Elwood Brehmer

Concept scrapped for unified Railbelt utility

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

More quake damage adds to troubles at Port of Alaska

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

Gasline agency laying off 60 percent of staff

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

Legislature breaks up over special session location

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

Agriculture Division grapples with managing vetoes

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

Valdez protests AK LNG analysis; Mat-Su Borough satisfied

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

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

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

Dunleavy follows through with massive budget vetoes

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

BLM lifts Alaska land withdrawals, opens 1.3 million acres

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

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

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

Tax credit issue plods along toward Supreme Court

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

Sub-500: TAPS throughput drops in 2019

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

Back from China, AGDC officials await draft environmental report

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

ConocoPhillips buys North Slope Nuna prospect from Caelus

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

B2B meetings give Alaska producers international exposure

Canadian food brokers and marketers recently gave a handful of Alaska startups a taste of what it would take to go international with their products in a first of its kind trade mission. Lyndsey Smith, a marketing coordinator with the state Division of Agriculture who helped organize the business-to-business meetings, said the goal of state officials is simply to help retail-ready Alaska food products gain exposure in a new market. “We are helping build relationships for local Alaska and Made in Alaska businesses to be able to strengthen a secondary market,” Smith said. The initial round of speed-dating style introductions took place the mornings of June 13-14 at the Grand View Inn in Wasilla. Brokers and marketers from across Canada discussed products, market opportunities and challenges with representatives from five Alaska brands in a series of half-hour, one-on-one meetings. The seven-member Canadian contingent then spent the afternoons touring retailers and farms in Anchorage and the Mat-Su area. Pola Schacter Ley of Vancouver said she came to the meetings with the hope of finding natural food products made from as many local ingredients as possible — and she found what she was looking for. “We’re really focused on plant-based; we’re really focused on vegan, clean ingredients and simple and traditional,” said Schacter Ley. She is not opposed to working with meat or protein-based products; however, they require adhering to a much more complex set of regulations when being sent across the border, she noted. A chef by trade, Schacter Ley said she enjoys working with food producers to find ways to tweak or add value to their products or develop new recipes with them. “I’m open to innovative ideas, always,” she said. Schacter Ley and her husband work with a variety of retailers from large “banner” stores to independent grocers, convenience chains and food service providers. The size of the producer company doesn’t matter as much as its backing, she said. Companies need to be on a positive trajectory and have substantial support to enter a new market. “If the company is small and they can’t supply, let’s say a large banner store, that doesn’t mean I’m not going to work with them. We circle around them with independents,” Schacter Ley said, adding that niche products are often a better in smaller retailers willing to try new products. Selling into large chains also comes with listing fees and other costs smaller stores don’t require, she noted. The meetings were set up through Alaska’s membership in the Western United States Agriculture Trade Association, which helped link the Canadian buyers and marketers with the nine Alaska companies looking to grow. “We are excited to offer these meetings to encourage innovative strategies to expand opportunities for Alaska’s agricultural businesses,” Agriculture Division Director David Schade said. “Leveraging our partnership with WUSATA to help agribusinesses find new markets, including international markets, is one of the many important services we provide to private-sector businesses.” Similar meetings are in the works for August to highlight the state’s booming peony and cut-flower industry. Schacter Ley recommended that the Alaska startups trying to enter a new market such as Canada find additional ways to get their products in front of more sellers, such as committing to trade shows and using social media campaigns. “Nowadays you can’t just work with a store. It takes a lot more,” she said. The trade mission didn’t come with a big set of expectations, either. Schacter Ley said she was happy providing advice and perspective from another market for the Alaska companies and making a single connection during the meetings would make the whole trip a success. She and other brokers from New Brunswick and Alberta said they believe Alaska-sourced products have a similar draw in Canada as they do elsewhere, despite the fact that the country and state share many features. “Vancouver loves Alaska,” Schacter Ley said. “It’s got that raw, rugged beauty and I think B.C. has a bit of that same vibe.” Angele Miller, with Edmonton, Alberta-based Abundant By Design Inc., said she believes many Canadian consumers are comfortable with the slightly higher price point that often comes with Alaska-sourced foods because Alaska is seen as “mysterious” and “pure and clean.” “I think people will pay more for Alaska products than if it came from (the Lower 48),” Miller said. Both Miller and Schacter Ley were impressed by Heather’s Choice, an Anchorage-based dehydrated food startup — think backpacking meals with Alaska ingredients. Sales representative Zach Menzel said all of the eight Heather’s Choice breakfast and general meal options are hypoallergenic; they’re free of gluten, dairy, soy and corn. The meals are based on Prince William Sound sockeye, grass-fed bison from Delta Junction and other Alaska-grown foods. The dehydrated meals have a shorter shelf life than traditional freeze-dried camp foods, “but higher quality ingredients — things a five-year-old could pronounce,” Menzel described. “There’s no preservatives, no artificial ingredients, no flavoring agents, nothing like that. Everything is just whole food dehydrated in our kitchen in Anchorage.” Heather’s Choice products are in about 20 Western states and several Alaska outdoor retailers, despite the company being just five years old, according to Menzel. “We’re just trying to aggressively grow this thing,” he said. ^ Elwood Brehmer can be reached at [email protected]

Alaska senators gain support on transboundary mining issues

Senators from the Western U.S. are joining the Alaska congressional delegation to press the issue of Canadian mining practices in transboundary watersheds . The bipartisan group of six senators — Mike Crapo, R-Idaho; Jim Risch, R-Idaho; Jon Tester, D-Mont.; Steve Daines, R-Mont.; Maria Cantwell, D-Wash.; and Patty Murray, D-Wash. — sent a letter along with Alaska Sens. Lisa Murkowski and Dan Sullivan June 13 to British Columbia Premier John Horgan highlighting the steps states and the federal government have taken to monitor transboundary rivers and what they want provincial officials to do in return. They were compelled to send the correspondence because there weren’t enough delegates to the International Joint Commission from either country to hold its biannual meeting in April, according to the letter. IJC spokeswoman Sally Cole-Misch said it took roughly a year for President Donald Trump’s three appointees to the commission to be confirmed by the Senate and Canadian Prime Minister Justin Trudeau appointed three new Canadian commissioners as soon as the terms of those appointed by his predecessor were completed. The panel of six new IJC commissioners was sworn in May 17. The Boundary Waters Treaty with Canada established the IJC in 1909 specifically to settle disputes over watersheds that cross or comprise the international border. For years, members of the Alaska congressional delegation have been asking provincial leaders, and domestically, State Department officials, to address potential water quality problems from large hard rock mines at the upper reaches of transboundary watersheds in British Columbia; this is the first time senators from other border states have formally joined them. In the Lower 48, transboundary concerns have centered on Canadian coal mines. While numerous Alaska environmental, commercial fishing and Alaska Native groups have called for IJC involvement to provide further protection for Alaska salmon fisheries downstream from mining activity, the commission can only be spurred by a formal call from either the State Department or Canada’s Global Affairs Department. Attempts by the Alaska delegation to get former Secretary of State John Kerry to review Alaska’s concerns regarding Canadian mining activity in transboundary watersheds largely proved unfruitful. Concerns over the British Columbia mine permitting process were heightened after the 2014 Mount Polley mine tailings dam failure. The Mount Polley copper and gold mine is in the upper reaches of the large Fraser River watershed, a major salmon producer for Canada and the U.S. A British Columbia auditor general report concluded the Mount Polley dam breach was the result of inadequate engineering and poor oversight from regulators. The senators’ letter notes that the departments of State, Interior and the Environmental Protection Agency set up a joint working group to determine what could be done to safeguard U.S. economic interests related to the commercial fisheries and tourism enterprises that could be compromised by the impacts from upstream mines. Congress last year approved $1.8 million for Interior Department agencies to spend on improved downstream water quality monitoring systems in transboundary rivers. “While we appreciate Canada’s engagement to date, we remain concerned about the lack of oversight of Canadian mining projects near multiple transboundary rivers that originate in B.C. and flow into our four U.S. states,” the senators wrote to Premier Horgan. “To address these concerns, we have taken steps in partnership with our federal and state governments to improve water quality monitoring and push for constructive engagement with Canada. “In sharing an update on our efforts, we hope to encourage you, in your role as Premier, to allocate similar attention, engagement, and resources to collaborative management of our shared transboundary watersheds.” Alaska Tribes and conservation groups insist a host of mines proposed in the Canadian portions of large salmon-bearing transboundary rivers that flow into Southeast Alaska, such as the Stikine and Unuk, could degrade water quality and endanger those fisheries. They also contend Canadian bonding requirements for mining companies are inadequate. “This is a multi-state, international problem for which we need a multi-state, international solution,” United Fishermen of Alaska Executive Director Frances Leach wrote in a formal statement following the release of the senators’ letter. “Right now B.C.’s massive open-pit mines and waste dumps put some of Alaska and B.C.’s most important salmon rivers, and the fishing jobs that rely on them, at risk. Alaska fishermen and the thousands of people across the world who enjoy wild salmon expect and deserve better from B.C regulators.” Former British Columbia Minister of Energy and Mines Bill Bennett said in a prior interview with the Journal that the provincial and federal Canadian governments have environmental protection requirements for mines on par with the U.S. and Alaskans’ concerns come from a lack of adequate communication between the governments on the issue. Bennett is now a director for the British Columbia-based mining exploration firm Eagle Plains Resources Ltd. The Alaska delegation specifically has asked provincial environmental regulators to provide State of Alaska officials, tribes and Alaska Native corporations a formal consultation process during mine permit reviews. In November 2015 former Gov. Bill Walker and then British Columbia Premier Christy Clark signed a memorandum of understanding to create a transboundary Bilateral Working Group to facilitate the exchange of best practices, marine safety, workforce development, transportation links and joint visitor industry promotion. Bennett said at the time that the MOU represented a significant change in how the state and province interact. Last November British Columbia mine regulators began the process of seeking firms to clean up acid rock leakage from the Tulsequah Chief mine in the Taku River drainage east of Juneau. State officials contend the multi-metal mine that operated for just six years has been leaking acid wastewater into the Tulsequah River, which feeds the Taku, since it was closed in 1957. ^ Elwood Brehmer can be reached at [email protected]

Report: US needs more domestic sources for critical minerals

Filling the country’s domestic deficit of numerous minerals and metals has been a priority of the Trump administration, which on June 4 released a plan for addressing what it considers to be a national security issue. The Commerce Department report, entitled, “A Federal Strategy to Ensure Secure and Reliable Supplies of Critical Minerals” lays out the ways in which the administration believes the U.S. can improve domestic control over 31 of the 35 often hard to pronounce minerals designated as “critical” in a May 2018 Interior Department report. Interior’s critical minerals list notes that the country imports more than 50 percent of its supply of 31 minerals and relies completely on outside sources for 14 of those, including graphite and many minerals that are essential for modern energy storage and advanced technologies. For several years, the U.S. imported all of its rare earth elements — used in very small quantities in many electronic devices from smartphones to components for fighter jets — until the Mountain Pass rare earths mine in southern California reopened last year. The Interior Department also highlights the fact that China is the country’s primary source for many of the minerals it imports, which provides leverage to a government the administration is now at odds with over trade issues. The reports were compiled following a December 2017 Executive Order signed by President Donald Trump directing the Agriculture, Commerce, Defense, Energy and Interior departments to prioritize addressing the nation’s critical mineral situation. Among the priorities in the critical minerals strategy is a push for federal agencies to thoroughly assess the country’s resources for the various imported minerals and for specifically the Forest Service and the Bureau of Land Management to reform their land-use planning methods to protect access to those resources. BLM oversees 245 million acres of federal land — about 10 percent of the country — and subsurface mineral rights to roughly 700 million acres. According to the bureau, BLM-controlled lands hold approximately 30 percent of the nation’s minerals. The Forest Service manages nearly 193 million acres. The report states that many mineral deposits cannot be developed because of existing land withdrawals, reservations or other land-use restrictions. It notes that those designations can serve useful purposes for everything from wildlife protection to military use, but recommends the Forest Service and BLM coordinate with the U.S. Geological Survey along with state and Tribal governments and mining industry representatives to evaluate areas with use restrictions for mineral resources. “Any (mineral resource) analysis performed should quantify and qualify the economic and national security implications of: reducing the size of an existing withdrawal, reducing the area affected by a land-use designation, changing planning allocations, or revoking an existing withdrawal,” the report states. It further emphasizes a desire to prioritize reviews of withdrawn areas based on the potential for discoveries of critical minerals. Sen. Lisa Murkowski, who chairs the Energy and Natural Resources Committee, said she welcomed the strategy report in a statement from her office. “(The report) provides clear direction on how to reduce our reliance on foreign minerals and thereby strengthen our economy and national security. I urge the administration to swiftly implement its recommendations, especially those that encourage domestic mineral production and continued research into processing technologies, and will continue my work to compliment these efforts with new legislative authorities,” she said. In May, Murkowski co-sponsored the American Mineral Security Act along with Sen. Dan Sullivan, which, among other things, would require the Interior Department to update a list of critical minerals every three years. The Mineral Security Act would also mandate nationwide assessments for the availability of each mineral on the critical list as well as direct Interior and Forest Service mineral project permitting reforms aimed at reducing the time to reach permit decisions and authorize research for critical mineral recycling or replacement materials. While many policymakers and national security experts regularly raise concerns about the United States’ reliance on China for many of the minerals the country imports — such as graphite, rare earths, bismuth, barite and others — the strategy recommends strengthening trade ties with current geopolitical partners and allied countries that could be preferable sources for some minerals. Bokan rare earths Alaska is rich in many minerals and a deposit near the southern tip of the state has the potential to be a significant domestic source of rare earth elements. The Bokan Mountain rare earth underground mine prospect near tidewater on southern Prince of Wales Island holds more than 4.7 million metric tons of indicated rare earth ore, according to a 2015 resource assessment by Nova Scotia-based Ucore Rare Metals Inc., the company working on the project. That translates to approximately 63.5 million pounds of collective rare earth metals. However, Ucore has shifted its attention away from advancing the mine since 2015 following a drastic fall in global rare earth prices. Instead, the company has focused on developing a small mineral processing facility in nearby Ketchikan by late 2020. Ucore leaders have discussed the prospect of financing at least part of the estimated $25 million strategic minerals complex through the state-owned Alaska Industrial Development and Export Authority. The Alaska Legislature in 2014 authorized AIDEA to issue up to $145 million in bonds to help finance the Bokan mine project, which the company estimated in 2013 would cost $221 million to develop. Ucore CEO Jim McKenzie said recent U.S.-China trade tensions have highlighted the importance of addressing domestic mineral supply issues and have recently boosted prices particularly for heavy rare earth elements. There are 17 minerals defined as rare earth elements, but “heavy” rare earths — such as europium, terbium, and ytterbium with a greater atomic weight — are the most sought after and are used in products that rely on high-temperature magnets. More common lighter rare earths are used in a plethora of applications including LED displays. Heavy rare earths account for roughly 40 percent of the mineralization at Bokan, according to Ucore. “The Bokan deposit is unique in the U.S., with its unusual skew towards these valuable (heavy rare earth elements). Bokan is also unique in its ease of access, its limited projected development cost, and its significant financial backing by the State of Alaska,” McKenzie said in a formal statement. “We applaud the Trump administration for identifying these critical resources and streamlining their route to production.” Ucore officials declined to comment on the progress of the Ketchikan processing facility because of Utah and Nova Scotia court battles the company is in with Utah-based IBC Advanced Technologies, a metal processing technology company Ucore had entered into a joint-venture agreement with. The companies are now in litigation over that agreement. Ucore Vice President Randy MacGillivray did write via email that the company completed drilling and resource assessment work in 2014 and is satisfied with the results of the 2013 preliminary economic assessment of the Bokan project. Once Ucore officials decide to move ahead with the mine, they expect it will require two-plus years of permitting before construction can begin, according to MacGillivray. ^ Elwood Brehmer can be reached at [email protected]

Alaska becomes a ‘First Frontier’ for 5G

GCI is partnering with global telecom giant Ericsson to make Anchorage among the first cities worldwide to have a standards-based 5G data network. The leaders of the Alaska- and Sweden-based companies made the announcement June 18 during a project unveiling at Alaska Pacific University. The transformation to a 5G network will be “one of the biggest initiatives in GCI’s history,” CEO Ron Duncan said. “The result will be a wireline-wireless experience that will provide our customers nearly ubiquitous data connectivity across the city,” Duncan said. GCI has worked with Ericsson for roughly a decade; the companies also partnered on the recently completed TERRA project, which offers fiber-based high-speed broadband internet to more than 80 Western Alaska communities. Ericsson CEO Börje Ekholm said GCI is joining “an elite group of operators” in being one of the first to launch a true 5G network. “Maybe it’s time to rephrase and not call Alaska the Last Frontier, but the ‘First Frontier,’” Ekholm said. The roughly $30 million project will increase Anchorage’s wireless data capacity by 10-fold and will make Anchorage the 22nd city worldwide to utilize Ericsson’s 5G technology, through GCI’s network, according to Duncan. Ericsson is a telecommunications technology developer that sells network infrastructure and software to telecom retailers and others. About 40 percent of the world’s mobile phone traffic occurs through an Ericsson network, according to the company. 5G is a term used for the fifth generation of wireless networks. The speed and capacity of 5G networks will make such data networks increasingly critical infrastructure, Ekholm said, comparing them to bridges, roads and airports, while acknowledging that it’s still unknown what uses others will come up with for the faster networks. He noted that developers did not consider mobile phone e-commerce or banking when building 4G networks. Supporting artificial intelligence, autonomous cars and “smart city” infrastructure were some of the things 5G networks could be utilized for, the men surmised. “What we know is that 10-times speed, 10-times lower latency, 100-times more connected devices per surface area — we will offer a lot of innovation,” Ekholm said. He estimated there will be roughly 1.9 billion 5G subscriptions globally by 2024. Duncan said he expects the Anchorage project to be done by the end of next year, with the first 5G being available in parts of the city early next year. The work will involve installing Ericsson’s standards-based 5G New Radio equipment and software at 82 cell tower sites across the city, according to GCI. Those towers will work in conjunction with “microcells” — through wireline connections in buildings and elsewhere — across the city to fully form the new network, Duncan explained. He said it’s unclear when the company might expand 5G coverage to other parts of the state. Ekholm added partnering with GCI allows Ericsson to test its products in and get feedback from one of the northernmost markets in the world with a harsh climate. Anchorage Mayor Ethan Berkowitz said GCI’s work will help make the city a more competitive place to attract new people and businesses and retain existing ones. “We live in a time of rapid acceleration where we are more connected than ever before, where things are moving more quickly than they ever have in the past. Unless we are on the cutting edge, we will be left behind,” Berkowitz said. For the Municipality of Anchorage, a faster, higher-capacity mobile network will help the city better deploy resources, such as police, monitor more of its assets in real-time and generally operate more efficiently, according to Berkowitz. “I know that GCI is one of our largest taxpayers; Ron reminds me of that periodically and I am sure that he’s going to appreciate the fact that with 5G we will be able to spend his tax dollars much more efficiently,” he quipped. He said the network would have been immensely helpful while officials were responding to last November’s 7.1 magnitude earthquake. AT&T, GCI’s primary mobile phone competitor, announced last year that Anchorage would be part of its 5G network rollout, which was set to be deployed this year and next. So far, the AT&T has updated its network to 5G Evolution in Anchorage, Bethel and Kusilvak in Western Alaska, which enables customers in those areas with 5G-enabled devices to access faster speeds, spokesman Brent Camara wrote in an email to the Journal. “While we have not yet announced specific plans for 5G cities in Alaska, we continue investing in building the network our customers need today and preparing for the future,” he said. Duncan said in a follow-up media briefing that only AT&T customers in Chicago and a handful of other Lower 48 cities are able to realize the benefits of the new networks. He added that rates for GCI mobile data plans shouldn’t change with the deployment of the 5G network, but noted that more expensive, 5G-capable devices are required to harness the network’s capabilities. Elwood Brehmer can be reached at [email protected]

Without Downtown office, Legislature lacks space for Anchorage special session

With the Legislature at a continued impasse over one of his top priorities, Gov. Michael J. Dunleavy has suggested calling a second special session outside of Juneau to deal with the PFD. The Legislature last held a special session outside of Juneau in 2015 at the former Downtown Anchorage Legislative Information Office building. The $44 million, six-story LIO custom-built for the Legislature in 2014 had adequate space and other amenities to hold floor sessions and committee meetings, said Legislative Affairs Agency Executive Director Jessica Geary, but there were significant sound issues at the time. “(Legislators’) main concerns there were sound quality. The walls were not soundproof and they had some problems with recordings,” Geary said. “If you go back and listen to the floor sessions the record is really lacking — so that was one of the biggest concerns and complaints that came up.” The Legislature eventually abandoned that space in 2016 in response to public pressure over spending to cover the $3.3 million annual lease payments the space required, eventually leading EverBank to foreclose on the owners. Legislators also had an opportunity to purchase the building outright for about $30 million, but former Gov. Bill Walker said he would veto the appropriation if they tried. The building is now occupied by the Anchorage Police Department. As an alternative Anchorage LIO space, lawmakers subsequently purchased a Midtown Anchorage office building from Wells Fargo bank for nearly $11.9 million in 2016. Remodeling the building to better suit lawmakers’ needs has brought the cumulative price for the building to approximately $24 million, according to LAA records. Geary said work on the building is ongoing this summer and should be done in August. While the new Anchorage LIO has three committee meeting rooms, it lacks space for the full House and Senate to meet and therefore still won’t be suitable for a special session, according to Geary. “It’s just office space; that’s all it is,” she said. The governor, who hosted a “Restore the PFD” rally June 6 at a Wasilla resort, specifically proposed holding a session at the Wasilla Middle School, where it’s presumed legislators would hear from more Alaskans who support full PFD payments and the governor’s plan for steep spending cuts. However, officials in the Legislative Affairs Agency, which handles business and behind-the-scenes operations for the Legislature, drafted a list at the behest of legislative leaders outlining the complicating issues with holding the session in the school. The agency cited concerns with security, IT networks, a lack of audio and video recording capabilities for committee meetings and floor sessions, and the fact that the governor’s office would control the camera system in the school, which LAA officials concluded “is not appropriate.” “The governor should not have access to security cameras over Legislative space,” the LAA paper states. The most workable places for a special session in Southcentral would be Anchorage’s Egan or Dena’ina convention centers, Geary said. “We could hold floor sessions there. It would take work to get that set up but it is doable because legislators will have their offices and then committee rooms at the LIO,” she added.

Southwest village prepares to harness river in harmony with salmon

A small Southwest Alaska village is trying to integrate the power of an iconic Alaska river into its electric grid without interfering with the millions of salmon that rely on the same water. The Village of Igiugig and Maine-based Ocean Renewable Power Co. are in the midst of a years-long partnership to refine and eventually utilize the company’s RivGen Power System generator in the Kvichak River. The village of about 70 residents sits at the outlet of Iliamna Lake — Alaska’s largest — which feeds the Kvichak that flows another 50 or so miles before emptying into Bristol Bay. The clear waters of the system support some of the largest salmon runs on Earth. Somewhere between 3 million and 7 million sockeye and countless numbers of other salmon pass by Igiugig each year on their way upriver to spawning grounds in Iliamna’s myriad of tributaries. However, the remote location that affords residents the opportunity to live in such a unique ecosystem also comes at a cost that many rural Alaskans are familiar with. Diesel fuel, which is the primary fuel source for power generation, averaged $5.85 cents per gallon last year in Igiugig, according figures compiled by the Alaska Energy Authority. Acting Igiugig Administrator Karl Hill said that fuel is flown into the village in batches of about 3,000 gallons. Those costs translate into residential electrical rates regularly in excess of 90 cents per kilowatt-hour, according to AEA, which the state then subsidizes through the Power Cost Equalization Program to a more manageable effective household rate of around 30 cents per kilowatt-hour. For comparison, recent electric rates in Anchorage were 18 to 20 cents per kilowatt-hour. Power for businesses and most public buildings is not eligible for the PCE funding, which makes the cost of power a major impediment to economic growth across much of Alaska. “We’re looking for any way we can to be more self-sufficient. To have the means to produce our own energy gives us that much more autonomy,” Hill said of the RivGen System. A 35-kilowatt RivGen system, which is 12 feet tall and about 40 feet wide, landed in Igiugig June 6 after being barged across Cook Inlet from Homer to Williamsport, trucked 15 miles up the Williamsport Road to Pile Bay at the east end of Iliamna and finally loaded on a second barge for the final leg of the journey across the length of the massive lake. That followed a May 23 order from the Federal Energy Regulatory Commission that approved a license for a pilot project to run two RivGen units in the Kvichak for 10 years. Sen. Lisa Murkowski, who chairs the Senate Energy and Natural Resources Committee, has supported federal research and grant programs to advance small-scale renewable energy production and integration into small, isolated power grids. According to her office, the Igiugig Village Council is the first Tribal entity in the country to gain federal approval for an in-river power project. “I am so pleased this project will be able to move forward, reducing local diesel consumption and energy prices. Igiugig’s efforts are blazing a trail for marine renewable energy and microgrid solutions around the world — when we prove these technologies can work in rural Alaska, we are proving they can work just about anywhere else on the planet,” Murkowski said in a June 5 statement. According to the FERC license, the single RivGen can produce power at an average annual cost of 78 cents per kilowatt-hour. Company and village officials plan to install the RivGen soon and operate it for up to a year, ORPC project manager Monty Worthington said in an interview from Anchorage just a couple days before he was to leave the city for a summer of working on the system. The lengthy test should prove whether the system can handle its two biggest remaining challenges: big chunks of ice and tiny salmon. Prior late-summer tests of a prototype bottom-dwelling generator indicated through five monitoring cameras that it can coexist with adult salmon and other fish, according to Worthington. “A million-and-a-half sockeye went past the turbines and we saw no adverse impact,” he said. Juvenile salmon, known as smolt, however, also pour out of Iliamna by the tens of millions each spring on their way to the ocean. The sheer numbers of them and the fact that they aren’t as adept as adults at avoiding hazards when in the strong main river current means how the smolt interact with the RivGen unit must be studied closely. As it’s currently designed there is nothing to block fish or other objects from interacting with the RivGen. A large grate to deflect drifting wood or ice could be added, Worthington said, but a screen small enough to deflect smolt would almost certainly disrupt water flow and in-turn the efficiency of the unit. The National Marine Fisheries Service recommended in comments to FERC that the twin-turbine generator be shut down for two weeks during the late May-early June peak of the smolt outmigration. FERC officials are not requiring such a stipulation, but stressed in their order that the interaction be watched closely. Worthington noted that like adult sockeye, the smolt usually stick closer to shore and the surface of the river when on the move. He also compared the leading edge of the five-foot diameter open turbine to a baseball bat, meaning any little fish that swim through it wont get cut by the unit. “They’re better at avoiding than we assume they are and also they just get pushed out of the way by the pressure wave on the front of these (turbines),” Worthington said. Still, a biologist will be on-site continuously during the smolt season to monitor any impacts the RivGen might have on them. “Certainly, if we find out that smolt are getting injured by our device we won’t be operating at that time of year; it’s a no-brainer,” he added. ORPC officials also feel that they will be able to work around ice flows emitting from Iliamna Lake each spring, though the upcoming winter will be the first that the RivGen is in the water. The Kvichak itself is a fairly quick, deep river near the outlet of the lake so it rarely freezes over and the large lake provides unusually stable flows when compared against other large Alaska rivers. Additionally, the chosen installation site is about 15 feet deep, Worthington said, so ice sheets should drift harmlessly over the 12-foot tall RivGen. The site is also immediately downriver from a large shoal that should deflect large chunks of ice. Still, ever more common mid-winter thaws can send ice downriver at unpredictable times and ice jams in a shallow, braided section below the RivGen site could complicate matters, he acknowledged. Keeping the unit in the water and operating year-round is paramount to maximizing the project’s efficiency and driving down its per-kilowatt cost. “It’s a big experiment and we recognize (ice) is probably one of the riskier aspects of the project, but it’s also such an important one,” Worthington said. If it is damaged ORPC will need to devise ways to protect it or pull it from the water easier, he said. If the yearlong test proves successful, the plan is to install a second unit; combined, the two could produce up to 70 kilowatts of electricity and mostly get Igiugig off of diesel-fired power. The village’s powerhouse has 40 kilowatts of generation capacity, according to the FERC license. Village Administrator Hill said the village has plans to purchase large batteries for power storage and is also working with micro-grid developers to better integrate existing small wind turbines into their power system as well. Completely shutting off diesel generation is rarely feasible, as it is needed to mitigate fluctuations in power from variable renewable sources and make up for sudden spikes in demand that — particularly in small isolated communities — can come from a single residence. ORPC believes two fully operable RivGens with the requisite grid upgrades should allow Igiugig to limit its cumulative diesel generation to about four weeks per year, Worthington said. The first unit and several years of shipping, testing and monitoring has been paid in part by federal Department of Energy grants totaling $2.3 million. Those grants required equal private matches for a total project cost of $4.6 million, according to Worthington, who acknowledged it’s a high price for a small village endeavor. “I think they key is this is all a first-build,” he said. “A lot of our construction costs are easily double what even a second unit would be because to build the turbines we had to build molds for them and everything’s sort of like that.” He estimated a second RivGen would cost about $1 million, with costs gradually shrinking for subsequent units. The technology could also eventually be scaled and applied to other river villages and is very applicable to shallow tidal sites near costal communities, he added. Even with another year or two of refinement, Igiugig’s hydrokinetic power project has already been years in the making. ORPC officials first visited the village in 2011 after initially investigating the prospect of testing their technology at the community of Nenana on the banks of the Tanana River south of Fairbanks. Worthington said the appeal of Nenana was that it’s right on the Parks Highway, which would’ve allowed the company to avoid all of the logistical challenges inherent to working in remote Alaska. However, the glacially muddied Tanana didn’t prove cooperative, he said. The dark water made it difficult to monitor fish, debris and even confirm the composition of the river bottom. Meanwhile, Igiugig leaders were starting to seek renewable energy prospects of their own through Alaska Energy Authority programs. “It was clear they really wanted to partner with technology providers to try to do this,” Worthington recalled. “It was an accepting community.” Prototype tests in subsequent years led to development of the latest commercial RivGen model. Hill said the work with ORPC has indeed been a long process, but one that’s necessary to pioneer new technology. “We have a very active village and council — very progressive,” Hill said. “Living next to this wonderful source of power that flows past us 24 hours a day…it’s pretty obvious that if we can harness some of that energy and not harm the salmon and some of the other fish in our area it’s definitely something worthwhile.” Elwood Brehmer can be reached at [email protected]

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