Elwood Brehmer

State officials cite costs, complications of initiative

State agency officials attempted to predict the impacts to the state of a pending fish habitat ballot measure during a July 20 Senate State Affairs Committee hearing. Ballot Measure 1, known as the “Yes for Salmon” initiative, would bolster the Department of Fish and Game’s statutory requirements for approving development activity permits in anadromous fish habitat areas as well as the department’s authority to enforce the stipulations of those permits. Championed by the Anchorage-based nonprofit Stand for Salmon, the initiative is scheduled to be on the general election ballot in November depending on the outcome of an Alaska Supreme Court ruling to determine its constitutionality. Gov. Bill Walker’s administration has argued that the measure is an unconstitutional usurpation of the Legislature’s authority to appropriate resources. The court is expected to rule on the constitutional question by early September to provide the Division of Elections time to prepare accurate materials for voters. On a high level Ballot Measure 1 would establish two tiers of permit application reviews. “Minor” habitat permits could be issued quickly and generally for projects deemed to have an insignificant impact on salmon waters. “Major” permits for larger projects such as mines, dams and anything determined to potentially have a significant impact on salmon-bearing waters would require the project sponsor to prove the project would not damage salmon habitat. Additionally, the project sponsor would have to prove that impacted waters are not salmon habitat during any stage of the fish life cycle if the waters are connected to proven salmon habitat in any way but not yet listed in the state’s Anadromous Waters Catalog. The initiative also states that mitigation measures to offset the impact at the development site may not be done by enhancing or preserving habitat on other waters, which is a practice allowed now and is what’s proposed for the Donlin mine project. On one level, Ballot Measure 1 would cost the state about $3 million per year in the near term to implement its changes, according to estimates in an Office of Management and Budget report. Not surprisingly, much of that would be in Fish and Game’s budget for developing updated regulations and guidance documents. ADFG Commissioner Sam Cotten said it would likely cost the department $1.3 million per year over five years to implement the law changes. The Department of Transportation, which is one of the most frequent applicants for fish habitat permits, would need another roughly $950,000 per year to comply with the more stringent fish habitat requirements, according to department leaders. The departments of Environmental Conservation and Law would each need up to an additional $450,000 per year to possibly broaden water quality standards currently required for discharges in fish spawning areas and enforcing new civil penalties for violating fish habitat permit terms. DOT Environmental Program Manager Ben White said the department would need to add a handful of hydrologists and hydraulic engineers to its current environmental permitting team. “We are committed to environmental stewardship as a department and really work very hard, in this particular instance, to support healthy salmon populations,” DOT Commissioner Marc Luiken said to the committee. While projecting fiscal impacts is an exercise agency staff are accustomed to — it is done for the majority of proposed legislation — the Republicans on the committee in opposition to the initiative posed increasingly speculative scenarios they are concerned about the initiative impacting while questioning administration officials. Walker, who is running for reelection, has expressed his opposition to Ballot Measure 1 as a policy while the Department of Law is challenging its constitutionality. At the same time, Civil Law Division Director Joanne Grace said the Department of Law has advised Walker’s commissioner’s to remain objective on the initiative. Emily Anderson, an attorney for Stand for Salmon, said the discussion in the hearing was premature because agency officials were asked to outline the impacts of the potential law change before the Supreme Court, which could also amend the initiative, has made its decision. Rather than wholly approving or rejecting the initiative, the Supreme Court could strike specific provisions of the proposal it feels are unconstitutional and allow the remainder of it to appear on the ballot if the general intent of the sponsors remains intact. Sen. John Coghill, R-Fairbanks, asked if language in the initiative that would extend fish habitat permit reviews into the riparian area near the shoreline of a water body could be used to preclude development in entire floodplains, such as the one his hometown is built on. Sen. Cathy Giessel, R-Anchorage, questioned whether fire departments could be prevented from filling their tanker trucks from salmon streams and if DOT would not be allowed to use rip-rap when dealing with emergency flood and erosion situations that can occur, particularly along Alaska’s large glacial rivers. Agency officials largely obliged the speculation, acknowledging there is a possibility the circumstances raised could be impacted because of the vague language of the initiative. DOT’s White said the agency could be forced to find alternatives to traditional rock rip-rap for erosion control and that temporary stream diversions — often used in culvert and bridge work — could be challenged. Habitat Division Biologist Ron Benkert said in an interview that Fish and Game already discourages the use of rock rip-rap when other bioengineered solutions such as root wads or other forms of woody vegetation can be used for erosion control, noting that in the most critical areas and emergency situations the department concedes to the use of rip-rap at the request of DOT and others. He also said large, fast rivers such as the Matanuska that regularly cause significant damage are primarily migration corridors for salmon and other species that use headwaters and tributaries for spawning and rearing, so the impact of bank stabilization efforts to critical habitat is limited most times. “Really high velocity — it’s just not a great place for fish to hang out,” Benkert said. Anderson said the initiative makes no changes to the ability for officials to respond to emergencies. She stressed in response to other concerns about the purview of the habitat permits that the initiative is limited to freshwater, as is the case today. Anderson said during an editorial board meeting with the Journal and Anchorage Daily News on July 19 that the initiative is primarily aimed at solidifying scientific best practices and guidelines Fish and Game currently uses in regulation and law to insulate the permitting process from political influence. Initiative sponsor and commercial fishermen Mike Wood has said the objective of the campaign is to fortify the state’s fish protections while the Environmental Protection Agency is scaling back its wetlands protections in the state, for example. Currently, Title 16, the state’s anadromous fish habitat permitting statute, directs the ADFG commissioner to issue a development permit as long as a project provides “proper protection of fish and game.” The initiative sponsors contend that is far too vague and an update is needed to just define what “proper protection” means. In early 2017, Alaska Board of Fisheries chair John Jensen sent a letter to legislative leaders urging them to update Title 16 with opportunities for public involvement in permit application reviews and enforceable development standards. The law now does not allow for public comment nor does it require Fish and Game to issue a public notice indicating the Habitat Division is adjudicating a permit application. The Kenai Peninsula Borough Assembly also unanimously passed a resolution in 2016 supporting an update to Title 16 to further protect fish habitat. DNR Project Management Associate Director Kyle Moselle said in response to questions that the vast majority of the permits DNR and DEC issue for large development projects already require public notice and comment periods, which would be a fundamental addition to the anadromous fish habitat permit process under the proposal. Giessel said in an email that the public should be included in matters involving public resources and that is why the comment periods and notices are required for other land and water use and quality permits. “If the issue surrounding this initiative is one of requiring an opportunity for Alaskans to comment and be involved on fish habitat permits, that is one matter. But proposing an up or down, take it or leave it, wholesale rewrite of our fish laws in November is another thing altogether,” Giessel said. It was also unclear from the hearing when existing developments with fish habitat permits already in hand would be subject to the new permitting system. Benkert said in an interview that while the department feels this is a “gray area” in the law, generally an existing operation would be grandfathered in until additional authorizations are needed for expansion plans or a fish habitat permit renewal. Most fish habitat permits are valid for two- to five-year periods before they need to be renewed. “It’s kind of a check so we can just come back and see if what we had permitted five years ago is still actually being done,” Benkert described. Stand for Salmon’s Anderson said worries about renewing permits for existing facilities “have been blown out of proportion” and re-upping authorizations should not be more difficult under the initiative. “There’s a whole class of facilities that never had a fish habitat permit and won’t require one; (they) are not only not affected by this but never will be affected by this,” she said. “Then there’s a whole class of facilities that did require a fish habitat permit but that habitat is no longer in existence, therefore you don’t need a new fish habitat permit and it never will be contemplated because there is no fish habitat left to get a new permit for.” White also said DOT is concerned the initiative could lead to more National Environmental Policy Act reviews for work now deemed to have a de minimis environmental impact because it prohibits Fish and Game from allowing activities that have a “significant adverse effect” on fish habitat. DOT regularly conducts work that has some impact on fish habitat, according to White. He said in an email that the concern specifically relates to many of the projects the department executes that are at least partially funded with federal money. Anderson and other initiative supporters insist it is not intended to prohibit unavoidable small or temporary impacts as many fear, which is why it calls for “minimizing” impacts if avoiding them is not practical. She also strongly contended that White “is just wrong” in his characterization of how it could lead to more projects being subject to NEPA and DOT is conflating the state and federal permitting systems. “NEPA is triggered by a federal action that would have significant adverse effects. It is not triggered by state laws,” Anderson said. Elwood Brehmer can be reached at [email protected]

State defends claim for $160M in back taxes

State attorneys issued a wholesale rebuttal July 18 in responding to a lawsuit brought by three companies that work on the North Slope against the state Revenue Department over how detailed portions of the state’s oil tax laws are applied. ExxonMobil, Hilcorp Energy and SAE Exploration, a seismic imaging company, sued the Department of Revenue in state Superior Court June 8 alleging Tax Division officials are using an unenforceable guidance document to improperly collect upwards of $160 million in oil production taxes. The state’s 14-page response, signed by Assistant Attorney General Katherine Demarest, admits the advisory bulletin in question issued by Tax Director Ken Alper in March 2017 interprets oil tax law and acknowledges the companies sued in the proper venue, but in line-by-line fashion flatly denies the rest of the complaint. ExxonMobil and Hilcorp contend the state informally adopted the six-page advisory bulletin as a regulation packet and subsequently applied to collectively increase their fiscal year 2018 oil production taxes by about $110 million and to collect another roughly $50 million plus interest in retroactive taxes since 2014. The state’s filing rejects the allegation that tax regulations “incorporate” the advisory bulletin, but rather asserts that it “interprets statutes” as allowed by state law. State attorneys also contend that one or more of the plaintiffs may lack standing in the lawsuit and that the state’s sovereign immunity may by applicable to this case. They request the case be dismissed and the state be compensated for the costs of its defense. 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. Limiting the amount of credits the producers can apply to their production taxes has in turn hampered SAE’s ability to sell its credits and reduced their market value, according to the original complaint. The advisory bulletin explains that use of the sliding scale credit prevents a company from using tax credits to take their production tax liability below the 4 percent gross minimum tax floor. The sliding scale credit, which starts at $8 per barrel when oil prices are less than $80 per barrel and steps down to nothing at extremely high prices, is used as a way to install progressivity into the production tax for oil produced from the state’s large, legacy fields such as Prudhoe Bay and Kuparuk River. 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 that Revenue’s own regulations allow taxpayers to choose the order in which credits are applied. The state’s filing does concur with that assertion, but additionally “denies that such an option relieves taxpayers of the duty to accurately report and pay tax,” the filing reads. The companies argue further 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. The Legislature and Parnell administration overhauled the oil and gas production tax system in 2013 with Senate Bill 21, which survived a voter referendum to repeal it in 2014. The current oil production tax law has since been modified twice at the behest of Gov. Bill Walker in 2016 and House Democrats last year. Elwood Brehmer can be reached at [email protected]

AK LNG leaders navigate trade battle with China

The $43 billion Alaska LNG Project is in a rather unique spot when it comes to the United States’ trade relations with China. It was a central piece of a Nov. 9, 2017, meeting between President Donald Trump and China President Xi Jinping in Beijing, a ceremony at which numerous deals totaling roughly $250 billion in potential trade between the countries were announced. That day Gov. Bill Walker and Alaska Gasline Development Corp. President Keith Meyer signed a joint development agreement with the state-owned Chinese companies Sinopec, China Investment Corp. and the Bank of China; it was one of a select group of trade pacts chosen to be signed in front of the two presidents. Although nonbinding, the JDA has been touted as the early stages of a foundational deal to support the gasline as it calls for selling up to 75 percent of the project’s LNG’s production capacity to Sinopec in exchange for a like percentage of the needed financing. It could represent billions of dollars per year of Alaska LNG exports to China, which would be a significant step towards rebalancing trade between the two countries. However, business relations between Beijing and Washington, D.C., have been on a well-publicized downhill path since. AGDC leaders acknowledge the 25 percent tariff the Trump administration levied on Chinese steel imports this spring could impact the viability of sourcing the steel for the project’s 800-mile, 42-inch natural gas pipeline and other components such as pipe racks. Reuters reported July 16 that the Trump administration recently rejected a request for a waiver from the 25 percent tariff on Chinese steel by Plains All American Pipeline LP, despite the fact that the company signed a contract for the steel to be used in a 550-mile Texas oil line last year prior to the tariffs taking effect or even being announced. At the same time, state gasline officials note that prefabricated modules and other constructed units that would make up large portions of the North Slope gas treatment plant, the Nikiski LNG plant and the pipeline compressor stations are exempt from the new tariffs, for now, at least. Many such components will have to be sourced internationally if the Alaska LNG Project is built because there simply are too few, if any, U.S. manufacturers. Additionally, cost savings are often available in world markets versus domestically sourced materials, according to AGDC Vice President Frank Richards. During a July 11 project update to legislators, Richards highlighted that China has not included U.S. LNG in its retaliatory tariff measures as part of the tit-for-tat trade dispute. It seems unlikely that LNG, or any energy form for that matter, would be hit with such a tariff as such a move would ultimately increase prices for Chinese consumers at a time when the government is making a major push away from coal for electric generation to cleaner fuels such as natural gas. “We feel that we have high visibility. China wants clean, efficient natural gas; Alaska has it; the U.S. wants to produce and export it, so we feel that we are in a good position as a project and as Alaska, too, to not hopefully be impacted by that (trade dispute),” Richards said. He added that AGDC learned in early July that there are pipe manufacturers in Arkansas and Illinois capable of rolling 42-inch steel pipe; AGDC previously didn’t know if sourcing the primary gasline steel from the U.S. was even possible. As for Alaska LNG’s end product, AGDC Commercial Vice President Lieza Wilcox told legislators asking about financial risks in the project that if China does puts a tariff on imported LNG, the downstream sales contracts will be structured so the additional tariff cost is borne by the LNG buyer. “Once the contract is concluded the price is not going to be discounted for tariffs,” Wilcox said. She — as other AGDC leaders have since the November announcement — emphasized that the Alaska LNG Project is well regarded in the trade circles of both countries and said it has the opportunity to “continue to be a force for good in the continuing discussions about trade.” Elwood Brehmer can be reached at [email protected]

ConocoPhillips raises reserve totals at Slope discoveries

ConocoPhillips believes its recent winter exploration campaigns on the North Slope have added up to 1.4 billion barrels of oil and gas resources to its portfolio, company officials said in a July 16 presentation to investors. The estimate is largely derived from the results of the six exploration and appraisal wells the company drilled into its western Slope prospects last winter, which built on the work of two wells drilled in the federal National Petroleum Reserve-Alaska in early 2016. The 2016 drilling led to ConocoPhillips’ Willow oil discovery — a shallow, Nanushuk formation-focused prospect — with an early oil estimate of up to 300 million recoverable barrels announced in January 2017. Company leaders said July 16 that four more wells drilled into Willow early this year indicate the field could hold between 500 million and 1.1 billion barrels of gross resources that will cost between $4 billion to $6 billion to fully develop, with first oil potentially in the 2024-25 timeframe. It was also noted that roughly 75 percent of the company’s prospective acreage in the area is yet to be drilled. With a conventional target zone in the 4,000-foot range, ConocoPhillips also believes it can produce from Willow for less than $40 per barrel, according to a release accompanying the presentation. “Alaska provides competitive investment opportunities and will generate profitable growth from diversified investments with significant exploration upside,” CEO Ryan Lance said in the release. “We are proud of the value we create for the State of Alaska through the revenues we generate, the jobs we create and the community investments we make. Our shareholders realize the advantages of (Alaska North Slope)-priced oil, competitive cash and earnings margins from our operations and our years of expertise and sound stewardship. We plan to continue to strive to safely unlock the energy potential of this world-class oil province for years to come and play an active role in Alaska’s economic future.” ConocoPhillips Alaska leaders have previously said Willow could produce at rates up to 120,000 barrels per day with standalone processing facilities, an investment the company is now leaning towards. The Putu and Stony Hill wells the company drilled this year on state leases south of the Nanushuk discovery in the Pikka Unit collectively hold another 100 million to 350 million barrels, according to ConocoPhillips. Production from those prospects has been pegged at up to 20,000 barrels per day each. ConocoPhillips is also expected to bring its roughly $1 billion Greater Mooses Tooth-1 project online sometime late this year. Located just east of Willow in the NPR-A, GMT-1 is expected to produce up to 30,000 barrels per day at its peak. The company is also in permitting with the Bureau of Land Management to develop its Greater Mooses Tooth-2 prospect, which is generally a mirror and just to the south of GMT-1. Elwood Brehmer can be reached at [email protected]

Board rejects emergency petition over pink salmon hatchery production

The Valdez Fisheries Development Association can move ahead with its plan to increase its pink salmon production after the Alaska Board of Fisheries rejected an emergency petition from groups led by the Kenai River Sportfishing Association who oppose the plan. The seven-member board ultimately decided the issue does not constitute an emergency on a 4-3 vote during a Tuesday afternoon meeting in Anchorage. Board members Israel Payton of Wasilla, Reed Morisky of Fairbanks and Orville Huntington of Huslia voted in favor of the petition meeting emergency criteria for consideration. Those voting against were chair John Jensen of Petersburg, Alan Cain of Anchorage, Robert Ruffner of Soldotna and Fritz Johnson of Dillingham. The petition was signed by KRSA Executive Director Ricky Gease and 18 individuals representing Lower Cook Inlet commercial fishing interests, the Chitina Dipnetters Association, the Kenai River Professional Guide Association, the Fairbanks Fish and Game Advisory Committee, among others. It urged the board to reverse a previously approved increase of 20 million pink salmon eggs by the Valdez Fisheries Development Association this year for expanding future hatchery-produced harvests. KRSA first submitted the petition May 1. The first version was signed by nine sport and personal use fishing groups, sans the Lower Cook Inlet commercial representatives. The board subsequently voted to a 3-3 tie on the issue during a May 14 teleconference meeting. The petition alleges that increasing the number of hatchery produced salmon poses a threat to wild salmon stocks as the hatchery fish compete with wild salmon for food while they are collectively rearing in the ocean. It highlights that a sampling study found up to 70 percent of pink salmon returning to some small Lower Cook Inlet streams in 2017 were found to be from Prince William Sound hatchery stocks. “In addition to the straying issues of PWS hatchery-origin pink salmon observed in Lower Cook Inlet, recent scientific publications (building on past published reports and internal Alaska Department of Fish and Game reviews) have provided cause for great concern over the biological impacts associated with continued release of very large numbers of hatchery salmon into the North Pacific Ocean, including the Bering Sea and the Gulf of Alaska,” the petition states. Fish and Game Commissioner Sam Cotten wrote to a letter to Gease June 14 in which he denied the petition via authority delegated to him by the Board of Fisheries, but noted two board members had already requested a special meeting to discuss the matter. Fish and Game officials as well as board chair Jensen said at the Tuesday meeting that emergency findings are rare; there must be an unforeseen event that threatens a resource or an instance where action would lead to a loss of harvest opportunity that couldn’t be had in the future. “I don’t think taking eggs is an emergency,” Jensen said. Gease said in an interview that the state has policies in place that make it illegal to transport salmon between regions, but the department is passively allowing it to happen by approving increased hatchery production when the fish are known to stray. “It seemingly now is OK that there is no standard for hatchery fish straying,” Gease said. Valdez Fisheries Development Association leaders could not immediately be reached for comment in time for this story. Morisky said he feels instances where 70 percent of the fish spawning in a stream have strayed from hatchery stocks constitutes an emergency and allowing an egg take that will lead to more hatchery fish could threaten wild salmon stocks, the health of which Fish and Game is required to prioritize above other salmon. Payton said the potential issue of hatchery fish competing with wild salmon for food in the ocean is of particular concern to him. “I do think there is a potential threat to the wild stock resource here,” Payton said. Fish and Game Commercial Fisheries Division Director Scott Kelley said the Valdez-area hatcheries originally wanted to take an additional 70 million eggs and increase the total egg take to 300 million from 230 million, but the department agreed to a phased approach of increases in 20 million-egg increments in 2016 and 2018. It’s an approach that is commonly used with hatcheries across the state, according to Kelley. “That’s why we ease in — test the waters, literally,” he said. Kelley noted recent wild stock returns of pink salmon to Prince William sound in 2013 and 2015 — pinks typically return in two-year high and low abundance cycles — were among the most prolific on record. Board member Johnson of Dillingham said the egg take is supposed to happen in three days, adding the board is already scheduled to take up hatchery issues during an October 15-16 work session in Anchorage. It was also emphasized at the meeting that the department, in conjunction with hatchery groups, is working on a long-term study to flesh out theories of how hatchery salmon from Prince William Sound and Southeast Alaska do or don’t impact wild fish stocks. Cain, of Anchorage, said the issues of how hatchery salmon interact with wild salmon are very important but the petition didn’t meet the board’s threshold for an emergency. Elwood Brehmer can be reached at [email protected]

King Cove road opponents file motions for summary judgment

The groups suing Interior Secretary Ryan Zinke laid out their final arguments in court documents filed July 11 against a federal land exchange that sets the stage for construction of an emergency access road through the Izembek National Wildlife Refuge. Friends of Alaska Wildlife Refuges, the Alaska Wilderness League, The Wilderness Society, the Sierra Club and five other national conservation organizations filed a motion for summary judgment with U.S. District Court of Alaska Judge Timothy M. Burgess, urging him to void the land swap signed Jan. 22 with King Cove Corp. on the grounds that Zinke violated several major federal laws in a hasty attempt to get the road built. The groups are represented by the Anchorage environmental nonprofit law firm Trustees for Alaska. A 55-page supporting memo accompanying the 4-page motion signed by Trustees attorney Brook Brisson alleges that Zinke, in order to expedite the transfer, ignored provisions in the 1980 Alaska National Interest Lands Conservation Act, which created the Izembek refuge; the National Environmental Policy Act, or NEPA, as the nation’s overarching environmental review law; and the Endangered Species Act. Federal attorneys contended in a May 3 response to the original complaint that the plaintiffs do not have standing to object to the land swap because they have not been harmed by it and their complaints are not ripe for a ruling because the final lands to be traded have not been selected. They further assert that the federal District Court does not have subject matter jurisdiction over the lawsuit. Section 1302 of the milestone 1980 public lands bill commonly known as ANILCA grants the Interior secretary the authority to carry out such a land exchange, but also states that such an action must be done to “carry out the purposes of this act.” Signed by President Jimmy Carter, ANILCA established or expanded many of the national parks, wildlife refuges and other federal conservation areas in the state. “The secretary made no findings that the land exchange would further ANILCA’s general or Izembek’s specific purposes and failed to acknowledge or explain the decades of findings and conclusions by the (U.S. Fish and Wildlife) Service that a land exchange and road were contrary to those purposes,” Brisson wrote. The suit was filed just nine days after the land exchange was announced. The agreement between King Cove Corp. and Interior has the Alaska Native village corporation trading up to 500 acres of its land for an equal-value chunk of a wilderness-designated section of the Izembek Wildlife Refuge, or enough refuge land to build an 11-mile, single-lane gravel road that would complete the connection to Cold Bay. The suit is moving relatively quickly to a judgment because there are few facts to dispute; it is simply a matter of Burgess interpreting the applicable laws and authorities. ANILCA also requires consultation with other federal agency leaders, including the Transportation secretary, on any application to construct a transportation corridor through conservation areas. It also states that Congress must approve any corridor through wilderness-designated areas. Opponents to the King Cove road stress the importance of the unique habitat in and around Izembek lagoon in debating the issue. In their view, it would set an extremely dangerous precedent approving a road through an area once designated as wilderness would set. At various times of the year the 315,000-acre Izembek Refuge is home to nearly the world’s entire population of Pacific black brant geese and other migratory birds that use it as breeding grounds and a resting place on their annual travels, according to the U.S. Fish and Wildlife Service. Alaska’s congressional delegation and state lawmakers insist the road is the only way to provide truly safe access to medical care for the roughly 950 residents of King Cove. Those in need of urgent medical care in King Cove currently must be flown via small plane or boated across the waters of Cold Bay to reach Cold Bay’s airport with its 10,000-foot runway that provides more reliable jet service during bad weather. The plaintiffs further insist that the land exchange deal — announced when it was agreed to with no public notice — is a “major federal action” and therefore requires an environmental assessment or impact statement be conducted before it is approved. Brisson wrote that an exception in ANILCA to that requirement does not apply because it relates to land conveyances to Alaska Native corporations under the Alaska Native Claims Settlement Act, which the January deal is not. “As the courts have stated, the fundamental policies in NEPA should not be discarded absent some clear indication that Congress so intended,” the plaintiffs’ memo states. “Instead, deciding whether to exchange federal lands for a road is the quintessential government decision that NEPA was passed to apply to: to ensure informed decision-making about environmental impacts and to allow public participation in a decision regarding national public lands.” Lastly, they argue Zinke violated the Endangered Species Act by not consulting with the Fish and Wildlife Service on the potential impacts of the land deal before agreeing to it. The ESA requires such coordination for federal actions that could harm species listed as “endangered” or “threatened.” In this case, that applies to the Northern Sea Otter and the Stellar’s eider duck, which breeds on the North Slope and overwinters in Izembek. The Alaska breeding population of the small ducks are listed as threatened, according to Fish and Wildlife. In late 2013, then-Interior Secretary Sally Jewell rejected land swap deal passed by Congress in 2009 after a U.S. Fish and Wildlife Service environmental impact statement urged against it; the EIS deemed the road would irreparably damage critical waterfowl habitat in the refuge. King Cove Native organizations and the State of Alaska subsequently sued Jewell over her decision to block the road, but the suit was dismissed in federal District Court and an appeal to the 9th Circuit Court of Appeals was later dropped. That swap would have traded 206 acres of Izembek land and 1,600 federal acres outside the refuge for about 56,000 acres of state and King Cove Corp. land. Members of Alaska’s congressional delegation have said the ANILCA provisions hadn’t been used during other Republican administrations that would seemingly be more open to the plan because key officials in President George W. Bush’s administration, for example, opposed the road through Izembek. The road has also become a priority for President Donald Trump, who was captivated by the situation when briefed on it in March 2017 by Alaska’s delegation shortly after he took office. Attorneys for the Interior Department have 30 days to respond. ^ Elwood Brehmer can be reached at [email protected]

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]


Subscribe to RSS - Elwood Brehmer