Elwood Brehmer

Pebble owner loses potential major investor

The company spearheading the Pebble mine is again long on mineral prospects but short on cash after another major potential funder turned away from the project, according to a release from Northern Dynasty Minerals Ltd. Vancouver-based Northern Dynasty Minerals, the sole parent company to Pebble Limited Partnership, issued a statement early May 25 acknowledging that its framework investment agreement with First Quantum Minerals has been terminated. In December, the two Canadian mining firms announced they had reached an option agreement under which First Quantum made an initial $37.5 million payment to Northern Dynasty with plans to make three more similar payments totaling $150 million over four years. At the end of that period First Quantum would’ve had the option to buy a 50 percent stake in Pebble Limited Partnership for $1.35 billion. First Quantum operates six primarily copper, gold and zinc mines worldwide. The pre-development Pebble prospect is Northern Dynasty’s sole project. The initial $150 million was intended to fund the permitting process for Pebble, while the subsequent major investment would have helped develop the mine and its extensive support infrastructure. First Quantum was originally supposed to decide whether or not it would invest in Pebble beyond the $37.5 million payment by April 6, according to the framework agreement. The companies first pushed that deadline back to April 30 and later to May 31. Groups opposing Pebble quickly began pressuring funds with investments in First Quantum to divest their interests in the company if it were to get involved in the Pebble project long-term. Those same groups were able to spend Memorial Day weekend celebrating Northern Dynasty’s announcement. “Today is a victory for Bristol Bay’s tribes,” United Tribes of Bristol Bay President Robert Heyano said in a prepared statement. “Our voices are being heard everywhere from our villages to the boardroom at First Quantum. Quyana (thank you) to First Quantum for listening to reason and divesting from this toxic project. No project is worth more than a culture or a way of life. It’s fitting that this announcement comes right on the cusp of fishing season, where Bristol Bay will once again harvest millions of salmon for the world.” Pebble Partnership leaders have long acknowledged they need to secure another major investor partner before the mine can be built, so what the revelation means for the future of Pebble and Northern Dynasty is unclear. Pebble CEO Tom Collier downplayed the significance of failing to reach an agreement with First Quantum in a formal statement following the Northern Dynasty announcement. Collier said he is continuing on with “business as usual” because he is confident the junior mining company will secure the funding it needs to complete the project’s environmental impact statement. “Pebble remains one of the nation’s most important undeveloped mineral resources. It is on state land and is an important economic asset for Alaska,” he said. “Our project is well defined and we are going to continue communicating with Alaskans about why we believe in the opportunity it represents.” A spokesperson for First Quantum could not be reached for comment. Northern Dynasty held $27.9 million Canadian, or roughly $21 million U.S., in cash on March 31, according to its first quarter financial report issued May 15. At the same time, it had also accrued $13.5 million Canadian in near-term liabilities and total liabilities of $68.7 million Canadian. Northern Dynasty stock closed trading May 25 on domestic markets at 47 cents per share, down 33 percent from its prior closing price of 70 cents per share. The company is also traded on the Toronto Stock Exchange. London-based mining major Anglo American withdrew from Pebble in 2013 after spending more than $540 million exploring the copper and gold deposit. In 2014, fellow British mining firm Rio Tinto donated its 19 percent ownership in Northern Dynasty to the Alaska Community Foundation and the Bristol Bay Native Corp. Education Foundation. Bristol Bay Native Corp. has helped lead the fight against Pebble. BBNC President Jason Metrokin said First Quantum “ultimately came to the right conclusion about the Pebble project”. “I commend First Quantum for exiting the Pebble project,” Metrokin added. “As we have said repeatedly since formally opposing the proposed mine nine years ago, Pebble mine is the wrong mine in the wrong place. The people of Bristol bay and the majority of Alaskans will not trade salmon for gold.” In early April, a group of 50 conservation and outdoor recreation companies and organizations sent a joint letter to First Quantum leaders imploring them to stay out of the Pebble project. Further, a group of Alaska Native leaders from the Bristol Bay-area traveled to First Quantum’s May 3 shareholder meeting in Toronto to deliver a similar message. California Treasurer John Chiang, a trustee to the state’s $360 billion-plus Public Employees’ and Teachers’ Retirement systems, sent a letter to First Quantum leaders Jan. 29 urging them to stay out of the Pebble project because CalPERS officials believe sustainable business practices are fundamental to long-term value growth for shareholders. According to Chiang, the Pebble project would risk the sustainability of fisheries in the Bristol Bay region as well as the fund’s investment in First Quantum. At the time, CalPERS held 4.3 million shares of First Quantum amounting to 0.62 percent of outstanding stock in the company as well as bonds in First Quantum with a maturity value of $2.3 million. Additionally, Environmental Protection Agency Administrator Scott Pruitt, generally seen as a bane to conservation advocates, issued a surprising statement Jan. 26 expressing his “serious concerns” about the impacts of mining activity in the Bristol Bay watershed. As a result, Pruitt said the EPA would not finalize its proposed withdrawal of the 2014 proposed determination to prohibit a large mine in the Bristol Bay region through its Clean Water Act Section 404(c) authority. Pruitt stressed that his decision would not impact Pebble’s environmental review under the National Environmental Policy Act, or NEPA, but it kept a cloud of uncertainty over the project that Pruitt was expected to remove. Pebble Limited Partnership filed its wetlands fill permit application with the U.S. Army Corps of Engineers Dec. 22. The initial application outlined plans to fill 3,190 acres of wetlands at the mine site. While not specific to any mine plan — a point Pebble and parent company Northern Dynasty minerals have stressed — the Bristol Bay Watershed assessment published by EPA in 2014 concluded a mine that would fill more than about 1,100 acres would be too damaging to fish habitat to allow. ^ Elwood Brehmer can be reached at [email protected]

88 Energy to reenter Icewine well to test production capacity

88 Energy is getting ready to test the production capacity of its latest North Slope exploration well as it evaluates seismic data that could lead to more drilling. The small Australian independent explorer plans to reenter the Icewine-2 well on June 11. After pressure gauges are retrieved from down the wellbore, the company will employ a nitrogen lift to recover up to 4,000 barrels of drilling and other fluids from the reservoir before production tests begin, according to a May 21 release on its upcoming operations. The nitrogen gas displaces the down hole fluids and allows them to be removed so, ideally, oil can begin flowing naturally after the process is complete. 88 estimates the work will take 10 to 14 days, after which time the well will continue to be flowed to test its drawdown pressure and decline rate. 88 Energy holds rights to roughly 475,000 acres of contiguous state leases south of the developed area of the North Slope. It also holds a 100 percent interest in about 15,500 acres south of the Point Thomson gas field and adjacent to the western edge of the Arctic National Wildlife Refuge. BP drilled the Yukon Gold-1 well in the area in 1994 and hit oil at several depths of the 12,800-foot well but did not develop it, according to 88 Energy. The company is working from the Franklin Bluffs drilling pad, about 35 miles south of existing North Slope fields, where it drilled the Icewine-1 well in late 2015. Its location adjacent to the Dalton Highway-trans-Alaska pipeline corridor makes it accessible year-round, a rare feature among Slope exploration projects that often require ice roads and winter-only drilling on undeveloped land. The Icewine-2 well, drilled in early 2017, is focused on appraising the unconventional oil resource in the HRZ shale, which 88 Energy describes as “a prolific source rock” in the Brookian geologic formation. The Brookian sequence of formations contains the shallow Nanushuk formation and the Torok sands, which have been the source of multiple large oil discoveries by Armstrong Energy, ConocoPhillips and Caelus Energy in recent years. The belief is the HRZ shale holds similar potential to the Nanushuk and Torok plays if it can be effectively fracked. Additionally, the company is processing 3-D seismic data it acquired this winter over nearly 180 square miles on its large swath of acreage west of the Dalton Highway. 88 Managing Directory David Wall said via email the seismic information will inform company leaders about where their next exploration wells could be drilled. In February the state Division of Oil and Gas approved permits for the company to drill two exploration wells roughly 25 miles west of the Franklin Bluffs pad near the Kuparuk River. The company had older, 2-D seismic over the area but did not feel it was sufficient to support base a drilling campaign on, according to Wall. Evaluation of the 3-D data should be done in midsummer, according to the May 21 release. He said 88 leaders are confident that with the new data and drilling permits in hand they will be able to raise money for further exploratory drilling. New seismic data from the company’s Yukon Gold leases should be available late in the year, as well. ^ Elwood Brehmer can be reached at [email protected]

NANA strengthens in-state business holdings

NANA Development Corp. has bought back into Alaska after a challenging financial period pushed the company to sell several of its subsidiaries. Vice President of Operations Eric Billingsley said in an interview that the Alaska Native corporation pulled the Alaska branches of WHPacific Inc. and GIS Alaska back under its umbrella after selling the Outside offices of the companies. The moves are part of NANA’s broader overhaul of its business model to focus its commercial sector on growth in the state. NANA Development Corp. is the business arm of NANA Regional Corp., which is the Alaska Native corporation for the northwest region of the state. The former Anchorage office of WHPacific has been renamed Kuna Engineering and GIS Alaska’s fabrication facility in Big Lake is now again known as NANA Construction. “We’re glad to have these companies back operating inside of NANA,” Billingsley said. He called the 27-acre Big Lake tract the best fabrication facility in the state given its large size and location, which allows truckers hauling materials to and finished products from the facility to avoid the congested areas of Anchorage and Wasilla. Leaders of the parent company have been encouraged by the gradual but consistent increase in oil prices — now to the mid-$70s per barrel compared to less than $50 per barrel a year ago — as well as recent oil discoveries by ConocoPhillips and other companies exploring on the Slope as indicators Alaska’s oil patch is set to resume growth. “We believe in the state. We believe in the opportunities going forward and we want to continue to prove the services across the gamut to everyone involved, not just to oil and gas but to broad-based commercial businesses as well,” Billingsley said. Kuna Engineering currently has 37 employees and NANA Construction has a workforce of about 190, according to NANA spokeswoman Amy Hastings. She wrote in an email that employment at NANA Construction should remain steady for the foreseeable future and Kuna’s workforce could increase slightly given its work with Teck Resources. The Kuna Engineering team over the years has come to provide a large portion of the engineering work Teck needs at the Red Dog mine, according to Billingsley. Teck operates the Red Dog zinc mine north of Kotzebue, which is located on NANA Regional land. Last year Teck announced that a prospect it had been exploring on state land about 7 miles northwest of Red Dog could be another world-class zinc deposit near what is already a world scale zinc mine if further exploration drilling proves out the resource estimates. Red Dog is one of the largest zinc mines on Earth. Teck is also in the midst of a $110 million upgrade to Red Dog’s mill to increase its production capacity by about 15 percent. Increased zinc prices have helped NANA Development rebound from several tough financial years, according to company leaders. NANA Development, which has roughly 15,000 employees through its subsidiary companies, is also heavily involved in the federal contracting sector. In 2016, the company’s losses in the oil services sector of $61.5 million were part of an overall net loss of $109 million, according to the corporation’s annual report. The corporation absorbed losses in 2014 and 2015 as well. It sold NANA Oilfield Services to shipping and logistics giant Saltchuk in 2016 and also saw Moody’s downgrade $300 million of its corporate debt, citing deterioration in its core businesses, namely oil and gas. NANA sold off WHPacific’s Lower 48 offices last year after holding the company for many years prior. It purchased Grand Isle Shipyard Inc., or GIS, in 2011. GIS was focused on oil and gas support in the Gulf Coast region, according to a NANA release at that time. GIS was then merged with NANA Construction. NANA also operates NMS, a camp services and facilities management firm, and NANA WorleyParsons, an engineering and project management company. Both are significant support service providers on the North Slope. Billingsley said he thinks NANA is in a unique position as a resource owner and an active participant in the resource industry through its support service companies. Keeping businesses like Kuna and NANA Construction also help the parent company and resource owner ensure that development costs are reasonable, according to Billingsley. “There is a suite of services Teck needs to operate the mine and we have the skills and the opportunities to take advantage of those and contract those; so those dollars stay with NANA and we’re also able to provide wages and opportunities for our shareholders,” he said. Billingsley noted that NANA has provisions in its agreements with Teck about using its support companies, but typically doesn’t leverage those provisions. “We want the economically preferable provider and if we’re not, we need to reevaluate some decisions,” he commented. In addition to supporting Teck at Red Dog, Kuna is engaged in rural development work, such as alternative energy projects for Alaska villages. “Really, we believe in Alaska, so all the pieces that weren’t Alaska we just let go,” Billingsley said. Elwood Brehmer can be reached at [email protected]

Successful Slope season stirs optimism at DNR

Alaska’s top resource managers believe a successful exploration season could signal the dawn of a renaissance on the North Slope. Department of Natural Resources Commissioner Andy Mack said that ConocoPhillips going “six-for-six” and finding commercial quantities of oil in all of the exploration wells it drilled last winter is not only encouraging for the company, but for the long-term future of the state as well. “I think what we see is the success rate of drilling wells in the Arctic is really high based on modern technology, really good seismic data, the fact that they’re starting to hone in on the Nanushuk formation. It’s incredibly good news for Alaska,” Mack emphasized in an interview. He pointed specifically to the Putu-2 well drilled near the Native Village of Nuiqsut as strong evidence that those technologies can be combined with targeted measures to reduce the above-ground impacts of exploratory drilling to result in the ability to search for and produce oil from areas that otherwise would face resistance for one reason or another. The Putu-2 well was spudded in February about three miles northeast of Nuiqsut, which sits on the edge of the Colville River delta, and is on the western edge of established Slope oil infrastructure. The area is also just south of the highly prospective Pikka Unit that Armstrong Energy is set to transfer to Papua New Guinea-based Oil Search in June. Spanish oil and gas major Repsol also holds a 49 percent stake in Pikka, according to the state Division of Oil and Gas. Armstrong estimates the Pikka Unit holds roughly 1.2 billion barrels of recoverable oil and could produce upwards of 120,000 barrels of oil per day once fully developed from the shallow and conventional but underexplored Nanushuk oil formation. A development plan for Pikka is currently being reviewed by the U.S. Army Corps of Engineers through the environmental impact statement process. First oil from Pikka is tentatively scheduled for 2023. “It’s hard to overestimate the value of what we see in the Pikka Unit specifically, in the Colville (area) generally, in the NPR-A, and they were able to drill those wells fairly close to the Village of Nuiqsut,” Mack said. “They did so with the support of the borough, with the support of the community — and we understand that’s not 100 percent — but it was a very safe operation and we think it will open the door to more development and similar operations like the one that we saw this winter.” ConocoPhillips first planned to drill the Putu well in early 2017. That exploration plan was a driving force behind Mack overturning his predecessor’s decision and transferring all 9,100 acres in and around Nuiqsut, and once part of the now defunct Tofkat Unit, from the small independent Brooks Range Petroleum Corp. to ConocoPhillips. However, those plans caught the attention of Nuiqsut residents, who became concerned that, among other things, exhaust from a traditionally diesel-powered drilling rig, which would be running continuously for more than two months, would ride the prevailing winds into the community. Kuukpik Corp. is the Native village corporation for Nuiqsut and holds title to about 147,000 acres on the Slope. It jointly holds surface rights along with the state to the Putu acreage, which the Department of Natural Resources awarded to ConocoPhillips in November 2016. The company has also taken on the role of being a public voice for the community of about 400 residents that it answers to. While a relatively small area in North Slope terms, the acreage around Nuiqsut is seen as a potentially rich piece of property given it is adjacent to the Pikka Unit as well as ConocoPhillips’ established Colville River Unit just to the north. ConocoPhillips held the acreage in the early 2000s but had to give it back to the state after failing to meet drilling requirements. Brooks Range also held the leases for years but was unable to secure an access agreement with Kuukpik, according to documents previously submitted to the state. ConocoPhillips Alaska leaders went as far as to state publicly even before drilling commenced that the Putu prospect could someday produce 20,000 barrels per day, a signal of confidence from the usually conservative, publicly traded oil company. Similar estimates were applied to the Stony Hill well, which the company also drilled last winter to the south of Nuiqsut. ConocoPhillips cited the concerns coming out of Nuiqsut as its reasons for deferring the exploration program, a move DNR officials were not happy with because the acreage was awarded to the company on the premise it would drill quickly. Mack eventually agreed to allow ConocoPhillips to keep the leases in August 2017 as long as the company committed to drill the Putu well when it did and pay the state up to $7 million in two installments by August 2020 if the decision is made to bring the area into production. Nuiqsut residents and Kuukpik Corp. focused their requirements on making the drilling as inconspicuous as possible. The drill site was moved about a half-mile farther from the village than initially planned, along with numerous other impact mitigation measures. The drilling rig, owned by Kuukpik, was electrified instead of diesel-fired. It was powered by six 975-horsepower, low-emissions diesel generators set about a mile north of the ice drilling pad. Exhaust scrubbers installed on the generators make them as much as 90 percent cleaner than the traditional drill rigs by capturing much of the sulfur and other particulate matter found in diesel exhaust before it is emitted, according to Kuukpik CEO Lanston Chinn. Multiple sensor stations monitoring for air, water and noise pollution originating from the Putu pad were also installed around Nuiqsut, in addition to other efforts aimed at reclamation procedures and lessening the impacts of gas flaring. Chinn said prior to the drilling that he believed the mitigation measures set a new standard for exploratory drilling, if not Slope-wide, at least on Kuukpik land near Nuiqsut. “They did a great job of executing the plan,” Mack said of ConocoPhillips’ work at Putu. Chinn concurred in a brief interview after the drilling was complete, noting, “There weren’t really any complaints to speak of” coming from Nuiqsut residents. He said further drilling proposals to delineate the Nanushuk formation in the area would be handled on a case-by-case basis. ConocoPhillips has until Aug. 15 to decide whether or not to make a $3 million lease bid-replacement payment to DNR in accordance with Mack’s August 2017 ruling. Mack said the company has not yet made the payment, “but we have every reason to believe from the announcements that we’ve had and heard and our observations that what we’ve proposed has worked.” The $3 million payment equates to a lease sale bid of roughly $320 per acre for the area known to be highly prospective. ConocoPhillips spent up to $111 per acre to win leases in the same general area in the state’s December 2016 North Slope sealed-bid lease sale. However, that payment would only allow the company to keep the area until 2020 and would also commit ConocoPhillips to drilling another well into the Nanushuk within the next two years. Further, the company has until Aug. 14, 2020, to make another $4 million bid-replacement payment if it wants to keep the acreage long-term for development. ConocoPhillips spokeswoman Amy Burnett said via email that the results from the exploration season were promising but the company still had extensive information to review prior to making any decisions about its plans for the 2018-19 winter Slope work season. She also noted that any development of Putu could be done with directional drilling from gravel pads farther away from the village. Mack said state officials would also keep an open dialogue with Nuiqsut residents about what can be done to ensure development around their village does not disrupt their way of life. “What we’re seeing is companies are better than ever at executing extended reach drilling and the actual production facility for the same area that was explored this winter — we have more flexibility, Mack said. “We’re going to continue to have that discussion about subsistence and quality of life and the things that are happening in that village. What I would envision happening is when (ConocoPhillips) gets to the production phase they’re going to be able to place permanent facilities that will not be as close as the exploration project this winter and still effectively produce.” Chinn said it is premature to speculate about permanent Putu development and Kuukpik leaders would discuss the relevant issues with ConocoPhillips when the time comes. More success in NPR-A While the apparent success at Putu is a win for the state given the complex history of exploration challenges in the area, ConocoPhillips also drilled three wells to the west, in the National-Petroleum Reserve-Alaska. Those wells were drilled to better delineate its Willow discovery — another Nanushuk prospect — which was first announced in January 2017. Preliminary estimates from the company put Willow at about 300 million barrels of recoverable oil, with production potential reaching 100,000 barrels per day. Alaska oil experts believe the Nanushuk formation, which for decades hid in plain sight, is largely a western Slope phenomenon; it quickly peters out to the east of the Colville Delta. However, 3-D seismic data indicates the oil-bearing formation could be prolific in the NPR-A, leading the state officials to keep pushing the Bureau of Land Management to revise its management plan for the reserve. Last May, while on a trip to Alaska, Interior Secretary Ryan Zinke issued an order directing the U.S. Geological Survey to update its oil and gas resource estimates for the reserve. That mean estimate, released in December, projects the NPR-A and nearby areas hold upwards of 8.8 billion barrels of oil predominantly in the previously overlooked Nanushuk formation. The previous resource assessment done in 2010 estimated the NPR-A held just 896 million barrels of technically recoverable oil. More than 7 billion barrels of the new oil estimate is expected to be in the northeast corner of the NPR-A, most of which was closed to oil and gas leasing by the Bureau of Land Management in the 2013 NPR-A Integrated Activity Plan. The area was put off limits to industry to protect subsistence activities and critical habitat for the Teshepuk Lake caribou herd. Environmental groups speculated when Zinke directed the assessment that it would be used as justification to open the protected area to industry. Mack said the Gov. Bill Walker and his administration would like to see BLM “rebalance the plan.” “We would look forward to a conversation about really defining what areas have (oil and gas) potential in what is the northeast NPR-A and what areas need to be protected,” Mack said. “This is a petroleum reserve. We would take our lead and be listening very carefully to the North Slope Borough, for instance.” State officials have also discussed the issue with area Native corporations and tribes, according to Mack. “Plans are always informed by new information,” he added. While federal land, oil and gas production from the NPR-A — expected to officially commence for the first time late this year with the startup of ConocoPhillips’ Greater Mooses Tooth-1 project — is subject to state taxes. The State of Alaska also receives half of federal royalty and lease sale revenue generated from the NPR-A. Mack said that the administration has made its feelings clear to Zinke, but also noted the NPR-A plan is one of several things the state is advocating to Interior for just in the North Slope region. “There’s an issue of how much we can get done in a short amount of time,” he said. ^ Elwood Brehmer can be reached at [email protected]

Lower costs, federal tax cut boost producers’ share of profits

For at least one quarter, the total taxes paid by Alaska’s largest oil producer appear to contradict a longstanding argument against raising them, but ConocoPhillips maintains that the results jive with its previous statements to the Legislature. Alaska oil industry advocates have fought attempts to raise North Slope oil production tax in part by insisting that “total government take,” an all-in calculation of combined taxes, royalties and fees paid to the state and federal governments, consistently exceeds the share of profits large companies are allowed to keep on the oil they produce at all prices. That claim has generally applied to the three major producers of BP, ConocoPhillips and ExxonMobil, which own the Prudhoe Bay, Kuparuk and Alpine oil fields that provide the lion’s share of North Slope production. More recently Hilcorp has joined those three as a large producer by state taxing standards with more than 50,000 barrels of production per day. ConocoPhillips reported net income of $445 million in the first quarter, while paying $400 million to governments — $298 million to the State of Alaska in royalties, property, income and production taxes, and $102 million in federal corporate income taxes — for a government take of 47 percent while the company correspondingly kept 53 percent of its taxable revenue. Before a one-time $79 million special item expense related to a Trans-Alaska Pipeline System tariff settlement, the company had $524 million in net earnings from Alaska. The company, Alaska’s largest oil producer, is required to break out its Alaska operations in its regular corporate financial reporting to the Securities and Exchange Commission because its activities in the state account for significant segment of its worldwide business. ConocoPhillips Alaska representatives emphasized that total government take is still greater than what the company retained based on its first quarter 2018 earnings. Spokeswoman Amy Burnett wrote in an email that on a net cash flow basis, which has been the basis of its presentations over the years to the Legislature, the company kept $367 million during the first quarter, or 48 percent of its total net cash flow of $767 million. The end net cash flow is calculated, according to Burnett, by adding back a $185 million depreciation expense on the company’s assets to the $445 million profit before deducting $263 million in capital expenditures for the quarter to arrive at the $367 million figure. Alaska Tax Division Director Ken Alper said total government take should generally be in the “low 50s range” at recent prices, but noted that “if you’re in a low 50s paradigm it doesn’t take that much to get further into a high 40s paradigm.” However, on the most basic level, “If in fact they’re now below 50 percent in the first quarter that’s going to be a hard admission for them because their reports are always caveated with how much taxes they pay.” Alper said that the changes in the numbers are driven by lower company costs and federal tax reform, which cut the top corporate tax rate from 35 percent to 21 percent as of Jan. 1. Before the federal corporate tax rate cut, the state share was larger than the producer share at all prices. The federal tax cut now puts the producer share larger than the state’s at prices up to $85 per barrel. Total take The complex state production tax is geared to support small companies and those producing oil from new developments while capturing revenue from the owners of the large, aforementioned legacy fields. ConocoPhillips Alaska leaders asserted in an April 2017 presentation to the House Finance Committee about a proposal to increase production taxes that the company’s share of taxable revenue peaked at 38 percent at oil prices between $70 to $80 per barrel. The company’s share shrank to 15 percent at roughly $45 per barrel and quickly became negative at prices of about $40 per barrel when costs outpaced revenue and the company began losing money on each barrel it produced. Companies and supporters of the current system note the royalty and gross tax require the producers to pay hundreds of millions each quarter during such exceptionally low price periods when they are losing money on each barrel of oil they produce. Burnett stressed, as others in the industry have, that the state’s tax and royalty levels must remain competitive with other regimes around the world so the producers will continue to invest in Alaska’s high-cost North Slope. BP paid $464 million to the state in 2016 when it lost $358 million in Alaska overall, with operating expenses combined with low prices more than erasing the $85 million North Slope upstream profit, according to BP Alaska Region President Janet Weiss. ConocoPhillips paid $492 million to the state in 2016 when it made $319 million here but lost $3.6 billion companywide. State royalties of 12.5 percent to 16.6 percent, depending on the leases where the oil is produced, and the gross 4 percent minimum production tax are collected regardless of a company’s profitability. During its April 2017 presentation at the Legislature, ConocoPhillips estimated the federal government would take 20 percent to 21 percent of the taxable revenue while the state would collect the remaining 41 percent to 42 percent in the $70 to $80 per barrel price band. More recently, during a Jan. 29 House Resources Committee meeting on another oil tax increase bill, company representatives showed a similar slide indicating a company’s would “take” peak at 48 percent when oil prices averaged $65 per barrel when the state got 39 percent and the feds took 13 percent. The chart also shows a large producer is likely profitable at lower prices as well, with the company not going into the red until $35 per barrel oil and still retaining 23 percent of taxable earnings at $40 per barrel prices. While the federal corporate tax calculation is seemingly a simple one — 21 percent of a company’s net earnings after state taxes and royalties are deducted — federal tax credits and depletion allowances mean companies are likely to not always pay the full rate, which would lower the government’s share from the high-level charts ConocoPhillips Alaska leaders used in their testimony to the Legislature, according to Alper. BP reports less-specific Alaska results to the SEC in its public annual reports and ExxonMobil, which discloses very little on any matter as its general practice, does not need to disclose its Alaska financials. BP netted $830 million in upstream Alaska profits, according to its 2017 annual report published in late March — on the back of $3.2 billion in operating revenue — is due to a roughly $500 million federal corporate tax accounting benefit stemming from the tax reform Congress passed in December. BP Alaska held a deferred tax liability of nearly $1.3 billion in 2016; that liability fell to $838 million in 2017, according to the report. A BP spokeswoman referred further questions about the company’s taxes in the state to the annual report. Gross versus net ‘crossover price’ The major producers were not eligible for the state’s now-scrapped North Slope refundable tax credit program, but they can purchase un-refunded credits from small companies to reduce their own production tax liability — potentially at steep discounts. The Department of Revenue estimates roughly $100 million of credits will be sold to the large producers over the next several years. Alaska’s oil price-linked production tax is structured to act as a progressive net profits tax at higher market prices and as a gross tax that ensures the state makes some revenue at lower prices. Whichever calculation between the net profits calculation, with the per-barrel credit that grows at low prices, and the simpler 4 percent gross tax is the one the state applies to tax North Slope oil. Currently, that “crossover” price, where the applied tax switches from the gross to the net tax calculation, is currently at about $65 per barrel based on the latest aggregated data reported to the state by the producers, according to Alper. The crossover price has been falling in recent years as companies have cut costs to while prices have been mostly less than $70 since late 2014 and bottomed at $26 in January 2016. In fiscal year 2015, North Slope operators deducted on average $43.60 in lease expenditures per barrel from the net taxable value of their produced oil, according to the Revenue Department. Today, those lease expenditures have fallen to about $25 per barrel, according to Revenue Department estimates. As a result, the state’s take is at its smallest percentage in relation to the profitability of the oil when near the gross-net crossover price as was the case in the first quarter. ConocoPhillips reported an average realized price of $68 per barrel in the first quarter on its Alaska oil. “There has been more efficiency in the industry and that has made them money but that has also made us money because it lowers the breakeven price of a barrel of oil,” Alper said during January testimony to the House Resources Committee. Unrestricted state petroleum revenue is expected to total $1.8 billion in the current 2018 fiscal year, with $654 million of that coming from oil and gas production taxes and the remaining majority coming from property and corporate taxes and royalties, according to the Revenue Department’s Spring 2018 Revenue Forecast. The state took in $876 million of discretionary petroleum-derived revenue in 2017 and the forecast is for $1.6 billion in unrestricted petroleum revenue in 2019. Supporters of the current system point to the increases in production even amid lower prices from 2015-17 as proof the tax regime is working for both the companies and the state. Alper said in an interview that the numbers between the companies would differ at least slightly because each has different spending patterns, noting ConocoPhillips is generally spending more than the other majors on capital expenditures as it is working to evaluate and develop several large prospects at once. ConocoPhillips drilled six separate exploration and appraisal wells this past winter, its busiest season in 15 years. Members of the Democrat-led House Majority Coalition have cited Department of Revenue reports that the effective production tax rate since 2015 has been as low as at any point in the state’s history as a reason to reform the current tax structure. The average tax rate during the last phase the state relied on a gross production tax prior to 2006 was as low as 6.4 percent in 2004 but generally higher. The economic limit factor, or ELF, tax rates varied depending on the field it was produced from. Alper added that the state paid $50 million in production tax true-ups in April on 2017 tax payments because of “migrating” per-barrel credits that companies can earn in one month and apply to another during years when oil price fluctuations push the tax between the gross and net systems. A similar situation occurred when prices collapsed in the latter half of 2014 and pushed the Walker administration to propose changes that would limit the ability of companies to use “migrating” per-barrel credits. As a result, just a few months of prices above the crossover point does not necessarily lead to additional state revenue, according to Alper. “I think the issue for the people interested in re-engaging in oil taxes is (government take) used to be deeper into the 60s and even into the 70s,” he said. Anchorage Democrat Sens. Berta Gardner and Bill Wielechowski cited a Legislative Research Division memo in a May 4 press release that states Alaska is ConocoPhillips’ most profitable region worldwide “by a wide margin.” “As this state continues to deflect billions of dollars in oil revenues in the form of per-barrel credits, the burden to balance the budget and provide necessary services is solely, and erroneously, forced upon working Alaskans,” Gardner said. “This is not about one company making significant profits. It’s about providing a balance to fixing our economic situation, and it takes all of us to achieve that.” The $445 million first quarter profit in the state, which is after the $79 million TAPS tariff special item deduction, was 39 percent of the company’s overall profit of $1.1 billion despite Alaska accounting for just 15 percent of its global oil and gas production. Further, ConocoPhillips netted an average of $26.18 per barrel of oil equivalent in Alaska during the period, compared to a $10.06 net per barrel average globally. Elwood Brehmer can be reached at [email protected]

As AGDC makes deals, details remain confidential

Those leading the state’s effort to commercialize its North Slope natural gas resources have touted recent agreements with key potential players in the $43 billion Alaska LNG Project as proof the project is viable and ever closer to coming to fruition, but what is in those agreements and how it impacts the state remains largely unknown. Gov. Bill Walker and Alaska Gasline Development Corp. President Keith Meyer signed the Nov. 9 joint development agreement, or JDA, with the government-owned Chinese mega corporations of Sinopec, an oil and gas company, the Bank of China and China Investment Corp. While a nonbinding agreement meant to set the framework for further negotiations, Walker and Meyer have characterized it as a watershed agreement because — in addition to being signed in front of the leaders of both countries — it brought entities into the fold that could finance a majority of the project in exchange for purchasing most of its end product, liquefied natural gas. Specifically, the JDA outlines the prospect of Sinopec signing up for up to 75 percent of the project’s liquefaction capacity with the Bank of China and China Investment Corp., the country’s sovereign wealth fund, providing a corresponding level of debt and equity financing to fund it. It also sets a soft May 31 deadline for the parties to have better defined the roles of each before finalizing those roles with binding deals later this year, as it notes Sinopec could also potentially participate in engineering, constructing or managing the project. It expires Dec. 31. As envisioned, the Alaska LNG Project would produce 20 million tons of LNG per year at full production, but Meyer has said the project could be built in phases if the market, financing or gas supply prevents full up-front development. Other, similar nonbinding agreements with potential Asian LNG buyers Korea Gas Corp., or Kogas, PetroVietnam Gas Corp. and Tokyo Gas have been announced ahead of and after the China JDA, but the details of those deals remain sealed. Walker said at the time that he insisted the JDA be made public despite objections from Chinese officials. On March 27, AGDC announced it had secured two of the world’s largest banks, again, the Bank of China, and Goldman Sachs, to assist the state-owned corporation in raising multiple rounds of debt and equity investment for the project. AGDC officials denied records requests for the memorandums with the other potential LNG purchasers and the contracts with the Bank of China and Goldman Sachs, citing the commercially sensitive information the documents contain. Spokeswoman Rosetta Alcantra wrote in a prepared statement that “Both Goldman Sachs and Bank of China will serve as AGDC’s financing arrangers, underwriters and placement agents for Alaska LNG. Bank of China will focus on raising funds from Chinese sources and Goldman Sachs will focus on U.S. and other international investors.” Additionally, Alcantra wrote, “The two companies will be paid a reasonable fee for services provided. Additionally, they will receive a success fee upon procuring necessary financing for Alaska LNG.”. The Legislature provided the public corporation exceptionally broad authority to withhold documents and information for commercial reasons in Senate Bill 138, the legislation that established an operational path for AGDC to participate in the prior, producer-led iteration of the project, and passed with broad bipartisan support in 2014. However, AGDC has released other contracts it has signed to media outlets, including agreements with Washington, D.C.-based consultants providing services as liaisons between Congress and the Trump administration. In an interview following the Bank of China-Goldman Sachs announcement, Meyer said the corporation works hard to be as transparent as possible through its board of directors meetings and legislative hearings in which AGDC officials testify and update the Legislature on Alaska LNG progress. “We’re dealing with public money and the money is to get a project done and we’re operating in a very, very competitive arena and we’ve got to recognize that. We’ve got to recognize that we’re somewhat handicapped because of this need to be so public,” Meyer said. “We’ve got people who can take pot shots at us in the public arena — having all of our commercial agreements out there posted on the internet by the press. We’ve got to recognize there’s some justification for that, no doubt, but at the same time it hinders us in this very, very competitive landscape and it’s getting increasingly competitive.” Working as a public entity in the closed-door oil and gas realm where success is measured in billions of dollars, Meyer said he welcomes the critiques and comments from Alaskans in positions of power or the public at-large and wants to be responsive whenever possible. “It pains me to get a request for information and not be able to comply. In spite of what you may have been led to believe we’re trying to be as transparent as we can at every turn,” he said. AGDC leaders have been willing to conduct interviews when their schedules allow. Additionally, Meyer noted he instituted a strict policy of following best business practices when he took the helm at the corporation in June 2016. “To me, and I’ve told the folks here, we’ve got to make decisions based on business fundamentals and they’ve got to be scrutinized on that basis. We don’t do a single thing here that has a political motive or has some appearance of something like that. It is strictly focused on execution. We’re trying to build America’s largest energy export project; that’s what we’re focused on; that’s what we’re doing and we’re fighting lots of people bigger than ourselves,” he said. The bank contracts have been withheld at the request of the banks, which didn’t even want their deals with AGDC shared between the two, according to Meyer. He further stressed that when it comes time to spend significant amounts of state money — during a time when the state is running budget deficits — the commitments the corporation makes will be “quite open.” “In terms of the banker deals, those guys get paid when they bring in third party money, not Alaska money; they don’t get paid for Alaska money,” said Meyer, who added they won’t get paid with State of Alaska money, either. “They get paid with a slice of the third party funds they bring in. If they don’t bring in funds there’s no slice that they get.” Most recently, AGDC announced May 7 it had inked a binding agreement with BP on the primary terms of a gas sales contract including price and volume to supply the Alaska LNG Project. As expected and generally understood, the key terms of that deal are confidential given — beyond BP’s desire that they remain classified permanently — AGDC would not want to compromise the similar negotiations it is still in with ConocoPhillips and ExxonMobil. Meyer and Walker said in separate interviews that the gas supply terms, which presumably commit AGDC to buy BP’s produced gas just before it enters the project’s North Slope gas treatment plant, are likely to be made public eventually, but neither could say exactly when. Legislators who have followed AGDC’s progress closely said they are most concerned about the project’s netback to the state treasury and how that might be impacted by the gas supply agreements. Anchorage Democrat and House Resources co-chair Rep. Andy Josephson said he expects AGDC will be required to disclose the terms of the major commitments it makes closer to when the corporation is ready to make its final investment decision, but he wouldn’t want those disclosures to run afoul of any agreements to the contrary. AGDC has pegged its final investment decision for early 2020 to coincide with when the Federal Energy Regulatory Commission has said it will rule on the Alaska LNG environmental impact statement. Meyer has said the state should expect at least $250 million per year in revenue from the project based on high-level financial modeling, while some legislators are wondering what happened to consultant reports that pegged the state’s annual income from Alaska LNG in the billions of dollars when the producer companies were directly involved in the project prior to 2017. A major change in the revenue estimate is largely to due global natural gas and LNG spot market prices that were twice as high in 2014 as they are currently, with delivered LNG prices to Asia now in the $7 per thousand cubic feet range, according to FERC. Senate Resources chair Sen. Cathy Giessel, R-Anchorage, said she appreciates why the gas sale terms are kept close to the vest, but said she wants to know how those terms relate to oil and gas taxes in addition to also having questions about state revenue from Alaska LNG. “What if the state of Alaska during this (project) raises production taxes? Will those added tax liabilities by passed on to AGDC or the LNG buyer?” she questioned. Giessel is the only legislator to have signed a confidentiality agreement with AGDC to review sensitive documents, but she did so prior to the state entity taking control of the project in early 2017 and said it’s her understanding that agreement is not valid for the current iteration of Alaska LNG and the documents produced to support it. She also noted the state taking over the project is not what the Legislature agreed to when it passed SB 138 and may not have given AGDC such broad authority to withhold information. “I believe had we ever envisioned it becoming a state-led project like this we would have structured it differently,” Giessel said. “In (Meyer’s) hands is the sole authority to commit the state and its resources for decades.” ^ Elwood Brehmer can be reached at [email protected]

Final budget deletes receipt authority for state gasline corp.

The Legislature left plenty of items in Gov. Bill Walker’s budget and added to others, but it took out a key provision in the Alaska Gasline Development Corp.’s effort to bring the Alaska LNG Project to fruition. Lawmakers pulled language allowing the gasline agency to accept outside funds from investors, known as receipt authority, for the $43 billion project in the 2018 and 2019 fiscal years. AGDC President Keith Meyer said in a statement to the Journal that he and his team look forward to working with the Legislature on the important aspects of the project as it advances. But lacking a substantial injection of new money could potentially challenge the ability of the corporation to stay on its desired schedule. AGDC leaders expect to have $52.5 million at the start of the 2019 state fiscal year that starts July 1, according to documents from its May 10 board of directors meeting. The state-owned corporation took over control of the Alaska LNG Project in January 2017 with $106 million remaining from prior gasline appropriations. An austerity program instituted by AGDC leaders at that time has helped them under-spend on their budget by $35.7 million since, Finance Manager Philip Sullivan said at the meeting. As a result, the corporation should be able to continue operating on its existing funds through June 2019, according to Sullivan. Senate Resources chair Sen. Cathy Giessel said in an interview that she believes AGDC can continue to advance the project’s environmental impact statement being drafted by the Federal Energy Regulatory Commission. Senate Republicans by and large have been the most skeptical legislators about the administration’s plan for the state-led gasline. FERC is expected to issue a record of decision on the project in March 2020. Meyer said May 10 — before the final operating budget was passed — that the corporation would soon initiate work drafting contracts for engineering, procurement and construction, or EPC, management firms to finish designing and build the project. The different aspects of the complex project — a North Slope gas treatment plant, 807 miles of buried, 42-inch pipeline, a very large LNG plant and marine terminal — will likely require multiple firms with varying areas of expertise to complete, according to Meyer. He has said AGDC has been in discussions with EPC firms for some time. Additionally, AGDC will soon be getting ready for an equity offering, Meyer said May 10. Giessel said she wouldn’t expect the corporation to secure EPC firms with its remaining funding, adding that third-party receipt authority shouldn’t be confused with financing for the corporation. “AGDC has plenty of revenue to continue on with the FERC process,” she said. “That’s what they need to focus on.” With AGDC seeking non-recourse debt and equity to finance the vast majority of Alaska LNG from banks and third-party investors, many legislators are concerned granting the corporation the ability to accept those funds would be ceding most of lawmakers’ oversight of the project. Giessel said AGDC leaders have yet to answer questions regarding how much equity ownership the state will have to give up and for how substantial an investment return among others. “These questions have to be answered before the Legislature gives up its appropriation authority on this project,” she said. The Legislature could revisit funding the project when it convenes next January if AGDC can provide more details on it, Giessel suggested. AGDC spokesman Jesse Carlstrom wrote that as corporation officials work with Goldman Sachs and Bank of China to arrange third party funding they will continue to keep legislators informed on all aspects of the project. “AGDC understands Alaska’s lawmakers are committed to making decisions that are in the best interest of all Alaskans,” Carlstrom said via email. “Throughout the remainder of 2018 and into 2019, AGDC will continue to present the Legislature with the information lawmakers need to make appropriate decisions for the responsible development of Alaska’s vast amounts of proven, stranded, North Slope natural gas.” The House originally limited the receipt authority to $1 billion per year rather than the open-ended language in Walker’s budget. However, some in the Legislature were still concerned the administration could use a procedural maneuver to request unlimited receipt authority through the Legislative Budget and Audit Committee outside of the regular session — a request the Legislature would have no authority to deny. Giessel also noted the Legislature did approve AGDC to use $12 million previously committed to the smaller, in-state Alaska Standalone Pipeline, or ASAP, project for the larger Alaska LNG export plan as the corporation had previously requested. House Resources co-chair Rep. Andy Josephson, D-Anchorage, said he shares AGDC’s concerns about the appearance of the Legislature’s hesitancy to support the project. “Markets and investors may be squeamish that we wont even agree to accept someone else’s money,” Josephson said. “I’ve been told it puts AGDC in a light they don’t want to be in.” He said Walker could call a special session to resolve the matter if he feels it warrants such an action, but Walker said after the session ended May 13 he had no intention to do so for any reason. Josephson noted further that if the Legislature would have acted before this year to implement a fiscal plan and drastically reduce the multibillion-dollar budget deficits it covered with the state’s savings for four years, lawmakers would have more flexibility to control the project. “With $10 billion in savings we could’ve done it ourselves,” Josephson added. Elwood Brehmer can be reached at [email protected]

Former UA Regent sues state over tax credit bonding plan

(Editor's note: This story has been updated from its orginal version to include comments from Eric Forrer, who filed the lawsuit, and his attorney Joseph Geldhof.) Questions regarding the constitutionality of the Walker administration’s plan to pay off the state’s $800 million-plus oil and gas tax credit obligation will likely be answered sooner than later. Former University of Alaska Regent Eric Forrer filed suit against the administration May 14 in Juneau Superior Court, just two days after the Legislature passed House Bill 331 authorizing the Department of Revenue to sell bonds to pay the credits. The lawsuit, filed in Juneau Superior Court, 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, including Attorney General Jahna Lindemuth, contend the plan 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. Department of Revenue officials testified in hearings on the matter that the arrangement has been used in the past to fund other projects. However, Forrer’s complaint argues that “Failure by future legislatures to make funds available to repay the ‘subject to appropriation’ bond scheme contained in HB 331 will have a negative impact on the credit rating of the State of Alaska,” just as not repaying more traditional general obligation bonds would. “The implied promise in HB 331 that future Alaska legislatures will make appropriations to satisfy the ‘subject to appropriation’ bond scheme contained in the legislation essentially amounts to an impermissible dedication of funds contrary to the Alaska Constitution,” the complaint continues. The state Constitution generally limits the Legislature from bonding for debt to 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 Revenue Commissioner Sheldon 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. The Walker administration hopes that paying off the credits in a lump sum would 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 Fisher and supporters of the plan in the Legislature. The 72-year-old Forrer said in an interview that he filed the lawsuit in the public's interest, adding that "atta boys are pouring in over the transom" since it became public. It's clear the state owes the credit money, he said, but noted it has also lived up to the law by making annual appropriations in line with the statute that spells out the calculation for the oil-price driven minimum credit payment formula in the past two budgets. "The pressure point is coming, we presume, from the banks and the oil companies holding credits," Forrer said. He suggested the Legislature and the Walker administration should have put the bonds up to a vote of the people, as is required for GO bonds, and that they should've expected a court challenge in the absence of additional measures to quell the constitutionality questions surrounding the plan. An amendment to HB 331 by Rep. Scott Kawasaki, D-Fairbanks, that called for a public advisory vote on the bonds was rejected during debate on the House floor. Questions to the Department of Revenue regarding how the suit might impact the bond sale were responded to by the Department of Law. Spokeswoman Maria Bahr said the Revenue Department will review the issue with its legal counsel and, as is general practice, the Law Department would not comment further on the active litigation. One matter state attorneys will likely analyze is whether or not the issue is “ripe” for a challenge given Walker has yet to sign HB 331 into law. The complaint notes that given it is the administration’s bill “the likelihood that HB 331 will become law is as certain as anything can be in the political context.” Forrer's attorney Joseph Geldhof acknowldeged there is a pottntial ripeness issue in filing the suit before HB 331 is officially the law of the land, but said they wanted to give Walker an opportunity to veto the bill and call the Legislature into a special session to address at least this year's credit payments. He said there is "a strong moral obligation" for the state to pay the tax credits, but turning that into a debt that could impact the state's credit rating is not the proper, or legal, way to do it. The suit also alleges a provision in the bill attempting to limit legal challenges to a period within 45 days after approval of a resolution to authorize a bond sale is an unconstitutional restriction on citizens’ abilities to seek judicial review. The provision was added to the bill by the Legislature after the constitutionality issues were raised. "It shows we're running the state like a clubhouse gang and not a real state," Geldhof said. The administration has 40 days to respond to the complaint. Elwood Brehmer can be reached at [email protected]

Hilcorp again lone bidder in Cook Inlet sale

For the second consecutive year Hilcorp Energy had free rein over the state’s annual Cook Inlet oil and gas lease sale. The Houston-based independent producer was again the only company to bid on tracts in the basin, which was revealed Wednesday morning when Division of Oil and Gas officials opened the bids. Hilcorp, the dominant natural gas supplier in the Inlet, spent about $298,000 on eight lease tracts over 16,636 acres, according to the preliminary results tallied by the division. Its bids ranged from $16 to $25 per acre. Most of the leases are on the southern Kenai Peninsula in the Anchor Point area near the onshore Nikolaevsk and Deep Creek units. Those units are mostly gas plays, according to Oil and Gas Director Chantal Walsh, but the company also bought two tracts near BlueCrest Energy’s Cosmopolitan development on the shores of the Peninsula. The near shore Cosmopolitan unit holds both oil and gas, but BlueCrest has focused on developing the oil resource first. Hilcorp also acquired two more leases between the offshore Trading Bay and Kitchen Lights units in the middle Inlet, which is another area with both oil and gas potential. “We’re excited that Hilcorp is still exploring in Cook Inlet,” Walsh said after the sale. In 2017 Hilcorp spent $3.95 million on 20 tracts over both state and federal acreage in the basin. The state’s 2016 Inlet lease sale drew no bids and industry representatives said that was due in large part to the state Legislature debating whether or not to end its oil and gas tax credit program for work in the basin at the time, which it did. Companies used the credits to offset their exploration and development costs. There is also limited interest in Inlet natural gas, as production from the basin supplies the relatively small demand from Southcentral gas and electric utilities and low global LNG prices have killed the economics of exporting Inlet gas. The plans for the Donlin and Pebble mine projects in Western Alaska include piping Inlet-sourced gas to the mines as feedstock for their on-site power plants. Those projects, as well as the possible reopening of the former Agrium, now Nutrien, fertilizer plant in Nikiski could provide new gas demand and trigger more gas development in the basin, but those plans are all uncertain and at least several years away. Elwood Brehmer can be reached at [email protected]

House approves tax credit bonds in split vote

Tangible action in Juneau is ramping up as the session winds down in the final week before legislators bump up against the 121-day constitutional limit. Amidst passing one of the most momentous pieces of legislation in the state’s history May 8 to use the earnings of the Permanent Fund for government services, the Legislature continued to plug away at the other big bill from this year’s session: the Walker administration’s plan to sell bonds to pay off the state’s $800 million-plus oil and gas tax credit obligation. House Bill 331 didn’t gain traction until late into the session but it has been moving along promptly in the past several weeks. It is largely seen as a substantial piece of end-of-session budget negotiations. The House passed its version of HB 331 May 3 on a 22-16 vote that split members of both the Democrat-led majority and Republican minority. The lion’s share of concern with the bill among those who voted against it related to questions about its constitutionality raised by Sen. Bill Wielechowski, D-Anchorage, about Senate Bill 176, its companion legislation . Others voting against the plan argued it would pit the need to make the debt payments against other funding priorities like education and public safety. HB 331 would create the Alaska Tax Credit Certificate Bond Corp. within the Department of Revenue to sell the bonds and pass the proceeds of the sales on to the bondholders, of which there are 37, according to Deputy Revenue Commissioner Mike Barnhill. The bonds would be “subject to appropriation,” meaning the revenue to pay for them would be contingent upon the Legislature appropriating money to pay the debt service each year. The legislation would also require credit holders to accept up to a 10 percent discount on the amount they’re owed to cover the cost of the state’s borrowing and avoid spending additional state money on the all-but defunct tax credit program. Credit holders could also opt for a lesser discount rate in the 5 percent range if they agree with the Department of Natural Resources to negotiate a higher state royalty in future oil and gas production or commit to reinvest a portion of the payment back in Alaska projects. The bonds would be paid off over 10 years. The annual debt payments would be up to $115 million, according to the Revenue Department, and would be smaller than the largest projected payments the state would make paying off the debt under the current statutory formula. Another roughly $200 million bond sale will likely be needed in a couple years to pay off a few remaining credits that are expected to be claimed before the remaining LNG storage and Interior basin credits sunset in 2020, according to Revenue officials, bringing the total bond amount to about $1 billion. Wielechowski, with the support of an April 13 opinion from Legislative Legal Services attorneys, contends the plan could violate the state Constitution, which generally restricts the Legislature from taking on debt outside of voter-approved general obligation bonds for capital projects and times of emergency. The administration, backed by its own legal opinion from Attorney General Jahna Lindemuth, argues the “subject to appropriation” nature of the debt makes it constitutional because it requires annual approval of the debt payments by the Legislature. And while failing to service the debt would undoubtedly damage the state’s credibility among financial markets, there would be no legal requirement to make the payments. The House Finance Committee attempted to address the possibility of a legal challenge by adding a provision to HB 331 requiring any challenges be made within 45 days of a bond sale, the first of which is expected to happen in late summer if the bill becomes law, according to Revenue officials. Additionally, Fairbanks Democrat Rep. Scott Kawasaki pushed an amendment during floor debate to hold a public advisory vote before the bonds are sold in an attempt to mirror the vote needed to sell general obligation bonds. “I think at the very least we owe it to the people of Alaska when we’re passing such large legislation with such a large fiscal impact that will be seen 10 to 15 years to come that we have an advisory vote basically to assert that it is something the people would like to see,” Kawasaki argued on the House floor. The amendment failed 10-28. House Resources co-chair Rep. Andy Josephson, D-Anchorage, suggested that not passing the bill and paying the credits to the small companies that have earned them could lead those companies to sell the credits to the large producers at a steep discount and further “basin control” on the North Slope by the major producers, which was one of the primary things the credit program aimed to change. Eagle River Republican Rep. Dan Saddler said the bonds would provide a predictable payment plan for the Legislature that in recent years has not known what the credit obligation would be in any given year until the Revenue Department published its Spring Revenue Forecast. This year the statutory minimum credit payment would be $184 million, according to the administration. The interest-only debt payment would be $27 million. “These credits are a cloud hanging over our economy and this allows us to clear those clouds up. It’s a practical business deal,” Saddler said in floor debate. A May 1 financial analysis of the plan by former Department of Natural Resources commercial analyst and economist Ed King found that back loading the debt payments, as is Revenue’s plan, could save the state nearly $680 million compared to following the statutory formula repayment schedule that would require payments of nearly $400 million in the next two fiscal years. That’s because it would leave investment return-bearing money in the Permanent Fund Earnings Reserve longer and allow that money to grow. King is the principal at King Economics Group. However, that assumes the Permanent Fund’s investments continue to earn strong returns over that time, and that the legislature does not spend down the savings. Revenue Commissioner Sheldon Fisher has said repeatedly that the administration back loaded the debt payments to give the state several years to get on better financial footing before having to make $100 million-plus annual payments to service the bonds. As of early May 9, HB 311 was in the Senate Finance Committee awaiting amendments from the committee before heading to the Senate floor for a vote. Elwood Brehmer can be reached at [email protected]

Fund value increases in 3Q

The $64 billion Alaska Permanent Fund again earned strong returns in the third quarter of the state fiscal year and going forward its performance is likely going to be scrutinized like never before. Fund managers saw their investments grow by 8.86 percent in the quarter. The Permanent Fund ended the quarter up $4.8 billion for fiscal year 2018 at $64.6 billion, according to a quarterly report released May 2. The Permanent Fund is up 7.65 percent over the prior three years and 8.35 percent over the last five. All of those figures are better than the corporation’s passive index benchmark by at least 1.5 percent. On May 8, the Alaska Legislature quickly and quietly took the long anticipated step of passing legislation to utilize a 5.25 percent of market value draw from the Fund to support government and pay dividends. How much will go to either long-term is still unclear. It is a move the APFC Board of Trustees has advocated for to provide stability in the expectations of Fund managers for long-term investment strategies. The draw in fiscal year 2019, which starts July 1, is expected to be about $2.7 billion. And while the POMV has a nameplate of 5.25 percent, it is done on a five-year look back of the Fund’s average value over that time. That will make it an effective 4.35 percent draw, legislators noted. Those draws will come out of the Earnings Reserve Account, which held $15 billion in net income and $2.6 billion in unrealized gains as of March 31. At 41 percent of the Fund’s total assets, the corporation’s $26.8 billion public equities portfolio returned 11.42 percent fiscal year-to-date, 16.31 percent over the past year and 8.65 percent over the previous three years. The $7.6 billion of private equity and special opportunities investments have done exceptionally well, returning 18.94 percent over the past nine months and 22 percent over the past five years. The success is due in part to the Fund’s co-investment program of 23 investments averaging $46 million each and has netted a 64 percent internal rate of return since it was started five years ago, according to the report. Elwood Brehmer can be reached at [email protected]

Legislature approves draw from Permanent Fund

It took three years, eight iterations of legislation and countless hours of debate filled with both meaningful questioning and pandering rhetoric, but the Legislature was finally able to send the centerpiece of a fiscal plan to Gov. Bill Walker Tuesday afternoon by employing one of the oldest adages known to mankind: keep it simple. A House and Senate conference committee on Senate Bill 26 introduced and passed a bare-bones version of the legislation to establish a percent of market value, or POMV, draw from the Earnings Reserve Account of the $65 billion Permanent Fund in a seven-minute meeting Tuesday morning. By 2 p.m. it had passed the House and Senate on 23-17 and 13-6 votes, respectively. Sen. Anna MacKinnon, R-Eagle River, who has led the push in the Legislature for utilizing the earning power of the Permanent Fund to greatly reduce the state’s ongoing budget deficits, called the day “a historic moment in Alaska’s future” during the brief committee hearing. “Today, (May 8) legislators from across the political spectrum came together for a historic vote to protect Alaska’s Permanent Fund. This bill stabilizes our revenue stream, providing reliable funding for Alaskans who rely every day on state troopers, educators, and health care providers,” MacKinnon further said after the votes. Democrat House leaders noted the approved version of SB 26 is closer to what the Republican-led Senate passed last year, but noted it will help ensure the prosperity of the Fund into the future by discouraging ad hoc appropriations from the Fund that the Alaska Permanent Fund Corp. cannot plan for. “Last year our coalition took charge and responded to the fiscal crisis and ongoing recession. We passed a comprehensive fiscal plan to the Senate that included a POMV draw as part of a larger plan but not the only part of the plan. We felt our plan was fairer because we didn’t want to burden one group over another,” said House Majority Leader Chris Tuck, D-Anchorage, referring to the House inclusion of an income tax to raise about $700 million in addition to the POMV draw. “However, our plan was rejected, which is why many of us voted against SB 26 today. Despite our differences on this bill, today’s vote was an example of lawmakers voting their conscience. The Alaska House Majority Coalition is a nonbinding caucus and today was a good example of that.” Tuck voted against the bill. House Speaker Bryce Edgmon voted for it. The vote similarly split the House Republican caucus as well as members of both parties in the Senate. Walker said in a statement from his office called SB 26 “landmark legislation” that goes a long way towards ensuring the perpetuity of the Fund and the dividend program as well. “By stabilizing revenues, we secure Permanent Fund dividends for our children and grandchildren, and ensure services provided by the Alaska State Troopers, road maintenance crews and teachers will continue for generations,” Walker said. “SB 26 lays the foundation for our economy to grow and prosper. It provides for efficient investment of the Permanent Fund, improves the state’s position in financial markets, and perhaps most importantly, allows Alaskans to be fully confident in the future of their households and their communities.” Alaska Permanent Fund Corp. CEO Angela Rodell joined Walker in commending the Legislature for passing the framework of a structured draw from the Permanent Fund, which aligns with what the corporation’s board of trustees has long advocated. “SB 26 is an important milestone for the Permanent Fund and (the) APFC,” she said. “It gives us the target we have been asking for in order to craft our investment strategy and will ensure the Fund is a resource Alaskans can rely on now and in the future.” While each body passed a version of SB 26 last year, it languished on the sideline of budget debates for more than a year as the contrasting contingencies put on a POMV draw by the House and Senate made it a particularly touchy subject. The House called tied a $600 million-plus income tax and oil production tax increases to a Fund draw and directed one-third of the amount to PFDs. On the other hand, the Senate insisted upon a spending cap and lowered the draw dollar-for-dollar as oil revenues increased to ensure the state did not end up with excess money available to grow the budget in high revenue years. The Senate also set PFDs at 25 percent of the larger POMV draw. The SB 26 about to become law does none of that. It sets a 5.25 percent of market value draw for three years, which drops to 5 percent per year thereafter. It also explicitly states the Legislature shall not appropriate money from the Earnings Reserve in excess of the yearly POMV amount. That’s it. No spending cap, tax talk or dividend split — the last of which will surely elevate PFD politics in the coming years, but at least the budget deficit will be a lot smaller. Legislators supporting the bill also stressed that the draw amount is based on a five-year rolling average of the Fund’s value, which will make the effective 2019 fiscal year draw on July 1 closer to 4.35 percent. Such a rolling average “look back” is common among endowment draws to mitigate the effects of any single year of very high earnings or very high losses. The upcoming 2019 fiscal year draw is pegged at roughly $2.7 billion, which, with the $1,600 per Alaskan PFD established in the operating budget, should leave the state with a deficit of roughly $500 million to $600 million. Without SB 26, the deficit would be in the $2.2 billion range. Anchorage Democrat Rep. Les Gara acknowledged the current SB 26 is far from the fiscal solution he hoped for but noted it is the biggest piece to ending the five-year run of billion-dollar plus deficits that have drained $14 billion from state savings accounts. “Even if it’s not the first thing I would’ve done to solve the fiscal gap I have to do it because the budget deficit is a math problem and this is part of dealing with that math problem,” Gara said on the House floor. He also noted that not addressing the PFD in SB 26 means the entirety of the POMV draw could go towards dividends in high revenue years, however unlikely that is to happen. A $2.7 billion draw would equate to PFDs in the $4,300 per person range this year, Gara added. Sen. Bill Wielechowski, D-Anchorage, said in floor debate that leaving the existing formula in place — that was disregarded by Walker and the Legislature in 2016 and 2017, respectively — means the Legislature will continue to bypass the PFD in law in favor of providing more cash to government agencies. “One statute will inevitably be violated and my prediction is it will probably be that statute that provides for a full dividend,” Wielechowski said. “In fact, that’s what’s happening this year, in this budget. That’s what’s happened the last two years.” Wielechowski is among a bipartisan group of lawmakers that has pushed to put the PFD in the Alaska Constitution. He also challenged Walker’s 2016 veto of half of the PFD all the way to the Supreme Court before losing the case. That case established the precedent that Walker’s veto authority (used in 2016) and the Legislature’s appropriating authority (used to set an $1,100 dividend in 2017) — both enshrined in the state constitution — are superior to any law subsequently passed, including the PFD formula. Staunch conservative Rep. David Eastman, R-Wasilla, argued SB 26 reverses the Legislature’s historic priorities by putting government funding ahead of the PFD and inflation proofing the Fund. “By enshrining this in statute we are putting the value and the longevity and the survivability of the Permanent Fund in third place,” Eastman said. Retiring Juneau Democrat Rep. Sam Kito, who voted against it, said he simply doesn’t trust the Legislature will follow SB 26 any more closely than it has followed the PFD formula or any of the other business and fiscal principles and laws it has bypassed in recent years. With the passage of SB 26, the major items left for the last week of the current session before the Legislature bumps up against its 121-day constitutional limit are the operating budget, which appears close to being resolved, and the capital budget, which should not be controversial. A bill authorizing the sale of bonds to immediately pay off the nearly $1 billion backlog of oil tax credits is also pending. Elwood Brehmer can be reached at [email protected]

BP, AGDC reach deal on North Slope gas

BP and the Alaska Gasline Development Corp. announced May 7 that they have reached agreement on the primary terms of a gas sales contract to supply the $43 billion Alaska LNG Project. The major North Slope producer and the state-owned corporation in charge of bringing a long-sought North Slope natural gas project to fruition signed a binding gas sales precedent agreement May 4, which includes gas price and volume figures, according to an AGDC release. BP holds a 26 percent interest in and is the operator of the Prudhoe Bay oil and gas field. It also holds a 32 percent stake in the Point Thomson gas field, which is operated by majority owner ExxonMobil. With roughly 28 trillion cubic feet, or tcf, of gas in Prudhoe Bay and another 8 tcf of gas available in Point Thomson, BP has rights to about 9 tcf of gas from the fields. The company has also assisted AGDC behind-the-scenes in advancing the Alaska LNG Project since the state took control of the project from the producers in January 2017. BP has regularly noted that its North Slope gas holdings are the largest undeveloped asset in its global portfolio. “BP has a long history in Alaska and Prudhoe Bay,” BP CEO Bob Dudley said in a release issued by AGDC. “We are very pleased to be part of the state’s vision to bring Alaskan natural gas to new and expanding markets globally. We think this is good for the state, good for BP and good for the environment.” In a statement from his office, Gov. Bill Walker said he thanked BP for its commitment to Alaska LNG in a call with Dudley. “This agreement means Alaskans are one step closer to finally monetizing the vast reserves of natural gas on the North Slope. The end result will be thousands of jobs, a significant reduction in energy costs to power homes and businesses, and cleaner air. Having BP — one of our longtime participants in this project — commit its share for the gas on the sale underscores the progress we continue to make to build a stronger Alaska,” Walker said. AGDC President Keith Meyer noted the gas sales agreement, the details of which are expected to be finalized later this year, is another important aspect of the project the corporation has succeeded in advancing over the past year. “We have secured the customers; we have progressed on the pipeline build with regulators and the finance community and now we have a commitment that there will be gas to sell and put through the pipeline,” Meyer said. “I look forward to continued negotiations to secure supply from other North Slope producers.” Meyer and Walker said in separate interviews that without forgetting the Nov. 9 signing of a nonbinding joint development agreement with three Chinese-owned mega corporations for potential project financing and LNG sales — a signing in Beijing witnessed by both President Donald Trump and China President Xi Jinping — reaching firm North Slope gas sale terms is a momentous achievement for the project because it means another fundamental aspect of Alaska LNG is coming together. “Not to disparage the meeting between the two presidents, which was quite significant; however, in Alaska, for sure this is the biggest deal,” Meyer said. “This is the first time I think in the history of talking about a (gasline) project, any project, that the producers have actually committed gas to a particular project. So, to me, this is a very, very significant milestone.” With resolution on the major issues of price and volume, further negotiations with BP will revolve around the details of the definitive agreement, “but none of those, I don’t think, will be deal killers,” he added. The terms of the deal are confidential, but it would have AGDC purchasing gas from BP just prior to it entering the North Slope gas treatment plant at the head of the 800-mile pipeline and marketing it globally as LNG in Nikiski. Smaller quantities of utility-grade natural gas would also be marketed to Alaska communities and industrial customers along the pipeline corridor, or as small-scale LNG for use in other areas of the state. Meyer has repeatedly said the corporation has set a benchmark price of about $8 per thousand cubic feet, or mcf, of gas delivered to Asia to be competitive with Gulf Coast LNG projects that have much lower capital costs but higher transport expenses on each LNG shipment to East Asia markets. With Alaska LNG financing, operational overhead, returns and shipping to Asia tidewater expected to total about $7 per mcf, that would leave roughly $1 per mcf of gas available for producers’ gas sales. Under that scenario, BP would be poised to make up to $9 billion in revenue on its share of North Slope natural gas resources if the Alaska LNG Project is built. The governor and AGDC head also said the gas sale terms will certainly remain confidential until negotiations with ConocoPhillips and ExxonMobil are complete. After that, what the state has been committed to might be made public eventually. “I’m not going to say that (the terms) won’t (be made public). My expectation is that they will, but sitting here today I don’t know the exact avenue that they will come to know that,” Meyer said. Walker added that he hopes the deal is fully disclosed, but again said he doesn’t know when that might happen. He also noted that he was the one to push for the joint development agreement to be made public, despite concerns from Chinese officials. “I want to make sure that Alaskans are comfortable with the transaction, not at the expense of the transaction, but at some point I think it would reach a point where it is appropriate,” Walker said. “Certainly, when it reaches a point that requires legislative involvement and approval on some of the pieces, then, at that point I think that could be a time when things are more public. I’m very sensitive to that.” BP expects the terms of the agreement will remain confidential, but it will be noted in the company’s annual report to the Securities and Exchange Commission once it is finalized, according to spokeswoman Dawn Patience. ExxonMobil spokeswoman Julie King wrote in an email that the company appreciates its recent gas sale agreement meetings with AGDC. “We hope to continue these discussions, and remain fully committed to working with AGDC to negotiate gas sale agreements under mutually agreed, commercially reasonable terms,” King wrote. ExxonMobil led the project’s $600 million-plus preliminary front-end engineering and design, or pre-FEED, effort from 2013-2016 before slumping global oil and gas markets pushed the producers to suggest either slowing the project or offering the state to take the lead. The state, BP, ConocoPhillips and ExxonMobil each contributed funding to pre-FEED based on their ownership shares of North Slope gas. ExxonMobil had previously insisted on “fiscal certainty” regarding gas production taxes for the life of any gas sales agreement in order to sell its gas, which would require amending the state constitution specifically for Alaska LNG. However, administration officials have said the companies are not owed such a concession if they are no longer substantial investors in the Alaska LNG Project. Meyer said the fiscal certainty provisions are addressed in the agreement in a way that does not require the lengthy and contentious constitutional amendment process, noting at least BP is comfortable with the undisclosed plan and he expects ConocoPhillips and ExxonMobil to sign off on it as well. “Basically, it’ll be able to insulate the deal from changes in the tax structure or fiscal terms for this particular sale. This sale is for a particular gas supply from a particular reservoir being Prudhoe Bay, but also Point Thomson, so it covers both reservoirs but it’s for a particular gas sale,” he explained. “We’re not trying to fix all the tax issues across the state; we don’t have the authority to do that, but we think we’ve got the pricing provisions covered such that the producer gets the benefit of their deal. It’s all part of the gas purchase and the LNG sale structure.” Walker was hesitant to discuss how production taxes play into the deal, but said, “This is an area I’ve had some strong positions on in the past and I’ll just say I’m comfortable with this contract.” ConocoPhillips Alaska spokeswoman Amy Burnett wrote in an email that the largest producer of North Slope oil is actively engaged in negotiations with AGDC on a wellhead gas sale agreement. “We remain supportive of a state-led project because of the state’s opportunities to pursue options that are not available to a commercial entity that could significantly lower the cost of service,” Burnett wrote. Meyer has also said the corporation is trying to reach a final investment decision on the project in the first half of 2019, contingent upon a favorable regulatory decision from the Federal Energy Regulatory Commission, which is expected to come in March 2020. On March 27 AGDC announced it had hired the Bank of China — one of the three companies in the joint development agreement — and Goldman Sachs to solicit debt and equity investors for Alaska LNG. Elwood Brehmer can be reached at [email protected]

Final environmental review released for Donlin, but without preferred alternative

The U.S. Army Corps of Engineers Alaska published a final environmental impact statement for the Donlin Gold mine Friday, but what regulators think of the complex development plan is still unclear. Donlin Gold’s proposal is for a large open-pit mine near Crooked Creek in the upper Kuskokwim River drainage. The mine would extract roughly 33 million ounces of gold over its initial 27-year life. Substantial support infrastructure for the mine would also be built, including a 315-mile natural gas pipeline from near Beluga on the west side of Cook Inlet to the mine site to provide a fuel supply for the 227-megawatt power plant at the mine site. Donlin’s plan also calls for a 30-mile access road from the Kuskokwim to the mine as well as expanding the Bethel barge dock and constructing additional fuel terminals in Dutch Harbor. Donlin Gold estimates the mine and associated infrastructure that includes a natural gas pipeline from west Cook Inlet and fuel storage all the way in Dutch Harbor, will cost $6.7 billion based on its plan from a 2011 feasibility study. Corps of Engineers Alaska District regulatory officials wrote in an email that the agency is still working through the Clean Water Act Section 404 analyses and will identify the least environmentally damaging practicable alternative through the culmination of the EIS process. The agency is expected to select its preferred alternative plan and issue the subsequent record of decision for the Donlin Gold mine sometime this summer. The alternatives identified by the Corps for the project outline the prospect of diesel fuel pipeline that could parallel the gasline to drastically reduce the need to barge additional diesel up the Kuskokwim, thereby cutting the risk of a fuel spill related to the mine. The longer diesel pipeline would likely start at either Port MacKenzie in the Matanuska-Susitna Borough or at the Village of Tyonek on the west side of Cook Inlet and then link up with the gasline. Another option to reduce diesel shipments that is considered in the final environmental impact statement, or EIS, is to mandate Donlin employ LNG-fueled haul trucks at the mine. The EIS also contemplates a dry stack tailings facility instead of the more traditional tailings pond and dam. Using the dry stack method would avoid a potential tailings waste release from behind the dam, but also require a filter plant that would produce a partially saturated “compactable filter cake,” according to the EIS, that would trucked to the storage facility and then be spread and compacted by bulldozers. Donlin is proposing a 2,300-acre fully lined wet tailings storage facility. The mine site is on lands owned by The Kuskokwim Corp. and Calista Corp., the area village and regional Native corporations, respectively. Donlin spokesman Kurt Parkan said in addition to the record of decision the company still has to secure numerous other state and federal permits, among them approvals for water discharge, waste management and a tailings dam safety permit that will eventually require additional geotechnical drilling. After the permits are secured company leaders will reevaluate the project’s economics, which they acknowledge are subject to the volatility of gold prices, and begin the search for financing if the project pencils out. Donlin Gold leaders acknowledge the project is more sensitive to gold prices than even other Alaska prospects simply because of its associated infrastructure costs. Elwood Brehmer can be reached at [email protected]

Habitat initiative gets day in Supreme Court

The Alaska Supreme Court heard arguments Thursday afternoon over an initiative that would likely be the most contentious choice for Alaskans on the 2018 ballot outside of the governor’s race. State attorney Joanne Grace, on behalf of Lt. Gov. Byron Mallott and the Division of Elections he oversees, argued that the Yes for Salmon ballot initiative is unconstitutional because it implicitly prohibits large development projects in the state that cannot avoid disrupting salmon habitat. A de facto prohibition on such activity violates the Alaska Constitution, which gives authority to allocate state resources — in this case salmon habitat — to the state Legislature, according to state attorneys. “Because (the Yes for Salmon initiative) bans any activity that displaces the habitat, that takes it out of the realm of regulation,” Grace said to the court. Yes for Salmon is what the ballot initiative drafted by the Stand for Salmon organization has been dubbed. Grace contended it gives the Department of Fish and Game, which issues development permits for anadromous fish habitat, no discretion in its decision because all activities determined to have a “significant adverse effect” on the habitat and in turn the fish are explicitly prohibited. Chief Justice Craig Stowers asked Grace if the proposed change in law maintains the Legislature’s discretion by allowing lawmakers to define the meaning of “significant adverse effect” and other terms to Fish and Game. Grace responded that the plain language of the initiative gives the department no discretion to grant permits for activities that will by their very nature permanently disrupt salmon habitat. The initiative does allow for the habitat to be disturbed as long as mitigation countermeasures are on the same water body, in close proximity to the development and the habitat can be restored within a “reasonable period.” “Mining projects routinely dewater and relocate streams, according to our affidavits,” Grace said, referring to documents submitted prior to a Superior Court hearing on the matter. On Oct. 9, 2017, Superior Court Judge Mark Rindner overturned Mallott’s Sept. 12 rejection of the initiative petition, which was based on the Department of Law’s determination that it is unconstitutional. Affidavits from Fish and Game and Department Natural Resources permitting officials asserted large mines, such as the large Donlin Gold mine proposed for the upper Kuskokwim River drainage that is at the end of a five-year environmental review, would likely not be allowable as planned under the Yes for Salmon language. (More: Fish and Game outlines current best practices  for habitat permitting) “If the habitat is never going to recover or be restored then ‘reasonable period’ has no meaning,” Grace said further, noting large mine tailings facilities that can cover hundreds of acres often remain after a mine is closed. Valerie Brown, legal director for the Anchorage-based nonprofit environmental law firm Trustees for Alaska, rebutted the argument that the language of Yes for Salmon sets high permitting bars for project proponents to clear, but would not preclude any specific project or type of development from being allowed in the state. “It’s a permitting scheme that allows the use of public resources without permitting harm,” Brown said in her opening remarks. She said under the multi-tiered habitat permitting process the initiative would establish Fish and Game would first have to determine if an application necessitates the most scrupulous assessment under the “major permit” review tract. After that, the department would decide whether or not the proposed project would cause the significant adverse effects that are central to the debate. If so, then onsite mitigation measures would have to be employed or the plans for the project would have to be amended, according to Brown. She said it could force re-siting or the employment of new technologies to get below the significant adverse impact threshold, but “it wouldn’t ban all of anything.” “It’s all about the amount of harm. The size of the project is irrelevant,” she added. Justices questioned Brown on why the initiative includes impact mitigation restrictions if it is all about preventing harm and whether or not a project in the exploration or pre-development phase would be grandfathered in under the current law if the initiative passes in November. Brown acknowledged the mitigation provisions are the most controversial parts of the law change, but said the mitigation sideboards are meant to protect the water body being disrupted. “If you rehabilitate a wetland that’s 400 miles away you’re not really correcting the harm you’ve done,” she said. Brown also speculated that a project in the works now, such as Donlin, would likely be under the new habitat laws when it moved to full development if Yes for Salmon passes. The Court also has the option of striking specific provisions of the initiative as long as they maintain the spirit of the measure, an alternative Grace rejected and Brown deemed acceptable. Grace contended the language of the complex bill is to intertwined to successfully pull apart and that removing the impact restrictions would leave a new but hollow permitting process. On the other hand, Brown said that while that would be unfortunate, it would still put more structure and opportunity for public input into what Stand for Salmon alleges is currently an ad hoc process without public notices or comment periods. Stowers questioned whether doing so would still meet the intent of the 40,000-plus Alaskans that signed petitions to get Yes for Salmon on the fall ballot, regardless of what the sponsors are ok with. Both sides agreed a ruling by Sept. 1 would be acceptable. The Division of Elections has until Sept. 5 to print the ballot books for the November election. Elwood Brehmer can be reached at [email protected]

ConocoPhillips nets $445M in Alaska to start 2018

ConocoPhillips’ first quarter earnings report issued Thursday was full of good news for the company as it generated $888 million of profits with oil prices in the $70 per barrel range. Houston-based ConocoPhillips grossed more than $8.9 billion in the first three months of 2018, which is its highest revenue quarter since oil prices collapsed in the fall of 2014. The company netted $445 million in adjusted earnings in Alaska during the quarter, also its highest income quarter in the state since the oil market reset. In fact, the $445 million of Alaska income is more than four times greater than its first quarter 2017 earnings in the state and nearly 70 percent of its total 2017 Alaska earnings of $652 million. ConocoPhillips paid $298 million in state royalty and tax payments during the quarter, according to spokeswoman Amy Burnett. As an upstream production-driven company, ConocoPhillips’ financials have been subject to oil and gas market prices far more than other major producers in Alaska that also have substantial refined product business operations. “We continue to differentiate ourselves by executing our strategic, financial, and operational plans. We remain focused on creating value for our shareholders by maintaining discipline, following our priorities and staying committed to our returns-focused value proposition,” CEO Ryan Lance said in a formal statement. “We safely delivered our plan again this quarter, while generating a strong improvement in free cash flow, reducing our debt and returning over 30 percent of cash from operations to shareholders through our dividend and buyback program.” The $888 million profit breaks down to 75 cents per share of common stock. ConocoPhillips stock traded for $66.85 per share shortly before the close of trading Thursday, up slightly from Wednesday’s closing price of $65.07 per share prior to the earnings release. The company increased its dividend payment by 7.5 percent to 28.5 cents per share during the quarter as well. After oil prices crashed the company reduced its dividend from 75 cents to 25 cents per share. ConocoPhillips spent $263 million of its $1.5 billion quarterly capital budget in Alaska. It produced an average of 190,000 barrels per day of oil and natural gas liquids from the state, which was about 15 percent of its daily worldwide oil and gas equivalent production during the quarter. However, that Alaska production may be set for a substantial increase down the road based on the six winter exploration drilling successes ConocoPhillips announced earlier this month. Three wells intended to delineate the company’s Willow prospect in the National Petroleum Reserve-Alaska largely confirmed the initial estimate that the prospect in the National Petroleum Reserve-Alaska holds at least 300 million barrels of recoverable oil. Additionally, the wells indicate the Willow oil resource could support its own processing facility, meaning it has the potential to produce up to about 100,000 barrels per day, according to Alaska spokeswoman Natalie Lowman. Other exploration results from wells to the south and east on state land also proved what industry experts in the state suspected: the Nanushuk formation oil play is going to be a major target in the western portion of the North Slope for years to come. While this year’s discoveries are five years or more from production, ConocoPhillips is scheduled to bring its Greater Mooses Tooth-1 project in the NPR-A — with up to 30,000 barrels per day of peak production — online this fall. Elwood Brehmer can be reached at [email protected]

Legislature quietly brings back Permanent Fund legislation

Legislators continue to plug along in Juneau as the calendar approaches May and their constitutional deadline to finish their work in the middle of that month. Much of the activity in the past couple weeks has been on relatively minor bills and resolutions as House and Senate leaders quietly negotiate the state’s finances. The Republican-led Senate on April 18 joined with the Democrat-led House in unanimously passing House Joint Resolution 21 by Fairbanks Democrat Rep. David Guttenburg urging the federal government to stay out of the state’s recreational marijuana business. A couple days later, on April 20, when levity would’ve suggested passing the marijuana resolution, legislators again unanimously passed a resolution aimed at the feds; this time asking for help in developing an Arctic deepwater port in Western Alaska. Sen. Peter Micciche’s Senate Bill 4, legislation to reduce requirements for occupational license requirements for barbers, hairdressers and others with student loans, was approved April 24. While those matters are undoubtedly important to those they impact, the last legislation approved with broad implications was House Bill 287, Rep. Paul Seaton’s proposal to fund the K-12 education early. It was sent to Gov. Bill Walker’s desk April 18. While it didn’t pass the Legislature early in the session as intended, HB 287 is still ahead of the operating budget, which remains unresolved as part of the ongoing discussions over a longer-term fiscal solution. A key aspect to the passage of HB 287 is that the Democrat-led House approved the Senate’s version of the bill. It calls for flat education funding in the upcoming 2019 fiscal year, but also provides for a $30 million increase to the primary school funding mechanism, the base student allocation, in fiscal year 2020 (the school year that begins in 2019). The House Majority coalition had been pushing for a $25 million increase for fiscal year 2019 after several years of flat BSA funding, which Democrats have noted has forced school districts to absorb fixed annual cost increases, namely health care. However, the Senate’s version of HB 287 also included a contingency that the extra money in 2020 is dependent passing Senate Bill 26, the seemingly forgotten bill passed by both chambers last year that would formally establish an annual percent of market value, or POMV, draw from the Permanent Fund Earnings Reserve Account to pay dividends and support government services. Senate leaders did an about-face by making the extra education funding dependent on the passage of SB 26 after repeatedly criticizing the House Majority and the Walker administration for leveraging one issue against another, but the fact that the House agreed to the proposal is a sign of progress on the centerpiece of any plan to resolve the state’s multibillion-dollar budget deficits. Subsequent to HB 287 passing, the House and Senate Finance Committee co-chairs held a April 21 conference committee meeting on SB 26. While the meeting lasted all of two minutes, it initiated the process of resolving the differences in the versions of the legislation each body passed last year. The House’s SB 26 tied approval of a Permanent Fund draw to passage of an income tax, while the Senate made it contingent on a reducing the government’s spending cap to a more substantive level. Meanwhile, formal conference committee negotiations over the operating budget have been put on hold. But given the House and Senate budget plans are more similar than they are different — each side has fiscal year 2019 unrestricted General Fund spending in the $4.5 billion range — a major hang-up over the budget seems unlikely. Finally, the capital budget has received no attention since the administration submitted it to the Legislature in January, which indicates legislators could pass a minimal and noncontroversial capital budget that spends little more state money than is needed to secure more than $1 billion in federal matching transportation construction grants in a day or two after other big issues are resolved as they did last year. Such “bare bones” capital budgets have become the norm since 2015 despite the fact that the state’s deferred maintenance liability continues to grow to upwards of $2 billion, according to the Department of Administration. ^ Elwood Brehmer can be reached at [email protected]

Merger expense, increased labor costs reduce Alaska Air income

Growing costs trimmed Alaska Air Group’s first quarter 2018 net income to $4 million, company executives reported April 23. The Seattle-based parent company to Alaska Airlines and regional carrier Horizon Air reported $18 million in profits excluding costs related to its 2016 acquisition of Virgin America airlines, a $1,000 per-employee bonus tied to federal tax cuts and fuel hedging accounting adjustments, among others. For comparison, Alaska Air Group netted $93 million in the first quarter of 2017 and $184 million in the first three months of 2016 — also the last first quarter of operations before it purchased Virgin American in a $4 billion deal that closed in December 2016. Alaska Air Group CEO Brad Tilden said Alaska Airlines is in the midst of the most important parts of its merger with Virgin America and the company is starting to plan for the time after the airlines are fully blended during a conference call with investors. The complex merger is “reaching a crescendo tomorrow night (April 24) as we transition to a single passenger service system,” Tilden said in the April 23 call. “This event will mark our shift to a single brand and customer experience everywhere our guests interact with us,” he said further. Alaska Air Group has been directing Virgin America bookings to Alaska and performing other operations as a single airline for some time to assure a smooth transition, according to Tilden, which means the remaining passenger service system integration will mostly be limited to what customers see and not integral behind-the-scenes processes. He emphasized that the company is encouraged about its prospects despite the immediate sharp decline in profitability. “Our platform, which is 33 percent bigger than it was just 16 months ago and 100 percent bigger than it was five years ago, maintains the same competitive advantages it always has,” Tilden said. The $4 million profit translates to 3 cents per diluted share. Alaska Air Group paid a first quarter dividend to its shareholders of 32 cents per share. The company’s stock closed trading April 23 at $69.11 per share, up 5.7 percent from its April 20 closing price despite the lukewarm financial results. First quarter revenue was up 5 percent year-over-year to more than $1.8 billion; however, operating costs were also up 14 percent, which led to an 82 percent drop in operating income to $29 million. Tilden said company leaders expect the merger to result in $280 million of new revenue in 2019 and that the company plans to grow its capacity by just 4 percent by 2020, choosing instead to leverage the benefits of its previous growth. “We are absorbing substantially all of the merger-related cost increases this year,” he added. Chief Financial Officer Brandon Pedersen said the executives are not happy with the first quarter financials and are taking steps to improve the profitability of the company. “Our near breakeven result came during a time of new merger integration activities, significant new market development, rising fuel prices, new labor agreements and continuing areas of competitive pressure in our network,” Pedersen said during the earnings call. A new labor agreement with Alaska Airlines flight attendants increased labor costs by $9 million for the quarter and when combined with a pilot contract signed in late 2017 amounted to eat up about two-thirds of the 5 percent revenue growth, according to Pedersen. Air Group’s wage and benefit costs increased $84 million, or 19 percent, in the first quarter. Additionally, total fuel costs were also up $93 million, or 29 percent, paralleling increased oil prices. Despite that, Pedersen said without the new, more fuel-efficient Boeing 737s Alaska continues to receive as it phases out older aircraft, the company’s fuel costs would have been $5 million more. Alaska Airlines’ fuel efficiency improved 1.5 percent year-over-year. He also noted the company has hedges on 47 percent of its expected fuel consumption for the remainder of the year. Overall, the company expects its full-year unit costs to be up about 3.5 percent. “In general, I’m seeing examples of great back-to-basics cost management across much of the company,” Pedersen said. “The credit goes not only to our leaders but also to our frontline employees for embracing the need for productivity gains.” Alaska Air Group recently lowered its expected capital expenditures in 2018 to $1 billion, with further plans to spend about $750 million per year on capital investments in 2019 and 2020. The company also restructured its new aircraft delivery schedule over the next three years to help lower capital costs and increase free cash flow, according to Pedersen. He thanked Boeing and the other airline manufacturers it has purchase agreements with for being amenable to the changes. Alaska Air Group generated $310 million in operating cash flow during the quarter and spent about $235 million of it on capital expenses, the earnings report states. The company, with $10.8 billion in total assets, held roughly $1.5 billion in cash at the end of the quarter. “Our balance sheet continues to get stronger with total on-balance sheet debt declining another $120 million since year-end,” Pedersen said. Company executives have long-stressed their desire to maintain an “investment-grade balance sheet” and with its aircraft leases the company’s debt-to-capitalization ratio held flat 53 percent for the quarter. Pedersen said the debt-to-cap ratio should drop to 50 percent by the end of the year, while at the same time returning about $200 million to Air Group shareholders through dividends and share buy-backs during 2018. Tilden also thanked Alaska Airlines employees for moving the merger along “in record time” in his comments during the earnings call. “I couldn’t be more excited about our future,” Tilden concluded. ^ Elwood Brehmer can be reached at [email protected]

Legal opinions diverge on constitutionality of tax credit bonding bill

An opinion from the Legislature’s attorneys has called into question the constitutionality of Gov. Bill Walker’s plan to pay off the state’s outstanding oil and gas tax credit obligation that is currently in excess of $800 million. Legislative Legal Services Deputy Director Emily Nauman wrote to Sen. Bill Wielechowski, D-Anchorage, April 13 that the administration’s proposal to sell bonds to pay down the tax credits in one lump sum may fall outside the Alaska Constitution’s tight restrictions on allowing the state to contract debt. Wielechowski raised the issue regarding the legislation, SB 176, during the initial Senate hearing on it Feb. 21. At the time he said he would be seeking a legal opinion on the matter. His office released the legal opinion April 18. “Although the outcome is difficult to predict, this office is concerned that a court reviewing SB 176 may find that, for purposes of bonding under (Article IX, Section 11 of the Alaska Constitution) revenue of a corporation does not include appropriations from the traditional sources of state income, such as taxes and other receipts received by the General Fund. Therefore, there is a substantial risk that a court may determine that SB 176 is unconstitutional,” Nauman wrote. Legislative leaders in both parties have mostly gone quiet as end-of-session budget negotiations are underway but there is a general indication that they are not worried about the legality of the bonding plan. However, there is the possibility that the questions from Wielechowski and Legislative Legal Services could raise the interest rates the state would have to accept to sell the bonds, at least slightly. They are subject-to-appropriation bonds, and the state’s financial reputation has taken hits in the last several years for a combination of not fully paying the tax credits each year starting with two vetoes by Walker in 2015 and 2016; the ad hoc setting of the Permanent Fund dividend without regard to the statutory formula either through veto (in 2016) or legislative action (in 2017 and 2018); and the Legislature using the subject-to-appropriation clause to leave Anchorage developers on the hook for a $28 million loan by abandoning the Legislative Information Office they commissioned and occupied for less than two years. The state’s failure to adopt fiscal measures to deal with annual deficits topping $2 billion has also led to the once perfect AAA credit rating being downgraded to the third lowest in the country. Wielechowski said in an interview he does not plan to challenge the legislation in court if it passes, but rather that he simply wanted to bring the issue to light. “We went back and read the Constitutional Convention minutes. This is the exact kind of thing they were trying to stop. They didn’t want the Legislature and the administration racking up debt for future generations,” Wielechowski said. The state Constitution prohibits lawmakers and state agencies from selling bonds except in the cases of an emergency; if they are general obligation bonds for capital projects; or housing loans for veterans and approved by voters statewide. State corporations may also sell revenue bonds but they are the obligation of that corporation and not the state as a whole and are backed by some segment of the corporation’s revenue. SB 176 and its mirror House Bill 331 — both in their respective Finance committees — would create the Alaska Tax Credit Certificate Bond Corp. within the Department of Revenue to sell the bonds and pass the proceeds of the sales on to the bond holders, of which there are 37, according to Deputy Revenue Commissioner Mike Barnhill. The bonds would be “subject to appropriation” meaning the revenue to pay for them would be contingent upon the Legislature appropriating money to pay the debt service each year. “This bill seeks to avoid the constitutional ban (on bond debt) by creating a pass-through state corporation whose sole purpose is to put the state in debt to pay the oil companies,” Wielechowski said. “Oil tax credits are clearly not an allowable state debt prospect, but the bill also jeopardizes the state’s credit rating without asking for the people’s say.” He also noted the state corporation would have no employees, revenue or assets in a statement from his office. Alaska Attorney General Jahna Lindemuth offered a quick counter to the Wielechowski and the Legislative Legal memo, contending in a statement from the Department of Law that the bonds proposed in the legislation are not general obligation bonds and the department has no constitutional concerns with the proposal because it is “consistent with long-established bond issuance practice in Alaska,” the Law release states. “We’ve carefully reviewed the legal issues and are confident that these bonds are lawful under Alaska law,” Lindemuth said. Attorneys with the Department of Law have stressed the subject-to-appropriation provision would make the bonds constitutional because it prevents the state from being totally bound to the debt. “It’s an important obligation but if you buy a subject-to-appropriation bond and the authority that issued it did not make a debt payment — unlike a general obligation bond where the court would order a payment — if you went to a court the court would say ‘It says right on your bond it’s subject to appropriation;’ that’s sort of the dividing line for us,” Assistant Attorney General Bill Milks testified to the House Finance Committee April 21. Nauman, who wrote the Legislative Legal opinion, testified on the other hand that because the revenue to pay for the bonds would strictly be tax revenue appropriated from the General Fund they are not traditional revenue bonds. As a result, the proposal creates legal ambiguity and the division can’t advise that the plan is constitutional until there is precedent, which there isn’t. State Debt Manager Deven Mitchell said during the Feb. 21 Senate Resources hearing that the situation would be similar to how the state financed the Goose Creek Correctional Facility in the Matanuska-Susitna Borough. In that case the borough issued revenue bonds on the state’s commitment to pay through its lease of borough lands. According to an April 16 letter from Mitchell to Revenue Commissioner Sheldon Fisher, the state currently has $237 million of outstanding subject-to-appropriation bonds related to the Mat-Su prison and the Alaska Native Tribal Health Consortium residential housing facility. It’s worth noting that someone with standing must challenge the constitutionality of a law or state spending for the legality of the issue to be determined; it is legal until someone decides to expend the resources and energy needed to prove it’s not. Administration officials have also pointed to a 1995 Alaska Supreme Court ruling in the case of Carr-Gottstein Properties v. the State of Alaska in which the court determined that a lease-purchase agreement was not unconstitutional debt because the obligation to pay was again subject to appropriation by the Legislature. However, Wielechowski contends the case ruling is irrelevant to the bond issue because it centers on a property lease, which is different than selling bonds in financial markets. The administration is touting the plan as a way to pay off the tax credits, which are expected to reach a roughly $1 billion bill in another year or two once the last of the credit certificates from the terminated program are submitted to the state for approval. The credits went to small producers, explorers and seismic data companies to subsidize a portion of their work on the hope the state help could spur more oil and gas production more quickly as payback for the state. Paying off the obligation quickly could also restart work slowed or stalled by small producers and explorers that have cited the lack of payments as a primary reason numerous companies have had to hold off previously planned investments. Adding to the issue is the fact that several banks provided loans to companies with the credit certificates as collateral; and when the credits were not paid as expected the banks stopped lending to the Alaska oil and gas sector, according to multiple companies, banks and Department of Revenue officials. Lender gives thumbs up at House hearing Despite the swirling issues of the constitutionality of the legislation, the House Finance Committee continues to work on HB 331. The committee heard broad support for the bill April 23 from oil and gas and finance industry representatives who said it could reinvigorate investment in the state. ING Managing Director Thomas Ryan said the large international bank lent against credit certificates to two oil companies working in the state in 2015. ING’s Peter Clinton said the process the state has gone through in dealing with the tax credit program since oil prices collapsed in late 2014 is not unlike what often happens elsewhere. “This is a fair and balanced proposal. It is consistent with the types of proposals you would see in private industry where you take an obligation that you recognize that you have and you try to get a solution to that problem where everybody participates,” Clinton testified. He said the legislation would likely enhance the state’s reputation in the finance realm greatly over doing nothing, as it would provide path to a solution. “Private lenders are not put off by situations like this where something unexpected happens and you have to figure out a way to deal with it,” Clinton said further. “Ultimately, at the end of the day what they look for in the solution is the ability for there to be a predictable payout.” The difference is that the state deals with its problems over years, in which one aspect of the issue is often handled each legislative session, as opposed to weeks or months it takes to resolve problems between private parties, he added. Passing either SB 176 or HB 331 would resolve a difference of opinion between the Democrat-led House and Republican-dominated Senate over how much to spend on the credits this year in the budget. The House budget appropriates $49 million to the Oil and Gas Tax Credit Fund, while the Senate would have the state put $184 million into the fund based on differing interpretations of the production tax-derived formula that is used to generate the statutory minimum production tax credit payment. The House amount is based on a calculation that uses the amount of production taxes the state is actually expected to receive in 2019, while the Senate’s calculation is based on the wholesale production tax amount before deductible credits are applied. The administration is backing the Senate, as its calculation is the formula that has been used the past two years. Elwood Brehmer can be reached at [email protected]

Long-awaited final EIS for Donlin nears release

The U.S. Army Corps of Engineers will publish its recommendations for the large Donlin Gold mine project in Western Alaska next Friday, April 27, Alaska District officials said Thursday. The Corps of Engineers has been working on the environmental impact statement, or EIS, for the open-pit gold mine proposal in the upper Kuskowkim River drainage since December 2012. A schedule for the EIS on the agency’s website for the project states the Corps hoped to have the final version of the massive environmental review document published sometime in March. Donlin spokesman Kurt Parkan said the company has been working on the mine for 22 years since initial exploration work began. “It’s a good day. We’re happy that we’ve reached (the final EIS). That’s a big milestone,” Parkan said in a brief interview. Corps of Engineers Alaska District officials who oversaw the drafting of the Donlin EIS held a media availability and a scoping meeting in Anchorage at the Dena’ina Civic and Convention Center on Thursday to solicit comments on the EIS for the Pebble gold and copper mine. Unlike a draft EIS — Donlin’s draft was published in November 2015 — a final EIS includes the oversight agency’s recommendations on how a project can be adjusted to minimize its environmental impacts. A “no action alternative,” or a recommendation to not approve the project, can also be selected. Donlin Gold estimates the mine and associated infrastructure that includes a natural gas pipeline from west Cook Inlet and fuel storage all the way in Dutch Harbor, will cost $6.7 billion based on its plan from a 2011 feasibility study. Parkan said the next steps will be getting a record of decision from the Corps later this year as well as securing numerous other permits, among them approvals for water discharge, waste management and a tailings dam safety permit that will evenually require additional geotechnical drilling. After the permits are secured company leaders will reevaluate the project’s economics, which they acknowledge are subject to the volatility of gold prices, and begin the search for financing if the project pencils out. “That is the plan and we’re working on ways to reduce the capital cost,” Parkan added. A true mega-project, Donlin Gold’s is for a conventional open-pit mine 1.5 miles across and up to 1,200 feet deep about 10 miles north of the village of Crooked Creek in the Upper Kuskokwim River drainage. A tailings facility, large power plant, workers’ camp and 5,000-foot airstrip would accompany the mine. As planned by Donlin, a joint venture between Barrick Gold Corp. and NovaGold Resources Inc., the mine would produce about 1.1 million ounces of gold per year over a 27-year mine life for a total of about 33 million ounces of the precious metal, making it one of the largest open-pit gold mines on Earth. The mine site, on lands owned by The Kuskokwim Corp. and Calista Corp., the area village and regional Native corporations, respectively, would also include a fully lined, 2,300-acre tailings facility to store the processed ore. Support infrastructure would include a 315-mile, 14-inch diameter natural gas pipeline originating on the west side of Cook Inlet needed to supply fuel to the 227-megawatt capacity power plant at the mine site. The pipeline has also been viewed as a first, indirect step to getting lower cost natural gas to numerous villages in Western Alaska that currently rely on fuel oil their primary heat and electricity sources. A 30-mile road would connect the mine to a new barge port on the Kuskokwim. Further down the Kuskokwim, port cargo facilities would be expanded in Bethel, and new diesel storage tanks would be needed Dutch Harbor to supply fuel for equipment at the mine. In all, the direct supply chain in Donlin’s proposal from Cook Inlet to Dutch Harbor would cover approximately 1,050 miles. Donlin Gold leaders acknowledge the project is more sensitive to gold prices than even other Alaska prospects simply because of its associated infrastructure costs. Company officials have said the project would not be economic at gold prices of about $1,100 per ounce. Gold was selling for about $1,355 per ounce in spot trading on Thursday. Elwood Brehmer can be reached at [email protected]

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