Elwood Brehmer

Valdez tug transition on track, Alyeska official says

WHITTIER — The major move to a new oil tanker escort firm in Valdez is going well according to Alyeska Pipeline Service Co. managers. “All the vessels, based on schedule analysis and the visits we make to the shipyards, are on schedule,” said Mike Day, the manager of Alyeska Ship Escort/Response Vessel Systems, or SERVS. Day reported to the Prince William Sound Regional Citizens’ Advisory Council board of directors at its Sept. 14 meeting in Whittier on the progress of the SERVS operator transition from Crowley Maritime to Edison Chouest Offshore. Edison Chouest announced in June 2016 that it had secured a 10-year contract from Alyeska to conduct SERVS operations out of the Valdez oil terminal starting in summer 2018. Crowley tugboats have assisted oil tankers docking in Valdez since the 1977 startup of the Trans-Alaska Pipeline System, which terminates there. The company added the Prince William Sound tanker escort and oil spill response duties to its work in 1990, a year after the Exxon Valdez oil spill. Edison Chouest is building 14 new vessels and spill response barges to fulfill its duties under the SERVS contract. The new SERVS fleet will include five large tanker escort tugs and four smaller support tugs, which are under construction at Edison Chouest’s various Louisiana shipyards. The first two tugs and a spill response barge are scheduled to arrive in Valdez in February. Shortly thereafter, the new tug captains and crews will begin five months of live training exercises — some with tankers in tow — before officially taking over for Crowley next July, according to Day. But formal crew training will begin before the tugs arrive. Day said each of the roughly 160 people Edison Chouest plans to commit to the SERVS contract will first go through 68 hours of classroom training starting in October on how to operate spill response equipment. Those folks will then get another 12 hours of hands-on equipment training “before they ever step foot on a vessel,” he said. In July, Edison Chouest shipped spill response equipment to Louisiana for two weeks of initial training. A ship bridge simulator Edison Chouest built in Louisiana will also be moved to Valdez once the company is done with it down south. Vessel operators are expected to put in 36 hours of simulator time and Day said Alaska Tanker Co. officials have expressed interest in participating in simulator training. Alaska Tanker Co. operates four 1.3 million-barrel capacity tankers for BP. Also starting in October, each SERVS tug captain will travel to Valdez and get on a working Crowley tug for at least a week. That observational training, which will run through March, was originally planned for last winter but was rescheduled for logistics issues, according to Day. “We’re hopeful they might find a big wave or two, or some wind, snow — find out what it’s like to operate a vessel in winter in Prince William Sound,” Day said. Sea trials on the first tugs are set for November. This past January, longtime Canadian naval architect Robert Allan made a presentation to the council board in which he was highly critical of the tug designs selected by Edison Chouest. Allan outlined a long list of perceived design flaws that could hamper the ability of the tugs to operate safely and successfully in the harsh winter conditions of Prince William Sound. However, he also acknowledged that he did not have access to the full, detailed tug design documents. At the time, Edison Chouest Alaska leaders could not be reached for comment but an Alyeska spokeswoman said the terminal operator has confidence in Edison Chouest and also noted that Allan only reviewed high-level information. In a separate presentation during the September meeting, Nathaniel Leonard, president of Maine-based Little River Marine Consultants, said Edison Chouest is using different design and construction methods than many in the industry are accustomed to. “Edison Chouest is a top-notch company and they’re building top-notch boats,” Leonard said to the council board. Day also reiterated Alyeska’s confidence in the full-service maritime company in comments to the board. When the tugs get to Alaska they will be thoroughly tested to assure they meet performance requirements, such as the ability to stop a loaded tanker moving at 6 nautical miles per hour with wind at its stern, Day said. He noted specific weather conditions will not be sought out for the performance tests; it will be up to the tug and tanker captains to decide when weather and sea conditions permit the exercises. Also, the Alaska Department of Environmental Conservation wants Alaska Tanker Co.’s largest tanker available for the tug tests, according to Day. The tests done with loaded tankers will at least first be done in the deep and open central area of the sound and not in Valdez Narrows to minimize the risk of an incident during training, he said. “I don’t anticipate any single test that’s pass or fail but a stepped approach to the force we put on a ship,” Day added. Such tests, in which the tugs are tethered to the tankers, only take about 10 minutes each, so several can be done in a day, he said. Additionally, Edison Chouest tugs will follow Crowley tugs on tanker escorts until they have passed all tether and towing exercises, Day said, which could continue through 2018 after the official July transition. Elwood Brehmer can be reached at [email protected]

State works to formalize method for assessing oil and gas properties

Some of the affected parties are raising concerns as state tax assessors are finalizing a methodology for valuing oil and gas properties other than the Trans-Alaska Pipeline System for the first time. Alaska Petroleum Property Assessor Jim Greeley said in an interview that the way the state currently assess values for oil and gas properties isn’t new; it’s been phased in over the last five years. However, the means for assessing the industry’s often complex and extremely expensive infrastructure has never been spelled out in state regulations, according to Greeley. “The regulation provides only high-level, broad guidance that basically says for production properties you have to use replacement cost (valuation),” he said. “Then for pipelines it says you can use sales, income or replacement cost and it stops there so there’s no specifics of methodology in currently. That’s what we’re trying to fix.” The vagueness of the regulations opens the door to subjectivity by the state and local governments or the property owners, creating a situation that’s “ripe for appeal,” Greeley added. That’s exactly why local governments and the producers fought over the value of TAPS for so many years, he said; there were no ground rules defining how it would be valued. The Tax Division hopes codifying a specific methodology in regulation will add transparency to the assessing process and clarity to the results so everything is understood by all the involved parties, he continued. The challenge in valuing oil and gas properties in the state — just another in the list of issues unique to Alaska — is that they don’t fit the mold of traditional business and residential properties, or even that of similar industry infrastructure elsewhere. The property tax assessments most folks are familiar with are market-based but that doesn’t work for Slope oil pipelines or process facilities. “When you have 50,000 homes in Anchorage you’ve got all sorts of comparables and you actually have an active market of buying and selling to conduct those assessments under that (market value) standard. We don’t have an active (oil and gas property) market where we have similarly situation properties to compare to. There’s only one Alpine; there’s only one Prudhoe Bay,” Greeley said. “Conversely, not only is there only one of them, they’re not being actively bought and sold so we don’t have that marketplace.” In most Lower 48 oil and gas basins, pipelines, reservoirs and their associated facilities change hands frequently enough to apply the well-understood market value principles, he noted. Father time has also complicated how the replacement cost of a property is calculated. When the laws outlining oil and gas property taxes were written roughly 40 years ago, replacement cost was pretty much what the facilities had just been built for. As things have aged and technology has changed, determining what it would cost to replace a facility has become largely theoretical, Greeley said. To combat those problems, the Tax Division has gone to the “use-value” standard first employed by the Alaska Superior Court and eventually the Supreme Court in litigation over TAPS. Greeley emphasized the regulations the division is considering are not for TAPS, which has a long history of value disputes. ‘Use-value’ standard In February 2014, the Alaska Supreme Court upheld a 2011 Superior Court ruling that concluded the value of TAPS is primarily based on the proven reserves that will eventually flow through it. At the time, the Supreme Court set the taxable value of the iconic pipeline at $9.9 billion; the owner companies had sought an $800 million value. In March 2016, the TAPS owners, who are the three major North Slope producers, the North Slope Borough, the City of Valdez, and the state settled on an $8 billion value through 2020 to at least temporarily stop the nearly endless litigation over the issue. While not for TAPS, the valuation methodology the state uses does follow the principles laid out by the Alaska courts. At its base, the use-value standard the state now employs on all unrefined oil and gas properties uses proven reserves — arrived at via production data — to determine the value of the facilities dedicated to exploiting those reserves. Refineries are assessed at the municipal level. “The reason we look at production is production is highly correlated to be the best measurement of what the proven reserves are,” Greeley said. “In other words, when Prudhoe Bay had 10 billion barrels of proven reserves it was producing at its plateau rate, 1.6 million barrels (per day); and when Prudhoe Bay had 2.5 billion barrels of reserves in 2009 it was producing 300,000 barrels per day.” He continued to explain that production data from the prior year is entered into a regression formula and looking back one can see that a field’s reserves and production correlate nearly perfectly over time. Reserves available to feed oil and gas facilities are a good measurement for valuing the facilities on a replacement cost basis because the infrastructure is almost always built to exploit a single reserve. As the available oil and gas depletes and production declines, the size and capacity of the facilities needed to serve a given reservoir also declines — and so does the minimum cost to replace it with a facility capable of handling a smaller oil and gas pool. Therefore the facility’s value depreciates. Greeley also said actual proven reserves data is very hard to get; companies generally keep detailed figures close to the vest and if it can be obtained it is confidential taxpayer information. Thus, using it would be contrary to a primary tenant of property taxes: that the method to calculate them is transparent and taxable values can be compared against each other. Production data is readily available to anyone on multiple state agency websites. “When the field has produced all of its proven reserves and you look back at how we depreciated it you’ll have no possible other outcome other than to have perfectly depreciated it over the life of that field and that’s because we’re letting the reservoir tell us what depreciation should be over the life of that field,” Greeley said. Oil price and other factors are accounted for through production, he added; if the economics of a field worsen the economically recoverable reserves will decline and that will ultimately show up in production figures. Prior to phasing in this methodology several years ago, state oil and gas property assessors conducted deterministic production forecasts, which Greeley described as “radically error prone” because they had to predict what a reservoir would produce. “When you look back at our depreciation applications it’s just the opposite. You have no other choice than to always be wrong. You need to be able to predict oil price; you need to be able to predict development; you need to be able to predict reservoir performance; you need to be able to predict all these things and then you have to come up with this deterministic estimate,” he said. “The probability of being perfectly correct is almost nil. By telling the reservoir what it’s going to do you’re just injecting a higher error rate into the assessment.” Overall tax revenue has not changed significantly since the new use-value approach has been applied, but most importantly it has not led to a single taxpayer appeal, according to Greeley. In 2016, the state collected $111.7 million in oil and gas property taxes, but much more went to municipalities, namely the North Slope and Kenai Peninsula boroughs. While the state conducts oil and gas property tax assessments, local governments are able to apply their mill rates on the state’s assessments to collect their portion of oil and gas property taxes. Companies then use the local tax payments as credits against the state’s 20-mill oil and gas property tax rate. In July, the Revenue Department held a workshop to explain the use-value approach and obtain feedback from taxpayers before formally proposing the regulatory changes. Whether or not the department will ultimately move to add methodology to state regulations hasn’t been decided, Greeley said, but the process to do so will likely be started sometime yet this year if the Revenue Department moves in that direction. That process also includes further opportunities for stakeholder input. The workshop elicited letters from the City of Valdez and three companies: BP, ConocoPhillips and small independent producer Caelus Energy. Greeley characterized the comments from BP and ConocoPhillips as primarily clarification questions, saying conversations with officials from both companies about the methodology have been favorable. He again noted the approach has not led to any appeals since it has been put into practice. Among other things, BP asked several questions regarding how equipment aging on the harsh North Slope is factored into the use-value approach and whether or not equipment that has been fully depreciated under the methodology still has an economic value even if it is idle and probably wont be used again. ConocoPhillips Alaska officials stated that the definition for replacement cost — while seemingly straightforward in that it is the estimate to construct a new property to meet current needs — could lead to differing interpretations and “provides plenty of opportunity for dispute.” They further noted that how the method is applied to facilities fed by multiple reservoirs was not addressed during the workshop and recommended the department share its plans on how potential issues arising from that will be resolved. Caelus Energy Vice President Marc Byerly had more direct criticism for Revenue officials. He wrote that the methodology is “inconsistent with both the current tax law and current tax regulation.” He contended that reproduction cost is being used instead of replacement cost, and that depreciation is not based on the economic life of proven reserves because reserves are not estimated in the calculation. Further, he stated that the methodology does not account for physical deterioration of assets and “ignores” external obsolescence, or depreciation based on factors outside the property. “We look forward to working with Caelus to deal with issues they’ve brought up and we hope the (proposed regulation) process will forward that opportunity,” Greeley said. To Valdez, he said the comments from city’s attorneys were mostly concerns based on where they’ve been with TAPS. The Tax Division believes TAPS’ value and the corresponding taxes will continue to be arrived at via settlement, according to Greeley. Local help Separate from the methodology regulations, the Tax Division is looking for help conducting oil and gas property assessments from the local governments that are home to Alaska’s oil and gas industry. It’s yet another consequence of the state’s continuing multibillion-dollar budget deficits. “Everything’s cut; we’re resource constrained so the state is looking at the provisions in (law) which allow for municipalities to assist in the assessments under MOU (memorandums of understanding),” Greeley said. “We’re looking to see if there’s any interest from municipalities to participate with the state and assist under those existing statutory provisions.” He said it’s something Tax Division and Revenue officials have been discussing with local leaders for a couple years. Personnel has been cut from the overall Tax Division, but Greeley said he still has his tax technician and staff appraiser. Where he felt the hit was in his contract budget. “I get real busy during the assessment season and historically we would spend significant amounts of money to bring in temporary assistance to get through the assessments in terms of contract staff and that has been completely wiped out. So, in other words when we need it most that assistance is no longer there,” he said. He specified the cost to usually be a couple hundred thousand dollars, noting it varied year-to-year. Valdez Mayor Ruth Knight signed an MOU, with the Revenue Department in late March to take on oil and gas property audit responsibilities inside the city under the department’s direction. That includes hiring contractors at the city’s expense, according to the MOU. The North Slope Borough agreed to help the state through MOU in 2015 and while that agreement is not active, Greeley said it remains in place so the state and borough can collaborate when need be. The MOU notes the state retains sole authority to determine taxable property values. Outgoing Kenai Peninsula Borough Mayor Mike Navarre, who has reached his term limit, decided against helping the state with assessments after conversations this summer because he couldn’t ask the Assembly for $25,000 the borough would get a tangible return on, according to Navarre’s Chief of Staff Larry Persily. Persily said the mayor is certainly aware of the department’s budget situation and sympathizes with Revenue officials over it but he couldn’t see how the local government would get its money back. He also said the $25,000 figure was one floated by the department leaders in the summer meetings as the amount they hoped the borough would kick in to the state’s effort. Persily did note, though, that the new borough mayor after the Oct. 3 election might be more amicable to the idea. New Revenue Commissioner Sheldon Fisher, who took over for Randy Hoffbeck after he retired from the position in August, might also have different ideas about how the borough could help, he added. Elwood Brehmer can be reached at [email protected]

Report recommends improvements for ferry system

Insulating the state ferry system from annual political battles is one of the biggest things lawmakers can do to improve its operating efficiencies, according to a draft report released Sept. 13. The Alaska Marine Highway System Reform Initiative draft report highlights the potential benefits the system could obtain from being converted into a public corporation as well as being forward funded by the state Legislature. In May 2016, Gov. Bill Walker signed a memorandum of understanding with the Southeast Conference to have the Southeast Alaska nonprofit economic development group lead an examination of what reforms the state can take to improve the system’s operations over the long-term. In recent years, as the State of Alaska has tried to reconcile annual and ongoing multibillion-dollar budget deficits, the AMHS has been caught in the middle of tense political battles. Conservative legislators from Anchorage, Fairbanks and the Matanuska-Susitna region have often criticized the ferry system, which operates at a significant annual loss, as a bloated government agency that needs to be scaled back greatly. Coastal legislators contend robust ferry service is vital for their communities and is often the only feasible way for residents in small communities to travel and ship vehicles, boats and all sorts of other goods. The draft report compiled by the Alaska research firm McDowell Group in concert with marine engineering consultant Elliott Bay Design Group of Seattle acknowledges the AMHS will never be a money-making operation. “Given the small markets served, long distances between ports, and often extreme weather operating environment, AMHS will always be dependent on public support to provide safe and reliable transportation,” the report concludes. McDowell and Elliott Bay studied other ferry systems worldwide for their report. The national firm KPFF Consulting Engineers was also contracted to draft a strategic business plan for the AMHS as part of the larger reform effort. During the 2016 state fiscal year, the ferry system collected $47.2 million in operating revenues on $145.2 million in operating expenses. The revenue gap is filled mostly with state general funds. Currently, the AMHS fleet consists of 11 ferries. State Transportation Department officials have been trying to sell the M/V Taku, one of the oldest mainliner ferries, and other vessels have been laid up due to budget cuts. After the state dropped the minimum bid several times, a group of Portland investors secured the purchase at a sale price of $300,000 to turn the Taku into a floating hotel and restaurant on the Willamette River. Bids were unveiled Sept. 15, and the state Transportation Department announced Sept. 19 that it was accepting the bid. Jonathan Cohen of Portland, Ore.,was the high bidder when the Alaska Department of Transportation opened three bidding envelopes for the 352-foot Taku. Cohen, who represents a group of Portland investors, bid $300,000 — almost six times the amount of the No. 2 bid — and said by phone on Sept. 18 that he intends to transform the Taku into a waterfront hotel and restaurant that will occasionally sail into the Columbia and Willamette rivers. “Our hope is to bring it to Portland, Oregon, where we’re based and to use it as a way to give this very historic vessel a second life,” he said. At the same time, two new smaller “day boat” ferries destined for service on the popular Lynn Canal routes out of Juneau are under construction in Ketchikan. Construction of those vessels, built with about $110 million of state money, was approved shortly before the state’s budget fell apart when oil prices collapsed in late 2014. The Department of Transportation is also working to replace the M/V Tustumena, which serves Homer, Kodiak and the Aleutian communities, but that replacement vessel will be paid for primarily with federal dollars. While the AMHS will probably never be self-sufficient, the aforementioned recommendations could help it maximize its strengths, according to the report. As it stands, the AMHS is a state agency managed as a public transportation service. Shifting it to a public corporation similar to the Alaska Railroad Corp. with its own board of directors would better allow for long-term operational and financial strategies to be implemented without the fear of them being changed or scrapped by political forces, according to the report. A public state corporation would also still be able to receive federal highway funds, which the system relies on heavily for vessel maintenance and replacement. As a public corporation the AMHS would be best suited to optimize operations if it were able to draw on the state AMHS Fund comprised of the revenue the system generates without approval from the Legislature, the report states. Allowing system leaders to manage the fund would provide a predictable revenue base. Funding the system’s remaining needs ahead of the next year would also allow it to maximize efficiencies and “is essential for the system to take full advantage of its revenue opportunities.” “Forward funding, which allows developing operating schedules up to 18 to 24 months in advance, would enhance revenue generation, especially in the nonresident tourism market where there is significant potential for growth,” the study authors wrote. “This growth would bring economic benefits to the many Alaskan communities that depend on the visitor industry.” Roughly 40 percent of ferry riders are non-resident, according to the AMHS. The system is often marketed as an alternative to traditional cruise ships, particularly in Southeast Alaska. However, seasonal ferry schedules are finalized just a few months prior to implementation because the system budget is not known each year until the overall state budget is approved. Cruise operators, on the other hand, set sailing schedules several years in advance to allow prospective customers ample time to plan vacations. The report contends that increasing passenger fares significantly would impact ridership to a point that it would negate the sought revenue benefits. Conversely, lowering fares would not attract enough new riders to offset the lost per-passenger revenue. It does suggest the AMHS employ demand management strategies as a way to grow freight revenue, which is currently about $2 million per year. “AMHS should look for opportunities to partner with private freight carriers to maximize revenue and community service,” the report states. Standardization of the ferry fleet to the extent possible and replacing the most expensive to operate ferries will in the long run significantly save money, according to the report; and utilizing modern automated ferries could reduce on-vessel labor by up to 10 percent. The McDowell-Elliott Bay team also determined that continuing the system’s service to Bellingham, Wash., is critical because it accounts for 44 percent of total operating revenues. The long-haul service through the Inside Passage is a popular way for people moving to and from Alaska, and to travel. Taku sale In July, Cohen outlined a plan to put a floating hotel at a pier in northwest Portland. According to the application, and as first reported by the Oregonian, the pier would be converted “into a terminal for river-related activities: floating hotel, watersports, seaplane terminal, spa, park, farmers’ market, and/or other amenities beneficial to adjacent condos and apartment buildings.” Cohen said by phone that the result would be similar to the Queen Mary, an ocean liner converted into a hotel and destination in Long Beach, Calif. “We’re not strangers to new and challenging projects. This is a different type of project, and it will come with its own challenges,” he said. Cohen said the Taku wouldn’t be a high-end hotel; it’d be similar to the Society Hotel, which offers hostel-style accommodations as well as individual rooms. “We’re not looking to offer high-end hotel rooms. We’re actually looking to make these the least-expensive hotel rooms in town,” he said. The Taku’s open car deck might be converted into a space for a farmers’ market or small businesses, he said. The lounges could become spaces for “digital nomads” who need working room. “Everyone has just been so positive about this boat, and I think it just has such a wonderful energy about it, and we want to keep that going,” he said. Refitting the Taku is likely to be an expensive proposition, something that deterred other bidders. The state extended the bidding deadline four times, and that came after two other offerings received no takers. According to information provided to bidders, the Taku needs several Coast Guard certifications and some significant maintenance work. Built in 1963, it is showing its age, and the cost of repairs was one of the reasons the ship was taken out of service in 2015. All three bids for the Taku were below the state’s reserve price of $350,000. Elwood Brehmer can be reached at [email protected] James Brooks of the Juneau Empire contributed to this report.

DNR starts work on North Slope road network

The Department of Natural Resources is trying to take advantage of what it sees as a convergence of fortuitous events to build a network of roads across the western Arctic. The Arctic Strategic Transportation and Resources, or ASTAR, project hatched out of a series of conversations Gov. Bill Walker had with North Slope Borough Mayor Harry Brower Jr. late last year about ways the state could support North Slope villages, DNR Commissioner Andy Mack said in a Sept. 12 interview. Mack noted that the talks between Walker and Brower were similar to those Alaska governors have had for decades with local leaders about the need for basic infrastructure in rural parts of the state. “In rural Alaska these infrastructure pieces sometimes take on a life of their own and can really improve the quality of life,” he said. However, it wasn’t until a remarkable victory last November — not the Chicago Cubs — that the administration really saw a chance to make a move. “Then the election happened last fall and President Trump was elected and very quickly we realized some of the things we’d been talking about — a lot had changed in the policy arena and there were some new opportunities to take the North Slope Borough up on what we’d been talking about and that was really to focus on community needs and whittling down the cost of living in those communities,” Mack continued. As a result, DNR began to put together the concept of a network of basic gravel roads to connect communities across the North Slope, primarily in the federal National Petroleum Reserve-Alaska. A map on the department’s ASTAR page shows potential road corridors connecting Anaktuvuk Pass and Umiat to the south to Point Hope, Point Lay and Wainwright to the west and Nuiqsut and Point Thomson to the east, among others. The administration then made a late addition to its capital budget request and in May, Mack and Brower sent letters to the House Finance Committee requesting funding to start planning for and prioritizing which parts of the large concept could move forward. The Legislature ultimately approved $7.3 million for ASTAR; money reappropriated from the Department of Transportation, DNR and leftover funds from the Alaska Railroad’s Tanana River bridge project southeast of Fairbanks. Mack said now is the time to investigate ASTAR despite the state’s serious budget problems because the Department of the Interior is reassessing its view of oil and gas potential in the NPR-A. Recent Nanushuk formation oil discoveries inside the reserve and on state lands near it by ConocoPhillips and Armstrong Energy and strong interest in NPR-A leases in the fall 2016 federal oil and gas lease sale give every indication the assessment will show increased oil potential and industry wants more access into the area. There has also been a push from resource development proponents in the state to reopen the NPR-A management plan and the Trump administration has hinted that it is interested in opening more areas in the 23 million-acre reserve. Mack acknowledged $7.3 million doesn’t build much on the Slope and said that money will be used to plan projects and hopefully devise a payment structure for what might actually be built, which he also said almost certainly won’t come close to the entire network. “We know we’re getting into some major (National Environmental Policy Act) planning. We think there ought to be good results for the communities on rights of ways so that we have clear plans for community development and if there’s a secondary benefit for industry, we’re happy, we’re extremely happy,” Mack said. Most of that planning will be done over the next year to 18 months, he added. DNR is currently advertising a long-term but temporary position to travel to the Slope communities, gather input and manage those planning efforts. Those secondary benefits for industry — accessing otherwise isolated prospects — could help pay for ASTAR infrastructure through fees or simply expedited projects leading to more state taxes and royalties, according to Mack. “Even if there is a minor uptick in production in one unit or field or it comes online a little sooner because a company might be able to pay tolls to get to that prospect it possibly has the ability to pay for itself,” he said. “Part of the project is to understand and examine the financial opportunities and one of the opportunities may be a tolling structure and how that might work.” He said further that companies have noticed the ice road season being consistently squeezed on both ends. Leaders of the small independent producer Caelus Energy have consistently noted that a road to their 6 billion-barrel Smith Bay oil prospect about 125 miles northwest of existing Slope infrastructure would bring down development costs immensely and likely get the project into production quicker. While the state is moving quickly on ASTAR, Mack emphasized, “We’re not backing away from our commitment to protect the area and the subsistence culture but we certainly see new information that should be considered.” He also said the roads could be used as utility corridors to bring lower cost energy and broadband to the region, but all that is a long ways off. “We don’t have any particular project in mind and it will probably start out with an effort to identify what one or two roads in the NPR-A looks like, maybe a marine facility or two and what they would look like,” Mack said. “We’ll kind of chew it bite sizes.” ^ Elwood Brehmer can be reached at [email protected]

Slope producers doing more with less

Alaska’s oil workforce has been hit hard by low prices, yet the companies in the state have managed to buck a longstanding trend and increase production for the last two years. So what gives? For state Labor Department Economist Neal Fried, the curiosity in the numbers goes back further than when oil prices started tumbling from the $100-plus per barrel plateau in August 2014. “The whole trend in oil production and employment has been very interesting just because in 2015 we reached a record number of employees in oil and gas in the state’s history, which is pretty amazing given the fact that we were producing significantly less than our peak in 1988 or for many years before that,” Fried noted. He said that the decade-long run-up in oil and gas sector jobs exceeded the generally accepted notion that oil fields — the three primary North Slope fields are 17 to 40 years old — require more investment as they age. In 2006, Alaska had an average of 9,600 oil industry workers, according to the state Labor Department. That year Trans-Alaska Pipeline System throughput averaged just more than 759,000 barrels per day. By the peak of industry employment in 2015, just before price-induced layoffs started taking their toll, oil accounted for about 14,200 jobs while TAPS carried just 508,000 barrels per day, the lowest annual production level in the history of the North Slope. Fried attributes the employment boom to the peak oil price years of 2011 to 2014. “Without that magical price I don’t expect that it would’ve ever happened but it still was surprising,” he said of the workforce expansion. “It kind of humbled anyone that makes any kind of long-term forecast on any industry.” However, the script has flipped in less than two years. So far this year Alaska has averaged 10,600 oil industry jobs, the fewest since 2006, while TAPS throughput is at nearly 523,000 barrels per day, according to the pipeline owner Alyeska Pipeline Service Co. The last month Alaska North Slope crude averaged more than $60 per barrel was June 2015. North Slope oil production has generally declined at about 5 percent per year with few exceptions since peaking in 1988 at just more than 2 million barrels per day. With the regular North Slope winter production ramp-up still on the horizon for the end of the year, 2017 is already on pace to surpass the 517,000 barrels per day of 2016. If that holds true, it would mark the first two consecutive calendar years and only the third year overall of year-over-year increased North Slope production since 1988. The only other year prior to 2016 to see a production increase on the Slope was 2002 when the Alpine field came online. New technologies could be starting to displace some traditional manpower, Fried surmised, but quantifying that for Alaska in the complex and extremely proprietary oil and gas industry is very difficult. “You just have all this other noise going on,” he said. On a high level, the federal Bureau of Labor Statistics estimates productivity in the oil and gas sector increased 5.4 percent nationwide in 2016 on a production per hours worked basis. The industry saw production output decrease over the year, but less than hours worked did, as oil prices down to less than $30 per barrel to start 2016 discouraged investment. Just because there are fewer people doesn’t mean there is less quality work going on, Alaska Division of Oil and Gas Deputy Director Jim Beckham said. He described it as producers “refining their techniques and their abilities to make efficiencies all the time.” “They will pick and choose, high-grade, so to speak, the work that they’re going to do targeting the projects that they’ll get the most benefit from,” Beckham said. He surmised a significant number of the jobs lost in the recent downturn could’ve come from Anchorage offices, allowing the Slope workers to continue the actual work of extracting oil. The oil and gas sector in the city is down about 700 jobs from mid-2016 to now, according to the Anchorage Economic Development Corp. Beckham said the production increase has been driven primarily by more oil from the Prudhoe Bay and Alpine fields. BP, which operates Prudhoe, outpaced its own estimates for oil and natural gas liquids production from the Prudhoe Bay field in 2016, with production averaging 197,900 barrels per day for the year. The company had expected reduced drilling activity brought on by low oil prices would result in average daily production to be flat or down as much as 40,000 barrels from 2015, when 196,400 barrels per day were pumped from Prudhoe. “In the Prudhoe Bay Unit they’re still reaping some of the benefits of their drilling and workover program that they had over the last couple of years,” Beckham said. BP is only down about 50 jobs since 2015, with 1,700 Alaska employees, according to spokeswoman Dawn Patience. The company has two drilling rigs working at Prudhoe this year. “We are pursuing well work which can be done less costly and more efficiently by non-rig equipment such as coil tubing,” Patience wrote in an email. “In today’s low oil price environment, Prudhoe Bay’s working interest owners must look closely at every investment decision.” Beckham added that BP has achieved “remarkable results for a field that’s that age and size” with its well workover and maintenance programs over the past couple years. At Alpine, in the Colville River Unit, ConocoPhillips started up its CD-5 oil project in October 2015. The company approved adding 18 new wells to CD-5 in April 2016 — bringing the total to 33 — and since then production from the Colville River satellite has approached 20,000 barrels per day, or about 25 percent above the company’s stated goal of 16,000 barrels daily. At the same time, ConocoPhillips Alaska is down about 240 positions since January 2015, spokeswoman Natalie Lowman said, adding a majority of the employees affected by layoffs worked in Anchorage. Overall, ConocoPhillips has managed to reduce its operating cost by about 20 percent since 2014, Lowman noted. “We have found ways to streamline processes both in the office and on the Slope,” she said. “We are a stronger, leaner company than before the oil price crash.” Beckham also noted ExxonMobil brought the Point Thomson natural gas field, which pumps liquid gas condensates into TAPS, online in April 2016. While technical problems have hampered Exxon’s ability to average its 10,000 barrels per day target, the field has pumped about 3,000 barrels per day into the pipeline. “You start to add those up and you get an 11,000-12,000 barrels per day increase,” Beckham said. It should be noted the new production must offset continuing decline in other fields before contributing to increased production Slope-wide. If the majority of job losses have not come from the largest companies operating on the Slope, there is only one other place to turn: their contractors. Alaska Support Industry Alliance General Manager Rebecca Logan said the issue of job losses amongst Slope contractors is a touchy subject, but acknowledged a majority of the positions cut from Slope oil work came from contractor companies. Best known simply as the Alliance, Logan’s trade association represents more than 500 companies with upwards of 50,000 employees working in the state’s oil and gas and mining sectors. Contractors are often the first place the operators turn for cost savings in the form of less expensive work, she said. “People are doing more with less and the less means fewer people,” Logan said. She added that when oil prices were at $100 per barrel, the operating companies were likely not looking as hard for efficiencies in day-to-day work. Additionally, Logan said the transition from the majors with large capital budgets dominating the Slope to smaller companies operating more fields likely means leaner contracts for her members. “I think that our contractors have known, especially the ones that have been around for a long time — who built the pipeline and have been here through all the ups and downs — to be working for companies like a Hilcorp, which comes in and does things differently than a global company like a BP, right?” she said. Hilcorp purchased operating interests in several of BP’s producing Slope fields and prospects in 2014 for $1.25 billion. Houston-based independent Hilcorp Energy is known for reviving aging oil and gas fields that larger companies no longer deem worthy of investment. Logan said she hopes the continued low prices and state policy decisions don’t deter future investment in Slope fields that could lead to a sharp decline in production in the coming years. Beckham said the state is very excited about a few massive Slope oil discoveries that have been announced but are yet to be developed that could add several hundred thousand barrels per day of new oil into TAPS. However, even the most advanced of those prospects, Armstrong Energy’s estimated 120,000 barrels per day Nanushuk project, is several years off. Elwood Brehmer can be reached at [email protected]

Hilcorp advances plan for cross-Inlet oil pipeline

Hilcorp Energy is moving ahead with its $75 million plan to ship oil across Cook Inlet. Harvest Alaska, Hilcorp’s pipeline subsidiary, filed applications with the Regulatory Commission of Alaska Sept. 8 requesting approval to expand the Inlet’s pipeline network and ultimately pipe oil from west Inlet facilities to the Andeavor refinery in Nikiski. The project includes constructing new subsea and onshore pipelines as well as repurposing a cross-Inlet gas pipeline into an oil line to feed the refinery at Nikiski. “The Cross-Inlet Expansion Project will bring a higher level of safety and reliability for shipping oil across Cook Inlet. We think it’s the right thing to do,” Harvest President Sean Kolassa said in a company release. Repurposing the existing cross-Inlet gasline will mean installing a new gasline from the Tyonek platform to tie into the large Beluga gas transmission line on the west side of the Inlet. Also, oil flow that now goes from Granite Point south to the Trading Bay processing facility and on to the Drift River storage and tanker loading terminal will be reversed. The Drift River tank farm, with capacity in excess of 1 million barrels of oil, feeds the offshore Christy Lee tanker loading platform via pipeline. Its location in the shadows of Mt. Redoubt, an active volcano, has long made it an environmental concern. The Drift River facility was partially flooded by a snowmelt-ash sludge in April 2009 after Redoubt erupted. Then operated by Chevron, the tank farm was shut down as a precautionary measure. Hilcorp restarted the then-40-year-old terminal in late 2012. Hilcorp has been investigating the prospect of a subsea oil transmission line — a lower spill risk option than tanker traffic — for some time, Hilcorp Senior Vice President Dave Wilkins said in a prior interview with the Journal. Its purchase of the Tyonek platform and associated pipelines last year from ConocoPhillips gave the company what it needed to make the project economic, according to Wilkins. The company has already ordered U.S. steel in preparation for next year’s construction season and hopes to have the project complete by the end of 2018, according to the release. Hilcorp took significant heat starting in February when a natural gas leak was discovered in one of its subsea Inlet pipelines and the company was unable to fix it for roughly two months as heavy ice flows made it unsafe for dive crews to reach the pipeline. Executive Director of the Cook Inlet Regional Citizens Advisory Council Mike Munger said in the Hilcorp release that the nonprofit tasked with oversight of Inlet oil and gas operations is pleased that the company is progressing an oil pipeline as a safer alternative to tanker shipments. “The council has advocated for a crude oil subsea pipeline since the reopening of the terminal after the 2009 Mt. Redoubt eruption,” Munger said. “We support Hilcorp’s project and we look forward to working closely with them through this process to ensure it’s done responsibly.” Elwood Brehmer can be reached at [email protected]

Ahtna apologizes to state regulators after $380K fine

Ahtna Inc. leaders admitted the Native corporation’s drilling subsidiary repeatedly failed to comply with state regulators’ demands over several months, but at the same time asked the Alaska Oil and Gas Conservation Commission to lessen the resulting $380,000 in fines that the corporate officials feel are excessive. Ahtna CEO Tom Maloney said during a Sept. 12 AOGCC appeal hearing that the company has the “deepest sorrow” for the internal communications failures that led the commission to levy the fines. He stressed the communications problems were fixed as soon as possible after he was notified. “We are committed that it will never happen again,” Maloney said. The commission issued the fines to Tolsona Oil and Gas Exploration LLC, a wholly-owned Ahtna subsidiary of which Maloney is also CEO, because the company, among other things, time and again did not provide data on the natural gas exploration well it drilled last fall and was not responsive to efforts by commission officials to contact the company, according to a May 24 AOGCC order. The Alaska Oil and Gas Conservation Commission is a technical state regulatory body responsible for oversight of subsurface oil and gas activity. The fine order in May followed an April 11 Notice of Proposed Enforcement Action that claimed Tolsona failed to hold up its end of a deal after the commission granted the company’s request to suspend the well it had challenges drilling. Maloney and Ahtna attorneys did not dispute the general conclusion that the company dropped the ball by having poor internal communications policies. He said he was made aware of the order on May 25 by an individual in the oil and gas industry but outside the Ahtna family of companies. “I was shocked and dismayed when I read the order,” Maloney testified to the commission. “We’re deeply sorry that this has occurred. It’s been a black eye for all of us in the corporation.” Late last September, the wholly owned Ahtna Inc. subsidiary spudded the Tolsona-1 gas exploration well on state land about 11 miles west of Glennallen. An Ahtna press release announcing the start of the drilling work said the well’s target depth was about 4,000 feet. The company statement also noted previous exploration wells in the region — Ahtna was a partner on one — hit high pressure water zones that hampered drilling. According to the AOGCC, the Tolsona-1 well reached its total depth on Nov. 22, after 54 days of drilling. Ahtna originally expected the drilling to take 26 days. A Jan. 6 Ahtna release stated the well was ultimately drilled to 5,500 feet on Dec. 5 to overcome challenges from unexpected complexities in the area’s geology. At that time Ahtna was preparing for detailed analysis of the well data, the company said. According to the commission, the well was evaluated until Dec. 14, when the company applied to the commission to suspend the well. That application was approved the same day. A day later, the company reported that pressure was building in the well casing annulus — the area between the inner tubing and outer casing — to nearly 900 pounds per square inch. The pressure again built back to approximately 1,110 pounds per square inch after Tolsona bled it to zero, according to AOGCC documents. As a result, the commission approved continued suspension of well operations and the installment of a second mechanical tubing plug. The commission additionally wanted Tolsona to monitor the well pressure and provide weekly reports until Jan. 20. On Jan. 12, the commission approved Tolsona’s request to further install a back pressure valve in the well tubing at the end of the pressure reporting period. As a stipulation of installing the back pressure valve, Tolsona was required to provide monthly pressure reports to the AOGCC and give commission inspectors three days notice so they could witness the pressure readings. Shortly thereafter the problems began. A March 6 AOGCC Notice of Violation issued to Tolsona Oil and Gas stated the company failed to report the well pressure on Jan. 20, but after a Jan. 23 follow-up by the commission, “Tolsona provided the data the same day with ‘apologies, we will not be late again.’” However, according to the March 6 notice, after not receiving the Feb. 20 pressure report, the commission did not hear back from Tolsona via email after Feb. 28 and March 2 phone calls were not returned. The commission subsequently sent an inspector to the drill pad March 3. The notice states that once on site, the inspector discovered that the well pressures had not been recorded over the past month; a Tolsona representative that met with the inspector did not know if the back pressure valve had been installed; and the Tolsona employee had not been trained to properly record the wellhead pressures. The April 11 AOGCC enforcement notice states that “Tolsona remains non-responsive and has failed to provide the required monthly well pressures for March 2017. Further, it alleges the company violated state regulations by not installing another pressure gauge on an outer well casing. Ahtna attorney Nicholas Ostrovsky said during the hearing that his subsequent review of company communications found a “choke point” in communications within Tolsona without redundancy measures to assure management was made aware of issues such as the AOGCC’s demands. That choke point came down to the company’s operations and development manager, according to the Ahtna officials. The commission’s directives simply did not make it to Maloney or any other senior leaders, they said, despite the fact that everyone involved works in the same office complex. Maloney said he talked with the individual responsible almost daily but the situation was never brought up. A clearly perturbed Commissioner Cathy Foerster asked a series of technical questions the Ahtna officials were unable to answer; the attorneys and Maloney said they understood the hearing was to focus on the timeline of events and not issues with the well. As a result, the commission gave the company 30 days to respond to the questions. Ahtna counsel Brewster Jamieson said the company sympathizes with what the commission initially thought was the case, that Tolsona was “simply blowing the commission off,” but said that was absolutely not the case because management did know what was going on. Therefore, he said the company believes the fines for not following the commission’s orders are excessive and not in line with similar previous cases. Foerster also asked why it should matter to the commission whether or not management was notified. “The AOGCC did everything in its power to get a hold of us and we simply failed to respond,” Ostrovsky said. The April 11 notice details the $380,000 proposed fine as $10,000 for failing to install the pressure gauge and another $10,000 for failing to submit the March 20 well pressure report. On top of that, the commission levied another $5,000 per day for each of the 50 days the gauge was not installed, from Feb. 20 to April 11, and $5,000 per day for each day the March 20 pressure report was past due. Jamieson contended the commission issued the $260,000 in fines for not installing the pressure gauge based on inapplicable regulations. He said the commission referenced production well regulations in issuing the fines, but the exploration well has never reached production so it couldn’t violate those regulations. The regulation application issues were not discussed further. AOGCC Chair Hollis French said the commission noted Ahtna’s contrition on the matter and left the hearing record open until Oct. 26 to allow for the company to respond to Foerster’s technical questions. No ruling was made on the fines as a result. ^ Elwood Brehmer can be reached at [email protected]

Mallott rejects salmon habitat ballot initiative

Lt. Gov. Byron Mallott denied an application on Sept. 12 to put a voter initiative on the 2018 statewide ballot that would have tightened the state’s permitting requirements for development projects with the potential to impact salmon streams. Assistant Attorney General Elizabeth Bakalar wrote a Sept. 6 letter to Mallott recommending he not certify the initiative because it would strip the Legislature of its power to allocate resources — in this case salmon habitat — and thus violate the Alaska Constitution. The lieutenant governor’s primary responsibility in Alaska is to manage state elections. The “salmon habitat initiative” pushed by the nonprofit Stand for Salmon, which is chaired by Cook Inlet commercial fisherman Mike Wood, met all but one of the four criteria the Department of Law uses to evaluate ballot initiatives, according to Bakalar. She noted that the Alaska Supreme Court has generally ruled broadly to allow citizen initiatives unless there is no debate the proposal in question is unconstitutional. “An initiative us unobjectionable as long as it grants the Legislature sufficient discretion in executing the initiative’s purpose. But an initiative that controls the use of public assets such that it essentially usurps the Legislature’s resource allocation role runs afoul of Article XI, Section 7 (of the Alaska Constitution),” Bakalar wrote. “17FSH2 (its technical title) clearly limits the Legislature’s ability to decide how to allocate anadromous streams among competing uses. The initiative contains restrictions and directives that would require the commissioner to reject permits for resource development or public projects in favor of fish habitat.” Specifically, it would have overhauled Title 16, the state’s permitting law for salmon streams, by establishing two tiers of development permits that could be issued by the Department of Fish and Game commissioner. “Minor” habitat permits could be issued quickly and generally for projects deemed to have an insignificant impact on salmon waters. “Major” permits for larger projects such as mines, dams and anything determined to potentially have a significant impact on salmon-bearing waters would require the project sponsor to prove the project would not damage salmon habitat. Additionally, the project sponsor would have to prove that impacted waters are not salmon habitat during any stage of the fish life cycle if the waters are connected to proven salmon habitat in any way but not yet listed in the state’s Anadromous Waters Catalog. Currently, Title 16 directs the Fish and Game commissioner to issue a development permit as long as a project provides “proper protection of fish and game.” The initiative sponsors contend that is far too vague and an update is needed to just define what “proper protection” means. The Department of Law deemed an earlier iteration of the initiative as a means to allocate resources and prohibit projects such as the Pebble and Chuitna mines and Susitna-Watana dam, which the initiative sponsors have opposed. Stand for Salmon wrote in a formal statement that Gov. Bill Walker’s administration has chosen to “play politics” and defer to the short-term gains of Outside mining companies instead of supporting the fish Alaskans depend on. “The decision to deny us our constitutional right as Alaskans to gather signatures and put this issue before voters is stunning, particularly from a governor who once promised to support fish first policies,” the group wrote. “Instead, Governor Walker and Lt. Governor Mallott have done next to nothing to uphold their promises to Alaskans who depend on salmon for jobs, culture, recreation and way of life. “The merits of our application should have been based purely on the law. Yet, the relentless lobbying and pressuring from corporate representatives and lawyers seemed to carry more weight than the integrity of the public process.” Opponents to the initiative have said Title 16 is working as it is and the proof is that Alaska has not had an environmental disaster related to projects under the law’s jurisdiction. Wood, one of the sponsors, said in a previous interview with the Journal that the state has simply been “lucky” that it has avoided such a disaster, noting most of the large mines and other projects in Alaska are well away from salmon rivers. Bakalar wrote in a June 30 letter to the sponsors that a previous version of the initiative would have also allocated resources without the Legislature’s consent. The initiative was then reworded in an attempt pass legal muster, but the revisions apparently didn’t go far enough. “Despite the altered language, we remain concerned that 17FSH2 would, theoretically and/or in practice, categorically prohibit certain mines, dams, roadways, gaslines, and/or pipelines,” Bakalar wrote Sept. 6. “In doing so, the measure would effectively set state waters aside for the specific purpose of protecting anadromous fish and wildlife habitat ‘in such a manner that is executable, mandatory, and reasonably definite with no further legislative action,’ while leaving insufficient discretion to the Legislature or its delegated executives to use that resource in another way.” She also noted the letter should not be viewed as an opinion to whether the initiative is good public policy or not, but is simply a legal opinion on its constitutionality. To that end, the public policy could still be changed via House Bill 199, sponsored by Rep. Louise Stutes, R-Kodiak. The bill largely mirrors the language of the initiative and if passed, would be the Legislature deciding to allocate and prioritize water resources for salmon. Board of Fisheries Chair John Jensen also wrote in a Jan. 19 letter to House and Senate leaders that there is nothing in current state laws or regulations defining what is a proper protection. The Kenai Peninsula Borough Assembly also unanimously passed a resolution about a year ago supporting an update to Title 16 to further protect fish habitat. Wood said HB 199 would be the ideal vehicle for changing Title 16, as it could be amended to include input from development proponents and thus be more agreeable to more Alaskans, but added that the initiative was the group’s way of showing how serious it is about getting the law changed. The sponsors have 30 days to appeal Mallott’s ruling and Stand for Salmon said it is currently evaluating its next move. Elwood Brehmer can be reached at [email protected]

Ballot measure would give greater say to ADFG

Alaska fishing groups concerned about the impacts that large-scale development projects could have on salmon habitat are pushing to reform the state’s permitting requirements through a voter initiative on the 2018 ballot. The initiative would primarily establish a two-tiered permitting structure for projects with the potential to impact salmon-bearing waters. It would give the Department of Fish and Game commissioner the authority to issue broad approval for projects deemed “minor,” but also require proponents of larger projects to prove they would not have a significant adverse impact on salmon habitat. Additionally, it would require project advocates to prove to Fish and Game that the area of the water body the development could damage is not used by salmon sometime in their life cycle if the water is connected to one known to have salmon. The initiative was sponsored by Cook Inlet commercial fisherman Mike Wood, Bristol Bay lodge owner Brian Kraft and Gayla Hoseth of Bristol Bay Native Association. Lt. Gov. Byron Mallott will decide whether to certify the initiative by Sept. 12. In an interview, Wood said it is not intended to stop development projects, but rather to simply update the state’s protections for salmon as the Board of Fisheries requested. Current law directs the Fish and Game commissioner to approve fish habitat permits if a project is deemed to provide “the proper protection for fish and game.” Board of Fisheries Chair John Jensen wrote in a Jan. 19 letter to House and Senate leaders that there is nothing in current state laws or regulations defining what is a proper protection. “Additional guidance is warranted for the protection of fish, to set clear expectations for permit applicants and to reduce uncertainty in predevelopment planning costs,” Jensen wrote. “To strengthen ADF&G’s implementation enforcement of the permitting program, the Legislature may want to consider creating enforceable standards in statute to protect fish habitat, and to guide and create a more certain permitting system.” The Board of Fisheries letter was spurred by public pressure to amend Title 16, the state’s general laws relating to Fish and Game, according to Jensen. To that end, the initiative, which would rewrite state law, is mirrored after House Bill 199 sponsored by Rep. Louise Stutes, R-Kodiak. “We don’t want to stop (development); we want to make sure that the permitting process is rigorous so that we don’t destroy the fish habitat that we need to get the returns that are so important to the Alaska economy,” Wood said. The Alaska Constitution was written with a huge amount of thought toward salmon resources and the effort is to get back to that mindset in the state, he added. “It’s gotten a little blown out of proportion because this won’t stop things; it’s just trying to elevate the level of accountability back to where we believe it began at statehood. Over the years the regulations have been whittled away from administration to administration,” Wood said. Initiative opponents have cited federal laws, such as the Clean Water Act and National Environmental Policy Act that guides the environmental impact statement process as additional adequate salmon habitat protections; meaning an update to Title 16 is unnecessary. “I think there was a time when we thought we could have faith in the feds, the EPA, to have those standards and I think now we’re seeing that we can’t and it’s just part of the state having a greater say in its own outcome to have those high (permitting) standards,” Wood said. Wood characterized Alaska as simply “lucky” it hasn’t seen a large-scale manmade disaster of late similar to the 2014 Mount Polley mine tailings dam failure in British Columbia. He noted many of the state’s largest mines and other developments are in the Interior region or otherwise away from major salmon-bearing watersheds. The Department of Law deemed an earlier iteration of the initiative as a means to allocate resources and prohibit projects such as the Pebble and Chuitna mines and Susitna-Watana dam, which the initiative sponsors have opposed. A June 30 Department of Law letter to the sponsors outlined the provisions in the first draft of the initiative that would not pass legal muster. Assistant Attorney General Elizabeth Bakalar emphasized in an interview that the letter was in large part a response to industry concerns about the initiative that the department heard and is the same type of opinion state attorneys issue on any ballot measure — just earlier. She commented that the department isn’t likely to issue “courtesy” opinions in the future because this one has been incorrectly perceived as the state helping the petitioners. However, it could just as easily be seen as a way to calm development industry concerns by clarifying ahead of time that the initiative would not be ratified. “It’s just a heads up; do with it what you will,” Bakalar said. Wood said small changes were made to the latest version to hopefully meet the Department of Law standards. He acknowledged that the preferable vehicle to address salmon habitat protections would be through HB 199, which could be amended to include input from development proponents, but characterized the ballot proposal as a “belt and suspenders” approach to the issue. The Resource Development Council and other pro-development groups stressed in testimony on HB 199 that reforming the state’s habitat permit requirements is a solution searching for a problem. “The intent to safeguard Alaska’s salmon fisheries is an objective we share and it is why we support Alaska’s existing rigorous and science-based regulatory system,” wrote a coalition including the Alaska Chamber, Southeast Conference and the Anchorage and Fairbanks economic development corporations in an April letter to legislators. “As a coalition that includes urban and rural Alaskans and businesses and associations representing tens of thousands of jobs for our state’s citizens, we cannot overstate how important it is to have consistent regulator and permitting processes.” They continued to contend that HB 199 or the initiative would likely cause delays to smaller community projects like wastewater facility upgrades or airport expansions while worsening the state’s fiscal crisis by slowing or stopping economic development without any true benefits to fish habitat. Alaska Native corporations such as Cook Inlet Region Inc., Calista Corp. and Doyon Ltd. have opposed the measures, while Native tribal organizations such as the Tanana Chiefs Conference and the Native Village of Eklutna support it. The Kenai Peninsula Borough Assembly unanimously approved a resolution in September 2016 supporting an update to Title 16 to further protect fish habitat. A 2014 state ballot measure requiring legislative approval for a large mine in Bristol Bay — which Pebble argues is a blatant violation of the Alaska Constitution — was billed as a way to protect the region’s salmon and passed with 66 percent support among Alaska voters. It was supported by 72 percent of voters in Bristol Bay and greater southwest Alaska, according to Division of Election results. Elwood Brehmer can be reached at [email protected]

Railbelt utilities make progress to pool resources

Leaders of Alaska’s largest electric utilities hope to have a green light from state regulators to form new infrastructure management companies in a little more than a year. A collection of officials from the six Railbelt region utilities told the Regulatory Commission of Alaska at a late August meeting that they are collectively working toward internally approving the joint formation of a transmission company, or transco, by the end of the year. That would allow the utilities to submit the plan to the RCA early in 2018 and possibly have it approved by the end of next year. Proponents of the new jointly owned company believe pooling transmission lines and the resources is the best way to spread the costs of large infrastructure projects and assure the benefits from them reach as many of the region’s residents as possible. The RCA strongly ordered the utilities to investigate forming a transco in 2015, stating the cooperatives had not collaborated enough to maximize efficiencies and economies of scale in delivering power to their ratepayers. Covering an area from Fairbanks to Homer — home to about 80 percent of Alaskans — managers at some of the utilities had previously been hesitant about forming a transco, as it means giving up control of the utility-owned transmission lines that can provide revenue from wheeling tariffs. They generally acknowledge a transco would be of at least some benefit, but also emphasize their cooperatives’ bylaws require them to do what’s best for their ratepayers and investing in a transco could mean spending on projects that provide the greatest aid to others. The transco would be a partnership between the utilities and Wisconsin-based American Transmission Co., a transco formed after its state’s Legislature passed a law mandating Wisconsin utilities to do so. American Transmission Co. has pitched its experience in operating a transco to the Alaska utilities and the positives of forming one in Alaska, where long lengths of expensive transmission lines are needed to serve relatively small populations. The Alaska Energy Authority just finalized a study that says more than $880 million of substations, new lines, and other improvements are needed to optimize Railbelt electric generation and distribution. The utilities have consistently downplayed the need for such large-scale spending, contending a less expensive, more targeted investments would give the greatest benefits for money spent. ATC Business Development Manager Eric Myers told the RCA that his company knows it must earn a right to participate in the Alaska transco. “(In Wisconsin) every company was doing what was best within his or her jurisdiction to meet its customers’ needs. But the interconnections were a little weak, and economics and reliability suffered as a result.” Myers said. Fairbanks-area Golden Valley Electric Association CEO Cory Borgeson and Matanuska Electric Association General Manager Tony Izzo both said the utilities need to form an independent system operator, or ISO, as well to similarly manage power transactions between utilities down to a minute-by-minute basis. MEA, Anchorage Municipal Light and Power and Chugach Electric Association entered into their own ISO-like power pooling agreement in January. They estimate pooling their generation resources to maximize efficiencies could save their ratepayers between $12 million and $16 million per year. Much of the savings comes in the form of less fuel, which in Southcentral Alaska means less burning of natural gas. Chris Rose the executive director of the Anchorage nonprofit Renewable Energy Alaska Project, also testified to the RCA that an ISO is as much of a necessity as a transco is. “We do not want to find ourselves in a situation where a transco is formed, the parties declare victory, and the momentum to do anything further dies out. New transmission assets may increase the ability of the Railbelt to economically dispatch electrons and add more nonfuel renewable energy to the grid,” Rose said. The utilities’ leaders said a governance model assuring maximum local control of the transco is a priority and remains something the utilities must finish. They also have to finalize the operating agreements and methods for allocating transmission costs before taking the plans to their boards for approval. The RCA has scheduled a meeting Sep. 27 for further updates on the progress of the utilities’ work. Elwood Brehmer can be reached at [email protected]

State rejects Point Thomson expansion plan

The Alaska Division of Oil and Gas has denied ExxonMobil’s plan to expand the Point Thomson North Slope gas project because it doesn’t live up to a prior settlement between the state and the company, according to Director Chantal Walsh. In a detailed six-page letter dated Aug. 29, Walsh wrote to ExxonMobil Alaska Vice President Cory Quarles that the Point Thomson Expansion Project Planning Plan of Development, or POD, is far too vague and offers no commitment that the company will live up to the 2012 Point Thomson Settlement Agreement. Separate from but related to the Expansion Project POD, the division parsed out and approved the Initial Production System POD despite the company not meeting production expectations of natural gas condensates at Point Thomson because of technical challenges. ExxonMobil submitted a single Point Thomson POD to the state on June 30, but division officials determined it contained two PODs because the 2012 settlement does not spell out what the company must do with its current infrastructure at the large eastern Slope gas field after this year. The settlement does, however, direct the company to start expanding production at Point Thomson by 2019 under one of several scenarios. PODs are submitted annually by the unit operator company for every oil and gas unit in the state. They detail the company’s work plan for the coming year. The plans are generally adhered to but not strictly enforced by the state if unforeseen factors, such as changes to a project’s economics from external market forces or technical challenges, arise, Walsh noted. But in the unique case of Point Thomson, development is prescribed by the settlement, which the Division of Oil and Gas considers to be a contract with the state, meaning its terms must be upheld regardless of extenuating circumstances, according to Walsh. The Point Thomson Settlement, reached under former Gov. Sean Parnell, ended years of litigation between the state and the company in which the state argued ExxonMobil had not fulfilled its responsibility to develop the leases it held for many years. It also set a course for ExxonMobil to develop Point Thomson and start production by May 2016. The field was discovered in 1977. ExxonMobil, which operates Point Thomson, and BP, its primary working interest owner partner, spent roughly $4 billion developing the gas field since 2012. Production started in late April 2016. Gov. Bill Walker, who’d lost to Parnell in the Republican primary in the 2010 governor’s race, promptly sued the state over the settlement in 2012 on the grounds that the settlement over state assets was reached in private negotiations and was not in the best interest of Alaska residents. He withdrew his appeal to the Alaska Supreme Court in February 2015 shortly after taking office. Last year Walker’s administration deemed the Prudhoe Bay Unit POD incomplete until BP, as unit operator, and the state reached an agreement that the company would provide more information on its efforts to further the Alaska LNG Project in future PODs. ExxonMobil outlined its plans to move gas from Point Thomson and inject it into the Prudhoe Bay oil and gas pool as a way to further enhance oil recovery from the large oil field. The reinjection of gas produced during oil production efforts at Prudhoe has been a primary driver behind BP’s ability to extract more than 30 percent more oil — currently about 12.5 billion barrels in total — from the massive field than was expected when it came into production 40 years ago. Production facilities at Point Thomson would first be expanded to handle production of more than 50,000 barrels per day of the diesel-like condensates and 920 million cubic feet per day of gas. The current Point Thomson facilities have a production capacity of about 10,000 barrels of condensates and 200 million cubic feet of gas per day. Moving gas to Prudhoe is one of the options for expanding Point Thomson under the settlement in the event major gas sales — the Alaska LNG Project — was not sanctioned by mid-2016. While the Alaska Gasline Development Corp. continues to advance the gasline project, it is still uncertain if it will be built. With an estimated 8 trillion cubic feet of natural gas, Point Thomson holds about a quarter of the gas needed to feed a large gasline; the rest is in the Prudhoe Bay pool. Point Thomson is one of the highest pressure producing gas fields on Earth, at about 10,000 pounds per square-inch. A positive of the reservoir pressure is that it makes separating the condensates, or natural gas liquids, from the gas much easier. According to ExxonMobil officials, the liquids essentially “fall out” of the gas once the pressure is relieved. Those liquids are then fed into the Trans-Alaska Pipeline System. The natural gas has so far been reinjected into the Point Thomson reservoir. Getting the gas from Point Thomson to Prudhoe would require construction of a 62.5-mile, 32-inch diameter gas pipeline between the fields and production would be ramped up with the drilling of three new wells, according to the plan of development. The two wells now used for gas injection would also be converted to production. Specifically, Walsh points to the wording the company used in its Expansion POD to justify her ruling. The POD states that before expansion planning can proceed, the working interest owner companies at Point Thomson and Prudhoe must sign a commercial agreement and fund the work, and according to Walsh, ExxonMobil confirmed that in a technical meeting with division officials. Company representatives said further that it had “not even approached the Prudhoe working interest owners to begin these discussion, but surmised that the Prudhoe working interest owners were aware of the need for an agreement,” Walsh recalled in her letter. She noted that BP, ExxonMobil and ConocoPhillips collectively own 99 percent of both fields — Chevron holds 1.6 percent of Prudhoe — and therefore Exxon was, in part, waiting to negotiate with itself. ExxonMobil corporate spokesman Aaron Stryk wrote in an email that, “We have been, and continue to be, in full compliance with the Point Thomson Settlement Agreement. We are aware of the letter from the Department of Natural Resources, but have not yet reviewed the letter, so we are unable to comment.” Walsh further emphasized that the need for a commercial agreement is not part of the settlement and the lack of one should not prevent Exxon from continuing expansion planning. “The POD conditions all FEED (front-end engineering and design) work — the work that the Settlement Agreement requires the Point Thomson Unit WIOs to conduct during this POD period — on whether the WIOs decide to fund the work. Exxon prefaces its discussion of FEED by stating, ‘if funded FEED would progress…’ and then proceeds to refer to activities it ‘would’ do, rather than activities it will do,” Walsh wrote. “The division questioned Exxon about this language to determine if it was intentional or merely inartful wording. Exxon confirmed at the technical meeting that the WIOs did not intend to proceed with any Expansion Project Planning work unless they both decide to fund the work and enter a commercial agreement for Prudhoe Bay Unit injection. Again, the division understands the importance of the commercial agreement, but it is not an impediment to complying with the Settlement Agreement.” She continued: “This proposed POD would allow the WIOs to decide that they would rather not pay for planning, and then Exxon would perform no work. This proposed POD would also allow the WIOs to not enter an agreement with themselves for Prudhoe Bay Unit injection, and then Exxon would perform no work.” Walsh additionally contended that the plan does not comply with the settlement because it is far too vague to be an adequate POD. The Settlement Agreement requires the plan to include the number of wells, their locations and other plans for completion of expansion, while Exxon simply stated it would drill three new wells on the Central Point Thomson pad, without identifying the wells’ targets or completion plans, she wrote. Similarly, it states Exxon expects to file for permits to do the work with little more detail. “Scheduling time to apply for permits is not a plan for acquiring them,” Walsh wrote. She summarized her displeasure with the company by writing that the “POD fails to paint even the most impressionistic picture of what Exxon will do over the next year and a half to engineer and permit an expansion project.” “The proposed Expansion Project Planning POD fails to provide for Exxon to fulfill this contractual obligation. The proposed POD includes conditions that would give the Point Thomson Unit WIOs control to avoid doing any planning work, effectively nullifying this portion of the Settlement Agreement,” Walsh concluded. Appeals to Oil and Gas POD rulings usually go to the Department of Natural Resources Commissioner; however, the Settlement Agreement nullifies the administrative appeal and sends Point Thomson disputes directly to the Alaska Superior Court, according to Walsh. ExxonMobil has until Oct. 13 to submit a revised Point Thomson Expansion POD. Production challenges ExxonMobil met its first big deadline at Point Thomson by starting condensate production and natural gas cycling in April 2016. Since then, however, the company has had difficulty meeting the 10,000 barrels per day of condensates production threshold called for in the 2012 Settlement Agreement with the state. ExxonMobil noted in its proposed Point Thomson POD that production exceeded 10,000 barrels of condensate and 200 million cubic feet of natural gas on Dec. 20, 2016. Yet, Walsh wrote the company has not met its obligation because production levels have fluctuated wildly in the year-plus since the project came online. According to Alaska Oil and Gas Conservation Commission data, Point Thomson produced 47,972 barrels of natural gas condensates in April 2016, but that fell to just 7,903 barrels for the entire month of May. Production was then ramped back up to hit 213,845 barrels in December, to average about 7,000 barrels per day for the month. Production then peaked in January with a daily average of 7,634 barrels, but fell again in June to a total of 8,400 barrels for the month, or just 280 barrels per day. In July, Point Thomson produced an average of 1,738 barrels per day of natural gas condensates. The production fluctuations stem from problems ExxonMobil has had with the gas compressor it uses to reinject the natural gas back into the reservoir, according to Walsh’s letter. “During the technical meeting, Exxon provided additional detail about the compressor and its design flaws and difficulties in relation to this reservoir. By Exxon’s account, it was conducting maintenance or repairs on the compressor during periods when production ceased or decreased,” she wrote. The company also acknowledged a requirement to pursue, but has not identified work, to “debottleneck” the Initial Production System, as it is directed to in the Settlement Agreement, Walsh noted. Finally, ExxonMobil has not advanced permitting for an East Pad and associated wells at Point Thomson — another requirement of the deal — beyond what it had done at the time the settlement was reached, she continued. Walsh wrote that the Oil and Gas Division is “hopeful” the company can resolve the technical issues with the IPS and sustain production at 10,000 barrels per day and the division appreciates its consideration of debottlenecking work. “While the division remains concerned about the future of the IPS, the proposed POD does generally provide for continued production, which is a benefit to the state. Unitized production like this generally conserves resources, minimizes environmental impacts, and prevents waste,” Walsh summarized. “The proposed POD does not create additional impacts to the land. Thus, despite the division’s continued concerns, the division hereby approves the IPS POD for the period Sept. 30, 2017, through December 31, 2019.” Elwood Brehmer can be reached at [email protected]

Coast Guard commandant keeps up push for icebreakers

U.S. Coast Guard Commandant Adm. Paul Zukunft has one very clear message: the country needs more icebreakers. Zukunft reiterated that point time and again during an Aug. 24 speech to members of the Alaska policy nonprofit Commonwealth North in Anchorage. He recalled a conversation he had with then-National Security Advisor Susan Rice when Rice asked him what President Barack Obama should highlight shortly before the president’s extended trip to Alaska in late August 2015. “I said (to Rice) we are an Arctic nation. We have not made the right investments and we do not have the strategic assets to be an Arctic nation and that translates to icebreakers and that’s almost exactly what President Obama said when he came up here,” Zukunft said. “Fast forward — it’s Jan. 20, 2017, and I’m sitting next to President Trump and as they’re parading by he says, ‘So, you got everything you need?’ I said, ‘I don’t. The last administration, they made a statement but they didn’t show me the money. I need icebreakers.’ (Trump said) ‘How many?’ ‘Six.’ ‘You got it.’ “You never miss an opportunity,” Zukunft quipped. It’s well documented in Alaska that the U.S. has “one-and-a-half” operable icebreakers. That is, the heavy icebreaker Polar Star and the medium icebreaker Healy, which are in the Coast Guard’s fleet. A sister ship to the Polar Star, the Polar Sea remains inactive after an engine failure in 2010. Zukunft noted Russia’s current fleet of 41 icebreakers to emphasize how far behind he feels the U.S. is in preparing for increased military and commercial activity in the Arctic as sea ice continues to retreat — a message Alaska’s congressional delegation stresses as well. “We are the only military service that’s truly focused on what’s happening in the Arctic and what happens in the Arctic does not happen in isolation,” Zukunft said. He added that Russia is on track to deliver two more cruise missile-equipped icebreakers in 2020. “I’m not real comfortable with them right on our back step coming through the Bering Strait and operating in this domain when we have nothing to counter it with,” he said. The Coast Guard’s 2017 budget included a $150 million request to fund a new medium icebreaker, which Zukunft characterized as a “down payment” on the vessel expected to cost about $780 million, according to an Aug. 15 Congressional Research Service report on the progress of adding to the country’s icebreaking fleet. For years it was estimated that new heavy icebreakers would cost in the neighborhood of $1 billion each, but those estimates have been revised down as the benefits of lessons learned through construction of the initial vessel and ordering multiple icebreakers from the same shipyard are further examined. The CRS report now estimates the first heavy icebreaker will cost about $980 million to build, but by the fourth that price tag would go down to about $690 million for an average per-vessel cost of about $790 million. That is on par with the cost for a single new medium icebreaker. Zukunft said the Coast Guard is working with five shipyards on an accelerated timeline to get the first icebreaker by 2023, but how it will be fully funded is still unclear. “We have great bipartisan support but who is going to write the check?” he said, adding that aside from Russia and China, the United States’ economy is larger than that of the other 18 nations with icebreakers combined. The Obama administration first proposed a high-level funding plan for new icebreakers in 2013 that has not been advanced outside of small appropriations. “Our GDP (gross domestic product) is at least five times that of Russia and we’re telling ourselves we can’t afford it,” Zukunft continued. “Now this is just an issue of political will and not having the strategic forbearance to say this is an investment that we must have.” He also advocated for the U.S. finally signing onto the United Nations Law of the Sea treaty, which lays out the broad ground rules for what nations control off their coasts and how they interact in international waters. Not signing onto the Law of the Sea, which was opened in 1982, leaves the U.S. little say as other nations further study and potentially exploit the Arctic waters that are opening, he said. “We are in the same club as Yemen; we are in the Star Wars bar of misfits of countries that have not ratified the Law of the Sea convention,” Zukunft said. ^ Elwood Brehmer can be reached at [email protected]

Court rules on PFD veto lawsuit

JUNEAU — The Alaska Supreme Court ruled that Gov. Bill Walker acted within his authority in reducing the amount set aside for checks to state residents from Alaska’s oil-wealth fund last year. The decision, released Aug. 25, affirms a lower court decision that sided with the state in the dispute over Alaska Permanent Fund dividends. The high court decided that the legislature’s use of fund income is subject to normal appropriation and veto processes. It says Walker validly exercised his veto authority when reducing the amount available for dividends last year. The case was brought by Democratic state Sen. Bill Wielechowski and two former legislators. Wielechowski said he is “bitterly disappointed” by the court’s ruling. Walker called it “by far” the most difficult decision he’s made as governor. They had argued that the Alaska Permanent Fund Corp. was required by law to make available nearly $1.4 billion from the fund’s earnings reserve for dividends, despite Walker’s veto. The case was heard before the Supreme Court on June 20. The court determined the “narrow question” it had to answer was whether the constitutional amendment that created the Fund and dedicated 25 percent of all state resource royalties to feed it also exempted the use of the Fund’s income from the anti-dedication clause, according to the ruling. “The answer cannot be found by weighing the merits of the dividend program or by examining the statutory dividend formula,” the justices wrote. Wielechowski’s group argued in part that Walker overstepped his authority by crossing out the reference to the dividend formula statute in the budget in addition to replacing the original estimated $1.36 billion collective dividend payment with $695 million. The Alaska governor has the authority to veto appropriations, but not existing laws. In its discussion of the ruling, the court noted it ruled in a 1982 case that the anti-dedication clause of the Alaska Constitution “prohibits the dedication of any source of revenue” without a constitutional exception. The crafters of the state Constitution believed dedicated funds to be a “fiscal evil,” according to the ruling, because they took control necessary to manage state finances away from the governor and Legislature. “No party suggests that Permanent Fund income (distributed for dividends) is not state revenue,” the ruling states. “Our starting point must therefore be that the anti-dedication clause prohibits the dedication of Permanent Fund income unless the 1976 constitutional amendment exempted not only the dedication of enumerated revenues into the Permanent fund but also — as Wielechowski argues — the Legislature’s potential future, unspecified dedication of revenues out of the Permanent Fund.” Attorney General Jahna Lindemuth thanked the state’s attorneys that argued the case in a Friday Department of Law release. “I know this was not a decision Gov. Walker took lightly, but I’m glad we have more clarity around the use of Permanent Fund earnings as we continue to try and resolve the state’s fiscal crisis,” she said. Walker announced that he roughly halved the dividend appropriation among other vetoes in June 2016 on what he called “a day of reckoning” to drive home his message to legislators and the public that drastic changes to state finances need to be made to resolve Alaska’s ongoing multibillion-dollar budget deficits. This year, the Legislature itself ignored the statutory dividend formula and set an arbitrary dividend appropriation to pay dividends of $1,100 per Alaskan, a compromise amount based on what dividends would be under the differing versions of Walker’s Permanent Fund restructure bill passed by the House and Senate. To Wielechowski’s arguments, the court concluded that a plain reading of the Permanent Fund amendment, which states that income from the fund will go to the General Fund, “unless otherwise provided by law,” does not amount to a dedication. The Fund clause in the Constitution directs the Fund’s income to be deposited for appropriation, but it does not give the Legislature the authority to dedicate that income, according to the court. “Interpreting the 1976 constitutional amendment to allow dedications of Permanent Fund income would create an anti-dedication clause exception that would swallow the rule,” the justices concluded.

Rodell reflects on Fund at $60B milestone

The Permanent Fund is many things to many Alaskans. It’s the State of Alaska’s way of transforming finite resources into potentially perpetual wealth. It’s the source of undoubtedly one of the most popular government programs ever envisioned, the Permanent Fund Dividend. It’s always a reliable topic for lively debate. At more than $60 billion, it’s currently worth about $83,000 per Alaskan. To Alaska Permanent Fund Corp. CEO Angela Rodell, it’s also beautiful. “When you think about the forward thinking and political will it took to set this up, it’s stunning. All too often I hear about the things that we’re not proud of in Alaska,” Rodell said during an hour-long interview with the Journal on Aug. 23. “Yet this one we got really right. This is something I think we should all be tremendously proud of and understand.” The understanding part is key, according to Rodell, particularly as the Legislature and Gov. Bill Walker debate whether the Fund should also be a funder of government. She said Alaskans, even some legislators, regularly refer to her organization as the “Permanent Dividend Division” or the “Permanent Dividend Fund,” referencing the corporation’s longtime sole purpose as far as much of the public is concerned: to produce the annual dividend checks distributed by the Revenue Department each October. On one level, the misconceptions about the Fund are understandable. Since 1976, when voters passed a constitutional amendment establishing the Permanent Fund, it has been cared for in relative anonymity. In 1980, the Legislature directed the corporation to start spinning off dividends based on the length of each Alaskan’s residency. The U.S. Supreme Court promptly nixed the idea of rewarding Alaskans based on their time served and in 1982 the Legislature approved the Permanent Fund Dividend formula that stands today. The PFD is half of the average annual net income generated by the Fund over the five most recent state fiscal years divided amongst all eligible residents. To date, the Fund supported more than 18.4 million dividend checks totaling about $21.1 billion. It was started with an initial deposit of $734,000 in oil royalties on Feb. 28, 1977. Continuous mineral royalty deposits and prudent management have grown the fund to $60.9 billion today. During the 2017 fiscal year that ended June 30, the Fund grew by more than $7 billion thanks to corporate managers achieving a 12.6 percent return on its investments. Rodell described the strong returns as a “nice recovery” after turbulence in financial markets through much of 2016 limited the Fund to about 1 percent growth. The 12.6 percent return was led by a roughly 20 percent return on the $26.1 billion of the Fund invested in public equities, or stocks. Rodell acknowledged that a market correction is all but assured given U.S. public markets continue to set records almost daily. “We know because history tells us there will be a correction. When and where — how much — is anyone’s guess. We don’t have any more insight into that than anyone else,” she said, noting that is why the Fund has an ever-more diversified portfolio. Rodell said the staff regularly run scenarios of various possible market downturns to evaluate how they could impact the Fund. Time of transition Rodell took the helm at the APFC in October 2015 just a couple months before Walker took a big political leap and proposed employing the Fund’s earning power to help alleviate what was then a roughly $4 billion budget deficit. Walker’s original bill would have drastically re-plumbed state finances to funnel most revenue through the Permanent Fund to fully harness that earning power and spin off about $3.2 billion to pay for government services. The governor has since endorsed a simpler percent of market value, or POMV, draw from the Fund’s Earnings Reserve Account each year, a plan his administration devised alongside Senate Republicans early in 2016. While the Democrat-led House and Republican-dominated Senate both passed similar version of Walker’s POMV bill earlier this year, the politically disparate leadership in the bodies have yet to compromise on the contingencies each has placed on doing something that was unheard of just a couple years ago, as Rodell and others have noted. Both House and Senate POMV plans would result in a smaller dividend check from the current statutory formula. Neither Walker nor former Gov. Sean Parnell ever mentioned turning to the Fund’s earnings to fix the deficit in the 2014 gubernatorial race, with Walker explicitly rejecting the idea of touching the PFD. However, less than three years later, it feels inevitable. Rodell was Revenue commissioner and a Permanent Fund trustee in Parnell’s administration. And though the Legislature is on the precipice of tapping the Fund for government — something it has resisted for 40 years — Rodell said it is being done properly, even if the politics is messy. “I think having a structural plan in place that is either POMV or a capped dollar amount draw really sort of helps everybody plan for some sort of distribution of the Earnings Reserve Account to the extent that (legislators) decide that’s the direction they want to go,” she said. Like the General Fund, the Earnings Reserve has always been accessible by majority votes in the House and Senate along with the governor’s approval. Additionally, the Alaska Supreme Court ruled Aug. 25 that the dividend is just another state appropriation that the governor has veto power over despite the best efforts of Sen. Bill Wielechowski and former state Sens. Clem Tillion and Rick Halford, who served in the Legislature when the dividend program was established. The bipartisan trio and some others in the Legislature have also supported the idea of enshrining the current dividend formula in the state Constitution to protect it from actions like Walker’s veto to halve the PFD appropriation in 2016 and the Legislature’s move this year to arbitrarily set dividends at $1,100 per Alaskan. Both moves resulted in PFD payments that were about half of what they would have been under the statutory formula. The $1,100 amount was a compromise between the dividends the House and Senate’s Permanent Fund POMV bills would provide for; the Senate’s was set at $1,000 with a 5.25 percent draw and the House’s at $1,200 with a 4.75 percent draw. Those bills would generate about $2.5 billion for government and dividends combined. Three times between 2000 and 2004, the Permanent Fund Corp. Board of Trustees passed resolutions in support of a POMV draw from the Fund of up to 5 percent after inflation; that was the last time lawmakers mulled employing the Fund to reduce deficits. Soaring oil prices and tax revenue soon pushed deficit worries aside. With all that as background, Rodell again stressed the importance of broadening knowledge about the Fund and its namesake corporation among both lawmakers and the general public. “For a long time nobody paid any attention because our purpose was to pay an amount over to (Revenue) to pay dividends, so you didn’t have a constituency that really cared,” she said. “Everybody cares about their dividend; they don’t really care how you get to the dividend or what it takes to generate that dividend. “I think in order for people to understand exactly what they’re being asked to make decisions about, whether it’s voters deciding the dividend or whatever it is, they need to understand what the Permanent Fund and the corporation is.” Fund 101 If the Fund is going to be expected to support part of the state’s budget each year, the first shift has to be mentally separating the Earnings Reserve that holds the Fund’s net income from its principal, according to Rodell. Together, the accounts make up what has always been known as the entirety of the Fund. Rodell admitted she often slips up, referring to the Fund as “$60 billion” to the Journal, instead of parsing out the $47 billion principal, or corpus, and the nearly $13 billion Earnings Reserve. The accounts are usually rhetorically lumped together in part because they are invested together. Stocks, for example, are purchased by the corporation with a pro-rated amount of the corpus and the Earnings Reserve. However, 100 percent of the income earned off that stock when it is sold is deposited into the Earnings Reserve, which is why inflation-proofing the corpus of the Fund is critical, Rodell said. The Legislature has not transferred money from the Earnings Reserve to the corpus for inflation proofing in the last two state budgets in an effort to build up the Earnings Reserve before starting to draw on it. It’s a decision Rodell appreciates, but it doesn’t make fighting the value degradation of the Fund any less important. In fiscal year 2016, it would’ve only taken about $47 million to counteract inflation — about 0.12 percent of the corpus value. But in 2017, that jumped to more than $500 million, according to Rodell. “If we’re not putting anything back into the corpus we still have that same $39 billion we had in the nominal value of the royalties contributed over the years; that’s all we have to invest,” she said. Rodell objects to the premise that the ongoing mineral royalty payments offset inflation. First, with current lower oil prices and much less production than the state has seen historically, last year’s royalty injection into the Fund of about $225 million isn’t even half of what was needed to offset inflation. Additionally, using royalties in-lieu of inflation proofing transfers does a disservice to young Alaskans, Rodell contended. “I would argue the royalty payment is the nonrenewable resource turning into a renewable resource. It shouldn’t even be considered a hedge against inflation by any stretch,” she said. “We’re still harvesting that nonrenewable resource and future generations should get the benefit of what we’re harvesting today and that’s the royalty payment.” Along with deferring inflation proofing, legislators also disregarded laws directing up to 50 percent of royalty revenue from some state leases to be deposited into the Fund. The Constitution requires a minimum of 25 percent of all resource royalties be used to grow the Permanent Fund and the Legislature has funneled the other 75 percent of royalty revenue into the General Fund of late in an effort to shrink the deficit. “There are a number of statutes that have been ignored without a plan being put in place. That concerns me,” Rodell said. Gov. Walker’s Permanent Fund restructure bills also reverted to the 25 percent royalty minimum and the POMV bills would only start to inflation-proof the Fund once the value of the Earnings Reserve is greater than four times the previous year’s draw. Any excess cash beyond the four-fold threshold would automatically be injected into the corpus. Budget battles While the realities of the state’s fiscal situation are putting pressures on the Fund, the Legislature’s ever-increasing inability to timely pass a budget is starting to weigh on the Alaska Permanent Fund Corp., as it is an arm of the state Revenue Department. Rodell recalled that the budget fight in 2015 drew into May, but the Legislature passed a receipts budget allowing self-sustaining state operations to stay open in the event of a government shutdown. The corporation’s budget comes out of the Earnings Reserve. By 2016, a budget deal was reached just days before the dreaded “pink slips” had to go out to state workers on June 1, but there was no receipt authority granted prior. In 2017, the budget battle lasted until a week before a government shutdown. At one point during the month, the Senate had passed a bill to use about $2 billion in Fund earnings while the House passed a budget to spend $5 billion. The eventual compromise ended up filling the deficit from the Constitutional Budget Reserve and dividends were funded as usual from the Earnings Reserve. “This year, they’re fine with sending out pink slips, but we’re not actually going to shut down state government. What do you think happens next year? I don’t care that it’s an election year,” she commented, adding that people in the Lower 48 are taking notice. “I’ve got headhunters watching this and calling my staff, calling me, saying, ‘Hey Angela, do you really want to keep working for the State of Alaska? I’ve got a great job in the Lower 48 for you.’ My (chief investment officer) got calls; we all got calls,” Rodell said. “Now the good news is we’re also residents of Alaska; we love Alaska, but how many more times are we going to do this?” “I don’t think there’s a single legislator out there that has any interest in seeing us shut off the lights and close our doors, not one, but we’re part of the bigger budget battles that happen.” To that, Rodell said the corporation Board of Trustees will likely decide at its late September meeting in Juneau whether or not the corporation will seek a change to state law to forward fund the corporation or otherwise remove it from the annual budget debates. She also characterized trying to adequately compensate the world-class finance professionals managing investments on the scale of the Permanent Fund requires as “a real challenge,” noting the Revenue commissioner faces the same obstacles with Treasury Division officials. Keeping up with compensation Because the APFC is technically an arm of the state, its salaries are viewed through the lens of what’s fair compensation for state government workers, Rodell said. “We got caught this year again in a debate of ‘no one’s getting merit increases.’ They cut $169,000 from our budget request I had built in for merit increases but we made $7 billion,” she commented, emphasizing that she does not advocate for Wall Street-like compensation at the APFC. Thankfully, the opportunity to work on the Permanent Fund — the United States’ premier sovereign wealth fund — in a place like Juneau usually sells itself, according to Rodell. She said investment types from worldwide hubs such as Singapore and London apply to move to Juneau to be a part of Alaska’s Fund. She described it as a “really crazy unique experience,” noting that the U.S. Treasury looks to the APFC to be its “eyes, ears, voice in the international camp. We participate in the International Forum of Sovereign Wealth Funds that was created by the World Bank and the IMF (in 2009); we are a leader in that organization.” Former CEO Mike Burns helped craft the Santiago Principles of transparency and good governance for sovereign wealth funds after the 2008-09 financial crisis, Rodell pointed out. “We have trillion-dollar funds — the staff come to Juneau and learn how we do things because they like the results that they see; they appreciate the transparency we create,” she said. “We bring a bit of a ‘halo effect’ we call it, to certain investments when we participate and I was not aware of that international reputation until I got into this job and started going outside.” She continued, “Knowing that we are voice in the international finance community — I think people would be really stunned by that. Now, whether or not people think that’s a role for us to play or not I don’t care. The fact is we can’t get away from it. “We have access to some of the most amazing, brightest thought leaders around the world and that’s a function of our size. It’s why I could recruit a chief investment officer the caliber of Russell Read.” Read joined the APFC in May 2016. He has also served as CIO for CalPERS, the $330 billion California state pension fund, among other positions, and holds master’s degrees from the University of Chicago and Stanford University as well as a Ph.D. in political economy from Stanford. Being able to participate on the global scale from a small town like Juneau offers other benefits, such as a work-life balance that is lost in the mega cities, Rodell added. “We save 170 hours in commuting time alone that you get back from New York if you come to Juneau. There’s no commuting time in Juneau,” she said with a laugh. The four-hour time difference between New York and Juneau can be a challenge but is not always a deterrent, according to Rodell. Investing internationally requires odd hours and one knows that going in. “If you’re a fixed income trader and you’re sitting at your desk when the markets open at 5:30 in the morning; you’re done by 1 o’clock in the afternoon,” she noted. “You know what that means in the summer in Alaska?” It’s changing times for nearly everyone in Alaska and Rodell said she doesn’t want to see the state’s biggest asset fall by the wayside or be pulled apart by competing pressures. She summed her thoughts up by reciting a question posed at a recent conference she attended. “Fifty years from now, what do you think your grandchildren will wish you had invested in today?” Rodell recalled. “My answer was the Permanent Fund because I worry that we’re not thinking about the Fund itself anymore; that we’re taking the Fund for granted in some ways and that it will be this perpetual ongoing resource.” ^ Elwood Brehmer can be reached at [email protected]

State to take on permitting for transportation projects; Cooper Landing bypass reconsidered

The Alaska and federal Transportation departments have inked a deal allowing the state to assume permitting responsibility on federally funded projects, which should speed environmental reviews and save government money, according to the agencies’ leaders. The memorandum of understanding, or MOU, will shift environmental assessment and environmental impact statement drafting from U.S. DOT sub-agencies to the state Department of Transportation and remove duplicative federal processes and “interagency squabbling,” DOT Secretary Elaine Chao said during a Thursday afternoon press conference in Anchorage. Alaska Transportation Commissioner Marc Luiken said the agreement will hopefully save money on large projects by spending less on studies — leaving more for construction. “We see the opportunity to accelerate project delivery,” Luiken said at the briefing. The State of Alaska will still follow the National Environmental Policy Act processes with oversight from its federal counterparts, but will issue its own decisions at the end of the reviews. “Every federal regulation, every federal law still has to be abided by, but we’re just the lead agency,” Luiken added. The standard 90-10 federal-state split on funding for large highway and airport projects still applies regardless of who is leading the studies, so the state will not be adding cost burdens, he clarified. Sen. Dan Sullivan, long an ardent critic of the layered federal regulatory process for construction projects, said it should provide more jobs for Alaskans by allowing more important infrastructure projects to move forward. “It’s a new era of state and federal cooperation,” Sullivan said. The MOU will be published in the Federal Register Friday and likely take effect in late October after a public comment period. Chao stressed the agreement as a way to add jobs to a state in a recession. “Infrastructure feeds economic development,” she said. Cooper Landing bypass The trio used the long-studied and proposed Sterling Highway bypass around the narrow, windy section of highway through Cooper Landing as a prime example of what can happen when multiple federal agencies are left to work on a major road project. However, they also announced the U.S. Fish and Wildlife Service, an Interior Department agency, has agreed to consider a swap with Cook Inlet Region Inc. of Kenai National Wildlife Refuge acreage for some of the Alaska Native corporation’s property that could facilitate the bypass route many Alaska leaders want. A spokesman for CIRI could not immediately be reach for comment on the proposal. The first draft EIS for rerouting the Sterling Highway around Cooper Landing was completed in 1982 but did not lead to construction. A second draft was published in 1994 before again stalling, according to the Alaska DOT’s website on the project. Publication of a final EIS this year left the state at odds with the Federal Highway Administration, which chose a route different than that preferred by many on the Kenai Peninsula and Gov. Bill Walker’s administration and the congressional delegation. The $250 million “G South” alternative selected by FHWA would add a third bridge over the Kenai River in the area and therefore not mitigate risks to the river from accidents such as tanker spills that the more northerly $205 million Juneau Creek option would, they contend. The Juneau Creek route would also use less of the existing highway corridor. In July, Walker, Sen. Lisa Murkowski, Sullivan and Rep. Don Young sent a letter to Chao and the Secretaries of Interior and Agriculture urging them to have their agencies rethink the alternatives. Walker commended Chao for agreeing to relook at the Cooper Landing bypass options in a statement from his office. “It is critical to the safety and health of both Alaskan motorists and our world-class salmon fisheries that this complicated project move forward,” the governor said. “The current road alignment does not meet current highway standards, is congested, and due to its proximity to the river has an increased risk of spills that would harm salmon in the Kenai and Russian rivers. I thank Secretary Chao for allowing all options for this project to be considered.” The Interior and Agriculture departments had allegedly been hesitant to sign off on the Juneau Creek option, as it would send the highway through additional Chugach National Forest and Kenai National Wildlife Refuge lands.   Elwood Brehmer can be reached at [email protected]

Rare Alaska hearing probes causes for plane crashes

Why, in the technological age, are airworthy planes still being flown into the ground in Alaska? That was the omnipresent question at the National Transportation Safety Board’s Aug. 17 hearing in Anchorage to further its investigation into the crash of Hageland Aviation Flight 3153 on Oct. 2, 2016, just outside of the Western Alaska village of Togiak. The Hageland Cessna 208 Caravan was en route to Togiak from the nearby village of Quinhagak with a load of mail and one passenger when it crashed high on a mountainside about 12 miles from Togiak, according to representatives from the commuter airline. The controlled flight into terrain, or CFIT, crash killed the passenger and both pilots on impact. While the number of CFIT accidents in Alaska has generally decreased over the last decade-plus, NTSB officials said leading up to the rare field hearing that they really shouldn’t be happening anymore at all. Board member Earl Weener stated in a press release that the board traveled to Alaska because most of the witnesses the agency wanted to hear from are here. However, the NTSB has investigated countless aviation accidents in the state over the years and the inquiry into the Togiak crash was the first investigative hearing the board has held outside of Washington, D.C., in nearly 20 years. It was the first in Alaska since the 1989 Exxon Valdez oil spill. Weener, who ran the hearing, noted at its outset that the hearing was “strictly a fact-finding mission.” “The board does not find fault or blame,” he said. Federal Aviation Administration officials and Hageland leaders testifying under oath before the board stressed throughout the intense, nine-hour day of inquiry that two age-old Alaska themes are often at the root of CFIT crashes in the state: much of rural Alaska still lacks needed infrastructure to give pilots the information they need — in this case for weather reporting and communications —and the daring, “bush pilot culture” is still pervasive amongst the state’s aviators. According to FAA data, the number of CFIT accidents in Alaska has gone from eight in 2002 and nine in 2003, to an average of four per year by 2016. The number of CFIT accidents — fatal and nonfatal — involving commuter and flight service operators known as Part 135 has gone from five in 2002 to four in 2004 and has been one or two per year since 2006. The overall average would be lower if not for a recent spike in incidents that prompted Alaska FAA Flight Standards Manager Clint Wease to issue a letter in May 2016 to Part 135 operations. According to Wease at the time, CFIT accidents involving Part 135 aircraft in the year before the letter had led to 24 fatalities or serious injuries. “Many of these CFIT accidents have occurred in aircraft with advanced avionics, which were capable of instrument flight and operated by experienced pilots,” Wease wrote. His first of several recommendations in the letter was for pilots to operate under instrument flight rules, or IFR, whenever possible. Hageland Operations Manager Luke Hickerson said in his testimony to the NTSB that about two-thirds of the airports the airline serves don’t have all of the equipment necessary to conduct IFR flights. According to Hickerson, Hageland has about 7,600 possible “city pairs” in its flight network and its pilots perform roughly 150,000 takeoffs and landings per year on about 55,000 flights. Erin Witt, Hageland’s chief pilot, estimated that up to 15 percent of the airports the company flies to have no communication capabilities at all. Hageland serves the numerous villages in the Yukon-Kuskokwim region of the state on behalf of its larger sister airline Ravn Alaska. The communications challenges are often compounded by the fact that the area regularly has low cloud ceilings that are sometimes at less than 1,000 feet, Hageland pilots testified. Flying an IFR route allows a pilot to fly through and above cloud cover, almost eliminating the risk of CFIT accidents. “I would love to operate a fleet of IFR aircraft” and fly by instruments all of the time, Witt said. The alternative is flying below the ceiling under visual flight rules, or flying VFR. Lacking weather reporting from official equipment such as National Oceanic and Atmospheric Administration automated weather observing systems, or AWOS, common at larger airports, Hageland pilots regularly use FAA weather cameras and call trusted sources in the villages such as state Department of Transportation workers at the airports for current conditions before take-off and, when possible, during a flight, Hickerson said. The FAA maintains a network of more than 230 weather cameras in Alaska at airports and high-risk points. While they are viewed by small commercial operators across the state, the cameras are geared towards general aviation and information they provide cannot be used as a formal weather report by a commercial pilot. When questioned by NTSB investigators why a pilot would rely on unofficial weather information, Hickerson responded by saying the pilots are “going from nothing and making something.” Hageland pilot Natoshia Burdick, who was the safety pilot on a flight about five minutes behind Flight 3153, noted in testimony that a pilot flying in the Yukon-Kuskokwim area is required to get near-immediate clearance from air traffic control in Bethel when requesting to fly IFR and the tower is not always reachable. “It’s a whole lot easier with the infrastructure that’s out there to go VFR,” Burdick said. Additionally, pilots on IFR-capable routes may still have to fly below the clouds because many of the village airports do not have de-icing equipment, according to Hickerson. Flying through clouds and at higher altitudes greatly increases the likelihood that ice will form on the aircraft and when a plane that has flown through icing conditions it cannot take back off without being sprayed down with a glycol solution. Hageland has developed its own small, portable de-icing sprayer that can be kept in the small aircraft it flies, but with only about five gallons of fluid its usefulness is limited, company representatives testified. Hickerson said there are reasons CFITs were a serious problem in the Lower 48 up until about 40 years ago. “I think the technology and infrastructure advancements that have been made in the continental U.S. need to be made here,” he told the NTSB. Deputy NTSB Director of Aviation Safety John DeLisi said the agency has recommended mandating CFIT avoidance training for all Part 135 pilots — it isn’t currently — while also seeming to commiserate somewhat with the Hageland witnesses. “It would be great to have that infrastructure and we’re going to do our job to make that point,” DeLisi said in response to Hickerson. FAA Alaska Region Administrator Kerry Long, who has held the position for about three years, said in an interview that he believes he and his staff have made progress of late in getting key agency personnel from the Lower 48 to visit Alaska and recognize the challenges the aviation industry faces in the state. Long said a pending report commissioned by the FAA from the RTCA — an aviation technology nonprofit —should highlight Alaska issues for decision-makers in Washington, D.C. He called the lack of weather and navigational infrastructure in parts of Alaska “a pressing issue.” “We believe that we have developed approaches that have made people more interested in coming up here as well as providing the information in forms that people understand better and this particular RTCA report will fit in with the recommendations that get made to the agency as a whole,” Long said. He noted the FAA’s funding has been flat for several years as a result of Congress repeatedly passing continuing budget resolutions, which challenges the agencies ability to install new equipment. “We can ask for it; we can push for it; we can do everything we can but if we can’t deliver we have to try harder,” he added. Alaska Air Carriers Association Executive Director Jane Dale wrote in an email that despite the facts that 82 percent of Alaska communities are only accessible by air and the FAA encourages Alaska carriers to fly IFR, the state lags in AWOS stations and working ground-based navigational equipment. “Infrastructure supporting IFR and VFR flights in Alaska is and has been the association’s number one priority for years,” Dale wrote. “This includes improving the availability of weather information in rural Alaska, proactive investment in aviation infrastructure and maintaining the existing infrastructure.” Flight 3153 crash Despite the apparent consensus among industry and government regulators at the hearing that Alaska’s aviation infrastructure is insufficient; it does not explain the Togiak accident. The Quinhagak-Togiak route is IFR capable. Burdick, a pilot on the trailing Hageland flight that detoured around the mountain before being notified of the crash, said agents at the company’s Operations Control Center led by Hickerson recommended flying IFR that day, but the Flight 3153 pilot chose not to. Little explains the crash of the flight that had a pilot-in-command to fly the Cessna and a safety pilot tasked with — as the title implies — being a redundant safety check. Hageland’s right-seat safety pilots are trained to clearly and directly voice any concerns they have with weather conditions or decisions made by the pilot-in-command, the company’s NTSB witnesses testified. Burdick said when news of the crash made its way to their plane, she and her pilot-in-command attempted to locate the crash site but the 2,500-foot mountain was obscured by clouds below the broader ceiling. The NTSB may yet find a definitive reason for the Hageland tragedy, but Hickerson and FAA officials said audacious attitudes are still far too prevalent among Alaska pilots, creating a wholly unnecessary danger, particularly among commercial pilots. Hageland’s operational control agents at the center in Palmer discuss the circumstances surrounding each flight with the pilot before approving, or releasing it, Hickerson said. An operations manager is involved if any disagreement arises between the pilot and the agent. He emphasized that the operations center is completely removed from the business side of the company. “There is not pressure on the OCC to ever release a flight,” he said. The OCC has cancelled more than 3,500 flights since the start of 2016 and turned another 600-plus around due to deteriorating weather, according to Hageland leaders. Culture shift Hickerson stressed that “safe, legal, and best practice” is what drives Hageland Aviation. “It’s a lot easier to write rules and regulations than it is to change hearts and minds and that’s what we’re trying to do right now,” Hickerson said. He continued: “The idea of turning around 10 years ago was unheard of and shamed not only by other pilots buy by companies as well.” Wease generally agreed in his testimony, saying a series of Hageland incidents in the 2012-13 timeframe pushed the FAA to uncover what he described as a “poor pilot culture,” that he believes has since been corrected. The company CEO starts each ground school with a talk to prospective pilots highlighting Hageland’s safety culture, Hickerson said, to illustrate it is truly companywide. He said the company looks for reckless behavior “in every aspect of pilots’ lives,” because risks don’t announce themselves. “You’ve got to listen for the whispers in the system,” Hickerson said. Dale, of the Alaska Air Carriers Association, said the industry group does not agree with the belief that there is still an unsafe pilot culture in the state. Alaska operators “work hard to ensure a culture of safety,” according to Dale. She again cited a lack of needed equipment in some areas of the state, noting some of the current AWOS and navigational infrastructure is often out of service. Witt said pilots applying to fly for Hageland are screened with questions related to their decision-making and risk tolerances and about 10 percent of applicants are denied solely on those answers. To that, FAA Alaska Certificate Office Manager Deke Abbott, who spent most of his career in aviation Outside, said he was taken aback by the adventurous nature of many Alaska pilots. “We push the airplanes to get where we’re going,” Abbott said to the board, adding that when a pilot makes a decision, the consequences of that decision are ultimately solely the pilot’s responsibility. “We’re trying to change a 100-year culture,” he concluded. Elwood Brehmer can be reached at [email protected]

Permanent Fund Corp. earns 12.6% in FY17

While the State of Alaska is still mired in a damaging cycle of multibillion-dollar budget deficits, it’s hard to imagine a scenario in which its biggest financial asset could be doing better. The Alaska Permanent Fund Corp. achieved a 12.57 percent return on its namesake Fund during the 2017 fiscal year that ended June 30. The Permanent Fund ended the year with a record value of $59.8 billion. The corpus, or principal, of the Permanent Fund is constitutionally prohibited from being spent; however, the Fund’s Earnings Reserve Account is available for appropriation and it ended fiscal 2017 with more than $12.8 billion of Fund income. Of that, more than $10.8 billion was available realized earnings. More than $3.2 billion in statutory net income was added to the Earnings Reserve in 2017. Historically, the Fund’s investment income has been only been distributed as dividends to Alaska residents based on a statutory formula. In the weeks since the end of the state fiscal year, the Fund has continued to grow to more than $60.6 billion as of Aug. 21, according to the corporation’s unaudited results. Permanent Fund Board of Trustees Chair Bill Moran said in an APFC release that the “high mark is a testament to the Alaskans who had the foresight to create the Fund, the leaders of yesterday and today who have maintained the integrity of the Fund and the dedicated professionals of the Alaska Permanent Fund Corp. who have attentively invested the Fund.” CEO Angela Rodell said the Permanent Fund has gained international recognition “as a model for converting a non-renewable (oil) resource into a renewable financial resource.” The strong 2017 results counter fiscal 2016 when volatile public financial markets kept Fund growth at a modest 1.35 percent. Gov. Bill Walker’s administration and many legislators have pegged a long-term return average of 6.9 percent as a foundational assumption for starting to spin off about 5 percent of the Fund’s annual value to support government services and continue to pay out annual dividends in the $1,000 to $1,200 range. Doing so could sustainably provide up to about $1.8 billion per year to reduce the state’s deficits, they contend. The below-average 2016 put the Fund’s three-year return average below the 6.9 percent target at 6.18 percent, but the corporation’s active management still greatly out produced passive benchmark investments of 60 percent stocks, 30 percent bonds and 10 percent real estate and inflation-protected securities that would have returned 3.37 percent over that time. Over the previous five years the corporation’s management has produced an 8.94 percent return, compared to a projected passive return of 7.10 percent. The 2017 performance was led by a roughly 20 percent return on the $26.1 billion of the Fund invested in public equities, or stocks. For rough comparison, the Dow Jones Industrial Average closed Aug. 22 up 18.19 percent over the previous 12 months. Another nearly $7 billion invested in private equities returned 20.98 percent and the Fund’s $5.5 billion of real estate investments earned 4.45 percent, according to the corporation’s June performance report. Infrastructure and private credit investments averaged roughly 9 percent paybacks, while $11.7 billion in fixed income assets naturally yielded more modest returns. Elwood Brehmer can be reached at [email protected]

Draft EIS released for Liberty offshore project

A long-anticipated North Slope oil project took a big step forward Aug. 18 when the federal Bureau of Ocean Energy Management released the draft environmental impact statement for Hilcorp Energy’s proposed offshore Liberty development. Houston-based Hilcorp and its partners in Liberty — BP and Arctic Slope Regional Corp. subsidiary ASRC Exploration LLC — are planning to construct a 24-acre gravel island in the federally-controlled shallow waters about six miles offshore and just east of Deadhorse in the Beaufort Sea. The island would allow Hilcorp as the project operator to access the up to 330 million barrels of light crude the companies believe are in place. With 16 wells, Hilcorp expects it could recover 41 percent to 48 percent of the oil in place. Peak production could hit up to 70,000 barrels per day a couple years after initial production, according to the company’s Alaska leaders. Liberty would produce for 15 to 20 years based on the current reserve estimates. The oil would be moved to the Trans-Alaska Pipeline System, or TAPS, through a 12-inch diameter pipeline that would tie in to the eastern Slope Badami transport line. About 5.6 miles of the roughly 7-mile Liberty pipeline would be a subsea line, buried and installed during the winter. The subsea portion of the 12-inch pipeline would also be contained within a 16-inch pipe, drawing on a technique used at other North Slope manmade island oil developments. With a 24-acre seafloor footprint, the island, in 19 feet of water, would have a working surface of 9.3 acres, according to the 1,270-page draft EIS. Hilcorp has pointed to the four large existing North Slope oil development islands — Endicott, Spy, Oooguruk and Northstar — as strong evidence that Liberty can be done safely. “Not only have similar proposals of the Liberty project been vetted and approved before, but gravel-based energy facilities have a proven record of safe operations, with some in production for over a decade in the Beaufort Sea,” Hilcorp Alaska Senior Vice President Dave Wilkins said in a joint release. “We are eager to work with the communities across the North Slope and our partners throughout the state to develop a project that will greatly benefit Alaska and bring greater domestic energy security to the country.” ASRC Lands and Natural Resources Vice President Richard Glenn said Liberty is the kind of project the company has determined is important for its region and “through local participation we can ensure that the needs and issues of our communities and shareholders are addressed.” Hilcorp is majority owner and operator of the Northstar and Endicott fields, after purchasing BP’s interests in them in a 2014 deal that also gave it a 50 percent interest in Liberty. BP subsequently sold 10 percent of its stake in Liberty to ASRC Exploration. BP purchased Liberty from Shell in 1996 after Shell discovered the prospect with four exploration wells in the mid-1980s. BP first planned to build an island to develop Liberty but put those plans on hold in 2001 to further study the project, according to the draft EIS. In 2005 the London-based oil major proposed drilling ultra-extended-reach wells from onshore to eliminate the need for an island and minimize the project’s impacts on Alaska Native subsistence whaling hunts in the area. That plan was scrapped in 2012 and Hilcorp subsequently took over the project in 2014. Gov. Bill Walker submitted a letter to BOEM in October 2015 supporting Hilcorp’s plan during the public comment period to determine the scope of the EIS. Walker wrote that the oil produced from Liberty would help extend the life and increase the operational efficiency of TAPS. Liberty would indeed be a boost to TAPS, but it would not do much for the state treasury because it is in federal waters. BOEM estimates the project would generate nearly $1.5 billion in federal lease and royalty payments — in 2015 dollars — over its operating life. The State of Alaska’s share of that revenue would be about $400 million, with another $15 million generated in state corporate income taxes and $3 million in state property taxes from the onshore facilities. The North Slope Borough would receive about $35 million in estimated property taxes from Liberty. BOEM’s alternatives to Hilcorp’s proposal include moving the island 1 to 1.5 miles to avoid the densest area of the “Boulder Patch,” an area of the seabed with small boulder substrate that “supports the richest and most diverse biological communities in the Beaufort Sea,” the draft EIS states. Moving the island 1.5 miles into state waters would lengthen the wellbores necessary to reach the oil reservoir by 3,300 feet to a length of 17,200 feet, according to BOEM. Another option the agency is considering would move the oil processing facilities to the manmade Endicott Island that Hilcorp operates about eight miles to the northeast of Liberty. Moving Liberty oil processing to Endicott was suggested after EIS scoping period comments asserted doing so would minimize impacts to marine life and subsistence harvests around Liberty by reducing noise and vibrations from the island, according to BOEM. Kuukpik Corp., the Alaska Native village corporation for the North Slope village of Nuiqsut wrote in a 34-page March 2016 letter submitted to BOEM as public comments that the EIS should closely examine the impacts of abandoning the pipeline and leaving the island in place once production from Liberty has ceased. While Kuukpik President Isaac Nukapigak wrote the company neither supports nor objects to Liberty, it would eventually like to see the island area restored. “Leaving the island to slowly drift apart would almost certainly cause navigation hazards in this critical travel corridor in the short-term at least,” Nukapigak wrote. Doing so would expose the Boulder Patch to artificial debris, he contended. “The only apparent justification for failing to remove this island is to cut costs. If there’s not more to it than cost savings (Hilcorp) should be required to remove the gravel that it wants to dump in this marine environment,” he continued. He concluded his letter by noting that Kuukpik is concerned about the impacts the building a gravel island in what is an important whaling area for North Slope Alaska Natives would have, urging BOEM “to proceed slowly and methodically” to ensure the agency’s review of Hilcorp’s proposal is as complete as possible. Kuukpik shareholders are also shareholders in ASRC, which holds the 10 percent interest in Liberty through its exploration subsidiary. The possibility of drilling into the Liberty oil reservoir from onshore was not advanced and given only cursory consideration because it would require drilling wells that would be nearly a mile longer than the current world record wellbore of 40,602 feet, the draft EIS states.

State unemployment rate hits five-year high

Alaska seasonally adjusted unemployment rate hit 7 percent in July according to the state Labor Department. It’s the highest the unemployment rate the state has seen in nearly five years since it was at 7.1 percent in October 2012. The rate was up 0.2 percentage points from June, up 0.5 for the year and up 0.3 from July of last year. By comparison, the national adjusted unemployment rate was 4.3 percent in July. The not-seasonally adjusted unemployment rate was 6.6 percent in July, down 0.4 percent from June, which is common. Economists try to account for seasonal employment demand swings with the adjusted rate to better show month-to-month employment trends. Alaska’s busy fishing and tourism industries make lower unadjusted rates a common occurrence during the summer months. The upward trend in unemployment was spurred by the estimated loss of 7,500 jobs over the past year — a 2.1 percent decline in jobs statewide since July 2016, according to the Labor Department. “Preliminary estimates show job losses spread across most industries, although the deepest losses remain concentrated in industries closely tied to oil and gas,” an Aug. 18 Labor release states. Alaska lost about 1,500 direct oil and gas jobs over the past year, another 1,200 construction jobs and about 1,000 jobs each in the professional and business services and state government sectors. Job growth in the state since July 2016 has been limited to health care, local government and federal government positions. Those sectors have each grown by about 1.4 percent over the past year, according to Labor figures. Overall, Alaska is down about 8,900 jobs, or 2.6 percent, this year from its 2015 statewide employment peak. The 330,000-job average through July is comparable to full-year employment in 2011. Alaska economists have generally said they expect the current two-year recession to relax in 2018 before the state eventually resumes small job growth in following years. Statewide direct oil and gas employment peaked in 2015, averaging just less than 14,200 jobs for the year before significant layoffs began. Alaska has averaged 10,600 oil and gas jobs so far in 2017, a 25 percent decline from the 2015 employment. The oil price decline of 2014-15 has hit Alaska contractors especially hard as North Slope oil companies have pulled back spending on large projects. Doubling down on that has been the virtual elimination of state-funded capital projects in the annual state budget as government oil revenues have dwindled as well. Alaska spent more than $1.8 billion in discretionary general funds in the 2013 fiscal year capital budget. That was down to $120 million in the 2018 capital budget passed last month — nearly all of which was for the state’s 10 percent match to federal funds for highway and airport projects. Construction employment has fallen from a near-term peak of averaging 17,800 jobs in 2014 to average about 15,100 jobs through the first seven months of 2017, according to preliminary Labor numbers. Alaska construction employment was at its greatest over the last 15 years in 2005 with 19,100 jobs. State government employment peaked in 2014 at an average of 26,500 jobs, including University of Alaska positions. This year, the State of Alaska has so far averaged 23,900 workers, which is about a 10 percent decline from 2014. Elwood Brehmer can be reached at [email protected]

RCA asks state telecoms for broadband coverage plans

State utility regulators are doing their best to live up to a legislative directive to examine broadband coverage in Alaska and providers’ future plans despite not having any authority to do so. The Regulatory Commission of Alaska issued an Aug. 9 request for companies providing broadband service in the state to answer any or all of two dozen questions the commission has about the current status of broadband infrastructure and what the state could do to help expand coverage, among other things. The seven-page request also asks for a contact list of broadband internet service providers in Alaska and inquires about communities where broadband is available and at what download speeds from those internet providers. While the RCA has regulatory jurisdiction over a broad range of public service-providing entities including gas, electric, telecom and wastewater utilities and pipelines, it does not in any way regulate the broadband industry in Alaska. The 2018 fiscal year state operating budget passed in late June under the threat of a government shutdown contains intent language ordering the RCA to draft an analysis of the state’s broadband situation for the House and Senate Finance committees and the Legislative Finance Division by Dec. 1 of this year. To that end, RCA spokeswoman Grace Salazar wrote in an email that the commission will do everything it can to comply with the Legislature’s intent but learning about the status of broadband in Alaska “is going to require a high level of cooperation from the telecommunications industry.” Rep. David Guttenberg, D-Fairbanks, a House Finance Committee member who pushed to have the broadband paragraph added to the budget, said in a House Majority coalition release that he’s convinced the RCA’s report will illustrate that Alaska needs more competition in the broadband sector to lower costs and improve service. “I am confident the effort by the RCA to document the coverage gaps in Alaska will provide lawmakers, regulators and providers with the needed information to make the right decisions to ensure Alaskans can use broadband as a tool to help start a small business, connect with people from across the globe, and enjoy all that is available online,” Guttenberg said. While the RCA is asking for some information as basic as maps detailing where coverage is offered and infrastructure is located, Alaska Telephone Association Executive Director Christine O’Connor said the commission is also requesting granular data and some information that could be competitively sensitive. Her members, primarily rural Alaska telephone and internet providers but also the state’s largest such as GCI and Alaska Communications, are trying to figure out what information they have, how quickly it can be provided and at what cost, according to O’Connor. “Broadband service is the priority for all ATA member companies and we support all efforts to provide broadband for Alaskans. It is important to us to help policymakers advance that goal wherever possible, while also balancing judicious use of limited resources which should be directed to broadband infrastructure and service whenever possible,” she wrote in an email. The RCA is asking for responses by Sept. 8. Some of GCI’s competitors and smaller, local rural internet providers have filed objections with the Federal Communications Commission to the pending purchase of GCI by the Colorado-based telecom investment firm Liberty Interactive Corp. for $1.2 billion. They contend GCI — the dominant Alaska telecom — has used federal subsidies to build a monopoly and control broadband access and pricing across the state. GCI counters that building out broadband infrastructure in rural Alaska is exceedingly expensive and it has been the only company willing to match the available federal funds with its own significant investments to do so. The company has stated it used $250 million of its capital to build the $300 million TERRA broadband network. Alaska Communications plans to respond to the RCA’s request, according to a spokeswoman for the company. GCI spokeswoman Heather Handyside said the company is reviewing the request and determining how to respond. Elwood Brehmer can be reached at [email protected]

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