Elwood Brehmer

BP bounces back from 2016 with $3.4B profit in 2017

While BP Alaska leaders are celebrating the success of stemming production decline from the aging Prudhoe Bay oil field despite belt-tightening in the industry, the company’s global executives on Feb. 6 celebrated the announcement of a $3.4 billion profit in 2017. The $3.4 billion in earnings last year comes after the London-based oil super major managed to net just $115 million in 2016. The entire industry was boosted by a gradual return to oil prices of about $70 per barrel by the end of the year, but the fact that BP’s settlement payments related to the 2010 Deepwater Horizon oil spill have started to shrink also helped the company. It paid out $6.9 billion in spill payments in 2016 and $5.2 billion in 2017, according to the fourth quarter earnings report released Feb. 6. “2017 was one of the strongest years in BP’s recent memory,” CEO Bob Dudley said in a formal statement. “We delivered operationally and financially, with very strong earnings in the downstream; upstream production was up 12 percent; and our finances rebalanced. And we did all this while maintaining safe and reliable operations.” However, the company netted just $27 million in the fourth quarter after a $1.7 billion profit in the third quarter. That was primarily due to non-operating expenses accounted for in the quarter, according to the report. Operating cash flow — excluding the Deepwater Horizon payments — was up substantially from $17.6 billion in 2016 to $24.1 billion last year. Operating cash flow for the quarter was $6.4 billion, up 42 percent year-over-year. In Alaska, the year was more mixed for BP. The company held Prudhoe oil production at roughly 280,000 barrels per day for the third straight year, which Chief Upstream Executive Bernard Looney called “a fantastic example” of the BP’s ability to optimize work while cutting drilling during a time of low prices during a conference call with investors. Looney further noted the progress the Alaska Gasline Development Corp. has made on the $43 billion Alaska LNG project, which would begin selling the roughly 35 trillion cubic feet of natural gas combined at Prudhoe Bay and Point Thomson. BP executives have said the North Slope gas reserves are the company’s largest non-producing asset in its portfolio. “In Alaska, the fiscal changes potentially around what has been achieved with the Trump administration around gas, which many people might have thought of as a big stranded asset, may actually come to light in terms of commerciality,” Looney said. In November, AGDC and Gov. Bill Walker signed a nonbinding agreement with three large Chinese companies to advance the gas project in front of President Donald Trump and China President Xi Jinping in Beijing. BP has also assisted AGDC in a behind-the-scenes role on the Alaska LNG Project since the state-owned corporation took it over at the start of 2017. While Dudley touted the BP’s safe operations in 2017, the company allegedly had near misses in Alaska during the year that pushed its state leaders to call for a “reset” of its safety culture in the state. Buzzfeed reported in October, based on leaked internal BP Alaska emails, that the company had at least five incidents during the year that put employees at significant risk and resulted in workers being sent to unscheduled safety training. Also, in April, a BP oil well failed at Prudhoe due to permafrost melting around the well, spraying about 100 gallons of oil onto the drilling pad. The incident caused the company to review all of its wells for a similar design — a few were found and shut in — and pushed state regulators to require all Slope operators to perform a similar review late in the year. BP’s Alaska-specific financials are reported each year in the company’s annual report, which is expected to be published in late March. Elwood Brehmer can be reached at [email protected]

AEDC: recession fading despite ongoing state financial issues

Anchorage is pegged to lose about another 1,000 jobs this year, but the analysts that track the numbers closely believe it could be the last year of a shrinking economy in the city. Anchorage Economic Development Corp. CEO Bill Popp said during the group’s annual forecast luncheon Jan. 31 that the job losses this year will continue to be widespread amongst the various sectors of the city’s economy. However, the workforce reductions are expected to be smaller in almost every industry than what has been endured in the past two years of recession. Losing 1,000 more jobs in 2018 would equate to a 0.7 percent decline in the city’s overall workforce of about 151,000. For context, Anchorage lost about 2,100 jobs last year and more than 2,900 in 2016, the first year of the recession. Popp said the city’s ever-burgeoning health care industry was the outlier in 2017; it added roughly 800 jobs. The transportation sector was flat, aided by a busy Ted Stevens Anchorage International Airport, which was aided by tourists and cargo from a strong Lower 48 economy. “Who lost, last year? Everybody else; that’s the simple way to put it,” Popp commented. But the major job losses seen in 2016 in the linked oil and gas, construction and professional and business services — engineers, architects, lawyers, accountants, administrators and the like — sectors have moderated. In 2016 those three industries shed 3,100 jobs in Anchorage. In 2017 they lost a combined 1,400 workers. Overall, AEDC is projecting the recession will fizzle out sometime late this year or early next. Oil prices have stabilized of late and a batch of prospective developments on the North Slope should help revitalize Alaska’s central industry, which is largely headquartered in Anchorage. Aside from that, the tourism and transportation sectors are expected to remain strong. The job losses haven’t equated to a ballooning unemployment rate, however. Anchorage averaged 5.7 percent unemployment in 2017, which is still near full employment as economists calculate it. And Alaska as a whole was at 6.9 percent, which is the highest in the nation, but close to historical trends. The city is losing jobs but not adding much to unemployment rolls because many without work are packing up and heading south instead of collecting unemployment assistance, according to Popp. “People are leaving town for the Lower 48, some are for better opportunities,” he said. The national unemployment rate, at 4.4 percent, is as low as it’s been in more than a decade. As a result, AEDC expects Anchorage to lose another 1,500 residents this year and end 2018 with a population of 296,000. Anchorage’s population peaked in 2013 with 300,880 residents, according to the state Labor Department. This year, AEDC is predicting the interrelated oil and gas, construction and professional service industries will lose a total of 400 jobs — 200 each from construction and business services with oil and gas hopefully holding flat. Anchorage retailers are expected to shed about 400 jobs this year, the biggest projected loss in the sectors AEDC tracks, but Popp noted that estimate was reached before the January announcements that Sears and Sam’s Club would collectively close three large stores in the city. He added, though, that the Alaska Sears and Sam’s Club closings were part of larger, national trends for the iconic retailers and not wholly a result of Alaska’s economy or reductions to the Permanent Fund Dividend. There simply aren’t numbers to support the theory that cuts to the PFD by Gov. Bill Walker and the Legislature the past two years have translated to massive declines in consumer spending as some like to purport, Popp stressed. “The Permanent Fund (dividend) is an important part of our economy; it adds $600 million to our state’s economy. A lot of that Permanent Fund is spent on paying off bills, going into savings, paying for education; a chunk of it goes to paying for stuff but it is not the driver of our $1 billion-plus retail economy here in Anchorage,” he said, noting past formulaic declines in the PFD amount to not correlate to retail losses. Popp also said he’s hearing rumors that the Sears and Sam’s Club buildings could have new tenants shortly after the stores close — and possible reemployment opportunities for at least some of the workers losing jobs. “In Alaska we still love us some retail,” he quipped. “We like to get out and shop.” The leisure and hospitality industry, despite being buoyed in the summer by record numbers of tourists in recent years, is expected to lose about 200 jobs mostly due to locals’ belt tightening, literally and figuratively, a classic recession symptom. Restaurants are having a hard time drumming up business when tourists aren’t around, according to AEDC. “If you’ve been holding back on going out to eat at one of your favorite restaurants, I’d suggest maybe it’s time to go out and have a meal because we need to support this industry,” Popp encouraged the forecast attendees. On the flipside, the transportation and health care sectors should break the recession trend again, adding 100 and 600 jobs respectively in 2018, AEDC projects. Transportation will continue to benefit from strong economies elsewhere resulting in strong cargo trade and passenger numbers at the airport, while Alaska’s highest-in-the-nation health care costs continue to support growth in the sector. On health care, Popp emphasized that more jobs are always good, but he also said that if the state can manage to get its health care costs under control the industry’s workforce might take a hit in the coming years. Anchorage’s health care sector has added nearly 7,000 jobs since 2006, an increase of more than 40 percent. “As we start to address those (cost) issues it could impact the job base in health care,” Popp said. “So there’s issues we have to balance there as we try to come up with the solutions that are going to be necessary to make this less of a problem for businesses.” Health costs hurt business confidence AEDC found in its annual Anchorage Business Confidence Report that business leaders feel the cost of health insurance is one of the biggest impediments to growing their businesses. An interesting revelation from the business survey was that employers still feel a lack of professional and technical workers is an impediment to growth, even during a recession. It was fourth behind Alaska’s near-omnipresent issue of high energy prices. Popp said the skilled worker shortage is likely attributable to qualified candidates moving to the Lower 48 where jobs are readily available and the cost of living is lower. The biggest issue facing Anchorage businesses, according to the survey, is the state economy, and specifically what lawmakers will or won’t do to try and stabilize it. “Business needs certainty and state government is not giving that to the business community and until businesses can pencil out what their taxes are going to be, no one can say what they’re going to be — the Legislature and the governor can’t seem to come together to an answer — this uncertainty continues to keep money on the sidelines, hence the reason it’s the number one issue,” Popp emphasized. AEDC is one of many business organizations across Alaska that for several years has been advocating for the Legislature to pass a fiscal plan centered on using a portion of the earnings of the Permanent Fund to pay down the state’s ongoing multibillion-dollar annual budget deficits. Despite the challenges, Anchorage business leaders overall have changed their tune from markedly negative in 2017 to “kind of ambivalent” in 2018, as they see more positive economic indicators aside from the state’s issues. GCI co-founder and CEO Ron Duncan reiterated Popp’s sentiment on the state budget in a speech following the economic forecast. He characterized the state’s budget problems and resulting economic hesitance as “purely a self-inflicted problem” because political leaders in both parties have chosen to hold out for what they see as the perfect solution instead of employing the one tool a large majority of lawmakers already feel is necessary to solve the vast majority of the problem — earnings from the Permanent Fund. State economists generally consider the current recession in Alaska has primarily been caused by a sharp retraction in government and a lack of public confidence that the deficits will be resolved soon and for the long-term. “It’s hard to feel comfortable investing more in Alaska until we can see a path to fiscal stability,” Duncan said. “If we start using the earnings in a sustainable way before we drain away all of our savings then we have a chance to restore business confidence.” ^ Elwood Brehmer can be reached at [email protected]

Mallott, Sullivan meet with top Canadians on transboundary issues

Lt. Gov. Byron Mallott and Sen. Dan Sullivan watched Super Bowl LII together in Ottawa and spent time strategizing on their approach to the next day’s meetings. They were there to discuss issues as far-reaching as ocean debris, missile defense and the North American Free Trade Agreement with Canadian federal officials as well as provincial and First Nations leaders, according to Sullivan, but the priority topic brought up in every discussion was that of Canadian mines at the headwaters of rivers that terminate in Alaska. The state officials reviewed the meetings in a Feb. 5 call with Alaska press. From the outset, Sullivan said the fact that Mallott, a longtime Democrat leader in the state, and himself, a staunch conservative, were in lockstep on the transboundary rivers issue sent a “powerful message of unity and that this is a very important issue of concern for the people we represent.” At the heart of the matter are 10 mines in British Columbia that are either in operation or stages of exploration and development. Those mines or mineral prospects are mostly open pit projects focused on copper and gold recovery. The mine locations within the watersheds of the large Taku, Stikine and Unuk rivers that support large salmon fisheries are the primary cause for concern among Southeast Alaska commercial fishing and conservation groups that fear problems at the mines could damage or destroy the rivers’ fisheries. Mallott and Sullivan said they pushed four priorities they are seeking action on from Canadian officials — either at the federal or provincial levels. The Alaskans requested increased transparency in the permitting process for the mines and opportunities for Alaskan stakeholders to provide input when mine plans are being reviewed. They also asked for additional financial assurances or bonding requirements for the mine operating companies to protect Alaska fishing and tourism businesses that rely on robust fisheries in the rivers “if, God forbid, we had a Mt. Polley-type disaster that went into our waters,” Sullivan described. The 2014 Mt. Polley mine tailings dam breach spilled more than 6 billion gallons of wastewater into the upper Fraser River system in British Columbia. Mt. Polley mine operator Vancouver-based Imperial Metals Corp. opened the Red Chris copper-gold mine in the upper Stikine River watershed in 2015. Sullivan added that they also asked the Canadian government to join in funding baseline water quality studies and ongoing monitoring to track if the mines are impacting the rivers, a program which Congress started funding last year. Lastly, they insisted on immediate reclamation of the Tulsequah Chief mine that has been leaching acid rock drainage into the Taku River near Juneau since the mine was abandoned in 1957. A temporary water treatment plant was built in 2011 to deal with the leaching but it was quickly shut down in 2012, according to the Alaska Department of Natural Resources. Chieftain Metals Corp. is now proposing an underground mine at the Tulsequah site that is about 10 miles upriver from the Alaska border. The project received regulatory approval from British Columbia in 2012 but is awaiting financing. Sullivan said he thought the meetings were constructive but the transboundary issue is far from solved. “We put forward some specific requests and we’re going to press on those,” he said Feb. 5. “I think they’re legitimate requests; I think they’re reasonable requests but they’re requests for specific actions and we certainly hope our Canadian friends will work with us to follow up on it.” Mallott said the talks furthered the progress made by the Walker administration on the issue. In 2015, Gov. Bill Walker and British Columbia Premier Christy Clark signed a memorandum of understanding to promote economic development in concert with environmental protection. That led to a statement of cooperation signed by Mallott and British Columbia Environment and Mines ministers in Oct. 2016, which established a working group of state and provincial officials to discuss transboundary issues. Mallott said the meetings were important because the sides were able to discuss important policies that are outside of the nonbinding statement of cooperation. A possible referral of the issue to the International Joint Commission — strongly advocated for by Alaska Native and conservation groups — was not discussed in detail during the meetings but will be part of talks between the governments in the spring, according to Mallott. “The process involved for an IJC referral will continue to be discussed by the (federal) governments and we have asked them to do so,” he said. The International Joint Commission consists of five commissioners, two from Canada and three from the U.S., who review transboundary watershed issues. It was established after the 1909 Boundary Water Treaty, which at the time settled a battle between Montana and Alberta farmers who had dug competing canals to divert water from area rivers to their farms. According to its website, the commission has since settled more than 100 matters raised by the governments. An arbiter body, IJC can only get involved when called upon by both governments. In the U.S., the State Department makes that call. In November, Walker, Mallott and three members of the Alaska congressional delegation sent a joint letter to Secretary of State Rex Tillerson, urging him to help protect Alaska’s economic interests of fishing and tourism in Southeast by raising the transboundary mine issue in talks with his Canadian counterparts. Charles Faulkner, of the State Department’s Bureau of Legislative Affairs, responded with a letter Dec. 14, writing that the State Department and the Environmental Protection Agency have established a workgroup to coordinate actions and communicate concerns to Canadian officials. State Department officials in October also got a commitment from Global Affairs Canada to take up a bilateral review of potential gaps or shortcomings in cooperative agreements between the countries that deal with transboundary issues. “The Department of State will lead this review process with interagency and stakeholder input, with the goal of sharing its findings with Global Affairs Canada at the April 2018 IJC meetings,” Faulkner wrote. “We value your assistance and input in this effort. As Canadian support would be required for a joint IJC reference, we will continue to raise this issue in upcoming bilateral meetings.” The issue of mines in British Columbia potentially impacting fisheries in Alaska waters has been one Alaska officials have tried to tread lightly on despite calls for a much tougher stance by some Southeast groups. That’s because, for one, they do not want to strain what has historically been a strong relationship with British Columbia and Canada in general, as well as the facts that the state has little actual leverage in addition to a long history if mining and support for the industry. To the latter point, Sullivan said he emphasized that Alaska supports resource development in the meetings, but he believes the state has valid concerns given what could happen downriver from the mines. He and Mallott also said the issue of oil exploration in the Arctic National Wildlife Refuge coastal plain — one Canadian Embassy officials actively lobbied against in Congress during the tax reform debate — came up in the transboundary river meetings. Sullivan described it as “probably one of the more contentious issues of our meetings.” “There was a bit of an analogy between the Porcupine caribou herd and transboundary mining and I, at least in my response, said I rejected that completely,” Sullivan recalled. Canadian officials have opposed oil development in ANWR for the fear that it would impact the calving grounds of the caribou herd that migrates into the Yukon Territory and is relied on by there by First Nations people as it is by some Alaska Natives. In a December interview with the Journal, Sullivan contended that the only reason Canada opposes development in ANWR is because the country didn’t find any oil on its side of the border when exploratory drilling was done in the Yukon Arctic decades ago. In that interview, Sullivan said he told the Canadian ambassador to the U.S. to “stand down” or he was going to “do everything I can to screw your country.” The delegation in an October letter to the Canadian ambassador to the U.S. said British Columbia to that point had done “remarkably little” to consider their transboundary concerns and pointed to the Mt. Polley and the Tulsequah Chief mine as demonstrable indicators that “Canadian mining is not always carried out to the same safety standards as in the U.S.” Mallott said the state will follow through with consultation that is required under a 1987 treaty with Canada meant to ensure a healthy Porcupine caribou herd. The state is also working to develop an accord with the Yukon Territory to address climate change and economic development matters, according to Mallott. “We were very clear to say we’re supportive of the exploration that is now authorized in the 1002 area of ANWR but that we also wanted to work closely with particularly the indigenous people on both sides of the border as we proceed ahead,” Mallott said. Elwood Brehmer can be reached at [email protected]

Permanent Fund value hits $64B at fiscal year midpoint

It was a good news-bad news kind of day for Alaska Permanent Fund managers. While the Alaska Permanent Fund Corp. reported strong returns of 8.45 percent and a total Fund value of $64 billion in the first half of the 2018 fiscal year on Monday, domestic markets were also down sharply for the second consecutive trading day. The Dow Jones Industrial Average closed Monday at 24,345, down more than 7 percent from the start of Friday trading. However, from July 1, 2017, to Jan. 1 the public equities portion of the Fund’s investments produced an 11.9 percent return and outperformed the corporation’s investment benchmark. Roughly $28 billion, or 44 percent of the Fund’s total assets are allocated to public equities, according to the latest APFC financial report. The $64 billion highlighted in the report was comprised of $48.7 billion in the principal portion of the Fund and $15.3 billion in the Earnings Reserve income account. CEO Angela Rodell said in a release that she was particularly “pleased to see the quality and diversity of the portfolio’s investment returns across all asset classes. Double-digit performance returns have been achieved not only in public equities, but in APFC’s private equity and infrastructure holdings as well.” The private equity investments totaling $7.6 billion generated 13.9 percent returns in the first six months of fiscal 2018. Infrastructure and private credit allocations of $3.5 billion netted a 12.4 percent return for the period. Fixed income investments totaling $13.6 billion as of Dec. 31 generated a 2.6 percent return, the smallest performance return among the Fund’s major asset classes, according to the performance report. Overall, the 8.45 percent six-month return surpassed the corporation’s blended performance benchmark by nearly 1.3 percent and outperformed the APFC Board of Trustees return objective of inflation plus 5 percent by 3.1 percent. As of Friday, the Permanent Fund had an unaudited value of $65.2 billion. The Permanent Fund has more than doubled in overall asset value since ending the 2009 fiscal year at $29.9 billion following the market crash that spurred the Great Recession in the Lower 48. The Permanent Fund principal is protected from being spent by the amendment to the Alaska Constitution that established the Fund. Spending from the Earnings Reserve, however, requires a simple majority vote from both bodies of the state Legislature. To date, the only spending from the Earnings Reserve has been to pay out annual Permanent Fund dividends to residents based on a percentage of the Fund’s previous five-year performance. Gov. Bill Walker and House and Senate leaders have pushed to implement a percent of market value, or POMV, appropriation structure from the Earnings Reserve to pay down up to nearly $2 billion of the state’s ongoing budget deficits in excess of $2.5 billion. While the House and Senate both passed similar versions of the governor’s POMV legislation last session with annual draws in the 5 percent range, contingencies linked to the bill on how the Democrat-led House and Republican-led Senate want to close the rest of the budget gap have stalled reconciliation to this point. Both versions of the legislation would use a portion of the POMV draw to continue paying dividends, but likely at a reduced rate from the current formula. The APFC board of trustees has long supported a sustainable POMV draw to provide stability for the Fund and its managers. With the state’s traditional savings accounts dwindling, legislators will very likely be forced to pull from the Earnings Reserve— via a POMV or a dreaded ad-hoc appropriation — within the next two state budget cycles. Elwood Brehmer can be reached at [email protected]

CP rebounds, buys Anadarko Slope interests for $400M

ConocoPhillips reported its largest quarterly earnings in more than three years Feb. 1 when the company announced a profit of nearly $1.6 billion for the fourth quarter of 2017. In Alaska, ConocoPhillips reported adjusted earnings of $283 million for the quarter and $652 million total for 2017. It also purchased all of Anadarko Petroleum Corp.’s North Slope assets for $400 million. The companies have been joint bidders, with Anadarko in a minority position, on significant lease tracts in the eastern NPR-A and western state Slope leases in the past few years. Many of those areas are not currently unitized. Also on Feb. 1, Andeavor, formerly Tesoro Corp., announced it has agreed to purchase the Kenai LNG plant and marine terminal from ConocoPhillips for an undisclosed amount. ConocoPhillips had been publicly shopping the aging facility since November 2016 and in July said it was taking steps to mothball the facilities. The plant has not exported LNG since 2015, primarily because of global market conditions. ConocoPhillips’ adjusted earnings companywide were $540 million for the quarter, according to the balance sheet. Company executives attributed the roughly $1 billion boost from its adjusted earnings to its overall profitability for the quarter primarily to benefits from the corporate tax reform legislation passed in December and an arbitration settlement in Ecuador. ConocoPhillips was able to recalculate its deferred federal corporate tax obligation at the new, lower 21 percent tax rate compared to the previous 35 percent corporate rate, resulting in $900 million of benefits, a company release states. Regardless, the fourth quarter of 2017 was by far the best quarter ConocoPhillips has had since oil prices began falling in the third quarter of 2014, when it netted $2.7 billion. For the full-year 2017, ConocoPhillips still reported a loss of $855 million, compared to a $3.6 billion loss in 2016. In 2017, its average realized price was $39.09 per barrel of oil equivalent, which includes the price of natural gas, compared with $28.35 per barrel equivalent in 2016. “2017 was a very successful year by all measures,” CEO Ryan Lance said Feb. 1. “We accelerated our disciplined, returns-focused value proposition and delivered on our strategic priorities. We transformed our portfolio, strengthened our balance sheet, returned 61 percent cash flow from operations to shareholders through our dividend and (stock) buyback program, and achieved our operational milestones, including 200 percent organic reserve replacement.” ConocoPhillips paid down $7.9 billion of debt in 2017 to bring its year-end debt to $19.7 billion. This year, the company has already paid down another $2.25 billion of debt, according to Lance. The $1.6 billion in quarterly earnings was on the back of $8.7 billion in total revenues, compared to $7.2 billion in the last months of 2016. For the year, ConocoPhillips generated $32.5 billion in revenue versus $24.3 billion in 2016. The company’s Alaska production was up an average of 4,000 barrels of oil per day in 2017 to 167,000 barrels per day, according to the financial report. ConocoPhillips operates the large Kuparuk and Alpine oil fields and holds a 36 percent stake in Prudhoe Bay. In November, the company began producing from its 1H NEWS (Northeast West Sak) viscous oil project in the Kuparuk field, which has an expected peak production rate of 8,000 barrels per day. It also recently brought additional wells online at its CD-5 development in the Alpine field, which started producing in late 2015 and has significantly exceeded production expectations. Originally expected to produce up to 16,000 barrels per day, CD-5 is currently producing roughly 37,000 barrels per day with the new wells, according to ConocoPhillips. Anadarko buyout Anadarko is a silent partner in much of ConocoPhillips’ work on the North Slope, but much of that partnership appears to be coming to an end. The deal, subject to regulatory approval, has an effective date of Oct. 1, 2017, according to ConocoPhillips. It includes the Alpine oil field assets that produced an average of 63,000 barrels of oil per day in 2017, in which Anadarko holds a 22.45 percent stake, according to the state Division of Oil and Gas. Conoco also reported the deal will give it a 100 percent interest in approximately 1.2 million acres of exploration and development areas; that includes the Willow prospect in the National Petroleum Reserve-Alaska, which the company estimates could produce up to 100,000 barrels of oil per day if fully developed. According to Oil and Gas, Anadarko has a 22 percent stake in the Greater Mooses Tooth Unit in the NPR-A — the site of Willow and the two Greater Mooses Tooth oil projects — and a 24.62 percent interest in the adjacent Bear Tooth Unit, also in the NPR-A. Elwood Brehmer can be reached at [email protected]

Alaska Air Group nets $1B in ’17 as Virgin integration continues

Alaska Air Group Inc. reported profits of just more than $1 billion in 2017 after its first full year owning Virgin America, but is still managing challenges associated with its purchase of the former competitor. The Seattle-based parent company of Alaska Airlines also posted a $367 million profit for the fourth quarter of 2017, which compared to $814 million full-year 2016 and $114 fourth quarter 2016 profits. Alaska Air Group executives announced the quarterly and year-end results in a Jan. 25 conference call with investors. The income came on the back of $7.9 billion in operating revenue for the year, up 34 percent from 2016, and $1.9 billion in revenue for the fourth quarter, a 29 percent increase year-over-year. The profits translated into $118 million in annual performance bonuses, which were paid out Jan. 26 to Air Group’s 23,000 employees. “This is the ninth consecutive year in which we’ve proudly shared profits with our employees at levels that have averaged about one month of additional pay,” CEO Brad Tilden said. “This year’s payout averages 7.3 percent of pay for Air Group frontline employees.” Alaska Air Group stock stayed mostly flat after the earnings call, ending Jan. 25 trading at $62.07 per share. It peaked in early March 2017 at nearly $100 per share. The company repurchased $75 million of stock in 2017 and also announced an increase to its quarterly dividend to 32 cents per share Jan. 25. It’s the fifth time the dividend has been increased since it was started in 2013. While the airline company’s revenue expectedly grew after acquiring Virgin America in the $4 billion deal that closed Dec. 14, 2016, integrating Virgin into Alaska Airlines has not come without significant costs as well. According to a chart provided by Air Group that blends its premerger 2016 numbers with those of Virgin America for comparison against the 2017 financials, operating revenues were up 6 percent in 2017, but pretax income was down 21 percent from the blended 2016 figures at $1.3 billion. Higher oil prices caused fuel costs to rise $323 million, or 29 percent, but other non-fuel operating expenses were also up $426 million, or 9 percent. Tilden said the company’s earnings are under pressure from step function cost increases along with competitors adding capacity in Alaska’s markets — primarily Delta Air Lines out of Seattle. However, he noted that while Air Group has incurred most all of the costs associated with the extremely complex task of integrating working airlines, it is just starting to see the benefits. “Of the $300 million original synergy target, we expect to realize $65 million in 2018, consistent with our prior forecast. We continue to believe the revenue potential of the new Alaska network is substantial, and we expect synergies to reach $200 million in 2019,” Tilden said. “More important than the synergies, however, is the incredible platform that we’ll have to grow revenue and profit in the years ahead and create value for our owners, our customers and our employees, just as we have in the last couple decades.” Alaska Air Group plans to move to a single passenger service system on April 25, which will blend the Virgin America shopping, flight scheduling and airport check-in systems with Alaska Airlines, according to Tilden. The company received a single operating certificate for Virgin and Alaska from the Federal Aviation Administration Jan. 11. Tilden also noted that the airlines’ operations had been co-located at 22 of the 31 airports needing consolidation and the rest of that would be done in April. “We’ve made all aircraft delivery and interior decisions, and our first Airbus airplane came out of the paint shop yesterday with new Alaska colors,” Tilden added Jan. 25. Alaska Airlines for years had flown only Boeing 737s, of which it has 154, but it is now also flying 67 Airbus A320s, which company leaders have said it will continue to fly at least through 2021 when some of the Airbus leases begin expiring. On the financial front, the company lowered its debt-to-capitalization ratio from 59 percent to 51 percent during 2017. Chief Financial Officer Brandon Pedersen said the company is committed to having a debt-to-cap ratio in the mid-40 percent range by 2020, noting it is well-positioned if interest rates continue to rise because half of the company’s debt is fixed. Alaska Air Group’s debt-to-cap was down to 27 percent at the end of 2015 shortly before buying Virgin America. The company ended 2017 with $1.6 billion in cash after generating $1.7 billion in operating cash flow and spending roughly $1 billion on capital projects, which left Air Group with $670 million in free cash flow, minus integration costs, according to Pedersen. Operationally, Tilden said the company is focused on continuing on-time performance improvements made in the fourth quarter. Alaska Airlines had long been the top domestic carrier in on-time performance, the fundamental operational metric. However — even including Virgin America’s 2016 on-time figures for comparison’s sake — Alaska’s on-time performance fell from 87.3 percent in 2016 to 82.6 percent last year. As Tilden mentioned, there was significant year-over-year improvement in the fourth quarter, with 83.4 percent of Alaska flights arriving on time compared to just 76.1 percent in the latter portion of 2016. For Virgin America, the trends were similar but the numbers were worse. Overall, just 70 percent of Virgin flights arrived on time in 2017, but the airline managed an improvement to 82.5 percent in the fourth quarter. Finally, Air Group has reached joint collective bargaining agreements with Alaska and Virgin pilots and customer service agents and Tilden said management believes it is close to similar agreements with the flight attendant and maintenance technician unions. In early January the Seattle Times published a lengthy story detailing employee discontent at Alaska Airlines due to cost-cutting and merger-related actions. Elwood Brehmer can be reached at [email protected]

Oil tax bill gets chilly reception from industry

State Revenue Department officials say the oil production tax increase being debated in the House would not change bottom lines much at current market prices but company leaders stress it would further cement Alaska’s poor reputation in the oil and financial sectors. Tax Division Director Ken Alper testified to the House Resources Committee Jan. 26 that the proposal to raise the minimum gross production tax from 4 percent to 7 percent would increase the state’s tax take by 54 cents per barrel at oil prices of $70 per barrel. According to the state Revenue Department, Alaska North Slope crude sold for $70.57 per barrel when markets closed Jan. 29. That 54 cents per barrel extrapolates out to an additional $91 million per year to the state per year at current prices and production rates. Alper said the state can be expected to receive about $400 million in oil production taxes at $70 oil and again current production rates forecast for about 533,000 barrels per day. House Bill 288, the vehicle for the tax proposal sponsored by House Resources co-chair Rep. Geran Tarr, D-Anchorage, would become revenue-neutral at $72 per barrel, Alper projected, because that is the price at which the progressive net profits tax calculation would generate more revenue for the state than the gross minimum tax and by law automatically kick in. However, HB 288 would amount to an annual collective tax increase of $205 million to $256 million at average prices between $50 and $60 per barrel — where the delta between the current 4 percent and proposed 7 percent minimum tax would be realized. 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 just less than $70 per barrel, according to Alper. The crossover price has been falling in recent years as companies have cut costs to stay in business while prices have been mostly less than $70 since late 2014. 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, Revenue estimates. “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. Anchorage Republican Rep. Chris Birch said the Legislature should be focused on doing what it can to spur more industry spending and oil production because the state also gets at least 12.5 percent of all North Slope oil through its royalty share, which, particularly during periods of lower prices, makes the lion’s share of petroleum revenue. “The tax against the net is certainly worthy of discussion here but I think we need to not lose focus on the fact that anything we can do to encourage investment and production is going to have a much larger and significant impact on our state revenues,” Birch said during the Jan. 26 meeting. Industry representatives testifying Jan. 29 before the Resources Committee stressed the fact that HB 288 could be Alaska’s eighth oil tax change in the 12 years since it switched from a gross to a net profits-based system in 2006. Benjamin Johnson, CEO of BlueCrest Energy, a small company developing the Cosmopolitan oil field in Cook Inlet, said despite the fact that his company would not be directly impacted by HB 288, “the stability of Alaska’s taxing regime affects all companies.” Cook Inlet oil is taxed at a flat $1 per barrel, and HB 288 applies only to North Slope production. “We have to create an environment of confidence with global capital markets. So far Alaska has unfortunately gained the reputation of trying to squeeze the oil industry in any way it can,” Johnson added. “For the long-term good of Alaska I urge you not to support HB 288.” While Alaska’s constant oil tax debates and not keeping up with expected refundable oil and gas tax credit changes has left a black mark on the state in the eyes of oil financiers, Tarr emphasized HB 288 is largely a means to start closing the state’s $2.5 billion-plus deficits absent another compromise from the Republican-controlled Senate. Senate Republicans shot down a House-passed income tax last year. Senate President Pete Kelly, R-Fairbanks, said before this session that any other broad-based tax proposals would be met with “mocking laughter” and summarily dismissed in favor of further budget cuts. House Speaker Bryce Edgmon, D-Dillingham, has said his caucus won’t push for an income tax this year but hasn’t ruled out other revenue measures. On the other hand, state business leaders in sectors other than oil have pushed for the state to resolve its four years of large deficits in some manner to bring stability to local economies that have been in limbo as legislators tussle over what government services to cut and who should be taxed. HB 288 is an alternative to otherwise fruitlessly pushing for a deal with the Senate on individual taxes, according to Tarr. ConocoPhillips Alaska Vice President Scott Jepsen told the committee that despite the cuts made to the oil and gas tax credit program over the past two years the key provisions of the tax structure that took effect in 2014 with Senate Bill 21 — a change industry by and large supported — remain in place. “I can tell you from our company, that (keeping SB 21 in place) has helped when it comes to our investment decisions,” Jepsen said. He indicated that while those in favor of raising taxes on the industry often note royalty and production tax rates are higher in many oil states across the Lower 48, oil in those basins requires drastically less money to produce and because companies factor all economic elements into investment decisions meaning Alaska needs to have lower taxes to stay competitive. “I like to say the center of gravity for oil and gas investment right now is in the Lower 48 and particularly in Texas,” Jepsen said. He continued to say, “No surprise, we would recommend this committee not pass this bill and try to keep the competitive environment that we still have in place here in Alaska.” ^ Elwood Brehmer can be reached at [email protected]

EPA’s unexpected decision welcomed by Pebble opponents

Environmental Protection Agency Administrator Scott Pruitt’s unexpected Jan. 26 comments expressing his environmental concerns about the Pebble mine were welcomed by mine opponents and reflected in the stock price of Northern Dynasty Minerals Ltd., which is the sole owner of the prospective copper and gold project. Pruitt announced Jan. 26 that the EPA would not finalize the 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. The agency said in a statement that it has “serious concerns” about the impacts of mining activity in the Bristol Bay watershed and public comments in stakeholder meetings stressed the importance of the world’s largest wild salmon fishery. Pruitt said it would be disingenuous for the agency to not to offer an environmental position at this stage of the project. Vancouver-based Northern Dynasty’s stock opened trading on domestic markets down 19 percent Jan. 29 from its closing price of $1.52 per share Jan. 26. The EPA’s statement on the project was issued after East Coast markets had closed that day. Northern Dynasty’s stock price stabilized at about $1.18 per share, or down about 22 percent after several hours of trading Jan. 29. Northern Dynasty is also traded on the Toronto Stock Exchange. Pebble Limited Partnership filed its wetlands fill permit application with the U.S. Army Corps of Engineers Dec. 22. The application outlines 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 concludes a mine that would fill more than about 1,100 acres would be too damaging to fish habitat to allow. Pruitt emphasized in his statement that his decision “neither deters nor derails” the Pebble environmental permit application process now underway while at the same time he has heard from stakeholders on whether to withdraw the proposed 404(c) restrictions. “Based on that review, it is my judgment at this time that any mining projects in the region likely pose a risk to the abundant natural resources that exist there,” Pruitt said Friday. “Until we know the full extent of that risk, those natural resources and world-class fisheries deserve the utmost protection. Today’s action allows the EPA to get the information needed to determine what specific impacts the proposed mining project will have on those critical resources.” According to the Federal Register docket, just more than 1 million public comments have been submitted to the EPA on the proposal to withdraw the proposed 404(c) restriction, but it is currently unclear how many favor or oppose the action. With that in mind, Bristol Bay-area Native groups, lawmakers and fishing organizations considered Pruitt’s position — largely surprising given the Trump administration’s push to promote mining and infrastructure projects — a step in the right direction. United Tribes of Bristol Bay Executive Director Alannah Hurley said the group is happy Pruitt left the proposed veto “on the table,” but it will be several years before the EPA could invoke it under the terms of a May 2017 settlement of a lawsuit filed by the Pebble Partnership. Pebble sued the agency in 2014 alleging the EPA was biased in its proposed action after improperly colluding with anti-Pebble groups to reach its conclusion. A federal judge issued an injunction in late 2014 that stopped the EPA from finalizing the proposed restrictions against mining in the Bristol Bay watershed; settlement talks between the EPA and Pebble started late in the Obama administration and were ultimately concluded under Trump’s. Pebble CEO Tom Collier highlighted in the company’s response that the agreement the EPA reached with Pebble last year gives the company the assurance it can go through the federal permitting process without the worry of the agency finalizing the proposed preemptive prohibition on Pebble. “The (Corps of Engineers) has determined we have a complete application and has initiated a thorough, objective review of the Pebble project,” Collier said. “We intend to participate fully in the process and encourage al project stakeholders to do the same. “We believe we can demonstrate that we can responsibly construct and operate a mine at the Pebble deposit that meets Alaska’s high environmental standards. We will also demonstrate that we can successfully operate a mine without compromising the fish and water resources around the project. We look forward to having all of our detailed information fairly reviewed by the Corps of Engineers and other participating regulatory agencies through the longstanding, lawful permitting process.” Specifically, the EPA-Pebble settlement called for the agency to start the process of withdrawing the proposed mining restriction, which it did in July, but it does not require that process be finalized and because it is a proposal to remove a proposal with nothing final, Pruitt’s action set a tone but did not change anything formally. The settlement also does not allow for the EPA to resume restricting the development until a final environmental impact statement is published for the project or four years after the May 2017 settlement, whichever comes first. UTBB President Robert Heyano said Pruitt’s decision shows the power of a unified local voice even in times of highly partisan politics. “The United Tribes of Bristol Bay would like thank EPA Administrator Scott Pruitt, (Region 10) Administrator Chris Hladick and the staff at EPA for their work. The fight to protect our watershed from Pebble is far from finished. But today’s decision, and all those who worked tirelessly to get us here, will be celebrated,” Heyano said. Hladick, a former city manager of Dillingham, where the project is widely opposed, transitioned from heading the Commerce Department in Gov. Bill Walker’s administration to leading the Alaska-Pacific Northwest region of the EPA in December. Walker said told the Journal while campaigning in 2014 that he opposed development of Pebble but also was worried about the precedent the EPA’s preemptive push to prevent the mine could have on other development projects in the state. The governor told Alaska Public Media in October that he had not been convinced Pebble should move forward and the company had a high bar to clear to had taken appropriate steps to prevent potential damage to the fish and wildlife habitat — a stance Pebble deemed appropriate at that time. “I have spoken to Administrator Pruitt about the Pebble Mine Project many times in the past year, and I have shared with him my belief that in the Bristol Bay region we should prioritize the resource that has sustained generations and must continue to do so in perpetuity. I thank the Environmental Protection Agency and the Trump administration for listening to my input, as well as the input of thousands of Alaskans who oppose rescinding the EPA’s Bristol Bay (restrictions),” Walker said Jan. 26. California treasurer weighs in Meanwhile, California Treasurer John Chiang sent a letter Jan. 29 to leaders of First Quantum Minerals Ltd. urging them to stay out of the Pebble project. Chiang is also a trustee to the California Public Employees’ Retirement and California State Teachers’ Retirement systems. He wrote that the California pension funds believe sustainable business practices are fundamentally important to long-term value growth for sharheolders and therefore, First Quantum, a Canadian mining firm investigating whether or not to invest in Pebble, should not. “As a fiduciary of these funds, I cannot ignore the far-reaching economic implications and sustainability risks at play here,” Chiang wrote to First Quantum CEO Philip Pascall and President Clive Newall. “In my view, investment in the Pebble project presents undue risk not only to the long-term sustainability to the Bristol Bay region, but also to the value of our long-term investments in First Quantum Minerals, Ltd.” CalPERs, with a total market value of $362 billion, holds nearly 4.3 million shares of First Quantum as well as bonds in the mining company with a maturity value of $2.3 million, the fund’s latest annual report states. There are more than 689 million outstanding shares of First Quantum stock, according to the company’s 2017 annual report. First Quantum and Northern Dynasty announced a framework investment agreement Dec. 18 under which the former could invest up to $1.35 billion in Pebble to buy a 50 percent interest in Pebble Limited Partnership, the project operating company. First Quantum made an initial $37.5 million option payment to Northern Dynasty to support permitting costs shortly after the deal outline was announced, according to Northern Dynasty officials. The company is expected to make a decision on the overall agreement in the second quarter of this year. Chiang noted that he and then-City of New York Comptroller John Liu in 2013 expressed their concerns about Pebble to Northern Dynasty’s then-partner Rio Tinto, a mining major, and Rio Tinto divested its share of Pebble in April 2014. Northern Dynasty has said it will need a large investment partner to help fund mine permitting and development. Elwood Brehmer can be reached at [email protected]

Slope well review reveals no issues beyond those flagged by BP

An emergency engineering review of all North Slope wells ordered last October by state regulators did not reveal any significant issues but a regulation change is still likely. The Alaska Oil and Gas Conservation Commission issued the emergency directive to North Slope production and exploration companies Oct. 30 after it was determined a BP well at Prudhoe Bay Drill Site 2 that failed and sprayed about 100 gallons of oil last April did so largely due to its outer surface casing being set in the permafrost — and the permafrost thawing and subsiding. The commission, which regulates all of the highly technical subsurface oil and gas activities in the state, ordered all wells found to have similar construction to be shut in by Dec. 31. BP had previously plugged five producing wells at Prudhoe after its own review spurred by the April leak, according to a company spokeswoman. The hot fluids produced from a well can melt the surrounding permafrost, causing the thawed water to drain away and leading the ground to sink. That gradually puts the outer well casing under a compression load, which combined with other pressure and temperature affects, can cause the casing to fail, according to BP’s report to the commission on the well failure. AOGCC Commissioner Cathy Foerster said in a brief interview that every operator did the evaluation and reported back to the commission, which found there are no other wells with construction characteristics mirroring the failed well other than those previously reported and shut in by BP. ConocoPhillips, operator of the large Kuparuk and Alpine oil fields, has a handful of wells with casings set in the permafrost, but other elements of construction necessary for the failure to occur aren’t present in those wells, according to Foerster. According to AOGCC records, there are more than 3,700 wells on the Slope, of which, nearly 1,600 are active production wells. The rest are injection, disposal or idle production wells. Despite the good news from the well review, the commission is proposing a regulation change that would require the surface casings of all future wells to be set below the bottom of the permafrost to prevent history from repeating itself. “Just to make sure that after this set of commissioners and engineers are gone in the future it can’t happen again we’re going to prohibit setting that casing string in the permafrost,” Foerster said. No one showed up to testify at a Jan. 4 public hearing to discuss the regulation change. “Usually what we do is pretty boring and this is just another example of that,” Foerster added. Elwood Brehmer can be reached at [email protected]

Alyeska, Prince William Sound council clash over tug training

Alyeska Pipeline Service Co. is at odds with the advisory group that monitors oil tanker activities in Prince William Sound over how far Alyeska’s tugboat operators should have to go to demonstrate they can operate safely in poor weather and wave conditions. The Prince William Sound Regional Citizens’ Advisory Council board unanimously passed a resolution Jan. 18 insisting that oil tankers and their tug escorts should not be allowed to operate in the Sound if weather conditions deteriorate beyond what has been deemed safe for training. “If it is unsafe to train personnel, it is unsafe to transport oil. This position does not just apply to the incoming contractor, but sets the standard to which the council feels all future new contractors, equipment and crews should be held,” Advisory Council board President Amanda Bauer said. “We believe strongly that these standards are needed to ensure the economic and environmental safety of the communities and groups we represent.” The incoming contractor Bauer referenced is Edison Chouest Offshore, which Alyeska announced in June 2016 would be taking over tanker escort and spill response duties for Crowley Marine Services in July 2018 with a new fleet of tugs and spill response barges. Crowley has provided tanker docking services in Valdez since the startup of the Trans-Alaska Pipeline System in 1977. It added the Prince William Sound tanker escort and spill response to its work when those duties were first mandated in 1990, a year after the Exxon Valdez oil spill. Alyeska Pipeline Service Co. is owned by the “big three” North Slope producers BP, ConocoPhillips and ExxonMobil. It manages TAPS operations and oversees the associated oil tanker activities in Prince William Sound. The Prince William Sound Regional Citizens’ Advisory Council was formed after Congress passed the Oil Pollution Act in 1990 in response to the Exxon Valdez spill. The legislation mandated the groups be established for Prince William Sound and Cook Inlet. While the advisory bodies made up of technical experts and community representatives from their regions do not have enforcement authority, they are generally well respected for taking informed positions. The resolution specifies that the advisory council believes “it is unsafe to require crews to respond to a vessel emergency in Prince William Sound during adverse weather with inadequate or no training or experience in these conditions, and that new crews must receive training and experience in the full range of operating conditions in which they are expected to perform.” It continues to assert that it is reasonable and prudent to limit loaded tanker traffic through the Sound to the range of conditions in which the escort vessels and crews have been trained. Alyeska responded with a formal statement that it shares the advisory council’s commitment to protecting the environment, which it demonstrates each day in often challenging conditions, but the company strongly disagrees with requiring demonstrations in potentially dangerous and uncontrolled conditions. “It is entirely inconsistent with a strong safety and risk management culture and not an accepted or proven training method for operational proficiency,” Alyeska stated. “There are many ways to demonstrate the competency and proficiency of crews and vessels that don’t create the level of risk to human life and the environment that the RCAC is promoting.” Alyeska further insisted it is hiring an experienced contractor with state-of-the-art vessels and training that will meet or exceed “current requirements for safe operations as well as the very high standards we set for ourselves.” Alyeska spokeswoman Michelle Egan compared it to firefighters no longer setting fire to derelict buildings with limited safety parameters for live training events. Loaded oil tankers are tethered to tugs as they leave the Alyeska oil terminal port and are then released but still escorted until they clear Hinchinbrook Island and hit the open Gulf of Alaska. Inbound, empty tankers are not escorted to the port unless an escort or other assistance is requested by the ship’s crew, according to Egan. If an emergency occurs, the tugs could come alongside the tanker and re-tether to it to either take it under tow or stop it, Egan said. It is specifically practicing those emergency situations in bad weather with a loaded tanker that Alyeska objects to. “That’s where the real danger and risk occurs and it’s not a part of normal operations,” she said in an interview. “To do that part of it in those closure conditions, we do not. It’s showing that you can handle the emergency under those conditions that we think is too risky.” Advisory council Executive Director Donna Schantz said in a formal statement that the council agrees with Alyeska and the regulating agencies that crew safety is the first priority, but that doesn’t preclude additional training. “We believe that drills and exercises, including in adverse weather, are controlled events, as they can be stopped at any time that the risk to crews or vessels becomes unacceptably high,” Schantz said. Alyeska Ship Escort/Response Vessel Systems, or SERVS, manager Mike Day told the council in September during an update report on the transition to Edison that he hoped the new tugs and crew would encounter some adverse weather in their training exercises, but said the training had to be scheduled well in advance for logistical reasons and specific wind and waves conditions would not be sought out. The advisory council noted in a white paper accompanying the resolution that Crowley has completed exercises in waves up to 15 feet with 35-knot winds. The Alaska Department of Environmental Conservation and the U.S. Coast Guard allow loaded tankers to operate in conditions up to 45-knot winds and 15-foot seas, according to the council, citing the tanker operational and escort response plans submitted to the agencies. DEC Central Region Manager Geoff Merrell wrote in a Dec. 12 letter to the Prince WIlliam Sound Response Planning Group that the new tugs will be expected to stop and control a fully laden 193,000-ton deadweight tanker in nine-foot seas and 40-knot winds, based on performance criteria in the existing operating plans, or closure conditions at Cape Hinchinbrook. Merrell wrote that the department acknowledges tankers are rarely loaded that full, however. “The department also understands that the scheduling of demonstration exercises combining both a fully laden tanker and inclement weather conditions may prove impossible during the transition timeline,” he wrote further. “The department remains open to the discussion of alternative demonstrations, surrogate ships or other options, but, ultimately, will require the satisfactory demonstration of system performance before a fully laden 193,000 (deadweight tons) tanker will be allowed to depart the Valdez marine terminal and transit Prince William Sound.” The advisory council also contends it has evidence indicating the buoy used by the National Weather Service to measure Gale Warnings, which equate to closure conditions, is somewhat protected from what can be worse wind and wave conditions at the adjacent Hinchinbrook Entrance at the same time. Elwood Brehmer can be reached at [email protected]

Producers celebrate Slope as House takes up another tax hike

Alaska leaders of the largest oil producers in the state are pointing to the recently-reversed production decline curve as proof the state’s oil tax system is working, but House Majority leaders contend Senate Republicans have forced them to again propose an oil tax increase to ease the state’s projected $2.7 billion budget deficit. BP Alaska President Janet Weiss, speaking at the Alaska Support Industry Alliance’s Meet Alaska Conference Jan. 19 in Anchorage, highlighted the fact that oil production at Prudhoe Bay has ostensibly been flat for three years despite the field’s age and low oil prices since then. “It was an amazing year to see no decline. In 2015, production was 281,700 barrels per day, in 2016 it was 280,700 barrels per day and déjà vu, 2017 it was 280,040, and in my book that’s no decline in a 40-year field that was supposed to have a life of only 30,” said Weiss, who had her head shaved the next day after losing a bet on the Prudhoe production output for 2017. Two days later, Weiss mailed her long black locks to Pantene, which has a program that makes wigs for cancer patients. At the operational level, she said the company improved the field’s plant reliability and did more than 500 non-rig well work jobs along with adding another previously drilled 100 wells to the active Prudhoe count. “It was like 100 wells coming online, so it’s the focus on the basics that enable extraordinary performance,” Weiss said. ConocoPhillips Alaska President Joe Marushack highlighted in a separate talk that several large and numerous smaller prospects and oil projects in development on the Slope could add more than 400,000 barrels per day of production at their peak over the next six years. Those projects include ConocoPhillips’ two Greater Mooses Tooth developments, at up to 30,000 barrels per day each; its Willow prospect with an estimated production capability of up to 100,000 barrels per day; Armstrong Energy’s Nanushuk project — to be taken over by Australian-based Oil Search in June — at 120,000 barrels; and Hilcorp’s offshore Liberty development at roughly 70,000 barrels per day of peak production. “We’ve got a lot of promise. We’ve got a lot of really good things (going),” Marushack said. He added that ConocoPhillips is working to add to that promise by drilling five exploration and appraisal wells this winter, its largest exploration program on the North Slope since 2002. It’s also the largest exploration program for ConocoPhillips this year across all the basins it operates, according to Marushack. “All eyes are on Alaska,” he said. Additionally, the company is preparing to shoot a seismic program across the roughly 250 square miles of state acreage south of the Alpine field along the east edge of the National Petroleum Reserve-Alaska that the company acquired last year. Weiss also noted that the coastal plain of the Arctic National Wildlife Refuge, just opened to industry by Congress and the Trump administration, is a greenfield area that could hold enormous potential and lead to longer term prospects. The U.S. Geological Survey estimates the coastal plain could hold upwards of 7 billion barrels of recoverable oil. She said BP would evaluate ANWR in light of the company’s global portfolio. The prospectivity is on top of two years of increased North Slope oil production already, with a third expected for the current state fiscal year 2018 that ends June 30. Production bottomed out in state fiscal year 2015 at 501,500 barrels per day but rebounded with two years of growth to 526,700 barrels per day in 2017. The Department of Natural Resources expects production to hit 533,000 barrels per day this year, according to the state Revenue Sources Book published this past December. Both Weiss and Marushack said keeping the existing but oft-debated state oil severance tax in place is critical to continuing growth on the Slope and seeing the prospects to production. Large producing companies on the Slope, such as BP and ConocoPhillips, were not eligible for the refundable exploration and development tax credit program that the Legislature ended last year, so they were not impacted by that change. The tax, passed by the state in 2013, was the primary driver behind the current production increases, Weiss said, reiterating a point hammered home by industry and most Republican lawmakers in the state. “We might be enjoying prices today that are over $70 per barrel but when you look at the fundamental — at BP anyway — we still think lower for even longer and staying competitive is very important,” she said. “It’s the lowest cost basins that will get produced,” Weiss continued. “Not all the barrels in Alaska are going to be produced if we don’t make them competitive.” Marushack said he is often competing within ConocoPhillips for investment dollars for Alaska projects, particularly against Lower 48 shale prospects, while his colleagues don’t continually have to worry about tax changes skewing project economics like he does. “We have to have stable, competitive fiscal policies,” Marushack said. House takes up tax hike Meanwhile, in Juneau, the House Resources Committee took up House Bill 288 for the first time Jan. 22. HB 228, introduced by Resources Committee co-chair Rep. Geran Tarr, D-Anchorage, would raise the minimum gross production tax on North Slope oil from 4 percent to 7 percent as a means of raising between about $220 million to $250 million of additional state revenue per year. Tarr said that while the broader criticism of the Legislature consistently changing oil tax policy is generally fair, she is proposing the oil tax change primarily because Senate Republicans have stonewalled attempts by Gov. Bill Walker and the Democrat-led House Majority coalition to pass an income or payroll tax that would diversify the state’s revenue streams and play a role in dissolving the multibillion-dollar budget deficits. Instead, the Republican-dominated Senate Majority has insisted on maximizing a draw from the Permanent Fund Earnings Reserve and relying on future budget cuts and increasing oil prices and production to balance the budget over several years. However, the prospect of achieving the further cuts of $400 million to $500 million — roughly 10 percent of the current Unrestricted General Fund budget — necessary to meet the Senate’s plan is unclear at best. Deeper cuts to education, community assistance and social programs proposed over the past few years have been withdrawn after being met with stiff resistance and public backlash. Tarr said House leaders feel “a little backed into a corner” in fighting for their constituents who do not want the reduced Permanent Fund dividends that come with utilizing the Earnings Reserve for government to be the only way out of the budget problems. She noted she represents the poorest part of Anchorage and her constituents often rely on the PFD to pay for essential items. “I could see some members of the industry thinking now’s the time to diversify and find some other sources (of revenue) so the finger’s not always pointed in their direction,” Tarr commented while outlining the bill. She stressed that it does not change the underlying production tax structure, but it would shift the oil price-sensitive “crossover point” where the tax switches from a gross to a profit-based tax to a higher price band. At its core, Alaska’s oil tax is a 35 percent net profits tax. On top of that is a sliding scale per-barrel credit that is $8 at prices less than $80 per barrel and fades out at prices greater than $150 per barrel. By applying the per-barrel credit, companies can achieve a lower tax rate at lower, less profitable prices. The last primary layer is the gross minimum tax, also known as the tax floor. It is applied at lower prices — the crossover is usually between $60 and $70 per barrel, according to the Revenue Department — when the amount 4 percent gross value calculation exceeds the amount of the profits tax calculation. For example, at $60 per barrel, the profits tax, with the per-barrel credit and deductible expenses applied, becomes a negative value. The 4 percent gross tax at $60 — minus oil transport costs that are never taxed — is approximately $2 per barrel and thus the oil is taxed on its gross value at that price. Anchorage Republican Rep. Chris Birch said the tax debate often omits discussion about the royalty revenue of 12.5 percent to 16.6 percent that the state receives on each barrel produced and he can’t see how increasing taxes will spur production and by extension more royalty revenue. “I’m almost struck by the old adage of ‘the beatings will continue until morale improves,’” Birch quipped. Tarr said she shares his concerns about keeping production up but characterized the proposal as being part of the state’s larger “math problem” when it comes to balancing the budget. She also contended the 7 percent gross tax would be among the lowest in the country for states with a gross severance tax on oil. The Resources Committee is expected to hear testimony from industry and Revenue Department officials starting Jan. 26. Elwood Brehmer can be reached at [email protected]

ConocoPhillips to drill Putu with unprecedented mitigation steps

ConocoPhillips is finally ready to drill into a small and long-sought piece of the North Slope, but only after agreeing to employ mitigation measures largely thought to be unprecedented, particularly for a single well. The Putu 2 exploration well is scheduled to be spudded in early February and finished in late April with completion of a well sidetrack, according to ConocoPhillips spokeswoman Amy Burnett. The cause for the unique drilling mitigation practices — from an electrified drill rig to multiple air quality monitoring sites and light suppression efforts — flows from the drill site’s proximity to the Native village of Nuiqsut. About three miles east-northeast from Nuiqsut, the Putu 2 drill site is in the direction of the prevailing winter winds that cross the tundra plains to the village. That caught the attention of many in Nuiqsut, according to Kuukpik Corp. CEO Lanston Chinn, who said the residents became concerned about, among other things, exhaust drifting into the community from a diesel drill rig that would be running continuously for more than two months. Kuukpik 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. ConocoPhillips first planned to drill the Putu well a year ago. That exploration plan was a driving force behind DNR Commissioner Andy 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. It is now part of the large Colville River Unit, commonly referred to as Alpine, from which ConocoPhillips produces about 65,000 barrels of oil per day. While a small area in North Slope terms, its proximity to a large, established oil field and the Nanushuk prospect that could hold more than 2 billion barrels of recoverable oil, according to its owner Armstrong Energy, make it a potentially rich piece of property. 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 President Joe Marushack said Jan. 19 at the Alaska Support Industry Alliance’s Meet Alaska Conference that even before drilling a well the company believes the Putu prospect could produce 20,000 barrels per day. It’s worth noting that as a publicly traded oil company, ConocoPhillips is in the business of making conservative public statements. When the company informed DNR last winter that it had decided to defer its 2016-17 Putu plan because of the villagers’ concerns, Mack, charged with assuring the state’s resources are developed as timely as possible, threatened to revoke the acreage. An agreement was eventually reached last August after a lengthy back-and-forth of formal correspondence to let ConocoPhillips keep the acreage if it drilled a well into the hot Nanushuk geologic formation by May 2018. The deal included a $7 million payment to the state in-lieu of the bids DNR estimated it would get if the area was put up for bid in a lease sale. While ConocoPhillips has long held a surface access agreement with Kuukpik Corp., according to the producer, it still needed to allay the worries of the locals downwind that they would not be ignored. They weren’t. For starters, the Putu 2 drill site is about a half-mile farther from Nuiqsut than the location chosen to drill last winter. The drill rig — Kuukpik 5, another part of the producer-Native corporation agreement — will be electrified and powered by six, 975-horsepower Tier 4 diesel generators located about a mile north of the drill site. Kuukpik Corp. has five subsidiary companies mostly focused on oilfield service support in the drilling, ice road, camp and catering, engineering and environmental monitoring specialties. Chinn said Kuukpik’s companies and Nuiqsut residents will do much of the work associated with drilling the well. According to Burnett, about 85 people will be on site at peak activity. A 13.8 kilovolt power cable encapsulated in ice 25 inches thick will connect the generators to the drill location, according to ConocoPhillips’ Putu 2 mitigation plan submitted to DNR. The Tier 4 generators are top-of-the-line in terms of limiting emissions, according to Cummins Power Generation, which claims to be the first generator manufacturer to receive the Environmental Protection Agency’s most stringent applicable certification. The 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 Chinn. “There will be zero emissions from the drill rig and zero emissions from the camp,” he emphasized. Further, three air monitoring stations will be set up for the project; two near the northeast edge of the village and one at the Putu 2 site. If particulate levels exceed EPA standards the whole operation will go into “warm shutdown,” Chinn said, and the generators and other engines will be run just enough to keep equipment and facilities from freezing. Noise monitoring equipment will also be installed at one of the air quality stations at the edge of the village and ConocoPhillips will limit vehicle idling at the site to cut down on noise pollution. A snow berm — if there is enough snow — will be built on the village side of the pad as a final noise-dampening measure, according to the mitigation plan. Water quality tests will also be done at the nearby lake that is Nuiqsut’s water source once it melts to assure none of the limited particulate matter emitted from the exhaust has settled and found its way into the lake, Chinn added. “Everything is monitored all along the path,” he said. “I think singularly it’s the most any oil company I know of here in Alaska has ever agreed to do.” If gas flaring is required to test the well, the flare will be enclosed and pointed away from the village, Chinn said. When drilling is complete, the well will be plugged and abandoned but the well will be caped and buried eight feet below the tundra, a full five feet beyond state requirements. Finally, ConocoPhillips plans to directional drill into the reservoir if it decides to develop the area, according to Burnett, meaning a permanent gravel well pad would be substantially farther from the village than the ice exploration pad. “Essentially, we got to the point where — it was kind of interesting — we kind of ran out of things to even ask them for,” Chinn said. “This is about everything you can possibly, conceivably think of to reduce (impacts). It’s not just reduction of impacts, it’s reduction of unnecessary impacts and we got to the point where the reduction of unnecessary impacts was just gone.” He said he believes the Putu 2 mitigation measures set a standard for exploratory drilling, if not Slope-wide, at least on Kuukpik land near Nuiqsut. “At this point I think it sets a good tone for the future relationship with industry too, because once it gets done, whether they want to admit it or not, it does set a precedent about how you go about doing things,” Chinn said. “We just demonstrated that you can and that under the right set of circumstances — they drug their feet initially because they’re not used to doing this. “But we said the environment is important; subsistence is important; the people are important; and therefore we have to address it accordingly. And I said if you’re not willing to address those major elements then we don’t need to be doing this. It’s important that the fundamental priorities that exist are treated that way.” He acknowledged that project economics would likely play a role in future mitigation discussions Kuukpik is involved in but the Putu well is close enough to Nuiqsut that economic considerations had to take a backseat in this instance. When asked if ConocoPhillips agreed that the Putu 2 well sets a precedent for future Slope exploration, Burnett wrote in an email that the well is much closer to a community than any other project on the Slope and the company is doing what it can to be a good neighbor. “We are committed to collaborating with the Nuiqsut community to address their concerns on having an exploration well drilled close to their village,” she wrote. “We want the community to be comfortable with the drilling program. With that in mind, we have developed a robust mitigation plan to address concerns related to the drilling program.” She said the company could not share the cost of the mitigation measures or the overall Putu 2 effort. Chinn said Kuukpik — deep in the oil business — is not trying to play both sides of the game, but rather is trying to represent the interests of its shareholders who live amongst the North Slope development. The company has objected to other projects as originally planned by ConocoPhillips and currently opposes the Nanushuk project in permitting north of the village because, he said, it’s pad and road designs do not adequately consider caribou migration routes and fill unnecessary amounts of wetlands. “Here, where subsistence is such a big issue; it’s a really big deal, you have to accommodate everything: where people fish in a stream or river or so forth, where people hunt caribou. This is what people live on, ok. Alaska is very unique in that way,” Chinn stressed. He added that fish — mostly from the Colville River that braids through much of the oil development north of Nuiqsut — account for up to 30 percent of a Nuiqsut resident’s diet. “I’m not a flaming environmentalist, but I do care about the environment. I do care about the subsistence. I do care about the people that are involved in this and what kind of legacy does this leave for them.” Elwood Brehmer can be reached at [email protected]

King Cove road deal checks another item on Alaska to-do list

Alaska’s congressional delegation celebrated another victory enabled by the Trump administration Jan. 22 when the Republicans revealed the details of a land swap allowing construction of a road out of the remote village of King Cove near the tip of the Alaska Peninsula. The land exchange between the Interior Department and King Cove Corp., the area Native village corporation, will provide a 12-mile right-of-way through a portion of the Izembek National Wildlife Refuge. The delegation, Gov. Bill Walker and King Cove residents say the road would provide an essential link for emergency services when bad weather prevents flights out of King Cove or boat travel across Cold Bay. With a paved runway longer than 10,000 feet, Cold Bay’s airport has one of the longest civilian runways in the state and is the area’s main link to Anchorage 600 miles away. The old military post was built during World War II. King Cove’s airport has a 3,500-foot gravel runway for the community with roughly 950 year-round residents. Over the years 18 people have died in plane crashes or waiting to get medevac service out of King Cove, according to the Interior Department. However, no one has died trying to leave since 1994. The U.S. Coast Guard has frequently served as a medevac service out of King Cove in bad weather — at more than $210,000 per trip when a helicopter is deployed from Kodiak, according to Sen. Lisa Murkowski’s office. Interior Secretary Ryan Zinke said the equal-value land exchange fulfills two of the primary duties of the federal government: keeping Americans safe and respecting treaty agreements with Native people. “Previous administrations prioritized birds over human lives, and that’s just wrong,” Zinke said in a statement. “The people of King Cove have been stewarding the land and wildlife for thousands of years and I am confident that working together we will be able to continue responsible stewardship while also saving precious lives.” Walker called the agreement “a paradigm shift” in a statement from his office, contending the feds had been irresponsible “by placing a higher value on appeasing people who will never get within a thousand miles of King Cove, over the health and safety of those who actually live there.” In late 2013, then-Interior Secretary Sally Jewell rejected land swap deal passed by Congress in 2009 after a U.S. Fish and Wildlife Service environmental review determined the road would irreparably damage critical waterfowl habitat in the 315,000-acre Izembek Refuge. That swap would have traded 206 acres of Izembek land and 1,600 federal acres outside the refuge for about 56,000 acres of state and King Cove Corp. land. The new eight-page agreement calls for an equal-value land swap between King Cove Corp. and Interior. Further work must be done to identify exactly what lands will be exchanged, but neither side is to give up more than 500 acres, according to the deal. Rep. Don Young called assertions by environmental groups and the others, including some Republicans, that the road would unacceptably damage the habitat of the unique waterfowl populations that use the refuge “pure poppycock or goose you-know-what,” in a delegation press call Monday with Alaska reporters. He added that he thought the Native corporation conceded too much in the previous proposal. In summer, the refuge is home to 98 percent of the world’s population of Pacific black brant, a goose that breeds there, according to the Interior Department, as well as other sensitive wildlife and waterfowl. Walker also thanked the Legislature for approving $7.5 million in last year’s capital budget to jump-start construction of the road if it were ever approved, despite the state’s ongoing budget problems. Last summer the state Department of Transportation assisted in survey work to help establish the specific road route. DOT has estimated construction to cost $30 million and the state is expected to largely fund the work. It is expected to take about a year and start in two or three years after design and other pre-construction work is completed. In February 2017 the Alaska Legislature unanimously approved a resolution in support of a land transfer for building the single-lane gravel road between King Cove and Cold Bay. Murkowski said she called Trump to thank him for his administration’s work, but was unsure if she’d get through. The president took her call informing him of the deal and spent roughly five minutes talking about King Cove. “There’s not too many 950 population communities that are off the road system that the president has taken an interest in and he was quite pleased to learn that an agreement had been inked today,” Murkowski said. Sen. Dan Sullivan said the delegation made Zinke “an honorary Alaskan today” after the agreement was signed. He also noted that President Donald Trump took a personal interest in the issue after a briefing on their priorities from the senators shortly after he took office and would periodically ask them about the status of the road. “This is an Alaska issue in many, many ways,” Murkowski added. “This is more than just a 10-mile, one-lane, gravel, non-commercial use road. This is about how we provide a level of fairness and equity to those who are seeking a simple resolution to a way that they can gain safety at times when the elements do not allow for folks to travel safely by air or by boat.” Leaders of the Alaska office of the Audubon Society said in a formal response that it’s hard to overstate the importance of the Izembek Refuge to migrating waterfowl and transferring public land to private hands epitomizes the Trump administration’s damaging resource management policies. “The Izembek NWR is not your typical piece of Alaska. At times it supports the majority of the world’s populations of Emperor geese, Pacific black brant and the federally listed population of Steller’s eiders,” Audubon Alaska Executive Director Nils Warnock said. “There’s a reason the Interior Department decided against authorizing this road back in 2013. Izembek is too critical to wildlife to risk by having a road blasted through it.” Audubon Alaska also alleged an “underlying commercial motivation” for the project in its statement. And while the delegation has long stressed the road would be limited to emergency-use only, the land exchange signed Monday states the road will be used “primarily” for health and safety purposes “and generally for noncommercial purposes. The commercial transport of fish and seafood products, except by an individual or a small business, on any portion of the road shall be prohibited.” Opponents have consistently argued building a road through wilderness-designated land would set a bad precedent nationwide. Additionally, Peter Pan Seafoods, which has a processing plant in King Cove, could end up using the road to further its business interests — an egregious reason to develop the area, they contend. Murkowski said Peter Pan would be prohibited from the road but the deal does not restrict resident travel, which would be unreasonable. “It’s recognized that if you’re a local fisherman and you’ve got some fish in the back of your truck we’re not going to prohibit you from accessing the road,” she described. The Interior Department cites Section 1302 of the 1980 Alaska National Interest Lands Conservation Act for its authority to make the deal, but opposition groups are expected to challenge that authority in court. Murkowski said she always prefers to take action via legislation — which would all but nullify avenues to sue — but going about the land swap administratively is a much quicker route. “We want the Outside groups to refrain from litigating this. We are in the right legally,” Sullivan added. The House passed a bill authorizing a land swap for the road in July, but it has not passed the Senate. Elwood Brehmer can be reached at [email protected]

Missile defense gets major boost from latest bill

While the Republican tax overhaul was dominating year-end headlines, a major piece of bipartisan legislation became law that also has significant implications for Alaska. The 2018 National Defense Authorization Act, signed by President Donald Trump in mid-December, allocates $699 billion to Defense agencies in the coming year. Broad support of the annual Defense funding bill is nothing new, but wrapped in this NDAA is nearly every provision of Sen. Dan Sullivan’s Advancing America’s Missile Defense Act. The missile defense provisions in the NDAA will not only improve national security, but should be a boon to Alaska contractors as well, Sullivan said in a late December interview with the Journal. That’s because the NDAA calls for 20 new intercontinental ballistic missile, or ICBM, interceptors at Fort Greely near Delta Junction. Another eight “spare” interceptors, set aside for testing the ground-based interceptor system, will also be deployed, according to Sullivan’s office. His original bill called for installing 14 interceptors and 14 test missiles. The latest round of interceptors is in addition to 14 the Pentagon decided to add in 2013 to the original 26 at Fort Greely. The last of those 14 were installed last November. The interceptors are the country’s primary defense against ICBM threats from North Korea and Iran. Another of Sullivan’s provisions in the NDAA directs studies to identify a Midwest or East Coast missile defense site and evaluate the necessity of up to 104 ground-based interceptors at installations across the country. Overall, the nearly $700 billion in the NDAA is $26.2 billion more than the administration’s request and includes $12.3 billion for the Missile Defense Agency, which is also $4.4 billion above what President Trump asked for and the largest Missile Defense appropriation ever. Sullivan said it reflects the bipartisan support to restore Defense funding after it declined from 2010-2016 because of budget sequestration — a bipartisan mistake, he added. The $200 million needed to construct a new missile field at Fort Greely that was authorized in the NDAA was also one of the only additions to the otherwise status quo continuing budget resolution Congress passed Dec. 22, Sullivan noted. The short-term government funding bill expires Jan. 19. The NDAA also includes another $168.9 million for construction projects at Eielson Air Force Base in Fairbanks in preparation for the two squadrons of F-35 fighters scheduled to arrive at the base starting in 2020. More than 2,700 personnel will accompany the fighters, according to Defense reports, and preparing Eielson for the squadrons is estimated to cost a total of $453 million and generate more than 2,300 construction jobs in the state. Some of that money from prior appropriations is already flowing to Alaska. “In the three years I’ve been on the Armed Services Committee we’ve had over $1 billion of authorized military construction in Alaska — a billion,” Sullivan said. “That’s really good for the national security of the country but those are really, really good jobs for Alaskans.” He added that leaders of the U.S. Army Corps of Engineers have assured him much of the work at the Alaska military installations will go to Alaska contractors. “I also think it’s good for taxpayer spending to make sure this money goes to Alaskan contractors, unions, companies, because they know how to do it better than a contract team from Georgia; they know how to work in 40 below,” Sullivan said further. In addition to the work at Eielson and Fort Greely, the Missile Defense Agency is in the midst of spending another $325 million over six years at Clear Air Force Station just south of Fairbanks. Clear is a radar base near Nenana along the Parks Highway. The money there is going towards installing a new power plant and missile detection radar system. Clear Air Force Station is on the electrical grid; however, the upgraded power plant is a backup facility that will be protected against electromagnetic pulse weapons that could be used to render electrical systems useless, according to former MDA Director Vice Admiral James Syring. The Long Range Discrimination Radar being installed at Clear —expected to be done in the early 2020s — could be part of an integrated, space-based ICBM detection system, which Sullivan likes to refer to as an “unblinking eye,” he said. Another of his missile defense amendments to the NDAA mandates creation of a plan to develop and deploy such a missile detection system. The military construction boom around Fairbanks comes just a few years after the Air Force was considering moving the F-16 Aggressor squadron from Eielson to Joint Base Elmendorf-Richardson in Anchorage. City leaders in Fairbanks said the move would’ve crippled the community’s economy and ostensibly made Eielson obsolete without officially closing the base. The Air Force dropped the plan to move the F-16s off Eielson in late 2013. More recently, the Alaska congressional delegation and Anchorage leaders pushed back against an Army proposal to cut the 4th Infantry, 25th Brigade, also known as the 4-25, from Fort Richardson in Anchorage. Citing the state’s strategic Arctic location, emerging threats in the Pacific theater and the 4-25 status as the only Airborne Brigade in the region, the delegation convinced the Army to delay any force reduction in Alaska. The turnabout in the Pentagon’s plans for Alaska has made Alaska the “cornerstone of missile defense, the hub of combat power for the Asia-Pacific and the Arctic,” Sullivan described. With the F-22s stationed at JBER, the state will soon be in the unique position of having more than 100 modern fighters once the F-35s land at Eielson. “No place in the world has 100 combat-coded fifth-generation fighters — those are F-22s or F-35s,” Sullivan said. Elwood Brehmer can be reached at [email protected]

Politicians, stakeholders want conditions for Juneau utility sale

Alaskans with addresses from North Pole to Washington, D.C., are objecting to the proposed sale of the Juneau electric utility by its current Washington state-based owners to a large Ontario utility. The cause for the North American geography mini-lesson is what will happen if the Regulatory Commission of Alaska approves the sale including the 78-megawatt Snettisham hydroelectric facility that provides up to 75 percent of Juneau’s base load power supply. In July, Toronto-based Hydro One Ltd. and Spokane, Wash.-based Avista Corp. announced that Hydro One would buy Avista for $5.3 billion in cash to form one of the largest utilities in North America with a combined asset value estimated at more than $25 billion. Avista bought Alaska Energy and Resources Co., the parent to Juneau’s electric utility Alaska Electric Light and Power, in a deal that closed in 2014 for $170 million. Prior to being under Avista, a Juneau family held majority ownership of AEL&P. The Juneau utility operates and maintains the Snettisham facilities located about 30 miles southeast of Juneau, but the hydro project was built by the U.S. Army Corps of Engineers in the 1960s and subsequently expanded multiple times. Snettisham was sold to the state-owned Alaska Industrial Development and Export Authority in 1998 as part of a broader federal move to divest from local utilities nationwide. The state investment bank financed the purchase with $100 million in revenue bonds, which will be paid off in 2034, according to AIDEA. The sticking point in the sale is what happens when those bonds are paid off and AIDEA owns the hydro facilities and the associated 44-mile transmission line free-and-clear. At that point, the owners of AEL&P have the option of purchasing the energy-producing infrastructure for $1, a condition of the 1998 purchase by AIDEA, according to a letter from Rep. Don Young to the RCA. Young’s Dec. 4 letter to the commission — submitted during the public comment period on the proposed Avista to Hydro One sale of AEL&P — urges the RCA to condition the sale to require the Snettisham facilities remain in state or local ownership. “The Snettisham assets were transferred to the State of Alaska at below construction and replacement value to help insure low electric utility rates in Juneau. I can (assure) you that it was never Congress’ intent that this asset be transferred for the potential profiteering by Canadian government interests,” Young wrote. “At this point, a foreign government entity could ‘hijack’ this public asset initially built to produce low-cost power and pledge, monetize or refinance this asset cashing in the equity at the U.S. taxpayer and Alaskan ratepayer expense without recourse,” he continued. “A Hydro One sale, without divesture of this asset option, could pre-empt Juneau from reaping the benefits of Congress’ intended purpose.” Young concluded by clarifying he does not object to the sale other than to ensure Snettisham remains in public ownership. Hydro One, Canada’s largest electric transmission and distribution utility according to its website, was formed by the Ontario Legislature in 1906. It became a publicly traded company on the Toronto Stock Exchange in late 2015 as the provincial government began divesting the utility. The government of Ontario currently owns 47.4 percent of Hydro One shares, according to the international investment research firm Morningstar Inc. Alaska Independent Power Producers Association Director and Juneau-area resident Duff Mitchell said in an interview that Snettisham power currently costs a little more than 5 cents per kilowatt-hour and once the bonds are paid off that rate could drop to less than 1 cent per kilowatt-hour. If Hydro One is allowed to own Snettisham it could refinance the project, monetize its equity or use it as collateral for other projects and potentially impact future rates in Juneau, Mitchell stressed. He said the $1 purchase option also applies to Avista, but wasn’t generally known when its purchase of AEL&P was pending in late 2013-14. “It’s a very simple fix; it doesn’t hurt Hydro One. Juneau will get its rates reduced and it keeps a foreign government entity from playing games with the asset,” Mitchell said. Alaska state Rep. Tammie Wilson, R-North Pole, reiterated Young’s sentiments in comments to the RCA, contending that, “If Hydro One is successful in obtaining RCA approval with the Snettisham asset rights, this would set a bad precedent that Alaska is for sale and that it is open season to plunder our state. This is a bad message.” Additionally, Alaska Chamber CEO Curtis Thayer, former legislators Cathy Munoz and Lesil McGuire and numerous Juneau residents joined in support of conditioning the sale of AEL&P. Hydro One and Avista wrote in a joint response to the public comments Dec. 11 that they agree with Young that Snettisham “should be preserved for the benefit of Alaskan utility rate payers so that it can continue to provide low cost power for Juneau” and should remain in local ownership. They argue, however, that the concerns are already addressed and conditioning the sale is unnecessary. Utility operations will stay the same when the deal closes, according to the companies. “As it does today, AEL&P will continue to manage the utility and will continue to have certain rights and obligations relating to Snettisham,” they wrote. “Avista has not inserted itself into AEL&P management and neither will Hydro One, because the structure of the merger leaves in place local control.” Former AEL&P director Neil MacKinnon wrote to the RCA that he supports the sale as-is because, among other things, it makes no difference who owns the hydro facilities given the power can only go to the Juneau area and the commission has to approve any rate changes. The expertise a large owner company provides the small utility is extremely valuable as well, according to MacKinnon. (This story has been amended to correctly note that former Alaska Electric Light and Power director Neil MacKinnon supports the Avista-Hydro One transaction without stipulations. The original version of the story incorrectly stated MacKinnon requested the RCA condition the sale.) The RCA rejected the utility companies’ first sale application in Nov. 8 on procedural grounds. They reapplied Nov. 21 and the commission has until May 20 to issue its decision. Wilson, who has championed open access for small, often renewable power producers to utility-owned transmission lines in the Legislature, also urged the RCA stipulate Hydro One provide open access to the Snettisham transmission line that runs from the generation facilities to Juneau. “The RCA, by conditioning Hydro One, can send a public interest message to the utility industry that if multi-state or multi-national corporations want to take over Alaskan utilities and do business in Alaska that they will have to treat Alaskan energy developers with the same nondiscriminatory transmission interconnection rights and privileges that they are required to provide energy developers in other jurisdictions,” Wilson wrote. The Federal Energy Regulatory Commission requires Lower 48 electric transmission owners to provide all power producers equal access to transmission infrastructure. Current Alaska laws and regulations do not, according to Mitchell, which has been a growing source of contention between renewable power startups in the state and the utilities that own or manage large segments of Alaska’s transmission lines. Hydro One sells power to Lower 48 utilities and as a result operates under FERC regulations in many instances despite being a Canadian company. Hydro One spokeswoman Tiziana Baccega Rosa wrote in an emailed response to questions that the benefits of the Snettisham facility will remain in Alaska and that AEL&P is already subject to the RCA’s open-access requirements and will continue to comply with them. However, Wilson and McGuire, of Anchorage who retired from the state Senate in 2016, further noted that Juneau Hydropower Inc. has been trying to gain access to the Snettisham line from AEL&P for several years without success. Juneau Hydropower, also led by Alaska Independent Power Producers Association head Mitchell, has regulatory approval to construct the Sweetheart Lake hydro project south of Juneau but needs to secure transmission capacity before it can start construction. The 20-megawatt hydro project would supply power to the Kensington gold mine north of Juneau, which currently runs on diesel-fired generation. Kensington’s owner company Coeur Mining also urged the RCA to condition the Hydro One sale on an access agreement with Juneau Hydropower, which has been trying to get such an agreement since 2012, according to the filings. The Sweetheart Lake condition was a request of AIPPA as well. Mitchell acknowledged that his company would stand to benefit from such terms, but said the stance is in line with what the association has sought for years in other similar instances across the state. “I believe our state is the breadbasket of renewable energy and we have manmade problems keeping those developments from happening. It’s not a question of financing; it’s not a question of natural, God-given resources. It’s a question of legislative and regulatory problems,” Mitchell said. “I have always been — Juneau Hydropower and AIPPA has always been — consistently for open access and non-discriminaatory access to transmission lines in Alaska.” He also noted that Sweetheart Lake, by getting Kensington off diesel, would cut Juneau-area greenhouse gas emissions by about 8 percent. “I’m doing what America is supposed to do,” Mitchell emphasized. “If you can offer a better product — this transmission issue does affect Juneau Hydropower but it also affects every independent power producer in Alaska.” Elwood Brehmer can be reached at [email protected]

Initiative sponsors turn in signatures as BBNC shifts to neutral

Advocates of strengthening Alaska’s salmon habitat protection took a big step forward when they dumped roughly 49,500 signatures on the front desk of the Division of Elections Anchorage office Jan. 16. The signatures from Alaskans statewide were collected by Stand for Salmon, the nonprofit aimed at reforming anadromous fish habitat permitting requirements via the ballot initiative they’ve dubbed “Yes for Salmon.” Early morning drizzle and icy roads didn’t damper the spirits of about 20 initiative backers that gathered outside the Division of Elections to be ready to submit the signatures for certification as soon as the state offices opened at 8 a.m. Jan. 16, the start of the legislative session, was the last day to hand the petition booklets in and get the initiative on the 2018 ballot. It was also the day that Bristol Bay Native Corp., a major opponent of the Pebble mine, revised its stance on the initiative from against to neutral. While the signature hurdle is a big one, the initiative still faces stiff opposition from industry groups and the State of Alaska. Lt. Gov. Byron Mallott first rejected the initiative on the advice of the Department of Law because the state’s lawyers deemed it would appropriate Alaska’s water resources for salmon habitat — the state Constitution requires resource allocation be left to the Legislature — and therefore be unconstitutional. After Mallott’s ruling was appealed and overturned in Superior Court, the state took its turn to appeal to the Supreme Court in October. Oral Arguments in the case are now set for April 26. “This is a promising moment for all Alaskans. Tens of thousands of Alaskans from Nome to Ketchikan, from every single legislative district, have said that we want the opportunity to reflect a true balance between responsible development and protection of salmon,” said Stephanie Quinn-Davidson, an initiative sponsor and director of the Yukon River Inter-Tribal Fish Commission. Quinn-Davidson replaced Bristol Bay lodge owner Brian Kraft, an original sponsor, after Kraft stepped away from the campaign in November for personal reasons, according to Stand for Salmon representatives. Sponsors are required to gather signatures from registered voters equal to at least 10 percent of number of voters in the previous election from 32 of the 40 House districts in the state. For 2018 initiatives that meant getting 32,127 signatures, according to the Division of Elections. Campaign workers said they set a goal of 45,000 to account for unqualified signatures and were proud to have gathered the required amount in all 40 districts. Specifically, the initiative seeks to overhaul Title 16, the Department of Fish and Game’s statutory directive on how to evaluate development projects in salmon habitat. Current law directs the Fish and Game commissioner to issue a development permit as long as a project provides “proper protection of fish and game.” The sponsors contend that is far too vague and an update is needed to just define what “proper protection” means. The initiative would, among other things, establish two tiers of development permits that could be issued by the Department of Fish and Game. “Minor” habitat permits could be issued quickly and generally for projects deemed to have an insignificant impact on salmon waters. “Major” permits for larger projects such as mines, dams and anything determined to potentially have a significant impact on salmon-bearing waters would require the project sponsor to prove the project would not damage salmon habitat. Mitigation measures would be acceptable as long as they are implemented on the impacted stream or wetland area. Additionally, the project sponsor would have to prove that impacted waters are not salmon habitat during any stage of the fish life cycle if the waters are connected to proven salmon habitat in any way but not yet listed in the state’s Anadromous Waters Catalog. The sponsors insist it is not aimed to stop development projects; rather, it would set high but transparent permitting standards that are necessary to protect salmon resources that are already being stressed by multiple factors, they contend. Even if it wins at the Supreme Court, a laundry list of resource development, unions and trade groups, along with the Alaska Native Claims Settlement Act Regional Association (made up of the 12 Native regional corporations) and the Alaska Chamber have formed an opposition group called Stand for Alaska. That group has already received contributions totaling $147,000 according to an Alaska Public Offices Commission report. Stand for Salmon has collected $271,000 as of Jan. 7 according to APOC with the biggest donor the Alaska Conservation Foundation at $60,000. Opponents contend the initiative would decimate the state’s economy and make even the smallest projects — down to road repairs — extremely difficult if not impossible to permit. SFA co-chair Joey Merrick of the Laborers’ Local 341, who is also a member of the Alaska Gasline Development Corp. board of directors, said in a press release that the initiative poses a risk to his members’ jobs. “Alaska already is in a serious recession with one of the nation’s highest unemployment rates. The last thing we need is more expensive, time consuming, and unnecessary policies that cost Alaskans their livelihoods,” Merrick said. AGDC President Keith Meyer has argued that the initiative would prevent the construction of the Alaska LNG Project, and Gov. Bill Walker has also expressed opposition to the measure. Walker said the initiative is too broad in its scope and it could hamper nearly every area of project development in the state. “I think when you’re making definitions that impact development of projects in Alaska and you do that through the initiative process — I was very concerned about that,” he said in a Dec. 22 interview with the Journal. “I would like there to be a discussion back and forth; hearings in the appropriate hearing rooms in Juneau and various folks being able to weigh in.” BBNC changes stance on initiative The Jan. 16 press release from Stand for Alaska lists Bristol Bay Native Corp. among the dozens of corporations, trade groups and chambers of commerce opposing the initiative, but that list may need to be revised. BBNC is no longer against the initiative, but is not for it, either. CEO Jason Metrokin said in a Jan. 16 statement to the Journal that “BBNC has been and continues to be neutral on the initiative; neither opposing it nor supporting it. The ANCSA Regional Association as a body took its own action in opposing the initiative. BBNC and other ANCSA regional corporations are discussing ways to improve Title 16; changes that would improve salmon habitat protection but not preclude responsible development projects.” Metrokin, in an October statement to the Journal, reemphasized the corporation’s longstanding opposition to the Pebble mine project, but also said that BBNC “did not support (House Bill) 199 last legislative session and cannot support the Stand for Salmon ballot initiative. Each would unnecessarily and negatively impact resource development projects and potentially the subsistence activities upon which our shareholders rely depend.” Metrokin continued to note in October that the Native corporation wants to work with the Walker administration and the Legislature to “appropriately update Title 16’s anadromous fish habitat provisions.” The ANCSA Regional Association, with a board comprised of the 12 regional corporation leaders and Alaska Federation of Natives head Julie Kitka, voted unanimously to oppose the initiative in July, according to an October op-ed penned by CIRI CEO Sophie Minich and Arctic Slope Regional Corp. CEO Rex Rock. Other media outlets subsequently reported in November that BBNC opposed the proposed ballot measure as well. BBNC issued a press release Jan. 5 urging the Legislature to revise Title 16 and stressing the company’s positions on salmon habitat and other resource issues are grounded in a belief that decisions about how to balance uses of competing resources should always start with putting “fish first.” “The protections in Title 16 help ensure that development projects do not threaten Alaska’s anadromous fisheries. It is imperative that Alaska periodically review and update those statutes. This has not been done in nearly 60 years. It is time for the Legislature to do so,” the Jan. 5 release concludes. Shortly thereafter, BBNC board of directors member H. Robin Samuelsen Jr. told the Journal there was a “misunderstanding” between Metrokin and board members regarding the corporation’s stance on the initiative, but referred further questions to BBNC executives. Those questions led to the Jan. 16 statement. Democrat House Speaker Bryce Edgmon of Dillingham has said the House Majority will hold hearings on House Bill 199 this session to gather information on how Title 16 can be improved with input from those that oppose the initiative and the current version of HB 199. The bill language largely mirrors that found in the initiative and Edgmon has said he does not expect it to pass this session because of the consternation the initiative has caused. Elwood Brehmer can be reached at [email protected]

DNR issues default to Furie for failure to drill

Department of Natural Resources officials issued a notice of default to Furie Operating Alaska Dec. 26 for failing to make good on its drilling commitments in the Kitchen Lights Unit the company operates. In a letter to the company’s Alaska leaders, DNR Commissioner Andy Mack recalled the drilling plans the company submitted to the agency since 2015 that went unmet. “Operation of the KLU previously and up through the present reflects a history of committing to drilling activities, but then delaying or changing those work commitments,” Mack wrote. The Kitchen Lights Unit is a large natural gas producing unit in the central part of Cook Inlet north of Nikiski and east of Trading Bay. Mack continued to note that Furie said it would drill two development wells in its 2015 plan of exploration, but in August that year proposed deferring that work until 2016. The change was approved by the Division of Oil and Gas. The company’s 2017 development plan called for completing the KLU-A1 well and drilling another to be completed later. That work was not done and instead was deferred to 2018 in Furie’s latest development plan, which Division of Oil and Gas Director Chantal Walsh approved Dec. 28. Furie leaders had intended to do a workover of the KLU-3 well, finish drilling its A-1 well and then drill another gas well and a deep oil test well, according to Webb in an interview with the Journal this past November. “Although the Randolph Yost jack-up rig was 100 percent staffed to commence drilling operations in April of this year, Furie was forced to delay its 2017 drilling plans — including purchasing tangible items with substantial lead times — until additional funding for the purchase of tax credits was approved by the Legislature and the governor,” Furie’s 2018 Kitchen Lights development plan states. The document was sent to the Division of Oil and Gas Oct. 6. Mack cited the Kitchen Lights Unit Agreement in his default notice, which states that the DNR commissioner can, at his or her discretion, determine that the company’s failure to meet its commitments constitutes a unit default. To cure the default Furie must follow through with its 2018 development plan. Failing to resolve the default could lead to DNR seeking to contract or terminate the Kitchen Lights Unit, according to the default notice. Furie officials contended in their 2018 plan that the drilling work was not done last year because the State of Alaska has not fulfilled its obligation to repay the “very substantial amount” of refundable production tax credit certificates it owes the company for previous work. “These certificates are a key component to funding further exploration and development activities in the KLU and were relied upon by Furie when putting together its work program and budget,” the 2018 Kitchen Lights plan states. Oil and gas companies and industry backers have roundly criticized Gov. Bill Walker for vetoing $630 million worth of appropriations in 2015 and 2016 to pay the industry tax credits. Walker has been steadfast in his assertion that the state could not afford to make the large credit payments while dealing with annual budget deficits upwards of $3 billion at the time. His fiscal year 2019 budget plan released in December includes a proposal for the state to bond for $900 million to pay off the state’s full credit obligation. Exactly how much Furie is owed is unknown. Senior Vice President Bruce Webb said he couldn’t comment on the matter and state officials cannot reveal the tax credit amounts because it is confidential tax information. While Furie didn’t drill last year, the 2018 plan further asserts that it “conducted substantial well and pipeline work in 2017,” noting the company removed plugs from the KLU-3 well readying it for production. It also flow tested KLU-3 and another well in August and achieved combined gas production 31 million cubic feet per day during the test. Also, Mack did not mention the two wells Furie did drill in 2016 in his Kitchen Lights default notice. Alaska Oil and Gas Conservation Commission records indicate the company applied for permits to drill the KLU-A1 and KLU-A2 wells in June 2016 and completed the KLU-A2 and KLU-A2A in July and September of that year. According to previous interviews with Furie leaders, those natural gas wells were allocated to feed the contract it has with regional utility Enstar Natural Gas, which commences this April. Furie also has an existing supply contract with Homer Electric Association, which uses natural gas to fuel its power plants, and last spring signed a 10-year contract to supply Chugach Electric Association starting in 2023. DNR officials asked to reschedule a Jan. 9 interview with the Journal to discuss the default decision and how it could impact Furie’s supply contracts if it is not resolved. In 2015 the company installed the Julius R platform in the Kitchen Lights Unit, from which it now produces the gas for its contracts. Furie is also looking to produce oil, which much of its currently planned work is aimed at. Company officials have said they could foresee eventually installing an oil-focused platform in the unit if exploration proves successful. Furie has 20 days from the issuance of the default to request Mack reconsider his decision. Elwood Brehmer can be reached at [email protected]

Permit application reveals size of scaled-down Pebble project

The official Pebble mine plan released Jan. 5 by federal regulators describes a scaled-back project relative to prior concepts, but opponents contend it is a way for the company to get its foot in the door for future expansion. Published by the Alaska District of the U.S. Army Corps of Engineers, the plan details a project that is much more than a mine. According to Pebble’s plan documents, its reach would stretch 187 miles from the mine site north of Iliamna Lake to the edge of the Sterling Highway on the southern Kenai Peninsula. In between would be a natural gas pipeline up to 12 inches wide traversing the Cook Inlet sea floor for 95 miles from the Anchor Point area to a deepwater port at Amakdedori west of Augustine Island. From there, a two-lane, private road would run 35 miles northwest to a ferry terminal on the south shore of Iliamna Lake. An ice-breaking ferry would then shuttle materials 18 miles across roughly the midpoint of the massive Iliamna Lake, which is the largest in Alaska. Another 30 miles of industrial road would connect the north ferry terminal near the village of Newhalen with the mine site. The gas pipeline would follow the rest of the transportation corridor to the mine. In early October, Pebble CEO Tom Collier unveiled a rough outline to the company’s plans. Collier said then the mine the company intends to construct is smaller than what has long been speculated and incorporates stakeholder concerns both in the footprint of the mine and broader project designs. The ferry, for instance, would be employed to reduce road construction and associated impacts to wetlands, according to Collier. He reiterated as much in a Jan. 5 statement issued by Pebble. “We believe that as Alaskans become more familiar with our proposed project design and the environmental safeguards it incorporates, there will (be) an increasing degree of support for the project, and the significant economic potential it represents for the State of Alaska,” Collier said. Pebble estimates the project will generate about 2,000 jobs during its four-year construction and about 850 full-time positions over its 20-year life. The now-public Pebble project plans were submitted to the Corps Dec. 22 in Pebble’s wetlands discharge permit application, required under Section 404 of the Clean Water Act. The Army Corps of Engineers first reviews wetlands permit applications and if deemed complete issues a public notice announcing the proposal within 15 days of the application and makes it available to the public. The Corps also issues a determination on what level of environmental review an application necessitates and, unsurprisingly in this case, deemed Pebble worthy of a full environmental impact statement. Corps Alaska regulatory officials have said the average EIS for a large project takes four to five years, while Collier has said he hopes the project can be approved in three. The next step is for the Corps to select a third-party contractor to develop the EIS. Ron Thiessen, CEO of Pebble’s parent company Northern Dynasty Minerals Ltd. said Pebble expects to sign a memorandum of agreement with the Corps “in the very near term” and subsequently issue a request for proposals from which the Corps will select the EIS drafter. At the end of the road but the center of controversy, the mine site would include a suite of facilities over several square miles. The heart of the operation would be the mine pit: 6,500 feet long; 5,500 feet wide and up to 1,750 feet deep. A large bulk tailings storage facility capable of holding 950 million tons of waste rock would collect most of the milled ore. A smaller, lined tailings storage cell designed to hold 135 million tons of potentially acid generating mine waste would be segregated from the bulk tailings but be behind the same series of tailings dams. The storage facilities are designed to handle mine waste generated over 20 years of operations, according to Pebble’s documents. The primary tailings embankment would be 600 feet tall and three others would be between 60 and 420 feet tall. Each would have a 2.6-to-1 slope, according to Pebble. The natural gas pipeline would terminate at and feed a 230-megawatt power plant, which would provide electricity to the mine and drastically reduce the need for diesel fuel storage, the application notes. For comparison, the power plant would be large enough to supply Golden Valley Electric Association, the electric utility for Fairbanks and surrounding areas, with enough electricity to meet its historical peak demand of 223 megawatts. The onsite facilities would all be in the Koktuli River watershed and avoid Upper Talarik Creek. Avoiding the Talarik drainage, which feeds Iliamna Lake and the Kvichak River, would seemingly avoid any potential damage to the Kvichak’s immense sockeye salmon runs, a point Collier has emphasized as proof of the company’s efforts to minimize its impacts to salmon habitat. Pebble will not use leaching processes that require cyanide to extract gold, which will lower recovery by 15 percent, according to Collier. However, mine opponents have noted the north and south branches of the Koktuli River are primary spawning habitat for the large run of chinook salmon that return to the Nushugak River system. Overall, the mine site would fill 3,190 acres of wetlands and water bodies, according to Pebble. The Environmental Protection Agency determined in 2014 — based on the conclusions of its Bristol Bay Watershed Assessment — that any project resulting in the loss of more than 1,100 acres of wetlands and water bodies in the area would be an unacceptable impact. How Pebble will, or can, sufficiently mitigate the wetlands losses is unclear. The environmental offsets will be established as the lengthy permitting process plays out, according to the application. Active mining from the pit would occur for 14 years and the final six years of operation would focus on mineral recovery from a stockpile of low-grade ore. As planned, the Pebble mine would produce 600,000 tons of copper-gold concentrate and 15,000 tons of molybdenum per year from 58 million tons of processed ore. Statements from several groups fighting the proposed mine said the tempered plan changes little. “The plan released (Jan. 5) includes only a fraction of the ore within the Pebble deposit, indicating that the impacts could be vastly greater than what’s indicated on the application we see today,” Trout Unlimited Alaska Director Nelli Williams said. “It is clear that Pebble is continuing to deceive and mislead Alaskans and Americans, and their ‘new’ plan is nothing more than the same old threat wrapped in a package they hope is more digestible. Don’t be fooled by this incomplete proposal.” While Pebble’s application is for a 20-year mine with a single pit to reduce its impact, opponents note investor pitches and statements from leaders of Northern Dynasty Minerals highlighting the immense size of the Pebble deposit. A November Northern Dynasty investor presentation stresses Pebble as “the world’s largest undeveloped copper and gold resource.” In its Section 404 application, Pebble notes the total deposit is estimated to hold 80.6 billion pounds of copper, 5.5 billion pounds of molybdenum and 107 million ounces of gold. However, the single pit would allow for recovery of just 6.7 billion pounds of cooper, 353 million pounds of molybdenum and 10.7 million ounces of gold. Collier has acknowledged the company might look to expand after initial production commences but contends growing the project would require additional rounds of environmental reviews and permitting that would be independent from any approvals Pebble already had. He said in a December interview that the company does not have a definitive cost estimate on its massive undertaking, but he did say Pebble is confident in the project’s economics at current metal prices. Elwood Brehmer can be reached at [email protected]

Regulators hopeful well test can jumpstart Mustang oil project

Positive results from a well test have helped give a small independent oil company another shot at finally developing its North Slope prospect. Anchorage-based Brooks Range Petroleum Corp. announced Jan. 8 that a late November flow test of the North Tarn 1-A at its Mustang oil project produced peak flows averaging 1,292 barrels per day with only small amounts of water. The test confirms the company’s prior assumptions and Brooks Range expects the results will lead to accelerated development of the Mustang project, according to a press release. “This recent success is very encouraging and highlights the dedicated and persistent support invested by the working interest owners, state agencies and the contracting community. These results confirm we are on the right track with our development plans,” Brooks Range CEO Bart Armfield said in the release. The Mustang project is in the small Southern Miluveach Unit on the southwest edge of the large Kuparuk River Unit. It’s estimated to hold 33 million barrels of proven and probable light oil reserves, according Brooks Range. Peak production estimates for the field have been in the range of 15,000 barrels per day. The Southern Miluveach Unit was set to expire at the end of 2017 because Brooks Range had repeatedly failed to make good on its development plans. Company leaders first said in late 2012 that they hoped to have Mustang in production by the fall of 2014. Between December 2012 and April 2014 the Alaska Industrial Development and Export Authority, the state-owned investment bank, invested a total of $70 million in a five-mile gravel road, a 19-acre production pad and a $225 million oil processing facility, which would be the first such open-access facility on the North Slope. Full development of the field has been estimated at $580 million, a price that included drilling 11 production and 20 more gas and water injection wells. In its Jan. 8 release Brooks Range said the next phase of work is installing the oil processing facility and drilling up to 18 production and injection wells. Brooks Range ultimately missed the 2014 production target, meaning the company would also have to deal with a new, lower oil price regime that is just now starting to turn around. Subsequent plans submitted to the state Division of Oil and Gas to develop Mustang have gone unmet with Brooks Range claiming it would install the necessary facilities and then, after not doing so, contending “unfavorable economic circumstances” forced the company to delay the work it had promised multiple times up to last November. With little construction work having occurred at Mustang in 2016 and 2017, according to Brooks Range’s submissions to the Division of Oil and Gas, the company again said it would move facility modules constructed in Canada and Alaska to the Slope this year and achieve production by early 2019 in its 2018 plan of development sent to state officials in late October. As a result, Division of Oil and Gas officials have met the company’s recent work plans with skepticism but have continued to approve them. Deputy Oil and Gas Director Jim Beckham approved the 2018 Southern Miluveach development plan Dec. 20. That approval extended the term of the unit for another year, but also brought with it a requirement for quarterly progress reports detailing the company’s work. The one thing of significance Brooks Range did accomplish in 2017 — which was a late amendment to it original 2017 plan — was the North Tarn-1A well test. Beckham said in an interview prior to the well results being released that division officials anticipated the test would be a success and the hope is it is one Brooks Range can build on. He noted, “the whole industry got turned on its head with the plummeting oil prices” in 2014 and said the decision to extend the unit term and give the company another shot because the state should do what it can to support struggling operators. “I have to protect the state’s interest and all that means, but, that said, my philosophy here is to get to ‘yes,’ right? If we don’t get to ‘yes’ we don’t have producers and explorers out there and if we don’t have that what do we have? We don’t have an economy. So, within reason and within statutory and regulatory bounds our job is to get to ‘yes,’” Beckham said. “I think it’s far better for the state to work closely with the companies and try to find a mutually beneficial path forward.” AIDEA’s investments in Mustang and other state investments in oil and gas projects do not factor into the Division of Oil and Gas’ regulatory decisions, according to Beckham. “We’re just concerned about the nuts and bolts of getting them into production,” he added. Brooks Range CEO Armfield said in a brief interview that company leaders are working intensely on plans now to meet the early 2019 goal for first oil and he would be able to detail how this year will be different than the prior few in the coming weeks. He also noted the state owes the company $44 million in unpaid tax credits. Some of the tax credits the company has earned for the work it has done at Mustang went to pay back a portion of AIDEA as a part of the structure to that agreement. In early 2016 Brooks Range attempted to transfer its leases in the nearby Tofkat Unit to ConocoPhillips shortly before the unit was set to expire. That led to a lengthy back-and-forth between Brooks Range, state officials and ConocoPhillips that ultimately concluded last August with Conoco agreeing to drill an exploration well on the Tofkat acreage this winter or relinquish the leases back to the state. In the case of Tofkat, Brooks Range allegedly was unable to explore and develop the leases because it couldn’t secure an access agreement with Kuukpik Corp., the Alaska Native village corporation that jointly holds surface rights to the state leases. Elwood Brehmer can be reached at [email protected]

Draft lease plan would open most of Alaska OCS

The Interior Department’s latest offshore oil and gas leasing proposal released Thursday juxtaposes the plan put in place late in the Obama administration in almost every way. For starters, it would put nearly all federal waters off Alaska up for sale. Published by the Bureau of Ocean Energy Management, the draft 2019-2024 National Outer Continental Shelf Oil and Gas Leasing Program calls for 19 lease sales covering 11 of the 12 designated sale areas off the coast of Alaska. The only area not included in the plan is the North Aleutian Basin, which is Bristol Bay and the surrounding waters. It was withdrawn from potential leasing by President Barack Obama in 2014. The current 2017-2022 OCS lease plan calls for a single Alaska sale for the federal waters of southern Cook Inlet in 2021. Similarly, the draft plan would make 90 percent of the total OCS acreage nationwide available for leasing. The current schedule puts 94 percent of leasable OCS areas off limits, according to the Interior Department. Interior Secretary Ryan Zinke said providing opportunities to for companies to develop offshore resources would not only help achieve the Trump administration’s goal of national energy security, but also provide “billions of dollars to fund the conservation of our coastlines, public lands and parks.” The Land and Water Conservation Fund, which provides money to states, local governments and federal agencies for environmental restoration and conservation programs, is funded primarily with OCS lease revenue. “Today’s announcement lays out the options that are on the table and starts a lengthy and robust public comment period,” Zinke said further. “Just like mining, not all areas are appropriate for offshore drilling, and we will take that into consideration in the coming weeks. The important thing is we strike the right balance to protect our coasts and people while still empower America to achieve American energy dominance.” Sen. Lisa Murkowski, who chairs the Senate Energy and Natural Resources Committee, echoed Zinke’s sentiment in a statement from her office. “This draft program is another positive step as we week to reinforce our nation’s status as a global energy leader,” she said. “Secretary Zinke’s ‘blank slate’ approach launches a new discussion with local stakeholders to determine where responsible energy development should take place. While nothing in this proposal is final, it is good to see the administration seeking to expand access in places like Alaska, rather than limiting our opportunities.” Murkowski and Sen. Dan Sullivan were among 36 Republican senators who in July signed a joint letter to Zinke requesting his department put together a new OCS plan. Likewise, Gov. Bill Walker said the draft proposal is “an important step toward allowing Alaskans to responsibly develop our natural resources as we see fit.” The Alaska leasing schedule proposes three sales each in the Chukchi and Beaufort seas off the North Slope in alternating years over the 2019-2024 period. It would also add a second Cook Inlet sale in 2023 in addition to the 2021 sale in the current schedule and one sale each in 2023 covering the 11 other areas that include the federal waters of Southeast, Kodiak, the Aleutians and the Bering Sea. When in draft form the current 2017-2022 OCS lease schedule included one sale each in the Beaufort and Chukchi seas, but they were culled from the final plan. The Wilderness Society’s Arctic Program Director Lois Epstein, based in Anchorage, said in a formal response that the challenges posed by offshore drilling in the Arctic would put sensitive coastal habitat and the subsistence resources coastal Alaska residents rely at unnecessary risk. “Re-doing the five-year program reflects this administration’s eagerness to sell out our public lands and water and pursue fossil fuel energy development everywhere. This is part of a wholesale assault on Alaska’s Arctic, with congress opening the Arctic National Wildlife Refuge’s coastal plain to oil drilling and the Trump administration seeking to revise the scientifically sound National Petroleum Reserve-Alaska management plan so it allows drilling even in currently protected, sensitive habitat,” Epstein said. BOEM will begin holding public meetings on the draft plan, which still requires an environmental impact statement review, Jan. 16 in Maryland. The Alaska meeting is scheduled for Jan. 23 at the Dena’ina Convention Center in Anchorage. While the debate over whether or not to allow drilling is a one for politicians, whether or not industry will want to actually sink a bit anywhere is unknown. Shell’s foray into Chukchi Sea exploration ended in 2015 after the company — which needed federal court orders to remove protesters that tried to block its ships — spent $7 billion over several years to drill one well that ultimately turned out to be a dry hole. BOEM’s mean estimate for undiscovered but recoverable oil and gas in the areas of the Beaufort Sea up to roughly 50 miles offshore is for 8.9 billion barrels of oil and nearly 28 trillion cubic feet of natural gas. That estimate, updated in late December, added roughly 700 million barrels of oil to the 2016 assessment based on the presumption that the onshore Nanushuk and Torok geologic formation oil plays — the sources of recent large onshore discoveries — extend into federal waters. The Beaufort Sea gas estimate did not change significantly. BOEM estimates the Chukchi Sea off the western North Slope holds 15.3 billion barrels of undiscovered oil and 76.7 trillion feet of yet-to-be-found natural gas. The agency also estimates the other vast unexplored areas that could be opened to leasing hold just about 1 billion barrels of oil. Elwood Brehmer can be reached at [email protected]


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