Elwood Brehmer

Change of course for Pebble reignites access issues

The U.S. Army Corps of Engineers has changed the course of the Pebble project but what it means for the fate of the highly contentious development remains to be seen as area landowners vow to prohibit access. David Hobbie, Army Corps of Engineers Alaska District regulatory chief, confirmed during a May 22 conference call with reporters that the lead permitting agency had changed the project’s transportation corridor from a southerly route across Iliamna Lake to one along the lake’s northern shore that also ends at a new site for a west Cook Inlet port. The total re-route is part of the least environmentally damaging practicable alternative, or LEDPA, identified by Army Corps Alaska officials, and combines aspects of other development alternatives evaluated in the draft environmental impact statement released in February 2019, according to Hobbie. Other details of the LEDPA will be discussed in the Corps’ record of decision that will follow the final EIS, which is currently scheduled to be published later this summer. Numerous groups opposing the project allege the north road route is a late-stage move to appeal to the Pebble Partnership’s ultimate desire to build a much larger 78-year mine instead of the 20-year mine plan the company is advancing because the Iliamna Lake ferry that is part of the south alternative could not support the larger operation. That’s in part because an April 24 memo from representatives of AECOM — the global engineering firm hired to write the EIS — indicates Pebble changed its preferred alternative from the southern ferry route to the northern road-only transportation corridor from the mine site to the port. However, Hobbie said Pebble changed its plans to conform to what the Corps had already determined: that the north road-only corridor was ultimately the best option for the environment. The Corps’ decision was based on widespread public concerns that the year-round ferry across the massive lake could disrupt winter travel across lake ice for residents of lake villages and impact Iliamna’s unique population of freshwater seals, among other issues, according to Hobbie. “We did exactly what the public asked us to,” he said of the Corps amending the plan for the project. Pebble leaders routinely stress that the company has applied for permits for its 20-year mine plan and any subsequent plans expand the project would require a whole new round of permitting while Pebble’s parent company, Vancouver-based Northern Dynasty Minerals Ltd., has advertised the project as a multi-generational opportunity and cites the metal resources in the total Pebble deposit — not just those that would be extracted via the 20-year mine — in its investor pitches. Pebble CEO Tom Collier noted in a prepared statement that the north route was Pebble’s preferred option for most of the project’s history and said the company initially selected the ferry route because it was thought regulators would prefer the smaller wetlands footprint it offers. “The choice between the two transportation alternatives for Pebble has always been a close call,” Collier said. “Now that the (Army Corps of Engineers), working closely with the Environmental Protection Agency, the U.S. Fish and Wildlife Service and other cooperating agencies, has indicated that the northern corridor is the preferred approach we look forward to seeing the final EIS for the project.” He added that the company also supports using a pipeline instead of trucks to haul concentrate from the mine site to tidewater. According to Northern Dynasty, the pipeline would cut truck traffic on the mine access road by roughly half. However, the Corps’ change of plans does not account for one potentially significant complicating factor for Pebble; the landowners along the north route, at least for now, want nothing to do with the project. Alaska Native village corporation Pedro Bay Corp. owns much of the land along Iliamna’s northeastern corner and Iliaska Environmental LLC is a majority owner of a rock quarry at Diamond Point, the new location for the Cook Inlet port needed to supply materials to the mine and export its metals. Iliaska Environmental is owned by the Igiugig Village Council and along with Pedro Bay Corp. and Bristol Bay Native Corp., which controls subsurface rights to the village corporation lands, strongly opposes the project. The Igiugig Village Council issued a statement May 25 contending the Diamond Point quarry is a “critical component” of the north route that Pebble will not have access to. “(Pebble’s) plan for Diamond point presented in the EIS does not fit with our plans for Diamond Point, and should not be considered an acceptable alternative,” the statement reads. In contrast, the south ferry route allowed Pebble to utilize lands owned by Alaska Peninsula Corp., which the junior mining company has an access agreement with, for the roads and ferry terminals on the north and south sides of the lake to access a port at Amakdedori on Cook Inlet. Pebble spokesman Mike Heatwole wrote via email that the company intends to work with each of the landowners along the north route and believes “we will be able to gain the right-of-way needed to build the transportation corridor.” Pedro Bay Corp. CEO Matt McDaniel wrote to Corps of Engineers Pebble project manager Shane McCoy last July to reiterate that the company “has not, and will not, consent to the Pebble Limited Partnership’s use of its lands for the Pebble project.” As such, the north route should not be considered practicable in the final EIS, McDaniel wrote. McDaniel’s letter quickly spurred a memo from the Corps to Pebble requesting an analysis of feasible northern corridor options around Pedro Bay Corp. lands, but a consultant to Pebble determined there isn’t one. While Pedro Bay Corp. owns most of the land along the northeast portion of Iliamna Lake; there is a mountainous strip of state lands to the north that is bordered by Lake Clark National Park and Preserve. The brief alternative route report concluded that a route around Pedro Bay lands would require up to 15 miles of tunneling or “extreme mountain road construction” and would be much longer than the proposed route across Pedro Bay lands. “Given the adverse nature of the terrain that exists north of PBC land, and the constraints imposed by design criteria for a road to serve the proposed Pebble mine; it has been determined that construction and operation of a road that would pass north (of) PBC lands is not practical or reasonable,” the July 2019 consultant report states. Several other Cook Inlet-area Native corporations including CIRI also own parcels around Diamond Point. BBNC leaders have also criticized Corps officials for advancing the north route as viable despite the landowners’ consistent opposition to the project. BBNC Lands and Natural Resources Vice President Dan Cheyette wrote in a May 21 letter to Corps of Engineers Alaska officials that the LEDPA must be the least environmentally damaging development alternative but must also be practicable, and a route across lands owned by entities that don’t support Pebble is not. “In defining the LEDPA for the Pebble project, BBNC demands that the Corps remove from consideration all alternatives that would require use of its subsurface or surface estate, as our lands are unavailable to (Pebble),” Cheyette wrote. “This includes the eastern terminus of the northern transportation corridor at Diamond Point,” which is also partly owned by a BBNC subsidiary. Cheyette and other opponents to Pebble argue that Corps officials should draft another EIS that would focus the public’s attention on the updated plan for the project. The Corps’ Hobbie said there are no plans for a new or supplemental Pebble EIS because the LEDPA doesn’t contain anything that wasn’t in the first draft. “There’s nothing in the current LEDPA that has not been evaluated in the EIS,” Hobbie said. Elwood Brehmer can be reached at [email protected]

Alaska businesses receive $1.2B in PPP loan with funds still available

There is still nearly $150 billion left in the federal government’s primary program to help small businesses through the worst of the COVID-19 pandemic. The Small Business Administration handled 4.4 million loan approvals totaling $511 billion nationwide through May 23 from the $660 billion Paycheck Protection Program, according to a summary report provided by the agency. Intense demand caused the initial $350 billion approved by Congress to jumpstart the program in the CARES Act to be exhausted in mid-April after being available for just two weeks as small businesses across the country applied for the financial relief. Congress subsequently approved another $310 billion in PPP loan funds April 24. Michael Huston, chief lending officer for Northrim Bank said the Anchorage-based lender has processed more than 2,400 PPP loan applications and continues to but demand has waned. “There is money available. Those applications have slowed significantly since the first few weeks of the program but we do stand ready to help businesses that need the assistance,” Huston said in an interview. Across Alaska, the SBA tallied 10,040 PPP loan approvals totaling just more than $1.2 billion before Memorial Day weekend, according to the report. The program is meant to provide small employers — primarily those with less than 500 workers, with some exceptions — payroll funding for up to eight weeks following the receipt of the loan. Sen. Dan Sullivan has stressed the desire in Congress to maintain the employer-employee relationship as much as possible through the worst of the pandemic-induced economic restrictions in multiple interviews and briefings following the passage of the CARES ACT and the PPP loans are meant to be a vehicle for that. Huston said there are very few “fine print” restrictions as to what small businesses — and 501(c)3 nonprofits and Tribal organizations as well — qualify for a loan. “For the most part it’s one-size-fits-all as long as you are an eligible business,” he said. Seasonal employers, who make up a major portion of Alaska’s economy, can now choose to use any 12-week period between May 1 and Sept. 15, 2019, to calculate their PPP loan amount instead of the prior limitation of Feb. 15 to June 30, according to updated SBA rules. The change is especially important for businesses that have peak activity in the summer, such as many tourism businesses in the state, as many do not have a full complement of staff early in the year but will still be hit hard by virus-related travel restrictions and consumer fears throughout the year. There are a few more hurdles to get the loan forgiven, such as using at least 75 percent of the money for payroll or other fixed costs, but generally businesses that were eligible for a loan should be eligible to have some portion of it forgiven, as Congress intended, Huston said. “Whether they’ll be able to get all of the amount forgiven is directly tied to how they used the funds,” he added. Employers can also have their total of forgiven funds reduced if they have fewer employees on June 30 than during their reference period used to tally the loan amount, but SBA rules indicate exceptions for laid off employees who did not accept rehire and other circumstances. Huston described the SBA’s 11-page PPP loan forgiveness application as being “a little bit like completing your 1040 tax return. They walk you through it and sure there’s going to be some questions that aren’t answered, but as the SBA and as the financial institutions are running into them on a consistent basis they’ll be able to get some answers to those FAQs that will help everybody else as they continue the process,” he said. He also noted ongoing discussions in Congress regarding extending the loan forgiveness period beyond eight weeks along with changes to the repayment terms and 75 percent payroll expense threshold. Currently, payments on unforgiven PPP loan amounts are deferred for six months and the loans have a maturity of two years with a 1 percent interest rate, according to the SBA. Elwood Brehmer can be reached at [email protected]

Alaska LNG Project gets major federal approval

Alaska has cleared the biggest regulatory hurdle to developing a long-sought North Slope natural gas pipeline project. The Federal Energy Regulatory Commission on Thursday issued a record of decision authorizing construction of the state’s plan for the many-billion-dollar Alaska LNG Project, concluding a three-year-plus environmental impact statement process. AGDC President Frank Richards called it a “momentous day for the project” and thanked FERC for largely sticking to its timeline for the EIS during a Thursday morning meeting of the AGDC board. AGDC submitted its application for the massive project to FERC in April 2017. “As anybody in the infrastructure development process knows, to go through the (National Environmental Policy Act) process in three years is an exceptionally fast time,” Richards said. Since the current iteration of the project began in 2013, the three major Slope producers and the state have spent more than $600 million to reach this point, with the state share about $240 million of that total. At its core, the project consists of a large North Slope gas treatment plant; an 807-mile buried natural gas pipeline from the Slope to the Kenai Peninsula; offtake points for state use, and a three-train liquefaction plant at Nikiski capable of producing up to 20 million metric tons of LNG per year for export to Asian markets. If developed, the project would generate upwards of 18,000 jobs during construction and roughly 1,000 new jobs during its 30-year operational life, according to AGDC and state Labor Department estimates. It would also provide natural gas to the Fairbanks area and other communities along the pipeline route that currently rely on fuel oil for heating and in some cases power generation. Gov. Mike Dunleavy and the members of Alaska’s congressional delegation commended AGDC for securing the construction permit in formal statements. Sen. Lisa Murkowski, who chairs the Senate Energy and Natural Resources Committee, called it a “capstone moment” for the project and said the FERC certificate and order are extremely valuable assets for the state. Sen. Dan Sullivan, who was Department of Natural Resources commissioner when the state, BP, ConocoPhillips and ExxonMobil began early-stage work on the project, said getting North Slope gas to world markets through the LNG export plan would benefit not only Alaska but also the entire country. “Producing more energy responsibly strengthens our economy, is good for the environment, and dramatically increases our country’s national security. I thank FERC for their diligence in completing this work, and thank all of the Alaskans who, throughout the years, have worked to move this project forward,” Sullivan said. The Alaska LNG Project is the latest attempt to commercialize the large volumes of North Slope natural gas. State and energy company officials have tried since the late 1970s to put together a plan to produce and sell the gas that is considered “stranded” based on the location lacking infrastructure to access global or even local markets. However, frequently changing market and political conditions and the tremendous expense of developing a North Slope gas project — the cost of the pipeline — have scuttled prior efforts. To that end, it’s also unclear at this point if the Alaska LNG Project is economically viable, especially at current low prices amid a global oversupply. While Alaska Gasline Development Corp. officials still have several other state and federal authorizations to secure, the favorable record of decision, or ROD, means confirming Alaska LNG’s economic viability is the next major task for the state-owned corporation. Dunleavy said an ongoing economic review of the project will go a long way toward determining where it goes from here. The governor has been sharply critical of the state leading the project through AGDC — a structure championed by former Gov. Bill Walker — but has followed the recommendation of the large North Slope producers and others who urged the administration to finish the permitting that was already well underway when Dunleavy took office in late 2018. Many observers and insiders view securing the FERC construction license as a way to de-risk the project for potential investors and developers. In April AGDC board approved a strategic plan calling for the state to find a new project sponsor by 2021 or put the project assets, such as its permits and engineering work, up for bid. According to Richards, Flour, an international engineering and construction firm, has completed an updated class 4 cost estimate for the project, which AGDC — with help from BP and ExxonMobil — is running through economic models. In 2016 AGDC pegged the project at about $43 billion including significant contingencies. Many industry experts believe the $43 billion estimate to be high given the rapid expansion and technological evolution of the LNG industry. A better picture of the project’s economic viability should be available in June, Richards said. Elwood Brehmer can be reached at [email protected]

Donlin owners hope to resume drilling soon

Update: Donlin Gold workers will begin returning to the project site May 22, accoridng to spokeswoman Kristina Woolston. Donlin with have "an aggressive and measured approach" to prevent the spread of COVID-19 that will include testing for the virus. About 120 people were working there before the camp was shut down in early April. The owners of the Donlin gold project hope to soon resume drilling work paused in response to the COVID-19 pandemic at the remote mine site and are starting to prepare an updated assessment of the project’s viability. NOVAGold Resources Inc. CEO Gregory Lang said Donlin Gold started its 2020 drilling campaign in February and worked through March before closing down the camp in early April to comply with state health recommendations and travel restrictions. Crews used three drilling rigs to complete six boreholes prior to April, according to Lang. NOVAGold is a 50 percent owner of Donlin Gold in Western Alaska along with mining industry giant Barrick Gold Corp. He said he believes Donlin’s ambitious drilling program — with 80 holes totaling approximately 22,000 meters — can still be completed this year but when it will resume is unclear. Company leaders are currently evaluating when workers can pick up where they left off, Lang said during NOVAGold’s annual shareholder meeting call on May 14 . “They will not return to site until it is safe to do so,” he stressed. Lang noted that Donlin donated its food supplies to food banks and shelters in area villages when the camp was closed. Donlin Gold secured several state permits and land-use approvals for an access road, fiber optic cable and other facilities in January. The company is also continuing a multi-year program started last year for the project’s key dam safety permit from the Department of Natural Resources, which is one of the last major approvals on Donlin’s list. The drilling work, along with engineering and geologic refinements in the project will be added to an updated feasibility study, according to Lang. “A lot of inputs have gone down since the last study, not very many have gone up,” NOVAGold chairman Tom Kaplan said. Kaplan said he does not believe the COVID-19 pandemic has pushed gold to more than $1,700 per ounce in recent days, noting it was at roughly $1,600 before the global crisis began. “It’s accelerating trends which were already in place,” he said. The price of gold is likely to double or triple from where it is currently, Kaplan contends. He said there is no defined price that will trigger development of Donlin. “When Barrick’s ready to move forward, we’ll be ready to move forward,” Kaplan said. Donlin Gold last performed a comprehensive analysis of its massive project in 2011 when it was concluded the complex undertaking would cost $6.7 billion to complete. As proposed, the open-pit mine in the upper Kuskokwim River drainage would be one of the world’s largest, producing more than 33 million ounces of gold over an initial 27-year life. A 315-mile natural gas pipeline from the west side of Cook Inlet would fuel a power plant at the mine and fuel storage tanks would be built at Dutch Harbor, in addition to the very large-scale operation at the mine site. Lang said with 39 million ounces of measured and indicated resources Donlin is roughly five times larger than the average large-scale development-stage gold mines worldwide. The deposit’s average grade of 2.25 grams per ton is also more than double the industry average, which continues to decline, he added. Additionally, the 39 million-ounce resource is contained to roughly three kilometers of an eight-kilometer mineralized trend, NOVAGold leaders highlighted. “It’s clear how hard it is to find a resource comparable to what we have at Donlin,” Lang said. The deposit is on a parcel owned by The Kuskowkim Corp., a Native village corporation and the mineral rights are held by the regional Native corporation Calista Corp, both of which have been strong supporters of the project, although some local village organizations and Tribal governments have become more vocal in their opposition to the mine in recent years. Opponents contend a mine the size of Donlin adjacent to the Kuskokwim poses an unacceptable risk to the river’s fishery, particularly the salmon runs that are widely depended upon for subsistence harvests. A group of 13 village and Tribal leaders from the area sent a letter to NOVAGold and Barrick executives May 13 noting the Association of Village Council Presidents formally opposed the project last year and they did not reach the decision lightly. “We are of course open to responsible resource development in our region when applicants can demonstrate through science that our waters and lands will not be threatened, the Donlin project has failed to meet this bar and thus it is our responsibility to future generations to say no to this risky project,” the letter states. Donlin and NOVAGold leaders often tout the support they have from The Kuskokwim Corp. and Calista for developing the project. The mining companies have partnered with the Native corporations on workforce development and scholarship programs among other things. Elwood Brehmer can be reached at [email protected]

New analysis of Livengood underway with improving markets

The Livengood gold project has renewed life amid rock-bottom oil prices and vastly improved expectations for gold. Marcelo Kim, chairman of Vancouver-based International Tower Hill Mines Ltd., which owns the Interior Alaska prospect, stressed that company leaders and many outside analysts believe the economic stimulus efforts being employed by governments worldwide to mitigate the impact of the COVID-19 pandemic will bring about a resurgence in gold markets. The Federal Reserve’s recent moves to cut interest rates in combination with widespread credit backstops and the loosening of banking requirements all add up to a very favorable outlook for gold producers and sellers, according to Kim. Kim said in a May 12 conference call that expectations for rising inflation following the federal stimulus package of the Great Recession in 2009 largely didn’t materialize because banks didn’t expand their credit offerings following the financial crisis. This time, however, much of the $2.2 trillion Congress approved under the CARES Act is intended to be quickly spent on businesses and individuals instead of keeping banks afloat. “We believe that these are signs that we are in the early innings of a new market for gold,” Kim said. He cited a late April report from Bank of America analysts that forecasts gold prices will rise to upwards of $3,000 per ounce over the next 18 months. Gold is currently trading for about $1,700 per ounce following a steady climb in price that started last year and hasn’t stopped. Gold prices peaked in late 2011 at nearly $1,900 per ounce but spent much of the intervening years fluctuating between $1,100 and $1,300 per ounce before starting to climb again last year. International Tower Hill Mines is sanctioning an updated pre-feasibility study that will build off of a similar study published in late 2016 and incorporate the metallurgical and optimized engineering work done since then, according to Kim. The junior mining firm, which holds 100 percent of Livengood, downsized its operational plans by nearly half following the 2016 study. That work concluded that a mine capable of milling 52,000 tons of ore per day over a 23-year life would cost approximately $1.8 billion to develop and have significantly reduced operating costs versus the company’s original plan from 2013 for a $2.8 billion, 14-year mine processing about 100,000 tons per day. The current mine plan calls for producing 6.8 million ounces over the 23-year mine life with an all-in cost of $1,247 per ounce. The Livengood prospect holds nearly 9 million ounces of proven and probable gold reserves at a market price of $1,250 per ounce and approximately 11.5 million ounces of measured and indicated resources, according to International Tower Hill. Kim said he expects much of the gold resources to become reserves as prices rise. As proposed, Livengood would be a conventional, open-pit mine near the Dalton Highway about 70 miles north of Fairbanks. International Tower Hill expects the mine will generate about 1,000 jobs during construction and 350 long-term jobs during operation if it is developed as currently planned. CEO Karl Hanneman said drilling has shown significant resource potential immediately beneath the pit deposit as well as elsewhere on the property. Historical placer deposits to the northeast of the pit resource reflect the need for additional drilling as well, Hanneman said. “Over the last several years, we have quietly remained laser-focused on improving our geological and metallurgical understanding of the Livengood gold deposit,” he said. That work will be incorporated into the new pre-feasibility study and a timeline for that work should be available in the coming weeks, according to Hanneman. ITH director Stephen Lang said during the call that Livengood is a deposit requiring an average of 140 tons of ore to recover an ounce of gold, which is a good “strip ratio” for a mine of its size. “The mine and the mill are both large enough to give a considerable economy of scale but not in the very, very large range, which adds quite a bit of complexity in the operations and scheduling,” Lang said. The relatively low mining requirement helps relieve cost pressures on the project and is “particularly helpful in offsetting any long-term oil price increases,” Lang added. While being on the road system limits some of the development and logistics costs incurred by more remote mines in Alaska, Livengood and other mines in the state are susceptible to changes in oil prices because diesel is used to power mine operations. Elwood Brehmer can be reached at [email protected]

Copper River closes for a week after poor sockeye showing

It’s been a very rough start to what was already a harried season for Copper River salmon fishermen. Alaska Department of Fish and Game managers announced the Copper River District will be closed for commercial fishing during the regular 12-hour period scheduled for May 21 due to very low initial sockeye catches indicating a lack of fish. Early indications for the May 18 opener show fishermen harvested 1,698 chinook, which Area Management Biologist Jeremy Botz described as “low,” but just 4,550 sockeye, which Botz called “dramatically low.” Subsistence gillnetting will remain open during the commercial closure, but waters inside the expanded Chinook closure area will be closed to all harvest. Botz said that while it has been a late and cold spring and weather deterred some fishing May 18, department officials expected a harvest of more than 28,000 sockeye based for that day based on the overall forecasted run. The total harvest from the first two 12-hour openers was 3,250 chinook, 6,023 sockeye and a handful of chum. Botz said May 19 that the sonar at Miles Lake used to enumerate Copper River sockeye had just been installed and was up and running. Managers expect fishing to resume May 25 with the time and area being announced May 22, according to the closure announcement. ADFG biologists initially forecasted a smaller Copper River sockeye run of 1.5 million fish this year compared to a 10-year average of 2.1 million wild fish. The Gulkana Hatchery supports a small portion of the annual Copper River sockeye run. The department’s official forecast estimated a commercial sockeye harvest of 771,000 fish versus a harvest of 1.2 million sockeye last year. The Copper River chinook return and harvest was initially expected to be strong with a total run of 60,000 fish and an all-fishery harvest of up to 36,000 fish possible. The early harvest figures this year are reminiscent of 2018 when the sockeye harvest averaged just 8,660 fish over the first three periods. Subsequent fishing closures limited the commercial catch to 44,400 fish in 2018; however they allowed the run to surpass minimum escapement goals with 701,577 sockeye counted at Miles Lake that year. Adding to the challenge for fishermen are lower prices for the salmon they do catch, a direct result of the restaurant closures largely in the Seattle area imposed to limit the spread of COVID-19. Botz said ground prices for the first period May 14 was $3.25 per pound for sockeye and $6.25 per pound for chinook. In recent years the price for famed Copper River chinook has been significantly higher; Botz noted it was around $10 per pound last year and the ex-vessel price averaged nearly $13 per pound in 2018. Botz said there is speculation that an improving retail market could boost prices for subsequent periods. Pike Place Fish Market in Seattle was advertising Copper River king salmon for $74.99 per pound at the time of this writing. Copper River sockeye was selling for $49.99 per pound at the renowned market. On May 20, 10th and M Seafoods in Anchorage had no kings for sale but was selling sockeye for $30.95 per pound. Botz and Cordova District Fishermen United Executive Director Chelsea Haisman both said participation in the fishery was down slightly from previous years but not much. Botz estimated it was 85 percent of normal and Haisman surmised about 70 fewer boats than last year participated in the first openers based on delivery totals. There were 372 deliveries made May 14 and 412 made May 18. Haisman said logistics complications delayed some fishermen from fishing and others have been slow to participate because of the cool spring. She said there is still some ice flowing downriver from Miles Lake. “Our hope is that it’s just early and time will tell,” she said. ^ Elwood Brehmer can be reached at [email protected]

New deal for idled North Slope oil project in the works

A cash-starved North Slope oil project could again have new owners with hopes of resuming production later this year. Majid Jourabchi, CEO of Houston-based Thyssen Petroleum, said May 20 that he is part of a team attempting to buy majority ownership in the long-delayed Mustang oil project from investors in Caracol Petroleum, the primary owner. Alpha Energy, through its subsidiary Caracol, has failed to make good on payment commitments to the Alaska Industrial Development and Export Authority for months. Singapore-based Alpha most recently missed an April 15 deadline to put a $60 million investment into Mustang, according to AIDEA spokesman Karsten Rodvik. The cash infusion into the project was part of a loan agreement the AIDEA board approved changes to in January after Caracol missed its first two quarterly loan payments starting last year. The loan was a modification of AIDEA’s $70 million total investment made in two tranches in 2012 and 2014 in the holding companies set up for the Mustang project’s infrastructure development. Rodvik wrote via email that the current volatility of oil markets has caused additional challenges for the project and the authority is reviewing its alternatives as a creditor to Mustang. The AIDEA board of directors discussed the project in an executive session during its May 20 meeting. Anchorage-based Brooks Range Petroleum — jointly owned by Thyssen and Caracol — operates the project. The current ownership group is the latest in a series of convoluted structures since oil prices first fell in 2014 and funding for the project became scarce. Brooks Range briefly started production from the small field in early November through temporary modular facilities after years of delays brought on by collapsed oil prices and other financing challenges. Alaska Oil and Gas Conservation Commission records show Brooks Range produced an average of 478 barrels of oil over 23 days from the well in November. However, production has been shut in since. The Mustang project is adjacent to the southern portion of ConocoPhillips’ large Kuparuk River field and also near the Nanushuk oil project being developed by Oil Search. The field is estimated to hold about 22 million barrels of oil and could peak at production rates of about 12,000 barrels per day when fully developed. Jourabchi, who said he is a shareholder in Alpha and is on the investment firm’s board of directors, said his group has plans to resume work at Mustang in the coming months and restart production late in the year if they are able to buy the project from Caracol and oil prices continue to recover. He declined to provide more information on the situation, saying it could compromise the negotiations. “We’re trying to bring ownership back to the North Slope,” he said. Alaska North Slope crude is selling for about $30 per barrel and prices are generally starting to recover following the market shocks of the COVID-19 pandemic and the Saudi-Russia price war. Representatives for Alpha and Caracol could not be reached. Elwood Brehmer can be reached at [email protected]

Alaska Air starting Bristol Bay, Unalaska service with regional help

Alaska Airlines is doing what it can to fill the void in air service to Western Alaska created when Ravn Alaska suddenly grounded its fleet earlier this spring. The major domestic airline is partnering with regional carrier Grant Aviation to provide twice-weekly scheduled service to Unalaska through Cold Bay starting May 16, Alaska Airlines Regional Vice President Marilyn Romano said. Regular passenger service between Anchorage and Dillingham and King Salmon — where Alaska has historically offered seasonal jet service — will also start earlier this year. The first flights to the Bristol Bay hub communities are scheduled for May 18, according to Romano. Dillingham, King Salmon and Unalaska-Dutch Harbor are just three of the 115 communities across the state that used to be served by Ravn Alaska and its subsidiary carriers. Ravn filed for Chapter 11 bankruptcy protection April 5, grounding its fleet of 72 aircraft, following a 90 percent drop in its passenger revenue as travel halted due to the COVID-19 pandemic, according to a company statement. Alaska Airlines had partnerships with Ravn at hubs across the state and Romano said it is very difficult to watch the company suffer largely as a result of the health crisis. “It’s hard to think about the 1,300 employees for Ravn that are currently out of work and I know they’re working hard still today, as far as I’ve been told, to see how they could possibly get their operation up and running,” she said in a May 12 interview. Alaska’s moves to backfill Ravn’s service are just part of a larger effort from multiple carriers statewide, Romano noted. “Very quickly, not just Alaska Airlines, the aviation community as a whole really stepped up from both the passenger and cargo side to quickly see how these markets could be served in some way and I think what we’ve got today is most of the markets, whether they’re a (larger) Part 121 market or a Part 135 (air taxi) market, are being covered in some form or fashion,” she said, adding that many of the smaller airports Ravn served are inaccessible to Alaska’s fleet of Boeing 737 jets. That is the case for Unalaska, so Alaska Airlines is flying to the Alaska Peninsula community of Cold Bay, which has a 10,000-foot runway from its days as a military airfield during WWII. From there, Grant Aviation will take passengers the remaining roughly 150 miles to Unalaska. The Cold Bay airport has periodically been used as an emergency landing site for international flights with mechanical or other issues. The Cold Bay stop will be part of Alaska’s service to Adak farther out the Aleutian Chain, according to Romano. She said preparing for the coordinated service to Unalaska — the largest seafood port in the country — has been “a real collaboration” between the communities, airlines and state and federal Transportation officials. While the travel restrictions imposed to limit the spread of COVID-19 have decimated the airline industry worldwide, Romano said the period of very low passenger demand has provided a window for Alaska and other carriers to work out solutions to serve rural communities. “It’s been relatively calm but you never want to, if you can help it, have a community with no access to travel. There are critical needs to travel,” she said. As for Bristol Bay, Alaska first had to arrange to sublease Ravn’s ground facilities at the King Salmon and Dillingham airports before it could start service, as the airlines shared space when they both flew to the communities in years past. “We’re ready to go,” Romano said. “We’ve got our plan for moving employees around filed with the state and the communities.” Alaska will start fly to Dillingham three times per week and King Salmon twice per week briefly before ramping up to daily flights in June along with activity in the region’s commercial salmon fishery. Many Bristol Bay-area residents have long pled for Alaska Airlines to provide year-round passenger service to the region and Romany said the airline currently plans to do so this year. “They seem really happy about that in those communities,” she said. Romano added that Alaska will be flying additional charter flights in and out of Bristol Bay to move commercial fishermen and salmon processor workers as safely as possible. Many leaders and residents in rural fishing towns have expressed serious concerns about the ability to safely move seasonal workers in and out of their communities amid the pandemic. “Some of those seafood workers will actually move from a quarantine situation right onto a charter flight as opposed to scheduled service. Any level of safety that any of us can do together is going to help,” she said. Elwood Brehmer can be reached at [email protected]

New Hilcorp-Enstar gas deal adds up to rate savings

Southcentral natural gas customers could collectively save $53.6 million under the latest contract between Enstar Natural Gas Co. and Hilcorp Alaska. According to a letter containing the amended contract terms filed with the Regulatory Commission of Alaska, Enstar customers should save approximately 7 percent in gas costs from June 1 through March 2023, when the utility’s prior contract with the Cook Inlet producer was set to expire. The new terms also extend the agreement through March 2033. According to Enstar’s filing, Hilcorp “reliably delivered” 82 percent of the utility’s gas in 2019 and is expected to cover 80 percent this year. Enstar could purchase anywhere from 64 percent to 97 percent of its annual gas requirement under the new terms. The utility expects its demand to remain at roughly 33.6 billion cubic feet, or bcf, per year through 2025. The contract has a base firm quantity of 25 bcf per year. Enstar officials noted that multiple Cook Inlet producers have filed for bankruptcy in recent years. Furie Operating Alaska had its gas production halted in early 2019 when a production line froze, causing Enstar and other utilities to purchase gas elsewhere and draw on stored reserves for several months. Furie filed for Chapter 11 bankruptcy last August. “This gas supply certainty is vital at a time of growing scarcity,” the letter states. Enstar supplies gas to approximately 148,000 customers. Gas will be sold at $7.55 per thousand cubic feet, or mcf, in the first year of the contract but will vary afterwards. According to Enstar’s filing, the price for gas in subsequent years will be set through a calculation based on three price indices published by the Bureau of Labor Statistics. However, the price cannot increase more than 1.5 percent or decrease more than 1 percent in any given year, meaning the deal has an effective price ceiling of $8.89 per mcf in 2033. Prior contracts between the two had fixed price inflation rates of 2 percent to 4 percent, but “Enstar does not believe that an inflexible, always-positive inflation factor appropriately reflects how production costs increase and decrease over time,” the letter states. The agreement amends and extends a contract signed in 2016. At the time most gas contracts in Cook Inlet were five years or less. In 2018, the first year of that deal, Hilcorp sold to Enstar for an average price of $7.56 per mcf. State Sens. Josh Revak, Shelley Hughes and Senate President Cathy Giessel all urged RCA to approve the contract in comments to the commission. Hughes and Revak noted the combination of price reductions and long-term supply as needed benefits during a highly uncertain economic period and Giessel highlighted that it will ensure Alaska is developing and utilizing its own resources. “When Alaska gas is on relative price parity with imports, this use of our own resource will support the direct and indirect jobs in the resource development industry that in turn support our communities,” Giessel wrote in her comments. A public comment period for the contract is open through May 20 on the RCA website. Elwood Brehmer can be reached at [email protected]

Alaska delegation signs on to effort against banks shunning Arctic

Alaska’s congressional delegation is at the center of a growing cadre of Republican lawmakers pushing back on big banks that have decided not to invest in Arctic oil and gas projects. Three dozen senators and representatives signed a May 7 letter to President Donald Trump that first thanked his administration’s pursuit of American “energy dominance,” which has largely focused development of coal, natural gas and oil resources nationwide. The U.S. was the top oil producer in the world immediately prior to the onset of the global COVID-19 pandemic, with companies producing just more than 13 million barrels per day in early March, according to the Energy Information Administration. But the letter mostly urged the Trump administration to look into how the federal government can counter the group of large banks that have recently publicized policies against financing oil projects in the Arctic and select other parts of the country. Many of the same institutions are also shying away from investments in coal as well. In recent months Goldman Sachs, JPMorgan Chase, Citigroup, Morgan Stanley and Wells Fargo have all confirmed that to varying degrees they would not be supporting future Arctic oil projects. Most of the statements have been made through the banks’ social and environmental policies. The decisions have been praised by numerous congressional Democrats, conservation groups and renewable energy advocates across the country but have made the banks a target for lawmakers from oil, gas and coal producing states. “Scoring cheap political points at the expense of American energy workers is an affront to our economic success and it must be confronted,” the May 7 letter states. The signatories included Sens. Dan Sullivan and Lisa Murkowski and Rep. Don Young. The lawmakers also questioned why lending institutions that received federal support during the 2008-09 financial crisis and will potentially benefit from participating in CARES Act programs should be allowed “to pick energy winners and losers in order to placate the environmental fringe.” “As every sector of our economy struggles to survive the COVID-19 pandemic and seeks financial stability from the federal government, environmental extremists are using the pandemic to accelerate their goal of putting American energy jobs in the grave,” the letter states. “We urge you and your administration to use every administrative and regulatory tool at your disposal to prevent America’s financial institutions from discriminating against America’s energy sector while they simultaneously enjoy the benefit of federal programs.” Sullivan helped get the ball rolling for Republicans while participating an April 24 signing ceremony for legislation to add funding to the Small Business Administration’s Paycheck Protection Program in the Oval Office. Sullivan first said the COVID-19 response aid would help many Alaskans, including those working in the oil and gas, fishing and tourism industries, through this exceptionally difficult period. He said further that he doesn’t believe the banks should be allowed to receive federal support and at the same time “discriminate against a critical sector of the U.S. economy.” “I like the idea of looking into that; you’re right. You know, that got (to) where they were pushed by the radical left, and so they’re afraid of the radical left,” Trump responded. Sullivan said in an interview with the Journal prior to the letter that it is the “irony and hypocrisy” that some of the same banks kept afloat by federal aid roughly a decade ago “still find it OK to discriminate against the energy sector, particularly our state” that goes beyond free market principles and at a minimum warrants congressional attention. He acknowledged that it’s currently unclear exactly what Congress or the administration could do regarding the banks but said his staff is working with administration officials and other congressional offices as well to find possible remedies to the situation. “If you implemented what the national Democrats want, America, as the energy superpower of the world, which we have achieved and is now being threatened, wouldn’t have a chance and the dominant powers would be Saudi Arabia, Russia; and somehow they think that would be good for our country. It’s remarkable and fundamentally frightening to me,” he told the Journal. In January, 16 Democrat senators wrote to Wells Fargo CEO Charles Scharf asking that the bank commit to not financing oil and gas exploration in the Arctic National Wildlife Refuge. Similar letters from congressional Democrats have been sent to other major bank executives as well. Alaska Oil and Gas Association CEO Kara Moriarty said Sullivan made “a really valid point” to Trump while noting that the banks have generally stated a prohibition on direct Arctic oil project financing, which does not preclude general lending to oil and gas companies that work in the region. How exactly the individual banks will decide which oil projects are acceptable and which aren’t is just one question they need to answer, she said, adding that how each institution defines “Arctic” is another. The bans on Arctic oil investments likely apply to the North Slope, as it is within the technical definition of the Arctic, Moriarty said, while also pointing out that the Arctic Council classifies the Aleutians as Arctic — and some federal agencies — have even broader definitions. “I do think it is frustrating to see these huge financial institutions in my mind arbitrarily decide that projects and financing in the Arctic is too risky because some of them have listed care for the environment and things of that nature (in policy statements) and yet they’re still investing in companies and projects in countries that have a way worse environmental record than America does and certainly Alaska,” she said. “If a bank’s risk profile doesn’t view that projects in the Arctic are going to meet their risk criteria, that’s fine, but making blanket statements that ‘we won’t be investing’ even without giving a project the benefit of the doubt is sort of like agencies saying ‘we’re never going to permit a project in the Arctic.’ How can you say that?” Wells Fargo interprets the Alaska Arctic to be the North Slope, according to spokesman David Kennedy. He wrote in an email that the bank did not have a comment on letter to Trump but clarified the bank’s policy regarding working with the oil and gas industry in the state, noting that the decision to forgo funding Arctic oil projects was part of a larger move away from all project-specific transactions in the region. The bank, which has branches in Alaska, will continue to offer general corporate credit facilities for oil and gas companies in Alaska, according to a statement from Wells Fargo. “Wells Fargo is a leading provider of credit to Alaska Native Corporations and responsible oil and gas exploration and production companies doing business in Alaska, and we want to continue those relationships long into the future,” the statement said. Moriarty said she hasn’t heard of any companies in Alaska struggling to find financing as a direct result of the banks’ decisions but that’s mostly because funding isn’t something oil companies often disclose. “We operate under some pretty strict anti-trust rules. Price and investors and who they’re getting money from and how they’re getting money for projects — that just isn’t stuff we talk about, but it doesn’t mean it’s not happening,” she said. First National Bank Alaska CEO Betsy Lawer said the large oil companies operating on the North Slope typically have lines of credit with other financial institutions to fund portions of their work. FNBA, as a community bank, instead focuses its oil industry lending on Alaska-based companies in the support service sector, Lawer said. A JPMorgan Chase spokesman declined to comment on the May 7 letter and other banks did not respond to questions in time for this story. ANWR lease sale Bureau of Land Management officials continue to inch ahead with plans for an oil and gas lease sale in the ANWR coastal plain despite historically bad dynamics in world oil markets but it remains unclear when the controversial silent auction-style sale will finally be held. BLM Alaska officials released the final version of the environmental impact statement in mid-September and BLM State Director Chad Padgett said at the time he hoped to hold a lease sale for the entire 1.6 million-acre coastal plain before the end of the year, reiterating a common theme heard from other Interior Department leaders. While a record of decision — a prerequisite to a lease sale — could have been signed by agency officials as soon as 30 days after the official Sept. 20 final EIS notice was published in the Federal Register, but 2019 ended with little word from BLM or Interior leaders about it. BLM Alaska spokeswoman Lesli Ellis-Wouters noted in an emailed response to questions that it is not uncommon for a record of decision to be issued up to several months after a final EIS is made public. “This decision will take into consideration the many important issues and potential impacts we heard during our multi-year scoping and public comment process which resulted in almost 2 million comments received,” Ellis-Wouters wrote. The commenters largely expressed concerns about impacts to subsistence lifestyles, the migratory patterns of the Porcupine caribou herd that uses the coastal plain for calving and opportunities for increased jobs and economic opportunities in the state, she added. Ellis-Wouters also noted that to comply with the 2017 tax bill, which opened the Coastal Plain to oil and gas exploration, BLM does not have to hold the first lease sale until December 2021. However, many supporters of drilling in ANWR have pushed for a sale before the end of President Donald Trump’s first term to make sure Republicans maintain control of the process. Bloomberg reported May 11 that Interior Secretary David Bernhardt said he does not think the immediate collapse of oil markets will dampen industry interest in an ANWR lease sale, which he believes will likely be held this year. Moriarty said it’s too tough to tell what industry’s response to a lease sale would be as uncertainty from the COVID-19 pandemic has made even very near-term predicting in the historically volatile industry impossible. “You’ve got to let the process work. You’ve got to make sure the EIS is defensible in court because those that oppose development of the coastal plain are going to say, ‘well, the reason they didn’t show is because of low prices’ or ‘the reason they didn’t show is because of high prices’ or ‘the reason they didn’t show is’ — it just doesn’t matter,” Moriarty said. “There’s always a reason fabricated as to why we’ll never have a successful lease sale in this price environment so the process has to continue.” It’s widely believed that a record of decision authorizing a lease sale will be challenged in court. If a record of decision advancing a sale is approved, BLM will issue a Call for Nominations to industry, which usually takes 30 days and then a Notice of Sale announcing the date will be issued following a review of industry’s submissions, according to Ellis-Wouters. ^ Elwood Brehmer can be reached at [email protected]

Long-sought Railbelt utility reform becomes law

After more than five years of highly technical analysis, delicate negotiations and numerous fits and starts along the way, the path to restructuring Alaska’s once-disjointed Railbelt electric system is officially complete. Gov. Mike Dunleavy signed legislation April 29 fortifying the authorities of the Regulatory Commission of Alaska and directing the six Railbelt electric utilities to establish a new organization to plan for and manage deeply integrated utility operations. RCA Chair Bob Pickett thanked Dunleavy for signing Senate Bill 123 — spawned from recommendations the commission made in 2015 — and said it will eventually help provide Railbelt region residents with more reliable and effective power service in a formal statement. “A cooperative effort of legislative leadership, the RCA, utilities, independent power producers and other public interest representatives contributed to this successful outcome, which started in 2014 at the direction of the Legislature,” Pickett said. SB 123 passed the Senate unanimously and received broad support in the House. It codifies the work that the Railbelt electric utilities have done at the behest of the Regulatory Commission of Alaska to better integrate the long-term planning of the six utilities and provide a consistent path for renewable power producers to access the regional transmission system. “SB 123 will foster cooperation among the interconnected utilities and ensure consumer needs are efficiently and reliably met,” said Sen. John Coghill, R-North Pole, the chair of the Railbelt Electric System Committee that drafted the legislation. Renewable Energy Alaska Project Executive Director Chris Rose called the signing of SB 123 “historic,” a term used by many individuals involved in the Railbelt electric work. “Efforts to reform the Railbelt electric grid to improve coordination and efficiency among the six utilities something that people have been trying to do for decades. This is a major win for everyone,” Rose said. “It will create a better environment for renewable energy development, create efficiencies that will lower electric costs for consumers and allow Alaskans to have a say on what projects are built in the future.” In 2014, lawmakers directed the RCA to conduct a detailed examination of the issues facing the Railbelt electric grid, which stretches across the service territory of six utilities from Fairbanks to Homer that collectively have a customer base typically served by a single utility in the Lower 48. The RCA’s analysis resulted in a frank June 2015 letter to the Legislature that characterized the Railbelt electric system at the time as “fragmented” and “balkanized” and recommended the utilities be afforded time to voluntarily improve their coordination before the commission would seek to clarify its authority to direct coordinated utility operations. At its core, SB 123 mandates the Railbelt electric utilities work with other stakeholder-driven organizations to form an electric reliability organization, or ERO, that would oversee implementation of system-wide reliability standards and coordinate long-term planning amongst the utilities. It also gives the RCA explicit authority to rule on the necessity of large infrastructure projects, such as generation plants, that utilities may pursue. The primary end goal for many stakeholders is to achieve “economic dispatch” across the entire Railbelt — from Homer to Fairbanks — or consistently maximizing use of the most efficient power generation through near-constant power sales between the utilities. Currently, the limited capacity of transmission lines in the region can inhibit economic dispatch of electricity, particularly from the state-owned Bradley Lake hydropower facility near Homer that provides some of the lowest-cost power in the region. While the process of getting from the June 2015 letter to the passage of SB 123 was lengthy and included multiple setbacks, such as the scrapping of an application to jointly form a transmission company to support transmission infrastructure investments last year, utility leaders generally supported the concept. Last December the general managers and CEOs of the regional utilities signed a memorandum of understanding outlining how they would form an ERO dubbed the Railbelt Reliability Council, governed by a board comprised of utility representatives and stakeholders championing independent power producers and others. Utility leaders acknowledged the bipartisan support already behind SB 123 last fall was an impetus to developing the MOU, which calls for the reliability council’s implementation committee to have a business plan for the council ready by this December. MEA spokeswoman Julie Estey wrote via email that the committee’s work has been slowed by a couple weeks while the utilities were immersed in responding to the COVID-19 emergency, but it has not stopped. According to Estey, 11 applications for two unaffiliated implementation committee seats are currently being reviewed and the results are expected in the middle of this month ahead of a vote to finalize the committee roster. Elwood Brehmer can be reached at [email protected]

Predictability a priority for ferry work group

Achieving consistent, dependable ferry service is the top priority for members of the Alaska Marine Highway Reshaping Work Group following their first working meeting April 30. “They just want to know that they can get from point A to point B on a reliable schedule,” Southeast Conference Executive Director Robert Venables said of the region’s residents. He acknowledged the frequency of future ferry service likely won’t be what folks want, but said it needs to be something communities and build around. Venables also chairs the state Marine Transportation Advisory Board. Sen. Bert Stedman, R-Sitka, went one step further, saying the need for predictable and reliable service is not even up for debate; it’s how the state gets there that needs to be hashed out. Stedman said ferry service needs to be a more affordable transportation option for Alaskans who don’t have the means to travel frequently by air. The Alaska Marine Highway System needs to get “back to the basics” as a system primarily for Alaskans, noting some accommodations must be made because it receives Federal Highway funding. “You’ve got to have a transportation corridor; it’s basically one of the most fundamental aspects of an economy,” Stedman said, also emphasizing that he’s open to significant changes in the system’s structure but cutting off service is unacceptable. “Isolation — that’s not much of a solution,” he said. Work group chair Adm. Tom Barrett said the first few meetings would focus on establishing the high-level objectives the group will push for. The AMHS Reshaping Group will also devise a strategy for implementing its recommendations and eventually provide the administration and Legislature with a path for how they can further the transition. Recently retired as president of Alyeska Pipeline Service Co., Barrett also served as Deputy Transportation secretary under President George W. Bush. The group was originally scheduled to meet April 16 but that meeting was cancelled for technical difficulties. An administrative meeting to set up the group was held in February. He stressed a need to simplify broad aspects of the system so its operations can be more easily adapted to varying conditions. Previous ferry system reform efforts produced recommendations that should be considered, Barrett said, suggesting they previously were not accompanied by a way to make them happen. “The heavy lift will be down in writing an implementation plan for the changes we agree to eventually,” he said. Gov. Mike Dunleavy appointed the nine-member Alaska Marine Highway Reshaping Work Group in February after his administration commissioned a study to examine ways to reform the system with a focus on reducing its annual state subsidy. The study, published in January, highlighted many of the challenges facing the system, but did not provide significant recommendations for restructuring its operations or management. The work group’s recommendations are due by the end of September for implementation in fiscal year 2023, according to the governor’s office. Former Gov. Bill Walker’s administration partnered with the Southeast Conference on a two-year study finished in 2018 that urged lawmakers to set up the system as a public corporation with an expert board of directors that could plan long-term and be largely above the political fray. The Alaska Marine Highway System is currently an agency in the Department of Transportation. That study led to a bill establishing that would have established the new structure, but it received little attention by the Legislature. Venables and Rep. Louise Stutes, R-Kodiak, stressed the common message that the current structure greatly inhibits efficient operations — in terms of spending and decision-making, among other issues — because each new governor means new leadership and often a new strategic direction. “It needs some kind of governing board where it doesn’t become a target each time the administration changes,” Stutes said. Gov. Mike Dunleavy added urgency to the desire to overhaul the ferry system last year when he proposed a roughly 75 percent cut to the system’s annual operating subsidy. The budget would have shut down the system in October after three months of service. Legislators and the governor ultimately agreed to a cut of just less than 50 percent for a $46 million appropriation that was intended to keep the system running year-round but with several-month gaps in service for some communities. A series of mechanical and structural problems among the ever-aging vessels and issues with shipyard repairs led DOT to charter private vessels to some communities as a stopgap measure last winter. Barrett questioned what the financial objective of the system should be — whether that is simply improving cost recovery or finding ways to operate within a set budget. He said the work group could meet as often as once per week as its work ramps up and he also wants to hear opinions from outside the group, such as from Tribal representatives. Barrett suggested the group might break into committees to work out the specifics of some of the broader issues facing the ferry system. ^ Elwood Brehmer can be reached at [email protected]

Senators: All tools on table to deal with Saudi oil glut

Alaska’s senators say the federal officials should consider all options to help buoy the country’s struggling oil industry but simply restricting imports could invite other issues. Sens. Lisa Murkowski and Dan Sullivan discussed the situation in separate interviews with the Journal. Sullivan said that limiting oil imports to the U.S. while the world is oversupplied makes sense at a “base level” but acknowledged that imposing such a restriction effectively would require accounting for a host of other factors. “All of the tools are on the table,” he said. Sullivan subsequently issued a joint statement May 4 with Republican Sens. Jim Inhofe of Oklahoma and Kevin Cramer of North Dakota urging the Trump administration to apply national security tariffs to oil imports from Saudi Arabia and Russia. The statement says the tariffs would counter the “anticompetitive behavior” of the two countries, which were embroiled in a roughly six-week oil price war that exacerbated the market impacts of the COVID-19 pandemic and ended in mid-April with a broad agreement to cut daily global production by nearly 10 million barrels. “Saudi Arabia and Russia’s continued dumping of crude is having lasting and damaging effects on American energy producers. This is intentional — Russia and Saudi Arabia are tired of competing with us and want to put American oil and gas producers out of business so the can once again dictate energy prices to the world,” the senators said. Murkowski, who chairs the Senate Energy and Natural Resources Committee, said she is wary of tariffs or an outright ban on oil imports, but echoed Sullivan in adding that “right now, all options are on the table” to deal with the oversupply of crude. “We’ve got a situation right now that is facing us that is a real challenge so how we can be creative is something that we need to look to,” Murkowski said in an interview. Both of Alaska’s senators signed a March 16 letter to Saudi leaders with 11 other senators urging the government to help stabilize oil markets but Sullivan has taken a much more direct approach since, highlighted by the May 4 statement with Inhofe and Cramer. Sullivan said he has been on several calls in recent weeks trying to improve the oil market situation with the Trump administration officials, fellow members of Congress and directly with Saudi leaders. In a two-hour call with 12 other senators Sullivan recalled telling Saudi Energy Minister Prince Abdulaziz bin Salman that there would be enough support in Congress to withdraw U.S. troops from Saudi Arabia if the country didn’t stop attempting to manipulate world energy markets. “I told the energy minister, ‘Right now you’re talking to 13 of your best friends but stand by and I promise you we will be your worst enemy if you don’t stop what you’re doing that’s hurting our constituents,’” he said. According to Sullivan, Texas Republican Sen. Ted Cruz participated in the call and noted that 54 senators voted against the administration’s last military weapons sale to the Saudis; however, Trump vetoed the Senate’s measure disapproving the sale and the Senate maintained it. Adding those 54 senators to the 13 on the call — all of whom voted in support of the arms deal — gets to a veto-proof 67 votes to remove troops from Saudi Arabia, Sullivan remembered Cruz telling the energy minister. “I’m not bluffing,” Sullivan said. “The Saudis can be very squirrely but they listen to threats to their existence and trust me, without the U.S. military protecting them there’s a major threat to their existence. The Saudi military is not formidable and couldn’t stop any of their neighbors from invading them.” The number of U.S. troops stationed in Saudi Arabia is classified, according to Sullivan, but he said that the U.S. has missile batteries there that could also be pulled. He also emphasized that he will be among many members of Congress watching the Saudis closely to make sure they adhere to the two-year production agreement. “When a country that we’ve helped and protected starts to take actions that directly negatively and significantly hurt people that I’m privileged to represent and there’s some indications that they’re doing it on purpose, for that reason, it’s a whole new ballgame,” he said further. The agreement to cut oil production by roughly 10 percent worldwide starting in May was hailed as “unprecedented” when the leaders of major oil producing countries announced it last month. Yet, oil prices continue to languish, particularly in the U.S., because the deal does not come close to counteracting the even more massive decline in daily oil demand brought on by economic shutdowns imposed to fight the spread of COVID-19. According to the International Energy Administration, worldwide oil demand fell by approximately 29 million barrels per day in April, or about 30 percent, from a year ago. The IEA expects overall oil demand in 2020 to fall by 9.3 million barrels per day, the group said in its April Oil Market Report. The price for global benchmark Brent crude has stabilized in the high $20s per barrel versus the $63 per barrel Brent oil averaged in January just prior to pandemic spreading across the globe, but prices for Alaska and Lower 48 oil have fallen even further. The prices for Alaska North Slope and West Texas Intermediate, or WTI, briefly went negative April 20 and have since recovered; however, oil in those markets continues to trade at a steep discount to Brent. As of May 4, WTI sold for $20.39 per barrel and a barrel Alaska North Slope crude went for just $14.60 despite trading at a slight premium to Brent as recently as January. Alaska economists have said that the relative isolation of the West Coast market where most oil from the state is sold from the rest of the country and a surge of oil imported from the Middle East — mainly Saudi Arabia — has depressed the price of Alaska oil even further. Before the production cut agreement in which Saudi Arabia is supposed to scale back to 8.5 million barrels per day, Saudi leaders insisted the country would increase its production to about 12.3 million barrels per day. According to a February S&P Global Platts report Saudi Arabia produced 9.7 million barrels per day in January. And even though the Russian-Saudi truce is approaching a month old, the impacts of the war are still being felt in the U.S. According to the Energy Information Administration, domestic crude stocks hit more than 527 million barrels in the third week of April, up 9 million barrels from the week prior and nearly 30 million barrels more than was stored a year ago. Stores of refined products have stabilized of late but also far exceed what was available a year ago, according to EIA data. Sullivan and Murkowski both acknowledged that roughly 40 million barrels of oil sitting in tankers off the West Coast was purchased in February and March by U.S. refiners. “As much as I want to say turn those tankers around we don’t want them here; they’re replacing Alaska crude or they’re taking up space in our limited storage — again I think we need to recognize that many of our refiners are set up to take just exactly that heavy Saudi crude and that’s what they need,” Murkowski said, while also questioning how the contracts would be resolved if the foreign oil was wholly turned away. North Slope crude generally has a slightly lighter makeup than Saudi oil and refiners can adjust to handle different oils with adequate lead-time. Sullivan and Murkowski both said they have tried to encourage other countries to fill their national oil storage systems to help ease the global oversupply. According to the IEA, which helps coordinate global oil storage, if each country with storage available were to “top off” its reserves up to 2 million barrels per day could be pulled from the market over about three months. “It’s not going to save us, but it’s not bad,” Sullivan said of the idea. Murkowski said following a call with Energy Secretary Dan Brouillette that the Energy Department has made space available to domestic producers in the U.S. Strategic Petroleum Reserve. “Lease it out so producers could offload, keep it there and basically pay to retrieve it later,” Murkowski said. She has said she will co-sponsor legislation authorizing $3 billion for the Energy Department to purchase U.S. oil to fill the SPR when Congress reconvenes. Additionally, Murkowski said Energy officials are looking into more storage for refined products. “We’re looking to what we can do to address the storage issues,” she said. Elwood Brehmer can be reached at [email protected]

Alaska Air Group absorbs $232M loss in first quarter

Alaska Air Group Inc. leaders reported a $232 million first quarter loss on May 5 as demand for air travel ostensibly remains at zero. It marked the first quarterly loss for the Seattle-based parent company to Alaska Airlines and regional carrier Horizon Air in more than a decade, CEO Brad Tilden said. Tilden called the result, which was driven by a 14 percent drop in passenger revenue for the quarter, “sobering” in an investor call but said there is “no doubt” that the second quarter will be much worse. Executives chose not to forecast even near-term financial performance and business metrics given the very high uncertainty as to what lies ahead but stressed a goal of reaching breakeven cash flow by the end of the year while also admitting they do not yet know how they will get all the way there. According to Tilden, the company had a cash burn rate of roughly $400 million per month at the start of April that has been brought down to about $260 million per month currently and the hope is to get it to $200 million per month in June to continue towards the breakeven goal. The company has suspended its share repurchase and dividend programs. Alaska Air Group stock closed May 5 trading at $28.97 per share. It had largely traded in the mid-$60s per share to start the year before a pandemic-induced drop started in late February. Tilden commended airline employees’ focus on safety and caring for guests even as business has nearly ground to a halt. “In the face of one of the greatest challenges in the history of aviation our people at Alaska and Horizon are doing extraordinary work to respond to these circumstances,” Tilden said. All Alaska and Horizon passengers will be required to wear facemasks starting May 11. He added that the airlines are requiring all flight attendants and customer-facing employees to wear face masks, are encouraging passengers to self-scan boarding passes, have slowed the boarding process to reduce crowding and suspended most in-flight services in attempts to limit the spread of coronavirus. Alaska Airlines President Ben Minicucci noted the airline was one of the first major domestic carriers to feel the impact of the public response to the virus hit its business in late February as the Seattle area saw the first confirmed outbreak in the U.S. Ticket cancellations overtook new bookings on March 11 for the first time in Alaska’s history, Minicucci said, and as of May 5 the airline was mired in a stretch of 56 consecutive days of net negative bookings. Alaska has waived all of its ticket cancellation and change fees through the end of the year. He said passenger levels are starting to show “very modest” week-to-week improvement but demand is still down more than 90 percent from historical levels. Capacity at Alaska Airlines was down approximately 80 percent in April and May and that trend is expected to continue at least into June. Alaska Air Group received $992 million in federal CARES Act assistance from the federal government April 23. The aid breaks down to a $725 million payroll grant and a $267 million 10-year Treasury loan. It requires the company not institute mandatory furloughs or pay cuts through Sept. 30. Tilden said the support covers approximately 70 percent of the company’s payroll through September. The Treasury Department also took rights to buy 847,000 non-voting shares of common Air Group stock at the April 9 closing price $31.61 per share. Overall, the $2.2 trillion CARES Act allocated $50 billion for grants and loans specifically to airlines. Air Group Chief Financial Officer Shane Tackett said the company currently holds about $2.9 billion in cash and short-term investments that includes the CARES money; a $400 million draw on existing lines of credit; $425 million from a 364-day term loan and $50 million in secured financing acquired after the end of the first quarter. Air Group started the year with about $1.5 billion in cash and marketable securities. The $2.9 billion will last the company a little more than 11 months and Air Group has the ability to borrow against about $2 billion worth of aircraft it owns outright, Tackett said. Alaska and Horizon also separately applied for $1.1 billion in CARES Act loans apart from the payroll funding. “Banks and investors we’ve spoken to have indicated interest in lending against these assets with reasonable terms,” he said. Alaska Air Group also has roughly $500 million in real estate as well as its loyalty program that could both be leveraged for further liquidity, Tackett said, adding that it all totals to between $7 billion and $8 billion of collateral that holds upwards of $4 billion worth of incremental liquidity potential. He acknowledged that taking on the potential debt load is not ideal but may be needed to simply survive. “Taken together, our hands-on liquidity, our access to additional financing and our aggressive goals to reach cash breakeven results will ensure that we bridge this downturn and are prepared to rebuild our success during a recovery,” Tackett said. Air Group executives for years have stressed a desire to have an “investment-grade” balance sheet and have focused on paying down debt in the past. The company’s debt-to-capitalization ratio stood at 48 percent at the end of the first quarter, compared to 41 percent to start 2020. Tackett said Air Group’s airlines have cut discretionary spending by $50 million per month and deferred $600 million in capital spending, meaning the company’s total capital spend will be less than $175 million this year. Additionally, more than 5,000 of Air Group’s 23,000 employees have taken 60 days of voluntary unpaid leave, according to Tackett. Executive pay has been cut and management hours have also been reduced by 10 percent as well, he said. Alaska Airlines has also expects to permanently ground at least 12 mainline aircraft — likely Airbus aircraft acquired from its 2016 purchase of Virgin America — and is retraining 240 of its Airbus pilots to fly the Boeing 737 aircraft Alaska has traditionally flown. “I believe that all 23,000 of our people understand that if we can achieve a breakeven cash burn rate our destiny is squarely back in our control, which means we are also in control of building towards a better future again,” Tackett said. “It’s an objective we have to get to.” Elwood Brehmer can be reached at [email protected]

ConocoPhillips to curtail Slope production by 100k per day

ConocoPhillips announced Thursday morning it will cut its North Slope oil production by about 100,000 barrels per day as the price for Alaska crude continues to flounder relative to other oil benchmarks. The announcement came as ConocoPhillips, which currently produces the most oil in Alaska, also reported a companywide first quarter loss of $1.7 billion as the global response to the COVID-19 pandemic ground economies to a halt and oil prices collapsed. Oil production will be curtailed in June at the company’s Kuparuk River, Alpine and Greater Mooses Tooth-1 fields. The large Kuparuk and Alpine fields are primarily on state lands, while GMT-1 is in the National Petroleum Reserve-Alaska. The state production tax is applied to NPR-A oil, but the state does not receive royalty revenue from production in the federal reserve. According to a company statement, the production curtailment will start in late May and how long it lasts will be determined month-to-month. ConocoPhillips 218,000 net equivalent barrels per day in the state during the first quarter. “This decision was made in response to unacceptably low oil prices resulting from global oil demand destruction caused by the impacts of the COVID-19 pandemic, combined with a global oversupply of oil,” ConocoPhillips Alaska said in a statement. “The curtailment will essentially leave the oil stored in the reservoirs, available for resumption of production at a later date. The actions ConocoPhillips Alaska is taking with this production curtailment underscore the extraordinary challenges currently facing the oil and gas industry in Alaska and elsewhere.” The cuts should not impact Trans-Alaska Pipeline System operations, according to the statement. ConocoPhillips Alaska spokeswoman Natalie Lowman said the cuts will be enacted by shutting in wells and the 100,000 barrels per day amount is largely driven by the minimum volume of oil the company needs to continue moving through its facilities at the fields to keep them operational. “We want to be able to respond quickly if market conditions improve,” Lowman said. Alaska Division of Oil and Gas spokesman Sean Clifton wrote via email that ConocoPhillips informed state officials about their curtailment plan last week and has assured them that TAPS throughput will remain sufficient. “It is likely they’ll have to bring production back up when Arctic temperatures return in fall, regardless of market conditions,” Clifton wrote. Alyeska Pipeline Service Co., which is owned by the major North Slope producers, said April 24 it had begun “prorationing,” or reducing oil throughput in TAPS by about 10 percent, or 50,000 barrels per day, to deal with a lack of oil storage capacity projected for late May in the system. Alyeska and the producers routinely slow TAPS throughput in summer for maintenance activities. While oil prices are depressed worldwide, the situation has been magnified for Alaska due to market conditions on the West Coast, where the vast majority of Alaska oil is sold. Alaska North Slope, or ANS, crude sold for $10.67 per barrel on Wednesday while West Texas Intermediate — the primary price for Lower 48 oil — sold for $15.06 per barrel and oil traded on the global Brent benchmark went for $22.54 per barrel. The spread between the ANS and global Brent prices that is now hammering Alaska was benefiting the state just a few months ago. As recently as January ANS crude was trading at a $2 per barrel premium to Brent and in prior months Alaska oil had sold for up to nearly $4 per barrel more than Brent. Transportation constraints limit the amount of oil produced east of the Rocky Mountains that can be sent west. That soft barrier has led to the development of ostensibly two oil markets in the U.S. West Coast refiners also purchase large amounts of Middle East oil and Saudi Arabia’s oil price war with Russia — that started in March and continued into mid-April — exacerbated the glut of oil available to West Coast buyers. Petroleum economists have also noted that West Coast oil demand largely comes from the transportation sector, which has been hit especially hard by government-mandated travel restrictions to slow the spread of the virus. Leaders from the world’s top oil producing nations on April 12 announced a global agreement to cut 9.7 million barrels from daily production in May, or about 10 percent of oil production worldwide. Under more normal market conditions prices would jump on the anticipation of such significant supply cuts, but the unprecedented drop in demand is overriding all other market factors. ConocoPhillips leaders have announced $400 million of cuts to the company’s spending plan in Alaska since mid-March. In early April the company told its drilling contractor Doyon Drilling that it would be laying down its North Slope drilling rig fleet indefinitely. On April 16, ConocoPhillips executives said they planned to curtail about 225,000 barrels per day of oil production from fields in the Lower 48 and Canada. A statement accompanying Thursday’s first quarter earnings report says companywide voluntary production curtailments in June will likely total approximately 460,000 barrels per day. Q1 numbers The $1.7 billion first quarter loss followed a $720 million fourth quarter and nearly $7.2 billion full-year profits. ConocoPhillips’ total revenue for the first quarter of the year was down more than 40 percent compared to the end of 2019 to just more than $4.8 billion. The overall loss translated to a loss of $1.60 per share. ConocoPhillips stock traded for $42.40 near the end of trading Thursday, on par with its prior closing price. The company’s per-share price bottomed out at $22.67 on March 18 when the first round of spending cuts was announced. It traded at around $60 per share for much of the winter. The overall quarterly loss was driven by losses absorbed in the company’s Lower 48, Canada and corporate business segments. According to the earnings report, ConocoPhillips’ Alaska operations netted the company $81 million during the first quarter. According to Lowman, ConocoPhillips paid $218 million in taxes and royalties to the State of Alaska and spent $509 million on capital projects during the quarter. The company remains on track to start oil production at its Greater Mooses Tooth-2 project on the North Slope in late 2021, according to the earnings report statement. ConocoPhillips realized an average price of $38.81 per barrel for its oil in the first quarter, down about 18 percent from an average of $47.01 for the fourth quarter of 2019. ConocoPhillips ended the quarter with $13.7 billion in liquidity compared to $14.1 billion in cash and short-term investments at the end of 2019. Elwood Brehmer can be reached at [email protected]

Doyon acquires stake in mining company with state prospects

Doyon Ltd. has taken a direct stake in a mining company exploring for gold on its land in an area of Alaska that has seen a resurgence in interest from prospectors. The Interior Alaska Native regional corporation invested $1.5 million in Tectonic Metals Inc., a Vancouver-based firm with claims to three Eastern Alaska gold prospects, according to a joint April 20 statement. The deal makes Doyon the largest single shareholder in the Tectonic with a 22 percent ownership stake. Tectonic is working two gold prospects, dubbed Seventymile and Northway, on Doyon lands near the Canadian border. Tectonic also holds the Tibbs prospect on state land about 20 miles east of the Pogo gold mine near Delta Junction. All of the prospects are in the Tintina Gold Belt, which runs across much of Interior Alaska and into the Yukon Territory. New technologies for conducting geophysical surveys and other analyses of prior drilling data have led a handful of companies exploring for large gold deposits to revisit the eastern Tintina region that historically has been an area worked by smaller placer mining operations. Tectonic co-founder and CEO Tony Reda said the investment is unique in that it amounts to an “endorsement” in the company as a whole, not just in the prospects Tectonic is working on Doyon’s land. While the Tibbs, Seventymile and Northway projects are each years from becoming an operating mine, Reda said in an interview that having a large backer like Doyon with the ability to potentially support development of a mine if one of the projects reaches that point is also a major selling point to other investors in the inherently high-risk junior mining industry. “Having Doyon as a shareholder gives us the ability to walk into a fund’s office in New York or Toronto — Wall Street, (Toronto’s) Bay Street, Vancouver’s Howe Street, pick your street — but we get to walk in their and say this is who we are and we’re actually aligned with our Native partner and there’s not too many companies that can do that,” Reda said. The $1.5 million investment netted Doyon approximately 10.4 million shares in Tectonic, according to the statement. Tectonic was formed by Reda and other former leaders of Kaminak Gold Corp., which discovered and advanced the 5 million-ounce Coffee gold prospect between Beaver Creek and Dawson City in the Western Yukon before selling the project to the mining giant that is now Newmont Goldcorp for $520 million Canadian in 2016. Doyon CEO Aaron Schutt said in an interview that the decision to invest in Tectonic started from internal conversations about how to encourage more economic development activity across the company’s vast land holdings. Doyon is the largest private landowner in Alaska with title to approximately 11.5 million acres. Alaska Native regional corporations such as Doyon also hold subsurface mineral rights lands owned by Native village corporations in their regions. Doyon leaders liked how Kaminak Gold approached its work in the Yukon — in terms of both geology and community engagement — and that continued into Tectonics first couple summer work seasons in Alaska, Schutt said. “It doesn’t show up in early in the economics of a mining project but it does later,” Schutt said of companies that are actively involved in the communities near their projects. He added that Doyon leaders anecdotally heard positive things from First Nations officials in the Yukon about Kaminak. Reda said Kaminak offered scholarships to area students and established a local hire program among other efforts to positively impact area residents while the company was working the Coffee project. “It’s not just about finding a mine; it’s about doing it properly in a way that benefits everyone,” he said. As for the prospects, Reda said the Seventymile property near Eagle is “drill ready” and the company had plans to do so this summer before the COVID-19 pandemic took over nearly every aspect of life. Those plans are on hold for now. “Right now we’re thinking outside the box on how to make that a reality but at the same time we have to be very much compliant with the rules and regulations and obviously the safety of our employees and service providers is of the utmost importance,” he said. Tectonic acquired the Seventymile property in 2018 did its own soil sampling and geophysical surveys along with analyzing historical drilling records from the area. The company drilled the Tibbs prospect last year with promising results. “We’re also champing at the bit to get out into the field there (at Tibbs) and flesh out the discovery and figure out just how big it is,” Reda said. He also noted that by taking a direct stake in Tectonic, Doyon would reap a portion of any benefits Tectonic realizes from the Tibbs prospect even though it’s on state lands. Alaska mining industry observers estimate companies spent roughly $150 million on exploration work in 2018 and 2019, up about $50 million from several years prior. The land-use agreements for the Northway and Seventymile prospects are typically structured and the direct investment does not change them or give Tectonic preferential rights to other Doyon lands, according to Schutt, who said the regional corporation is also looking to do some early-stage mineral exploration on its lands itself this year. “It’s not even drilling, just data review,” Schutt said, adding Doyon has gotten interest from other exploration companies of late, adding further to the revived interest in the Eastern Interior’s gold potential. Doyon has previously explored for oil and gas on its lands with mixed results. Elwood Brehmer can be reached at [email protected]

Oil Search hits target in two wells but slows Nanushuk development

Oil Search had a successful exploration drilling campaign on the North Slope this winter but the company has cut spending and delayed a final investment decision on Alaska’s largest oil project in decades amid horrendous market conditions. The Mitquq-1 and Stirrup-1 exploration wells both hit oil and had flow rates better than expected, according to Oil Search’s first quarter earnings report. The Papua New Guinea-based producer is advancing the Nanushuk oil project in the Pikka Unit located on state lands between ConocoPhillips’ large Kuparuk and Alpine fields. Oil Search also said in its quarterly report that a final investment decision on the roughly $5 billion project has been deferred until market conditions improve. Company leaders had previously planned on making the decision in the second half of the year. The Nanushuk project is expected to produce up to 120,000 barrels of oil per day once it is fully developed. According to the report, Oil Search has cut its project development spending in Alaska this year by about $10 million and its exploration and appraisal budget in the state by about $70 million just in the past six weeks in response to collapsed global energy markets. The company previously planned to spend between $335 million and $415 million on exploration and development activities in Alaska this year. It spent $68.9 million on North Slope development activities, such as laying gravel for roads and drilling pads, in the first quarter, according to the report. Oil Search produces oil and natural gas from fields it operates in Papua New Guinea; the company does not yet have any production in Alaska. Companywide, the 2020 spending plan has been cut nearly 40 percent, or roughly $300 million. Last October Oil Search announced it was taking steps to move up its initial production timeline on the Nanushuk project from late 2023 to 2022 in part by utilizing oil processing facilities at Kuparuk until the Nanushuk facilities are operational. Oil Search’s operating revenue fell by 20 percent to $359 million in the first quarter compared to the end of 2019 primarily due to down oil and gas markets. Alaska North Slope oil prices have settled in the $10 per barrel range in recent days following a brief period of going negative as oil production far exceeds current demand worldwide. Managing Director Keiran Wulff said the company’s actions have put it in a good place to “weather a potentially protracted period of global disruption” brought on by the COVID-19 pandemic. “While the company is now in a robust position to withstand a sustained period of low oil prices, we are undertaking further measures to drive down breakeven costs across our business, targeting a reduction in production costs of $1-$2 (per barrel of oil equivalent), and to enhance our capital management programs,” Wulff said in a formal statement. “This will ensure we are in a good position to progress our world-class growth projects in Papua New Guinea and Alaska when market conditions improve.” The Mitquq and Stirrup exploration wells, drilled on state leases outside of the Pikka Unit, provided Oil Search with additional geologic and well productivity data from the Nanushuk oil play that will help support future development, according to the report. The Mitquq well and sidetrack well located just east of the Pikka Unit hit a net pay zone of 172 feet and consistently flowed 1,730 barrels per day during a flow test. Mitquq also hit gas and oil in the Alpine C formation across 52 feet of net pay. The Stirrup well, drilled about 20 miles southwest of Pikka, hit an oil column with net pay of approximately 75 feet in the shallow Nanushuk reservoir and flowed 3,520 barrels of oil per day during a test, which is one of the highest flow rates yet from the play for a single-stage stimulation of a vertical well, according to the report. An Oil Search Alaska spokeswoman Amy Burnett wrote via email that the company is encouraged by the results but it will be some time before the drilling results can be incorporated into the company's overall resource estimates for the Nanushuk play. Oil Search completed an $850 million buyout of Armstrong Energy and a silent owner in Pikka in 2018 to take a 51 percent operating stake in the unit. Spanish major Repsol holds a 49 percent interest in the Pikka Unit and its Nanushuk oil project. Efforts to sell a 15 percent stake in the project have also been suspended, but company leaders are continuing discussions with parties that were interested prior to the recent oil price collapse, the report states. Elwood Brehmer can be reached at [email protected]

Budget picture gets worse with TAPS flow cut

Alaska’s finances are deteriorating so fast it’s even hard for the professionals tasked with doing so to keep up. Legislative Finance Director Pat Pitney told the House Finance Committee on April 22 that the Department of Revenue’s updated spring revenue forecast — which looked bleak when it was released April 6 — is likely “very optimistic” given what happened in the interim. That’s because what started as a small budget surplus before the Legislature approved this year’s Permanent Fund dividend distribution of $1,000 per eligible Alaskan, required supplemental spending and COVID-19 gripped the world has turned into a $1.3 billion deficit this year that will likely be at least $1 billion next year, according to Legislative Finance calculations. Revenue officials revised their spring forecast downward by nearly $530 million based on Alaska oil prices generally being below $30 per barrel for the rest of the 2020 fiscal year, ending June 30. At the time, Alaska North Slope Crude was selling in the $30 per barrel range following a broad agreement by major producing countries to cut global production in May by nearly 10 million barrels per day, or about 10 percent of total oil production worldwide. However, the promise of major oil supply cuts was still not enough to offset the demand drop from a global economy idled by COVID-19 work and travel restrictions. On April 20, domestic market oil prices fell into the red with the price of Alaska oil falling by $18 in a single day to -$2.68 per barrel, which Legislative Finance analyst Alexi Painter called a “paper negative” driven by trades in the futures market. While, according to Painter, there likely was no oil actually traded at a negative price and the price quickly rebounded to $9.01 per barrel the following day, it is an apropos descriptor of the State of Alaska’s fiscal situation. Civic-minded Alaskans are very familiar with the mantra that the state needs to fix its structural budget deficit as the debates over spending cuts and taxes have dominated lawmakers’ time since oil prices started falling in late 2014. Lawmakers off all stripes have routinely been sharply criticized — and voted out of office — for supporting unpopular budget remedies. But Pitney, former Gov. Bill Walker’s budget director, briefly revisited that history to illustrate just how drastically the State of Alaska’s fiscal picture has changed in less than 10 years. She noted that the state took in nearly $9 billion of petroleum-generated tax and royalty revenue in 2012. The “very optimistic” projection for this year is just less than $1.1 billion. The 2021 budget passed in late March calls for more than $5.1 billion of state spending, but Pitney noted that both the 2020 and 2021 deficits could grow further with supplemental spending packages needed to combat the effects of the pandemic and other, more common needs, such as wildfire suppression. “That traditional revenue stream is gone and with the price volatility and the uncertainty in the demand drop the coronavirus has brought, that less than a quarter of our revenue stream and our budget needs from oil is probably something we need to get used to,” she said. Alaska oil has temporarily stabilized in the $10 per barrel range in the days since and the Revenue Department expects Alaska oil to average just $37 per barrel in fiscal year 2021. Painter noted that at $10 per barrel companies are barely able to cover the cost of transporting the oil from the North Slope to West Coast markets. “The breakeven for all oil company spending is generally around $40 (per barrel) in Alaska, so even at the forecast price of $37, which would be a substantial increase from where we are, the companies are losing money,” he said. In 2018 lawmakers thought they had solved the majority of the structural budget imbalance by approving an annual 5.25 percent of market value, or POMV, on the Permanent Fund; it drops to 5 percent in 2022. The predictable POMV draw will grow from $2.9 billion this year to nearly $3.1 billion in 2021, but the state will feel the impacts of the COVID-19 pandemic through the POMV for years to come. The lost value of the Permanent Fund from recent financial market declines means the POMV will be $47 million less than previously expected in 2022. The annual POMV revenue forgone from a poor 2020 will peak at about $300 million in 2027, according to Pitney, before the year falls out of the five-year trailing average window used to calculate the POMV. That’s all based on the fund ending fiscal 2020 with a balance of $63.1 billion and immediately returning to its historical 7 percent historical return average. As of April 27, the fund had an unaudited value of $62.5 billion, up from $60 billion at the end of March. It peaked in late January with a total balance of nearly $67 billion. On top of all that, Aleyska Pipeline Service Co. said April 24 that it had begun to cut Trans-Alaska Pipeline System throughput by about 50,000 barrels per day to deal with a lack of oil storage capacity projected for late May in the system. Reducing TAPS throughput directly translates to less money for the state, but exactly how much will be forgone is unclear at this point due to a host of ever-changing variables. What is clear is that the original fiscal year 2020 North Slope production forecast of 492,000 barrels per day — another fundamental factor in the revenue estimates — will not be met. TAPS throughput for 2020 averaged 485,583 barrels per day immediately following the throughput cut. Pitney said before Alyeska confirmed the throughput proration that the Constitutional Budget Reserve, which once held roughly $14 billion and lawmakers have relied on to backfill annual deficits, will be down to $1.4 billion by the end of June and is likely to be functionally exhausted in a little more than a year without making structural budget changes. The Department of Revenue uses the CBR to manage daily cash flow and its March 31 balance of nearly $2.2 billion includes $465 million held in the state’s General fund as short-term cash flow borrowing, according to Pitney. She added that turning to the Permanent Fund’s $16 billion Earnings Reserve Account to backfill what the CBR can’t also has long-term consequences. Each $1 billion pulled from the account — which is the spendable portion of the Permanent Fund — beyond the POMV draw translates to $50 million less available each year in perpetuity. “We have to address the structural budget deficit soon and it’s going to be continued budget reductions, but it’s also got to be new and diversified revenue sources,” she said. “Changing the dividend formula is not enough to close the structural budget deficit.” Elwood Brehmer can be reached at [email protected]

Upside down: Alaska crude prices chart negative territory

Market forces that not long ago pushed refiners to pay a premium for Alaska oil have been turned upside down, further depressing an already collapsed oil market and deepening the financial pain of producers and the state. Alaska North Slope crude sold for an unprecedented price of -$2.68 on April 20, a daily drop of $18.09 according to the state Department of Revenue. At prices near zero, North Slope producers are losing an average of more than $30 on each barrel and oil royalty and production tax revenue to the State of Alaska is nonexistent. Longtime Alaska petroleum economist Roger Marks noted that while the prices for Alaska and West Texas Intermediate, the primary benchmark for Lower 48 oil are shockingly low — WTI sold for -$37.63 on April 20 — the price for Brent crude stayed relatively stable at $25.57 with a daily drop of just $2.51. The price for Alaska oil rebounded somewhat April 21 to $9.01 per barrel and WTI was back to $10.01 per barrel at the end of trading. Brent is the primary benchmark price for many of the water-borne oil trades made worldwide. The name originated from the Brent oil field in Europe’s North Sea. Marks said it’s possible just a small number of “distressed” sales by sellers needing to find a place to offload their oil in a vastly oversupplied market could have contributed to driving the ANS price down further. “ANS is a pretty thin market. There’s just a few sales a month that drive the public market,” Marks said. The vast majority of ANS oil is exported from Valdez to West Coast refineries and transportation constraints limit the amount of oil produced east of the Rocky Mountains that can be sent west. That soft barrier has led to the development of ostensibly two oil markets in the U.S. Per state regulations, Revenue officials estimate daily ANS price in part via reports from Reuters and Platts reporting services. There is no instant spot price data for the ANS market as there is for more widely traded oil benchmarks. The fact that the West Coast oil demand is largely from transportation — a sector hit particularly hard by the virus-induced economic shutdown — just adds to the challenges for those selling ANS crude, Marks said. He also said much of the oil refined in state is traditionally used to produce jet fuel, for which demand has all but dissipated as well. “If you want to buy (ANS crude) you can really lowball them right now,” Marks said. Chief Department of Revenue Economist Dan Stickel said state officials have also heard reports of West Coast refiners slowing their production due to COVID-19 infections among refinery personnel. Analysts expect extremely low or even negative oil prices to be a short-term phenomenon, as prices globally have not bottomed out to the degree of U.S. oil markets that appear to be even more saturated. According to the Energy Information Administration, West Coast refineries processed an average of 1.75 million barrels per day in the week ending April 10, which was down nearly 20 percent from more than 2.1 million barrels per day a year ago. The U.S. had a 35-day supply of oil as of April 10, the most recently available data. That is up about 25 percent from a year prior, according to the EIA. Recent reports worldwide have indicated oil tankers are being used as storage vessels in some instances where traditional storage means are full. Marks said Brent futures for June are still in the $30 per barrel range, indicating buyers feel there will be at least a little more balance to oil markets as global production is scaled back. “Not that $30 is good but at least there’s the right symbol in front of it,” he said. “(Oil prices) will come back. The world’s in a very, very weird place these days on a number of fronts and oil prices are just a response to that.” Leaders from the world’s top oil producing nations on April 12 announced a global agreement to cut 9.7 million barrels from daily production in May, or about 10 percent of oil production worldwide. The spread between the ANS and global Brent prices that is now hammering Alaska was benefiting the state just a few months ago. As recently as January ANS crude was trading at a $2 per barrel premium to Brent and in prior months Alaska oil had sold for up to nearly $4 per barrel more than Brent. At the prior price plateau of $60 to $65 per barrel, each dollar to the positive netted the State of Alaska an additional $42 million over the course of a year, Tax Division Director Colleen Glover said at the time. Industry observers then attributed the positive — for Alaska — differential to increased exports from Valdez to South Korea and President Donald Trump’s re-imposed economic sanctions against Iran that restricted the country’s ability to export oil. However, Marks, Stickel and other oil industry analysts have said ANS crude has been forced to compete with more Middle East oil of late on the West Coast, particularly from Saudi Arabia. Sen. Dan Sullivan has been among members of Congress pushing the administration to respond to Saudi Arabia’s part in flooding oil markets. Trump said April 20 his administration is considering a ban on Saudi oil imports in an attempt to stabilize domestic oil prices. An oil price war between Russia and Saudi Arabia ostensibly ended with the April 12 deal, but the full effect of the drastic production cuts isn’t expected until May and the consequences of the conflict, which started after the countries couldn’t agree to a production cut in February, have already been felt. Oil imports to the West Coast averaged just more than 1 million barrels per day during the four-week stretch ending April 10, a 9 percent year-over-year increase, according to the EIA, while refiners are using much less. Stickel emphasized that even though the current price situation is a scary one for the state’s finances, it’s not nearly as bad as it would have been a few years ago. That’s because since the Legislature and former Gov. Bill Walker approved an annual structured draw from the Permanent Fund’s earnings in 2018, oil now accounts for less than 20 percent of the state’s unrestricted revenue, he said. The Permanent Fund draw provides roughly $3 billion per year to state coffers. Stickel noted that revenue from oil and gas property taxes, which generated $121 million in 2019, is stable regardless of prices. Corporate income taxes from the large producers, on the other hand, will likely be “very minimal” in fiscal 2020, he said. Oil and gas corporate taxes netted $217 million to the state last year, according to the 2019 Annual Tax Division Report. Stickel also said oil production tax calculations are made based off of monthly average prices, so a given day or cluster of days with highly abnormal prices will not dramatically alter the overall calculation. Additional provisions of the state’s blended gross-net production tax system are based off of calendar year prices, making it even less likely that the immediate situation will significantly impact state finances over the long-term. The 4 percent gross tax “floor,” — which kicks in when the gross production tax calculation is greater than the net tax payment — gradually steps down to zero if prices average less than $25 per barrel for a calendar year. ANS prices have averaged about $45 per barrel so far in calendar 2020. The Revenue Department’s official forecast published April 6 for the average price in state fiscal year 2020, which ends June 30, is $51 per barrel. Alaska oil was selling for about $28 per barrel at the time. Additionally, the state receives royalties of at least 12.5 percent of the gross value of the vast majority of oil produced on the North Slope. Royalties are calculated based on the wellhead value of the oil minus transportation costs, which average about $9 per barrel, according to the Revenue figures. “As long as prices are above that (transportation cost) level, there will be a gross value so we’ll get some royalty,” Stickel said. If prices stay extremely low much longer than expected, issues between state auditors and producers could arise from having to interpret portions of the production tax law that haven’t previously been considered, he surmised. “It’s kind of an unprecedented situation,” Stickel said. Marks added that an extended period of ultra-low ANS prices could also lead producers to curb production beyond deferring drilling and other capital expenses. “The last place you can store oil is in your reservoir,” Marks said. “You can’t shut down an oil field but you can throttle it back.” That would go against traditional state policies that typically require companies to produce what they are capable of, but Marks said it could benefit both parties to wait until prices improve — if that’s what the markets eventually dictate. ConocoPhillips announced April 16 it would be cutting production by approximately 225,000 barrels per day in the Lower 48 and Canada. Division of Oil and Gas spokesman Sean Clifton wrote in an emailed response to questions that North Slope oil production typically hasn't fluctuated with oil price swings in part becasue it is sold on futures contracts negotiated well before the oil is produced and delivered. Clifton also noted that maintaining a certain level of throughput in the Trans-Alaska Pipeline System, or TAPS, is important for the operational integrity of the pipeline and upstream assets. Leaders at Alyeska Pipeline Service Co. have said there could be operational challenges with TAPS if daily throughput consistently falls below about 300,000 barrels per day; the pipeline currently carries roughly 500,000 barrels of oil per day. Division of Oil and Gas officials are holding discussions with producers to ensure a balance between resource development, infrastructure integrity and commercial sales, according to Clifton. ^ Elwood Brehmer can be reached at [email protected]

Hendrix bid to acquire Furie revived with AIDEA loan

An Alaskan bid for a struggling Cook Inlet gas producer appears to be back on following revisions to a state-backed loan for the purchase. The Alaska Industrial Development and Export Authority board of directors on April 15 approved technical changes to a March 4 resolution authorizing a loan up to $7.5 million to Hex LLC, a company formed late last year by longtime Alaska oil and gas industry player John Hendrix. Hendrix, through Hex, submitted the winning $15 million bid in a December bankruptcy auction for Furie Operating Alaska, a small Texas-based natural gas producer that operates the Kitchen Lights Unit and has contracts to supply a handful of Southcentral utilities. Originally from Homer, Hendrix was general manager of Apache Corp.’s operations in Cook Inlet prior to becoming former Gov. Bill Walker’s oil and gas policy adviser in 2016. But February court filings by Hex in Furie’s ongoing Chapter 11 bankruptcy case asserted that the auction was advertised as an asset sale but conducted as an equity sale to keep Furie in control of its Inlet operations and eligible to receive outstanding refundable tax credit payments from the state. In its bankruptcy filing, Furie claimed $105 million in outstanding credits owed by the state. Uncertainties stemming from a royalty claim filed by three minority owners in the state leases that Furie operates are alleging collectively shorted them an estimated $50.7 million also prevented Hex from obtaining financing for the sale, Hex attorney David Bundy wrote at the time. Attorneys for Furie and its primary lenders countered in separate court filings that Hex did not negotiate “in good faith” during the process, an allegation Bundy disputes. With Hex unable to finance the purchase, one of Furie’s primary lenders New York-based Melody Capital Partners LP attempted an acquisition by foreclosure through a firm it formed with GFR Holdings LP of Dallas, Kachemak Exploration LLC. Melody Capital Partners was one of several lenders that collectively loaned approximately $244.5 million to Furie, according to court filings. However, Hendrix told the AIDEA board April 15 that he recently signed an agreement to acquire Furie and his company is now moving towards a June 30 closing date. An omnibus court hearing is scheduled for May 8. Hendrix and others involved in the case have declined to discuss details of the proceedings as they are ongoing, but he said to AIDEA leaders that he hopes to increase in-state employment within Furie. Sources said the global recession that has accompanied the COVID-19 pandemic and caused significant downturns in financial and energy markets largely scuttled the Kachemak Exploration proposal. Hendrix said Furie works with Alaska-based contractors, but the company’s workforce is mostly Lower 48 workers. According to a memorandum outlining the $7.5 million loan, Hex’s purchase would initially provide 15 new resident jobs on the Kenai Peninsula and support another 300 indirect jobs. “We see a great opportunity to — it’s called studying the rocks and getting back to base management,” Hendrix said to the AIDEA board, adding that he hopes to look for more drilling opportunities for oil and gas. Furie officials said in 2017 they planned to work on developing oil prospects in the Kitchen Lights gas field, but those plans were largely scuttled because of the state’s delay in repaying millions of dollars in oil and gas tax credits the company earned for its previous work, according to the company’s filings with the state Division of Oil and Gas. The company filed for Chapter 11 bankruptcy protection Aug. 9 in federal Bankruptcy Court for the District of Delaware. According to the company’s bankruptcy petition, Furie owed lenders approximately $440 million when it filed for Chapter 11 protection and was also owed roughly $105 million in refundable tax credits from the State of Alaska. The company installed the Julius R platform in the Kitchen Lights field in 2015, which at the time was the first new production platform the Inlet built since the 1980s. Furie officials estimated the value of the company’s assets at between $10 million and $50 million in their initial bankruptcy filings. The financial challenges were nearly continuous for the company, which had net gas sales of $25.4 million and absorbed a net loss of $58.5 million in 2017, according to the bankruptcy filings. The situation worsened in 2018 when the company sold $42.8 million of natural gas but took a loss of nearly $152 million. Furie lost $21.4 million in the first quarter of 2019, when a freeze-up in a gas production pipeline kept the company from supplying HEA and Enstar with gas for more than a month. Once gas deliveries resumed, Furie was only able to supply Enstar with less-than-contracted amounts for several months as well. Elwood Brehmer can be reached at [email protected]

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