Elwood Brehmer

House Majority counters Senate offer on oil tax credits

With less than 10 days left in the year’s second special legislative session and a laundry list of critical issues left to tackle, House Democrats offered Senate Republicans their own compromise to tentatively end the omnipresent oil tax debate. The Democrat-led House Majority coalition issued a statement Friday afternoon saying its members would agree to just end North Slope oil tax credits this year on the premise the Legislature would again revamp the overall production tax next year. The Legislature overhauled the production tax code in 2013 when both the House and Senate were under Republican control. That legislation, best known as Senate Bill 21, withstood an August 2014 voter initiative to repeal it by a 52-48 margin. House Majority members said during a Thursday afternoon press briefing in Anchorage that the caucus is open to compromise — just not the deal the Republican Senate Majority offered exactly a week earlier at a similar gathering. Republican legislators have urged their counterparts to pass legislation to end the state’s North Slope oil and gas tax credit program, the one thing on which both sides and Gov. Bill Walker agree. Fairbanks Republican Senate President Pete Kelly said he will reconvene the Senate July 10 to hopefully reach an oil tax and credit deal. The current special session called by Walker ends July 16. The Senate proposal to retroactively cut the payouts as of July 1 sounds good, but according to the House Majority it would not save the state the $1.5 billion over the next decade that Senate leaders purport. That’s because the version of House Bill 111 the Senate is pushing would simply switch the $150 million per year of tax credits the Revenue Department estimates North Slope operators will earn on average from direct cash payments each year to equal-value tax deductions, meaning about $1.5 billion less in future production tax revenue. The primary tax credit at the heart of the issue is the 35 percent net operating loss, or NOL, credit available to North Slope oil explorers and producers with less than 50,000 barrels per day of production. It can be earned by companies that end the year in the red as a result of exploration and development costs, low oil prices or a combination of those factors. House Resources Co-chair and primary drafter of the original HB 111, Rep. Geran Tarr, D-Anchorage, said swapping out the cashable tax credits for like tax deductions would just prolong the oil tax fight. “Our concern is the industry needs stability,” Tarr said Thursday. “They need to have whatever incentive program — something we actually can afford, which has not happened over the last few years. So if you replace it with something that’s the same amount of money I have every reason to believe that would not be affordable either.” A year ago Senate Republicans were dead-set against changes to the North Slope tax credits while reluctantly agreeing to phase out credits for Cook Inlet operators. But continued low oil prices translating to less state revenue and political pressures caused them to reverse course on their stance. The Senate Majority also floated the proposal to “ring fence” deductions, or require they only be used to offset production from the project through which they were earned, a provision suggested by Walker in his pitch for a broader fiscal plan compromise to alleviate the state’s $2.5 billion-plus annual budget deficits. However, they are still fighting the House Majority on changing the underlying production tax code. “Creating fair oil tax reform is a priority for our coalition and is vital to any comprehensive fiscal plan,” Anchorage Democrat and House Majority Leader Rep. Chris Tuck said Thursday. Republicans and industry representatives stress keeping the 35 percent tax deduction is critical to maintaining the viability of future North Slope developments, noting that the ability to deduct expenses or losses from a tax liability is a fundamental feature to nearly any net tax regime, whether it is a personal or corporate income or a severance tax. The problem with the status quo, according to the House Majority — particularly at current oil prices — is the effective production tax rate doesn’t come close to matching the 35 percent loss deduction. Therefore, the House coalition is pushing for a simple 25 percent net profits production tax with a corresponding 25 percent loss deduction. While applying deductions to a net profits tax is a nearly universal practice, the percentage of a loss that can be applied to reduce a tax obligation also usually matches the statutory tax rate. Alaska’s current oil production tax has a base rate of 35 percent, but that is only applicable to oil produced from the state’s large and mature fields at prices in the $150 per barrel range. As prices fall the major oil producers can apply per barrel credits that increase in value as the price falls to lower the effective tax rate. According to the state Tax Division, the effective production tax rate on legacy oil under current law is 20 percent at $90 per barrel and down to 8.1 percent at $70 per barrel. Producers operating more recent developments can apply a fixed $5 per barrel credit to reduce the taxable value of their oil regardless of price and are eligible for other tax reductions. The House Democrats contend their tax proposal would generate about $800 million in additional production tax revenue over the next 10 years and more closely resemble other profits-based tax systems. Republicans argue the lower tax rates at lower prices are necessary to offset the unavoidably high North Slope operating costs. They also point to increased North Slope production over the past two years — historical anomalies — as proof the current tax structure is working. According to the Democrats, the state isn’t seeing the benefit of the production boost and won’t in the future with the current tax and oil price regimes because the deductions will evaporate virtually all of the production tax revenue before it reaches state coffers. Tarr called the Senate’s idea to retroactively end the cashable credit certificates July 1 “unworkable.” The state fiscal year started July 1, but companies pay their taxes on the calendar year. Additionally, Republican legislators have long said tax changes need to be made prospectively and both version of HB 111 passed by the House and Senate have Jan. 1, 2018, effective dates, which made the July 1 idea a surprise. Tarr said she was also caught off-guard by the Senate Republican’s June 29 press conference and credit proposal because the sides were talking behind the scenes. “We had been in conversations and I thought the conversations were really productive,” she said. The senators stressed at the June 29 press conference that the state is currently accruing a credit liability of about $1 million per day; so ending the program six months sooner could save the state nearly $200 million. Tarr also chairs the conference committee on HB 111 and thus it is ultimately her decision as to when the committee meets because it is a House bill. Walker added the Senate’s version of HB 111 to the special session call after the two bodies agreed on an operating budget June 22. Tarr said in a brief interview that she thought there was agreement to raise the gross minimum tax floor to 5 percent from the current 4 percent, which would raise an estimated $45 million per year, as well as consensus on smaller provisions. The large producers are now paying the gross tax minimum at the current price of less than $50 per barrel. The net profits tax kicks in at about $70 per barrel. Ensuing negotiations will determine if House members join the Senate back in Juneau next week. “If we can see some progress in some preliminary discussions I think (holding meetings) would be worthwhile, but it’s very costly for people to go to Juneau and be there if we cant resolve those issues,” Tarr said. She indicated a desire to have the Legislature’s new suite of oil and gas consultants testify before the conference committee as a means to a public dialogue but said Senate leaders prefer to stick to tradition and use conference committee meetings to formalize what was agreed to in private negotiations. The Legislative Budget and Audit Committee has contracted with Houston-based oil and gas consultant firms Gaffney Cline and Associates and Palantir USA Inc. It also renewed its contract with Rich Ruggiero, a longtime industry engineer and founder of the oil economics consultant firm Castle Gap Advisors who testified extensively on HB 111 and legislators in both parties generally liked. Elwood Brehmer can be reached at [email protected]

Murkowski takes another crack at energy bill; OCS review opens

As promised, Sen. Lisa Murkowski is taking another shot at the major task of updating the country’s energy policy. Murkowski introduced the Energy and Natural Resources Act June 28. The omnibus energy reform bill is pretty much a continuation of the Energy Policy Modernization Act, which died last December when House and Senate conference committee negotiations stalled. “This new bill encompasses a wide range of Alaska priorities for energy, resource, innovation, infrastructure and land management policies. It will allow us to tap into more of our world-class mineral base, removes hurdles to the gasline, expand the use of hydropower and other renewables, reauthorize critical programs that provide vital funding, boost Alaska Native energy development, increase sportsmen’s access to federal lands and protect against natural hazards,” Murkowski said in a release from her office. “This is a bill written by and with Alaskans, for the benefit of our whole state and I’m eager to work with my colleagues to move it forward.” Murkowski, who chairs the Senate Energy and Natural Resources Committee, often stressed that last session’s Energy Modernization Act was also drafted in concert with Washington Sen. Maria Cantwell, the ranking Democrat on the committee and a co-sponsor of the current bill. Last year’s legislation passed the Senate with 85 votes and Murkowski blamed House leaders — who she accused of being more interested in leaving for the holidays than working on the bill — when it fell just short of making it to the president’s desk. This go-round, Murkowski got Senate Majority Leader Mitch McConnell to put the Energy and Natural Resources Act on the Senate Calendar right away, giving the bill an expedited timeline for a floor vote, according to a committee release. Among many other provisions, the bill federally classifies hydropower as renewable energy; gives route options for a natural gas export pipeline through Denali National Park; mandates the Secretary of Energy to rule on LNG export applications within 45 days after the environmental review of a project is finished; and directs a suite of permitting reforms for energy generation and distribution and mineral projects. Arctic OCS plan In between scolding President Donald Trump on Twitter for regular off-hand remarks on social media, Murkowski praised the Trump administration June 29 for working to reverse a ban on federal Arctic offshore oil and gas leasing instituted by President Barack Obama in the waning days of his presidency. In April, Trump issued his own executive order to reverse Obama’s moratorium on Arctic offshore leasing. On June 29, the Interior Department issued a request for information to revise the 2017-2022 outer continental shelf, or OCS, oil and gas leasing plan the Obama administration finalized in November sans a schedule for any Arctic lease sales. The request for information is the first step in what is likely to be a multi-year process to revise the leasing schedule. Interior Secretary Ryan Zinke also ordered onshore oil and gas resource evaluations for the Arctic National Wildlife Refuge and a new look at the management plan for the National Petroleum Reserve-Alaska during a trip to Anchorage May 31 with an eventual aim at more industry activity on federal North Slope lands. “I’m pleased the administration has wasted no time in starting the process for a new and better plan that could increase offshore development in Alaska and elsewhere,” Murkowski said. “With technological innovation, offshore development is now cheaper, easier, safer and farther-reaching than ever before. “What has not changed is that offshore development is a critical source of energy, jobs and security, so I look forward to working with Secretary Zinke to develop a strong plan for our state and nation.” Arctic development in near shore state waters to date has consisted of constructing manmade islands and Hilcorp Energy is currently in permitting for its Liberty prospect, which would be the first such manmade island project in shallow federal waters off the North Slope. The U.S. Geological Survey estimates the Beaufort and Chukchi Seas could hold 23 billion barrels of oil and another 104 trillion cubic feet of natural gas. Even with federal support to drill for those resources, it is unclear how much interest industry would have in green field development in such a high-cost arena with oil and prices expected to remain low for years to come. ^ Elwood Brehmer can be reached at [email protected]

State, Korean gas buyer agree to collaborate on AK LNG

The state gasline corporation reached a preliminary agreement with one of the largest LNG buyers in the world June 28 in Washington, D.C. Alaska Gasline Development Corp. President Keith Meyer and Korea Gas Corp. CEO Seung-hoon Lee signed a memorandum of understanding that puts in place a framework for the two state-run corporations on opposite ends of the LNG trade to work on development of, and possibly investment in, the $40 billion Alaska LNG Project. Under the MOU, AGDC and Kogas, as it is commonly known, will set up a joint committee that will have decision-making authority to collaborate on Kogas’ potential involvement in development and in some fashion operations of the project, according to AGDC. “This MOU between AGDC and Kogas is beneficial for both organizations. AGDC gains the opportunity to move Alaska LNG forward with an internationally recognized natural gas infrastructure company,” Meyer said in a corporate release. “Kogas gains the prospect of investing in Alaska LNG as well as participating in all aspects of project development and financing. The MOU is not exclusive and recognizes AGDC is in discussions with other parties to ensure timely development of Alaska’s energy infrastructure and export project.” Kogas is the main LNG buyer in South Korea and the second-largest corporate LNG buyer in the world. South Korea is also well established as the number two LNG importing nation in the world behind Japan. In 2015, South Korea imported 33 million tons of LNG, which was about 13 percent of the global LNG trade that year, according to the International Gas Union. The Alaska LNG Project is designed to produce up to 20 million tons of LNG per year at full capacity, but that would almost certainly be split amongst numerous buyers. AGDC’s top priorities this year are marketing the Alaska LNG Project to potential buyers and investors and subsequently establishing a commercial structure to underwrite construction of the trans-Alaska natural gas export project, Meyer has said. The corporation and Gov. Bill Walker ultimately hope to have the project up and running in the mid-2020s. While the AGDC and Kogas leaders posed for a handshake after signing the MOU, their bosses were also meeting in Washington, D.C., as part of President Donald Trump’s “Energy Week” initiative. Walker met with South Korea President Moon Jae-in June 28 after Walker participated in an energy roundtable discussion at the White House, according to a release from the governor’s office. “Korea has been one of the largest consumers of Alaska’s coal, timber and fish,” Walker said in a formal statement. “President Moon said he would like to add LNG to the list of imports and offered his government’s support of the Alaska LNG Project. I was pleased to hear President Moon say LNG will play a very important role in helping Korea combat climate change. I also told President Moon that during my meeting at the White House, President Trump had expressed deep support for the export of LNG from the United States to Asia, including Alaska’s LNG.” AGDC is also currently holding an open season to solicit customer interest in the natural gas and liquefaction tolling project, Meyer said at the corporation’s June board meeting. The open season will run from mid-June through August and AGDC’s goal with the marketing effort is to attract non-binding deals mainly from the state’s former partners in the project, the North Slope producers, to sell gas into it. Elwood Brehmer can be reached at [email protected]

Senate wants end to oil credits now, reconvening July 10

State Senate Republicans pitched their latest plan to once and for all end refundable oil and gas tax credits much sooner than later. Senate President Pete Kelly, R-Fairbanks, said at a Thursday morning press conference in Anchorage that a combination of lower-than-expected oil prices and fewer exactable budget cuts than Republican majority members wanted has made ending the program immediately an urgent matter. For those reasons Senate Republicans proposing the final version of House Bill 111 have an effective date that retroactively ends the credits for North Slope operators and explorers elsewhere in the state July 1. The differing versions of the bill that passed the House and Senate this spring have Jan. 1, 2018 implementation dates and would end the credit program then. The senators stressed that the state is currently accruing a credit liability of about $1 million per day; so ending the program six months sooner could save the state nearly $200 million. Those payments, which under current law are for up to 35 percent of a small producer or explorer’s annual losses, would be transformed to tax deductions that could be applied immediately or held to offset future liabilities. It would be similar to how the North Slope majors that are not eligible for the cashable credits use their carry-forward production tax deductions. Legislators are unofficially adjourned from the special session Gov. Bill Walker called June 16 to address a litany of budget and fiscal issues. Kelly said the Senate will convene in Juneau again July 10 with the hope of quickly resolving the differences in HB 111 with the Democrat-led House Majority. The 30-day special session ends July 16. Both caucuses and the governor have said since before the regular session started in January that ending the credit program was a priority. However, House leaders want structural changes to the underlying oil production tax code that would simplify it while increasing taxes at current, lower oil prices. “The entire fiscal regime of how we treat our businesses that drill for oil up north may be up for discussion, but not now; the Senate wants to stick to cash payments,” Kelly said. “This is so easy we think we can go down and in a day — that might be a little optimistic — but in a day, we should be able to end these things.” Kelly then called on House Resource Committee co-chairs Reps. Andy Josephson and Geran Tarr, the Anchorage Democrats who drafted the original HB 111 and are on the conference committee, to the conference table when the Senate reconvenes. Republican legislators have long emphasized stability and prospective changes in regards to oil taxes, but Senate Resources Chair Sen. Cathy Giessel said the retroactive effective date shouldn’t be a shock to industry because it’s generally been understood the cashable work credits were on their way out. Additionally, Gov. Walker's vetoes of $630 million in credit payments over the past two years have limited the value of the credits to companies, as it is now unclear when they will be paid, she noted. Walker vetoed portions of the previous two credit appropriations to save the state from immediate expenses while facing annual budget deficits approaching $3 billion. “It will have a negative impact on companies, we know that and we regret that but the fact of the matter is the state cannot afford this anymore,” Giessel said. Caelus Energy cited tax credit uncertainty as part of the reason it decided to defer drilling an appraisal well at its very large Smith Bay North Slope oil prospect. Giessel also said Senate Republicans are on board with Walker’s proposal in his fiscal compromise to “ring fence” deductions, or require they only be used to offset production from the project through which they were earned. The ring fencing provision is intended to prevent a company from purchasing a non-producing project and “cannibalizing” the tax deductions earned by the seller for use against taxes earned elsewhere, Giessel explained. “No deduction without production,” she said without starting a chant. Rep. Tarr said in an interview that the Senate’s proposal simply masks the credit problem by shifting away from cash payments now to forgone tax revenue in the future, when the 35 percent deductions are applied with her own slogan. “Quick reaction is — we don’t want to change the name to pay the same,” Tarr said. The House proposal would set a flat 25 percent production tax rate at prices up to $100 per barrel and offset it with a 25 percent loss deduction. Democrats say the problem with the current production tax law known as Senate Bill 21 is credits built into the system ramp the tax rate down from the 35 percent statutory rate to less than half that while companies can still get deductions at 35 percent. For those reasons, the Revenue Department projects the House’s HB 111 would take in about $800 million more than the Senate’s over the next decade. At current oil prices of about $45 per barrel, the state already takes 77 percent of the profit on an average barrel of North Slope oil, according to Giessel. Tarr said HB 111 is a key revenue component of the House Majority coalition’s overall fiscal plan. She also agreed with industry’s regular criticism that the State of Alaska consistently changes oil tax policy making it hard for companies to plan, saying settling oil taxes — and other fiscal matters — for several years would give the Legislature time to focus on other major issues such as health care and education. “We think now is the time for action,” Tarr said.   Elwood Brehmer can be reached at [email protected]

Despite delays, Brooks Range says Mustang will produce in ’17

The company developing a small North Slope oil field with the help of $70 million in funding from the State of Alaska says the project will finally come together this winter after years of delay. Anchorage-based independent Brooks Range Petroleum Corp. plans to have oil flowing from its stalled Mustang project in December, according to the development plan the company submitted to the Division of Oil and Gas. The Mustang prospect is in the Southern Miluveach Unit on the west edge of the large Kuparuk River field. Brooks Range expects it to produce up to 15,000 barrels of oil per day at its peak from about 22 million barrels of proven reserves. In December 2012, the state-owned Alaska Industrial Development and Export Authority invested $20 million of the $27 million needed to build a five-mile road to Mustang and a 19-acre pad for production and processing facilities. The gravel road and pad — in which AIDEA is an 80 percent owner — were finished in April 2013. At the time, Brooks Range leaders said they wanted to have the field in production by fall 2014 and credited incentives in the just-passed and industry-supported oil production tax structure under Senate Bill 21 for improving the economics of the project and spurring it forward. In April 2014, AIDEA committed another $50 million equity investment in the $225 million Mustang oil processing facility. Brooks Range Chief Operating Officer Bart Armfield said at the time that the project would start production in late 2015 and likely peak in 2017. To date, AIDEA has invested $49.8 million of the $50 million commitment in Mustang and spent another $670,000 on project management and other in-house expenses related to the project, according to the authority. Full development of the field was estimated at about $580 million and included drilling 11 production and 20 more gas and water injection wells. With AIDEA’s investment, the Mustang processing facility would be the first such open-access facility on the Slope and hopefully help in the development of other nearby fields. Historically, independent North Slope explorers have had difficulty negotiating access agreements with BP, ConocoPhillips and ExxonMobil, which own most of the processing capacity for basin’s producing fields. AIDEA’s equity was also key to Brooks Range’s ability to secure loans to finance the remainder of the project, authority and company officials said when the deal was made. By August of 2014, Brooks Range was changing hands. Houston-based Thyssen Petroleum LLC and two partners, JK Tech Holdings Ltd. of Singapore and MEP Alaska LLC, a New York-based firm, purchased the independent oil company. Armfield then told the Journal production would start in early 2016 at about 8,000 barrels per day and grow from there with additional drilling. Thyssen, JK Tech and MEP Alaska purchased Brooks Range from Alaska Venture Capital Partners and Ramshorn Investments. However, almost as soon as Brooks Range was sold oil prices started to tumble to the current $45 per barrel range. August 2014 was the last month the average daily price of Alaska North Slope crude exceeded $100 per barrel. That put a damper on Mustang. Engineering of the processing facility and associated infrastructure started in January 2015 but was put on hold by the third quarter of the year as low oil prices hampered financing and project economics, according to the Mustang development plan Brooks Range submitted to Oil and Gas last September. Armfield declined a request for an interview regarding the status of Mustang. Now president of Brooks Range, he wrote in a December 2015 letter to then-Natural Resources Commissioner Mark Myers that the company had spend $145 million on facility engineering, reservoir evaluation, permitting, drilling and other expenses to move Mustang forward. Brooks Range completed one injection well into the Kuparuk reservoir and started a second well, but drilling challenges prevented the completion of any production wells at the time, Armfield wrote. In addition to the oil price problem, Gov. Bill Walker’s veto of $200 million out of $700 million in state oil and gas tax credit payments in June 2015 forced the Mustang development schedule to be pushed back “to deal with unfavorable economic factors,” according to Armfield. According to the Mustang plan, facility modules will be arriving to the Slope in August and September for installation and start-up to lead to first oil by December. In November 2016 then-acting Oil and Gas Director Jim Beckham wrote in a letter to Brooks Range approving a term extension of the Southern Miluveach Unit that “the division remains concerned that BPRC will be successful” in getting to first oil by the end of this year. “Based on the materials BRPC provided, it appears possible for BPRC to meet this deadline,” Beckham wrote further. “But the schedule is extremely tight and leaves little room for deviation.” The slow development of Mustang also caused AIDEA and Brooks Range to rework their financing deals for the project. AIDEA’s $50 million was to be repaid with 10 percent annual interest within seven years after the start of oil production from Mustang, or by the end of 2022, according to memo from AIDEA staff to the board of directors when the investment was approved. That repayment plan has since been pushed back to start in 2018, according to documents on the authority’s website. AIDEA spokesman Karsten Rodvik wrote in response to questions that the authority made its investments understanding the project could be impacted by the price of oil. “We are taking steps to restructure our investment to reflect current market conditions, and given these comprehensive efforts, we believe that Mustang should move forward,” Rodvik wrote in an email. AIDEA executives declined direct interview requests. Similarly, the unpaid balance of AIDEA’s $20 million share of the Mustang road and pad is to be paid starting next year. In 2014 and 2015, the authority got $11.5 million back in state oil and gas tax credits transferred from Brooks Range for its $20 million. If the project ultimately is unsuccessful, AIDEA’s stake in MOC1 LLC, the company set up for the processing and production facility investors, provides the authority multiple forms of collateral, such as the equipment that would be used in the facility, according to Rodvik. “Additionally, MOC1 has real estate security interests in the Mustang oil and gas leases, and other North Slope oil and gas leases in which the owners of Brooks Range Petroleum Corp. have a working interest,” Rodvik wrote. “If Mustang were not to go into production and the other parties default on their payment obligations, MOC1 can foreclose on the lease positions to sell those to third parties.” Getting Mustang to first oil in 2017 is important because the company needs to drill and test a viable production well and either be in production or be working towards it by Dec. 31, according to Beckham, which is when the unit is set to expire. DNR officials referred questions about Mustang’s progress to Brooks Range. The department terminated the nearby Tofkat Unit held by Brooks Range in 2016 after the company held the acreage for years without doing much with it. In the case of Tofkat, Brooks Range allegedly was unable to secure an access agreement with Kuukpik Corp., the Alaska Native village corporation that holds surface rights to the state leases. ^ Elwood Brehmer can be reached at [email protected]

Interior Dept. grants state survey permit for King Cove road

The State of Alaska is preparing to build a long-debated road on the Alaska Peninsula as legislation authorizing the project inches its way through Congress. Gov. Bill Walker said in a June 26 statement from his office that Interior Secretary Ryan Zinke called him that morning to notify the governor that the Interior Department had granted the state permission to survey a route for a road between the communities of King Cove and Cold Bay. “For far too long, King Cove residents suffering medical emergencies have had to brave harsh elements just to get health care,” Walker said. “They travel by boat or helicopter — often in inclement weather — to access the Cold Bay airport in order to be medevaced out. Our fellow Alaskans deserve better than that. I’m grateful to Secretary Zinke for recognizing that need and doing his best to advance the process to build that life-saving road.” For the next few weeks Alaska Department of Transportation surveyors will be working to identify the least impactful route for the road through the Izembek National Wildlife Refuge. The work should be done by mid-July, according to the governor’s office. On June 27, the House Natural Resources Committee approved a bill introduced by Rep. Don Young to authorize an equal-value land exchange between the State of Alaska and the federal government to give the state the 206 acres of the Izembek refuge that it would need for the 11-mile road right-of-way to complete the roughly 30-mile, single-lane gravel road. The legislation, which was also introduced in the Senate by Sens. Lisa Murkowski and Dan Sullivan, would allow for up to 43,000 acres of state land to be added to the refuge and swapped for the 206 acres of refuge land. That is very close to the swap that passed Congress and President Barack Obama approved in 2009. In 2013, Interior Secretary Sally Jewell chose the “no action” alternative and rejected the exchange — preventing the road — after the Fish and Wildlife Service determined the road itself would damage critical waterfowl nesting areas and could lead to additional habitat damage through increased access to the refuge. True to form, Young pulled no punches in a press release statement when his bill moved. “Secretary Jewell’s heartless denial of the King Cove emergency access road was a willful and deliberate dismissal of human life in the name of wildlife; it represented one of the worst government actions I’ve seen in all my years in Congress,” Young said. “And since that decision, the community has experienced 53 medevacs in often treacherous conditions. This legislation is an important step to ensuring the people of King Cove have safe and reliable transportation during medical emergencies.” The 315,000-acre Izembek Refuge surrounds the village of Cold Bay and is home to entire populations of some waterfowl species, such as the Pacific black brant, at certain times of the year. The road would give King Cove residents in urgent need of medical care a reliable link in bad weather to the large World War II-era airport at Cold Bay. Conservation groups and the Yukon-Kuskokwim Delta-area Association of Village Council Presidents have pushed back against efforts by the state and the delegation to build the road. AVCP wrote to Jewell in 2013 about a worry it could impact the populations of geese western Alaska residents hunt for subsistence. In February the Alaska Legislature unanimously passed a resolution in support of the construction project. DOT has the road listed as a $30 million project in its Transportation Improvement Plan for fiscal year 2019 and differing state House and Senate versions of the fiscal 2018 capital budget each reappropriate $10 million of unspent DOT funds to start paying for what is known to most as the King Cove road. ^ Elwood Brehmer can be reached at [email protected]

Sun hasn’t set yet on ANWR

Alaska oil advocates lauded Interior Secretary Ryan Zinke’s order directing federal agencies to reevaluate the oil and gas potential within the National Petroleum Reserve-Alaska and the coastal plain of the Arctic National Wildlife Refuge, but what did it get them? The answer, unsurprisingly, will largely depend on how much money is willing to be spent and who will spend it. The secretarial order, signed May 31 in front of a cheering crowd during the Alaska Oil and Gas Association’s annual conference in Anchorage, directed resource evaluators in the U.S. Geological Survey and the bureaus of Land Management and Ocean Energy Management to send operational plans within 21 days of the order to execute the resource assessments up the chain of command. By all counts, those plans and budgets for them were submitted on time. Next, the Counselor to the Secretary for Energy Policy is supposed to collate the three plans into a document for Zinke — himself a geologist by trade — to review by July 1. While the USGS is the federal government’s collection of underground experts and their associated data and has done hydrocarbon resource assessments in the past, BOEM stores and interprets resource data for BLM, which manages the NPR-A, according to USGS Senior Research Geologist David Houseknecht. Houseknecht led or participated in the drafting of similar assessments of the NPR-A in 2002 and 2010 and the ANWR coastal plain in 1998, and is well-regarded by many geologists that have studied the North Slope. He declined to comment on the details in the USGS plan as it is still in the amendment phase, but said without additional funding it would be unlikely that his agency would be able to gather much new data. Key new information would almost certainly come in the form of 3D seismic data, the acquisition of which has in recent years pretty much become an industry standard prerequisite for nearly any investment in a prospect. A seismic program conducted from 1983 to 1985 in the 1.5 million-acre ANWR coastal plain collected 1,180 miles of 2D data, but geologists today often compare it to an X-ray of the earth; 3D seismic is likened to an MRI. During the winter of 1985-86 Chevron and BP partnered to drill the KIC-1 exploration well on ANWR in-holdings owned by Kaktovik Inupiat Corp. and Arctic Slope Regional Corp. It is the only well drilled in ANWR and what was found remains one of Alaska’s best-kept secrets. As for the NPR-A, Houseknecht hinted that Interior leaders might want to get the assessment done before much new data can be collected. “With the timeframe we have to work with it’s unlikely any new seismic will be acquired within the NPR-A, but certainly the workflow will include the USGS and BOEM together analyzing data that already exists,” he said. Zinke’s order states the joint assessment plan for the NPR-A and Section 1002 of ANWR “shall include consideration of new geological and geophysical data that has become available since the last assessments, as well as potential for reprocessing existing geological and geophysical data.” While that may not sound very exciting to those hoping for a comprehensive new look at the oil potential of the state-sized federal holdings on each end of the North Slope, Houseknecht said there is already a lot of 3D data available for the northeast portion of the NPR-A, which is the area closest to existing oil infrastructure. Companies occasionally provide seismic data to government geologists for licensing and evaluation on the premise the data itself remains private. The ANWR coastal plain is regularly called the “1002 area”, a reference to the section of the 1980 Alaska National Interest Lands Conservation Act, or ANILCA, that describes it. ANILCA established many of the designated federal areas in Alaska, including ANWR. Section 1002 of the exhaustive legislation called for the initial wildlife and hydrocarbon resource assessments and outlines the subsequent steps for oil and gas exploration and development if Congress were to approve it. Federal refuges are usually off-limits to such activity, but the proximity of the coastal plain to the mega fields of the central North Slope pushed Congress to make an exception regarding ANWR. When ANILCA was passed the country was also heavily dependent on imported oil and the 1973 OPEC embargo on exports to the U.S. was not a distant memory. Alaska’s congressional delegation has long led a Republican effort in Congress to pass legislation opening the 1002 for exploration. It passed Congress once as an amendment to a budget bill President Bill Clinton ultimately vetoed in 1996. President Donald Trump has $2 billion in revenue from an ANWR lease sale in his 2018 budget proposal. The Alaska delegation has again introduced legislation to open the coastal plain to exploration drilling. The bills in the House and Senate set a cap on impacted areas at 2,000 acres on the presumption exploration could be done in the winter and any development would fully utilize new long range drilling technologies. The USGS last updated its oil and gas resource estimate of the coastal plain in 1998 and leaned heavily on the data from the mid-80s to do it, according to Houseknecht. The agencies’ calculations were large but speculative; the mean estimate for technically recoverable oil in the ANWR coastal plain was 7.6 billion barrels, with another 3.5 trillion cubic feet of extractable natural gas. “I’m asked every year, ‘Why hasn’t the USGS not updated its 1998 assessment?’ My first answer is always, ‘There is no new information,’” Houseknecht said. “One thing that could be done would be to reprocess the old 2-dimensional data that were collected in 1984 and ’85 because in the last 20 years seismic processing has made leaps and bounds in terms of the capacity to enhance old data.” Integrating data from adjacent areas and a couple offshore wells that wasn’t available before could be of some benefit as well, he added. To attract bids, a lease sale would almost certainly require substantial 3D seismic data to be available to companies, Houseknecht said further. In 2013, former Gov. Sean Parnell’s administration, which included current Sen. Dan Sullivan as Natural Resources commissioner, submitted a work plan to the Interior Department that would’ve had the state fund up to a $50 million winter 3D seismic shoot in the 1002 area. The administration attempted to use a section of ANILCA that it believed allowed any entity to submit a qualifying exploration plan for the area, but then-Interior Secretary Sally Jewell rejected the proposal and ultimately had her decision upheld by the U.S. District Court for Alaska. Current DNR Commissioner Andy Mack said the Parnell administration had a solid plan. “Understanding the resource potential in that area is critically important,” Mack said in a June 14 interview. The Walker administration is open to resubmitting a winter seismic application for ANWR, according to Mack, and would be happy to partner with industry on an application as well. Mack also said the administration is willing to support the effort financially at some level, but neither he nor Houseknecht could say how far $50 million would go. “That was 2013 — different budget times,” Mack said. “But I think most Alaskans would look at this as a solid investment in the future.” Alaska environmental groups were not pleased with Zinke’s order, contending it is the first step towards drilling in the renowned refuge. However, Mack said he believes a very large majority of Alaskans want to see ANWR opened up. In early 2015 the state Revenue Department estimated large-scale oil production in ANWR could eventually net the State of Alaska upwards of $150 billion, but that was at $100 per barrel oil. Under current federal law the state would receive 90 percent of royalty revenue from production, but that could change in legislation to open it to drilling, if it were to pass. The state production tax would also apply. NPR-A Recent large oil finds in or adjacent to the eastern portion of the NPR-A mean it’s almost a given the resource estimate figures for the 22 million-acre parcel would go up significantly, according to Houseknecht. The NPR-A was last assessed in 2010 when the USGS estimated it holds about 900 million barrels of recoverable oil and a very large natural gas resource with a mean estimate of 53 trillion cubic feet. That was after a 2002 assessment put the expected mean oil resource at more than 9 billion barrels. “I was on everybody’s dirty list when I reduced the oil estimate, or we did, in 2010,” Houseknecht recalled. The 2002 estimate was based in part on the assumption that the oil in the Alpine formation found on the east edge of the reserve continued halfway into it, he added. But within two years ConocoPhillips had drilled exploration wells west of Alpine that found mostly gas and little oil. So the 2010 assessment was scaled back, and it put the largest NPR-A oil accumulations in the 250 million-barrel range and said the largest finds in the Nanushuk or Torok stratographic trap formations would likely recover about 10 million barrels. Last October Caelus Energy announced it discovered up to 2.4 billion recoverable barrels in the Torok formation in the state waters of Smith Bay, just offshore from the NPR-A. ConocoPhillips also revealed its discovery of 300 million recoverable barrels in the Nanushuk in the NPR-A in January. Repsol and Armstrong Energy are working a 1.2 billion-barrel-plus Nanushuk prospect just to the east of the NPR-A. The large number of bids in the 2016 NPR-A lease sale indicated renewed industry interest there, too. Zinke’s order also called for a review of the NPR-A Integrated Activity Plan, and the prospect of more oil in the reserve could be used as support for reopening areas closed to leasing under the last NPR-A plan in 2013. If the land-use plan for the NPR-A is overhauled it won’t happen quickly, as it involves a multi-year environmental impact statement. “As new data becomes available our perspective changes on these rocks and how much oil they may contain,” Houseknecht said. ^ Elwood Brehmer can be reached at [email protected]

BP: time of transition for energy markets

Improved efficiencies at nearly every level of the energy game has put markets in flux, according to BP’s Statistical Review of World Energy released in June. For Alaska, that has led to a buyer’s market in the global LNG trade, fading coal demand and oil prices that will be “lower for even longer,” BP Alaska Commercial Vice President Damian Bilbao said. Bilbao presented the highlights of the company’s annual report to the Anchorage Chamber of Commerce June 26. “The new normal in energy consumption is growth in consumption coming from developing countries,” he said. More than half of global economic growth in 2016 occurred in China and India, according to Bilbao. However, while China’s economy grew by about 6 percent last year, its energy consumption grew by just 1 percent. That is in line with a change in the general relationship between economic growth and energy consumption, he said. According to BP, global energy demand has historically grown about 2 percent per year. Inversely, the amount of energy needed to produce one unit of gross domestic product, known as energy intensity, has generally decreased by about 1 percent per year, as the world becomes more energy efficient. In 2016, global energy demand grew slower than normal, about 1 percent, and energy intensity remained at its usual 1 percent per year decline. “There’s something changing fundamentally about how energy demand is met globally,” Bilbao said. Increased use of natural gas and renewable energy, which has primarily displaced coal, kept global carbon emissions virtually flat for the third consecutive year, according to BP. The global oil trade largely rebalanced itself last year and as a result there was a modest increase in prices early this year. Lower 48 oil production declined by about 400,000 barrels per day, the first domestic production drop since 2008. Overall non-OPEC production fell by about 800,000 barrels per day, the largest single-year decline in nearly 25 years, according to BP’s data. Additionally, OPEC’s prescribed production cut of about 800,000 barrels per day that started in November has helped production more closely match demand, Bilbao said. At the same time, slower than historical demand growth and the oil supply buildup has kept global oil inventories higher than expected and prices lower. Bilbao also said lower drilling rig count figures don’t necessarily mean less production to come anymore. The report states that new well production among Lower 48 shale drillers increased 40 percent per rig per year in 2015 and 2016. That led to oil production growth from Texas’ Permian basin despite a 75 percent drop in the number of drilling rigs in the field. “A rig operating in the Permian today is equivalent to more than three rigs at the end of 2014,” the report states. Those operational efficiencies have led to a resurgence in shale production in 2017, which has partially offset OPEC’s output curbs and put prices that approached $60 per barrel early this year back to the mid-$40s. According to the Energy Information Administration, the 50-year average price for oil adjusted for inflation is just less than $50 per barrel. Bilbao said it also shows OPEC’s influence can tweak oil markets in the short-term, but the cartel cannot stop long-term structural market shifts. On natural gas, low prices led to just a 0.3 percent increase in production globally, which was the weakest such growth in 34 years, according to BP. However, global demand increased by just 1.5 percent, compared to the 2.3 percent 10-year average. U.S natural gas production fell by 2.6 percent in 2016 after growing 4.2 percent per year since 2005; but that was largely offset in the world arena by Australia, which had multiple LNG projects come online last year and increased its gas production by 25 percent. Also, for the first time in history, the U.S. is not the largest producer of renewable energy. While domestic renewable energy production grew by nearly 17 percent last year — and accounted for 19 percent of global renewables — China upped its renewable energy output by a full one-third in 2016 to become the global renewable leader. Renewable energy only makes up about 4 percent of global energy consumption, but Bilbao said its growth is primarily being driven by economics and not political motives. The economic viability of renewable forms of energy, and to a greater extent low natural gas prices, have put coal on the backburner. U.S. coal production fell by 19 percent in 2016 but still accounted for 10 percent of global output. China produced about 8 percent less coal in 2016, but still dominated the market with 46 percent of global supply. But according to BP, a move by the Chinese government to improve profitability of its coal mines could have hurt the global solid fuel market. Among other measures, China reduced coal production in 2016 by limiting the days its mines could operate from 330 to 276. That led to coal prices in China jumping from less than $60 per metric ton in January 2016 to roughly $100 per ton by the end of the year. “The events in China spilled over into global coal markets, with world prices taking their cue from China,” the BP report states. “This rise in global coal prices further depressed global coal demand, particularly in (the) power sector around the globe, with natural gas and renewable energy the main beneficiaries.” Global coal consumption fell by 1.7 percent last year and production fell “by a whopping” 6.2 percent, BP notes. Low demand for coal has caused Usibelli Coal Mine near Healy to scale back production. That has in turn hurt the Alaska Railroad, which has long hauled coal from the Interior mine to Seward for export to South American and Asian customers. In Britain, coal has pretty much come full circle, according to BP. The country’s last three underground coal mines recently closed, its coal consumption is back to levels last seen about 200 years ago at the start of the industrial revolution and U.K. electrical generators had their first-ever coal-free day in April. Elwood Brehmer can be reached at [email protected]

Hilcorp spends $3.95M on Inlet leases

Hilcorp Alaska LLC was the big, and only, winner in both the state and federal Cook Inlet oil and gas lease sales June 21. The company spent $3.95 million on combined 20 tracts on state land and in state and federal waters. Hilcorp was also the only bidder in both sales and is the primary producer of oil and gas in the Inlet. In the state Inlet sale it picked up six leases: two onshore tracts just to the north of the Beluga gas field it operates on behalf of the Anchorage electric utilities, another split onshore-offshore lease between the Ninilchik and Cosmopolitan units on the southern Kenai Peninsula and three more along the shore of Kalgin Island west of Kenai. State Division of Oil and Gas Director Chantal Walsh said it appears Hilcorp is mostly trying to fill in gaps in the state territory it holds. “We’re excited to see Hilcorp is interested in exploring Cook Inlet,” she said. Hilcorp kept its plans for its new acreage guarded in a statement to the Journal. "The leases we acquired today (June 21) help strengthen our ability to continue to provide energy and jobs for Alaskans," spokeswoman Lori Nelson wrote in an email. Hilcorp spent $922,000 on its state leases and $3.03 million on the federal tracts. The 14 federal leases Hilcorp won are just offshore from the Ninilchik and Cosmopolitan units, which are in state territory, and in the middle of the Inlet in front of Kachemak Bay. The state’s 2016 Inlet lease sale drew no bids and industry representatives said that was due in large part to the state Legislature debating whether or not to end its oil and gas tax credit program for work in the basin at the time, which it did. Companies used the credits to offset their exploration and development costs. There is also limited interest in Inlet natural gas, as production from the basin supplies the relatively small demand from Southcentral gas and electric utilities and low global LNG prices have killed the economics of exporting Inlet gas. This was also the first time in years the federal waters of Cook Inlet drew any attention from industry. According to the Bureau of Ocean Energy Management, the Inlet sale was the first federal offshore lease sale in Alaska since 2008. State and federal managers don’t hold sales if they don’t receive interest from industry prior to the public sale. Environmental groups have also lobbied the feds to quit proposing Inlet lease sales, citing the lack of interest and a fear activity could harm Cook Inlet’s endangered Beluga whales and other marine life. A state sale of Alaska Peninsula land and water did not draw any bids, which is common for the remote region. ^ Elwood Brehmer can be reached at [email protected]

ISER: State payments to local governments doubled over decade

State spending has grown to comprise nearly 30 percent of all revenue for Alaska’s local governments in recent years, according to a report from the University of Alaska Institute of Social and Economic Research published June 19. State support to Alaska’s 19 boroughs and municipalities grew from a near-term low of 12 percent of the average borough budget in 2004 to an average of 28 percent in 2015, the most recent year for which adequate data was available, study author and ISER economist Mouhcine Guettabi said. Guettabi and other ISER researchers examined audited borough financial reports to gather data for the study as a means of consolidating the most consistent, accurate figures possible. It ultimately shows that the State of Alaska’s spending habits have a dramatic effect on the amount of money available to its local counterparts. “Overall, state spending is very sensitive — or has been over the last few years — very sensitive to oil prices and that certainly makes its way down to borough government revenues,” Guettabi said in an interview. In 2000, the first year the study examined, state money paid for an average of 19 percent of borough budgets. At that time, oil prices averaged roughly half of what they are currently in nominal terms; however North Slope oil production was also more than double what it was in 2015. Unsurprisingly, the largest local governments in Alaska were generally the least dependent on state aid, as they have populations that are able to generate enough tax revenue to make them mostly self-sufficient. Between 2000 and 2015, state money made up just 4 percent of the Municipality of Anchorage’s budget, according to the study. For the Matanuska-Susitna Borough, the like figure was 11 percent, while Juneau and the Kenai Peninsula Borough each drew 14 percent of their revenue from the state over the period. The Fairbanks North Star Borough had the largest share of state support in its budget at an average of 15 percent. Conversely, the some of the smallest and remote regions of the state relied most heavily on the State of Alaska. The Bristol Bay Borough in Southwest Alaska, which doesn’t include the regional hub of Dillingham, used state funds for 31 percent of its revenue, and in the adjacent Lake and Peninsula Borough the figure was 37 percent. Haines in Southeast and the Northwest Arctic Borough each had the highest shares of state-sourced revenue in their budgets at an average of 38 percent over the study period. The outlier was the Ketchikan Gateway Borough. With about 13,700 residents in 2015, Alaska’s southernmost borough was the just the seventh-largest but state money averaged only 7 percent of its overall revenue since 2000. Ketchikan has local property, sales and lodging taxes, and the latter two capture revenue from the roughly 1 million tourists that visit the city in busy years. Guettabi said state appropriations for capital projects often made up the largest portion of state money in local budgets over the study period. Given that, it is worth noting that the 2015 fiscal year was the last year of significant discretionary spending in the state’s capital budget before oil prices and state revenue collapsed. The 2016 and 2017 capital budgets have subsequently lacked almost any purely state-funded projects. The study also examined how much boroughs would have to raise in taxes to replace the state dollars each received in 2015. Despite getting $74.3 million of state money in 2015 — more than double what any other borough received — the Municipality of Anchorage’s relatively large population means it would only have to come up with tax revenue equal to $248 for each of its nearly 300,000 residents to go state money free. The Fairbanks North Star Borough, which got $27.4 million from the State of Alaska in 2015, was the next lowest at $278 per person. To the contrary, the 887-resident Bristol Bay Borough would have to generate $4,874 per person to offset the state support it received in 2015. Many of the boroughs fell in the $1,000 to $2,200 per person range. “It makes it clear small places would have to levy very, very high taxes to replace how much (state) money they’re getting,” Guettabi said. What is the appropriate level of state support for local governments has become a conversation inside of the larger state budget debate as lawmakers have tried to resolve annual budget deficits that have been at least $2.5 billion annually over the last three budget cycles. Guettabi said ISER is also working on another report examining State of Alaska spending per capita and why it is generally the highest in the country. “The health of local communities is something that needs to be part of this conversation as we’re thinking about the right size of government and thinking about how to fund government,” he said. “I think that understanding the ramifications of those choices on these borough economies is paramount to the next few years.” To that end, Department of Revenue Commissioner Randy Hoffbeck said to the House Finance Committee in February that 46 percent of the total state budget is “cash out the door” to fund programs and services statewide. Currently, $1.6 billion of the state’s roughly $4.2 billion operating budget goes to assist communities in paying school debt, employee retirement obligations, education and general revenue sharing statewide, according to the Revenue Department. More than $1.2 billion of that is in the state’s base student allocation education funding formula. Alaska is unique in that the state constitution requires the state to fund public education. However, just eliminating the roughly $300 million in state payment assistance for school debt and retirements would “implode” the budgets of most of Alaska’s smaller communities, Hoffbeck said. He was testifying on state income tax legislation passed by the House that failed in the Senate, but that Gov. Bill Walker’s administration generally supports as part of a broad-based revenue fix to the deficit. Elwood Brehmer can be reached at [email protected]

Supreme Court hears arguments in PFD veto lawsuit

Forty years to the day after the oil that generated the revenue to capitalize the Permanent Fund started flowing, the Alaska Supreme Court heard arguments over who controls distribution of the annual dividend payments of the Fund’s investment income. Anchorage Democrat Sen. Bill Wielechowski said the Permanent Fund Dividend is the primary reason Alaska has the lowest income inequality in the nation. “The PFD is unique; there’s nothing else like it in Alaska or the country for that matter,” he said to open his argument. Wielechowski, an attorney by trade, represented himself and former state Sens. Clem Tillion and Rick Halford before the court. The trio sued the Alaska Permanent Fund Corp. last September contending corporation officials violated state law when they adhered to Gov. Bill Walker’s partial veto of the 2016 dividend appropriation and transferred $695 million from the Permanent Fund Earnings Reserve to the Dividend Fund and not the full $1.36 billion that the formula in statute calls for and the Legislature approved. It was the first time a governor had vetoed any of the PFD amount. Tillion served in the Senate when the Permanent Fund was formed in 1976 and Halford was a state representative when the Legislature started the dividend program in 1982 and eventually served as Senate president. Superior Court Judge William Morse shot down their case last November, and concluded that eliminating the governor’s veto authority over the PFD would provide the Legislature more power than the Alaska Constitution provides. They immediately appealed to the Supreme Court. Walker made the bold move that some have called courageous and others have called stealing to send the message to Alaskans that their state is in a fiscal crisis and the status quo of government spending, and how it is paid for, is unsustainable, he said at the time and has continued to stress. The 2016 PFD would have likely been the largest in history at about $2,100 per person; Walker’s veto cut it to $1,022 each. The Alaska Constitution gives governors broad authority to make line-item vetoes in appropriations bills, and they regularly use it on budget bills. However, Walker also crossed out the language in the budget that notes the money transfer “is authorized under AS 37.13.145(b).” That is the statute that states the Permanent Fund Corp. “shall transfer” the formula-determined amount from the Earnings Reserve to the Dividend Fund for the annual payouts. Before the high court, Wielechowski agreed with Walker that the state is in a fiscal crisis, but called it a “crisis of government.” He also noted that the Legislature is free to appropriate from the Earnings Reserve of the Fund and change the law to reduce the dividend. That said, Wielechowski argued that until the Legislature changes the law to do that — which Walker has proposed and has bipartisan support in the Legislature — the dividend statute is indicative of a dedicated fund. It therefore mandates the Department of Revenue commissioner to calculate the lump sum dividend amount and the Permanent Fund Corp. to subsequently make the fund transfer, according to Wielechowski. “By the governor striking this statute he’s requiring the Permanent Fund Corp. to come up with an incorrect number,” he contended. Wielechowski said that after reviewing legislative records from when the Permanent Fund was formed by a voter-approved constitutional amendment in 1976 that, “All indications are that the Legislature intended to make this a dedicated fund.” The Alaska Constitution prohibits the Legislature from dedicating money to a particular cause, but the amendment to establish the Permanent Fund and divert at least 25 percent of state resource royalty revenue is one exception. Wielechowski stressed that the first three Dividend Fund transfers were made automatically, without language in the operating budget. Following that, for 26 years until the fiscal year 2010 budget, the transfer was made with just the language in the budget directing the transfer, he said. There was no dollar figure specified for appropriation. It all lends to the fact that the Dividend Fund to date has been treated by the Legislature as a dedicated fund, according to Wielechowski, and the budget line item and governor’s veto are therefore meaningless. Attorney Sonja Kawasaki, who argued the plaintiffs’ 10-minute rebuttal, called putting the PFD in the budget an “accounting notation” of the Legislature. Each side had 30 minutes to argue their case to the five Supreme Court justices. State Assistant Attorney General Kathryn Vogel represented the Permanent Fund Corp. Vogel said the amendment that formed the Permanent Fund mentions nothing of an annual citizen dividend or limits on the governor’s authority to veto appropriations. Further, she said the dividend formula statute does not approve spending without an appropriation and while a dedication can exist in law and prohibit some forms of appropriation, it simply binds the use of those funds and does not create a “hall pass” to supersede the need for an annual appropriation. “Fundamentally, there’s nothing about the dedicated fund clause not applying (to the Permanent Fund) that changes the normal course of appropriation,” Vogel argued. Federal funds the state receives are dedicated to specific causes but are still appropriated in each budget, she noted. Vogel continued to say that both sides in the case agree the PFD is a “statutory entitlement” that is not part of the constitutional amendment and therefore the governor’s veto authority holds. She concluded by saying the “veto struck what was a number described by words” and contended ruling for the senators would ostensibly give the 1982 Legislature that approved the first dividend formula binding authority over the Legislature and governor today. Chief Justice Craig Stowers wrapped up the argument hearing by thanking the audience for participating in such an important case but did not offer a timeline for a ruling. ^ Elwood Brehmer can be reached at [email protected]

State opens season for AK LNG Project

It’s open season for the Alaska Gasline Development Corp. That’s not to be confused with open season on AGDC, which legislators skeptical of the state-owned corporation leading and continuing the roughly $40 billion Alaska LNG Project have had on its biggest proponent, Gov. Bill Walker. AGDC’s open season to reserve pipeline and liquefaction capacity in the Alaska LNG Project started Thursday, June 15, and will run through Aug. 31, President Keith Meyer said during the corporation’s board of directors meeting, also Thursday. Potential customers interested in reserving capacity in the Alaska LNG tolling system won’t be expected to make a definitive commitment yet, Meyer stressed. But the capacity solicitation will provide pricing protection to those potential customers that do raise their hand, he said, as well as some rights to expand their share of capacity in the project and the right to have their capacity assigned to another party among other things. “We’re a little early to have a full binding open season,” Meyer said during the meeting. He also said AGDC estimates the tolling tariff will be about $6 per million British thermal units of LNG, which is nearly equivalent on an energy-cost basis to on thousand cubic of natural gas, of mcf, which is the standard unit of measurement for the commodity. Companies with interest will be expected to provide AGDC with a letter of intent to purchase capacity in the system and in-turn AGDC will respond with a term sheet specifying the foundation customer terms, including some of the aforementioned benefits. Meyer said his team has been talking with the large producers who hold rights to the North Slope natural gas that would supply the system about the process. From the state’s side, the open season will give AGDC an idea as to how much interest the market really has in the Alaska LNG Project. While there has long been ample discussion about the viability of the project — particularly since LNG prices took a worldwide dive along with oil in 2014 — it all, has been speculation to this point. According to Meyer, this is the first time the state has asked prospective customers in an LNG project to formally express interest, even if it is non-binding. Walker and Meyer have continuously said 2017 would be a year for ending that speculation and seeing if Alaska LNG could compete globally with a new financial structure since the state took the project over from BP, ConocoPhillips and ExxonMobil late last year. The crux of their position has been that the state-led project could be successful with smaller investor returns than the oil majors require while adding a major new revenue source for the State of Alaska and getting natural gas to many more communities in the state. Under the previous equity-share owner model, the producers wanted to slow down the project until the current global LNG glut subsided and prices subsequently recovered. The governor did not want the project to lose momentum after the state and the producers spent roughly $600 million studying and designing it since 2013, and took up the option for the state to take over the lead role. Also, the open season on customer solicitation will give AGDC an idea as to whether or not construction of the massive project, designed to produce up to 20 million tons of LNG per year, should be phased to match demand, Meyer said. Some pieces of infrastructure, primarily the 800-mile, 42-inch diameter pipeline, would have to be built even if the market can’t fill it right away, but the North Slope gas treatment plant and Nikiski LNG plant could start small and grow. That’s because they were designed using three “trains” to reach the 20 million tons per annum total, and those trains don’t all have to be installed at once. This round of solicitations is aimed at gaining insight into whether the producers might want to reserve capacity to sell gas into the state’s LNG tolling project. Meyer said it is still a little early in the process to expect Asian LNG buyers, many of whom he says just recently heard about the Alaska LNG Project for the first time, to step forward with a letter of intent. That’s a step Asian utilities don’t take lightly, he added. And though AGDC has been working hard to get the word out this year to spread the word about its project with Meyer making several trips to Asia, LNG customers typically don’t take the letter of intent step until at least 12 to 18 months after initial engagement from a project proponent, according to AGDC Commercial Vice President Lieza Wilcox. At the same time, Meyer said potential customers will be expected to make firm commitments by May 2018, as the customer contracts will underwrite the tens of billions of dollars of debt that will likely be needed to finance construction. To further interest from Asia, Meyer said AGDC plans to host several big LNG buyers from China this summer, but he declined to go into further detail about how many or what type of customer any of those companies might be. Elwood Brehmer can be reached at [email protected]

Marine highway supporters look for new ideas amid challenges

The M/V Tustumena is again on the disabled list for most of the season as the state nears drafting its replacement. Earlier this month the Alaska Marine Highway System announced the “Rusty Tusty,” as the state ferry is affectionately known to many, would be out of service until at least Aug. 15 after inspectors uncovered more damage to steel in the Tustumena’s engine room. The latest setback builds on the first delay of the 53-year-old ferry’s return-to-service date, which in early May was pushed back from May 27 to mid-July after the initial discovery of wasted steel in the ship’s engine room. Workers at Vigor Industrial’s Ketchikan Shipyard went to work on the Tustumena March 13 for its annual overhaul. At that time, it was expected the vessel would be back in service May 27. In 2013, unexpected repair work coupled with shipyard mistakes kept the Tustumena out of service for most of the year. It was then that state Department of Transportation officials began the process of drafting designs for the Tustumena’s replacement vessel. The Tustumena was dry docked at a shipyard in Seward at that time. The challenge the state ferry system has faced regarding the vessel is that at 296 feet it is significantly smaller than the other mainliner ferries the state operates but for several reasons, including the fact that it is the only ferry with a vehicle elevator to match the fixed docks in many of the communities the vessel serves, there aren’t other options. As a result, the relatively small, aging Tustumena has long been tasked with running the rough and tumble route between Homer, Kodiak, the Alaska Peninsula and the Aleutians, much of which is exposed to the vast Gulf of Alaska. The dock situation along the Tustumena’s route means it is more feasible to replace the Tustumena with a new vehicle elevator-equipped ferry than it is to replace all of the fixed docks with floating infrastructure, according to AMHS leaders. Previously when the Tustumena was laid up the M/V Kennicott would stand in and pick up at least some of the slack in accessible communities, as happened in 2013. This year, however, multiple years of budget cuts to the AMHS have eliminated that option. “We don’t have the funding to absorb those changes,” AMHS spokeswoman Meadow Bailey said. That means the normal 10 ferry runs through Southwest Alaska will be cut to three this year, according to AMHS — unless the Tusty is delayed yet again — with the first starting Aug. 22. Bailey added that overall ferry service has been cut 20 percent from its peak several years ago as the solely state funded AMHS budget has shrunk. She also noted that private shippers have tried to stand in for the Tustumena. Seattle-based Coastal Transportation, which operates solely between Washington and Southwest Alaska, is hauling cargo and vehicles on a space-available basis for displaced freight at AMHS rates and Samson Tug and Barge and Grant Aviation have assisted as well, Bailey said. On June 13 the AMHS announced the M/V Columbia, which runs between Southeast and Bellingham, Wash., will be at Vigor’s shipyard in Portland longer than expected for propeller repairs. The Columbia is now expected to be back in service July 26. It struck an unknown object last September and immediately went in for repairs. However, parts of the newly installed propeller system failed during sea trials and the problem is now being diagnosed, according to the ferry system. The M/V Malaspina is filling in for the Columbia, but because it is a smaller vessel, some vessel cabins and vehicle space reserved for the larger Columbia will be unavailable. The $244 million for the Tustumena replacement vessel is in the state capital budget that is tied up in the Legislature’s ongoing debate over what the State of Alaska’s long-term fiscal plan should be. The state’s cost to replace the Tustumena is $22 million, with the feds picking up the remaining $222 million tab. Because the Alaska Marine Highway System is classified as a traditional highway by the federal government, new state ferries can be built with primarily federal money by employing the 90-10 federal-state funding split that funds most highway projects across the country. However, using federal funds also means the new vessel likely won’t be built in Alaska, as any shipyard nationwide will have the ability to bid on the project. The two smaller Alaska-class “day boat” ferries currently under construction at the Ketchikan Shipyard were paid for completely with state funds, allowing state officials to make sure the state money was spent in Alaska. The Alaska-class ferries, the Tazlina and the Hubbard, are scheduled to be finished in October 2018. Bailey said the 330-foot, unnamed Tustumena replacement could be done about five years after it is funded, putting the earliest likely completion date sometime in 2023. Ferry officials have also been unsuccessful in trying to sell the one of the system’s original vessels, the 54-year-old M/V Taku. Sealed bid auctions this year with minimum bids starting at $1.5 million and then $700,000 did not attract any buyers. In 2003, the State of Alaska resorted to eBay to sell the E.L. Bartlett for $389,500, which was the last time an Alaska state ferry was sold. AMHS reform The State of Alaska and the Southeast Conference are also asking for input from AMHS stakeholders on how to best shape the long-term future of the ferries. Last year Gov. Bill Walker signed an agreement with the Southeast Conference to collectively examine reforming the Alaska Marine Highway System into a more efficient and financially stable operation. The Southeast Conference is Southeast Alaska’s nonprofit regional development organization. Currently run as a division of the Alaska Department of Transportation and Public Facilities, the AMHS is funded through annual legislative appropriations. This regularly makes it subject to political funding battles between legislators from smaller coastal communities and those from the rest of Alaska who are highly critical of the AMHS because it is not self-sustaining financially. Phase One of the reform study, finished in December, examined the organizational structure of other ferry operations and recommended the AMHS be morphed into a public corporation to, as much as possible, eliminate politics from leadership and decision-making. The study also concluded the ferry system should have a dedicated funding stream to help stabilize service levels. That in turn would allow ferry schedules to be set further in advance than the several months ahead of schedule they are set now. More reliable scheduling would likely increase ridership, according to the study, particularly from tourists who often book trips a year or more in advance. Phase Two is examining a 25-year operating plant that includes looking at funding options, possible partnerships with the private sector and a fleet renewal plan in more detail and should be done late this fall.

Innovation targeted at teacher turnover, remediation

The leaders of Southcentral school districts and a nationally renowned University of Alaska Anchorage program are blending high school and college in an attempt to cure the state of multiple education ills. The Anchorage School District recently took over the Alaska Middle College from the Matanuska-Susitna Borough School District, which is expanding the program in its own territory. Given the classes are held at UAA’s Eagle River campus, it made sense for Anchorage School District students to attend and allow Mat-Su students to utilize a similar opportunity closer to home, ASD Administrative Projects Director Kathy Moffitt said. Moffitt first worked on the Alaska Middle College with the Mat-Su District before transitioning to Anchorage. Over at UAA’s main campus, Alaska Native Science and Engineering Program founder Herb Schroeder is expanding his wildly successful efforts to grow more young Alaskan engineers and scientists to include building “a cadre of Alaskan teachers,” Schroeder said. “We need Alaskan teachers, people who love this place, people who will always be here no matter what,” he said. Moffitt and Schroeder spoke during a June 13 luncheon in Anchorage hosted by the local public policy think tank Commonwealth North. The work both are doing is aimed at conquering major issues in Alaska’s K-12 education system from the ground up. It’s based on the presumption that more prepared students will make better teachers who improve what are currently less-than-stellar student performance metrics. According to Schroeder, 60 percent of University of Alaska freshman coming from the 37 largest high schools in the state over the past decade have needed remedial math or English courses. At the lowest performing high schools, the remediation rate is nearly 75 percent of college-bound students, who have an average high school GPA of 3.16, he said. That means many of the students who qualify for the state Performance Scholarship don’t have the skills to jump into college. Annually, about 1,000 students arrive at a UA campus in need of remedial education, Schroeder said. “Imagine being on the honor roll and an academic hero with scholarships to prove how awesome you are and you find out that you are a year or more in some cases behind where you thought you were,” he described. “It’s an esteem-shattering gut punch. Financially, it can be devastating for families.” Adding a year of remedial classes — that don’t count towards college credits — collectively costs the families of those students about $24 million each year in extra tuition, books and room and board expenses. It also costs the state another $18 million per year given its support of the university budget, according to Schroeder. Finally, because the state is the primary funder of K-12 education and 70 percent of the students in need of remediation passed high school classes that should have prevented that need, “the state’s paying twice,” he said, while at the same time trying to fill a $2.5 billion budget shortfall. “Right now that whole $42 million is being spent (by families and the state on remedial classes) trying to repair the damage that was done over the previous 12 years and what I want to do is to take a portion of that money and reinvest it earlier so that we don’t have to repair that damage,” Schroeder said. Alaska Middle College has quietly been providing high school students the opportunity to earn high school and college credits at the same time for five years. In the school’s last graduating class, 13 students took an associate’s degree home along with their high school diploma, according to Moffitt. “Students test into college just as any student would and they attend classes with other college students,” she said. Available to high school juniors and seniors, Alaska Middle College is a way to support the students through what is ostensibly their first year of college, which is usually the most difficult, Moffitt said. It’s a way to ease the transition from high school to adulthood — and it’s free to students and their families. “The power behind the program is the opportunity,” she said. Alaska Middle College is mostly aimed at getting students a head start on general education college courses, but is also developing a career and technical education, or CTE pathway focused on preparing students to become teachers. The four-course startup program is awaiting accreditation to make it college-credit eligible, Moffitt said, and the district wants to install it in Anchorage’s East High School next year. The Alaska Middle College students are placed in K-12 classrooms to mostly to observe teaching methods and student-teacher interactions from a different viewpoint the first year. In year two they “become active contributors and teachers working with students,” Moffitt said. The education-focused program came out of the University of Alaska Fairbanks’ K-12 outreach program, she added. Schroeder stresses a need for quality control and consistency in what is being taught in high school classrooms to match what the university needs students to know. Many, including him, believe the problem is directly linked to high teacher turnover across the state. According to the UAA Institute of Social and Economic Research, teacher turnover averages about 20 percent statewide and costs the state about another $20 million each year. Given the four largest school districts are generally below 10 percent turnover, many rural districts are watching upwards of 40 percent of their teachers leave each summer without coming back. Additionally, each year Alaska school districts hire about 1,000 teachers, while the state’s postsecondary schools produce only about 200 teachers per year, according to ISER. High teacher turnover — often due to the culture shock of moving from the Lower 48 to remote parts of Alaska — leads to teachers that don’t understand the unique needs of their students and apathy amongst teachers who decide quickly they will be leaving at the end of the year, among other problems, state education officials acknowledge. So Schroeder is trying to produce more homegrown teachers who know about and are excited about living and working in rural Alaska. He is working to start another of ANSEP’s full-time Acceleration High Schools in Anchorage in 2018. Classes in a summer version of the Acceleration school are going on now at UAA and ANSEP has another Acceleration program in the Mat-Su. ANSEP is open to all Alaska middle and high school students. “Many rural students want to live in villages and teaching is one of the few employment opportunities available there and the Acceleration High Schools provide the opportunity to complete much of the degree before students ever arrive at the university,” he said. Classes at Acceleration schools are taught by university faculty with support from K-12 teachers and— similar to the Alaska Middle College — students earn dual credits that can be applied to biology, engineering, business, education and other degrees. The schools are predicated on experiential learning and getting students excited about their work and their future, which Schroeder emphasizes is the most basic key to improving classroom performance. Acceleration students are also regularly mentored by peers and university students, which has helped many ANSEP students discover a love of teaching, Schroeder said. “We’re developing these schools now and success is going to require a new look at how we do education. Nibbling around the edges is not going to get us where we need to go,” he said. Elwood Brehmer can be reached at [email protected]

Eni files plan to explore federal Arctic OCS leases

Italian oil major Eni Petroleum is preparing to drill four exploration wells into offshore federal territory from its manmade North Slope island in state waters. If approved by the federal Bureau of Ocean Energy Management, the work program would take 18 months, according to the proposed work plan Eni submitted to the agency. The work would start with the drilling of the first well in December and end when the flow test of the final well is complete in May of 2019. Eni is the sole owner and operator of the Nikaitchuq unit in state waters just offshore from the large Kuparuk River field. Drilling in the Nikaitchuq unit is conducted from the manmade Spy Island, which sits roughly in the center of the unit and is about halfway between the shore and the three-mile boundary that delineates near shore state and offshore federal waters. The company has produced between 20,000 and 22,0000 barrels of oil per day from Spy Island in recent months. In late February BOEM approved the Harrison Bay unit, which is comprised of 13 federal outer continental shelf leases. Specifically, Eni is proposing to drill two main wellbores, each with a lateral sidetrack, from Spy Island that will reach seaward into the company’s federal Harrison Bay leases. The first main bore well would be drilled and tested from December through March 2018. That would be followed by the drilling and flow testing of a sidetrack next spring as well. The second set of wells would similarly be drilled and tested the following fall to spring. Eni is planning to drill the main wells to depths of about 7,500 feet and 8,300 feet with the offshoots extending more than 20,000 feet to reach the targeted areas in the federal leases. The drilling will be done with Doyon Drilling’s Rig 15, which is capable of drilling on an eight-foot well spacing pattern on the space-constrained gravel island, according to Eni’s exploration plan. Spy Island has space for 36 producer and injector wells. It currently has 31 production and injection wells and one disposal well, according to Eni. BOEM is soliciting public comments on Eni’s exploration drilling plan through July 3. Elwood Brehmer can be reached at [email protected]

Oil prices, policy uncertainty prompt Caelus to postpone well

Caelus Energy won’t be drilling new wells on the North Slope next winter for a host of reasons. As a result, Alaskans will have to wait at least another year to see whether the company’s promising but remote Smith Bay oil prospect, which Caelus leaders have touted to be a 6 billion-barrel discovery, lives up to its billing. The company had planned to drill a production-like appraisal well at Smith Bay in early 2018 to prove up what its two early 2016 exploration wells and detailed 3-D seismic data indicated — that Smith Bay could produce upwards of 200,000 barrels of oil per day. However, Caelus spokesman Casey Sullivan said in an interview that the company wants to advance Smith Bay as quickly as it can but “lower for longer” oil prices and the continued dismantling — on a couple of levels — of the state’s oil and gas tax credit program are impeding progress. Smith Bay is a very remote prospect about 125 miles northwest of existing central-Slope oil infrastructure and about 70 miles east of Barrow. While its location, size and the unavoidable long-term nature of North Slope projects means development will assuredly take at least five years or more and ostensibly makes current oil prices meaningless for Smith Bay’s commercial viability, prices have impacted revenue from Caelus’ Oooguruk development, the company’s only sustained revenue source. Smith Bay’s location makes even a small winter drilling program a $100 million-plus venture, according to Sullivan. And despite indications for months that there was bipartisan agreement in the Legislature, with support from Gov. Bill Walker, to end the cashable tax credit program on the North Slope, Sullivan said House Bill 111 did impact the decision to delay drilling again at Smith Bay. “Any prudent investor, any prudent company will take pause and make sure we understand what the next layer of rules might be before we make significant investments,” he said. The final version of HB 111 is currently being debated in the Legislature. Both the House and Senate versions of the bill cut refundable oil tax credits from state law Jan. 1, 2018, just before Caelus would have drilled the Smith Bay well. While the Senates bill does little else, the Democrat-sponsored House legislation would also increase taxes on the state’s large producing fields and restrict how companies can utilize future production tax deductions. Last November Caelus Energy Senior Vice President Pat Foley said at a Resource Development Council of Alaska conference that the company had been told on no uncertain terms that “the ongoing liability that’s created by the refundable tax credits is just not sustainable by the state.” In the same speech Foley said Caelus was planning to drill an appraisal well at its prized prospect and hoped to drill two exploration wells on state acreage it holds east of Prudhoe Bay in early 2018. Sullivan said at this point Caelus doesn’t have work planned for its eastern Slope holdings anymore, either. Caelus has also applied for roughly $200 million in tax credit certificates, more than $100 million of which are past due for payment from the state due to Walker’s vetoes of $630 million in credit payments since 2015, according to Sullivan. Walker vetoed the tax credit payments — and drew sharp criticism from Republican legislators and the oil industry for it — contending the state could not afford to pay down the obligation while continually battling $3 billion budget deficits without a long-term fiscal plan. Additionally, Sullivan said low oil prices and activity elsewhere have made rounding up private support all the more challenging these days. “We believe, based on our science, that there’s more than 6 billion barrels in place (at Smith Bay), but it still takes money to get out there and prove up that resource and again there’s intense competition for that capital currently under the price environment and under what we’re seeing happen in the Lower 48, particularly in the (Texas) Permian basin, where you have the ability to — I’d leave it at there’s intense competition for capital,” he said. Caelus, a small independent, receives significant funding from Apollo Global Management LLC, a New York-based private equity investment firm along with financing through debt from other lenders, according to company leaders. Some state officials and independent industry representatives have noted Caelus’ tight oil find at Smith Bay is unequivocally encouraging, while at the same time trying to temper optimism about it, saying it is far from proven absent a flow test from an appraisal well. And if Smith Bay in fact is as large as Caelus purports, full development would still require leaping a series of regulatory and economic hurdles given its remoteness and location adjacent to the federally owned National Petroleum Reserve-Alaska, which any access road or pipeline would likely have to cross. As for what Caelus already has in production, the company is undertaking a well workover program to get the most oil it can out of its small Oooguruk field. “It’s a multimillion-dollar investment to go back in and hope to optimize production from some of the wells we’ve already drilled,” Sullivan described. Caelus stopped drilling at Oooguruk for the first time in seven years last spring when sustained low oil prices and the issues with the state’s tax credit payments made new investment challenging, company leaders said. Oooguruk is currently producing about 15,000 barrels of oil per day. According to Foley about 40 wells have been drilled at Oooguruk and Caelus wants to drill another eight. The company also holds the sanctioned-but-suspended Nuna project on the North Slope, which with about $1 billion of capital could start producing in two years and peak at about 20,000 barrels per day whenever North Slope oil economics improve. “We’re still super bullish on Alaska and we’re ready — as soon as we get some stability in price and policy — we’re ready to get moving forward again,” Sullivan said. Elwood Brehmer can be reached at [email protected]

Final Railbelt electric plan cost estimate nears $900M

The Alaska Energy Authority is sticking with its belief that one of the state’s most critical pieces of infrastructure needs close to $900 million of improvements to truly be both reliable and efficient. AEA’s final Railbelt Transmission Plan completed this spring concludes there are $885 million worth of projects to improve the economics and reliability of the electric grid from the southern Kenai Peninsula to Fairbanks. Another $54 million of work to add substations and transmission lines primarily around Anchorage would improve system reliability but not significantly improve the economics of the Railbelt electric grid, according to AEA. The Railbelt Transmission Plan was compiled for AEA by the Anchorage-based consulting firm Electric Power Systems Inc. A draft version of the study released in early 2014 estimated the need to be $903 million, but that included some smaller projects to integrate the now-suspended Susitna-Watana hydropower project into the region’s transmission system, AEA Chief Operating Officer Kirk Warren said during the authority’s May board meeting. Warren said about $400 million of the total estimate is for projects aimed at improving the flow of power from the 120-megawatt, AEA-owned Bradley Lake hydropower plant near Homer to the demand centers of Anchorage, the Mat-Su and Fairbanks. However, leaders of the six Railbelt electric utilities have to varying degrees dismissed AEA’s assertions that all of the transmission upgrades — with a steep collective price tag — are necessary. They contend a smaller, more targeted work plan could provide improved efficiency with far less cost. Matanuska Electric Association officials have said upgrading capacity of the southern Railbelt transmission intertie between the Kenai Peninsula and Anchorage could be done for as little as $50 million without the expensive reliability improvements that many in the utilities believe are unnecessary. While there is disagreement over how much should be spent, there seems to be consensus among the key players that improving access to Bradley Lake power is imperative. The current Kenai Peninsula transmission system, which is a single line between Soldotna and Anchorage, limits the availability of Bradley power when the hydro plant is operated at above 65 megawatts, or just more than half of its capacity. The oldest part of the line was built originally in 1961 to move power from the small Cooper Lake hydro plant near Cooper Landing to Anchorage, according to the study. It’s the inability to maximize the use of Bradley Lake whenever the utilities want it — at about 4 cents per kilowatt-hour, the hydro plant is the cheapest power source in the region — that limits its usefulness. Additionally, AEA is pursuing a $50 million project to divert part of nearby Battle Creek into the Bradley Lake system, which would increase Bradley’s generation capacity by about 10 percent. Specifically to combat the transmission line constraints and improve system reliability, AEA is proposing to run a new, subsea 100-megawatt, high-voltage direct current, or HVDC, line between Nikiski and Chugach Electric Association’s Beluga power plant on the west side of Cook Inlet. That standalone project is estimated at $185 million. The cross-Inlet HVDC line improves reliability, but doesn’t completely free Bradley Lake power because the hydro plant would still have to be operated at a level that the existing intertie could handle in the event the subsea line was lost, according to the transmission plan. As a result, more than $100 million in additional capacity upgrades to the existing transmission lines on the northern Kenai Peninsula, as well as a new, $66.6 million 115-kilovolt line between Soldotna and Bradley Lake are recommended. The system redundancy created by the new subsea line could also allow spinning reserve, or backup, generation plants on the Peninsula to be shut down. That could then save money for Peninsula ratepayers who would not have to support the full cost of their own backup generators if today’s line to Anchorage were lost or any reason, Warren said. The southern intertie has been out of service for almost a month each year over the past decade, according to the study. The lack of extra transmission capacity is also a direct impediment to new renewable energy projects, the study also notes. A similar scenario with added spinning reserve costs plays out in Fairbanks, as much of the northern electric intertie between Willow and Healy is a single transmission line, too. For the northern half of the Railbelt, AEA suggests a new 230-kilovolt line between Point MacKenzie and Willow at a cost of $128 million and another new $245 million line between Willow and Healy, which would de-constrain and add redundancy to the northern transmission lines. AEA owns the northern intertie, which was built in the mid-1980s with direct state appropriations. The second transmission line between the Interior and Southcentral “will prevent the loss of load in Fairbanks for single line outages and will allow (Golden Valley Electric Association) to access electrical and gas markets in the Southcentral system,” the transmission plan states. “It will also allow GVEA to evaluate the most economic solution for replacement generation capacity as its power production fleet continues to age or if coal resources are retired.” AEA estimates the suite of projects — forecasted in 2030 dollars, when the work could be completed — would save Railbelt consumers between nearly $35 million and $83 million collectively on their electric bills each year strictly through allowing utilities to always use the cheapest power source and the potential to optimize spinning reserve Railbelt-wide. The earlier draft of the transmission plan had much greater estimated savings, between about $80 million and $240 million per year, because it made assumptions that the utilities would minimize or eliminate their spinning reserve once redundancy was built into the transmission system, according to AEA’s Warren. However, he said the final study focused on the most economic dispatch of power because each utility has its own requirements for back-up generation. “Without additional transmission improvements, generation planning will continue to be completed by individual utilities, located in geographically dispersed areas,” The study concludes. “Capacity sharing and deferral will be limited by the existing transmission system and customer rates will not be at their lowest level possible.” As is often the case, one of the biggest hurdles is determining who pays for what, particularly given the fact the State of Alaska won’t be offering the grant funds that have covered these types of infrastructure projects in the past. The utilities could debt finance the projects themselves, Warren said, but that is quickly complicated by several factors. “The real issue revolves around settlement amongst the utilities on who pays for what,” he said. Partially because ownership of the transmission lines is fragmented to each utility’s service area, a utility that owns a segment of transmission and thus is on the hook for it may not be the entity to benefit from an upgrade or new line altogether — therefore eliminating the willingness to invest. For example, Golden Valley Electric’s Interior ratepayers would undoubtedly see the benefits of more transmission capacity in Anchorage and the Mat-Su area to allow additional lower cost and cleaner natural gas-fired and renewable-sourced power to flow north. But absent complex agreements to pay for the upgrades, the Southcentral utilities would have to pass along the costs of the transmission work to their ratepayers while most of the benefits would likely be realized elsewhere. To that end, the utilities have been working with American Transmission Co., a Milwaukee-based transmission-only utility that has been pitching the idea of forming a Railbelt transmission company, or TRANSCO, for nearly two years, which the utilities could become member-owners of. Ideally, the TRANSCO would be a vehicle for the utilities to collectively finance the major transmission investments; it could also set a flat, Railbelt-wide transmission tariff to encourage more selling of the most economic power amongst the utilities. Currently, each utility adds its own tariff to power that travels across its lines, challenging the economics of moving power across multiple transmission jurisdictions. Warren said AEA, as a transmission asset owner itself, has an interest in how the TRANSCO talks shake out and the utilities — each with their own transmission and generation profiles and internal requirements — “are all over the place.” Elwood Brehmer can be reached at [email protected]

No repeat of Prudhoe standoff as state approves 2017 plan

State Department of Natural Resources officials have approved BP’s work plan for the Prudhoe Bay oil and gas field without issue, a year after state demands for new information led to a summer-long standoff over the annual report. Division of Oil and Gas Director Chantal Walsh approved the 2017 Prudhoe Bay Plan of Development May 25 in a letter to BP Alaska management. This year’s Prudhoe POD contains sufficient information about BP’s efforts to support a project to commercialize North Slope natural gas reserves — and those of its fellow Prudhoe Bay working interest owners ConocoPhillips and ExxonMobil —that the plan was approved on a normal schedule, according to Walsh. Resistance to state demands for natural gas development and marketing information last year led to the plan approval being delayed until early September. BP submitted the development plan to the Division of Oil and Gas March 30. It takes effect July 1 and covers the drilling and major maintenance activities planned for the field in the coming year as well as reviews the prior year’s work. The 2017 plan outlines several engineering studies BP conducted in preparation for the Alaska LNG Project, which Gov. Bill Walker’s administration is pushing to have ready to pipe gas off the Slope in the mid-2020s. It also notes the company responded to more than 145 requests for information related to the Alaska LNG Project last year. For the coming year, the plan states BP expects information the requests to continue; now they will be coming from the state-owned Alaska Gasline Development Corp., which officially took control of the project from the consortium of producer companies last December. BP has offered a draft confidentiality agreement to AGDC so it can more easily share potentially sensitive technical and commercial data with the state-owned corporation to everyone’s satisfaction, according to the 2017 Prudhoe POD. Containing about 28 trillion cubic feet of natural gas, the Prudhoe Bay field has more than three-fourths of the known North Slope gas reserves that the Alaska LNG Project, or any other gas commercialization effort, would draw from. In the interim, BP will continue using the gas to enhance oil production. The company estimates that reinjecting the natural gas that comes to the surface with oil and repressurizing the reservoir supports approximately 40 percent of current oil production. In January, BP and the Alaska Gasline Development Corp. also signed a one-year agreement under which the producer will assist the state corporation in securing financing and customer contracts to support the roughly $40 billion Alaska LNG Project. In January 2016, then-DNR Commissioner Mark Myers sent a letter to all oil and gas unit operators informing them state officials would be requesting new information about efforts to market and develop natural gas resources for either in-state or Outside uses, depending on the field and situation. BP’s 2016 Prudhoe POD, submitted in late March of that year, included two brief and generic paragraphs about developing natural gas from the field. It stated that “major gas sales” from Prudhoe depend on many market variables and until a viable project is sanctioned the company and its field partners would continue to use the gas to maximize oil recovery. The 2016 POD was quickly deemed incomplete by top DNR officials, while BP, ConocoPhillips and ExxonMobil contended the new demands broke from longstanding regulatory precedent. That resulted in a summer-long schism between the producers and the Walker administration and an extension of the 2015 POD as the effective operating document. The conflict ended in September when BP and ConocoPhillips sent a joint letter to Walker announcing their support of a state-led Alaska LNG Project. DNR Commissioner Andy Mack also wrote in the approval letter to BP that the working interest owners would be expected to detail their activities to support major gas sales in upcoming Prudhoe PODs. On the oil side, BP is projecting oil production will be flat to down 40,000 barrels per day from the 197,900 barrels per day of oil and natural gas liquids the company extracted from Prudhoe Bay in 2016. The company made an identical prediction for production in last year’s POD, but ended up with a slight but unexpected increase in production over 2015. ^ Elwood Brehmer can be reached at [email protected]

Judge in LIO case denies owners’ request to enter new evidence

A request for new evidentiary hearings in the $37 million lawsuit brought by the owners of the now-vacant Downtown Anchorage legislative information office against the Alaska Legislature was shot down in a Wednesday state Superior Court ruling. Judge Mark Rindner’s order means the case will likely be decided on the facts already presented — and was a win for legislators. 716 West Fourth Avenue LLC, the building owner group comprised of Anchorage real estate developers, appealed its $37 million contract claim to the Superior Court last December after then Legislative Council chair Sen. Gary Stevens denied the claim last fall. The full, 14-member council subsequently denied 716’s appeal of Stevens’ decision without a hearing. The Legislative Council — the actual defendant in the suit — handles business matters for the full Legislature. Attorney for 716 Jeffrey Feldman argued before Rindner in a May 19 hearing on the matter that Stevens relied heavily on “hearsay” evidence such as newspaper articles to support his decision and largely ignored supporting materials submitted by the developers. According to Feldman, an allowance for new evidence in the case would expose the fact that legislators shirked their responsibilities to act in good faith and uphold the 2013 deal that had 716 invest $37 million in the $44.5 million on the premise the Legislature would occupy the building long-term. The Legislature contributed the remaining $7.5 million. Instead, legislators bowed to political pressure from constituents who were unhappy with the 10-year, $3.3 million per year lease they signed for the space built just for them and backed out of the deal without compensating his clients, Feldman contended. In his order Wednesday order, Rindner wrote that allowing an evidentiary hearing, or trial de novo, would be outside the norm procedurally for an administrative appeal such as 716’s claim and that “there are significant questions of law that must be resolved before any additional findings of fact are made.” Rindner said during the May 19 hearing that it shouldn’t be a surprise that legislators make decisions for political reasons and expressed hesitancy towards a court-ordered exposure of why they ultimately decided to leave the building, saying the court could very quickly be blurring the separation of powers between the branches of government. If and when the legal questions are answered, Rindner can then decide if further discovery is needed, at which point the case could be remanded back to Legislative Council to unearth new evidence, which would be normal procedure, he wrote further. He did not elaborate on which legal issues are unresolved, but concluded with, “Proceeding in this way will allow remaining factual issues, if any, to be more narrowly defined.” Legislative Council is now chaired by Juneau Rep. Sam Kito, who repeatedly advised against the Legislature walking away from its Anchorage offices on the belief doing so would invite such a lawsuit. Elwood Brehmer can be reached at [email protected]

Zinke orders new looks at Arctic oil development

It’s safe to say the Alaska Oil and Gas Association won the day Wednesday. Not only did new Interior Secretary Ryan Zinke deliver the keynote address at the association’s annual conference, he signed a secretarial order directing Interior agencies to review management and leasing of the North Slope National Petroleum Reserve-Alaska and conduct a new oil and gas resource assessment of the Arctic National Wildlife Refuge coastal plain. According to Zinke, it is believed to be the first secretarial order signed in Alaska. During a press conference following his speech, Zinke questioned the rationale of the decision by President Barack Obama’s administration to make roughly half of the 22 million-acre NPR-A off limits to oil and gas leasing. “In military terms it’s almost been a delaying, rear-guard action over the past administration,” Zinke said. “When you look at the area that was off limits in the National Petroleum Reserve — arguably the most productive areas.” Interior’s 2013 Integrated Activity Plan for the NPR-A, which is the Bureau of Land Management’s plan for how to manage the area, prohibited leasing in much of the northeast portion of the reserve that is closest to existing Slope oil infrastructure. That area also contains Teshepuk Lake, a massive breeding ground for waterfowl and caribou. The 2013 NPR-A plan potentially kept 350 million barrels of recoverable oil and 45 trillion cubic feet of natural gas away from development, according to Interior estimates. In 2010, when oil prices were about twice what they are today, the U.S. Geological Survey estimated the NPR-A held nearly 900 million barrels of economically recoverable oil. In January, ConocoPhillips announced that it believes its Willow discovery on the eastern edge of the NPR-A holds 300 million recoverable barrels of oil. The ever-controversial Arctic National Wildlife Refuge — on the other side of the North Slope from NPR-A — could hold upwards of 10 billion barrels of oil, with more than 7.6 billion barrels in the 1002 coastal plain area, according to a 1998 USGS evaluation. The 1.5 million-acre 1002 Section of the 19 million-acre refuge was carved out by Congress in 1980 and left open to the prospect of petroleum development because of that potential. To date, one well — the results of which are still confidential — has been drilled into the ANWR coastal plain in 1985. A 2-D seismic survey was also conducted in the 1980s and is the main source of information about its oil potential. Zinke referenced President Donald Trump’s directive to him to make America “energy dominant” time and again during his five days in Alaska and it was a frequently used phrase Wednesday. “Energy dominance can’t happen unless Alaska is a partner,” Zinke said. Gov. Bill Walker, who has long pushed for exploring ANWR, compared the significance of Zinke’s action today to Vice President Spiro Agnew’s 1973 tiebreaking vote in the Senate in favor of constructing the trans-Alaska pipeline. “This is a day we have waited for for a long time,” Walker said. While the impact of Zinke’s order almost assuredly won’t be as immediate, the excitement among resource development advocates at the AOGA conference couldn’t be oversold. “The attitude of partnering…We had to play defense for so long we forgot what offense is like and now we’re going to be able to work in partnership (with the federal administration),” Walker said, referencing land management battles with the Obama administration. The ANWR coastal plain assessment will be done by federal and likely state geologists and Zinke said he wants to include industry as well to continue fostering the partnership mentality he is working to instill across his department. Today’s 3-D seismic technology should also provide a much better resource estimate than what was capable in prior exploration. In 2013, former Gov. Sean Parnell and then-Alaska Department of Natural Resources Commissioner turned U.S. Sen. Dan Sullivan submitted an ANWR Section 1002 exploration plan to the Interior Department that estimated a winter seismic shoot would cost approximately $50 million. Regardless of what is found, opening the ANWR coastal plain to development and oil production requires congressional approval, which is still a long ways off. “It’s hard to make decisions unless you know what’s there, so we’re giving the green light to do the (ANWR) assessment,” Zinke said. And on the day he signed the order, The Wilderness Society released an update to its report against oil activity in ANWR entitled, “Too Wild to Drill.” Zinke, who in his address to AOGA described himself as a “Teddy Roosevelt Republican,” said he strongly supports the National Environmental Policy Act, which prescribes the process to evaluate large development projects across the U.S. However, he stressed NEPA should not be used to manipulate conservation or development decisions, as Republicans have regularly accused the Obama administration of doing. “Nothing I signed today skirts NEPA,” Zinke said. “Nothing I signed today diminishes or relaxes environmental protections that are necessary.” Elwood Brehmer can be reached at [email protected]


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