Elwood Brehmer

Hilcorp agrees to operate Point Thomson

ExxonMobil is in the process of transferring operations at its Point Thomson gas field on the North Slope to Hilcorp Energy, according to representatives of both companies. An agreement signed Oct. 19 calls for Hilcorp to take over as operator at Point Thomson early next year presuming the requisite state regulatory approvals are secured. ExxonMobil Alaska spokesman Hans Neidig said there is no change in ownership associated with the arrangement. ExxonMobil owns 62% of the eastern North Slope field, which started producing natural gas liquids in 2016. Hilcorp purchased BP's 37% stake in Point Thomson as part of its $5.6 billion takeover of the London-based major's Alaska assets. Other parties collectively own less than 1% of Point Thomson. “This change takes advantage of Hilcorp's scale and experience operating North Slope assets and allows the Point Thomson working interest owners to contribute our respective strengths to the value of the asset,” Neidig said. No cash changed hands in the deal. Hilcorp took over operations at Prudhoe Bay from BP in June 2020. Prudhoe Bay and Point Thomson are seen as primary sources of natural gas for the state's long-sought pipeline and LNG export project. Hilcorp Alaska Senior Vice President Luke Saugier said the company is excited to continue its commitment to Alaska in a prepared statement.  “We welcome the opportunity to apply our proven record of enhancing conventional assets to Point Thomson,” Saugier said. Hilcorp has leaned on its business model of extending the life of mature assets to steadily increase its position in the state since entering the Cook Inlet basin approximately a decade ago. The Point Thomson deal will impact 38 ExxonMobil employees, according to Neidig, who said they would be able to interview with Hilcorp or be repositioned within ExxonMobil, possibly outside of Alaska. ExxonMobil agreed to construct Point Thomson in 2012 at a cost of roughly $4 billion. Development of the high-pressure gas field was a key precursor to a large LNG project.   Elwood Brehmer can be reached at [email protected]

With last grants, Exxon Valdez oil spill council provides funding for cultural preservation

Little, if any, money from the $900 million Exxon Valdez oil spill settlement remains unspoken for. But much of the last round of funding was distributed with an eye toward investments in facilities and resources that numerous Alaska Native organizations and some current stewards of the settlement funds say were long overdue. Exxon Valdez Oil Spill Trustee Council members unanimously approved approximately $150 million in grants for research and restoration of habitat and resources impacted by the 1989 oil spill during their Oct. 13 meeting. Among the largest funding proposals approved was $8 million for expanding the Alutiiq Museum and Archeological Repository in Kodiak. Following the council’s vote on the proposal, Alutiiq Museum Executive Director April Laktonen Counceller said that the renovation and expansion will address all of the major issues identified in a 2019 survey of the museum’s audience. “The museum will transform its entire first floor into a public space. The exhibit gallery and store will be significantly enlarged, and a classroom created. Here, the museum will be able to meet with elders, hold classes, and host receptions,” Counceller said. “We are going to create a living culture classroom — a place where people can gather to share knowledge and celebrate traditions.” Work on the museum, which currently houses a collection of roughly 250,000 artifacts, is scheduled to start in February. Grant funding will also be used to build a new vault in the museum’s basement. The original vault was filled about 10 years ago, according to museum leaders. The initial funds to build the Alutiiq Museum largely came from a 1993 EVOS Trustee Council grant. Current council chair and Department of Environmental Conservation Commissioner Jason Brune said in an interview after the meeting that it was important for the state trustees, who include Fish and Game Commissioner Doug Vincent-Lang and Attorney General Treg Taylor, to make sure there is long-term funding in place for continuing operations at the Alutiiq Museum, as well as other facilities and organizations that arose from the spill. Helping the museum expand and improve its operations is one way to do that. “The anthropological resources, cultural resource efforts have really been overlooked and it’s important to ensure they will be appropriately preserved for generations,” Brune said. He added that several trustees were able to tour the museum and better understand what leaders there wanted to do. Shauna Hegna, president of Koniag Inc., the Kodiak-area Alaska Native regional corporation, said she is thrilled the council made the decision to invest in the museum, which coincides with Koniag donating a portion of the building. The first floor of the building was built with EVOS council funds and Koniag has worked over the past year to purchase the basement of the building, which will be turned over to the nonprofit for the renovation. “The Alutiiq Museum will now own its facility and be able to renovate it,” Hegna said. She thanked the trustees for reviewing the museum proposal and others focused on cultural priorities impacted by the oil spill that previously had little opportunity to secure EVOS funding — $6.8 million for a new Chugach Heritage Foundation Museum and $2.4 million for subsistence resource camps in the Chugach region. The lion’s share of projects the council historically funded were scientific research and habitat restoration efforts. Numerous projects in those realms were also funded Oct. 13. Chugach Corp. Executive Vice President Josie Hickel echoed Hegna’s sentiment in regards to the broader proposal review, adding it is one of several improvements Chugach leaders feel the council has made in recent years. She highlighted the support for culture camps aimed at rejuvenating subsistence activities in the Chugach region as recognition of a major facet of life that was almost completely lost in many spill-affected areas. “Subsistence was one of those things that was drastically and immediately impacted by the spill,” Hickel said. “That disruption caused a generation of young people to not learn subsistence practices.” She added that she believes an ultimately unsuccessful stakeholder-led effort to encourage the council to move its last roughly $200 million into an endowment to maintain funding for decades caused council leaders to rethink their approach, at some level. According to the trustees, a legal opinion from the Justice Department precludes putting the remaining EVOS funds into a traditional endowment fund; that would require an act of Congress. Brune said that in the alternative, the council funded several 10-year science programs to stretch out the money. A former member of the EVOS Public Advisory Committee, Brune said he and other trustees worked to improve the transparency in the funding process by voting on each of the 65 proposals submitted. Previously, it was much more difficult for unsolicited proposals to garner the attention needed to get funded, according to Hickel and others. The remaining $10 million-$12 million in unencumbered funds — as of Friday, council staff were still crunching the final numbers for several proposals amended or partially funded at the meeting — will mostly go to staff and expenses for administering the outstanding grants as the EVOS Trustee Council gradually “winds down,” Brune said. He expects to hold another council meeting over the winter to determine the council’s budgeting but then only hold meetings every several years or on an as-needed basis. The trustees have traditionally held at least one full council meeting each year. “We’re trying to put as much money into restoration and science-based efforts, as well as those legacy facilities,” he said, noting the trustees were presented with more than $250 million in proposals when they had approximately $160 million to distribute. “We put our money where our mouths were and funded what should be funded,” he said. Elwood Brehmer can be reached at [email protected]

ConocoPhillips and Biden administration won’t appeal court ruling blocking Willow permit

With the deadline to appeal an August court decision come and gone, it appears federal approval for ConocoPhillips’ massive Willow oil project on the North Slope will be subject to at least a partial do-over, all but ensuring the development will be delayed multiple years. Environmental and Alaska Native groups successfully sued the Bureau of Land Management over the agency’s approval of the environmental review for the major oil development, which took place under the Trump administration. On Wednesday, those groups thanked BLM officials under President Joe Biden for not appealing the August court ruling invalidating the permit. But they also acknowledged that the Houston-based oil major has given every indication it will not drop the 100,000-barrels-per-day-plus oil prospect. “The Biden administration’s decision not to appeal comes as good news. It also comes as the same old news, because we know that ConocoPhillips will continue to pursue this harmful extraction project on Iñupiat lands,” Sovereign Iñupiat for a Living Arctic Executive Director Siqiñiq Maupin said in a statement. “We know the real impacts on our bodies and communities. We know that fossil fuel industrialization is an attack on our health and food security. What oil corporations seeking to exploit our homelands need to know is that Indigenous groups around the country are united. We will, alongside our climate and human rights allies everywhere, continue to protect the lands and waters our ancestors protected for us.” Tuesday was the deadline for attorneys for the Justice Department and ConocoPhillips to appeal an August order from Alaska District Court Judge Sharon Gleason, throwing out BLM Alaska’s October 2020 approval of the Willow Master Plan environmental impact statement. Gleason ruled that BLM officials erred in, among other things, not sufficiently justifying their rationale for not estimating the project’s likely contribution to foreign greenhouse emissions. That was in part due to a 2020 9th Circuit decision that vacated the environmental review for another North Slope oil project approved by the Trump administration. In that instance, the court ruled that the Bureau of Ocean Energy Management’s approval for Hilcorp Energy’s offshore Liberty project was “counterintuitive,” in that the agency concluded that not developing the oil would result in greater foreign greenhouse gas emissions. ConocoPhillips Alaska spokeswoman Rebecca Boys said in an email that company leaders opted not to appeal because they felt the best path forward is to resolve the issues highlighted in Gleason’s decision directly with the agencies. “We, and many important stakeholders, remain committed to Willow as the next significant North Slope project,” Boys wrote. “The merits of the project represent a strong example of environmentally responsible, low cost of supply development that offers extensive benefit to the public and the residents of the North Slope, including significant employment of Alaskan skilled labor from union and non-union trade associations and revenue for federal, state, borough and local governments.” At $6 billion to reach first oil and up to $8 billion to fully develop, oil industry advocates see Willow as an infrastructure hub on the western North Slope that could spur other oil projects in the otherwise mostly undeveloped National Petroleum Reserve-Alaska. ConocoPhillips had targeted the winter of 2025-2026 for first oil production from Willow, and estimated the project would generate up to 2,000 construction jobs over several years of development. Bridget Psarianos, a lead attorney for SILA and the coalition of environmental groups, said she was not caught off guard that Interior Department officials and ConocoPhillips, which intervened in the suit, did not appeal. “I think given the similarities with our case and the Liberty decision, which the 9th Circuit pointed to when we won our injunction back in February, we would’ve been a little surprised if they would’ve taken an appeal to the 9th Circuit,” Psarianos said. In February, the 9th Circuit ordered fieldwork stopped at Willow largely before it started. ConocoPhillips had planned to open a gravel pit and begin laying gravel for roads and pads last winter before the ruling. The appeals court then sent the case back to Gleason, who then issued her broader August ruling invalidating the environmental review. Interior spokeswoman Melissa Schwartz declined to comment on the decision not to appeal Gleason’s ruling, but said BLM officials are determining their path forward in regards to Willow’s federal permits. BLM’s initial environmental review and approval for Willow took slightly more than two years. It’s unclear how long a supplemental review or entirely new review would take, but it would likely be a multi-year process based on similar situations in the past. Longtime Alaska oil industry attorney and analyst Brad Keithley said he believes the agency and company may have taken the more expeditious route to keep moving Willow forward by not appealing. That’s particularly true if the Biden administration still backs the project, he added. “If (the Biden administration) wants to make this work, I think they can pull together the supplemental EIS in the short-term. If they view this as an opportunity to shut down development in the Arctic or set a precedent that’s going to apply to other projects — ANWR and elsewhere — then I think that’s what is going to lengthen it out,” Keithley said. In May, attorneys for BLM filed court briefs backing the approval of Willow, which drew the ire of the same groups now commending the administration for withholding an appeal. Psarianos said her clients want BLM to improve the public involvement process, which was disrupted by the onset of the pandemic, for any future Willow review and take a much more holistic look at the project’s potential consequences. “I think they really need to take a step back, gather baseline information and engage with the communities most impacted by the project,” Psarianos said.   Elwood Brehmer can be reached at [email protected]  

Alaska Air Group returns to profitability without pandemic aid

Alaska Airlines stood up on its own in the third quarter for the first time since the pandemic began, company executives said in a Thursday earnings call with investors. Alaska Air Group Inc., which also owns regional carrier Horizon Air, reported  $194 million in third quarter net income without COVID-19 financial assistance from the federal government. The profit stands in stark contrast to the $431 million loss the airline company endured a year ago. CEO Ben Minicucci said the turnaround exemplifies the success of Alaska Air Group's approach to maintaining discipline in its balance sheet and operations. He noted the final pre-tax earnings margin beat internal projections of 10%for the quarter. “Our 12% pretax margin solidly led the industry and was just six points shy of our third quarter 2019 margin,” Minicucci said. “I'm proud of how our company is recovering strong from the pandemic.” Alaska Air Group netted $397 million in the second quarter — it's first after five consecutive losses totaling more than $1.5 billion — but that was the direct result of more than $660 million in federal pandemic relief loans and grants the company accepted during the period. Without the federal aid and other special items, Air Group would've reported a $38 million second quarter loss, according to company executives. Minicucci attributed the rebound to pent-up leisure travel demand and thanked the company's employees for their strong performance in a fluid environment. Activity around theFourth of July and Labor Day approached 2019 levels. Customer service metrics have exceeded internal targets each month of the quarter, according to Minicucci. “Sustaining operating performance with high guest satisfaction is a remarkable achievement given how complex re-ramping our operations has proven to be,” he said. Minicucci is planning for Alaska Air Group to return to its pre-pandemic size “no later than next summer and then grow from there,” he said. Air Group added back nearly 4,300 employees last quarter, which correlates to 27% growth in the company's workforce. The $194 million third quarter profit was generated on the back of more than $1.9 billion in total revenue, nearly triple what the company generated a year ago. The income translates to net earnings of $1.53 cents per share. Alaska Air Group stock traded $54.49 per share near the end of trading Friday, which was down from a pre-earnings open price of $57.23 per share despite the reported profit. Chief Financial Officer Shane Tackett said Alaska Air Group's healthy liquidity and balance sheet should give company leaders the flexibility to reinstate shareholder distributions later in 2022, while also funding a large order of new Boeing 737-900 aircraft. Alaska Air Group ended the quarter with $3.6 billion in total available cash, including unused credit, which was down from $4.4 billion after paying down nearly $550 million in debt and making a $100 million voluntary contribution to employee pensions, which are now 94% funded, according to Tackett. The pension payment allowed Alaska Air Group to capture a one-time, $14 million tax benefit, he said. Cash from operations was “essentially breakeven” in the quarter, Tackett said, adding operational cash flow will likely be slightly in the negative, up to $100 million. But company leaders ultimately expect to net up to $100 million if Alaska Air Group's 2020 tax refund comes as expected. Chief Commercial Officer Andrew Harrison said load factors, or the percentage of seats filled by revenue customers, dropped from 88% in July to 72%, largely due to the emergence of the delta variant across the country. Fourth quarter bookings are being impacted, as well, he said. “The consequences from the delta variant have not yet dissipated and we're still working to build back Q4 bookings that were lost from the fourth COVID wave, given it occurred during an important period for building fourth quarter traffic,” he said. Despite the broader, immediate challenges, demand for first-class and premium seating has exceeded 2019 levels and should be sustained as business travel returns, according to Harrison. Alaska Air Group additionally netted its largest cash payment ever from its credit card loyalty program, up 7% from the same period in 2019, he noted. “Our loyalty program is one of the most durable, competitive advantages and we are squarely focused on maintaining and improving this momentum over the coming quarters,” Harrison said. Relatively high oil prices are likely to add marginal costs over the coming quarters if they hold, according to Tackett, despite the fact that 50% of the company's expected fuel consumption is hedged over the next six months. Fuel hedging has saved the company about 11 cents per gallon this year as oil prices have climbed, he said. Despite a contracted workforce, overall per-unit costs have been higher than pre-pandemic levels and were 9.3% over 2019 levels, but still beat internal projections in the third quarter, according to Tackett. He expects unit costs to drop as Alaska Air Group's airlines continue to bring back capacity, even with higher fuel prices and upward pressure on entry-level wages. “Notwithstanding the headwinds, we will emerge as an airline with a cost structure equal or better than 2019 in short order,” Tackett said. Operating costs will also be aided by the addition of many new, more efficient Boeing 737-900 aircraft in the coming years, he said. Alaska Airlines currently has seven Boeing  737 “dash nines,” as they are known in the industry, and should have 93 by 2024 with options for 52 more, according to Minicucci.  The new Boeing fleet will replace the Airbus aircraft acquired in Alaska's 2016 purchase of West Coast rival Virgin America, and also positions the airline for significant growth when demand fully recovers, Minicucci said.   Elwood Brehmer can be reached at [email protected]

Despite low expectations for special session, Alaska House plugs away on fiscal policy

Official business in Alaska’s Capitol has been limited, but there is, in fact, still an ongoing special legislative session. House lawmakers have led most of the work, aimed at addressing the state’s long-standing structural fiscal imbalance. Senate business has largely been kept to the requisite technical floor sessions — brief formal proceedings to keep the session active — and hearings of the joint Redistricting Board. House Ways and Means Chair Rep. Ivy Spohnholz, D-Anchorage, has held meetings in recent days out of the Anchorage Legislative Information Office, focused on legislation promoting the multi-pronged approach to raise revenue and curb spending growth that most House majority members have generally endorsed. Most legislators have attended hearings by phone or videoconference from across the state. Spohnholz on Oct. 13 reemphasized her support for a 25-75 split of the $3 billion-plus in annual Permanent Fund earnings available for spending under the Legislature’s 2018 formula. It calls for spending no more than 5% of the fund’s overall value in a given year, which she says is a key element of a comprehensive fiscal plan, along with legislation for an education head tax, fuel tax increases and revisions to the state’s oil tax system. Based on currently proposed legislation, those elements would combine for a $72 million deficit next fiscal year and a small surplus in fiscal year 2024, Spohnholz said, “so we could start to address our capital deferred maintenance deficit and also start to make strategic investments as needed.” Next year’s Permanent Fund dividends would be approximately $1,248 per eligible Alaskan under a split in which 25% of available fund revenue would go to dividends, and PFDs would gradually grow to $1,575 per person by 2028, according to Spohnholz. While PFDs would start out larger than this year’s amount of $1,114 per person, the 25-75 split is still just half of what Gov. Mike Dunleavy has demanded from legislators. Dunleavy said his intent in calling the latest special session, which started Oct. 4., was in part to push legislators to add to the PFDs being paid out this month. However, it became clear near the end of the prior session that ended in mid-September that substantive policy changes would be unlikely this year with many lawmakers fatigued from one of the busiest legislative years in the state’s history. A major sticking point all year has been the disparate projections on the state’s fiscal future coming from administration officials and the Legislature’s finance experts. Officials in the Department of Revenue focused on unexpectedly strong current oil prices; impressive near-term Permanent Fund and state pension fund returns; and forecasts for gradually increasing North Slope oil production as the basis for estimates of future deficits peaking in the $500 million-per-year range with Dunleavy’s proposed 50-50 PFD-government split of fund earnings. Legislative Finance Division analysts, on the other hand, continued to project near-term deficits of $1-billion-plus per year with no new revenues under the governor’s plan. The disagreement over the parameters of the long-term fiscal problem has made settling on a range of options to solve it similarly challenging. Additionally, in the previous session, administration officials presented conceptual options for new revenues — such as a sales tax and oil tax changes — that they said Dunleavy would be open to with stipulations, but Dunleavy has repeatedly downplayed the need for taxes in recent press briefings. Administration officials have mostly been absent from fiscal policy hearings so far this session. Spohnholz also introduced a new version of House Bill 141, her legislation to tighten the state’s existing spending limit during an Oct. 14 Ways and Means hearing. The bill would base future appropriations limits on prior years spending and adjustments for inflation and population changes. The starting baseline for 2023 would be nearly $5.8 billion, which is an increase over the earlier versions of the bill in recognition of the “historically low spending,” when accounting for inflation and population, the state has enacted in recent years, Spohnholz said. Lawmakers approved nearly $4.6 billion in unrestricted general fund spending so far this year. HB 141 would not count PFDs or the state’s portion of school construction bond debt reimbursement as part of the annual spending limit and would allow lawmakers to exceed the cap for certain capital and deferred maintenance projects. Members of the House Judiciary Committee heard an alternative plan for capping state spending that attempts to capture the performance of Alaska’s private sector in calculating how much money is needed for state government from Anchorage Republican Rep. James Kaufman Oct. 15. Kaufman’s uniquely linked House Joint Resolution 401 and House Bill 4006 would set a lower statutory spending limit of 11.5% of total state product and a higher constitutional spending cap at 14% of state GDP. The ostensive spending limit range would prevent significant spending growth in high revenue years but also provide a buffer for unforeseen expenses, according to Kaufman. While it is very unlikely the Legislature will pass significant fiscal legislation in the remaining two weeks of the special session, the current work can build momentum for the next regular session in January. “This appropriation limit is not attempting to drive draconian cuts; it’s more about trying to smooth out our economic planning, our forecasting, our spending,” Kaufman said. “It would shave off (spending) peaks and move them forward over time. It would create money going forward over time.” The current year budget would have fit within Kaufman’s lower proposed statutory limit with $16 million to spare if it were effective, and the 2022 constitutional cap would be nearly $6 billion, according to materials accompanying the legislation. Kaufman’s legislation also excludes school bond debt, PFDs and other state debt payments from the appropriations limits. Elwood Brehmer can be reached at [email protected]

Shell asks Alaska regulators for more time to find partners for North Slope prospect

Shell Offshore is asking Alaska regulators for more time to find partners to explore a remote North Slope prospect. In Oct. 6 filings recently posted to the division’s website, attorneys representing the subsidiary of Royal Dutch Shell asked Division of Oil and Gas officials for an extra year to secure a new operator for exploring the oil giant’s West Harrison Bay Unit. Oil and Gas officials last December approved formation of the West Harrison Bay Unit in state waters of the Beaufort Sea, north of ConocoPhillips’ $6 billion Willow oil project, as well as a multi-year exploration plan for the area. The exploration plan at the time called for Shell to bring in partners to spread out the costs and risks of drilling the area. That included finding a company willing to take on the operator role for the West Harrison Bay Unit by the end of 2021. Shell is proposing that deadline be pushed back to Dec. 31, 2022. According to the proposed amended exploration plan, Shell’s attempts to finalize commercial arrangements with other industry players continue to be hampered by the pandemic. That is despite Alaska North Slope oil prices in the $80-per-barrel range, which have recovered from an early 2020 collapse to now exceed pre-pandemic prices. Shell currently holds 100% of West Harrison Bay. “COVID-19 makes marketing the (West Harrison Bay) project more challenging as all meetings and negotiations have to be held virtually, and because the timing of execution of the project is uncertain due to logistical restrictions to operations, including surveying; and, until very recently, the low oil price suppresses the cashflow available to prospective investors for new projects and management appetite for new, higher risk exploration projects,” the second West Harrison Bay exploration plan states. Shell’s focus in the area is on the Nanushuk sands formation — the relatively shallow, conventionally produced oil-bearing geologic formation that is the primary source for the large Pikka and Willow developments, as well as a host of smaller North Slope prospects identified in recent years. Leaders of Oil Search Alaska, the company that has led exploration and development work at Pikka since 2018, have also acknowledged challenges they have had securing funding to construct the $3 billion first phase of the oil project. If Shell can put together a team for West Harrison Bay, the game plan is for the operator to drill an initial exploration well — and possibly a sidetrack — into the Nanushuk formation during the 2023-24 winter drilling season. A second well and potential sidetrack would be drilled in the 2024-25 season, according to Shell’s filings, after which time an additional exploration or development plan would be submitted to the division depending on the outcome of the drilling. The company is also asking state oil and gas officials to remove an expectation in the first exploration plan filed last year for the wells to penetrate the deeper Torok sands, which Shell claims would add unnecessary time and expense to the work and could jeopardize the timing of the overall program. The Torok zone was the primary target for Caelus Energy’s similarly situated Smith Bay prospect, discovered in 2016 to the west of Shell’s acreage. Caelus leaders said at the time the Smith Bay prospect could hold upwards of 6 billion barrels of oil, but appraisal drilling at Smith Bay was not conducted largely due to funding and logistical challenges associated with the isolated prospect.   Hilcorp plans more Prudhoe drilling Hilcorp North Slope expects to drill up to 10 wells next year into the western portion of Prudhoe Bay as oil prices continue to strengthen. According to the proposed 2022 Prudhoe Bay Unit Western Satellites Plan of Development recently filed with the Division of Oil and Gas, the Alaska subsidiary of Houston-based Hilcorp Energy plans to drill the wells into the Aurora, Borealis, Orion and Polaris participating area after restarting development drilling at Prudhoe earlier this year, following a pandemic-induced pause on development drilling work. In July, Hilcorp filed an amended 2021 Prudhoe plan with the division to drill up to six wells into the Orion participating area in the far western portion of Prudhoe. According to the 2022 development plan, one well was spud into the Orion area on Sept. 22 and the rest will be drilled the remainder of 2021 or possibly early next year depending on operational timing. Hilcorp increased oil production from the western Prudhoe satellite areas by 43% in the first year after taking over for BP, mainly through returning idle wells to service, targeting under-developed reservoirs and optimizing production through existing infrastructure, according to the filings with the state. Elwood Brehmer can be reached at [email protected]

Former Brooks Range executives seek second shot at Mustang

Some of the players in a failed North Slope oil project want to revive the state-backed field under a new name. Alaska Division of Oil and Gas officials in mid-September approved the transfer of state leases from Brooks Range Petroleum Corp. to Finnex LLC, according to documents recently published on the division’s website. Finnex is led by CEO Majid Jourabchi and Chief Operating Officer Harry Bockmeulen, who previously held the same positions at Brooks Range. Finnex was formed in June 2020 and is located in the same South Anchorage offices as Brooks Range, according to records filed with the state Division of Corporations, Business and Professional Licensing. Brooks Range was the Anchorage-based oil junior that, under a prior management team, first attempted to produce oil from the small Mustang project with $70 million of help from the Alaska Industrial Development and Export Authority, the state-owned development bank. AIDEA took control of the Mustang project in December 2020 following years of fits and starts by Brooks Range that ultimately led the authority to foreclose on the project assets in an attempt to recoup the $70 million authority officials invested in the Mustang development between 2012 and 2014. Division of Oil and Gas officials also issued a notice to Brooks Range on Sept. 9 that they had terminated two of the company’s North Slope leases for failing to pay rent on the acreage that was due Sept. 1. AIDEA officials have said they are working to eventually sell its share of Mustang assets. The authority has a 90 percent working interest ownership in the Southern Miluveach Unit that contains the oil prospect. The tipping point was when Brooks Range’s majority owner, Singapore-based Alpha Energy Holdings, failed to make good on loan payments to AIDEA stemming from a prior refinancing of the investment firm’s obligations to the authority. Jourabchi is also president of Houston-based Thyssen Petroleum, once a minority owner in Anchorage-based Brooks Range. Jourabchi told the Journal in May 2019 that he was part of a team of investors attempting to buy a majority stake in Mustang from Caracol Petroleum, a subsidiary of Alpha Energy. The Mustang field is adjacent to the southern portion of ConocoPhillips’ large Kuparuk River field and also near the Pikka 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. Brooks Range drilled test wells at Mustang in 2011 and 2012 that led AIDEA in December 2012 to take a stake in Mustang. The state oil lease interests approved for transfer to Finnex by TP North Slope Development, Brooks Range and Caracol are outside of the Southern Miluveach Unit, which holds the Mustang facilities, but Jourabchi said in an Oct. 12 interview with the Journal that Thyssen Petroleum submitted a proposal to AIDEA to purchase the Mustang assets with the intent of producing from the field quickly. Thyssen owns 85 percent of Finnex. “We feel it’s very credible,” Jourabchi said of the proposal. He also said Finnex has secured $35 million in financing to restart development of Mustang. “We feel we can get (Mustang) to production very quickly, but if it doesn’t happen, we have other ideas that clearly will take much longer,” Jourabchi said. Brooks Range briefly produced oil from Mustang in 2019 but a lack of funding prevented sustained production operations. A spokeswoman for AIDEA did not respond to questions about Mustang in time for this story. Full development of the field was initially estimated to cost about $580 million and included drilling 11 production and 20 more gas and water injection wells, according to AIDEA’s project documents. Brooks Range later changed its plans to utilize smaller, modular production facilities to spur development. Brooks Range leaders said when AIDEA made its first investment that they hoped to have Mustang in production by late 2014, and said when AIDEA made its second payment to the project oil would start flowing in late 2015. Thyssen has producing assets in Louisiana. Elwood Brehmer can be reached at [email protected]

Alaska LNG would cut C02 emissions by 50% over coal, report says

Exporting Alaska’s natural gas to power-generating customers in Asia would roughly halve carbon dioxide emissions versus burning coal, according to a study commissioned by the agency leading the Alaska LNG Project. The 16-page report made public at the Alaska Gasline Development Corp.’s Oct. 7 board of directors meeting also concludes exports from the $38 billion Alaska LNG Project would ultimately result in fewer carbon dioxide emissions than Gulf Coast-based LNG projects for several reasons. AGDC leaders previously said they expected a pending review of the mega-LNG project’s lifecycle greenhouse gas emissions by the Department of Energy to show using Alaska’s gas overseas to displace coal-fired power generation would significantly reduce overall carbon emissions over what is largely the status quo. AGDC President Frank Richards said in an interview that the study largely confirms what he and other proponents of Alaska LNG have long said: North Slope natural gas is one of the cleanest sources of hydrocarbon fuel on the planet. Project officials wanted to get a head start on the DOE evaluation that is being done by the National Energy Technology Laboratory, which will come in the form of a supplemental environmental impact statement, or SEIS. Officials in the DOE office expect to publish a draft SEIS in early May, with a final order coming in mid-December 2022, according to a schedule published by the Office of Fossil Energy and Carbon Management. “We’re very pleased at the outcome that shows, using publicly available sources and the same (DOE) methodologies that have been used to evaluate other LNG projects around the world, we are a lower-greenhouse-gas project,” Richards said. The Energy Department announced in early July it would conduct the SEIS following a petition by the Sierra Club urging DOE officials to withdraw their approval of the project, which is based on the Federal Energy Regulatory Commission’s 2020 final Alaska LNG environmental impact statement. Representatives from the Sierra Club, the Fairbanks-based Northern Alaska Environmental Center and other environmental groups have been critical of the Alaska LNG Project for the carbon dioxide it would emit; instead insisting coal and other carbon-based fuels should be replaced with renewable energy sources. LNG industry players tout their product, relative to coal and oil, as a cleaner-burning “bridge fuel” that can support a longer energy transition as new renewable technologies and infrastructure are developed. Richards said FERC conducted a “project specific” carbon emissions analysis while the study commissioned by AGDC and the DOE review encompasses all of the potential project-related carbon sources. “What the DOE is saying is they want to go beyond Prudhoe Bay,” he said. AGDC’s study was compiled over about six weeks by three independent consulting firms that had all previously done similar work for the National Energy Technology Laboratory, according to Richards. It cost AGDC approximately $30,000. According to AGDC’s report, operating the 20 million tonnes per year Alaska LNG Project would emit approximately 13.5 million tonnes of carbon dioxide-equivalent greenhouse gases per year, with more than half of the total coming from processing the gas through the North Slope gas treatment plant and operating the massive three-train, gas-fired liquefaction facility. The gas treatment plant is largely needed to strip carbon dioxide, which is about 10 percent of North Slope natural gas, off of the methane that is pure natural gas. The carbon dioxide removed from the gas would be reinjected into the Prudhoe Bay reservoir. When greenhouse gas emissions from project operations are added to the emissions from shipping, regasification of the LNG and ultimately burning the fuel the project’s total supply-chain emissions would be roughly 77 million tonnes of carbon dioxide-equivalent gases per year, according to AGDC’s report. That’s almost exactly half of the greenhouse gases emitted from burning coal in China to produce the same amount of power in 2019. Burning coal accounted for nearly 60 percent of China’s primary energy consumption in 2019, according to the U.S. Energy Information Administration. The report also concludes that producing and shipping LNG from Gulf Coast projects — the primary competitors to Alaska LNG — is significantly more greenhouse gas-intensive than North Slope-sourced LNG, Richards noted. That’s due to longer shipping routes through the Panama Canal, and the fact that the existing wells in the Prudhoe Bay and Point Thomson fields from which gas would be drawn versus the energy needed to drill the many shale gas wells to supply most Lower 48 LNG projects. He added that Lower 48 gas frequently changes hands and goes through multiple systems that increase the possibility of “fugitive emissions” from potential gas leakage. Richards further highlighted that utilizing Prudhoe Bay gas in the LNG project would eliminate the need to run the gas-fired compressors currently used to reinject the gas back into the field. The report gives AGDC leaders an understanding of what the results of the SEIS will likely be, but also provides valuable information for marketing the project to potential customers and investors interested in reducing global emissions, he said. “They’re looking for products with low carbon footprints,” Richards said. “We want to position ourselves as a low-carbon LNG product.” AGDC leaders have said they have reached preliminary agreements with private parties to lead the pipeline and gas treatment facilities and hope to reach a similar spot with a lead LNG party soon to move toward the detailed front-end engineering and design stage sometime next summer. Elwood Brehmer can be reached at [email protected]

Alaska DNR reaches royalty oil sale deal with Petro Star

Officials in the Alaska Department of Natural Resources have agreed with Petro Star Inc. on a royalty oil sale that avoids the need for legislative approval. A best interest finding signed by DNR Commissioner Corri Feige and published Sept. 23 along with the proposed contract states that department officials, for their part, opted for a shorter contract out of concerns a longer approval process could lead to interruptions in the delivery of royalty oil to Petro Star. The longer-term contracts DNR officials have often negotiated with the state’s refiners are required to be reviewed by the state Royalty Oil and Gas Development Board and approved by the Legislature. The longer contracts are rarely politically controversial but they can move slowly, the best interest finding notes. “This approval process takes time, and here, could mean months without royalty oil being delivered to Petro Star’s two refineries, but contracts entered into to relieve market conditions are not required to go through these steps so long as they are for one year or less, pursuant to (state law),” the document states. Petro Star Inc. is a wholly owned subsidiary of Arctic Slope Regional Corp. Its refineries largely produce jet fuel, diesel and heating oil. The state’s existing contract with Petro Star expires in December. It took effect in 2018. DNR sells much of the state’s royalty oil to local refiners because the state can typically make a small per-barrel premium when it is sold in-kind versus receiving an in-value payment from the producers for the state’s oil that they sell. Department officials and local refiners agree on a negotiated price differential that allows the state to capture some of the revenue lost from transportation costs when oil is otherwise shipped to West Coast refineries. In recent royalty in-kind, or RIK, oil contracts, the state has generally netted $1 to $2 more per barrel than if it sold its royalty oil in-value, according to DNR; however, the state briefly lost money when oil prices and demand collapsed last year with the onset of the pandemic. DNR officials estimate the Petro Star sales could net the state roughly $4 million over what it would receive from royalty in-value, or RIV, sales in which the producers sell Alaska’s oil — typically to West Coast refineries — on the state’s behalf. The marine transportation costs for Alaska North Slope crude are expected to total approximately $3.25 per barrel in fiscal years 2022-23, according to state projections. The agreement with Petro Star calls for the state to cumulatively sell 10,000 barrels of oil per day in 2022 to the company’s refineries in North Pole and Valdez for a RIK price differential of $2.17 per barrel, meaning the state would generally collect the delta between the marine costs and the RIK differential as additional income. The volume represents about 12 percent to 17 percent of the state’s available royalty oil based on production forecasts, according to the finding, and the RIK differential matches the contract DNR officials signed with Marathon Petroleum Corp. in late April. The contract with Marathon, which owns the Kenai refinery, is for 10,000-15,000 barrels per day and is also for one year. DNR officials do not commit all of the state’s oil to RIK contracts, in order to maintain some RIV sales through which they can gain insight to oil market information that otherwise is difficult to come by. Elwood Brehmer can be reached at [email protected]

Chugach Electric faces revenue shortfall from pandemic

With many once-bustling Anchorage office buildings dimmed as a result of the pandemic, Chugach Electric Association is having a hard time meeting its financial obligations, and utility leaders are asking for help from state regulators. Attorneys for the state’s largest electric cooperative in early July filed a petition with the Regulatory Commission of Alaska asking to modify its detailed and highly technical approval of Chugach’s $1 billion purchase of formerly city-owned Municipal Light and Power, so Chugach can remain in good standing with its lenders and avoid raising electric rates. The long-discussed deal closed in October 2020. Chugach spokeswoman Julie Hasquet wrote via email that the pandemic “has taken a toll” on the utility’s revenue, noting that power demand from commercial customers is down about 8 percent for the Anchorage-area utility. “Like many businesses, we are feeling the effects of the economic downturn. In response, we are managing costs, and we are asking the RCA to allow us to modify the stipulation (agreement) that was accepted when we bought ML&P,” Hasquet said. “The modification, if accepted by the RCA, would provide a reprieve on the treatment of certain expenses over the next several years. This reprieve would allow revenues to recover and additional savings to be realized through integration efforts. We certainly don’t want to raise rates in a pandemic.” Chugach leaders emphasized before the deal was final that rates for customers of both utilities would not increase as a result of the purchase. More specifically, Chugach leaders are asking the RCA to allow the utility to forgo amortization of $19 million in fees and other costs related to the ML&P deal if it cannot maintain a “margin for interest” ratio of at least 1.20 on portions of the debt it took on to buy ML&P, according to the petition. Chugach would continue to operate and maintain its books as if it will hit its original targets, but would “be entitled to reverse entries in its books associated with the amortization” if the margin for interest ratio is less than 1.20 at year’s end, the petition states. Chugach borrowed approximately $800 million in private markets to purchase ML&P, according to Hasquet. On Sept. 30, the state-owned Alaska Energy Authority became the latest stakeholder organization to back Chugach’s plan in filings with the RCA. AEA Director of Planning T.W. Patch, a former RCA commissioner, during the agency’s board meeting called the issue “inordinately complex” even in the oft-arcane realm of utility regulation. “Chugach has failed or is on the cusp of failing to meet certain covenants in its debt structure,” Patch described to the AEA board. “If you borrow money and you promise that you will pay that money back, there is a cost to that money if you don’t meet certain earnings targets. That is the nexus of the present case before the RCA,” he added. Patch also highlighted that no other stakeholders, such as the other Railbelt utilities, have offered what he believes would be a better solution; they have largely supported Chugach’s petition. “Frankly, I’m not sure that there’s a better way to protect the ratepayers, which is what Chugach is attempting to do,” he said, adding he believes it’s likely the RCA will approve the request. RCA officials do not comment on issues before the commission. Chugach leaders once expected to close the year with margins of $12.6 million and a margin for interest of 1.30 when they approved the utility’s 2021 budget late last year. However, that changed when Chugach received ML&P’s financial statements from the municipality the following month, according to the petition. “Upon review, it became apparent ML&P (and now Chugach) was experiencing a significant decline in North District sales and revenues,” the filing states. Chugach’s amended budget, including the updated ML&P figures, calculated out to year-end margins in the $600,000 range. The not-for-profit cooperative utility model is largely based on thin operating margins to keep members’ rates as low as possible. The structure typically works well in the highly regulated and mostly predictable power industry, but it often leaves little financial cushion for utilities when the balance is upset. ML&P’s former service area in the north and east portions of Anchorage included the Downtown, Midtown and U-Med areas, which have some of the highest concentrations of offices and other businesses in the city. According to the petition, power sales from Chugach’s North District — the former ML&P service area — were down 14 percent and billing demand was off nearly 16 percent for the 12 months ending May 31. That resulted in a $16.2 million decrease in base revenue for the North District, while Chugach saw revenue from its more residential Southern District decline by just about $400,000 over the same period. More broadly, Chugach and other large energy utilities in Alaska are facing flat or declining demand now and for the foreseeable future from a declining state population, as well as more efficient appliances causing households to use less energy. Chugach’s purchase of ML&P had been contemplated for decades and was supported by some prominent Anchorage business leaders. Chugach officials insist it has still been beneficial to the community and ratepayers overall. They note ML&P would be facing the same situation if it were still a standalone utility and Chugach has so far captured savings of approximately $21 million in fuel, labor and not needing to account for inter-governmental charges, according to Hasquet. “We are saving roughly $1 million each month in fuel alone. We expect savings to continue to materialize over the next several years as integration efforts are completed,” Hasquet wrote. Elwood Brehmer can be reached at [email protected]

Murkowski seeks permanent waiver from law compelling Alaska-bound cruises to stop in Canada

Sen. Lisa Murkowski is trying to make a temporary, pandemic-driven exemption from longstanding federal maritime laws permanent for Alaska cruises. Alaska’s senior senator submitted the Cruising for Alaska’s Workforce Act in the U.S. Senate Sept. 23 to end the historical requirement that Alaska-bound cruises embarking from U.S. West Coast ports also stop at a foreign port on their way north. The legislation builds on and would solidify the 2021-only exemption to the Passenger Vessel Services Act that passed in late May, which allowed for a scaled-back cruise season in Southeast Alaska this year. Last spring, the Alaska congressional delegation successfully propelled the current, temporary exemption through Congress to President Joe Biden’s desk, via Rep. Don Young’s Alaska Tourism Restoration Act, reaffirming the trio’s collective influence in the Capitol. For large cruise vessels to call on Alaska this year, the exemption was needed because Canadian transportation officials in February announced they again would not allow the ships to dock in the country’s ports in 2021 after similarly banning cruise ships in 2020, in an attempt to limit the spread of COVID-19. The 19th Century-era PVSA requires foreign-built, crewed or flagged passenger vessels sailing between U.S. ports to make at least one stop in a foreign port; an attempt to buoy the nation’s shipbuilding and maritime industries. The modern-day effect has been for cruise lines to use a Canadian port, most often Vancouver, as either the starting point or a stop en route for Alaska-bound voyages to comply. The pandemic hang-up for international cruise companies and the plethora of Alaska tourism businesses — from fishing charters in Ketchikan to the Alaska Railroad to gift shops in Fairbanks — that depend on cruise passengers is that no American yards build large cruise ships. All of the large cruise ships currently operating were built elsewhere. Murkowski said in a statement from her office that the new legislation guarantees that the PVSA will not interfere with Alaska’s tourism industry again without allowing foreign-built ships to compete with the domestic industry. That’s because the Cruising for Alaska’s Workforce Act includes a provision that would reinstate the foreign stop requirement for foreign-built vessels if a large U.S.-built cruise ship were to enter service. “While the PVSA still serves its purpose in the Lower 48, it unintentionally put many Alaskan businesses at the mercy of the Canadian government when Canada closed its borders, including ports,” Murkowski said. “The inability for cruises to travel to Alaska nearly wiped out our economies in Southeast; communities like Skagway for example saw an 80 percent drop in business revenues.” The temporary exemption passed in late May gave cruise companies time to start limited sailings in July. Overall, this year’s cruise season in Southeast was about 10 percent of normal, according to a report commissioned by the Southeast Conference, a regional community development nonprofit. Alaska’s cruise industry peaked in 2019 when roughly 1.3 million tourists — more than half of all visitors to the state that year — arrived via cruise ship. Last year, the region lost approximately 45 percent of the nearly 8,400 tourism-dependent jobs it had in 2019, primarily due to the lack of cruise ships. Delegation staffers have said they would expect a permanent Alaska cruise exemption to the PVSA to garner support similar to what the temporary waiver received. Murkowski’s bill is first set to be heard in the Senate Commerce, Science and Transportation Committee chaired by Washington Democrat Maria Cantwell, who worked closely with Murkowski for years when they led the Energy and Natural Resources Committee for their respective parties. Cantwell backed the temporary exemption, noting at the time that the lost 2020 Alaska cruise season cost Seattle an estimated 5,500 jobs and $900 million in potential economic activity. Elwood Brehmer can be reached at [email protected]

Pebble touts economics as EPA moves to reinstate mine ‘veto’

The Pebble Limited Partnership continues to press ahead on pre-development work for its highly contentious mine, despite major roadblocks set by federal agencies under both the Trump and Biden administrations. The mining venture’s parent company, Vancouver-based Northern Dynasty Minerals, earlier this month released a summary of the preliminary economic assessment for its latest mine plan, which until recently was long demanded by the project’s opponents. According to Northern Dynasty, the 20-year mine plan Pebble submitted to the U.S. Army Corps of Engineers in late 2017 would generate an internal rate of return of nearly 16 percent and represents a 7 percent discounted net present value of approximately $2.3 billion, based on long-term metal price assumptions. At current prices for the prospect’s copper, gold and silver, the 20-year Pebble plan would generate returns of nearly 24 percent and holds a discounted net present value of $4.8 billion, the PEA states. The full report will be made public by late October, according to Northern Dynasty. Pebble last issued a formal evaluation of its project’s economics in 2011, which led opponents in recent years to demand updated economic estimates for its newer, scaled-back mine plan. They claimed the company avoided making its internal figures public because the smaller mine is not economically feasible on its own and would simply be a precursor to significant expansion. Northern Dynasty CEO Ron Thiessen said the report outlines the “robust economics” of Pebble in a statement accompanying the PEA. “It is a project that can be designed, built and operated with industry-leading environmental safeguards while generating significant financial returns over multiple decades,” Thiessen said. The 20-year economic forecast for the project is based on processing approximately 180,000 tons of ore per day from the open-pit mine and cumulative production of roughly 6.4 billion pounds of copper, 7.3 million ounces of gold and 37 million ounces of silver, along with ancillary production of other metals. An expanded mine capable of processing up to 270,000 tons of ore per day over 90-plus years would increase the project’s internal return to roughly 20 percent at forecasted metal prices and 25-30 percent at current prices, according to the PEA figures. The expansion economics are based on producing up to 60 billion pounds of copper and 50 million ounces of gold. For comparison, the proposed Donlin gold mine in the Kuskokwim region is forecasted to produce upwards of 33 million ounces of gold, which would make it one of the largest gold operations on Earth. At the same time Pebble and Northern Dynasty leaders were touting the moneymaking ability of their project, attorneys for the Environmental Protection Agency were indicating the Biden administration’s plan to resurrect a regulatory “veto” of Pebble in federal court filings. EPA attorneys filed a scheduling motion in U.S. District Court of Alaska on Sept. 9 outlining their intent to reverse the Trump administration’s 2019 withdrawal of a proposed determination to prohibit a large mine in the Pebble area through the agency’s Clean Water Act Section 404(c) authority. The withdrawal was partly rejected by the 9th Circuit Court of Appeals in June as part of a separate lawsuit filed against the EPA in 2019 by numerous Tribes and environmental groups opposed to the mine. The Appeals Court panel partly overturned a District Court ruling, finding that EPA regulations allow for a 404(c) withdrawal “only when an ‘unacceptable adverse effect’ on specified resources was not ‘likely,’” the June 17 order states. According to the order, the EPA under the Trump administration did not sufficiently justify its rationale for reversing the proposed determination, as required by the agency’s regulations. The EPA began the years-long veto process in 2014 under former President Barack Obama. But the settlement to a subsequent lawsuit by Pebble against the EPA was resolved by EPA leaders in the Trump administration, which allowed Pebble to move ahead with permitting its project. In a surprising move last November, the U.S. Army Corps of Engineers rejected the mine plan at the end of a nearly three-year environmental impact statement process, which resulted in a final EIS that broadly concluded the mine could co-exist with the area’s other resources and would cause “no measurable change” in the numbers of salmon returning to the Nushagak and Kvichak rivers, or in the long-term health of the commercial fisheries in the region. Pebble’s appeal of the Army Corps of Engineers Alaska District’s record of decision for the project EIS is primarily based on the perceived inconsistencies between the EIS and the agency’s final decision. Pebble spokesman Mike Heatwole wrote in an emailed response to questions that the company maintains its position that the withdrawal of the 404(c) veto by the EPA under the Trump administration “was sound and appropriate.” Heatwole emphasized that the EIS published last year concluded the project could be built without harm to the region’s fisheries or water resources and further represents a “tremendous economic opportunity” for nearby communities. “Our focus remains on working through the formal appeals process via the (Army Corps). As the Biden administration seeks lower carbon emissions for energy production, they should recognize that such change will require significantly more mineral production — notably copper,” he wrote. “The Pebble project remains an important domestic source for the minerals necessary for the administration to reach its green energy goals.” Pebble’s appeal of the record of decision to Army Corps Pacific Division leaders is ongoing. Elwood Brehmer can be reached at [email protected]

Native corporations slowly approach shared revenue ‘cliff’

Alaska Native corporations across the state face a “fiscal cliff” of their own that is still years off, but there are currently few options to avoid it. For decades, the 12 Alaska Native regional corporations and nearly 200 village corporations statewide have shared revenue generated from resource projects amongst themselves to the tune of roughly $3 billion since 1982, according to figures from a 2018 report on the revenue sharing program by the McDowell Group combined with more recent data. Generally known as the “Section 7(i)” program for its place in the Alaska Native Claims Settlement Act, the provision in the landmark legislation directs Alaska Native corporations to distribute 70 percent of the revenue originating from resource projects on their land to the other Native corporations statewide. The land or resource owner company keeps the remaining 30 percent. ANCSA Regional Association Executive Director Kim Reitmeier said the 7(i) program is a critical component of ANCSA “that truly reflects the Alaska Native values of unity and collaboration.” Revenue from the 7(i) program has been a significant source of funds for benefits each of the regional corporations have offered their shareholders, according to Reitmeier. The money is often used for cultural education, language revitalization, and scholarships, or is paid directly in shareholder dividends, but the individual corporations ultimately determine how it is spent. “There’s been trials and tribulations for the regional corporations and 7(i) revenue, and assistance from the other regional corporations has been paramount in the success of all of them,” she said. Revenue shared in the program — greatly influenced by commodity prices and production — totaled $246 million in fiscal year 2019 and $158.4 million last year, according to Reitmeier. She also noted it’s a model that flies in the face of the country’s traditional business principles. “It’s really something that baffles the mind. Ask Lowe’s and Home Depot and all those entities to share profits with each other. You take those concepts to Western business cultures and it blows people’s minds,” Reitmeier said. From 2015-2017 Bristol Bay Native Corp. collected between $5.6 million and $9.6 million per year in 7(i) revenue, net of what the company also turned around and distributed to village corporations in its region through the closely linked 7(j) program, according to BBNC’s 2017 annual report. Section 7(j) of ANCSA subsequently directs the 12 regional corporations to distribute half of the shared revenue they receive to the area’s village corporations. The 12 regional corporations are all involved in numerous industries and business sectors, from government contracting to oil field services to remote fishing lodges, typically through subsidiaries and partnerships. And while many village corporations are often more focused on a single industry, whether drilling oil wells or managing parking garages, Alaska Native Village Corporation Association Executive Director Hallie Bissett said that the 7(j) income accounts for all or nearly all of the revenue collected by approximately two-thirds of the 177 village corporations that are ANVCA members. Similar to Reitmeier, Bissett said the emphasis on spreading the benefits of natural resources across the state is one of the first socially responsible business models. “People often forget the Alaska Native piece of ANCs and just focus on the corporation,” Bissett said. “It’s very similar to the way we would share subsistence food,” she added. The problem lies in the fact that resource revenue from Alaska Native corporation-owned lands is generally declining and the fall is likely to accelerate in the coming years. As is the case with oil production across the North Slope, production from lands owned by Arctic Slope Regional Corp. or state leases to which ASRC holds an overriding royalty interest has been on a downward trend, with no outlook for an abrupt recovery. Shared revenue from the Red Dog mine in northwest Alaska — one of the world’s largest zinc producers — also has an expiration date, and it’s the one Bissett is most concerned with. “There’s a huge cliff coming for 7(j),” she said in an interview. Opened in 1989, the Red Dog mine is on NANA lands north of Kotzebue. However, the metal deposit Red Dog operator Teck Resources Ltd. has been mining from is projected to be exhausted by 2032, according to Teck, with a likely ramp-down of production in the years preceding closure. Teck leaders in 2018 announced a second major discovery in 2018 that company representatives characterized as another world-scale zinc prospect, but it is on nearby state land. A spokeswoman for NANA did not respond to questions about royalty and 7(i) revenue from Red Dog in time for this story. According to the Alaska Industrial Development and Export Authority, which owns the industrial toll road used to access the mine, royalty payments to NANA average greater than $130 million annually. Through 2016, Red Dog had generated more than $1.3 billion in royalties for NANA, of which $860 million was subsequently distributed to Alaska Native corporations through the 7(i) and 7(j) programs, according to figures in a 2017 AIDEA asset review report. “Awareness is the first big piece,” Bissett said in regards to addressing the looming dilemma. “Some (village corporation leaders) don’t even know where the money comes from.” She said Native corporation leaders attempted to get a 3 percent royalty from possible oil production from the Arctic National Wildlife Refuge but that was unsuccessful. Leaders of the Donlin gold project in the upper Kuskokwim region of Western Alaska tout their world-scale prospect — with the potential to produce upwards of 33 million ounces over a nearly 30-year planned mine life — as a possible solution to the 7(i) and 7(j) revenue outlook. The Donlin prospect is on land owned by The Kuskokwim Corp., a consolidated village corporation and, as is the case across the state, the subsurface rights and royalties are controlled by the regional corporation — in Donlin’s case, Calista Corp. A Donlin spokeswoman referred questions about royalties to Calista officials. Calista spokesman Thom Leonard noted via email that Donlin isn’t the only resource development opportunity on Alaska Native-owned lands, but it is the next major opportunity after Red Dog to contribute to the 7(i) program. “Like we can’t predict how many fish we will catch, we can’t speculate on the amount of 7(i)/7(j) revenue (from Donlin). It will depend on the price of gold and other factors. That said, if the Red Dog mine is any guide, we expect to be a significant contributor to 7(i)/7(j) distributions to all Alaska Native corporations,” Leonard wrote, also noting that Red Dog accounted for 70 percent of all 7(i) revenue between 2015 and 2018. Bissett concurred that Donlin could be a major source of shared revenue, but also added that it is several years from the start of a lengthy construction process, if the mine is ultimately built at all. She suggested it could be 20 years before significant 7(i) revenue is collected from Donlin. “As my chairman said, (shared revenue) is the difference between being in business and not in business” for many village corporations, Bissett said. Elwood Brehmer can be reached at [email protected]

Alaska’s budget fights resemble Lower 48 fiscal struggles

States such as Illinois and New Jersey are often used as a punchline for their historic money management troubles, but a decade of deficits has Alaska headed down a similar path, according to fiscal policy analysts at The Pew Charitable Trusts. Josh Goodman, a senior officer with Pew’s State Fiscal Health project, provided examples of the choices states struggling with a structural fiscal imbalance often make during a Sept. 24 gathering of the local policy think tank Commonwealth North. It turns out Alaska has made pretty much all of them. Lawmakers in states with ongoing budget issues often struggle to agree on the severity of the problem, according to Goodman, a symptom Alaska’s elected leaders continue to exhibit. The special legislative session that wrapped up in mid-September was intended to put a bow on Alaska’s new fiscal plan by settling the remaining budget gap with spending cuts or revenues, after the future of the Permanent Fund was settled in June. Instead, the June session was consumed by the immediate need to pass a budget and avoid a government shutdown. It ultimately resulted in a last-minute deal to pass a fiscal year 2022 budget with Permanent Fund dividends of about $525 per person, an amount Gov. Mike Dunleavy called insufficient after vetoing it. That led to the most recent 30-day fight over this year’s PFD, which resulted in $1,100 dividends the governor is also unhappy with, rather than the long-sought resolution to the state’s fiscal imbalance. There is little reason to believe the special session starting Oct. 4 — the fourth of the year — will end any differently based on the political dynamics of the Legislature. Alaska’s 2021 political stalemate built on the inaction of prior years and resembled what has gone on in Illinois, according to Goodman. “In Illinois’ case, they had these deeply flawed budgets to the point that they struggled to pass a budget at all,” he said. To discourage talk of new taxes, budget and revenue officials in the Dunleavy administration spent much of the last special legislative session emphasizing optimistic views of the state’s revenue outlook based on projections for increased oil production and relatively strong oil prices over the coming decade. Conversely, legislators from both sides of the aisle, skeptical of Dunleavy’s proposal to pay out half of the state’s annual Permanent Fund revenue appropriation in dividends, presented their own, much less rosy figures for the state’s long-term revenue. Independent budget analysts and political observers have said the most accurate assumptions are likely somewhere in the middle. “The more different stakeholders can agree on what the problem is, at least it gives a common starting point for figuring out what the solution should be,” Goodman said. The inability to reach a common understanding of the state’s fiscal situation — largely driven by the itseliance on unpredictable commodity prices and financial market conditions — has pushed Alaska lawmakers to paper over the deficit each year with a variety of unsavory but well-established tactics. Meanwhile, the state’s savings have dwindled in the absence of a comprehensive solution. Goodman said Kentucky, for example, has struggled to invest in its priorities, namely improving the capacity of its workforce, and has relied heavily on one-time funding sources to fill its budget. “You have the chamber saying, ‘our biggest investment is our workforce; we need to invest in our workforce,’ and Kentucky isn’t doing it,” he said. Alaska business leaders have long said employers in many industries struggle to find and keep skilled workers, even before the pandemic extended those problems to service industry businesses. Dunleavy’s 2019 proposal for deep cuts to the University of Alaska System, among other reductions, was a key driver behind the now-defunct effort to recall him from office. The governor has also proposed using money generated by the Alaska Industrial Development and Export Authority, the state’s development bank, to pay for recurring expenses such as oil and gas tax credit payments. Dunleavy also previously insisted the endowment-style Power Cost Equalization fund, used to subsidize high rural power costs, should be rolled into the state’s general fund. Legislators also have occasionally moved money in various state funds to pay for unintended items, including funding PFDs with money from the state’s savings accounts. In California, state lawmakers began deferring school funding after the Great Recession took a substantial bite out of the state’s tax revenue, according to Goodman. “It’s just, ‘push it into the next fiscal year and then we won’t have to worry about it this fiscal year,’” he said of California’s situation. In Alaska, Dunleavy has partially vetoed the Legislature’s formula-driven appropriations to fund the school bond debt reimbursement program, which under state law calls for the state to help local governments cover the cost of school capital improvement projects. With the shrinking of the American auto industry in the early 2000s, Michigan had well-publicized budget problems, Goodman noted. There, state government leaders struggled to make good on industry tax incentives after revenue driven by the industry dissipated. New Jersey has faced similar situations with a host of development programs, he said. “New Jersey promised economic development incentives for businesses and the Legislature simply didn’t appropriate the money to pay for those incentives,” Goodman said. Former Gov. Bill Walker in 2016 broke the state’s longstanding tradition of annually paying off several hundred million dollars worth of oil and gas tax credits by vetoing much of the appropriation down to a minimum formula-driven amount called for in state law. Lawmakers have since struggled to make meaningful progress paying down the obligation, which peaked at nearly $1 billion. A bill that passed in 2018 to sell bonds to pay off the tax credit liability was unanimously ruled unconstitutional by the Alaska Supreme Court. The tax credits have been relegated to little more than an afterthought in recent budget debates. Dunleavy spokeswoman Shannon Mason said via email that the administration “will continue to propose paying tax credits as required by statute.” Goodman said in an interview that Alaska’s situation, with its uniquely large $80 billion Permanent Fund, is viewed in a few different ways. The state’s traditional savings accounts, the Constitutional and Statutory Budget reserves, have jointly been drawn down to just more than $1 billion after starting the deficit run with funds of roughly $16 billion. “Alaska is a state, depending on how you look at it, is among the strongest (fiscal) position of any state or the weakest position of any state,” he said. Those starkly opposing views of the state’s finances likely play into perpetuating the challenges, Goodman suggested. “Is the political disagreement a cause of the fiscal problem or the result of the fiscal problem?” he said. Elwood Brehmer can be reached at [email protected]

Once-heralded ‘Slope Renaissance’ projects now face uncertain futures

For several years now state officials and the leaders of Alaska’s oil industry have been touting a “North Slope renaissance” driven by large projects tapping newly discovered conventional Nanushuk oil plays across the western half of the region. In the span of less than a year, however, the future of two multibillion-dollar oil projects planned for the coming years has gone from promising to highly uncertain. Early-stage construction at ConocoPhillips’ $6 billion-plus Willow project in the National Petroleum Reserve-Alaska was stopped before it started last winter when the federal 9th Circuit Court of Appeals granted a temporary injunction to environmental and North Slope Tribal groups that previously sued to stop Willow. ConocoPhillips was expecting to dig a quarry to source gravel for permanent roads and pads to access the remote oil prospect until the mid-February ruling. The company then requested a summer resolution to the matter from Alaska District Court Judge Sharon Gleason so work could commence this winter, but Gleason issued a subsequent ruling in August invalidating the Bureau of Land Management’s environmental impact statement for Willow, the overarching environmental document that formed the basis for the agency’s approval of the development. Gleason ruled, largely based on the 9th Circuit injunction, that BLM and Fish and Wildlife Service officials under the Trump administration failed to adequately account for foreign carbon emissions stemming from Willow and did not provide sufficient specificity regarding how the development’s impacts to polar bears would be mitigated. Gov. Mike Dunleavy and Alaska’s all-Republican congressional delegation previously lauded the Biden administration for backing the Willow EIS in court filings before Gleason issued her decision. The August order has made the question, “What’s next?” unanswerable, at least publicly, for ConocoPhillips Alaska leaders. Company officials continue to review Gleason’s ruling and are moving ahead with engineering and design of Willow’s facilities in anticipation of a final investment decision, they have said. BLM and the company have until Oct. 18 to appeal the ruling. Specific flaws identified in environmental reviews are often remedied through a supplemental EIS that focuses its study on the given issues and can take as little as several months to complete. Attorneys for the groups that brought the Willow lawsuits say a resolution might not be that simple. They contend the Willow Master Development Plan contains multiple significant legal violations that might necessitate a wholly new, and likely multi-year, EIS process for the project before construction could start. First oil at Willow had been expected during the 2025-26 winter with peak production reaching upwards of 160,000 barrels per day, according to ConocoPhillips’ estimates. Pikka At Oil Search Alaska’s Pikka project on state land, the issue is money. Oil Search Alaska executives have openly acknowledged the struggles they have had in securing funding for the $3 billion first phase of the already scaled-back Pikka project. With first oil from Pikka pegged for late 2023 as recently as early 2020 and peak production once seen at rates near 120,000 barrels per day, Oil Search representatives said earlier this month the mid-sized firm — historically a gas producer in the South Pacific — is investigating every avenue it can to secure funding and move Pikka forward. However, such Arctic oil projects are rapidly falling out of favor with the large banks that traditionally fund them. Startup of the first phase of Pikka is tentatively pegged for 2025. Oil Search leaders insist they are still shooting for a final investment decision later this year but the company is also in the process of merging with fellow South Pacific producer Santos Ltd. The deal will give Santos owners a controlling share of the melded company. A Santos spokesman wrote to the Journal after the deal was formally announced that the company at this point supports Oil Search’s work to advance Pikka. The uncertainty for two of the largest oil projects Alaska has seen in decades correlates directly to the numbers underlying the omnipresent fiscal debates in the state Capitol. While its location on federal land means the State of Alaska will at best receive minimal royalty contributions from Willow to the general fund, state oil production taxes will still apply to the project. ConocoPhillips estimates Willow would generate approximately $2.1 billion for the state. Oil Search estimates Pikka would produce upwards of $7 billion for the state over a roughly 30-year life. Forecast uncertainty The state’s latest official oil production forecast published in March projects North Slope oil will steadily increase to 565,000 barrels per day by 2030 after bottoming out at approximately 460,000 barrels per day this year. Those annual estimates are 30,000 barrels per day to more than 80,000 barrels per day greater than the forecast issued late last fall when uncertainties surrounding the pandemic were still in control of oil markets. Taken at face value, nearly half of the forecast for the late 2020s could be comprised of oil expected from Willow and Pikka based on the companies’ public estimates. Longtime oil analyst and Alaska oil and gas attorney Brad Keithley said he believes the state’s production forecast is overly rosy from a budgeter’s perspective. “I’ve thought for a long time the back end (of the production forecast) is high,” Keithley said in an interview. “It may turn out to be accurate but if you were just sitting here with what we know now, with what we know about Willow and Oil Search it’s a stretch case, a big stretch case to think those production numbers are going to turn out.” Keithley is also the managing director for Alaskans for Sustainable Budgets, a nonprofit project aimed at informing the public about the state’s financial challenges. Former state petroleum economist Roger Marks said he has a hard time critiquing the state’s production forecast because “there are a lot of unknowable things out there right now,” but added, “I can imagine it staying where it is. I can’t imagine it going up too much.” Marks foresees some sort of legal resolution that will allow ConocoPhillips to move ahead with Willow eventually and said the level of future North Slope investment will likely be tied to oil prices, which have been relatively robust this year in the $70-plus range. Keithley noted that the Revenue Department’s most recent long-term price forecast calls for average Alaska North Slope crude prices to increase from the low $60s per barrel the next couple years to $71 per barrel by 2030; he suggests that’s backwards. “There’s a huge disparity between the oil price numbers that the (Dunleavy) administration is still using for the back end and what the markets are telling us the oil price numbers are going to be,” he said. According to Keithley, oil futures for the late 2020s currently indicate a return to prices in the low $60s to high $50s per barrel, which was mostly the range they were in for several years prior to the arrival of COVID-19. Pascal Umekwe, a commercial analyst with the Division of Oil and Gas involved in developing the oil production estimates, said in an interview that he could not attribute a specific volume of projected barrels in the forecast to a specific project. For one, state officials use probabilistic not deterministic models to generate a range of likely outcomes. They also are reluctant to discuss information pertaining to individual operators to prevent potential violations of state confidentiality statutes and maintain the trust of company officials who discuss sensitive business information with them. He stressed state forecasters bake the numerous risks inherent in major oil developments — regulatory and financial for ConocoPhillips and Oil Search — into their final numbers. “We’re not happy these things happen but as a result of 1,000 factors (oil projects) might not happen the way they were supposed to happen,” Umekwe said in an interview. Elwood Brehmer can be reached at [email protected]

Second busy summer wraps at Donlin Gold

Bursts of canary yellow on an otherwise deep green landscape indicated Alaska’s infamously fleeting fall had arrived to Western Alaska. At Donlin Gold’s camp in the upper Kuskokwim drainage, that meant wrapping up another busy drilling season before autumn departs. The last Donlin drilling crew was boring its final hole into the bedrock underlying a valley adjacent to the camp’s rather unique runway — more on that later — when the Journal toured the world-scale gold project with Sen. Lisa Murkowski Sept. 17. The drill was turning into what could end up being the bottom of the gold mine pit. “Ahead of schedule and under budget,” Donlin Gold General Manager Dan Graham said of the 2021 summer work season. Crews drilled approximately 80 holes totaling about 24,000 meters after originally planning to do about 20,000 meters of work at the outset. Mining major Barrick Gold Corp., the world’s second largest gold producer and a 50 percent owner in Donlin with junior Vancouver-based NovaGold, has been the driving force behind two consecutive drilling-intensive years at the Donlin prospect. About 23,000 meters of core was drilled last year. A little more than 400,000 meters of drilling has been done at Donlin since major exploration started, according to Graham. The latest core samples are largely needed to improve the companies’ understanding of the ore body before making a final investment decision on the massive mine project, last priced at nearly $7 billion back in 2011. Other geotechnical-focused drilling is informing work on the mine’s tailings storage dam. 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 supply 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. Donlin representatives have long said the project generally needs sustained, high gold prices because of the extensive network of support infrastructure that needs to be developed but have declined to specify what parameters they believe are needed to green-light development. The last two active drilling seasons came after a period of general dormancy at the camp from 2013 to 2018 while the company focused on permitting and gold prices were at their lowest. Spot Gold prices hit a recent peak of nearly $2,100 per ounce in mid-2020 and since have been largely in the range of $1,700 to $1,900 per ounce after bottoming out at less than $1,100 per ounce near the end of 2015. To that end, Graham said at this point the outlook is for another full season next year. Executives for Barrick and NovaGold said in a joint statement earlier this month that they are working towards an updated feasibility study, which would likely include a new cost estimate, before deciding whether or not to start construction. That decision could come in two or three years if Donlin Gold can secure its remaining requisite permits. The company received a favorable record of decision from the Army Corps of Engineers in 2018 on its environmental impact statement following a roughly six-year review. Donlin still needs approvals from state Dam Safety officials in the Department of Natural Resources for its large tailings facility. Located on land owned by The Kuskokwim Corp., the area’s consolidated Alaska Native village corporation, the Donlin Gold project exemplifies the disconnect that often occurs between local Tribes and Native corporations when it comes to development projects. More than a dozen Tribes in the region have formally opposed Donlin since the project got its overarching federal approval largely over concerns the project will harm the Kuskokwim’s salmon runs, which have already been in a general state of stress in recent years. Leaders for Donlin, TKC and Calista Corp., which holds the subsurface and royalty rights to the land and gold, insist locals’ fears often stem from being misinformed; the company will be expected to discharge water treated to a higher quality than it would be if the mine were not there at all, Donlin External Affairs Manager Kristina Woolston said. “My focus is on the region and Barrick is on board with bringing the benefits (of the project) to the region,” Graham later added. Those benefits start with up to 3,000 construction jobs during the multi-year development phase and another 1,400 expected during the life of the mine, according to Donlin Gold, but the financial benefits of Donlin would also extend statewide through the Alaska Native Claims Settlement Act Section 7(i) and 7(j) resource revenue sharing programs for regional and village Native corporations, company leaders note. Currently, Donlin employs more than 100 workers at the camp when activity is high. As an example of the work the company is doing to understand and minimize the environmental impacts of the project, Graham said Donlin commissioned first-time studies of the Kuskokwim’s Rainbow smelt run — an important spring subsistence resource — this year to get a better understanding of when and how barges supplying the mine should be sent upriver to avoid out-migrating smelt fry. For her part, Murkowski tries to talk with workers from the region when visiting projects such as Donlin to get their perspectives on how it is viewed locally, she said. It was Murkowski’s third attempt to reach the project; the first two were weathered out. Upon approach to the camp, it was easy to grasp why the senator had previously been unlucky. The broken ceiling Sept. 17 allowed for safe travel; however an 8 percent incline to the Donlin camp runway means planes are limited to one-way in and one-way out with few options to account for wind direction or other considerations. The ridges surrounding the project — similar to the one the camp is perched on — also prevent flying in low cloud cover. The uphill landing at Donlin provides a sensation this reporter had not previously experienced. “The third time’s the charm,” Murkowski remarked prior to the morning flight from Anchorage, which was held up only briefly on a “weather.” Elwood Brehmer can be reached at [email protected]

PPP still driving income for state’s banks

Compared to his, Bill Murray would envy the kind of Groundhog Day Alaska’s banks have been living. While full of work, the last year-plus has also been full of growth and profits for Alaska’s lenders. It continued in the second quarter of the year. Northrim Bank Chief Financial Officer Jed Ballard said the Small Business Administration’s uber-popular Paycheck Protection Program, or PPP, instituted early in the pandemic provided the bank with nearly 6,000 new loans totaling more than $600 million in the past year. “That was a tremendous amount of money we put into the system. For us that is several years of activity,” he said. Ballard and leaders at other Alaska banks have said the PPP loans spurred levels of activity that had loan officers working long hours and sometimes weekends while other employees took on new roles to assist where needed. “A tremendous amount of work,” Ballard said. Anchorage-based Northrim, which has branches in Southcentral, the Interior and Southeast, reported income of $8.3 million for the second quarter, which followed a $12.1 million first quarter profit. The pace at which Northrim and other banks are processing PPP loans has slowed but fees normally amortized over the life of a loan are collected up front when a PPP loan is forgiven as intended, which means the program continues to benefit banks’ bottom lines. According to Ballard, Northrim closed out roughly $130 million of forgiven PPP loans during the second quarter. Northrim’s assets grew by 4.2 percent to more than $2.45 billion in the quarter, according to its filings with the Federal Deposit Insurance Corp. The bank surpassed $2 billion in assets a year prior. Northrim’s total loans were down 4 percent to approximately $1.6 billion — a reflection of the forgiven PPP loans — but the bank had solid “core loan growth” in the period as well, Ballard said. Mortgage activity continues to be strong and PPP loans also gave Northrim access to customers it might not otherwise have secured, he added. The Alaska Housing Finance Corp. continues to publish daily interest rates for 30-year mortgages starting at 2.5 percent. Ballard noted that mortgages represented roughly half of the bank’s non-interest income for the quarter; for most banks home loans are about 10 to 20 percent of non-interest income, he said. First National Bank Alaska, the state’s largest state-based lender, netted nearly $13.7 million in the quarter, its third such period with a profit in the $13 million range following quarterly nets of $15.5 million and $14.5 million in the middle of 2020. FNBA grew its total position 8.1 percent in the second quarter to more than $5.33 billion in assets. The bank’s total assets have increased more than 16 percent over the past year. According to an earnings release, FNBA originated more than 3,000 second-round PPP loans totaling $238.1 million in the first half of the year, while other PPP borrowers have had a total of $278.8 million in loans forgiven. “The lessons learned in 2020 give us great confidence we will continue to be able to deliver the financial services Alaskans need, and to adapt to circumstances as they develop,” FNBA CEO Betsy Lawer said in a statement. FNBA representatives did not respond to further questions in time for this story. FNBA’s loan loss allowance stayed ostensibly flat at $23.5 million; Northrim was similar with a loss allowance of $14.5 million for the quarter on a $1.6 billion portfolio. Fairbanks-based Denali State Bank grew its total position by 14.3 percent in the second quarter to more than $454.2 million. The Interior community bank netted a profit of $1.33 million, nearly matching the $1.37 million earned to start the year. Elwood Brehmer can be reached at [email protected]

North Slope veteran Weiss joins gasline board of directors

Gov. Mike Dunleavy added a unique perspective to the state’s team trying to build the massive and long-sought Alaska LNG Project when he named Janet Weiss of Anchorage to the Alaska Gasline Development Corp. board of directors on Aug. 23. That’s because Weiss spent seven years leading BP’s Alaska business — and working Alaska LNG from a different angle — before the global energy giant left Alaska when its $5.6 billion sale to Hilcorp Energy closed last year. When BP left, Weiss retired from the industry, but stayed. “No plans to leave, 28 years (in Alaska), so it’s definitely home,” she said in a recent interview with the Journal. As president of BP Alaska, Weiss led the business through the first iteration of the $39 billion Alaska LNG Project: a producer-led consortium formed officially in 2014 that the state was a minority partner in and was championed first by former Gov. Sean Parnell. She also observed, from the inside, the transition in 2016 under former Gov. Bill Walker to a state-led project. That shift was largely the result of depressed oil and gas markets that caused the producers to slow their development plans and spending for Alaska LNG as well as Walker’s long-held belief that the State of Alaska should take a more active role in spurring the project on. Dunleavy said in a statement from his office that Weiss’ 35 years of experience in the oil and gas industries will be an “extremely valuable” addition to AGDC. “Like so many others, when Janet arrived in Alaska in 1986 she fell in love with our great state and its rocks and reservoirs. Janet spent her career in almost every corner of the oil and gas industry and from 2013 to 2020 she led BP Alaska as its President, while continuing to be involved in the Alaska philanthropic community. Her remarkable experience and capable leadership will be indispensable as AGDC continues its work to unlock Alaska’s natural gas on the North Slope,” he said in a statement for the Journal. Former AGDC board chair Dave Cruz, who was the longest serving member on the corporation’s board when he stepped away last year, said he believes Weiss will bring a perspective to AGDC that the state hasn’t had before and has more knowledge about what the producers need to continue progressing the project. His interactions with Weiss came at big events related to the project, such as stakeholder meetings, during his roughly seven years on the AGDC board. Cruz added that he thinks Weiss’ years in Alaska before taking over the leadership position for BP can be valuable. Weiss applied for the board after getting some encouragement from others involved in the project, she said. “She wasn’t a transplant here at the executive management level, Cruz said. “She came up through the ranks here. She understood extremely well the dynamics of the North Slope because she came up as a management person who worked her way up here. And that’s the best way for people to understand it.” A reservoir engineer by training, Weiss was BP’s vice president of resource development in Alaska before taking the lead role with the company in the state. Under Weiss, BP agreed in 2019 along with ExxonMobil to each provide up to $10 million to AGDC for completing the exhaustive AK LNG environmental impact statement, or EIS, which the Federal Energy Regulatory Commission approved in May 2020. She wrote in an email to follow-up questions that she advocated strongly for BP to help fund the EIS despite the fact that it was the state’s responsibility at that point because “that body of work was the culmination of a lot of funding and man-hours, and it best served all parties involved to complete it,” she wrote. “Keeping the opportunity moving forward.” Now, AGDC leaders are hoping to turn the project back over to private hands under the Dunleavy administration. They have said they hope to secure commitments from developers, operators and investors in the LNG and gas treatment plants by this fall, with the project’s major financial agreements coming next year. AGDC President Frank Richards has said agency officials are in confidential negotiations with a lead party to manage the gas pipeline portion of the project at least partially contingent upon the availability of federal funds for the first phase of construction. Then-ExxonMobil CEO Rex Tillerson notably said in 2015 that Alaska is its “own worst enemy” because the plan for a major North Slope gas project changes every time a new governor is elected, which has been every four years since 2002. Weiss said she believes the most important aspects of successfully developing a megaproject such as Alaska LNG are having sufficient expertise to lead the many facets of such a complex endeavor and, just as importantly, alignment amongst those expert parties on how to move forward. “There’s not one answer to all of this. Different players have different parts to play and come in at different levels of project definition,” she said of advancing Alaska LNG. “Do you have the right expertise for the various parts of the project because you can’t have a massive ‘whoops’; that’s what you can’t have. You don’t want this project to come in and cost double. Something that you think is going to be wonderful for the state turns into the biggest albatross; so you have to have the right experience and not have the ‘whoops.’” Under Walker and former AGDC President Keith Meyer, the state pushed an aggressive development timeline for the project, hoping to have it operational by the mid-2020s in order to capitalize on what they and many others noted is a window to secure long-term contracts with some of the world’s largest LNG buyers in Asia. That focus on timing was likely a point of misalignment between the state and company leaders, according to Weiss, because of how important it is to balance all of the complex — and sometimes competing — priorities of developing a project the scope of Alaska LNG. “There is a window, an opportunity, so you can see that somehow you have to figure out that level of alignment so you can have your cake and eat it, too,” Weiss said. She also went out of her way to emphasize that the many Alaskans, including Walker, who have been critical of state officials and leaders of the North Slope producers for not constructing a gas pipeline project in some form over the decades since the oil was first developed often overlook a very key factor: the gas was being put to work that whole time. The natural gas produced along with oil at Prudhoe Bay has long been injected back into the field to boost reservoir pressure and ultimately enhance oil production. In 2015, the Alaska Oil and Gas Conservation Commission approved increased gas “offtake” from the North Slope to supply the Alaska LNG project, with production expected to start in 2025 at the time. The decision was seen as a recognition by state regulators that the economic value of continuing to inject the gas for oil recovery would be bested by the value of commercializing the gas in the middle of this decade. Prudhoe Bay was originally expected to produce about 9.5 billion barrels of oil but it has now given up more than 13 billion barrels of crude, Weiss noted. “A gas project wouldn’t have worked all those years ago. That additional oil recovery was worth far more than a gas project would’ve been at the time so it’s a wonderful thing that we got that additional 3 billion barrels of recovery from what we did with the gas for all those years,” she said. ”So now is the time to see if we have a project and it works out with the field life in Prudhoe Bay.” When the AOGCC issued its decision in 2015 approving gas offtake from Prudhoe, the capital cost for Alaska LNG Project was roughly pegged at $45 billion to $65 billion. It has since been cut through multiple rounds of engineering down to about $39 billion, according to AGDC leaders. Weiss stressed that cutting the project’s overall cost of supply, which includes, but is not limited to, the immense capital expense, continues to be imperative even with the progress that’s been made. It’s something the producers each track very closely and have specific, if fluid, targets for. That cost of supply target was in the range of $10 to $11 per million British thermal units, or mmbtus, a standard unit in the LNG industry, in 2013-14 when work started in earnest on the Alaska LNG Project, according to Weiss, and it has fallen significantly since. “I remember when it fell to $8 and we really had to scramble and come up with…what are some additional levers, what can we do?” she recalled. “The bar is lower now and I’ve got to dive in there and understand — where are we?” AGDC leaders have said they believe the cost of supply for delivered gas to Asian customers from Alaska LNG is now in the $7 range. Weiss said she has an idea of what the target should be based on current market conditions but she’s “going to reserve that one” for now. To that end, there is still some confidential information Weiss has from her years with BP that she can’t use in her new role with the state gasline corporation, but much of it has an expiration date “when it’s not helpful” to BP, she said. “What’s really helpful, from my perspective from BP, is just being a participant and understanding a lot more about how these projects work,” Weiss said. “There’s less of this sensitive information than you might think because of time.” Elwood Brehmer can be reached at [email protected]

Merger may shift timing of Pikka development decision

The future of the multibillion-dollar Pikka oil project on the North Slope is unclear, but what is almost certain is that it will be changing hands for the third time in six years. Papua New Guinea-based Oil Search, which owns Pikka, announced a merger with Australian-based Santos Ltd. Sept. 10 that will collectively give current Santos shareholders 61.5 percent ownership in the new venture, according to a joint statement from the companies. Leaders of the South Pacific producers confirmed in early August that they were in negotiations and on Sept. 6 publicly extended a due diligence review period for the deal by one week. Oil Search bought into Pikka in the fall of 2017, when it agreed to an $850 million deal with then-operator Armstrong Energy and a silent minority owner to take a 51 percent stake in the project over two payment tranches. Armstrong Energy, a Denver-based explorer, had taken over the operator position at Pikka from Spanish major Repsol in late 2015. Repsol remains a 49 percent working interest owner in the project. Oil Search has since finished permitting the overall Pikka development plan and has all of the gravel laid that it needs to commence construction of the facilities for a first, scaled-back phase of the project, Oil Search Alaska Subsurface Senior Vice President Mark Ireland said during a Sept. 9 presentation to the Alaska Support Industry Alliance, a resource industry trade group. Ireland said shortly before the formal merger announcement that Oil Search leaders expected to make a final investment decision, or FID, on the $3 billion first phase of Pikka this year. “The headwinds from the merger may cause some issues (with the decision) but the team’s dedicated to delivering what we need to,” he said Sept. 9. Santos and Oil Search are similarly situated firms, according to Ireland, who said they are both primarily regional gas players that also already jointly own some assets in Papua New Guinea and are looking for opportunities to grow outside of that area. “That’s why Oil Search came here (to Alaska),” he said. Santos spokesman James Murphy, in responding to emailed questions about what the deal means for Oil Search’s Alaska assets, referenced an August statement from Santos officials that said they “would be supportive of Oil Search working towards (front-end engineering and design) and FID as publicly announced.” Oil Search Alaska spokeswoman Amy Burnett wrote via email Sept. 14 that the company’s Alaska employees were waiting to learn more about what the merger means for their work as well. Oil Search leaders stressed in the joint announcement with Santos that the merger will give their shareholders the ability to participate in a larger company with greater access to capital. “The combined entity will have the capacity to deliver on an exciting pipeline of organic growth opportunities,” Oil Search Chairman Rick Lee said. Current Santos CEO Kevin Gallagher will lead with the combined company, according to the joint statement. “The merger will create a company with a balance sheet and strong cash flows necessary to successfully navigate the transition to a lower carbon future with the combination of Santos’ leading (carbon capture and storage) capability combining with Oil Search’s ESG programs in PNG and Alaska to provide a strong foundation.” Santos and Oil Search are expected to have a combined market capitalization of approximately $15 billion. Oil Search shareholders are tentatively scheduled to vote on the merger Nov. 29 and the deal would then be effective Dec. 2 if it is approved, according to a timeline provided by the companies. Oil Search leaders slowed the pace of work at Pikka and significantly revised their plans last year after the economic realities of the pandemic forced them to cut approximately $80 million from what was a $400 million North Slope capital plan for 2020. “We were knocked flat in the dirt and had to pick ourselves up,” Ireland said of 2020. “We had planned to have a much larger facility and three drill sites instead of one but with the collapse in oil prices and issues around the pandemic we had to regroup and that’s what we did.” What resulted was the current plan for a single drill site capable of producing up to approximately 80,000 barrels per day from 43 total injector and producer wells with startup in 2025. Oil Search Alaska applied with the state as recently as mid-2019 to move its original first-oil target of late 2023 up a year to produce up to 30,000 barrels per day starting in 2022. At the time the company envisioned a $5 billion project capable of production upwards of 120,000 barrels per day. As it stands, the current Pikka plan incorporates truck-able modular facilities that will give project managers flexibility in the logistics and timing of the development, according to Ireland. Oil Search leaders have openly acknowledged the fact that the company has had a difficult time securing funding for the project and Ireland said it stems at least partly from the large banks and other lenders that will no longer finance Arctic oil and gas projects. “We’re not leaving any stone unturned and we’re making, I’ll say, good progress but it’s not an easy road to travel right now,” Ireland said of financing Pikka. Industry analysts have said the increasing reticence in the finance world towards Arctic oil and gas developments would have little impact on the largest producers on the North Slope, such as ConocoPhillips and ExxonMobil, which have other avenues for funding, but would likely impact mid-sized companies looking for large amounts of development funding such as Oil Search. At the same time, many analysts also insist that Pikka will almost certainly be developed at some point given its location on state land between ConocoPhillips’ mature Kuparuk River and Alpine oil fields and its relatively shallow, conventional Nanushuk oil resource, regardless of which company ultimately starts producing it. Elwood Brehmer can be reached at [email protected]

Convention centers stay hopeful in 2nd year of cancellations

What was supposed to be a celebrated return to a form of normalcy became topsy-turvy as spiking COVID-19 case counts are disrupting a second fall convention season in Anchorage for event planners and those behind the scenes. Greg Spears, general manager for both of Anchorage’s city-owned Egan and Dena’ina convention centers sums up the last year-and-a-half with one word: brutal. According to Spears, his team has fielded event cancellations totaling roughly $600,000 in just the past month as the resurgent virus, fueled this time by the infamous delta variant, continues to hammer many service-based industries. Revenue from room rentals this year is trending at about twice the level of last year but is still only about half of what the Egan and Dena’ina generated in 2019, which Spears referred to as a “decent year.” He has taken the approach of doing everything reasonably possible to accommodate everyone who wants to hold in-person gatherings, whether that can still happen now or needs to wait. Once-standard policies of 60 percent deposit refunds for cancellations within 60 days and no refunds inside of 30 days before an event have been relaxed. It has mostly been around that one-month out timeframe that most event organizers have sought to postpone or outright cancel their plans, Spears said, and staff for the downtown convention centers have done their best to accommodate. “We have been very flexible the last 18-19 months because we understand the situations our clients are in,” Spears said in a Sept. 14 interview. “We’re working with every client so we can hopefully one day get their events back in the building.” While the centers have sizable reserves to draw on from years of profitability, it has not made laying off nearly 100 workers and other unforeseen obstacles any easier to navigate, he added. The Alaska Oil and Gas Association was among the first local organizations to move its annual conference back in recent weeks. Originally scheduled for Sept. 2 at the Dena’ina Center, leaders of the industry trade group decided in early August to push the event to mid-January in an attempt to keep attendees as comfortable and safe as possible while also recognizing the deeply rooted desire a growing number of people have to meet again, CEO Kara Moriarty said. Normally a gathering of about 500 people, the size of the AOGA conference also necessitated considering the potential impact on hospital capacity by holding it as once scheduled, according to Moriarty. “We also consciously made the decision not to go virtual because our audience is ready for an in-person event,” she said. Moriarty also corroborated Spears version of how the cancellations are being handled by convention center officials, saying they were in “lock-step” with each other on the decision to postpone, again. Once scheduled for May, AOGA’s conference had already been moved once this year. “(Dena’ina Center staff) were really great but we had been in communication with them the whole time,” Moriarty said. “We moved our date before they had to incur costs they couldn’t recover.” She said similar things about the guest speakers and sponsors, nearly all of whom agreed to reschedule or roll deposits to January instead of backing out altogether. “I don’t think anyone’s asked for a refund. At this point, everyone is just, ‘OK, see you in January,” Moriarty said. Alaska Federation of Natives leaders also decided in late August to push their three-day conference — one of the largest gatherings annual gatherings of its kind in the state — back to mid-December instead of committing to another wholly online event as was done last year. The AFN convention is also held at the Dena’ina Center when it is in Anchorage. Visit Anchorage CEO Julie Saupe said Outside groups that hold events in Anchorage are modifying plans as well. Some events first booked for last fall and rebooked for this year are now being pushed to 2023 or 2024 because plans for the interim years have already been made, she said. More than 1,000 people from Outside were expected to attend the IEEE Signal Processing Society International Conference on Image Processing in Anchorage Sept. 19-22, according to Visit Anchorage spokesman Jack Bonney, who wrote via email that Visit Anchorage officials are working on options with that group and others toward meetings in the city in future years. Overall, about 70 percent of the events once planned for the Egan and Dena’ina that have been altered since March 2020 have already been rebooked and more rebookings are expected, according to Bonney. Anchorage Economic Development Corp. CEO Bill Popp said his group, which holds some of the city’s largest luncheons each year, is planning for an in-person 2022 Anchorage Economic Forecast Luncheon in late January after staying virtual for its annual 3-year Economic Outlook presentation held in early August. At the time, COVID-19 cases were just starting to increase significantly across Alaska. “I think people are ready to get back in the three-dimensional world. I think that networking, collegiality are tangible benefits in the minds of most of our constituents,” Popp said. “The business community, community leadership, the public — they all want to be in the room.” Adding to the challenges for Spears have been the widespread labor and supply shortage that has hit the convention centers as well. “Restarting for the Foo Fighters concert here a couple weeks ago was just a major headache in staffing. We enlisted volunteers, took help from family and friends. I myself took on different roles checking vaccination cards and whatnot,” Spears said, adding that several members of his core, full-time staff are also currently sidelined with COVID-19 infections of their own. However, the clear pent-up demand for large gatherings at some point keeps him upbeat about what’s to come. “Our future is bright if we can get COVID under control,” Spears said. Elwood Brehmer can be reached at [email protected]

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