Elwood Brehmer

AGDC gets help soliciting investors for LNG Project

The Alaska Gasline Development Corp. has secured two of the world’s largest banks to help raise funds for the $43 billion Alaska LNG Project. Goldman Sachs and the Bank of China will assist AGDC in raising multiple rounds of debt and equity investment, according to a late announcement March 27 from the state-owned corporation. Equity offerings will be made to Alaska municipalities, Native corporations and all Alaska residents in addition to more traditional private equity investors, as required by Senate Bill 138, which set up the initial commercial framework for the project in 2014. “Bank of China and Goldman Sachs are well-positioned to provide AGDC with world-class institutional knowledge and resources required to arrange the equity and debt financing to build Alaska’s natural gas infrastructure and LNG export project,” AGDC President Keith Meyer said in the release. The first rounds of equity solicitation will be used to provide working capital for AGDC until the corporation has secured sufficient funding and regulatory approvals for full-scale development. Before AGDC can accept any money from outside investors, however, the Legislature must first give the go-ahead. Gov. Bill Walker’s fiscal year 2019 state budget proposal included language allowing AGDC to accept unlimited third-party funds but the House Finance Committee limited the corporation’s receipt authority to $1 billion per year. Such receipt authority is required for state corporations to accept non-state money. Spokeswoman Rosetta Alcantra denied a public records request for the corporation’s contracts with the Bank of China and Goldman Sachs citing the broad authority the Legislature gave AGDC to sign confidentiality agreements and withhold commercial documents that would otherwise be public. “Both Goldman Sachs and Bank of China will serve as AGDC’s financing arrangers, underwriters and placement agents for Alaska LNG. Bank of China will focus on raising funds from Chinese sources and Goldman Sachs will focus on U.S. and other international investors,” Alcantra wrote. “The two companies will be paid a reasonable fee for services provided. Additionally, they will receive a success fee upon procuring necessary financing for Alaska LNG.” The contracts other state-owned corporations enter into are generally public documents and AGDC has selectively released other contracts it has signed to media outlets upon request. The Journal is appealing the denial of the records request. Authorizing AGDC’s funding is the Legislature’s primary source of control over the project that the Walker administration is pursuing. Securing the outside working capital will likely be necessary for AGDC to keep the project moving because additional state funds will be exceedingly difficult to come by, but not just because the state continues to struggle through annual budget deficits in the $2.5 billion range. Many legislators on both sides of the aisle are also skeptical of AGDC’s ability to pull the massive project together with a staff of less than 40 individuals; there are also questions about the project’s economics, regardless of the entity leading it. AGDC officials expect the corporation will have about $43 million on-hand by the end of June, which is also the end of the state’s fiscal year, according to documents presented at the March 8 board of directors meeting. The corporation spent nearly $37 million in 2017 and has been operating with funds remaining from prior legislative appropriations when a consortium of BP, ConocoPhillips and ExxonMobil led the Alaska LNG Project until the start of 2017. The producers estimated the period when the project’s designs are being finalized and materials and equipment are being ordered would cost roughly $2 billion before actual construction commenced, also known as full front-end engineering and design, or FEED. However, that was also when the project was operating under a different management structure and the overall cost estimate was still between $45 billion and $65 billion. The state and the three producers spent about $650 million combined in the pre-FEED stage before the state took the lead on the project. The nationalized Bank of China is one of three large Chinese companies — oil and gas giant Sinopec and the country’s sovereign wealth fund managers China Investment Corp. are the others — to sign a nonbinding framework deal with AGDC last November that in broad terms exchanges 75 percent of the project’s 20 million tons per annum of LNG capacity for financing 75 percent of the $43 billion Alaska LNG price tag. “Under the witness of both President Xi (of China) and President Trump, Bank of China was one of three China-owned entities to sign a joint development agreement with the State of Alaska and AGDC. We believe it is a very important project for China-U.S. economic ties. Joint development agreement parties are advancing the economic analysis of the project in order to lay (a) more solid foundation for investment and financing,” Bank of China said in a statement issued by AGDC. Goldman Sachs Managing Director Kevin Willens said simply that he is pleased the bank is working with AGDC and the Bank of China on the project in the AGDC announcement. Meyer has said he hopes to have firm agreements in place with the Chinese companies by the middle of the year to continue rapidly progressing the project. AGDC is also pushing to start construction shortly after receiving regulatory approval, the lion’s share of which is tentatively scheduled to happen in March 2020 — when the Federal Energy Regulatory Commission earlier this month said it plans issue a record of decision on the project’s environmental impact statement — presuming a favorable ruling from FERC. However, the corporation could begin contracting for long-lead items before then, according to Meyer. Elwood Brehmer can be reached at [email protected] AGDC hires consultants The state agency leading Alaska’s gas line megaproject has brought on a pair of well-connected consultants to pitch its message to policymakers in Washington, D.C., and to the Alaska public. The Alaska Gasline Development Corp., a public entity whose board is chosen by the governor, has hired the Virginia-based firm of Mike Dubke. He worked for three months last year as communications director for President Donald Trump and has also worked as a campaign strategist for both of Alaska’s U.S. senators. The gas line corporation has also hired Kevin Sweeney, who recently left his job as a top aide to one of those senators, Lisa Murkowski. Sweeney, formerly Murkowski’s state director, is now working as a subcontractor for Dubke’s communications firm, Black Rock Group. While both Sweeney and Dubke have close ties to Alaska’s congressional delegation, neither is formally lobbying on AGDC’s behalf, Dubke said in a phone interview last week. Instead, they’re effectively advising AGDC on its own lobbying — on how best to communicate with Congress, the White House, federal regulators, Alaska policymakers and the public. “There’s a big difference between helping them craft their message in a way that Washington would understand — which is what I do — and what a lobbyist would do, which is setting up meetings and pressing for certain pieces of legislation,” Dubke said. “I’m just helping them frame their arguments in a way that people will understand.” Part of Dubke’s job, he added, is monitoring to make sure that Trump’s administration and Congress don’t adopt policies that could inadvertently damage the project, known as Alaska LNG. Trump this month ordered steep new taxes on steel and aluminum imports, which Murkowski said could add as much as $500 million to the project’s cost. And Trump’s tough stance against Chinese imports has prompted fears that he could start a trade war — just months after China’s state-owned enterprises announced they’d partnered with Alaska on the pipeline project. AGDC’s $15,000-a-month contract with Black Rock Group was signed in November and runs through June. Sweeney’s company, Six-7 Strategies, was hired last month as a subcontractor to Black Rock Group at the same monthly rate, also through June. Sweeney’s wife, Tara Sweeney, has been tapped by Trump for a top job at the U.S. Department of the Interior, though her appointment has been held up by questions about her ownership of shares in an Alaska Native corporation. An AGDC spokeswoman, Rosetta Alcantra, provided copies of the contracts in response to a records request from ADN. Asked to discuss them, she provided a prepared statement. “The Alaska LNG project is on an aggressive timeline and we need contractors who are familiar with Alaska, the White House and the Trump administration to assist us in building the project awareness in Washington, D.C.,” she said. — Nathaniel Herz, Anchorage Daily News

Corps of Engineers releases two-year schedule for Pebble EIS

The U.S. Army Corps of Engineers is looking to fast-track the environmental review of the proposed Pebble mine and the project’s opponents, to put it mildly, aren’t happy about it. The Corps released a schedule March 20 of roughly two years to complete the Pebble environmental impact statement, or EIS, and reach a record of decision on the project. A 30-day scoping period, in which the public can submit comments to the Corps regarding what they believe should be evaluated for potential impacts from the project, is set to start April 1. Alannah Hurley, executive director of United Tribes of Bristol Bay, called the Pebble timeline “outrageous.” UTBB is a consortium of 15 Alaska Native governments from the region. Hurley contends that while it is legal — 30 days is the minimum time for an EIS scoping public comment period — public scoping for a single month is well outside the bounds of precedent the Corps and other federal agencies have set for projects the size of what Pebble Limited Partnership is proposing. “There is no way you can get meaningful comment in 30 days,” Hurley said. A statement from Trout Unlimited Alaska notes the Corps of Engineers is currently leading the EIS for three other large projects in Alaska: the state-sponsored Alaska Standalone Pipeline, or ASAP, project, the Nanushuk North Slope oil development, and the Donlin Gold mine in the Kuskokwim River drainage to the north of Pebble. The scoping comment periods for those projects were from 75 to 106 days. The Corps’ Pebble Project Manager Shane McCoy in an interview called the EIS timeline “a strawman schedule.” He said the Corps is required to publish the schedule, but the agency will know much more about how long the Pebble review will actually take after scoping is complete and the comments are analyzed. McCoy acknowledged the two-year schedule is “aggressive” but said Pebble also has provided substantial baseline information to support the work. He added that agency leaders will also decide soon whether or not to extend the scoping period after receiving requests to do so. “We understand the emotions surrounding this project,” McCoy said. Hurley said a longer 60- or 90-day scoping comment period would run up against the annual time when countless area residents are busy prepping for the salmon season that starts in mid-June; however, that would also allow individuals who fish in the region but live elsewhere an opportunity to have their voices heard directly. Hurley also said it’s particularly concerning to her that the only public hearing in the Nushagak River watershed is in the local hub of Dillingham, with no meetings scheduled for upriver Nushagak villages closer to the mine site. The Nushagak is one of two large salmon-producing drainages the project straddles; the Kvichak River-Iliamna Lake system is the other. While fungible, the overall two-year EIS timeline, from March 2018 to early 2020, also comes as a surprise to those monitoring the project closely. When Pebble submitted its Clean Water Act Section 404 wetlands permit application in late December, Corps of Engineers Alaska regulatory officials noted the average EIS for a large project in the state usually takes four to five years. Pebble CEO Tom Collier said at the time he hoped the review could be done in three. According to the schedule, Corps officials hope to have a draft EIS finished by next January with the final EIS published late next year leading to the early 2020 record of decision, according to the project website. The Corps manages Clean Water Act wetlands activity permits for the Environmental Protection Agency and large wetlands fill applications such as Pebble’s usually trigger a full EIS. The mine site north of Iliamna Lake would fill 3,190 acres of wetlands, according to Pebble’s Section 404 application. In January, Pebble’s adversaries got a bit of welcomed but unexpected news from EPA Administrator Scott Pruitt, who declined to remove the Obama administration’s proposed prohibitions on developing a large mine in the Bristol Bay region. Pruitt indicated the agency is still highly skeptical the project can adequately coexist with the area’s fisheries, but also stressed his decision “neither deters nor derails” Pebble’s environmental permitting process because nothing has been finalized. The entire project stretches over 187 miles from the start of a natural gas pipeline near Anchor Point on the Kenai Peninsula, across Cook Inlet to a deepwater port that would be built on the edge of Kamishak Bay on the west side of the Inlet 53 miles of roads plus a ferry leading to the mine itself. Hurley noted that residents near the Donlin project — similarly a large open-pit mine proposal with a gas pipeline from Cook Inlet — were afforded 16 public scoping meetings by the Corps. The Donlin Gold EIS was initiated in December 2012; a draft EIS was published in November 2015 and a final EIS is expected soon. Pebble spokesman Mike Heatwole said the company is pleased with the schedule the Corps has put forth. “I think they’ve laid out a fairly comprehensive and transparent approach to what they’re hoping to accomplish,” Heatwole said in an interview. “We certainly hope, as we’ve said for quite a while, it’s an expeditious permitting review process for the project. There’s a lot of material to cover and we hope that we get a comprehensive review through that.” He also stressed that scoping is the time when the public can weigh in with what they feel the Corps should evaluate relating to Pebble — much of which have been aired for years — and those issues “are pretty well known.” “Once the draft EIS comes out, that’s when you really get into the comprehensive look at what the Corps has put forward,” Heatwole added. The minimum public-comment period after a draft EIS is published is 45 days. For Pebble, eight scoping meetings were originally planned: seven in Bristol Bay-area communities and one each in Homer and Anchorage. However, a March 22 release from the Corps’ Alaska District indicates a meeting planned for Igiugig, a community at the outlet of Iliamna Lake has been cancelled, leaving seven scoping meetings. Those meetings are set for the period from April 9 in King Salmon to April 19 in Anchorage. The Corps also translated a condensed version of the Donlin draft EIS into Yupik, which is the first language for many of the region’s Alaska Native residents, but no action has been set for Pebble, Hurley contended. “It’s the Corps’ mandate to make sure people can engage whether they’re English speaking or not,” she said. Donlin Gold translated additional project information on its website into Yupik on its own, according to a company spokesman. Heatwole said the Pebble Partnership is still evaluating the best ways for it to engage with communities near the project. Elwood Brehmer can be reached at [email protected]

Legislators on all sides concerned about receipt authority for AGDC

Gov. Bill Walker’s administration is not asking for more state funding to advance the $43 billion Alaska LNG Project, but some legislators are concerned allowing the gasline developers to accept outside money could sign away much of their remaining control over the project. Included in the governor’s 2019 fiscal year budget proposal is language giving the Alaska Gasline Development Corp. the authority to accept third-party funds from potential Alaska LNG investors. The provision would cover the remaining months of fiscal year 2018, which ends June 30, and fiscal year 2019. Resources Committee chair Sen. Cathy Giessel, R-Anchorage, said legislators generally like to guard their appropriation authority, which is one of the most fundamental powers they are granted by the state constitution. “Receipt authority is a lot like giving a blank check,” she said. Giessel, who has monitored AGDC’s work as close as anyone in the Legislature, said at this point the Senate Majority still has a lot of questions about what the state-owned corporation would do with the third-party funds — or what it would have to offer to receive them. The House Finance version of the 2019 operating budget released March 19 capped the receipt authority at $1 billion per year to give AGDC financial headroom to keep working without the freedom to commit to building the whole project without further review by the Legislature. Giessel said the House concept might not be a bad idea. She also noted that the Federal Energy Regulatory Commission published a schedule for the Alaska LNG environmental impact statement March 12 that likely would not have the project receive regulatory approval until early 2020 or possibly later. “We wonder if perhaps, based on the new FERC timeline, if (AGDC) wouldn’t have enough money through next year anyway,” Giessel said. The administration had been pushing FERC to have the EIS done by early 2019, but the extra year could slow the need for money to advance the project quickly. AGDC President Keith Meyer has said ideally he would like to start construction in late 2019 or at least be contracting for long-lead time items in preparation for construction by then. Meyer and Walker said when the state took control of the project from the producers in early 2017 that AGDC would rely on the roughly $100 million it had left from prior gasline appropriations for the foreseeable future. Corporation leaders expect to have about $43 million left when fiscal 2019 rolls around in July, according to a financial summary from the March 8 AGDC board of directors meeting. As the proponents of the project, AGDC is responsible for funding work on the EIS and officials said it’s unclear if the corporation currently has enough cash available to finish the environmental review because the extent of additional work FERC will require isn’t yet known. Spokesman Jesse Carlstrom said via email that the corporation can continue advancing Alaska LNG on its current pace with no new funds through 2019. “AGDC is preparing to engage investors. Authority to accept funds from third-party investors will enable AGDC to build Alaska LNG without the necessity of additional state funding,” Carlstrom wrote. Absent sure-fire success on the project there likely won’t be additional state funds to support AGDC as long as the state is struggling through continued budget deficits. Legislators have exuded bipartisan skepticism in the project since AGDC took it over but have allowed the administration to keep working on it with the remaining funds. They are now wondering what role the three Chinese nationalized mega corporations, Sinopec, Bank of China and China Investment Corp., could have in the project if they also end up being the primary funders. The nonbinding joint development agreement Meyer and Walker signed with them Nov. 8 would have the Chinese consortium provide debt and equity to cover 75 percent of the gasline development costs in exchange for 75 percent of they system’s LNG capacity. There is concern design and construction work that could otherwise go to in-state companies and Alaskans might be offered to Sinopec, one of the world’s largest oil and gas companies, instead. As Giessel said she understands it, if legislators were to give AGDC unlimited receipt authority the only control they would have over the corporation and the project — short of disbanding AGDC — would be in approving the Department of Natural Resources to take the state’s royalty share of North Slope natural gas “in-kind.” “The rest of the authority, the approvals, that were in SB 138 (passed in 2014) really went by the wayside when the state took over,” she said. Elwood Brehmer can be reached at [email protected]

Southcentral community leaders want in on AKLNG site selection studies

Nearly five years after Nikiski was chosen as the terminus for the $43 billion Alaska LNG Project, the leaders of other Southcentral communities are now questioning the process behind that decision. On Jan. 9, the Matanuska-Susitna Borough sought intervener status in the Federal Energy Regulatory Commission’s drafting of an environmental impact statement, or EIS, for the Alaska LNG Project. The state-owned Alaska Gasline Development Corp., which is leading the project, did not object to the borough’s intervener petition even though it came well after the formal May 2017 deadline for intervener petitions on the EIS. FERC granted the borough request Feb. 27. Mat-Su officials contended to the regulatory agency that not only were years of requests to have the borough-owned Port MacKenzie considered as an alternative to Nikiski humored and then dismissed, but a location fictitiously dubbed “Point MacKenzie” was instead evaluated and ruled out. Mat-Su Borough Internal Auditor James Wilson, tasked by Manager John Moosey to be the borough’s point-person on the project, said in an interview that he came across a photograph last fall when reviewing documents AGDC submitted to FERC that revealed the discrepancy in locations. Wilson said that AGDC President Keith Meyer met with borough officials shortly after he was hired in spring 2016 and told them that the state corporation would evaluate the port and resolve the borough’s concerns. ExxonMobil — part of a consortium including BP, ConocoPhillips, pipeline company TransCanada and the State of Alaska — led the project from its informal inception in 2012 until AGDC took over management early in 2017. Mat-Su officials were told for several years that project managers were using “Point” and “Port” MacKenzie interchangeably and the actual port would be given a fair shake, according to Wilson. He detailed what he found in a Dec. 29 letter to FERC’s Dispute Resolution Service. “To MSB’s astonishment and surprise, the aerial photograph showed that ‘Port’ MacKenzie was NOT ‘Point’ MacKenzie. This photograph completely contradicted what MSB had been told for several years that Port MacKenzie was included in the FERC Alternative Analysis,” Wilson wrote to the federal agency. “This revelation leads to the decision by MSB to make a formal request to include ‘Port MacKenzie’ in the Screening and Feasibility Analyses.” AGDC leaders and others that have closely followed the project note the map Wilson saw and the associated site evaluation information has long been publicly available. However, it is part of 13 voluminous Resource Reports and other documents — roughly 60,000 pages of environmental, engineering and socio-economic data — gathered over several years by the ExxonMobil-led Alaska LNG team and submitted to FERC for the 800-mile long project. The project team studied more than 20 sites across Cook Inlet, Resurrection Bay and Prince William Sound. Mistaken identity Borough Manager Moosey said the map in Resource Report 10 confirmed what he and others at the borough had been worried about since Nikiski was selected in 2013. “Every time (AK LNG managers) came back they came back with information that just didn’t jive with the details of our port. At practically every turn they said, ‘We’ll look at it’; We’ll make adjustments’ or ‘We have experts on this who really understand this so there’s some things you just don’t know,’” Moosey said in an interview. 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. Borough leaders have long touted the naturally 60-foot deep water at the end of the 500-foot Port MacKenzie dock trestle as a major selling point for the port they hope can be an industrial center. Additionally, the borough owns 8,940 acres of adjacent uplands. The Alaska LNG Project plant will need roughly 800 acres for facilities that would produce 20 million tons per year. The geographical feature more commonly known as Point MacKenzie is about another three miles south of the port, or six miles from the “Point MacKenzie” evaluated for the Alaska LNG Project. “After we had these conversations (with project managers) and then we see the documents it was like ‘You got to be kidding me,’” Moosey said. “At least that was my attitude. We’ve asked for this stuff to be corrected in their reports for seven years. If they would’ve taken any time along the way I don’t think we’d be where we are right now.” Interestingly, the maps submitted to FERC as official documents detailing potential LNG plant sites near Anchor Point and on Kalgin Island in west Cook Inlet site the plant in a state game refuge and critical habitat area, respectively. FERC assigns work On Feb. 15, FERC and cooperating federal agency officials asked AGDC to respond to 570 questions or data requests; that was after the state corporation announced Jan. 22 it had finished answering the first round of 801 questions. Among the February queries were directives to do environmental and engineering analyses for locating the plant at Port MacKenzie and Valdez. The two are likely alternatives to be evaluated in the environmental impact statement FERC is drafting but at this point there is little reason to believe the pipeline will end somewhere other than Nikiski if it is approved. FERC issued a schedule for the project March 12 indicating the agency expects to have the draft EIS out for public comment in about a year, with the final document published in December 2019. AGDC has advocated having the final EIS done this year to stay on the fastest-possible construction schedule. Meyer, who took over at AGDC after the data gathering was largely complete, said in an interview the corporation would evaluate Port MacKenzie as requested by FERC, but added the Mat-Su port is not an ideal place for large-scale LNG operations, in part because of its proximity to the Port of Anchorage and its designation as a multi-use facility in the borough’s master plan. “You can’t really put an LNG terminal in the middle of a multi-use port,” Meyer said. “No one will argue that you can’t build an LNG terminal in Nikiski.” The Mat-Su Borough was working to develop Port MacKenzie into an industrial district back in 2012 and 2013 when the Alaska LNG Project team was evaluating LNG sites. The port was also a site of interest to other, smaller LNG projects such as an export effort proposed by Japanese consortium Resources Energy Inc. that was courted by borough officials. At the same time, the state’s budget deficit led to slashed capital spending and funding stopped flowing for the half-finished Port MacKenzie rail spur intended to spark further development. Today, the port remains mostly quiet. AGDC regulatory Vice President Frank Richards noted being farther north in Cook Inlet would add miles to tanker trips and the area is also listed as critical habitat for the Inlet’s endangered population of Beluga whales, who feed on the salmon and herring that return to the area’s many large rivers. Wilson, of the borough, said space and 10,000 feet of shoreline could be dedicated to the plant. “We’re still open for business but the bottom line is the area is 1,000 acres along what we call the waterfront dependent area — that acreage is 100 percent exclusive Alaska LNG,” he said. As for the “point” versus “port” confusion, ExxonMobil’s Steve Butt, who led the project until 2017, would not provide any information beyond what was in the public filings, according to Wilson and Moosey. Likewise, AGDC was only working on a portion of the LNG plant at the time, when the producers and TransCanada owned a majority of the project, and there was what Richards referred to as a “Chinese firewall” between the project groups. He said specific questions beyond what can be answered by the Resource Reports should be directed to the producers. Former Gov. Sean Parnell, whose administration created the original Alaska LNG framework in parallel with reaching a settlement of the Point Thomson lawsuit on the North Slope, wrote in an email similarly that the state approved Nikiski after receiving a briefing from the producers’ team, which drove the site selection work. Representatives for BP and ConocoPhillips said there were no individuals in the Alaska offices with that knowledge given the time that has passed and suggested contacting AGDC. ExxonMobil did not respond to a request to speak with Butt. Butt said in 2013 that Nikiski was chosen largely for its terrain and the ability to provide natural gas to the state’s four largest population centers along the pipeline route. Former Federal Alaska Gas Pipeline coordinator and Kenai Peninsula Borough oil and gas advisor Larry Persily — often a critic of the state-led LNG effort — mostly concurred with Meyer and Richards on Nikiski versus Port MacKenzie. “You cannot use a public dock for fuel tankers; for security purposes that’s not going to work,” Persily said. He added that Nikiski is already a heavily industrial area with the smaller legacy ConocoPhillips LNG plant nearby that was recently purchased by Andeavor (formerly Tesoro). The town is also in a flat area with acceptable geotechnical characteristics and by Alaska standards is close to a suitable workforce and easily accessible by road, Persily noted. At the same time, he said it would not be unreasonable to expect the state to have information on why the wrong site was evaluated in the Mat-Su Borough. “You’d like to think that as a 25 percent partner you’d have paid attention to that decision,” Persily said. The producers have also purchased about three-fourths of the roughly 800 acres the plant is expected to span and the state Department of Transportation is drafting a plan to reroute the Kenai Spur Highway, which currently bisects the property. Next steps Meyer said March 8 that a resolution to drawn-out negotiations with the producers over acquiring access to that acreage in Nikiski was “imminent.” AGDC — with an uncertain funding future from the Legislature and expected to have only about $42 million in cash on hand by July 1 — would not purchase the land immediately but rather would get an option to acquire it at the appropriate time in the future. Frustrations aside, Moosey and Wilson said the project’s success is their number one priority; they just want correct the misinformation they believe did not follow the National Environmental Policy Act process and prevented the borough from getting a fair shake. “We think a lot of our port but this project is so important to the state that if it pencils out it’s got to go, regardless,” Moosey said. “The last thing we want to do is, if it doesn’t come to us, is to kick and scream and cause problems.” He pitched Port MacKenzie as a staging and assembly area for the project if it is not built there. Richards said Mat-Su officials have offered the extensive data set the borough has acquired on the port’s geophysical characteristics — down to borehole samples — which should expedite the site review FERC is requesting and hopefully prevent delaying the EIS. AGDC asked for a public meeting to discuss the specifics of what FERC wants in its latest round of questions. The meeting is on March 22, in Washington, D.C., at 5 a.m. Alaska time. For example, Richards said he hopes to find out if a GIS-based analysis for Valdez-route options around the Scenic and Wild River-designated sections of the Delta and Gulkana rivers will suffice, or if a more costly and time-consuming survey must be done. Even if the Mat-Su Borough makes a New England Patriots-esque comeback and Port MacKenzie is ultimately chosen by FERC as the Alaska LNG endpoint, it would not be an insurmountable challenge to reroute the project because the smaller, in-state Alaska Standalone Pipeline, or ASAP, project is planned to end 12 miles from the port, according to Richards. Being able to use almost the entire ASAP route should preclude another major round of data collection. The long-awaited ASAP final supplemental EIS is expected from the U.S. Army Corps of Engineers soon. While AGDC did not object to the Mat-Su Borough intervening late because the borough is a major landowner along the Alaska LNG Project, the Kenai Peninsula Borough did. Mayor Charlie Pierce wrote to FERC Jan. 29 that Kenai Borough officials could find nothing in the docket until the Jan. 9 intervener motion to support Port MacKenzie as the LNG plant site. “Although we do not doubt that the Matanuska-Susitna Borough believed Port MacKenzie would receive further review, the lack of any earlier comment in the docket is a reminder to all of us the value of participating in the public record of the NEPA process,” Pierce wrote. Aside from the obvious economic benefits getting the LNG plant would offer the surrounding communities, it could also be a boon for local tax rolls. The plant and associated marine terminal account for nearly half of the cost of the estimated $43 billion project and Meyer has said repeatedly AGDC would allocate $450 million per year for payments in-lieu of property taxes to the local governments the project crosses. Exactly how the PILT money would be divvied up amongst the cities and boroughs along the Alaska LNG route has not been settled. Valdez chimes in For their part, local government officials in Valdez don’t want FERC to forget about their town, either. Valdez Mayor Ruth Knight sent a letter to FERC March 13 urging the commission to deny AGDC’s request to allow it to apply methods for wetlands assessment, mitigation and constructing the 36-inch ASAP line to the 42-inch Alaska LNG pipeline. The ASAP project is generally seen as a backup plan if the large export project does not pan out, as it would provide a long-term supply of North Slope natural gas for in-state users. At 733 miles long, the ASAP line would be shorter than the Alaska LNG pipeline because it would tie into the existing Beluga gas pipeline near Point MacKenzie and not go all the way south to Nikiski. It would also be substantially cheaper without the need for the large LNG plant to convert the gas into a shippable liquid; cost estimates for the first, 24-inch iteration of ASAP done in 2012 were up to roughly $10 billion. However, whether or not there would be enough demand for gas to make ASAP economically feasible is uncertain. While the current plans for ASAP and Alaska LNG follow the same corridor across most of Alaska, they would diverge in the upper Susitna Valley where ASAP would cross the river and continue south along the Parks Highway on the east side of the river and Alaska LNG is planned to parallel the Susitna to the west. Knight noted, among other issues, the 130 miles of differing route, the need for a wider Alaska LNG right-of-way and ASAP’s lack of compressor stations, which are needed to transport the roughly six times more gas the Alaska LNG line would carry. “These and other differences in pipeline design will result in the AK LNG Project impacting 68,290.94 acres during construction and the ASAP Project impacting 21,237 acres during construction,” Knight wrote. She continued to contend that AGDC has not provided any evidence that the different pipelines will have similar impacts to wetlands. AGDC has urged FERC to apply the wetlands requirements the Corps of Engineers deems necessary for ASAP to the Alaska LNG Project because the Corps is drafting the ASAP supplemental EIS and is the lead federal agency for issuing wetlands fill permits under the Clean Water Act. The Corps also has well-established policies for mitigating construction impacts to wetlands. Richards said the Corps has determined it has jurisdiction over roughly half of the ASAP corridor due to the existence of wetlands in those areas but to what degree the Corps will require construction mitigation in those areas is unclear. Knight said in an interview that city officials are very happy FERC directed AGDC to study the Valdez option more thoroughly. The Alaska Gasline Port Authority, once managed by Gov. Bill Walker, first petitioned FERC to consider Valdez for Alaska LNG in February 2017. AGPA is a longstanding municipal port authority formed by the City of Valdez and the Fairbanks North Star Borough to promote an export project for North Slope natural gas. Following the Trans-Alaska Pipeline System, or TAPS, corridor from the North Slope to Valdez would be the most economical and least environmentally damaging gasline alternative because of the existing pipeline development, according to Knight. “The ASAP corridor is like apples and oranges so throwing the ASAP corridor in there sort of muddies the waters,” she said. “(FERC) needs to look at the line as the state has filed it and keep the ASAP corridor out of the mix.” She added that AGDC has touted the environmental benefits of following the TAPS corridor until the two split under current plans near Livengood north of Fairbanks. 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, much of which is above ground, and a gasline that would be completely buried. Whether there is nearly 1,000 acres of mostly undeveloped, flat land suitable for an LNG plant near Valdez is another question that has been raised. “We want what’s most economical for the state. I don’t want to make it the political choice,” Knight said. Elwood Brehmer can be reached at [email protected]

Oil legislation could come off the back burner in a budget deal

Bills to raise oil taxes and pay off the state’s $800 million refundable tax credit obligation have stalled for weeks but legislators say both could be part of what is sure to be a strenuous lift at the end of a session in which the festering $2.5 billion annual deficits are coming to a head. House Resources Committee co-chair Rep. Andy Josephson, D-Anchorage, said during a Majority Coalition press briefing that House Bill 288, which would raise the minimum production tax, could be part of a package of legislation to settle end-of-session negotiations with the Republican Senate. Josephson held several hearings on HB 288 early in the session and took unfavorable industry testimony over raising taxes, but it hasn’t been addressed formally since Jan. 29. Sponsored by Resources co-chair Rep. Geran Tarr, D-Anchorage, it would raise the gross minimum production tax rate from 4 percent to 7 percent and generate up to about $250 million in additional revenue at current prices, according to the Revenue Department. Tarr and others in the Democrat-led Majority have said they felt the need to propose an oil tax increase as some sort of additional revenue measure after the Senate wholly rejected income and payroll taxes last year. Revenue officials said the bill becomes revenue-neutral at a price of about $72 per barrel, which is when the state’s net profits tax rate takes effect. Government take of Alaska’s oil is at its lowest level in state history at roughly 54 percent, according to Finance co-chair Rep. Paul Seaton, R-Homer. Josephson suggested the bill could have a tiered gross tax as well to make it more palatable to Republicans averse to another oil tax change. Industry representatives said the tax increase would come at a time when many companies have just righted their balance sheets after the $26 per barrel bottom of the oil market in 2016 and are ready to start growing again with more stable prices. Tax credit bonds Senate Resources chair Cathy Giessel, R-Anchorage, said in an interview that there is a fair chance that Gov. Bill Walker’s plan to pay off the $800 million-plus refundable tax credit debt could move out of her committee by the end of March. Senate Bill 176 would have the Revenue Department sell 10-year, subject-to-appropriation bonds in two tranches to pay off the outstanding tax credit certificates expected to total $900 million when the last credits sunset in a couple years. The debt has accumulated since 2015 when Walker made the first of two vetoes totaling $630 million for the tax credits, and the 2017 and 2018 fiscal year budgets passed by the Legislature have contained only the statutory minimum payments. Prior to Walker’s veto in the early throes of the current budget crisis, the credits had been paid in full every year since 2006. The Legislature has since ended both the Cook Inlet and North Slope credit programs. The generally small companies owed the money — and some bigger ones such as Repsol that have no production — would need to agree to take a haircut on the tax credits of up to 10 percent on the full amount they’re owed in order to get the vast majority of the money immediately. The administration hopes the plan could jumpstart industry spending in the state again as banks that lent on the credits as collateral — expecting they would be paid in full each year — now have nonproducing loans and have stopped lending to oil companies in the state. Numerous companies such as Caelus Energy, Blue Crest and Furie Operating Alaska have cited unpaid tax credits as a reason for delaying previously announced work. It would also clear the state’s books of the obligation without costing the state additional money, Revenue Commissioner Sheldon Fisher emphasizes, because the state’s expected cost to borrow the money is in the 5 percent range and credit holders would need to accept a discount rate. That discount could be lowered to 5 percent if companies commit to reinvesting the money in the state or agree to make seismic data public sooner. Republicans have generally indicated at least modest support for the bill, but some on the Resources Committee suggested the state should cut the bond terms and pay the debt off quicker. Giessel indicated the bill could come up again after amendments are drafted to that effect. Democrat Sen. Bill Wielechowski of Anchorage questioned whether or not the bill fits within the constitutional limits of the state’s ability to bond as a means to pay off other debt. House Democrats are mixed on the idea but there is a belief it could gain traction if SB 176 makes it over from the Senate. It is scheduled for Senate Finance after the Resources Committee. Elwood Brehmer can be reached at [email protected]

Revenue forecast up on oil prices, but production short of forecast

Income will be up but oil production will be down, according to the state’s Spring Revenue Forecast released March 16. Department of Revenue officials project the State of Alaska will take in roughly $2.3 billion in unrestricted General Fund revenue during the current 2018 and 2019 fiscal years, which would be an increase of $256 million and $212 million per year, respectively, from the financial forecast issued last fall. A new state fiscal year starts each July 1. The Revenue Department issues a comprehensive analysis and projection of the state’s financials each December and, for budgeting purposes, updates the forecast with revised projections during the legislative session. The department is anticipating unrestricted revenue to increase by between $124 million and $213 million from 2020 to 2026 from the Fall 2017 forecast as well. “Expected revenue has increased $125 million to $250 million per year across the forecast period,” Revenue Commissioner Sheldon Fisher said in a statement accompanying the forecast release. “This is good news for all Alaskans. Unfortunately, even after this additional revenue Alaska continues to face a budget deficit in excess of $2.3 billion. The (Walker) administration will continue to work with the Legislature to address the fiscal gap during the legislative session.” Realized earnings from the Permanent Fund — likely to support government services starting with the fiscal 2019 budget currently being debated in the Legislature — are expected to be $4.4 billion in 2018 and nearly $4 billion in 2019. The Fund’s performance is highly dependent on how domestic and international stock markets fare. Higher than anticipated oil prices are behind the unrestricted revenue bump. Petroleum-derived revenue from taxes and royalties usually accounts for between 75 percent to 90 percent of the state’s unrestricted General Fund revenue in most years. Last fall, the Revenue Department estimated Alaska North Slope crude would average a price of $56 per barrel during fiscal 2018, but as of March 14 North Slope oil was averaging exactly $60 per barrel for the year, which is 7.1 percent above the fall forecast price. Daily prices have hovered between $64 and $66 per barrel in March. The revised forecast projects a final average ANS price of $61 per barrel when the 2018 fiscal year ends June 30. Alaska oil sold for $49.43 per barrel in 2017. For 2019, the price estimate was increased to $63 per barrel from $57 per barrel. The forecast for North Slope oil production, however, is not as positive. Department of Natural Resources officials, who oversee the production projections, estimate North Slope production will fall from an average of 526,500 barrels per day in 2017 to 521,800 barrels per day in 2018 but rebound to average 526,600 barrels per day in 2019. North Slope production has averaged 518,517 barrels per day so far in fiscal 2018, which is 2.8 percent below the fall estimate of 533,400 barrels per day. Had that forecast come true, it would have been a third straight year of production increases. Fisher said in a March 19 Senate Finance Committee detailing the revised forecast that an unusually warm North Slope winter has curbed production efficiency and is largely to blame for the production drop this winter. North Slope temperatures have been about 14 degrees above the long-term average this winter. Deputy DNR Commissioner Mark Wiggin noted in an interview that Slope oil production is still tracking very close to the Fall 2017 forecast even though the daily numbers are not as high as hoped. “It’s within the margin of error,” Wiggin said of fiscal 2018 production numbers. He also explained that the production facilities on the Slope are designed run most efficiently at very cold winter temperatures. The natural gas compressors that help reinject gas at many wells to enhance oil production are not as effective at warmer ambient temperatures — which is the primary reason for less summer production each year — and can lead producing companies to focus on extracting oil from wells that have a lower gas-to-oil ratio when things warm up, according to Wiggin. Longer term, North Slope production is expected to grow to a peak of 536,100 barrels per day in 2020 and gradually decline from there, before stabilizing at about 494,000 barrels per day from 2024-27. ConocoPhillips’ Greater Mooses Tooth-1 oil development in the National Petroleum Reserve-Alaska is expected to come online late this year with about 30,000 barrels per day at its peak and provide a production boost, as is Brooks Range Petroleum’s Mustang project near Kuparuk, which could provide more than 10,000 barrels per day of new oil. Oil prices over the period are forecasted to gradually climb to $75 per barrel by 2027. With that in mind, Fisher noted in a cover letter to Gov. Bill Walker with the forecast that the price increase over the next decade would still have Alaska oil in the low $60 per barrel range in today’s terms as inflation will likely degrade the real value. Fisher also acknowledged, “predicting future prices is inherently uncertain.” Republican legislators have cited the improved oil price and production prices as proof the state does not need to implement a broad-based tax to resolve the deficit, but instead can rely on reduced spending and drawing from the Earnings Reserve of the Permanent Fund to balance the state budget within a few years. Walker and the Democrat-led House Majority Coalition insist a tax is needed to balance the budget sooner and provide revenue stability in the event oil prices — which Fisher acknowledged projecting is “inherently uncertain” in his letter to the governor — and production do not meet expectations. The state’s remaining savings will almost assuredly fall below $2 billion at the end of the current fiscal year regardless of what revenue and budget-cutting measures are adopted this session. ^ Elwood Brehmer can be reached at [email protected]

As habitat initiative debate swirls, ADFG outlines current best practices

The Alaska Supreme Court will still have its say, but there’s a good chance voters will be asked whether or not the state should overhaul its permitting regime for construction projects impacting salmon habitat. It’s the latest battle in the ongoing debate over how far the state should go to protect its prized fish resources while at the same time promoting development of the state’s renowned petroleum and mineral resources. The sponsors of the Stand for Salmon ballot initiative — Alaskans with commercial, sport and subsistence fishing interests — contend Title 16, the state statute for permitting projects in fish and wildlife habitat that has not been updated since statehood, needs serious strengthening to continue protecting anadromous fish as the state continues to grow. They argue the ambiguous wording of the law, which directs the commissioner of Fish and Game to approve projects that provide for the “proper protection of fish and game,” is too open for interpretation by political appointees who could be swayed to overlook stringent construction requirements for potentially profitable developments. Opponents of the initiative — led by trade groups for the state’s oil and gas and mining industries and Alaska Native corporations with huge land holdings that are also heavily involved in those industries — point to Alaska’s generally prosperous salmon runs as proof the significant changes to Title 16 the initiative would institute are unnecessary and would debilitate an economy dependent on resource development. They have formed their own campaign group, Stand for Alaska. The Supreme Court will hear arguments in April over whether the initiative is unconstitutional after conflicting opinions have been handed down from the Alaska Department of Law and Superior Court. The sponsors, who collected enough signatures to place it on this November’s general election ballot, retort that to date Alaska has for the most part been “lucky” that large developments have occurred outside of major salmon fisheries so the inadequacies in Title 16 haven’t been exposed. Gov. Bill Walker is among the opponents of the Stand for Salmon initiative. He insists such fundamental law changes should be left to the legislative process so the statute can be crafted with input from all impacted parties. The initiative would apply to all waters that support anadromous fish — those species that migrate freely between fresh and salt water — that, in addition to salmon, include everything from steelhead to smelt and lampreys. However, salmon are king in Alaska and therefore dominate the discussion. It should be noted that the Stand for Salmon sponsors did not stir this political hornets’ nest on their own. In January 2017 the Board of Fisheries wrote a letter to legislative leaders requesting revisions to Title 16. The seven-member board is comprised of individuals first appointed by pro-development Govs. Frank Murkowski, Sean Parnell and Walker. “Additional guidance is warranted for the protection of fish, to set clear expectations for permit applicants and to reduce uncertainty in predevelopment planning costs,” the letter states. “To strengthen ADF&G’s implementation and enforcement of the permitting program, the legislature may want to consider creating enforceable standards in statute to protect fish habitat, and to guide and create a more certain permitting system.” Kodiak Rep. Louise Stutes, who chairs the House Fisheries Committee, is currently working on a new draft to House Bill 199, which she submitted last year and originally mirrored the initiative. She decided to rework HB 199 after hearing testimony from supporters, detractors and regulatory agencies involved in development projects. What’s in it? Specifically, the eight-page initiative would start by setting up a two-tiered permitting regime for projects in salmon habitat. “Minor” habitat permit applications could be issued quickly and generally for projects deemed to have an insignificant impact on salmon waters. “Major” permits for larger projects such as mines, dams and anything determined to potentially have a significant impact on salmon-bearing waters would require the project sponsor to prove the project would not damage salmon habitat. Supporters assert upwards of three-quarters of the habitat development permit applications Fish and Game currently adjudicates would fall in the minor category and what exactly constitutes unacceptable or “significant adverse affects” on anadromous fish habitat would still be up to the Legislature and Fish and Game commissioners to determine. Additionally, the project sponsor would have to prove that impacted waters are not salmon habitat during any stage of the fish life cycle if the waters are connected to proven salmon habitat in any way but not yet listed in the state’s Anadromous Waters Catalog. Among other changes, it would also limit mitigation of habitat impacts by major projects to the impacted watershed, thereby eliminating offsite compensatory mitigation to other anadromous waters, and require sufficient fish passage be maintained throughout the life of the project. Finally, it would provide for public comment periods on major project permits, a provision the Board of Fisheries advocated for in its letter that is not part of the current permitting process. What’s the standard now? So, other than lacking public participation, which initiative opponents note is usually available through other permits developments need, what does the current anadromous waters permitting process consist of? That’s the question Ron Benkert with the Department of Fish and Game attempted to answer for the Journal during an hour-long interview. A fisheries biologist by trade, Benkert has been with the Habitat Division for 10 years after many years of salmonid experience through various research positions in the Pacific Northwest and California. In discussing what it takes to design, dig and develop in salmon habitat in Alaska, Benkert likes to start with what goes into the seemingly simple task of installing culverts in small salmon streams, which he refers to as one of the “bread and butter” projects the department oversees. “It’s one of the things we do an awful lot of because we have assessed a lot of the culverts in the state and obviously DOT and the boroughs and other entities have all got a lot of bad culverts out there,” he said. “We all recognize the problem out there and I think DOT and the boroughs are really stringently trying to correct those as funding becomes available.” The problem often lies in what work originally went into culverts set in road and rail beds decades ago — but under the same Title 16 — before rigorous design standards were applied that allow for fish passage. If not in the original installation, the issue is likely because of erosion or a changing stream channel that has made a once-suitable culvert impassable. ADFG has a catalog of “bad pipes,” as Benkert calls them, which officials reference each time there is roadwork scheduled, he said. “Every time DOT conducts some kind of maintenance or road construction DOT has been very responsive, as well as the boroughs, at recognizing that (a culvert) needs to be fixed as part of the project,” Benkert said. Installing a fish-friendly pipe is more than burying a culvert big enough for a few chinook salmon to squeeze through. In 2001, the departments of Transportation and Fish and Game signed a memorandum of agreement, or MOA, detailing how the former will ensure the culverts it puts in its roads are compatible with the species in a given stream. The 33-page document delves into the particulars of how to design a culvert to simulate stream water flow conditions as well as the sustained and burst swimming performance at varying water temperatures of 15 fish species common to Alaska. ADFG has enforcement authority over DOT projects despite the two being equal state agencies. Benkert said he considers the agreement to be a prime example of how Fish and Game works with project proponents to achieve specific but important characteristics of a project under the broad “proper protection” mandate. And while a culvert replacement isn’t the kind of project that garners headlines, the cumulative effects of restoring the ability of fish to move through small, seemingly insignificant braids of water can’t be overstated, according to Benkert. “Connectivity is huge,” he stressed. “You reconnect fish to habitats they haven’t been able to access; especially up in the headwater areas that are big rearing areas (for juvenile salmon). You’re just really expanding fish habitat or at least reestablishing fish habitat that was available to them before urbanization occurred.” At the same time, habitat regulators must be pragmatic and evaluate the practicability of improving fish passage. Benkert said in some instances — for example when the upstream portion viable fish habitat is particularly small, as can be the case where roads parallel mountainsides — the department won’t apply the MOA standards if the added costs are into the millions of dollars to restore access to a couple hundred feet or less of stream. “We like to put our money where it’s going to get the best bang for the buck,” he added. Large projects On larger projects things can get increasingly more complex. That’s where the department’s habitat impact mitigation sequence of avoid, minimize, rectify and reduce or, as a last line of defense, compensatory mitigation comes into play. It’s also why project plans rarely look the same after applying for an anadromous fish habitat permit. “That’s our first line of defense, if you will, as far as negotiating with an applicant. How can we change the project footprint or how you’re operating so that you’re not even having an issue with an anadromous water body,” Benkert said. In Feb. 15 testimony before the House Fisheries Committee, he said the department rarely denies a habitat application because proponents usually withdraw them first if it becomes clear that the project won’t be able to meet the department’s thresholds. “We have mid-sized placer miners that want to relocate anadromous streams all the time and I’ve still to this day not had one come in with a plan that’s good enough for us to permit,” Benkert said. “They usually withdraw their application because of that high bar.” Such small business miners simply don’t have the financial wherewithal or the “quiver of biologists and bioengineers” needed to succeed in that type of work, he added. However, on the largest projects such as major mines, dams or oil developments, significant restoration or mitigation can become viable. Real world examples Habitat Division Operations Manager Alvin Ott wrote in a Sept. 27 Superior Court affidavit for Stand for Salmon’s appeal of Lt. Gov. Byron Mallott’s rejection of the initiative that Donlin Gold — in the upper Kuskokwim River drainage — is proposing to destroy two anadromous streams, American and Anaconda creeks, to build the tailings dam and impoundment for its proposed gold mine. In exchange, the company would offset the loss of that habitat by restoring coho salmon rearing habitat damaged by historic placer mining activity in the nearby Crooked Creek watershed, according to Ott. He wrote further that he believes such offsite compensatory mitigation would not be permitted under the initiative language. Benkert acknowledged that constructing or restoring anadromous fish habitat is a tremendous undertaking that’s as much an “art form” as it is science. “It doesn’t matter how good the design looks, if you’ve got an operator that’s saying ‘that’s good enough;’ it’s a very precise thing. You’re talking (bank) elevations within tenths of an inch; making sure everything’s just right so when a big storm hits it doesn’t just unravel,” Benkert said. “It’s a very rigorous process if we’re going to try to replace some kind of anadromous habitat with something that’s artificially created that’s supposed to be able to maintain itself into perpetuity.” As a result, Fish and Game rarely agrees to a 1-1 tradeoff during mitigation negotiations; project proponents are expected to replace more than is damaged, according to Benkert. However, he was enthusiastic to discuss the artificial wetlands complex built similarly from what was placer mine waste below the tailings dam to the Fort Knox gold mine near Fairbanks. It’s not an anadromous system, Benkert conceded, but the department has been monitoring it for nearly 15 years and has many positives to report. “It went from a place that was fairly low density population of fish and wildlife because it was just trashed landscape,” he said. “Now we have huge numbers of grayling and burbot in that system; all kinds of wildlife that’s associated with that habitat.” He noted there are ospreys nesting in the area because there are enough fish — ospreys’ almost exclusive prey — in the system to support them. Whether a simple culvert replacement or a total rebuild to a former salmon stream, Fish and Game relies on best practices learned in Alaska or elsewhere and a lot of professional judgment to determine what activities will be permitted and what mitigation will be deemed sufficient, he said. It’s for that reason that the department has no regulations to accompany the Title 16 statute; the best way to do things is in constant evolution. Benkert said Fish and Game codifies in its own way what is “proper protection” through the information department officials rely on to make decisions. “There’s not a list of things in regulation that says you have to do this, this, this and this but we’ve got all kinds of guidance documents, technical reports, working guidelines and then we go to the literature, too,” he explained. “We always look to see what’s happening in the Pacific Northwest because there’s a lot of new technology out there and it keeps changing.” The 2001 agreement with DOT, for example, specifies culverts should be 0.9 bank full widths of the stream channel in diameter. Benkert described the rule as “old school now,” noting the latest recommendations out of Washington and Oregon call for culverts equal to 1.2 bank widths plus two feet, which DOT has agreed to abide by. Beyond advancing technical standards for development projects, the Habitat Division has expanded the areas it classifies as anadromous waters in the state’s catalog to wetlands in recent years as well. Wetlands, now understood to often be critical juvenile salmon habitat, can be afforded the same protections as well-known rivers under the Anadromous Fish Act if Fish and Game confirms a wetlands area to be anadromous fish habitat. The entire Colville River delta on the North Slope, which includes ConocoPhillips’ Alpine oil field and the large Nanushuk oil project that is in permitting, is officially anadromous territory, according to the state. Though the Department of Fish and Game has considerable leeway in how far it can go to demand fish protections, Benkert noted the state is obligated to accept all factors and utilize, develop and conserve “all natural resources belonging to the state, including land and waters, for the maximum benefit of its people.” “The wrinkle we always have to remember here is our constitutional mandate. It doesn’t say you’re just going to protect fish; you need to protect fish but consider the economic welfare and development of the state, too. Our mandate here is specific. We are supposed to figure out how to allow development in the stat with minimal or avoiding impacts to the fish. That’s something we need to consider all the time,” he continued. “We can’t just say no because the fish may have the potential of being impacted by it; that’s why we have this whole process. That’s the tricky part. The fish come first at the end of the day but we try really hard to get the project to the point where it can be environmentally acceptable.” It all comes back to differing views as to what’s acceptable. Elwood Brehmer can be reached at [email protected]

Interior leaders talk progress on priorities after year under Trump

Interior Secretary Ryan Zinke introduced himself and his department’s priorities to Alaskans in person last May when he said the state is a lynchpin to achieving American energy dominance. Deputy Interior Secretary Dave Bernhardt and Assistant Secretary Joe Balash, a former Alaska Natural Resources commissioner, were back in Anchorage March 8 to report on the progress of Interior’s work during the first year of the Trump administration. “We had a very, very productive year if you compare our policy development to prior administrations,” Bernhardt told the biweekly breakfast gathering of Alaska Support Industry Alliance members. A key piece of that policy has been issuing executive orders and working with Congress through the Congressional Review Act to rescind orders and rules issued under the Obama administration, which Bernhardt referred to as a “wide-ranging deregulatory agenda.” He estimated the administration was able to cut about half of the regulations it wants to in its first year. “I think you can capsulate our regulatory vision in a couple of sentences,” he said. “We’re not willing to sacrifice health, safety or the environmental standards but we are committed to being a good neighbor, respecting the role of other governments and being passionate about ensuring people have access to our public lands.” Bernhardt served in the Interior Department during the George W. Bush administration as the Interior solicitor in charge of the U.S.-Canada International Boundary Commission, among other roles. The Interior leaders were in Alaska in part for meetings on the Bureau of Ocean Energy Management’s push to revise the 2019-24 Outer Continental Shelf Lease Sale Program and prepare for onshore lease sales of the coastal plain of the Arctic National Wildlife Refuge. The draft OCS lease sale plan would reopen many areas nationwide that were previously closed to oil and gas leasing by Obama, including the Beaufort and Chukchi seas. “We have an opportunity as Alaskans to get a lot done and see a lot done,” said Balash, who oversees the bureaus of Land Management, Ocean Energy Management, Safety and Environmental Enforcement and the Office of Surface Mining. “Every day I get to work on something related to Alaska.” Bernhardt said Balash’s work will likely continue to be Alaska-centric as the Bureau of Land Management should be publishing a Notice of Intent to initiate the environmental impact statement process for ANWR lease sales within several weeks. A component of the tax cut bill passed by Congress in December mandates the Interior Department to hold two oil and gas lease sales with at least 400,000 available acres for the 1.5 million-acre ANWR coastal plain within the next decade. And while the U.S. Fish and Wildlife Service typically manages refuge activity, the rider also directs the lease sales to be managed similarly to the National Petroleum Reserve-Alaska, which means BLM, under Balash, is the lead agency. When asked how long the ANWR leasing environmental review will take, Bernhardt noted that he sent out a memo to Interior agencies stressing that he expects environmental impacts statements done in a year. “We’re starting this process very, very soon and I take my memos very, very seriously,” he said. Balash said he is also working to increase the acreage available to industry in the NPR-A to the west of Prudhoe Bay. The U.S. Geological Survey in late December updated its assessment of the recoverable oil in the NPR-A to a mean estimate of 8.8 billion barrels in the 23 million-acre reserve and adjacent state lands. The new assessment was directed by Zinke during his May trip to Alaska and is largely based on recent oil discoveries in the area sourced from the Nanushuk and Torok geologic formations by Armstrong Energy, Caelus Energy and ConocoPhillips. A 2010 assessment of the NPR-A pegged the mean oil estimate at just 896 million recoverable barrels. The BLM offered all 900 lease tracts covering 10.3 million acres in its fall 2017 NPR-A lease sale, but bidding was subdued other than ConocoPhillips purchasing acreage around its declared discoveries. The management plan for the NPR-A, finalized in 2013, removed many of the most prospective oil and gas areas in the northeast corner of the reserve from leasing in order to protect the Teshepuk Lake caribou herd and other subsistence resources in the area. Balash acknowledged that expanding the leasable acreage in the NPR-A is “something that’s going to require a lot of care and consultation with the North Slope Borough.” However, he mentioned to ConocoPhillips Alaska leaders in the audience that he has a copy of the draft supplemental EIS for the company’s Greater Mooses Tooth-2 development, indicating it should be out for public review soon. GMT-2 is a roughly $1 billion oil project the company expects will have peak production upwards of 30,000 barrels per day. GMT-1 is currently under construction and expected to start production next year, also at about 30,000 barrels per day at peak. In January 2017 ConocoPhillips executives said the EIS, being evaluated by the BLM, was moving slower than expected. A spokeswoman for the agency said then that a record of decision for GMT-2 was expected in early 2018, which would have made for an EIS process of about two-and-a-half years. On the broader issue of what is at times an arduously slow EIS process when managed by Interior agencies, Bernhardt said he has given guidance to agency officials at the state level that EIS planning and business processes need to move faster — aside from changing environmental regulations or other requirements. Bernhardt linked part of the problem back to 2001 when the then-Interior secretary chief of staff ordered all Interior-related Federal Register notices be sent to him as a means of monitoring the department’s activities. It ended up spurring what Bernhardt referred to as a “surname process.” “Let me tell you that if you don’t know what a surname process is you should just know that it’s evil,” he quipped. The process grew into up to 30 officials in some cases demanding they be able to sign off on Federal Register notices, according to Bernhardt, which in the case of an EIS usually means three times — once each for the Notice of Intent to file an EIS and the Notice of Availability for both the draft and final versions of the document. As a result, the surname process often leads to upwards of 90 days of delay each time a notice is issued, or 270 days in total. BLM took 11 months to publish the Notice of Intent for the GMT-2 EIS, according to ConocoPhillips. Bernhardt said he is trying a pilot process in which state agency directors and an attorney sign off on such documents and agency and department leaders then collectively have about two weeks to approve them. “The purpose of (the National Environmental Policy Act) is to make sure we take a hard look at issues — that we’ve looked at a reasonable range of alternatives, that we have had public participation to ensure that we as federal decision-makers are more fully informed before we make our decision, whatever it’s going to be,” he said. “And the documents that are written today, when they’re 8,000, 10,000, 25,000 pages, I can tell you that no one on the planet reads them so they’re not serving the purpose they’re intended to.” Elwood Brehmer can be reached at [email protected]

FERC sets December 2019 deadline for AK LNG review

Federal officials analyzing the plans for the Alaska LNG Project issued a timeline March 12 that would extend the review about a year beyond what state officials were hoping for. Federal Energy Regulatory Commission Secretary Kimberly Bose signed off on the environmental impact statement schedule that calls for the agency to issue a Notice of Availability for the final Alaska LNG Project EIS by Dec. 9, 2019. The subsequent record of decision would then be made by March 8, 2020, within the required 90-day period after the final EIS is published. FERC plans to have the draft EIS out for comment next March, according to the filing. Alaska Gasline Development Corp. leaders in mid-November requested the schedule be published by Dec. 15. President Keith Meyer has said repeatedly he wanted the final EIS out late this year to match the corporation’s proposed timeline of having commercial agreements in place for an early 2019 final investment decision with construction starting late next year. The schedule is still fungible depending on how the EIS drafting plays out, but the self-imposed timeline does set a significant precedent. Meyer said at the March 8 AGDC Board of Directors meeting that a slower schedule, such as the one FERC just published, would set back actual construction but the agency and its contractors could start ordering numerous long-lead items in anticipation of a favorable decision ahead of official final approval to build the $43 billion project. On AGDC’s ideal timeline the first train of the three-train 20 million tons per year LNG plant would be in service in 2023 and production would ramp up over the next couple years as the other trains would be constructed and brought online by 2025, according to Meyer. However, AGDC officials said in formal statements March 13 that they are happy to have a schedule to work from. “Achieving clarity on the permitting timeline is another critical step forward for the project; AGDC is appreciative to FERC and to the (Trump) administration for their continued commitment to keeping this project on the fast track,” Meyer said. “A draft EIS in March 2019 with availability of a final EIS in December 2019 will allow us to keep Alaska’s gas export project on track for a 2024-25 in-service date. FERC’s expeditious and comprehensive analysis of our application is a testament to the hard work and dedication of commission staff.” Gov. Bill Walker thanked FERC for issuing the schedule and said it’s a “major step forward that establishes clarity and predictability in the federal permitting process, which is critical for investors.” AGDC filed its EIS application last April — nearly 60,000 pages of environmental, engineering and socioeconomic data believed to be the largest EIS filing in history. It was hoped the immense amount of data, along with the fact that the U.S. Army Corps of Engineers is preparing a final supplemental EIS for the smaller, backup Alaska Standalone Pipeline project, which largely mirrors the AK LNG route, would allow FERC to meet the agency’s aggressive schedule. On Jan. 22 AGDC announced it had responded to all 801 of FERC’s questions regarding the initial filing information, but on Feb. 15 the regulators followed up with 288 more; directing AGDC to further examine routing the pipeline to Port MacKenzie or Valdez instead of the Nikiski, the LNG site chosen by the producers in 2013. AGDC leaders insist the new round of questions is not uncommon in the often back-and-forth process, and they expect more as FERC continues to evaluate the tremendous amount of data for the project. EIS public scoping meetings to determine what all regulators should evaluate were held in late 2015 under the former ExxonMobil-led project structure. The next major step under a standard EIS development would be for FERC to issue a preliminary draft EIS for cooperating federal agencies to review and comment on. Subsequent to that, the resulting draft EIS would be issued, initiating a public comment period of at least 45 days — on very large or contentious projects it is often longer — and associated public meetings. FERC would then respond to the appropriate comments and incorporate them into the final EIS publication, after which a minimum 30-day waiting period must be held before a record of decision on the project is reached. Elwood Brehmer can be reached at [email protected]

Feds change course, pick Alaska’s choice for Sterling Hwy re-route

There finally appears to be a resolution to the saga over how best to avoid Cooper Landing. Gov. Bill Walker was joined Wednesday in the Capitol by Kenai Peninsula legislators Sen. Peter Micciche and Rep. Gary Knopp, to watch DOT Commissioner Marc Luiken and Alaska Federal Highway Administration head Sandra Garcia-Aline sign a final environmental impact statement for the Cooper Landing bypass project and bring the project one big step closer to reality. Walker said he is among the countless Alaskans to have navigated the winding, narrow stretch of the Sterling highway through Cooper Landing in an oversized RV, adding that he has never talked to a group of residents from the area and not had the issue come up. “This is a safety issue,” the governor said. “This is a milestone that’s been long-awaited.” State and federal officials working to advance the Cooper Landing bypass project have said they believe it to be the longest running EIS for a transportation project in the country, if not the most drawn out EIS overall for any type of development. The transportation agencies are on the third iteration of an EIS for the project since publication of the first draft in 1982. Micciche and Knopp expressed their appreciation for the agencies’ efforts to listen to stakeholders concerns and address the longstanding public safety problems the current highway presents during the summer. “This project began when my voice cracked with puberty and today we’re signing the EIS,” a gray-bearded Micciche quipped. A major hang-up has been over what route to choose through the challenging mountainous terrain and the sensitive Kenai River watershed. Sentiment is mixed amongst Cooper Landing residents and business owners as to whether the project should be built at all, as some fear it will steer potential customers away from their businesses that rely on the traffic. The state recently completed work to straighten and add passing lanes to the Sterling Highway east of Cooper Landing and is preparing for similar work on the stretch of highway west of the Cooper Landing bypass area over the next two years. Publication of an EIS last year left the state at odds with the Federal Highway Administration, which chose a route different than that preferred by many on the Kenai Peninsula and Gov. Bill Walker’s administration and the congressional delegation. The final EIS signed Wednesday selects the Juneau Creek alternative route favored my most Alaskans who have formally voiced their opinions on the project. The Juneau Creek corridor would take the highway north of Cooper Landing and add 10 miles of new road, with a cost estimated at $205 million, before reconnecting with the existing highway west of the community and the Kenai-Russian River confluence area that draws thousands of anglers each summer. The FHWA originally chose a route known as the G South alternative, which also would take the highway north of Cooper Landing, but would reconnect to the current road after about five miles and not avoid the busy Kenai-Russian area. At $250 million, the G South option is also estimated to cost more because it would require a new bridge over the Kenai and reconstruction of the existing Schooner Bend Bridge at the west end of the project. Walker and the members of Alaska’s congressional delegation sent a joint letter to leaders of the federal Agriculture, Interior and Transportation departments last July urging them to reconsider the G South selection and work to reach agreements that would facilitate the Juneau Creek alternative. They contended the Juneau Creek route provides better protection for the Kenai River and its sought-after trout and salmon because it pulls more of the highway away from the river, thus reducing the likelihood of tanker truck spills or other potential hazards damaging the river. The letter was sent to Interior and Agriculture because the Sterling Highway project would impact the Kenai National Wildlife Refuge and the adjacent Chugach National Forest, which had been a complicating factor. Transportation Secretary Elaine Chao subsequently visited Alaska in August and committed to reexamining the Cooper Landing bypass decision by reopening the Least Environmental Harm Analysis portion of the EIS. Luiken said the fact that the governor and delegation took up the issue together helped get Chao's attention on the matter. Chao also announced at the time that the U.S. Fish and Wildlife Service, an Interior Department agency, agreed to consider a swap with Cook Inlet Region Inc. of Kenai National Wildlife Refuge acreage for some of the Alaska Native corporation’s property that would aide the Juneau Creek route. FHWA Alaska Administrator Garcia-Aline said the new choice was made in partnership with CIRI and the local Kenaitze tribe. “This sets an example for the nation as to how we can move some of these projects forward and get them into construction,” Garcia-Aline said. She added that a public comment period on the final EIS will commence soon and likely end in mid-April, setting the project up for a record of decision in early May. A state DOT spokeswoman said, barring additional delays, construction is expected to start on the first phase of the three-phase project in 2020, as about two years of design work will be needed after the record of decision is published. The bypass should be completed around 2026 if all goes as planned.   Elwood Brehmer can be reached at [email protected]

Oil sector leads construction spending rebound

The last couple years have been tough for Alaska contractors. While it took about two years to really be felt as money on large multi-year and preplanned projects continued to be spent, the precipitous fall of oil prices in late 2014 led to construction spending declines of 18 percent in 2016 and 10 percent in 2017 year-over-year. Not only did the price collapse hit contractors working in the state’s oil fields, but state capital spending has all-but disappeared since the oil revenues the State of Alaska relies on dried up as well. Similarly, Alaska’s construction industry workforce has declined by 17 percent since peaking in 2014 with a year average of 17,800 jobs, according to the state Labor Department. Last year the industry averaged 14,900 workers. It’s worth noting that those figures do not reflect construction jobs classified within the oil and gas sector, which has seen its workforce shrink by 5,000 jobs, or more than 30 percent, over the same period. However, there are signs of a turnaround. The 2018 Alaska Construction Spending Forecast, compiled by the University of Alaska Anchorage Institute of Social and Economic Research estimates “on the street” spending will increase 4 percent to more than $6.5 billion this year. Authors Scott Goldsmith and Linda Leask wrote in the report for the Association of General Contractors-Alaska that the modest increase will be driven by a rebound in spending by oil and gas companies that will more than offset continued declines in infrastructure investment by other sectors. At more than $2.5 billion, oil and gas company spending will be up about 15 percent from 2017 on the back of improved and stabilized, if not robust, oil prices in the $65 per barrel range, as well as continued work on a burst of potentially large oil discoveries in recent years and more favorable federal policies. For reference, Alaska oil and gas capital spending peaked in 2014 at $3.9 billion, according to ISER. “Perhaps the most significant recent federal policy change affecting Alaska is the decision to open the 1002 (coastal plain) region of the Arctic National Wildlife Refuge to exploration,” Goldsmith and Leask wrote. “That decision — along with the opening of federal offshore lands to leasing — will not immediately lead to spending, but it does demonstrate a renewed federal interest in the petroleum industry in Alaska.” ConocoPhillips has led greenfield activity on the Slope of late and is drilling five exploration and appraisal wells this winter, the company’s busiest exploration season in 15 years. Additionally, the company is finishing work on its roughly $1 billion Greater Mooses Tooth-1 development, which is scheduled to start producing oil late this year. Industry leaders in Alaska have said spending has been cut to the point where company’s budgets are again stabilized and at least incremental investment is a possibility. Further, Gov. Bill Walker has a bill in the Legislature to pay off the state’s $800 million-plus oil and gas tax credit liability in one lump sum, which administration officials believe could spur additional oil and gas activity if it passes. Walker has also proposed an $800 million capital projects plan to address the state’s deferred maintenance backlog, estimated at roughly $2 billion, and provide a small economic stimulus across the state. However, the funding source for the plan is a proposed temporary payroll tax that is politically unpopular and it’s unlikely the plan will pass this session. The mining industry is also projected to be on the rebound with $239 million of capital projects, up 6 percent from 2017 after years of subdued activity worldwide, according to the forecast. Teck, which operates the Red Dog mine north of Kotzebue, is exploring a large new zinc deposit and Trilogy Metals is continuing work on its prospects in the Ambler Mining District, also in Northwest Alaska. The U.S. Army Corps of Engineers is also expected to release a final environmental impacts statement for Donlin Gold’s massive gold project along the Upper Kuskokwim River later this spring. A favorable decision for Donlin will not mean more spending this year and company leaders have acknowledged the economic viability of the remote mine is very sensitive to gold prices, but if it goes forward Donlin likely represents $5 billion of work over several years of development. Another positive will come from the federal government in the form of Defense spending, which with six large military installations in the state is a significant contributor to the construction industry. The feds are expected to spend $630 million on Defense projects in Alaska this year, an 11 percent increase from 2017, according to the forecast. Missile defense work at Fort Greely will eventually add to the number of interceptor missiles at the Army base. The Air Force is in the midst of $325 million of work to install a long-range discrimination radar system at Clear Air Force Station near Nenana. Further work is also ongoing at Eielson Air Force Base in Fairbanks to prepare for the 2020 arrival of the first squadron of F-35 fighters that will be stationed at the base. The 2018 National Defense spending bill signed by President Donald Trump in December approved nearly $170 million in projects for the F-35 bed-down and $200 million for a new missile field at Fort Greely. Surface transportation spending, particularly on roads and highways, should be up about 6 percent to $667 million, Goldsmith and Leask project. While most surface transportation funding comes from the federal government with a small state match and is generally pretty stable year-to-year, the increase this year is due in part to money from a $453 million state bond package approved in 2012 finally “hitting the street.” “It can take considerable time for transportation appropriations to become cash on the street, so state funds from past capital budgets and bond sales are still contributing to current spending,” the forecast states. “Consequently, the level of spending this year will be a little higher than last.” Much of that money will fund major projects on the Glenn, Seward and Sterling highways. Capital spending in other sectors and industries is generally expected to fall by up to 20 percent year-over-year as bare-bones state capital budgets and the third year of Alaska’s ongoing recession continue to constrain investment. ^ Elwood Brehmer can be reached at [email protected]

LNG tank construction a sign of progress for Interior gas project

Backhoes are back digging in south Fairbanks as construction work is again underway on the Interior Energy Project. Ground-turning work on the effort to expand the natural gas supply to the region had been on hold since the summer of 2015 as IEP leaders looked revise the scope of the project in the face of challenging economics brought on by lower oil prices. The last physical work on the project involved laying gas distribution lines in North Pole and Fairbanks. Contractors for Pentex Alaska Natural Gas Co., which owns Fairbanks Natural Gas, began foundation work in the final days of December for a $48-million, 5.25 million-gallon LNG storage tank. As of March 1, excavation for the tank foundation has been completed, which meant removal of up to 15 feet of silt and ice-laden material at the site near the Tanana River. In place of the topsoil, a series of conduit loops and three feet of insulation have been laid. They’ll be buried under a new bed of gravel that will support the tank, according to Pentex CEO Dan Britton. The conduit will support a passive cooling system known as a “thermosyphon” to keep the permafrost under the foundation frozen and stable if Fairbanks’ climate warms significantly over the next 75 years, which is the planned life of the tank. The insulation and a separate heating loop will act as a barrier between the LNG tank, its super-cold contents and the ground below. Natural gas turns to LNG at about 260 degrees Fahrenheit below zero. Britton noted that while it is counterintuitive to refrigerate the ground beneath a facility that is as cold as the dark side of the moon, the whole system needs to be monitored and controllable. “The concern from the geotechnical engineers is that if we didn’t have an ability to create a thermal break, the LNG could make the ground too cold. It could take it from our desired temperature of about 28 to 30 degrees (Fahrenheit) down to zero, -10, -15 and then it will become a wick for water,” Britton explained during the March 1 Alaska Industrial Development and Export Authority board meeting. “They don’t want us to be wicking water from outside the foundation into the foundation and creating ice lenses and jacking the tank.” He added that if the thick layer of insulation works as intended, the glycol heating loop would be an idle insurance policy. AIDEA purchased Pentex and Fairbanks Natural Gas in early 2015 and is in the process of transferring it to the borough-owned Interior Gas Utility as part of a $331 million plan to integrate the utilities and expand natural gas availability in Fairbanks and North Pole. The tank itself will be a double-walled, fully contained facility with plenty of redundancy. Britton said the request for proposals Pentex issued last summer was for a single-wall tank because the large size of the site and its isolated location meant a single-wall design with an outer containment system would be adequate. However, when Boston-based Preload Cryogenics submitted a comparably priced bid for a double-wall tank, there was no reason not to go with the more robust protections, according to Britton. The outer wall of the roughly 100-foot diameter tank will be 10-inch thick reinforced concrete. The primary inner tank will be made of roughly one half-inch thick welded steel plates The steel comprising the tank will also be about 9 percent nickel to keep it from becoming overly brittle when in contact with the super-cold LNG. “If the inner tank were to breach for some reason the outer tank is designed to contain the full capacity of the LNG. It’s also designed to handle cryogenic temps,” Britton said. Between the walls will be about 3 feet of insulation — largely perlite similar to the white grains found in potting soil. Many important facilities have backups for key parts installed. Fairbanks LNG tank will be no different, other than the fact that it will have backups for the backups. Britton said the tank would have three pump wells, each fully capable of keeping the system operating on its own. Likewise, there will be double redundancy in its vaporizers. They system is also designed to accept LNG from the truck tankers if need be. “In the event we have a problem with the line from the tank feeding the vaporizers we can take LNG directly out of the trailers straight into the vaporizers and into they (distribution) system,” Britton said. “(We’re) trying to put as much redundancy in the system as we can.” More than just a visible indicator for area residents that the long-delayed Interior Energy Project is closer to reality, AIDEA board member Gary Wilken of Fairbanks has called the LNG tank the heart “of the Interior Energy Project.” That’s due in large part to the fact that just the storage tank will allow Fairbanks Natural Gas to nearly double the amount of gas it can provide customers even without additional gas supply. When the tank is finished in late 2019 — in time to capture a $15 million LNG storage tax credit from the state before it sunsets — it will allow Pentex to run its Titan LNG plant in the Mat-Su Borough full-bore nearly all year because it will now have a place to hold the LNG. That means LNG produced during the low-demand summer months can be stored and drawn down during the winter. Currently, with just several small portable storage tanks, the Titan plant, capable of processing about 1.5 billion cubic feet of gas, or bcf, per year, must be run to match immediate gas demand from end users. In recent years that demand has been for between 750 and 900 million cubic feet of gas per year, according to Britton. The 5.25 million gallon LNG tank will allow Pentex to run the Titan plant to process up to 1.4 bcf of gas, he said, allowing for a few weeks of maintenance downtime each year, he said. Britton described the tank as providing a “direct line of sight” to when more natural gas will reach Fairbanks customers. Finally, while the overarching contract for the tank went to an Outside firm, there is no shortage local contribution to the construction. “We have a lot of work that’s being completed by Alaskan contractors and Alaskans,” Britton emphasized. He listed 10 Alaska companies that are subcontractors for Preload Cryogenics on the project. Great Northwest Inc., a Fairbanks-area general contractor handled all of the site preparation and gravel fill. Anchorage Sand and Gravel is casting the outer tank panels, which will be trucked north to Fairbanks. Three of the 85-foot long concrete test panels will be started later this month and the first will head to the site in early June when spring weight restrictions on the highways are lifted, according to Britton. Elwood Brehmer can be reached at [email protected]

Walker puts out call to join trade mission to China

Who wants to take a trip with the governor? At a March 5 press conference in Anchorage, Gov. Bill Walker said his office is looking for business leaders interested in participating in a trade mission to China this spring. The weeklong business trip, scheduled for May 19-26, is the governor’s attempt to continue building off of a stop in Anchorage last April by China President Xi Jinping and Chinese cabinet officials. “The discussions that took place at that dinner at the Captain Cook (hotel) were very fruitful in many ways since then,” Walker said of Xi’s visit to Alaska. The Chinese government leaders were on their way home and made an extended refueling stop after meeting with President Donald Trump. Walker said plans are for the Alaska trade delegation to be primarily made up of people from the state’s private sector joined by state Commerce Commissioner Mike Navarre, International Trade Director Shelley James and the governor. It’s not yet known if any other state officials will participate. Those interested in participating in the administration’s trade mission to China should contact the state Office of International Trade. Attendees will be required to pay a $3,000 participation fee for meeting arrangements, interpretation, logistics, in-country transportation and other services, according to the governor’s office. Airfare and lodging are not included in that cost. China is already Alaska’s largest trade customer, buying up nearly 30 percent of the state’s exports in recent years. Last year China imported $1.32 billion worth of Alaska products, a 7 percent increase from 2016, according to the state Office of International Trade. Seafood, Alaska’s top export, has accounted for about half of the exports from Alaska to China in recent years, followed by minerals and timber. Despite being tops locally, Walker cited statistics that Alaska is among the bottom three states nationwide in terms of business activity with China. “We have a long ways to go but we have a tremendous opportunity,” he said. The biggest fruit borne so far from Xi’s visit is the framework agreement Walker and Alaska Gasline Development Corp. President Keith Meyer signed in Beijing last November with three state-owned Chinese mega-corporations to possibly buy from and invest in the $43 billion Alaska LNG Project. While the deal with oil and gas giant Sinopec, the Bank of China and China Investment Corp., which manages the country’s sovereign wealth fund, is nonbinding, Meyer has said AGDC hopes to have firm agreements in place by early summer that would be the foundation for a final investment decision on the project early in 2019. Meyer said Trump’s talk of tariffs on imported steel and aluminum — met with bipartisan opposition — and other tough talk on trade with China is due to the massive trade imbalance with the U.S. That creates an opportunity for Alaska, Meyer said. “Really, the pushback (on China) is a message to buy more stuff from the United States and that’s where I think Alaska has the stuff that China wants, so I see this message of ‘buy more stuff’ really being a call to ‘hey, buy more stuff from Alaska,’ so we can do our part there,” Meyer commented. “I think the message is really harmonious with our mission.” A partnership to bring the long-sought Alaska LNG Project to fruition would be an iconic achievement but the project still has many hurdles to clear, the most recent to arise being the state’s permit application declared to be incomplete by the Federal Energy Regulatory Commission. More immediately, Walker said the impact of one sentence uttered by Xi on-camera while he was here is already being felt by Alaska businesses. The Chinese president referred to Alaska as “a Shangri La of China” and subsequently predicted what the result would be, according to Walker. “The cameras were off — as he walked away he smiled a bit and said, ‘You will see an uptick in tourism as a result of my saying that,’” Walker recalled. “And he certainly was correct.” Visit Anchorage CEO Julie Saupe, invited by the governor’s office to participate in the press briefing, said tour operators, travel agents and others in the industry have anecdotally confirmed Xi’s prediction. She noted hard data on tourism growth for the country won’t be available for some time as international tourist travel is usually planned many months or years in advance. “We are seeing a tremendous increase in inquiries from China visitors and also in products available both in Anchorage and also in Fairbanks to serve Chinese visitors, so we do see a lot of potential in this market as do other destinations,” Saupe said. “It’s a very competitive environment that we’re working in for the Chinese visitor because they are going to really have a lot of increased visitation throughout the U.S.” Tied to the interest in tourism, Ted Stevens Anchorage International Airport Manager Jim Szczesniak said his team is trying to make the airport again a major hub for international passenger flights. The Anchorage airport is consistently among the top five airports worldwide for cargo plane activity mostly due to its prime location as a midpoint refueling stop between East Asia and the Lower 48. Szczesniak said airport officials are promoting a similar model for passenger flights as a means for airlines dealing with worldwide shortages of pilots and commercial aircraft as well as high demand for gate space at the largest domestic hubs. “We’re looking to offer airlines the opportunity to come directly into Anchorage, be able to transfer passengers in Anchorage — some of them like in Icelandair’s model will be able to get off here and be able to tour; do five, six, 10 days in Alaska — and then get back on a plane and continue on to their further destinations,” Szczesniak described. Anchorage was a hub for international passenger traffic for many years until the early 1990s when the fall of the Soviet Union reopened airspace over the former communist country and popularization of the Boeing 747 made nonstop trans-Pacific flights feasible between more locations. Szczesniak said today a daily eight- to nine-hour flight between Anchorage and most East Asia hubs requires just two pilots and one plane, while a similar schedule going direct to the Lower 48 would require two planes and six pilots per day due to flight-time constraints. “Now that there’s a constraint back on the system we’re offering an opportunity for Anchorage to mitigate that constraint,” he added. Szczesniak noted the airport waives some landing fees for airlines offering new or expanded direct passenger service to or from Anchorage depending on the frequency of flights and length of service. Elwood Brehmer can be reached at [email protected]

House budget slashes credits, inflation-proofing, adds $19M for UA

The House is getting ready to vote on the operating budget and three perennially contentious issues were addressed in Finance Committee amendments to Gov. Bill Walker’s budget proposal. The House Finance Committee spent much of Feb. 26 and Feb. 27 debating amendments to Walker’s $4.5 billion 2019 fiscal year operating budget proposal. Finance co-chair Rep. Paul Seaton, R-Homer, said public testimony on the House version of the budget would be taken March 1-3 and the budget would move to the floor for a vote by the middle of the month. The governor’s budget is generally on par with the current year budget, which has been a source of discontent for Republicans who insist further substantial cuts are needed before taxes proposed by the administration and the Democrat-led House Majority are considered. Tax credit payments slashed While much of the debate was over small monetary or technical changes as is often the case, an amendment by Seaton would change how the state calculates the required minimum annual payment of oil and gas tax credits. Seaton, one of three House Republicans to caucus with the mostly Democrat majority coalition, pushed to appropriate $49 million to the Oil and Gas Tax Credit Fund instead of the $206 million statutory minimum payment calculated by the Department of Revenue. Seaton’s amendment passed 6-5 with House Majority member Rep. Jason Grenn, I-Anchorage, voting with the minority against it. Seaton’s amendment also removed $27 million from the governor’s budget intended to make the state’s first yearly payment on a 10-year bond package to pay off nearly $1 billion in outstanding and expected tax credit certificates. The administration’s bonding proposal is separate legislation that the governor’s budget assumes will pass. Legislation passed over the previous two years effectively ended the tax credit program but unpaid credits from 2015 to 2017 remain on the state’s books. Until Walker vetoed $200 million worth of the credits in 2015, the state had always paid the year’s balance of credits in full. The sticking point is over when state officials calculate producers’ oil production tax liability for the purposes of generating the statutory minimum payment amount for the tax credits. By law, the state is obligated to appropriate back to the Tax Credit Fund 15 percent of production taxes when oil prices are forecast to average less than $60 per barrel or 10 percent of the taxes when oil is more than $60 per barrel. The Walker administration arrives at the minimum credit payment by determining the 35 percent net profits tax and then arriving at the minimum payment amount before factoring tax credits, including the key per barrel tax credit, which drastically lowers the effective tax rate. Seaton and some, but not all, members of the House Majority members of the Finance Committee, contend the minimum tax credit payment should not be figured until after the credits are applied, thus lowering the minimum payment because the state does not actually receive the production tax amount the administration calculates. Seaton said the intent of the Legislature and former Gov. Sean Parnell’s administration was to base the minimum payment formula on the “net” taxes received and not the “gross” tax amount before other credit deductions when the legislation was passed. Rep. Tammie Wilson, R-North Pole, argued that while she has been one of the few Republicans in the Legislature comfortable with paying the formulaic minimum credit amount because that’s what has been in law all along, changing the formula now would appear as if the Legislature is trying to bend its own laws whenever it can to benefit the state and further damage the state’s reputation as a reliable business partner. Anchorage Republican Rep. Lance Pruitt noted the administration has used the gross minimum tax credit formula for several years and the Legislature agreed to pay the Tax Credit Fund $77 million last year based on the administration’s formula. Revenue Commissioner Sheldon Fisher said the administration has consistently applied the gross formula and Tax Director Ken Alper noted that in prior years the delta between the two calculations was only $10 million to $20 million. This year it’s more than $150 million based on slightly higher oil prices and reduced company spending that results in a much greater pre-credit profits tax calculation. “It is the same calculation that got us to $30 million in fiscal year ‘17 that got us to $206 million in fiscal year ’19,” Alper testified. Permanent Fund Amendments by Seaton also passed to remove language from the governor’s budget to move nearly $2.4 billion from the Earnings Reserve Account of the Permanent Fund into the corpus of the Fund. Legislators have declined to inflation-proof the corpus the previous three years to maximize the value of the Earnings Reserve in preparation for utilizing the Earnings Reserve for government services via a percent of market value, or POMV, draw — which is likely to happen this year because other state savings accounts aren’t sufficient to cover the projected deficit. “The one thing we can’t do is we can’t devalue the corpus; we have to protect it,” Pruitt said. The Alaska Permanent Fund Corp. Board of Trustees passed a resolution last fall urging the administration and the Legislature to pass a law that would automatically inflation-proof the Fund without needing direct appropriations. While a bill to that effect did not materialize, the governor’s budget would backfill the corpus with a $1.45 billion transfer to cover 2016-18 inflation-proofing payments and another $943 million for fiscal year 2019, the upcoming budget year being debated. However, another amendment forwarded by Seaton reduced the POMV draw on the Fund from 5.25 percent in the governor’s budget to a more conservative 4.75 percent, which the House Majority has advocated. Walker included the POMV-style calculation in his budget bill in order to propose a fully funded budget, which he is required to do, in the event legislation formalizing the POMV draw is not passed. The administration and the Republican Senate Majority have pushed the higher draw to reduce deficits in the near-term, with the plan to lower it to a five-year rolling average 5 percent draw after three years at 5.25 percent. Legislative Finance Director David Teal said 5 percent is “aggressive but not out of line,” while the 4.75 POMV draw “is sustainable and should keep pace with inflation.” UA increase There was bipartisan support for increasing the University of Alaska budget by $19 million; an increase arrived at by the University of Alaska Budget Subcommittee. State fiscal support for the UA System has fallen from $378 million in 2014 to $317 million currently. Walker proposed holding it flat at $317 million. UA President Jim Johnsen said in a speech Feb. 20 that the system offers 50 fewer programs and has 5,000 fewer students and nearly 1,200 fewer employees today than it did three years ago as a result of the cuts. Johnsen and the Board of Regents have said over that time that they expect the university budget to be cut but asked for smaller cuts to better manage internal reforms that would save money over the long-term. Rep. Steve Thompson, R-Fairbanks, said the $19 million increase is a compromise between what the regents requested and what the governor proposed when also considering the peak budget amounts. “Our future’s in our young people that are graduating from our university,” Thompson said Feb. 26. Elwood Brehmer can be reached at [email protected]

Cost estimate drops for Ambler mining prospect

The company that has led exploration in the Ambler mining district is now shifting to develop its primary prospect after many years of work. Trilogy Metals released a pre-feasibility study for its project at the Arctic prospect in Northwest Alaska with a higher initial capital estimates cost but a lower overall cost Feb. 20. Formerly NovaCopper Inc., Vancouver-based Trilogy Metals changed its name in 2016 to reflect the multi-metal deposits the company holds. Located in the middle of the large Ambler mining district that stretches along the southern face of the Brooks Range in Northwest Alaska, Trilogy leaders project the high-grade Arctic deposit to be the first of several mines in the area. The Arctic prospect holds an estimated 2.4 billion pounds of indicated copper resources at a 3.07 percent grade; 3.3 billion pounds of indicated zinc at 4.23 percent; and precious metal resources estimated at 55 million ounces of indicated silver and 730,000 ounces of gold, according to the Feb. 20 report. Estimated costs to develop Arctic have grown 9 percent since a 2013 preliminary economic assessment and are now pegged at $780 million. However, a 60 percent drop in expected annual operating and 20 percent decrease in closure and reclamation costs — to about $65 million each — cut the all-in cost for the mine by 5.5 percent from $964 million in 2013 to $911 million today. Trilogy executives said during a call with investors that the drastic drop in operating costs is due to changes in the plan for waste rock and tailings management, fuel and federal tax reform. The original high-level Arctic design called for potentially acid-generating waste rock to be comingled with mine tailings, which resulted in the need for a larger tailings facility and dam, according to Trilogy CEO Rick Van Nieuwenhuyse. The current revised design has mine tailings and wastewater behind a dam with waste rock and an associated collection pond directly in front of and below the tailings dam at the head of the Subarctic Creek valley that will hold the mine waste. Additionally, switching from diesel to LNG as a fuel source to power the mine facilities equates to a 41 percent reduction in the cost of power at Arctic, according to the pre-feasibility study. “We’ve worked hard over the last several years to confirm that we can use LNG that’s available in Alaska — and they’re trucking it up to Fairbanks now,” Van Nieuwenhuyse said, referencing Fairbanks Natural Gas’ use of LNG trucked north from Point MacKenzie in the Mat-Su Borough to supply its customers. “We can haul LNG just as easily as diesel.” Utilizing LNG should also make obtaining an air quality permit for the project from the state Department of Environmental Conservation much easier, he noted. The natural gas could be sourced from Cook Inlet as the Fairbanks utility currently does or from a large gasline off the North Slope if the state’s Alaska LNG Project materializes. Van Nieuwenhuyse also said Trilogy has settled on using enclosed cubed containers for trucking metal concentrates from the mine — with a higher upfront cost than open trailers — that should eventually pay for themselves through no lost concentrates during transport. “I think more importantly by not losing concentrate as fugitive dust you’re not contaminating the environment. This is a win-win for the overall project,” he said. Developing the Arctic mine — or any project in the Ambler district — is predicated on the state-owned Alaska Industrial Development and Export Authority being successful with its effort to permit, finance and construct a 220-mile road west from the Dalton Highway to access the region. The federal Bureau of Land Management is currently drafting the first version of the environmental impact statement for the $300 million-plus road. Van Nieuwenhuyse said Trilogy has tried with its work at Arctic to keep pace with AIDEA’s work on the Ambler access road. A permit decision on the road is expected in early 2020, according to AIDEA, with two subsequent years of construction. The state’s plan is to pay for the road through tolls from the companies mining and exploring the Ambler region. Accordingly, Trilogy hopes to start applying for its environmental permits in 2019 and embark on a full feasibility study in 2020, Van Nieuwenhuyse said in an interview. Ideally, it would all lead to a completed road and the start of Arctic construction in about five years, he said. This summer Trilogy will be doing $4 million to $5 million worth of water management studies and geotechnical evaluations of the tailings dam site. The company is also preparing for another $10 million exploration program at its Bornite prospect to the south of Arctic. Overall, Van Nieuwenhuyse said the company will be employing about 80 people at its projects during the summer work season as it has in recent years. Trilogy’s financials at Arctic are based on a minimum 12-year mine life. It’s a small but very prospective deposit. The company is estimating it can recover pre-tax development costs within two years of operations based on an average market price of copper at $3 per pound. Even at $2 per pound copper, Trilogy estimates after-tax payback within three years. Copper has traded in the $3 per pound range of late. Annual production from the mine is planned at about 160 million pounds of copper, 200 million pounds of zinc, 33 million pounds of lead, 30,600 ounces of gold and 3.3 million ounces of silver over its life. While Arctic holds and is expected to produce more zinc, copper generally sells for significantly more than zinc, which has traded between $1.20 and $1.60 per pound over the past year. Total costs for mine development, operations and access road tolls are pegged at 63 cents per pound of payable copper, according to Trilogy. “At current prices your cash flow is well over $500 million of free cash flow so this thing is really crunching out a lot of cash,” Van Nieuwenhuyse commented. As a result, Trilogy leaders aren’t nearly as worried about metal prices as the proponents of other remote mines— with extremely high costs — in Alaska. “If we’ve got the kinds of commodity prices that would shut down this mine we’ve got other things to worry about,” Van Nieuwenhuyse said in an interview. “We certainly envision here for the future a central milling facility at Arctic that is conveniently located smack dab in the middle of this 100-mile long (Ambler) belt.” Elwood Brehmer can be reached at [email protected]

Senate committee takes up Walker’s bill to retire oil tax credits

Gov. Bill Walker’s plan to clear the state’s books of nearly $1 billion in oil industry tax credits is generating a lot of interest but also plenty of “what ifs.” The Senate Resources Committee took up Senate Bill 176, which would have the state sell bonds to pay off the credits, for the first time Feb. 21. Administration officials characterized the proposal as a cost-neutral way to pay off the credits immediately while hopefully spurring industry activity and at least partially restoring the state’s business credibility. Under the proposal, the Department of Revenue would issue a series of 10-year bonds equal to the total outstanding tax credit obligation. The money generated from the bond sales would then be paid out to the primarily exploration and small producing companies holding credit certificates. Central to the plan is getting the companies to agree to take a discount of up to 10 percent off the face-value of the credit certificates in order to be paid immediately — in essence take a haircut to end the prolonged tax credit saga and get on with life. Revenue Commissioner Sheldon Fisher called it a “unique opportunity” for the state. “It’s almost free money, if you will, to be able to accelerate the payment into the current time period, pay off these debts, result in a stimulus, but moving forward the cost of that borrowing will be borne by the credit holders themselves,” Fisher testified to the Senate committee. Walker vetoed a total of $630 million from budget bills in 2015 and 2016 while the state was running annual deficits in excess of $3 billion. The actions drew sharp and continued ire from the industry and Republican legislators who argued the governor was not keeping the state’s commitment to fully pay off the credits each year as companies claimed them. Those annual tax credit bills reached $700 million, which Walker said was unsustainable as the state was cutting other services and facing such large budget shortfalls. Prior to the 2016 veto the Walker administration proposed legislation to phase out the credits and appropriate $1 billion to pay off the obligation then — if the Legislature would pass the fiscal reforms needed to resolve the deficits. Subsequent legislation in 2016 and 2017 effectively ended the cashable tax credit program in Cook Inlet and then on the North Slope, respectively, but the previously earned obligations remain. Current law requires the state to pay only a portion of the credit certificates each year based on a percentage of the year’s expected oil production tax, which some Democrats have stressed as proof that the state has actually kept up its end of the bargain. However, Fisher said the state bears some responsibility in creating an atmosphere that the credits would be fully paid off each year. Walker’s veto was the first time the full balance of credits earned in a year was not paid. Fisher characterized paying off the obligation as a “matter of ethics” that would also help restore the state’s business credibility. In 2017 the Legislature appropriated the statutory minimum payment of $77 million to the Oil and Gas Tax Credit Fund amid larger battles over spending cuts and taxes to solve the state’s fiscal problems. The tax credit bill was $806 million at the start of the year, according to the Revenue Department. Tax Division Director Ken Alper said officials anticipate about $100 million of the existing credits will be sold to large producers that can’t receive cash for them but can use the certificates to pay down their own production tax obligations. Another roughly $200 million in credits that have not yet been claimed or will be earned through ongoing refinery and LNG storage credits that were not killed with the legislation last year but will sunset in a couple years is likely to be added to the obligation before the issue is finally settled, according to Alper. Further complicating the matter is the fact that credit holders — particularly small operators with little cash flow — have borrowed against the credit certificates and banks lent money on the presumption the credits would always be paid at the end of each fiscal year. As a result, not funding the credit payments has led to companies defaulting on those loans. In turn, planned oil and gas work has been delayed for lack of cash and banks working in the industry are now generally hesitant to lend for work in Alaska. “While this money may be pledged and go to pay off debt we are confident that (companies) are going to be able to access additional sources of capital and bring it into the economy,” Fisher said. Numerous field operators working in both Cook Inlet and on the North Slope such as Caelus, Blue Crest and Furie Operating Alaska have cited unpaid tax credits as a reason they have deferred or cancelled work plans in recent years. Southeast Republican Sen. Bert Stedman said bankers he’s talked to regarding the credit issue have said they simply missed the “subject to appropriation” language in the tax credit program statute during their due diligence and assumed the certificates would always be paid. “I think (banks) are going to be a lot more cautious and do a much tighter review of their underwriting as they go forward,” Stedman commented. Details of the discount To the intricacies of the bill, of which there are several, Fisher said the administration settled on the 10 percent discount rate as a general midpoint between what the state can borrow for and the interest rates in the 15 percent range that oil industry borrowers often face. “They need the money now and even though 10 percent is well above the state’s cost of capital we believe it’s well below their cost of capital,” Fisher explained. At the 10 percent discount rate a company or bank holding $100 million of certificates would be paid $87.2 million, according to Fisher, because under the status quo that $100 million would be spread over several years and the per annum discount is applied starting in the second year. A second option would give credit holders the option of taking a smaller discount of 5.1 percent, but that would come contingent on negotiating with the Department of Natural Resources on an overriding royalty interest on future oil and gas production or commitments to further invest in projects in Alaska. A small number of companies holding seismic exploration credits could also agree to waive the 10-year confidentiality provision in state law and make the data gathered with the expected credit funds public immediately. The first round of bonds would likely be sold in August, giving credit holders until about late July to decide if they want to participate, according to Fisher. He said the administration is doing its best with the bill to balance several competing interests. Paying the credits in-full using savings is politically unlikely and at this point might not be fiscally advisable given the state is expected to have less about $2.3 billion in savings when the current fiscal year ends June 30. Administration and legislative budget managers insist the state needs at least $1 billion on-hand at all times for cash flow management and responding to unforeseen emergencies. Fisher also noted that if the legislation does not pass, the Legislature would have to add about $180 million to the governor’s budget proposal — an unsavory thought with dwindling savings — because the minimum payment for fiscal year 2019 is $206 million, up significantly from prior years. The governor’s budget appropriates $27 million to make the first interest-only payment on the bonds but presumes SB 176 or its mirror version in the House will pass and as such does not include the traditional tax credit appropriation. Industry interest The administration is still feeling out what companies might want to participate, but none of the roughly dozen banks and oil industry companies holding credit certificates have wholly dismissed the idea. “So far I haven’t met anyone who has said they don’t want to participate,” Fisher said. Casey Sullivan, a spokesman for Caelus Energy said the company is happy the administration is taking on the issue and is trying to find new ways to solve the credit problem but wants to see what happens to the bill as it moves through the Legislature. Caelus operates the small Oooguruk oil field on the North Slope and has been forced to delay its adjacent Nuna oil project for several years because it hasn’t been paid the credits it is owed in addition to the sharp drop in oil prices since 2014. Caelus has also put off further evaluation of its large Smith Bay oil prospect discovered in 2016 due to the credit issue and prices, according to company leaders. Ahtna Inc., the regional Native corporation for the Copper River area, said in a statement to the Journal that the company is in favor of the state trying to find a solution to pay the owed money sooner. “While it’s good that the state is working to pay obligations, it’s unfortunate that payments won’t be made at 100 percent,” spokeswoman Shannon Blue wrote. “Ahtna has paid our vendors at 100 percent and the lack of tax credit payments has slowed business investment when it’s needed most to get out of a severe recession.” Ahtna and Interior Native regional corporation Doyon Ltd. have drilled exploration wells near Glennallen and Nenana, respectively. A spokeswoman for Doyon said the company is still reviewing the bonding proposal and couldn’t comment on it yet. House Bill 111, which passed last year and largely ended the refundable tax credit experiment, included a provision allowing the Native corporations owed money to apply the production tax certificates against their state corporate tax payments. Other oil industry representatives said they are amenable to the concept of SB 176 but need to know more about how it would impact their specific situation and what happens if they don’t opt in if the bill passes. Fisher said the Legislature would have to appropriate additional funds for companies that decide not to participate in the bonding program. Senate Republicans on the committee were generally receptive to the idea as well, but questioned why the administration wants to start with interest-only payments and backload the bond payments over 10 years. Fisher responded that putting off the lion’s share of the bond payments to future years gives the state some time to get on better fiscal footing and noted the largest annual payments would be $115 million from fiscal years 2024 to 2028, with final payments of $82 million and $65 million in 2029 and 2030. The statutory minimum payment schedule has the state paying out at least $119 million each year until 2024 under the current formula. “Central to this proposal is a desire to produce a savings to the state budget in the near term,” Fisher added. Anchorage Sen. Bill Wielechowski, the lone Democrat on the Resources Committee, emphasized that the state has done all it is obligated to by paying the annual minimum and questioned the constitutionality of the subject to appropriation bonds. Article IX of the Alaska Constitution generally prohibits the state from taking on debt outside of voter-approved bonds for capital projects and revenue bonds issued by a state corporation. State Debt Manager Deven Mitchell said the Revenue Department would form a public corporation for the purposes of selling the bonds; and the situation would be similar to how the state financed the Goose Creek Correctional Facility in the Matanuska-Susitna Borough. In that case the borough issued revenue bonds on the state’s commitment to pay through its lease of borough lands. “This would be what I’ve heard lawyers refer to as lowercase ‘d’ debt,” Mitchell said. “There’s a commitment to pay,” he continued. “It’s pledge to third parties; it’s the basis of the rating on those bonds and the basis of the investors’ risk weighting.” Elwood Brehmer can be reached at [email protected]

Modular processing facilities aimed at small Slope fields

North Slope oil has historically been a game of making big discoveries needed to justify big development costs, but a team of NANA WorleyParsons engineers is trying to rewrite that playbook. Kairos LLC, a subsidiary of NANA WorleyParsons, has developed what company leaders believe could turn small or otherwise marginal North Slope oil finds into productive members of the state economy. Kairos is a Greek term for “a time when conditions are right for the accomplishment of a crucial action,” according to Merriam-Webster. The time was early 2015; oil prices had just fallen to less than $50 per barrel and the industry was coming to grips with the fact that the downturn was the result of fundamental changes in global oil markets and not a recession-induced blip like 2008-09. The crucial action, for NANA WorleyParsons, was finding a way to help its industry partners be profitable in Alaska, particularly during periods of lower prices. And the accomplishment turned out to be Kairos’ Mobile Arctic Production System. The recently patented MAPS, as it is conveniently referred to, is a scaled-down and modular oil processing facility. Engineers of the system compare it to a “very small portable version of a flow station or gathering center.” NANA WorleyParsons General Manager Daniel Formoso described it as a “plug and play” system that could preclude operators from having to spend upwards of $200 million or more on traditional processing facilities. “This allows production of smaller fields that could otherwise be uneconomic to develop,” Formoso said. The basic processing system consists of four modules: one each for power generation, natural gas handling, electrical controls and a 5,000 barrels per day liquids production module. It can be leased for $13 million per year, according to company officials. Storage tanks and a truck loading facility are also part of the standard package. Additional modules for handling sand, water, production heating and processing to sales-quality oil are available as well. The system is scalable in 5,000 barrels per day increments by adding additional production modules, but company officials acknowledge that traditional, large facilities would probably be warranted for production above roughly 15,000 barrels per day. It’s intended for developments with less than about 10 wells. While produced natural gas is intended to power the system, if the MAPS is installed on a well pad near accessible power — or a pipeline for that matter — the power generation or liquids storage equipment can be omitted. “We could tailor it to be handling more gas than oil if we needed to,” Formoso added. The flexibility in configuration should make the MAPS a viable option for most any oil-gas-water-sand production mix an operator encounters on the North Slope, according to Kairos. The only thing an operator needs ahead of time is a small gravel pad of at least three acres, which is enough space for a few wells and a handful of the 20-foot by 60-foot truckable modules. The upfront cost to an operator would then be in the $20 million range, Kairos engineers estimate, as opposed to the cost of a more traditional 10- to 12-acre gravel pad to hold a suite of wells and large, permanent production facilities. The MAPS could be applicable not only for small oil fields — of which there are several the company has identified that have been found and dismissed by producers because of traditional production costs — but it could also provide a revenue stream for a small producer while long-term full development of a larger field is ongoing. Kairos estimates it could lower the all-important breakeven production cost on a new field from $55 per barrel of oil to $37 per barrel. The modular production facility concept is not new; it’s widely used across the shale fields of the Lower 48. Kairos’ MAPS is similar to the systems employed down south but with Arctic-specific additions. Company engineers note the small production systems popular in the North Dakota and Texas shale oil fields are built on open-air skids with no fire and gas detection or suppression systems and very little insulation on piping and other equipment. Down south, where power connections are easy to find, gas is generally flared. The MAPS not only uses gas for self-sustaining power, thereby minimizing the need for diesel and its risks, but any gas flaring that needs to be done is enclosed as well, according to the designers. “It’s made for our environment,” Formoso said. NANA WorleyParsons officials said the first systems will likely require 12 to 18 months of lead time, during which a company could develop the requisite gravel pad infrastructure. The company, which is a contractor for numerous Slope operators, has received interest from several producers, according to Formoso. Not to be discounted is the fact that the MAPS is intended to be a fairly autonomous system with truck drivers transporting liquids being the primary on-site personnel during operations. A single person could monitor a handful of MAPS remotely, thereby reducing safety risks in the event of an accident on the production pad. Finally, decommissioning — whether because of a field being exhausted or full-scale facilitates being completed — is as simple as calling NANA WorleyParsons and telling them to “come get your stuff” company leaders described. That cost is rolled into the lease. Elwood Brehmer can be reached at [email protected]

Young, Murkowski talk immigration, infrastructure, Tongass and pot

The Presidents’ Day recess in Congress gave the Journal an opportunity to sit down with two-thirds of Alaska’s congressional delegation. Rep. Don Young stressed the need to update the nation’s infrastructure, from bridges to icebreakers, and the means to pay for it during a Feb. 19 interview at the Journal office. Sen. Lisa Murkowski highlighted her ongoing efforts to repeal the Roadless Rule in the state as a way to provide Southeast communities with more economic options. Both discussed a similar desire to permanently resolve the in-limbo status of immigrants known as “Dreamers” — children brought to the U.S. at a young age by illegal immigrant parents or relatives — but with differing views on how the issue will play out in the coming weeks. Sen. Dan Sullivan met with the Journal in late December. Young said he wants to see a way for the immigrants to obtain expedited citizenship for those without criminal records and those who are employable or on their way to be if they are still too young to be in the workforce. He added that he doesn’t like referring to them as “illegal” immigrants given the unique nature of their situation. “Some people say that’s amnesty. I’m saying no; if they were born here or came across (the border) unbeknownst to them and they’re living here they ought to have the opportunity just like anybody else,” Young said of the dreamers (so dubbed for a failed immigration bill known as the DREAM Act that would have addressed their status), many of whom are now adults. Law enforcement agencies should focus on stopping illegal immigration, which undermines the efforts of those who attempt to move to the U.S. legally, according to Young. President Donald Trump said last fall that he would end the Deferred Action for Childhood Arrivals, or DACA, program established via executive order by President Barack Obama after six months — on March 5 — if Congress does not reach a deal to settle their status. Murkowski said the current situation does not allow Dreamers to better their situation through education or formal job training because they are technically illegal immigrants, and that helps no one. Young contended the DACA issue wouldn’t be resolved because Democrats in Congress do not want to solve what they can blame Republicans in Congress and Trump for not fixing. He noted that despite Republicans holding majorities in both chambers of Congress, Democrat support for legislation is needed to reach the filibuster-proof 60-vote threshold in the Senate. Murkowski, on the other hand, said, “It’s not dead, I refuse to believe that,” in a Feb. 20 interview. Four bills, including one Murkowski worked on with 25 other Senators, failed last week in the Senate. Murkowski’s bill received 54 votes of the 60 needed to advance. On the budget, Alaska’s senior senator said she is desperate for Congress to get away from passing more continuing resolutions, or CRs, just to keep the government open now that an overall spending deal for the next two years has been reached. The current continuing resolution is good through March 22. On Feb. 8, Congress agreed on a budget deal to raise current spending caps by about $300 billion over the next two fiscal years. The increased spending limits gives appropriations subcommittee leaders more flexibility in drafting agency budgets, Murkowski said, so the new numbers are being worked into prior spending plans that will hopefully result in an omnibus budget package. “If we’re not successful with this (budget) and we need to do a short-term CR I think that would either be six or seven. It’s horrifying; it’s embarrassing; it’s wrong; it shouldn’t be done,” Murkowski emphasized. “Now that we got the budget deal and the caps have been set it’s ‘alright gang, everybody get to work.’” The Tongass Murkowski chairs the Appropriations subcommittee that covers the Interior Department, the Environmental Protection Agency and the Forest Service budgets. In November she released a $32.6 billion discretionary 2018 budget for those agencies with language that would have the Forest Service temporarily stop its transition to exclusively young-growth timber harvest in the Tongass National Forest and permanently exempt Alaska from the Roadless Rule. The Tongass provisions would require the Forest Service to start the process to amend the 2016 Tongass Land and Resource Management Plan by Jan. 31 of next year. The current Tongass plan — an environmental impact statement started in 2013 by the Obama administration — took effect last December and directs forest managers to fully transition to only young-growth timber harvests in the Tongass within 16 years. Murkowski supports eventually moving to young-growth harvests in the nation’s largest national forest but has sided with Southeast loggers who contend the management plan is not based on accurate timber inventories and does not provide adequate harvest volumes to keep what’s left of the region’s timber industry alive. “We need to make sure in the Tongass we have a multiple use management policy. I set out on a strategy — there was no secret to it — I said, ‘within the Tongass we need to have some forest management reforms. If we’re going to have an inventory it needs to be an honest inventory,’” she said. Murkowski couldn’t say whether or not the Tongass and Roadless Rule language would stay in the Forest Service budget bill when the full budget is debated but noted the state is petitioning the Forest Service for an exemption to the Roadless Rule as well. Several attempts by the State of Alaska to secure an exemption to the Roadless Rule through the federal courts or have it thrown out entirely have been unsuccessful. The petition route to a Roadless exemption is lengthy, but Murkowski said the administration is aware of the challenges the Clinton-era order presents and other western states such as Idaho have managed to negotiate exemptions that have benefitted their economies. She added that the Roadless Rule doesn’t only hamper timber harvests, but it also impedes small communities in the Tongass from advancing generally supported infrastructure projects. “In certain parts of Southeast — even though you have so much hydropower — there are certain communities that are not tied into one another and the (energy) costs that they’re facing are just sky high and yet you can’t have some kind of access road to build transmission (lines), to build your renewable energy resource,” Murkowski said. “If nothing happens those villages will die on the vine.” Opponents to the Tongass management changes stress the region’s economy has shifted from timber and fishing to tourism and fishing since the peak logging days of the 1980s and early 1990s. Attempting to revive a marginally economic timber industry will just deter visitors who do not come to Alaska to see logging — not to mention the potential for damage to salmon habitat — they argue. Infrastructure, icebreakers The Trump administration’s scaled-back $200 billion federal infrastructure spending proposal is too small for Young’s liking because it is the federal government’s responsibility to provide a reliable brick and mortar foundation for the country, he said. “We need a universal (transportation) system for economic purposes,” Young said. A $1 trillion infrastructure package was one of Trump’s primary campaign pledges. But adding spending in roads, bridges and airports should not grow the deficit, either, he said. Young supports the president’s 25 cents-per-gallon increase to the federal gas tax as a means to pay for the upgrades. “It seems high; it looks high; I know Alaskans won’t like it but if you want a transportation system someone has to pay for it and we’re $23 trillion in debt. You’re not going to borrow to do that,” he said. The problem with the current gasoline tax of 18.4 cents per gallon is that when it passed in 1993 it was not indexed to inflation and therefore the effectiveness of the tax to support the Highway Trust Fund has dwindled, according to Young. He has long supported other types of highway user fees based on miles driven or other options as well to capture revenue from drivers of electric cars and more fuel-efficient vehicles that use roads but pay less or no fuel taxes. Young said despite broad rhetorical support in Congress he does not foresee a direct appropriation for roughly $1 billion to the U.S. Coast Guard to build a new heavy icebreaker. Instead, he supports providing the Coast Guard an avenue to lease icebreakers long-term, which would also get around a federal statute that requires the Coast Guard to maintain its vessels with the cheapest parts possible, regardless of quality. It’s that mandate that has led to the degradation of the nation’s current small fleet of three icebreakers — one of which, the Polar Sea, has been inactive since a 2010 engine failure. “The ship (would be) maintained by the owner of the vessel and you sign a 25-year contract or a 30-year contract or a 10-year contract, that’s up to the owners. And when you get done as the Coast Guard you decide to release it, then the ship is still in good shape and the owner of the vessel can lease it to another agency,” Young described. Federal cannabis conflict Murkowski and Young reiterated their opposition to legalized recreational marijuana in their state but also held firm on their joint stance that they will support the will of the majority Alaska voters who legalized it and try to remove federal roadblocks to operating a safe cannabis industry in the state. Both said federal laws prohibiting banks from entering the state-legal cannabis trade continue to be a problem. “I don’t like it; I don’t use it but it’s a states’ rights issue to me,” said Young, who is vice chairman of the House Cannabis Caucus made of representatives from states with legalized marijuana use. “I got interested because if you want to cause problems, have too much cash laying around. What I want (cannabis business) to be able to do as a business is work with the banks.” Being unable to use banks has forced cannabis growers and sellers to operate on a cash-only basis, which has made them targets for robberies. Young and Murkowski agreed that a bill changing the marijuana banking restrictions is not likely to make it through the Senate despite the fact that medical or medicinal use is permitted in a 29 states and polls show a majority of Americans support some form of legalization. More states are expected to have marijuana initiatives on 2018 election ballots. “I think you have some resistance from members (of the Senate) who are just so opposed to marijuana legalization in any way, shape or form that regardless of what has happened in their states they’re not willing to move on that,” Murkowski commented. “We are setting up law abiding citizens to be (robbery) victims and that is just wrong,” she continued. “We have got to be able to reconcile this.” Young said he expects Congress to prohibit the Justice Department from spending any money to enforce federal marijuana laws in states where recreational use is legal after Attorney General Jeff Sessions on Jan. 4 issued a memo nullifying the 2013 Cole memo, which said the Justice Department would defer to state laws regarding marijuana. Sessions is a staunch opponent to legalized marijuana and the spending prohibition for recreational use would expand what Congress’ similar directive related to medical marijuana operations. While preventing spending as a means to control agency actions is far from ideal, as both indicated, it’s the best option for the time being, they said. Murkowski added that she found Sessions’ marijuana memo “troubling” because it caught her off-guard. She said to her knowledge no senators were given a heads-up that it was coming, though it could have been different in the House. “(Marijuana enforcement) has almost been kind of left to the U.S. attorney in the respective states for determination as to where they’re going to go,” she said. “That’s not very good policy either. I think it lends to further inconsistencies in application of the laws that are out there.” The Alaska U.S. attorney has indicated enforcing federal marijuana laws is not currently a priority of federal prosecutors in the state. ^ Elwood Brehmer can be reached at [email protected]

State gets incomplete grade from FERC

While Alaska Gasline Development Corp. officials often tout the reams-worth of documents they’ve submitted to federal regulators for the Alaska LNG Project, those regulators responded with a letter Feb. 15 contending the state agency has refused to send information imperative to analyzing the $43 billion megaproject. In a three-page letter to corporation executives — followed by 168 pages detailing AGDC’s alleged shortfalls to provide information for analysis and requests for additional data — regulators wrote that they have repeatedly requested study data from the state-owned corporation during the pre-filing review phase for the project’s environmental impact statement but “an adequate response has not yet been received.” The Federal Energy Regulatory Commission, or FERC, is an agency of the Energy Department that leads LNG export project permitting. It also expects further data on the project’s safety, reliability and engineering plans will be requested, according to the letter. AGDC filed its EIS application for the Alaska LNG Project with the agency last April. At nearly 60,000 pages, AGDC leaders said they believed it to be the largest EIS filing in the history of the National Environmental Policy Act process, which became the federal permitting standard for large projects nearly 50 years ago. According to FERC, AGDC has said it will not provide certain study information because the studies are not required by the state or other entities at this point, the Feb. 15 letter states. Future responses by the gasline corporation that such information won’t be passed along because the state and other federal agencies don’t require it will be deemed incomplete and the requests will be made again. “Certain requests ask for studies to be completed and provided, or information on the specific avoidance and mitigation measures that may be implemented by AGDC for the various proposed construction-related activities. “Rather than providing specific avoidance and mitigation measures to be adopted or describing potential considerations if the construction schedule cannot be maintained, AGDC has deferred providing information to future plans or the permitting phase (e.g., through Alaska Department of Fish &Game Fish habitat permit application or other processes),” the FERC letter states. “It is imperative that the information provided in AGDC’s responses include definitive commitments to implement specific avoidance, minimization, and mitigation measures. Incomplete information or ill-defined commitments by AGDC may compromise our ability to adequately assess and disclose the full impact of the project.” The agency asked for a complete response within 20 days, adding that the information is necessary to continue drafting the EIS. AGDC spokesman Jesse Carlstrom said the corporation’s regulatory experts are drafting a schedule to provide to FERC within the 20-day window as to when the specific requests will be responded to but some of the agency’s questions will require additional field work. “This is a talented team and we’re working fast but to knock all this out in 20 days would be a stretch,” Carlstrom said. He added that FERC wants all of the information it will need to write the EIS up front while AGDC has been operating on the presumption that specific mitigation measures and other detailed, site-specific environmental data would be provided as other state and federal agencies need it for their permit reviews. That’s how the Army Corps of Engineers, which is preparing to release a final supplemental EIS for the smaller Alaska Standalone Pipeline, or ASAP project, has allowed AGDC to operate, according to Carlstrom. “We’ll get FERC what they need,” he said. Leaders of the state corporation have been pushing for FERC to issue its schedule for the project since late last year and have said they hope the significant detail in the many volumes of studies filed in the application would help the agency finish the final EIS by the end of 2018. In a Jan. 22 press release, AGDC announced had responded to all of FERC’s 801 original data requests that were generated from the April filing. Carlstrom and AGDC leaders characterized the latest round of 570 questions as a positive indication that the Alaska LNG Project is at the forefront of the agency’s work. AGDC President Keith Meyer has said the preferred timeline, which he acknowledges is aggressive, is needed to keep the project on track to be in production by 2024-25. That would allow the project to meet a demand window in a global LNG market that has been flooded with supply and driven prices down in recent years. Carlstrom said AGDC leaders are still hopeful FERC will be able to publish a draft EIS by the end of the year, but that would push their ideal timeline back by several months at a minimum. After a draft EIS is published a public comment period of at least 45 days — on very large or contentious projects it is often longer — and associated public meetings are required. The final EIS is then issued once the appropriate comments are considered and incorporated into the draft documents. Ports of consideration Of particular note among FERC’s specific requests attached to the letter are directives to study rerouting the roughly 800-mile gas pipeline to Valdez and ending it at Port MacKenzie — across Knik Arm from Anchorage — instead of AGDC’s preferred pipeline terminus and LNG plant site in Nikiski. Meyer has said repeatedly the plan is to end in Nikiski, noting the state, BP, ConocoPhillips and ExxonMobil spent more than $600 million over the past five years evaluating the Nikiski route and changing to Valdez could take years of additional study time. AGDC officials note the state was a minority partner in the project when Nikiski was selected, owning just 25 percent share of the LNG plant at the time. AGDC took control of the Alaska LNG Project in early 2017. The corporation announced Feb. 8 that it would be opening a one-person office in Nikiski to better interface with area residents who will be directly impacted by the project. The producers have also purchased about 650 acres of land in Nikiski to site the massive natural gas liquefaction plant and marine export terminal at the end of the 800-mile gas pipeline. AGDC is in negotiations to purchase or gain access to the property. The state is also planning to reroute the Kenai Spur Highway, which currently bisects the planned LNG plant site. Previous efforts to export North Slope gas have evaluated a route to Valdez; the final EIS for the Trans-Alaska Gas System released in 1988 determined Valdez to be preferable over Cook Inlet, according to FERC. “AGDC indicated that the difference between the Valdez delivery option evaluated in 1988 and the current alternative alignment is that the Delta and Gulkana Rivers were designated as Wild and Scenic Rivers on December 2, 1980, subsequent to the issuance of the 1988 final EIS, and that the approvals necessary to cross these rivers are an excluding factor,” FERC asserted in its attachment to the Feb. 15 letter. “However, the TAGS final EIS evaluated the Delta and Gulkana Wild and Scenic Rivers along the Valdez delivery option and concluded that ‘there would be no direct impacts to the Gulkana and Delta Wild and Scenic River areas since the route would not cross the designated portions of these rivers.’” The Alaska Gasline Port Authority, comprised of the City of Valdez and the Fairbanks North Star Borough, urged FERC about a year ago to consider routing the Alaska LNG Project to Valdez as it would provide natural gas along the Richardson Highway corridor and save the Fairbanks Borough up to $100 million to build the 30-mile spur line needed to get gas from the large line under the current alignment, local officials said at the time. More recently Matanuska-Susitna Borough officials asked FERC to consider Port MacKenzie on Jan. 9. According to a Feb. 16 borough press release, AGDC dismissed a Port MacKenzie alternative, but according to the borough, it mistakenly studied a shallow-water site about 4 miles north of the actual port. Mat-Su officials contend ending at their port could save the project up to $3 billion because the pipeline — about 50 miles shorter — would not have to cross the bottom of Cook Inlet and as such would be environmentally safer as well. “The Mat-Su Borough fully supports this worthy (gasline) effort and simply requests that our deep draft port be considered, as promised,” Mayor Vern Halter said in a formal statement. Mat-Su Borough spokeswoman Patty Sullivan said in an interview that borough officials learned of the site discrepancy after the EIS application was filed. Carlstrom said Port MacKenzie was removed from consideration when the project was led by the producers’ joint venture because it is classified as a multi-use port and a 20 million tons per year LNG plant spreading over hundreds of acres would preclude other activities. According to Sullivan, the area examined north of the port is referred to as “Point MacKenzie” by AGDC when the actual Point MacKenzie, classified by the U.S. Coast Guard, is a short distance south of the port. The discrepancy has not been explained, she said. Additionally, the borough has long touted Port MacKenzie for its naturally deep water — up to 60 feet at low tide — and the thousands of acres of developable land in the area. “We really are the large industrial port with the least amount of neighbors,” Sullivan said. She emphasized the Mat-Su Borough supports the gasline project, but that officials simply want their proposals vetted appropriately. AGDC officials that have worked on the project since its inception said they were informed of the producers’ choice of Nikiski in 2013 but specifics as to why were not offered and additional examination beyond what the producers — highly experienced in this type of work — had done would have added substantially to costs and potentially delayed the project for years. ExxonMobil project leaders said in October 2013 that Nikiski was the preferred choice out of 20 possible locations because it allows the gasline to feed the state’s largest population centers with a long-term supply of natural gas. The Nikiski site also offers more flat land that is easier to develop along with better access and weather that allows for year-round construction, the producers said in 2013. Carlstrom said avoiding crossing the Chugach Mountains on the route to Valdez was also a factor in choosing Nikiski. “Mountain ranges for pipelines, though not insurmountable obstacles, they’re best avoided and by following the corridor paralleling TAPS from Prudhoe Bay to just north of Fairbanks and then connecting with the Parks Highway corridor we completely avoid that mountain range,” he said. ^ Elwood Brehmer can be reached at [email protected]

FERC says gasline filings still incomplete

While Alaska Gasline Development Corp. officials often tout the reams-worth of study documents they’ve submitted to federal regulators on the Alaska LNG Project, those regulators responded with a letter Thursday contending the state agency has refused to send information imperative to analyzing the $43 billion megaproject. In a three-page letter to corporation executives — followed by 168 pages detailing AGDC’s alleged shortfalls to provide information for analysis and requests for additional data — FERC officials wrote the agency repeatedly requested study data from the state-owned corporation during the pre-filing review phase for the project’s environmental impact statement but “an adequate response has not yet been received.” FERC also expects further data on the project’s safety, reliability and engineering plans will be requested, according to the letter. FERC, an Energy Department agency, is the lead body responsible for permitting LNG exports projects in the country. AGDC filed its EIS application for the Alaska LNG Project with the agency last April. At nearly 60,000 pages, AGDC leaders said they believed it to be the largest EIS filing in the history of the National Environmental Policy Act process, which became the federal permitting standard for large projects nearly 50 years ago. According to FERC, AGDC has said it will not provide certain study information because the studies are not required by the state or other entities, the letter states. Future responses by the gasline corporation that such information won’t be passed along because the state and other federal agencies don’t require it will be deemed incomplete and the requests will be made again. “Certain requests ask for studies to be completed and provided, or information on the specific avoidance and mitigation measures that may be implemented by AGDC for the various proposed construction-related activities. Rather than providing specific avoidance and mitigation measures to be adopted or describing potential considerations if the construction schedule cannot be maintained, AGDC has deferred providing information to future plans or the permitting phase (e.g., through Alaska Department of Fish & Game Fish Habitat permit application or other processes),” the FERC letter states. “It is imperative that the information provided in AGDC’s responses include definitive commitments to implement specific avoidance, minimization, and mitigation measures. Incomplete information or ill-defined commitments by AGDC may compromise our ability to adequately assess and disclose the full impact of the project.” The agency asked for a complete response within 20 days, adding that the information is necessary to continue drafting the EIS. Spokespersons for AGDC could not be reached Friday. Leaders of the state corporation have been pushing for FERC to issue its schedule for the project since late last year and have said they hope the significant detail in the many volumes of studies filed in the application would help the agency finish the final EIS by the end of 2018. In a Jan. 22 press release AGDC announced had responded to all of FERC’s 801 original data requests that were generated from the April filing. AGDC President Keith Meyer has said the timeline, which he acknowledges is aggressive, is needed to keep the project on track to be in production in 2024-2025. That would allow the project to meet a demand window in a global LNG market that has been flooded with supply in recent years. Of particular note among FERC’s specific requests attached to the letter are directives to study rerouting the roughly 800-mile gas pipeline to Valdez and ending it at Port MacKenzie — across Knik Arm from Anchorage — instead of AGDC’s preferred pipeline terminus and LNG plant site of Nikiski. Meyer has said repeatedly the plan is to end in Nikiski, noting the state, BP, ConocoPhillips and ExxonMobil spent more than $600 million over the past five years evaluating the Nikiski route and changing to Valdez could take years of additional study time. The corporation announced Feb. 8 that it would be opening a one-person office in Nikiski to better interface with area residents who will be directly impacted by the project. The producers have also purchased about 650 acres of land in Nikiski to site the massive natural gas liquefaction plant and marine export terminal at the end of the 800-mile gas pipeline. AGDC is in negotiations to purchase or gain access to the property. The state is also planning to reroute the Kenai Spur Highway, which currently bisects the planned LNG plant site. Previous efforts to export North Slope gas have evaluated a route to Valdez; the final EIS for the Trans-Alaska Gas System released in 1988 determined Valdez to be preferable over Cook Inlet, according to FERC. “AGDC indicated that the difference between the Valdez delivery option evaluated in 1988 and the current alternative alignment is that the Delta and Gulkana Rivers were designated as Wild and Scenic Rivers on December 2, 1980, subsequent to the issuance of the 1988 final EIS, and that the approvals necessary to cross these rivers are an excluding factor,” FERC asserted in its attachment to the Thursday letter. “However, the TAGS final EIS evaluated the Delta and Gulkana Wild and Scenic Rivers along the Valdez delivery option and concluded that ‘there would be no direct impacts to the Gulkana and Delta Wild and Scenic River areas since the route would not cross the designated portions of these rivers.’” The Alaska Gasline Port Authority, comprised of the City of Valdez and the Fairbanks North Star Borough, urged FERC about a year ago to consider routing the Alaska LNG Project to Valdez as it would provide natural gas along the Richardson Highway corridor and save the Fairbanks Borough up to $100 million to build the 30-mile spur line needed to get gas from the large line under the current alignment, local officials said at the time. More recently Mat-Su Borough officials asked FERC to consider Port MacKenzie Jan. 9. According to a Friday borough press release AGDC dismissed a Port MacKenzie alternative but incorrectly identified a shallow-water site in its filings about 4 miles north of the actual port, which has naturally deep water. Mat-Su officials contend ending at their port could save the project up to $3 billion because the pipeline — about 50 miles shorter — would not have to cross the bottom Cook Inlet and as such would be environmentally safer as well. “The Mat-Su Borough fully supports this worthy (gasline) effort and simply requests that our deep draft port be considered, as promised,” Mayor Vern Halter said in a formal statement.   Elwood Brehmer can be reached at [email protected]


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