Elwood Brehmer

Alaska included in latest five-year OCS lease proposal

Alaska wasn’t excluded from the Interior Department’s latest five-year Outer Continental Shelf Oil and Gas Leasing Program plan released March 15, just days after President Obama issued a joint statement with Canadian Prime Minister Justin Trudeau calling for further protections of the nations’ Arctic areas. The proposed 2017-2022 program is a step in the Interior Department’s environmental impact statement process for determining what, if any, Outer Continental Shelf, or OCS, oil and gas lease sales it should hold. It does not ensure drilling off Alaska’s coast in the coming years, but it does evaluate potential sales in the Chukchi and Beaufort seas as well as the federal waters of Cook Inlet between 2017 and 2022. Also included are options to move a potential Beaufort Sea sale up from 2020 to 2019, and a no sale option. The Chukchi sale is scheduled for 2022 and Cook Inlet for 2021. The last Cook Inlet sale was in 2004 and drew no bidders. Elsewhere the proposal includes options for leases in the Gulf of Mexico, but removes sales in the mid- and South Atlantic coast areas. Interior Secretary Sally Jewell said in a department release that the program is a balanced proposal that protects sensitive areas and supports save development of the nation’s energy resources. Specifically to Alaska, Jewell said the proposal removes areas from consideration for leases — a 25-mile coastal buffer and the Hanna Shoal walrus foraging area in the Chukchi, and all of Bristol Bay — that Obama withdrew from future lease consideration in January 2015. “We know the Arctic is a unique place of critical importance to many, including Alaska Natives who rely on the ocean for subsistence,” Jewell said. “As we put together the final proposal, we want to hear from the public to help determine whether these areas are appropriate for future leasing and how we can protect environmental, cultural and subsistence resources.” The March 10 statement from the White House and Canadian Prime Minister Trudeau called for protecting at least 10 percent of each country’s Arctic federal waters by 2020. The Interior program report notes the fact that the Trans-Alaska Pipeline System, or TAPS, is currently running about one-quarter full and oil discoveries in the Chukchi and Beaufort seas have the potential to stem TAPS throughput decline. It also mentions a request by Gov. Bill Walker to move the Beaufort sale up from 2020 to 2018. In a statement from his office Walker commended Jewell’s decision to include potential Alaska OCS lease sales to this point in the program process. “Over the past year, I have had many meetings with Secretary Jewell to discuss our access to our resources. In those meetings, I emphasized to her the need for forward planning and ensuring that Alaska is part of the Interior’s five-year leasing plan,” Walker said. “Secretary Jewell and I have not always agreed on issues affecting Alaska, but I’m pleased that we can work with the federal government on this topic.” The Wilderness Society issued a statement expressing a hope the Obama administration will remove all Arctic areas from the Bureau of Ocean Energy Management’s final five-year OCS lease plan. Shell abandoned its multi-year, $7 billion effort to explore its Chukchi leases in September after the company received what it said was disappointing results from its lone exploration well. Shell also cited the federal regulatory process as a reason for discontinuing its Alaska OCS exploration. ConocoPhillips and Statoil followed Shell in announcing they would also suspend work on the Arctic OCS leases they hold. Shell spent more than $2 billion for its Arctic OCS leases; ConocoPhillips spent about $500 million. Soon after, Jewell announced Interior was canceling planned lease sales for the Chukchi and Beaufort scheduled for 2016 and 2017 based on lack of industry interest. Interior has also denied requests by Shell for extra time on its leases set to expire in 2017 in the Beaufort and in 2020 in the Chukchi, but the company is appealing that decision.   Elwood Brehmer can be reached at [email protected]

Alaska pushes back on Arctic plan with Canada

Alaska’s leaders in Juneau and Congress had harsh words for a joint March 10 statement from the White House and Canadian Prime Minister Justin Trudeau announcing plans for new emissions caps on the oil and gas industry and preservation of significant chunks territory in each country’s Arctic. The statement was released as Trudeau made the first official visit by a Canadian prime minister to the White House in nearly two decades. “Beyond deepening cooperation to reduce greenhouse gas emissions — which will have an outsized impact on the long-term health of the global Arctic — President Obama and Prime Minister Trudeau are announcing a new partnership to embrace the opportunities and to confront the challenges in the changing Arctic, with indigenous and northern partnerships, and responsible, science-based leadership,” the statement reads. It asks the leaders of all Arctic nations to embrace the objectives of conserving Arctic biodiversity, incorporating traditional indigenous knowledge in decision-making, supporting strong Arctic communities and building a sustainable economy in the region. The U.S. took chairmanship of the international Arctic Council last year from Canada, which held the post starting in 2013.  The council is a non-binding body of eight Arctic nations meant to spur positive relationships between the countries on Arctic issues. Secretary of State John Kerry will lead U.S. representation at an Arctic Council meeting in Fairbanks next week. Sens. Lisa Murkowski and Dan Sullivan and Gov. Bill Walker all noted the omission of Alaska in drafting the 10-page agreement in formal statements of their own. The sentiment is similar to comments made following the president’s three-day visit to Alaska last summer, which was used as a vehicle to promote his climate change policies. “The Arctic presents great opportunity for our state and our nation to prosper in a global economy. However, the way to achieve that is by greater federal investment in our state’s Arctic development efforts, and not the restrictive policies that were presented today,” Walker said March 10. “It is important to consider the interests of all stakeholders in the region – whether it be focused on marine and wildlife preservation, international travel and shipping, or natural resource development. In doing so, we will ensure Alaska and the United States remain at the forefront of a flourishing Arctic economy.” Walker has said he pushes Obama to allow for oil and gas exploration on the coastal plain of the Arctic National Wildlife Refuge each time he meets with the president, despite actions from the White House to move further towards preservation, not development, of the area. Specifically, the U.S.-Canadian Arctic plan calls for protecting at least 17 percent of the countries’ Arctic land and 10 percent of far north marine waters by 2020. Obama and Trudeau also agreed to the “ambitious and achievable” goal of reducing methane emissions from oil and gas operations by up to 45 percent below 2012 levels by 2025, according to the statement. Further, both countries also endorsed the World Bank’s initiative to eliminate routine methane flaring from oil and gas facilities by 2030. Methane is the primary component of natural gas. “Recognizing the role that carbon markets can play in helping countries achieve their climate targets while also driving low-carbon innovation, both countries commit to work together to support robust implementation of the carbon markets-related provisions of the Paris (climate) agreement” reached in December, the joint statement reads. The countries would also be required to consult each other before approving future oil and gas development in the Arctic. Murkowski called the consultation requirement “simply stunning” in a release from her office. She also said by focusing almost solely on climate change in regards to the Arctic, the Obama administration fails to address other needs in the region, namely economic development. “Although the joint statement makes topical reference to consultation with indigenous people and the incorporation of traditional knowledge into decision-making, it also implies unjustifiable limits that will leave Alaskans standing at the door, rather than seated at the table, on Arctic policy,” Murkowski said. Environmental groups hailed the announcement as leadership towards protecting one of the world’s most delicate environments. To achieve the methane reduction goals the Environmental Protection Agency and Environment and Climate Change Canada will develop new regulations governing methane emissions from existing oil and gas sources as soon as possible. The EPA will quickly begin a process requiring producers operating existing methane emissions sources to provide data that will assist in developing “comprehensive standards to decrease methane emissions,” according to the joint statement. The proposed actions will harm the nation’s energy sector, and in-turn could impact the lives of hundreds of millions of Americans that rely on low-cost energy for their quality of life, Sullivan said, adding they could be “particularly devastating” for Alaska at a time when the state needs oil and gas revenue more than ever. “If the initiatives are enacted, less oil and gas will be produced in our state, more jobs will be lost, and state coffers will be increasingly diminished,” he said. “Now is the time when Alaska needs a federal government that will work with the state, instead of working against us to stymie economic opportunity.” Arctic fisheries were also addressed in that Obama and Trudeau are calling for an international agreement to preemptively close unregulated fishing in the central Arctic Ocean, an area that is increasingly accessible as summer sea ice continues its retreat.   Elwood Brehmer can be reached at [email protected]

Walker orders operational review of state-owned corporations

Gov. Bill Walker’s administration is exploring ways Alaska’s state-owned corporations can maximize their benefit to the state economy through efficiencies and possible combining of efforts. The governor issued an administrative order Thursday morning to jumpstart the operational review process for the Alaska Housing Finance Corp., the Alaska Energy Authority and the Alaska Industrial Development and Export Authority. That process will also involve several regular state departments. Walker said in a press conference that the administration is doing with the three state agencies what it has been trying to do in executive branch departments — to save the state money during a time of multi-billion dollar budget deficits without impacting critical services. He emphasized the review would have no impact on the agencies’ existing projects or obligations. “This is not about cutting back services to Alaskans; this is about doing things more efficiently and how do we use the assets — combined it’s roughly $4 billion of worth in these companies. That’s a big economic engine in the state,” Walker said. The end result of the review is unknown at this point, but Department of Administration Commissioner Sheldon Fisher said there are three main steps to the process. First, each agency’s role in improving conditions for economic development in the state will be examined with help from the Commerce Department. Second will come program reviews to ensure what the three are doing is necessary or being done to the maximum extent possible; and third will be a look at business operations and how those can be improved, streamlined or even combined, according to Fisher. He said it would be similar to the shared services initiative being done to ensure administrative duties in state departments are being handled as efficiently as possible. From there, the process will result in identifiable outcomes, according to Walker. The quasi-government agencies are self-funded enterprise organizations that were originally sown with legislative appropriations in the 1960s and ‘70s. AEA and AIDEA are largely consolidated already. The organizations share an Anchorage office and board of directors, but the authorities’ missions are separate. Both also fall under the purview of the Department of Commerce, but are rarely subject to executive branch requirements. AIDEA’s focus is on traditional economic development through direct project investment and business loans. AIDEA Executive Director John Springsteen said the authority averages about a 5.5 percent return on its business deals, or about $380 million total since its creation. AEA focuses mostly on rural energy, administering the state’s Renewable Energy Fund grant program for small-scale energy projects and the Power Cost Equalization Program, which subsidizes rural electric costs down to rates more comparable with urban parts of Alaska. AEA has also led the state’s evaluation of the large Susitna-Watana Hydro project. “Affordable energy is the foundation of economic development,” AEA Executive Director Sara Fisher-Goad said. “Our return to the state is really in the projects we’ve managed and working with communities and utilities to reduce energy costs for Alaskans.” AIDEA and AHFC each return annual investment dividends to the state General Fund. The foundation of AHFC’s business is the more traditional mortgage lending market, but its niche is to provide financing for affordable housing projects that don’t quite “pencil out” for private investors, its Executive Director Bryan Butcher said. AHFC also administers several housing-focused energy efficiency rebate and loan programs for the state. It is under the Department of Revenue for management purposes much the same way AIDEA and AEA fall under Commerce. House Speaker Rep. Mike Chenault said in a press briefing following the announcement that the House would be willing to look at the prospective benefits of combining the organizations, but doing so would almost certainly require changes in legislation, which Walker said would likely come next year. While it is unknown how long the review process will take, Chenault noted that the administration asked for $500,000 from the Legislature to support the effort. That would be matched about $500,000 in receipts from the agencies, he said, to bring the total cost to about $1 million. Along with the evaluation Administration will do on the agencies’ operations, it will give the Commerce and Revenue departments an inventory of state facilities “appropriate for enterprise development, consolidation, or other forms of efficiencies,” the administrative order states. Similarly, the Department of Natural Resources will compile an inventory of state lands it deems suitable for economic development.   Elwood Brehmer can be reached at [email protected]

IEP talks advance with Cook Inlet gas partner

The Interior Energy Project took a big step forward March 3 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 2015 request for proposals, or RFP, issued by the state authority. According to an analysis by the global consulting firm Arcadis Inc. of Salix’s proposal, 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 past 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. Avista spokeswoman Jessie Wuerst said the company is very pleased to have been chosen as a partner to this point but declined to comment further because project negotiations are ongoing. The basic financing structure for the plant would start with a $30 million equity investment by AIDEA and a $28 million, long-term, low-interest loan from the state Sustainable Energy Transmission and Supply Fund. Salix would post a $10 million equity stake; requiring an 11.7 percent rate of return. Shefchik said the $3.24 per mcf tolling fee identified by Salix for the LNG plant  — the first major cost layered on the wholesale gas price to add up to the final “burner tip” cost of gas for consumers — could fall in negotiations. “As we work with Salix on both the term sheet and the financing, our effort is to push that $3.24 down to the $2 range and we believe that’s possible,” he told the AIDEA board. 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. Financing for the Salix plant would come from that pot of funding, as the legislation was amended last year to support a Cook Inlet-sourced Interior Energy Project. The ability for Cook Inlet producers to supply another market long-term was unclear in 2013, but the Inlet’s available gas reserves have grown since, as new companies have entered the market and Hilcorp Energy’s work on existing gas fields has also greatly improved the situation. Further buoying Salix’s proposal is a $6 per mcf Cook Inlet wholesale gas price, and the prospect of even lower-cost natural gas to feed the LNG plant, according to the project evaluation. Southcentral utilities have signed gas supply contracts in recent months for base demand in the $7.50 per mcf range, less than a current state-mandated price cap that expires at the end of 2017. Shefchik said in an interview the project team is negotiating with multiple producers for gas supply. He also 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. Larger LNG trailers should also play directly into improving the final cost of gas in Fairbanks, Shefchik said. Pentex Alaska Natural Gas Co., the parent company to Fairbanks Natural Gas owned by AIDEA, has been testing a 13,000-gallon capacity LNG trailer for suitability along the route from Southcentral the Fairbanks. Positive results from those test runs means the larger LNG trailer could lower transportation costs by about 30 percent versus the 10,500-gallon capacity trailers currently used to supply Fairbanks Natural Gas from the small LNG plant on Point MacKenzie. Additionally, building the Salix plant on the same pad as the plant run by Pentex subsidiary Titan LNG could offer operational savings by running both plants with a single operator. Shefchik said the location the Salix plant isn’t yet settled but he hopes it can be built alongside the existing plant to minimize capital costs and maximize operational efficiencies. 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 are with Salix are ongoing, according to Shefchik, and an official recommendation from the AIDEA board to continue is expected at its March 31 meeting. Fairbanks rates drop 10.4 percent Fairbanks Natural Gas President Dan Britton told the AIDEA board that changes to the utility’s pricing structure implemented Jan. 1 have largely been successful, resulting in ratepayers bills being lowered by an average of 10.4 percent during the first two months of the year. AIDEA took ownership of the utility last year through the authority’s $52 million purchase of FNG’s parent company Pentex. Transfer of the private, unregulated utility to a public entity allowed for lower rates of return and tax savings among other items that were first expected to result in 13 percent rate reductions for FNG customers. At the same time, Britton wrote in a brief operational report to the AIDEA board that the warm Interior winter and low fuel oil prices have combined in a gas sales volume that is 17 percent, or about $700,000 below budget for January and February. “We will be watching expenses very closely,” Britton said, adding capital projects may be deferred if the trend continues. He said in an interview that margins were already thin after the rate reduction but that the utility is still on solid financial footing. With the forecast showing no sign of a cold snap, Fairbanks seems to have escaped this winter without hitting minus-30 degrees Fahrenheit. Most winters the city sees more than 20 days colder than minus-30, Britton said, which simply means customers burn less natural gas. The number of heating degree days — a temperature-based metric for determining how much energy is required to heat a structure during cold weather — in Fairbanks has also been off 17 percent from FNG’s budget in the first to months of the year, according to the report to the board. Piling on the warm weather is cheaper fuel oil that has led some Fairbanks Natural Gas customers to revert back to the fuel the city has so badly wanted to get off of. At about $2 per gallon delivered, fuel oil is about 25 percent cheaper on an energy equivalent basis than FNG’s current price for natural gas, which is about $20 per mcf, according to Britton. He said 12 of the 14 school district buildings that the utility had budgeted to be on natural gas switched to fuel oil in January and February, along with the state’s Ruth Burnet Sport Fish Hatchery. Many of the utility’s large customers are interruptible, which allows FNG to supply them with gas when it is available. That also means interruptible customers must have a backup fuel source — and when the backup fuel is cheaper it is their prerogative to switch. Elwood Brehmer can be reached at [email protected]

Enstar to save $14M in first year of new gas deal with Hilcorp

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. 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 primary fuel source have made similar comments regarding their own demand forecasts. Last year Chugach Electric Association and Homer Electric Association signed gas supply contracts extending beyond 2017 at prices less than 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 add about 15 cents to the average yearly gas price 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, but the state and its partners have announced they won’t have key agreements in place for approval by the Legislature this year, likely delaying the effort. As to the large share of the contract — filling upwards of 70 percent of Enstar’s total gas demand through one producer — Smith said frankly, “It’s because nobody else could do it.” While there is little doubt gas reserves in the basin could supply Southcentral for at least several decades, limited local demand continues to hinder the market for Inlet gas. Producers could develop the resource, but they would have no one to sell it to. Thus, the market has narrowed to one with a single, dominant producer in Hilcorp, despite having some of the highest wholesale natural gas prices the world currently. Hilcorp’s near exclusive control of Cook Inlet natural gas supply spurred the Consent Decree — a way for the state to limit the monopoly power over a critical commodity. Smith said the Consent Decree did its job in that it ended exorbitant high bidding for peak demand gas sales and added a “degree of functionality” to the market. For its part, Hilcorp has been a reliable partner and provided good service to its utility customers, she said. “Without engaging in hyperbole, (Hilcorp has) acted as very good stewards of the state resource to ensure stability for utilities,” Smith said. She added that Enstar would still like to see more players, on either side, in the market. Since Agrium Inc. shut down its Nikiski fertilizer plant in 2007, Enstar has become the major buyer, accounting for a third to half of all gas demand from the Inlet. Just three years ago Enstar resisted the idea of new Cook Inlet customers because the market was strained on the supply side, Smith said. Hilcorp’s work to improve supply from existing fields has flipped the market challenge. Now, the utility would prefer to be “noise” in a much larger gas market, Smith said, under the premise that a larger market would spur more production leading to better security of supply and price competition. Sporadic sales from ConocoPhillips’ Nikiski LNG export facility have increased gas demand slightly over the last couple years, but depressed worldwide LNG prices have put the immediate viability of future exports in question. Furie Operating Alaska LLC is finishing early development of its Kitchen Lights Unit and has one small contract in place with Homer Electric, under which gas sales are set to start in April. The base load gas price in that deal is $7.42 per mcf, according to RCA filings. Elwood Brehmer can be reached at [email protected]

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]al.com.

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]            

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