Elwood Brehmer

On eve of fifth session, Walker done appealing to legislators

Round five starts Monday, July 11. Including last fall’s “gasline special session” when the Legislature approved a buyout of TransCanada Corp.’s interest in the Alaska LNG Project, the pending special legislative session is the fifth in less than 15 months and is beginning to resemble a heavyweight fight between the Legislature and Gov. Bill Walker. However, it’s far from déjà vu all over again. Last month the Senate passed a version of the governor’s vision to restructure how the Permanent Fund’s investment earnings are used: from just paying dividend checks to splitting the revenue between PFDs and general government services as the state continues to grapple with budget deficits well in excess of $3 billion. The Senate’s vote was by a wide 14-5 margin, meaning the House is Walker’s sparring mate this time. And it’s a House divided. Last special session — the fourth of the 29th Alaska Legislature — the House Finance Committee vote on the Permanent Fund legislation that ultimately killed the bill was split almost every way possible for as many different reasons as there are committee members. Sources within the Legislature told the Journal some of the votes against Senate Bill 128 were less about legislators disagreeing with the necessity of the bill and more about them following constituent sentiment. Retooling the Permanent Fund to put a significant dent in the annual budget deficit — SB 128 would add about $1.8 billion per year to spendable state revenue and roughly cut the current deficit by half — also means a future with dividend checks that are likely half of near-term projections. That is, unsurprisingly, unpopular. Rep. Tammie Wilson, R-North Pole, said repeatedly and defiantly in committee meetings and on the House floor that she will never vote to change the PFD. Other majority members said they needed to see more budget cuts before they could ask their constituents to accept potential PFD reductions. House Minority Leader Rep. Chris Tuck, D-Anchorage, said in an interview that only demanding a Permanent Fund plan is not a comprehensive fiscal plan and that calling the Legislature back so soon after the last session ended unceremoniously in late June will simply “embolden people against his plan.” Walker has pushed for personal and industry taxes also, but his main focus has been on the Permanent Fund, given it is the single biggest way to fill the deficit and there is little appetite to pass additional taxes on top of that. Tuck suggested revisiting the idea in next January’s regular session, after the November elections when the Legislature could look much different and lawmakers could be refocused without a pending election to worry about, particularly in the House, which has two-year terms. He emphasized the Legislature’s original budget cuts that took several hundred million dollars out of the 2017 budget, although some were one-time savings, as well as the omnibus criminal justice and Medicaid reform bills that will hopefully save significant money long-term as evidence of the Legislature’s successes. “We’ve done a lot of work this year trying to save money in the budget,” he said. On the positive, Tuck said he thinks the dissolving caucuses, at least in the House, is a good thing. “It doesn’t mean the system is breaking down; it means it’s coming together,” Tuck said, as factions of each caucus have joined forces this year on contentious budget issues. The difference with this round, Walker said in a July 6 interview, is that he took away as many of the “excuse de jours” that legislators have used against the Permanent Fund bill as he could when he rolled out a state budget with $1.3 billion in vetoes June 29. Walker said legislators told him in private meetings they needed him to take the political heat for steep budget cuts and reducing this year’s PFD from about $2,000 to $1,000 per Alaskan. He did it. Walker cut the dividend appropriation in half; cut the 2017 fiscal year oil and gas tax credit appropriation by $430 million to the statutorily required amount of $30 million; and among other agency reductions, cut combined education funding by nearly $70 million. “Now we’re going back to go back to and see if those that said, ‘You do this; we’ll do that,’ we’ll see how that goes. If nothing happens in this session and they gavel in, gavel out, I will have an address to the state because at that point it’s clear that the legislative process is not going to fix this problem,” an at times exasperated Walker said. To legislators who have said the governor needs to do more to gain public awareness on the state’s budget crisis: “Trust me, I’ve got the public’s attention as a result of what I did (with the vetoes). All eyes are focused on me as a result,” Walker said. To legislators hesitant to make a politically unpopular vote to change how the PFD is paid: “They owe it to their constituents that Alaska has a future. So while some are fighting for a dividend check I’m fighting for Alaska’s future. I’m looking at the next 10 years, the next 15 years, the next 50 years for Alaska.” To those in the oil industry that have been sharply critical of the second straight year of credit payment vetoes: “Remember, my fiscal plan was to pay off all those credits in totality. That’s still available, but we need to have a fiscal plan as well. “They pushed back to me and I pushed back to them. My push back to them was, ‘What are you doing to help on the fiscal plan in Alaska? What are you doing other than just fighting for your slice of the pie? What are you doing about the rest of the pie?’” While the version of tax credit reform that ultimately passed the Legislature and was signed by Walker was milder and more gradual in fading out some of the credits than his original proposal, the administration’s bill had a $1.5 billion appropriation to pay all past and future expected credit obligations. Elwood Brehmer can be reached at [email protected]

Edison Chouest to build new vessels to take over SERVS contract

Edison Chouest Offshore will be adding new vessels to its fleet when it takes over the oil tanker escort and spill response duties out of Valdez in July 2018. Linda Leary, president of Edison Chouest Alaska subsidiary Fairweather LLC, wrote in response to questions from the Journal that the maritime services provider parent company plans to take advantage of its in-house shipbuilding capabilities to execute its 10-year ship escort-response vessel system, or SERVS, contract with Aleyska Pipeline Service Co. Louisiana-based Edison Chouest announced in early June that it was selected by Alyeska to provide tanker escort and spill response services in Prince William Sound. The company will take over for Crowley Marine Services after a detailed two-year transition process. “(Edison Chouest) will be building new state-of-the-art tugs and new response barges for SERVS Prince William Sound operations. These tugs and barges will include the latest technology and comply with the latest regulations,” Leary wrote. The company owns five shipyards along the East and Gulf coasts from Virginia to Louisiana that allow it to build “mission-specific” craft, Leary added. Crowley has provided tanker docking services in Valdez since the startup of the Trans-Alaska Pipeline System in 1977. It added the Prince William Sound escort and spill response duties to its work in 1990, a year after the Exxon Valdez oil spill. Since then, Crowley has executed the SERVS contract virtually without issue. In February, Crowley announced it had gone 7 million work hours, or about six years, without a lost time injury in its Valdez operations. Alyeska Pipeline Service Co., which is owned by the “big three” North Slope producers BP, ConocoPhillips and ExxonMobil, manages TAPS operations and oversees the associated oil tanker activities in Prince William Sound. Alyeska spokeswoman Michelle Egan said cost was a factor in deciding to make the change from Crowley to Edison Chouest, but also noted the companies were “very, very close on cost” in their bids. She said the complexity of the contract makes it impossible to narrow the selection to a single issue. “One of the things that was particularly appealing about Edison Chouest was the new equipment that they plan to bring into the system — more modern technology, new vessels and then of course just their expertise and experience,” Egan said in an interview. She said Alyeska is obviously aware of and factored Edison Chouest’s involvement in the grounding of the Shell drill rig Kulluk during a winter storm near Kodiak Island late in 2012 into its decision. A 2014 U.S. Coast Guard report on the incident determined design flaws in Edison’s tow vessel caused fuel system issues that caused all four of the tug’s engines to fail and contributed to the grounding. However, most of the blame was placed on Shell for instructing Edison make the tow from Dutch Harbor to Seattle despite a significant storm forecast in the Gulf of Alaska. “Every company has events in its history and what’s really important is what gets learned and applied from those events and then also the overall record of the company and Edison Chouest has a superior (performance) record relative to its industry,” Egan said. “We look at it holistically.” Specific information regarding the new vessels and equipment won’t be made public at least until the SERVS contract between Alyeska and Edison Chouest is finalized. That is expected to happen later this summer, according to Egan. She noted that Crowley and Edison Chouest work cooperatively in other areas and said Alyeska does not foresee any significant issues during the two-year transition process from one SERVS operator to the next. According to Leary, Alyeska is developing a transition plan to integrate Edison Chouest personnel and equipment into existing operations over the next two years. “(The transition plan) will include specific milestones and areas of focus like vessel construction and assurance, contingency plan compliance, personnel training, regulatory and stakeholder engagement and operational continuity,” Leary wrote to the Journal. “Both Edison Chouest Offshore and Crowley will be active partners in the process, and both have committed to a thorough and professional transition.” Florida-based Crowley CEO Tom Crowley said in a release when the company announced it was unsuccessful in its bid to renew the SERVS contract that the company will “continue to work constructively” with Alyeska until its current contract expires in 2018. “Crowley and Alyeska agree that there is nothing more important than the continued protection of Prince William Sound,” Crowley said. The Prince William Sound oil spill response contingency plan, managed by the state Department of Environmental Conservation, sets mandates for much of the SERVS contract and should quell fears by some about a new company in the mix, Egan said. “It’s not like a new operator can come in and do things in a completely different fashion,” she said. Additionally, Alyeska has a continuous and “pretty rigorous” improvement process for all of its contractors, she said. Prince William Sound Regional Citizens’ Advisory Council Executive Director Donna Schantz said the SERVS contract selection process was tightly held and confidential. However, Schantz also said it is not in the council’s purview to recommend which contractors Alyeska should chose. The Prince William Sound Regional Citizens’ Advisory Council was established at the behest of a group of Cordova fisherman shortly after the Exxon Valdez spill in 1989 as a means to improve communication between the public and Alyeska. The 1990 federal Oil Pollution Act mandated the formation of citizens’ councils in Prince William Sound and Cook Inlet. While the nonprofit occasionally receives grant funding, it is almost exclusively funded by Alyeska Pipeline Service Co., at about $3.5 million in recent years, according to the council’s financial records. Schantz described the Prince William Sound Council’s relationship with Crowley as “very positive” and said she expects that to continue with Edison Chouest. The council will have a role in the transition, but has not yet been told what the specifics of that role will be, she said. “We’re going to be doing whatever we can to put together a prioritized list of what we would like to see tested to verify (Edison’s) crew capabilities — basically pre-qualify the crews before the change happens and just make sure that the level of care is maintained,” Schantz said. “We have very high standards here for prevention and response in Prince William Sound and the services this contract provides are key oil spill prevention and response measures. It’s so important that we maintain the high standards.” Crowley has about 250 employees in Valdez and operates 17 vessels for the SERVS contract. Leary described having crews based in Valdez as “critical” to Edison’s success under the SERVS contract. “Our crews will consist of qualified and experienced mariners with tractor tug and escort experience including local personnel, Alaska Natives and (Edison Chouest Offshore) mariners,” she wrote. “Our goal is to provide training and opportunity to develop local, Alaskan crews.” Several maritime unions have loudly criticized Alyeska for changing SERVS operators in spite of Crowley’s successful track record. Democratic candidate for the U.S. House of Representatives Steve Lindbeck has also highlighted that incumbent Republican Rep. Don Young has received nearly $300,000 in campaign donations from Edison Chouest and its related companies over the past decade. Through his office, Young has said it’s not appropriate for him to express an opinion on contracts between private companies. Schantz said the advisory council is simply concentrating on protecting Prince William Sound regardless of the SERVS operator. “Our focus is on escorting tankers in Prince William Sound and preventing and responding to an oil spill,” Schantz said. “I know there’s been a lot of talk from the unions and others but I’m not sure that’s very productive at this point. We need to kind of wait and see what’s going to be proposed and then move forward to make sure we can have the best system we can.” Elwood Brehmer can be reached at [email protected]

State rejects 2016 Prudhoe plan, extends current plan to Nov. 1

The state Division of Oil and Gas has officially rejected BP’s 2016 operational plan for Prudhoe Bay, but is extending last year’s plan until Nov. 1 in hopes the company will provide information on its efforts to market natural gas from the oilfield. Oil and Gas Director Corri Feige wrote a 15-page letter to BP Alaska Reservoir Manager Scott Digert June 30 rebutting several arguments BP and the fields primary working interest owners, ConocoPhillips and ExxonMobil, have made over the past few months as to why they cannot give the state what it wants. In the letter Feige contends the state needs to be able to plan for “major gas sales” — a natural gas pipeline and export project — and doing so requires BP and the working interest owner companies sharing specific work they’ve done to market the gas worldwide. “Major gas sales, in the relatively near future, are necessary to realize the benefit of the enormous gas resource within the (Prudhoe Bay Unit) to the people of Alaska, and planning for (major gas sales) must be done now,” the letter states. Prudhoe holds roughly three-quarters of the natural gas planned for export in the now-tenuous Alaska LNG Project. The 2015 Prudhoe Bay Plan of Development was set to expire June 30. The renewal dates of the annual operational plans for oil and gas units vary because they are based on when the original plan was approved and thus often do not follow a calendar year. BP has until Sept. 1 to submit a modified plan of development for review by the division, according to the letter. Subsequently, the 2015 plan has been extended until Nov. 1 “to allow continued operations at (the Prudhoe Bay Unit),” the letter states. BP Alaska spokeswoman Dawn Patience wrote in an email that the company is reviewing the letter but couldn't provide further comment at this time. In January, now-retired DNR Commissioner Mark Myers sent letters to all the unit operating companies across the state informing them the department, through the Division of Oil and Gas, would be requesting additional information in future unit development plans about natural gas production and sales. The information would be used to better understand how the state can maximize those resources, either through instate uses or export sales, Feige explained in a previous interview with the Journal. BP’s submitted its Prudhoe plan just before the submittal deadline in late March. The plan document contained a few short and general paragraphs that indicated BP has significant interest in selling its gas from the North Slope field, but lacked any further detail. Feige responded in a letter dated April 11, stating the plan needs to contain “a detailed discussion of the efforts to market gas from the unit during the preceding year, and a detailed plan for marketing efforts the (working interest owners) or unit operator will undertake under the proposed (plan of development).” More specifically, the division has demanded information about which, if any, potential gas buyers the companies have talked to as well as potential pricing terms that would make gas sales viable. Gov. Bill Walker has declined to comment on the division's push for the gas marketing information because it is a regulatory matter, according to a statement from his office. The company held firm that the original plan document is complete in a back-and-forth of letters with the division since, stating much of the information the state wants does not exist, and if it did sharing it with the state could violate antitrust laws because the state is a potential competitor with the companies whenever the gas from the field is sold. ConocoPhillips and ExxonMobil have stood behind BP in their own correspondence with the division, saying they also believe the plan is complete. The companies also contend the new demands are a significant departure from the precedent that has been set over the nearly 40 years that the state has been approving development plans for Prudhoe. The first one was approved in 1977. On the other hand, the state argues it needs the marketing information to being preparing for major gas sales in about 2025, since that’s when the producers sought and got approval from the Alaska Oil and Gas Conservation Commission last October to start taking gas from the Prudhoe and Point Thomson fields. Further, the state has cited the companies’ “duty to produce” the gas resources repeatedly since the disagreement arose. While each side’s argument has largely remained the same in multiple letters, Feige, in her June 30 letter, referenced lines in the original 1977 Prudhoe Bay Plan of Development that states BP planned “to commence gas pipeline deliveries of 2 (billion cubic feet per day) as soon as a pipeline and plant to condition the gas to specification can be completed. This is currently estimated to be about five years after the start of oil production,” for the first time. Look for updates to this story in an upcoming issue of the Journal. Elwood Brehmer can be reached at [email protected]

New AGDC president gets grilled by resource committees

The Alaska LNG Project is at an unexpected crossroads. Consensus among state’s producer partners to continue the $45 billion-plus export plan for North Slope natural gas beyond this year has been lost. Concurrently, new Alaska Gasline Development Corp. President and CEO Keith Meyer is presenting an option to overhaul the financial structure of the project that would allow the state to lead the project, but still depend on the producers selling their shares of natural gas from the Prudhoe Bay and Point Thomson fields into the project. “This project needs a cooperative relationship with the producers and I want to have a cooperative relationship with the producers,” Meyer said during a daylong joint House-Senate Resources Committee project update hearing held June 29 at the Anchorage Legislative Information Office building. Meyer’s vision of a state-led Alaska LNG Project — one Gov. Bill Walker has long alluded to — would keep the project on its current schedule for LNG exports by 2025, if not a year or two sooner. To do that, the state would take the lead role in marketing the project not only to potential buyers, but to potential investors as well. The idea was met with predictable skepticism from legislators, particularly those in the Republican-led majorities. They have spent more than two years familiarizing themselves with the existing Alaska LNG Project structure — that with the state, BP, ConocoPhillips and ExxonMobil as equity partners to the end. Finance Committee members of each body also participated in the meeting discussion. Meyer repeatedly emphasized to legislators that seeking out investors for the project that are content with lower, but stable long-term rates of return are the lynchpin to lowering the cost of the project beyond what can be done to engineer the cost down. “Because we’re starting with a high-cost framework we’re going to have to beat this project down on rate-of-return,” Meyer said. A state-led project could also reap tax-exempt benefits from the Internal Revenue Service, Meyer speculated, but he could not provide assurances on that front. Alaska LNG Project Manager Steve Butt said the project team has narrowed the overall cost to the “lower end” of the $45 billion to $65 billion price range estimate that has been used almost since work began. He added, however, that the market still provides significant challenges to a $45 billion-or so project. “I think at the right time the known (natural gas) resource on the North Slope will be developed, I just don’t know if that time is today,” Butt testified. “At the same time as we’ve cut 10 to 15 percent off the cost the market has gone down 50-60 percent. When I look at the market that’s a really heavy lift.” While everyone is familiar with the oil price collapse over the last two years, the Asian LNG market has not been far behind. LNG spot market prices have fallen nearly 75 percent, to about $4 per million British thermal units, since the Alaska LNG Project plan was formalized in 2014. The “high-cost framework” touched on by Meyer is unavoidable. To make the project economic, it has to be a mega project in the truest sense. The Alaska LNG Project is designed to process up to 3.3 billion cubic feet of natural gas per day — more than 10 times what the state currently consumes in an average day. Prepping all that gas for transport down the 800-mile, 42-inch diameter pipeline will require a massive gas treatment plant on the North Slope. Finally, the LNG plant and marine terminals planned for Nikiski will cover more than 600 acres and consume roughly half of the project cost. Meyer insisted that adding responsibilities to the state’s role would not equate to adding risk. That would be spread among multiple investors and contractors. In a previous interview with the Journal, Meyer said the financial structure change would transform the project from an LNG export project limited to the equity investors — the state and producers — to an infrastructure project that ships natural gas and processes LNG for anyone it contracts with. “If you get this built, this becomes the way to open up the North (Slope) to explorers. It’s not just the way to monetize Prudhoe Bay and Point Thomson gas reserves,” he said at the June 29 meeting. “I think the state will be well served to have somewhat of an open access regime.” At the same time, Meyer said AGDC would welcome any or all of the producers as investors if the project fit their criteria. Legislators questioned him as to why it would be prudent for the state to move forward with a project that the world’s largest companies in the business are wary of. “If the discussion is internal versus external capital, I’m open to discussion. If the discussion is more rogue in nature, I remain concerned,” Sen. Peter Micciche, R-Soldotna, said. Meyer stressed the financial overhaul is a concept and not anything the state has committed to. He also said numerous times during several hours of grilling by legislators that if the state wants to continue pursuing a project it has to evaluate other options. “We have two choices: You can either delay the project or you can look for something different and I think we have enough support among the parties to look for something different,” Meyer said in response to questioning from Anchorage Republican Rep. Mike Hawker. BP and ExxonMobil representatives testified that their companies continue to support an aligned project with the state and producers but acknowledged the market challenges. ConocoPhillips Alaska Project Integration Manager Darren Meznarich said the company is committed to completing the pre-front end engineering and design, or pre-FEED, process this year as the project schedule calls for. However, he followed that by saying ConocoPhillips is not likely to commit to the front end engineering and design, or FEED, stage in 2017, which could require the project partners to commit nearly $2 billion over a couple years and is the final process before a final investment decision. Meznarich added that ConocoPhillips would still make its share of North Slope gas reserves available to a project it is not an investor in for commercially acceptable terms and is open to the concept proposed by Meyer and AGDC. Elwood Brehmer can be reached at [email protected]  

Constrained Inlet gas market remains a quandary

Which comes first, supply or demand? That question quickly becomes chicken-and-egg tough when it pertains to the Cook Inlet natural gas market, where constrained demand impedes development of high-cost supply. It is, at best, an untenable situation. Natural gas produced from the Cook Inlet basin, which includes shore side developments on the Kenai Peninsula and to the west of the Inlet, exclusively supplies the energy needs of nearly 60 percent of Alaskans from the outlying areas of the Matanuska-Susitna Borough south to Homer. Electricity generated at natural gas-fired power plants in Southcentral supplied more than a third of Interior’s power in 2014, according to Golden Valley Electric Association; and about 1,000 Fairbanks residents and businesses have rid themselves of their backyard fuel oil tanks since Fairbanks Natural Gas began providing them Cook Inlet-sourced gas via truck in 1998. With no nearby alternative supply, those numbers exemplify the importance maintaining Inlet gas production: it means keeping the lights on and buildings warm in the economic heart of the state. While those population centers have grown over the past 10 years, the demand for gas has not. Alaska’s appetite for Inlet gas was mostly stable at roughly 200 billion cubic feet, or bcf, per year for more than 20 years from the mid-1980s until 2007. The impact of increased residential and commercial demand from population growth was muted by larger industrial needs — namely that of the Agrium Inc. nitrogen fertilizer plant in Nikiski, which closed in 2007 for lack of gas supply — and ConocoPhillips’ LNG exports to Japan. At about the same time a confluence of factors hit the market hard. In late 2006, the Regulatory Commission of Alaska rejected a gas supply contract between Enstar Natural Gas Co. and Marathon Oil that was linked to Lower 48 Henry Hub market pricing. That ultimately resulted in a separation of pricing for the isolated Inlet gas from the indexed trading market. Since the de-linking, shale gas has depressed Henry Hub to the $2 per thousand cubic feet, or mcf range, while Inlet gas has generally fluctuated between $6 and $8 per mcf. The primary gas fields in the basin were also starting to show their age. Some had been producing oil and gas since the mid-1960s. Waning oil reserves made reinvestment uneconomic for the large operating companies at the time and consequently impacted gas production as well. With Agrium’s annual demand of about 55 bcf off the table and little exploration occurring, gas demand, and production, fell sharply for years until stabilizing somewhat in 2013 to roughly the current level of about 100 bcf per year. When the Southcentral utilities saw the declining production curve they began contingency planning — “self-protection mode” as Matanuska Electric Association General Manager Tony Izzo described it — and began discussing LNG imports to meet consumer needs, despite having one of the most historically prolific gas basins in the country in their backyards. The prospect of importing energy to one of the most hydrocarbon-rich regions of the world did not sit well with state lawmakers, who promptly drafted and passed the Cook Inlet Recovery Act in 2010, which incentivized development of the Cook Inlet Natural Gas Storage Alaska facility in Kenai and added to the oil and gas tax credits available to Inlet-operating companies. Two years later came Hilcorp Energy. In nearly one fell swoop Hilcorp purchased the Inlet holdings of majors Chevron and Marathon and immediately became the basin’s dominant producer. With Hilcorp came the 2012 consent decree between the state and the company — the agreement that has largely regulated Inlet gas pricing since then and will through its expiration in early 2018. Stable but not optimal The Cook Inlet gas situation began to stabilize with the consent decree, according to leaders of several Southcentral utilities. It capped base load natural gas prices at $6.60 per mcf in 2013, with annual 4 percent increases to a cap of $7.72 per mcf in 2017. The consent decree “added a degree of functionality to a previously dysfunctional market” and ended spot price bidding well in excess of $10 per mcf, Enstar Vice President and General Counsel Moira Smith said. Izzo said his only significant issue with the agreement, as a gas buyer, is the 4 percent price escalator. The most recent gas supply contracts between the utilities and Hilcorp and new gas producer Furie Operating Alaska LLC start when the consent decree expires and extend out to 2023. The initial prices in those contracts are up to 20 percent lower than the end of the decree pricing scale. While securing fuel supply is typically a utility’s top priority, Smith said in an interview that Hilcorp was willing to extend terms beyond 2023. Rather, it was Enstar that wanted to keep its long-term options open for potential new producers. Since Hilcorp took the lion’s share of the gas market, the lone new Inlet entrant with significant production at this point is Furie. Last September the state Division of Oil and Gas estimated there is about 1.2 trillion cubic feet of proven plus probable, or 2P, recoverable natural gas reserves in the Cook Inlet basin. With current local demand at about 85 bcf per year and ConocoPhillips annual LNG exports in the 15 bcf range the past two years — conducted in summer to balance seasonal utility demand swings — the division’s 2P reserve projection would provide a little more than a decade of supply. The U.S. Geological Survey has published total Inlet gas reserve estimates as high as 17 trillion cubic feet for conventional and unconventional plays — economics not considered. Furie Senior Vice President Bruce Webb said in an interview that he believes the current reserves could supply the status quo market for longer based on what Furie thinks it has, but the situation is still far from ideal. Regardless of the exact extractable reserves, Izzo said MEA’s contract with Hilcorp inked in April to supply all of its natural gas through March of 2023 provides the electric utility with only “temporary relief.” “As a buyer (of gas) and a provider of an essential service, the level of concern has not diminished for me at all,” he said. “For me, in three-to-five years I’m going to have to be looking at importing LNG again if I don’t see things turn around.” A “turnaround” would mean new players bringing new investment to new fields resulting in new gas production, according to Izzo. There has been a turnaround on the oil front since Hilcorp came to the scene. Cook Inlet oil production bottomed out at about 7,500 barrels per day in 2009. Almost always the more sought-after commodity, oil production has more than doubled to nearly 16,000 barrels per day from the Inlet in May, according to Alaska Oil and Gas Conservation Commission data. “In many ways, one could say that gas production hasn’t seen the same degree of turnaround because it’s a restricted domestic market where you’re limited to the demand that’s available,” Janak Mayer told the House Resources Committee during a Feb. 26 hearing on oil and gas tax credit legislation. Mayer is chairman of the Legislature’s oil and gas consulting firm Enalytica. Flat demand ConocoPhillips’ LNG exports, in addition to being subject to the forces of a depressed world market, are also limited by the company’s export license, which was renewed in February by the Department of Energy. It now runs into February 2018. The license allows ConocoPhillips to export up to 40 bcf of natural gas in liquid form over the next two years. However, those exports can only be made if local utility demand is met first. Thus, ConocoPhillips exports have come during the off-peak summer season since the plant reopened in 2014. Part of the market challenge stems from utilities, and residents, doing what we’ve been told to do for decades — saving energy. Enstar is not expecting demand growth from its natural gas customers through 2023 in filings with the RCA related to its latest gas supply contract with Hilcorp. Smith said incentive programs to purchase energy efficient appliances and state rebates for home weatherization projects, along with individual consumer efforts to use less natural gas, have offset the annual small growth in the utility’s customer base. “The conservation effect will result in flat annual demand from now into the foreseeable future,” Smith said. Izzo noted that the suite of new natural gas-fired generation plants in the region that have come online in recent years or are about to are all 25 percent to 30 percent more fuel efficient than the plants they are replacing, thus eliminating any significant demand growth from the electric utilities. Finally, Municipal Light and Power and Chugach Electric Association basically took up to 80 bcf of demand off the market over the next 15 years to 18 years when they partnered to purchase ConocoPhillips’ share of the Beluga River Unit in February. The utilities expect the field to produce between 70 bcf and 80 bcf in total before being depleted. Hilcorp owns the remaining third of the Beluga field and will operate the unit for the utilities, but it is a portion of valuable gas demand that will not be available to bid on for years to come. “We all think there’s gas out there but you have to think you can sell it before you can go out and invest,” Izzo commented. “If you went out and drilled a gas well now you wouldn’t be able to sell it until about 2021 or 2023,” Webb added. Tax credits For better or worse, Cook Inlet natural gas is about to return to a truly free, but still constrained, market. House Bill 247 signed by Gov. Bill Walker would eliminate state support for work in the basin starting in January 2018. That is just before the blanket price control of the consent decree will officially end on April 1, 2018. While much of the extra-extended legislative session this year focused on tax credits for the oil and gas industry, bill versions from House and Senate committees varied greatly on North Slope issue, but fairly quickly settled on eliminating credits from the Inlet within a few years. HB 247 cuts the current 25 percent Net Operating Loss, 20 percent Qualified Capital Expenditure and 40 percent Well Lease Expenditure reimbursable credits in half on Jan. 1, 2017. The halved credits are then fully killed off a year later. Webb testified in legislative hearings on HB 247 that Furie took advantage of all of the available Cook Inlet tax credits in developing the $700 million offshore Kitchen Lights gas discovery, which included installation of the first production platform in the Inlet in roughly 30 years. Furie began producing gas in time to fill its first utility contract with Homer Electric Association this spring. However, he noted the company recognizes the position falling oil prices quickly put the state in — that of annual budget deficits approaching $4 billion. “The state didn’t see this oil crisis — budget crisis — coming so we can appreciate the state’s position that they just can’t afford to pay everything anymore,” Webb said. He added that the final version of HB 247 that passed the Legislature gives companies needed time to adjust, while the administration’s proposal would have cut some of the Inlet credits nearly immediately this July 1. The tax credits helped Furie mitigate its biggest risk and the biggest risk any company takes —the risk of exploration — in a basin that is “easily 300 percent more expensive than the Lower 48” in terms of gas development, Webb said. Izzo said he is worried the state acted just a little too soon in wholly eliminating the credit program before additional gas reserves could be developed. BlueCrest Energy of Fort Worth, Texas, began producing small amounts of oil from the Cosmopolitan Unit just offshore of Anchor Point via a single onshore well in late April. The company committed upwards of $525 million to the project and hopes to produce up to 5,000 barrels per day this year. CEO Benjamin Johnson credited tax credits with helping the company develop the well-defined but green field reserve. BlueCrest investigated options to make gas production from Cosmo worthwhile — the gas reservoir sits directly above the oil — but the uncertainty about the credit program starting after Gov. Walker’s well-publicized line-item veto of $200 million of fiscal year 2016’s $700 million budget appropriation to pay for credits earned caused the company to delay tapping the Cosmo gas reserve, Johnson said in testimony to legislators this year. Another challenge for selling gas from Cosmo is that Hilcorp and Furie have eaten up much of the utility market for years to come. This year each secured contracts with Enstar through at least 2021. Hilcorp also recently inked a deal to supply all of Matanuska Electric’s demand from the end of the consent decree into 2023; and the two have other contracts in place as well. Now, BlueCrest is preparing to frack wells drilled from onshore to increase oil production. Legislative consultant Mayer said that infill drilling of developed fields should be profitable given Inlet gas prices and drilling costs; the situation Hilcorp is mostly in and Furie is working to get to with its first few gas wells in place. The economics of early development drilling, however, can be much different, he said. In a written response to questions from the Journal, Hilcorp stated: “House Bill 247 that recently passed the Legislature impacts our industry negatively. We, like all other oil and gas companies, have to consider these impacts when making our investment decisions. “In deciding where to spend our capital, a number of factors come into play and the stability of Alaska’s fiscal regime is an important one. Continued turmoil and instability within the Alaska oil and gas tax structure will also place Alaska at a disadvantage in attracting new players. We hope the result of any new legislation being considered will create a predictable and stable tax structure that encourages more oil and gas activity in Alaska.” A proposal by the administration to potentially offset the loss of the credits died in the Legislature and is not on the governor’s July 11 special session agenda; however oil and gas tax credits are an item once again. House Bill 246 would have established an oil and gas project development loan fund within the state-owned Alaska Industrial Development and Export Authority to provide low-interest loans for low-risk development projects. The fund would not have been immediately capitalized because the budget had already been passed, but HB 246 passed the House by a wide margin in the final days of the special session. The Senate had little time to address the legislation and adjourned without taking it up. Furie’s Webb said it obviously would not replace the tax credit system, which could offset more than half of the development costs of some projects, but has the promise to be useful, if it is not too restrictive. “If you go to Wall Street (for funding), the interest is really high because you’re trying to finance a project that may or may not prove out and you may or may not have a market for the product,” Webb said. “If the state has a good low-cost financing tool, that would definitely help out further development.” The Alaska Oil and Gas Association initially testified against the loan fund proposal, but later warmed slightly to the idea while emphasizing it would not be an adequate replacement for the credit program. Mayer testified to House Resources that spending more than $300 million per year on tax credits in Cook Inlet — as the state has done the past three years — is simply not feasible, particularly given the state receives minimal the production taxes the credits are tied to. “I think it’s hard to look at those (credit expense) numbers and see that as a sustainable system,” Mayer said. However, in the same hearing he added, “The basic impact of the credits is to make what is a very marginal investment maybe just possible,” exemplifying the challenge of the situation. Demand on the horizon The nearest demand growth appears to be at least four or five years away. That is, unless Agrium suddenly decides to restart its Nikiski facility, which seems unlikely given a statement by Richard Downey, a company vice president, who said nitrogen prices do not make that feasible at this point. “We continue to keep the plant warm, so to speak, in terms of upkeep, in hopes that someday we can return it to production. I would say market conditions are not conducive to that at the moment,” Downey told the Journal. He added that lower energy prices worldwide make restarting the Nikiski plant that relies on the Cook Inlet gas market a challenge. Webb also said he doesn’t think the Alaska LNG Project, or any other large North Slope export project, would impact the Southcentral gas market much, unless the Inlet gas supply fades and prices rise because the cost to move the gas down the 800-mile pipe would not match the local cost advantage. AIDEA officials leading the Interior Energy Project initiative to get natural gas to the Fairbanks area hope to start trucking more LNG north in 2018, but the 3 bcf per year starting point would be a minimal change in the overall market. The mega-mine Donlin Gold project is looking at a 315-mile natural gas pipeline from the west side of Cook Inlet to the mine site in the Kuskokwim River valley. As currently planned Donlin would need about 12 bcf per year to fuel the mine’s power plant and it would add the potential of getting natural gas to some of the nearby villages in the region. It would be a long-term customer, but would it provide enough to spur significant new exploration. The mine is also still in the environmental impact statement process, awaiting a federal decision sometime next year with operation still years away, along with being economically challenged by low gold prices. A mid-sized LNG export plant proposed at Port MacKenzie by Resources Energy Inc., a joint venture of Alaska and Japan interests, could crack the market egg. The plant’s 1 million tons per year of LNG processing capacity could add nearly 50 bcf of gas demand over 20-plus years and be the elusive “anchor tenant” to replace the void left by Agrium. With startup planned for 2021, the lead-time would allow for field development if need be. REI is looking for utilities interested in investing in gas reserves, which Japan has plenty of, General Manager Mary Ann Pease said, noting gas supply is not a worry. “We definitely think the gas supply is there,” she said. The challenge will be achieving the project’s $4 per mcf price target for wholesale gas, but that could be helped some through buying directly into a field. “The cost of gas is the single biggest thing that drives our project,” Pease said. Elwood Brehmer can be reached at [email protected]  

Furie takes first steps toward adding Inlet oil platform

Furie Operating Alaska is taking the first steps towards adding an oil platform to its Kitchen Lights gas development in Northern Cook Inlet. Furie Senior Vice President Bruce Webb said in an interview the company plans to re-enter the KLU-4 well roughly six miles north of the Julius R platform the company installed last year above its natural gas producing wells. The KLU-4 well was originally drilled to 10,000 feet in 2014 and will be punched down to 18,000 possibly this year but more likely next, according to Webb. “We know there’s gas there for sure; we’ve drilled through some gas and we see the gas on the seismic and on the seismic it appears to be a pretty large oil reservoir, but again, you don’t know for sure until you drill into it,” he said. “It could be really good sandstone with water.” The company once intended to drill farther, into the Jurassic formation, but expiration of the state tax credit for drilling with a jack-up rig in July caused Furie to back off on the extra drilling, Webb added. The work will be done with the Randolph Yost jack-up rig, a modified shelf-drilling rig the company moved to the Inlet early this year from the South Pacific. He said Furie hopes to get at least 2,000 barrels per day from KLU-4 starting sometime in 2019, about the time the company believes the oil production will become profitable. While Furie has identified gas in KLU-4, it hasn’t been fully delineated. “We’ll go after the oil and the gas will be there when we need it,” Webb said. It has begun the permitting process for another platform and is shooting for mid- to late 2018 to start development and eventual installation. “Depending on which road the federal agencies take (the permitting process) could be anywhere from one to three years. It depends if they decide (the platform) warrants an environmental impact statement,” Webb speculated. He said the second platform should cost less than the roughly $200 million it took to install the Julius R because a pipeline tie-in would only have to reach six miles back to the Julius R platform. Webb said a second pipeline to shore is already permitted if production from the combined developments eventually exceeds current pipeline capacity. The experience gained from the Julius R should also help keep the costs of a second platform down. “We learned a lot from the last installation,” Webb said. In the meantime, Furie is also drilling two development gas wells from the Julius R platform to supply the gas contract it signed with Enstar earlier this year. That contract starts in April 2018. Elwood Brehmer can be reached at [email protected]  

Walker names AG, introduces latest cabinet additions

Gov. Bill Walker’s cabinet is finally whole again. Walker introduced Anchorage attorney Jahna Lindemuth as Alaska’s new attorney general at a Tuesday afternoon press conference. Lindemuth replaces former Attorney General Craig Richards who resigned abruptly June 23 citing personal reasons. Walker said he was “struck” by her “passion for Alaska.” He referenced more than 950 hours of pro bono work she did in 2015 representing a victim of domestic violence and a wrongly convicted defendant in the very public “Fairbanks Four” case. “Everything she’s been involved in in her professional life she’s risen to the top,” Walker said of Lindemuth. Head of the Anchorage office of the international firm Dorsey and Whitney, Lindemuth has represented several Alaska Native regional corporations and ConocoPhillips Alaska in both state and federal court, according to the governor’s office. Acting Attorney General Jim Cantor will remain in that position until Lindemuth takes over the permanent position as Alaska’s top lawyer in early August. She will be the second woman to serve as attorney general of Alaska. Lindemuth conceded she will face “a steep learning curve” in transitioning from private practice to public service, but said she is confident the attorneys within the Department of Law will help make that switch easier. “Keeping in mind that there are real people behind the decisions that we make (as state attorneys) is important,” she said at the press briefing. Senate Judiciary Committee Chair Lesil McGuire, R-Anchorage, said in a formal statement that she is pleased with Lindemuth’s appointment. “(Lindemuth) brings years of Alaska experience to bear on the legal challenges facing our great state,” McGuire said. “With the Alaska LNG Project, Corrections reforms, arctic development and tribal sovereignty questions facing our state, I am confident Jahna Lindemuth will work for the best interests of all Alaskans.” Tuesday as also the first time Alaskans heard directly from new Department of Natural Resources Commissioner Andy Mack, who is taking over for acting DNR Commissioner Marty Rutherford, who is stepping down June 30. His appointment was also announced June 23. Walker said Mack has served as a behind-the-scenes consultant on oil and gas issues to the administration and has accompanied the governor in several meetings with Interior Secretary Sally Jewell. “I see an opportunity to play a little more offense than we have in the past” in relation to the state’s interaction with federal agencies regarding oil and gas development issues, Walker said. The governor has said repeatedly that he intends to continue pushing for exploration and development of oil resources in the coastal plain of the Arctic National Wildlife Refuge, a goal that is the opposite of the Obama administration’s view of the refuge. Mack said the move from his current position as a director for the Anchorage-based private equity firm Pt Capital to the head of DNR should not be an issue given both positions are tasked with bringing more investment into the state. “I can’t tell you how pleased I am to take this position the governor has offered me,” Mack said. Elwood Brehmer can be reached at [email protected]  

Anchorage attorney Jahna Lindemuth named new AG

Gov. Bill Walker’s cabinet is finally whole again. Walker introduced Anchorage attorney Jahna Lindemuth as Alaska’s new attorney general at a Tuesday afternoon press conference. Lindemuth replaces former Attorney General Craig Richards who resigned abruptly June 23 citing personal reasons. Walker said he was “struck” by her “passion for Alaska.” He referenced more than 950 hours of pro bono work she did in 2015 representing a victim of domestic violence and a wrongly convicted defendant in the very public “Fairbanks Four” case. “Everything she’s been involved in in her professional life she’s risen to the top,” Walker said of Lindemuth. Head of the Anchorage office of the international firm Dorsey and Whitney, Lindemuth has represented several Alaska Native regional corporations and ConocoPhillips Alaska in both state and federal court, according to the governor’s office. Acting Attorney General Jim Cantor will remain in that position until Lindemuth takes over the permanent position as Alaska’s top lawyer in early August. She will be the second woman to serve as attorney general of Alaska. Lindemuth conceded she will face “a steep learning curve” in transitioning from private practice to public service, but said she is confident the attorneys within the Department of Law will help make that switch easier. “Keeping in mind that there are real people behind the decisions that we make (as state attorneys) is important,” she said at the press briefing. Senate Judiciary Committee Chair Lesil McGuire, R-Anchorage, said in a formal statement that she is pleased with Lindemuth’s appointment. “(Lindemuth) brings years of Alaska experience to bear on the legal challenges facing our great state,” McGuire said. “With the Alaska LNG Project, Corrections reforms, arctic development and tribal sovereignty questions facing our state, I am confident Jahna Lindemuth will work for the best interests of all Alaskans.” Tuesday as also the first time Alaskans heard directly from new Department of Natural Resources Commissioner Andy Mack, who is taking over for acting DNR Commissioner Marty Rutherford, who is stepping down June 30. His appointment was also announced June 23. Walker said Mack has served as a behind-the-scenes consultant on oil and gas issues to the administration and has accompanied the governor in several meetings with Interior Secretary Sally Jewell. “I see an opportunity to play a little more offense than we have in the past” in relation to the state’s interaction with federal agencies regarding oil and gas development issues, Walker said. The governor has said repeatedly that he intends to continue pushing for exploration and development of oil resources in the coastal plain of the Arctic National Wildlife Refuge, a goal that is the opposite of the Obama administration’s view of the refuge. Mack said the move from his current position as a director for the Anchorage-based private equity firm Pt Capital to the head of DNR should not be an issue given both positions are tasked with bringing more investment into the state. “I can’t tell you how pleased I am to take this position the governor has offered me,” Mack said. Elwood Brehmer can be reached at [email protected]

Walker administration shuffled as AG, DNR commissioner step down

The Walker administration looks a lot different after separate announcements were made Thursday that Attorney General Craig Richards and acting Department of Natural Resources Commissioner Marty Rutherford will both be leaving Gov. Bill Walker’s cabinet. Richards’ resignation is immediate. Deputy Attorney General Jim Cantor will take over as acting attorney general until Walker appoints a new one, according to a release from the governor’s office. Rutherford’s is leaving at the end of June. Walker thanked Richards and Rutherford for their work for the state in formal statements. “When I appointed Craig (Richards) in December 2014 as attorney general, I knew Alaskans would benefit from his deep respect for the law and his vast knowledge of finance,” Walker said. “As the state’s top attorney, work has pulled him away from his three-year-old son, and I am grateful for the sacrifices he and his family have made in service to Alaska. Given Craig’s knowledge of gasline issues, I’m certain the state will continue to benefit from his oil and gas expertise as we push toward completion of a project.” Richards said in a statement that he is leaving for personal reasons. “I feel I need to re-focus on my family, which is impractical given the travel and workload requirements of the job. The Department of Law has top-notch lawyers, and I know the state is in good hands with these devoted public servants,” Richards said. Previously a law partner of the governor’s, he also worked as an attorney with Alaska Gasline Port Authority, a municipal group that was focused on developing a gasline from the North Slope to Valdez. In addition to his traditional duties as attorney general, Richards has been one of the administration’s point persons on the proposal to restructure how the Permanent Fund’s investment earnings are managed to significantly alleviate the state’s multi-billion-dollar annual budget deficit. Walker also put Richards on the Alaska Permanent Fund Corp. board of trustees earlier this year. Rutherford, who has worked for the state in some capacity for 27 years, is retiring from DNR June 30, but her work for the state is not over. Walker also appointed her to a public seat on the Permanent Fund Corp. board of trustees, replacing Gary Dalton. Rutherford’s father, John Kelsey, also served as a Permanent Fund trustee from 1987-95. “For nearly 30 years, Marty has helmed various important projects, including the gasline. Her knowledge of various topics and inimitable ability to connect with anyone she meets has inspired the utmost respect of people statewide — from the Legislature to the industry,” Walker said. Rutherford was a deputy DNR commissioner before taking the lead role after the retirement of Mark Myers from the commissioner position. As deputy for Walker, she led the state’s negotiating team for the Alaska LNG Project. She was also a deputy commissioner with DNR from 1992-2005 and held the same position in the state Department of Community and Regional Affairs before it was merged with the Commerce Department. “This is bittersweet for me,” Rutherford said. “I was born and raised here in Alaska, so it’s truly been an honor and great privilege for me to give back in some way to the state that has given me and my family so much.” Finally, Walker also appointed Andy Mack as DNR commissioner. Mack is currently a director at the Anchorage-based private equity firm Pt Capital. An attorney, Mack has served on the Resource Development Council of Alaska board of directors. He is also currently an advisor to several Alaska Native corporations involved in the North Slope oil and gas industry, according to the governor’s office. “As we look for more oil and gas exploration and development opportunities, Andy has the vision and passion Alaska needs to aggressively chart our own path. I am grateful to Marty, who has led the department seamlessly these past four months (as acting commissioner),” Walker said. “Alaskans owe Marty a debt of gratitude for her nearly three decades of government service.” Early in 2015 Walker appointed Pt Capital CEO and co-founder Hugh Short to the Alaska Gasline Development Corp. board of directors. Elwood Brehmer can be reached at [email protected]

Meyer shares gov’s vision of state-led LNG effort

One thing is clear: The state’s new point man on all things gasline has a new perspective on the Alaska LNG Project. Self-proclaimed “gas guy,” and, as of June 15, Alaska Gasline Development Corp. President and CEO, Keith Meyer views one of the largest and complex projects the country has ever seen more simply, as the “logistics infrastructure of moving gas from the supply point to a market point,” he said in an June 21 interview with the Journal. “When I look at this project, I look at it as an infrastructure project, not as an extension of a producing unit and I think that’s going to be a significant shift,” Meyer said. With a low-end cost estimate of $45 billion and an 800-mile long footprint from the North Slope to the Kenai Peninsula, the immensity of the Alaska LNG Project certainly isn’t lost on Meyer. A 35-year veteran of the energy industry, he oversaw the development of the Sabine Pass LNG terminal on the Texas-Louisiana line as president of Cheniere LNG. Sabine Pass was once the largest LNG import terminal in the country and has become an export facility after the shale gas revolution. Former AGDC President Dan Fauske, who led the corporation since its inception, abruptly resigned last November at the request of Gov. Bill Walker, who thanked Fauske for his service at the time, but said he wanted someone with more LNG industry experience to lead AGDC as the project developed further. Fauske’s background is in finance; he was also the longtime CEO of the Alaska Housing Finance Corp. After the taking hold in the late 2000s, the shale gas revolution quickly became the shale oil revolution that helped flood world oil markets with supply and is now indirectly challenging the AK LNG Project status quo. The gasline project Alaskans have come to know since early 2014 with BP, ConocoPhillips, ExxonMobil and the state as partners — now without TransCanada’s initial participation after the Legislature agreed to buy out the company’s interest last fall — moving ahead as one likely won’t be the project that is finished next decade, at least according to Meyer. Depressed oil prices have hit the producers’ and the state’s balance sheets hard. Walker’s strong desire to keep progressing to construction, combined with the producers’ waning willingness and ability to move along at the same pace has the parties in talks about a new Alaska LNG structure. That’s where Meyer comes in. By separating the need to be an owner in the project from the ability to obtain pipeline and liquefaction capacity, he said the state could lead the Alaska LNG Project as an infrastructure project. That would not mean, however, that the state would be forced to foot the bill. Meyer said he envisions potentially numerous investors: those looking for stable, long-term investment returns in the “low double-digit” range, percentagewise, or less. With the state in the lead the project could also reap tax advantages that, when combined with a larger pool of investors, could cut costs on the finance side. Those investors could be pension or insurance funds, or the large Asian utilities that are the likely LNG customers. The producers would not be excluded from that list either. “The producers are going to be welcome owners. We’d love to have them,” Meyer said. In the event one or more of the current producer partners chose not to buy into the project further, they would then become welcome upstream customers in what he described as a “contract carrier” pipeline and LNG plant. “When I look at the producers I first see customers,” he said. “We want to recognize that however this project goes we’re going to look at them as customers. We’re going to provide a very valuable service and we’re going to provide that service at a very reasonable price because they’re going to need to sell their product into the global arena as well.” The prospect of the producers not wanting to sell their gas into the state’s line is an unlikely one, he said. “My belief is that if we build a pipeline that lets them access the global market they will definitely want to sell their gas,” Meyer said. Last fall Walker requested and got informal letters of commitment to sell gas into a project from BP and ConocoPhillips in the event the companies decide not to directly invest. ExxonMobil did not provide such an assurance. The nine-page agreement signed last December states that the sales offer will be made to the State of Alaska if “mutually agreed commercially reasonable terms can be reached between the relevant party (the withdrawing company) and DNR (the state Department of Natural Resources).” In an analysis for the Legislature, Janek Mayer and Nikos Tsafos, of the firm enalytica, estimated that if the state were to purchase ConocoPhillips’ 22 percent share of the 35 trillion cubic feet of North Slope gas reserves, the cost, at $4 per million British Thermal Units, would be $19.2 billion. The structure would also open up the project to other North Slope producers with natural gas to sell. It would be an outlet that would hopefully spur new gas development, Meyer said. Project objectives Changing the investment structure does not mean changing the look of the infrastructure itself, though. The North Slope gas treatment plant, 42-inch pipeline and 20 million tons per year liquefaction plant that have been heavily studied and partially engineered is what the state would move ahead with — an export-sized project as opposed to an in-state only pipeline. With producers as upstream customers of the project contracting for space in the pipe and capacity in the liquefaction plant, the end buyers of LNG are then customers of the producers, or the state, with its share of gas, and not direct customers of the Alaska LNG Project. The new structure fills the first of the two major objectives that need to be achieved to make the project successful: It relieves the $45 billion-plus investment burden from the current project participants, including the state, according to Meyer. “There’s a lot of cash sort of sitting on the sidelines waiting for a good infrastructure project. An Alaskan LNG project is a good infrastructure project,” he said. “You’ve got a U.S. project — not only U.S. — it’s in Alaska, which has a demonstrable track record of LNG and energy exports, so this will be a very good infrastructure project.” He also doesn’t see convincing some key legislators, who have butted heads with the governor over prospective changes to the project can be successful as an issue. There are concerns about the state taking a larger role. “What I want to see us do is shave billions off the cost and years off the in service (timeline) and I think if we do that we’ll have full support of legislators,” Meyer said. “I think there’s a misconception out there that ownership is equivalent to investment and from my background I’ve never assumed that.” The second overarching objective is making the project globally competitive. Alaska’s near 50-year history of LNG exports from ConocoPhillips’ liquefaction plant and export terminal, just down the road in Nikiski from where the new plant might go, is a big plus for utilities that emphasize reliability of supply as much as anything, Meyer said. Additionally, Alaska is a direct sail to all the potential Asian markets; while Lower 48 competitor selling LNG have to go through a third country, Panama, to reach Pacific customers. Those factors, along with the fact that the gas reserves at Prudhoe Bay and Point Thomson are very well defined and developed, combine to still make the Alaska LNG Project a good one, according to Meyer. The established North Slope infrastructure also helps de-link the cost of North Slope natural gas from oil, easing price fluctuations. “If you take reduced volatility, stable venue, state, location and competitive price I think we’ve got a real winner. It’s all those things that go into a large utility purchase decision. It’s not just price, but price is important; we have to recognize that,” he said. He added that even though Lower 48 Henry Hub priced natural gas is now in the $2 per thousand cubic feet, or mcf, range, making it competitive with Alaska in Asia despite much longer shipping times, the Henry Hub market has historically been a volatile one, as well. Market analysts vary on projections for long-term Henry Hub pricing. Some feel that fracking fundamentally changed the North American natural gas market; while others contend it will still be subject to future price spikes. Since “fracked” gas became an established commodity in 2010, Henry Hub indexed natural gas exceed $5 per mcf once for a brief period early in 2014. The price issue for Alaska LNG will be at least partially addressed through timing. The current spot prices for LNG delivered to Asian ports of about $4 per million British thermal units (roughly equivalent to a per mcf price of natural gas) is nearly half of what Asian market spot prices were a year ago and nearly 75 percent less than what they were when the Alaska LNG Project was being conceived just a few years ago. That is simply the effect of LNG suppliers responding to the largest increase in demand the world has ever seen with the largest supply increase ever, Meyer said. The world is oversupplied with LNG. However, he sees the market imbalance correcting in the 2022-25 timeframe, which is the “demand window” the state needs to hit, he said. “One of the good things about natural gas is it is the preferred hydrocarbon molecule. The world is trying to get cleaner,” Meyer said. “We’re going to have this consistent demand curve (growth) for natural gas.” The current project timeline calls for startup sometime in late 2024 or 2025. But that also means time is of the essence. Meyer said the state “needs to be out in front of customers right now,” and starting to get contracts signed within the next two years. That will mean developing an AGDC marketing team. “Our marketing won’t just be LNG, it can also be this project,” he said, noting a utility could buy gas from a producer and use the Alaska LNG Project as a means to move and process what it bought. The corporation has until now filled the role of a technical body, first focused on engineering the idled Alaska Stand Alone Pipeline, or ASAP, project. To that end, the work done to date on the project’s upcoming Federal Energy Regulatory Commission license filing — FERC’s environmental impact statement process — “far exceeds” what is typically done on Lower 48 export projects at this point in development, Meyer said.  

Interior budget bill takes another shot at King Cove road

Alaska is a big part of the $32 billion bill headed to the Senate floor to fund the Interior Department, Environmental Protection Agency and the Forest Service. That shouldn’t be surprising considering Sen. Lisa Murkowski chairs the Interior and Environment Appropriations Subcommittee that drafted the legislation. The wide-ranging funding bill passed the Appropriations Committee June 16 on a 16-14 vote without Democrat support. “What we’re trying to do is direct federal resources where they’re needed,” Murkowski said during a June 19 teleconference with Alaska media. Overall, the $32 billion in funding for fiscal year 2017 would be about $340 million less than 2016, according to the committee report. On the Interior Department, Murkowski included language to initiate a new land swap between the State of Alaska and the federal government that would allow the state to finish construction of an emergency road between the Alaska Peninsula communities of King Cove and Cold Bay. She has led the Alaska congressional delegation’s push to get the link completed, particularly since Interior Secretary Sally Jewell blocked a land transfer for that purpose late in 2013. The land swap is needed because 11-mile unfinished section of the longer gravel road would run through the Izembek National Wildlife Refuge, where development of any kind is prohibited. Jewell ultimately rejected the previous land trade of about 43,000 acres of state and Alaska Native corporation land for 206 acres of Izembek territory — included in a 2009 omnibus public lands bill signed by President Barack Obama — after a U.S. Fish and Wildlife Service environmental impact statement determined the swap would negatively impact migratory bird habitat in the refuge and chose the “no action” alternative. Last September, U.S. District Court of Alaska Judge H. Russel Holland ruled in favor of the Interior Department decision in a lawsuit filed by King Cove Alaska Natives over the land swap rejection. According to the language in the bill, the land swap must be completed within 180 days of the legislation taking effect. With it being a funding bill and the federal 2017 fiscal year starting Oct. 1, 2016, that deadline would be in late March 2017. It also state’s that the land swap would “not constitute a major federal action for purposes of the National Environmental Policy Act,” meaning an environmental impact statement would not be necessary. Any difference in the appraised value of the federal and state land up for trade could be resolved with a direct payment by the State of Alaska to the federal government or through inclusion of more federal land. An appraiser would be selected jointly by the state and the Interior secretary. The 315,000-acre Izembek Refuge surrounds the village of Cold Bay and is home to entire populations of some waterfowl species, such as the Pacific black brant, at certain times of the year. The road would give King Cove residents in urgent need of medical care a reliable link in bad weather to the large World War II-era airport at Cold Bay. Murkowski said the previous deal that was rejected by Jewell is “off the table.” The latest appropriations bill directs the Interior Department to work out a deal of equal land value with the state. By stating that the land exchange and construction of the road “is in the public interest,” the bill appears to take any department discretion off the table as well. “It’s fully my intent to hold the Interior Department and the secretary — hold their feet to the fire and facilitate this transfer,” Murkowski said. The bill would also resurrect the Alaska Land Use Council. First established through the 1980 Alaska National Interest Lands Conservation Act, or ANILCA, the council was allowed to sunset in 1990. According to Murkowski, bringing back the council should help alleviate the often contentious working relationship between the state and federal agencies and give Alaskans “a stronger voice in the decisions made about the lands” in their state. Implementation of the EPA’s Waters of the U.S. rule would also be delayed by a year if the bill passes. The Obama administration and supporters of the rule, which is currently suspended in federal court after states sued to stop its implementation, contend it would clarify what waters the EPA has jurisdiction to regulate. Opponents argue it is another example of “federal overreach” that would inflate the agency’s authority and stymie development projects nationwide.Murkowski said the one-year hold is better than nothing. “We’re kind of counting on the courts here to recognize that this is a broad expansion of EPA’s authority to regulate under the Clean Water Act and to help us ensure that EPA is not allowed to proceed with this,” she said. “So, do I wish that it could have been a permanent moratorium, or ban? Certainly. Is a one-year delay what we were able to gain support for? Yeah, that’s where we are.” Indian Health Service funding for some Alaska-specific programs was also increased in the bill. It directs $11 million — $7 million more than 2016 — to the Village Built Clinics Program, which funds health care infrastructure in Alaska villages. Another $10 million is set aside for the Small Ambulatory Clinics Program to fund clinics in the extremely remote Western Alaska villages of Gambell and Savoonga. Nationwide funding for IHS drug and alcohol and behavioral health treatment efforts is also upped by $37 million in the bill to more than $240 million. Pertinent to Southeast Alaska, the bill prohibits the Forest Service from finalizing the Tongass National Forest Land Use Plan before conducting an inventory of harvestable timber in the 17 million-acre forest. The Forest Service’s preferred management plan for the Tongass, which is going through the public process, calls for a harvest transition from old growth to young, or second growth, timber in the coming years. The Forest Service is not opposed to the inventory measure, according to Murkowski. “It’s not about saying we don’t want to do the transition; it is about ensuring that the transition is based on a full and complete understanding of what we have and the Forest Service recognizes that,” Murkowski said. The bill provides $77 million for federal forest inventories nationwide, including portions of Interior Alaska. Conservation groups have lauded the Tongass transition as a major step to protect salmon habitat in the forest. Timber industry representatives in the state have said they are not opposed to a transition, but emphasize that it needs to happen slowly, over decades, to allow young growth stands to mature. Until then they continue to push for some old growth harvest. Elwood Brehmer can be reached at [email protected]  

Tesoro to sell some fuel storage in consent deal with state

Tesoro Alaska Co. has agreed with the state to sell about one-quarter of its fuel storage capacity at the Port of Anchorage. The state Department of Law reached a consent decree deal with the fuel service company dated June 10 that calls for Tesoro to sell its Terminal 1 fuel storage facility, with about 220,000 barrels of capacity. Last year Tesoro agreed to buy the majority of Flint Hills Resources’ fuel storage in the state. That included about 580,000 barrels of storage at the Port of Anchorage, as well as a rail loading facility. Tesoro previously owned storage capacity at the port. A six-month Department of Law investigation determined the Tesoro-Flint Hills deal would unduly limit competition among fuel providers at the port, according to a June 21 department release. The Port of Anchorage is the primary off-load point for the vast majority of goods, including fuel, headed for destinations across the state. “Allowing a new competitor into the Port of Anchorage will increase competition in this very constrained market,” Chief Assistant Attorney General Ed Sniffen said in the release. According to the consent decree, Tesoro has a year to find a buyer for Terminal 1. If it can’t find one, it must lease the storage capacity. An Alaska Superior Court judge must still approve the consent decree. In a June 20 release, Tesoro said its deal with Flint Hills initially reached late in 2015 had officially closed, with the consent decree a part of that deal structure. “This acquisition enhances our capabilities to efficiently and reliably serve our customers in the state of Alaska,” Tesoro CEO Greg Goff said in a formal statement. Tesoro also purchased Flint Hills’ fuel marketing contracts and a 22,500-barrel jet fuel facility at the Fairbanks International Airport. The refinery was not part of the deal. Flint Hills closed its North Pole refinery in May 2014, a move that impacted a range of businesses and industries across the state. Since, it has slowly divested its other assets in Alaska, such as its fuel storage tanks. Elwood Brehmer can be reached at [email protected]

Walker left with decisions after House committee rejects using Fund earnings

Where does it go from here? The House Finance Committee failed to move Senate Bill 128, the Permanent Fund restructuring bill, to the floor on a 5-6 committee vote early Friday afternoon. Gov. Bill Walker has all but said he would call the Legislature back again if the central piece of his fiscal plan to pull the state out of $3 billion-plus annual deficits is not adopted. Some members of the committee hinted that the governor has indicated he would back off that stance if the bill at least made it to a floor vote. Finance co-chair Rep. Steve Thompson, R-Fairbanks, summed up the situation in final comments before the vote: “I would like to see (SB 128) go to the floor and if it doesn’t we’ll be here next month.” Fellow co-chair Rep. Mark Neuman, R-Big Lake, made it clear that he would be a “No” vote on the floor because “that’s what my constituents expect of me,” he said, but supported moving the bill out of committee to give the full House a chance to resolve the matter. Rep. Dan Saddler, R-Eagle River, voted against moving the bill because he doesn’t feel “the Legislature has earned the public’s permission to go the revenue side” without further budget cuts. If Walker doesn’t call legislators back, or if they fail once again to adopt Permanent Fund reforms, he could partially veto the PFD appropriation in the operating budget that would pay checks of just more than $2,000 to each Alaskan this fall. When asked if he felt there is any way the currently calculated PFD for this year could be "held harmeless" during a June 15 press briefing Walker simply said, "No." Under the version of SB 128 that passed the Senate 14-5, dividend checks would be $1,000 for the next three years. The Senate Majority released a statement saying its members were “disappointed” in the House Finance Committee action. "We are facing uncertain times. SB 128 provided some level of certainty to help stabilize our economy and continue the divided program Alaskans have grown to rely on," said Sen. Anna MacKinnon (R-Eagle River), co-chair of the Senate Finance Committee. "The tough decisions have only just begun. We will continue to change the status quo and business as usual. The Senate stands ready to act." Republican Reps. Lynn Gattis of Wasilla and Tammie Wilson of Fairbanks both said the administration’s message about the importance of using the Permanent Fund’s earnings to partially pay for state government now has not adequately reached the people of the state. Gattis characterized it as the bill not being “ready for prime time.” “It’s been tough to try to convince the folks back home of what (budget) situation we’re in because we’ve had a great time, a great ride for these many, many years,” Gattis said. Wilson has been a clear opponent of any change to the Permanent Fund Dividend calculation that would likely lower future PFD payouts. “This is Alaskans’ money and I’m not going to take it from them,” Wilson said. She also asked Revenue Commissioner Randy Hoffbeck, who has been the administration’s point person — and the Legislature’s whipping post — on the Permanent Fund plan and the tax proposals, if a public referendum on restructuring the Permanent Fund was ever considered. “I think to simply say that every time you’ve got a hard decision you take it back out to the people — I don’t think that’s why the people — that’s not the way the system is set up; that’s not exactly (what) I think people expect from their legislators,” Hoffbeck responded. “I think they expect you to use your judgment because you will beyond the shadow of a doubt have multiple times more information to make the decision than the public will no matter how much time we put in trying to educate them on the issue.” He reiterated that the Permanent Fund was first set up to support the General Fund with the dividend program coming later, and continued: “I think when we talk about people owning the money in the dividend we also have to recognize that the people own the schools and the roads and other various forms of infrastructure and there needs to be money to keep those up and active and functioning and those don’t happen free of charge.” The administration has insisted since before the session that failing to overhaul how the state pays for its budget will drain state savings accounts and kill the dividend program and life as Alaskans know it within five years. That’s because of the belief that oil markets have changed worldwide, and a long-term return to the prices of $100 per barrel or more that would be needed to balance the current budget is a pipe dream. Thompson noted that the version of SB 128 as amended by the House Finance Committee that ultimately failed to move Friday guaranteed $1,500 PFDs for two years, with projected future payouts in the $1,000 range under the new formula. The version that passed the Senate by a wide margin guaranteed three, $1,000 PFDs with future checks likely just below $1,000. “$1,500, that’s larger than four of the dividends over the last six years,” Thompson said. He supported the bill on the belief that the Legislature will continue to reduce state spending in future years. Minority Democrats on the committee pushed back against the bill because they feel the budget is still too “bloated” with oil and gas tax credits to support a change how the Permanent Fund is utilized, as Rep. David Guttenberg of Fairbanks described the sentiment. Fairbanks Democrat Rep. Scott Kawasaki called the bill a “massive flat sales tax only on the shoulders of Alaskans.” Anchorage Democrat Les Gara, who has been a vocal critic of changing how dividends are paid, voted to move SB 128 to the floor, but did not indicate how he would vote if it had passed the Finance Committee. The House Finance Committee vote on SB 128 was as follows: Rep. Bryce Edgmon, D-Dillingham: Yes Rep. Les Gara, D-Anchorage: Yes Rep. Lynn Gattis, R-Wasilla: No Rep. David Guttenberg, D-Fairbanks: No Rep. Scott Kawasaki, D-Fairbanks: No Rep. Cathy Munoz, R-Juneau: Yes Rep. Mark Neuman, R-Big Lake: Yes Rep. Lance Pruitt, R-Anchorage: No Rep. Dan Saddler, R-Eagle River: No Rep. Steve Thompson, R-Fairbanks: Yes Rep. Tammie Wilson, R-North Pole: No Oil and gas loan fund approved; vote on taxes delayed Shortly after the House Finance Committee killed the Permanent Fund bill — at least for this special session — the full House quietly passed House Bill 246, which would establish a $100 million revolving loan fund for oil and gas infrastructure development projects within the Alaska Industrial Development and Export Authority. The bill received little attention during the regular session, but was a big part of the administration’s oil and gas tax credit reform plan. It would provide low-interest loans for companies in the place of some of the refundable tax credits that dominated debate late in the regular session. With the Senate all but formally adjourned and just holding technical floor sessions as the House worked through SB 128, it remains unclear what the Senate will do with the AIDEA loan program legislation. Votes on the motor fuel, mining and fishing industry tax increase bills were pushed back another day. It appears unlikely the tax hikes will pass the House if they are eventually voted on. Elwood Brehmer can be reached at [email protected]

Citing jurisdiction, Juneau seeks dismissal of head tax suit

The City and Borough of Juneau is asking a federal judge to throw out a lawsuit by cruise line representatives alleging the city misused tens of millions of dollars in revenue from passenger fees because the court doesn’t have the authority to rule on the matter. Attorney Robert Blasco, outside counsel for Juneau, wrote in a June 7 motion to dismiss the suit that the U.S. District Court of Alaska lacks jurisdiction to hear the suit that claims the city violated the U.S. Constitution by spending funds from vessel passenger fees on general government services. Cruise Lines International Association Alaska, or CLIA, which represents 12 cruise companies that operate in the state including some of the world’s largest cruise ship companies, filed the suit in April requesting a permanent injunction to the fees that total $8 per cruise passenger. Blasco cited the 1948 federal Tax Injunction Act, which prevents federal district courts from stopping collection of any state tax when the case can be heard in state court. “The Tax Injunction Act strips the federal courts of jurisdiction to enjoin or restrain the levy, collection, or assessment of state taxes, including local taxes authorized by state law, where plaintiffs can obtain adequate remedy in state court,” he wrote. The 14-page dismissal motion focuses almost entirely on the court’s jurisdiction as it pertains to the Tax Injunction Act, and does not rebut or significantly address the claims of misuse of head tax revenue CLIA cited in bringing the suit. The industry association contends the city spent more than $41 million collected from Juneau’s $5 per person Marine Passenger Fee and $3 per passenger Port Development Fee over roughly the past 15 years on projects and expenses not related to the cruise industry. That is potentially a problem because the Commerce Clause of the U.S. Constitution prohibits state and local taxes or fees imposed strictly on individuals engaged in interstate travel unless the money collected is used for projects or operations that benefit the travelers or are necessary to accommodate them. The vast majority of Alaska-bound cruises embark from Seattle. The State of Alaska also collects head taxes from cruise passengers and distributes that money to cruise ship ports-of-call communities. A state audit of how local governments have historically spent head tax revenue found with minor exceptions that the money was handled in accordance with the Commerce Clause. The audit did not investigate how local head tax revenues are spent. Juneau and Ketchikan — Alaska’s most visited cruise port communities — are the only locales with their own head taxes. However, Ketchikan is not a defendant in the suit. CLIA’s complaint alleges $22 million collected from the passenger fees, also known as “head taxes,” funded general government operating expenses; while another $11 million funded capital projects in the borough that “provide no direct benefits to the cruise lines’ vessels and passengers.” Likely the most visible illegitimately funded project, according to CLIA, is a manmade island being built in Gastineau Channel that includes a whale statue and is nearly a mile from the cruise ship docks. That is using $10 million in head taxes, CLIA claims. The dismissal motion contends that because the fees are imposed on all large cruise line passengers — nearly 1 million of which visit Juneau each summer — they qualify as taxes under the Tax Injunction Act. Blasco also wrote that because CLIA asserts the money in question was used for general government purposes, the Tax Injunction Act applies again. “The Ninth Circuit and other courts have repeatedly found assessments that were spend on such general uses as those alleged by (CLIA) to be taxes under the Tax Injunction Act,” he wrote. On the other hand, CLIA argues that because the head taxes are only levied on passengers of commercial vessels over 200 tons and those with overnight accommodations, they discriminate against large cruise ships, therefore requiring the revenue to be dedicated for cruise-related expenses. Elwood Brehmer can be reached at [email protected]

Walker wants balky House to act on using Fund earnings

All eyes are on the House Finance Committee. The only legislative committee meeting late in the special session, it met for nearly seven hours on June 14 to hear testimony from the administration, the Alaska Permanent Fund Corp., and the public on Senate Bill 128, the compromise proposal to establish a structured annual draw from the Permanent Fund earnings reserve account. The mechanics of the bill have been discussed at length since it was changed from an annuity-style draw to a percent of market value, or POMV, approach months ago in the regular legislative session. At this point, the focus is, unsurprisingly, on the dividend. SB 128 would change the Permanent Fund Dividend calculation from strictly a percent of Fund earnings to 1 percent of the Fund POMV plus 20 percent of state resource royalty revenue. The sticky wicket is that means this year’s projected record-high PFD of nearly $2,200 per Alaskan would be reduced to $1,000, as the bill also ensures $1,000 PFDs for three years, after which the new formula kicks in. The new formula is also projected to kick out dividends in the $1,000 range based on stock, oil price and production forecasts. The Senate passed the bill June 6 on a 14-5 vote, but House members hearing from constituents angry about the prospect of smaller checks are unwilling to make an unpopular vote. “Everybody knows the votes are not there (among House members) for this bill as it is written,” Rep. Les Gara, D-Anchorage, said June 14. Anchorage Republican Rep. Lance Pruitt said the concerns are bipartisan and that much of the worry is that SB 128 is the beginning of a “slow creep” to take the PFD away. In a June 15 press briefing Gov. Bill Walker commended the Senate for its June 6 vote that “ensured the dividend program would continue,” he said. “What’s remarkable about (the Senate) vote is it was a bipartisan vote. You had some Republicans; you had some Democrats. It was not a party line vote at all and I cannot thank them enough for that,” the governor said. Walker also reiterated what he, members of his administration and business groups that support revamping how the Permanent Fund is used have said countless times since the governor’s New Sustainable Alaska fiscal plan was unveiled in December. “Without changing, without Senate Bill 128, the Permanent (Fund) Dividend program in a few years will go to zero,” Walker said. “No one has disputed that. It’s not debatable.” That’s because without overhauling how state services are paid for, or without a dramatic and unforeseen rebound in oil prices, the current $3.5 billion or so annual budget deficit will drain the Constitutional Budget Reserve within two years. After that, the state would have to start burning through the Permanent Fund earnings “ad hoc” style, which the administration insists would eliminate the PFD by 2020. The 5.25 percent POMV draw called for in SB 128 would provide a smaller, but sustainable draw from the earnings of the Fund. It is supported by the nonpolitical Alaska Permanent Fund Corp. The governor added that “no action is unacceptable,” not-so-subtly implying that he will call the Legislature back into another special session if some form of Permanent Fund restructuring legislation is not passed by June 22, then end of this current 30-day special session. Walker talked with many members of the House by phone over the weekend, he said, and possible changes to the bill to garner more support were discussed. However, he told reporters that keeping the status quo on the dividend simply wouldn’t work. “We’re going to get across the finish line,” Walker said. That’s not how North Pole Republican Rep. Tammie Wilson sees it. She said emphatically during a brief and very poorly attended June 14 House floor session that cutting the dividend would be the “biggest mistake” the Legislature could make at a time when Alaska’s economy needs all the fiscal infusion it can get. “Reducing the dividend down to $1,000 could be one of the biggest things we could do to negatively affect our economy so therefore I don’t care how many times the governor wants to call us back if this bill (SB 128) doesn’t pass because I will stay here, and I know a lot of my colleagues will, to do what’s best for Alaskans no matter where this bill goes,” Wilson said. University of Alaska Anchorage Institute of Social and Economic Research Director Gunnar Knapp said in an interview that not infusing the economy with roughly $750 million — the collective PFD reduction — would undoubtedly impact the economy, but it’s not that simple. Knapp’s report entitled, “Short-Run Economic Impacts of Alaska Fiscal Options,” has been used continuously this year as a reference for measuring the potential impact of state budget cuts, new taxes and the like. In House Finance the banter was that the PFD cut would cost the economy upwards of 8,000 jobs. Knapp said his low-end calculation actually put the impact at about 4,200 jobs with a high potential impact of about 6,600 jobs. “Nobody wants to do anything that hurts — why would they? — except that we don’t have any choice. Over the next three to four years we’re going to have to do a few things that hurt and the sooner we do them the sooner we’ll fix the problem and the more savings we’ll be left with,” he said. “You can (preserve spending) by continuing to draw down on your savings but you need to think about the consequences of drawing down your savings.” The credit ratings agencies continue to hint at those consequences. Fitch Ratings quietly became the last of the “big three” ratings agencies to downgrade Alaska’s credit rating from AAA to AA+ when it announced the action June 14 as House Finance prepared for the first installment of its marathon meetings. On June 9, S&P Global Ratings — the first agency to downgrade its rating for Alaska back in January — put the State of Alaska on “CreditWatch with negative implications,” an indication that further, more significant downgrades are coming if a long-term budget solution is not realized. Walker said the downgrades send a message “across the country that something is wrong with Alaska.” His concern is that future downgrades would have a “chilling effect” on private investment in the state, the governor said. Revenue Commissioner Randy Hoffbeck said during the governor’s press conference that going from AAA to AA+ roughly equates to a 0.25 percent interest rate increase on bonds the state tries to sell, which alone is not catastrophic. “We recognize that AAA to AA+ is a fairly minor change — that one-quarter of 1 percent, even though it does add up — but we’ve got S&P saying they’re looking at a one, two or three more notch downgrade. Now we’re talking about really big dollars so there’s a lot of concern,” Hoffbeck said. The downgrades also impact local governments that bond for school and city projects on the back of the moral obligation of the State of Alaska, allowing them to capture better interest rates based on the state’s credit rating. Elwood Brehmer can be reached at [email protected]  

CIRI partners with Doyon on Nenana drilling

Doyon Ltd. is teaming up with Cook Inlet Region Inc. to fund its exploratory drilling in the Nenana basin this year, the Alaska Native regional corporations announced June 14. Two weeks earlier, Doyon spud the Toghotthele No. 1 well on a large gravel pad about seven miles west of the town of Nenana. The 10,000-foot Toghotthele well, which is the beginning of the shared investment, should reach the anticipated resource-bearing rocks by late July, Doyon leadership has said. “We are excited about this new partnership with a fellow Alaska Native corporation,” CIRI President and CEO Sophie Minich said in a joint release. “The Nenana basin offers a promising opportunity to meet the energy needs of Interior Alaska and provide additional benefits to our shareholders.” Doyon also hopes to drill a second well on the pad later this year to better delineate the results of Toghotthele No. 1. “We are beyond pleased to be partnering with CIRI in our exploration efforts. CIRI’s commitment speaks to the potential of a commercial-sized oil or gas find in the Nenana basin and their confidence in our efforts so far,” Doyon CEO Aaron Schutt said. Doyon holds 400,000 acres of state leases in the Nenana basin and has subsurface mineral rights to another 42,000 acres. It has been exploring in the area on and off since 2005 and has drilled two wells — the latest in 2013 — that indicated hydrocarbon-bearing formations worthy of further investigation. As is typically the case, Doyon’s primary target is oil, but the desire for a natural gas supply in Interior Alaska would seemingly provide a suitable market in the event of a significant gas find. When Doyon first announced its intent to drill the Toghotthele well last summer it put the odds of a commercially viable natural gas discovery at 50-50, and the likelihood of a significant oil play at about 20 percent. CIRI spokesman Jason Moore said those are the probabilities CIRI invested in the first well on, but the Southcentral region Native corporation is ready to extend the partnership should the well results warrant further drilling. “We really do view this as we’re investing in more than a well. We’re investing in an exploration program,” Moore said. In an interview, he said he could not disclose the terms of the partnership, but CIRI is taking a working interest share in the well and Doyon will remain as the operator, given its experience in the basin. The well is being drilled with a rig owned by Doyon Drilling, a subsidiary of the regional corporation. The partnership had been in the works for several months, according to Moore, and he said he could not recall a similar deal. “As far as a major investment partnership with another regional corporation, this may be a first for CIRI,” he said. Doyon spokeswoman Charlene Ostbloom said the corporation partnered with Arctic Slope Regional Corp. early in its exploration around Nenana, but she was not aware of any other business ventures with regional corporations. The state is also chipping in on the Nenana work. While the contentious oil and gas tax credit reform package passed by the Legislature earlier this month focuses on reducing state subsidies for Cook Inlet and North Slope activity, it extends a “Middle Earth” credit that funds 80 percent of drilling costs up to $25 million for the first two wells in each of the state’s six identified frontier basins. That credit was set to expire next month, but will remain in place until July 2017 if Gov. Bill Walker signs the legislation. Schutt has said the state’s Middle Earth oil and gas exploration tax credits were important in progressing Doyon’s previous drilling. Ahtna Inc., another Alaska Native regional corporation, is similarly drilling for gas near Glennallen. The administration pushed hard for cuts to the overall tax credit program, but also supported extending the Middle Earth credits to allow Doyon and Ahtna to complete their work that has been planned for some time. Doyon has also conducted 3-D seismic programs looking for likely oil and gas formations in the Yukon Flats region northeast of Fairbanks in recent years. Similarly, CIRI is becoming more active in the industry. Moore said the Nenana investment along with a seismic program shot on CIRI land on the Kenai Peninsula signifies “a bit of an evolution” by the company into the oil and gas realm. Elwood Brehmer can be reached at [email protected]  

AGDC hires Houston LNG exec as new CEO

The Alaska Gasline Development Corp. will have a new leader as of June 15. That is scheduled to be Keith Meyer’s first day on the job as AGDC’s president and CEO. Meyer will join AGDC from LNG America, a Houston-based energy logistics firm he founded in 2008 that focuses on increasing the use of LNG as a fuel for the maritime and transportation industries, according to an AGDC release. The hire was announced at the corporation’s monthly board of directors meeting Thursday morning. It comes nearly seven months after Dan Fauske resigned from the position at the request of Gov. Bill Walker last November. At the time, Walker commended Fauske, who had led AGDC from its inception, for his work there, but said the state needed someone with more direct experience in the pipeline and LNG industries. Prior to leading AGDC, Fauske had a long career in finance with the Alaska Housing Finance Corp. Meyer is starting on a three-year contract with a base salary of $550,000. He will be eligible for an annual performance bonus of up to $200,000, which will be decided by the AGDC board. Fauske’s salary was $360,000. As its name implies, AGDC is the organization leading the state’s efforts — currently focused on the Alaska LNG Project — to export North Slope natural gas through a pipeline project and get a portion of that gas to communities along the project corridor. “Keith’s contribution will be immediate and impactful. He’s a proven leader who understands what’s at stake in Alaska, and possess the skills and experience we need at this critical time in the development of our natural gas pipeline and LNG project,” AGDC board chair Dave Cruz said. “Keith believes in Alaska and in the mission of AGDC. I’m proud to welcome him aboard.” Interim president Fritz Krusen will return to his role as a vice president with AGDC. “Fritz did a heck of a job when he was called upon,” Cruz said succinctly at the meeting. AGDC vice chair Hugh Short, who led the board’s executive search, said Meyer has already met with key legislators. “We are entrusting (Meyer) with a significant task, but I think he has the ability to carry this project through,” Short said. Meyer has 15 years of experience in the LNG business and more than 35 years of broad experience in the energy industry, according to AGDC. Prior to founding LNG America, he led Houston-based Cheniere LNG as it developed the Sabine Pass LNG terminal in Louisiana, the country’s largest LNG receiving terminal. Meyer is joining AGDC at a critical time for the $45 billion-plus AK LNG Project. Much slower than expected progress on commercial negotiations between the project’s producers, BP, ConocoPhillips and ExxonMobil, as well the double whammy price collapse of the world oil and LNG markets have added to the already long list of challenges the any mega project faces. “Alaska is engaged in one of the largest energy projects in North America. I’m excited by the challenge and incredibly honored by the trust and confidence the board is placing in me. I understand how vital the gas pipeline and LNG project are to our Alaskan economy, and I’m committed to getting them built,” Meyer said in a formal statement. He was preparing for a family wedding and thus unable to attend the Thursday AGDC board meeting, corporation spokesman Miles Baker said. Elwood Brehmer can be reached at [email protected]

Senate votes to tap Fund earnings to fill deficit

Fourteen Alaska state senators were willing to put their names in the “Yea” column and vote to use the Permanent Fund’s profits to pay for government services and restructure how the annual dividend payment is calculated. The question now is how many in the House are willing do the same? Hours before the June 6 Senate floor vote, Sen. Peter Micciche, R-Soldotna, said just prior to moving the bill out of the Finance Committee and to a floor vote, that the decision is a politically painful but fiscally responsible one. “I certainly didn’t sign up, when I was elected four years ago, to say, ‘I want to be the guy — I want to be the guy to be the first one to have to use the earnings of the Permanent Fund,’ but the reality of it is that’s where we are and I think it’s the responsible thing to do,” Micciche said. “It’s a tough vote, but I know that’s why my district sent me here, to make those tough decisions and be well-informed in those decisions and make sure we’re not being wasteful in any one of those (state) departments. So I’m not excited about this bill going to the floor, but duty calls.” The floor vote to restructure the Fund made for odd bedfellows. Republican Sens. Mike Dunleavy, R-Wasilla, and Bill Stoltze, R-Eagle River, from two of the most conservative districts in the state, joined Anchorage Democrat Sens. Berta Gardner, Johnny Ellis and Bill Wielechowski in voting against Senate Bill 128. Wielechowski said in floor testimony that changing how the dividend is calculated, and setting the PFD amount at $1,000 per Alaskan for the next three years, “is a regressive tax. I don’t think there’s any doubt about it.” He touted that Alaska has the lowest income inequality of any state, thanks in large part to the PFD. “I made a promise to my constituents that I would not cut their Permanent Funds, their dividends,” Wielechowski said. Dunleavy said in the bill’s last Finance Committee hearing that he could not support using the Permanent Fund for government services until significantly more budget cuts were made. The earliest the House could take up the bill is the week of June 13, as legislators have been forced out of hotels in Juneau for the latter part of the week and weekend for the long-planned Celebration, put on by Sealaska Corp. An overhaul of the Permanent Fund status quo is the centerpiece to Gov. Bill Walker’s New Sustainable Alaska Plan along with cutting spending and increasing taxes to get the state out of its fiscal crisis by 2019. The actual size of the budget deficit changes daily with oil prices and who is talking, but it is still somewhere between $3.5 billion and $4 billion, even after the latest round of budget cuts. “I thank members of the Senate for taking this important vote to but Alaska on the pat for a sustainable future. We recognize the concern some have raised about the need for balance, which we have addressed through the remaining pieces of the New Sustainable Alaska Plan,” Walker said a statement from his office late June 6. “Restructuring the Permanent Fund is the cornerstone of this plan, and a significant portion of it, but make no mistake — the work to put Alaska on a sustainable path is far from over. I applaud the Senate for taking this bold step.” A week earlier the governor called a press conference and openly scolded legislators for not moving ahead sooner on his tax and Permanent Fund proposals to balance the budget. While SB 128 is technically “the governor’s bill” that the administration introduced at the start of the regular session, the mechanics of it have been changed to more reflect what was first proposed in April 2015 by outgoing Anchorage Republican Sen. Lesil McGuire. It uses a percent-of-market-value, or POMV, approach to calculate how much money the state can pull from the earnings account of the Fund each year. SB 128 sets a 5.25 percent POMV draw, meaning 5.25 percent of the Fund’s five-year average overall value will be used to pay for government and the dividend checks. Drawing from the earnings of the Permanent Fund as prescribed in SB 128 would roughly cut the projected annual deficits in half by allowing the state to apply $1.8 billion in Fund earnings directly towards deficit reduction. Another $700 million in earnings would pay this fall’s $1,000 dividend, as it would for the two following years. Dividends in the out years would come from 20 percent of the POMV draw, which amounts to 1.05 percent of the Fund value, and 20 percent of the state’s royalty revenue. Combined, they are projected to total about $1,000 for the foreseeable future. But given the PFD would then be based on market performance, oil production and oil price, long-term PFD amounts under SB 128 are still anyone’s guess. In a case of unfortunate timing, this and last year’s PFDs, based on the current calculation formula — strictly on the market performance of the Fund — were and are more than $2,000, some of the largest checks ever paid. Had the change been necessary in 2012 or 2013 when the financial collapse of 2008-09 shrunk the PFD to about $900, the $1,000 checks proposed in the bill would not be a PFD cut. On the floor, McGuire called the POMV approach a “tried and true method of money management,” noting that it is how the vast majority of endowment funds are managed worldwide. “This bill is the most important thing that I will do in my 16 years (in the Legislature) and I will dare to say the most important thing that anyone in this room will do in their political career,” she said. “It is the main step towards stabilizing Alaska’s future.” Sen. Anna MacKinnon, R-Eagle River, noted that without revamping state fiscal policy, ratings agencies have said they will be forced to further downgrade the state’s credit rating, which will impact the ability of local governments and the state to bond for needed projects, including a gasline. McGuire emphasized that the principal of the Fund, comprised primarily of invested state resource royalty income, is constitutionally protected, but the dividend is not. She, as Micciche did in the Finance hearing, and the Walker has for months, referred to the Permanent Fund as a “rainy day account to preserve revenue that came from nonrenewable commodities.” No one discussed dividend checks when the Fund was created, McGuire said. However, “We’re obligated to reflect on the laws that we pass and to say that in 2016 the world looks very different than it did in 1982,” when the dividend program was established, she said.

Oil tax credit bill passes by one vote

It’s in the governor’s hands now. After coming out of a House-Senate conference committee earlier in the day, House Bill 247 was quickly passed by the Legislature June 6 with little fanfare given the consternation the oil and gas tax credit legislation has caused since Gov. Bill Walker introduced it in January. The version of HB 247 sent to the governor’s desk is essentially the same version of the bill that passed the Senate a few weeks prior, at least as far as finances go. As a result, it passed the Senate easily. In the House, it was a different matter. Because the hours of debate, rhetoric and grandstanding that typically accompany controversial legislation were spent when the bill was on the House floor several weeks ago, it was simply time to vote. With Anchorage Republican Rep. Mike Hawker, a staunch supporter of the tax credits, back in Juneau after missing most of the session to receive cancer treatment in Anchorage, the milder HB 247 passed the House on a 21-19 vote. Because it only goes about half as far in cuts and revenue generation as his bill, it remains to be seen what Walker will do with it. The governor has a policy of generally not commenting on pending legislation. As the previous House and Senate versions did, this HB 247 limits future refundable tax credits for work in the Cook Inlet basin to the companies with a presence there already. However, those credits will also be short-lived, as the bill ramps down the percentage of capital expenses the state will reimburse in 2017 and wholly eliminates the Cook Inlet basin tax credit system in 2018. Increased activity in the Inlet in recent years — driven to some extent by the availability of the credits — has roughly doubled oil production and significantly grown the Southcentral natural gas supply. That activity has also cost the state between $260 million and $400 million in annual refundable credit payments since fiscal year 2014 for areas outside of the North Slope, according to the Legislature’s consultant firm Enalytica. With very little “Middle Earth” oil and gas activity in the areas between the Slope and the Inlet, companies working in Cook Inlet earned the vast majority of those credit totals. The Department of Revenue had projected the annual payment of Inlet-area credits to naturally decline over the next few years for several reasons, meaning the actual “bottom line” impact of HB 247 won’t fully reverse the high-spend years. Rather, it will accelerate Revenue’s prediction. Overall, the bill is expected to save the state about $160 million per year by the time it takes full effect in fiscal year 2020. That’s roughly half the dollar figure that the version of HB 247 that passed the House in mid-May would have saved through credit cuts and generated through tax tweaks, according to Tax Division reports on the bills. As for the Slope, all recent iterations of the bill close a loophole that allowed companies producing “new oil” eligible for the 20 percent Gross Value Reduction credit to use the GVR to enhance, or grow, a reported operating loss to the point that it would be greater than the actual operating loss. While a GVR-enhanced operating would occur mostly at times of very low prices and amount credit totals in the single-digit millions of dollars, there was largely consensus among legislators the state should not pay companies more than their actual incurred losses through the Net Operating Loss credit. It is how the Net Operating Loss, or NOL, credit is handled, or not, that is the biggest difference between the HB 247 that first passed the House with minority support and the one that squeaked by on a majority-led vote June 6. The HB 247 that is on its way to Walker retains the 35 percent refundable NOL credit for small North Slope producers. The majors are able to deduct losses at time of high expense or oil low prices from production tax liabilities in future years.  Rep. Paul Seaton, R-Homer, testified in a brief floor debate June 6 that not cutting the NOL — as the bill that previously passed the House did for all but the very smallest producers — will basically leave the state without production tax to collect if oil prices stay relatively low as forecasted. “The problem is that we’re anticipating oil prices varying between $40 and $60 (per barrel) for some time in the future, which is the worst possible situation where we will have in the less than $46 (per barrel range) — we will be generating hundreds of millions of dollars of loss carry forward credits, which are then applied in the subsequent years when the price goes up towards $60 and takes the tax below the floor to zero,” Seaton said. “And so that means that as we address other issues of fiscal stability we are totally hamstrung, because there will be no production tax in the anticipated oil price ranges.” The basic North Slope NOL credit was one of the few areas of the state’s oil and gas tax credit system the administration’s original bill did not touch. Despite basically being the Senate’s bill, the compromise to the compromise of HB 247 did adopt the House language to annually disclose the names of the companies receiving direct tax credit payments and the individual amounts they received. The Senate bill allowed the state to disclose the amount paid for each type of credit without disclosing specific credit holders. Current law only allows the Department of Revenue to disclose the aggregate amount of credits earned in each basin, without revealing the type of credits or to whom they were paid. While some legislators sided with industry and opposed any “confidentiality” change, several general supporters of the tax credits in the Legislature acknowledged the lack of disclosure to be a hindrance to fully understanding where the state is making sound or ill-advised investments.

After Alaska successes, FAA weather cam program expands

What started as a small program to help Alaska pilots that fly some of the most dangerous routes in the state is ready for the big time, and your smartphone. “We help reduce CFIT (controlled flight into terrain) accidents,” said Walter Combs, who is the Federal Aviation Administration’s Weather Camera Program manager. “We give pilots enough information that they look before they launch. They used to fly out to see if they could go and turn around and come back if they couldn’t. Now, they take a look and see if they can go and if they can’t they sit on the ground and wait until they can.” Despite being based in Anchorage, his title mentions nothing about Alaska. That’s because there is nothing regional about his program, other than it started quietly in Alaska nearly 10 years ago. Combs and his 10-person team design, install, maintain and repair nearly 900 cameras at 228 sites across Alaska. Those cameras are often in locations specifically chosen for their isolation, difficulty of access and virtually perpetual inclement weather. “We serve anybody flying,” Combs said simply. And the idea is simple enough, too. Give small aircraft pilots an eye to look beyond the mountain peaks visible from the runway and push back against the temptation to take unnecessary risks because one is already in the air. Combs said the high rate of avoidable flight accidents and deaths in the state meant something had to be done. “We got started because there were so many CFIT accidents,” he said. Combs noted one of Alaska’s most popular, and notorious, mountain passes, Merrill Pass, as a prime example of the need for the weather cameras. Named after Russel Merrill, the pilot who first traversed the route from Anchorage and over the Alaska Range to the Kuskokwim Valley in 1927, Merrill Pass is home to two of Combs’ camera sites. Anchorage’s Merrill Field is named after him as well. “If you fly through Merrill Pass in the summer you can just see this (plane) wreckage scattered all over,” Combs said. The program has worked. The FAA required hard data to justify funding the program when the first cameras were installed in 2007. At that time, Alaska had an average of 0.28 weather-related flight accidents per 100,000 flight hours. A third-party consultant developed an algorithm that set targets to reduce the frequency of weather-related crashes by about 10 percent per year in the early years of the program. By 2011, the actual number of weather-induced accidents had been cut by more than half, to 0.13 per 100,000 flight hours. In 2014, the rate was down to 0.04 per 100,000 hours, or an 86 percent reduction in crashes caused at least partially by weather, according to the FAA. But the cameras do more than improve safety; they also improve operational efficiency. As Combs said, pilots no longer have to be in the air to see an impenetrable cloudbank for themselves. They can check the trouble spots of their route from the terminal, or the hangar or their office — wherever the nearest computer screen happens to be. Combs said he has received testimonials from pilots who would regularly fly into Lynn Canal north of Juneau up to six or seven times per day only to be turned back before cameras were installed at two sites along the route. Again back in 2007, when the first 80 sites were installed, the FAA estimated Alaska pilots unnecessarily flew for more than 15,300 hours on flights that would ultimately be cut short by inclement weather. Unnecessary flight time logged was down to about 5,000 hours by 2014, based on FAA data. Combs contends the actual number is still less than that. “What (pilots) are not doing is taking chances in those passes, what we call pinch-points, or hazard areas where weather is known to sock in,” he said. User-friendly upgrades to the program’s website have encouraged more use, meaning the safety and efficiency metrics should keep getting better, although it will likely be hard continue the impressive year-over-year improvements. The website avcams.faa.gov averaged 27 million hits per year in the program’s first eight years. The reformatted website, with added information, quicker and easier navigation and always more cameras, pushed the number of views to nearly 200 million in 2015 alone. Combs said several small flight service operators have added the weather cameras to their “ops specs.” In other words, the pilots are now required to check the cameras along their route as part of their pre-flight routine. Alaska Air Carriers Association Director Jane Dale confirmed that and said Combs gets nothing but “high marks” from her members. “The carriers don’t do anything until they look at the cameras,” Dale said. It’s more than just one photo of the horizon, however. Most sites, except those with partially obstructed views, have four cameras to show incoming our outgoing weather in any direction. Weather conditions not viewable in a still photo, such as temperature, wind, barometric pressure and cloud ceiling are also provided. Additionally, camera shots taken in 10-minute intervals are stored for six hours, allowing pilots the opportunity to review how the weather is changing — is it getting better or worse? Combs said National Weather Service officials in Juneau are also taking advantage of his program to make their forecasts. After a recent tour of the NWS Alaska office he said, “The forecasters will have all the cameras on that are in their section that they’re doing the forecast on.” He has also taken requests from commercial fisherman in Southeast Alaska for cameras near their favorite fishing grounds, Combs said. To date, the FAA has invested about $25 million in the program over nearly a decade, according to Combs, a relatively small amount of money when one considers the locations of some of the equipment. One of the newest sites, per a Parks Service request, is situated on Kahiltna Glacier at the foot of Denali. When word gets around that Combs’ team is looking to establish a camera site somewhere in the state, locals often do their best to make his job as easy as possible, exemplifying the understood value of the program, he said. “Wherever we can get commercial power, we do. And that’s interesting because most people that we approach are willing to give us free power and free (Internet) communication if they have it,” Combs said. “So we’ve got a lot of sites out here where I’m not paying for any power, I’m not paying for any communication.” In those places without power, the program team has developed solar and wind power modules to energize the cameras that must operate with only one maintenance trip per year. FAA Alaska Region Administrator Kerry Long said much of the Weather Camera Program’s success is due to the direct connections Combs has made with the industry. He’s managed to cut through the bureaucracy the FAA is known for. “There aren’t six levels of getting things done. It’s Walter that makes these decisions,” Long said. “There’s no largesse to it. If you can convince Walter that there’s a need and you’re a user, assuming we can afford it, he’ll do it.” Now, the program is on the verge of expanding to the Lower 48, Combs said, at the request of the National Transportation Safety Board, which has requests for future sites in many mountainous regions of the West. That expansion will largely depend on funding. But in the more immediate future, more website improvements and Android and IOS mobile apps are currently in the works and should be ready for the public early this fall, Combs said. The new website and the mobile apps will allow pilots, or the countless other camera users, for that matter, to save and recall their favorite routes. Efforts are also being made to add more local flight information, such as NOTAMs (notices to airmen), according to Combs. He has 40 pilots actively testing the apps this summer. “They’re using the app every day. In fact, we’re using Survey Monkey for their feedback,” Combs said. “We’re on track. We’re giving pilots what they’re after. It’s really cool. It’s really neat to do.” Elwood Brehmer can be reached at [email protected]


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