Elwood Brehmer

Low gas prices boosted Alaska tourism in ‘15

Winter, spring, summer and fall, lots of people are coming to Alaska. Visitor numbers were steady or increased nearly everywhere across the state during the latest summer tourism season. In Anchorage, municipal hotel, or bed, tax revenue is on pace to set a fourth consecutive record, which would also be a seventh straight year of bed tax growth. “Definitely for leisure travel, I feel that we’ll be on target with banner hotel revenues,” Visit Anchorage CEO Julie Saupe said. Bed tax revenue was up nearly 5 percent year-over-year through the first half of 2015. Anchorage pulled in more than $25.2 million last year from its 12 percent tax on room rental transactions. Saupe said the city’s fall meeting season would be strong this year, but it remains to be seen if it will top 2014, which had a record number of convention-goers in October. While low oil prices strain much of Alaska’s economy and state budgets, cheaper prices at the pump in the Lower 48 correlate to more visitors in the Last Frontier. More discretionary income — money not spent on gas — provides an opportunity for Americans to scratch the travel itch, Saupe said. There is also a feeling that competitive airfares and less expensive travel once in Alaska encourages visitors as well. Indicators from Ted Stevens Anchorage International Airport support Saupe’s premise, too. Enplanements at the Anchorage airport were up each month this year versus 2014; they were up an average of nearly 8 percent during the summer months. Southcentral cruise traffic, primarily to the ports of Seward, Whittier and Anchorage, was also up this year. It is expected to hold steady in 2016. Anchorage will see nine ports of call from cruise ships again next year, Saupe said, but the ship will be slightly larger than the 1,200-berth Holland America Line Statendam that visited Anchorage this year. A pair of tourism industry meetings next year could bode well for the hospitality industry beyond the meeting attendees, according to Saupe. The Go West Summit, a gathering of international tour operators that sell vacations in the Western United States, will convene next February in Anchorage. In September, it will be the Adventure Travel World Summit put on by the Adventure Travel Trade Association. “For future business these folks will get a chance to take a close look at what Alaska has to offer in the adventure travel world and we hope develop itineraries and send future clients our way,” Saupe said. “It’s a great chance to show off our product to some big sellers of adventure travel.” The Anchorage Economic Development Corp. estimates about 10 percent of jobs in the city are tied to the tourism industry, meaning a strong travel business can help mitigate potential downturns in other areas of Anchorage’s economy. The industry relies on the Outside domestic and international travel, which are both on a growth curve, Saupe said. Fairbanks Bed tax revenue collected by the City of Fairbanks was up more than 4 percent through July year-over-year, while passenger traffic at the Fairbanks International Airport was steady through the summer compared to 2014. “We had a solid summer,” Explore Fairbanks CEO Deb Hickok said. Preliminary passenger figures from the Alaska Railroad Corp. were steady as well; 451,000 people road the rails the past two summers. The Alaska Railroad offers service between the Southcentral cruise ports and Fairbanks. Tourism growth in Fairbanks has come during the aurora season — late August through April — lately, and Hickok said this season is shaping up to be a “transition year” for historical markets. China Air announced in September it plans to fly three new charter flights direct from Taiwan to Fairbanks in December full of travelers hoping to see Alaska’s northern lights. “The aurora is really the big thing in Fairbanks,” Hickok said. At the same time, Japan Airlines is flying only two aurora charters this year, which Hickok said is largely a result of restructuring as the airline comes out of bankruptcy. “They acknowledge there is still market demand,” for aurora flights out of Japan, she said. The Alaska Railroad has also added midweek trains between Anchorage and Fairbanks in February and March to its schedule. Hickok said she is happy to see the railroad’s commitment to winter tourism beyond its normal winter weekend routes. Juneau Numbers of both cruise and independent travelers increased in Juneau this summer, too. Juneau Convention and Visitors Bureau CEO Liz Perry said more than 976,000 people visited the capital city via cruise ship this year, an increase of about 2 percent. That growth is expected to continue into next year with about 1 million cruise passengers expected in 2016. “The reduction in gas prices across the U.S. has allowed for some competitive airfares,” Perry said. “Even the little difference we’ve seen here in Alaska allows people to consider bringing cars in on the ferry and so forth to move around Southeast.” Another nearly 100,000 people booked hotel rooms in Juneau over the summer and campground occupancy was up as well, she noted. “We are seeing an increasing number of people who are calling here and seeking information about Juneau who have previously visited on a cruise and want to come into town and spend more time and really enjoy the place and explore it on a completely different level,” Perry said. Elwood Brehmer can be reached at [email protected]

Nonprofits cite economic impact as budgets tighten

Alaska’s nonprofit sector wants its voice heard when discussions about the state’s budget future are had. So, the Foraker Group is convening nonprofit leaders across the Alaska this fall to hear from a large, but often quiet, portion of the state’s economy before the budget battles intensify once again in Juneau. The first meeting was held Oct. 20 in Anchorage; subsequent meetings are scheduled for Bethel, Fairbanks and Juneau in November. The Foraker Group is Alaska’s state nonprofit association. State Office of Management and Budget Director Pat Pitney laid out Alaska’s $3 billion-plus budget shortfall with Alaska North Slope crude selling for less than $50 per barrel. Pitney was followed by Foraker President and CEO Laurie Wolf, who said nonprofits need to be taken seriously when considering the economic impacts of state budget cuts or revenue enhancements. “We are a big part of (Alaska’s) economy,” Wolf said. “We are the jobs in rural Alaska.” There are more than 5,000 registered nonprofits in Alaska that account for about $6.5 billion in direct expenditures to the state’s economy, according to an Institute for Social and Economic Research study commissioned by the Foraker Group. Of that, $4.4 billion is from traditional, 501(c)(3) charitable organizations. The sector also generates 63,000 jobs in the state, which collectively pay $2.5 billion in annual wages. By comparison, Alaska’s commercial fishing industry supports 78,000 jobs paying out about $1.6 billion in wages, Wolf noted. “We are driving this conversation both in terms of expenditures but also in terms of employees,” she said. Direct nonprofit employment accounts for 39,000 positions, about 12 percent of the state’s workforce. Nationwide, nonprofits are about 10 percent of the workforce, the ISER study states. Despite nearly half of all the nonprofit jobs being in Anchorage, more than a third of all employment opportunities in the Interior, Western and parts of Southeast Alaska are with nonprofits. More than 20 percent of the permanent jobs on the North Slope and in the Northwest Arctic Borough are nonprofit positions, according to the study. The rural nonprofits often provide health care and other essential functions including utility services, Wolf said. While Alaska’s overall workforce grew 5.2 percent from 2007 to 2013, the state’s nonprofit jobs increased 22 percent. Wolf said the sector felt the impact of budget negotiations simply being prolonged last spring. Because the Legislature finalized the operating budget in early June as opposed to the typical late April the state was late in letting usual contracts, forcing many nonprofits to dip into savings in the interim. Declining government funding is not something new to Alaska’s nonprofits. From 2009-2013, overall federal funding fell 40 percent, from $8.4 billion to $5 billion. The grant part of that was reduced by more than half, from $3.3 billion to $1.5 billion, according to the Foraker Group. Still, Alaska’s nonprofits fare better than the national average in terms of grant funding. While it has declined from 60 percent of the sector’s revenue portfolio in 2007 to about 40 percent today, both figures are above the 32 percent national average. Earned revenue is up to half of what Alaska nonprofits take in, which is “leaps and bounds better” than the 30 percent it was less than 10 years ago, Wolf said. The entire sector is figuring out how to diversify funding through monetizing intellectual capital and finding new customers among other ways, she said. If government funding, particularly on the state side, is going to keep sliding, it will be essential for nonprofit leaders to continue to partner with state and local governments, something Wolf said Alaska already does better than most states. She also noted the sector’s ability to maximize government funding. “A cut of a dollar in one place is not the same dollar in another place because we as nonprofits, we are leveraging other dollars. Every dollar they cut from us — there’s a multiplier effect,” Wolf said. Private contributions have held steady, averaging 9 percent of Alaska nonprofits’ revenue over the study years. Walsh said she doesn’t believe donations will fade if the state economy suffers. Rather, she said other states have seen donations increase. Corporate donations from the oil industry have understandably slipped some, she said, but smaller industries have stepped up giving in the months since the state’s economic situation has become tenuous. “I think Alaskans understand nonprofits are a valuable investment,” Wolf said. Foraker Public Policy Director Mike Walsh encouraged the assembled nonprofit staff and executives not just to advocate but also to lobby — within the law. “As we take our (budget) conversations to the next level it really is going to include the people who make the laws,” Walsh said. “As a sector we have standing in this conversation.” The Internal Revenue Service allows nonprofits to use an “insignificant amount” of their budgets for lobbying, up to 5 percent to 7 percent, according to Walsh. State law permits individuals to lobby up to 10 hours per month before registering as a lobbyist. First Alaskans Institute CEO Liz Medicine Crow said including nonprofits in state budget considerations is a “value proposition about inclusivity and equity.” Alaskans in need of support from nonprofits have been kept out of funding discussions because of the structure of the political system, she said. Investing in the state’s nonprofits is “a long-term investment in the social, cultural progress of the state of Alaska,” Medicine Crow said. “The vision that needs to drive the conversation at the state level around how to deal with the budget has to be created because there’s not one right now.” Elwood Brehmer can be reached at [email protected]

AK Railroad gets LNG approval; capacity may need revisiting

The Alaska Railroad Corp. has approval to be the first railroad in the country to transport liquefied natural gas. The Federal Railroad Administration granted the Alaska Railroad’s application to haul LNG in a letter dated Oct. 9 to the state-owned rail company. The Alaska Railroad submitted its request Nov. 14, 2014. Currently, LNG is not hauled by rail anywhere in the country and the Alaska Railroad is the first state to receive the approval, according to the Federal Railroad Administration. The letter could spell good news for Alaska Industrial Development and Export Authority’s Interior Energy Project, or IEP, which is searching for the least expensive way to get natural gas to Interior residents and businesses. LNG, like any other bulk commodity, could potentially be transported from Southcentral to the Interior by rail in a much more cost-effective manner than by truck, the other primary option. AIDEA officials recently selected plans to haul either imported or domestic LNG north by rail as finalists among others in the latest Interior Energy Project effort. Alaska Railroad spokesman Tim Sullivan said the railroad is “happy about this being a good first step” towards moving LNG on its tracks. If the Alaska Railroad begins hauling LNG it must report the activity to the Federal Railroad Administration each month. The railroad is also limited to two LNG trains per week carrying a maximum of eight, 11,000-gallon LNG containers. The Interior Energy Project proposals all call for producing at least 100,000 gallons of LNG per day to meet eventual projected demand — far exceeding the volume approved for transport. Fairbanks Natural Gas and its sister companies currently truck a small amount of LNG north from Southcentral to meet the utility’s demand. The Railroad Administration said in a statement the volume limit was based on the amount the Alaska Railroad requested. That limit may be reevaluated in the future based on demand and the administration’s confidence the LNG is being handled safely. IEP Manager Bob Shefchik said his team discussed the capacity restriction with the railroad and the next two years — before the approval expires — could be used to prove the safety and reliability of the system through test shipments before a greater volume is possibly requested. Proposals from Interior Energy Project finalists that include rail transport will be evaluated with that in mind, he said. First gas for the IEP is hoped for by mid-to-late 2017. Before Alaska LNG is moved by rail, the Matanuska-Susitna Borough’s 32-mile Port MacKenzie rail spur will likely have to be finished as well. Several companies have pegged Port MacKenzie — across Knik Arm from Anchorage — and the nearby real estate as a prime area for an LNG plant. However the unfinished rail line connecting the port to the rest of the Railbelt still needs about $120 million to complete it during a time of severe budget tightening for the state. The lone Interior Energy Project plan remaining to import LNG proposes offloading LNG from British Columbia in Seward, which is the southern tip of the Railbelt. Elwood Brehmer can be reached at [email protected]

Alaska Railroad gets LNG approval

The Alaska Railroad Corp. has approval to be the first railroad in the country to transport liquefied natural gas. The Federal Railroad Administration granted the Alaska Railroad’s application to haul LNG in a letter dated Oct. 9 to the state-owned rail company. The Alaska Railroad submitted its request Nov. 14, 2014. Currently, LNG is not hauled by rail anywhere in the country. The letter could spell good news for Alaska Industrial Development and Export Authority’s Interior Energy Project, which is searching for the least expensive way to get natural gas to Interior residents and businesses. LNG, like any other bulk commodity, could potentially be transported from Southcentral to the Interior by rail in a much more cost-effective manner than by truck, the other primary option. AIDEA officials recently selected plans to haul either imported or domestic LNG north by rail as finalists among others in the latest Interior Energy Project effort. If the Alaska Railroad begins hauling LNG it must report the activity to the Federal Railroad Administration each month. The railroad is also limited to two LNG trains per week carrying a maximum of eight, 11,000-gallon LNG containers. Alaska Railroad spokesman Tim Sullivan said the railroad is “happy about this being a good first step” towards moving LNG on its tracks. Before Alaska LNG is moved by rail, the Matanuska-Susitna Borough’s 32-mile Port MacKenzie rail spur will likely have to be finished as well. Several companies have pegged Port MacKenzie — across Knik Arm from Anchorage — and the nearby real estate as a prime area for an LNG plant. However the unfinished rail line connecting the port to the rest of the Railbelt still needs about $120 million to complete it during a time of severe budget tightening for the state. Elwood Brehmer can be reached at [email protected]

Ready or not, here comes the gasline special session

Hopefully the latest special legislative session will go smoother than the first two. Lawmakers will convene in Juneau Oct. 24 for the third time this year, with time-sensitive gasline issues on the agenda this go-round. Gov. Bill Walker called the session Sept. 24 with a short but crucial list of topics to debate, including whether the state should buy out current Alaska LNG Project partner TransCanada Corp.’s share of the project, instituting a natural gas reserves tax on the producers and funding the state’s ongoing gasline work. State law requires the governor give the Legislature 30 days notice before starting a special session, which will also be 30 days. Legislators in the majority adjourned a special session called by the governor immediately following the regular session in April to address unresolved budget and Medicaid issues. They reconvened their own special session on the budget in Anchorage several weeks later; one that included talk of a government shutdown during a majority versus minority battle over state spending. Walker has supported the idea of the state taking a larger role in the $45 billion to $65 billion liquefied natural gas export endeavor. Taking TransCanada’s stake in the pipeline and the North Slope gas treatment plant would give the state a better negotiating position and increase revenue over the life the project, the governor contends. Right now, the State of Alaska has a 25 percent share of the LNG plant proposed in Nikiski. TransCanada holds the state’s share of the 800-mile pipeline and the North Slope facility. BP, ConocoPhillips and ExxonMobil collectively hold the remaining 75 percent share of the project. TransCanada’s involvement is largely the result of the settlement of an agreement the state had with the company under the defunct Alaska Gasline Inducement Act. Buying out TransCanada, an Alberta-based pipeline company, before the end of the year will initially cost the state $108 million according to consultant estimates. The state — with a full 25 percent share of the project — would then also be on the hook for TransCanada’s development costs, roughly doubling Alaska’s contribution to $14 billion or more, depending on final construction costs. However, with TransCanada out of the picture the state would also see an additional $400 million in revenue per year for the duration of the 25-year project, along with a net present value increase of up to $1.2 billion, state consultant Black and Veatch predicts based on numbers from the state Revenue Department. State revenue from the Alaska LNG Project — pegged to start producing by 2025 — is currently estimated to be near $3 billion per year initially and increase to around $5 billion in later years. Republican majority leaders in the Legislature have not opposed buying out TransCanada but they have expressed concern about the state’s ability to finance an extra $7 billion or more with major budget deficits and credit agencies threatening to tweak Alaska’s sparkling “AAA” credit rating if budget challenges are not resolved soon. The prospect of a natural gas reserves tax came as a surprise to at least some in the Legislature. House Speaker Rep. Mike Chenault, R-Nikiski, said he was “shocked” by the reserves tax proposal in a release following the special session proclamation, as the governor did not hint at the possibility in meetings with legislators prior to the announcement. Walker argues a natural gas reserves tax is a way for the state to assure the Alaska LNG Project moves forward even if a producer partner pulls out. The tax on gas in the ground would be levied only in the event a producer decides to keep its share of North Slope out of the project. A reserves tax would not add to state revenue in the long-term if the project is fully completed. The state levied an oil reserves tax on producers as a way to generate revenue during construction of the Trans-Alaska Pipeline; however, the tax paid was then credited against producer obligations once oil was flowing. This time, the producers said a reserves tax would “complicate” and potentially “undermine” progress on the complicated mega project. The administration had not put forth bills for the special session as of early Oct. 14. Walker spokeswoman Katie Marquette said the governor will introduce legislation before the start of the session. The Legislature also needs to pass a constitutional amendment exempting the Alaska LNG Project from constraints in the state Constitution sometime before next August or the project could be delayed two years. State legal opinions have said an amendment would be required for the state to enter into long-term fiscal contracts with the producers. The Alaska Constitution forbids one Legislature from binding future Legislatures, which contracts for the 25-year project would do. An amendment must be passed by two-thirds of the House and Senate before being judged by voters during a general election. The Legislature needs to address the issue before mid-August to get it on the November 2016 ballot. Sen. Cathy Giessel, R-Anchorage, chair of Senate Resources said she has urged the governor to introduce an amendment in the special session to get the issue resolved. She was told fiscal contracts, which are being negotiated with the producers, need to be finalized before a constitutional amendment is offered, Giessel said. Elwood Brehmer can be reached at [email protected]

WOTUS suspended, Corps memos show dissention over final rule

Nobody outside of Alaska’s congressional delegation seems to agree about the Environmental Protection Agency’s Clean Water Rule. The 6th U.S. Circuit Court of Appeals in Ohio stayed implementation nationwide of the Clean Water Rule in a 2-1 decision Oct. 9. Judges Richard Allen Griffin and David McKeague found enough evidence to suspend it based on key parameters in the final rule that are not substantiated by adequate scientific conclusions and that the same parameters may not have been added to the Clean Water Rule in accordance with public comment regulations. The Clean Water Rule, also known as the waters of the U.S. rule, or WOTUS, took effect Aug. 28 in 37 states. Alaska and 12 other primarily western states challenged the regulation and received a preliminary injunction from a federal District Court in North Dakota, staving off implementation in those states, just one day before the rule took effect. Judge McKeague wrote in the stay order that the clarification the Clean Water Rule tries to achieve “is long overdue,” but how the EPA reached its conclusions needs review. The original Clean Water Act often relies up case-by-case analysis of water bodies to determine jurisdiction. The final rule deviated from draft versions by delineating some waters in and out of federal jurisdiction through “bright line” boundaries.” Under the final rule, waters adjacent to traditionally jurisdictional waters that are within the 100-year floodplain to a maximum of 1,500 feet are subject to the Clean Water Act and from the jurisdictional waters under federal authority. Isolated water bodies with a “significant nexus” to navigable waters, which are considered waters of the U.S. and fall under the Clean Water Act, must also be within a 100-foot floodplain of the navigable body and within 4,000 feet of the navigable, jurisdictional water to fall under federal authority based on the new rule, the EPA states. The demarcations were added to the Clean Water Rule after the public comment period, possibly violating the Administrative Procedure Act which requires that final rules must related to what is in the proposed rule. “(The EPA’s) argument that ‘bright line’ tests are a fact of ‘regulatory life’ and that they used ‘their technical expertise to promulgate a practical rule’ is undoubtedly true, but not sufficient,” McKeague wrote. Excluded from the final Clean Water Rule are ditches that flow intermittently, according to the EPA. It does not change municipal storm sewer regulations. Griffin and McKeague also concluded that “it is far from clear” whether the jurisdiction limitations in the new rule are in-step with a U.S. Supreme Court decision on the Clean Water Act. In 2008, the Supreme Court ruled that for a water body to be under federal jurisdiction it must either be a traditional navigable water or have a “significant nexus” to navigable waters. The wetland or water body in question must significantly affect the chemical, physical or biological makeup of any downstream navigable waters. That Supreme Court ruling in Rapanos v. EPA overturned a prior 6th Circuit decision that favored the agency. Alaska’s congressional delegation welcomed the Circuit Court’s decision. Sens. Dan Sullivan and Lisa Murkowski and Rep. Don Young have characterized the Clean Water Rule as expansion of EPA jurisdiction outside of the boundaries set in law under the Clean Water Act. “(The) decision to put a national hold on the controversial WOTUS rule is further good news for opponents of the EPA’s culture of overreach,” Murkowski said in a formal statement. “I’ve been fighting to reign in the EPA and the harmful impacts the WOTUS rule could have on almost every corner of Alaska. I will continue my efforts to do my part to ensure this rule will never be imposed on the state.” Murkowski, who chairs the Senate Interior Appropriations Subcommittee, added a provision to the 2016 EPA and Interior Department budget bill prohibiting the agency from funding implementation of the Clean Water Rule. Young said the rule could “create insurmountable hurdles for even the most basic activity” and significantly damage local economies in Alaska. Sullivan, who last year campaigned largely on pushing back against federal overreach, said in a release from his office that he is grateful for the court’s decision. “This rule is a prime example of this administration’s persistent disregard for the rule of law and yet another attempt to bypass Congress and the American people by granting the EPA vast new authority over lands across the country, particularly in Alaska, which is home to 60 percent of the nation’s jurisdictional waters,” Sullivan said. The EPA has contended since proposing the draft rule in April 2014 that it would clarify jurisdictional ambiguity that exists under the Clean Water Act for some wetlands and water bodies. Its economic analysis of implementing the rule, published in May, concludes fewer waters would be under federal authority. “Compared to the current regulations and historic practice of making jurisdictional determinations, the scope of jurisdictional waters will decrease, as would the costs and benefits of CWA (Clean Water Act) programs,” the analysis states. The agency also argued in court to maintain status quo — keep the rule in place — while it is challenged. While the states would not suffer immediate and irreparable harm if the rule was kept in place, the court found no indication the nation’s water bodies are in peril without it at least while the legalities are sorted out. “What is of greater concern to us, in balancing the harms, is the burden — potentially visited nationwide on governmental bodies, state and federal, as well as private parties — and the impact on the public in general, implicated by the rule’s effective redrawing of jurisdictional lines over certain of the nation’s waters,” the order states. Judge Damon Keith questioned the 6th Circuit’s subject-matter jurisdiction in his dissent and did not attempt to evaluate the merits of the case. Corps contradictions There also appears to be dissent among rank and file in the U.S. Army Corps of Engineers regarding the final Clean Water Rule. The Army Corps of Engineers manages Clean Water Act programs and permitting for the EPA. Corps Assistant Chief Counsel for Regulatory Programs Lance Wood wrote in an April 24 internal legal analysis of the final draft rule that the 4,000-foot jurisdictional limit on certain water body types would exclude important components of navigable waters that have been under federal authority since 1975. “The corps believes that the 4,000 feet limit on jurisdiction would cause significant adverse environmental effects as a result of the loss of jurisdiction over a substantial amount of jurisdictional ‘waters,’ based on the Corps’ experience in implementing the CWA Section 404 (wetlands) program and performing the majority of jurisdictional determinations under the CWA,” Wood wrote. EPA staff told the Corps during a March conference call that the agency planned on cutting off jurisdiction at 5,000 feet from traditional navigable waters. Then, according to Wood, the EPA changed its position three days later and decided on the 4,000-foot cutoff, thus demonstrating the “arbitrary nature” of the limit, he noted. Corps staff also presented 15 examples of the types of waters currently under jurisdiction that would be excluded under the draft final rule to Assistant Secretary of the Army for Civil Works Jo-Ellen Darcy as well as EPA decision-makers and technical staff, according to Wood. He claims the findings were not countered. “No one has presented any basis to refute or challenge the Corps’ determination that the draft final rule would cause significant adverse effects on the human environment and thus would require an (environmental impact statement) before the final rule could be promulgated in its current form,” Wood wrote. As the court noted, Wood states the 4,000-foot cutoff was first presented in the final draft rule after public comment ended, which likely violates the Administrative Procedures Act. Wood contends the final Clean Water Rule should address isolated water bodies — those subject to the 4,000-foot rule — as the proposed rule did, on a case-by-case basis. Finally, the arbitrary nature of whether isolated water bodies are included in jurisdiction could be seen as “regulatory over-reach” because it contradicts Supreme Court decisions, which undermines credibility of the rule, according to Wood. Another internal Corps memo from May 15 questions the legitimacy of the Economic Analysis of the EPA-Army Clean Water Rule published in May. Corps Regulatory Program Chief Jennifer Moyer wrote, “the document mixes terminology and disparate data sets” and also “makes certain assumptions that have no analytical basis.” The report “grossly overestimates” the amount of compensatory wetlands mitigation required under Section 404 of the Clean Water Act, according to Moyer. Section 404 wetlands permits are typically administered by the Army Corps of Engineers. She added that the EPA requested no quality checks on mitigation data. “EPA appears to have placed its own data into tables originally provided by the Corps. This results in a gross misrepresentation of the corps’ raw data,” Moyer wrote. She ended the memo by requesting that any reference to the Army Corps of Engineers’ participation in the analysis should be removed by the EPA. An Army Corps of Engineers spokesman said the Corps could not comment on the Clean Water Rule because of the ongoing litigation. Despite the concerns of Corps staff, Army Assistant Secretary Darcy testified Sept. 30 before the Senate Subcommittee on Fisheries, Water, and Wildlife, chaired by Sen. Sullivan, that the Army was an “active partner” in developing the Clean Water Rule with the EPA. “I am proud of the Army’s role in developing the rule,” Darcy said. “We should stand should to shoulder with our colleagues at EPA in support of the merits of the final rule and the process used to develop it.” President Barack Obama appointed Darcy to her post in 2009. Drafting of the final rule produced a lively and productive interagency process, between not only the corps and the EPA, but with other agencies as well, according to Darcy. She also said the varying interpretations of the rule are part of the vetting process. “The inevitable internal differences of opinions encountered along the way to this final rule were not unusual in the course of a rulemaking process,” Darcy said. The Army followed the EPA’s Administrative Records Guidance manual, she said, and the public record of the rulemaking was filed with the 6th Circuit Court of Appeals shortly before her testimony. Elwood Brehmer can be reached at [email protected]

Hospital CEOs: Prioritizing primary care over services a must

Reducing Alaska’s health care costs, or at least limiting cost escalation, will require philosophical shifts from both patients and providers, according to the leaders of three of the state’s hospitals. Central Peninsula Hospital CEO Rick Davis said the first step is getting providers on board with a wholesale change from the fee-for-service payment model that dominates Alaska to a payment-for-value structure. Davis, Alaska Regional Hospital CEO Julie Taylor and PeaceHealth Ketchikan Medical Center Chief Administrative Officer Ken Tonjes discussed care models Oct. 9 at the State of Reform health care conference in Anchorage. The fee-for-service model does not incentivize quality care; however, that’s not to say Alaska physicians are not providing good care. The value equation of care quality divided by cost simply is not emphasized, according to Davis. “We compete on who can do the most surgeries, who can do the most MRIs, because we get paid for doing that,” he said. “If the quality is there, that’s nice, but it doesn’t really matter to the provider because we’re still getting paid anyway.” If a procedure needs to be repeated, providers just get paid twice, he noted. Davis envisions what is beginning to happen in the Lower 48 coming to Alaska, he said in an interview. That is, the “value-based” purchasing components of the Affordable Care Act, or ACA, spreading to private payers. Under the ACA, some Medicare payments are being held back based on patient satisfaction and procedure quality scores. This year is the first year for provider penalties under the Medicare Physician Quality Reporting System set up by the ACA. Penalties result from performance two years prior, so physicians who did not report in 2013 or were found unsuccessful that year receive a 1.5 percent penalty on Medicare payments, according to the American Medical Association. The penalty increases to 2 percent in 2016. Lower 48 insurance companies are beginning to follow the ACA methodology, Davis said. Bundled payments for predictable procedures — hip and knee replacements and back surgeries among others — that include “the whole episode of care” down to physical therapy also emphasize value for payment, he said. Payers in Alaska have begun to ask for case rates and bundled payments. While no providers have agreed to those terms yet, Davis predicted they are not far off. The state’s small insurance market could slow the growth of bundled payments because insurers have less leverage, so it will likely start with the government structure and evolve into private plans. “Once the practice is in place it becomes sort of a natural progression” through the types of payers, Davis said. Davis, Taylor and Tonjes all agreed that hospitals need to take a back seat in the state’s care structure. “We all have to take a little bit of a leap of faith,” Tonjes said. He emphasized that patients aren’t the only ones who need to change their behavior; hospital administrators do too. Taylor outlined the reasoning behind Alaska Regional’s decision announced in January to open a community health clinic in Anchorage’s Mountain View neighborhood, an area currently lacking in primary care. However, a bus route takes patients directly from Mountain View to the Alaska Regional emergency room, she noted. “I’m paid very well for patients that come in with sniffles and sore throats and it’s not the right thing to do,” Taylor said. “Reimbursement does not encourage us to keep people out of the ER.” The Mountain View clinic is an effort to put proper, economical care where it is needed most, she said. Taylor has led Alaska Regional for nearly two years following hospital administration positions in Idaho and Denver. She said primary care physicians led the decision-making process of appropriate care at her previous hospitals, another Lower 48 lesson Alaskans could learn from. The idea of having one’s health care guided by a primary care doctor doesn’t always sit well in Alaska, when direct access to specialists is available, according to Taylor. The lack of care management that exists in the state is costing everyone a lot of money, she said, because preventative care and less-expensive treatment options often aren’t explored. Taylor used the example of a patient going under the knife for back pain who might have missed key care steps such as physical therapy because they went directly to a specialist before consulting a primary care physician. “This is not just the hospital reducing cost or physicians aligning; this is changing behavior and an expectation (by patients) that’s been set for many years,” she said. In small Alaska communities, hospitals will still be the umbrella organization for care, but patients will be directed to primary physicians under this coordinated care model. Davis said he is in the early stages of shifting the mentality among providers towards a coordinated care model at Central Peninsula Hospital. Population health management is an angle of coordinated care he feels could work well in Alaska. In the population health management structure, large payers — state Medicaid and large defined groups — and providers agree to a lump sum payment amount to cover groups of patients numbering into the thousands each year. “(Population health management) gives the payer a confidence that their costs aren’t going any higher and it incentivizes the system to put better coordination of care in place,” Davis said. Because group members can now go out of network and still charge the provider group, providers are encouraged to get the patient as healthy as possible as inexpensively as possible, according to Davis. Payment amounts are negotiated on available data and stop-loss insurance for providers is available to cover costs exceeding the payment, particularly for smaller groups where percentage cost variance risk increases. The group management system also pushes provider networks to invest in behavioral health and primary care as ways to avoid high-cost ER use and prevent long-term conditions as often as possible, Davis said. Alaska’s primary care and behavioral health provider shortage would not be a major issue under a coordinated care model, according to Davis. According to the Alaska’s Health Workforce Vacancy Study, about 20 percent of primary care positions are vacant in rural areas of the state. Rural behavioral health positions are 14 percent vacant, according the report released in August 2014. Statewide, there is a need for a 10 percent increase in behavioral health professionals, the report states. Coordinated care has helped increase wages for primary care physicians and slowed specialist pay increases in the Lower 48 where it has been implemented, he said. Higher wages in Alaska should encourage more primary care and behavioral health providers, he said. “The incentive is to shift the money over to those primary care providers who are going to be the captain of the ship,” Davis said. Elwood Brehmer can be reached at [email protected]

Changes to credits eyed as payments hit deficits

When Gov. Bill Walker vetoed $200 million of oil and gas tax credits from the state budget June 30, he said it was done to “start a discussion” about the incentive program. It worked. He called the current credit structure “unsustainable” given the state’s $3.5 billion deficit and low oil prices that are forecast to stay that way for several years. Agree with the veto or not, Sen. Cathy Giessel established an Oil and Gas Tax Credit Working Group that has met five times since early September to review the how the state’s current tax credit structure impacts the industry and state revenue. Walker’s veto did not eliminate any credit payments; rather the governor deferred $200 million of $700 million appropriated in the budget for the credits from fiscal year 2016. Thus, the $200 million will be added to anticipated credit demand in fiscal year 2017, which begins July 1, 2016. Tax Division Director Ken Alper said the administration has tried to work with industry and investors to resolve any liquidity issues arising from the lower state credit repurchase limits this fiscal year. Overall, more than 20 meetings have been had with industry, investors, oil and gas support companies and legislators to understand the importance of the credits and how the program could be revamped, Alper said. “What’s important is a plan of transition. We don’t want to pull the rug out from anybody,” he said. The Oct. 13 working group meeting focused on the lesser-known North Slope credits. Cook Inlet credits have been praised by industry and many in the Legislature for helping spur the resurgence in natural gas production in the basin. Since the 2007 fiscal year, Alaska has paid out $7.4 billion in oil and gas tax credits, with all but $1 billion of that going towards North Slope work. The former tax regime known as ACES was in place from fiscal year 2008 until Jan. 1, 2014, when the current tax structure under Senate Bill 21 took effect. However, 65 percent of the nearly $630 million of credits repurchased in fiscal year 2015 was for work south of the Slope in Cook Inlet and “Middle Earth” Alaska — everywhere else. So far this fiscal year about $425 million in credits has been repurchased of the $500 million available after the governor’s veto. Most of that money has gone to Cook Inlet and Interior work, according to the Tax Division. The State of Alaska offers four types of oil and gas tax credits that can either be directly repurchased by the state or used against a tax liability. They are: a credit for expenditures and operating losses; a credit to help cover exploration expenses; a per-barrel credit for small producers; and one used against corporate income tax. Alaska Oil and Gas Association CEO Kara Moriarty said the credits are the “core” reason many small independent companies are in the state. However, Alper said the state’s production tax revenue could go from about $300 million in fiscal 2015 to nearly zero if the major North Slope producers, BP, ConocoPhillips and ExxonMobil, post net operating losses in the state this calendar year. That’s because the companies could claim the 45 percent net operating loss credit against the 4 percent gross minimum production tax for legacy oil. “Tax credits, which are tied more to spending, have outstripped the production tax, which is tied more to the price of oil,” Alper said. He added that neither of the state’s recent oil tax regimes, ACES and SB 21, which have been the focus of intense political battles, were drafted with $50 per barrel oil in mind. The tax structures were meant to work with oil prices in the $80 to $120 per barrel range, Alper said. The state also receives royalty payments, corporate taxes and property taxes from the oil industry. Those totaled $1.8 billion fiscal year 2015 that ended June 30. The small producer per-barrel credit will sunset — the long Alaska summer type of sunset — in 2016. Producers pulling less than 100,000 barrels per day have been eligible to get the credit for up to $12 million. The credit total scales down towards zero as production increases from 50,000 barrels to 100,000 barrels per day. The small producer credit will close to new applicants next year, but companies can receive the credit for up to nine years. Alper said small Slope producers received $50 million from the credit in fiscal year 2015, all of which was taken against tax liability, as the credit is not refundable. Most exploration credits on the Slope expire along with the 2016 fiscal year, but most of those expenditures will continue to qualify for a 35 percent net operating loss credit, according to Alper. At the same time, the Department of Natural Resources will take a hit. Companies taking advantage of the exploration credits must provide their findings to the state. “The seismic and down-hole data is lost to the state when the exploration credits go,” he said. Potential changes to future credit programs could include an annual cap on state repurchases, Alper said; the current credits are unlimited, with the budget line items drawn from what the state predicts will be claimed in the coming fiscal year. He was quick to emphatically note that any alterations discussed at the meeting were purely ideas, not proposals from the Walker administration. A pre-approval process could tighten what work is eligible for tax credits. Eliminating “stackable” spending and loss credits is another of several options, Alper said. New programs could include direct state loans through the Alaska Industrial Development Authority to help smaller companies fund projects, the state taking a direct working interest in a project or a combination of both, according to Alper. AIDEA has helped finance Cook Inlet natural gas projects and Brooks Range Petroleum’s Mustang Field infrastructure on the North Slope. Sen. Peter Micciche, R-Soldotna, said the state needs to look at the “long game” and not be engrossed in immediate potential savings from cutting oil and gas tax credits. “Credit revisions affect the development side” of oil and gas projects, Micciche said. Challenging the development economics of the equation will likely kill future key production, he warned. Micciche manages the ConocoPhillips liquefied natural gas export facility in Nikiski. Anchorage Democrat Sen. Bill Wielechowski encouraged analyzing the current credit structure, but said cuts and improvements need to be made. “If we don’t make cuts here we’re going to have to start levying taxes on Alaskans and going after the Permanent Fund and that’s not something I’m going to support,” Wielechowski said. Elwood Brehmer can be reached at [email protected]

Buyout doubles cost, adds revenue

Gov. Bill Walker’s proposal to increase the state’s share in the Alaska LNG Project could put Alaska on the hook for more than $14 billion, but also generate about $400 million in additional annual revenue, according to a report from Department of Natural Resources consultants. The report released Sept. 30 performed by Black and Veatch, a consulting company that has evaluated the Alaska LNG Project in the past, firmed up an earlier estimate that the near-term cost for the state to buy out TransCanada Corp. would be $108 million. Alaska would then be on the hook, however, for TransCanada’s 25 percent portion of financing the North Slope gas treatment plant and the 800-mile pipeline south to Nikiski. The state’s share in construction costs would roughly double, from $6.5 billion to $13.1 billion without TransCanada’s involvement. The projections in the report assume a baseline $45 billion cost for the Alaska LNG Project and long-term oil prices in the $80 per barrel range, also in 2015 dollars. Buying out TransCanada is an agenda item for the special legislative session Walker called to start Oct. 24 in Juneau. “I appreciate this objective review of the consequences of the state purchasing or not purchasing TransCanada’s share of the (Alaska LNG Project),” Walker said in a statement. The $400 million in annual cash flow increase — in 2015 dollars — by terminating TransCanada’s role, would come from not paying the company’s tariffs on the state’s gas through the North Slope plant and the pipeline. Overall cash flow to the state over the first 20 years of operations would increase $7.4 billion, or about 6 percent, without TransCanada, according to the report. It estimates annual state revenues in the $3 billion to $5 billion range, totaling $76.7 billion over 20 years with TransCanada’s participation and $84.1 billion without the extra partner. Black and Veatch also concluded that the net present value to the state without TransCanada could be up to $1.2 billion because of the state’s ability to secure better financing for project infrastructure. Alaska’s midstream cost obligations would also drop from $8.20 per million British thermal unit, or mmbtu, with TransCanada to $7.30 per mmbtu without the company because the state should be able to secure lower cost financing, Black and Veatch estimates. That midstream cost alone — collectively the expense of the North Slope natural gas treatment plant, the pipeline and liquefying the gas — is roughly equal to what Asian markets are currently paying for delivered LNG, according to the Federal Energy Regulatory Commission. Landed LNG prices in Japan, the world’s largest LNG buyer, were $7.25 per mmbtu in September, a FERC chart states. Comparably, the landed price was nearly $15 per mmbtu across Asia in May of 2013 when the Alaska LNG Project structure began to take shape. House Resources Committee vice chair Rep. Mike Hawker, R-Anchorage, said in an interview that he was originally skeptical of the role TransCanada could play in the project when Senate Bill 138, the state’s guideline legislation for the project, was being debated. However, Hawker became convinced that “TransCanada brought a lot to the table and did not take a very big piece of the revenue pie,” he said. Hawker emphasized that the Black and Veatch report lacks critical information about its background assumptions. He also noted Black and Veatch declares that substantial portions of the report were provided by the Department of Revenue. “We need more than just a summary political document,” Hawker said. Senate Resources chair Sen. Cathy Giessel agreed that the report lacks important details. Giessel has said recently that she believes the Legislature would be open to buying out TransCanada if it makes fiscal sense for the state in the project. The latest report “causes pause because of the cash calls that are articulated in it,” she said. Black and Veatch cites state financial consultants First Southwest Co. and Lazard Ltd. that contend Alaska would likely have the ability to access bank debt and bond markets to replace TransCanada’s debt. Giessel said conclusions from the financial consultants haven’t been released yet. “That’s key information,” she said of the financing assumptions. “Clearly Black and Veatch thinks we can finance (the buyout). Really? Show me the money.” Currently, TransCanada, an Alberta-based pipeline company, has the state’s portion of the gas treatment plant and the pipeline and is responsible for financing a quarter of the engineering, design and construction of the infrastructure. The State of Alaska owns a 25 percent share of the liquefaction plant on the Kenai Peninsula, which is projected to be nearly half of the total project cost. The three major North Slope producers, ExxonMobil, ConocoPhillips and BP, make up the other 75 percent of the project, with shares equity shares equal to their ownership in their natural gas planned for export. The state has two buyout deadlines for TransCanada based on the current project agreements, Dec. 31, 2015, and Dec. 31, 2018, which would be just prior to construction. Buying out TransCanada late in 2018, after the front-end engineering and design, or FEED, stage would cost the state about $490 million. That would be roughly TransCanada’s development costs in the project, according to the study. Elwood Brehmer can be reached at [email protected]

Cohen Group questions EPA’s Pebble process

Former Maine Senator and Defense Secretary William Cohen agrees with Pebble Limited Partnership on at least one point: the Environmental Protection Agency’s Bristol Bay Watershed Assessment is not an adequate document to replace the federal environmental permitting process. Pebble contracted Cohen to review the procedure the EPA used to develop the assessment, which is the document the agency has based its Clean Water Act Section 404(c) proposed determination on. Section 404(c) of the Clean Water Act gives the EPA authority to prohibit any development project that it deems would have an “unacceptable adverse effect” on wildlife and nearby water supplies. Cohen asserts in the opening pages of the 364-page report that the work undertaken by him and his firm The Cohen Group was conducted as an independent review of the Section 404(c) action that began last year and the preceding events. He also notes that the report is not meant to take a stance on the project, rather it is to evaluate the process the EPA used in regards to Pebble. He further stated that Pebble had no control over the conclusions he reached and was not allowed to perform any edits on the report. More than 60 people were interviewed as part of the review process, including three former EPA administrators. The EPA did not allow current agency personnel to be interviewed for the report, according to Cohen. He claims that the EPA’s use of the 404(c) authority “compounded the shortcomings” of the assessment, that it used assumptions based on economic analyses done for Pebble to draw its conclusions instead of actual permit applications. Cohen states that EPA personnel had “inappropriately close relationships with anti-mine advocates” while compiling the assessment, raising questions as to whether the agency “orchestrated the process to reach a predetermined outcome.” A key argument in Pebble’s second lawsuit against EPA is that agency personnel and mine opponents formed de-facto advisory committees, which left Pebble out of the loop while researching the Bristol Bay Assessment, and violated public processes intended to be objective. Pebble is the first time the EPA has used its 404(c) authority to attempt to block a project before Clean Water Act permit applications have been submitted to the U.S. Army Corps of Engineers, which handles the permitting process for the agency. A U.S. District Court judge has stopped the 404(c) initiative at least temporarily while Pebble’s claims are heard in court. The EPA Inspector General is also examining the agency’s actions in regards to the Bristol Bay Watershed Assessment and Cohen calls for a Congressional Oversight Committee review. “This project is too important, for all stakeholders, to pilot a new, untested decision-making process,” Cohen wrote. “The fairest approach is to use the well-established permit/(National Environmental Policy Act) process, and I can find no valid reason why that process was not used.” He bases his conclusion at least partly on the EPA’s concession in comments to peer reviewers that gaps in the 1,100-page assessment that would be addressed in the NEPA process, which Pebble has not yet attempted to initiate. Sen. Lisa Murkowski criticized Pebble in 2013 for leaving Alaskans wondering if the controversial project would ever be built and called for the then-Northern Dynasty Minerals and Anglo American consortium to release more specifics about its plan. Pebble opponent groups were quick to criticize Cohen’s report after its release. Statements from Trout Unlimited Alaska, United Tribes of Bristol Bay and Commercial Fisherman for Bristol Bay all highlighted the fact that it was paid for by Pebble Limited Partnership. “The report wants Americans to believe that Pebble is the victim of an ‘unfair’ process. Let’s be clear, EPA’s process is one that is authorized by Congress under the Clean Water Act and is intended to be used in circumstances where mine activities will do insurmountable damage to the spawning rivers and habitat of this country’s last great sustainable wild resource: salmon,” a statement from United Tribes of Bristol Bay reads. Trout Unlimited Alaska Director Nelli Williams called the report “propaganda disguised as a credible document.” Pebble CEO Tom Collier said in a release that the EPA failed to take into account the potential economic benefits of a mine to an economy reliant upon a seasonal resource or the use of mitigation and control measures to reduce a mine’s impact on the environment, points noted by Cohen. “This report clearly makes the case about the criticality of a stable, objective and transparent permitting process for evaluating resource projects such as Pebble,” Collier said. “We did not ask The Cohen Group to evaluate a mine at Pebble as our view remains that this should be handled via the permitting and NEPA review process. The report validates the established regulatory and NEPA process is the fairest and most appropriate process for evaluating a complex issue such as ours.” The report also notes that Pebble participated in the assessment process with the EPA’s assurance that the final document would not be used to make a Section 404(c) decision. Since the release of the final Bristol Bay Watershed Assessment in January 2014, the EPA has acknowledged its conclusion that large-scale mining in Bristol Bay would significantly and irreparably damage the region’s salmon fisheries was drawn from the assessment as the primary evidence for working to ban the proposed mine. The official assessment process began in February 2011.

P3s offer financing options for cash-strapped governments

Public-private partnerships are gaining popularity across the country as governments with tighter budgets — see: Alaska — look for ways to fund critical public infrastructure. The potential benefits of the partnerships, best known as P3s, and the often-overlooked pitfalls were discussed Oct. 5 at the International Economic Development Council convention held in Anchorage. Generally, there are two categories of P3s, the international and American project models, each with its own merits. John Finke, a program manager for the National Development Council said the first and biggest difference between the project structures is how they are financed. The American model takes advantage of financing that is uniquely American: tax-exempt financing, typically through bonds. Tax-free debt can be sought through nonprofit public benefit corporations or by partnering with a more traditional 501(c)3 nonprofit. International model P3s, most common in Europe, Canada and Australia, bring private equity and private debt to public facilities, infrastructure and buildings, Finke said. It uses a long-term public concession for operations in buildings — up to 40 years in some cases. “It’s essentially control privately, ownership publicly,” Finke said of the standard concession agreement part of an international P3. American P3s typically use short-term building management contracts for operations and maintenance, along with a long-term lease from the nonprofit entity to the government for use of the building. Taxable financing is more expensive; “equity is the most costly source of money,” Finke noted, but it could open a project up to more partners. International P3s typically have higher debt-to-equity ratios and multiple lenders, compared to tax-exempt American model projects with a single lender. Finke has participated in 30 public-private partnerships across the U.S., including the $28 million expansion of the Wood Center dining hall on the University of Alaska Fairbanks Campus. The 46,000 square-foot addition to the Wood Center was done with no state funding. UAF will take back ownership of the facility when the debt, financed by the National Development Council, is paid off. The benefits of using the P3 process start with the simple principles behind the public and private sectors, according to Finke. “The whole gain in public-private partnerships tends to be getting out of the public works process,” he said. “The private sector is motivated by profit.” The public process has its place, but it does not have a motive for efficiency. However, private delivery of a project with performance incentives usually leads to lower cost, he said. Most public buildings, and infrastructure for that matter, are built using design-bid-build, or DBB, procurement. A P3 allows for nontraditional procurement methods that could save time and money. The goal of the American model is to take the delivery process out of the public sector, Finke said. He described each project as having three buckets: finance, construction and operations. “In those three areas the public’s goal ought to be to figure out how to pick the pieces out of the bucket that deliver the least costly project,” he said. “You cannot do that in a public works arena.” Finke and Arizona Department of Transportation Director of P3 Initiatives Gail Lewis both encouraged bringing a project team together earlier than would be normal in the public process. Finke said it provides an opportunity to “value engineer” a project as well as determine a feasible cost, which provides a baseline for bidding the project on a level playing field. That all helps the selection committee better understand the project and pick the best partner, he said. The quality cost estimate can also be used as a cap or limit for the project, above which the developer incurs any cost overruns. Finke also encouraged the private partner bid out as many aspects of the project as reasonable to drive down cost as well. When evaluating a highway project’s potential for being a P3, Lewis said she gets the engineering, finance, environmental and right-of-way teams together in one room. “At the end of the day you end up with a 70-80 percent confidence level that you can get a project done for somewhere in this cost range, somewhere in this time frame and that gives you the basis for your own knowledge of this project,” Lewis said. From there a project’s cost value is rendered, and determining whether or not partnering with the private sector can improve that value can follow. About half of the time it’s found that the public sector process is the way to go, she said, but that determination couldn’t be made without a meeting of the minds. Lewis also warned against claims — popular with politicians — that P3s don’t cost anything extra. “If there’s going to be private money involved you have to build the return, the amount of private capital that’s going to be returned and the interest that’s going to be repaid, into the model. And it’s often that you find the numbers just don’t work,” she said. “The next time someone tells you (that) you don’t have to raise the gas tax to pay for a project, just use a P3, it’s just not true.” Elwood Brehmer can be reached at [email protected]

Legislative committees get update on rural water projects

Despite major progress made in plumbing Alaska’s rural communities, the state is still more than a half a billion dollars behind in funding rural sanitation infrastructure. The actual need, according to the Department of Environmental Conservation, was more than $700 million in the 2014 fiscal year, while state and federal funding provided a total of $51.5 million in relief through the Village Safe Water and Wastewater Infrastructure program. That left a gap of $660 million. DEC has also received about $2.5 million per year over the past several years in federal assistance for subsidies and loans awarded through the Alaska Drinking Water Fund. Government funding for rural water systems has been mostly flat and even declined some since 2006, when DEC got nearly $79 million and the gap was $315 million, the department states. “A lot of the early systems we put in the (1970s), ‘80s and ‘90s are deteriorating; they’re aging and they need replacement,” DEC Facility Programs Manager Bill Griffith said during an Oct. 2 gathering of House and Senate committees. The joint meeting of the House Economic Development, Tourism and Arctic Policy and Senate Arctic committees was intended to update the bodies on work state agencies have done to implement the recommendations of the final state Arctic Policy Commission report. The report, published in January, directs state agencies — DEC in this case — to “foster the delivery of reliable and affordable in-home water, sewer and sanitation services in all rural Arctic communities.” The issue is related to un-served homes, but also many with drinking water systems already installed. Frequent regulatory changes to federal drinking water standards continually push rural water systems in place out of compliance and add to the fiscal need, Griffith said. For more than 50 years, DEC’s mission has been to eradicate the “honey bucket” from Alaska, and significant progress has been made in spite of the lack of money today. In 1985, fewer than a quarter of rural Alaska homes had running water and flush toilets; by 1996, the number of fully plumbed rural homes was up to 55 percent, according to DEC. Today, more than 90 percent of rural Alaska households have the necessities that are an afterthought elsewhere. A fairly large number of very small communities, 31 of them with about 3,500 homes, which comprise 17 percent of rural Alaska communities, remain un-served by water and sewer systems. Griffith said those villages are primarily in the Interior and on the Yukon-Kuskokwim delta. Adding to the need is that a lack of in-home water and sewer systems can lead to skin infections and respiratory illnesses for residents. Griffith said nearly all households in the state have access to clean water, but without plumbing they do not have access to enough clean water. He added that more information is needed to fully understand the exact relationship between the illnesses and the amount and uses for water in the home. Since about 1970, the state has focused on a “centralized” approach to water treatment, according to Griffith. That is, treating 100 percent of in-home water to full regulatory compliance, regardless of whether it is intended for drinking or flushing a toilet. Storing the necessary quantities of water, distributing that treated water, either via pipe or hauled by vehicle and collecting and storing household sewage are expensive propositions in rural communities particularly given the added cost of supplying the heat often needed to keep the system flowing. Installing the original system is expensive in itself, but maintaining it is another intense and expensive burden for cash- and expert-strapped communities, Griffith said. As a result, “the cost of operating a water and sewer system (in rural Alaska) is magnitudes greater than it is in urban areas or the Lower 48,” he said. Water and sewer user fees in some Western Alaska communities are more 6 percent of the areas’ median household income. The Environmental Protection Agency’s sustainability threshold for water and sewer fees is 5 percent. The average cost in the Lower 48 is just less than 2 percent of median income, while Juneau and Anchorage are cheaper yet. It’s clear a solution to these issues will not come from federal or state grants. This is where DEC’s Water and Sewer Challenge comes in. In 2013, the department began an international soliciting effort to grab the attention of engineers, social scientists, research institutions and manufacturers interested in solving Alaska’s rural sanitation challenges. This summer, six teams were narrowed to three finalists: one group led by the University of Alaska Anchorage and two private teams led by Tok-based Summit Consulting and Dowl Alaska, both engineering and consulting firms. Griffith said in an interview that contracts with the teams are being finalized. Part of the evaluation process includes the teams’ efforts to include input from the affected communities and their ability to draft an innovative design solution that will help close the $660 million funding gap. “This could be a place for innovation — a place for entrepreneurial opportunity,” Sen. Lesil McGuire said. Companies retain ownership of intellectual property used in the Alaska Water and Sewer Challenge to encourage private investment, Griffith said. Systems will be evaluated on 10 criteria and must provide 15 gallons of water per person per day, or 60 gallons per day for a four-person household. Those that can provide more potable water with less water delivery and wastewater removal will fare better in evaluation, according to DEC. Standard household service laid out by the challenge consists of kitchen and bathroom sinks, a toilet, a shower and washing machine hookups. Successful systems must also be usable within the confines of existing water systems in rural homes and require minimal additional floor space. Paramount for rural Alaska, systems must also have the capacity to be left unheated for multiple weeks and restart with minimal effort. The bottom line for the challenge is $135 per month; each system should meet performance goals without exceeding an operational cost of $135 per month, which is 5 percent or less of median household income in 75 percent of rural communities, DEC states. A full year of field tests will be done on the final systems, which will wrap up in 2017. A steering committee with then evaluate the results and systems demonstrating viable improvements over existing water supply and treatment methods will be deployed using funding sources available at the time. Griffith said DEC got $4 million for the challenge through an EPA appropriation and state match. “It’s a specific (EPA) appropriation for Alaska rural water and sewer,” he said in an interview. Whether or not $4 million will cover the entire program is unclear, given the cost to test the future systems is unknown, he noted. The state is also trying to take advantage of the U.S. chairmanship of the international, eight-member Arctic Council, Griffith said. DEC has proposed an international conference on water and sewer service in rural Arctic communities, to be held in Anchorage next fall. The premise of the conference has been supported by the State Department, Griffith said, but still needs “a couple hundred thousand dollars” to become reality. Elwood Brehmer can be reached at [email protected]

TransCanada buyout will cost $7B, but likely be worth it

Gov. Bill Walker’s proposal to increase the state’s share in the Alaska LNG Project could put Alaska on the hook for more than $14 billion, but also generate about $400 million in additional annual revenue, according to a report from Department of Natural Resources consultants. The report released Sept. 30 performed by Black and Veatch, a consulting company that has evaluated the Alaska LNG Project in the past, firmed up an earlier estimate that the near-term cost for the state to buy out TransCanada Corp. would be $108 million. Alaska would then be on the hook, however, for TransCanada’s 25 percent portion of financing the North Slope gas treatment plant and the 800-mile pipeline south to Nikiski. The state’s share in construction costs would roughly double, from $6.5 billion to $13.1 billion without TransCanada’s involvement. Buying out TransCanada is an agenda item for the special legislative session Walker called to start Oct. 24 in Juneau. The $400 million in annual cash flow increase — in 2015 dollars — by terminating TransCanada’s role, would come from not paying the company’s tariffs on the state’s gas through the North Slope plant and the pipeline. Overall cash flow to the state over the first 20 years of operations would increase $7.4 billion, or about 6 percent, without TransCanada, according to the report. It estimates annual state revenues in the $3 billion to $5 billion range, totaling $76.7 billion over 20 years with TransCanada’s participation and $84.1 billion without the extra partner. Black and Veatch also concluded that the net present value to the state without TransCanada could be up to $1.2 billion because of the state’s ability to secure better financing for project infrastructure. Estimates in the report assume a baseline $45 billion cost for the Alaska LNG Project and long-term oil prices in the $80 per barrel range, also in 2015 dollars. Currently, TransCanada, an Alberta-based pipeline company, has the state’s portion of the gas treatment plant and the pipeline and is responsible for financing a quarter of the engineering, design and construction of the infrastructure. The State of Alaska owns a 25 percent share of the liquefaction plant on the Kenai Peninsula, which is projected to be nearly half of the total project cost. The three major North Slope producers, ExxonMobil, ConocoPhillips and BP, make up the other 75 percent of the project, with shares equity shares equal to their ownership in their natural gas planned for export. The state has two buyout deadlines for TransCanada based on the current project agreements, Dec. 31, 2015, and Dec. 31, 2018, which would be just prior to construction. Buying out TransCanada late in 2018, after the front-end engineering and design, or FEED, stage would cost the state about $490 million. That would be roughly TransCanada’s development costs in the project, according to the study. Elwood Brehmer can be reached at [email protected] Look for updates to this story in an upcoming issue of the Journal.

Walker calls session; producers pan gas tax

Gov. Bill Walker’s administration released a report Sept. 24 outlining his review of the Alaska LNG Project, and issued a call to a special session to consider legislation to buy out TransCanada Corp. and a gas reserves tax. “For far too long, Alaska’s gas has been treated like milk with no expiration date, and it never gets to the front of the cooler,” Walker said in a formal statement of the gas reserves tax. “Without this insurance policy, Alaska runs the significant risk of never monetizing our gas resources for the benefit of all Alaskans and future generations.” Alaska is in partnership with BP, ConocoPhillips, ExxonMobil and TransCanada, a pipeline company, on the Alaska LNG Project. Walker has suggested the state should buy out TransCanada’s 25 percent stake in the 800-mile pipeline and North Slope gas treatment plant in an effort to maximize the benefit of the project to the state. The current estimate to buy out TransCanada is $108 million. “Introducing a gas reserves tax undermines the efforts of all parties to progress the Alaska LNG Project and puts investment in Alaska’s future at risk,” wrote ExxonMobil spokeswoman Kimberly Jordan in a statement released following Walker’s Sept. 25 press conference to discuss the special session. BP said in a statement that: “BP wants to be part of a successful Alaska LNG project that includes the State of Alaska as an equal participant and co-investor. A gas reserves tax complicates this process and results in unintended negative consequences, such as: distraction and delays to negotiations, impacts to investment, and Alaska jobs. “A targeted tax at any one of the Alaska’s oil and gas producers impacts all companies and will reduce work activities on the North Slope during an already challenged time for the State. The gas reserves tax makes an Alaska LNG project more difficult.” A ConocoPhillips spokeswoman said she had no comment until the company sees the specific legislation. Walker, meanwhile, had an answer to questions about the companies’ concerns. “If a producer found this objectionable, I’d have to question their motives,” he said. “It’s not a penalty at all unless they fully intend to not do a project.” The 11-page report follows what the governor said he intended to be a “45-day review” of the large natural gas export project, when he announced the review April 1. That was 177 days before the release of the report. “The purpose of the review is to ensure that if any course corrections to the gasline process were necessary, we recognize those changes early on,” Walker wrote in a letter to legislators accompanying the report. “It is in that spirit that I submit this report.” The Summary Report on the Review of the AK LNG Project Process, which also delves into the history of Alaska’s attempts at a large gasline, raises several issues with the current effort. It concludes that Senate Bill 138 — legislation introduced by former Gov. Sean Parnell’s administration and passed in 2014 — lays out a project process that “poses serious challenges that make AK LNG very difficult to progress in a manner, and on a timeline, that can maximize benefits to Alaskans.” SB 138 incorrectly assumes all involved parties will be motivated to bring the project to fruition, according to Walker’s report. The report claims there is “uncertainty regarding the role of TransCanada” in the Alaska LNG Project. It raises nine concerns about the status of the project — the first being time delays brought about by lagging participants potentially killing the project. Until there is alignment among the parties as to when the project should enter the front-end engineering and design, or FEED, stage and ultimately investment and construction, the party with the most interest in completing the project — the state — will have the most reason to make concessions to advance it, the report contends. “Part of the lack of alignment derives from some producers having other LNG projects that are competing with AK LNG, both in terms of market and access to corporate capital,” it states. Depressed oil prices could also slow progress and impact the ability of the participants to make capital investments that will be in the billions of dollars for each, according to the report. Thus, the state needs assurance that it will be able to acquire the stake of any party that pulls out and have “a reasonable commitment” that the withdrawer will toll gas through the pipeline or sell its gas back to the state. The State of Alaska is negotiating withdrawal agreements and milestones to resolve those issues, the governor’s report declares. Walker, who has also pushed for a 48-inch diameter pipeline, also argues in the report that the current 42-inch pipeline plan disincentivizes future gas discoveries by limiting the capacity of the project, and that the additional cost of the large pipe can be offset over time by operational efficiencies such as fewer compression stations needed along the route. The additional capital cost of a 48-inch line could be recouped in 14 years of 25 planned years of production assuming a base fuel price of $4 per thousand cubic feet of gas because about half the number of compression stations would mean less gas burned while fueling their operation, according to the report. A larger gasline could also benefit the Trans-Alaska Pipeline System. “Without question, the best way to put more oil into TAPS is to have a gasline that allows new companies who explore for oil to ship their newly found gas to market while exploring for oil,” the report states. It is noted that expanding the pipeline diameter could add six to eight months to the pre-FEED process that the AK LNG Project is currently in, but that should not significantly delay the final investment decision. Finally, concerns about the producers demanding more fiscal certainty in oil and gas tax structure than the state is willing to provide are briefly discussed. The state has heard from the producers about a need to have certainty on gas production and property taxes for the duration of the project, along with not having a gas reserves tax imposed during construction. However, according to the report, unnamed producers have expressed an expectation for certainty on taxes unrelated to the AK LNG project. “It is the administration’s belief that the people of Alaska will not support a constitutional amendment that authorizes fiscal certainty on oil and unrelated taxes, and the economics of the project do not require it,” Walker’s report states. “The state is concerned that offers made during past gas project negotiations, such as the (Stranded Gas Development Act), established producer expectations that are unrealistic.” Alaska voters narrowly upheld the flat-rate oil tax structure endorsed by the state’s oil industry known as SB 21 in an August 2014 referendum. Elwood Brehmer can be reached at [email protected]

Long, bumpy Arctic road reaches a dead end for Shell

Alaska’s political leaders were disappointed but not discouraged when Royal Dutch Shell announced Sept. 27 that it would cease its Arctic offshore oil exploration program in the Chukchi Sea. Gov. Bill Walker said in a press briefing later in the day that he was optimistic about what the oil giant would find under the waters off Northwest Alaska, and that Shell’s decision further highlights the need for development of the state’s known oil and gas resources. “I first want to compliment Shell on all they have done in Alaska; all their efforts on safety and environment, and the extra mile they have gone to persevere,” Walker said. “This has not been an easy task for them. It’s one that was met with challenges along the way; their staying power is very, very impressive.” However, the governor also called it a “very tough day” for both Shell and Alaska. Shell said in a formal statement that broke the news of the decision that it found indications of oil and gas in the Burger J well it drilled this summer, but that there was not enough positive about the results to further explore the prospect. Burger J, drilled to about 6,800 feet in the Burger prospect, is about 150 miles west of Barrow. The well will be sealed and abandoned. The Bureau of Ocean Energy Management, or BOEM, estimates there are about 15 billion barrels of oil and more than 76 trillion cubic feet of natural gas in the Chukchi federal lease area. However, how much of that is economically recoverable depends on many factors. Shell said in its statement that the large basin is “substantially under-explored.” The company also noted a “challenging and unpredictable federal regulatory environment” overseeing work in the region. “The Shell Alaska team has operated safely and exceptionally well in every aspect of this year’s exploration program. Shell continues to see important potential in the basin, and the area is likely to ultimately be of strategic importance to Alaska and the U.S.,” Shell Upstream Americas Director Marvin Odum said in a release. “However, this is a clearly disappointing exploration outcome for this part of the basin.” The company holds a 100 percent working interest in 275 Outer Continental Shelf, or OCS, lease blocks in the Chukchi. Shell’s Arctic saga Shell has spent approximately $7 billion on its Arctic OCS drilling program since the 2008 lease sale and encountered a bounty of challenges since in the effort that ultimately produced a single well. Its struggle to explore beneath the Arctic waters was a modern-day melodrama filled with fights in court, fights against Mother Nature and most recently a standoff with Greenpeace activists. It was preparing to mobilize for drilling in 2010 when the BP Deepwater Horizon disaster happened in the Gulf of Mexico, leading the government to halt all offshore operations including Shell’s Arctic exploration program. After a partial season in 2012 when Shell was only allowed to drill topholes at its Beaufort and Chukchi prospects because its spill response barge and capping stack hadn’t passed inspection, the Shell drill rig Kulluk broke free from its tow vessel on New Year’s Eve in high seas near Kodiak Island and grounded on a nearby small island. The U.S. Coast Guard successfully airlifted the Kulluk’s crew off the stranded vessel and thankfully the hull of the Kulluk, carrying more than 150,000 gallons of fuel and petroleum products, was not damaged to the point of spilling its cargo. The drillship was on its way from Dutch Harbor to Washington state, the timing of which was influenced by avoiding state property taxes had it remained in Alaska on Jan. 1. Ultimately, the massive drill ship was a total loss following the incident. Shell’s drill contractor Noble Drilling was fined $12.2 million late in 2014 for environmental violations on the Noble Discoverer during the 2012 season. Noble Drilling also operated the Kulluk for Shell, although the unpowered drill rig was being towed by Edison Chouest Offshore when it broke free. Shell was also fined $1.1 million in 2013 by the Environmental Protection Agency for air permit violations by the drill ship Noble Discoverer and the Kulluk while working in the Chukchi and Beaufort seas in 2012. Arctic OCS exploration was suspended for 2013 as Shell regrouped and prepped to try again later. Late in the year the company announced plans to focus on the Chukchi and delay its Beaufort Sea exploration. Environmental groups, which sued the federal government for underestimating the size of the Arctic OCS oil resource, and the subsequent spill potential in the region, managed to halt work in 2014 as BOEM revamped the environmental impact statement needed for Shell’s leases. With the supplemental EIS approved earlier this March, Shell appeared to be back on track in 2015. This time, it brought the Polar Pioneer drill rig leased from Transocean as well as the Noble Discoverer. By early May, Shell and its tug contractor Foss Maritime Corp. were in a fight with Seattle Mayor Ed Murray, who attempted to block the companies from docking the Polar Pioneer at the city’s port while preparing for the upcoming Arctic drilling season. Under pressure from environmental groups, Murray claimed the Port of Seattle terminal Foss had a lease for was strictly a cargo terminal, and thus prohibited the maintenance intended for the Polar Pioneer from being performed while docked there. Foss insisted its lease was in good standing and called the mayor’s bluff. A flotilla of kayakers protesting Shell’s Arctic exploration then attempted, ultimately unsuccessfully, to block the Polar Pioneer from entering the Seattle port May 18. The drill ship eventually made its way out of Seattle to Dutch Harbor, but in the meantime the U.S. Fish and Wildlife Service restricted Shell’s drilling plans by requiring simultaneous drilling efforts be kept 15 miles apart in the Chukchi to not disrupt walruses and polar bears in the area. Shell had originally planned to drill the Burger V and Burger J wells — nine miles apart — at the same time. It chose to drill Burger J. Shell hit another pothole July 3 when the Fennica, a 380-foot ice-capable vessel, struck an uncharted shoal exiting Dutch Harbor on its way to the Chukchi. The Fennica was carrying an underwater well capping system required to be on-hand for any drilling in the event of a spill or well blow out. After the three-foot gash to its hull was patched in Dutch Harbor, the Fennica set out for permanent repairs in Portland, Ore., again slowing Shell’s progress. The Fennica tried to leave a Portland shipyard and return to Alaska in late July, but was turned back by Greenpeace activists hanging from a bridge across the Willamette River in Portland. U.S. District Court of Alaska Judge Sharon Gleason, ruling from an Anchorage courtroom on activity in Portland, heard arguments by phone from Greenpeace attorneys in Boston and Shell counsel in Seattle, and found Greenpeace in contempt of a prior injunction that prohibited the environmental group from impeding Shell’s work. Greenpeace was initially fined $2,500 per hour until the dangling protestors were pulled from the bridge. Then, on July 30, Shell finally “spudded” the Burger J well and drilling was underway. The company drilled above oil-bearing layers until the Fennica arrived in the Chukchi. Good news, bad news All that led to Shell calling off its Arctic plans. The results from the Burger J drilling were not known until Shell’s Sept. 27 announcement — an announcement heralded by environmental supporters. “Moving to develop this oil, the production of which would still be decades away, would be feeding our addiction to fossil fuels at a time when we should be developing and moving clean, cheap and efficient forms of renewable energy into the mainstream,” Alaska Wilderness League Executive Director Cindy Shogan said in a formal statement. “With this announcement, President (Barack) Obama should seize on this historic opportunity to look forward and protect the Arctic for our children.” The Wilderness Society Arctic Director Lois Epstein said the news means Arctic coastal villages and wildlife are safe from a major offshore oil spill. “Hopefully, this means that we are done with oil companies gambling with the Arctic Ocean, and we can celebrate the news that the Arctic Ocean will be safe for the foreseeable future,” Epstein said. To the contrary, House Speaker Mike Chenault called Shell’s decision “a punch in the gut” in a statement from the House Majority caucus. He blamed a restrictive federal regulatory process for stymieing Arctic offshore oil and gas development. Majority Democrat Rep. Ben Nageak of Barrow echoed Chenault’s message. “Our people have been paying close attention to Shell’s actions and plans, and (the announcement) is heartbreaking for us,” Nageak said. “We stood on the cusp of another economic boom that could have propelled our young people and their children to better futures. Instead, due to strangulation of Shell’s proposal by our draconian and poisoned federal government, one well coming up dry is all it took for the company to say it’s not worth it anymore in the Alaska Arctic.” The sentiment of Alaska’s congressional delegation regarding Shell’s exit from from the state was summed up by Rep. Don Young. “I’m sure somewhere (Interior Secretary) Sally Jewell and President Obama are smiling and celebrating Shell’s decision to cease operations off the coast of Alaska. For Alaskans, this announcement is a major blow to our local communities, the future of Alaska’s economy and the Trans-Alaska Pipeline,” Young said in a release from his office. Sen. Dan Sullivan noted the likelihood of other countries, specifically China and Russia, developing Arctic resources “with little regard for the environment,” regardless of what happens in the U.S. And Sen. Lisa Murkowski, chair of the Senate Energy and Natural Resources Committee, called for a strong federal lease program in the future, offshore revenue sharing for Alaska and developing the non-wilderness — 1002 coastal plain — portion of the Arctic National Wildlife Refuge. Walker said he talked with Jewell Sept. 24 and planned to meet with her in the near future to discuss other opportunities to develop the state’s oil. He said Shell’s decision to halt exploration “underscores the critical importance that we make sure that we monetize, we develop our known resources.” The governor added he saw a “glimmer of hope” that Shell hopes to extend its federal Arctic OCS leases — its Beaufort leases expire in 2017 — and that the company may someday return to the prospects. Finally, Walker noted that it was just speculation to wonder if Shell would have stayed longer had it been allowed to drill multiple wells at once but said, “Do I think it hurt the prospects? Absolutely.” Elwood Brehmer can be reached at [email protected]

Producers agree to $16.5B for PILT, AK LNG impact payments

The “big three” producers involved in the Alaska LNG Project have agreed with the state to pay $16.5 billion for property tax obligations and to offset impacts in communities affected by construction and for the life of the project. Of the $16.5 billion sum, $800 million would be for community impact payments during construction. Afterwards, $15.7 billion would be payments in-lieu of tax, or PILT, substituted for property tax payments in project infrastructure and property holdings, Revenue Commissioner Randall Hoffbeck told the Municipal Advisory Gas Project Review Board Sept. 23 in Fairbanks. The board consists primarily of mayors of local governments along the project route from the North Slope to Nikiski on the Kenai Peninsula. The board did not pass recommendations on the state’s negotiations at the meeting; it simply needs more detailed information on details related to payment allocation and timing, according to Kenai Peninsula Borough Mayor Mike Navarre. The $800 million figure was negotiated by the state and is a fairly firm number, according to Hoffbeck. Having the community impact payment amount settled will be important for generating financial models as the $45 billion to $65 billion natural gas pipeline and liquefaction export project moves forward, he said. “If there was a firestorm of pushback (from local governments) we would take it back to the negotiations,” Hoffbeck said. That money would pay for increased public services, such as police and fire, in communities along the project corridor during construction. It is based on a five-year construction timeframe, and would have to be appropriately managed by the state to ensure funds remained if construction exceeded five years, Hoffbeck said. He noted that the state was sensitive in the negotiations to the fact that if it did not get enough money for impact payments, local governments would “become creative” in imposing fees on construction activity to cover growing budget line items. Navarre suggested the payments might need to be front-loaded as construction activity fades in the last couple years before the project is complete. A big question that remains to be answered is where the “direct construction impact” line is drawn, Navarre said in an interview. Communities outside of the immediate construction area — Fairbanks as a staging hub — will undoubtedly see significant impacts as a result of the Alaska LNG Project. How much money will they get, Navarre questioned. During the meeting Navarre said he worried about the powerful legislative delegations in Anchorage and Fairbanks pulling inordinate amounts of impact money to their communities. The future of the TransCanada Corp.’s role in the project could also weigh heavily on how much money is available for impact payments and from the PILT allotment, too, Navarre said in an interview. It was for these reasons, he said, the board did not pass recommendations on the state’s negotiations at the meeting. Hoffbeck described the $800 million in impacts funds as a “four-fourths” amount. Meanwhile, Gov. Bill Walker has expressed interest in buying out TransCanada’s 25 percent share in the North Slope gas treatment plant and the pipeline. “If the state owns 25 percent based on this four-fourths and the state’s exempt (from paying out) does that mean 25 percent of this number goes away, and if it does, whose share does it come out of, the municipalities’ or the state’s share?” Navarre asked. The $15.7 billion of PILT funds was deemed to be a reasonable amount of property taxes during operation and is based on a full, 42-inch pipeline over a 25-year project life, Hoffbeck said. Currently, the 25-year life is dependent upon finding new gas. “Right now there’s only enough gas to get to about year 18 in this project, so if they don’t find more gas it will be less than $15.7 (billion),” Hoffbeck said. However, if enough gas is found to extend beyond 25 years, the PILT amount would grow. Hoffbeck described it as a “pennies per mcf” surcharge on gas. Mcf is an industry abbreviation for one thousand cubic feet of natural gas, which a base measurement of gas volume. The $15.7 billion PILT amount is based on a 13.75-mill rate — an average of the state’s 20-mill rate for the gas treatment plant and pipeline combined with a negotiated 7.5-mill rate for the LNG plant and terminals in Nikiski. Navarre said the Kenai Peninsula Borough’s general rate is about 10 mills for most properties, and the 7.5-mill figure should be about right for such a massive facility. The producers have purchased about 600 acres for the LNG plant and need about 800 for the entire complex, project leaders have said. Navarre noted the facilities would roughly quadruple the tax base in the entire borough if they were to be taxed as normal properties. The overall $15.7 billion PILT amount is based on a mid-range capital cost of $55 billion multiplied by 3.25 percent inflation minus 0.75 percent for depreciation of the facilities. That figure is then calculated into the project’s throughput and finally the 13.75 mills. Yearly payments would start at $556 million and escalate 1 percent per year to $706 million in year 25 based on the current project design. Actual payments, highly dependent on throughput, would be based in part on the five-year rolling average of project production. Hoffbeck said the early years would be based on shorter averages that would increase over time so payments start at a reasonable amount. According to Navarre, allocation between state and local jurisdictions of the funds is as important as the overall figure. “I think the administration did a pretty good job on the negotiations of this,” Navarre said. “It really boils down to the allocation of the negotiated amount.” Elwood Brehmer can be reached at [email protected]

AIDEA loan aids state's first Krispy Kreme

It looks like Southcentral Alaskans will have a new way to get their sugar fix, thanks in part to the Alaska Industrial Development and Export Authority. The state economic development corporation’s board approved participation in a $6.9 million loan Sept. 24 to finance an East Anchorage retail center that is slated to house Alaska’s first Krispy Kreme donut shop. Located near the intersection of Debarr Road and Muldoon Road, the 21,000 square-foot retail center will also include a BurgerFi, the national chain’s second Alaska restaurant, and a Body Renew fitness center. The center is currently under construction, but an opening date was not discussed at the AIDEA board meeting. Krispy Kreme announced plans in late 2013 to open four shops in Anchorage and the Matanuska-Susitna region over the coming three years. The loan is to Westdahl LLC of Anchorage. AIDEA is participating in the loan for nearly $6.3 million over 25 years — 90 percent of the total amount. The remainder will be handled by Northrim Bank, which brought the deal to AIDEA and will service the entirety of the loan. Elwood Brehmer can be reached at [email protected]

Gov to call session for TransCanada buyout

It appears a fall special session is back on after Gov. Bill Walker met with a small group of legislators Sept. 21 to discuss issues key to the Alaska LNG Project. House Speaker Mike Chenault, R-Nikiski, said in an interview that the governor wants a 30-day special session to begin on or about Oct. 20. The docket would probably be limited to Walker’s proposal to buyout TransCanada Corp. from the project and forward funding the state’s role, according to Chenault. Chenault, Republican Sens. Kevin Meyer and Cathy Giessel and Republican Reps. Craig Johnson and Mike Hawker attended the meeting with the governor. Walker confirmed the likely special session agenda items in an interview and said contracts with the other players in the AK LNG Project would not be up for approval by the Legislature. By notifying the Legislature Sept. 21 of an upcoming special session, Walker would meet the statutory requirement for 30 days notice for a special session call an still have it begin Oct. 20. Chenault said he considered the Sept. 21 meeting as sufficient notice to start the session as early as Oct. 20. Alaska Gasline Development Corp. CEO Dan Fauske said Sept. 9 at a joint Resources Committee hearing in Palmer that Walker was unlikely to call a special session unless significant progress was made quickly in the gasline negotiations. The state is negotiating with North Slope producers BP, ConocoPhillips and ExxonMobil, who are partners in the $45 billion to $65 billion liquefied natural gas export project, the lynchpin of which is an 800-mile pipeline from the Slope to a mega LNG processing facility in Nikiski. Chenault said that he doesn’t believe the financial agreements are ready to be reviewed yet. “Naturally, we’d like to do it all at one time,” he said. However, he added that it’s positive to see the state making progress on such a big project. Calling a narrow-focused special session will indicate where the state wants to head, he said. Giessel said in an interview with the Journal that Walker asked for the legislators’ input, and that they asked him to keep the call limited. The governor agreed and indicated that the natural gas pipeline would be the main topic. Currently, the State of Alaska has a contract with TransCanada, a pipeline company, for it to own and operate the state’s 25 percent share of the large North Slope gas treatment plant and the pipeline. The state would own 25 percent of the LNG plant planned for Nikiski. The remaining 75 percent ownership of the project would go to the producers; roughly equivalent to the gas ownership each has in the project. Those partnerships were agreed to in Senate Bill 138 passed in 2014, which outlined the structure of the project. The state owns 12.5 percent of the gas as its royalty share, and could take an additional 13 percent “in-kind” rather than as a fiscal tax although a final decision on that has not been made. Walker has said assuming a larger ownership role could be in the long-term best interest of the state. In June, the governor proposed the state taking over TransCanada’s role among other options, including exercising an option to purchase a 40 percent share of the company’s interest in the project or keeping the consortium structure as-is. Giessel said a potential buyout of TransCanada could cost the state $108 million at a time when Alaska North Slope crude is selling for less than $50 per barrel and it is facing multi-billion dollar deficits. “Our (Senate) Finance Committee is interested in where that money would be coming from. That is a big deal,” she said. Giessel feels the Legislature could be convinced to get TransCanada out of AK LNG, a position Walker is rather committed to, she said. A TransCanada representative recently said at a joint House and Senate Resources Committee meeting that the company is ready to help the state in such a transition. Beyond the buyout price, Giessel said the state would need to make “cash calls” to pay for what would have been TransCanada’s equity share in the pipeline and the treatment plant. “We were going to have TransCanada carry that for us, like a young family depending on parents for a down payment — that was going to be their role,” she said. “With TransCanada out, how do we carry this on our own?” Giessel said legislators have been told the administration has modeled the costs for the state to finance its share of the project if it buys out TransCanada. “We would like to see that sooner rather than later,” she said. “This was the discussion we had with the governor.” The state taking TransCanada’s share — a commitment that will be in the billions of dollars — was discussed when SB 138 was being deliberated, according to Giessel. She noted that was also when the state was in a much better fiscal situation and oil was more than $100 per barrel. Even if the TransCanada buyout is resolved, another gasline special session could be in the works for next summer. The Legislature will almost certainly be consumed in the regular 90-day session with state revenue options to fill in the fiscal gap, more budget cuts and the hot-button issue of funding the state’s share of Medicaid expansion. Chenault said taking the issues up incrementally “shows good faith from the state” paramount to a project so important to the future. The producers have shown good faith in the project by continuing to spend millions on pre-front end engineering and design, or pre-FEED, work during a time of low oil prices, he said. Still to be resolved are financial agreements among the state and producers, which need to be hashed out before the Legislature, and then voters, can take up a constitutional amendment needed to move AK LNG forward. The amendment must be approved by a two-thirds legislative vote in a special session or the 2016 regular session if it is to be placed before voters in the 2016 November general election, as the Constitution requires. For the state to agree to long-term agreements, the amendment to the Constitution, which currently does not allow one Legislature to bind subsequent bodies to contracts or policy, is needed. Missing the November 2016 election would mean waiting until 2018 and potentially push the project back two years. Elwood Brehmer can be reached at [email protected]

Port MacKenzie rail almost out of cash

The Port MacKenzie rail line extension is nearly two-thirds complete, but there is currently no funding for future work. Matanuska-Susitna Borough Manager John Moosey said the borough has about $500,000 available for the approximately $303 million endeavor. “Segment 5 is close to being complete, but essentially what we have for this next season is only money to not mothball the project,” Moosey said. Construction of the 32-mile rail spur from Houston to Port MacKenzie began in 2013 and to date the borough has received about $183 million primarily from legislative appropriations, with a portion coming from voter-approved state general obligation bonds. Construction delays from partial funding have already added about $20 million to the project cost; however, Moosey noted the $300 million-plus cost is in line with initial estimates, which were then lowered. Getting the remaining $120 million sooner would be much better than later. “The longer we wait the more (the cost) goes up,” Moosey said. The eight-segment line is now about 65 percent after the summer construction season, he said. But getting the money through capital funding is all but a lost cause given the state’s $3.5 billion annual deficit. As it stands, embankment work is done on Segments 1, 3 and 6 — about 14.5 miles that is ready for track, according to Port MacKenzie Director Marc Van Dongen. Segments 4 and 5 are under construction and funding is needed for Segments 2, 7 and 8. Mat-Su Borough officials have touted the capability of their deep-draft commodity port, but its success is dependent on the rail line being complete. Plans for transporting liquefied natural gas from Port MacKenzie to the Interior are made much more feasible with direct rail access. Van Dongen is always quick to note that having the ability to rail raw materials virtually to tidewater at the port would improve the viability of numerous resource extraction projects along the entirety of the Railbelt. He said the borough is projecting one vessel per week would likely be moored at the 1,200-foot dock within five years of the rail line being complete. After that, the borough has plans for another large general commodity dock on the site. With another dock would come development of another 21.5 acres of gravel pad along the shore, Van Dongen said. Unique shipments for special projects In addition to exporting Alaska’s mineral and timber resources, Port MacKenzie has also been pegged as a site for LNG export facilities by Resources Energy Inc. and WesPac Midstream LLC. Along with 14 square miles of uplands for lay down area and eventually mile-long rail loop, the port has the potential for up to four more dedicated LNG terminals, according to Van Dongen. “Where else in the country do you have the opportunity to develop a deep-draft port a mile-and-a-half from the largest city in the state?” he said. “This is a unique opportunity. We’re still in the infancy of development.” Port MacKenzie will be a “world-class port” with several million tons of cargo traversing its docks each year after the rail line is complete, Van Dongen predicted. Before the potential of Port MacKenzie — across Knik Arm from Anchorage — can be realized, rail extension needs to be paid for and finished. Moosey said the uncertainty regarding the rail extension has undoubtedly hurt business development at the port, with companies needing to know when a transportation link beyond the two-lane road to the port will be available. If the funding were immediately secured, he said the project could be done in two years. The Mat-Su Borough has been looking at every financing option available to complete the key piece of infrastructure, including Railroad Rehabilitation and Improvement Financing and Transportation Infrastructure Finance and Innovation Act loans through the federal Transportation Department, he said. At the same time, the borough would likely have a hard time borrowing $120 million on its budget, according to Moosey. “The challenge is as soon as the project is complete we will be turning it over to (the Alaska Railroad Corp.) so we will not earn any revenue off that,” Moosey said. Further, the borough would have difficulty amortizing loans in the early years after the line is finished and before major development occurs even if some sort of revenue sharing agreement with the railroad could be reached, he noted. Gov. Bill Walker understands the position the borough is in, and Moosey said he has had positive discussions with the state railroad and the administration in efforts to come up with a funding solution. He added that Alaska Railroad CEO Bill O’Leary has been understandably conservative about the railroad’s ability to participate in financing the Port MacKenzie line. Alaska Railroad spokesman Tim Sullivan said the unfunded federal Positive Train Control mandate has consumed the railroad’s ability to take on debt, leaving little ability to help finish the promising project. Elwood Brehmer can be reached at [email protected]

Alaska trying to enter a shifting LNG market

The world of natural gas is an unsettled one. Low oil prices have hurt the economics of some gas projects; North America shale production has flooded the domestic market while Asian demand for liquefied natural gas continues to grow. All this as Alaska attempts to pull off the Alaska LNG Project, a potential $65 billion gas export plan, which could be a turning point in the state’s future, whether it happens or not. Resources Energy Inc. Vice President Brian Murkowski said to Alaska Oil and Gas Congress attendees Sept. 21 that understanding when and where unconventional gas basins will be produced would go a long way in determining how the LNG market will play in the future. REI is proposing a 1 million-ton per year LNG export facility for Cook Inlet natural gas at Point MacKenzie in the Matanuska-Susitna Borough. Additionally, conventional gas developments worldwide continue to outpace global demand for LNG, Murkowski said. Still, he thinks Alaska has potential. “If the economics are there (Alaska) should be able to compete,” in the LNG market, he said. A big reason for that could be the state’s proximity to the largest sector of the market in the world, East Asia. Total global LNG demand is projected to be roughly 260 million tons this year, with more than 65 percent of that need in Asia, according to Murkowski. Even as Japan restarts some of its nuclear energy capacity, the energy-hungry country will likely remain the largest importer of LNG in the world for at least another 15 years, he predicted. Japanese officials shut down the country’s 95 nuclear reactors after the 2011 Tohoku earthquake and subsequent tsunami that caused the Fukushima disaster. The country quickly switched to importing LNG as its primary source for electricity generating fuel. Japan now accounts for about 30 percent of the world LNG market, but it’s believed up to half of the country’s nuclear reactors could be restarted in the next five years, Murkowski said. “What Japan decides to do with LNG is of paramount importance to the market,” he said. Asia will still need most of the world’s LNG if Japan decides to go back to its nuclear program. Murkowski said global demand for LNG is expected to be more than 400 million tons per year by 2025. Of that, Japan will likely account for about 23 percent of the market, with China taking a 13 percent market share and Korea demanding 11 percent. In 2012, Korea was 14 percent of the LNG market and China purchased 6 percent of the 216 million tons sold. The Alaska LNG Project is a 20 million-ton per year LNG export project as currently constructed, with North Slope gas piped 800 miles south to a liquefaction plant at Nikiski. Alaska LNG from Cook Inlet has been shipped to Japan from ConocoPhillips export facility in smaller quantities since 1969, a relationship that bears significance in Japan, industry representatives often note. Gov. Bill Walker said at the Alaska Oil and Gas Congress that 25 to 30 Japanese and Korean companies were eager to meet and discuss the potential of the Alaska LNG Project during the LNG Producer-Consumer Conference held Sept. 16 in Tokyo. “The response in the market in Japan was one I’ve never seen before,” said Walker, who has been a longtime proponent of exporting North Slope gas. The governor spent about a week in Japan meeting with prospective buyers of Alaska LNG. He said he met with companies representing a large majority of the Asia market. Murkowski and Walker both noted the timing of the Alaska LNG Project, scheduled to start producing in 2024, as fortuitous, with some other long-term LNG contracts in Japan ending about then. The most likely international competition to Alaska LNG could come from Australia, where seven sanctioned projects could eventually add up to 87 billion cubic feet, or bcf, per day of natural gas to the market, Murkowski said. However, high labor and material costs could hamper the feasibility of some of Australia’s plans, he noted. Domestically, the Gulf Coast states are pushing for LNG exports from former import terminals, Walker said. To Alaska’s advantage, as it is in many arenas, is the state’s location, according to the governor. While the state’s project requires an 800-mile pipeline, the LNG at the end of the process is a seven-day sail from Japan, as opposed to a 26-day voyage from the Gulf Coast. That is a big selling point for Alaska, Walker said. “A lot of things can change in a project, but the locations never do,” he said.  A pair of Japan’s largest LNG buyers joined forces in April to garner a larger share of the market and increase their purchasing power. Tokyo Electric Power Co. and Chubu Electric Power Co. formed JERA Co., which accounts for 45 percent of Japanese LNG demand. Walker said he was told JERA will need at least 20 million tons of LNG per year, which could be supplied by Alaska. Traditional Southeast Asia exporters of gas, Malaysia, Thailand and Indonesia, may soon become importers as well, according to Murkowski. In other areas, he said some LNG sellers could fade in traditionally gas-rich regions. Saudi Arabia, for example, is using much more gas than it has in the past. “The only real exporter in the Mideast is soon going to be Qatar, and of course Iran,” Murkowski said. He called Qatar a “global balancer” because it’s gas can go east or west depending on where the demand is greatest. Another exporter with options is Russia, and new gas discoveries in the eastern Mediterranean could lessen European demand for Russian gas imports. Russia’s gas can also go east and west via pipelines and the country’s Arctic emphasis could bode well for it in the LNG market, too. “The Russians are developing an icebreaking fleet that could really create a superhighway across the Arctic and bring product to wherever it’s needed,” Murkowski said. He noted, however, that Russia’s less-than trustworthy political nature could continue to hamper its ability to secure long-term export deals. Elwood Brehmer can be reached at [email protected]


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