Elwood Brehmer

Plan for Southeast alternative fuel revived with propane

Alaska has a love affair with natural gas, but Frank Avezac says rural areas of the state should at least consider a date with its little sister, propane. Avezac is CEO of Alaska Intrastate Gas Co., a startup utility that March 4 announced plans to provide 17 coastal communities — from Kodiak to Metlakatla — with propane as an alternative to fuel oil with construction starting as soon as this year. The aggressive proposal by Alaska Intrastate Gas Co. would start in Cordova with infrastructure buildout in 2016 and then move to Juneau, Valdez and Ketchikan. Residents of the communities planned for gas development could see fuel cost savings of up to 30 percent from a switch from fuel oil to propane for space heat, according to Alaska Intrastate Gas Co. The full list of communities Alaska Intrastate Gas hopes to serve includes Kodiak, Valdez, Cordova, Yakutat, Klukwan, Haines, Skagway, Juneau, Angoon, Sitka, Kake, Petersburg, Wrangell, Klawock, Craig, Ketchikan and Metlakatla. Larry Head, vice president of power and energy for Alaska Intrastate Gas’ global engineering partner AECOM, said both the physical and market characteristics of propane make it a better option for remote Alaska communities. “The capital cost for producing, shipping and storing LNG is many times higher than that of propane,” Head said. Propane is a byproduct of sorts in natural gas reserves. It is typically separated from the methane that is pure natural gas. Cook Inlet’s natural gas is “clean” or “dry” gas, meaning it is almost pure methane, while North Slope natural gas is “dirty,” with a host of vapor fuels and carbon dioxide that must be pulled off before the gas can be shipped and sold. The project would buy Canadian propane and barge it from Prince Rupert to the coastal towns at a delivered price of about $1.10 per gallon to $1.30 per gallon, up to 50 percent cheaper than delivered LNG, according to Head. At that point, the vaporized propane would be mixed with air to produce a blended gas known as syngas, which has virtually the same burn characteristics as natural gas, he said, meaning the two can be used interchangeably in distribution pipes and appliances. The advantages of propane over LNG for small-scale use “go on and on,” Head said. Natural gas has to be chilled below minus-260 degrees Fahrenheit to make it LNG for ease of transport. When done on a small scale, the liquefaction process can add $2-$3 per gallon to the cost of LNG. Propane, on the other hand, liquefies at minus-44 degrees and can be kept liquid at warmer ambient temperatures for transport with relatively little compression. It has also historically been cheaper than diesel, or fuel oil, on an energy equivalent basis, Head said, and likely always will be because there just aren’t enough backyard grills to use it all. Delivered fuel oil is selling in small quantities for about $2.60 per gallon in Cordova, according to vendors. “Right now there’s a major glut of propane and there’s going to be a major glut for many years ahead because there’s not outlets for its use,” he said. Cordova was chosen as the starting point for the project because its fish processing facilities can act as market anchor tenants to supply the base demand needed to make the development of propane and propane accessories economically viable from the get-go, according to Head. “Our analysis shows we don’t need heavy adoption, we simply need the anchor clients to sign up and then residential clients will be provided, based on their interest in having a change-over (from fuel oil),” he said. Commitments to convert from a majority of residents and small businesses will likely be needed in the smallest communities without large anchor market tenants, Head added. Changing home heating systems from fuel oil to propane or natural gas can cost as little as $1,000 to $1,500 for newer boilers, in which just the burner must be replaced, or up to nearly $10,000 for a complete replacement boiler. The project has tentative agreements with fish processors in Cordova to buy gas that should be finalized soon, Head said. The first step is getting the infrastructure in place. “Right now, all we want to do is get pipe in the ground, because without pipe getting in the ground you’re never going to bring any type of gas to anybody,” Avezac said in an interview. Outgoing Cordova Mayor Jim Kasch said Alaska Intrastate Gas first came to Cordova with a plan to supply LNG nearly 10 years ago when energy prices in Alaska were at record highs. At that time, the claim was natural gas for half the cost of fuel oil, he said. The Cordova City Council approved a land sale to the utility for a landing facility, but the deal was rejected in a public vote. Kasch was on the city council when the people of Cordova rejected the deal. This time, Kasch said he was first made aware of the revived plan March 7 and sees it as a “cart before the horse scenario,” because Alaska Intrastate Gas and AECOM have yet to apply for permits to build the necessary storage, vaporization and distribution infrastructure while wanting to start building this year. “If they can do something to mitigate (high energy costs) and reduce the cost of daily life here in rural Alaska, boy, I’m all for it but they need to sell themselves to the communities where they plan on doing this and I’ve yet to see that,” Kasch said. Avezac said the holdup on the land sale years ago was opposition to filling in tidelands, which Alaska Intrastate Gas doesn’t intend to do this time around, not an opposition to the overall plan. “We’ve never met anybody that doesn’t want gas, ever,” he said. As for working with the city, Head said, Alaska Intrastate Gas has certificates of public necessity and convenience that give the utility access to right-of-ways for piping, and while permit applications have not been filed, discussions have been had and he sees no issues in getting the paperwork squared away. He said further information about project financing and detailed construction timelines would be made public soon. Elwood Brehmer can be reached at [email protected]

Enstar, Hilcorp ink gas deal to 2023

The eventual return to a free Cook Inlet natural gas market is looking good for consumers as the latest round of gas supply contracts are signed by utilities. Enstar Natural Gas Co. has reached a deal with Hilcorp Energy to fuel the lone Southcentral gas utility through March 2023 at prices more favorable than those outlined under the Consent Decree that regulates Inlet gas contracts through 2017. Filed with the Regulatory Commission of Alaska Feb. 29, the gas sale and purchase agreement between Enstar and Hilcorp would kick in April 1, 2018, at an average price of $7.56 per thousand cubic feet, or mcf, for firm gas deliveries. That would amount to a 9.2 percent price decrease compared to contracts under Consent Decree terms that will expire at the end of March 2018 — an overall $14 million savings in the first year. Enstar Vice President and General Counsel Moira Smith said that savings will be passed on directly to utility’s customers. “It’s a nice discount off of Consent Decree prices,” Smith said in an interview. “We thought it was a big win for our customers.” The firm gas price at then end of the deal in 2023 is $8.19 per mcf. The tentative agreement, which is subject to RCA approval, also calls for an annual 2 percent price increase, versus the 4 percent yearly escalation allowable under the Consent Decree. The Consent Decree is the deal reached by the Attorney General’s office and Hilcorp in late 2012 that set price caps for Inlet gas contracts from 2013 through 2017, thus allowing Hilcorp to purchase gas and oil interests from Marathon and Chevron and become the majority gas supplier in the basin. At more than 22 billion cubic feet, or bcf, per year, Hilcorp would supply about 70 percent of Enstar’s projected demand under the contract — a demand forecast that is flat at 33 bcf for the foreseeable future. Smith said Enstar’s customer base grows a little more than 1 percent a year, but increasingly energy efficient homes using less natural gas offsets new customer demand. Regional electric utilities that use natural gas as a primary fuel source have made similar comments regarding their own demand forecasts. Last year Chugach and Homer electric associations signed gas supply contracts extending beyond 2017 at prices below Consent Decree prices as well. Enstar was able to combine firm, base delivery and peak volume demand prices in the deal, which will cover for contacts of each type the utility had with Hilcorp that are expiring in 2018, according to Smith. Higher prices for peak demand purchases make the yearly average gas prices about 15 cents per mcf higher than the base gas prices paid by Enstar under the agreement. Utilities typically hunt hard for the longest-term contracts they can to provide customers with security of fuel supply, but there were other factors that led to the five-year term. “Our goal was to get some stability and five years gives us some stability while simultaneously allowing other producers time to get on their feed and get some real production up and going and also allow room for a (pipe)line from the North Slope that we could purchase from,” Smith said. “It was not Hilcorp saying they did not want to negotiate for more than five years.” If seen to fruition on its current schedule, the Alaska LNG natural gas export project would begin shipping North Slope gas to Southcentral in late 2024 or 2025.

IEP moves ahead with Inlet gas plan

The Interior Energy Project took a big step forward Thursday when the Alaska Industrial Development and Export Authority announced it is negotiating with a sole project partner to supply Cook Inlet natural gas to the Fairbanks area. IEP Manager Bob Shefchik said to the AIDEA board that the proposal by Salix Inc. to build a small natural gas liquefaction facility on Point MacKenzie in the Matanuska-Susitna Borough is the best option for the project as it faces viability challenges brought on by low oil prices. Salix is the last standing of 13 companies that offered 16 ideas to get an alternative space heating energy source to the Interior in response to a June request for proposals, or RFP, issued by the state authority. According to a third-party analysis of Salix’s proposal by the global consulting firm Arcadis Inc., the plan for a $68 million, 3 billion cubic feet per annum natural gas liquefaction plant should equate to gas delivered to Interior customers for $15.74 per thousand cubic feet, or mcf. That price would nearly meet the project’s stated goal of $15 per mcf, which is roughly the energy equivalent price of $2 per gallon fuel oil. Salix and Spectrum LNG, a small Oklahoma-based LNG company with a North Slope-sourced proposal, were the finalists in the RFP process started this summer. Salix is a subsidiary of Avista Corp., a Spokane, Wash.-based utility company that operates electric and natural gas utilities in Idaho, Oregon and Washington. Avista also purchased Juneau’s Alaska Electric Light and Power Co. in 2014. AIDEA’s first attempt at the project in 2014 was limited to North Slope gas by legislation passed in 2013 that funded the project with $332.5 million with primarily low-interest loan and bond authority, as well as a $57 million grant appropriation. The ability for Cook Inlet producers to supply another market long-term was unclear at that point, but the Inlet’s available gas reserves have grown since, as new companies have entered the market. Hilcorp Energy’s work on existing gas fields has also improved the situation. Shefchik noted the unavoidable reality of high capital costs on the Slope as a main reason for moving forward with Salix over Spectrum. That was evidenced in the first IEP go-round, which was scrapped by the authority just prior to making an investment decision because construction costs for a larger plant kept final projected gas prices in the $18 per mcf and higher range — too high to continue. Now, oil in the $30 per barrel range has pushed fuel oil down to the $2 per gallon range, challenging the IEP from any gas source, as potential customers are less likely to make upfront investments to convert to natural gas. However, Shefchik said the energy price reprieve has also given AIDEA the time to develop a project durable across a range of energy prices rather than rushing to complete a less optimal solution. Besides the economic benefits of a potentially lower- and stable-cost energy supply, a successful Interior Energy Project would significantly improve the region’s winter air quality — some of the worst in the country due to low-level atmospheric inversion that occurs in the area and traps wood smoke and emissions from fuel oil furnaces. Detailed negotiations with Salix are ongoing, according to Shefchik, and an official recommendation from the AIDEA board to continue with Salix as a partner is expected at its March 31 meeting.   Look for updates to this story in an upcoming issue of the Journal. Elwood Brehmer can be reached at [email protected]

Bleeding cash, still exploring on the North Slope

It might not be a great time to be an oil company, but independents across Alaska are saying “the show must go on” through their exploration and development work this winter. One of the newest players on the North Slope, Australia-based junior 88 Energy Ltd. announced Feb. 29 that positive results from its first well Icewine No. 1 have led the company to start a two-dimensional seismic survey this month. 88 Energy plans to drill a second, horizontal exploration well, Icewine No. 2H, this year on its leases south of Prudhoe Bay, according to a company release. 88 Energy Managing Director Dave Wall said in a statement the results from Icewine No. 1 met and exceeded expectations. The well was spudded Oct. 15. “As a consequence of these continued good results, we have tailored our seismic acquisition to focus on mitigating risk for the next well,” Wall said. The company is focused on shale plays in the Icewine prospect. It is estimated to hold a mean unconventional resource of 492 million barrels, according to investor reports. Anchorage-based Great Bear Petroleum is also exploring shale prospects just north of Icewine. 88 Energy and its minority partner Burgundy Xploration of Houston began acquiring leases on the central North Slope in November 2014. The partnership will hold more than 270,000 acres of state leases about 35 miles south of Prudhoe once its 2015 lease sale awards are final, 88 Energy states. An existing gravel road off the Dalton Highway makes the area accessible for year-round work. The lease position is also bisected by the trans-Alaska Pipeline System, providing easy access to markets should Icewine be seen through to production. 88 and Burgundy are working under the joint venture Accumulate Energy. Wall said the 2-D seismic program will give a broader picture of the acreage and should identify any large conventional features that would be economic at lower oil prices. 88 Energy had first planned for a 3-D seismic program to follow drilling of Icewine No. 1. While Alaska North Slope crude is currently selling for just more than $30 per barrel, it is costing producers about $46 per barrel to extract and ship to market, according to the state Department of Revenue. The cost for Icewine No. 1 came in on budget at $16.1 million, according to 88 Energy, and was drilled by Kuukpik Drilling’s Rig 5. Overall, the budget for both wells and the seismic program is projected at $60 million to $75 million. The State of Alaska is expected to cover upwards of 75 percent of the exploration costs through its refundable tax credit incentive program, according to 88 Energy. To the north, Dallas-based Caelus Energy is digging into the remote Smith Bay prospect, which holds “true billion-barrel potential,” according to the company. Smith Bay is about 150 miles northwest of Prudhoe, far west of the developed areas of the Slope. Alaska Division of Oil and Gas Director Corri Feige said in a Feb. 24 House Resources Committee hearing that Caelus has shifted attention from its Nuna development this winter and is currently drilling the second of two exploration wells at Smith Bay from a grounded, shallow water ice pad. Caelus’ Nuna project is progressing on schedule to meet an October 2017 deadline for first oil agreed to in a royalty modification deal with the state, Feige said. At its adjacent producing Oooguruk Unit, development is continuing. “Caelus has done a lot of work recently to optimizing the frack and to optimize their recovery and increase production from those wells,” Feige said. All of Caelus’ work on the Slope is using fracking techniques. Oooguruk has produced about 23 million barrels since 2008. Arctic Slope Regional Corp.’s exploration subsidiary AEX also spudded the Placer No. 3 well in late January, Feige said. The Placer Unit just west of the large Kuparuk Field. Placer No. 3 will delineate a reservoir first explored with Placer No. 1 and No. 2 wells drilled by other companies in 2004, according to an ASRC release. Feige said the exploration work by a range of small and mid-sized independents, on top of continued infill drilling being done by the “big three” producers reveals the strength companies still see in Slope prospects. “I think fundamentally what this tells us is that the industry still views the resource endowment (on the Slope) and the environment of investing in Alaska as being a good place to be,” she said. To the large producers, Feige said BP continues to be “very aggressive” at expanding and maintaining production from Prudhoe Bay, while ConocoPhillips is in the midst of drilling eight new wells at its CD5 development this year. Production from the $1.1 billion CD5 development started ahead of schedule in October. ConocoPhillips spokeswoman Natalie Lowman said early production has met expectations, while the reservoir quality beneath part of the development exceeded expectations. Peak production from CD5 is estimated at 16,000 barrels per day. The $4 billion Point Thomson natural gas development led by ExxonMobil is also on schedule to meet its mid-May production deadline, Feige said. Natural gas liquids should begin flowing from the eastern Slope project to TAPS in early May, she said. BP is a minority owner in the large Point Thomson gas field, which is a lynchpin to the Alaska LNG Project. Elwood Brehmer can be reached at [email protected]

DOD to spend $325M on Clear missile defense radar

Another big chunk of the roughly $1 billion the Defense Department is spending to upgrade the country’s missile defense system is headed to Alaska. Missile Defense Agency Director Vice Admiral James Syring said Feb. 23 to during a presentation to the Fairbanks Chamber of Commerce that more than $325 million will be spent at Clear Air Force Station over the next six years to install a new power plant and missile detection radar. Clear Air Force Station is a radar base located near Nenana along the Parks Highway southwest of Fairbanks. Much of the construction spending will begin in 2017, Syring said, when $155 million of work on the mission control facility and related infrastructure is started. In 2019, another $150 million will be spent on the station’s new power plant and fuel storage facilities. This year, the Missile Defense Agency plans to spend about $25 million building a 350-person man camp and decommissioning the Ballistic Missile Early Warning System, among other things, Syring said. That work will be contracted through the Alaska District of the U.S. Army Corps of Engineers. Syring said he expects much of it will be done by local contractors. Long Range Discrimination Radar, or LRDR, being developed by Lockheed Martin in New Jersey, will replace the early warning system. The LRDR will then be shipped to Alaska and installed at Clear. Syring said the man camp will be used from 2017 to 2021, with peak occupancy in 2019. Clear Air Force Station is on the electrical grid; however, the upgraded power plant is a backup facility that will be protected against electromagnetic pulse weapons that could be used to render electrical systems useless, Syring explained. “Everything we are doing here in Alaska is to expand our defense against that North Korea threat,” he said. Early in 2013 the Pentagon announced plans to add 14 interceptors to the 26 currently installed at Fort Greely near Delta Junction by 2017. Those interceptors are the country’s main defense against the intercontinental ballistic missile (ICBM) threats primarily coming from North Korea and Iran, according to Syring. He said the impetus for adding interceptors to Greely was a rocket launched into orbit by North Korea in 2012. A similar test several weeks ago demonstrated the temperamental country still has the capability to reach orbit and is still pursuing an ICBM feet. Repeating nearly every Defense official who references Alaska, Syring noted the state’s global position as key to its role in the missile defense program. “Why we are here is (Alaska’s) strategic and geographic location and there’s no two ways about it,” he said. Army Chief of Staff General Mark Milley said to Sen. Lisa Murkowski in testimony before a Senate committee Feb. 24 that he wants to delay a force reduction from Joint Base Elmendorf-Richardson planned for 2017 by at least a year because of increasing threats — North Korea included — in the North Pacific. Milley cited the ability of Alaska forces to reach East Asia within hours of deployment as a primary reason for keeping strong military resources in the state. Elwood Brehmer can be reached at [email protected]

Tax credit changes show unpredictability, consultant says

A consultant to the Legislature reviewed the oil and gas tax credit changes proposed by Gov. Bill Walker and concluded the State of Alaska needs one thing above all else: fiscal stability. Janak Mayer, chairman of the petroleum industry consultant firm Enalytica, said in a marathon session of presentations before the House Resources Committee Feb. 25-27 that the administration’s proposals to reduce state expenses and increase revenue are not individually drastic. However, they collectively make significant changes to the industry-favored tax structure known as Senate Bill 21 that was implemented less than three years ago. “It is said over and over again, but stability is the most important element in any fiscal system,” Mayer said. House Bill 247, the administration’s bill to change Alaska’s oil and gas credits, is not a tax policy overhaul, but incremental changes to the credits with the goal of more revenue could give industry the impression the state is headed down a “slippery slope” of tax tweaks, he said. Collectively, Mayer said the small tax changes would likely have a significant adverse impact on producers, particularly at the low oil prices of today’s market. Soldotna Republican Kurt Olson commented that the Legislature changes oil tax policy virtually every two years. “That’s not (HB) 247’s fault, it’s just the newest one,” Olson said. The Alaska Oil and Gas Association contends the bill amounts to drastic changes in the state’s oil tax system that will directly impact production and investment if enacted. Walker’s suite of oil tax revisions was introduced along with tax increases on other prominent industries as part of an overarching fiscal plan to pull the state out of annual budget deficits that have grown to more than $3.5 billion as fast as the price of oil fell to the current $30 per barrel range. The tax changes include raising the minimum production tax rate from 4 percent to 5 percent, as well as “hardening” the tax floor to prevent companies from claiming losses against tax liabilities in order to pay less than the minimum tax. Among closing other loopholes, HB 247, and its companion legislation Senate Bill 130, would limit the amount of money the state pays out to explorers and producers each year by setting a refundable credit limit of $25 million per company per year. Refundable credits can be applied to tax liability, sold to another company with a liability or cashed in to the state, resulting in a direct expense for the state. Walker deferred — through a partial veto — $200 million of a $700 million line item in the 2016 budget for the state’s projected refundable credit obligation this fiscal year. That action was meant to start a conversion about the expensive subsidy program, Walker said, and it did. At the same time, the veto is alleged by those in industry to have scared potential private investors and killed some deals in the state that were dependent on the credits as collateral for additional financing. The state’s payout of refundable credits peaked in fiscal year 2015, with more than $400 million paid to companies working in Cook Inlet and another $224 million going to North Slope operators, according to the Department of Revenue. If passed as proposed, HB 247 would cut the annual credit outlay to about $200 million and generate about $100 million per year in additional tax revenue, the administration has said. Of the eight tax credits that would continue beyond 2016 under current law, five are refundable; the remaining three are non-transferrable credits that can only be used by North Slope producers. HB 247 would eliminate two of the refundable capital expenditure credits available for companies working in Cook Inlet. The loopholes the governor’s bill attempts to close are mostly related to what have been described by legislators as unintended consequences of SB 21’s credit provisions, which were not modeled for fiscal impacts at oil price regimes below about $60 per barrel when it was being debated. One of Walker’s changes would prevent the state from covering more than 100 percent of a North Slope operator’s losses for producing new oil during times of low prices, which could occur if the Gross Value Reduction for new oil and the Net Operating Loss credits are combined. Mayer, who helped the Legislature scrutinize SB 21, said he was surprised to learn of the possibility for the state to pay more than a company’s loss through the combined credits, but the bigger issue is again how many statutory cracks lawmakers try to fill at once. “There are a number of things in (HB 247) that are really important questions to be thinking about,” Mayer said. “It’s some of the specific solutions and the incremental nature of what’s being proposed that I have the biggest worry about.” He testified Feb. 25 that on top of Alaska being an innately high-cost place of business for oil companies, the state’s near total dependence on the industry for revenue makes it a more risky business environment. When in need of cash, Alaska is more likely to turn to the industry for concessions than other state’s or countries that have an oil and gas sector as part of a more diversified economy, he reasoned. Additionally, Alaska’s overall industry tax structure combines tax systems kept separate in other jurisdictions. The state’s mineral royalty acts as a steady, regressive gross tax often used by resource-dependent governments to provide income during low price cycles, Mayer said, while the more volatile and net production tax — on its own — gives producers a break at low prices but captures more revenue during profitable periods through progressivity. Another issue of concern is the July 1, 2016 effective date for most of the provisions in the bill, according to Mayer. He said immediately changing the credit system could significantly impact exploration and development plans that have already been drafted. The Oil and Gas Tax Credit Working Group led by Sen. Cathy Giessel, R-Anchorage, recommended to harden the minimum tax floor, as the administration wants to do, but also noted that any changes to the system be made gradually. Cook Inlet Cutting Cook Inlet tax credits wouldn’t generate new revenue, as no production tax is collected on the basin’s oil and its natural gas production tax would not be impacted. Eliminating the capital and drilling credits would save the state money, but what effects that would have on an out-of-step gas market needs to be considered, Mayer and Enalytica President Nikos Tsafos said. The 2010 Cook Inlet Recovery Act, passed by the Legislature to encourage natural gas development, among other things, instituted a 40 percent drilling and exploration credit that HB 247 would cut. The reliability of Southcentral’s natural gas supply has improved since the passage of the act when fears of gas shortages abound, but the act contributed to distorting the isolated market, according to Mayer and Tsafos. Further complicating matters is the Consent Decree that Hilcorp Energy and the state agreed to in 2012, which allowed Hilcorp to purchase a vast majority of the producing assets in the Inlet, but also set gas prices on most utility contracts through early 2018. The prices laid out by the Consent Decree are in the $6-$8 per thousand cubic feet, or mcf, of gas. Recent contracts for gas supply beyond 2018 have been at slightly lower prices than the Consent Decree, evidence that some natural market forces may at play. A simple lack of demand for Cook Inlet natural gas has put nearly everyone involved in a bind. As Henry Hub-based natural gas prices have fallen in the Lower 48 to about $2 per mcf in recent years and worldwide LNG prices have fallen as well, Cook Inlet has become one of the most expensive natural gas markets in the world. High gas prices and tax credits have undoubtedly incentivized new investments and helped turn Inlet production around — and secured Southcentral’s primary energy source — but the whole situation has led to unsustainable state expenses that won’t be recovered under the current system, according to Mayer. The credits, combined with the lack of a significant production tax, has led to Cook Inlet being one of the most generous fiscal regimes for oil and gas in the world, he said, with about 40 percent total government take. Still, companies are only able to manage about a 10 percent to 15 percent return on investment because the volume of gas they can sell is basically capped with limited exports and no major industrial anchor customer. “The basic impact of the credits is to make what is a very marginal investment maybe just possible,” Mayer said. While it’s time for the state to have a “serious conversation about what the state’s policy aims are” through the Cook Inlet credits, he added that eliminating the capital credits July 1 “seems like a rash decision.” Tsafos suggested — now that the Inlet can supply Southcentral for at least 10 years based on Department of Natural Resources reserve estimates — allowing market forces to return as much as possible in the coming years as the Consent Decree expires. “The broad instinct should be rather than try to artificially prop up a market that isn’t working, it’s to try to think more generally about how do we make this market work better,” Tsafos said. Rep. Mike Hawker, R-Anchorage, a sharp critic of many provisions in HB 247, said the state should be careful to not disrupt the Cook Inlet gas market further through credit changes because it will change the Consent Decree’s current March 2018 expiration.

Budget deficit hits state energy programs, rebates cut

Belt tightening throughout the State of Alaska has reached the Alaska Housing Finance Corp. The state-founded lending agency announced Feb. 24 it will suspend its popular Home Energy Rebate Program at the close of business March 25 due to lack of funding. Applications for energy efficiency improvement funding will be accepted through the late-March date; however reimbursement will be subject to available funds in addition to applicant qualifications. The program held about $5 million as of last December, according to AHFC Director of Public Affairs Stacy Schubert. While AHFC’s primary mortgage business is self-sustaining and it returns an annual dividend to the state General Fund each year, the quasi-government entity also manages programs related to its business for the state when directed by the Legislature. The Home Energy Rebate Program was last funded by the Legislature with an $18.5 million appropriation in fiscal year 2015, which ended in June 2014, just prior to the start of oil’s precipitous price slide. Overall, the program has received $252.5 million since its inception in 2008. According to AHFC, about 40,000 families have completed an initial energy audit to determine qualifying energy efficiency upgrades to their homes. More than 24,500 families completed improvements to existing structures and received rebates averaging $6,463. Another 3,200 households received rebates for new homes built to the six-star efficiency, the highest level of the U.S. Department of Energy’s Energy Star rating system. AHFC Executive Director Bryan Butcher said in a statement that a broad spectrum of Alaskans benefited from the Legislature’s investment in the program beyond just the homeowners. “Independent studies by the University of Alaska’s Institute for Social and Economic Research, Cold Climate Housing Research Center and others have shown increased technical job skills and the program saved an equivalent of 18,104,986 gallons of No. 2 fuel oil, buoying local economies and helping bridge the natural gas shortfall experienced in Southcentral during the brownout practices in 2009 and 2010,” Butcher said. Hopeful participants eligible for a rebate have up to 18 months after the home energy rating audit to complete the qualifying improvements. The maximum rebate for each home is $10,000. The direct rebate program may be coming to an end, but AHFC’s longstanding Home Energy Loan Program is alive and well, Schubert said. Under the loan program, borrowers with a mortgage through the corporation can apply for up to a $30,000 loan on a maximum 15-year term to pay for energy efficiency upgrades at low rates. As of Feb. 26, the interest rate on an AHFC Home Energy Loan was 3.375 percent. In the first seven months of the 2016 fiscal year AHFC financed 87 energy efficiency “add-on” loans, which is nearly an identical activity level to the comparable 2015 period, according to Schubert. Renewable Energy Fund cut Gov. Bill Walker turned to the Alaska Energy Authority’s Renewable Energy Fund for savings in his amended 2017 fiscal year budget proposal. The governor cut out a $5 million General Fund appropriation for the fund that he had included in his first 2017 budget submitted in December. Each year the governor is required to draft an initial budget proposal for the Legislature by mid-December. Governors then have until mid-February to make changes to their first proposal. Budget Director Pat Pitney wrote to the Legislature’s Finance committees in a Feb. 16 letter, explaining that the administration would not be opposed to funding the Renewable Energy Fund through sources other than the General Fund. AEA spokeswoman Emily Ford wrote in an email that there would be unintended consequences to eliminating the full $5 million appropriation. Doing so would impact to the authority’s ability to staff and manage the existing 133 active Renewable Energy Fund grants that total $131 million of state investment for ongoing projects, according to Ford. The authority is working with the Office of Management and Budget to restore $2 million in receipt authority for the fund through the legislative process. That would allow AEA to administer the ongoing Renewable Energy Fund grants, she wrote. With $271 million in total commitments from the Legislature, the Renewable Energy Fund has helped complete 54 projects across the state since its inception in 2008. Those projects, with a total cost of about $500 million, have generated more than $1.2 billion in benefits to local communities, according to AEA. The fund got an $11.5 million appropriation in the current 2016 fiscal year budget passed last spring. AEA had recommended seven Renewable Energy Fund applications for funding up to the first-presumed $5 million limit for future projects in its latest round nine of fund activity. The authority received 52 applications for the current round of program funding. Recommended grant applications are ranked each year based on numerous criteria including project cost, cost-benefit ratio, and available applicant matching funds. The projects are then funded based on ranking and the amount of funding made available by the Legislature. Elwood Brehmer can be reached at [email protected]

TAPS value settled at $8B for 5 years

The next court battle over the value of the Trans-Alaska Pipeline System won’t be for at least another five years. Two settlements over the taxable value of TAPS between the State of Alaska, its owners, and municipalities along the pipeline corridor were announced March 1. The agreements fix the value of the 800-mile pipeline, for property tax purposes, at $8 billion through 2020, according to a release from the North Slope Borough. All pending litigation in Alaska courts regarding TAPS value will be dismissed as part of the deals as well. North Slope Mayor Charlotte Brower thanked the Walker administration for the state’s help in reaching the linked deals. “By fixing the value of the Trans-Alaska Pipeline System for the next five years, this agreement will provide a more stable and predictable budget environment and help ensure the financial security of the borough moving forward,” Brower said in a statement. “It also brings an end to the need for continuous litigation in which the borough and other municipalities have spent a decade and millions of dollars to obtain a fair valuation of TAPS.” Under the deals for property tax years 2007 through 2015, the North Slope Borough will repay the state nearly $7.6 million and the City of Valdez will pay $7.3 million back to the State of Alaska for prior tax payments the state believes were in excess of the statutory cap on property tax revenues, according to a statement from the Department of Law. The pipeline is primarily owned by subsidiaries of BP, ConocoPhillips and ExxonMobil. Unocal Pipeline Co. owns a 1.3 percent share of TAPS, according to Alyeska Pipeline Service Co., the pipeline operator. In May 2014, the State Assessment Review Board valued TAPS at $10.2 billion. At the time, the owners estimated its value at $2.7 billion; the municipalities pegged the value at $13.7 billion; and the Department of Revenue suggested $5.7 billion as the taxable value for the year. The proper value of the pipeline and subsequent property tax rates has been a source of legal contention for the Valdez and the North Slope and Fairbanks North Star boroughs for many years. Coincidentally, the pipeline cost $8 billion to build in 1977 and was the world’s largest privately funded construction project at that time. Elwood Brehmer can be reached at [email protected]

TAPS value settled at $8B for 5 years

The next court battle over the value of the Trans-Alaska Pipeline System won’t be for at least another five years. Two settlements over the taxable value of TAPS between the State of Alaska, its owners and municipalities along the pipeline corridor were announced March 1. The agreements fix the value of the 800-mile pipeline, for property tax purposes, at $8 billion through 2020, according to a release from the North Slope Borough. All pending litigation in Alaska courts regarding TAPS value will be dismissed as part of the deals as well. North Slope Mayor Charlotte Brower thanked the Walker administration for the state’s help in reaching the linked deals. “By fixing the value of the Trans-Alaska Pipeline System for the next five years, this agreement will provide a more stable and predictable budget environment and help ensure the financial security of the borough moving forward,” Brower said in a statement. “It also brings an end to the need for continuous litigation in which the borough and other municipalities have spent a decade and millions of dollars to obtain a fair valuation of TAPS.” Under the deals for property tax years 2007 through 2015, the North Slope Borough will repay the state nearly $7.6 million and the City of Valdez will pay $7.3 million back to the State of Alaska for prior tax payments the state believes were in excess of the statutory cap on property tax revenues, according to a statement from the Department of Law. The pipeline is primarily owned by subsidiaries of BP, ConocoPhillips and ExxonMobil. Unocal Pipeline Co. owns a 1.3 percent share of TAPS, according to Alyeska Pipeline Service Co., the pipeline operator. In May 2014, the State Assessment Review Board valued TAPS at $10.2 billion. At the time, the owners estimated its value at $2.7 billion; the municipalities pegged the value at $13.7 billion; and the Department of Revenue suggested $5.7 billion as the taxable value for the year. The proper value of the pipeline and subsequent property tax rates has been a source of legal contention for the Valdez and the North Slope and Fairbanks North Star boroughs for many years. Coincidentally, the pipeline cost $8 billion to build in 1977 and was the world’s largest privately funded construction project at that time.   Elwood Brehmer can be reached at [email protected]

Budget deficit hits state energy programs

Belt tightening throughout the State of Alaska has reached the Alaska Housing Finance Corp. The state-founded lending agency announced Feb. 24 it will suspend its popular Home Energy Rebate Program at the close of business March 25 due to lack of funding. Applications for energy efficiency improvement funding will be accepted through the late-March date; however reimbursement will be subject to available funds in addition to applicant qualifications. The program held about $5 million as of last December, according to AHFC Director of Public Affairs Stacy Schubert. While AHFC’s primary mortgage business is self-sustaining and it returns an annual dividend to the state General Fund each year, the quasi-government entity also manages programs related to its business for the state when directed by the Legislature. The Home Energy Rebate Program was last funded by the Legislature with an $18.5 million appropriation in fiscal year 2015, which ended in June 2014, just prior to the start of oil’s precipitous price slide. Overall, the program has received $252.5 million since its inception in 2008. According to AHFC, about 40,000 families have completed an initial energy audit to determine qualifying energy efficiency upgrades to their homes. More than 24,500 families took the next step, completed the improvements and received rebates averaging $6,463 to existing structures. Another 3,200 households received rebates for new homes built to the six-star efficiency, the highest level of the federal Department of Energy’s Energy Star rating system. AHFC Executive Director Bryan Butcher said in a statement that a broad spectrum of Alaskans benefited from the Legislature’s investment in the program beyond just the homeowners. “Independent studies by the University of Alaska’s Institute for Social and Economic Research, Cold Climate Housing Research Center and others have shown increased technical job skills and the program saved an equivalent of 18,104,986 gallons of No. 2 fuel oil, buoying local economies and helping bridge the natural gas shortfall experienced in Southcentral during the brownout practices in 2009 and 2010,” Butcher said. Hopeful participants eligible for a rebate have up to 18 months after the home energy rating audit to complete the qualifying improvements. The maximum rebate for each home is $10,000. The direct rebate program may be coming to an end, but AHFC’s longstanding Home Energy Loan Program is alive and well, Schubert said. Under the loan program, borrowers with a mortgage through the corporation can apply for up to a $30,000 loan on a maximum 15-year term to pay for energy efficiency upgrades at low rates. As of Feb. 26, the interest rate on an AHFC Home Energy Loan is 3.375 percent. In the first seven months of the 2016 fiscal year AHFC financed 87 energy efficiency “add-on” loans, which is nearly an identical activity level to the comparable 2015 period, according to Schubert.   Renewable Energy Fund cut Gov. Bill Walker turned to the Alaska Energy Authority’s Renewable Energy Fund for savings in his amended 2017 fiscal year budget proposal. The governor cut out a $5 million General Fund appropriation for the fund that he had included in his first 2017 budget submitted in December. Each year the governor is required to draft an initial budget proposal for the Legislature by mid-December. Governors then have until mid-February to make changes to their first proposal. Budget Director Pat Pitney wrote to the Legislature’s Finance committees in a Feb. 16 letter explaining the budget changes that the administration would not be opposed to funding the Renewable Energy Fund through sources other than the General Fund. AEA spokeswoman Emily Ford wrote in an email that there would be unintended consequences to eliminating the full $5 million appropriation. Doing so would impact to the authority’s ability to staff and manage the existing 133 active Renewable Energy Fund grants that total $131 million of state investment for ongoing projects, according to Ford. The authority is working with the Office of Management and Budget to restore $2 million in receipt authority for the fund through the legislative process. That would allow AEA to administer the ongoing Renewable Energy Fund grants, she wrote. With $271 million in total commitments from the Legislature, the Renewable Energy Fund has helped complete 54 projects across the state since its inception in 2008. Those projects, with a total cost of about $500 million, have generated more than $1.2 billion in benefits to local communities, according to AEA. The fund got an $11.5 million appropriation in the current 2016 fiscal year budget passed last spring. AEA had recommended seven Renewable Energy Fund applications for funding up to the first-presumed $5 million limit for future projects in its latest round nine of fund activity. The authority received 52 applications for the current round of program funding. Recommended grant applications are ranked each year based on numerous criteria including project cost, cost-benefit ratio and available applicant matching funds. The projects are then funded based on ranking and the amount of funding made available by the Legislature.   Elwood Brehmer can be reached at [email protected]

Trustees hear plans for Fund

The plans before the Legislature to use the Permanent Fund’s investment returns to pay for government have much in common, while their differences exemplify the priorities of their sponsors. The plan that is ultimately chosen will go a long way toward shaping the relationship Alaskans have with their state government. The Alaska Permanent Fund Corp. Board of Trustees got rundowns of the three ideas in “to the point” presentations from the proposers themselves, Anchorage Republicans Rep. Mike Hawker and Sen. Lesil McGuire and officials from Gov. Bill Walker’s administration on Feb. 19. Legislators largely agree that filling the state’s $3.5 billion-plus budget deficit will require some utilization of the Permanent Fund’s earning power. The bigger lift could be getting the public on board, as Alaskans have become detached from how their government is funded, each of the presenters noted. Hawker, a vocal critic of many Walker policies, commended the governor for his effort to “reconnect Alaskans to the financial and budget decisions made by their public officials,” through his overarching fiscal plan. “We have been blessed in this state for the past 30 years with untold wealth; wealth that is the envy of every state in the union and probably three-quarters of the world through the earnings we’ve had from our oilfields we’ve been able to pay for every needed and desired government service as well as distribute a portion of that wealth to individuals in the form of Permanent Fund dividends,” Hawker said. “We’ve paid for both necessities and we have had the luxury of being able to distribute money back (to the public), which has been wonderful.” However, the combination of ever-declining oil production and unforeseen low prices will force changes to the status quo, according to Hawker. “We are at an economic crossroads in the state where we can no longer afford to have everything we want,” he said. Alaska would need Alaska North Slope crude prices to rebound from the $30 per barrel range to nearly $110 per barrel to balance the budget at status quo. McGuire, a 15-year veteran in the Legislature, said she “gasped” when she first learned that upwards of 90 percent of state revenue is tied to the oil industry. “It made me sick to my stomach to think that every year you would get a fall and spring (revenue) forecast based on hypotheticals regarding a single commodity of crude oil that is extremely volatile and then make decisions that affect every Alaskan’s life profoundly,” she said. Hawker and McGuire are not seeking reelection this fall. The Permanent Fund ended calendar 2015 at $52.3 billion, with about $6 billion of that being realized, spendable investment revenue in the fund’s Earnings Reserve Account. Unrealized income and the amount currently committed to the 2016 dividend raise the value of the Earnings Reserve to about $8.1 billion. At that size, Alaska is better off than other governments with similar funds, according to Attorney General Craig Richards, who is also a member of the Fund Board of Trustees. He said Alaska’s Permanent Fund, when compared against the state’s average annual spending, is the largest “sovereign wealth” style fund in the world. Walker laid out his ambitious New Sustainable Alaska Plan in early December. While it includes ongoing budget cuts and a suite of industry and personal tax hikes, the lynchpin of the proposal, the Alaska Permanent Fund Protection Act, relies on Fund returns to pull up to $3.3 billion for government services each year. The Alaska Permanent Fund Protection Act would significantly re-plumb state coffers and transform the fund into a basic annuity. It would shift petroleum production taxes and the 75 percent of available royalty revenue into the Earnings Reserve Account. From there would come the $3.3 billion annual “allowance”, which, when combined with other revenues and further budget cuts would balance the state budget by the 2019 fiscal year, according to the administration. Revenue Commissioner Randy Hoffbeck said the governor’s plan would allow the state to disconnect its annual budgets from a commodity with high price volatility and thus stabilize government spending to support economic growth in the state. All of Alaska’s petroleum tax and “other” revenues have historically gone directly to the state’s General Fund, along with 75 percent of resource royalties. The remaining 25 percent of royalties is constitutionally mandated to the Permanent Fund principal, or corpus. That system has led to the state “chasing oil prices” and resulted in highly cyclical, and unhealthy spending, Richards said. “When your economy is doing well (because of high oil prices) is not when you want your large capital budgets,” he commented. “You want your large capital budgets probably when your economy is not doing as well.” The same pattern can be seen in the state’s operating budget, Richards noted. Last year lawmakers cut roughly $800 million — about $400 million each from the operating and capital budgets in response to the oil slide and declining state revenues that began in the third quarter of 2014. “That’s just sort of the way governments around the world work; you spend the money when you get it,” Richards said. The actual draw on Fund earnings would be about $2.3 billion in the early years of the plan, as oil income would contribute a little more than $1 billion to the Earnings Reserve at low prices, according to Revenue projections. “We’re housing these volatile revenue streams into a large savings pot and we take out of that savings pot a fixed amount every year,” Richards said. To date, Permanent Fund Dividend payments have been the only draw on the Earnings Reserve Account. Legislators over the years have shown discipline towards the account despite being able to access its funds with a simple majority vote, Richards said. The administration is betting that discipline continuing once the account is funding government to prevent overdraws. A $3 billion transfer from the Constitutional Budget Reserve, or CBR, savings account to the Earnings Reserve would jumpstart the process and help the fund weather potential down years. Currently, the CBR has about $8.7 billion available for appropriation. The annual draw would be adjusted for inflation starting in fiscal year 2020, Richards said. An Earnings Reserve starting at about $13 billion would provide about four years of funding and be a buffer from individual years of poor Fund returns. The Alaska Permanent Fund Protection Act would require average annual investment returns of 6.9 percent, according to the administration. The annuity-like draw could deplete the Earnings Reserve faster than the Percent of Market Value, or POMV, draw proposals by Hawker and McGuire, Richards acknowledged, because a POMV plan pays out less following years of poor returns. However, a four-year review cycle of the plan’s draw and Fund returns would allow lawmakers to adjust spending up or down while maintaining the sustainability of the fund, Richards and Hoffbeck said. On the flipside, a POMV approach adds to available state funds but doesn’t address volatility in petroleum revenue, Richards said. The drastic spending swings could still occur. He said a $2.5 billion swing, positive or negative, in the fund’s value would equate to roughly $100 million more or less available for a sustainable draw each year under the administration’s plan. As for dividends, the administration borrowed an idea from McGuire’s plan to tie the payment to Alaskans to resource income, thus connecting Alaskans to their state’s fiscal situation. After a guaranteed $1,000 dividend in the first year of the plan, the dividend would be 50 percent of annual resource royalty revenue — somewhere between $800 and $1,000 per person in the coming years based on the state’s future oil price and production estimates, Hoffbeck said. A year of current oil prices in the $30 range would roughly equate to a $400 check for each Alaskan, he noted. The longstanding dividend formula distributes half of the fund’s annualized five-year rolling average of realized earnings each year. “One of the things we really tried to do with this plan is to make the dividend payment somehow reflect the state’s ability to pay the dividend, so we don’t end up in a situation like this year when we’re paying a historic high dividend (about $2,000) at a time when the state is in a historic difficult time financially,” Hoffbeck said. McGuire’s plan would provide a slightly higher dividend with nearly 75 percent of royalty revenue being devoted to the checks. A 0.5 percent share of royalties would add to the state Public School Trust Fund. The final dividend and government funding amounts are little more than a balancing act. Adding to one ultimately means pulling from the other and the final shares are debatable policy decisions, Hoffbeck and McGuire said. Both also addressed the misconception that the annual PFD checks are constitutionally protected and that the proposals to change the dividend calculation would automatically cut the payment amount. Overall strong financial market performance since 2010 has led to large PFDs the last two years, but a look back farther shows volatility in the dividend as well. Hoffbeck said over the last 12 years four PFDs have been more than $1,500; four have been between $1,000 and $1,500; and 4 have been less than $1,000. McGuire said pushback to changing the dividend calculation comes from an emotional attachment many individuals have with the annual October check. “The constitutional amendment that was put forward by (former Gov. Jay) Hammond — of course approved by the House and the Senate and then put on the November 1976 ballot — was to create a Permanent Fund, not a Permanent Fund Dividend or a Permanent Fund Dividend Program and this is a point that is still lost in the public,” she said. McGuire’s Senate Bill 114 McGuire quietly introduced Senate Bill 114 last April while a long and ugly battle over the operating budget was just beginning. It was the first of the three plans now under review in the Legislature to utilize the Permanent Fund’s earnings for state operations. She proposes to use an annual draw equal to 5 percent of the rolling five-year average market value of the Permanent Fund, or POMV, from the Earnings Reserve to add $2 billion, and hopefully more in future years, to the General Fund in fiscal year 2017 beginning July 1. Allocations of oil production taxes and other revenues would continue to flow into the General Fund. The Permanent Fund Board of Trustees passed resolutions in 2000, 2003 and 2004 — the last period of sustained low oil prices — supporting a 5 percent POMV spending limit for the Fund. McGuire said the recognition of the Legislature’s authority to statutorily restructure the payout of Fund earnings has been a “light bulb moment” for some legislators. Simply, her plan would not balance the budget, but it would put the state in a better situation and give lawmakers more time to debate further budget cuts or other revenue options while keeping dividends intact in some form. The process of transforming state government funding must be taken in pieces, she said. McGuire and Hawker both said their plans hit on what they feel is politically possible to accomplish over what might be a philosophically perfect solution. “If we could just get the Legislature to adopt this one piece, whether it’s my bill or another bill, but just examine the role of the Permanent Fund itself — whether it’s appropriate to have some distribution to the government,” McGuire said. “If we could just do that one thing it would be good and in the process of doing that the conversation can begin in earnest about the size and cost of government that Alaskans want and what they’re willing to pay for. “This is a conversation we have needed to have for decades and it is at the heart of what will make this state viable in the future because Alaskans have been completely out of touch with what pays the bills.” Hawker’s House Bill 224 Hawker’s House Bill 224 prioritizes a balanced budget over everything else, including dividends. It’s based on the “fiscal responsibility rule” of necessities over luxuries, Hawker said to the trustees. “My bill simply says to the Legislature that we need to provide our schools; we need to provide our roads; we need to provide health and service benefits; we need to do all this before we pay dividends,” he said. His plan has goals similar to the administration’s proposal, but reaches them more simply, he said. It uses savings to mitigate oil and financial market volatility. With an annual draw equal to 4.5 percent of the Permanent Fund’s average market value, Hawker’s bill would draw about $2 billion from the Earnings Reserve to the General Fund each year. Like SB 114, it would keep other current revenue flows in place, but the royalty cash used to pay dividends in the plans from McGuire and the administration, would also be used to close the fiscal gap. Further budget cuts would also be needed. Dividends could be paid in years of surplus, a determination that would be up to the Legislature and also depend on whether state savings accounts need to be replenished as well. The 2016 fiscal year dividend appropriation could be paid in one year or spread over several years — another legislative decision — to wean Alaskans off of the annual check, he said. In years of particularly high market returns the Legislature could also appropriate excess POMV revenue directly into the corpus of the Permanent Fund to continue growing the fund, Hawker said. “My bill specifically has provisions in it that very clearly state the Legislature is not in any way prescribed from making any appropriation that would move money anywhere,” he said, noting he plans to add further clarification that a 4.5 POMV appropriation to the General Fund is not required either. Hawker’s POMV would be calculated using the average Fund value from the first five of the previous six years. As a result, the POMV draw would be based on finalized, audited Fund results, rather than using preliminary figures from the current fiscal year to calculate the draw. McGuire said she will likely add the “five out of six” provision to SB 114 as well. A fund perspective (Editor's note: This story has been updated to reflect Greg Allen's role as a consultant to the Alaska Permanent Fund Corp. An earlier version incorrectly listed Allen as an APFC trustee.) Greg Allen, head of the fund's consulting firm Callan Associates Inc., shared the prospective impacts each of the plans could have on the fund with his fellow trustees. The results? They’re all about the same. “I’m happy to report that all of these plans in the median case result in a slightly higher market value” for the fund, Allen said. The full viability of each plan, as originally constructed, would be hurt by poor projected fund returns this year, he noted. Callan is forecasting a 3.7 percent loss in fiscal year 2016, which ends June 30. Through Feb. 19 the total return was down 5.6 percent from the start of the state fiscal year, Allen said. The Permanent Fund’s value was $50.2 billion as of Feb. 22 compared to the $52.3 billion it held at the end of the 2015 fiscal year last June 30. When the poor expected return for 2016 is accounted for, the inflation adjusted value of the fund after 10 years would be $49.6 billion under the Alaska Permanent Fund Protection Act, $50.2 billion under McGuire’s SB 114 and with a slightly smaller POMV draw, $51.7 billion under Hawker’s HB 224. The fund’s status quo ending value for 2016 is projected at $48.6 billion. The status quo market value of the fund, in 2015 dollars, would be $63.1 billion after 10 years, Callan estimates. While the fund would benefit the most from high oil prices under the governor’s plan because it places oil revenues in the Earnings Reserve, the plan also has the highest risk of hitting a draw limit. The governor’s Permanent Fund Protection Act would require a draw recalculation under 30 percent of market scenarios, while the POMV plans would need to be reworked in 25 percent of market forecasts, according to Callan. Hoffbeck emphasized the importance of management to remain free from state needs regardless of the plan chosen by the Legislature. “It is absolutely critical that the investment side has to stay autonomous, independent from the spending so that the trustees and the Permanent Fund don’t get into a place where they have to start making investment decisions to meet a budgetary requirement,” Hoffbeck said. If that were to happen the whole system would begin to crumble, he said.

Fuel tax bill moves with industry support

Gov. Bill Walker’s bill to increase state fuel taxes has support from some industry groups it would directly impact. It is also the only tax bill amongst a suite of revenue proposals by the administration to help close the $3.5 billion-plus budget deficit to have moved out of a single committee so far. The Senate Transportation Committee passed the bill onto the Finance Committee last week with lukewarm support on a 3-2 vote. Committee chair Sen. Peter Micciche, R-Soldotna, said he was for moving the bill to Finance for further vetting, but not necessarily in favor of the bill itself. Senate Bill 132, and its mirror House Bill 249, would raise the per gallon state fuel taxes as follows: highway fuel tax from 8 cents to 16 cents; marine fuel tax from 5 cents to 10 cents; aviation gasoline from 4.7 cents to 10 cents; and jet fuel from 3.2 cents to 10 cents. The legislation would correspondingly increase the per gallon highway fuel tax rebate for off-road use from 6 cents to 12 cents. In all, the tax hikes are projected to raise $49 million per year, according to the Revenue Department. Leaders of the Associated General Contractors of Alaska, Alaska Airmen Association, Alaska Trucking Association and the Alaska Region of the Aircraft Owners and Pilots Association all supported the tax increases in letters to House and Senate committees. Alaska Trucking Association Executive Director Aves Thompson wrote to Senate Transportation that the tax hike is part of a “durable, long-term fiscal plan” for the state. “The Alaska Trucking Association has long supported a fuel tax increase if the funds could be dedicated to transportation needs,” he wrote. “We realize that this won’t happen in this bill but feel strongly that we need to help to resolve the fiscal issues by doing our part.” Owner of the Anchorage taxi service Checker Cab Michael Thompson wrote in opposition to the tax increase. He estimated doubling the highway fuel tax would “burden each driver an additional $325 per year.” Alaska’s 8-cent per gallon highway fuel tax is the lowest in the nation. The national average for state highway fuel taxes is 20 cents per gallon, according to the American Petroleum Institute, while the federal tax is 18 cents per gallon. Alaska’s highway tax hasn’t been raised since 1970, Transportation Commissioner Marc Luiken wrote in a letter informing the committees on the legislation. The 3.2-cent per gallon jet fuel tax is the 32nd lowest in the country, according to the national policy research group the Tax Foundation. The State of Alaska collected $41.8 million from fuel taxes in fiscal year 2015. Those fuel taxes accounted for 3.5 percent of all state taxes last fiscal year, according to Revenue. SB 132 moved out of Senate Transportation with limiting amendments added by the committee, including a sunset date of July 1, 2018, and a provision reverting the taxes back to previous amounts if the average price for Alaska North Slope crude is more than $85 per barrel in the previous calendar year. At that oil price the state’s need for other revenue sources would be diminished, committee members reasoned. “If we reduce our budget as we have planned we would have more revenue than we need at those (oil) price ranges and I think that’s the right place to promise Alaskans that we would be returning some of this revenue,” Micciche said. Sen. Mike Dunleavy, R-Wasilla, who opposed moving the bill, said the Legislature needs to spend another year doing its “due diligence” to cut spending before adding to taxes. An amendment to add subaccounts to track the tax revenue by fuel source was also added by Fairbanks Republican Sen. Click Bishop. Opponents to the fuel tax increases have said the legislation could have more support if highway fuel tax money, for example, was dedicated to highway maintenance, instead of being lumped into the General Fund. The same could be applied to airports and aviation fuel taxes. The Department of Revenue tracks the taxes by fuel type, but those monies are not dedicated for specific uses. The Department of Transportation has $113 million in unrestricted general fund money to spend on road and airport maintenance this fiscal year, according to department spokesman Jeremy Woodrow. He said roughly 75 percent of that goes to road work, but winnowing out exactly how much is allocated to the specific type of work is difficult because DOT crews in rural communities often handle both road and airport duties with the same equipment. Fuel for flight Aviation fuel tax collections totaled nearly $4.9 million in 2015; and the vast majority of that, about $4.4 million, came from jet fuel. At the same time, the state spends about $39 million per year to wholly operate its 247 airports, Alaska Airport Division Operations Manager Troy LaRue said. The higher aviation fuel taxes would generate about $9 million, according to a DOT model. The state Aviation Advisory Board, comprised of state and industry members, unanimously recommended in November the state use fuel tax hikes to add revenue over landing fees or airport user fees, largely because the latter two proposals would require implementing new payment systems while the fuel taxes are already in place at lower levels. The state airport system also generates about $1.5 million in lease revenue, LaRue said. “We know we’re probably never going to earn enough money to insulate the airports from the General Fund, but maybe we could get a lot closer,” he said in an interview. Alaska Airlines Senior Vice President Joseph Sprague told the House Transportation Committee that the airline believes it will pay 30 percent of the additional revenue generated by the jet fuel tax increase from 3.2 cents per gallon to 10 cents per gallon. He said to the Juneau Empire that it’s difficult for the airline to directly oppose the tax increase as it is advocating for a solution to the state’s budget deficit, as many businesses and trade organizations have. Delta Air Lines, which has increased its presence in the state in recent years, wrote in opposition to the jet tax change, as did UPS. UPS uses Ted Stevens Anchorage International Airport primarily as a fueling stop for flights between Asia and the Lower 48. However, jet fuel for flights with an international origin or destination is exempt from taxes at the Anchorage airport because the airport is in a federal Foreign Trade Zone established primarily to encourage cargo companies to use the airport as a transfer facility. Elwood Brehmer can be reached at [email protected]

Army chief says Alaska 4-25 troop reduction should wait

U.S. Army Chief of Staff General Mark Milley said he wants to delay proposed force reductions at Joint Base Elmendorf-Richardson at least a year in testimony to a Senate committee Feb. 24. The revelation came as Sen. Lisa Murkowski questioned Milley during a Senate Appropriations Defense Subcommittee hearing. Army officials first announced plans to cut 2,600 soldiers from the 4th Airborne Brigade Combat Team of the 25th Infantry Division, also known as the 4-25, stationed at JBER last July as part of an Army-wide cut of 40,000 troops. The full division stationed in Alaska is about 4,000 troops. Milley, who visited Alaska military installations earlier this month, said increasing aggression and force buildup by Russia, particularly in the North Pacific, along with an “increasingly assertive” China and “very provocative North Korea” create heightened conditions for potential conflict in the region. “I think it would be contrary to U.S. national security interests to go ahead and pull out the 4-25 at this time,” Milley said to Murkowski. “My thought is that we should extend them at least a year to see how the strategic situation develops and then move from there.” He added that those beliefs were confirmed in conversations with on-site commanders and the troops themselves. “There’s a great joint strategic deployment capability with the Air Force up there. (The 4-25) can move by air; they can move by sea. We’ve got a national capability up there (in Alaska) that I think is worth keeping,” Milley said. Murkowski responded that Milley provided “very welcome news,” as the 4-25 Airborne Brigade Combat Team is the only such Army force stationed in the Pacific. Further, Milley noted, as members of Alaska’s congressional delegation have in their fight to keep the 4-25 intact, the brigade’s strategic ability to reach East Asia and other parts of the world in less than eight hours from its position in Alaska. Acting Army Secretary Patrick Murphy said to Murkowski that the Army has invested “a lot of money up there” in training facilities that are “second to none” and that he looks forward to working with the senator to fully resolve the issue. Sen. Dan Sullivan said in a statement reacting to Milley’s comments that he appreciates the general’s willingness to evaluate how important the 4-25 is in protecting the country’s global interests. “The 4-25 is the only extreme cold weather and mountain-trained airborne brigade combat team in the entire U.S. Army, and the only one strategically located to respond to threats in the Asia-Pacific and the Arctic,” Sullivan said. “This kick-in-the-door capability is vital to our national security and provides deterrence against increasingly aggressive actions from Russia, China and North Korea.” Sullivan requested Milley reconsider the troop drawdown last year when the general was going through the confirmation process. Sullivan also succeeded in adding an amendment to the defense spending bill requiring the Defense Department to draft an Arctic Operations Plan. He received verbal assurances from Army brass that the 4-25 would not be moved until the plan was complete, Sullivan told the Journal in December. During an Armed Services Committee hearing a day earlier U.S. Pacific Commander Admiral Harry Harris said to Sullivan that without the 4-25 in Alaska that “I don’t know where we’d be if we had a major fight on the Korean Peninsula.” The 4-25 also just completed a training exercise at Fort Polk in Louisiana with a full Airborne Task Force of nearly 1,600 troops to show the value of the full force, according to a U.S. Army Alaska press release. U.S. Army Alaska officials asked branch leaders to consider training with the full force last year after the Army directed the 4-25 to downsize to an Airborne Task Force of 1,046 soldiers as part of the effort to restructure to a smaller, more agile force, the release states. The release stated that the exercise at Fort Polk validated the 4-25 as “the only U.S. airborne unit in the Pacific region capable of performing forcible entry operations.” Elwood Brehmer can be reached at [email protected]

Army chief says Alaska troop reduction should wait

U.S. Army Chief of Staff General Mark Milley said he wants to delay proposed force reductions at Joint Base Elmendorf-Richardson at least a year in testimony to a Senate committee Feb. 24. The revelation came as Sen. Lisa Murkowski questioned Milley during a Senate Appropriations Defense Subcommittee hearing. Army officials first announced plans to cut 2,600 soldiers from the 4th Airborne Brigade Combat Team of the 25th Infantry Division, also known as the 4-25, stationed at JBER last July as part of an Army-wide cut of 40,000 troops. The full division stationed in Alaska is about 4,000 troops. Milley, who visited Alaska military installations earlier this month, said increasing aggression and force buildup by Russia, particularly in the North Pacific, along with an “increasingly assertive” China and “very provocative North Korea” create heightened conditions for potential conflict in the region. “I think it would be contrary to U.S. national security interests to go ahead and pull out the 4-25 at this time,” Milley said to Murkowski. “My thought is that we should extend them at least a year to see how the strategic situation develops and then move from there.” He added that those beliefs were confirmed in conversations with on-site commanders and the troops themselves. “There’s a great joint strategic deployment capability with the Air Force up there. (The 4-25) can move by air; they can move by sea. We’ve got a national capability up there (in Alaska) that I think is worth keeping,” Milley said. Murkowski responded that Milley provided “very welcome news,” as the 4-25 Airborne Brigade Combat Team is the only such Army force stationed in the Pacific. Further, Milley noted, as members of Alaska’s congressional delegation have in their fight to keep the 4-25 intact, the brigade’s strategic ability to reach East Asia and other parts of the world in less than eight hours from its position in Alaska. Acting Army Secretary Patrick Murphy said to Murkowski that the Army has invested “a lot of money up there” in training facilities that are “second to none” and that he looks forward to working with the senator to fully resolve the issue. Sen. Dan Sullivan said in a statement reacting to Milley’s comments that he appreciates the general’s willingness to evaluate how important the 4-25 is in protecting the country’s global interests. “The 4-25 is the only extreme cold weather and mountain-trained airborne brigade combat team in the entire U.S. Army, and the only one strategically located to respond to threats in the Asia-Pacific and the Arctic,” Sullivan said. “This kick-in-the-door capability is vital to our national security and provides deterrence against increasingly aggressive actions from Russia, China and North Korea.” Sullivan requested Milley reconsider the troop drawdown last year when the general was going through the confirmation process. Sullivan also succeeded in adding an amendment to the defense spending bill requiring the Defense Department to draft an Arctic Operations Plan. He received verbal assurances from Army brass that the 4-25 would not be moved until the plan was complete, Sullivan told the Journal in December. During an Armed Services Committee hearing a day earlier U.S. Pacific Commander Admiral Harry Harris said to Sullivan that without the 4-25 in Alaska that “I don’t know where we’d be if we had a major fight on the Korean Peninsula.” The 4-25 also just completed a training exercise at Fort Polk in Louisiana with a full Airborne Task Force of nearly 1,600 troops to show the value of the full force, according to a U.S. Army Alaska press release. U.S. Army Alaska officials asked branch leaders to consider training with the full force last year after the Army directed the 4-25 to downsize to an Airborne Task Force of 1,046 soldiers as part of the effort to restructure to a smaller, more agile force, the release states. The release stated that the exercise at Fort Polk validated the 4-25 as “the only U.S. airborne unit in the Pacific region capable of performing forcible entry operations.” Elwood Brehmer can be reached at [email protected]

Producers, Walker admit AK LNG stall

The leaders of the Alaska LNG Project coalesced at a press conference Feb. 17 to quell uncertainty about the project’s future, but vague statements ultimately led to more questions than answers. Gov. Bill Walker said in opening remarks that his administration began discussions with the producer partners in the project — BP, ConocoPhillips and ExxonMobil — about how to continue the project at a time when margins are thin for everyone involved. “The elephant in the room has been for some time — what do we do in the challenging times of low oil prices and how does that impact the project?” Walker said. Simply put, a continued low oil price environment could impact the decision to continue the project beyond 2017, when the decision to move into the front-end engineering and design, or FEED, stage is set to be made, Walker acknowledged. The governor said he appreciates the companies’ willingness to begin evaluating possible changes to the project structure now, rather than in a year or so when the FEED decision was to be made. Along with entering the two- to three-year FEED stage comes a collective investment of up to $2 billion to fund the work, so it is one of several potential stopping points. More will be known in a month or so as to whether changes to the project structure are needed to keep it going, according to Walker. “The goal is to have the project proceed — momentum maintained — and have the lowest-cost project both from a construction standpoint and an operational standpoint as well,” he said. ConocoPhillips Alaska President Joe Marushack said the “economic headwinds are pretty tough right now” and revising the current rough cost estimate of $45 billion to $65 billion in the remaining preliminary front-end engineering and design, or pre-FEED, stage will help determine if the project is financially viable. BP Alaska President Janet Weiss and project manager Steve Butt of ExxonMobil emphasized that the focus now is on getting the lowest possible cost of natural gas supply in the remaining pre-FEED schedule that has already been funded. “BP really wants to see this project; Alaska needs this project; it’s an important project in BP’s portfolio,” Weiss said. Butt noted that ExxonMobil has spent more than $500 million on the project to date and will continue to spend more as the roughly two-year pre-FEED process wraps up this fall. A narrower project cost estimate is expected at the end of pre-FEED. “It’s been a real privilege for ExxonMobil to lead this project and commit the majority of resources to the project and we’re glad to have that opportunity and look forward to working with the parties on forward options,” he said. Rebecca Logan, general manager of the Alaska Support Industry Alliance trade group, said she was happy to see the project partners unite during tough times. She commented that the financial pressure a low-oil price environment should not be compounded by higher industry taxes. Part of Walker’s proposed overhaul of the state’s fiscal regime is tax increases on nearly every major industry in the state, which for the oil and gas industry means closing some loopholes and raising the minimum oil production tax by 1 percent from 4 percent to 5 percent. “We know we have to have a strong oil industry here (in Alaska) to support AK LNG,” Logan said. A lack of progress on commercial negotiations for eight major issues — starting with the foundational Gas Balancing Agreement primarily between the producers — could push the timeline back two years. A constitutional amendment allowing the state to enter into long-term contracts that essentially set tax policy for the life of the project must be voted on by the public in a general election year, either this November or in 2018. Walker has said his administration would not propose an amendment without first having the agreements in place for the Legislature to review. That was all supposed to happen during a special legislative session this spring in to meet the statutory deadline of June 23 to have the amendment on the November ballot. House Speaker Mike Chenault told the Associated Press in a statement that he would have liked more concrete information from the news conference but that he welcomes greater scrutiny of the project costs. Walker would not rule out the possibility of hitting the target dates and also said they “may not be as critical as they once were from a timing standpoint.” Marushack, from ConocoPhillips, conceded meeting the near-term goals is unlikely, as members of the administration directly involved in the negotiations have said to the Journal. The producers have made it clear they require fiscal — tax — certainty over the 25-year life of the project. Walker alluded to financial terms that could remove the need for a constitutional amendment but said it is too soon to expand on what those might be. Elwood Brehmer can be reached at [email protected]            

LIO saga continues with third-party analysis sought by Stevens

And the beat goes on. Legislative Council chair Sen. Gary Stevens directed the Legislative Affairs Agency on Feb. 11 to hire a third-party for an independent analysis of dueling financial conclusions as to whether the Legislature should stay in the Anchorage Legislative Information Office or move to the Atwood Building that houses executive branch agencies including the governor’s office. The meeting was anticipated to bring some sort of resolution to the at times ugly dispute over the $3.3 million annual lease the Legislature has for the year-old space, but Stevens said more information is still needed with contradictory cost-savings proposals for moving versus staying. “This has all been political to this point,” Stevens said. “There’s been political advice and we need financial.” The Legislature’s lease of the building has drawn intense scrutiny from many legislators and the public as the state faces an annual budget deficit approaching $4 billion. Stevens said he has already discussed hiring a third-party consultant with the council’s outside attorneys who have been in contact with potential independent finance experts. A proposal submitted Jan. 29 by 716 West Avenue LLC, the building owner group, argues the State of Alaska should purchase the building for $37.9 million to accrue maximum savings that would outpace projected savings of moving legislators into the Atwood Building. However, in a Feb. 5 memo to Stevens, Pam Varni, executive director of the Legislative Affairs Agency that handles business for the Legislative Council, disputed cost-saving figures for staying at the LIO compared to Atwood. A spokeswoman for the LIO’s owner group said in a statement that the group will gladly provide all necessary information for a third-party financial review and also will continue to work with the Legislature to find the best way forward for the State of Alaska. Stevens acknowledged the need to have the financial review complete in time for the Legislature to fund, or not, its current Anchorage LIO lease in the state operating budget, which is usually finalized in late April. The current year’s rent is paid through May 31. On Dec. 19, 2015, the council recommended to the full Legislature via a unanimous vote not to fund the lease in fiscal year 2017 if a solution to stay in the LIO that is cost-competitive with moving the legislative offices to the nearby state-owned Atwood Building could not be reached. During the brief Feb. 11 meeting the council voted to remove the lease funds from its 2017 budget to bring its actions in compliance with the December motion. The full Legislature could add the lease payment appropriation back into the state operating budget if the current Anchorage LIO is retained. The Legislature could also terminate the lease seemingly without legal ramification because of a clause in nearly all government contracts stating fulfillment of the agreement is “subject to appropriation,” in this case, by the Legislature. If the Legislature doesn’t fund it, for any reason, the lease or contract falls apart. Mark Pfeffer, the managing partner of 716 West Fourth Avenue LLC has indicated an intention to sue if the Legislature walks away from its obligation. Proposal vs. proposal In the LIO owners’ proposal, tax-exempt financing to purchase the building would be “considerably less” than the current lease payments of $281,000 per month the Legislature currently pays, and the equity in the building would serve as an accrued savings account for the state. Varni wrote to Stevens that the proposal overstates the costs of moving to the Atwood Building by $11 million over 10 years and by $16.3 million over 30 years by including costs for debt service that is currently set to expire in March 2017. She concludes that purchasing outright or financing a purchase of the building would cost the state from $22.5 million to $94.4 million over 30 years compared to moving to the Atwood Building. The 716 proposal creates a “statistical misperception,” according to Varni. “The purpose of statistics is to make something easier to understand; however, when used in a misleading fashion, may trick the casual observer into believing something other than what the actual data show,” she wrote. “In this instance, 715 West Fourth Ave LLC, asserts it is less expensive to stay at 716 W. 4th Avenue than the Atwood Building, based on unrealistic and erroneous debt service data.” 716 West Avenue spokeswoman Amy Slinker said in a statement that Varni’s memo lacks third party analysis. “The Department of Revenue’s professional review shows the ability for clear savings,” Slinker said. The 716 West Fourth Avenue proposal also states the building owners have secured a settlement to dismiss a lawsuit brought by Jim Gottstein, owner of the adjacent Alaska Building, against the LIO owner group and the Legislative Affairs Agency. Gottstein’s complaint alleges the LIO lease is illegal because it is neither an extension of an existing lease, nor 10 percent below market value, as statute requires for a long-term extension. To fully settle the suit the Legislative Affairs Agency must agree to waive potential claims to recoup legal fees, according to the proposal document. Last month, the judge in the suit denied Gottstein’s petition to receive a “whistleblower” award of 10 percent of any money saved if the lease is ruled illegal. Trial in the case is currently scheduled for March. The proposal stated that the suit could be settled Feb. 12, a deadline that passed after the Legislative Council meeting, but Slinker said the settlement offer is still on the table. The Department of Revenue analysis of the Legislature’s options based on figures provided by 716 West Fourth Avenue — buying the building outright, having another state agency purchase it, break the 10-year lease and move to the Atwood or keep the status quo — found a potential savings of more than 55 percent over the existing lease if another state entity finances the purchase for the Legislature. Another stopgap solution offered to lower the existing rent by 5 percent, or $169,000 per year, beginning July 1 until a purchase could be executed. A rent reduction would require lender approval. The owner group also notes it has approval to waive earthquake insurance on the building, which could save another $59,600 per year from the Legislature’s $3.3 million annual bill. Revenue’s examination of the options put the upfront cost to move out of the LIO and remodel 30,000 square feet of the Atwood at $3.5 million to $5.5 million, with an annual building operating cost of $664,000. Purchasing the LIO in some fashion would require the initial payment and then operating payments of $269,000 per year for 45,000 square feet of usable space. Legislative Affairs concludes the Atwood’s annual operating cost to be $613,000, based on Varni’s memo. State ownership would also save $231,000 per year in municipal property taxes; however, taking the building off the city’s tax roll has been a reason cited by legislators for why the council did not purchase it initially. The building houses off-season offices for 25 Anchorage legislators and is the de-facto home to much of the general Legislature’s out-of-session activity. The Legislative Council, then led by Rep. Mike Hawker, R-Anchorage, decided to rebuild on the old LIO building site in 2013 after numerous attempts to find existing suitable space that meets the unique needs of a public government body in Anchorage failed. The Legislature contributed $7.5 million towards the construction cost, so Pfeffer and his company ultimately funded $37 million, about $28 million of which is long-term debt and $9 million is Pfeffer’s cash equity position in the property, he has said. Appraisals of the six-story building plus its underground parking facility have been as high as $48 million, but numerous estimates put its value at $44 million. The customized office space cost $44.5 million to build in 2014, according to Pfeffer. His group first drafted and submitted terms for the state to purchase the building for $37 million plus closing costs Oct. 9; a proposal requested by the Legislative Affairs Agency. The original terms agreed to by Legislative Affairs attorneys set a Jan. 31 deadline to act on the sale option, according to correspondence between attorneys for both sides. 716 waived the deadline in its Jan. 29 letter on conditions that the council either vote to buy the LIO by Feb. 5 or appropriate funds for fiscal year 2017 rent in the state budget. Elwood Brehmer can be reached at [email protected]

Administration seeks $17.7M increase for AK LNG budgets

The Walker administration wants to increase its gasline budget by $17.7 million to move its part of the Alaska LNG Project forward and that ask would be greater if not for the project’s struggling commercial negotiations, according to administration officials. Gov. Bill Walker’s initial $35.7 million request for the North Slope Gas Commercialization office has been cut to $26.6 million because the state can’t move forward with its full marketing plan as hoped until underlying project agreements are in place Deputy Natural Resources Commissioner Marty Rutherford told a House Finance subcommittee Feb. 11. Rutherford will become acting commissioner of DNR March 1 after the retirement of Mark Myers announced Feb. 16. The ask duplicates $8.9 million appropriated this fiscal year for the project that is split between the Law, Natural Resources and Revenue departments, plus the new marketing money. This past November during a special session called by Walker, the Legislature approved spending $160 million to buy out TransCanada Corp.’s share of the project in the pipeline and North Slope facilities and fund the state’s pre-front end engineering and design, or pre-FEED, technical work in 2016. The administration’s revised $26.6 million request includes $21 million for outside negotiating counsel and marketing contractors and would also fund four positions with annual salaries and benefits up to $1.4 million for the state’s gas marketing lead, an existing but currently vacant position. Three new positions for marketing negotiators and a market analyst totaling $2.4 million in compensation would be added to the Gas Commercialization office as part of the budget plan. Rutherford acknowledged a reference to the “sticker shock” of a $1.4 million state Alaska LNG marketing lead position by Rep. Lance Pruitt at a time when budgets and jobs in nearly every state agency are being cut. Lack of progress on the commercial side of the project means the marketing lead position would likely be filled by a contractor initially, Rutherford said in an interview. The full budget request must still be made, however, so the state is prepared to move forward if the pace and progress of the project increases, she added.  “Our total request is $26.6 (million); it’s still a lot of money. I’m not going to pretend it is not,” Rutherford said. “But it is simply one marketing organization.” The “incredibly complicated and incredibly competitive” nature of the LNG market the state is trying to jump into means paying for the best people available is a necessity, she said. “They will be developing the state’s marketing team with a level of expertise that none of us possess in the state,” Rutherford said. Whether or not the administration returns to the Legislature to ask for the full $35.7 million will depend on the pace of the commercial, or fiscal, negotiations between the state and the producers as well as what type of gas marketing arrangements the parties agree to. How the state’s 25 percent share of LNG from the project is marketed, and how much that marketing will cost, will depend on the outcome of the commercial negotiations, according to Rutherford. Those negotiations have been ongoing for more than a year, but terms of the foundational Gas Balancing Agreement between the producers, BP, ConocoPhillips and ExxonMobil have not been reached company representatives testified to House and Senate committees in late January. Alone, the Gas Balancing Agreement determines how and when the companies — each with different ownership shares of the natural gas in the Prudhoe Bay and Point Thomson fields — can pull their share of the gas and get it to market. However, seven other contracts, including marketing terms, depend on having the Gas Balancing in place. Senate Bill 138, the legislation that outlines the state’s role in the $45 billion-plus North Slope natural gas export project, called for a late 2015 special legislative session for the Legislature to review and rule on the fiscal agreements. A “gasline” special session was held, but it was to buy out TransCanada, not approve the critical agreements. The administration has had hopes of getting the contracts in place for another spring special session, but Rutherford, one of the state’s lead negotiators, told the Journal that is unlikely. She said the timeline slippage is somewhat understandable “given the complexities” of the four-party, megaproject negotiations. SB 138 also lays out four possible gas marketing scenarios for the state possibly with all, or none, of the producers. Those scenarios are: a joint-venture marketing arrangement including the state and all of the producers; individual joint-ventures between the state and each producer, or two producers and the state; the state selling directly to a producer that must make an offer to buy the gas at close to market rates; or each party going it alone in equity marketing ventures. The State of Alaska will participate or be completely responsible for marketing under three of the possible scenarios, Rutherford said to the subcommittee. “If we are an equity marketer, basically we would be competing in the market against every other LNG marketer in the world, including our co-venturers,” she said. The commercial agreements also set the backdrop for whether the state will take its 12.5 percent share of royalty gas “in-value” as cash or “in-kind,” as the actual gas molecules, a decision that will be made by the DNR Commissioner. Rutherford said the department has prepped as much as it can for that decision and should be able to make it within 60 days after the upstream commercial agreements are in place. An in-kind determination will likely lead to the producers paying their production tax as gas, which would fill the state’s 25 percent share of the project’s gas. While production from the Alaska LNG Project won’t commence until 2025 at the earliest, Rutherford said the state needs at least some of the highly paid gas marketing experts on its team to start building relationships with potential customers in Asian markets now. Eventually the Legislature will have to form a state gas marketing organization whether it’s in a joint venture or not, according to Rutherford. She compared the prospective entity to the Alaska Permanent Fund Corp. “It needs to be as independent as possible, as nonpolitical as possible and as expert as possible,” Rutherford said about the state’s future gas marketing group. DNR is leading marketing efforts currently because it is the state’s upstream expertise, which ties the department to buyers in need of supply certainty, according to Rutherford. Once the gas begins its journey down the 800-mile pipeline it would be transferred to the state marketers. In-state gas The Alaska Gasline Development Corp. is the state’s technical expertise in the project, also tasked with providing natural gas to in-state users. To the second duty, AGDC formed its own in-state gas “aggregator” subsidiary last fall. AGDC Gas Aggregator Co. would amount to an intermediary to, as the name implies, aggregate the demand of the state’s gas and electric utilities looking to buy gas from the project, rather than forcing each utility to individually barter with the project’s marketing ventures, however many there may be. The AGDC board is expecting to have an in-state program plan from the Gas Aggregator in June, according to discussion at the corporation’s Feb. 11 board meeting.  

House puts Walker oil tax bill under lens

The plumbing behind Gov. Bill Walker’s attempt to reduce the state’s oil and gas tax credit payments was exposed Feb. 12 in a House Resources Committee hearing. Rep. Mike Hawker, R-Anchorage, took the lead in criticizing the administration’s exhaustive 29-page House Bill 247 that closes complex loopholes in some sections and simply raises industry taxes in others. Tax Division Director Ken Alper got through less than half of the 46 sections of the legislation during the two-hour committee meeting. Much of that time was spent discussing ways the administration has proposed to prevent producers from lowering their tax liability below the intended minimum production “tax floor,” currently set at 4 percent, during periods of low oil prices. HB 247 would eliminate the ability for credits to be used to take a tax liability below the tax floor. Credits would then be held until a company had a sufficient tax obligation against which to use them. Legislators that supported the industry tax structure in Senate Bill 21, which was passed in 2013 under former Gov. Sean Parnell and upheld by a voter referendum in August 2014, have said the intent was to set a hard tax floor when SB 21 was passed, but there are ways that deductible credits can be used to take a liability below that floor. The issue is one that has only come up recently as low oil prices have reduced the prescribed production tax rate along with producers’ profitability. Alper noted, as others have, that SB 21 was first modeled and drafted in 2013 with an oil price regime between $80 per barrel and $120 per barrel, so some issues at today’s prices in the $30 per barrel range were unforeseen. The Oil and Tax Credit Working Group formed last summer and headed by Senate Resources chair Cathy Giessel, R-Anchorage, also recommended hardening the tax floor, a move the Alaska Oil and Gas Association referred to as a “flagrant money grab at a time when the state should be encouraging industry to continue making vital investments in the state,” in comments on the administration’s sectional analysis of the bill. Giessel said at a press briefing Feb. 15 that the Legislature’s consultant, Enalytica, is modeling the financial effects of Walker’s proposed tax credit changes. The report should be available by the week of Feb. 22. AOGA President Kara Moriarty noted in an interview that a hard minimum tax would not allow producers to apply a loss and lower a potential tax liability to zero; something companies in other industries often do with losses against their corporate income tax payments. The state’s oil and gas tax credit system once again became headline news last June when Walker vetoed $200 million from a $700 million appropriation for refundable, or cashable, credits paid by the state in the current fiscal year budget. Industry representatives and numerous Republican legislators have emphasized the credits as a necessity for doing business in Alaska’s high-cost environment, particularly during times of low oil prices. The governor contends the current program is unsustainable as the state faces annual budget deficits approaching $4 billion. Annual outlays attributable to the credits peaked at more than $1.5 billion when credits under the previous Alaska’s Clear and Equitable Share, or ACES, and SB 21 tax regimes were combined with one another in fiscal year 2014. ACES had a 20 percent capital expenditure credit that was repealed under SB 21 and replaced with a per-barrel tax credit that was designed to encourage additional production. The Revenue Department projects the state’s credit obligation will average about $850 million through 2020 under current statutes. In companion legislation to HB 247, Walker has also proposed establishing a $200 million oil and gas development revolving loan fund, administered by the Alaska Industrial Development and Export Authority, to offset some reductions to the overall credit program. Monthly calculations HB 247 would prevent companies from claiming per barrel production tax credits that could not have been applied during a specific month, because the credit can’t be applied to go below the minimum tax, at the end of the year true up. “If (the credit) is limited because of the minimum tax in a month, that month’s limitation should carry through for the rest of the year,” Alper said. “What we’re trying to prevent is if there is a limitation in one month, that the company can’t scoop up that limited credit by applying it against another month’s taxes.” Such circumstances can occur with the per barrel credit that is up to $8 per barrel at times of low prices and inversely shrinks to zero at times of high prices. The administration is attempting to constrain moving the value of that per barrel credit, which is already calculated monthly, to other months in which it could be applied, according to Alper. The situation is most notable during years of high price volatility. In 2014, when the price for Alaska North Slope crude peaked at $110 per barrel in June but fell to $60 per barrel by December, the state paid out somewhere between $100 million and $150 million to producers at the end of the year “because of the ability to in effect migrate some of those credits from month to month,” he said. AOGA called the monthly credit limitation “nothing more than a disguised tax increase.” Hawker said the portion of HB 247 dealing with monthly per barrel credits described by Alper as complex is actually simple; it allows the state to tax at high rates during certain months and takes taxes from being an annual calculation to a monthly affair strictly in an effort to generate more revenue. The state is attempting to take away the industry upside of price fluctuation, he contended. “Let’s just be honest about what we’re doing here. This is just clearly a money grab,” Hawker said, echoing the comments of AOGA. AOGA wrote that limiting the credits to monthly calculations disregards inevitable uncertainties in monthly calculations compared to year-end results and would mean credits that can’t be carried forward or transferred would be lost, amounting to a “significant and permanent tax increase.” Not addressed at the hearing, in HB 247 and its mirror legislation, Senate Bill 130, credits held beyond 10 years would expire. The 10-year sunset would apply both to deductible credits held because of minimum tax limitations and to refundable credits paid directly by the state. The legislation would also put a $25 million per year cap on refundable credits. A proposal the production tax floor from 4 percent to 5 percent would alone generate about $50 million for the state, Revenue estimates. Part of the rationale behind raising the minimum production tax to 5 percent was to make sure each industry contributed to the administration’s overarching fiscal plan to close the budget deficit, Revenue Commissioner Randy Hoffbeck said. Walker has proposed similar 1 percentage point tax increases on fishing and mining along with an increase in head taxes for cruise passengers. Hardening the minimum tax floor would add roughly $50 million to state coffers in the 2017 and 2018 fiscal years. Beyond that, the price of oil is expected to rebound sufficiently to where the minimum production tax is no longer an issue. AOGA contends that the price per barrel would have to rebound to $85 per barrel before the minimum tax does not apply. Operating losses and new oil Alaskans are constantly looking for ways to produce “new oil,” whether from existing fields or new discoveries. The administration is trying to encourage new production while limiting how much the state compensates companies for expenses incurred in bringing that new oil to the surface. Currently, North Slope companies producing new oil under SB 21 can subtract 20 percent from their net profit via the Gross Value Reduction, or GVR, credit before calculating the production tax on new barrels. Alper said the concept of the GVR was to reduce the tax as a reward for producing new oil. The issue with the credit, from the administration’s perspective, is when a new oil producer can claim both the GVR and a net operating loss. With old, or legacy, oil, companies can claim a Net Operating Loss credit to be refunded by the state for part of an annual loss. Last year that refund was 45 percent of a loss, meaning the state would offset a $10 million loss with $4.5 million in cash, Alper explained. Future Net Operating Loss credits for the North Slope will be paid at 35 percent, a change prescribed for the end of 2015 in SB 21. However, adding the GVR to the loss credit calculation can achieve much different results, according to Alper. Through a modification based on gross revenue with the GVR, an $10 million loss could be turned into a $30 million loss on the books and push the state’s payment beyond the actual loss amount. A 35 percent credit on a $30 million loss equates to a $10.5 million check. “That was a circumstance we found surprising that it was allowable under law; but it was according to the attorneys’ strict interpretation of Senate Bill 21’s provision’s as they were written,” Alper testified while sitting alongside Revenue Commissioner Hoffbeck. Accordingly, HB 247 would limit the loss credit, with the GVR calculation, to the actual size of the loss. Hawker said the change would be “truncating” the incentive for new production. “What is going to be our consequence? Is it going to have a chilling effect on the pursuit of new oil, which was a very high priority for us by essentially taking away that opportunity, that advantage, in a situation where somebody’s getting started?” Hawker questioned. “They’re getting their field developed; they’re getting their initial production going and they have a loss and we’re saying, ‘Oh, by the way, that incentive that we were trying to give you to get this done — you don’t get it.” Transparency One of the few parts of the legislation not focused on revenue generation attempts to increase what the state can disclose about the credits it pays. According to the administration’s analysis, HB 247 would allow the Revenue Department to publish each company claiming a credit, the amount claimed and a general description of the work being done — information Alper described as “summary level.” All of that information is currently held confidential by the state in accordance with statute. “I think it’s really imperative for us to be able to tell our people what we’re investing in,” Rep. Paul Seaton, R-Homer said. Walker said in a previous interview with the Journal that he would support making more tax credit information public if revenue collected through a broad-based tax — he has proposed an income tax — were used to support the credit payments. Hawker said the oil and gas tax credit information would take away a company’s  competitive advantage by revealing what companies are trying to accomplish. “It’s obviously philosophical, but I want to respect the taxpayers. I want to give them the advantage that when they make an investment in Alaska they are given the greatest advantage possible for having made that investment,” he said. However, companies are not required to accept credits for which they qualify. Hoffbeck noted that more transparency in the credit program would allow for a “more open discussion” around what is a major budget obligation for the state. The issue came up repeatedly when the administration could not provide legislators and others with enough data to inform discussions about policy changes, he said. AOGA wrote that the impetus for increased transparency arose from credits earned by one or two companies, which can’t be described on an aggregated basis. The industry group and Hawker also called the legality of the proposed reporting into question. The language in the bill could apply to Net Operating Loss credits and others that could put portions of a company’s financial results into the public realm, Hawker said. Alper acknowledged the potential issue of inadvertently revealing some of a company’s finances and said the administration would like to find language that is acceptable to all parties involved. Limiting the information to specific refundable credits the state pays directly — exploration, drilling and development credits, for example — could be a middle ground, he said. “We merely want to be able to report where public money is being spent for the purposes of providing subsidies and benefits to oil companies,” Alper said.   Elwood Brehmer can be reached at [email protected]  

Stevens asks for independent review of Anchorage LIO options

(Editor’s note: This is the continuation of a Feb. 5 story entitled Anchorage LIO proposal offers savings, settlement to suit; LAA disputes figures.) And the beat goes on. Legislative Council chair Sen. Gary Stevens directed the Legislative Affairs Agency on Thursday to hire a third-party for an independent analysis of dueling financial conclusions as to whether the Legislature should stay in the Anchorage Legislative Information Office building. The meeting was anticipated to bring some sort of resolution to the at times ugly dispute over the $3.3 million annual lease the Legislature has for the year-old space. The Legislature's lease of the building has drawn intense scrutiny from many legislators and the public as the state faces an annual budget deficit approaching $4 billion. Stevens said he has already discussed bringing hiring a third-party consultant with the council’s outside attorneys who have been in contact with potential independent finance experts. He acknowledged the need to have the financial review complete in time for the Legislature to fund, or not, its current Anchorage LIO lease in the state operating budget, which is usually finalized in late April. On Dec. 19, the council recommended to the full Legislature via a unanimous vote not to fund the lease in fiscal year 2017 if a solution to stay in the LIO that is cost-competitive with moving the legislative offices to the nearby state-owned Atwood Building could not be reached.  “This has all been political to this point,” Stevens said. “There’s been political advice and we need financial.” During the brief Thursday meeting the council voted to remove the lease funds from its 2017 budget to bring its actions in compliance with the December motion. The full Legislature could add the lease payment appropriation back into the state operating budget if the current Anchorage LIO is retained. A spokeswoman for the LIO’s owner group said in a statement that the group will gladly provide all necessary information for a third-party financial review and also will continue to work with the Legislature to find the best way forward for the State of Alaska.   Anchorage LIO proposal offers savings, settlement to lawsuit; LAA disputes figures A proposal by the building owners to keep the Legislature in the Anchorage Legislative Information Office building could save the state millions of dollars and get the legislators out of a political bind. However, Pam Varni, executive director of the Legislative Affairs Agency, which handles business for the Legislative Council, disputed the figures in a Feb. 5 memo to Council Chair Sen. Gary Stevens. The proposal, submitted Jan. 29 to Stevens, suggests the State of Alaska purchase the building for $37.9 million to accrue maximum savings that would outpace projected savings of moving legislators into the nearby Atwood Building, primarily occupied by executive branch agencies. A meeting of the Legislative Council is Feb. 11 is scheduled for 5 p.m. to discuss the proposal. Tax-exempt financing would be “considerably less” than the current lease payments of $281,000 per month the Legislature currently pays, and the equity in the building would serve as an accrued savings account for the state, according to 716 West Fourth Avenue LLC, the building owner group. The leaseholder company name is the Downtown Anchorage address of the LIO and the offer is signed by longtime Anchorage developer Mark Pfeffer, the firm’s managing member. Varni wrote to Stevens that the proposal overstates the costs of moving to the Atwood Building by $11 million over 10 years and by $16.3 million over 30 years by including costs for debt service that is currently set to expire in March 2017. She concludes that purchasing outright or financing a purchase of the building would cost the state from $22.5 million to $94.4 million over 30 years compared to moving to the Atwood Building. The 716 proposal creates a "statistical misperception," according to Varni. "The purpose of statistics is to make something easier to understand; however, when used in a misleading fashion, may trick the casual observer into believing something other than what the actual data show," she wrote. "In this instance, 715 West Fourth Ave LLC, asserts it is less expensive to stay at 716 W. 4th Avenue than the Atwood Building, based on unrealistic and erroneous debt service data." The Legislature could terminate the lease seemingly without legal ramification because of a clause in nearly all government contracts stating fulfillment of the agreement is “subject to appropriation,” in this case, by the Legislature. If the Legislature doesn’t fund it, for any reason, the lease or contract falls apart. Pfeffer has indicated an intention to sue if the Legislature walks away from its obligation. The proposal also states that 716 has secured a settlement to dismiss a lawsuit brought by Jim Gottstein, owner of the adjacent Alaska Building, against the LIO owner group and the Legislative Affairs Agency. Gottstein’s complaint alleges the LIO lease is illegal because it is neither an extension of an existing lease, nor 10 percent below market value, as statute requires for a long-term extension. To fully settle the suit the Legislative Affairs Agency must agree to waive potential claims to recoup legal fees, according to the proposal document. Last month, the judge in the suit denied Gottstein’s petition to receive a “whistleblower” award of 10 percent of any money saved if the lease is ruled illegal. Trial in the case is currently scheduled for March. A Department of Revenue analysis of the Legislature’s options based on figures provided by 716 West Fourth Avenue — buying the building outright, having another state agency purchase it, break the 10-year lease and move to the Atwood or keep the status quo — found a potential savings of more than 55 percent over the existing lease another state entity finances the purchase for the Legislature. Another stopgap solution offered to lower the existing rent by 5 percent, or $169,000 per year, beginning July 1 until a purchase could be executed. A rent reduction would require lender approval. The lease is paid through May 31, 2016. The owner group also notes it has approval to waive earthquake insurance on the building, which could save another $59,600 per year from the Legislature’s $3.3 million annual bill. Amy Slinker, a spokeswoman for 716, said in a statement that Varni's memo lacks third party analysis. "The Department of Revenue's professional review shows the ability for clear savings," Slinker said. Revenue’s examination of the options put the upfront cost to move out of the LIO and remodel 30,000 square feet of the Atwood at $3.5 million to $5.5 million, with an annual building operating cost of $664,000. Purchasing the LIO in some fashion would require the initial payment and then operating payments of $269,000 per year for 45,000 square feet of usable space. Legislative Affairs concludes the Atwood's annual operating cost to be $613,000, based on Varni's memo. State ownership would also save $231,000 per year in municipal property taxes; however, taking the building off the city’s tax roll has been a reason cited by legislators for why the council did not purchase it initially. Anchorage Democrats, the public and legislators from elsewhere in the state have disparaged the LIO lease terms as far too expensive at a time when the state is facing annual budget deficits approaching $4 billion. On Dec. 19, the Legislative Council unanimously recommended the full Legislature vote not to fund the lease at a meeting in the Anchorage LIO unless a solution that is cost-competitive with moving to the Atwood Building could be resolved within 45 days — by Feb. 5. In a statement released prior to the proposal being made public — multiple news outlets were denied a copy when requests were made to Stevens’ office — Slinker wrote the group trusts the council will consider the proposal that meets the council’s terms. “Our discussions with Sen. Stevens over the past 45 days have pushed us to dig deep for short-term, interim savings,” Slinker wrote. “That then set the stage for a long-term solution to save millions of dollars and help avoid any negative financial implications for the state.” The building houses off-season offices for 25 Anchorage legislators and is the de-facto home to much of the general Legislature’s out-of-session activity. The Legislative Council, then led by Rep. Mike Hawker, R-Anchorage, decided to rebuild on the old LIO building site in 2013 after numerous attempts to find existing suitable space that meets the unique needs of a public government body in Anchorage failed. The Legislature contributed $7.5 million towards the construction cost, so Pfeffer and his company ultimately funded $37 million, about $28 million of which is long-term debt and $9 million is Pfeffer’s cash equity position in the property, he has said. Appraisals of the six-story building plus its underground parking facility have been as high as $48 million, but numerous estimates put its value at $44 million. The customized office space cost $44.5 million to build in 2014, according to Pfeffer. His group first drafted and submitted terms for the state to purchase the building for $37 million plus closing costs Oct. 9; a proposal requested by the Legislative Affairs Agency, which manages business for the council. The original terms agreed to by Legislative Affairs attorneys set a Jan. 31 deadline to act on the sale terms, according to correspondence between attorneys for both sides. 716 waived the deadline in a Jan. 29 letter on conditions that the council votes to buy the LIO by Feb. 5 or appropriate funds for fiscal year 2017 rent in the state budget.   Look for updates to this story in an upcoming issue of the Journal. Elwood Brehmer can be reached at [email protected]  

AK LNG talks ‘unlikely’ to meet deadlines

A lack of progress in negotiations between the state’s producer partners on major Alaska LNG Project agreements is likely to throw the project off schedule, according to a key member of the Walker administration. Deputy Department of Natural Resources Commissioner Marty Rutherford said in an interview that BP, ConocoPhillips and ExxonMobil are still working on the structure of the Alaska LNG Project’s critical Gas Balancing Agreement after more than a year of negotiations. Rutherford is the state’s lead negotiator for commercial terms on the project, Gov. Bill Walker has said. The Gas Balancing, or gas supply, Agreement is the underpinning contract for at least seven more issues that must be resolved within several months to keep the project on track, according to the administration. It provides a framework for the companies — each with a different share of North Slope natural gas dedicated to the project — to pull their gas from the fields at certain times without upsetting the overall operations of the project. Even if the Gas Balancing terms were reached immediately, she said, it would still be “highly, highly unlikely” that all the agreements could come together in time because it still takes months to finalize agreements met in principle. Rutherford noted she always thought the Alaska LNG Project commercial terms would be wrapped up in time for a spring 2016 special session, but she also characterized the general challenge of several-party negotiations, regardless of the topic. “Two-party negotiations are tough; three are very difficult and four are — it’s hell,” she said. Company representatives acknowledged the slow pace of the negotiations in recent testimony before state legislative committees. Gas supply agreements are common in joint-venture LNG projects, but disparate ownership in the Alaska LNG Project’s two major gas fields, Point Thomson and Prudhoe Bay, makes this negotiation particularly challenging, ConocoPhillips Vice President of Commercial Assets Leo Ehrhard told the Senate Resources Committee Jan. 27. The agreement dictates how gas is “lifted” from the field under normal operations, but also during downtimes for maintenance on one field or the other. Gas draws must also jive with when customers want LNG from the $45 billion-plus export project, further complicating matters. On top of all that, each party comes to the table with differing risk perspectives and policy goals in a time of particular financial stress, given the state of world oil markets, Rutherford noted. “There have been some pieces we haven’t even begun (negotiating) yet because the foundational, what I call the threshold agreement, hasn’t been landed, even structurally,” she said. Walker sent a letter to the company leaders in Alaska on Jan. 18 expressing his concern over the lack of progress. He said the state would seek other alternatives to commercialize its gas if the parties don’t reach an agreement by the end of the regular legislative session, which is in late April. The governor has said for several months he hoped to have a comprehensive set of project agreements in place for the Legislature to review late in the regular session so a special session to vote on the agreements could be held shortly thereafter. A special session would also include a vote on a constitutional amendment needed for the state to enter into long-term contracts — tax policy — for the initial 25-year life of the project. The Alaska Constitution prohibits one Legislature from taking the authority to tax away from future bodies, which locking the state into a 25 percent share of the project’s gas would seemingly do. “There is an absolute certainty that a constitutional amendment is needed if the fiscal agreements that the producers want contain the Legislature suspending their power to tax,” Attorney General Craig Richards said to the Senate Resources Committee Jan. 29. Richards noted many, if not most, states have similar clauses in their constitutions. He also said the Stranded Gas Development Act, an earlier attempt to monetize North Slope natural gas, included fiscal terms that would have required an amendment as well. Because the public must vote on the amendment in a general election, the Legislature’s vote needs to happen in time to get it to the Division of Elections before June 23, the deadline for getting it on the November ballot. If any of that falls apart, the project is all but delayed for at least two years until the 2018 general election. The timeline was imposed by the producers’ prerequisite to have fixed project tax terms, Rutherford said, which added deadlines for the fiscal term sheets and the subsequent constitutional amendment. Ehrhard also said the agreements are necessary for the project to enter the full-fledged front-end engineering and design, or FEED, stage. The decision whether to enter FEED has been expected sometime next year. Despite the challenges, the parties are continuously negotiating. “We’re working hard to try to get breakthroughs on all fronts with the hope that the unlikely could happen,” Rutherford said. “We’re totally focused on trying to make these dates.” Gas supply from each field is also an issue for the state, she said, but not on the level it is for the producers because the state holds an equal 25 percent share of gas in each field through royalties and the proposed tax share to be taken in-kind. The negotiations started even before the Walker administration took office in December 2014, but began in earnest about a year ago. Last June the producers asked the state to step aside so they could work on the issue themselves and the State of Alaska was invited back to the Gas Balancing table about a month ago, according to Rutherford. Elwood Brehmer can be reached at [email protected]

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