Elwood Brehmer

Gasline leaders face daunting list of tasks

Even small construction projects are often complex in their own ways, but a July 11 legislative hearing emphasized the daunting amount of highly sensitive and technical work that must all be carefully coordinated to successfully thread the $43 billion Alaska LNG Project needle. Held in Anchorage, the joint meeting of the House and Senate Resources committees updated legislators on the progress of the megaproject, which by all accounts would be the largest in the history of the country. Alaska Gasline Development Corp. board of directors Chairman Dave Cruz said the quasi-state group has now secured letters of intent or other memorandums expressing interest in buying LNG from 15 entities. AGDC has announced a handful of those nonbinding agreements since early 2017 signed with some of the world’s largest LNG buyers, but has mostly declined to disclose details, citing commercial sensitivity and the wishes of its counterparties. The notable exception is the November 2017 signing of a joint development agreement, or JDA, with three nationalized Chinese mega corporations, which outlines the prospect of China buying up to 75 percent of the project’s LNG in exchange for financing 75 percent of its cost. The remaining 25 percent of the project’s planned production capacity of 20 million tons per year of LNG would be split among other buyers if a deal with terms similar to the nonbinding JDA is finalized with the Chinese. “I’ve absolutely been amazed at the reception we’ve gotten from the Asian countries. I’m still waiting on a call from (North Korean dictator) Kim Jong Un,” Cruz quipped. East Asia is the key market for Alaska given LNG demand from the region is likely to continue to grow and Alaska’s location is advantageous for selling into Asian — but not European — markets. AGDC Commercial Vice President Lieza Wilcox again stressed that long-term demand for LNG will continue to grow in those markets and overcome the recent supply glut as nations, notably China, move away from coal and nuclear power and towards cleaner and less risky natural gas for power generation. AGDC President Keith Meyer was occupied by a financing meeting with New York investors and was unable to attend the hearing, according to Cruz. Supply negotiations On the supply side, detailed gas sale negotiations with BP, ConocoPhillips and ExxonMobil are ongoing, Wilcox said. AGDC and BP made a big announcement May 7 that they had reached a binding agreement on the key terms of gas price and volume the company would sell into the Alaska LNG system, but further points still need to be hashed out. Gas sale negotiations with ConocoPhillips and ExxonMobil are nearing a similar level of detail as talks with BP, according to Wilcox, who also added that the companies might want to work directly on final agreements and bypass a term sheet, which makes for a longer series of talks before successes are announced. Under the tolling structure AGDC is proposing, the corporation would buy the gas shortly before it enters the North Slope gas treatment plant. AGDC would then sell the LNG at the marine terminal in Nikiski. The final LNG sale price would include the project’s revenue-generating toll that needs to cover all of the project’s costs. Wilcox said the project could afford a toll of about $6 per thousand cubic feet, or mcf, of gas and remain competitive in global markets. AGDC officials also mentioned feedstock gas prices from the producers would likely be in the $1-$2 per mcf range after stating for months that the producers would have to sell gas into the project at about $1 per mcf or less to make price-competitive LNG. AGDC’s Meyer has said the producers should generally be willing to accept a lower price for their shares of North Slope gas than previously expected because they no longer have to invest in the project infrastructure, unless they choose to. Royalty gas However, reaching agreement on commercial terms for gas sales with all three major producers — as important and momentous as it would be — is only part of getting upstream Alaska LNG issues resolved for a successful project, Department of Natural Resources leaders described at the hearing. For starters, administration officials and then legislators must decide if they want the state to get its 12.5 percent royalty portion of North Slope gas reserves in-kind or in-value. Natural Resources Commissioner Andy Mack said at this point the priority for the state is royalty in-kind, or RIK, but that could change. Royalty in-kind refers to the state taking its share as natural gas, instead of receiving payments from the producers for the market value of the resource, which is what would happen if the state took its royalty in-value, or RIV. The state regularly takes its share of royalty oil in-kind and sells it to local refineries in an effort to maximize the in-state economic benefits of oil production. Department officials are also in talks with the producers to get a sense of their preferences regarding royalty gas issues. Those issues include: the RIK or RIV, decision; details around whether the producers will pay gas production taxes in equivalent value volumes of gas, known as tax-as-gas, or TAG; the interplay of gas production from the Prudhoe Bay and Point Thomson fields; and how carbon dioxide disposal impacts other upstream matters. The 35 trillion cubic feet of North Slope gas intended to feed the Alaska LNG Project is about 10 percent carbon dioxide, which must be stripped out of the gas and re-injected underground. “I can’t go any further other than to say we’ve had detailed conversations” with the producers and AGDC, Mack said. “We do have preferences and we’ve expressed those.” Deputy DNR Commissioner Mark Wiggin said the department has a draft RIK-gas sales term sheet that is being discussed with AGDC officials. If the state makes an RIK selection, AGDC will buy the state’s royalty gas to use it in the project, Wiggin said. He also noted that valuing production is a challenge, which makes reaching acceptable RIV calculations all the more complex. “That is not necessarily, by any means, an easy or simplistic path to go down,” Wiggin commented. Additionally, the Prudhoe and Point Thomson lease agreements currently allow the state to switch between RIK and RIV every six months. Rather understandably, the producers would prefer the state to pick one for the duration of the project, which could necessitate amending the leases, he said. Mack also said that he anticipates further discussions on how to align what is happening in the project with the 2012 Point Thomson Settlement Agreement, which specified how the high-pressure gas field would originally be developed and expanded depending on whether a large natural gas project moved forward. ExxonMobil operates the Point Thomson field. Alaska LNG state investment While DNR is working on the litany of technical resource management issues for the project, Department of Revenue officials said they are busy preparing recommendations for state investment in Alaska LNG based on numerous possible scenarios. Deputy Revenue Commissioner Mike Barnhill said the department’s investment analyses is based on the high-level assumption that the state would fund about $11 billion, or 25 percent, of Alaska LNG’s overall $43 billion estimated cost. From there, it needs to be determined what portion of that $11 billion investment would be direct equity injections and how much would be raised through debt. AGDC’s Meyer has long said he envisions the project being funded through roughly 75 percent debt and 25 percent equity investment. The project’s contracts and other financial arrangements will be structured to allow debt to be “non-recourse,” according to AGDC leaders, meaning the loans would be underwritten by LNG sale contracts. In that scenario, if LNG buyers fall short on their payments, in-turn shorting AGDC’s revenue stream and ability to service its debt, the banks would seek repayment from the end buyers and not the state corporation. Barnhill commented that the risks inherent in such a large project are not necessarily bad. “Ultimately, you’re trying to answer the question: Is the projected return commensurate with the expected risks? Are you being compensated for the risk? Now, we want risk in an investment context. We want to be commensurately compensated for that risk,” he said. “Obviously, the more that this project can be structured with no recourse to the state is a good thing.” Wilcox said AGDC doesn’t expect there to be any risk to the stat in the gas sale agreements with the producers as the wholesale gas price would be passed on to LNG customers. Maria Tsu, Revenue’s gasline financing specialist and a former investment director with the Alaska Permanent Fund Corp., said the department is modeling investment scenarios and risks based on likely commercial terms AGDC can secure and then looking at potential disruptions to those assumptions. For example, the department is analyzing how construction delays could impact the project’s economics over its expected initial life of 25 years. She noted that de-risking the project can make investors — the state or others — more comfortable with it but at the same time likely means lower returns. “I think there will need to be state participation in order for the project to move forward and prevent the state’s equity interest from being diluted and for the state to not lose control it will be important for the state to provide both possibly development capital as well as construction capital to the project,” Tsu said. Investing when construction risks are largely settled would likely lead to lower, but stable, infrastructure-type returns in the 8 percent to 10 percent range, according to AGDC and Revenue officials. Meyer has stressed that investors willing to sacrifice high returns in exchange for reliability would supply the bulk of the project’s equity investments. Sen. Bert Stedman, R-Sitka, who manages an investment firm, emphasized that cost overruns of up to 20 percent — beyond the $9 billion of contingency costs built into the $43 billion Alaska LNG estimate — are often considered a relative success for megaprojects. He urged Revenue officials to test the impacts of overruns in the $20 billion to $30 billion range, which he said are not out of the realm of possibility for the project that had an original estimated cost range of $45 billion to $65 billion. He further requested the department analyze the financials of specifically Arctic infrastructure developments given the inherent challenges of building in that environment. “I don’t mind betting the cow but I won’t bet the farm,” Stedman said of the state’s role in financing Alaska LNG. Elwood Brehmer can be reached at [email protected]

In one of final acts at EPA, Pruitt updates Alaska wetlands management

In his final weeks leading the agency, former Environmental Protection Agency Administrator Scott Pruitt issued a memo reemphasizing the unique abundance of wetlands in Alaska and outlining how the EPA will manage them. The joint memo, signed June 15 by Pruitt and Assistant Army Secretary for Civil Works R.D. James, replaces longstanding guidance in prior memos from 1992 and 1994 covering wetlands mitigation. The U.S. Army Corps of Engineers manages Clean Water Act Section 404 wetlands fill permits under the direction of the EPA, which has ultimate say over if and how often-sensitive wetlands areas are developed. Pruitt abruptly resigned as EPA administrator July 5. Southeast Alaska Land Trust Executive Director Allison Gillum said she sees the memo as largely clarifying the language in Clean Water Act requirements and regulations with the recognition that wetlands management in Alaska is a much different task than it is in the Lower 48. Gillum also attended a stakeholder meeting the EPA held in Anchorage to discuss how the guidance will be applied by the agencies going forward. “I felt like they just wanted to remind people that there’s room in the rule for doing things (in Alaska) kind of outside how they are done in the Lower 48. I’m not really sure what’s going to come of it,” she said. The Southeast Alaska Land Trust is an in-lieu fee wetlands mitigation sponsor. An in-lieu fee sponsor organization is certified by the Corps of Engineers to take on the responsibility of finding wetlands to preserve that will offset those damaged by a project. The 10-page memo highlights the agencies’ mitigation sequence, describing when avoiding, minimizing or compensating for wetlands disturbances is warranted. “Given the unique climatological and physiographic circumstances found in Alaska, it is appropriate to apply the inherent flexibility provided by the guidelines to proposed projects in Alaska. Applying this flexibility in a reasoned, commonsense approach will lead to effective decision-making and sound environmental protection in Alaska,” the memo states. The members of Alaska’s all-Republican congressional delegation have for years stressed that more than half the state is classified as wetlands — accounting for more than 60 percent of the remaining wetlands in the entire country — and therefore the stringent requirements for wetlands protections used in the Lower 48 should not apply to Alaska. “When the Lower 48 were being developed, they didn’t need to deal with today’s onerous regulatory restrictions. I am encouraged to see EPA and the Army Corps recognizing these issues,” Sen. Dan Sullivan said in a formal statement accompanying the memo. “I hope we can continue to work together to set up a practical regulatory structure that protects our watersheds and cleans up existing environmental problems, while allowing us to build the projects we need to build in Alaska.” EPA Region 10 spokeswoman Suzanne Skadowski wrote in an emailed response to questions that the new guidance is meant to improve consistency and remove ambiguity regarding the agencies’ authority to be flexible in making decisions on when to require compensatory wetlands mitigation. In Alaska, compensatory mitigation usually means preserving an undisturbed wetlands area to offset filled wetlands elsewhere, Gillum noted, while in the Lower 48, compensatory mitigation is often aimed at restoring previously damaged wetlands areas. “The updated guidance ensures fair and transparent implementation of mitigation requirements across Alaska,” Skadowski wrote in response to whether or not the guidance loosens mitigation requirements in light of the Trump administration’s overarching push to ease federal regulations. “Practicable,” a key word in determining what shall be required to meet the EPA’s mitigation standards, is defined in the memo as “available and capable of being done after taking into consideration cost, existing technology, and logistics in light of overall project purpose.” When avoiding or compensating for development impacts to wetlands is not practicable, minimizing wetlands impacts will be the main means of complying with Clean Water Act requirements, according to the memo. “In Alaska, minimization of impacts has been in many circumstances the only mitigation required,” the memo notes. The memo also explains that compensatory mitigation over larger watershed scales could be appropriate for Alaska given that options to offset wetlands losses on a more localized scale are often limited. Gillum said looking at using larger watershed scales allows for more flexibility when compensatory mitigation is required. “Our service area is all of Southeast Alaska, so we could see an impact in Ketchikan and we could potentially offset it in the Juneau area; depending on a lot of different factors,” she said. Additionally, it states that “applying a less rigorous permit review” for projects deemed small, with minor environmental impacts, is consistent with Clean Water Act regulations. The guidance does not lay out quantitative thresholds for determining major versus minor impacts — that is decided on a case-by-case basis — but it outlines what should be considered in making that determination, according to Skadowski. Gillum added that she found it interesting that the memo points out the challenges of wetlands development, specifically on the North Slope. “I feel like it could be setting it up to defend certain decision that the EPA and the Army Corps might be making on big projects in that area but I don’t necessarily feel like the memorandum said anything completely new,” Gillum said. ^ Elwood Brehmer can be reached at [email protected]

Reprocessed state seafood exports exempted from Chinese tariffs

It appears the blowback from President Donald Trump’s trade dispute with China will fall on some, but not all of Alaska’s seafood exports to the country. The Trump administration’s 25 percent tariff on an estimated $34 billion of goods imported to the U.S. that took effect July 6 prompted Chinese leaders to respond with their own 25 percent tariff on U.S. goods headed for their country, including seafood, Alaska’s primary export. National Oceanic and Atmospheric Administration Fisheries Director of International Affairs John Henderschedt said June 28 that seafood products destined to be reprocessed and re-exported from China will be exempt from the tariffs after agency officials discussed the issue with the U.S. Embassy there. While a positive development for Alaska fishermen and processors, the cumulative impact the tariffs could have on the commercial fishing industry in the state is still unknown, Alaska Seafood Marketing Institute Technical Program Director Michael Kohan said in an interview. Overall, Alaska exported more than $4.9 billion of goods in 2017, of which more than $2.4 billion was seafood, according to the state Office of International Trade. China bought $1.3 billion worth of Alaska’s exports last year, including $796 million — nearly a third — of the state’s total seafood exports. Kohan said leaders at ASMI, the state’s flagship seafood advocacy group, have been wondering what role the tariffs would play in their industry since they were officially announced June 15. She noted that the ever-shifting dynamics of the volatile industry make it difficult to pin down exactly how much Alaska seafood stays in China and how much is sent back out after value-added processomg. Part of the challenge of tracking the Chinese market is that it has grown rapidly, according to Kohan, which of course is a good thing. Prior to about 2003, China bought minimal amounts of Alaska seafood — less than $100 million per year — mirroring demand growth in the country for other Alaska products as well. “We do know that higher end species are consumed domestically, so those are geoducks, sea cucumber, crab, sablefish; and most of the species that are going to be reprocessed and re-exported are pollock and pink and keta (chum) salmon,” Kohan said. Adding to the challenge of trying to quantify and track what goes where is the fact that each processing company sends different volumes of various products to different countries every year, Kohan said further. “With a billion dollars of seafood exports to China it’s a very serious issue for Alaska and could have potential effects on harvesters,” she said. “However, it’s too soon to know the full impact on Alaska seafood harvesters or the state’s overall economy.” Chris Woodley, executive director of The Groundfish Forum, a trade association the for Bering Sea Amendment 80 factory trawler fleet, said the vast majority of U.S. exports of frozen seafood to China are reprocessed to be shipped out of the country later. Such U.S. exports to China that are then re-exported are not subject to Chinese duties or the countries value-added tax because imposing them would just raise the cost of the products when they are resold. Kohan said the true impact of the tariffs should be better known in the coming weeks as more geoducks and other seafood is shipped to China and processors begin making decisions on where to send their products now that the tariffs are in place. If those impacts prove to be unworkable, the seafood could be sent elsewhere in the future, but that move would be gradual as well, she said. “Alaska seafood has a strong and growing demand worldwide. The products that are being exported to China now could fill markets for Alaska seafood such as South Korea, Japan, Brazil, the U.K., northern and southern eastern Europe are all large markets for us so there’s a great network for Alaska seafood internationally,” Kohan said. “However, as with the (2014) Russian embargo, these shifts in markets take time to develop and so we will see possibly some changes but obviously we’ll be searching to develop our other strong markets with these seafood products in the future.” ^ Elwood Brehmer can be reached at [email protected] Correspondent Jim Paulin in Unalaska contributed to this report.

Despite slight production dip, state oil revenue grows in FY18

Oil production was down a bit but higher oil prices likely afforded the State of Alaska a little more revenue than expected during the 2018 fiscal year. The final cumulative tally for North Slope production in fiscal year 2018, which ended June 30, was 190.3 million barrels, or an average of 521,398 barrels per day. In March, the Department of Revenue issued its Spring Revenue Forecast with a daily 2018 North Slope production prediction of 521,800. North Slope production in fiscal 2017 averaged 526,500 barrels per day, making for a decline of about 0.9 percent. The spring publication is a regular update to the annual Revenue Sources Book the department publishes each fall. The spring forecast, which usually provides greater accuracy than the one done released each December, is meant to provide legislators with more current information as they plan out the state’s budget for the upcoming fiscal year. The situation for oil prices was much the opposite. Revenue officials in the spring forecast upped their fiscal 2018 Alaska North Slope average oil price projection to $61 per barrel from $56 per barrel last fall. Similarly, the price estimate for 2019 was increased to $63 per barrel from $57. Alaska oil sold for $49.43 per barrel in 2017. Revenue was supposed to increase by $200 million-plus in fiscal years 2018 and 2019 based on the higher price assumptions in the spring forecast, but that will likely rise further given the actual average price for the 2018 fiscal year was higher yet at $63.61 per barrel, or 4.3 percent greater than the spring prediction. Revenue officials wrote via email that because June taxes aren’t collected until late July it is still too early to provide a preliminary estimate, but higher oil prices of late should push the state beyond the $2.3 billion forecast for unrestricted General Fund tax and royalty revenue during the year by at least $100 million, they said. The indeterminate increase in revenue will help pay down the state’s budget deficit, which has previously been pegged at about $700 million for fiscal year 2019, which began July 1. In May the Legislature passed operating and capital budgets totaling roughly $4.7 billion to largely be paid with unrestricted General Fund revenue of about $2.3 billion and about $1.7 billion from the Earnings Reserve Account of the Permanent Fund. The remaining deficit will be filled out of the Constitutional Budget Reserve savings account, which held $2.3 billion on June 30, according to the Revenue Department. The Fall 2017 Revenue Sources Book originally pegged fiscal 2018 North Slope oil production at 533,400 barrels per day. That would have been the third consecutive year of production growth from the large oil basin after many years of decline. However, Revenue officials said when the spring forecast was released in March that higher than normal temperatures on the Slope were hampering the efficiency of production facilities and leading to less oil being pulled from the ground each day. As a result, North production is expected to rebound to 526,600 barrels per day in fiscal 2019, according to the spring forecast. ConocoPhillips is scheduled to bring its Greater Mooses Tooth-1 oil project online late this year, which the company expects should provide up to 30,000 barrels of new oil per day. Additionally, leaders of the small independent Brooks Range Petroleum Corp. have said they expect to produce several thousand barrels per day of oil starting in early 2019 from their greenfield Mustang oil development. Production on July 9 almost matched the 2019 estimate at 526,489 barrels, but production for the first nine days of 2019 averaged 481,9000 barrels per day. It is common for summer production figures to be significantly lower than winter as facility efficiency is diminished and regular Trans-Alaska Pipeline System maintenance work during the warmer months forces production to periodically be reigned in. A spring surge in oil prices has helped Alaska oil start fiscal 2019 with an average price of about $79 per barrel, which is 25 percent more than the $63 per barrel expected average. Former Department of Natural Resources official and economist Ed King, who now manages King Economics Group, wrote June 29 that his firm is projecting average oil prices in the $80 range for the next 12 months. King added that the gross value of Alaska’s North Slope oil in fiscal 2018 was roughly $12.1 billion, of which he expects the state to ultimately collect about $1.9 billion in unrestricted revenue. That does not account for mandatory royalty payments to the Alaska Permanent Fund and other dedicated allocations. Elwood Brehmer can be reached at [email protected]

Field hearing focuses on improving efficiency at SBA

A senator from Idaho gave up part of his July Fourth recess to spend time talking business in Alaska. Senate Small Business and Entrepreneurship chairman Sen. Jim Risch, R-Idaho, held an oversight hearing at the Loussac Library in Anchorage June 29 to get feedback from Alaska business leaders on how Small Business Administration programs are working — or not — to help them navigate the complex world of federal contracting. Risch deferred much of the hearing to Sens. Dan Sullivan and Lisa Murkowski, who participated despite not being on the committee, as they are more familiar with the issues facing Alaska small businesses, he said. He held the hearing in Anchorage at Sullivan’s request. Risch said its critical to hear directly from those that participate in the federal programs because the SBA helped small businesses contract for more than $105 billion of federal work last year. Federal contracting for Alaska small businesses grew by more than $200 million last year, according to Risch. “The key, whether it’s the U.S. economy, or the Alaska economy, is small business growth,” Sullivan said in his opening remarks. Travel issues prevented Murkowski from attending the early portions of the hearing, but she participated in later rounds of questioning the business owners. When she did arrive, Murkowski emphasized that even a state as small, population-wise, as Alaska, has 71,000 small businesses. “We are small business. That is what we do here,” Murkowski said. Witnesses from Alaska Native corporations and professional trade sector businesses consistently stressed that federal regulations often make it difficult for the SBA to efficiently administer the guidance to the small businesses it is tasked with assisting. The specific regulations and requirements can vary greatly amongst the different assistance programs the SBA offers, but Associate SBA Administrator for Government Contracting Robb Wong largely concurred with that sentiment, saying the agency is continually working to ease those challenges. Wong said he first worked for the SBA at a lower level and moved to the private sector before returning to government, so he understands both sides of the equation. “I’m a sales guy by nature and I truly believe that if you have a better mousetrap people won’t beat down your door if they don’t know you have a better mousetrap,” Wong said. He acknowledged that the SBA’s business opportunity specialists, who work directly with small business owners seeking help, are “burdened by compliance work” to keep businesses eligible for the SBA’s federal contracting programs. For starters, he said the agency is looking at increasing the number of these specialists in Alaska and is working on a new website that will be easier to navigate and hopefully make it easier for business owners to help themselves. Additionally, the SBA is making strides in helping government contracting officers understand and use the small business programs it offers, Wong said. Sullivan said he’s hopeful a new interpretation of a provision in the 2010 Defense authorization bill that aimed to limit sole source federal contract awards at $20 million without high-level agency approval will again increase the government contracting dollars flowing to Alaska Native corporations. Known as the Section 811 provision, members of Alaska’s congressional delegation have been pushing to reverse the law since it was enacted, contending it was “airdropped” into the bill with no debate. Alaska Native regional and village corporation subsidiaries are heavily involved in multiple areas of federal contracting through the SBA’s 8(a) program, which aims to help minority and “socially and economically disadvantaged” small business owners by allowing them to receive sole-source government contracts generally capped at $6.5 million, according to the SBA. The 8(a) program provides those eligible small businesses with preferential consideration for government contracts. After much pressing, Sullivan recently got the military branch secretaries to reread and reinterpret the Section 811 language. It was previously believed the secretaries were required to sign off on any sole source contract over $20 million — which rarely happened given their other duties. “Those contracting opportunities essentially went to zero from hundreds of millions (of dollars),” Sullivan said. Based on the new reading that authority could be delegated to others who are able to focus more on such contract reviews. According to a 2012 Government Accountability Office report, the number of sole-source contracts to 8(a) businesses fell from an average of about 50 per year from 2008-2010 to about 20 per year after enactment of Section 811 in 2011. Chugach Alaska Corp. CEO Gabe Kompkoff said the 8(a) program helped the regional corporation’s leaders to build their business skills and processes in the early years after it was formed. “The SBA’s business development program proved to be the missing link for (Alaska Native Claims Settlement Act corporations),” Kompkoff testified. He pushed back against critics who characterize the 8(a) program as a government handout to the Native corporations, stressing that they still have to perform well on the contract to get follow-on work. “We believe the customer is receiving greater value in the work we do,” Kompkoff said. He and other Native corporation leaders who testified also noted their businesses also have an obligation to the overall wellbeing of their shareholders that other businesses do not. “The problem we have with the (Alaska Native corporations) is they’re misunderstood,” Wong added. “Nobody understands the responsibility they have to take care of their people.” Kompkoff said he was able to attend college only through scholarships Chugach provided. Sullivan noted that many Native corporations’ shareholders are from rural Alaska among the most economically depressed regions in the country. Elwood Brehmer can be reached at [email protected]

Pruitt calls for curbs on Clean Water Act vetoes

Environmental Protection Agency Administrator Scott Pruitt issued a memo June 26 directing staff to write regulations aimed at limiting the agency’s ability to block development projects that impact wetlands. Pruitt’s goal is to stop the agency from using its historically broad authority to overrule U.S. Army Corps of Engineers decisions regarding Clean Water Act Section 404 wetlands fill permits before a permit application is filed or after a permit is issued and a project is underway. The Corps of Engineers reviews wetlands fill permit applications on behalf of the EPA, but the Clean Water Act gives the EPA the power to overrule a Corps decision if agency officials determine a project would have unacceptable impacts on wetlands areas or other water bodies, which Pruitt cited in the document. The decision has nationwide consequences, but Pruitt noted in the memo that the move largely stems from the EPA’s actions under the Obama administration’s attempt in 2014 to block the hotly contested Pebble mine project in the Bristol Bay region before the Pebble Partnership had applied for its Section 404 permit. Pebble submitted its 404 application to the Corps last December, which triggered an environmental impact statement review given the large scope of the proposed mine and ancillary facilities. “Today’s memo refocuses EPA on its core mission of protecting public health and the environment in a way that is fair and consistent with due process. We must ensure that EPA exercises its authority under the Clean Water Act in a careful, predictable, and prudent manner,” Pruitt said in an EPA release. The four-page edict, specifically directed at the agency’s Office of Water, further requires regional administrators to ask EPA headquarters officials for permission to initiate an action to restrict a development at the end of the environmental review process. Subsection 404(c) of the Clean Water Act outlines the EPA’s authority to issue such project “vetoes.” Pruitt wrote that he wants the regulations drafted within six months. The EPA has not often invoked its Section 404(c) authority — using it 13 times since the Clean Water Act was passed in 1972. However, Pruitt notes in the memo that regulations guiding how the agency implements its 404(c) power haven’t been updated since 1979 and a “long-overdue” update will provide certainty to landowners, businesses and investors hoping to advance development projects. “I am concerned that the mere potential of the EPA’s use of its Section 404(c) authority before or after the permitting process could influence investment decisions and chill economic growth by short-circuiting the permitting process,” he wrote. The possibility of EPA using its 404(c) veto authority was behind a 2010 decision by the Corps to initially deny ConocoPhillips a permit to build a bridge over the Colville River to reach its CD-5 development; the EPA favored an underground pipeline and no bridge. ConocoPhillips appealed that Corps decision and it was reversed to allow construction of the bridge to begin in 2013, which prompted a lawsuit by environmental groups and a few villagers from nearby Nuiqsut. The Corps decision to allow the bridge was ultimately upheld and CD-5 has been producing since 2015. Pebble sued the EPA twice in 2014, first contending the agency overstepped its authority by moving towards, but not finishing, a Section 404(c) veto before the company had applied for its permits. That suit was thrown out by federal Alaska District Court Judge H. Russel Holland because the action had not been finalized and therefore the issue was not ripe for adjudication. Another suit argued the agency had colluded with anti-mine activists in reaching what Pebble claims was a predetermined conclusion that the mine would be an irresponsible development amongst salmon habitat. Holland issued an injunction in that case, halting the EPA from further steps to preemptively stop Pebble, and that suit was ultimately settled out of court in May 2017. The settlement allowed Pebble to apply for its 404 permit with parameters on when the EPA could revisit a Pebble veto in the future. Pruitt’s push to end preemptive and retroactive 404(c) actions is seemingly at odds with his January decision to stop short of withdrawing the Obama-era proposed restrictions on Pebble. The aforementioned EPA-Pebble settlement called for the agency to start the process of withdrawing the proposed mining restriction, but did not require it to be finalized. An agency statement at the time said the EPA has “serious concerns” about the impacts of mining activity in the Bristol Bay watershed and public comments in stakeholder meetings stressed the importance of the world’s largest wild salmon fishery. Additionally, Pruitt said his decision would not derail Pebble’s ongoing permit review. However, he wrote in the June 26 memo that the Corps can process permit applications and conduct an EIS while a 404(c) action is ongoing, but the Corps cannot issue a permit with an outstanding 404(c) proposal. A spokeswoman for the EPA’s headquarters office did not respond to emailed questions in time for this story. Conservation and Bristol Bay-area fishing and Native groups commended Pruitt in January but hammered his latest memo. “Earlier this year Administrator Pruitt made a very strong statement regarding his concerns about the large, adverse impacts of the Pebble mine,” Trout Unlimited Government Affairs Vice President Steve Moyer said in a prepared statement June 27. “His concerns make our point. Some projects are so destructive of irreplaceable resources that they should be nipped in the bud. We urge Administrator Pruitt and the EPA to reconsider the position stated in the memo and instead, look for ways to protect aquatic treasures and fulfill the promises of the Clean Water Act.” On May 3, 18 members of the Republican-heavy Congressional Western Caucus and resource development advocates sent a letter to Pruitt urging him to lift the proposed restrictions on Pebble. The letter noted Pruitt’s history as an advocate for economic and resource development, but asked “that the proposed (veto) determination be withdrawn, as was originally planned.” It also contends that the decision is at odds with the administration’s position of making mineral development a top priority. Rep. Don Young, a member of the Western Caucus leadership group and a critic of the EPA’s attempt to stop Pebble before the permits were applied for, did not sign the letter. Elwood Brehmer can be reached at [email protected]

Dillingham village corp. acquires majority stake in Bristol Alliance cos.

Bristol Bay Native Corp. announced June 26 that it has sold off a majority interest in a large group of its subsidiaries, but not only are those companies staying in Alaska, they are staying in the Bristol Bay region as well. A controlling share of the large group of Bristol Alliance companies was purchased by Choggiung Ltd., the village corporation for Dillingham, in what company leaders believe is a first-of-its-kind deal between a regional and village Alaska Native corporation. The Bristol Alliance companies are a group of eight construction, environmental and business support service companies based in Anchorage that are heavily involved in federal contracting, a common industry among Alaska Native corporation subsidiaries. BBNC will retain a minority interest in the Bristol companies, according to a press release from the regional corporation. “We are thrilled to see Bristol Bay village corporations like Choggiung gaining ground in the federal contracting arena,” BBNC CEO Jason Metrokin said in a formal statement. “We are confident the Bristol Alliance of companies have a bright future ahead under Choggiung’s leadership. BBNC looks forward to continuing to identify unique economic development opportunities in Bristol Bay.” Choggiung Ltd. President Cameron Poindexter said in a brief interview that the transaction gives his corporation the opportunity to provide additional benefits to its more than 2,100 Alaska Native shareholders. “This acquisition presents an extraordinary opportunity for Choggiung to grow its capabilities and build its financial strength,” Poindexter said. Beyond the basic benefit of providing potentially larger dividends, the Bristol Alliance partnership will help Choggiung provide more job opportunities, workforce training and development assistance and increased scholarship support to its shareholders, according to Poindexter. It will also grow Choggiung’s current workforce of about 90 by more than 250 employees, he added. Poindexter and Metrokin both thanked the federal Small Business Administration for helping complete the deal. The SBA had to approve the deal because two of the Bristol Alliance companies — Bristol Prime Contractors and Bristol Site Contractors — are currently participating in the agency’s 8(a) federal contracting program for small businesses owned by minorities or individuals coming from an economically or socially disadvantaged situation. The government’s broader goal is to award at least 5 percent of all federal contracting dollars to 8(a) eligible companies each year. The SBA approved the deal June 20 and it is expected to close July 31, according to BBNC. Metrokin said further that the sale was born in part out of BBNC’s In-Region Government Contracting Initiative, which the regional corporation started in 2014 to offer area village corporations mentorship, training and joint-venture opportunities in the federal contracting realm. Choggiung participates in the initiative. “This historic partnership demonstrates the potential value the In-Region Government Contracting Initiative can bring to Bristol Bay village corporations. Choggiung has worked hard to get to this point, and BBNC hopes to continue to find more opportunities with village corporations across Bristol Bay through the IGC program,” he said. Elwood Brehmer can be reached at [email protected]

Bill to pay tax credits signed, but lawsuit puts bond sale on hold

Gov. Bill Walker’s administration filed a motion in state court June 25 to dismiss a lawsuit challenging the constitutionality of a plan to sell bonds to pay off more than $800 million in oil and gas tax credits, but state attorneys are not pushing the most obvious argument to have the case thrown out. Assistant Attorney General Bill Milks filed the documents in Juneau District Superior Court contending former University of Alaska Regent Eric Forrer, who filed the public interest lawsuit May 14, did not correctly state a claim for relief in his complaint. Milks also argued against Forrer’s challenge of a provision limiting lawsuits questioning the constitutionality of the plan to within 45 days after the administration’s House Bill 331, which authorized the bonds, because the bill hadn’t passed when the suit was filed. He further wrote that several other states have enacted similar provisions limiting the time in which bond sales can be challenged and Alaska has similar laws relating to other public finance issues. “These statutes reflect an understanding that delay, because of litigation, might impair a public agency’s ability to operate financially, be troublesome to third parties, and decrease the marketability of bonds issued by public agencies,” Milks wrote. Milks continued that because the lawsuit was filed before the clock on the 45-day limit had started, “Forrer’s claim as to the application of the statute is thus moot.” Deputy Revenue Commissioner Mike Barnhill said in a brief interview that the administration would hold off on a bond sale, at least initially, while Forrer’s lawsuit is still ongoing. The concern is the litigation could impact the marketability of the bonds. “Impacting the marketability of course impacts the economics of the transaction,” Barnhill said, as interest rates for the bonds would undoubtedly be much higher if the state tried to sell them while the lawsuit is active. The state will reevaluate the situation this fall and determine what to do going forward depending on the status of the lawsuit, according to Barnhill. The Walker administration hopes that paying off the credits in a lump sum will restart investment by small producers and explorers in Alaska’s oil and gas fields that has been slowed by three years of less-than-full credit payment amounts while the Legislature and the administration debated how to resolve the state’s large budget deficits, according to Revenue Commissioner Sheldon Fisher and supporters of the plan in the Legislature. Forrer and his attorney acknowledged in interviews shortly after the suit was filed that by filing it preemptively — HB 331 had not yet passed the full Legislature and been signed by Walker, although all indications were it would be — they had left themselves open to a ripeness argument because the plan was not yet law. However, they said they would simply re-file the suit after Walker signed the bill if it was dismissed on ripeness grounds. Administration officials said the state likely would not ask for dismissal based on the timing of the suit because doing so would just drag out a legal process they want resolved as quickly as possible. Walker said when he signed the bill June 20 in Fairbanks that he expects to see new jobs and increased oil and gas exploration work stemming from the new law. “Alaska’s economy is on the right track thanks to progress we made this year by working together across party lines to advance innovative solutions, including the one that became law today,” Walker said. The lawsuit alleges the bond sale would commit the state to debt outside of the restrictions the Alaska Constitution puts on the Legislature’s ability to incur financial liabilities. Administration officials contend the plan, drafted by Fisher, is legal because the 10-year bonds would be “subject to appropriation” by the Legislature, which the bond buyers would be aware of, and therefore would not legally bind the state to make the annual debt payments. The state Constitution generally limits the Legislature to bonding for debt through general obligation, or GO, bonds for capital projects, veterans’ housing and state emergencies. In most cases the voters must approve the GO bond proposals before the bonds are sold. State corporations can also sell revenue bonds, but those are usually linked to a corresponding income stream and only obligate the corporation to make payments, not the State of Alaska as a whole. Legislative Legal Division attorneys in an April 13 opinion questioned whether the Alaska Tax Bond Corp. that HB 331 authorizes Fisher to set up would truly have a revenue stream that could pass legal muster given it would rely on annual legislative appropriations to fund the debt payments. Sen. Bill Wielechowski, D-Anchorage, raised the potential constitutionality issues in the first hearing on the plan in February. Fisher said in testimony on the bill that the department planned to sell roughly $800 million in bonds sometime in late July or August and another, much smaller bond sale would be needed in a couple years to pay off the remaining credits that companies have earned but not yet claimed from the state. A backstop provision authorizing the state to allocate up to $100 million for companies holding credits that chose not to participate in the bond plan — they would take a up to a 10 percent discount on the amount they are owed to get the money right away and insulate the state from borrowing costs — was also included in the operating budget. Barnhill said the $100 million could also be used to pay companies if a bond sale is delayed because of the litigation, but that likely wouldn’t happen until sometime in 2019. The administration calculated the minimum fiscal year 2019 tax credit payment at roughly $184 million. ^ Elwood Brehmer can be reached at [email protected]

Veteran industry engineer questions aspects of AK LNG plans

A longtime Japanese LNG industry engineer is raising fundamental concerns about the schematics behind major portions of the $43 billion Alaska LNG Project. A semi-retired process engineer from Tokyo, Keiji Akiyama said in multiple interviews that he believes the Alaska Gasline Development Corp. is on a path to repeating the mistakes made in numerous other large LNG projects across the globe without wholesale changes to the design of the LNG plant with capacity of 20 million tons per year planned for the terminus of the project in Nikiski. Akiyama, most recently a senior LNG technical advisor for INPEX Corp., Japan’s largest oil and gas company, according to his resume, said he began following the Alaska LNG Project after an industry friend asked him to review the design of the small Kenai LNG plant when ConocoPhillips put it up for sale in late 2016. That plant has since been sold to Andeavor Corp., which also owns the Nikiski-area oil refinery. Akiyama, with more than 40 years in the industry, said he was peripherally involved in Alaska’s early gasline ventures 20-plus years ago but hadn’t tracked more recent efforts to monetize the North Slope’s huge gas resources. Since, though, he has been involved primarily as a contractor in many LNG developments throughout the Middle East, Southeast Asia, Australia, and most recently Russia’s Arctic Yamal project. “I saw that it’s a good opportunity to look into some detail. I know how people tend to think about energy projects from my experience; so I have focused on how most people will look at this project with a primarily commercial view or even, as you say, a political view, but not technical view, no,” he told the Journal. “That is always an issue because from my experiences if plant doesn’t work as expected it’s extremely painful, extremely painful and sometimes it will kill the country because of the size of the project.” Akiyama prepared a 26-slide PowerPoint presentation for AGDC and added that he has come to understand the bind declining oil revenues have put the State of Alaska in how and important the Alaska LNG Project could be for the state. “If government will see an unexpected result, it’s really a disaster for everybody and if I can do something I should do it as expert of technical aspect,” he said. Plot points The issues he insists he has identified largely relate to the layout of the massive Alaska LNG plant, which would be located on a parcel of more than 600 acres. A simple overhead view, blueprint-style illustration of one of the three LNG trains planned for the plant, which Akiyama refers to as a “plot plan,” shows rows and rows of heat exchanger fans running east-west across much of the structure. Akiyama is concerned the heat exchangers are situated too close to the compressors that intake air to start the chilling process. That’s because the fans release air hot with waste heat from the liquefaction and if the compressors intake the hot air it could severely hamper the efficiency of the plant, requiring more fuel gas to produce the LNG product. AGDC leaders have long touted the plant efficiency advantage Alaska maintains over LNG projects in warmer climates for the simple reason the air used in the system won’t need to be cooled quite as much. Akiyama compares it to multiple air conditioning units, acknowledging Alaskans might not be as familiar as most people with the appliances. “If you have a so-called outside unit in your garden, you have a lot of warm air coming out. Air conditioning machine is exactly the same as LNG, same thing,” he said. “Finally, all warm air will come up from air-cooled heat exchangers, particularly propane condenser. Propane condenser will release a lot of warm air and most people will never install a lot of air conditioning machines in your garden too close to each other.” The documents he referenced, at one point labeled confidential, are part of AGDC’s public filings with the Federal Energy Regulatory Commission to support the project’s environmental impact statement application. Nikiski’s summer winds could add to the issue of hot air recirculation, according to Akiyama. He said most plants are designed with prevailing wind in mind, but the focus is usually on the average prevailing wind direction over an entire year. Cold Alaska winter winds need not be accounted for, Akiyama said, but Nikiski’s common summer wind blowing up Cook Inlet from the south-southwest could compound the impact of the hot air recirculation by blowing the hot air into the compressors. Hot air recirculation has hampered production at a number of LNG plants worldwide, according to Akiyama. The West Australian, a newspaper in Perth, has reported that Chevron’s massive Gorgon project on an island off the country’s coast — pegged at $37 billion when it was started in 2009 and finished for $54 billion — has seen its expected production cut by 13 percent because of the problem. It could cost the company up to $500 million per year and challenge Chevron’s ability to meet its contracts, according to a report from the paper. “I got in a big fight with them,” said Akiyama, who worked as a contractor on Gorgon. “‘Don’t do it; don’t do it; let’s think, stop,’ but they didn’t listen. That is the very first LNG project for Chevron.” He said further that hot air recirculation has caused the North West Shelf LNG project, also in Australia, to completely shut down at times. Akiyama said he informed Masatoshi Shiratori, AGDC’s marketing representative in Tokyo, of his concerns, but he wasn’t aware if they had been relayed to officials in Anchorage. AGDC spokesman Jesse Carlstrom wrote in an emailed response to questions that it does not appear Shiratori discussed Akiyama’s conclusions with anyone in Anchorage. AGDC engineers do not believe hot air recirculation will be an issue, according to Carlstrom. “The hot air flow was checked with seasonal wind speed and direction considered, and additional heat exchanger capacity was added as appropriate for the project economics,” he wrote. “The seasonal wind directions in Nikiski are well-known, and this was factored into the simulation.” At a more basic level, Akiyama also questioned whether the layout of the plant allows enough room for maintenance cranes to maneuver amongst the fixtures. While the plot plan illustrations Akiyama has studied are relatively simple sketches, he contends much can be gleaned from them and they are among the most important documents for a large project. “So although the plot plan once completed is merely a drawing, we have to think and imagine from various aspects. So it takes a long time to train people to develop the plot plan. Looks like a very simple drawing but actually it is not. A lot of consideration for process, safety, construction, everything — of course, money,” he said. “So once I have a plot plan on my desk I can tell it is more or less ok or a very bad job or so-so. And although they didn’t disclose a lot of technical documents, fortunately or unfortunately, they have disclosed the most important document, site layout.” Akiyama believes the issues are fundamental enough to warrant redrafting and resubmission of the documents to FERC, which he notes could set the project back by a year or more. He suggested extending the LNG trains to farther to the east into what is now planned as a lay down area. AGDC President Keith Meyer is pushing hard for making a final investment decision on the Alaska LNG Project in late 2019 or early 2020 — which is later than he initially targeted after the state took over the project in 2017 — or as soon as FERC issues a favorable record of decision. The documents submitted to FERC were largely compiled when ExxonMobil led the project and then transferred to AGDC at the start of 2017 and Akiyama said he doesn’t understand why a company with significant experience in LNG would put together what he sees as significantly flawed work. “Most of the points I have described here are obvious and easy to find so they should be fully aware from day one. So I’m curious why they have done this kind of work — very unusual for ExxonMobil,” he said. ExxonMobil has referred all questions about the project documents to AGDC since the state-owned corporation took over Alaska LNG. AGDC pointed to ExxonMobil when it was discovered that maps developed early in the project work outlining prospective LNG plant sites marked an incorrect location for Point MacKenzie, near the port the Matanuska-Susitna Borough has advocated as a potential site for the plant. Carlstrom said via email that the designs in question were done by a joint venture between contractors CB&I and Chiyoda Corp during the two-year-plus pre-front end engineering and design, or pre-FEED, period that ended when AGDC took over the project in January 2017. He added that the designs are current but they will likely be updated as the last phase of the project before an investment decision is made and when performance guarantees are made. Economics of gas treatment Finally, Akiyama said he wonders whether or not the project can be economic in part because of the high content of carbon dioxide in the raw natural gas and the North Slope location of the gas treatment plant, or GTP. The carbon dioxide, upwards of 10 percent, must be stripped out and sequestered back in the reservoir at the GTP. Usually, gas treatment and LNG plants are integrated to take advantage of operational efficiencies. “We need a lot of energy to pull carbon dioxide out. So GTP consumes a lot of energy, also,” he said. Traditionally, GTP plants use waste heat from the gas turbine engines that drive the LNG compressors to help in the process of stripping the carbon dioxide out of the raw gas, according to Akiyama. Gas for Alaska LNG must be piped as utility-grade gas for use by communities and industrial work along the corridor. Without the ability to join the plants, the Alaska LNG Project will have to burn comparatively more gas than other LNG plants to power the North Slope GTP, Akiyama said. Elwood Brehmer can be reached at [email protected]

BP America chief: Pursuit of efficiencies meeting ‘dual challenge’

At BP, the motto is “reduce, improve, create,” according to Susan Dio, president of the London-based oil major’s America division. Dio spoke June 20 to a crowd gathered in Anchorage for the Resource Development Council for Alaska’s annual membership lunch. Her speech largely focused on how one of the world’s largest oil companies plans to match its business objectives with the larger, global need for cleaner, if not clean, energy supplies. It’s what BP is calling the “dual challenge.” “We’re working to reduce emissions in our operations, improve our products and create new low-carbon businesses,” Dio said. She noted that the expected increase in future energy demand will be driven less by population growth than a rapidly growing global middle class. According to BP’s annual Energy Outlook, which examines all aspects of global energy consumption and production, worldwide economic output is projected to increase by nearly 75 percent by 2040 as more than 2.4 billion people move to the positive side of the poverty line. “Over that same period, we project that global energy demand will increase by 35 percent,” Dio said. “Interestingly, the entire increase will come from developing countries, most notably, China and India.” Oil industry advocates have long touted affordable energy supplies — primarily fossil fuels — as a building block for developing nations. China in particular is embarking on a major overhaul of its energy consumption away from coal and towards natural gas as a feedstock for electrical generation. Not coincidentally, three of the country’s large government-owned companies are potential lynchpin partners to buy from and finance the $43 billion Alaska LNG Project that BP is assisting the Alaska Gasline Development Corp. with. BP and AGDC also announced in May that they had reached agreement on North Slope gas pricing and volume terms should Alaska LNG continue to move forward, the first time a producer has taken that step for an Alaska gasline proposal. However, Dio also stressed that even under the most aggressive global energy transition scenarios the company has forecast for the next 20-plus years, traditional energy sources will still represent the lion’s share of the world’s energy consumption. Oil and natural gas currently account for 57 percent of the world’s energy mix, with coal totaling 28 percent and all other supplies combining for the remaining 15 percent, according to BP’s Energy Outlook. “Even in a scenario thought to be consistent with meeting the Paris climate goals, fossil fuels still account for more than 50 percent of total energy in 2040, and oil and gas alone account for more than 40 percent,” she said. Under that scenario, hydropower and other renewables would make up 41 percent of worldwide energy sources. Coal usage would decline the most — down to 10 percent of the energy portfolio — with nuclear power growing from 4 percent to 8 percent of the overall supply. BP estimates that if current energy policy and technology trends persist, fossil fuels will still comprise nearly three-quarters of global consumption in 2040, with renewables collectively making up 21 percent of the energy mix. That is despite the fact that renewable energy sources are currently the fastest-growing energy source in history, according to the company. It’s important to note that all of the projections are based on overall energy demand increasing by roughly one-third by 2040, which means consumption of energy from a given source could increase even if the source becomes a smaller portion of the global energy portfolio in years to come. That all means business operations will have to become much more energy efficient, at least for BP, to meet broader carbon emissions reduction goals. Dio highlighted one of BP’s chemicals plants located in South Carolina as an example of the company’s efforts on that front, among others. “In 2017, BP’s Cooper River plant completed a modernization project that will allow the site to reduce the amount of electricity it purchases from the grid by 40 percent and cut up to 110,000 tons of carbon emissions per year, while also boosting production by 10 percent,” Dio said. She said further that the company’s 26 freight and crude tankers are more than 20 percent more fuel efficient than its older vessels and the six LNG tankers BP is building now will be about 25 percent more fuel efficient than their predecessors. Additionally, BP, which sells more traditional natural gas in North America than any other company, is also the largest supplier of renewable “biogas” — derived from methane-producing organic waste — to the country’s transportation industry, according to Dio. The company is also a strong proponent of carbon pricing mechanisms. “In BP, we continue to believe that carbon pricing must be a key element of any such (emissions reduction) approach as it provides incentives for everyone — producers and consumers alike — to play their part,” CEO Bob Dudley wrote in the 2018 Energy Outlook report. The state’s draft Climate Change Policy released in April by Gov. Bill Walker’s administration recommends Alaska develop its own carbon pricing plan. BP Alaska President Janet Weiss is on the governor’s task force that generated the climate policy objectives, a fact that Dio said BP is “enormously proud” of. “We’ve been urging policymakers to remember that energy production and environmental protection are not mutually exclusive,” she said. “The world can have the energy that powers economic growth and lifts people out of poverty while also reducing greenhouse gas emissions. New look at Prudhoe As for Alaska, Dio was quick to emphasize that BP has managed to hold oil output steady at Prudhoe Bay since 2015 — not a small feat considering the size and age of the oil field that has been producing oil for more than 40 years. “BP Alaska has been a global leader in deploying enhanced oil recovery technology. For many years now, this technology has helped us increase production at Prudhoe Bay. We’ve also become more efficient through increased well work,” Dio said. Operational advancements of late have improved the company’s efficiency on the North Slope from 80 to 85 percent, which equates to between 10,000 and 15,000 additional barrels of oil from Prudhoe, according to Dio. She also announced that the company will be conducting a 3D seismic shoot of the entire Prudhoe Bay field next year using its internal proprietary technology. “The survey will provide high seismic coverage to support new drilling and well work, which will help us further prolong the life of the field,” Dio said. ^ Elwood Brehmer can be reached at [email protected]

Independents team up on Nanushuk play

Several small explorers are teaming up on the hope of cashing in on the North Slope’s hottest oil play. Australian-based 88 Energy Ltd. announced Monday that it has agreed to a partnership with Anchorage-based Great Bear Petroleum Corp. to drill its leases adjacent to the successful Horseshoe exploration well and sidetrack drilled in early 2017 by Armstrong Energy. The Horseshoe well extended the prospective Nanushuk formation play more than 20 miles south of Pikka Unit — in which Spanish major Repsol also holds a significant position — and Armstrong estimates holds roughly 1.2 billion barrels of primarily Nanushuk-sourced oil. CEO Bill Armstrong said when the Horseshoe results were announced that the well is a strong indicator that the Nanushuk resource in the area could be double what is known in the Pikka Unit. Armstrong has since sold a portion of its position in Pikka to Oil Search for $400 million, which has operations in Papua New Guinea and takes over as the operator of Pikka July 1. The four leases totaling about 22,700 acres in the agreement with Great Bear are north and west of 88’s large tracts of state leases and the targeted drilling area is about four miles west of the Horseshoe well. According to an 88 Energy release, the companies believe the area could hold 400 million barrels of Nanushuk oil based on 3D seismic data. The drilling consortium also includes the Australian firms Red Emperor Resources and Otto Energy, which currently holds an 11 percent interest in the leases; Great Bear holds the remaining 89 percent. Upon finalizing the deal 88 Energy will hold the largest interest in the leases at 36 percent and manage the drilling program. Red Emperor will hold a 31.5 percent stake in the acreage, followed by Otto Energy at 22.5 percent and Great Bear will be a 10 percent working interest owner. However, the agreement also allows for Great Bear to buy back another 10 percent stake before the well is spud. Drilling costs estimated at $15 million and a $3 million state performance bond will be funded by the three Australian companies, unless Great Bear executes its additional 10 percent buy-in option. In that case, Great Bear will fund 20 percent of the expenses based on its ownership stake, according to an 88 Energy release. Great Bear holds interests in leases totaling 384,000 acres, according to Chief Commercial Officer Pat Galvin, and has also focused much of its previous exploration work south of the producing North Slope fields. “We’re a small exploration company so we’re always looking for partners,” Great Bear’s Galvin said in a brief interview. 88 Energy holds rights to roughly 475,000 acres of contiguous state leases south of the developed area of the North Slope. It is currently flow testing the Icewine-2 well it drilled in early 2017 on the Franklin Bluffs drilling pad along the Dalton Highway about 35 miles south of Deadhorse. The company is targeting the HRZ shale formation in that work, which is believed to be a source rock for the Nanushuk and Torok plays. 88 Managing Director Dave Wall said in a formal statement that the partnership provides an entrance into “one of the most prospective oil plays in the world,” for the company’s shareholders. “Preparations for drilling are now underway and commencement of the exploration well is scheduled in less than nine months,” Wall said further. This coming winter Great Bear also plans to reenter and test the Alkaid well it drilled in early 2015 — also south of established Slope oil development — according to Galvin. The company would also like to drill additional wells on its southern Slope acreage but doesn’t have plans to at this point in 2019, he said. Elwood Brehmer can be reached at [email protected]

Army Corps releases final EIS for in-state gasline

The environmental review for one Alaska natural gas pipeline is complete. The U.S. Army Corps of Engineers released the final supplemental environmental impact statement for the roughly $10 billion Alaska Standalone Pipeline project, or ASAP, on Friday morning with a short list of options for smaller, in-state gas delivery proposal. The final supplemental EIS was originally scheduled to be out in March. Alaska Gasline Development Corp. Senior Vice President Frank Richards said in a prepared statement that although only one can be built, AGDC is advancing parallel gasline efforts for ASAP and the Alaska LNG Project at the direction of the Legislature and that both projects have benefitted from data sharing with similar impacts along the pipeline routes. The much larger Alaska LNG Project would require expansive gas treatment and LNG plants on the Slope and in Nikiski, respectively. ASAP needs a North Slope gas conditioning facility, but does not include a terminal LNG plant given there are no initial plans to export gas from the project. “The final SEIS for the ASAP project sets the stage for AGDC to build a pipeline from the North Slope of Alaska and better positions the Alaska LNG Project for success. AGDC will leverage this federal approval in our work with the Federal Energy Regulatory Commission to advance the Alaska LNG Project expeditiously as the federal agencies are now intimately familiar with the environmental conditions along this common alignment,” Richards said. As AGDC’s regulatory lead, Richards has advocated for FERC to utilize the Corps’ evaluation of the wetlands impacts of ASAP in its drafting of the Alaska LNG EIS, which is ongoing. AGDC notes the pipeline corridors for Alaska LNG and ASAP are virtually identical and therefore evaluation of the route does not need to be duplicated. The primary differences in the two pipelines is the line for the ASAP project, meant for in-state gas use, is 36 inches versus the 42-inch Alaska LNG pipe and would stop near Big Lake in the Matanuska-Susitna Borough. The Alaska LNG line would continue south, cross beneath Cook Inlet and end at the LNG plant in Nikiski. "This is yet another milestone for the Alaska Gasline Development Corporation and further proof the federal government is committed to making sure the Alaska LNG Project moves thorugh regulatory processes expeditiously," Walker posted on his Facebook page June 22. "Thanks to AGDC's staff, Board Chair Dave Cruz, and President Keith Meyer for working hard to make this happen!" The ASAP project is commonly referred to as the state’s “backup plan” to pull natural gas off the North Slope. Its genesis predates even the concept of the commercial export Alaska LNG Project being pursued by Gov. Bill Walker’s administration with support from BP. Accessible Cook Inlet natural gas reserves that heat and power much of Southcentral Alaska were dwindling in 2009 when the Legislature formed AGDC as a wing of the Alaska Housing Finance Corp. The subsidiary of the state mortgage bank was tasked with developing a project plan to provide North Slope gas for in-state use. The AGDC-AHFC in-state pipeline work culminated in late 2012 with a design and final EIS for a 737-mile, 24-inch high-pressure pipeline also capable of carrying natural gas liquids from the North Slope to a tie-in to Southcentral’s gas network just north of Wasilla at rough cost of $7.7 billion. The capital cost for the pipeline, a 12-inch offshoot line to Fairbanks and a gas conditioning facility on the Slope did not fully address financing mechanisms that could’ve added to the $7.7 billion estimate depending on how the project was funded. In the spring of 2013, legislation was passed to stand up AGDC as a separate state corporation. It also included a $355 million lump sum, which funded a revised ASAP plan — what AGDC is working on now. The latest iteration of an in-state pipeline is a lower pressure, 36-inch buried pipeline to carry utility-grade natural gas that is ready for a wider array of uses. As designed, ASAP would carry up to 500 million cubic feet of gas per day. With current in-state consumption at about 250 million cubic feet per day when averaged over a year, project officials have said the excess capacity could supply new resource or industrial developments along the pipeline corridor. The Alaska LNG Project has a planned daily capacity of about 3.5 billion cubic feet of gas per day. Overall, the two alternatives for the 36-inch pipeline plan vary little; they follow the same corridor from the North Slope to the Point MacKenzie area except for a roughly seven-mile stretch where the pipeline would skirt the edge of Denali National Park. AGDC proposed a route that runs just east and outside of the Park along the short section of the Parks Highway that is inside the Park boundary. The Corps drafted an alternative that more closely aligns with the highway through the Park because of 2013 federal legislation authorizing a pipeline route through parts of the Park, according to the final EIS. Additionally, the Corps evaluated the prospect of an above ground pipeline for the first 62 miles coming off the Slope as well as an aerial crossing of the Yukon River. Corps officials wrote that other agencies participating in the supplemental EIS expressed concerns about burying the pipeline along the Arctic coastal plain. “If the active layer of insulation is disturbed during construction (i.e., trenching), permafrost could be vulnerable to thermokarst and subsidence during the summer due to exposure to higher temperatures. In addition, [the] U.S. Fish and Wildlife Service specifically requested consideration of elevating the pipeline on vertical support members for the first seven miles through the Arctic coastal plain where ice-rich, saturated soils and continuous permafrost are found. The first 30 miles in particular contain a high density of oriented thaw lakes, which provide important habitat for North Slope species,” the document states. Unlike other federal agencies, the Corps does not issue its recommendation on which, if any, project alternative should be advanced until a record of decision is issued after a mandatory 30-day public review period for the final EIS. Elwood Brehmer can be reached at [email protected]

‘Poison pill’-free Interior Dept. spending bill moves ahead

Sen. Lisa Murkowski is touting her Interior and environment budget bill as much for the process behind it as what’s in it. Alaska’s senior senator emphasized in a June 14 call with reporters that the $35.8 billion fiscal year 2019 discretionary spending bill passed unanimously out of the Senate Appropriations Committee earlier that day, which she said is a sign that Congress might finally be returning to regular order when it comes to funding the government. Murkowski chairs the Appropriations subcommittee covering the Interior Department, Environmental Protection Agency and the Forest Service. “As of (June 14) we have moved through over half of the appropriations bills,” of which there are 12, Murkowski said. “All, all of them on a strong bipartisan basis, many of them, like we did with the Interior bill, unanimously. So it’s a new day on the Appropriations Committee and I’m optimistic about our way forward, but we’re going to have to be diligent to stick to a commitment to achieve results and not just send a message.” The messages she referenced are political ones inserted into spending bills that otherwise don’t belong there. “We had to stand down on some of the controversial provisions that have been included in years past that have been the poison pills,” Murkowski said further. “One person’s priority can be another’s poison pill.” Those poison pill messages that have in part been to blame for the government funding process that has been derailed in recent years. As far as anyone can tell, 2010 was the last time an Interior budget bill moved through the Appropriations Committee with bipartisan support, according to Murkowski. Since then the spending bills have largely moved on party lines only to get rolled into omnibus bills in good years and scrapped for continuing budget resolutions other times. Murkowski called that practice, which has become commonplace, simply “a bad way to run a government. Some call me overly optimistic but I need to believe that we can fix an appropriations process that has just been allowed to flounder.” Murkowski acknowledged everyone in the Senate, she included, has participated in the troubled process. Last November Murkowski released a similar, $32.6 billion Interior budget bill for fiscal year 2018 with language calling for the Forest Service to temporarily stop its transition to young-growth only timber harvest from the Tongass National Forest, amend the Tongass Management Plan and exempt the Chugach and Tongass National forests from the controversial Roadless Rule. Those provisions were ultimately scrapped from the $1.3 trillion omnibus spending bill Congress passed in late March amid the looming threat of a government shutdown. She said Appropriations chairman Sen. Richard Shelby, R-Ala., made it a priority to return to the regular order of vetting and voting on the 12 annual spending bills when he took over the committee. Murkowski also thanked ranking Interior Appropriations Subcommittee Democrat New Mexico Sen. Tom Udall for gathering support amongst his caucus members to move the bill. Udall echoed Murkowski in a formal statement, noting the bill is “free of poison pill riders,” but he also stressed it does not include deep cuts to the EPA, and Indian Health Service budgets proposed by the Trump administration. “I thank Sen. Murkowski for her work and chairman Shelby and ranking member (Sen. Patrick) Leahy for their commitment to regular order. As this and other appropriations measures are considered, I am committed to working together to adequately fund the federal agencies and programs that provide New Mexico and Americans with the services and protections they deserve,” Udall said. Shelby noted in a June 19 statement that President Donald Trump vowed he wouldn’t sign another omnibus spending bill after approving the one in late March. He said the committee had passed seven of the 12 appropriations bills and was on track to consider all of them before the July 4 recess. “What has been truly remarkable, however, is not the speed of the fiscal year 2019 appropriations process, but the bipartisanship that has given it new life,” Shelby said. “All seven of the bills passed by the committee thus far have garnered overwhelmingly bipartisan support. Most of them, in fact, have been approved unanimously. This is no small accomplishment in today’s partisan political environment.” Interior appropriations Getting bipartisan support typically means spending, and Murkowski’s bill includes increases to the National Park Service’s deferred maintenance and construction budgets along with a $234 million increase to the Indian Health Service budget. The IHS funding includes $192 million for water and sewer infrastructure upgrades in Tribal communities as well as $30 million for construction of Tribal and Alaska Native health care facilities. “This is a very important bill for Alaska, very significant for Alaska. I say that this bill is about land, water and people,” Murkowski commented. The bill also provides $4.3 billion for wildfire suppression efforts, which is the 10-year average funding level, and another $900 million in anticipation that the regular funding will not be enough, according to Murkowski’s office. Specifically to Alaska, it provides $9.5 million for legacy well cleanup in the National Petroleum Reserve-Alaska and $7 million for the U.S. Geological Survey to conduct assessments in the NPR-A to improve topographical and geological mapping. It also includes $22 million that should allow the federal government to fulfill its requirements to transfer selected lands to the State of Alaska and Alaska Native corporations, according to Murkowski’s office, among many other provisions. Elwood Brehmer can be reached at [email protected]

Coastal Villages study renews fight over CDQ quota allocations

A new study reaffirms that large and long-standing inequities still exist in a federal program aimed at improving the economic situation in Western Alaska. Coastal Villages Region Fund commissioned the report conducted by the Seattle-based research firm Community Attributes Inc., which concludes the fisheries allocations in the Community Development Quota Program prevent the groups representing the poorest regions in Western Alaska from fully achieving their mission. Coastal Villages is the CDQ group for 20 villages on the Yukon-Kuskokwim Delta, which is one of the most economically depressed regions not only of Alaska, but the country as well. The Western Alaska CDQ Economic Needs Report notes that Coastal Villages serves 35 percent of the population meant to benefit from the program, yet has access to just 24 percent of the pollock, about 18 percent of the crab and 17 percent of the Pacific cod quota dedicated to the CDQ Program. Those fisheries quotas are allocated amongst the six CDQ groups that cover residents within 50 miles of the Bering Sea coast in an area starting north of Nome on the Seward Peninsula south and west through Bristol Bay and out the Aleutian chain. Overall, the CDQ Program is allocated 10 percent of federal groundfish fisheries quota as a means to keep more of the economic benefits from the fisheries in the region. The program was established in 1992 and is part of the federal Magnuson-Stevens Act fisheries management law. Comparatively, the Aleutian Pribilof Island Community Development Association, or APICDA, covering communities on the western Alaska Peninsula and the island chain, and the Central Bering Sea Fishermen’s Association, or CBSFA, dedicated to St. Paul Island, represent just 2 percent and 1 percent of the total CDQ population but get 14 percent and 5 percent of the program’s pollock quota, respectively, according to the report. It states further that Coastal Villages represents 41 percent of the total CDQ population that lives on incomes below 125 percent of the federal poverty line while APICDA and CBFSA again are in the 1 to 2 percent range of the metric. “From this report we’re seeing that the most economically disadvantaged people in the region are receiving less benefit from the program than others,” Coastal Villages Outreach Manager Michelle Humphrey said in an interview. The goal of the study, which reinforces a message Coastal Villages has long been sending, was to again illustrate the economic disparities between the CDQ sub-regions and motivate officials to restructure the allocations amongst the groups, according to Humphrey. CDQ allocations were last addressed by Congress in the 2006 Coast Guard authorization bill, which generally kept the allocations in place but also directed the State of Alaska to conduct performance reviews of the groups and recommend quota reductions if they aren’t meeting their mission. The last reviews published in January 2013 concluded that Coastal Villages, APICDA and CBSFA all met the goals of economic improvement in their regions to varying degrees and thus no changes to quota allocations were recommended. However, Humphrey said the study also highlights the fact that the Norton Sound Economic Development Corp. and the Yukon Delta Fisheries Development Association also receive allocations that are disproportionately small relative to the economic need in their regions, but the disparity is not quite as great as it is for Coastal Villages. She said the allocations have never been based on a formula that takes into account population or economic need. Exactly how the quota distribution was originally determined is unclear, but Coastal Villages insists “they were created in a very political atmosphere,” Humphrey said. Coastal Villages acknowledges changing the allocations is a challenging process as it requires an act of Congress, but notes similar assistance programs are often driven by needs-based calculations. “I think at this point we’d be interested in seeing what the best practice for (this) type of program is. There’s lots of formulas that are currently in place for housing funds and other federal programs,” Humphrey said further. “So I hope that we can start the discussion about what that formula would look like but I don’t think we have a formula at this time.” Members of Alaska’s congressional delegation have generally shied away from the issue, insisting the CDQ groups need to agree on the matter before they can act. Sen. Lisa Murkowski’s spokeswoman Karina Petersen wrote in an email that Murkowski has encouraged the group’s leaders to discuss the issue. “If a reallocation effort is to move forward, it should be consensus-based and flow out of a constructive dialogue between all six groups,” Petersen wrote. A spokeswoman for Rep. Don Young, who authored the 2006 Coast Guard bill through his leadership position on the House Transportation Committee at the time, did not answer emailed questions in time for this story. In the past, Young has been emphatic that the allocations will not change without the CDQ leaders reaching agreement on what the changes should be. APICDA CEO Larry Cotter did not respond to requests for an interview on the topic and — exemplifying its sensitive nature — neither did Norton Sound officials, despite the report’s conclusions that the Nome-area group is on the short end of the stick. And while the performance of the CDQ groups has generally been positive, they have drawn criticism over executives’ pay and investment decisions in some instances. In 2009 Coastal Villages opened a $35 million fish processing plant in the village of Platinum that was meant to employ 125 people and make the group the third-largest employer in the region. Coastal Villages said at the time the plant would likely operate at a deficit for the first five years. It has been closed since 2016 and Humphrey said the group does not foresee itself working in local fisheries in the near future. Instead, Coastal Villages is focused on programs that bring broader benefits to all of its region’s residents, she said. Yukon Delta Executive Director Ragnar Alstrom testified in August 2017 before the Senate subcommittee covering oceans and fisheries and chaired by Sen. Dan Sullivan that the program has enabled the region’s communities to directly participate in the commercial fishing industry and now provides more than 5,500 jobs and $60 million in wages and other forms of income. Yukon Delta is the largest private employer in its region, accounting for 615 direct jobs in 2016 and investments of $10.2 million into the region over the year, according to Alstrom. He said that overall the program has worked well and needs stability, but the Western Alaska Community Development Association established in 2006 to act as a collective body for the CDQ groups to interact with Congress “has ceased to function in any meaningful way.” At the same time, Alstrom said Yukon Delta is encouraged that all six groups want to make the association functional again. Elwood Brehmer can be reached at [email protected]

Rear Adm. Bell eager for third Alaska Tour

Orders to Alaska were a homecoming for Rear Adm. Matthew Bell and his wife Nancy. Bell took over as commander of the U.S. Coast Guard District 17 in early May and now works out of the district headquarters for Alaska in Juneau. A 33-year veteran of the Coast Guard, Bell said he requested the Alaska mission as the couple holds Alaska residency and still makes a home in Kodiak after two prior tours there in the late 1980s and early 2000s. He has also served as chief of staff and chief of operations for the Coast Guard’s Pacific area, which has afforded him further familiarity with Alaska issues. “I tell everybody they’re two-year orders but I asked for three even before I got here. We’ve been looking to get back here for a while,” Bell said during a June 18 meeting with the Journal and the Anchorage Daily News. “We like the people; we like the state; we like the challenges; we like the tyranny of distance and the weather, so to me that’s exciting work for us.” As the District 17 commander, Bell is responsible for nearly 1,900 active-duty personnel, 15 cutters, 18 aircraft and a $430 million-plus annual budget. He discussed a wide range of topics in an hour-long discussion, but the man tasked with protecting more than half of the nation’s coastline used the phrase “tyranny of distance” repeatedly. For starters, Bell said he is excited about the new vessels headed to the state that will help the Coast Guard combat that tyranny a little more effectively. Specifically, there are six 145-foot fast response cutters headed north, which will initially be split between the Kodiak and Ketchikan stations. Two other larger, offshore patrol cutters are also destined for Kodiak as well. Bell noted that the two fast response cutters that have already reached Ketchikan conducted more boardings in four months than the entire Alaska patrol fleet had done in a year prior. Most of the boardings, particularly in Southeast, are carrying out fisheries enforcement missions in cooperation with Alaska State Troopers and the state Department of Fish and Game, according to Bell. The Coast Guard also entertains National Oceanic and Atmospheric Administration fishery officers on some of its law enforcement patrols in the state. Further, the Coast Guard regularly coordinates with the Alaska Air National Guard, Civil Air Patrol and even “locals on ATVs” when conducting search and rescue missions, Bell added. “To me, one of the benefits of living in Alaska is everybody relies on their neighbor for something else. You’ve got to rely on them; well, we’ve got to rely on those partners,” he said. As for the longstanding issue of adding new vessels to the Coast Guard’s current, operable icebreaking fleet of one, there appears to be progress. The Senate passed the 2019 fiscal year Defense budget authorization bill June 19 with language authorizing the Coast Guard to contract for up to six heavy icebreakers and a directive for Navy officials to draft a report on what equipment they would like to see on those vessels. To that, Bell commented that he sees icebreaking as less of a mission and more of a capability, as a vessel with icebreaking ability will undoubtedly be called upon for numerous scientific, navigation and rescue tasks, among others. “That particular hull, that class of vessel, needs to be able to break ice. That’s not going to be it’s mission; it just has to be able to do that so it can exercise its mission,” he said. Bell also stressed the importance of mariners taking a note from their aviating counterparts and filing a float plan each time they embark on the water. He said it is still easy for vessels seeking shelter to inadvertently hide from responders as well as the weather along Alaska’s jagged coastline, with Southeast’s Inside Passage being the best example of that. “When you start a search it’s easy to say, ‘Well, this is where we’re going to start. We’ve got that nailed down and this is where we’re going to end,’” Bell said. “Well, (the vessel) could’ve gone in 50 different directions and as soon as you put an asset out in the water or up in the air, well, now you’ve taken that asset away from another search and rescue case.” In another example of the “tyranny of distance” he described that a helicopter deployed to a distressed vessel might have to travel hours just to get to the search area, leaving little fuel and time for the actual search, which makes being able to narrow the search area all the more imperative. The biggest takeaway Bell has from his prior tours in the state might be intuitive to many longtime Alaskans, but its importance can’t be overstated — Alaska’s weather is dynamic. “You could talk about weather in the state; well, you can’t, because there are five, six, seven different patterns (at once). “If you don’t have an appreciation for that it can set you up for mistakes,” he said, noting a similar recognition for daylight is needed as well. He is also familiar with some of the state’s most infamous maritime disasters, having responded to both the Exxon Valdez and Selendang Ayu groundings during his previous time in Alaska. In March 1989 Bell was part of a maritime border patrol in the Bering Sea when his vessel was ordered to turn south and steam full-bore for Prince William Sound. He recalled feeling “inadequate” when they finally arrived. “We were a big ship and we do fisheries law enforcement work and we show up in Prince William Sound, and, I mean, you could smell the oil — the ship’s still up on the rocks at the time,” Bell said. His patrol vessel ultimately became a temporary air traffic control center for all of the aircraft responding to the Exxon Valdez spill and the private pilots flying the area simply to observe the disaster. He described the traffic in and out of Valdez going from “three to 300 flights a day.” Bell was the skipper of the cutter Alex Haley in December 2004 when the 283-foot vessel responded to the grounding of the soybean-carrying freighter the Selendang Ayu of off Unalaska Island in the Aleutians. The 738-foot cargo ship lost power, drifted into shallow water along the island and eventually broke up on the rocks during a violent winter storm. Six Selendang crewmembers died in the wreck and a Coast Guard chopper was lost when it was hit by a breaking wave, but the pilot was rescued. “I’m very familiar, up close and personal, with the risks associated with those Great Circle (shipping) routes,” Bell said. He urged vessel captains experiencing problems in Alaska waters to notify the Coast Guard of their issues sooner than later even if it appears at the time that a rescue won’t be necessary. The responders would much rather embark on a rescue mission and turn around halfway through instead of arriving late to a scene — often hours away — that has become critical due to weather, injury or other factors. On a positive note, Bell said relations with the Coast Guard’s counterparts in the Bering Sea, the Russian Border Guard, remain mostly healthy despite the ongoing tensions between Moscow and Washington, D.C. “We’re maritime neighbors. We have the Bering Strait that’s 40-50 miles across. Their traffic could be our traffic. Their calamity could be our calamity very, very quickly, so to stay at that working level is much better for both nations,” he said. The nations routinely run communications drills and the Border Guard has expressed an interest in expanding those to include search and rescue exercises, according to Bell. On fisheries, he said the Coast Guard has a continual dialogue about monitoring shipments offloaded to at-sea processor vessels in areas near the international border. “Nobody really has eyes on what they caught or where they went so we’re continuing to work on those efforts,” Bell said. However, he added that based on what his knowledge, Russian officials take fisheries violations seriously. Bell referred to “a couple of instances where the master loses the vessel, catch gets sold off at auction and none of the guys go back to work. I know that’s happened in a couple of cases. That’s pretty extreme. NOAA can issue a fine but would we ever take somebody’s boat away from them and sell off the catch and never let them back on?” With a desire to visit every community in Alaska with a Coast Guard presence, Bell joked that it will take him three years just to do that. He also said Vice Adm. Linda Fagan, who took over command of the Pacific Area June 8, will be in Alaska in July and similarly new Coast Guard Commandant Adm. Karl Schultz will visit the state in August for a Coast Guard Foundation event. “I wish it was January or February because I think they would appreciate the tyranny of distance and the challenges of the weather a bit more but July and August — at least they’ll get to go all the places and they won’t get constrained by weather for the most part,” Bell commented. Elwood Brehmer can be reached at [email protected]

Interior gold mine gets new life, $100M expansion

It appears one of Alaska’s largest mines is going to get a little bigger and stay open a little longer. Kinross Gold Corp. announced June 12 that it has decided to move forward with a $100 million expansion to the Fort Knox gold mine about 25 miles northeast of Fairbanks. Fort Knox is on land owned by the state Alaska Mental Health Trust Authority; the expansion, known as the Gilmore project, is on a recently acquired 709-acre parcel of state land just to the west of the existing mine pit that was previously held by the federal National Oceanic and Atmospheric Administration. A feasibility the Toronto-based Kinross conducted on the prospect indicates the Gilmore project could yield 1.5 million ounces of gold and initially extend operations at Fort Knox to 2030. Milling at the mine is expected to stop in late 2020 without it, according to Kinross. Now, mining is expected to continue into 2027 with ore processing running to 2030. The mine opened in 1996. The prospect also increased the proven and probable gold reserves at Fort Knox by 2.1 million ounces to 3.4 million ounces overall, Kinross notes further. CEO J. Paul Robinson said the company will likely be able to fund the $100 million expansion with Fort Knox’s existing cash flow, which will help Kinross maintain financial flexibility. “With additional upside potential at Gilmore and beyond, Fort Knox is a significant asset in our portfolio located in an excellent mining jurisdiction,” Robinson said in a Kinross release. “The Gilmore project and the addition of estimated mineral resources improves value and is expected to be a key contributor to the future growth of our company.” Kinross operates eight mines across North and South America, West Africa and Russia. Gov. Bill Walker and Fairbanks-area legislators rejoiced at the news that Fort Knox, which currently employs about 630 people, will probably stay open longer. The mine is also the largest property tax payer in the Fairbanks North Star Borough, according to the governor’s office. “We are excited to see the Fort Knox mine plan, an extension onto newly state-owned land, potentially extending the life of the mine to 2030,” Walker said in a formal statement. “This is a significant development for Alaska’s economy, and was made possible by our administration, federal agencies and our congressional delegation cooperating to transfer these lands from federal ownership to State of Alaska ownership.” Kinross estimates the Gilmore project will generate a 17 percent internal rate of return with a net present value of $130 million and cash flow of $240 million, assuming an average gold price of $1,200 per ounce. At prices averaging $1,300 per ounce, those projections jump to a 26 percent return and a net present value of $239 million. Spot prices for gold are currently about $1,280 per ounce. The company has pegged the all-in operating cost of Gilmore at $950 per ounce. Combined with current operations, Fort Knox’s overall production cost from 2018-2030 is expected to be $1,005 per ounce with annual production averaging 205,000 ounces of gold. Early construction is expected to start in the third quarter of this year, with mining work starting next year and gold production from Gilmore being realized in early 2020.   Elwood Brehmer can be reached at [email protected]

Oil companies sue over tax calculation with $160M liability

A trio of oil industry companies is suing the state Department of Revenue over a 2017 interpretation of oil tax law that they contend wrongly results in an additional $160 million-plus tax liability for them. ExxonMobil, Hilcorp Alaska and SAE Exploration Inc. filed the lawsuit with the Anchorage District of state Superior Court June 7 alleging a March 2017 advisory bulletin written by Tax Division Director Ken Alper arbitrarily changed the state’s position on how oil production tax credits can be applied to a producer’s tax liability. They argue further in the 19-page complaint that the bulletin is being applied as a de facto regulation, for which there was no public notice and opportunity for public comment issued, and therefore is a violation of the Alaska Administrative Procedures Act. As a result, they want the court to void the bulletin and deem it unenforceable. The advisory bulletin posted on the division’s website lays out that use of the sliding scale credit, which grows from nothing at very high oil prices to $8 per barrel at prices less than $80 for oil produced from the legacy North Slope fields, and prevents a company from using tax credits to take their production tax liability below the 4 percent gross minimum tax floor. However, if a producer were to forgo the per-barrel credit or use a fixed $5 per barrel credit for “new” oil production, the new oil credit and others could reduce a production tax liability to less than the 4 percent floor, according to the bulletin. The companies insist the bulletin reinterprets production tax laws and regulations resulting in a liability that is roughly $110 million greater in 2018 and $50 million greater for 2014-2017 — plus interest payments on the back taxes — than it should be. They also note that Revenue’s own regulations allow taxpayers to choose the order in which credits are applied. State regulations do not spell out what happens when a taxpayer first applies the sliding scale credit to reduce its liability to the 4 percent minimum and then applies other credits to go below the minimum tax calculation, according to the complaint. “The 2017 advisory bulletin conflicts with this statutory and regulatory authority by prohibiting the use of the ($5 per barrel) new oil credit and other credits against the minimum tax in any tax year in which any sliding scale credits are also used,” attorneys for the companies wrote. They argue that a 2011 advisory bulletin, issued under former Gov. Sean Parnell’s administration, stated that North Slope producers could reduce their liability below the minimum tax by using new oil or other credits. Additionally, they assert that Alper testified in 2016 legislative hearings that the Revenue Department interpreted production tax laws to allow new oil and other credits to reduce a tax liability below the 4 percent minimum in the same year that sliding scale credits were applied. Revenue officials referred questions to the Department of Law, which does not comment on active litigation. The tax obligations would be borne by ExxonMobil and Hilcorp as producers; SAE Exploration is a support services company that contracts with exploring companies to collect geologic seismic data used to inform oil and gas drilling campaigns. SAE, which holds refundable tax credits earned through its seismic shoots, planned to sell those credits to producers, which in turn could use them against their tax liability, according to the complaint. However, because the bulletin “drastically reduces the circumstances in which a North Slope producer would purchase SAE’s other credits, the 2017 advisory bulletin has drastically reduced the value of SAE’s other credits,” the complaint states further. Elwood Brehmer can be reached at [email protected]  

Startup Sabrewing aims at Alaska launch

Sabrewing Aircraft Co. has plans to revolutionize the air cargo industry, starting with Alaska. The team behind the Camarillo, Calif. -based startup isn’t trying to replace the venerable Boeing 747, which has helped Anchorage become one of the busiest cargo hubs on Earth, at least not yet. And they aren’t trying to beat Amazon in realizing the concept of door-to-door deliveries via drone. Rather, Sabrewing’s business model falls in-between: it is built on regional cargo deliveries with the company’s large unmanned aircraft. Sabrewing co-founder and CEO Ed De Reyes, a former Air Force test pilot, has 40 years of aviation experience and has flown for McDonnell Douglas and Boeing. (Photo/Courtesy/Saberwing Aircraft Co.)   Co-founder and CEO Ed De Reyes said the concept of a large cargo-carrying unmanned aerial vehicle, commonly referred to as a UAV, is a byproduct of the “nascent dream” that is the flying car. A former Air Force test pilot with more than 40 years of aviation experience, De Reyes has flown for numerous aircraft manufacturers including McDonnell Douglas and Boeing. He said that while he is also engulfed in the “flying car craze,” the infrastructure needed to support a wholly new form of transportation for the general public means flying cars are many years if not decades away from becoming a common reality. “I thought, there needs to be another solution, a solution that’s much closer at hand and that’s how the thought of cargo came about, because cargo — there’s still a lot of requirements that are placed on air cargo carriers and air cargo manufacturers — but it’s a little bit lower hanging fruit, so to speak, from the fact that we’re not flying passengers,” De Reyes said in an interview. “What is it that we can do now? What are we capable of doing now and let’s build on that instead of trying to build a system that’s going to rely on massive amounts of, at this time, nonexistent infrastructure.” The ability to take off and land vertically is integral to the company’s model. It is named after Sabrewing hummingbirds, a Central American subspecies that can do just that. The company’s flight testers wear an insignia of a hummingbird while at work, De Reyes noted. “It goes back to that dream that humans have had since the beginning of time of being able to take off and land anywhere on Earth and fly to another location. The most remote locations on Earth would be accessible because you’d be able to get there by air,” he said. Sabrewing began to take shape in the summer of 2016 and has advanced quickly since then. The company is developing three UAVs of different sizes off of a single platform design. The smallest, dubbed the Rhaegal after a dragon from the popular television series “Game of Thrones,” is intended as a battlefield resupply vehicle for the U.S. military. With foldable wings spanning 20 feet when deployed, the Rhaegal will be able to fly up to 1,000 nautical miles with a payload of about 800 pounds. The key difference between the Rhaegal and Sabrewing’s other aircraft is it will fly autonomously, according to De Reyes. The Draco-2 is Sabrewing’s entrant in the Pacific Drone Challenge, an Orteig Prize-esque competition for UAV developers to test their craft against a nonstop 4,500-mile flight. (Rendering/Courtesy/Sabrewing Aircraft Co. Inc.) The mid-sized Draco-2, with a wingspan of 38 feet, is the company’s test vehicle, for which De Reyes has big plans. “We hope that one day, maybe it’ll go into the Smithsonian, we don’t know, but it’ll never go into production,” he said. The Draco-2 is Sabrewing’s entrant in the Pacific Drone Challenge, an Orteig Prize-esque competition for UAV developers to test their craft against a nonstop 4,500-mile flight. “The Orteig Prize, when it came about, was the first person to fly the Atlantic, you know; New York to Paris wins the Orteig Prize and that’s what’s going to happen with the Pacific Drone Challenge. The first person to fly the Pacific from Japan to the (continental) U.S. is going to win,” De Reyes said. The open-ended competition currently lacks a prize — New York hotel owner Raymond Orteig in 1919 offered $25,000 for the first nonstop trans-Atlantic flight — but is really about demonstrating the capability of UAV technology, according to De Reyes. “The ability to show our customers that we can do this and do it safely and do it repeatedly is really the goal here. We’d have to do this anyway for certification,” he said regarding the Pacific Drone Challenge. Sabrewing is aiming to make its challenge flight late next year, presuming the Draco’s flight tests go well. The company also has a scaled-down wind tunnel version that has performed well so far. Aimed at Alaska Named after another dragon, the Wyvern is what Sabrewing hopes Alaskans will eventually be very familiar with. With a 60-foot wingspan, it is the largest of the company’s UAVs. Its 4,400-pound payload, 1,600-mile range and 22,000-foot ceiling are comparable to that of the popular Cessna 208 Caravan that carries cargo and passengers all over Alaska every day. “(The Wyvern) was actually designed to be able to go from Anchorage to Barrow, discharge cargo and turn around and come back,” De Reyes said, while doing it all in weather conditions that would keep other aircraft grounded. He stressed that the Wyvern is not a means to compete with or replace traditional air cargo carriers. Instead, those carriers are Sabrewing’s target customers. As an aircraft manufacturing company, Sabrewing is intent on helping them grow their businesses by opening up new markets. Sabrewing’s aircraft are built on a composite airframe with a gas-electric hybrid power system that drives four electric motors, each turning a variable-position fan. While a hybrid system, the Sabrewing powertrain does not alternate between power sources in the way the popular Toyota Prius hybrid car does. Instead, a light, super-quick response rotary engine generates the power that is converted into electricity by the four motors in real-time. “There is a conversion loss, but it really is only apparent at takeoff and landing,” when the most power is needed, De Reyes said. There are no batteries in the system, he added, because the capabilities of the engine don’t necessitate them and battery technology is not advanced enough to store sufficient energy without greatly sacrificing payload capacity. Sabrewing officials investigated dozens of battery options before determining a viable option doesn’t yet exist, according to De Reyes. “The lighter you make the air vehicle the more cargo you can carry,” he said. “You’re being paid for every single pound that goes onto a cargo aircraft.” The rotary engine can be fueled either with Jet A fuel or ultra-low sulfur diesel. The Wyvern will be equipped with three independent “detect-and-avoid” systems to fly safely in airspace occupied by more traditional aircraft, or other Wyverns, for that matter. De Reyes said the detect-and-avoid mechanisms were among the first things the company settled on when starting to develop its aircraft. An automatic dependent surveillance-broadcast, or ADS-B, system common in modern aircraft will be the first, long-range instrument for detecting other aircraft. A camera system developed by Iris Automation, which develops avoidance systems for UAVs, will back up the ADS-B. The camera system well help the Wyvern pilot see smaller objects when flying at altitudes below 18,000 feet and in favorable visual flight rules, or VFR, weather conditions, according to De Reyes. Finally, a light detection and ranging, or LiDAR, system by Attollo Engineering, another Camarillo, Cali., company, which can detect objects as small as a hummingbird out to 1,000 feet, will be the last line of defense. “All those will send a signal back to the autopilot that will allow the autopilot to autonomously avoid anything that’s out there,” De Reyes said. “It’ll certainly avoid a goose or a Piper J-3 Cub that has no radio or transponder onboard so all those things that could possibly get by one won’t get by the other.” He said Sabrewing is exploring the possibility of adding a fourth detect-and-avoid system as well. The aircraft will also have cameras onboard primarily for takeoff and landing. And while the aircraft will have the ability to avoid potential hazards autonomously, it won’t be for lack of a pilot. Each flight will be operated by a pilot in a control room with a computer display that would resemble a simulator in most cases, but will amount to the cockpit of a Sabrewing UAV. De Reyes said the pilot will have the same altimeters, turn and bank indicators, vertical velocity indicators and other instruments and gauges afforded traditional pilots — even a virtual display of the terrain below the aircraft, if they so choose. And because it’s basically a flight simulator, all pilot certifications to fly the Wyvern will be conducted in a simulator, according to De Reyes. “It’s like being in (instrument meteorological conditions) at night. You don’t really see where you’re going as far as ground reference goes but the aircraft knows where it is because of the information you have in front of you,” De Reyes described. Though not yet in production, Sabrewing is targeting a base price of $2 million, possibly more, for a Wyvern, which again would be in line with the cost of a Cessna Caravan at the lower end. Despite the comparisons, De Reyes insisted his company is not in competition with Cessna, a message he has emphasized to Cessna representatives at industry conferences. “We can’t carry people, the Caravan can. That’s one of the things a Caravan does very, very well actually in remote places. The Caravan can carry infinitely more people than we can,” he commented, noting it will likely be decades before the Federal Aviation Administration approves unmanned passenger flights, if at all. Why Alaska? FAA regulation is one of the reasons Sabrewing turned to Alaska. The agency has made Alaska, through research done at the University of Alaska Fairbanks, a primary testing ground for small UAVs. De Reyes sees the same happening with larger unmanned craft, with commercial approvals for larger craft likely within five years. “We’re going to have to show safe operations in Alaska and show that we can deliver cargo safely in Alaska before they ever allow it in the Lower 48 and most Alaska cargo carrier recognize that too,” he said. “’Hey, we’re going to be the testing ground for this. We’re going to be so far ahead of our competition.’” The Sabrewing team pitched their plan in May to a gathering of cargo company representatives at the Alaska Air Carriers Association annual meeting in Anchorage. Shortly thereafter, the company was accepted as an associate member, the first UAV-focused company to be a member of the influential industry organization. De Reyes called the response from Alaska cargo carriers “overwhelming” after the presentation, noting that one executive told him, “if you had one (Wyvern) on the ramp that you could point to I’d write you a check for it right now.” “I thought, ‘Wow, that’s very forward thinking,’” De Reyes said. “These are people that operated DC-3s and C46s and that kind of aircraft. They’re looking at this and saying it really does open up new markets.” AACA Executive Director Jane Dale said the organization’s board members look at Sabrewing’s business model as simply another form of commercial aviation that is to be embraced. “I think it’s an inevitable transition; just like we’re seeing in automobiles and in the military,” Dale commented. “It’s another tool in the toolbox. That’s the light bulb that went off at the board meeting. I think we’re entering a modernization of aviation in Alaska.” Sabrewing is also a member of the Alaska Airmen Association. Most products intended for use in Alaska are made Outside. The economics of the situation dictate it. However, for Sabrewing, the opposite is true; and therefore the company has pegged Anchorage for its manufacturing facility. De Reyes acknowledged that the company will pay a small premium to get parts and raw materials to Alaska, but those prices will pale in comparison to the cost and logistical challenges of staying in the Lower 48. That’s because without approval to fly a large UAV over the crowded ground and through the busy Lower 48 airspace Sabrewing would have to construct, deconstruct, ship, and reconstruct every aircraft it would send to Alaska — its primary market. He added that western Canada, similar to Alaska in terms of geography and sparse, isolated communities, is a natural successive market opportunity. As a result, De Reyes and his cohorts have toured facilities at Kulis Business Park across the runways from the terminals at Ted Stevens Anchorage International Airport. Merrill Field is a possibility as well. “We’re hoping to do the ‘golden shovel’ (groundbreaking) so to speak, by early 2020. Right after the race we hope to be able to start,” De Reyes said. Before that, Sabrewing will be back in Anchorage next March to test the Draco-2 before heading to Japan for the Pacific Drone Challenge. “The more time that goes on the more sense it makes for us to be located in Anchorage,” De Reyes said further. “I can’t think of any other place in the United States that has that unique — not only position in the aircraft industry — but that unique place in unmanned cargo UAVs. It makes more sense than any other location that I can think of.” The company will look to employ about 200 people in the early years of production, he said, with the expectation they will be producing more than 100 UAVs per year based on demand for traditional, manned cargo aircraft serving remote areas. Ideal Sabrewing employees will be ex-military service men and women with experience in electronics systems and composite materials and eventually pilots, according to De Reyes. “People who want to remain in Alaska but are looking to continue with their aviation skill that they’ve picked up in the military would be great,” he said. Elwood Brehmer can be reached at [email protected]    

Audit concludes Mental Health Trust improperly invested $44M

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

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

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


Subscribe to RSS - Elwood Brehmer