Alaska Journal of Commerce

Tesoro acquires Flint Hills marketing operation

Tesoro will acquire Flint Hills Resources’ fuels marketing and logistics facilities in Alaska, the company announced Nov. 23. The Interior Alaska refinery closed by Flint Hills in April 2014 is not included in the transaction. Tesoro operates a refinery at Nikiski, on the Kenai Peninsula in southern Alaska. “This investment represents our commitment to efficiently and reliably serve customers in the state of Alaska, said Tesoro CEO Greg Goff in a statement. “We have been part of the Alaska community since 1969 and over the last five years we have invested $300 million in our Alaska facilities. We look forward to continuing our operations in the state.” Under the deal Tesoro will acquire Flint Hllls’ wholesale fuel marketing contracts in Alaska, a terminal in Anchorage with 580,000 barrels of storage capacity, truck racks and rail-loading facilities. A 22,500-barrel capacity jet fuel storage facility at the Fairbanks International Airport in the state’s Interior is also included as well as access to rail offloading facilities in Fairbanks that will provide Tesoro better access to the Interior market, according to the company’s statement. The transaction is expected to close in 60 days, Tesoro said. No purchase price was given. Tesoro has been supplying diesel and jet fuel to Flint Hills for that company’s Interior Alaska customers since Flint Hills shut down operations at its refinery at North Pole, east of Fairbanks. “What’s important to us is to be as close to our customers are possible, and this transaction allows us to connect our refinery more efficiently to people we serve in Fairbanks,” through Flint Hills, said Nate Weeks, Tesoro’s vice president for strategy and business development. Tesoro has been investing corporate-wide in infrastructure and logistics in recent years and the new acquisition in Alaska fits that strategy, said Weeks. An important aspect of the purchase is that the former Flint Hills bulk fuel facilities and logistics chain will be open to third parties to use under contract, which is not currently possible with Flint Hills, Weeks said. As an example, a large volume customer could contract to store its fuel in the Anchorage or Fairbanks fuel terminals. Now only Flint Hills-owned products are stored. Tesoro does this at many of its other Lower 48 terminals and even at storage facilities near its Nikiski refinery. “Obviously this is on a space-available basis, but we want to make it available because there is limited fuel storage capacity in the market and we don’t want to appear to be choking off competition by buying more storage capacity,” he said. Flint Hills’ refinery was closed mainly for economic reasons and Flint Hills would like to sell the refinery, the company has said, but buyers are reluctant because of potential liability for soil and groundwater contamination at the site. Flint Hills is currently engaged in a protracted negotiation with Williams Co., a previous owner of the refinery, over cleanup costs. Tesoro’s Nikiski refinery has a capacity to process up to 72,000 barrels per day of crude oil and makes a full range of products including gasoline, jet fuel and ultra-low sulfur diesel. The Nikiski refinery is connected to Anchorage with a 69-mile, 48,000 barrels-per-day pipeline, which gives the company the ability to ship jet fuel to air carrier customers at Ted Stevens Anchorage International Airport by pipeline. The Flint Hills refinery in Fairbanks, in contrast, could make jet fuel and gasoline but not ultra-low sulfur diesel, which put the plant at a competitive disadvantage. Flint Hills also had to ship its jet fuel to Anchorage, to customers at the airport, by rail, which is less efficient than Tesoro can do with its pipeline. At one time Tesoro considered closing its Nikiski refinery because of high costs and supplying Alaska customers from Washington State but the plan was shelved. The Nikiski refinery is now benefitting from a surge of new oil production in Cook Inlet, which allows Tesoro to reduce imports of crude from other regions. The refinery was originally designed to process Cook Inlet crude. Tim Bradner can be reached at [email protected]

Anchorage port contractor claims no liability in failed project

A key subcontractor in Anchorage’s failed port expansion project wants out of a lawsuit first filed by the Municipality of Anchorage because it claims the city has no jurisdiction to recover lost money. Attorneys for Quality Asphalt and Paving, the contractor that led construction work at the Port of Anchorage in the late 2000s, argued in U.S. District Court of Alaska Nov. 20 that QAP already settled claims related to the project with Integrated Concepts and Research Corp., or ICRC. ICRC managed the project to update and expand dock and shore side facilities at Anchorage’s aging port on behalf of the U.S. Maritime Administration, or MARAD, a federal Department of Transportation agency commissioned by the municipality to oversee the project. The Port of Anchorage Intermodal Expansion Project began in 2003 as a $210 million endeavor, but problems installing the patented open cell sheet pile system chosen to build the docks exploded project costs over time.  Construction work at the port ceased in 2010. Ultimately MARAD spent $302 million of the money Anchorage, the State of Alaska and the federal government contributed to the project.  The city has about $130 million remaining from $439 million appropriated for the work and has begun a scaled back plan known as the Anchorage Port Modernization Project. QAP attorney Michael Geraghty said during the Nov. 20 hearing that a 2012 settlement in which MARAD paid ICRC $11.3 million for QAP’s and MKB’s work released the contractors’ claims and effectively ended their ties to the project. The municipality has said it was not party to the settlement and was even unaware of it at the time it was reached. Attorneys for the municipality have said Anchorage is looking to recoup more than $300 million in two outstanding lawsuits, one initially filed in 2013 against ICRC, project designer PND Engineers Inc. and CH2M, which purchased project consultant VECO Alaska, and another suit filed last year against MARAD in Federal Claims Court. By partnering with MARAD to execute the project on behalf of Anchorage, the municipality subjected itself to federal contracting guidelines that place responsibility for delivery with MARAD, Geraghty argued.  “You’re letting someone else decide if that work is acceptable for your benefit,” in the federal contracting process, he said. Geraghty also noted it should not be lost that the municipality has not submitted claims against QAP; rather, PND filed a third-party suit against the subcontractors. PND has long claimed the problems with the disastrous project come down to shoddy installation of its proprietary sheet pile design, not its suitability for the site. QAP and MKB are still waiting for PND to clarify its case against the contractors. The subcontractors contend the problems were issues of engineering and constructability and those responsibilities fall on the owner of the project, the municipality. QAP filed a motion for summary judgment in the case in August — the motion argued Nov. 20. Geraghty furthered his point by noting what he considers a simple conflict in the municipality’s stance; Anchorage is attempting to recover the same damages through its separate lawsuits against MARAD and the private project participants. Municipal counsel Donald Featherstun said that there are many material facts in dispute yet in this case; summary judgment can only be rendered when the facts are not in dispute and the only questions are interpretations of the laws at issue.  “The arena of government contracts is enormously complicated,” Featherstun said. He also contended that if QAP is allowed to walk away as a subcontractor without potential liability, the viability municipality’s case against the rest of the defendants goes too. Featherstun emphasized the point that the municipality was kept in the dark regarding 2012 settlement between MARAD and ICRC. “In effect, they were all hiding from (the municipality),” he said. Geraghty rebutted by asking why the municipality would sue MARAD and at the same time claim that MARAD released itself from claims through the settlement. Claiming a need to sort out federal contracting complexities as a reason for QAP to continue in the case is “a deliberate attempt to sandbag the court,” Geraghty said. A trial in the suit first against ICRC, PND and CH2M was once set for October of this year, but is now scheduled for September 2016. Elwood Brehmer can be reached at [email protected]

Independent power producers cheer RCA rules revisions

Alaska’s independent power producers are claiming victory over regulatory changes that they say will encourage investment in renewable energy projects. The Regulatory Commission of Alaska on Nov. 20 finalized revisions to state regulations pertaining to how electric utilities calculate their cost of power and mandating them to purchase power from economically viable third-party sources. Alaska Independent Power Producers Association Director Duff Mitchell said the changes simply bring Alaska’s scheme in line with Federal Energy Regulatory Commission, or FERC, regulations followed in the Lower 48. “What this does is it allows independent power producers and qualifying facilities to sit at the table. The elements of a fair playing field is what this creates,” Mitchell said. The state framework governing power purchases had not been updated since 1982. Sponsors of several renewable energy projects across Alaska felt those regulations allowed utilities to discriminately purchase power from their own generation sources regardless of potential cost savings — a power grab to retain control of the state’s electric market, the independent producers claim. The revisions require utilities to use an incremental avoided cost methodology to determine their cost of power, which mirrors FERC requirements, versus the historical option to choose an average avoided cost model. The Nov. 20 final order was the culmination of a public rulemaking process that took more than two years to complete. FERC regulates Lower 48 utilities because the electric grid crosses borders and connects states. Alaska Railbelt electric network and many smaller grids are cut off from the rest of the country, which removes FERC’s jurisdiction on the matters in the state. Given an option, electric utilities will almost always draw power from several generation sources at once as a result of need or preference, usually both. Multiple sources of power are often a necessity for larger utilities that can’t get ample supply from a sole generation plant. Multiple sources also provide redundancy in the system, which helps a utility keep the lights on if one source should drop offline for any reason. In an incremental avoided cost model, a utility calculates the cost of each power source individually and tries to limit the amount of power purchased from its most expensive source. If a less expensive source becomes available, the most expensive power is turned off, or at least throttled back. An average avoided cost model allows utilities to average the cost of all its power generation and purchase power from another source only if it is less expensive than the averaged cost. Mike Craft, owner of Alaska Environmental Power, a small wind farm near Delta Junction, has long said he would build more turbines to his two-windmill operation if Alaska utilities would relax their hold on the market. “Alaska’s outdated regulations were a big factor holding up the expansion of our wind generation facility in Delta Junction,” Craft said in a release. “This ruling will help us move forward and benefit the community by displacing even more expensive diesel fuel, reducing air pollution, and improving energy security in Interior Alaska.” Cook Inlet Region Inc. wind power manager Suzanne Gibson said the decision should help larger projects, such as CIRI’s Fire Island Wind farm, which has had difficulty obtaining a power purchase agreement with utilities needed to continue with planned expansions. The state’s few larger electric utilities — some of the only ones with power generation options — have said they are always looking for less expensive power, but the average avoided cost model allows them to better calculate the true costs of variable renewable sources, particularly wind power in Alaska. Managing other power generation to match the clean and cheap but fickle nature of wind power adds hidden costs that also vary, so averaging those costs assures a utility it is buying a balance of cheap and stable power, utility leaders have said. Alaska Power Association Executive Director Crystal Enkvist said some of her members disagree with aspects of the regulations and didn’t think the power-cost revisions were necessary, but added that regulatory clarity is always beneficial. “We can understand the commission’s desire to directly align the RCA regulations with the language of the FERC regulations,” Enkvist said. The Alaska Power Association represents 21 electric utilities across the state that are active members in the organization. Its members include four of the large Railbelt utilities. The new regime further mirrors FERC standards by eliminating a distinction between firm and non-firm power — the difference in controlled generation such as natural gas- and oil-fired power plants or large hydropower and variable, often renewable power sources. Mitchell said bluntly that implementing variable power sources into generation is the responsibility of the utilities that must simply follow the law. “Utilities don’t get special treatment down south so why are ours?” he said. The biggest positive for Alaska could come from not what the regulations require, but what they encourage, according to Mitchell. Aligning Alaska’s electric purchase requirements with the rest of the country removes regulatory uncertainty for investors interested in the potential for expanded renewable power in the state, he said. By mandating utilities to purchase power on an incremental cost basis, investors will be assured that power from financially feasible projects will be purchased, he added. CIRI’s Gibson agreed in a formal statement. “The RCA’s decision helps remove impediments for renewable energy development projects, and it will make it more feasible for Native corporations and other independent power producers to invest millions of dollars of private capital to help stabilize rates and develop a clean and reliable energy system for Alaska,” she said. Mitchell said further revisions are needed to relax regulations on small windmills and other power generation for private use, but the Nov. 20 order was a major step forward. “We don’t like federal overreach. This eliminates some of our state overreach,” he said. Elwood Brehmer can be reached at [email protected]

Alaska USA leads a strong third quarter for CUs

Alaska’s six biggest credit unions had another beefy quarter, on average, though delinquent loans and foreclosures cut into the bottom line for an unlucky few. Overall, the six largest credit unions increased their collective net income 39 percent compared to last year to $52.7 million, up from $38 million. Total assets grew 10 percent year-over-year, topping $8.5 billion. Each financial institution grew its loan portfolio, for a total $6.4 billion. Alaska USA, the state’s largest credit union, gained the bulk of the overall third quarter net income, up to $39.5 million in 2015, a $13.6 million gain. The company grew its total loans $650 million. This follows a strong second quarter, where net income shot up 54 percent year over year. Denali Alaskan led the pack in growth rate, despite holding $900,000 more in delinquent loans than in the same quarter 2014. The credit union vaulted its net income over 200 percent year-over-year to $4.9 million. Matanuska Valley credit union made an 82 percent gain as well, breaking the $3 million mark for the quarter, driven by a $40 million total loan increase and 21 percent reduction in delinquent loans. Not all were as fortunate. Credit Union 1 saw a 39 percent net income decline for the quarter, driven by a $1.5 million spike in delinquent loans over last year. Spirit of Alaska’s income dropped 23 percent, saddled with $900,000 in foreclosed property it didn’t have in 2014. This is the second quarter in a row foreclosed properties have bitten chunks from the credit union. Second quarter net income decreased 33 percent to $349,000, having lost $2.1 million in loans and gained $1.2 million in foreclosed property. Juneau’s True North Credit Union has had a rough year as well. Third quarterly net income plummeted over 350 percent year over year to $155,160, down from more than $700,000, with $140,000 more in foreclosures than last year. This marks the second quarter of declining income; net income shrank from $351,000 in second quarter 2014 to just more than $12,000 in 2015. DJ Summers can be reached at [email protected]

ConocoPhillips only successful bidder at federal lease sale

In contrast to a state areawide lease sale held the same day, bidding was very light at a federal U.S. Bureau of Land Management sale in the National Petroleum Reserve-Alaska Nov. 18. NPR-A is the large federal reserve west of state lands on the North Slope,. Only six bids were submitted for six tracts, all by ConocoPhillips. The acreage bid on was adjacent to leases already held by ConocoPhillips and Anadarko Petroleum, a minority partner. In total, BLM netted $788,680 in total high bids in the sale, half of which will be shared with the state of Alaska under terms of a 1975 federal law. ConocoPhillips’ high bid per acre was $31.91, and the highest bid for a lease was $199,760, BLM officials said. The federal sale was area-wide, like the state sale, meaning that all unleased tracts in the area open for bidding were offered. Most of the area open to bids in the sale was of moderate potential for oil and gas discoveries. Lands with higher potential to the north of the lands offered, and nearer the coast, were off-limits to bidding because of the environmental sensitivities of the area, which is a waterfowl breeding area during summer. ConocoPhillips also announced Nov. 18 it would proceed with development of its Greater Moose’s Tooth, or GMT-1 project, in the area near the new leases acquired. The company is also working on a prospective GMT-2 a few miles further into NPR-A from GMT-1. The 23-million-acre NPR-A was created in 1923 by President Warren Harding as a petroleum reserve for the U.S. Navy, although it had no known oil deposits at the time. Designated as Naval Petroleum Reserve No. 4, the region has had several phases of exploration beginning with a Navy-led effort in years following World War II that was followed by a program managed by the U.S. Geological Service. In 1975 the reserve was transferred from the Navy to the U.S. Interior Department and re-designated the National Petroleum Reserve-Alaska. In the 1980s, parts of NPR-A were opened to leasing by private companies and several exploration wells were drilled over the following years. Modest oil and gas discoveries were made in the government-led exploration including a small oil field at Umiat, in the reserve’s southeast, and a gas field at Barrow, which now supplies gas to the community. Federal government geologists now believe the NPR-A has only modest potential for oil discoveries but more substantial prospects for natural gas. Tim Bradner can be reached at [email protected]  

Bristol Bay permit stacking, plan revisions on board agenda

The Alaska Board of Fisheries will hold its last meeting of 2015 from Dec. 2-8 in Anchorage to discuss changes to the management of Bristol Bay finfish, largely sockeye salmon, the region’s largest moneymaker. The board has 70 proposals to consider, the bulk of which concern permit stacking for commercial fishermen and amending district management plans, boundaries, and permit requirements. Bristol Bay is the largest natural sockeye run in the world. The resulting fishery, the most valuable in the state, is the region’s largest source of employment. The board meets once every three years for each region under its control. Permit stacking Nine of the proposals, submitted by members of the public or by the board’s regional advisory councils, request that Bristol Bay fishermen be allowed to hold several commercial permits at once. Currently, setnetters are allowed to hold two permits but only allowed to fish one. Driftnetters are held to similar restrictions. The unpredictable value of the fishery, they said, has made it uneconomical to only fish one setnet or driftnet permit. In some cases transfer restrictions prevent families from making full use of their existing permits. Such permit stacking was allowed only between 2009-2012, then discontinued by the board. Permit stacking, the board said, raised the price of permits and made them less available to Bristol Bay locals. Setnetters said the board should reinstate the program, and that fears were overblown. “The program worked like it was supposed to,” wrote Kim Rice, setnet permit holder. “There were no problems. We had over 82 percent positive comments at the last board cycle for Bristol Bay. It was a sound program that allowed setnet fishers to not have to transfer between family members all the time.” Bristol Bay locals have felt the region’s unpredictability sharply in 2015. After a massive season in 2014 left vendors stockpiled with extra sockeye salmon, the equally impressive but oddly timed 2015 sockeye run only paid out 50 cents per pound to fishermen. This is half the average price. Bristol Bay fishermen have circulated a petition asking for more transparent interactions with processors to ensure fair treatment. Management plans and boundaries Residents of Port Heiden are asking the board to redefine boundary lines so their members can participate in Bristol Bay fisheries. Other members of the public are asking the board to redraw boundary lines or create new areas to allow more fishing opportunity and decrease competition among permit holders in cramped areas. Also geared towards cutting competitiveness, the Togiak Advisory Committee is suggesting the board prohibit tenders, fish buyers, and fish transport vessels from anchoring within 1,500 feet of set gillnet sites. Tenders, the committee says, often encroach “upon set net sites to impede drifters from drifting legal distances from set net sites.” Other proposals would establish minimum distance requirements for specific districts. An argument is also taking place over registration times. In the Egegik district, locals say the registration dates to fish in their district needs to be pushed back, as incoming fishermen will dart between several districts during the season and make fishing more competitive and more dangerous. Incoming fishermen, however, are proposing several looser registration requirements, arguing they need as much leeway as possible to go from one fish-heavy district to another and maximize their income. Several village councils are requesting that the board create individual salmon management plans for new areas, including the Alagnak River, Kvichak River, and a special harvest area in the Graveyard Creek area. The Alaska Department of Fish and Game is proposing several upkeep items, including updating salmon management plans to reflect in-river run goals and escapement goals for Nushagak coho salmon and Togiak sockeye salmon.

Schedule slipping on pre-FEED work, critical agreements

State officials say they are worried that the schedule for the big Alaska LNG Project could slip because of delays by North Slope producers in reaching key agreements. However, the state itself is contributing to some of the delay, as well as part of the cost increase of the pre-front end engineering and design, or pre-FEED, sources familiar with the project say.  Gov. Bill Walker had hoped to have the agreements earlier this fall in time for legislative approval in a special session of the Legislature held in late October, but that did not happen. The governor did present a proposal that the state buy out the interests of TransCanada Corp. in the project, which lawmakers approved. Several big issues remain, however. “We’re not making progress on the commercial agreements needed and this could be costly to the project timeline,” Alaska Natural Resources Deputy Commissioner Marty Rutherford said in a recent briefing to legislators. The Alaska LNG Project involves an 800-mile, 42-inch pipeline from the North Slope to a large gas liquefaction plant in southern Alaska, along with a large gas treatment plant on the North Slope that would mainly remove carbon dioxide from the produced gas. AGDC is the state corporation that represents Alaska’s 25 percent interest in Alaska LNG Project. The project has been given federal approvals to export up to 20 million tons of LNG yearly. Construction costs are estimated between $45 billion and $65 billion. Frequent changes in the state’s gas negotiating team by Walker have created uncertainty for the industry negotiating partners, the sources said, who asked not to be identified. The governor has made three changes of his lead negotiator since earlier this year. Rutherford, at DNR, was the lead of the gas team until late spring, when Walker requested that Audie Setters, an experienced, retired Chevron LNG official, take over the role. Setters had been working as a consultant for the state. He was replaced in the summer by Rigdon Boykin, a retired California attorney who now lives in South Carolina, and who had worked with the governor in prior years on the Alaska Gasline Port Authority, a group Walker headed. Boykin was sent home to South Carolina by Walker the week of Nov. 9. Boykin’s departure was not announced and no replacement was named but sources told the Journal that key decisions on the negotiations are now being made by three officials: Attorney General Craig Richards, Revenue Commissioner Randy Hoffbeck and Rutherford. Timeline slipping The schedule is slipping in other ways. It looks now that preliminary engineering now underway will not be complete until mid-2016, instead of late 2015 or early 2016 as was hoped earlier. Part of that delay is due to Walker, too. Late in the summer the governor requested the Alaska LNG Project team to reevaluate the use of 48-inch diameter pipe rather than 42-inch pipe. Industry partners had earlier concluded that 42-inch pipe was optimal for shipping the known gas reserves, and that the pipe could be manufactured by several suppliers including steel mills in North America. Walker argued, however, that there will eventually be much more gas found on the North Slope and that building in extra capacity, with bigger pipe, will be more efficient in the long run than handling expansions by building more compressor stations. Industry partners in Alaska LNG agreed, some reluctantly, to the reassessment of the bigger pipe, which is adding $30 million to the pre-FEED cost and delaying its results. The analysis of 48-inch pipe against 42-inch pipe is to be finished by March with the final evaluation to be done by May, according to sources. The decision on the pipe size must be made before the decision to move to front-end engineering and design, or FEED, which is currently estimated to cost the project partners a combined $2 billion, of which the state would be responsible for a quarter, equivalent to its ownership stake. All that means the FEED decision could be delayed to late 2016, Rutherford told legislators in the briefing. However, industry partners in the gas project may also wait to see the outcome of the November 2016 state general election. That’s when voters will decide whether to approve a necessary constitutional amendment to allow the state to enter long-term fiscal agreements with the producers for the gas project. Dan Fauske, CEO of the Alaska Gasline Development Corp., or AGDC, told its board in a briefing Nov. 12 that while the hoped-for schedule is slipping it is still within an overall timeline laid out by the partners, which calls for beginning of FEED no later than July 2017. This could still allow a final investment decision in 2019 and project completion in 2025, which is the current plan. Rutherford said the most critical agreements the governor wants by early December are a gas balancing agreement among North Slope producers BP, ConocoPhillips and ExxonMobil, who are partners with the state in the project, and a separate agreement to cover contingencies over a partner withdrawing from the project, she said. Withdrawal, gas-balancing agreements The partner withdrawal agreement has been requested by Walker, who is concerned that if a partner pulls out of the project it could stymie others in proceeding. Rutherford said the governor is pushing the producers to have the gas balancing and withdrawal agreements by Dec. 4, the date on which the project members are to vote to approve the 2016 budgets for completing the preliminary engineering. “Meeting this goal will be a significant challenge,” Rutherford said. AGDC Operations Vice President Joe Dubler said the balancing agreement is proving to be complex because gas for the project will come from two North Slope fields, Prudhoe Bay and Point Thomson, and there are differing percentages of ownership by the producers. “They’ll get there, but it is taking time,” Dubler said in the Nov. 12 briefing to AGDC’s board. Agreements for withdrawn partners are normal in big projects but Walker wants an added provision that guarantees that the withdrawing party will commit gas to the project, meaning that it would agree to sell to a buyer. That is proving to be very difficult in the negotiations because it essentially involves an agreement to sell gas to an unknown buyer for an unknown price. One option is that the state itself could buy the gas now owned by a withdrawing partner, but that could entail huge financial risks for the state, advisors to the Legislature have warned lawmakers. Dubler told AGDC’s board Nov. 12 that the partners are working hard on an agreement and hope to have it by the governor’s Dec. 4 deadline. Fauske said the Alaska LNG Project partners could vote on the 2016 pre-FEED budget without the withdrawn parties and gas balancing agreements but that the governor prefers to have them done. The state itself will vote on the budget, as a partner. Deadline for amendment looms Meanwhile, Rutherford said a hard deadline the project faces is June 24, 2016. That is the day a proposed constitutional amendment on fiscal terms must be sent to the Division of Elections to appear on the November general election ballot. By that that time Legislature must also have ratified the agreement between the state and North Slope gas producers that will fix state tax and royalty terms for a period of years, presumably the length of long-term contracts to sell Alaska LNG. To be legal, the fiscal agreement will require an amendment to the state constitution. The constitution currently forbids the Legislature approving a guarantee that state taxes won’t change. North Slope gas producers say the fiscal term deal is a “must-have” because of Alaska’s past record of frequently changing state taxes on oil production. However, fiscal terms deal is proving to be another big sticking point in current negotiations, the governor has said in recent briefings. At least one Slope producer is pushing to have it cover taxes on crude oil as well as gas, Walker said. The state is pushing back on that. Assuming the fiscal terms deal agreement is eventually concluded it will have to be ratified by the Legislature next spring, most likely in an April or May special session following the end of state lawmakers’ regular 2016 session. A constitutional amendment requires a two-thirds vote of both the state House and Senate and that must be done by June 20.  “If we don’t meet that the entire project schedule begins to slip,” Rutherford said, because the next general election for ratification of the amendment is November 2018, which would effectively delay the project two years. ASAP update In other developments, managers of AGDC told its board that work is continuing to complete a supplemental environmental impact statement, or SEIS, on the state’s backup pipeline plan, the 36-inch Alaska Stand Alone Project, or ASAP. This is important because while ASAP itself is on hold (it is a backup in case the larger Alaska LNG Project doesn’t go) the work being done for the SEIS and the U.S. Army Corps of Engineers Section 404 wetlands permit is transferable to the larger project. Dave Cruz, an AGDC board member who heads the board’s technical committee, said there are no indications of any delay in the Corps of Engineers issuing the final supplemental EIS, its Record of Decision, as well as the Section 404 permit and other permits by fall 2016, most likely October. A right-of-way across 100 miles of federal lands would also be issued by the U.S. Bureau of Land Management as a part of the other federal documents. “Those permits are transferable to Alaska LNG even though there is a six-inch difference between the 36-inch pipe (of ASAP) and the 42-inch pipe (of Alaska LNG),” Cruz told the board. What’s important is that the physical footprint of the two pipeline projects, including the space needed for construction equipment, are similar, which should be the case for 36-inch or 42-inch pipe, he said. “There’s still some debate on this but it shouldn’t be a problem,” for the regulatory agencies, Cruz said. However, 48-inch pipe may be a different matter, he acknowledged. If 48-inch pipe is decided on and the Federal Energy Regulatory Commission, which is lead agency on the federal EIS for Alaska LNG, decided that the larger pipe represents a “substantial” change, at least some of the work on the 36-inch SEIS won’t be usable. A critical factor, however, is that the routes of the two projects, ASAP and Alaska LNG, have been exactly aligned from Prudhoe Bay to a location in the Matanuska-Susitna Borough where the bigger pipeline would veer off toward a Cook Inlet crossing to the Kenai Peninsula.  ASAP would end in the Mat-Su Borough where it would connect with existing regional pipelines. Meanwhile, AGDC is finishing up other parts of the ASAP project that will be useful to Alaska LNG. This includes a fine-tuning of information gathered to support final engineering on the ASAP project including a c“works package” of equipment needed for construction, AGDC Engineering Vice President Frank Richards told the board that information is available from a Request for Information the state corporation had sent out to vendors for estimates equipment packages. Material sites for construction were also identified. “They have been looking at equipment, parts, camps, pads–those early activities that will need to be done well in advance of construction. There will also be development of material sites and the opening of access roads,” AGDC spokesman Miles Baker said. This information will be useful to the Alaska LNG project, he said. “There may be some differences in equipment due to the differences in pipe size, 36-inch instead of 42-inch, but the civil works side of the project will be roughly the same,” for both ASAP and the larger Alaska LNG Baker said. Moving to 48-inch pipe would require heavier equipment and more updated information, however. “We would have four mainline contractors (on different parts of the 800-mile route) using similar equipment and working simultaneously to build the pipeline, and we need to make sure they are serviced and supplied,” Baker said. Tim Bradner can be reached at [email protected]

Lengthy to-do list remains for Alaska LNG negotiators

There is a long list of commercial issues yet to be resolved in the Alaska LNG Project negotiations but many of these may be combined, so the number of agreements, in the form of contracts, is yet to be determined, sources familiar with the negotiations have told the Journal. At the top of the list are four items important to the state of Alaska, two of which Gov. Bill Walker hopes to see resolved by early December. They are: • Gas balancing agreement: Sometime called a gas supply agreement, which spells out how and when gas will be withdrawn from the two fields supplying Alaska LNG: the Prudhoe Bay and Point Thomson fields. This agreement is between the three Slope producers — ExxonMobil, BP and ConocoPhillips — and is complex because of differing ownership levels at the two fields. ExxonMobil and ConocoPhillips each own about 36 percent of the gas at Prudhoe, and BP another 26 percent. At Point Thomson, ExxonMobil and BP own about 93 percent of the gas and ConocoPhillips less than 5 percent. About 75 percent of the gas for the project is to come from Prudhoe and the remainder from Point Thomson. The gas at Prudhoe, unlike at Point Thomson, is used to enhance oil recovery. • Withdrawn partners agreement: This would spell out terms for a partner withdrawing from the project and clarify how the partner’s gas, as a producer, will still be available for purchase through the project. Other issues pending include: • Fiscal agreement: This would stipulate that state taxes on gas produced for the project would not change over the terms of LNG sales contracts, which could span 20 years to 25 years. Purchasers of the LNG will require this provision, or at least will ask producers to absorb any state tax increase, which the producers will not do. The state constitution currently forbids long-term tax deals, so a constitutional amendment will be needed. Sources have told the Journal that attorneys for the state and the companies are currently debating whether a narrowly-drawn constitutional amendment is possible, such as one that relates to specific contract terms, or whether the amendment will have to be more broadly written. Alaska voters are considered more likely to approve a narrowly-drawn amendment than a broadly-written approval. • Governance agreement: This would provide the long-term framework on how the project would be managed and how costs would be allocated. Decisions have to be made on whether a stand-alone operating entity, such as Alyeska Pipeline Service Co., would be created. This is needed by late 2016, the time that the project would move into final engineering, if that happens. As it has been described the governance agreement would guide the work on final engineering, construction and operations. • Expansion agreement: This is a request by the state, and it involves how a physical expansion of the project, such as if there were more gas to be shipped, would be funded and managed. Sources said this may wind up being rolled into the governance agreement. • PILT, impact payments: It was revealed Sept. 23 that the producers have agreed to pay the state $16.5 billion for property tax obligations and community construction impacts related to the Alaska LNG Project. Revenue Commissioner Randy Hoffbeck made the announcement during a Municipal Advisory Gas Project Review Board meeting in Fairbanks. Of the $16.5 billion sum, $800 million would be for community impact payments during construction. Afterwards, $15.7 billion would be payments in-lieu of tax, or PILT, substituted for property tax payments in project infrastructure and property holdings, according to Hoffbeck. The negotiated $800 million amount is a “fairly firm” number, Hoffbeck said, and would pay for increased public services — police, fire and other first responders — needed in communities along the project corridor that grow from an influx of construction workers. How the massive dollar figures will be allocated amongst the state and the communities affected by the project still needs to be worked out. Whether or not the state’s purchase of TransCanada Corp.’s share of the gas treatment plant and the pipeline — done after the PILT and impact amounts were announced — plays into how much money is distributed is another question Kenai Peninsula Borough Mayor Mike Navarre has raised. The board consists primarily of mayors of local governments along the project route from the North Slope to Nikiski on the Kenai Peninsula. The state commissioners of the Natural Resources, Revenue and Commerce departments also serve on the board. The next Municipal Advisory Gas Project Review Board meeting is scheduled for Dec. 7 in Anchorage. • Contract operator service agreement: This would govern how a company acting as project operator, currently ExxonMobil Corp. in the preliminary engineering now underway, would perform its duties. • Member services agreement: This could be a separate agreement, providing administrative services like independent accounting, to support the contract operator. This could be rolled into the contract operator service agreement. Sources told the Journal that ConocoPhillips has been asked to provide the administrative support function until decisions are made on a possible independent operating company. • Capacity release agreement: This would cover how an owner of capacity in the project, most likely a producer, would release it to other parties if there is spare capacity. The state wants this in place as an assurance to third party access, such as independent explorers. • In-state sales agreement: This is needed to spell out whether and how producers, or the state, will offer gas for in-state sales, such as to utilities. Sources told the Journal that the producers are not keen to supply in-state needs because they would prefer all of their gas go to long-term export customers, and that they would prefer that the state supplies in-state needs with its gas. The state is concerned that if it is the only supplier of in-state gas there will be huge political pressure to sell state gas at a discount. Having producers among the sellers of gas to in-state customers would provide a buffer against these kinds of pressures. • Financing of spur lines and gas conditioning facilities at gas take-off points: The Alaska LNG Project has agreed to at least five of these, but there could be more, as many as 20. The governor is pressing the producer members of Alaska LNG to allow the project to pay for these, including spur pipelines of several miles, such as will be needed to connect the Alaska LNG pipeline to Fairbanks. This is still an issue on the table. The producers thought that Alaska Gas Development Corp., the state gas corporation, was supposed to be responsible for this, which is spelled out in Senate Bill 138, the legislation providing the framework for state participation. So far, AGDC has funded the engineering and design of the “kits,” or facilities, needed at the takeoff points, but there have been no decisions made on where  the points will be except for one near Fairbanks, in the Matanuska-Susitna Borough and on the Kenai Peninsula. Who would fund the takeoff kits and spur lines is also undecided. Tim Bradner can be reached at [email protected] Journal reporter Elwood Brehmer contributed to this article.

Confidentiality regs get pushback from producers, AGDC

Who can see, and say, what has become a contentious issue as the Alaska LNG Project moves toward some key milestones. The state’s partners in the $45 billion-plus North Slope liquefied natural gas pipeline project, the Alaska Support Industry Alliance and Alaska Gasline Development Corp. leaders have all taken positions against draft regulations that would make public the contracts the state enters related to the project. The Alliance is a trade association that represents about 500 businesses that work in the state’s oil and gas and mining industries. The proposed confidentiality regulations, first presented at AGDC’s Aug. 13 board meeting, would keep financial reports, business plans and other proprietary information of partner companies private. However, contracts AGDC could enter into would be made public at least 10 days prior to the board meeting at which they would be considered. AGDC President Dan Fauske said in an interview that he takes issue with making contract terms public because the producer partners — BP, ConocoPhillips and ExxonMobil — do. The regulations are a “speed bump” that the project won’t be able to get over as they are currently written, Fauske said. “I just want agreements that enhance the development of this project — that the state’s happy and the producers are happy (with),” he said. The regulations were drafted primarily by the Attorney General’s office, in coordination with AGDC legal counsel, according to corporation spokesman Miles Baker. They are very similar to the confidentiality rules followed by the Alaska Industrial Development and Export Authority, which makes its contracts public. AIDEA typically acts as a state lender to private business, but has delved directly into smaller oil and gas business deals in recent years in Cook Inlet and on the North Slope. However, AIDEA often holds much of the leverage in its partnerships with smaller companies as the primary financer of a project, as opposed to AGDC through the State of Alaska, which just acquired 25 percent of the immense project. There is no timeline for the AGDC regulations to be adopted. AGDC board chair John Burns said at a Nov. 12 meeting that a committee consisting of board members Rick Halford, Dave Cruz, Joey Merrick and corporation attorney Ken Vassar would take up the regulations. “We are very cognizant of the (regulations) issue,” Burns said. All three producers submitted questions and comments expressing concern over how the draft confidentiality regulations would affect the progress of the Alaska LNG Project during a public comment period that closed Oct. 21. ExxonMobil Commercial Advisor Bill McMahon submitted a letter that states the producer is troubled by the proposed confidentiality guidelines and it believes they would prohibit AGDC from continuing in the project if they are adopted. “Disclosure of the commercial terms relating to the AK LNG Project would not only be to the competitive detriment of the AK LNG Project, but also would put the AK LNG participants at a significant disadvantage in commercial negotiations with potential LNG buyers, potential contractors, suppliers and vendors to the project and potential lenders,” McMahon stated. He added that the Legislature has already given AGDC authority to enter confidentiality agreements necessary for the project under House Bill 4 and Senate Bill 138, the legislation that formed AGDC and outlined the project process, respectively. ConocoPhillips Senior Lead Negotiator Patrick Flood noted in eight pages of formal comments that state participation in a competitive gas project is unique in the United States and echoed that the Legislature provided AGDC with broad powers to participate in the project. BP contends the proposed regulations would allow for information previously considered confidential to be released to the public without consent. The company signed a confidentiality agreement with AGDC May 9, 2014, according to its comments. “Public disclosure of this information could jeopardize the competitiveness of the Alaska LNG Project,” BP stated. “It would also deter third parties form disclosing their confidential information to all the Alaska LNG Project participants and impair the ability of the project participants to share technical and commercially sensitive information with each other.” Fauske, the former head of the Alaska Housing Finance Corp., and AGDC Vice President of Commercial Operations Joe Dubler, who served as AHFC’s chief financial officer before moving to the gasline project, both likened making AGDC’s contracts public with making public the mortgage term sheets AHFC has agreed to with thousands of Alaskans. Under AHFC regulations that information is kept private. “I think what’s being missed here in this whole thing is in a lot of cases it’s in the state’s best interest not to disclose that (confidential) information,” Dubler said. “When you’re talking about information your customers can use to determine what it cost you to produce the gas — when you sit down and negotiate with them — if they know what it cost to produce the gas, guess what they’re going to offer your for that gas: it’s not going to be a whole lot more than what it’s costing you.” According to a description of the draft regulations provided by AGDC, the corporation would continue to honor all third-party confidential agreements made prior to April 1, 2015. The regulations state that no contract the corporation enters after Dec. 1 to protect the confidentiality of information shall itself be treated as confidential. The confidentiality issue is festering as the state looks to secure financial agreements with the producers that will need to be in place before a constitutional amendment needed for the project can be approved by the Legislature. The Legislature needs to have the amendment wrapped up and ready for the fall election ballot by June 24 to meet statutory requirements or the whole timeline could be delayed two years. At the same time, the project is moving towards the end of the pre-front end engineering and design, or pre-FEED, stage later next year — the end of which will require significant decisions by all parties as to whether or not the project should continue. Fauske said the challenge with not signing strong confidentiality agreements is that what is deemed confidential by one party could be debated by another, slowing the whole process down. Currently, two AGDC board members, board chair Burns and Cruz, have signed confidentiality agreements. They signed the agreement that all corporation employees and board members signed prior to Gov. Bill Walker’s administration, according to AGDC’s Baker. That agreement binds those who have signed it to any confidentiality agreement the corporation enters into with third parties. In January, Walker fired three AGDC board members and ordered new board members not to sign the confidentiality agreement. Around the same time, Attorney General Craig Richards said in an interview with the Journal that the current requirement, which is still in place, keeps too much information from the public and that a new policy could be expected that would allow more open discussion of Alaska LNG Project issues while protecting certain private information. Walker has not signed a confidentiality agreement relating to the Alaska LNG Project, however he can review the same information that is available to the CEOs of the three producers, according to his spokeswoman Katie Marquette. Fauske said the Legislature appropriates all the money AGDC spends and what it will be spent on is vetted in committee hearings. “You trust the system that you have in place to work,” he said. “We’ve got to start acting more like business partners instead of regulators.” Elwood Brehmer can be reached at [email protected]

Kenai mayors offer $60K to lure Cook Inlet board meeting

If Alaska fishermen want coffee at the 2017 Upper Cook Inlet finfish meeting, the Alaska Board of Fisheries might have to change the location to the Kenai Peninsula. In a Nov. 16 letter to the Board of Fisheries, Kenai Peninsula Borough and City of Kenai mayors Mike Navarre and Pat Porter, and Soldotna Mayor Pete Sprague offered the board over $60,000 in service savings if the board were to hold its 2017 Upper Cook Inlet finfish meeting on the Peninsula instead of Anchorage. The board spent a large chunk of time discussing a potential relocation at its annual October work session. Opponents of a location shift say the travel to the Peninsula will be prohibitive. Proponents say it’s been prohibitive for them for nearly two decades. “Not having reasonable, periodic access to the (Board of Fisheries) process is simply unfair to the large populations of Alaskans living on the Kenai Peninsula,” the mayors’ letter reads. The Board of Fisheries oversees all commercial, sport, and personal use fishing in the state waters of Alaska, which are within three miles of shore. The board operates in three-year cycles, reviewing each area and species type once every cycle. The last Upper Cook Inlet finfish meeting, which overwhelmingly focuses on salmon, was held in Anchorage in February 2014. At that meeting, as in 2011, the board made major amendments to its Kenai and Kasilof river management plans. The board hasn’t held an Upper Cook Inlet meeting on the Peninsula since 1999, or five regulatory cycles. Apart from issues of fairness, the Peninsula mayors make a fiscal offer in their letter. Board meetings are expensive, and due to the state’s fiscal situation the board is going to have to discuss cost-cutting measures. By volunteering local venues, they estimate to save the board $61,288, according to similar expenses from the 2014 meeting. According to board Executive Director Glenn Haight, the bulk of board meeting expenses are, in fact, the exact services the Kenai officials are volunteering at no cost to the state: a place to hold the meeting, and the coffee service to fuel it. Haight said the Egan Center venue for the 14-day 2014 meeting cost $41,000. Coffee service alone, which provides coffee, tea, and water for all board meeting attendees, cost $20,000 for the Downtown Anchorage meeting. The Peninsula mayors say they would provide one of two available venues to the board for free: the Soldotna Regional Sports Center of the Kenai Central High School Auditorium and Challenger Center. Either city would also throw free joe into the deal, along with transportation service courtesy of local school buses. Ancillary costs like board member travel, board support travel, and freight add another $3,000 to $4,000 to the tab, while division staff transportation and hotel costs are borne by the Alaska Department of Fish and Game. Board costs for hotel stays in Kenai or Soldotna would equal an Anchorage meeting; only one board member lives in Anchorage. Both Kenai and Soldotna also promise one uniformed police officer to be present at the meeting. Board support is funded from unrestricted general funds, which have been slashed in light of state budget shortfalls. Haight said even without further reductions to unrestricted general funds, the board is projecting a $170,000 shortfall for the 2017 fiscal year, when the Upper Cook Inlet meeting will occur. Board support has already ceased any further hiring and kept an eye on advisory committee travel to keep costs down. “This is just a really basic kind of question that we have to ask ourselves,” said Haight. “Right out of the chute we’re in jeopardy for next fiscal year.” The board will discuss solutions and cuts at its upcoming Bristol Bay finfish meeting in Anchorage in December. Coping strategies drafted by Haight include consolidating finfish and shellfish Southeast meetings, cancelling training meetings, furloughing board executive directors, and combining meetings. Coffee service, Haight said, is “one of those things that would need to come off.” At the October work session, the board voted unanimously to change the 2017 Upper Cook Inlet meeting to Feb. 22-March 9, but only voted 4-3 in favor of discussing a UCI meeting location change at its December meeting. Alaska Gov. Bill Walker wrote a letter to the board Oct. 21, asking it to consider changing the location and promising to attend if it were held on the Peninsula. “There has been much attention given to the controversies surrounding the Cook Inlet fisheries, and I feel we should attempt to improve the communication and exchanges among the many interested parties,” wrote Walker. “Holding a meeting on the Peninsula, possibly Soldotna, may show a willingness to consider points of view from local residents who may not have been able to participate over the past five board cycles.” Several Alaska representatives have also expressed support for a location change in letters to the board, including Alaska Speaker of the House Mike Chenault, R-Nikiski, in a Nov. 9 letter, Sen. Cathy Giessel, R-Anchorage, Sen. Peter Micciche, R-Soldotna, Rep. Kurt Olson, R-Soldotna, and Rep. Paul Seaton, R-Homer in a letter from Sept. 24, 2014. City managers and mayors from Kenai Borough, Homer, Seldovia, Soldotna, and Seward have also expressed support of a location change. DJ Summers can be reached at [email protected]

Administration will introduce bill to convert Fund earnings

The slide in crude oil prices is continuing, and transforming Alaska’s state finances to revenue sources more predictable and sustainable than oil income has taken on more urgency. Year-to-date prices for North Slope crude oil were at an average of $49.98 per barrel as of Nov. 17. That’s since July 1, the start the current fiscal year, and it is $16 per barrel less than the price of $66.03 per barrel predicted by the state last March and used as the basis for budget planning. Year-over-year production numbers are better, with an increase of about 3.7 percent since the start of the fiscal year through Nov. 15. Daily production in November is averaging about 555,000 barrels per day compared to about 537,000 barrels per day in November 2014. How much the price shortfall will balloon the state budget deficit is uncertain, but a deficit well greater than $3 billion is certain. Is there a better way? State officials have been quietly working since last January on a plan to transform Alaska’s fiscal system and some concepts have been rolled out in recent weeks before legislative and business leaders.  State Attorney General Craig Richards surfaced the concept, still a work-in-progress, in a recent briefing to state legislators and, more recently, to the Alaska business policy group Commonwealth North. The plan, being labeled a “sovereign wealth” fund, would replace oil revenues with earnings from the $53 billion Alaska Permanent Fund. Richards warned, however, that the idea if implemented next year would still leave an estimated $1 billion gap that would require new revenues, most likely new taxes. A preliminary estimate for the idea allows for about $3.1 billion per year to be paid to the general fund from Alaska Permanent Fund earnings, and have about $1 billion paid additionally from other state taxes, for a total of $4.1 billion. This assumes a status-quo state budget of about $5.1 billion in unrestricted general fund spending, leaving the $1 billion remaining gap. However, legislators are likely to reduce the budget to less than $5.1 billion next year. Legislators were briefed on the idea in Juneau during the recently-concluded special session of the Legislature, which had been called to consider Gov. Bill Walker’s idea to buy TransCanada Corp.’s share of the Alaska LNG Project, which lawmakers approved. Members of the administration’s working group have not been identified except that it includes economists from the Department of Revenue and other state agency officials as well as Richards. The administration officials confirmed that there will be a bill introduced for the 2016 session outlining the plan. The concept basically involves bulking up the Permanent Fund by diverting some oil revenues to the Fund that now go to the state general fund. Income earned by the Fund would flow into its Earnings Reserve Account, as it now does. Currently there is about $9 billion in the earnings account. Withdrawals would be made annually from the earnings account by the Legislature to support the state budget, using some as-yet-undetermined formula. The state constitution prohibits spending money from the principal of the Permanent Fund but income that has accumulated in the Earnings Reserve can be appropriated by the Legislature. An important change in the plan is that it would indirectly reduce the amount of money available for the Permanent Fund dividend. If the plan were in place next year the 2016 dividend would be $1,000, about half the 2015 amount, Richards told the legislators. The effect of that would be, indirectly, to put more money into the Permanent Fund, creating more earnings that would support the state budget. John Tichotsky, chief economist in the state Department of Revenue, told members of Commonwealth North’s fiscal task force recently that a major goal of the plan is to take the volatility of oil revenues out of the state general fund, which is now 90 percent dependent on oil, and place it into the Permanent Fund, which can smooth out the volatility because of its sheer size. There would also be a more stable source of revenues for the state general fund. Other key goals include keeping the Permanent Fund on a sustainable basis in terms of its real, or inflation-proofed, value, Tichotsky told the Commonwealth North group. Legislators have voiced few opinions about the plan but some who did speak were cautious. Sen. John Coghill, R-Fairbanks, who is Senate Majority Leader, attended the Juneau briefing and complimented the governor for stepping forward with a plan, but had some mixed views. “I think it’s complicated. It doesn’t really bring in more money, but just rearranges the plumbing,” he said. Coghill’s point was that the same goals can be accomplished in simpler ways that would be more understandable by the public, and possibly more transparent. For example, just appropriating a portion of the Fund’s annual earnings and capping the dividend might achieve the same results. Others who have looked at the concept are intrigued, however. Cheryl Frasca, a former state budget director who chairs Commonwealth North’s fiscal policy task force, is open to the new ideas. “I think it’s an interesting approach for a couple of reasons,” she said. One is the proposal, in the plan, to fund the annual citizen dividend with a percentage of oil royalties rather than earnings from the Permanent Fund, as happens now. “It ties a ‘royalty dividend’ (now the Permanent Fund dividend) directly to oil and gas development instead of Wall Street investment returns,” the current system, she said. “That changes the dynamic of support and creates a constituency that supports future oil and gas development. After all, it’s claimed that it’s ‘our oil.’” A second interesting point, she said, is that it would require a limit on the amount of revenue taken annually from the earnings account, although the mechanism for that is still being developed. “This could be a good tool to control spending. I believe Anchorage’s municipal tax cap (a somewhat similar mechanism) is a very efficient tool that has limited Anchorage’s spending swings over the years,” Frasca said. “This means that if the Legislature wants more money it will have to go to other tax sources,” which will encounter resistance. “Other taxes become the wild card in terms of generating additional revenues to support increased spending. Lots of constituencies protecting sources for these revenues, so it creates a counter-balance against increasing spending,” Frasca said. In a recent talk before the Alaska Miners Association’s annual convention, Northrim BanCorp CEO Joe Beedle said he likes overall concept the Walker administration is advancing. “Whether it’s called an endowment, a sovereign wealth fund or Permanent Fund, I believe the concept is very good,” Beedle said. He also liked the direct connection between the dividend and state oil and gas income, he said. There are other views on that, however. Some see a severing of the connection between the Permanent Fund and the dividends having the effect of reducing citizens’ interest in the Fund and their role as watchdogs on any imprudent investments or a Legislature’s way to “raid” the fund indirectly by using it as loan collateral, which can be done. Linking the dividend to the Permanent Fund performance was central to the idea of the dividend advanced in 1980 by former Gov. Jay Hammond, who saw it as a way of developing safeguards for the Fund. There are also many features of Walker’s fiscal plan that are not yet developed, however, and details are important. Tichotsky, of the Department of Revenue, told Commonwealth’s fiscal task force that a crucial decision yet to be made is whether to use some form of Percent-of-Market-Value, or POMV, formula to annually draw funds for the budget or to develop a fixed yearly payment, perhaps inflation-adjusted. The Percent-of-Market-Value payout method is commonly used by large endowments like those held by universities and large charitable funds. It makes a payment based on the overall market value of the endowment. The payment is typically less than the projected average total earnings, such as a 4 percent payment from earnings averaging 8 percent, with the remaining 4 percent of earnings are retained to adjust for inflation. One problem with the POMV is that, assuming a steady growth of market value, it would tend to automatically increase the amount of revenue available to the Legislature, which would inevitably lead to greater spending. One advantage of the fixed-draw is that this would be a true cap on spending, although there would have to be periodic “reopeners” of the cap to make adjustments, such as for inflation or population growth. Eric Wohforth, co-chair with Frasca of the Commonwealth North task force, said he is concerned about a fixed-draw because any necessary adjustment mechanisms would be complex, difficult for the public and inevitably less transparent. “There’s total transparency to percent-of-market value. Everyone can see what the market value is, so it’s very simple,” Wohlforth said. Wohlforth is an Anchorage attorney and a former Permanent Fund trustee and state Revenue commissioner.

Ferry system braces for cuts; state funds down 15% since ‘14

“There is no money, so our approach should not be ‘How do we get more money?’” Marine Transportation Advisory Board chair Robert Venables said. “While there may not be money, there are solutions.” Venables’ remark, which opened the Nov. 16 Marine Transportation Advisory Board, or MTAB, meeting, was specific to the Alaska Marine Highway System but could have been directed to countless state functions. As references to the state budget deficit grow from $3 billion, to $3.5 billion to more, the state ferry system and the public board are working on ways to optimize ferry service and revenue. The Alaska Marine Highway System, which operates 11 ferries for 35 ports from Dutch Harbor to Bellingham, Wash., is projecting a $25.5 million budget cut in the 2017 fiscal year compared to 2014, according to Deputy Transportation Commissioner Mike Neussl. “That’s a huge hit,” he said. In fiscal year 2014, the Marine Highway System was appropriated $162.6 million by the Legislature. It will have a budget of about $137 million in the 2017 fiscal year, which begins next July 1, if the administration’s projection holds true. The current fiscal year 2016 system operating budget is $14.6 million less than the 2015 fiscal year, which ended June 30.  “Extra” amenities, such as gift shops and bars on the vessels that have them, have been closed to save money over the past couple years. This year, 45 positions were eliminated and significant service cuts are starting. The Marine Highway System measures its service level by the sum of the weeks its 11 ships are sailing. From 2011-2013, the state ferries provided more than 400 combined weeks of service; the last two years service declined to about 378 weeks as several vessels returned to work late after winter overhauls. Most notably was the M/V Tustumena in the spring of 2014. This fiscal year’s operating plan calls for 350 weeks of service as vessels are laid up to save money. The fast ferries Fairweather and Chenega are scheduled to enter layup May 1 after coming out of federally-funded winter capital improvement programs. The M/V Taku will be in layup for the entirety of fiscal 2016 because a pot of state capital money used for repairs to assure the ferries pass annual U.S. Coast Guard inspections shrank from $12 million to $10 million this year, which left the Taku tied to a dock, according to Neussl. “We’re starting with less (money) than we normally do with vessels that are older and need more work than years ago,” Neussl said. Nearly every vessel had “discovery work,” or additional repairs that were found when the inspections began, straining that budget item even more, he added. Further harm could come from the federal government, if ferry formula funding for capital projects is cut for Alaska, as proposed in the Senate version of the long-term transportation funding bill, according to Neussl. Taking vessels out of service to save money isn’t free, either. Laid-up ferries must be manned with minimal crews while dockside. The 352-foot Taku, a mid-sized Alaska ferry, will cost the system $3.6 million to sit idle this year, Neussl said. The proposed 2016 summer schedule reflects the anticipated 2017 fiscal year funding hit that will take effect July 1. Most notably, Sitka’s service is reduced from near daily fast ferry service last summer to twice-weekly visits from mainline vessels next summer. Also, Prince William Sound ports will not have service for six weeks beginning in mid-September under the draft schedule. Neussl said he was pleased to see the public focus on the tangible impacts of reduced service in public comments on the proposed 2016 summer schedule, which he called “bleak.” Solutions to managing Alaska’s ferry fleet on a shrinking budget need to be locally based with an emphasis on providing basic transportation for Alaskans, while working to at least narrow the system’s internal budget challenges, Venables said. The Alaska Marine Highway System never has been and never will be a profitable venture for the state. Making money was never its intent. Since the current 11-vessel fleet took shape in 2006, the system’s “fare box recovery rate” has been between 30 percent to 35 percent of its overall budget. Getting back to the 50 percent recovery range achieved in the early 2000s would be a success, system officials have said. That likely means reducing the fleet size and compressing traffic onto fewer sailings, according to Neussl. At the same time, providing some level of service to all 35 port communities is the Alaska Marine Highway System’s first goal, he said. From there, providing tourism and commercial opportunities, while maximizing revenue, becomes a challenging mix. While ferry ridership remained fairly steady, the number of sailings continued to increase when the state was flush with cash in the mid- to late-2000s. Southeast Conference Executive Director Shelly Wright also said at the Nov. 16 meeting that striking a balance between service and budgets starts at the local level. The Southeast Conference, a regional development organization, is organizing a series of community meetings with DOT to discuss the importance of the system directly with the public. Senate Transportation Committee chair Sen. Peter Micciche of Soldotna held an Alaska Marine Highway System listening session in Sitka Oct. 23 and said during the MTAB meeting that he hoped hold additional meetings to hear from other coastal Alaska communities. Legislators from areas not served by the ferry system have been blamed for dismissing the transportation service and quickly looking to it when state budgets need to be tightened. “I believe (legislators) are ready for a change; they’re ready to listen to something new; they’re ready to support the Marine Highways as long as they know that it’s not going to be just business as usual — ‘please give us more money and we’ll figure it out,’” Wright said. She added that legislators need to know about the social and cultural importance of the system beyond the bottom line “because we all know the bottom line is never going to be a black one.” AMHS General Manager Capt. John Falvey said the system commissioned a study to examine the economic impact the system has on the entire state, not just the regions it serves. The last such study was done in 1995. The final report should be done in time for the upcoming legislative session that begins in late January, he said. It’s widely understood that communities along the Marine Highway rely on the ferries to bring tourists and serve as a freight carrier to communities without barge service, but the actual benefits have been anecdotal. A new online reservation system, set to go live in May, should also help the system collect data on its riders and eventually develop a fare formula, both of which will help optimize revenue, Falvey said. Historically, fares have been set at the discretion of the DOT commissioner and that has led to a disjointed structure of more than 20,000 fare combinations. Falvey and Neussl admitted there is no rhyme or reason to the fare structure and the new reservation system should be a good starting point to overhaul fares and get to a system-wide fee-per-mile structure. Fares on a majority of routes were increased 4.5 percent earlier this year to bring them more in line with the most expensive ferry trips, but the fares are so disjointed that much more work is needed. New ferries A bright spot for the beleaguered Marine Highway System, construction of its Alaska class ferries, or day boats, at Vigor Alaska’s shipyard in Ketchikan is on schedule and going well, Neussl said. The pair of $60 million, 280-foot ferries is destined to serve Haines, Skagway and Juneau in Lynn Canal. The first of the twin vessels is scheduled for completion in October 2018, with the second coming shortly thereafter. Replacing the 51-year old Tustumena, the only ship that can adequately serve the Homer, Kodiak and Aleutian ports, is off to a good start, too. Falvey said the final design of the 330-foot vessel is coming in at about $6 million, less than the $10 million set aside for it in the state’s Vessel Replacement Fund. Overall replacement of the Tustumena has been pegged between $211 million and $237 million. The final design is expected in January from Glosten, a Seattle-based marine engineering firm. Elwood Brehmer can be reached at [email protected]

Huge Inlet, Bay sockeye forecasts in face of price slump

Next year promises to be a big year for sockeye harvests. Both Bristol Bay and Upper Cook Inlet are forecast to have sizable sockeye returns in the midst of global and domestic market hostile to U.S. higher sockeye prices detailed in a new economic report.  In Cook Inlet, the second-largest sockeye producing region in the United States’ largest seafood producing state, the Alaska Department of Fish and Game forecasts a run to the major rivers of 7.1 million salmon, with 4.1 million available for commercial harvest. This exceeds the most recent 20-year average by 1.1 million fish. The biggest gain for the area is on the Kenai River. ADFG forecasts a Kenai River run of 4.7 million fish, exactly 1 million more than the 20-year average. The Kasilof and Susitna rivers both have run forecasts 13 and 12 percent lower than the 20-year average, respectively, at 861,000 and 372,000. Fish Creek, the fourth major Upper Cook Inlet spawning river, is forecast to see 31 percent more sockeye than the 20-year average at 110,000. Sockeye escapement on the Kenai and Kasilof rivers has exceeded the maximum escapement goal several years running. Between 2011 and 2015, the Kenai River sonar counted an average 285,000 sockeye beyond the maximum goal. For the Kasilof River, the 2012-15 average sonar count was 104,000 over the maximum goal. Commercial fishermen in the region argue the management framework has needlessly slashed their fishing opportunities for the sake of sportfishing opportunities. Taking the average pounds per fish, along with the average annual ex-vessel price per pound of sockeye, United Cook Inlet Drift Association calculated $30.5 million dollars of ex-vessel value foregone, or approximately $60 million in first wholesale value. Bristol Bay, Alaska’s most valuable fishery and the world’s largest wild sockeye salmon run, is forecast for its third straight massive run and commercial harvest. ADFG biologists are forecasting 46.5 million sockeye in the 2016 Bristol Bay run, with an escapement of 15.3 million and commercial harvest of 31.2 million. The run size and the harvest prediction surpass both recent and long term averages. The run forecast is 15 percent greater than the previous 10-year average, and 41 percent greater than the long-term average of 32.9 million. The projected harvest is broken down between 29.52 million fish in Bristol Bay and 1.72 million fish in the South Peninsula fisheries. A Bristol Bay harvest of 29.52 million would be 8 percent greater than the previous 10-year average of 27.3 million, and 46 percent greater than the long-term average of 20.2 million. This would make 2016 the third-biggest sockeye crop in as many years. In 2015, the total Bristol Bay harvest was 36.7 million, which is second only to 2014 in the last 20 years. This year, ADFG had predicted a run of 48 million and a harvest of 37.6 million. Bristol Bay’s fishermen in particular had a difficult 2015 season, with a massive but oddly timed run preceding a 50-cent per pound ex-vessel price, half the average for the region. To examine the marketplace factors affecting this price, the Bristol Bay Regional Seafood Development Association contracted McDowell Group, a Juneau economics firm, to produce a research paper. The paper’s author Andy Wink said 2014 harvest particulars blended with 2015 market conditions and geopolitics to create an the exceptionally low ex-vessel price. Fishermen got paid less in 2015, the report claims, partly to correct an overpayment in 2014. Ex-vessel prices usually correspond to first wholesale prices; between 2006-2015, fishermen received an average 25 percent of the first wholesale price as their base ex-vessel pay. In 2014, the ex-vessel percentage of first wholesale was 30 percent. In 2015, it was 17 percent. “Bristol Bay processors paid significantly higher ex-vessel prices in 2014, relative to average first wholesale value per pound of product sold, due to lower than expected wholesale prices and sales volumes,” according to the report. “Overall gross processing margin declined 44 percent during the 2014 sales cycle and inventories increased. This resulted in a very weak ex-vessel price for 2015 sockeye, as processors acted conservatively to protect capital and minimize risk from declining wholesale prices.” Other sockeye producing areas did not suffer the same drop in fishermen’s pay. Bristol Bay’s ex-vessel price was not only low in comparison to its own historical average, but also low in comparison to other areas. Wink wrote that Bristol Bay’s uniquely rising volume output for 2014 and 2015 accounts for the locality of the price drop. “Bristol Bay sockeye harvests increased 75 percent in 2014 and another 16 percent in 2015, compared to a decline of 1 percent and an increase of 13 percent, respectively, for all other Alaska sockeye fisheries combined,” according to the report. “Given the difference in regional harvest volume, market destination, and product forms, a larger difference in ex-vessel price compared to other regions is understandable, though still unfortunate.” Sockeye, despite a large U.S. consumer base, is primarily an export product. The U.S. dollar’s strength relative to key foreign markets and exports is cited as yet another reason for the overall decline in sockeye value, with the value of relevant currencies declining between 18 and 49 percent in the last two years. Despite the loss of export value, however, exports for 2015 sockeye rose instead of dropping. “U.S. sockeye exports following the Bristol Bay season (July-September) are up 51 percent in 2015 over the same period last year,” according to the report. “Exports of frozen (head and gutted) sockeye increased 81 percent, while year-to-date export volumes of canned sockeye increased 16 percent.” DJ Summers can be reached at [email protected]

Statoil quits the Alaska Arctic OCS, following Shell’s exit

Norway-based Statoil has quit its Alaska Arctic program in the Chukchi Sea, becoming the second company to officially withdraw from the region.  ConocoPhillips, the remaining holdout among the Chukchi Sea explorers, has not indicated its intentions but said the company’s Arctic offshore plans had been on hold for some time. Earlier this fall Shell announced disappointing results on Chukchi Sea drilling and said it would end its program. Statoil is returning its leases, however, while Shell is retaining its Chukchi holdings, as is ConocoPhillips, although all leases expire in 2020. The U.S. Department of the Interior refused a request by the companies to suspend the clock on the leases. In a statement, Gov. Bill Walker said, “We are disappointed in Statoil’s decision not to pursue further offshore development in the Chukchi, and understand it is largely tied to Shell’s decision to terminate its offshore drilling efforts in Alaska as well. This further emphasizes the need to develop our onshore opportunties, such as the 1002 section of ANWR.” Environmental groups reacted positively. Oceana, which focuses on the offshore, said, “Decisions made by oil companies in the Arctic Ocean are finally starting to make sense. First Shell and now Statoil abandoning offshore leases sends a strong message to decision-makers meeting in Paris next month,” on climate change, said Susan Murray, Ocean’s Deputy Vice President for the Pacific. “Pursuing oil and gas development in the Arctic Ocean is too risky.” Statoil said its leases in the Chukchi Sea are no longer considered competitive. The company also closed its office in Anchorage on Nov. 16, laying off two employees who were still here. Statoil will also drop 16 leases that were 100 percent owned by the company and also a part ownership, with ConocoPhillips, in 50 other leases in the Chukchi Sea.  “Since 2008 we have worked to progress our options in Alaska. Solid work has been carried out, but given the current outlook we could not support continued efforts to mature these opportunities,” Tim Dodson, Statoil’s executive vice president for exploration, said in a statement. Statoil U.S. spokesman Peter Symons said the company is in discussions with ConocoPhillips on the disposition of Statoil’s shares of the 50 jointly-owned leases, in which Statoil holds varying percentages. ConocoPhillips spokeswoman Natalie Lowman, based in Anchorage, said it is possible that if Statoil surrenders its share of leases that portion of ownership would revert to ConocoPhillips, but that the matter is not clear. As for ConocoPhillips’ own position, she said, “Our plans for the Chukchi Sea were on hold prior to Statoil’s announcement and they remain on hold.” Statoil’s last Alaska employees had expected the office closure. “Statoil is a great company but there were just too many obstacles placed in the path of drilling, and low oil prices don’t help,” said Ella Eide, who until Nov. 16 was Statoil’s spokeswoman in Alaska. The company had been gradually winding down its Alaska presence, and its workforce in the state, for some time. Statoil acquired its Arctic offshore leases in the Interior Department’s 2008 OCS lease sale in the Chukchi Sea along with, Shell, ConocoPhillips and Repsol. Statoil and ConocoPhillips began environmental and early planning for drilling but decided to let Shell take the lead in clearing regulatory obstacles and legal challenges. After about $7 billion in expenditures including over $2 billion spent for the OCS leases in 2008, Shell was finally able to drill a well into potential oil formations in 2015, but the results were disappointing. Randall Luthi, president of the National Offshore Industry Association, a trade group, said, “Statoil’s decision to withdraw from the Alaskan Arctic is disappointing yet understandable given current tough economic and regulatory conditions. These are challenging times for the oil and gas industry with continued low commodity prices making for hard choices, and I know this was a difficult one for Statoil.  “The company has a substantial investment in the U.S. Arctic and had hoped to become a producer of both energy and economic growth there for Alaskans and for our nation. Hopefully, another company will step in to fill the void left by Statoil, but given the harsh economic climate and the difficulty obtaining lease extensions, the outlook is rather bleak.” Kara Moriarty, president of the Alaska Oil and Gas Association, said Statoil’s decision is a stark reminder of the importance of regulatory certainty in the oil and gas business. “While lawmakers and policymakers cannot control an oil basin’s geology, they can control permitting and regulatory policies to make the region competitive for exploration and development,” Moriarty said in a statement. “Unfortunately, Alaska is an expensive place to do business, and the federal regulatory environment is known for being difficult and unpredictable. Coupled with oil prices staying stubbornly low and expected to remain so for the foreseeable future, taking huge financial risks in Alaska is just not feasible for most oil companies, even large ones like Statoil and Shell.” The decisions by the two companies to depart will not have a large adverse economic impact on the state, although had Shell had better results and continued with drilling in 2016 it would have generated work for many Alaska-based support companies. There is no effect on state finances either, since it would have been a decade or more before any offshore oil flowed into the Trans-Alaska oil pipeline. Also, oil and gas from federal offshore waters pay no production taxes or royalties to Alaska, although state taxes on onshore property, like pipelines, would have been a benefit.  Offshore production would mainly have helped keep the TAPS pipeline viable by providing more oil. That would lower TAPS’ operating costs, which would have lowered costs for transporting oil produced on state lands. That would have resulted in new revenues to the state.  Tim Bradner can be reached at [email protected]

ConocoPhillips greenlights $900M Greater Moose’s Tooth-1

It was an announcement that lifted spirits at the annual Resource Development Council conference on Nov. 18. ConocoPhillips Alaska President Joe Marushack said his company will proceed with construction of its Greater Moose’s Tooth No. 1 oil project in the National Petroleum Reserve-Alaska. “GMT-1 has been approved for funding. It is expected to cost about $900 million and follows our recent completion of CD-5,” which is also in the NPR-A, Marushack said. The new project will be in production in late 2018 and will produce 30,000 barrels per day at peak, he told the RDC annual conference in Anchorage. The timing likely means that construction activity will begin in 2016, a boost for North Slope contractors and their workers. “We are pleased to have been able to work through key permitting issues with the Corps of Engineers and BLM (Bureau of Land Management) that now allows us to move into the development phase,” he said. GMT-1 is in the northeast NPR-A about seven miles west of the reserve’s eastern boundary with state-owned lands. The producing Alpine field and now the CD-5 project near Alpine are owned 78 percent by ConocoPhillips and 22 percent by Anadarko Petroleum Corp., as is the planned GMT-1. CD-5 began producing ahead of schedule in October, and will have peak production of about 16,000 barrels per day. ConocoPhillips’ Drillsite 2-S in the Kuparuk also began producing and will add about 8,000 barrels per day at peak. GMT-1 will be connected by road and pipelines with CD-5 and the Alpine field. The project has long been in the planning stages and was approved following an extended environmental and regulatory proceeding by the U.S. Bureau of Land Management. Although GMT-1 is within the federal NPR-A, parts of the mineral rights are owned by Arctic Slope Regional Corp., the Alaska Native corporation based in Barrow. ASRC received rights in the reserve as a part of the Alaska Native Claims Settlement Act approved by Congress in 1971. ConocoPhillips is also at work on a planned GMT-2 project a few miles farther west in the NPR-A from GMT-1. The petroleum reserve is a 23-million-acre federal enclave that dominates the western part of the North Slope. It was created in 1923 by President Warren Harding as a future oil reserve for the U.S. Navy, However, after years of exploratio, no commercial oil deposits were found until ConocoPhillips and Anadarko made the discoveries now being developed in the northwest part of the reserve. Marushack also told RDC that ConocoPhillips now has six rigs at work in the North Slope fields it operates, the most since the mid-1980s. The company’s capital budget for 2015 is about $1.4 billion, down slightly from $1.6 billion in 2014. “Our capital budget in Alaska remains strong and the reason is that the projects we do here are what ConocoPhillips does well,” which are large, conventional oil and gas projects, Marushack told the RDC. No capital spending figures for 2016 have been announced.  Journal reporter Elwood Brehmer contributed to this article.

Independents win big acreages in state North Slope lease sale

Some people in industry still have a lot of faith in the North Slope, even with crude oil prices skidding. Independent companies bid aggressively for acreage Dec. 18 in the state’s North Slope “area-wide” sale, acquiring acreage at rock-bottom prices. The bulk of the offers were rock-bottom bids but with the exception of two high bids by Denver-based Armstrong Oil and Gas on tracts near a discovery Armstrong plans to develop with Repsol. Armstrong beat out competing bids by ConocoPhillips, in fact. The Alaska Department of Natural Resources auctioned off 131 tracts on 186,400 acres with high bids totaling $9.51 million. Armstrong was the highest bidder in the sale, offering $1.92 million on two tracts near the Colville River, the area of the Repsol/Armstrong discovery. ConocoPhillips offered the only competing bids in the sale of $160,000 for those two tracts. Two other parts of the North Slope were put up for bid, the “foothills” area of the southern Slope and state offshore acreage in the Beaufort Sea, but drew no bids. About 2.2 million acres of 5.1 million acres in the state’s central North Slope area were up for bid, not including the southern foothills and Beaufort Sea state acreage where there were no bids. In a big surprise, Armstrong Oil and Gas offered $3,007 per acre on the high-bid tracts through its affiliate, 70&140 LLC. The discovery area by Repsol and Armstrong is to the north of the tracts just acquired but the high bids reinforce a belief that the two companies have found a significant new discovery. Repsol, the operator for itself and Armstrong, has filed applications for development permits with federal and state agencies for facilities capable of producing 120,000 barrels per day.  The bulk of the leases sold Nov. 18 were to two small independents bidding together, Accumulate Energy Inc. and Burgandy Xploration LLC in a potential shale oil belt south of the Prudhoe Bay field where 88 Energy, an affiliate of Accumulate, is now drilling an exploration well to test shale prospects. The two companies bid together with Accumulate at 77.5 percent and Burgandy Xploration at 22.5 percent on the leases. The offers were a few cents above the state’s minimum bid of $25 per acre on most of the leases acquired. 88 Energy and another independent, Great Bear Petroleum, are exploring shale oil prospects in a wide area south of the Prudhoe Bay and Kuparuk River fields that are now producing conventional oil. The oil accumulated in the existing North Slope fields originated in deeply-buried shales to the south, which has led Great Bear and 88 Energy to a theory that these could produce oil similar to that now produced in the Eagleford and Bakken plays of the Lower 48 states. Tim Bradner can be reached at [email protected]

Current LNG buyers’ market not dooming AK LNG Project

It is a good time to be an LNG buyer on the global market. Long-term contracts with Asian buyers — the prospective market for the Alaska LNG Project — are almost exclusively tied to the price of oil through an energy equivalent formula. While a flooded oil market has helped liquefied natural gas buyers dependant on its price, there is simply a lot of LNG right now, too. “Today’s global LNG market is dreadful,” Kenai Peninsula Borough Oil and Gas Special Assistant Larry Persily said in an interview. “It’s just like oil; it’s way oversupplied.” Persily served as the federal pipeline coordinator for Alaska natural gas projects before joining the borough. In just a few years, delivered LNG prices in Asian markets has gone from nearly $20 per million British thermal units, or mmbtu, to less than half that. Japanese and Korean LNG buyers were paying $14.95 per mmbtu in May 2013; by last June, those prices were down to $7.25, according to the Federal Energy Regulatory Commission. In China, it was a little cheaper, at $7.10 per mmbtu on average. The cause for the current bloated market is fairly simple: high demand for natural gas several years ago pushed producers worldwide to develop LNG projects. The 2011 Japan earthquake and subsequent Fukushima nuclear disaster drove the country to shut down its nuclear energy program, forcing utilities to buy LNG for electricity production, further straining the market and driving prices up. Domestically, shale gas production exploded at roughly the same time and turned some Gulf Coast LNG import terminals into export facilities. Most analysts expect it to remain an LNG buyers’ market for several years, along the same lines as oil, Persily said, but the value of those projections are always up for debate. Eiji Hashio, a Tokyo-based vice president of Resources Energy Inc., said Japan is now buying about 90 million tons of LNG per year and about a quarter of that is on the spot market rather than long-term contracts. Japan is viewed as a primary market in Asia for Alaska LNG. The country accounts for about 35 percent of the global LNG market, which stood at more than 240 million tons in 2014, according to the International Gas Union. Worldwide demand grew about 2 percent last year. Combined, Japan and South Korea demand almost exactly half the world LNG market. Resources Energy Inc. is an Alaskan-Japanese consortium looking to develop a smaller Cook Inlet LNG export project. In July, the Japan Economy, Trade and Industry Ministry set a goal to resume nuclear power generation and increase renewable energy use — to the point where nuclear power meets 20 percent of the country’s electric demand by 2030 and renewable energy supplies another 20 percent. Eiji said “industry is very suspect of those targets,” because the nuclear target would require restart of more than 30 of the country’s 43 reactors, many of which are aging facilities. Japan produced no nuclear power in 2014. Still, he said the spot LNG market in Japan would likely diminish by 2020 as some nuclear power is brought back online. Today about 35 percent of LNG is traded on the spot market, according to Damian Bilbao, BP’s business development director for the Alaska LNG Project, the $45 billion-plus North Slope LNG export proposal that partners the State of Alaska with BP, ConocoPhillips and ExxonMobil, the gas suppliers for the project. Also in about 2020, many legacy contracts Japanese utilities have with gas suppliers will be expiring and a push towards decoupling LNG prices from oil will be emphasized, as will efforts to mirror the Henry Hub gas market of North America, Persily and Eiji said. Doing so would hopefully relieve LNG buyers from the volatility of the markets, according to Eiji. “The days of, ‘I’ll pay you whatever oil is with an energy equivalent factor; just send me the bill;’ those days are over,” Persily said. Linking to Henry Hub — at least these days — would also mean very low LNG prices. Henry Hub natural gas was up 13 cents from the day prior Nov. 16, at $2.14 per mmbtu. The prime advantage for Alaska LNG over Gulf of Mexico produced LNG is shipping. Tankers heading out of the Gulf must first go south through the Panama Canal and then traverse the entirety of the Pacific, adding days and “a couple bucks” per mmbtu to the final price of Henry Hub-linked Gulf LNG, Persily said. Eiji also noted that not all contracts will be structured the same, even amongst a single portfolio. Buyers want a blend of LNG sources, which leads to a blend of pricing. “What we would like to do is just cost-plus reasonable margin for the producers and developers,” he said simply. More LNG supply is also being developed in Australia. Persily said three export projects began production within the last year and another three are in construction. In total, the new LNG projects down under should add about 10 billion cubic feet, or bcf, of natural gas to the market per day, he said. Pegged at 20 million tons of LNG per annum, the Alaska LNG Project would add about 3 bcf per day to the world market over its 25-year initial design life. At 90 million tons per year, Japan’s LNG demand roughly equates to 13.5 bcf of natural gas per day. Worldwide capacity is expected to increase by about 50 percent over the next three years, Bilbao said. Where does all that leave the Alaska LNG Project, hoping to move first gas around 2025? Persily called today’s LNG market a “war of attrition” for export projects, which has likely helped Alaska with less feasible projects in British Columbia, Africa and other places falling out of sight. The work going on in Australia is not in competition with Alaska because those projects are further along and already have sale and purchase agreements in place, Persily noted. “After the dust settles later this decade, when hopefully the market begins to recover, the stronger projects will still be in the running. That’s the hope,” he said. A report from the Department of Natural Resources consultant firm Black and Veatch estimated the AK LNG midstream costs alone at $7.30 per mmbtu. Today’s global LNG prices simply aren’t workable for the Alaska LNG Project, but they don’t have to be, Black and Veatch consulting director Deepa Poduval said. On its current schedule, the Alaska LNG Project won’t be in production for another 10 years and hopes are to keep the pipeline full of gas for another 25 years at minimum after that. “You’re looking at a 50-year time horizon and you can’t make that decision based on a five-year forecast in prices,” Poduval said. Realistically, there isn’t a specific price that makes the project feasible from the state’s perspective, according to Poduval. The state’s benefit will not only come from the sale of its gas, but also from corporate income taxes and property tax revenue, among other sources. The Revenue Department announced in September that the producers had agreed to pay $15.7 billion to the state and local governments in PILT, or payments in-lieu of taxes, relating to the Alaska LNG Project. Those payments would be made over the operating life of the project. As a result, the state’s requirement for gas revenue is almost certainly well below what the producers will need, Poduval said. And among the three, varying financial positions will undoubtedly leave them with different perspectives as to what is a favorable project and LNG market. Among the biggest variables is the capital cost of the project. Current cost projections between $45 billion and $65 billion leave a capital swing of more than 40 percent. Next comes project financing. “What you probably need is (an LNG) price basis that works for the least common denominator. In effect it represents a level where everyone is basically happy — some are fairly happy, others are quite happy, but at that point where everyone believes uniformly that the project can be economical,” Poduval said. Even with a push in Japan and other markets to separate natural gas prices from oil, the fortunes of the Alaska LNG Project will still lie somewhat in the value of crude. Higher oil prices will improve the health of the producers’ financials, if nothing else. “I would think somewhere in the $70 (per barrel of oil) threshold would be important for our project,” Poduval said. “It probably needs to be higher than that to be confident for everyone and it will depend on the different pieces coming together.” The producers will not be too worried with the LNG market and how it impacts the Alaska LNG Project for several years, according to statements from ExxonMobil and ConocoPhillips. Purchase and sales agreements will be negotiated during the front-end engineering and design, or FEED, process, which should begin late next year and continue for several years, based on the current project timeline. ExxonMobil spokeswoman Kim Jordan wrote in a statement that the company expects LNG imports to Asia Pacific countries to grow by 60 percent by 2025, which could well position the Alaska LNG Project. BP’s Bilbao said China, which hasn’t historically been an LNG player, will continue to grow its demand. He also said that the current market gives the Alaska project partners an opportunity to drive down capital costs and continue to improve the project’s financials. The fact that three of the world’s largest, reliable oil and gas producers are partnering with the State of Alaska is a major benefit to the project and can’t be ignored by potential customers looking for national energy security through LNG contracts, according to Bilbao. When looking for buyers, LNG marketers want to “brand” their projects, he said, and Alaska LNG has credibility through its participants. “You want buyers in the market looking to transact with your project,” Bilbao said. Elwood Brehmer can be reached at [email protected]

Resource heavyweights gather at momentous time for Alaska

It’s November, and time for the big Resource Development Council annual conference. This year, more than any other, huge issues loom for Alaskans including the proposed $50-billion plus North Slope gas pipeline and liquefied gas project and the state’s fiscal troubles, with $3 billion-plus annual deficits. All will be discussed at the conference. RDC is a pro-development advocacy group representing all of Alaska’s industries that touch on use of the state’s rich natural resources. That includes tourism, which relies on an unspoiled wilderness landscape as its prime attraction. Tourism companies work side-by-side with oil and gas, minerals, fisheries and forest products companies in RDC, which demonstrates how these industries are not only compatible but reinforce each other. Organized labor is active in RDC too, because the state’s human resources, its labor force, are critically important. Municipalities are members and participants, too, because what happens in the state’s basic industries, which are mainly resource-driven, affects them. The annual meeting held in November is where all of this comes together, where all the state’s business and political movers and shakers rub shoulders, trade information and frequently move off into side-meetings. If there’s any one place where one can see who drives the state’s economy, this is it. This year’s conference, scheduled for Nov. 18-19 at the Dena’ina Civic and Convention Center in Anchorage, is expected to attract about 1,200, as it has in recent years. Briefings on all the state’s major industries are on the agenda as well as economic trends and updates on key federal and state regulatory issues. Joe Marushack, president of ConocoPhillips Alaska, will discuss his company’s positioning for the future in Alaska; Steve Butt of ExxonMobil, senior project manager of the Alaska LNG Project, will update the conference on the proposed North Slope gas pipeline and LNG export project; Dan Fauske, president of the Alaska Gasline Development Corp., will discuss the state’s role in Alaska LNG, and Kenai Peninsula Borough Mayor Mike Navarre will discuss how his municipality is preparing to deal with a huge construction project, although it is still some years off. There will also be briefings on activities of smaller oil and gas companies, such as BlueCrest Energy with its Cosmopolitan oil project in Cook Inlet; Caelus Energy with a new North Slope oil project, and Hilcorp Energy on that company’s work in redeveloping Cook Inlet oil fields and several mature North Slope fields acquired from BP. Mining companies will also talk about their operations and plans, including Eric Hill, general manager at the Fort Knox gold mine near Fairbanks, and Jan Trigg, community relations manager at the Kensington gold mine near Juneau. RDC’s members include several hundred businesses and groups and a large number of individual members, according to Marleanna Hall, the newly-appointed executive director. As an organization, RDC is unique in a number of ways. There are few, if any, similar organizations in other states that represent diverse interests and with a focus on responsible development of natural resources. Beyond its big annual conference, RDC is known, at least in Anchorage, for its biweekly breakfast meetings that typically feature presentations by business and agency leaders. All of these are posted on RDC’s website, Hall said. The group also offers a unique service to its members by representing them before federal and state agencies on often-complex regulatory and environmental issues. Many of these — endangered species is one example — may or may not have immediate effects on company operations but the potential of disruption is there. Through its engagement with the regulatory agencies RDC makes its members’ views known and also keeps its members informed on regulatory actions. The organization has also takes a leadership role at times in advocating legislative solutions to problems, one example being how state agencies allocated costs to private firms when development permits were applied for. In this case the solution worked out by RDC and its members, a framework on how agency staff costs are allocated, was enacted into law. A recent RDC initiative is with the state Department of Natural Resources’ decision on granting in-stream flow reservations to non-governmental groups. Hall testified in hearings on the issue, which has raised many concerns, and RDC has also submitted detailed comments to the state DNR. In another effort, RDC helped get its members out to support Hilcorp Energy’s planned Liberty offshore project in the Beaufort Sea. The U.S. Bureau of Offshore Energy Management is taking public comments on the application by Hilcorp to do the project. “This is very important because now that Shell has left the Arctic, at least for now, there are opposition groups that are shifting away from Shell to target this proposal,” Hall said. Another past effort was in combating the U.S. Environmental Protection Agency’s new “Waters of the United States” rule, which threatens to sharply expand that federal agency’s role in regulating Alaska development projects. In response to a lawsuit from 13 states including Alaska, a federal judge recently issued an injunction prohibiting the EPA from administering the rule.   The 36th Annual Alaska Resources Conference  November 18-19, 2015 • Dena’ina Civic & Convention Center, Anchorage, Alaska Resource Development Council - Growing Alaska Through Responsible Resource Development. For more information, visit akrdc.org. Wednesday, Nov. 18 7 a.m. Registration/Check-in/ Exhibits Open Eye-Opener Breakfast in Exhibit Area – Sponsored by Wells Fargo 8 a.m. Opening Remarks Ralph Samuels, RDC President, Vice President, Government and Community Relations, Holland America Line Governor Bill Walker (invited) Alaska Economic Trends: 2016 Outlook Neal Fried, Economist, Alaska Department of Labor Alaska Industry 2015 Year in Review and 2016 Outlook Oil & Gas: Kara Moriarty, President and CEO, Alaska Oil and Gas Association Fisheries: Glenn Reed, President, Pacific Seafood Processors Association Forestry: John Sturgeon, President, Koncor Forest Products Mining: Karen Matthias, Managing Consultant, Council of Alaska Producers Tourism: Scott Habberstad, Director of Sales and Community Marketing, Alaska Airlines 10 a.m. Gourmet Break – Sponsored by ConocoPhillips Alaska, Inc. 10:30 a.m. ConocoPhillips Alaska: Positioning for the Future Joe Marushack, President, ConocoPhillips Alaska, Inc. Global LNG Market Update and Framing the Opportunity for Alaska Felipe Arbelaez, Chief Commercial Office, BP Supply & Trading 11:30 a.m. Networking Break Noon Keynote Luncheon: Sponsored by Northrim Bank It’s Still North to the Future: Moving Ahead in the Arctic Wayne Westlake, President and CEO, NANA Regional Corporation Rex Rock Sr., Chairman and President, Arctic Slope Regional Corporation 1:30 p.m. Alaska Can’t Quit Now: Why the Arctic Still Matters Randall Luthi, President, National Ocean Industries Association Marine Freight Transportation: Safety and Environmental Stewardship Charlie Costanzo, Vice President, Pacific Region, American Waterways Operators What Alaskans Need to Know About Federal Overreach Bill Kovacs, Senior Policy Advisor, U.S. Chamber of Commerce 3 p.m. Gourmet Break – Sponsored by Colville, Inc. 3:30 p.m. Pebble vs. EPA: Finally Some Real Progress Tom Collier, CEO, Pebble Partnership Point Thomson: Dawn of a New Era Gina Dickerson, Point Thomson Project Manager, ExxonMobil 4:30 p.m. VIP Networking Reception – Hosted by ExxonMobil open to conference registrants and speakers Thursday, Nov. 19 7 a.m. Exhibits Open Eye-Opener Breakfast in Exhibit Area – Sponsorship Available 8 a.m. Real Solutions to Alaska’s Budget Crunch Cheryl Frasca, Former Director State of Alaska Office of Management and Budget, 2002-2006 Mike Navarre, Mayor, Kenai Peninsula Borough Give the State Some Credit: How Oil Tax Credits Are Changing Alaska’s Investment Game Benjamin Johnson, President, BlueCrest Energy, Inc. Casey Sullivan, Director, State Public Affairs, Caelus Energy Alaska, LLC Hilcorp: Boosting Efficiency and Production in Alaska Greg Lalicker, President, Hilcorp 10 a.m. Gourmet Break – Sponsored by Stoel Rives LLP 10:30 a.m. Communities and Mining: Why it Works Eric Hill, General Manager, Kinross – Fort Knox Mine Jan Trigg, Manager, Community Relations and Government Affairs, Coeur Alaska – Kensington Gold Mine Wayne Hall, Manager, Community and Public Relations, Teck Alaska Incorporated Lance Miller, Vice President, Resources, NANA Regional Corporation 11:30 a.m. Networking Break Noon Keynote Luncheon: Sponsored by Holland America Line Navigating Alaska’s Inside Passage and Policy Linda Springmann, Vice President, Deployment and Tour Marketing, Holland America Line 1:30 p.m. Progress Report on the AKLNG Project Steve Butt, Senior Project Manager, Alaska LNG Project Dan Fauske, President, Alaska Gasline Development Corporation Mike Navarre, Mayor, Kenai Peninsula Borough 3 p.m. Grand Raffle Drawing Send-off Champagne Toast – Sponsored by CLIA Alaska

Pebble conflict moves to Capitol Hill following latest report

The fight over the proposed Pebble mine at times makes politics look tame. That impassioned battle resumed on Capitol Hill Nov. 5 when the House Committee on Science, Space and Technology heard from those on the front lines of both sides. The committee also received testimony from former Maine senator and Defense Secretary William Cohen, whose recently published report about the Environmental Protection Agency’s involvement in the matter has once again made Pebble a topic of national debate. Published Oct. 6, “The Cohen Report,” as it is known, questions the objectivity and scientific process of the EPA’s Bristol Bay Watershed Assessment. The assessment is the baseline document used by the EPA to justify its attempt to block Pebble development through its Clean Water Act Section 404(c) authority, which gives the agency the power to prohibit projects that would have an “unacceptable adverse effect” on fish, wildlife or wetlands habitat. The title of the hearing, Examining EPA’s Predetermined Efforts to Block the Pebble Mine, leaves little wonder about the sentiment of committee chair Rep. Lamar Smith, a Texas Republican. “Secretary Cohen’s report lays out evidence that shows collusion and a cozy relationship between the EPA and groups actively opposed to the Pebble mine,” Smith said in a statement to open the hearing. In its ongoing lawsuit against the EPA in U.S. District Court of Alaska, Pebble contends the agency violated the Federal Advisory Committee Act by working with anti-mine groups to develop the Bristol Bay Watershed Assessment and shunning Pebble from the process. Additionally, the mine developers claim the agency had already determined it would use its 404(c) authority to prohibit a large mine on Pebble’s copper and gold claims before the multi-year assessment process officially began in 2011. The judge in that case, Judge H. Russel Holland, granted Pebble an injunction about a year ago, halting the 404(c) process until the suit is resolved. The EPA argues it met with Pebble representatives 30 times while drafting the assessment and that Pebble had additional opportunities to have its voice heard. The Federal Advisory Committee Act, or FACA, requires government agencies remain impartial and hold open meetings — published in the Federal Register — with both sides of contentious issues represented. Pebble Limited Partnership board of directors chair John Shively, a former Alaska Department of Natural Resources commissioner, said Nov. 5 at the Alaska Miners Association annual meeting in Anchorage that EPA Region 10 Administrator Dennis McLerran lied to him in a letter sent when the assessment began by claiming it was not aimed at stopping Pebble. Shively also asserted that the EPA lied to the public about how the movement to stop Pebble began. “I spent a fair amount of time in rural Alaska and I never believed that Tribal governments out in Southwest Alaska had any idea what Section 404(c) of the Clean Water Act was,” Shively said. Pebble insists it has evidence obtained through Freedom of Information Act Requests that prove the EPA helped draft the petition submitted by six Bristol Bay-area Tribes that urged the agency to invoke its 404(c) power and spurred it to begin the assessment. “Unfortunately, it appears that the Pebble mine project is another victim of this EPA’s extreme agenda,” Smith stated. “In fact, one of the former EPA employees who this committee found to have colluded with environmental groups to stop the Pebble mine project fled the country when Congress attempted to interview him.” The employee Smith referenced is former Kenai-based EPA biologist Phillip North, who was scheduled to be deposed in Anchorage Nov. 12 by Pebble and EPA attorneys. Pebble has said it believes North is in Australia, but his exact whereabouts are unknown. In an interview with the Redoubt Reporter published July 17, 2013, North said he planned on sailing around the world with his family after his retirement from the agency. The 364-page Cohen report supports Pebble’s claims. At the same time, groups opposed to the mine have hammered Cohen’s assertion that it is an independent document because Pebble Limited Partnership commissioned it. Former Republican Alaska Senate President Rick Halford testified to the House committee that before learning of Pebble he had never opposed a mine project. However, the size and location of the proposal by Pebble Limited Partnership forced him to take a stand against its development. “The size of the Pebble deposit is beyond imagination,” Halford said. “The pit would be well over a mile deep in places, and the footprint would cause the direct loss of between 24 and 94 miles of stream; 1,200 to 4,900 acres of wetlands; and 100 to 450 acres of ponds and lakes. The waste would be stored on site in perpetuity.” While not directly responding to Halford, Shively said Nov. 5 back in Anchorage that the impact of the mine has been vastly overblown. “The idea that you could build something (on) several thousand acres, with the kind of grade that we have — over 99 percent of what we take out of the ground is basically just dirt — how we could devastate a fishery is beyond me, but that’s what people have been told,” Shively said. He described the mines the EPA drafted as “fantasy mine plans.” Shively added that the EPA’s requirements for an acceptable mine in Bristol Bay are for a project that is uneconomically small. “(The EPA) designs mines that fail; we’re going to design a mine that succeeds,” he said. Halford also cited more than a dozen claims by Pebble that it would begin the federal permitting process, the first of which came in 2004. He called those claims “empty promises” to start the public review process which would bring resolution to the issue for area residents. Cohen’s report omits the fact that Pebble itself has been the only thing stopping the project from entering the National Environmental Policy Act review process, Halford said. Sen. Lisa Murkowski, who has been a harsh critic of the EPA under President Obama, also criticized Pebble back in 2013 for not releasing a formal mine plan that could be reviewed. Shively insisted Pebble Limited Partnership will enter the review process on its own timeframe, not the opposition’s timeframe. Halford added that the EPA’s involvement in evaluating what would be the largest open-pit mine in the country that would lead to obvious environmental impacts should not be a surprise. “As a resident of Bristol Bay, I can tell you that nothing seems predetermined to me in EPA’s actions,” Halford testified. “EPA collected information and data, met with and listened to both sides, and engaged in extensive outreach to all the stakeholders. I do not believe that EPA’s engagement itself was out of the ordinary as it is common for developers and the public to seek EPA’s perspective in advance of formal project initiation.” Elwood Brehmer can be reached at [email protected]

Final Interior gas decision by AIDEA approaches

FAIRBANKS — Interior Energy Project pitches were made to the Fairbanks public Nov. 4; now it’s up to the Alaska Industrial Development and Export Authority to pick the right project partner. IEP manager Bob Shefchik said he feels both goals of the meeting were accomplished: sharing the proposals from the project finalists with the community they hope to serve with natural gas, and verifying with the community that the process to select a viable private partner is moving forward. While the Interior Energy Project revolves around its namesake region, AIDEA’s public board meetings are held at the authority’s headquarters in Anchorage. Open seats at were hard to come by at Fairbanks’ Pioneer Park Civic Center when the three-hour open house started. Presentations were heard from four of the five IEP finalist teams. “We figure there were 150 people that showed up on a Wednesday night to listen to five PowerPoints, so that’s a good turnout,” Shefchik said in an interview. Hilcorp Energy’s LNG subsidiary Harvest Alaska was a last-minute scratch from the agenda. A Hilcorp spokeswoman declined to comment as to why the independent producer and IEP finalist was not represented at the Fairbanks meeting. Harvest Alaska’s proposal includes options to simply liquefy natural gas at a Southcentral plant for a tolling fee of $4.95 per thousand cubic feet, or mcf, of natural gas; provide a Cook Inlet gas supply and liquefaction for $12.25 per mcf; or deliver LNG to the Fairbanks “city gate” at $15 per mcf equivalent. Harvest wrote in its Sept. 3 proposal summary that the project could deliver either 3 billion cubic feet, or bcf, of gas per year or 6 bcf, and is planned with private financing, but using AIDEA’s IEP-dedicated grant-loan-bond package could lower those costs. The gas supply and all-in proposals include a 10-year contract with utilities. AIDEA’s IEP team plans to recommend a project partner to the authority board at its Dec. 3 meeting. Shefchik reminded those attending the Nov. 4 meeting that the goal is not only to lower energy costs in the Interior, but also to improve winter air quality, which is dangerously poor at times due to large numbers of Fairbanks and North Pole residents who heat their homes with wood, a cheaper option to fuel oil. The IEP will also provide a ready market if the Alaska LNG Project, or another large North Slope gasline project comes to fruition. Before either happens, he noted, AIDEA’s purchase of Fairbanks Natural Gas will lower natural gas prices by about 13 percent for the small group of area residents and businesses that are the utility’s customers by removing tax and profit obligations associated with the formerly private business. From there, the IEP will bring natural gas to more residents cheaper yet, if it ultimately meets the $15 per mcf “burner tip” price. “The goal with every step is to drop the price of gas incrementally until we can” get energy prices competitive with Anchorage, Shefchik, an Interior resident, said. The last step to get the Interior on par with Anchorage would be a large gasline. Phoenix Phoenix Clean Fuels LLC Chief Operating Officer Chris DeBerry was first to pitch his company’s plan. Phoenix Clean Fuels is a consortium of five companies: General Electric Oil and Gas, a LNG plant manufacturer; Alaska Industrial, a North Pole-based trucking company; TDX Power, which operates a North Slope electric utility; and Scimation and SLR, project management and engineering firms. “We’ve tried to pull together a team that can execute this project, not just the liquefaction, but from start to finish — get (LNG) to the city gate just to make AIDEA’s job easier and provide a clearer picture to customers of how the project works,” DeBerry said. All told, Phoenix is projecting a delivered LNG price of $9.65 per mcf equivalent from the North Slope, at least 25 percent cheaper than AIDEA’s first attempt at a North Slope gas trucking operation could achieve with MWH Global Inc. as it private partner. That price would allow for $4 to $5 to be added to the gas price for storage, regasification and distribution and still meet the $15 per mcf customer price goal. Phoenix plans to control transport costs through buying the LNG trailers outright, DeBerry said. GE’s liquefaction plant design is being used at 30 other places worldwide, he noted. “Everybody knows GE; it’s a household name,” DeBerry said. “GE has a modular plug-and-play solution that lends itself to a quick and easy installation in the harsh environment of the North Slope.” LNG plant capital costs were a major impediment to the first Interior Energy Project attempt, which began to fizzle out about a year ago. The GE plant would be assembled, broken down and shipped on 35 skids from a production facility in Texas. That mobility would allow Phoenix to use the plant other places on the Slope or around the world. There is little risk of it being a stranded asset if the state’s gasline wishes come true, according to DeBerry. Phoenix, and the other North Slope proponent Spectrum LNG, modeled prices with a gas feedstock price of $2.10 per mcf. That is the current price of natural gas — tied to oil prices — in an unused contract Golden Valley Electric Association has with BP for North Slope gas, according to Spectrum LNG CEO Ray Latchem. Indentifying the cheapest source of gas was Phoenix’s first task in developing its proposal, DeBerry said, and the roughly $4 per mcf premium for a Cook Inlet supply over the North Slope made the decision simple. The Phoenix operation could be up and running by September 2017 on the current IEP timeline, according to DeBerry. Salix Salix Inc., a subsidiary of Pacific Northwest utility company Avista Corp., is proposing a Cook Inlet liquefaction plant with a “cost of service” tolling fee, versus a firm price contract, Salix President Bob Lafferty said. “Our part is just the liquefaction part,” he said. A cost of service fee includes a utilities energy supply or generation cost, operation and maintenance expenses and a rate of return. Lafferty said the cost of service route provides transparency for customers. Salix projected an initial liquefaction cost of $2.87 per mcf in its proposal summary. The company also said it expects to enter into 20-year tolling service agreements with Interior utilities. Salix estimates first commercial projection in early 2018. Spectrum Spectrum LNG’s Latchem highlighted his company’s experience in the LNG arena. “We’re the only finalist that has produced LNG,” he said. Spectrum developed Fairbanks Natural Gas’ LNG supply chain in the late 1990s before selling the company and currently produces LNG for vehicle use in Arizona. Latchem said his company could produce North Slope LNG for $5.06 per mcf equivalent, leaving $10 available for trucking and distribution costs, while still meeting the project goals. He added that Spectrum would postpone its management fee for the first year of operation to keep retail costs down while a customer base is built. “Our commercial agreement with AIDEA would be a revenue requirement divided by how much the plant produces, so if we sell more LNG it doesn’t make our company any more money — what it does is it drops the unit price to the end users,” Latchem described. “It’s a simple enough deal; we just need to sell as much LNG as possible.” He added that Spectrum has negotiated a feedstock price of about $2.10 per mcf with ConocoPhillips as well, and he feels that price could ultimately drop lower yet. Spectrum could be ready to supply the Interior fairly quickly — in January 2017 — according to its proposal. WesPac WesPac Midstream LLC’s proposal would start with either a new LNG plant at Port MacKenzie, a project the company has been investigating for more than a year, or expansion of the Southcentral Titan LNG plant owned by AIDEA as part of the Fairbanks Natural Gas sale. WesPac is building LNG plants in Tacoma, Wash., and Jacksonville, Fla., to supply Totem Ocean Trailer Express, or TOTE, vessels with fuel. TOTE is in the midst of revamping its cargo ships that serve Anchorage and Puerto Rico to run on LNG. Both of WesPac’s Interior Energy Project LNG plant proposals include 500,000 gallons of on-site LNG storage, which could reduce the need for storage in Fairbanks or North Pole. Anchorage-based oil and gas attorney Jon Katchen, who represented WesPac at the public meeting, said the company chose a Cook Inlet gas source primarily because of the location, despite a higher feedstock price. WesPac also has a 100 percent working interest in a Cook Inlet gas reserve. “Perhaps the biggest advantage Cook Inlet provides is access to additional markets in the event demand doesn’t show up in Fairbanks,” Katchen said. WesPac has expressed interest to serve coastal Alaska communities with LNG, and demand there could help mitigate costs to Interior residents. WesPac pegged its final, delivered LNG price at $12.25 per mcf equivalent in its proposal summary and it could be operating by January 2018. More LNG capacity for Alaska Railroad The Alaska Railroad Corp. now has approval from the Federal Railway Administration to haul enough LNG to meet projected Interior Energy Project demand. In a Nov. 2 letter, the Railway Administration, or FRA, wrote that the Alaska Railroad’s expanded LNG transport authorization is for up to 12 portable tanks of LNG per train on up to three round-trip trains per week from Jan. 1, 2016, through the end of 2017. Beginning in 2018 and through 2020 the railroad can haul up to 60 tanks on one train every four days. The letter came less than a month after the FRA approved the Alaska Railroad for hauling eight, 11,000-gallon LNG tankers on up to two trains per week through two years. This first authorization would have allowed the railroad to prove its ability to transport LNG for the Interior Energy Project, but would not have met projected capacity needs once the project is up and running. The Alaska Railroad is the only railroad in the country approved to transport LNG. Alaska Railroad CEO Bill O’Leary said in an interview that the railroad went back to FRA and explained the situation after the first approval. The subsequent approval would allow the railroad to meet that need. “The governor (Bill Walker) was extremely helpful, as was our congressional delegation in emphasizing the importance of this” capacity increase to the FRA, O’Leary said. Moving LNG from Southcentral to the Interior by rail could potentially cut transportation costs for the IEP by more than 50 percent over the cost of trucking the fuel, according to railroad estimates. However, LNG by rail would add complexities to what is already a challenging logistical project.

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