengthy written comments —signed by Hladick — stated the project as proposed could have significant adverse environmental impacts and the draft review document lacked important analysis of the project’s downstream impacts, among other things. “A large majority of BBNC shareholders, more than 80%, are concerned about the risks Pebble poses to the region and its fisheries and are opposed to the project. BBNC will always advocate for its shareholders’ best interests and will continue to oppose this inherently dangerous proposal,” Metrokin said. “One thing is certain: the people of Bristol Bay will not stand down. Bristol Bay’s commercial fishery is once again on pace for a record sockeye salmon harvest, but the people, the economy and a way of life that is dependent on these incredible fish are put at risk by today’s decision.” He also asserted that the EPA’s move comes just weeks after agency officials said they had no timeline for revisiting the proposed restriction. Pebble’s Collier said the concerns listed in EPA’s comments on the project review and those from other federal and state agencies were largely the result of overlooked information that is in fact in the roughly 1,400-page EIS. “For the most part the issues that have been raised aren’t of great surprise and aren’t of great significance. I think they’ll be dealt with by the Corps and the third party contractor (working on behalf of Pebble) and we’ll march ahead towards getting our permit,” Collier said. “There’s a reason they call it a ‘draft,’” he added. EPA General Counsel Matthew Leopold directed Hladick in a June 26 memo to reconsider the agency’s proposed 404(c) restriction. Hladick wrote in his 404(c) lifting notice that the Pebble EIS provides an analysis of Pebble’s actual plan, instead of relying on the 2014 Bristol Bay Watershed Assessment, which contemplated several hypothetical mine projects and Pebble claims was written to justify stopping the project. The allegation that the watershed assessment was biased formed the basis for Pebble’s lawsuit against the EPA but it was not invalidated in the 2017 settlement. A January 2016 EPA Inspector General report supported the validity of the assessment, but scolded the agency for months’ worth of missing emails and other procedural missteps related to evaluating the prospective Pebble project. Collier said he doesn’t see a need to invoke the more stringent but somewhat nebulous 404(q). “Sometimes a project just becomes one where decisions are being made at the highest levels of the agency in Washington, D.C.; I think that’s where we are,” Collier said. “So I’m not sure elevation would change a damn thing. You saw that the highest level person at EPA who has not rescued himself and that’s the general counsel (Leopold), was involved in this decision essentially in-lieu of the administrator.” EPA administrator Andrew Wheeler has rescued himself from anything relating to Pebble to prevent a potential conflict of interest stemming from business at a law firm where he previously worked. Leopold sent a letter to Army Corps of Engineers leadership July 25 asking for an extension to the deadline in the 1992 working agreement by which the EPA was supposed to request the 404(q) process be started. That deadline was July 26. Specifically, Leopold asked for EPA officials to have 30 days after the Corps drafts preliminary decision documents for Pebble’s permits before the EPA has to make its decisions regarding the project. That would likely be sometime next year. The EPA began the process to withdraw the proposed Section 404(c) veto — named for where it is found in the Clean Water Act — in July 2017 following the settlement of a lawsuit earlier that year by Pebble against the agency that directed EPA officials to take steps to lift the proposed development prohibition. The settlement, however, did not mandate the proposed veto be lifted, as the EPA has now done, but the action needed to happen before the U.S. Army Corps of Engineers could issue a final wetlands fill permit for the project. The Army Corps of Engineers adjudicates wetlands fill permits on behalf of the EPA for development projects across the country, but the Clean Water Act gives the EPA the authority to override wetlands fill permits the Army Corps issues if it determines the project would have unacceptable impacts to the environment. The EPA has used that authority very sparingly over the decades since the Clean Water Act was passed, but Pebble was the first instance in which it had been invoked prior to a wetlands fill permit being applied for. Pebble applied for its 404 wetlands fill permit in December 2017. In January 2018 in an unexpected move, former EPA Administrator Scott Pruitt suspended the 404(c) withdrawal process after the agency took public comments on the move citing “serious concerns” he had regarding the impacts the large Pebble mine and infrastructure project could have on the area’s salmon fisheries, which support an estimated 14,000 commercial fishing jobs in an otherwise economically depressed region. Pebble has long touted that it would provide roughly 2,000 jobs to Alaska, many of which would be high-paying opportunities in inland parts of the Bristol Bay region that see less benefit from the commercial fishing industry. Elwood Brehmer can be reached at [email protected]

AGDC president outlines path forward; China deal is dead

Interim Alaska Gasline Development Corp. Joe Dubler insists that Alaska is still making unprecedented progress towards a long-sought natural gas pipeline project despite the fact that the lead agency on the effort is downsizing significantly. “I think we’re closer now than we’ve ever been” to making a gasline project happen, Dubler told House Resource Committee members on July 19. AGDC officials informed the Journal July 10 that the quasi-state agency would be ending its work to secure customers and investors for the roughly $40 billion Alaska LNG Project, as well as closing its public and government relations department. The reductions are expected to take AGDC’s personnel count from about 20 to less than 10 over the coming weeks. The remaining eight or nine employees will focus on completing the ongoing Alaska LNG environmental impact statement process the Federal Energy Regulatory Commission. FERC published the project’s nearly 3,700-page draft EIS June 28. Dubler told the legislators the reductions are intended to make AGDC “more fit for purpose,” as it focuses on completing the crucial EIS process, which is scheduled to be completed next June. Staffing levels at the corporation have always been low considering the massive scope of the project it is working on and AGDC has relied on contractors and consultants to help complete major tasks. “We’re going to have just enough people to get this thing done and at the end of next (fiscal) year in June, then we take a look and say, ‘where do we go from here?’” he said. It’s at that point that AGDC will reexamine and determine the state’s participation, if there will be any, in the project going forward, according to Dubler. He said it’s tough to forecast where the project will go in a year, but stressed the state will no longer be leading it through AGDC. Dubler confirmed that he had the authority to make personnel decisions, which was delegated to him by the corporation’s seven-member board of directors. Sources within AGDC said the staffing changes followed a detailed review of the project and corporation by Gov. Michael J. Dunleavy’s administration. Dunleavy has consistently said he wants the state to back away from leading the complex project and instead focus on bringing in partners, such as large oil companies, to again take it over. By getting a favorable decision on the EIS, AGDC can reduce the regulatory risk to Alaska LNG and make the project more enticing to potential partners, according to Dubler. He said the state still wants to monetize the roughly 35 trillion cubic feet of known natural gas on the North Slope. “This isn’t a change in what we’re doing; it’s a change in how we’re going about it,” Dubler said. He highlighted that FERC largely agreed in the draft EIS that AGDC’s plan for the 807-mile pipeline and a 20 million tons per year LNG plant at Nikiski is the least environmentally damaging option available. China deal is dead He also confirmed that AGDC did not renew the nonbinding joint development agreement, or JDA, it had with three large, nationalized Chinese firms to buy up to 75 percent of the project’s LNG in exchange for an equal share of the needed financing. Signed in front of President Donald Trump and China President Xi Jinping in November 2017, the JDA was touted as a signature achievement in former Gov. Bill Walker’s effort to secure partners for a state-led Alaska LNG Project. The agreement was extended multiple times under Walker and former AGDC President Keith Meyer. Dubler said the project envisioned in the JDA “frankly doesn’t exist anymore” given that the Dunleavy administration is not comfortable with the risk the state would have to assume to lead the project to fruition. “What we told them is moving forward we will work with the producers and them to see what their role would be, if any, moving forward,” he said of a recent teleconference with representatives from Sinopec, China Investment Corp. and the Bank of China, the three other JDA parties. Dubler acknowledged that the commercial work AGDC had done since taking over the project in late 2016 was beneficial in that it proved there is international interest in the Alaska LNG Project, but he said much more work needs to be done before major LNG purchase and investment agreements can be finalized. AGDC officials have said they signed about 15 nonbinding agreements with potential partners — mostly in East Asia — but the content of those agreements has been kept confidential. “(Those agreements) really didn’t do anything as far as progressing the project and they didn’t do anything for the other side as well because they had no commitments there either so what we said is we don’t need to do those anymore until we have something we can commit to,” Dubler said. “In another two or three years, whoever’s going to be building this project would again go to the market and look for off takers.” The overall cost of Alaska LNG — last estimated at $43 billion by AGDC in 2017 — is currently a major impediment to developing it, according to Dubler. That cost translates to LNG delivered to Asian customers at $11 to $12 per million British thermal units, which is nearly three times the going rate for spot market LNG purchases today. “That’s so far out of the market now nobody would return your phone call. I mean, they wouldn’t even talk to you,” he said. Dubler’s predecessor Meyer regularly stressed that spot LNG prices are deceptive in that contracted LNG prices are often significantly higher because they come with long-term commitments to deliver scheduled cargoes and that reliability is something large utility buyers covet. Role of producers Rep. Chris Tuck, D-Anchorage, said the refocusing of AGDC’s work appears to be taking the project back to early 2016 when BP, ConocoPhillips and ExxonMobil were partners with the state in Alaska LNG but determined that depressed global energy markets challenged the economic viability of the project at the time. The producers’ Alaska leaders then said they would either shelve or slow down the project until market conditions improved or allow the state to examine ways to make it more economic, and the state enthusiastically chose the latter under Walker. BP and ExxonMobil, which collectively hold rights to a lion’s share of the gas in the Prudhoe Bay and Point Thomson fields, agreed to general terms including prices for gas sales into the project in 2018. They also agreed to fund up to $10 million each towards completing the Alaska LNG EIS, which state officials have said could cost close to $30 million. An economic analysis of the Alaska LNG Project conducted during the producer-state transition by the international energy consulting firm Wood Mackenzie concluded that a project led by the producers would likely not be viable because of the comparably high investment returns large oil companies require, among other considerations. However, a state-led project could be profitable because of the state’s exemptions to federal taxes and lower return requirements, according to Wood Mackenzie. “It seems like the light is dimming on a potential gas pipeline,” Tuck said. “It just seems less and less hopeful as we either lose interest from other entities or we are no longer interested in those entities.” Dubler responded that AGDC has done a detailed review of the project’s costs and potential economics using Department of Revenue economic models and has received assistance from BP and ExxonMobil on how to reduce the overall cost. Those cost reduction workshops have led state officials to believe the project is “in the ballpark” of being economically competitive, Dubler said. However, he declined to provide a new cost estimate, saying that disclosing those figures could harm a project proponent’s position in future LNG sales negotiations. “Instead of pulling everybody behind us we’re going to be behind them helping them set up whatever the state can do to help them be successful,” Dubler said of AGDC’s new role while also acknowledging that it’s unclear who “them” is at this point. He added, though, that major participation from a major oil company, as the administration envisions, would likely require “fiscal certainty” for the project, a term commonly used when the producers were leading Alaska LNG. Fiscal certainty is the concept that the producers would need the state to agree to set firm tax rates for natural gas — and possibly oil — before they would agree to multibillion-dollar investments in Alaska LNG. Clauses in the Alaska Constitution prohibit the Legislature from contracting away its taxing authority, so achieving fiscal certainty for Alaska LNG would likely necessitate a potentially highly controversial constitutional amendment. ^ Elwood Brehmer can be reached at [email protected]

Murkowski still pushing energy policy overhaul featuring nuclear power

Expect to hear more from Sen. Lisa Murkowski on her plan to overhaul the nation’s complex energy policy. Alaska’s senior senator said during a July 19 speech to the nonprofit policy study group Commonwealth North in Anchorage that its been 12 years since Congress last did a full-scale update to federal laws covering energy development, security, reliability and innovation. Murkowski has said technology has made many of those policies outdated. She chairs the Senate Energy and Natural Resources Committee. “There are things that you’d imagine coming from an Alaskan senator but there’s also a few things that you look at and you say, ‘well, where’d that come from?’” she said in reference to her proposed energy reform legislation. Both the House and Senate passed versions of an energy reform package Murkowski championed in 2016. However, the bill died when conference committee negotiations stalled. At the time, Murkowski blamed House Republican leaders for opting to leave Washington, D.C. for December holiday parties elsewhere instead of working out minor differences in the detailed legislation. This go-round Murkowski is particularly highlighting the prospects of advanced nuclear power, which is something she said Alaskans should be very interested in for what it could to in rural communities to lower the cost of energy with zero emissions. “Just imagine a system that’s the size of a connex and provides continuous power and needs to be refueled once every 25 to 30 years,” she said of potential small-scale nuclear power generation. On July 16 the Energy and Natural Resources Committee passed the Nuclear Energy Leadership Act with broad bipartisan support. The bill directs the Energy Department to establish advanced nuclear development goals, support nuclear research and work to make low-enriched uranium — nuclear power “fuel” — available for research and demonstration projects. Murkowski has long touted Alaska’s capability to be on the forefront of energy technology development with its high energy costs and ranging climate and geography. “We are leading as a state when it comes to microgrids and how we’re piecing these smaller energy solutions together,” she said. “We’re getting not only the attention of the nation, but of the world for what we’re doing.” On health care, Murkowski, who was one of three Republican senators to vote against the party’s “skinny” repeal of the Affordable Care Act in 2017, said lawmakers and the public often get caught up in the cost and availability of health insurance, without addressing the underlying cost of care. She also serves on the Health, Education, Labor and Pensions Committee, which sent the Lower Health Care Cost Act to the full Senate for consideration in early July. According to the Congressional Budget Office, the bill would have a net cost of about $9.4 billion over five years primarily through cuts to federal health insurance subsidies countered with increased spending for community health centers and other programs. Murkowski said the Lower Health Care Cost Act attempts to curb some of the fundamental cost drivers for patients. “It’s the first time that we’ve really drilled down on efforts to lower the actual cost of care through greater (billing) transparency, addressing prescription drug pricing and ending this surprise medical bill issue,” she said. It would also change the minimum age to buy tobacco from 18 to 21. And while members of Alaska’s congressional delegation rarely weigh in on issues before the state government, the severity of the budget-related impasse between legislators and the governor have tested that precedent. Sen. Dan Sullivan has urged state lawmakers to capture as much federal revenue as possible by appropriating the necessary state funds to match federal program contributions. Murkowski echoed that sentiment. She said part of the delegation’s job is to stabilize and enhance the state’s economy, noting the $286 million in Defense spending Congress approved on projects at Interior Alaska military installations for this year. The ongoing work to update infrastructure and expand operations at Eielson Air Force Base, Clear Air Force Station and Fort Greely has largely been credited with supporting the state’s construction industry while the state’s capital spending has been cut drastically amid years of budget deficits exceeding $1 billion. Murkowski said the delegation is collectively working to determine exactly what the many deadlines are for the state to match funds for various federal programs. “The thing with the federal side is they really don’t care what are problems are up here; they really don’t care whether we’re in Wasilla or Juneau, there’s a date and if they don’t hear from us by that date they assume that they’ve got access to something that was going to be in the Alaska pot, so they’re moving on to something else,” she described. The largest single pool of money the state is at risk of losing because of the inability to pass funded capital budget is more than $910 million of federal highway and aviation infrastructure funds, which requires a state match of less than $100 million. On July 23, the Anchorage Daily News reported that the Federal Highway Administration’s chief congressional liaison confirmed that Alaska has until 2020 to come up with matching funds for hundreds of millions of dollars in federal aid following an inquiry from the office of U.S. Sen. Dan Sullivan. The federal government’s fiscal year starts Oct. 1, explained liaison Tim Arnade, and the state becomes eligible for its federal highway aid at that point. As long as the state comes up with its matching funds before August 2020, it receives the full amount of federal highway aid. If it doesn’t come up with the money in time, the federal aid is redistributed to other states. The inability of the Legislature and Gov. Michael J. Dunleavy to resolve their differences over the budget just adds to the air of economic uncertainty in the state, Murkowski said. “Not everything’s perfect up here, but it never, ever, ever has been so let’s not get so focused on some of the challenges that are just gripping us and bringing us down. We’ve got to remember that we’ve got some challenges in front of us but we’ve got more opportunity than anybody out there. We still have still have $65 billion, with a ‘B,’ in the bank,” she said referring to the Permanent Fund. “We are not so broke we can’t figure our way out of this. We know how to do this we just have to come together as Alaskans and do it.” Elwood Brehmer can be reached at [email protected]

Anchorage Assembly delays vote on port repair contract

Caught between potential disasters, the Anchorage Assembly again delayed a vote on July 23 to decide whether the city should start rebuilding its aging port that is badly in need of repair or wait to determine if more cost-effective solutions exist. Anchorage Mayor Ethan Berkowitz’s administration insists the Assembly should approve a $42.1 million contract with the marine construction firm Pacific Pile and Marine to build the first phase of a new petroleum and cement terminal, or PCT, at the municipal-owned Port of Alaska. While port officials and members of the administration acknowledge the contract, which is for the 2020 construction season, would leave the city about $100 million short of finishing the PCT, they stress that it would give the port one very basic but seismically resilient dock structure that could be used in an emergency while the rest of the years-long construction on the rest of the port is underway. Municipal Manager Bill Falsey also noted at the Assembly meeting that part of the reason the administration is pushing the PCT plan is the need to move fuel and cement offloading away from the rest of the docks to free up space for the logistical juggling that is rebuilding the port at the same time ships continue to regularly call on it. The new PCT would be well to the south of the current petroleum and cargo terminals. “The PCT is the key to unlocking the whole project,” Falsey said during the July 23 meeting. Port officials also continue to discover new earthquake damage to the already badly corroded steel piles that support the docks and are largely past their intended useful life. At the same time, the port’s primary user companies are urging the Assembly to suspend the port construction plan because the users fear the PCT is the first step towards another port project that will turn into a financial nightmare, particularly because the city does not have a firm plan to finance the rest of the work. “We don’t doubt there are problems, but what other options are there and what do they cost?” asked Ryan Zins, a vice president for Alaska Basic Industries, the primary cement importer at the port. The overall price for the current port reconstruction plan has escalated from roughly $500 million in 2014 to $1.9 billion today because of a myriad of factors that include federal steel tariffs and stringent seismic design criteria, among other reasons. Falsey and port officials have repeatedly said they do not plan to build the $1.9 billion project — even though the PCT is the first part of it — and will look for major savings in constructing the larger cargo terminals and other aspects of the project. Their experts contend the port has less than 10 years before some of the docks will have to be de-rated for weight capacity or closed altogether if they are not rebuilt. The users have suggested repairing one of the existing petroleum terminals but the viability of that is unclear at this point. Consultants hired by the Assembly to review the project for cost saving measures have said alignment between the city and the users will be critical to move the project forward successfully. The Assembly ultimately voted 8-3 to push the contract vote back about a week, likely to a July 30 special meeting, to give the city and the users time to discuss their options and see if a compromise can be reached. The users pledged to work diligently and in good faith with the administration in the coming days, and Falsey highlighted that the administration is doing its best to provide as much information as possible on the complex project to anyone who wants it. Pacific Pile and Marine representatives have said the contract needs to be approved by Aug. 1 in order to ensure the massive steel pilings can be ordered and fabricated in time for the 2020 construction season and to get the best price. Assemblyman John Weddleton, who owns Bosco’s Comics in Anchorage, said the city needs to listen to its customers at the port and do a more diligent review of the project’s costs. “Ignore your customers at your peril,” Weddleton said. His comments were echoed by several other Assembly members. Assemblywoman Meg Zaletel said she’s worried Gov. Michael J. Dunleavy’s administration might claw back the $49 million in uncommitted state grants the city has received for the project in recent years if the money is not spent soon. “I’m unwilling to wait for an emergency and worse yet a catastrophe,” Zaletel said, partly responding to assertions from the users and other opponents to the PCT plan that the docks are not truly in dire need of immediate repair. Assemblyman Fred Dyson of Eagle River wants to slow the project for a more detailed cost review. “I believe the administration is acting in good faith. I believe they got off-track because they didn’t have the best information,” he said. Falsey asked Assembly members to send the administration every question they have about the PCT plan and the overall project in the coming days so they have absolutely all the information they need to make a decision on the PCT at the special meeting. It’s unclear at this point how the Assembly will vote then. Major construction at the port has been on hold since 2010 after major damage to the sheet pile then being installed to support new docks was discovered. The original port expansion project cost upwards of $300 million but resulted in little usable infrastructure. The Municipality of Anchorage is currently engaged in a lawsuit against the federal Maritime Administration, or MARAD, which oversaw the failed work. The Federal Claims Court judge presiding over the lawsuit is scheduled to visit the port Aug. 1-2. In February, city officials released a concept analysis that indicated the port’s import charges on fuels and cement would have to be increased five-fold or more if the municipality needed to sell $200 million worth of revenue bonds to pay for the new PCT. That caught the attention of the users, who also fear the lack of a firm financing plan for the overall project could lead to steep tariff increases, even though city officials have repeatedly pledged to not levy tariffs to fund construction that would drive away business or otherwise harm the Anchorage or state economy. The ongoing lawsuit with MARAD has made it difficult for the city to secure large chunks of financing for the port since it’s unclear what the suit could potentially yield. ^ Elwood Brehmer can be reached at [email protected]

Marathon acquires Interior fuel assets

Marathon Petroleum Corp. has purchased the site of the now-demolished North Pole oil refinery formerly owned by Flint Hills Resources. Marathon Alaska spokesman Casey Sullivan confirmed the refining and fuel transportation company purchased the 233-acre industrial site, which it now uses for fuel storage, in a deal that closed July 1. Sullivan wrote via email that owning the Interior Alaska fuel storage terminal will help the company optimize its operations across the state. “We are excited about the opportunities that this will bring for the company and for the community alike,” he said. “We believe this facility is a natural extension of our long-standing operations in Alaska and will enhance our ability to efficiently and reliably serve customers in the Interior and strengthen the integration from our Nikiski refinery to our customers.” Marathon had been leasing the 285,000-barrel North Pole terminal to store fuels it imports or produces at its Nikiski refinery on the Kenai Peninsula and then ships north on the Alaska Railroad for eventual distribution to Interior customers. The company took over the state’s largest oil refinery in Nikiski — long operated by Tesoro Corp. — late last year after finalizing a $23 billion deal to buy Andeavor, which ran the refinery briefly after purchasing Tesoro in 2017. In late 2015, Tesoro purchased a 580,000-barrel capacity fuel terminal in Anchorage and a 22,500-barrel jet fuel storage facility at the Fairbanks International Airport as well as wholesale fuel contracts in the state from Flint Hills; all that is now owned by Marathon. Flint Hills Resources closed its North Pole oil refinery — the site of historic soil and groundwater contamination — in May 2014 citing in part the high operating costs in the state. It began demolishing the oil refining facilities in December 2016 but kept the fuel storage terminal. The Flint Hills refinery was a primary supplier of jet fuel to Eielson Air Force Base. Fairbanks North Star Borough property records indicate that the former refinery-turned fuel terminal parcel has an assessed value of $24 million, down from $35.8 million in 2017 due to a decline in the value of on-site facilities. The land value has held steady at $2.5 million, according to borough records. Marathon also took ownership of the former ConocoPhillips LNG plant in Nikiski when it purchased Andeavor. The company is seeking approval from the Federal Energy Regulatory Commission to use the idled plant to import LNG that could be used to fuel part of the operations at its nearby refinery. Sullivan said Marathon has not ruled out selling imported LNG that has been regasified into the Southcentral market, but the company is focused on getting the requisite federal permits for importing LNG at this point. Elwood Brehmer can be reached at [email protected]

Concept scrapped for unified Railbelt utility

Alaska’s Railbelt electric utility leaders are headed back to the drawing board after five years of work now that efforts to jointly manage the region’s transmission infrastructure have failed, at least for the time being. The utilities behind Alaska Railbelt Transmission LLC withdrew the startup transmission company’s application for a certificate of public convenience and necessity, or CPCN, from the Regulatory Commission of Alaska on June 20. An RCA-approved CPCN is required for any regulated electric utility to operate in the state. A transmission company, or transco, has long been seen as a way for the five large Railbelt utilities, plus the City of Seward, to coordinate construction of new power generation facilities and pool resources for expensive transmission infrastructure projects that a single utility might not be able to afford but would benefit the customers on the broader system. Such a joint transmission-only utility would be a first for Alaska but they are more common in the Lower 48. When the transco CPCN application was sent to the RCA in February, Homer Electric Association, Anchorage-owned Municipal Light and Power, Golden Valley Electric Association, the City of Seward and Wisconsin-based American Transmission Co. were signatories to the 750-page document. American Transmission Co. operates as a transco in the Upper Midwest and company representatives coordinated transco development in Alaska since 2015, though the concept was being discussed prior to that. Work to formally integrate Railbelt utility operations became more urgent following a sternly worded June 2015 letter from the RCA to the Legislature in which the commission characterized the Railbelt electric system at the time as “fragmented” and “balkanized.” The RCA also insisted that if the utilities would not voluntarily work together for the betterment of their customers, the commission would do what it could to mandate better cooperation, either through its own regulations or by seeking statutory help from the Legislature. In May, the early drafts of in-depth legislation clarifying the RCA’s authority to oversee a transco or other joint utility organizations was introduced in both the state House and Senate. Some critical observers of the Railbelt electric system contend the six utilities — spread over a large area but with collective demand less than many individual Lower 48 utilities — have overbuilt generation capacity in recent years while ignoring transmission investments that could make it more cost effective to move lower cost power from one end of the system to the other. The 2015 letter notes the utilities had spent roughly $1.5 billion on new generation facilities over the previous five years. Currently, the Railbelt utilities continuously buy and sell power to each other; however, they also each apply their own transmission, or wheeling, tariffs, when power is sent across the portion of the main transmission lines they own. This can lead to situations where tariff “pancaking” disincentives power transactions that could otherwise maximize the efficiency of the system as a whole. Renewable energy advocates, in particular, stress that an open-access transmission system with a flat wheeling tariff would allow independent power producers to compete on a level playing field with current power plants for power sales and would incentivize more investment renewable projects in the region. Alaska Railbelt Transmission was challenged from the outset by not having participation from two of the larger utilities in the region, Chugach Electric and Matanuska Electric associations. Golden Valley CEO Cory Borgeson said when the group learned that ML&P was withdrawing its support for the transco it was scrapped. Chugach officials have said in filings to the RCA that the Anchorage-area utility wants to resolve its pending $1 billion purchase of ML&P from the Municipality of Anchorage, which is also under review by the commission, before entering into any binding agreements. ML&P officials did not respond to questions in time for this story. Seward Utility Manager John Foutz said Seward supports a transco because it would give the city “a buyer’s market.” “Right now we’re attached directly to Chugach’s transmission lines so any power we that we purchase has to go through Chugach’s system. If there was a transco that covered all of the transmission system then we would have the opportunity to basically shop around for the lowest price for our ratepayers and pay one unified transmission price to get it to us,” Foutz said. Seward currently buys the vast majority of its power from Chugach; it also has rights to a small portion of power from the state-owned Bradley Lake hydro plant near Homer, according to Foutz. MEA General Manager Tony Izzo said his utility hired outside consultants to evaluate the transco application and business plan and who concluded MEA should not get involved in the company. “We are convinced from the analysis that the transco as filed did not do what even the cover letter of the filing said it would do,” he said in an interview. Last November, prior to the transco application being filed, Izzo wrote in a letter to the RCA that MEA was “in full support of the formation of a transco,” but the utility wanted to see a sister cooperative organization formed to address transmission system reliability standards and perform economic power dispatch — consistently running the most efficient generators for the demand — across the Railbelt. Izzo insists the transco, as envisioned in the application, would not lessen the cost of wheeling tariff pancaking on the system, but would largely combine the existing tariffs into “one big pancake,” he said. Izzo has also questioned the ultimate motivation of a for-profit transco, which Alaska Railbelt Transmission would have been with ATC’s involvement, saying he would worry about costly and unnecessary transmission projects. The Alaska Railbelt Transmission application requested a 10 percent return on equity investments in its projects. Izzo said he believes the conceptual Railbelt Reliability Council cooperative can perform the functions of a transco while also implementing a single set of operating reliability standards in the Railbelt and coordinating the most efficient dispatch in the region. Chugach Electric CEO Lee Thibert similarly said the transco application gave Alaska Railbelt Transmission the authority to dictate long-term system planning and power dispatch; functions he said would be best performed by the reliability council. “Before you had two parallel paths and it was very difficult when you had two things going to the commission and competing against each other. At least with the transco pulled back maybe we can all agree on how we can move forward with the RRC and try to resolve our transmission issues at the same time,” Thibert said in an interview. “I’m hoping it opens the door to try to solve some of those things.” Borgeson noted that significant progress has been made with the utilities agreeing to a single set of reliability standards across the system, which Thibert said was a big deal for protecting their IT networks. “Probably the biggest focus (with reliability) is making sure we all have the same cyber security standards because we’re all interconnected,” Thibert said. There is no definitive timeline for the utilities to settle on the final structure of an RRC, but utility leaders said it would likely have a 13-member governing board with seats for each utility, the Alaska Energy Authority as a transmission asset owner, independent power producers, public experts and an RCA delegate. While they acknowledge the RRC does not inherently solve the issues with wheeling tariffs, its believed the organization would be able to work through those challenges. “Part of the RRC is to make sure we have a common way of dealing with interconnection guidelines (for independent power producers) and then it’s not a burden to move power from one side of the system to the other,” Thibert said. Despite the challenges, the utility leaders insist their relationships — which have been blamed for slowing reform in the past — are still very good. “A couple steps forward and one step back,” Borgeson said, adding that the utilities are already working continuously to provide the lowest cost power. GVEA purchases roughly 30 percent of its power from Southcentral utilities that have access to natural gas-fired generation versus the typically higher cost fuel oil plants the Fairbanks utility operates, according to Borgeson. “We’ll pick up the ball on the transco and we’ll keep moving the ball on the RRC,” he said. ^ Elwood Brehmer can be reached at [email protected]

More quake damage adds to troubles at Port of Alaska

The primary users of Anchorage’s beleaguered port want city officials to delay the first major rehabilitation work at the port in years while port leaders continue to discover earthquake damage to critical infrastructure. The eight companies that make up the informal “Port of Alaska Users Group” sent similar letters to Anchorage Mayor Ethan Berkowitz June 28 and members of the Anchorage Assembly July 12 urging them to stop advancing work to build a new petroleum and cement terminal. They contend the municipality’s plan to start building the roughly $220 million petroleum and cement import terminal, or PCT, without having a way to pay for all of it would leave the city with a “trestle to nowhere,” according to the July 12 letter to the Assembly, and could invite tariff increases that would impact business at Anchorage’s other logistics hub. “Fuel is a highly sensitive commodity and as the 5th busiest air cargo hub in the world, it seems imprudent not to conduct this type of analysis before proceeding down any path that might produce negative fiscal impacts to our fragile Alaskan economy. Ultimately, without knowing what the final cost of the project will be, it is impossible to determine what the appropriate tariff should be to underwrite the project, and by extension, whether the increased tariff is even feasible for the airport customers,” the July 12 letter to the Assembly states. The port user group is comprised of the general cargo shippers Tote Maritime and Matson Inc.; five fuel supplier and distribution companies; and Alaska Basic Industries, which is primarily a cement distributor. The Anchorage Assembly officially changed the name of the city-owned port in 2017 from the Port of Anchorage to the Port of Alaska in an attempt to highlight its importance statewide and possibly drum up support for funding the rebuild. Some sections of the pile-supported docks have been in place since 1961 and have far exceeded their initial 35-year design life. Studies indicate the pile maintenance program can keep the docks open for about another nine years before pervasive corrosion from seawater will start forcing closures. Major construction at the port has been on hold since 2010 after major damage to the sheet pile then being installed to support new docks was discovered. The original port expansion project cost upwards of $300 million but resulted in little usable infrastructure. The Municipality of Anchorage is currently engaged in a lawsuit against the federal Maritime Administration, or MARAD, which oversaw the failed work. The Federal Claims Court judge presiding over the lawsuit is scheduled to visit the port Aug. 1-2. Additional quake damage discovered Port officials stress rebuilding the docks is becoming more and more a time sensitive issue. While the port survived the 7.1 magnitude Nov. 30 earthquake, it didn’t come out of the shaking unscathed, according to port spokesman Jim Jager. He said in an interview that post-earthquake inspections of the already corroded pilings supporting the docks conducted since breakup have shown the port’s two current fuel docks are the facilities most at-risk of failure in another earthquake. This month, port engineers de-rated the load capacity of the Terminal 1 dock adjacent to petroleum, oil and lubricant dock No. 1 because of earthquake damage, according to Jager. Additionally, roughly 20 percent of the pilings under petroleum dock No. 2 have failed, he said, and most of the damage is likely due to the earthquake. “Engineers say that dock is vulnerable to progressive collapse…consequently, the dock is likely to function normally, until it doesn’t. Individual pile failures may not cause the overall dock to fail…until they create a failure that moves from one pile to adjacent piling (think of dominos falling),” Jager added via email. In February, city officials released a concept analysis that indicated the port’s import charges on fuels and cement would have to be increased five-fold or more if the municipality needed to sell $200 million worth of revenue bonds to pay for the new PCT. At the time, Anchorage Municipal Manager Bill Falsey said the city was trying to spread the $60 million it has for the port modernization effort to support preconstruction work on other portions of the project; however, officials have since decided to put that $60 million towards a new PCT. Airport cargo concerns Port users immediately responded to the concept tariffs by stressing the cost increases would certainly have major negative consequences on their business and could also drive air cargo traffic away from Ted Stevens Anchorage International Airport. The Anchorage airport is the fifth-busiest cargo hub in the world mainly because of its position between manufacturers in East Asia and consumers in North America, and that cargo business is a large reason the airport supports 10 percent of the jobs in the city, according to the Anchorage Economic Development Corp. Refueling in Anchorage allows carriers to fill aircraft with more cargo instead of carrying the added fuel that would be needed to reach refueling hubs or destinations to the south and east. However, the economics of the cargo business model rely on a difference of pennies per gallon between hauling more fuel or hauling more cargo, industry experts note. As a result, any tariff change at the port could impact international business at the airport, according to fuel company representatives. The PCT tariff analysis was largely an exercise to elevate the discussion about how the work most everyone agrees needs to happen should be paid for and less a step towards actually implementing large tariff hikes, city officials have said. “We talked to people and we agree, a tariff of that rate would have negative impacts on cargo operations at the airport,” Falsey said during a July 12 Assembly work session on the matter, adding the city will won’t do anything to drive business away from the airport or port, which could end up reducing the tariff revenue to fund port improvements. Still, he noted that some tariff increases on most cargo crossing the Anchorage docks are likely unavoidable as the overall port rehabilitation project continues. Port managers received a $42 million bid last month from Seattle-based Pacific Pile and Marine to build the PCT access trestle and platform next year with cathodic corrosion protection. The bid would leave the city about $100 million short of finishing the PCT, which would still need piping, utilities and mooring dolphins to secure offloading vessels, Falsey said. City officials initially expected the “phase one” PCT work to cost closer to $60 million, and delaying the work would likely push the cost back up, Falsey added. While not ideal, building part of the PCT would give the port a new, seismically resilient “dock” that could be used to offload fuel and cargo if an emergency — such as another major earthquake — rendered the three existing cargo terminals unusable before they are rebuilt, according to Falsey. The Assembly is scheduled to vote on funding the contract July 23. Marathon Petroleum spokesman Casey Sullivan urged the Assembly to reject the PCT construction contract and other major port work until the city has an overall financing plan. Moving ahead without full funding and a more detailed economic impact analysis of tariff increases is a signal of uncertainty to the port’s customers who would still have to plan for the most severe tariff increases possible, he and other representatives of port user companies said. “That (PCT) trestle is good but that trestle doesn’t ultimately fix the port,” said Lev Yampolsky of Petro Star, an Alaska fuel refining company. However, Falsey said in a brief interview that city and port officials have not been able to get specific information from fuel companies engaged in a highly competitive industry as to what level of tariff increases they would be able to absorb. Other Anchorage economic experts have similarly said getting detailed information on what would deter air cargo companies from stopping here is virtually impossible. The municipality is also concerned delaying the work could also hurt future logistics business prospects in Anchorage as companies could see slowing the work at the port as a signal the city has no plan to rebuild the docks before they deteriorate to the point of needing to be closed, he said. According to Falsey, the Assembly needs to approve the contract by about Aug. 1 if the city is going to have the work done next summer to allow Pacific Pile and Marine to order long lead time items such as the steel piles that would support the PCT trestle and platform. Building the PCT to the south of the current docks will also free up port frontage needed when the larger cargo docks are replaced, port officials emphasize. Sullivan and Yampolsky said the user companies have ideas on how to substantially lessen the $1.9 billion cost estimate for the overall port modernization project, and taking the time to develop a new, comprehensive plan would help gain the support of all the stakeholders in the project. That support will be needed to obtain large sums of federal grants or other funding for the work, they said. Falsey and port officials have stressed they will not build a $1.9 billion port; it’s simply unaffordable, and the Assembly has hired a consultant to review the high cost estimate and suggest lower-cost alternatives. That report is due in September and the port users encouraged the Assembly to hold off on any major decisions on the port at least until then. Elwood Brehmer can be reached at [email protected]

Gasline agency laying off 60 percent of staff

The Alaska Gasline Development Corp. is drastically cutting its staffing while it is in the midst of permitting the $43 billion Alaska LNG Project. The state-owned corporation issued a statement to the Journal Wednesday afternoon from Interim President Joe Dubler that reads: “AGDC is restructuring to reflect our primary focus on completing the FERC permitting process to advance the Alaska LNG Project. AGDC will continue to pursue (Federal Energy Regulatory Commission) authorization, expected in June 2020, with an eight-person technical staff plus contract support as needed, and reduce employee headcount by twelve. Completing the permitting process will substantially de-risk Alaska LNG and open the door to a wider range of potential project parties with the broad expertise required to unlock the value and manage the risks associated with a project of this magnitude.” Spokesman Tim Fitzpatrick said Dubler is responsible for staffing at the corporation and the decision was made under his authority. Most of the changes are expected to be complete by the end of July, according to Fitzpatrick. FERC released a draft version of the Alaska LNG Project environmental impact statement June 28. A final EIS is expected next March. Sources within AGDC said Dubler — who took the job in January on an interim basis and has no long-term plans to stay — and Vice President of Program Management Frank Richards will be the only executive-level employees that will be retained full-time. Vice President Fritz Krusen, who briefly served as acting AGDC president in early 2016, will be retained on a contract basis. Cutting back to a staff of eight means the group leading what has the potential to be one of the largest infrastructure projects in the world will be nearly as small as its board of directors, which is comprised of seven individuals. Staffing levels at the corporation have always been low considering the massive scope of the project it is working on and AGDC has relied on contractors and consultants to help complete major tasks. Still, the layoffs mark a complete shift in the state’s pursuit of a gasline project from former Gov. Bill Walker to current Gov. Michael J. Dunleavy. Under Walker, who for decades has touted the economic benefits exporting North Slope natural gas could bring to the state, AGDC accepted control of the Alaska LNG Project from the North Slope producers and worked to find investors and customers while also attempting to expedite the complex pre-construction work for the project. Walker and former AGDC President Keith Meyer regularly stressed a need to have the project start producing LNG in the mid-2020s to meet a global LNG market window of unmet demand in that timeframe. Dunleavy insists the project is too large and complex for the state to manage and has said repeatedly he wants private sector companies — whether the North Slope producers of BP, ConocoPhillips and ExxonMobil or other companies — to partner with the state. AGDC under Walker also signed approximately 15 early-stage agreements with potential Alaska LNG investors and customers, most notably the November 2017 joint development agreement with three large nationalized Chinese corporations. That signing was conducted at a trade ceremony in Beijing in front of President Donald Trump and China President Xi Jinping and at the time seemed to indicate Alaska’s long-awaited gasline was gaining significant momentum. Fitzpatrick said AGDC has a number of confidential agreements with potential customers that remain in effect and some other agreements have been allowed to expire. He would not disclose what entities AGDC still has agreements with or how many preliminary agreements are still active. The cutbacks are not being driven by near-term state financial considerations, according to sources. The timing of the decision was not linked to the governor’s $444 million of budget vetoes to dozens of state programs. AGDC’s roughly $10 million annual operating budget was not subject to a veto from the governor. Fitzpatrick could not provide what the budget savings would be at this point. Sources said the decision to shrink AGDC was made by officials in the governor’s office after significant time was spent reviewing the project. A spokesman for the governor did not immediately respond to questions regarding the layoffs. On May 29, Lt. Gov. Kevin Meyer announced BP and ExxonMobil are contributing $10 million apiece to help the state finish the FERC process. The major producers signed a memorandum of understanding with AGDC in March to provide technical assistance on the project. They also signed separate confidential gas sales precedent agreements with AGDC last year that outline the terms — including price — under which they would sell gas from the Prudhoe Bay and Point Thomson North Slope fields into the project. The companies are also currently assisting AGDC in reevaluating the overall economics of the project and its $43 billion cost estimate amid new global LNG market conditions. Spokespersons for BP Alaska and ExxonMobil could not immediately be reached. AGDC is scheduled to hold its next board of directors meeting Aug. 8 in Anchorage. Elwood Brehmer can be reached at [email protected]

Legislature breaks up over special session location

As legislators continue to posture in Wasilla and Juneau, a small group of them continues analyzing the history, and future, of the Permanent Fund dividend program. Members of the Bicameral Permanent Fund Working Group discussed the pros and cons of varying levels of PFD payments July 8, the result of a “homework assignment” given them shortly after the committee was formed near the end of the first special session. An impasse over the size of this year’s dividend payment has stalled progress on all other outstanding issues this year. Gov. Michael J. Dunleavy and the group of 22 legislators meeting in Wasilla, mostly House Republicans, are demanding the PFD be paid according to the statutory formula — equating to roughly $3,000 per Alaskan — while the majority of the Senate and House in Juneau favors smaller budget cuts that would result in a smaller PFD. While the governor’s $410 million of vetoes to General Fund spending increase the amount of surplus revenue available for dividends when combined with the Legislature’s approximately $280 million of budget reductions, the $1 billion available for PFDs from the Earnings Reserve Account of the $65 billion Permanent Fund is still only sufficient to pay dividends in the $1,600 per person range. Getting to “full,” $3,000 PFDs would still require drawing about $900 million in excess of the 5.25 percent of market value, or POMV, draw cap the Legislature put on appropriations from the fund just last year. As of this writing, the Legislature was scheduled to hold a joint session in Juneau July 10 to vote on overriding some or all of Dunleavy’s 182 line-item budget vetoes. However, with a high supermajority override threshold of 45 of 60 legislators needed to override budget vetoes and roughly a third of legislators committed to staying in Wasilla — where Dunleavy called the special session — it appears the vetoes will stand, at least for now. Republican House Minority Leader Lance Pruitt, R-Anchorage, has said members of his caucus could be open to backfilling some of the vetoed appropriations in the still unfinished capital budget, but that would only happen after the PFD is settled. Rep. Jonathan Kreiss-Tomkins, D-Sitka, who was paired with Sen. Shelley Hughes, R-Palmer, in the Permanent Fund Working Group to examine the consequences of a $3,000 PFD, said other issues aside, being able to put $3,000 in Alaskans’ pockets is “generally a good thing,” but noted in reality there is a “basic tension” between the size of the budget and the PFD that the state continues to struggle with. Kreiss-Tomkins supports more modest budget cuts and a corresponding smaller PFD, while Hughes has consistently supported cutting the budget to free up enough funds to pay full dividends. Still, he said they concur on one important principle. “Of all the available options in looking for fund sources for a $3,000 statutory PFD, we agree that overdrawing or overspending the Permanent Fund itself in excess of the POMV is least desirable or the worst option,” Kreiss-Tomkins said. With that as a backdrop, Hughes said even after the governor’s reductions the state still has an “unsustainable budget at this point” and that’s why she feels the Earnings Reserve has sufficient funds to pay full PFDs. The House Finance Committee also introduced a bill July 8 to pay $1,600 PFDs, but it would likely overdraw from the Earnings Reserve by a relatively small amount — less than $100 million depending on exactly how many recipients are eligible this year. The special Permanent Fund committee is expected to draft a new PFD formula sometime this summer near the end of its work; however, whether that could gain enough support in the Legislature as well as the governor’s blessing remains to be seen. Hughes said if the formula is changed the eligibility requirements should be examined along with the calculation because paying fewer dividends would mean larger per person amounts for those who are eligible. Finance co-chair Sen. Bert Stedman, R-Sitka, who for years has stressed the need to limit spending from the fund to preserve its value for future generations, was tasked with examining the value of a “surplus” PFD with Rep. Kelly Merrick, R-Eagle River. Stedman said paying dividends based on whether or not the state has surplus funds available in a given year is a good place to start working, but he acknowledged that could lead to years without a dividend, something he doesn’t think the Legislature as a whole is interested in. “A little bit of tension, I guess, has some value between the dividend and the operating budget, but I’m personally more inclined to have and more comfortable with a predictable and robotic structure where the dividend is paid out regardless of our current fiscal situation that given year and I guess that would be created when we restructure the formula,” he said. Stedman has supported recalculating the PFD while also saying the current formula — appropriating half of a five-year average of fund income — worked well for more than 30 years but it also was established under very different circumstances; the Permanent Fund was new and had only about $1 billion and there were far fewer Alaskans to receive dividends. Merrick insisted that while the state has a spending cap, it is ineffective and any move towards a surplus PFD would also require drastically lowering that limit. “Unless (the spending cap) is changed somehow government will slowly eat away at those funds and there will be nothing left over,” she said. The Legislature’s budget sent to Dunleavy this year would have allowed for a “surplus PFD” of roughly $900 per person. Finally, Rep. Adam Wool, D-Fairbanks, said in examining a $1,600 PFD, which is what was paid last year, said injecting additional money into the state economy through the dividend is undoubtedly a positive, but the actual economic benefits are mostly anecdotal, as it’s understood that many Alaskans save much of their dividends or spend it in ways that send the money out of Alaska. Instead, he suggested the Legislature might consider linking the PFD in part to the state’s oil revenue in a given year to better tie it to the fiscal reality of the day. Wool said drawing from 20 percent of the state’s oil revenue and 20 percent of the $2.9 billion POMV appropriation would provide for roughly $1,600 PFDs this year. “The Permanent Fund is independent from oil revenue but the State of Alaska isn’t,” he said. Elwood Brehmer can be reached at [email protected]

Agriculture Division grapples with managing vetoes

Decision makers in the Department of Natural Resources are in the same boat as Alaska farmers when it comes to making sense of what Gov. Michael J. Dunleavy’s budget vetoes mean for the state’s agriculture development programs. Nobody seems to know. Division of Agriculture Director David Schade referred questions about how the agency will revamp its operations to Deputy DNR Commissioner Brent Goodrum, who oversees Agriculture and other arms of the department. “We’re in a state of flux,” Schade said, presuming the vetoes are not overridden by the Legislature. DNR spokesman Dan Saddler said department officials are working to implement the reductions and would be able to talk about the changes at a later time. Department commissioners and other agency leaders have mostly been excluded from the budgeting process in the Dunleavy administration. Dunleavy cut the Division of Agriculture budget by more than 60 percent, from approximately $5.1 million to $2 million, on June 28 as part of his $444 million of vetoes to enable the state to pay larger Permanent Fund dividends. The governor’s vetoes followed roughly $280 million in operating budget reductions passed by the Legislature. He chose to eliminate “lower priority programs” in the Division of Agriculture including the Marketing, Agricultural Veterinarian, Farm to Institution, Agriculture Inspections, seed production and pest research programs. Budget documents indicate lower priority programs in the North Latitude Plant Material Center in Palmer will also be cut by more than $1.1 million and $319,000 to administer the state’s active Agriculture Revolving Loan Fund was removed as well. DNR officials told the House Resources Committee in February that the state had 55 loans totaling $7 million in the Agriculture Loan Fund. How the state will oversee what many feel could become a highly successful new crop in Alaska, hemp, is also unclear. The governor vetoed $375,000 of receipt authority, or the ability to accept fee revenue, from the division’s budget; he also struck through the state’s ability to accept $559,000 in federal agriculture development grants and matching funds. Office of Management and Budget documents detailing the reductions explain that “The State’s fiscal reality dictates a reduction in expenditures across all agencies.” Former Gov. Bill Walker signed Senate Bill 6 last year, authorizing the state to develop a pilot project for industrial hemp growers. Since, the state has been working to develop regulations and plans to allow farmers to start growing industrial hemp. The receipt authority in the budget was intended to be for fees the department collected from prospective hemp farmers to get approved for the crop. SB 6 was championed by Palmer Republican Sen. Shelley Hughes, who has largely supported the governor’s plan to drastically cut the budget and state services. Alaska Farm Bureau Executive Director Amy Seitz said she is also trying figure out how the state and its growing agriculture industry will adjust while noting that much of the blocked federal money was for pass-thru federal specialty crop block grants the Division of Agriculture accepts on behalf of Alaska farmers and then distributes. The specialty crop grants are available in some form for “almost everything that’s not livestock,” Seitz said, and they are often used to support value-added crop endeavors. There have already been awardees assigned for this year,” she said of the grants. “My understanding is right now they’re saying those grants are going to have to be sent back to the feds so those projects won’t have funding.” Seitz added that the prospect of an industrial hemp industry was of interest to many farmers. She also wondered how the popular Alaska Grown program will be handled as the $1.5 million marketing section of the division’s budget was reduced by approximately 80 percent. Alaska is one of few states to have a growing agriculture industry. As of 2017, Alaska had 990 farms and had added more than 300 in the previous decade, according to the U.S. Department of Agriculture’s Census of Agriculture. Alaska’s farm product sales brought in $70 million in 2017 as well, according to USDA figures. In June, the Division of Agriculture hosted its first round of business-to-business international trade meetings between Alaska farmers and local food manufacturers and Canadian brokers in conjunction with the Western U.S. Agriculture Trade Association. The state’s membership in the organization helped connect the Canadian buyers with the Alaska producers, participants said. According to Seitz, it’s also unknown whether the state will continue to provide Good Agriculture Practices and Good Handling Practices audits that are a prerequisite for farmers to get their products into many grocery chains. “Are the grocery stores going to be able to buy local products — or who’s going to take that on?” she wondered. She added that the Northern Latitude Plant Material Center has long been the primary location for a wide range of research, such as what species perform best in Alaska in addition to seed cleaning and other services. “I think it’s going to be harder than people realize,” Seitz said. “I’m really concerned that it’s going to hurt.” ^ Elwood Brehmer can be reached at [email protected]

Valdez protests AK LNG analysis; Mat-Su Borough satisfied

Federal regulators all but confirmed Nikiski should be the terminus of the proposed $43 billion Alaska LNG Project when they released the draft version of its environmental review June 28, but officials hopeful to see the project in two other areas have very divergent views on that conclusion. The City of Valdez filed initial comments July 8 with the Federal Energy Regulatory Commission on the Alaska LNG environmental impact statement, or EIS, that note just one page of the roughly 3,800-page document is devoted to analyzing a route to Valdez and it “ignores the substantial advantages” that route would provide the project. Previous gasline investigations have determined routing a project to Valdez is the least environmentally damaging option, largely because the pipeline would follow the existing Trans-Alaska Pipeline System route, according to city officials. “Moreover, FERC appears to have taken (Alaska Gasline Development Corp.’s) unsupported assertions regarding the impacts of the Valdez Alternative at face value without conducting the additional research or analysis mandated by (the National Environmental Policy Act),” the comments state. Alaska Gasline Development Corp. leadership has, through multiple management changes, stuck with Nikiski as the chosen locale for the project’s massive LNG plant. Nikiski was selected in 2013 when ExxonMobil was leading early work on the project in a consortium with BP, ConocoPhillips and the state. Former ExxonMobil Alaska LNG Project manager Steve Butt said at the time that the project team studied more than 20 sites across Cook Inlet, Resurrection Bay and Prince William Sound. Nikiski was chosen largely for its flat terrain and the ability to provide natural gas to the state’s four largest population centers along the pipeline route. The draft EIS largely affirms the conclusions of AGDC and the producers. The producer companies solidified their project endpoint by subsequently purchasing nearly 700 acres along tidewater in Nikiski to begin preparing for the eventual LNG plant. Interim AGDC President Joe Dubler said in a statement following the release of the draft EIS that publication of the voluminous document indicates significant progress toward obtaining the key authorization to build the project. The final EIS is expected in March 2020 with a commission decision on the project coming in the following months. The public comment period on the draft EIS closes Oct. 3. Whether or not the State of Alaska, through AGDC, will follow through and build Alaska LNG if it gets authorization from FERC remains to be seen. Gov. Michael J. Dunleavy has directed the state-owned corporation to drastically slow its marketing and contract efforts related to the project and focus on the regulatory issues, which is a marked reduction in the work AGDC was doing under former Gov. Bill Walker’s administration. “The ongoing permitting process incorporates more than 150,000 pages of data and should give Alaskans confidence that the project’s merits and impacts are being rigorously scrutinized,” Dubler said. Valdez officials note that going to Nikiski requires approximately 196 miles of new pipeline right-of-way through currently undeveloped areas as well as a 27-mile subsea crossing of upper Cook Inlet, which is considered critical habitat for the endangered population of Cook Inlet Beluga whales. The comments note their route would also avoid construction in several state game refuges and possibly the edge of Denali National Park; however, whether or not the 42-inch Alaska LNG pipeline would cut through a small portion of the park or skirt around it is unclear at this point. AGDC’s current route plan — primarily developed by the producers — is to generally have the gasline follow the TAPS corridor from the North Slope south to about Livengood north of Fairbanks before splitting off and cutting through the Alaska Range along the Parks Highway. The southern portion of the pipeline route would parallel the Susitna River along its west side until reaching the Cook Inlet crossing to Nikiski. A gasline to Valdez has been studied extensively in the past but AGDC officials contend crossing over Thompson Pass just north of Valdez presents engineering challenges. They also note the different engineering requirements for the oil-carrying TAPS, more than half of which is above ground, and a gasline that would be completely buried. The comments also contend that the draft EIS “unlawfully includes impacts” from a potential spur pipeline from Glennallen to Palmer, which Valdez officials insist is not a reasonable foreseeable impact of routing to Valdez. “By aggregating Palmer Spur and Valdez Alternative data, FERC makes it impossible to discern the environmental impact specifically with (the) Valdez Alternative and the Nikiski Alternative,” the document states. The City of Valdez was granted intervener status on the project, meaning it can request the commission to reconsider its decisions on the Alaska LNG Project and can also appeal FERC actions in federal court. Site analysis FERC officials wrote in the draft EIS that AGDC first looked for plant sites with between 800 and 1,200 available acres with waterfront access for development, but reduced the size requirement to at least 400 acres after additional design work was done for the Nikiski site. They evaluated seven LNG plant site alternatives identified by AGDC, according to the EIS. Anderson Bay is a 464-acre state-owned site adjacent to Valdez and within its city limits that FERC evaluated. The EIS notes that it would not drastically increase the length of the mainline pipe from the 807 miles needed to reach Nikiski and would avoid the construction issues associated with Cook Inlet’s turbid and turbulent waters, but it would require an additional 113 miles of lateral pipelines to reach Anchorage and Fairbanks. The current plan calls for a roughly 30-mile spur pipeline running east from the main gasline to Fairbanks. It would connect to the Anchorage and Matanuska-Susitna Borough population centers through the existing gas pipeline network in the region. The Anderson Bay option would impact an additional nearly 1,400 acres of land, much with wetland and forest resources, according to FERC. “Unlike the proposed mainline pipeline, the Anderson Bay mainline pipeline would also cross two federally designated Wild and Scenic Rivers; however, minor deviations from the TAPS corridor would avoid the areas within the WSR designations,” the EIS states. FERC officials also largely agreed with AGDC’s assessment of burying the gasline for about five miles through Thompson Pass. It would “likely add significantly to the construction complexity, lengthen the construction schedule and increase environmental impacts,” they wrote. Laden LNG tankers traversing narrows near Valdez and the Hinchinbrook Entrance to Prince William Sound would also cause vessel traffic problems, according to FERC, as those tankers would need a very large safety zone established around them to travel safely. A 968-acre Robe Lake site near Valdez would require moving the Richardson Highway and several residential developments, according to the EIS, along with adding between 4 million and 13 million cubic yards of fill to get the plant above potential tsunami wave heights. The current plan calls for re-routing the Kenai Spur Highway through Nikiski to avoid the LNG plant site, which would require 3.4 miles of new highway, according to AGDC. A Robe Lake LNG plant would also require the loading dock to extend about a mile and need additional dredging to reach the 60-foot water depths large LNG tankers demand. It would also have the same vessel traffic constraints as Anderson Bay and would mean displacing 142 homes instead of the 16 estimated under the Nikiski option, according to FERC. Valdez officials said through their comments to FERC that they will file additional comments further detailing the failures in the draft EIS. “Alaskans deserve a robust comparative analysis of the Nikiski Alternative and the Valdez Alternative to allow a reasoned decision between them and ensure that both environmental impacts and project costs are minimized,” the comments state. Mat-Su satisfied After expressing their displeasure for years over allegedly having their favored LNG plant site unfairly dismissed by AGDC and the producers, Mat-Su Borough officials seem to be satisfied with FERC’s analysis. Mat-Su Borough Manager John Moosey said in a brief interview that borough staff are still reading through the EIS, but he believes it shows the Port MacKenzie site “in a fair and more accurate light, and that’s really what we wanted.” He noted that borough officials simply wanted the federal record to accurately reflect Port MacKenzie — across Knik Arm from Anchorage — whether for the Alaska LNG Project or other potential developments. “If the State of Alaska believes Nikiski is the best place and the project can happen we’re all in favor of that,” Moosey added. “I just think a lot of extra energy got wasted over five years of being ignored and not providing factual information.” They contended over the past several years that ExxonMobil’s initial review of potential LNG plant sites didn’t even consider the correct site. The site evaluated and dismissed by the Alaska LNG consortium is private land about three miles north of Port MacKenzie. It has extensive tide flats that would require a 1.6-mile trestle or a massive dredging operation to access water that is continuously 50 feet deep, which is necessary for the large LNG tankers that would berth at the dock. The EIS states that borough officials asked FERC to analyze a liquefaction site about 2 miles from tidewater that turned out to consist mostly of wetlands. AGDC also said the distance from tidewater would add design and operational challenges. Therefore, FERC did not evaluate it in detail. AGDC officials have said that while ending the pipeline at Port MacKenzie would cut 60 miles off the pipeline it would require demolishing the existing dock and construction of a larger one, which the EIS notes would mean additional dredging during construction. According to the EIS, the shipping channel across Knik Shoal would also have to be dredged to the tune of 700,000 cubic yards per year for the life of the project based on AGDC’s projections. Additional considerations for Port MacKenzie being in some of the most critical Beluga habitat and more challenging winter ice conditions in the upper reaches of Cook Inlet, among others, led FERC to conclude Port MacKenzie would not be a significant improvement over Nikiski. “FERC did what they’re supposed to do and I thought they did a fine job,” Moosey said. Elwood Brehmer can be reached at [email protected]

EPA sharply critical of Pebble draft; ‘preemptive veto’ revisited

Environmental Protection Agency headquarters leaders want their Pacific Northwest colleagues to again consider rescinding a proposed restriction for the Pebble mine. At the same time, those regional officials have several questions about the thoroughness of the ongoing environmental review of the project. EPA Region 10 Administrator Chris Hladick signed off on 174 pages of comments July 1 to U.S. Army Corps of Engineers Alaska officials overseeing the Pebble environmental impact statement, or EIS, and the closely related Clean Water Act wetlands fill permit. The public comment periods on the draft EIS and the Clean Water Act Section 404 permit application closed July 1. The 115 pages of EIS comments stress a desire from EPA Region 10 leaders to see significantly more analysis regarding possible damage to the environment and subsistence activities, among other things from the proposed mine and its expansive network of support infrastructure. “Given the substantial potential impacts and risks of the proposed project and weaknesses in the (draft EIS), the DEIS likely underestimates adverse impacts to groundwater and surface water flows, water quality, wetlands, fish resources, and air quality. Therefore, conclusions that the project will not violate applicable water quality and air quality standards should be further supported,” Hladick wrote in an accompanying letter to Corps of Engineers Project Manager Shane McCoy, who is in charge of the Pebble EIS. Hladick is a former commissioner of the Alaska Department of Commerce, Community and Economic Development under former Gov. Bill Walker and has served as manager to several local governments across Alaska, including the City of Dillingham, a commercial fishing hub in the Bristol Bay region. As currently proposed, the Pebble project would consist of a 608-acre open pit mine with a depth of nearly 2,000 feed accompanied by two large tailings storage facilities, water management ponds and other structures such as the ore mill, a worker camp and a large power plant. The megaproject would also require support infrastructure including 77 miles of new roads from the mine site to tidewater; an ice-breaking ferry across Iliamna Lake to haul metal concentrates; a deepwater port in Kamishak Bay on the west side of Cook Inlet; and a 188-mile cross-Inlet natural gas pipeline from the southern Kenai Peninsula to the mine site to provide feedstock gas for the power plant. The mine site would cumulatively disturb more than 8,000 acres, nearly half of which would be from the tailings storage facilities. The overall project would result in the destruction of approximately 3,500 acres of wetlands and 80 miles of streams, according to Pebble’s wetlands fill permit application. The EPA determined in 2014 — based on the conclusions of its Bristol Bay Watershed Assessment — that any project resulting in the loss of more than 1,100 acres of wetlands and water bodies in the area would be an unacceptable impact. How Pebble will, or can, sufficiently mitigate the wetlands losses is unclear at this point and is an issue Region 10 officials and many groups opposed to the mine have highlighted. EPA’s comments on the draft EIS insist the roughly 1,400-page EIS does not provide sufficient baseline data regarding the ecological functions of the potentially impacted wetlands and other water bodies; therefore, it is difficult to develop a requisite mitigation plan to offset the project’s impacts. Similar work needs to be done in regards to the prospective impacts on fish populations and their habitat, Region 10 officials concluded. “The EPA recommends significant improvements to: (fish) habitat characterization, assessment, quantification, and spatial referencing; assessment of linkages between the loss and/or degradation of habitat and impacts to fish species and life stages [i.e., incubating eggs, spawning fish, and rearing juveniles]; groundwater and surface water flow characterization at a scale that is more relevant to fish and fish habitat; and analysis of the potential population-level effects and effects on genetic diversity in the context of the Bristol Bay salmon portfolio,” the comment document states. The U.S. Army Corps of Engineers adjudicates wetlands fill permit applications under the Clean Water Act. The EPA has the final authority to veto a permit for projects it deems would result in unacceptable environmental damage. The Democrat-controlled U.S. House of Representatives passed a spending bill June 19 with language — known as the Huffman amendment — prohibiting the Army Corps of Engineers from spending money to finalize the Pebble EIS in the 2020 federal fiscal year. That legislation is now under consideration in the Senate. Region 10 officials also note that Pebble’s draft compensatory mitigation plan “includes only a conceptual discussion” of potential means to offset the project’s substantial impacts to wetlands and water bodies and does not mention specific mitigation work the company could employ. Pebble’s draft compensatory mitigation plan in the EIS notes that restoring wetlands near the project — a common practice for project proponents elsewhere in the U.S. — is impractical because the area is undeveloped. As a result, it states the company will likely focus on fish habitat restoration in adjacent watersheds such as the Kenai, Susitna and Matanuska “through culvert rehabilitation and other fish passage improvements that have the potential to benefit the greater Bristol Bay and Cook Inlet watershed areas.” Pebble Partnership spokesman Mike Heatwole said Pebble plans to develop more specific wetlands mitigation measures as the permitting process continues and the exact permit requirements become more clear, which he said is common for large projects such as the mine. According to the EPA, the draft EIS also lacks up-to-date information regarding subsistence activities in and near the project area. Much of the information it contains regarding subsistence harvests is from a 2004 Alaska Department of Fish and Game analysis and other studies up to 2008; Region 10 officials recommend more recent data be collected or more justification as to why the included subsistence data is sufficient be provided. The EPA also suggests the final EIS should include development alternatives for lining the tailings storage facilities to prevent contaminated water from percolating into the water table. Heatwole contends that lining the tailings storage facilities would be counter to the water management plan the company developed specifically in response to concerns about a potential tailings dam failure. Currently, Pebble plans to allow water to flow through the tailings facilities to prevent additional pressure buildup behind the dams. The water will be treated to meet state and federal water quality standards before it is released into the environment, according to Pebble. Many mine opponents stress the water at the mine site will need to be treated in perpetuity — something they argue can’t be guaranteed. Finally, the Region 10 officials contend the draft EIS should contain more information about the impacts of potential further development of the Pebble copper and gold deposit beyond what the company is currently applying for. They note Pebble’s parent company, Vancouver-based Northern Dynasty Minerals has discussed mining the larger, deeper eastern portion of the deposit as recently as 2017. For that and other reasons, the EIS should consider an expanded mining scenario in more detail or explain why evaluating the impacts of additional mining is unnecessary, according to the EPA. Pebble opponents also emphasize that the current smaller, 20-year mine plan is an attempt by the company to get a mine approved that will undoubtedly grow. According to Pebble’s Clean Water Act wetlands fill permit application, the 20-year plan would recover 6.7 billion pounds of copper, 353 million pounds of molybdenum and 10.7 million ounces of gold, while the overall Pebble deposit is estimated to contain more than 80 billion pounds of copper, 5.5 billion pounds of molybdenum and 107 million ounces of gold at higher average grades than the initial mining area. The latest Northern Dynasty investor presentation dated June 2019 also touts the Pebble deposit as containing precious metal resources equivalent to “1.8 percent of all the gold ever mined” in human history. It also contends the draft EIS is “robust and comprehensive” and is the result of more than $150 million worth of environmental baseline data collected over 10 years. The draft document contains “no substantive data gaps” and “no significant impacts” that cannot be sufficiently mitigated, according to Northern Dynasty. ‘Preemeptive veto’ revisted While EPA Region 10 officials were busy critiquing the draft Pebble EIS, the agency’s headquarters leaders in Washington, D.C. were asking them to also revisit lifting a proposed ban on building the mine. EPA General Counsel Matthew Leopold directed Hladick in a June 26 memo to reconsider the agency’s July 2014 preliminary determination that it should use its Clean Water Act authority to prohibit mine development in the Bristol Bay — commonly referred to as a “preemptive veto” of the mine. Leopold noted that the proposed veto determination is still pending five years after it was reached and has not been finalized either way; it must be lifted as an administrative requirement before the Corps of Engineers can approve Pebble’s 404 wetlands permit application. Former EPA Administrator Scott Pruitt in January 2018 unexpectedly chose to keep the Obama administration’s proposed determination in place, at the time citing “serious concerns” the agency had about the impacts of mining activity on the Bristol Bay watershed and the salmon it supports. Pebble sued the agency in 2014 alleging the EPA was biased in its proposed action after improperly colluding with anti-Pebble groups to reach its conclusion. A subsequent 2017 settlement company called for the agency to consider rescinding the proposed veto determination. The current situation has caused confusion about where the agency stands in regards to the project, according to Leopold. “To remove any confusion and uncertainty, Region 10 should lift the ‘suspension’ and withdraw the 2014 proposed determination or leave it in place,” Leopold wrote. According to Region 10 officials, Hladick, as regional administrator, is believed to be the decision-maker on the proposed determination, but that decision will be made in close coordination with headquarters officials. Current EPA Administrator Andrew Wheeler last year recused himself from all Pebble decisions because he had worked for a law firm that provided services to a client related to Pebble issues. Pruitt had indicated the EPA would hold additional public hearings on the determination if it were ever revisited; however, Leopold wrote that Region 10 should forgo more public input given the several rounds of public comments the EPA and Corps of Engineers have solicited on Pebble in recent years. Leopold also urged Hladick to invoke “elevation procedures” for Pebble under a 1992 EPA-Army Corps agreement that provides for additional scrutiny on projects that could cause “substantial and unacceptable impacts to aquatic resources of national importance.”

Dunleavy follows through with massive budget vetoes

Gov. Michael J. Dunleavy followed through on many of his budget proposals but faltered on some of his other stated priorities when he announced his state budget vetoes June 28. The governor vetoed $410 million in General Fund spending from part or all of 182 items in the Legislature’s 2020 fiscal year state operating budget before signing it. He said in a press briefing that his reductions, when combined with the $280 million in cuts the Legislature made, get the state about halfway to a balanced budget. Dunleavy has prioritized paying full, statutorily calculated Permanent Fund dividends and balancing the budget without adding state revenue. Collectively, the budget cuts total nearly $700 million and get the state almost halfway to closing what started as a roughly $1.6 billion budget deficit for the 2020 fiscal year that started July 1. “Next year it’s our goal to complete this process and completely close the gap,” Dunleavy said. “I believe we’re on our way to having a balanced budget.” With the vetoes, the 2020 budget is about 12 percent less than the current year budget, which ends June 30, and the lowest level of state spending since 2005, according to Office of Management and Budget Director Donna Arduin. The University of Alaska absorbed the largest cut from the governor’s red pen, with a reduction to the Anchorage and Fairbanks campuses of $130 million — as Dunleavy first proposed in February — after the Legislature reduced the UA budget by $5 million. The cuts take state support for the university system budget from $327 million to $191 million, or a 42 percent cut. The state’s UA appropriation, which comprises about 40 percent of the overall university budget this year, peaked at $378 million in 2014 and has fallen since as the Legislature and governor deal with the impacts of lower oil revenues. OMB officials noted the cuts don’t impact community college campuses around the state or the University of Alaska Southeast. Those institutions provide the type of career and technical training the governor hopes to expand in Alaska. They arrived at the $130 million cut for the main campuses by first starting with the national average state contribution to higher education of about $7,600 per student and added a 40 percent Alaska cost adjustment to get to funding equivalent to about $11,000 per student. According to OMB, UAA is roughly at that level currently, while UAF funding is about three times that level. Dunleavy said he thinks the UA System can be transformed into a “smaller, leaner, but still very positive, productive university.” “This budget is going to impact all of Alaskans,” Dunleavy said further. “The University of Alaska I have a lot of faith in. I know their leadership. I know many of the regents. I believe that they’re going to work through this and I believe they can turn the University of Alaska into, if not the finest university of the Arctic, in a few select areas — they can’t be all things to all people.” UAF is widely regarded as the world’s leading Arctic research institution and UA President Jim Johnsen has said each dollar of state support translates to $6 of outside investment in research for Fairbanks. He called the cut “devastating” to the Anchorage Daily News and furlough notices have been sent to 2,500 UA staff. Dunleavy also cut $50 million from the state’s general Medicaid appropriation on top of a more than $70 million cut by the Legislature. The administration originally proposed a $225 million cut to Medicaid this year but eventually backed off that stance. Department of Health and Social Services officials previously said they could achieve $102 million in savings through provider rate reductions and other regulatory actions that do not require legislative approval. The governor also vetoed $8 million of state funding for preventative adult dental treatment under Medicaid, which equates to a loss of $18 million in federal funds. Alaska State Hospital and Nursing Home Association CEO Becky Hultberg, who has been roundly critical of the administration’s plans to cut Medicaid support, said the governor’s vetoes are “arbitrary” and could actually lead to additional costs in future years. “The governor’s own department has been unable to identify how to implement cuts of this magnitude, which calls into question the Department of Health and Social Services’ ability to reduce costs without cutting the Medicaid program,” Hultberg said in a formal statement. “Alaskans deserve a more complete explanation of these reductions. Since the Medicaid program is statutory, benefits must be provided. Further cuts will simply result in the need for supplemental funding next year, delayed payments to providers, and reduced access to care for vulnerable Alaskans.” She has previously told the Journal that major Medicaid cuts not tied to programmatic reforms could result in the closing of small, rural health care facilities that don’t have the financial base of larger hospitals. DHSS is currently awaiting the results of a consultant study on ways to further reduce Medicaid spending. Dunleavy did not veto the Alaska Marine Highway budget beyond the Legislature’s $44 million cut, which will allow ferry managers to run a bare-bones sailing schedule through the winter. Dunleavy had previously proposed a $95 million cut to the state ferry system and shutting down service completely this winter. And while the governor has stressed a need for lawmakers to “follow the law” in regards to the PFD, he diverted from that principle himself with several of his vetoes. He eliminated $3.4 million for the Ocean Ranger program — which regulates cruise ship activity in Alaska waters and is paid for through passenger fees, not state dollars. The Ocean Ranger program was established via a 2006 voter initiative. It’s funded through a fee on cruise ship passengers that travel to Alaska. The vetoed funds for the program remain in the General Fund. He also vetoed more than $21 million for the Senior Benefits program and halved the state’s school bond debt reimbursement appropriation to $48.9 million; in a fact sheet accompanying the vetoes, Dunleavy defended the cut to debt reimbursement by citing the “subject to appropriation” clause in the law. In the same sheet, he said the senior benefit veto “eliminates” the program. Local government officials from across the state have said cutting the bond debt cost-share, which is spelled out in state law, would lead to higher local property taxes. “I believe the communities are going to have to make decisions on how they deal with that,” he said at a press briefing in response to a question about the cut. Dunleavy largely avoided questions regarding how his moves to de-fund programs still on the books levels with his emphasis on following state laws but noted that his administration proposed repealing many of those programs; those proposals were rejected by the Legislature. He also vetoed $1 billion from the $2.9 billion percent of market value, or POMV, draw from the Permanent Fund to pay PFDs and support government services. The move was made to keep the $1 billion out of the General Fund and leave it in the Permanent Fund for paying PFDs that are expected to cost $1.9 billion based on the current formula. He also vetoed $5.5 billion of the $9.5 billion one-time transfer the Legislature planned to make from the spendable, currently $19 billion Earnings Reserve Account to the constitutionally protected corpus of the $65 billion Permanent Fund. He said the full transfer put the ability to pay future PFDs at risk. “We need to provide for a full PFD. Until that statute is changed or until the people of Alaska have a voice in changing that statute we’ve got two statutes that some say in some respects compete,” Dunleavy said to a question about he justifies his vetoes that don’t follow some state laws. Meanwhile, legislators were gathered in Anchorage for a meeting of the Bicameral Permanent Fund Working Group, which was established several weeks ago to hopefully find a resolution to the ongoing battle over the PFD and how to use the earnings of the fund without damaging its long-term value. Senate Democrats denounced the governor’s decisions in formal statements. “Gov. Dunleavy simple doesn’t value public education in Alaska,” said Senate Minority Lead Tom Begich, D-Anchorage. “The majority of his cuts cripple our university system, which should be a world-renowned leader in Arctic and global research, and takes away certainty from public schools, educators and families.” House Speaker Bryce Edgmon, I-Dillingham, said the Legislature’s budget “struck a balance” between funding essential services and necessary cuts. “Today, the governor made major vetoes that will have drastic, negative impacts on all Alaskans. The fundamental question is now squarely before Alaskans. What’s more important: a healthy economy, our schools, university, and seniors, or doubling the Permanent Fund dividend at the expense of essential state services? The governor has made his choice clear,” Edgmon said. Whether or not the Legislature will override some of the vetoes is unclear. Veto overrides require support from 45 of 60 legislators, an intentionally high bar set in the Alaska Constitution. Legislators and their staffers gathered in Anchorage for the Permanent Fund meeting said they needed time to evaluate all 182 line-item actions before determining which, if any, of the vetoes there is support to override. The Legislature is set to convene July 8 to consider this year’s PFD — with the location still being disputed between Wasilla as the governor has called for or in Juneau as a majority of lawmakers want — at which point the larger budget questions should start to be answered. Elwood Brehmer can be reached at [email protected]

BLM lifts Alaska land withdrawals, opens 1.3 million acres

More than 1.3 million acres of federal land in Alaska are a big step closer to being “open for business.” Assistant Interior Department Secretary Joe Balash signed directives June 26 in Anchorage revoking decades-old federal public land orders, in the process making more than 1.3 million acres overseen by the Bureau of Land Management eligible for conveyance to the state, Alaska Native corporations and other uses. Balash said lifting the PLOs will allow the federal government to make good on longstanding commitments to the State of Alaska and Native corporations. “We know that these lands can be unlocked for development responsibly without sacrificing (public) access,” Balash said during a speech to the Resource Development Council for Alaska prior to acting on the orders. Balash also led the Department of Natural Resources under former Gov. Sean Parnell. The PLOs covered two areas: approximately 1.1 million acres of BLM land in eastern Interior Alaska, generally between Delta Junction, Tok and the Yukon River, as well as about 200,000 acres east of the Copper River delta and near the large Bering Glacier. Both areas are known for their mineral potential. The Interior Fortymile region is an area popular among Alaska placer miners and revoking the orders will open the areas to new federal mining claims. The actions take effect in 30 days, according to BLM Alaska officials. According to Balash there are 17 such withdrawals that impact the use of roughly 50 million acres in the state. Most of them were put in place shortly after Congress passed the 1972 Alaska Native Claims Settlement Act to allow for careful evaluation of land-use classifications at a time when the State of Alaska and Native corporations were selecting millions of acres to receive from the federal government. Balash said the PLOs were a prudent step when they were put in place but largely are no longer necessary. “This is the first of many (PLO revocations) that will take place over the next several months. We’re going to have a conveyor belt operating here,” he said. Gov. Michael J. Dunleavy, whose administration has stressed the motto that “Alaska is open for business” said Interior Department officials are serious about doing the right thing in lifting the withdrawals. The governor was headed to meet with President Donald Trump, who was making a Air Force One refueling stop at Joint Base Elmendorf-Richardson, and said he would thank the president for his administration’s push to open more land in the state to development. “It’s land that Alaska can use to hopefully create wealth,” Dunleavy said during a press briefing. He has also expressed a desire to transfer more state land to private ownership. The members of Alaska’s congressional delegation also commended the moves, citing the economic development opportunities and the need to fulfill land conveyance commitments to the state and Native corporations. The State of Alaska is entitled to 104.5 million acres from the federal government under the Alaska Statehood Act and to date has received title to approximately 99.3 million acres. In total, Alaska covers roughly 365 million acres and BLM manages about 70 million of those acres. Balash said the state has selections in the eastern Interior-Fortymile area that will become available, but has already “over-selected” acreage for conveyance beyond what it is entitled to, meaning state officials have to determine which selections they want to move forward with. Elwood Brehmer can be reached at [email protected]

Furie back to supplying gas to Homer, but still short with Enstar

Furie Operating Alaska has returned to meeting some, but not all, of the natural gas supply commitments it has with Southcentral Alaska utilities. The small Texas-based gas producer resumed supplying Homer Electric Association with all of the Kenai Peninsula electric utility’s demand of approximately 12.4 million cubic feet of feedstock gas per day for its power plants on April 11, according to HEA Manager of Fuel Supply and Renewable Energy Mikel Salzetti. For about six weeks before that, HEA leaders were forced to purchase spot market gas from other producers in the Cook Inlet basin as well as draw on reserves stored in the Cook Inlet Natural Gas Storage Alaska facility commonly known as CINGSA. Furie had stopped supplying gas to HEA on about Feb. 25, Salzetti said in an early April interview. Enstar Natural Gas Co., on the other hand, stopped receiving gas from Furie on Jan. 25, according to utility spokeswoman Lindsay Hobson, and hasn’t gotten the amount of gas it contracted for in early 2016 since. Enstar’s parent company SEMCO Energy Inc. is the majority owner of CINGSA. Hobson wrote in a June 24 email that the Southcentral gas utility “has been able to negotiate the delivery of short-term volumes from Furie. These volumes vary week to week.” Hobson said previously that the less-than-contracted deliveries started in late March. Furie operates the offshore Kitchen Lights natural gas field in central Cook Inlet. Furie is one of the newer entrants to Cook Inlet that were supposed to ease Southcentral gas supply concerns by developing new fields and adding competition to the market. In 2015 the company installed the Julius R platform at Kitchen Lights, which was the first new production platform built in Cook Inlet in since the 1980s. The company is one of several small oil and gas operators in Alaska that were impacted by less-than-full payments of refundable tax credit payments by the state, which started in 2015 and are an ongoing issue. Furie officials said in 2017 they planned to work on developing oil prospects in the Kitchen Lights gas field, but those plans have largely been scuttled because of the state’s delay in paying millions of dollars in oil and gas tax credits the company earned for its previous work, according to the 2019 Kitchen Lights Plan of Development filed last October with the state Division of Oil and Gas. While Furie’s financial situation is unclear, the company’s website was offline as of June 25. Furie leaders did not respond to requests for comment in time for this story. In May, Furie produced an average of 14.3 million cubic feet of gas per day from the four wells it has in the Kitchen Lights field, according to Alaska Oil and Gas Conservation Commission records. A Feb. 11 letter from Enstar and Alaska Pipeline Co. President John Sims states that Furie has had problems proving up its gas reserves to meet its contract with Enstar and has had operational problems with its wells. The producer asked for a delayed delivery of more than half of its firm supply commitment to Enstar on Jan. 17 as it worked on issues at its facility, according to the letter. Elwood Brehmer can be reached at [email protected]

Tax credit issue plods along toward Supreme Court

Alaska lawmakers are relying on the prospect of a favorable court ruling this year to pay down the state’s remaining and roughly $700 million obligation of refundable oil and gas tax credits. The 2020 state fiscal year operating budget the Legislature passed June 10 includes language authorizing Department of Revenue officials to sell bonds through the Alaska Tax Credit Certificate Bond Corp. that would allow the state to pay off the entirety of the obligation. The budget also reauthorizes a $27 million unused appropriation approved last year to make the first interest payment on the debt if the 10-year bonds are sold under House Bill 331. However, the budget approved last year — for the fiscal year that ends June 30 — also contained a $100 million contingency appropriation in case the bond sale didn’t occur or some companies holding the credits did not agree to the terms that come with participating in the bond plan. As it turned out, the bond sale originally set for last August was scuttled by a public interest lawsuit by former University of Alaska Regent and Juneau resident Eric Forrer challenging the constitutionality of HB 331. That led the state to pay just $2.8 million in tax credits during 2018, according to Department of Revenue documents, the smallest annual credit payment total in years. Previous tax credit payments totaled in the tens or hundreds of millions of dollars per year. In response, Revenue officials released the $100 million early this year as a means to provide the small explorers and producers eligible for the credits — several of which have had significant financial issues in recent years — some financial relief, according to Commissioner Bruce Tangeman. “These companies have gone through this process for too long,” Tangeman said in a brief interview. The bond plan was hatched by former Gov. Bill Walker’s administration early last year as a way to quickly pay off the credit holders, put what had become an extremely messy political issue to rest, and eventually restore the state’s reputation among private financial institutions that lent money to companies backed by the presumption of past credit payments. At the time, administration officials estimated the final tax credit obligation would total nearly $1 billion but Tangeman said the latest total after the $100 million installment is closer to $700 million. The reason for the discrepancy is unclear; however, some small companies could have sold their credit certificates to larger North Slope oil producers that are not eligible for payment but can use the credits against their annual oil production tax liability. Such transactions would not have to be publicly reported and would reduce the final amount of money the state is obligated to pay. Numerous oil and gas companies used the state credit certificates as collateral to secure loans from large banks to fund exploration and other work. A commonly used credit for explorers with no production and no tax liability had the state paying 35 percent of the cost of qualifying work in cash. When Walker diverted from the state’s prior practice — but not law — of paying off the annual credit bill in full each year by vetoing $200 million of a coincidentally $700 million appropriation in the face of a $3 billion-plus budget deficit in 2015, it ostensibly froze the market that had grown around the state tax credits. Walker vetoed another $430 million of the payments in 2016 when he also reduced the Permanent Fund dividend appropriation by half. Subsequent years of minimum tax credit payments based on a statutory formula that incorporates the state’s oil production tax revenue also pushed some companies to default on those loans. Many Republican legislators who were roundly critical of Walker’s approach to the refundable industry tax credit program now acknowledge the now-defunct policy became unaffordable when oil prices began to fall in late 2014, but still contend the state should make paying the remaining balance a priority. That’s where the tax credit bonds come in. To get paid sooner, the credit holders would have to accept a discount of up to 10 percent less than the face value of the certificates. The state Department of Revenue would then use the difference between the credit values and the discounted amount to cover the borrowing costs. Supporters of the bond plan insist it is a way to restart stalled investment by small companies in Alaska’s oil and gas fields; Forrer and some in the Legislature contend it flies in the face of strict limitations on the state’s ability to incur debt laid out in the Alaska Constitution. The state constitution generally prohibits lawmakers from taking on debt unless it is for capital projects that are also approved by voters, in response to a natural disaster or invasion, or it is in the form of bonds sold to support a specific project repaid through the eventual revenue of that project. State corporations such as the Alaska Industrial Development and Export Authority and the Alaska Housing Finance Corp. regularly utilize such revenue bonds. Superior Court Judge Jude Pate dismissed Forrer’s lawsuit in January, concluding that while the fiscal policy implications of the bonds are worthy of debate, the plan fits within the constitutional sideboards relating to state debt. Forrer appealed Pate’s ruling to the Alaska Supreme Court and has said he believes allowing the tax credit bond plan to move ahead would give lawmakers and local governments the freedom to employ the scheme in countless other situations, potentially strapping the state with substantial additional debt. State officials contend similar plans have already been employed to pay for capital projects, including the Goose Creek Correctional Facility in the Matanuska-Susitna Borough. State attorneys argue, and Pate agreed, that a provision in HB 331 establishing the plan that calls for the bond repayments to be “subject to appropriation” by the Legislature each year means the State of Alaska would not ultimately be liable for defaulting on the payments. Proponents acknowledge that not making bond payments would likely have a significant negative impact on the state’s credit rating but the state would technically not be liable for the bonds if the Legislature in any year decided not to repay the bonds. Instead, bondholders would have to sue the Alaska Tax Credit Certificate Bond Corp. — which Forrer notes would be comprised of a couple Revenue Department leaders and would have no money of its own — and not the State of Alaska for recourse because the state corporation would actually hold the debt. Forrer’s attorney, longtime Juneau lawyer Joe Geldhof, wrote in a 60-page May 16 brief filed with the Supreme Court that Judge Pate incorrectly overlooked the plain language and meaning of the state constitution. “The position advanced by the state and adopted by the trial court to the effect that the debt is not debt because the statute says it is not debt amounts to an unsupported argument resting on circular ‘logic’ that should be viewed with doubt when evaluating a constitutional claim,” Geldhof wrote. “The Alaska Constitution is our state’s guiding framework of law and policy and its intent should be respected; the state’s search for a clever loophole — some sort of technicality — to provide an end-run around the constitution’s clear intent should not be sanctioned,” he continued. “the state should be deterred from offensive attempts to disregard the known meaning of the constitution, now and into the future.” In a 49-page June 19 brief, state attorneys cited prior Supreme Court cases that permit the state to take on some forms of debt and contend that even if the court finds that HB 331 is prohibited by the constitutional limitations on debt, “it constitutes a refinancing of a pre-existing state financial obligation rather than the creation of a new one and the bonds are backed only by the resources of an independent public corporation rather than by the state treasury.” Oral arguments before the Supreme Court are scheduled for Sept. 12. ^ Elwood Brehmer can be reached at [email protected]

Sub-500: TAPS throughput drops in 2019

Measured on the state calendar, Alaska North Slope oil production is about to be at its lowest level since the first days after startup of the Trans-Alaska Pipeline System. North Slope crude production averaged 499,103 barrels per day through June 24 for the 2019 state fiscal year, which ends June 30. The last time North Slope wells pumped that little oil was 1977 when oil first started flowing through TAPS in late June; production averaged 10,500 barrels per day in 1977, according to Revenue Department figures. It jumped to 789,600 barrels per day in 1978 and peaked at 2.1 million per day in 1988. Daily North Slope production dipped to about 501,000 barrels per day in 2015 but that was followed by two years of increases, which were celebrated by industry and state officials, as it was the first instance of production growth on the North Slope since 2002. The 499,103-barrel average for 2019 is unlikely to improve much in the last days of the month as the combination of warm weather and scheduled maintenance makes summer the least productive season for companies on the Slope. State production analysts in the Department of Natural Resources expected the average daily throughput to decline in their latest projection, but not this much. The Spring 2019 Revenue Forecast released in March pegged fiscal 2019 North Slope production at 511,460 barrels per day. Actual production has been off by about 2.4 percent. However, 2019 was originally supposed to be a bounce-back year after unexpected decline in 2018. The 2019 forecast released in December estimated 526,800 barrels of oil per day from the North Slope following the 521,400 barrels produced per day last year. In the end it means North Slope oil production this year will decline a little more than 4 percent instead of increasing about 1 percent as state officials once thought would happen. Alaska Oil and Gas Association CEO Kara Moriarty said the unexpected decline is probably the result of several smaller factors given the complexity and diversity of North Slope operations. She noted that the long-term production trend has improved, from the industry and state’s perspectives, in recent years and the state’s forecasts are often optimistic. “I do know that we are significantly higher than the forecasts of 2012 and 2013,” Moriarty said. In the fall of 2012, state officials expected North Slope production would be about 421,600 barrels per day this year. At that time, the annual decline rate was in the 6 percent range. Last year, state officials surmised the unexpected drop in oil flow could have been from higher than normal winter North Slope temperatures. Warmer weather decreases the efficiency and capacity of compressors used to process the natural gas that comes with the oil on the Slope, and thus has an impact on how much oil can be produced. BP Prudhoe Bay Production Manager Jennifer Starck said last January actually produced some record cold temperatures at the iconic oil field, but noted that March was warmer than usual. Last March is believed to be the warmest March on record across Alaska. “We live with the natural ambients,” Starck said. Currently, Prudhoe Bay is producing a calendar year 2019 average of about 275,000 barrels per day compared to about 279,000 barrels per day a year ago, Starck said. She added that BP currently has two drilling rigs working at Prudhoe and the company is also “working over” old wells. It also conducted a 3-D seismic shoot over the entire field this winter and believes it can recover another billion barrels from the basin. While the company does what it can to buck production trends for mature fields, she stressed that production from nearly all oil fields starts naturally declines — and Prudhoe is more than 40 years old. Hilcorp Alaska officials did not respond to questions in time for this story, but Moriarty and acting state Division of Oil and Gas Director Beckham also pointed out that Hilcorp’s Moose Pad development in the Milne Point Unit was originally slated to start producing in last fall, but didn’t come online several months later. The $400 million project is now producing about 7,000 barrels per day, according to AOGA and Hilcorp leaders have said it should peak at 16,000 to 18,000 barrels per day. ConocoPhillips’ Greater Mooses Tooth-1 project in the National Petroleum Reserve-Alaska, which started flowing oil last October, is off to a bit of a slow start as well. The company estimated GMT-1 could produce up to about 30,000 barrels per day at its peak; three wells are currently producing about 11,500 barrels per day. ConocoPhillips Alaska spokeswoman Natalie Lowman wrote via email that the company’s estimates are usually a mid-range figure of what a project could produce and the smaller projects generally see more variability because production is dependent upon fewer wells. As a counter to GMT-1, she noted that the company’s nearby CD-5 development, which started in late 2015, was first estimated to produce about 16,000 barrels per day but actual production has been more than double that. Monthly production from ConocoPhillips’ large and aging Kuparuk River field has also been roughly 6,000 to 8,000 barrels per day less than last year, according to Department of Revenue figures. Beckham said he had noticed the daily production totals for 2019 were approaching 500,000 barrels, but said he thinks focusing on the exact number is a bit unnecessary. “For years, for whatever reason, that 500,000-barrel level has been somewhat of a benchmark and it’s an arbitrary number but we do have concerns about low-flow in the pipeline, although I think Alyeska (Pipeline Service Co.) has most of those covered,” Beckham said. “I think the optic is more impactful than the actual volume but I do expect that we’ll have more production online this year and as other years come up.” Alyeska officials have said TAPS should run smoothly as currently designed down to production levels of about 300,000 barrels per day. Brooks Range Petroleum Corp. is expected to start its small Mustang field near Kuparuk this summer, among other work. Longer term, ConocoPhillips’ Willow, Oil Search’s Nanushuk and Hilcorp’s Liberty projects could collectively add nearly 300,000 barrels per day of production to the Slope over the next five-plus years. The Liberty and Nanushuk projects have federal approval and ConocoPhillips is currently in the process of permitting Willow with a final environmental impact statement scheduled to be issued in 2020. ^ Elwood Brehmer can be reached at [email protected]

Back from China, AGDC officials await draft environmental report

Alaska gasline officials are preparing for the long-awaited first draft of the $43 billion Alaska LNG Project’s environmental review after returning from an overseas trip to update potential LNG customers and investors on the latest plans for the project. Alaska Gasline Development Corp. officials expect the Federal Energy Regulatory Commission, which oversees the domestic LNG industry, to publish a roughly 4,000-page draft Alaska LNG environmental impact statement June 28, the last working day of the month. Interim AGDC President Joe Dubler said during a June 20 board meeting that leaders of the state-owned corporation and members of Gov. Michael J. Dunleavy’s administration had productive discussions with senior development representatives from national Chinese companies that are potential participants in several aspects of Alaska LNG on a trip to Asia earlier this month. Dubler and AGDC commercial staff traveled to Beijing and Bangkok, Thailand, from June 10-18. They were joined on part of the trip by Brett Huber, a senior policy advisor to Dunleavy as well as Department of Natural Resources Commissioner Corri Feige and Revenue Commissioner Bruce Tangeman. Dunleavy has long been critical of former Gov. Bill Walker’s plan for a state-led Alaska LNG Project. He made it clear soon after being elected last fall that his administration would slow the pace of the project and try to bring the major oil companies back into the fold. Officials from Chinese oil and gas giant Sinopec Corp., the Bank of China and China Investment Corp. recognize the benefit of focusing on the regulatory and permitting progress for Alaska LNG as a means to de-risk the project for possible future investments, Dubler said. The state-owned oil and financial companies signed a nonbinding joint development agreement with AGDC in November 2017 to advance the prospect of financing up to 75 percent of the project in exchange up to 75 percent of the LNG it produces. At the time, Walker and AGDC leaders were pushing hard to make a final investment decision on Alaska LNG in 2020, shortly after the state would receive a presumably favorable permitting decision from FERC, to capture demand opportunities in the rapidly expanding global LNG trade. “The message was very well received from (the Chinese representatives) that the governor is keeping the project moving with the producers involved,” Dubler said. LNG exports to China have declined dramatically this year after retaliatory tariffs were imposed and increased from 10 percent to 25 percent on June 1. He also stressed that AGDC is no longer pursuing LNG customers or gas supply agreements as the corporation had been under Walker’s plan. Instead, AGDC is refocusing on the “stage-gate” project development process often used by major oil companies to evaluate large projects. The state, BP, ConocoPhillips and ExxonMobil were in between the preliminary front-end engineering and design, or pre-FEED, and the full FEED stage — estimated to cost $1 billion-plus — of development in 2016 when the producers chose to back away from Alaska LNG project because of depressed global oil and LNG prices. The international energy consulting firm Wood Mackenzie concluded at the time that the Alaska LNG Project likely wasn’t economic if developed by Alaska’s major producers, as first envisioned, in part because of the high internal return requirements oil companies typically have. However, a state-led project with federal tax exemptions could be viable, Wood Mackenzie said. The AGDC team also met with officials from Public Company Ltd., known as PTT, Thailand’s national oil and gas company to maintain the relationship, according to Dubler. AGDC signed nonbinding, early-stage agreements with approximately 15 potential Asia-Pacific Alaska LNG customers and investors from 2016-2018 under Dubler’s predecessor Keith Meyer, according to corporation officials. Revenue Commissioner Tangeman, a former AGDC finance official, said meetings with the Chinese companies went very well. The primary message from the Alaskans was that the Dunleavy administration is still interested in monetizing North Slope natural gas through an LNG export project, he said, adding that the recent support from BP and ExxonMobil provided the Chinese representatives “a lot of comfort.” “We’re not interested in doing this (LNG project) at any cost,” Tangeman said in a brief interview. “I think the previous administration’s hurdle was much lower.” The North Slope producer companies own the lion’s share of the roughly 35 trillion cubic-foot gas resource that would feed the project and both have been providing technical assistance to AGDC since March; BP’s assistance goes back to 2017. On May 30, Lt. Gov. Kevin Meyer announced BP and ExxonMobil had agreed to contribute up $10 million apiece to help the state pay for completing the FERC licensing process. AGDC leaders expect that will cost roughly $30 million over the next year or more. The AGDC board approved $20 million in expenditures over the next year to advance the project EIS, which should be finished next June, according to FERC documents. Dubler noted during the meeting that through April 30 AGDC was operating at 9 percent below its $10.3 million budget for the 2019 fiscal year, which ends June 30. Among other things, the corporation gave up its 6th floor boardroom and some office space in the Midtown Anchorage Calais office building it occupies. The June 20 board meeting was the first held in public meeting rooms at the state Atwood Building in Downtown Anchorage and was hampered by technical difficulties. Overall 2019 spending — including corporate operations and Alaska LNG-specific project expenses — is down about $5 million, according to Dubler, who said those cost reductions will continue into 2020. Elwood Brehmer can be reached at [email protected]

ConocoPhillips buys North Slope Nuna prospect from Caelus

A North Slope oil prospect is changing hands in a deal that appears to be another step out of Alaska for a small independent oil company. ConocoPhillips Alaska announced June 17 that it has agreed to purchase 100 percent of the mid-sized Nuna project from Dallas-based Caelus Energy. “This transaction represents an attractive addition to our expanding North Slope position and will allow ConocoPhillips to cost-effectively develop Nuna utilizing Kuparuk River Unit infrastructure. “We believe this acquisition could lead to more oil production, more revenue for the state and more jobs for Alaskans,” ConocoPhillips Alaska President Joe Marushack said in a formal statement. ConocoPhillips officials declined to disclose the terms of the sale. Caelus representatives referred questions about the deal to ConocoPhillips. The Nuna sale marks the second asset Caelus has sold this year. Italian oil major Eni announced in early January that it would acquire Caelus’ 70 percent operator stake in the small Oooguruk field. The company still holds the potentially multibillion-barrel Smith Bay oil prospect discovered in 2016 in remote state waters adjacent to the National Petroleum Reserve-Alaska, but work to appraise and advance Smith Bay has largely been shelved. For ConocoPhillips, the Nuna acquisition is the latest in a series of moves to grow the company’s already large presence on the North Slope. ConocoPhillips purchased all of Anadarko Petroleum Corp.’s North Slope assets for $400 million. The companies had been partners in western Slope exploration and development work, with Anadarko holding a silent minority share in those projects. In December ConocoPhillips also closed a deal to ostensibly swap BP’s 39 percent interest in the large Kuparuk River field for a portion of its interest in the British Clair oil field. ConocoPhillips has also been an aggressive player in recent federal NPR-A lease sales. Development of the Nuna prospect has been subject to fits and starts since Pioneer Natural Resources discovered it in 2012. Pioneer sold Nuna to Caelus in 2014 as part of a larger $550 million deal for all of Pioneer’s Alaska assets. Caelus CEO Jim Mussleman said at the time that the company planned to drill roughly 30 wells at Nuna to produce between 20,000 and 25,000 barrels of oil per day from more than 100 million barrels of reserves. First production was expected in late 2016 for the development pegged at roughly $1.5 billion. Nuna currently consists of a 22-acre gravel pad and road and several exploration and appraisal wells. Caelus subsequently asked for and in January 2015 received a reduction in the oil royalty rate for Nuna from 12.5 percent to 5 percent from the state Department of Natural Resources to improve the economics of the prospect. The state oil royalty modification required the company had to quickly sanction the project and start oil production by October 2017. However, the combination of sustained low oil prices and former Gov. Bill Walker’s decision in June 2015 to veto a portion of refundable state tax credits for oil project development in response to a nearly $4 billion state budget deficit — also the result of fallen oil prices — pushed Caelus to delay work on Nuna. Caelus’ March 2016 request to extend the special royalty terms was denied by then-Division of Oil and Gas director and current DNR Commissioner Corri Feige. Company leaders have said Caelus was once owed more than $100 million in tax credits by the state. The aim of the now defunct tax credit program was to encourage more small independent operators, such as Caelus, to work in Alaska’s oil and gas basins. Elwood Brehmer can be reached at [email protected]

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