Elwood Brehmer

UA plan focuses on campus strengths

The University of Alaska Board of Regents and university President Jim Johnsen have agreed on a framework to restructure the system’s campuses at a time when saving money is paramount. “Each main campus — Anchorage, Fairbanks and Juneau — will focus its research, teaching and service on its unique strengths, capabilities, advantages and opportunities. “The ‘lead campus’ model will eliminate duplication and strengthen degree programs, reduce duplicative administration and put a greater emphasis on delivery of courses through technology,” Johnsen said in a formal statement. The draft strategic outline resulted from a two-day regents work session held in Anchorage Jan. 21-22. The unrestricted General Fund portion of the University of Alaska’s budget has been cut significantly in recent years and Gov. Bill Walker’s 2017 fiscal year budget would cut it by another $15 million, to $335 million next year. Under the university plan, the University of Alaska Anchorage, for example, would focus on workforce development in nursing and lead economic and policy sciences research, a UA release states. The University of Alaska Fairbanks would focus on technological and engineering research — its historic strengths; and the Southeast campus would focus on interdisciplinary studies and programs to support the maritime and mining industries. General education classes required as prerequisites for most all coursework would still be available at all campuses, according to the university system. “While this will have impacts on students, communities and university employees, restructuring will preserve excellent and diverse program options across the system and respond to the unprecedented reductions in our budget,” Johnsen said. “The board of regents and university leadership believe this is the best way to use increasingly scarce resources to meet the needs of students and our state.”

Walker bills would shift tax credits to development loans

After more than six months of speculation, Alaska got its first look at Gov. Bill Walker’s solution for what he calls an “unsustainable” oil and gas industry incentive program Jan. 19 when Senate bills 129 and 130 were read for the first time on the Senate floor. Walker jumpstarted the oil and gas tax credit debate last June when he nixed $200 million in credit payments from state operating budget before signing it. What started as a $10 million per year tax credit program in 2003 has grown to a $700 million obligation this year and that payment could eventually hit $1.2 billion if left untouched, the governor contends. SB 130, if enacted, would significantly trim the current credit program and nearly immediately save the state an estimated $500 million at a time when oil prices below $30 per barrel have edged the state’s budget deficit ever closer to $4 billion. The bill would cut spending by eliminating the Qualified Capital Expenditure and Well Lease Expenditure refundable credits applicable to Cook Inlet basin work. When combined with closing a loophole that currently allows some North Slope companies producing “new oil” to claim a 20 percent Gross Value Reduction Credit on top of a net operating loss, repealing the credits would save about $200 million per year. The Qualified Capital Credit reimburses up to 20 percent of all capital development costs and the Well Lease Credit covers up to 40 percent of drilling expenses. Both of the Cook Inlet credits are transferrable. Another $200 million in savings would come by way of adding stipulations companies must meet before the state will directly repurchase tax credits from small producers, according to a fiscal analysis of the bill. Walker’s proposal would cap annual repurchases at $25 million per company and directly tie the refundable percentage of a credit certificate to a company’s — and its contractors’ — Alaska resident hire rate. The remaining credit amount not eligible for a refund based on Alaska hire limits could still be applied to a tax liability. Small producer credits would still be transferrable; however, companies not meeting the stricter guidelines would have to hold the credits until they accrue a tax liability with the state. Credits held for too long would expire after 10 years. Finally, SB 130 would “harden” and raise the minimum gross production tax for oil from North Slope fields not eligible for the Gross Value Reduction Credit. It would prevent several credits, including the Net Operating Loss, or NOL, Credit from being applied to take a production tax obligation below the minimum, often referred to as the tax “floor,” which is currently at 4 percent. That 4 percent minimum production tax would go up to 5 percent in the governor’s bill, a move that would generate about $100 million per year to the state in additional revenue. The increased floor would be applied to all North Slope fields, even new fields eligible for the 20 percent Gross Value Reduction. In its final report, the Senate Oil and Gas Tax Credit Working Group assembled over the summer by Resources chair Sen. Cathy Giessel also recommended hardening the tax floor to prevent large producers from paying no production tax, but the group did not weigh in on raising the minimum tax. Everything the working group proposed was with the future in mind, Giessel said in an interview Jan. 26, and Walker’s bill, as currently constructed, would make the tax floor change retroactive to Jan. 1, 2016. She also called raising the minimum tax to 5 percent a “blatant change” to the More Alaska Production Act, better known as Senate Bill 21, something Walker said he would not do after it was upheld by the voters in an August 2014 referendum. SB 129 Senate Bill 129 would form an Oil and Gas Infrastructure Development Program within the Alaska Industrial Development and Export Authority. A $200 million appropriation would be needed to jumpstart the fund, which would finance oil and gas infrastructure development projects on proven reserves for small and medium-sized companies in lieu of some credits. AIDEA, as the state’s financier, manages revolving loan funds aimed at economic development and holds business interests around the state. The authority typically invests with market returns in mind, but its goals can change with legislative direction. Revenue Commissioner Randy Hoffbeck said during a Jan. 22 press briefing that there is flexibility within the loan program, but AIDEA should be able to recover a competitive rate of return and still offer more attractive financing than private lenders. “What we’re trying to do is build a loan program that steps in where some of these companies are paying venture capital rates or private equity rates that run in the neighborhood of 18 to 20 percent on some of these projects,” Hoffbeck said. “We feel that we can step in and give (companies) a rate that’s a little more reflective of a project that’s a little further down the road because we see a little more certainty in what they’re doing than what they’re finding in the marketplace.” Smaller companies often use the cashable credits as collateral for loans to fully cover exploration costs. AIDEA board member and former Fairbanks-area state senator Gary Wilken said he is excited about the prospect about helping support Alaska’s premier industry and has no qualms about the authority’s ability to meet the challenge. “I think the seven people on the board, including myself, will have the talent to figure out how to execute this if we’re given the responsibility,” Wilken said in an interview. “I think we see the vision; I think we see the benefit and I just have to believe that we’ll reach out and get whatever it takes. If it’s beyond our resources we’ll go get the proper resources to do this right.” While under the auspice of the Commerce Department, AIDEA is a self-funded, for-profit entity that is not bound by the state’s current budget challenges and therefore could expand to manage an additional program. Giessel said the idea of running a loan program through AIDEA would put the state in competition with private lenders, a move that “makes no sense.” The authority on its own has partnered with small producers to finance development projects on the Slope and in Cook Inlet in recent years. It would also mean money already in Alaska would be recycled through the program, while the tax credits, as loan collateral, are bringing in new money from Outside lenders, she said. Impact of changes Walker’s remodel of the oil and gas tax credits is without question a substantial shift from the status quo, something the Oil and Gas Tax Credit working group report urged against — at least right away. His $200 million deferment from the 2016 fiscal year still left the state paying $500 million of what was a $700 million General Fund line item. The remaining $200 million from 2016 is included in a transition fund of nearly $1 billion to pay off credits expected to be earned before the legislation could be enacted. From there, the state’s obligation would shrink to about $200 million per year through 2022, a projection based on the remaining tax credits. Under the current system, the State of Alaska pays upwards of 65 percent of development costs on many projects and up to 85 percent of the cost of exploration because of the ability to “stack” credits, according to the Department of Revenue. A sea change is exactly what representatives from the industry and their supporters in the Legislature have said they don’t want. Walker said in an interview with the Journal that his administration met with each independent exploration and production company that has used the tax credit system to make sure none “fall through the cracks” during a shift away from the current credit structure. “We’re unique with the credit program across the country and (the companies) realize that,” Walker said. His critics on the issue largely agree with the governor that Alaska is unique; they contend the state has a uniquely high cost of doing business, and therefore the credits are essential to spurring development. Alaska Oil and Gas Association President Kara Moriarty said in an interview that she understands the fiscal pickle the state is in, but changing the tax credit system at a time when the companies are also cash-strapped brings about the ever-dreaded political uncertainty. “Policymakers cannot control the price of oil, so you want to have policies that attract investment even when the price of oil is low,” Moriarty said. A member of Giessel’s working group, she also questioned the equity of hardening the production tax floor and not allowing producers to claim a loss against future tax burdens that would take them below the minimum tax threshold. Moriarty said allowing oil and gas producers to claim NOLs, regardless of the minimum tax, is no different than companies in other industries deducting losses on future corporate tax liabilities. On raising the minimum tax, Moriarty was clear: “That will impact production, it just will.” A Revenue Department analysis of SB 130 states that — based on the department’s Fall 2015 Revenue Sources Book — Alaska North Slope crude prices should rebound by 2019 to a point where hardening and raising the production tax floor to 5 percent will no longer factor into tax payments for producers. Revenue is predicting an average ANS price of $68.95 per barrel in fiscal 2019. Now, early in 2016, the state has 12 credits available to explorers and producers across the state. Most are specific to the Slope and Cook Inlet basins, while two are for “Middle Earth” exploration and development credits for work outside of the developed areas, such as Doyon Ltd’s drilling in the Nenana basin near Fairbanks. Four of those credits will sunset by Jan. 1, 2017, if the program continues unchanged. The governor’s proposal to eliminate two of the Cook Inlet capital credits would leave six on the table at the start of next year: three nontransferable and one refundable Slope credit; a refundable Middle Earth exploration credit; and a lone 25 percent Carry Forward Annual Loss Credit for Cook Inlet. Sen. Bill Wielechowski, D-Anchorage, another working group member, has said the state has employed a “scattershot approach” to the credits without thoroughly vetting their benefit. Credit benefits A brief Department of Revenue report examining the fiscal pros and cons of the North Slope credits made public over the summer determined that the credits don’t represent a sound financial investment for the state. Hoffbeck said the seven-page report was incomplete and should not have been released because it limited the benefits to historical production and did not include assumed future production aided by the credits in its analysis. Definitively concluding whether the credits are a good investment for the state is “almost an unanswerable question,” Hoffbeck said in an interview. It’s unknowable whether certain projects would have moved forward or not without the state’s help. The department is more focused on figuring out what’s affordable for the future rather than analyzing historical credits, he said. Those wary of major changes to the credits at a time when North Slope producers are faced with production and transportation costs — in the $48 per barrel range, according to the Revenue Department — far exceeding oil prices that have slid to less than $30 per barrel, say the benefits of the subsidies go well beyond the state’s bottom line. Pat Galvin, chief operating officer for Great Bear Petroleum LLC and a former Alaska Revenue commissioner, recalled during a Jan. 8 discussion panel on the issue a conversation he had with a member of the Walker administration, who said the state will go from paying two-thirds of most exploration costs to about 30 percent under the governor’s plan, with the anticipation the companies themselves will be willing and able to cover the gap. Great Bear Petroleum, founded in 2010, conducted a $50 million exploration drilling last winter on its Slope prospects south of Prudhoe Bay. Galvin said just the exploration credits already set to expire July 1 with the start of the 2017 fiscal year would directly impact activity. “By taking on that exploration risk, the state is allowing for more exploration activity,” Galvin said. “Exploration leads to discoveries; those lead to development, which leads to production. If you don’t get enough projects in the hopper you don’t get enough exploration activity taking place you’re going to get less discovery, less development and less production at the end of the day.” Increasing exploration is the best way for the state to assure future production, he said. He added that if AIDEA is too risk averse and won’t lend to explorers, the loan program won’t accomplish much. Kenai Peninsula Borough oil and gas expert Larry Persily said during the Jan. 8 panel that the credits should be examined not only by their contribution to the state treasury, but what they do for local economies. A study commissioned by the Alaska Oil and Gas Association calculates each direct Alaska exploration and production job supports another nine private sector positions. While Cook Inlet oil carries no production tax and gas from the basin has a minimal tax, the production still contributes royalties, property and corporate income taxes to the state, Persily said. He also noted that incentivizing Cook Inlet gas production helped stave off the natural gas shortages that were feared in Southcentral just three years ago. “There’s no question that tax credits have been good for Cook Inlet, good for utilities, good for customers, good for production — certainly good for the local economy and jobs. Whether they’ve been a net plus, a net gain to the state General Fund is a separate question,” Persily said. Lease expenditures in Cook Inlet have increased fourfold since the state focused in incentivizing activity in the basin in 2010, according to Persily. Giessel concurred with him, saying even small producers not paying production tax bring back three to four times to state coffers what they receive in credits. “This oil tax credit program is a rebate. Folks do not get this money unless they spend money,” Giessel said. “It’s not a giveaway.” The Senate Resources Committee will take up the bills in a couple weeks and get plenty of illumination from the administration on the legislation’s finer points, she said. “I need more clarity as to how it increases production,” Giessel said. She added that she certainly has ideas on how to adjust the tax credit system and a separate bill could be on the way in several weeks as well. Transparency Giessel’s working group also encouraged opening the books, at least a little, so the public can see what the state’s oil and gas tax credit investments are returning. “Though it is not advocated for the names of the operators to be disclosed at this time, the public disclosure of investment amounts can better inform both the public and policymakers, on any other changes to make to the credit system,” the working group report concluded. “Alaskans deserve to know what the other side of the table is spending on a project if their money is investing in its success.” Walker would support more disclosure of the tax credit program, he said, but current statutes tightly restrict what data the state can release and his bills do not address the issue of transparency. He said if the state goes to a broad-based tax on residents while continuing to fund the credits it would definitely be more appropriate for Alaskans to understand what the state is investing in. Moriarty said she believes her member companies are forthright in explaining what the credits have done for them, but contended narrowing disclosures to specific projects “would really allow policymakers and the public to pick winners and losers” amongst the companies, a situation she is not comfortable with. “We’re open to ideas to be more transparent as long as that information is not used against us by other policymakers,” she said. In most years the governor’s 38 pages of oil and gas tax credit and loan program legislation would be enough to dominate the Legislature’s time, as oil industry policy has in the past. This year, however, even bigger budget issues, the Alaska LNG Project and criminal justice and Medicaid reform make oil and gas tax credits just another item on the Legislature’s daunting to-do list. Elwood Brehmer can be reached at [email protected]

Interior Energy Project decisions moved back again, to Feb.

The Alaska Industrial Development and Export Authority should have its new Interior Energy Project partner in place by the end of February, according to project leaders. A partner recommendation can be expected the second week of February, IEP manager Bob Shefchik said in an interview, with a special AIDEA board meeting to be held later in the month to take formal action on the staff recommendation. The time between the announcement and the board meeting will allow the AIDEA board and the public to scrutinize the IEP team’s recommendation, Shefchik said. AIDEA officials spent much of 2015 evaluating new proposals to get natural gas to Fairbanks-area consumers for the project’s stated goal of $15 per thousand cubic feet, or mcf, of gas. What started as 16 ideas in early August has been whittled to two: Spectrum LNG’s proposal to build a North Slope LNG plant and a plan by Salix Inc. to build a Cook Inlet-sourced LNG facility at Point MacKenzie. Oklahoma-based Spectrum LNG operates a small LNG plant in Arizona and helped develop Fairbanks Natural Gas’ supply chain in the late 1990s to feed the utility with LNG trucked from Southcentral. Salix is a subsidiary of Avista Corp., which owns electric and natural gas utilities in Idaho, Washington and Oregon. Avista also owns Alaska Electric Light and Power Co., the Juneau-area electric utility. Shefchik said that the project team is working to secure natural gas contract terms from both Cook Inlet and North Slope producers before making a final suggestion to the AIDEA board. “We want to make sure we have gas contracts underneath the North Slope and Cook Inlet so that as we’re making recommendations on $50 (million) to $80 million investment we’re not modeling what the gas costs, we know what it costs,” Shefchik said. Golden Valley Electric Association, the Interior’s main electric utility, has a 15-year gas supply agreement for North Slope natural gas with BP that the utility has made available to the Interior Energy Project as well. Shefchik said the group is evaluating all supply options. The omnipresent contrast between lower wholesale gas costs from the Slope against lower construction and transportation costs in Southcentral has made defining a clear-cut winner difficult. The desire to have a complete project for review is what led to pushing an initial, self-imposed early December deadline for a project recommendation back two months, he said. Spectrum’s plan is for an $85 million North Slope LNG plant that would need $30 million in equity and $50 million in low-interest loans from AIDEA. Spectrum would contribute $5 million in equity. Salix is hoping to build a $68 million Southcentral plant also with a $30 million equity investment by AIDEA and a $28 million loan, with Salix offering a $10 million investment. The new oil price reality Alaska’s lawmakers are dealing with is also straining the economics of the Interior Energy Project. “We’re challenged on the differential between the price of oil translating into fuel oil and the target price of gas, so we’re being pretty careful on having lowered our conversion expectations and then deciding how can we continue a project in a low price environment,” Shefchik said. Revised estimates on the demand for natural gas, once it becomes available in the Interior, have lowered the demand forecast by as much as a 30 percent since the project began. Natural gas at $15 per mcf is about half the energy equivalent cost of $4 per gallon fuel oil — roughly the price scenario facing Fairbanks when the Legislature funded the project in 2013. Since then, plummeting oil prices have pulled the price of fuel oil closer to $2 per gallon, which makes it less likely residents will spend potentially thousands of dollars to convert their home heating systems. Consequently, AIDEA is also working to consolidate state and federal energy rebate and loan programs to help offset conversion costs for residents and keep the Interior Energy Project financially viable. Elwood Brehmer can be reached at [email protected]

Legislature gets first update on pros, cons of AK LNG Project

Legislators got their first briefing of the session on the Alaska LNG Project on Jan. 25 direct from the project’s lead manager, ExxonMobil’s Steve Butt. In presentations to the House and Senate Resource committees, Butt implored legislators to view themselves as the board of directors for the state, as a 25 percent owner of the $45 billion to $65 billion prospective development. “We view ourselves as kind of a project organizer evaluating technical and economic viability of the AK LNG Project; does it make sense to the investors?” he said to House Resource members. In a time of a depressed global LNG market — spot prices have fallen by some 50 percent over the last three years — Butt outlined some of the simple but not-to-be understated benefits of Alaska’s project and how it compares to others around the world competing for market share. First, Alaska’s North Slope resource of 32 trillion cubic feet, or tcf, of natural gas is well defined and largely developed. The gas beneath Prudhoe Bay has been captured and re-injected many times to maximize oil production and the wells and other infrastructure needed to retrieve the gas from the reservoir are in place.  ExxonMobil and BP have spent roughly $4 billion developing Point Thomson to the east of Prudhoe Bay to supply about 25 percent of the gas for the AK LNG Project, but that work is also wrapping up as Point Thomson will begin producing about 10,000 barrels of natural gas liquids per day to go into the trans-Alaska Pipeline System this year. Further development will still be needed to equip Point Thomson for gas production and transport to the AK LNG Project, however. Butt said many other LNG projects worldwide have upstream development costs that Alaska does not. Additionally, the Federal Energy Regulatory Commission, as the federal overseer of the project, enjoys the knowledge of known resources and established infrastructure in its decision-making process, he said. Alaska’s relatively close location to Asian markets that will likely be the buyers of from the project is a benefit that has been well documented. Shipping LNG from Alaska to Japan, Korea and China is cheaper and faster than from export projects in the Gulf of Mexico or Australia where competing projects are likely to be. Alaska’s location in the northern hemisphere also allows the project to maximize production efficiency that matches swings in market demand, according to Butt. LNG is produced by chilling natural gas to minus-260 degrees Fahrenheit, which results in a condensed, easily transportable liquid product. Alaska’s cold, dry climate allows liquefaction plants here to produce 10 percent to 15 percent more LNG than comparably sized plants in the Middle East or other warm locales. “Buyers are in the northern hemisphere and they want more LNG in the winter — January and February — when the turbo machinery in Alaska is more efficiently generating LNG,” Butt said. A more efficient process means a more cost-effective project. Those advantages hopefully offset the AK LNG Project’s big but unavoidable disadvantages, he said, which are the North Slope gas treatment plant and the 800-mile pipeline needed to get the gas to an ice-free port. The natural gas coming out of Prudhoe Bay is about 12 percent carbon dioxide; a higher carbon dioxide concentration than the gas source for any currently producing LNG project in the world, he noted. When combined with the 4 percent carbon dioxide gas of Point Thomson, the project will have a blended gas of about 10 percent carbon dioxide makeup. That 10 percent carbon dioxide must be separated from the methane that is the usable natural gas and re-injected into the Prudhoe Bay reservoir. As a result, the project requires an upstream treatment plant pegged at roughly $15 billion. “That’s why there are no projects around the world handling this amount of (carbon dioxide) — it’s very expensive,” Butt said to the Senate Resources Committee. The $15 billion pipeline and associated infrastructure is the other major cost hurdle. LNG projects have been done with pipelines up to about 400 miles, he said, but Alaska’s would be double that. Therefore, minimizing cost by maximizing efficiencies in transportation, design and construction is paramount for a project with tremendous overhead in a highly competitive marketplace, Butt emphasized. Elwood Brehmer can be reached at [email protected]

Alaska Air does it again with record $842M profit in 2015

The State of Alaska might be rubbing pennies together, but its namesake airline is not. Alaska Airlines’ parent company, Alaska Air Group Inc., once again posted record fourth quarter and full-year earnings in 2015. Alaska Air Group executives reported a $186 million fourth quarter profit and a 2015 net income of $842 million in a Jan. 21 investor conference call. The quarterly profit is a 49 percent year-over-year improvement and the full-year return is 47 percent better than 2014. Many domestic carriers have seen profits grow as fuel costs have fallen over the last six quarters; however, Alaska Air Group’s strong performance, led by Alaska Airlines, has withstood high fuel prices as well. The company has now posted six consecutive years of record profitability. Seattle-based Alaska Air Group also owns Horizon Air, a regional carrier that serves Kodiak, Anchorage and Fairbanks. “While every airline has benefited from low fuel prices, Alaska led the industry in many of the underlying drivers of financial performance: areas like operation reliability, customer satisfaction, customer growth, and low fares-low cost,” Air Group CEO Brad Tilden said during the investor call. Alaska’s average fuel cost was $1.88 per gallon in 2015, down 39 percent from $3.08 per gallon a year prior. Tilden noted that markets constituting 95 percent of Alaska Air Group’s revenue would still be profitable at fuel prices of $3 per gallon. Fuel can account for up to a third of a major airline’s operating cost at higher prices. Flight capacity increased 10.6 percent for the year with the addition of 20 new markets in 2015, primarily on the back of 10.7 percent capacity growth by Alaska Airlines. That led to a 33 percent decrease in actual fuel cost. Consolidated yearly revenue was nearly $5.6 billion, up 4 percent from 2014, while total operating expenses fell 2 percent. At $1.3 billion, Air Group’s pretax income was up 35 percent. Air Group also used its strong year to buy back 5.5 percent of its outstanding stock. Since 2007, the company has repurchased 35 percent of its stock, according to Chief Financial Officer Brandon Pedersen. The $842 million full-year profit translated to adjusted earnings of $6.51 of per share, a 56 percent increase over 2014. Alaska Air Group stock sold on the New York Stock Exchange for $72.60 per share at the close of trading Jan. 21. The company also announced on Jan. 21 a 27.5-cent per share quarterly dividend that will be paid March 8. It paid a 20-cent per share dividend in the fourth quarter of 2014. Pedersen said non-fuel operating costs declined 1.3 percent in the fourth quarter and 0.8 percent for the year. “We recognize that low fuel prices will probably not last forever, so we remain focused on creating a permanent, sustainable advantage by lowering nonfuel unit costs and increasing the fuel efficiency of our fleet,” Pedersen said. Alaska Airlines is in the midst of phasing out older, Boeing 737-400s over several years and replacing them with newer, more efficient 737s. Air Group’s fuel burn improved 2 percent per available seat mile in 2015, Pedersen said. That led to an 8.3 percent increase in overall fuel consumption despite the 10.6 percent increase in capacity. Alaska Air Group continued to pay down debt in 2015. At the end of the year its debt-to-capitalization ratio stood at 27 percent, leaving the company in a $300 million net cash position with $686 million in outstanding long-term debt, according to Pedersen. The median debt-to-cap ratio for S&P 500 companies is 45 percent, he noted. “Alaska (Airlines) remains one of only two U.S. airlines to have an investment grade balance sheet,” Pedersen said. The other is Southwest Airlines. Tilden said Air Group’s return on invested capital, or ROIC, was 25.2 percent for the year, up from 13 percent in 2012. He added that the company’s 15,000 employees will share in the record year through $120 million in bonuses expected to be paid this year.

Alaska Air does it again with record $842M profit in ‘15

The State of Alaska might be rubbing pennies together, but its namesake airline is not. Alaska Airlines’ parent company, Alaska Air Group Inc., once again posted record fourth quarter and full-year earnings in 2015. Alaska Air Group executives reported a $186 million fourth quarter profit and a 2015 net income of $842 million in a Jan. 21 investor conference call. The quarterly profit is a 49 percent year-over-year improvement and the full-year return is 47 percent better than 2014. Many domestic carriers have seen profits grow as fuel costs have fallen over the last six quarters; however, Alaska Air Group’s strong performance, led by Alaska Airlines, has withstood high fuel prices as well. The company has now posted six consecutive years of record profitability. Seattle-based Alaska Air Group also owns Horizon Air, a regional carrier that serves Kodiak, Anchorage and Fairbanks in the state. “While every airline has benefited from low fuel prices, Alaska led the industry in many of the underlying drivers of financial performance: areas like operation reliability, customer satisfaction, customer growth, and low fares-low cost,” Air Group CEO Brad Tilden said during the investor call. Alaska’s average fuel cost was $1.88 per gallon in 2015, down 39 percent from $3.08 per gallon a year prior. Tilden noted that markets constituting 95 percent of Alaska Air Group’s revenue would still be profitable at fuel prices of $3 per gallon. Fuel can account for up to a third of a major airline’s operating cost at higher prices. Flight capacity increased 10.6 percent for the year with the addition of 20 new markets in 2015, primarily on the back of 10.7 percent capacity growth by Alaska Airlines. That led to a 33 percent decrease in actual fuel cost. Consolidated yearly revenue was nearly $5.6 billion, up 4 percent from 2014, while total operating expenses fell 2 percent. At $1.3 billion, Air Group’s pretax income was up 35 percent. Air Group also used its strong year to buy back 5.5 percent of its outstanding stock. Since 2007, the company has repurchased 35 percent of its stock, according to Chief Financial Officer Brandon Pedersen. The $842 million full-year profit translated to adjusted earnings of $6.51 of per share, a 56 percent increase over 2014. Alaska Air Group stock sold on the New York Stock Exchange for $72.60 per share at the close of trading Jan. 21. The company also announced on Jan. 21 a 27.5-cent per share quarterly dividend that will be paid March 8. It paid a 20-cent per share dividend in the fourth quarter of 2014. Pedersen said non-fuel operating costs declined 1.3 percent in the fourth quarter and 0.8 percent for the year. “We recognize that low fuel prices will probably not last forever, so we remain focused on creating a permanent, sustainable advantage by lowering nonfuel unit costs and increasing the fuel efficiency of our fleet,” Pedersen said. Alaska Airlines is in the midst of phasing out older, Boeing 737-400s over several years and replacing them with newer, more efficient 737s. Air Group’s fuel burn improved 2 percent per available seat mile in 2015, Pedersen said. That led to an 8.3 percent increase in overall fuel consumption despite the 10.6 percent increase in capacity. Alaska Air Group continued to pay down debt in 2015. At the end of the year its debt-to-capitalization ratio stood at 27 percent, leaving the company in a $300 million net cash position with $686 million in outstanding long-term debt, according to Pedersen. The median debt-to-cap ratio for S&P 500 companies is 45 percent, he noted. “Alaska (Airlines) remains one of only two U.S. airlines to have an investment grade balance sheet,” Pedersen said. The other is Southwest Airlines. Tilden said Air Group’s return on invested capital, or ROIC, was 25.2 percent for the year, up from 13 percent in 2012. He added that the company’s 15,000 employees will share in the record year through $120 million in bonuses expected to be paid this year. It will be the seventh consecutive year that each employee will receive a full month’s pay in performance bonuses, Tilden said.   Elwood Brehmer can be reached at [email protected]

Home sales decline around Alaska to end 2015

Home sales declined across much of Alaska in the fourth quarter of 2015, according to data provided by the Alaska Association of Realtors. Single-family transactions in Anchorage fell by 3.5 percent versus the last months of 2014, from 743 sales to 717. Condo sales fell by 9.6 percent in the state’s largest market, to 262 condos sold. Fourth quarter home sales fell by 4 percent in Fairbanks, 3.1 percent on the Kenai Peninsula and 2.6 percent in Southeast Alaska as well, compared to 2014. Average residential sale prices increased 2.4 percent to $358,400 in Anchorage and the average “days on market” also fell by 14.5 percent to 47 days, despite decreased sale activity. Condo prices in Anchorage fell by nearly 1 percent to $216,800. Single-family activity increased by 7.8 percent in the Matanuska-Susitna Borough and average sale price increased by 3.7 percent to $246,700. Along with that, the average number of days on the market for a single-family home in the valley fell from 73 at the end of 2014 to 63 in the fourth quarter of last year. Listing time in decreased by at least 14 percent for Southeast single-family homes and condos, as well as for Fairbanks, where the average single-family unit sold for $213,100 and spent just over two months on the market. Elwood Brehmer can be reached at [email protected]

Judge keeps subcontractors in port lawsuit

Subcontractors are still potentially liable for work done years ago on the disastrous Port of Anchorage expansion project, according to a federal court ruling. U.S. District Court of Alaska Judge Sharon Gleason ruled Jan. 13 that Quality Asphalt Paving Inc. and MKB Constructors, its working partner on the Anchorage port project in the late 2000s, are still subject to a lawsuit filed by the Municipality of Anchorage because the city never knowingly reconciled with the companies. Quality Asphalt Paving, or QAP, joined by MKB, filed a motion for summary judgment in the suit in August, claiming a September 2012 settlement for $11.1 million between the U.S. Maritime Administration, as the port project manager, and the subcontractors released them from liability. Gleason wrote in her Jan. 13 order denying the judgment motion that court records indicate the Maritime Administration, or MARAD, attempted to reassure the municipality shortly after the 2012 settlement that it did “not preclude (the municipality) from pursuing its own litigation.” An Oct. 19, 2012, letter from then Anchorage Mayor Dan Sullivan to MARAD Administrator David Matsuda supports the municipality’s contention that it was unaware of the settlement and further found the federal agency to be a weak negotiator, settling for $11.1 million when the agency found $11.5 million of a $17 million claim to be valid. Sullivan wrote that he was “surprised and disappointed” to learn MARAD settled a contract dispute with Integrated Concepts and Research Corp. on behalf its contractors QAP and MKB regarding the Port of Anchorage Intermodal Expansion Project. MARAD hired ICRC, a former subsidiary of the Kodiak-area Alaska Native corporation Koniag Inc., early in the project to act as its on-the-ground prime contractor. “When pressed whether ICRC (and subsequently its contractors) had been released from further claims, particularly claims that might be asserted by the Municipality of Anchorage, MARAD only made vague and general comments,” Sullivan wrote. “When further pressed as to whether funds of the municipality were used to settle the matter, MARAD pretended not to know the answer, although the clear implication was that the funds provided by the municipality were used without our knowledge or consent.” MARAD, a federal Transportation agency, was brought into the project in 2003 by the municipality to manage construction and be a vessel to acquire federal funding. Originally intended to update and expand the Port of Anchorage’s aging docks, the project was fraught with control and communication issues nearly from its outset. Those issues were manifested in construction problems and led to work being stopped partway through in 2010, which was never resumed. In all, the municipality spent roughly $302 million of state, federal and its money for virtually nothing. The Municipality of Anchorage originally filed suit in March 2013 against ICRC, dock designer PND Engineers Inc. and CH2M, which now owns a former project consultant. Anchorage filed a separate suit against MARAD in Federal Claims Court in February 2014 seeking to recover damages for the project. An August 2013 Inspector General report was deeply critical of MARAD for its handling of the Anchorage port project and other similar work in Hawaii and Guam. PND has long contended the construction problems associated with its patented Open Cell Sheet Pile dock were due to inexperienced contractors, not a faulty design, as the municipality and a study commissioned by the city conclude. PND filed a third-party suit against QAP and MKB, bringing the subcontractors into the tangled legal mess.   Elwood Brehmer can be reached at [email protected]  

Fairbanks wants bigger slice of $15.7B PILT pie

Emotions can run high when $15.7 billion is up for grabs. Decorum held Jan. 15 as mayors of the boroughs along the proposed Alaska LNG Project corridor debated the appropriate allocation of $15.7 billion the state and local governments could get in-lieu of traditional property tax revenue on the project’s infrastructure. However, the Municipal Advisory Gas Project Review Board meeting discussion certainly had an undercurrent of tension. Much of the back-and-forth centered on parsing out what is fair, particularly for the Fairbanks North Star Borough. While it’s widely assumed the Interior local government area will act as a hub for much of the project construction and operating activity, the current route of the 800-mile pipeline would cross only two miles of FNSB territory. That would leave the borough with a 0.2 percent allocation for the pipeline portion of the $15.7 billion payment in-lieu of property tax, or PILT, total. FNSB Mayor Karl Kassel has made it clear that he would not accept a scenario in which the borough received a PILT allocation based solely on infrastructure value within local government boundaries. Revenue Commissioner and board chair Randy Hoffbeck offered an allocation matrix at a December meeting that would split the PILT money based on infrastructure valuation, while leaving a small portion for distribution to local governments statewide based on population. Hoffbeck noted at the time that the model was intended to be a starting point for the discussion — a visual to outline the complex relationship between PILT takes by the State of Alaska, locales within the AK LNG Project corridor and the rest of Alaska. Kassel said in an interview that the Revenue Department’s draft is still the basis for discussion, but added that even as there is “somewhat of a general consensus” the final allocation will be something different, no one, including himself, has come up with an agreeable solution. The $15.7 billion PILT figure was negotiated by the state with the AK LNG Project partners as a sum to be paid over the initial 25-year life of the project. The yearly payments, starting about 2025, would be tied in part to the natural gas throughput of the project, with payments starting at $556 million and escalating to $706 million in year 25. If the project exceeds its initial life as expected and processes more gas, the final PILT sum could increase. Under the Revenue Department model — based heavily on allocating in-area asset valuation similar to a property tax — the Fairbanks North Star Borough would get just $75,600 per year for its two miles of pipeline. The Fairbanks North Star Borough will feel major impacts from the project despite holding only two miles of pipeline, Kassel emphasized. “We’re the supply depot; we’re the hub of the network,” he said in an interview. The Trans-Alaska Pipeline System, or TAPS, has given Fairbanks a very good idea as to what the community can expect with the gasline. Kassel said the borough’s payroll increased 75 percent during TAPS construction. He said he doesn’t expect growth on that scale given the state has matured greatly since the mid-1970s, but expecting growth up to 20 percent is not unreasonable, according to Kassel. He said at the meeting he expects everyone to fight for their communities, but Fairbanks “would rather not see the pipeline filled with the (Revenue Department’s) structure.” Regardless of the model, the State of Alaska will likely take a significant share of the PILT because 304 miles of the pipeline runs through unincorporated areas of the state north and west of Fairbanks and the state, as a 25 percent owner of the project, will presumably recoup its portion of the PILT. Without the state’s quarter share, about $11.8 billion would actually be split between the state and local governments. Matanuska-Susitna Borough Mayor Vern Halter proposed a model allocating 50 percent of the $15.7 billion PILT to the state, including the 25 percent state tax payback; 20 percent to areas with AK LNG Project infrastructure; and 30 percent to local governments statewide based on population each year. The 20 percent share for boroughs and the state with project assets would be weighted, with 70 percent as a ratio of asset value and 30 percent based on population. Kassel said the model has merit, but shouldn’t distribute facility asset values from the North Slope and the Kenai Peninsula boroughs because the gas treatment plant to the north and the massive LNG plant at the end of the pipe are wholly located within those areas. The ratio split should focus on the pipeline asset allocation to acknowledge impacts to Fairbanks, he said. Kassel suggested a 50-50 split of the pipeline portion of the PILT based on the location of assets and the population of the jurisdictions within the pipeline corridor. Hoffbeck noted that allocating based on population within the project corridor is “getting a long way from property tax,” but said it is up to the larger board to decide its recommendation. Halter said he doesn’t want the ultimate allocation “over-weighted to infrastructure,” which the Revenue model is, he contends. Kenai Peninsula Borough Mayor Mike Navarre said the idea that a PILT is not tied to property taxes simply isn’t accurate. The $25 billion LNG plant expected for Nikiski on the Peninsula is projected to bring in massive amounts of tax revenue for the Navarre’s borough even if it is taxed at a lower rate than current borough statute, as the negotiated PILT calls for. Navarre commented at the meeting and Kassel said in an interview that regardless of what the board recommends to Gov. Bill Walker, the Legislature makes the final decision. “I think it’s important for us to be involved and give it a best-faith effort to come up with the best recommendation we can,” Kassel said. “Where it goes from there — we know it goes into the sausage maker of the legislators and what comes out the other end — who knows?”    

Industry: Tongass timber forecast flawed

A U.S. Forest Service study projects growth in Tongass timber harvest over the next 15 years, but leaders of Alaska’s timber industry are saying the forecast is still too low. The draft Tongass National Forest Timber Demand report calls for a timber harvest increase from fiscal year 2014 of nearly 25 percent by 2030 on Tongass lands. Southeast mills took 39 million board feet of lumber from the national forest in 2014; the 2030 harvest is forecasted to be 51.8 million board feet. Alaska Forest Association Executive Director Owen Graham argues the demand analysis is based on a restricted timber supply, which artificially limits demand for Alaska forest products. “The analysis attributes the supply constraints to federal budgets and (National Environmental Policy Act) issues, but fails to acknowledge that its self-imposed standards and guidelines for its timber sale program have greatly increased the cost of harvesting timber sales,” Graham wrote in formal comments about the study. “These high costs are one of the primary reasons the agency has been unable to prepare economic timber sales.” Agriculture Secretary Tom Vilsack issued a memo in 2013 expressing an intent to transition to young-growth harvest in the Tongass National Forest within 15 years. That transition would be faster than was prescribed in the 2008 Tongass Forest Plan. Graham has said the industry needs to harvest at least some old-growth trees for about another 30 years to allow young, or second-growth, stands to fully mature, which takes about 90 years for most trees in Southeast Alaska. Young-growth stands are often more dense and thus hold more board feet of raw lumber. However, Alaska’s downsized timber industry in recent years has survived on high-value, “shop grade” lumber products from large spruce and hemlock trees harvested from the Tongass. Southeast sawmills will not be able to manufacture that high-value lumber from the 60-year-old, young-growth trees that would be available under an expedited shift away from old-growth harvesting, according to Graham. “The spruce custom-cut lumber that currently enjoys very high prices in the Pacific Rim markets will no longer be produced. Likewise, since shop grade hemlock lumber requires logs that are at least 16 inches in diameter, this high value lumber will also disappear,” he wrote. “What the (demand forecast) is missing is the most likely outcome of the transition strategy — the end of timber manufacturing in Southeast Alaska.” Allowing young-growth stands to mature another 30 years to age 90 would roughly double the harvestable volume per acre usable for Alaska mills, Graham said. Smaller logs can be exported to other markets, but that eliminates the value-added sawmill industry from the logging process, he said. The study forecasts the total Southeast timber harvest will increase from 120.6 million board feet in 2015 to 155.1 million by 2030. That includes timber sales from state land and Alaska Native corporation property, primarily the area Native regional corporation Sealaska Corp. Nearly all of the harvest increase will come from logs meant for export — 31 million board feet of the overall Southeast harvest increase of about 35 million board feet is in the form of export saw logs, based on the Forest Service projections. Sealaska, which gained 68,000 acres of formerly Tongass timberland in a conveyance from the federal government last year, exports nearly all of its timber as raw logs because it cannot process the logs in Alaska economically. Sealaska CEO Anthony Mallott has said the company wants to add timber processing and the new acreage will be an opportunity to study the economics of its entire timber business model. The study projects harvest from Southeast Alaska Native corporation lands will increase from 61.5 million board feet in 2015 to more than 80 million board feet 15 years later. Graham contends Sealaska is the only major private timberland owner in the region. According to Sealaska, it can now maintain an average harvest of 45 million board feet for the next 25 years, stretched from earlier projections of 45 million board feet 15 years. Sealaska is also interested in bidding on up to 20 million board feet per year of harvest from public lands. Further, Alaska’s Southeast State Forest has a maximum sustainable harvest of about 12 million board feet per year, according to state Forestry Director Chris Maisch. The study projects harvests from State of Alaska lands in the region to grow from 18.2 million board feet to 23.1 million board feet over the 15-year study period. The Alaska Mental Health Trust Land Office occasionally offers large timber sales upwards of 50 million to 60 million board feet from its Southeast properties. However, Trust Land Office Resource Manager Paul Slenkamp said the large sales are sporadic and none are expected for the next three to four years. Southeast Alaska’s timber industry is a shell of its former self. Average annual harvest from the Tongass ranged from about 280 million board feet to more than 400 million board feet during the late 1980s and early 1990s. The last year timber harvest from the 17 million-acre national forest exceeded 100 million board feet was 2000, which was the last full year before President Bill Clinton issued the Roadless Rule, restricting access to undeveloped tracts of national forests. At its peak, the industry supported more than 4,000 jobs in Southeast, today that number is down to about 300, according to Graham. Study co-author Jean Daniels, a federal research forester, said the demand forecast is a continuation of trends seen in related markets after the global recession in the late 2000s. The study was also kept independent from the Tongass Land and Resource Management Plan ongoing update process, Daniels said. “For the most part we tried to stay as separate from what was going on with the (Tongass environmental impact statement) process as possible to try to be as unbiased as possible with the results of the analysis,” she said. The Alaska Region of the Forest Service released a draft environmental impact statement for the Tongass Management Plan in November. The plan amendment calls for continuing the 15-year transition to young-growth harvest in the Tongass. Susan Alexander, a manager in the Forest Service’s Pacific Northwest Research Station, also helped pen the demand forecast study and said that Graham is looking at the forecast from the supply side, while the Forest Service attempted to figure out demand for all West Coast timber markets, with Alaska and the Tongass harvest subsets to the larger picture. “It’s a demand side analysis and I think that is sometimes confusing for people in Alaska who think that the supply equals demand, but it doesn’t, not from a theoretical standpoint,” Alexander said in an interview. Alexander and Daniels said they viewed Alaska as if timber supply was unconstrained and concluded that the cost of transportation has simply pushed Alaska out of the West Coast market. Demand is growing for lower value construction-grade lumber, but Alaska mills simply can’t compete with the rest of the Pacific Northwest. “Washington and Oregon have made all of the industry retooling necessary to be competitive in commodity markets and that’s a dimension lumber market where you’d be a price taker and Alaska has always been more competitive in the high-quality, shop-grade lumber,” Daniels said. Revamping Alaska sawmills to process dimension, or construction lumber from smaller young-growth trees would require hundreds of millions of dollars of investments and extremely high volumes of timber, Graham says. Additionally, those mills are highly mechanized, mostly eliminating the benefit of jobs in the industry, he argues. Alaska’s congressional delegation has criticized the Forest Service for pushing a quick transition to young-growth timber in the Tongass without helping Southeast mill operators transition their operations.   Elwood Brehmer can be reached at [email protected]

Nome graphite mine progress slowed, but ongoing

Development of the Graphite Creek mine near Nome has been delayed, but progress continues on the project that could become the country’s lone such mine. Executive chairman of Vancouver-based Graphite One Resources Doug Smith said his company is moving from exploration to the technical and economic evaluation phases of the project. At the same time, Graphite One is in the midst of another round of fundraising, “a never-ending requirement in the business of junior mining,” Smith noted. He said large drill samples are currently being technically evaluated and results that will feed into the mine’s preliminary economic assessment should be available in late February. The Graphite Creek prospect sits about 40 miles north of Nome on the northern slope of the Kigluaik Mountains on the Seward Peninsula. It is about 10 miles from spur-road access to that region’s Taylor Highway. Considered a high-grade, large flake graphite deposit, Graphite Creek would give the U.S. a stake in the graphite market that has been dominated by Chinese mines for decades. Flake graphite is a primary component of potent lithium-ion batteries — the power cells for electric cars and storage banks for some renewable energy projects. The average lithium-ion battery is 16 percent graphite by weight, according to the U.S. Department of Energy. Smith said Graphite One is continuing to collect environmental data in parallel with community outreach and preliminary economic assessment work that will hopefully lead to a favorable feasibility study in a couple years. “As soon as the water starts to flow then we have water samples to get and those types of things,” Smith said in an interview. Initial development is likely three years out if all goes according to planned and funding is available, according to Smith. Earlier company predictions had mine development starting as soon as 2017. Graphite One spent nearly $10 million exploring the deposit between 2012 and 2014. The current inferred resource is 154 million metric tons averaging 5.7 percent graphite; the indicated resource is 18 million tons with an average graphite content of 6.3 percent. The indicated resource is more than 1.1 million metric tons of in-situ graphite. Some of the highest concentrations are up to 10 percent graphite making for what is believed to be a very high-quality resource, according to Smith. No drilling was done in 2015. “Our focus has been on lab work,” Smith said. However, further infill drilling is still needed to determine the exact scope of the mine, he said — indicated resources stretch for 750 meters. Base assumptions are for a 50,000-ton per year mine with an initial 15- to 20-year life, with the understanding it could run much longer. “We have a significant amount of graphite there for many, many years given the size,” Smith said. “We’d look at a 50,000-ton per year operation that’s, as mines go, not a large operation, but as graphite mines go that’s good size.” He described the future mine as a large quarry without some of the requirements of other mines. That the main resource is on the surface, making it easier to access, is another big benefit to the project. “The graphite goes through a milling process and then it goes through a float-sink process, but it does not go through a leaching process like a metal mine would,” Smith said. Development costs should be in the $125 million to $150 million range, with further investment needed if upstream processing into concentrates optimal for shipping can be done on-site, he projected. The potential workforce at the mine is still unknown because whether it will be a year-round operation is also undecided, given the quarry-style and seasonal barge access at the Port of Nome could make for a seasonal mine. In that case, a more intensive summer mining operation could add to the workforce and lead to processing in the mining off-season, Smith surmised. Elwood Brehmer can be reached at [email protected]

BP to cut Alaska workforce by 13%

BP is cutting 4,000 jobs worldwide and some of those reductions will be in Alaska. An intra-company email obtained by the Journal sent to BP Alaska employees Jan. 12 states that the company plans to reduce its total in state workforce by 13 percent. All employees should know their status by early spring and the majority of layoffs will be conducted by mid-year, according to the email. BP directly employs about 2,100 people and has another 6,000 contract workers in Alaska, based on the company’s 2015 Alaska Hire report. The 13 percent reduction will come from the company’s direct employees, or about 270 people. “Today, the cash we generate from our business is not sufficient, meaning we have to borrow from the BP Group to meet our Alaska investment,” the email reads. “Improving our cost base is critical to maintaining our activity level at Prudhoe Bay and the long-term viability of the region.” In a formal statement BP said it plans to further reduce employee numbers in its upstream division to less than 20,000 — the Gulf of Mexico, Lower 48 onshore and Alaska in the U.S. — to simplify its business, cut cost and improve efficiency. “To reach this level we will need to reduce our current workforce of BP employees and agency contractors by at least 4,000 additional people,” the company said. BP’s restructuring comes as the price for Alaska North Slope oil has fallen to near $31 per barrel. At the same time, North Slope crude production and transportation costs are estimated at $46 per barrel, according to the state’s Fall 2015 Revenue Sources Book. BP cut 475 Alaska positions in late 2014 when it sold North Slope assets to Hilcorp Energy. About 200 of those employees ultimately transitioned to work for Hilcorp, a Houston-based independent. ConocoPhillips announced a 10 percent cut to its 1,200-employee Alaska workforce last September in a cost-cutting move. BP has incurred pre-tax damages upwards of $55 billion related to the massive 2010 explosion and subsequent oil spill from its Deepwater Horizon drilling rig in the Gulf of Mexico, according to the company’s third quarter financial report. Overall oil and gas industry employment was down 900 jobs statewide in November from a year prior, based on preliminary Labor Department numbers. Elwood Brehmer can be reached at [email protected]

The Costs and Risks for Alaska LNG Project

“Cost is everything.” No longer a concept, nearly everything done on the Alaska LNG Project from here forward will be focused on moving the prospective project towards reality for the least cost, and risk, possible, ExxonMobil Senior Project Manager Steve Butt said Jan. 8. Butt recapped the progress made over the last year on the $45 billion to $65 billion behemoth of an endeavor at the Alaska Industry Support Alliance’s annual Meet Alaska conference held in Anchorage. Generally referred to as “the gasline,” he noted the project is much more than an 800-mile pipeline to transport liquefied natural gas from the North Slope to Cook Inlet. More than half of the project’s mid-range estimated cost would be tied up in a $25 billion LNG plant and marine terminals near Nikiski, while the North Slope gas treatment plant and the pipeline infrastructure would each need $15 billion. As currently designed, the project would export roughly 20 million tons of LNG per year and generate upwards of $3 billion per year to the State of Alaska. The state is a 25 percent owner in the Alaska LNG Project with BP, ConocoPhillips, and ExxonMobil collectively comprising the other three-quarters of ownership. The LNG export license for the project approved by the federal Department of Energy in 2014 and the Alaska Oil and Gas Conservation Commission’s approval to move North Slope natural gas last year were “huge milestones” for the project, Butt noted. Historically, the gas that would be sold through the project has been pulled out of the ground and re-injected to maximize oil production of North Slope fields. To date, the project has spent roughly $470 million, with $370 million of that coming since the pre front-end engineering and design stage, known as pre-FEED, began in June 2014, Butt said. He noted the scale of spending ramp-up if the project continues to move forward into the front-end engineering and design, or FEED, and ultimately construction, emphasizing the importance of driving costs down in a challenging market. “In concept, the project spent $30 million a year; that was our cost. In pre-FEED, we’re spending $30 million a month. In FEED, we will spend $30 million a week and in execution we will spend $30 million a day,” Butt said. In an earlier presentation, ConocoPhillips Technology and Projects Executive Vice President Al Hirshberg said the worldwide LNG market forecast is for about 200 million tons per annum of new demand in 10 years — when Alaska LNG would begin production. However, about 140 million tons per year has “already been spoken for” through other projects that are further along, he said. “We have to admit the current market does create some headwinds on the project; that’s just the fact on the ground,” Hirshberg said. Butt described the market a different way, noting the “gated” process of concept, pre-FEED, FEED, final investment decision and then construction helps increase dedicated resources as investment risk decreases. “It’s not Copper River salmon; nobody pays extra for LNG. So it’s all about cost of supply,” Butt said. Simply put, that cost of supply is about $50 billion to build the project divided by the 32 trillion cubic feet of natural gas it hopes to process, export and sell. By the end of the year, the Alaska LNG Project should have filed its environmental impact statement application with the Federal Energy Regulatory Commission, the lead federal agency for the project. As part of that process the project will complete the second draft of its 13 resource reports; Butt said the first draft was roughly 10,000 pages. On the technical side, hydraulic modeling for the pipeline is 98 percent complete, according to Butt. The last 2 percent, he said, is knowing where Alaska Gasline Development Corp., the state’s representatives, wants the “offtake” points for in-state gas consumption along with how much project gas the state will use. Stress testing on the 42-inch pipe originally planned for the project just wrapped up and went well, he said. The pipe was able to withstand 8 million foot-pounds in a compression test without failing, which is critical for a buried pipeline. “The ground will move in Fairbanks. It’ll get cold in the winter; it’ll get hot in the summer; it’ll move all over; it’ll exert its load but the pipe will be fine,” Butt said. Sections of 48-inch pipe were ordered in August and should arrive soon be tested similarly in February, he said. A pipeline size decision should come by early April, according to Butt. Gov. Bill Walker has said he wants a 48-inch pipeline to add capacity to the project, which could incentivize additional gas exploration and production on the Slope or elsewhere along the project corridor. Evaluating the feasibility of a 48-inch pipeline is pegged at $30 million, based on 2016 project budget documents. Walker has also said he hopes to have critical fiscal agreements between the partners and the state in place for the Legislature to review before the end of the legislative session in late April. Corralling an adequate workforce for the project will be another in the list of hurdles for the AK LNG Project. “The biggest challenge for us is going to be on craft labor,” Butt said. The project is estimating it will need upwards of 8,500 construction workers during the peak work period of 2021 and 2022.  “What we’re hoping is that as the market shifts we’ll be able to have a better opportunity to get labor and the materials,” he said. “We’ll see a softening in the prices of the things we need like steel and other skills that we’ll need to acquire.” Butt said there is still a lot of competition for that labor, particularly in the Gulf of Mexico, as LNG buyers ramp up work in a favorable market for them. “Marrying” Alaska-specific engineering and construction expertise with global LNG project experience will also be important, he noted, as the complexity and scale of the Alaska LNG Project are virtually unmatched and it will be done in a very unique environment. The project has contracted with over 100 geotechnical firms over the past year and it should have formal contracting strategy in place by the latter half of 2016 as work continues to ramp up, Butt added. Elwood Brehmer can be reached at [email protected]

IG finds no bias in EPA Bristol Bay assessment

The Bristol Bay Watershed Assessment is on the up-and-up, at least according to the Environmental Protection Agency Office of Inspector General. Based on “obtainable records,” an Inspector General report issued Jan. 13 found no bias in how the EPA conducted its lengthy assessment of the potential impacts of mining within Bristol Bay watershed. The agency’s assessment process also met requirements for peer review and public involvement and followed appropriate procedures for verifying the quality of the information in the assessment before 1,000-plus page document was released to the public in early 2014, according to the report. While the report absolves the agency of misconduct regarding alleged bias, it notes that 25 months worth of missing government emails from the retired employee believed to be retired ecologist Phillip North could not be recovered and evaluated. Further, the IG notes that North used nongovernmental email to comment on a draft 404(c) petition submitted to the agency from tribes before it was officially submitted to the EPA. “We found this action was a possible misuse of position, and the EPA’s senior counsel for ethics agreed,” the report states. “Agency employees must remain impartial in dealings with outside parties, particularly those that are considering petitioning or have petitioned the agency to take action on a matter.” The 17-month IG review of the agency began in May 2014 and focused on the process used to develop the assessment. Its conclusion contrasts with a recent report authored by former Secretary of Defense William Cohen that was critical of the EPA’s process, finding the agency to be cozy with scientific and local Alaska Native groups that oppose Pebble Mine.  “EPA is pleased that the Inspector General’s independent, in-depth review confirms that our rigorous scientific study of the Bristol Bay watershed and our robust public process were entirely consistent with our laws, regulations, policies and procedures and were based on sound scientific analysis,” EPA Region 10 Administrator Dennis McLerran said in a formal statement. “We stand behind our study and our public process, and we are confident in our work to protect Bristol Bay.” The Bristol Bay Watershed Assessment ultimately determined that large-scale mining in the region would irreparably harm Bristol Bay’s world-class salmon fisheries that currently support much of the areas economy. Subsequently, the EPA used the assessment as its basis for using its Clean Water Act Section 404(c) authority to prohibit a large mine in the watershed, a proposal that would effectively kill the prospect of developing Pebble Limited Partnerships premier copper and gold deposits. The 404(c) action is on hold as a federal court tries to determine what the IG’s office and former Secretary Cohen could not agree on: whether the EPA conspired with Pebble opposition to reach the conclusion in the assessment. Pebble sought and received an injunction to halt the EPA’s work until the court case is resolved. Pebble CEO Tom Collier called the IG report an “embarrassing failure” and a “whitewash” in a formal statement. “Based on a limited number of documents received through (the Freedom of Information Act), we were able to place in front of the IG incontrovertible evidence that EPA had reached final decisions about Pebble before undertaking any scientific inquiry; that it had inappropriately colluded with environmental activists; that it had manipulated the scientific process and lied about its intentions and actions to both us and to U.S. Congress,” Collier said. “Just as importantly, our record shows that these abuses reach to the highest offices within the agency.” Officials from the EPA’s offices of the Administrator, Region 10, Water, Research and Development and a retired Region 10 ecologist, presumably Phil North, were interviewed for the IG report. Additionally, more than 8,300 emails sent or received by agency officials between January 2008 and mid-May 2012 were reviewed. North, who retired from the EPA in April 2013, has received national notoriety for his involvement in the Bristol Bay Watershed Assessment. Pebble supporters and general EPA critics have zeroed in on him as the likely link for the alleged collusion with mine opponents. Attempts by the IG to access North’s personal email through subpoena were unsuccessful, as his whereabouts are unknown, the report states. Because the IG could not find North, the office issued a subpoena to North’s lawyer, who refused to accept service on behalf of North. North also did not surface when subpoenaed for deposition last November in Pebble’s ongoing suit against the EPA in federal court. The IG recommended to the EPA that the agency incorporate examples of “misuse of position” in its ethics training as well as mandatory tribal training to define appropriate parameters for Tribal assistance by agency staff. Elwood Brehmer can be reached at [email protected]

Judge hits both sides in Anchorage LIO suit

A lawsuit challenging the legality of the Anchorage Legislative Information Office lease will continue, but neither side came out of a court ruling unscathed. Anchorage District Superior Court Judge Patrick McKay wrote in a Jan. 7 order denying a defendants’ motion for summary judgment that the filer of the suit, Anchorage attorney James Gottstein, waited an unreasonably long time to file the suit. At the same time, McKay found that the Anchorage LIO owners could in a roundabout way benefit from the building lease being voided. The building is owned by 716 LLC — the Downtown Anchorage LIO address — a real estate partnership in which longtime Anchorage developer Mark Pfeffer is a primary member. Gottstein filed the suit on March 31, 2015, claiming the 10-year, $281,638 per month lease the Legislative Affairs Agency agreed to is illegal because it is not 10 percent below market value, a requirement for state lease extensions that do not go through a competitive bidding process. Legislative Affairs and 716 West Fourth Avenue agreed to expand and renovate the old 23,600 square-foot Anchorage LIO in September 2013 and Gottstein became aware of the agreement a month later; however he did not file suit at that time despite expressing concerns over the legality of the agreement, according to court records. Construction commenced in December 2013 and the new 64,000 square-foot building was finished in January 2015. Gottstein contends on his office’s website that the lease, which he claims equates to $7.15 per square foot, is well beyond the market rate of about $3 per square foot for Downtown Anchorage office space. On a total square-foot basis, the monthly lease works out to about $4.40 per square-foot, while the usable square-foot lease rate is higher. Pfeffer told the Journal in a previous interview that the building was renovated specifically to meet the Legislature’s unique layout and on-site parking requirements and therefore has no equal in the market. The new Anchorage LIO has been appraised multiple times at $44 million by several banks who financed the construction and the long-term debt. Pfeffer, caught in the middle of what has become a political issue, has offered to sell the building to the Legislature for 716’s financial obligation on the building — about $37 million — or millions less than its appraised value. An appraisal of the LIO conducted by the Alaska Housing Finance Corp. estimated the value at $48.5 million. McKay’s order notes that Gottstein, president of the adjacent Alaska Building Inc., collected $25,000 in fees and rent from 716 and the contractor before filing the suit. “The court views Mr. Gottstein’s financial gains as acquiescence and, combined with the 17 months (he) waited to bring the lawsuit, this delay seems ‘unreasonable,’” the judge wrote. If the lease is found “illegal, null and void,” 716 and Legislative Affairs could renegotiate to a rate 10 percent below market value, which could force Pfeffer and his partners to refinance the building over a longer term and thus incur harm, the order reads. Additionally, the building’s unique characteristics may not find anyone to lease the full space on similar terms and incur harm that way. “On the other hand, in the event that the court declares the lease ‘illegal, null and void,’ and the parties are unable to reach a new agreement, 716 will be able to lease the building at a greater rate since it claims the current rate is 10 percent below the market value,” Judge McKay wrote. “Indeed, 716 may even benefit from a finding that the lease is ‘illegal, null and void.’” In its arguments, Legislative Affairs argued it could be harmed because of the $7.5 million the Legislature contributed to the building improvements. McKay wrote that if the lease is found null and void, “the Alaskan taxpayers will be saving potentially much more than the original $7.5 million. It remains a question of fact whether the LAA would ultimately forfeit the original $7.5 million it spent on improvements since the lease makes no specific mention of such a contingency.” Impact of LIO move The messy Anchorage LIO situation has become political, with Anchorage minority Democrats and legislators from outside the city saying the state should break its lease because it cannot afford the building when Alaska is facing a $3.5 billion annual budget deficit. During a Dec. 19 meeting at the Anchorage LIO, the Legislative Council, which directs the Legislative Affairs Agency, voted to move out of the building unless a lease rate equal to what the Legislature would pay in the state’s nearby Atwood Building can be negotiated. Breaking the lease would technically be legal because of a “subject to appropriation” clause that voids the lease if the Legislature votes to not fund it. Pfeffer, some legislators, and state financial experts have warned that walking away from a roughly $26 million remaining obligation would hurt the state’s credit rating at a time when Standard & Poor’s just downgraded Alaska’s debt rating because of its fiscal problems and current lack of a plan to address them. “716 has acknowledged that the State is in a different fiscal environment now than when the lease was legally signed in 2013. Mindful of this reality, 716 West Fourth Avenue, LLC has indicated its willingness to work with the Alaska Legislature to find a pathway to savings,” spokeswoman Amy Slinker said in a formal statement. Gabe Petek, Standard & Poor’s primary credit analyst for Alaska, told the Journal Jan. 8 that the state walking away from a subject-to-appropriation lease likely wouldn’t impact rating agencies’ view of Alaska because the action is a way to reduce spending in the larger budget picture. “In a perverse sort of way it can be a strengthening — (legislators) have the ability when push comes to shove to push things around a little bit. People on the other end of it may not like it, but from the standpoint of the investors and the bondholders it can actually be a protective attribute, I guess,” Petek said. “We’re primarily focused on (the state’s) ability to fund their debt payments in full and on time on their debt that’s out in the public debt markets.” Elwood Brehmer can be reached at [email protected]

BP will cut Alaska workforce by 13 percent

BP is cutting 4,000 jobs worldwide and some of those reductions will be in Alaska. An intra-company email obtained by the Journal sent to BP Alaska employees Jan. 12 states that the company plans to reduce its total in state workforce by 13 percent. All employees should know their status by early spring and the majority of layoffs will be conducted by mid-year, according to the email. BP directly employs about 2,100 people and has another 6,000 contract workers in Alaska, based on the company’s 2015 Alaska Hire report. The 13 percent reduction will come from the company's direct employees, or about 270 people. “Today, the cash we generate from our business is not sufficient, meaning we have to borrow from the BP Group to meet our Alaska investment,” the email reads. “Improving our cost base is critical to maintaining our activity level at Prudhoe Bay and the long-term viability of the region.” In a formal statement BP said it plans to further reduce employee numbers in its upstream division to less than 20,000 — the Gulf of Mexico, Lower 48 onshore and Alaska in the U.S. — to simplify its business, cut cost and improve efficiency. “To reach this level we will need to reduce our current workforce of BP employees and agency contractors by at least 4,000 additional people,” the company said. BP’s restructuring comes as the price for Alaska North Slope oil has fallen to near $31 per barrel. At the same time, North Slope crude production and transportation costs are estimated at $46 per barrel, according to the state’s Fall 2015 Revenue Sources Book. BP cut 475 Alaska positions in late 2014 when it sold North Slope assets to Hilcorp Energy. About 200 of those employees ultimately transitioned to work for Hilcorp, a Houston-based independent. ConocoPhillips announced a 10 percent cut to its 1,200-employee Alaska workforce last September in a cost-cutting move. BP has incurred pre-tax damages upwards of $55 billion related to the massive 2010 explosion and subsequent oil spill from its Deepwater Horizon drilling rig in the Gulf of Mexico, according to the company’s third quarter financial report. Overall oil and gas industry employment was down 900 jobs statewide in November from a year prior, based on preliminary Labor numbers.   Elwood Brehmer can be reached at [email protected]

Credit downgrade timed on bond sales, continued oil decline

Standard & Poor’s Jan. 5 downgrade of Alaska’s credit ratings, which caught many state leaders by surprise, was triggered by upcoming bond sales, according to an analyst from the ratings agency. Gabe Petek, Standard & Poor’s primary Alaska analyst, said in an interview that the agency had a duty to revisit the state’s ratings because of general obligation bond sales scheduled for late January and February. “If you’re selling debt we can’t just sit back and let it go forward without updating our viewpoint,” of the state’s credit, Petek said. In August, Standard & Poor’s revised the State of Alaska’s credit rating outlook from “stable” to “negative,” citing the state’s budget deficit growing towards $3.5 billion annually as the main reason for the change. An associated report acknowledged the state’s significant existing savings — currently a sum of about $15 billion — but also said legislators must act quickly to address the pessimistic trend of the fiscal situation in what Standard & Poor’s at the time called a “contentious” state political climate. The agency officially downgraded Alaska’s formerly sterling “AAA” credit rating to “AA+” for general obligation, or GO, debt Jan. 5. Along with that came single-level downgrades to state appropriation-backed debt and Alaska Energy Authority bonds with a moral obligation pledge from the state to “AA” and “A+,” respectively. A collective negative outlook accompanied the ratings. At a press briefing immediately following the Standard & Poor’s downgrade Gov. Bill Walker said his initial reaction was “give us a chance” to address the state’s long-term budget issues during the regular legislative session that begins Jan. 19. He added at the time it was his understanding a bond sale pushed the issue. Walker put forth an aggressive plan to balance the state budget over several years in early December — a proposal to revamp how the state manages its money through the Permanent Fund, change how resident dividends are paid and increase personal and industry taxes. Whether it is done using the governor’s plan or another method, there is near unanimous consent among legislators that a major fiscal structure change is coming, and soon, for Alaska. Senate Finance Committee co-chair Anna MacKinnon, R-Eagle River, said in a Jan. 5 statement that she was disappointed by the decision to downgrade the state’s credit rating so soon after changing the credit outlook and before the session. The agency’s rationale, as MacKinnon put it, in August was that the Legislature needed to stabilize the budget situation. The specific GO bond sales scheduled for Jan. 20 that Petek said pressed Standard & Poor’s to revisit Alaska’s credit rating are for bond approvals dating back as far as 2005. Those bonds, totaling $38.5 million, are for projects in the Kenai Peninsula and Kodiak Island boroughs and the small Southeast Alaska city of Klawock approved as part of a 2005 bond resolution. Refinancing of a bond for the City of Seward is also included in the package. Fitch Ratings, on Dec. 23, announced a rating of “AA+” with a stable outlook for the GO bonds, which nearly aligns with Standard & Poor’s overall rating downgrade for general state bonds. Alaska Municipal Bond Bank Authority Executive Director Deven Mitchell said another state GO bond sale for statewide transportation projects is scheduled for the end of February. Voters approved those bonds in 2012 as part of a $460 million package. Public infrastructure projects are long-lived, Mitchell said, so the state bond bank regularly asks the Department of Transportation when it needs funds for various projects. Alaska’s credit rating downgrade also comes at a time when the Walker administration is proposing a $500 million multi-year GO bond package to fund essential and capital projects along with pension bonds to stabilize the state’s retirement payment obligation. Mitchell said the downgrade could result in interest rate hikes of about 0.1 percent on future bond sales. Walker equated that to roughly an additional $1,000 per year payment on each $1 million the state borrows. In several years the state could also look to bond for at least part of its share — at least $13 billion — of construction costs on the Alaska LNG Project. However, the state’s credit rating and fiscal situation will have ample time to change for better or worse before then. The state’s financial group made a pitch to Standard & Poor’s analysts in an early August meeting just prior to the negative ratings outlook report for a ratings adjustment after the upcoming legislative session to give Alaska’s leaders a chance to stabilize the state’s fiscal situation, according to Mitchell. “That’s been the state team’s discussion point with the analyst. If you look back 18 months to August of 2014, the price of oil was over $100 per barrel. The state was looking at a balance with a draw on the (Statutory Budget Reserve), but we were going to have growth in the net position of the state because of investment earnings that were going to float a savings in funds like the (Constitutional Budget Reserve), the Earnings Reserve of the Permanent Fund and so we went from that kind of very strong position to a year later trying to deal with a price of oil that had dropped below $50 per barrel and now obviously it’s below $40 per barrel,” Mitchell said. “And it just takes a long time, it’s kind of like you’re in a ship and you want to turn around you can’t just start going the other way; it takes a while to get turned around.” Petek said the timing of the ratings are not tied to the legislative cycles and that Standard & Poor’s does not try to persuade or pressure political leaders into any decisions. Its reports specific to Alaska simply lay out the state’s bind, he said. Since the August ratings outlook adjustment the state’s revenue forecast has declined along with oil prices, further exacerbating Alaska’s fiscal issues, Petek noted. “The problems have gotten larger; that’s one thing, and the state is going to sell debt into the market,” he said. “And we just have a very strong interest in making sure there’s no uncertainty as to what our views are when they’re going to go and sell debt so it kind of forced the issue in a way.” Petek added that Alaska, at “AA+” remains in a “really strong” position — equal to or better than about half of the other states around the country. It is a rating agency’s responsibility to assess based on a state’s immediate situation and not to predict what politicians will do, he said, and currently Alaska’s fiscal house is deteriorating.   Elwood Brehmer can be reached at [email protected]

MEA says economics of single transmission co. overstated

Matanuska Electric Association is questioning the benefits of transferring regional transmission infrastructure to a single utility. In a Dec. 29 letter to the Regulatory Commission of Alaska chair T.W. Patch, MEA General Manager Joe Griffith cited eight reasons why the Southcentral electric utility believes forming a Railbelt electric transmission company could be unnecessary and possibly add costs to participating utility ratepayers. Among the issues raised by MEA is the utility’s belief that a $903 million estimate for needed performance and reliability upgrades to the Railbelt electric system is a “grossly inflated number,” the letter states. The hefty sum is based on reliability standards that don’t return a justifiable value, according to Griffith. He said in an interview that all the Railbelt utilities — there are six — could reap significant benefits from as little as $50 million invested strategically. “The ($903 million) study was done properly for the boundaries and conditions they studied it under,” Griffith said. “It isn’t a bogus study; it’s probably right, but the first question you have to ask is, ‘Do we need it?’” The Alaska Energy Authority commissioned the 2013 study that came to the $903 million conclusion. It was based on a single-loss contingency standard, known in the industry as N-1, meaning the entire Railbelt electric transmission system, from Fairbanks to Homer, would be able to absorb the loss of a single transmission line or substation without consequence. The authority is currently updating that study to include double contingency and status quo costs; that study is expected in March. MEA uses an N-1 standard in its system, Griffith said, and his letter noted that while system-wide planning for a single contingency is prudent, the utilities have consistently determined the cost of reliability improvements is not justified. The 173-mile, state-owned transmission intertie is a single line between Willow and Healy, and a lone connection ties Anchorage to the Kenai Peninsula. Adding redundancy to the interties would allow for the cheapest power to flow freely and continuously, but because each utility has its own generating capacity, improved reliability is not imperative. The utilities are working to finalize a set of system-wide reliability standards that will go a long way towards determining what level of contingency planning will be used where, according to MEA representatives. Griffith concurred with other experts in the field when he said loosening access to Bradley Lake, the 120-megawatt state-owned hydro project near Homer, is the Railbelt’s most pressing need. A lone upgrade of the single-line intertie between Anchorage and the Kenai Peninsula from the decades-old 115-kilovolt line to a 230-kilovolt line would de-constrain Bradley Lake and add needed capacity to the transmission system, not unnecessary reliability, he said. Griffith ballparked a southern intertie upgrade cost at about $50 million. AEA has estimated that full investment to add capacity and reliability to the system could save Railbelt ratepayers between $80 million and $240 million per year simply by accessing the lowest cost power through economic dispatch. MEA contends those cost savings are unsubstantiated. The RCA demanded the Railbelt utilities move to establish a united electric system last June. In a letter to legislative leadership, the commission stated it would seek the authority to mandate the utilities to take action if they failed to heed the warning on their own. In December 2014, American Transmission Co., or ATC, a Milwaukee-area transmission-only utility, inquired about the possibility of developing a Railbelt transmission company to spur investment in the system. The utilities ultimately signed a memorandum of understanding with ATC to investigate the feasibility of a Railbelt transmission company, or TRANSCO. A TRANSCO would centralize management of the transmission system and allow participating utilities to invest in, and thus benefit from, projects across the system, not just those in their service area. ATC has experience with the TRANSCO model and would provide access to capital through its Lower 48 investors. The utilities expect to apply for a license to form a TRANSCO in the third quarter of this year, according to a Dec. 22 update report to the RCA. Griffith also noted that adding another utility with its own workforce and rate of return to the Railbelt could actually increase costs to ratepayers. The progress report to the RCA estimates the net cost of a TRANSCO would be about $7 million per year once it is fully up and running. Beyond operational costs, a for-profit TRANSCO would also require a rate of return — another cost to ratepayers, Griffith said. ATC spokesman Eric Lundberg said the company currently earns a 12.2 percent return on its Midwest business, but added that the Federal Energy Regulatory Commission regulates any return in the Lower 48. Similarly, the RCA would set profit parameters for an Alaska Railbelt TRANSCO, Lundberg noted. ATC operates like most utilities in that it seeks long-term business, understanding its return will ebb and flow with market conditions and regulations, he said. “We don’t look to flip investments; we look to be there,” Lundberg said. The “weak link” of a TRANSCO is the inherent incentive to invest in infrastructure because each investment makes a return, Griffith said. A major selling point of a TRANSCO has been the prospect of a single transmission tariff across the Railbelt — the elimination of “rate pancaking” for power producers needing to cross multiple utility service areas to get power to a buyer. Independent power producers have argued the stacked transmission tariffs are an economic barrier to developing low-cost renewable energy in the state’s most populated region. Griffith said a postage stamp tariff would simplify the cost, but is not likely to lower it for everyone because each utility has a different tariff rate. The transmission tariffs are set by the RCA to allow the utilities to service debt on their transmission infrastructure. “You’ve got to recognize the legacy investment each utility has made. If you don’t do that it’s a dead-bang loser,” he said. Turning over transmission infrastructure to a TRANSCO through a lease or direct change of ownership also provides a disincentive for local reliability investments, according to Griffith’s letter to the RCA. “MEA members could be faced with bearing the burden of both the total cost of their own future transmission improvements while subsidizing the system-wide legacy assets largely serving the retail loads of others,” the letter states. System operator benefits MEA’s concerns about forming a TRANSCO do not mean the utility is averse to changing the structure of the Railbelt electric network. Organizing an independent, or unified, system operator, often referred to as an ISO or USO, along with transmission capacity upgrades, would reap the greatest benefits of economic dispatch without adding unnecessary costs, according to MEA representatives.  “(A system operator) is where all the money is because that lets you maximize the efficiency of the (generating) machines as well as the gas contracts and that’s got to be folded into all this because that’s millions and millions of dollars annually,” Griffith said. Southcentral utilities relying on Cook Inlet natural gas as their generating fuel source sign contracts with producers that have a tiered pricing structure — typically base load, swing load and peak load. When demand peaks a utility can pay a 50 percent to 65 percent premium for natural gas. In theory, a system operator acting as a central power dispatcher would work to distribute as much base load power as possible, regardless of which utility owns the generation. MEA spokeswoman Julie Estey said the new, more efficient power plants coming online in the Railbelt — Municipal Light and Power and Chugach Electric Association’s joint Southcentral Power Plant and MEA’s Eklutna Generating Station — have already started this coordination between the utilities in an informal “loose pool.” For example, the 10 small generators that power the 171-megawatt Eklutna Generating Station can be powered up and down to meet fluctuating demand more efficiently than some of the larger gas turbine generators at other power plants in the region, Griffith said, so the utilities purchase power amongst themselves without a structured agreement. MEA’s vision of a system operator would have each participant represented on a board of directors, with board seats for independent power representatives as well. Alaska’s independent power producers often contend that the utilities control the Railbelt system and have pushed for a system operator to make dispatch decisions separate from the utilities. Estey, of MEA, said other issues the independent power producers raise with the utilities, such as who pays for interconnection fees to independent power sources, would likely be solved with a system operator. “It seems to me there has been more unified support (from the utilities) around a system operator, but ATC has been doing such a good job of driving the utilities around the TRANSCO model that that seems to be making more progress and has more legs, but that’s because more resources have been put into it,” Estey said. Elwood Brehmer can be reached at [email protected]

Feds decide against ESA listing for Alexander Archipelago wolves

A group of Southeast Alaska wolves will not be listed under the Endangered Species Act, according to a Jan. 5 U.S. Fish and Wildlife Service announcement. The Fish and Wildlife Service estimates the population of gray wolves, known as the Alexander Archipelago wolves, at between 850 and 2,700 animals. “Although the Alexander Archipelago wolf faces several stressors throughout its range related to wolf harvest, timber harvest, road development and climate-related events in Southeast Alaska and coastal British Columbia, the best available information indicates that populations of the wolf in most of its range are likely stable,” a Fish and Wildlife Service release states. Conservation groups have petitioned the service to list the wolves as endangered or threatened for more than 20 years. The latest determination comes after a yearlong review of the Alexander Archipelago wolf population in response to a petition filed by the Center for Biological Diversity. In March 2014, the Fish and Wildlife Service began a 90-day petition to list the wolves as threatened based on preliminary information at the time. The petition led to the 12-month finding. Had the wolves been listed, habitat protection measures would likely have further damaged Southeast Alaska’s struggling timber industry. Related efforts by conservationists to get Prince of Wales Island wolves recognized as a distinct population for the purpose of an Endangered Species listing have been unsuccessful as well. Sen. Lisa Murkowski commended the Fish and Wildlife decision, noting that Alaska has the largest population of gray wolves in the nation. “There is agreement that the gray wolf population in Southeast Alaska is healthy and stable in most places and growing in others,” Murkowski said in a release. “At a time when timber harvesting on Prince of Wales Island is barely a tenth of its levels of two decades ago, the attempt by some environmental groups to list the wolf seemed to be an effort solely to end the last of the remaining timber industry in Southeast Alaska. Fortunately, it did not work.” Gathering concrete data on wolf populations and genetics is particularly difficult in the dense Southeast rainforest because of the animals’ elusive nature.

No ESA listing for Alexander Archipelago wolves

A group of Southeast Alaska wolves will not be listed under the Endangered Species Act, according to a Jan. 5 U.S. Fish and Wildlife Service announcement. The Fish and Wildlife Service estimates the population of gray wolves, known as the Alexander Archipelago wolves, at between 850 and 2,700 animals. “Although the Alexander Archipelago wolf faces several stressors throughout its range related to wolf harvest, timber harvest, road development and climate-related events in Southeast Alaska and coastal British Columbia, the best available information indicates that populations of the wolf in most of its range are likely stable,” a Fish and Wildlife Service release states. Conservation groups have petitioned the service to list the wolves as endangered or threatened for more than 20 years. The latest determination comes after a yearlong review of the Alexander Archipelago wolf population in response to a petition filed by the Center for Biological Diversity. In March 2014, the Fish and Wildlife Service began a 90-day petition to list the wolves as threatened based on preliminary information at the time. The petition led to the 12-month finding. Had the wolves been listed, habitat protection measures would likely have further damaged Southeast Alaska’s struggling timber industry. Related efforts by conservationists to get Prince of Wales Island wolves recognized as a distinct population for the purpose of an Endangered Species listing have been unsuccessful as well. Sen. Lisa Murkowski commended the Fish and Wildlife decision, noting that Alaska has the largest population of gray wolves in the nation. “There is agreement that the gray wolf population in Southeast Alaska is healthy and stable in most places and growing in others,” Murkowski said in a release. “At a time when timber harvesting on Prince of Wales Island is barely a tenth of its levels of two decades ago, the attempt by some environmental groups to list the wolf seemed to be an effort solely to end the last of the remaining timber industry in Southeast Alaska. Fortunately, it did not work.” Gathering concrete data on wolf populations and genetics is particularly difficult in the dense Southeast rainforest because of the animals’ elusive nature. Elwood Brehmer can be reached at [email protected]

Pages

Subscribe to RSS - Elwood Brehmer