Elwood Brehmer

Producers again reject Prudhoe demands

BP Exploration Alaska can’t market its Prudhoe Bay natural gas, and it hasn’t, company officials wrote in the revised plan of development for the North Slope field. In a cover letter to state Division of Oil and Gas Director Corri Feige about the latest plan document submitted Sept. 1, BP Alaska Reservoir Manager Scott Digert wrote that BP, the state and the other Prudhoe Bay working interest owners — notably ConocoPhillips and ExxonMobil — have a confidentiality agreement in place for the Alaska LNG Project that all are currently participating in. Additionally, BP and the state have a separate bilateral confidentiality agreement that prohibits the company from sharing any information it has about efforts to market Prudhoe Bay natural gas as the division has requested. Those confidentiality agreements and antitrust laws prohibit BP from “requesting, possessing or discussing the Prudhoe Bay Unit working interest owners’ proprietary marketing information,” Digert wrote. The “Major Gas Sales” section of the revised 2016 Prudhoe Bay Plan of Development begins with the two paragraphs that comprised the entire section in the original document submitted to the division March 31, which first state that selling gas from the North Slope field remains contingent upon having infrastructure to sell the gas into. Also, the Prudhoe owner companies will keep evaluating plans to “further optimize gas and oil recovery, and to address facilities, equipment, wells and operational changes to position for major gas sales.” BP has signed confidentiality agreements for technical information related to gas production from the unit and made that available to third parties to further “potential gas-related projects,” according to the plan of development. The third and last paragraph — new in the revised document — describes the company’s limitations. “BP Exploration (Alaska) Inc., as Prudhoe Bay Unit operator, is not involved in marketing of hydrocarbons produced from the unit. Such action is outside the authorized scope of operations conducted by the Prudhoe Bay Unit operator and is prohibited under the Prudhoe Bay Unit Agreement executed by the State of Alaska and the Prudhoe Bay Unit working interest owners,” it states. “Each Prudhoe Bay Unit owner takes and markets hydrocarbons allocated to that owner and, due to competition and anti-trust considerations, the unit operator cannot and does not solicit, accept, or receive proprietary marketing information from any Prudhoe Bay Unit owner.” BP, as the unit operator, manages Prudhoe operations for the working interest owner companies with a stake in the field. Its first 2016 Prudhoe development plan document submitted March 31 was deemed incomplete because it did not contain detailed marketing information about the company’s efforts to sell gas from the field. Prudhoe holds roughly three-quarters of the gas available on the Slope to sell through the prospective $45 billion Alaska LNG Project. BP spokeswoman Dawn Patience wrote in a statement similar to previous statements the company has released on the issue that the Prudhoe working interest owners believe the revised unit plan of development, or POD, is complete and should be approved. “The level of information provided is consistent with the previous PODs that DNR has approved each year since 2000. This POD satisfies all of the Prudhoe Bay Unit Agreement’s and POD regulations’ requirements,” Patience wrote. In January, now retired DNR Commissioner Mark Myers sent a letter to all unit operators in the state notifying them the new information would be requested in subsequent unit development plans. The plans have historically been mostly technical documents to inform the state about drilling plans, facility operations, anticipated production and the like. When the Division of Oil and Gas ruled the first Prudhoe plan incomplete, it set off a back and forth of correspondence between the division and the company, with both sides reiterating their stance. ConocoPhillips supported BP in a May 4 letter to the division. The June 30 deadline for an approved Prudhoe plan eventually came and went and the division extended the 2015 plan through Nov. 1 and gave BP until Sept. 1 to submit a revised version. Division of Oil and Gas spokeswoman Diane Hunt said the division is using the 10 days it has to review the Prudhoe plan and can’t comment on it at this time.  ExxonMobil Production Co. Asset Manager Gilbert Wong also sent a letter to Oil and Gas Director Feige stating the company is in line with the other producers in believing the March 31 plan satisfies state regulatory requirements. “Any discussions regarding marketing and sales of production must occur directly between individual sellers and potential buyers under strict confidentiality consistent with applicable legal considerations and agreements already in place. In this regard, both the Prudhoe Bay Unit Agreement as well as confidentiality agreements entered into by the state jointly or individually with (the working interest owners), prohibit sharing or discussing the information currently requested by the division,” Wong wrote. Gov. Bill Walker indicated in a Sept. 6 interview prior to release of the latest documents that he had not seen them, but noted the state is working “marketing concepts” with the producer companies under a new, state-led structure for the Alaska LNG Project. Walker said the goal is to reach an agreement on the Prudhoe plan. “I don’t think anybody’s trying to take it off the rails in any way,” the governor said Sept. 6. In a July interview with the Journal, Walker said that because the state is a partner in the Alaska LNG Project, and is dependent upon the companies to produce its share of the North Slope gas, it needs to know what they are doing in preparation to sell their gas so the state can effectively market its share. At the time he said he was in discussions with BP’s top Alaska officials to find a way to share what the state wants while addressing the companies’ concerns. While talking with the Journal Sept. 6, Walker said that “since that discussion began the world has changed a little bit on the gasline, in my opinion, in a good way. I think that, in some respects, helps.” BP threw its support fully behind the state-led Alaska LNG Project that has been championed by Walker’s administration during an Aug. 25 joint House and Senate Resources Committee hearing on the project. Elwood Brehmer can be reached at [email protected]  

State floats idea for vetoed tax credits as investments

The Walker administration is looking for ways to mitigate the impact on industry of vetoes to $630 million of oil and gas tax credit payments over the last two years and is suggesting that the Permanent Fund Corp. might be able to help in that effort. Former Attorney General Craig Richards presented potential tax credit investment opportunities to Fund leadership during a Board of Trustees planning session Sept. 2 in Anchorage. The concept relies on the Alaska Permanent Fund Corp. — or any other investment fund for that matter — purchasing the right to the eventual credit payment at a discount to provide stop-gap cash flow for the companies that earned the credits and any banks that loaned to those companies until the credits are paid. Richards, who now works as a contract attorney in Gov. Bill Walker’s office after abruptly resigning from the attorney general post in late June for personal reasons, said officials in the administration have been brainstorming ways to help operators and their financiers deal with the delayed credit payments, which led to the thought that sharing the ideas with the managers of the $54 billion Permanent Fund could be helpful for everyone. “(The state) wants to make the opportunity known that these credits are out there and that they have value, what the credit risk looks like — and it really wants to because the State of Alaska owes this money regardless of when it gets paid, so it wants the financial markets surrounding these credits to be active and as liquid as possible for all types of investors,” Richards said. Last summer Walker used his line-item budget veto authority to nix $200 million from a $700 million appropriation to capitalize the state’s oil and gas tax credit fund for fiscal year 2016. The action, he has said since, was meant to raise awareness to the fact that the state could no longer afford to make the large annual outlays with oil prices down to a point where corresponding production tax revenue would reasonably offset the credit payments. His administration submitted legislation early last year to drastically scale back the credit program while paying off all current and anticipated credit obligations with a nearly $1 billion lump sum payment to the credit fund. When a milder version of the governor’s credit reform package finally passed after contentious debate it did not include the credit payoff. In past years the state had appropriated enough money to pay the credits off each year. However, the tax law that created the tax credits also established a formula tied to production tax revenue that requires the state to pay only a portion of its annual obligation. With lower oil prices comes less production tax meaning the required credit payment also drops in a given year even though the full obligation will eventually have to be paid. Before signing the fiscal 2017 budget in June Walker again vetoed $430 of the $460 million; the remaining $30 million fulfilled the formula minimum. The credit veto was part of $1.3 billion in budget vetoes that included the first-ever partial Permanent Fund dividend appropriation veto as well. Walker said at the time he couldn’t authorize the credit payment out of state savings because the Legislature had not passed a plan to resolve the state’s $3 billion-plus annual deficit. Richards emphasized the recognition of the fiduciary responsibility Fund managers have and that any investments they make “must stand on their own without consideration for state policy,” he said. The roughly $700 million of outstanding credits breaks down into about $100 million of older credits earned for exploration and other work, with the remaining majority being mostly refundable net operating loss credits accrued recently by small companies that have lost money since oil prices dropped, Richards said. Banks that may have loaned money to operators that used the credit certificates as collateral anticipating prompt payment could now be looking for someone to buy the credits at a discount to at least partially pay off those loans in search of a less-than-perfect solution, according to Richards. He said some private equity funds have also been “sniffing around this space” to perhaps fill the funding gap left by the state. Also, while the refundable credits can be sold to companies with a tax liability, low oil prices have for the most part dissipated producer profits and corresponding taxes to the point where that market is pretty much dead. Richards said it is rumored that credits sold to offset taxes are garnering only 20 to 30 percent of face value. He laid out an example in which a bank made a loan to an operator last year for 90 percent of a credit payment anticipated this year. The bank then likely holds the payment assignment, which can be transferred. Because the state did not fund the credit, the bank is now looking for its money. This is where the third party investor could come in. If an investor would make a discounted cash payment to the bank, the bank could then close out its position and send any remaining cash back to the operator. Then when the state pays up, the credit cash would be paid from the bank holding the assignment to the investor, according to Richards. “You’re buying a state bond, effectively, but you don’t know when you’re going to get paid. If you have some level of confidence that (the State of Alaska) will get our fiscal house in order next year — there’s some chance it will take two years; some chance it could take three, maybe,” he said. “That’s really the risk of the credit play.” It all comes down to timing because delayed or not, the credits are paid without interest based on when they were applied for. There is virtually no bank risk to the investor because the banks that have lent in this space are “big, bulge-bracket banks” that aren’t going anywhere, Richards commented. He added that there is currently discussion in the governor’s office regarding what information can be provided to give financial markets more clarity around when the credits will be paid. Alaska Permanent Fund Corp. Executive Director Angela Rodell, in a brief interview following the presentation, called the idea “interesting and intriguing.” She dismissed the potential for a conflict if the corporation were to make such an investment given members of Walker’s cabinet, state Revenue and Administration commissioners Randy Hoffbeck and Sheldon Fisher, also serve as Permanent Fund trustees. She said trustees, regardless of their day jobs are always “wearing their fiduciary hats” when acting as Fund directors and do not share any outside information. Alaska Oil and Gas Association CEO Kara Moriarty watched Richards’ presentation and said needs to be vetted by the industry and its financial partners, but the prospect of the Fund investing in the credits “creates some interesting relationship challenges.” “It all comes down to when the money is going to be paid, so what does it matter? Some of these expenditures were made (by operators) at least two years ago,” she said. Still, Moriarty expressed confidence the administration’s wishes won’t impact how Alaska’s largest asset is managed. Fund leadership is “solely focused on what’s best for the Permanent Fund,” she said. Elwood Brehmer can be reached at [email protected]  

Gold prices rising as Donlin mine keeps plugging on EIS

With gold prices on the rebound, it’s full steam ahead for the Donlin Gold mine in Western Alaska. Donlin Gold spokesman Kurt Parkan said in an interview that “things are moving along pretty steadily” as the company continues through the federal environmental impact statement, or EIS, process. A variety of other state and federal permits are being sought in concert with the multi-year EIS process, according to Parkan. As far as the EIS goes, the ball is the U.S. Army Corps of Engineers’ court for now. The Corps is the lead permitting agency for the project. “We’re still waiting to hear back from the Corps of Engineers on follow-up that might be necessary after they had a chance to review the (public) comments that they’ve received,” Parkan said. The Corps, which received about 540 written comments during an extended public comment period, is expected to come back to Donlin with any unresolved issues that arose from public comments or that it discovered by the end of September, he added. Release last November of the draft EIS marked, to that point, the culmination of 20 years of work on Donlin. Early resource definition of the gold prospect began in 1995. Donlin Gold is a 50-50 joint venture of Canadian mining companies Barrick Gold Corp. and NovaGold Resources. A $6.7 billion endeavor with a footprint from Cook Inlet to the Aleutian Islands, the Donlin Gold mine is the definition of a megaproject. At the heart of the project is a prospective conventional open-pit gold mine 1.5 miles across and up to 1,200 feet deep located about 10 miles north of the village of Crooked Creek in the Upper Kuskokwim River drainage. At that size, Donlin is projected to be the largest open-pit gold mine on Earth. As initially planned, Donlin Gold would produce about 1.1 million ounces of gold per year over a 27-year mine life for a total of about 33 million ounces of the precious metal. The mine site, on lands owned by The Kuskokwim Corp. and Calista Corp., the area village and regional Native corporations, respectively, would also include a fully lined, 2,300-acre tailings facility to store the processed ore. Support infrastructure would include a 315-mile, 14-inch diameter natural gas pipeline originating on the west side of Cook Inlet need to supply fuel to the 227-megawatt capacity power plant at the mine site. The pipeline has also been viewed as a first, indirect step to getting lower cost natural gas to numerous villages in Western Alaska that currently rely on fuel oil their primary heat and electricity sources. A 30-mile road would connect the mine to a new barge port on the Kuskokwim. Further down the Kuskokwim, port cargo facilities would be expanded in Bethel, and new diesel storage tanks would be needed Dutch Harbor to supply fuel for equipment at the mine. The EIS includes an alternative that calls for LNG-powered equipment, which would reduce the risk of a barged fuel spill on the Kuskokwim, but also require construction of an on-site natural gas liquefaction plant. Once Donlin has heard back from the Corps, Parkan said it would likely take the company until late 2017 to release the final EIS, pushing back the overall timeline slightly. The Corps of Engineers’ project EIS website estimates a final EIS early next year. “It always takes a little longer than you hope it would,” Parkan said. The public comments on the project were mostly in line with what was expected, he said. However, a stance opposing the project emerged from the Yukon-Kuskokwim Health Corp. because jobs at the mine could provide a means for people in the region to move elsewhere while making a long range commute to the mine on a rotating work schedule. Parkan said simply that Donlin Gold feels the up to 1,400 jobs the mine would support would ultimately be a significant benefit to the Yukon-Kuskokwim region that is one of the poorest in the country. “People are already moving out of the region because they don’t have jobs,” he said. “If you bring jobs into the region you might stop that flow of outmigration. People could stay home and take care of their families; they could afford to hunt and fish, which is part of the problem that exists now.” Donlin estimates up to 3,000 workers will be needed during construction if the mine is built. The company has often touted its record of about 90 percent local hire during the exploration and study phases of the project. The concerns over outmigration were one of several points raised by the Yukon-Kuskokwim Health Corp. in opposition to Donlin, which included potential damage to the salmon and wildlife resources people in the region rely on for subsistence harvest. When the draft EIS was released last year, Donlin General Manager Stan Foo said the project would not be built at gold prices at the time of less than $1,100 per ounce; and while the long-term viability of the project is not completely at the mercy of metal prices any one day, gold is currently trading at about $1,350 per ounce. Parkan said there is no definitive price at which the mine is a go. Donlin’s owners are committed to getting through permitting and then will evaluate how gold prices could impact the project, he said. “The more above $1,200 (per ounce of gold) the happier we are,” Parkan added. Elwood Brehmer can be reached at [email protected]  

Project updates and LNG outlook on tap at 12th O&G Congress

The members of this congress actually get stuff done. The 12th Alaska Oil and Gas Congress starts Sept. 20 at the Anchorage Marriott hotel. Day one of the conference features a lineup of prospect leaders, starting with Paul Basinki, founder of Burgundy Xploration. Great Bear Petroleum CEO Mike Mason will give the latest on his company’s work on the second day of the two-day conference. Burgundy and Anchorage-based Great Bear are small independents exploring oil plays south of the established North Slope fields. Oil and Gas Congress attendees will also here the latest about a $30 billion plan to build a railroad from Northern Alberta’s oil fields to Interior Alaska from G7G Railway Corp. head Matt Vickers. The rail link could be a way to get the province’s immense heavy oil resources to market and increase throughput in at least the lower half of the trans-Alaska Pipeline System by tapping into TAPS and shipping the thick crude out through the Valdez oil terminal. Resources Energy Inc. Vice President and General Manager Mary Ann Pease will update the progress of REI’s plan to export Cook Inlet natural gas via a new 1 million tons per year LNG facility the Japanese-Alaska consortium hopes to construct at Port MacKenzie. Cook Inlet producers have said REI’s project could act as an anchor tenant gas customer to spur new exploration in the ever-tenuous and constrained market. Additionally in Cook Inlet, Benjamin Johnson, president of BlueCrest Energy will offer his insight into the future of the basin that provides natural gas for Alaska’s largest economic and population centers and how his company plays into that. BlueCrest began oil production from an onshore well near Anchor Point on the Kenai Peninsula earlier this year. While currently producing less than 1,000 barrels per day from a single well, the company has announced plans to drill 10 more wells that could produce up to 17,000 barrels per day. That would roughly double the current daily oil production from the entire Cook Inlet basin. On the policy side, Alaska Tax Division Director Ken Alper will provide Gov. Bill Walker perspective on the legislative changes made earlier this year to the state’s oil and gas tax credit system, what the next steps are and the likely impact of changing the incentive program on future state revenues and development of the resources. Walker submitted legislation to further scale back the credit program during a July special legislative session in which the issue went unresolved. Industry regulators from the Alaska Oil and Gas Conservation Commission, the Bureau of Land Management, the Environmental Protection Agency and the Alberta Energy Regulator agency will also present. Attendees are advised not to throw rotten food at the presenting regulators, despite potential urges to do so. Finally, there will be two presentations on LNG, one on each day. Black and Veatch Management Consulting LLC Director Deepa Poduval will present on “Effects of Global Natural Gas Demand Pricing and Future LNG Development” on Sept. 20 while Kenai Peninsula Borough Oil and Gas Advisor Larry Persily will help close the conference Sept. 21 with his thoughts on “Years of Political and Public Frustration over North Slope Gas Commercialization.” Persily worked as the federal coordinator for Alaska natural gas pipeline projects prior to his time at the Kenai Borough. Elwood Brehmer can be reached at [email protected]  

BP has no Prudhoe gas marketing info to share, company says

BP Exploration Alaska hasn’t, and can’t, market its Prudhoe Bay natural gas, company officials wrote in the revised plan of development for the North Slope field. In a cover letter to state Division of Oil and Gas Director Corri Feige about the latest plan document submitted Sept. 1, BP Alaska Reservoir Manager Scott Digert wrote that BP, the state and the other Prudhoe Bay working interest owners — notably ConocoPhillips and ExxonMobil — have a confidentiality agreement in place for the Alaska LNG Project that all are currently participating in. Additionally, BP and the state have a separate bilateral confidentiality agreement that prohibits the company from sharing any information it has about efforts to market Prudhoe Bay natural gas as the division has requested. Those confidentiality agreements and antitrust laws prohibit BP from “requesting, possessing or discussing the Prudhoe Bay Unit working interest owners’ proprietary marketing information,” Digert wrote. The “Major Gas Sales” section of the revised 2016 Prudhoe Bay Plan of Development begins with the two paragraphs that comprised the entire section in the original document submitted to the division March 31, which first state that selling gas from the North Slope field remains contingent upon having infrastructure to sell the gas into. Also, the Prudhoe owner companies will keep evaluating plans to “further optimize gas and oil recovery, and to address facilities, equipment, wells and operational changes to position for major gas sales.” BP has signed confidentiality agreements for technical information related to gas production from the unit and made that available to third parties to further “potential gas-related projects,” according to the plan of development. The third and last paragraph — new in the revised document — describes the company’s limitations. “BP Exploration (Alaska) Inc., as Prudhoe Bay Unit operator, is not involved in marketing of hydrocarbons produced from the unit. Such action is outside the authorized scope of operations conducted by the Prudhoe Bay Unit operator and is prohibited under the Prudhoe Bay Unit Agreement executed by the State of Alaska and the Prudhoe Bay Unit working interest owners,” it states. “Each Prudhoe Bay Unit owner takes and markets hydrocarbons allocated to that owner and, due to competition and anti-trust considerations, the unit operator cannot and does not solicit, accept, or receive proprietary marketing information from any Prudhoe Bay Unit owner.” BP, as the unit operator, manages Prudhoe operations for the working interest owner companies with a stake in the field. Its first 2016 Prudhoe development plan document submitted March 31 was deemed incomplete because it did not contain detailed marketing information about the company’s efforts to sell gas from the field. Prudhoe holds roughly three-quarters of the gas available on the Slope to sell through the prospective $45 billion Alaska LNG Project. In January, now retired DNR Commissioner Mark Myers sent a letter to all unit operators in the state notifying them the new information would be requested in subsequent unit development plans. The plans have historically been mostly technical documents to inform the state about drilling plans, facility operations, anticipated production and the like. When the Division of Oil and Gas ruled the first Prudhoe plan incomplete, it set off a back and forth of correspondence between the division and the company, with both sides reiterating their stance. ConocoPhillips supported BP in a May 4 letter to the division. The June 30 deadline for an approved Prudhoe plan eventually came and went and the division extended the 2015 plan through Nov. 1 and gave BP until Sept. 1 to submit a revised version. ExxonMobil Production Co. Asset Manager Gilbert Wong also sent a letter to Oil and Gas Director Feige stating the company is in line with the other producers in believing the March 31 plan satisfies state regulatory requirements. “Any discussions regarding marketing and sales of production must occur directly between individual sellers and potential buyers under strict confidentiality consistent with applicable legal considerations and agreements already in place. In this regard, both the Prudhoe Bay Unit Agreement as well as confidentiality agreements entered into by the state jointly or individually with (the working interest owners), prohibit sharing or discussing the information currently requested by the division,” Wong wrote. Gov. Bill Walker indicated in a Tuesday interview prior to release of the latest documents that he had not seen them, but noted the state is working “marketing concepts” with the producer companies under a new, state-led structure for the Alaska LNG Project. Walker said the goal is to reach an agreement on the Prudhoe plan. “I don’t think anybody’s trying to take it off the rails in any way,” the governor said Tuesday. In a July interview with the Journal, Walker said that because the state is a partner in the Alaska LNG Project, and is dependent upon the companies to produce its share of the North Slope gas, it needs to know what they are doing in preparation to sell their gas so the state can effectively market its share. At the time he said he was in discussions with BP’s top Alaska officials to find a way to share what the state wants while addressing the companies’ concerns. While talking with the Journal Tuesday morning, Walker said that “since that discussion began the world has changed a little bit on the gasline, in my opinion, in a good way. I think that, in some respects, helps.” BP threw its support fully behind the state-led Alaska LNG Project that has been championed by Walker’s administration during an Aug. 25 joint House and Senate Resources Committee hearing on the project. Check back for updates to this story. Elwood Brehmer can be reached at [email protected]

Walker: state will sue over game management rule

The State of Alaska and the federal government are headed back to court — again — to resolve another instance of “federal overreach,” Gov. Bill Walker said. Walker said in a Tuesday morning interview with the Journal that the state is planning a lawsuit to stop implementation of a U.S. Fish and Wildlife Service rule that shifts fish and game management authority in federal refuges from the state to the feds. When the suit will be filed is unclear, but state officials are consulting with other Alaska stakeholders in the rule to file suit as a group, according to the governor. “We are working on an aggressive response," Walker said, to the rule that was finalized Aug. 5 and coincidentally took effect Tuesday. He added that challenging the rule, which is specific to federal refuges in Alaska, is something he would likely discuss with the governors of other western states because it is a states’ rights issue. Specifically, the rule transfers regulation of non-subsistence, or sport, harvest of fish and game to the Interior Department agency. Fish and Wildlife has long managed for subsistence harvests on refuges in Alaska. “(Fish and Wildlife) has ultimate management authority over resources in the federal National Wildlife Refuge System pursuant to a variety of statutes,” the Aug. 5 Federal Register final rule notice states. “However, effective stewardship of fish and wildlife resources, various statutory provision, and Department of the Interior policy require close cooperation with the state. Indeed, as a general rule state regulations governing hunting and fishing on refuges in Alaska are adopted with exceptions tailored to the purpose of each refuge and the relevant federal authority. The members of Alaska’s congressional delegation unequivocally condemned the rule as superseding states’ rights. Rep. Don Young said at the time it directly violates the 1980 Alaska National Interest Land Claims Act, or ANILCA, a federal law that established guidelines for, among other things, state management of fish and game on federal lands in Alaska. A release from Sen. Lisa Murkowski’s office stated the rule “will likely serve as a model for similar takeovers in the Lower 48.” The passage of ANILCA also added 54 million acres to the federal refuge system in Alaska by expanding existing refuges or creating new ones entirely. In total, there are about 77 million acres of federal refuge lands in Alaska. Check back for updates to this story. Elwood Brehmer can be reached at [email protected]

Fund return revised down to 1.02%

The Alaska Permanent Fund Corp. has revised its 2016 investment return figure to 1.02 percent, down slightly from an estimate made a couple weeks ago. The Permanent Fund finished the 2016 fiscal year, which ended June 30, with a total value of $52.8 billion, according to a Thursday release from the corporation. That includes $44.2 billion in the Fund principal and $8.6 billion in the Earnings Reserve Account, which holds both realized and unrealized investment gains. APFC Executive Director Angela Rodell said during an Aug. 18 meeting of the state policy study group Commonwealth North that preliminary figures indicated the Fund earned 1.35 percent in 2016. Rodell added at the time that she believed “if anything it will go up, not down.” The return difference equates to approximately $200 million on a portfolio of nearly $53 billion of investments. Thursday’s release states that the 2016 returns reflected a volatile market year. The value of the Fund dropped by $1 billion in the first half of the fiscal year and gradually recovered over the second six months, according to the APFC. “Diversification proved its value in 2016,” Rodell said in a formal statement.” Despite losses across nearly all equity markets, the gains in the fixed income, real estate and private market investments led to overall growth for the Permanent Fund.” The Fund’s final audited returns for last fiscal year will be presented to the APFC Board of Trustees at is annual meeting Sept. 27-28 in Juneau.   Elwood Brehmer can be reached at [email protected]

Attorney General explains Alaska joining other states against Exxon

(Editor's note: This story has been updated from its original version to include a brief response from state Rep. Gabrielle Ledoux.) Alaska Attorney General Jahna Lindemuth, in a letter to legislators, defended her decision to support other states in an evolving federal court case against ExxonMobil Corp. Lindemuth wrote to House Speaker Rep. Mike Chenault and House Judiciary chair Rep. Gabrielle LeDoux Aug. 25 that the State of Alaska joined 17 other states in an amicus brief against ExxonMobil to protect states’ authority, not to go after the oil company for any other reason. The brief filed in North Texas U.S. District Court Aug. 17 asks Judge Ed Kinkeade to dismiss ExxonMobil’s suit against Massachusetts Attorney General Maura Healey because, according to the attorneys general, the issue should be kept in a state court. Lindemuth emphasized in her letter that Alaska is “not joining, taking a position or spending state resources on the merits of” Healey’s probe.  “Our decision to join the amicus brief does not and should not in any way reflect support for the merits of the attorneys general’s underlying investigation. I believe ExxonMobil and any other company involved in a consumer protection investigation deserves its day in court,” she wrote. “The question of interest underlying our decision to join the brief is where and how challenges to this type of investigation — which involves an area that has historically been within the states’ purview — should be brought.” A day prior to Lindemuth’s letter Chenault and LeDoux sharply criticized the state’s support of Healey in a House Majority caucus release. “It seems that Alaska has joined up with other liberal states such as New York and California to go after oil companies,” Chenault said in a formal statement. “Alaska’s Department of Law has even stated (that) ‘none of these issues directly involve the state,’ so why are we getting involved? The Walker administration was very critical of the Legislature’s separation of powers (Medicaid expansion) lawsuit, but they have no problem being a part of this one; it’s hypocrisy at its best.” LeDoux said the state’s participation portrays an image that the State of Alaska is at odds with the companies that produce the state’s primary revenue source, oil. ExxonMobil is also currently leading the Alaska LNG Project, a $45 billion-plus joint effort with the state, BP and ConocoPhillips to export North Slope natural gas. “In this time of tightening budgets it is inconceivable to me that our state is squandering these limited resources to join other states’ attorneys general who are basically declaring war against responsible energy production,” LeDoux said. Leading to the suit in federal court was an investigation spurred by Healey’s subpoena of ExxonMobil for documents dating back decades pertaining to the company’s research and knowledge of how its business could potentially impact climate change. ExxonMobil subsequently filed its suit June 15, contending Healey’s investigation violates state and federal laws including the company’s constitutional rights under the first, fourth and 14th amendments. Healey was among a collection of 15 top state attorneys and those from the U.S. Virgin Islands and the District of Columbia who in late March formed a coalition dubbed “AGs United for Clean Power.” The group has also been championed by former Vice President Al Gore. The company filed its suit in North Texas U.S. District Court because ExxonMobil is headquartered in the state where most of its activities relating to the case occurred and the records sought by Healey are stored there, according to the complaint. Lindemuth added in her letter that Alaska “has previously been the victim of this type of forum shopping” for a potentially favorable court. Rather than challenging the state on state law in state court, Alaska has had to spend resources to defend its actions in other jurisdictions on cases that were ultimately dismissed, she wrote. “Consumer protection is an area regulated largely by the state, and I believe it is important that consumer protection actions remain a state — not a federal — issue. If bad precedent is set in a case like ExxonMobil v. Healey, it could adversely impact state investigations seeking to root out bad actors that harm Alaskans and Alaskan businesses,” Lindemuth wrote in her letter. After meeting with the attorney general on the matter, Ledoux said she stands by her statement in the House Majority release. Law spokeswoman Cori Mills said the department, out of respect for other states, reviews all requests from them to join cases and then makes a decision to support the stance or not. The amount of time and money expended by the state is about the same whether or not the attorney general signs on to a brief, according to Mills. “Basically, all we’re doing is saying, ‘You can use our signature — the attorney general’s signature — to say we support the principles in this brief,” she said.   Elwood Brehmer can be reached at [email protected]

Lack of training led to election snafus

Problems with voting procedures in a couple rural areas during Alaska’s Aug. 16 primary election likely stem from a lack of training for election workers, Division of Elections Director Josie Bahnke said during a legislative hearing on the issue. Retiring Chugiak Republican Sen. Bill Stoltze held a State Affairs Committee hearing Aug. 29 in which a group of primarily Republican legislators questioned Bahnke about vote totals that seemingly don’t add up in primaries that could go a long way in shaping House control for the coming years. Bahnke said the division contracted with the Juneau public broadcasting station KTOO to use its equipment to provide videoconference training for some election workers in an effort to save money and abide by travel restrictions imposed by Gov. Bill Walker while the state fights through multi-billion-dollar budget deficits. The six sessions of videoconference training saved the state about $225,000, she said. As of late Aug. 26, which is the most recent election result available from the division, state House hopeful Democrat Dean Westlake led District 40 incumbent Rep. Ben Nageak, D-Barrow, by 21 votes, or a 1.3 percent margin. A total of 1,617 votes were cast in the primary election for the massive district that covers the North Slope and much of Northwest Alaska. Voters in the Kobuk River village of Shungnak were reportedly given two ballot cards, one each for the Republican and Democratic primaries, but they should have gotten only one. The Division of Elections reported 50 voters with 100 cards cast. Westlake, who is from the Kobuk area, won the Shungnak precinct 48-2. Bahnke said the division was made aware that Shungnak voters were given both ballots the day after the election when the precinct chair reported results to the Nome office. Alaska has open primary elections that allow voters registered with either party to vote in the primary of their choosing. Voting in both party primaries is prohibited. There was no Republican primary candidate for the House District 40 seat. Lt. Governor Byron Mallott, who oversees elections in the state, appointed Bahnke to her post last October. Prior to 2016, training was typically conducted in regional hub communities prior to each election. State law requires election workers to receive training before each election. This year, there was no in-person training in the District 40 communities of Barrow and Kotzebue, according to Bahnke. She said it has become obvious some of the nearly 1,600 election workers the state employs did not participate in this year’s round of election prep and the division needs to refocus its efforts on educating workers in the northern district prior to the general election. “While we try in earnest to ensure that our election workers are prepared, sometimes they don’t attend (training) and there’s really no ramifications if they don’t attend,” Bahnke acknowledged. During the Aug. 29 hearing she said the District 40 results would probably be certified later that day. The results need to be certified by Sept. 2 to meet the statutory timeline. Bahnke wrote in an Aug. 30 afternoon email to the Journal that the results hadn’t yet been certified because the division was still waiting to get election materials, including ballots, memory cards and registers from four precincts in the district. “Due to the close race in House District 40 and (the) potential for a recount request, the State Review Board is working to certify those results as soon as election materials arrive,” she wrote. A losing candidate or a group of 10 voters in the district can request a recount within five days of the election review. The state picks up the tab for the recount if the margin is 20 vote or less or less than 0.5 percent of all votes cast. If a recount is requested and the margin is greater than 20 votes, the request must include a $750 deposit for a House district recount. Nageak and Westlake could not be reached for comment in time for this story. In the Western Alaska House District 38 primary, 215 registered voters in the Newtok precinct cast 220 ballot cards, according to the unofficial election results. “That’s some spirited patriotism,” State Affairs chair Stoltze commented. Democrat candidate for House District 38 Zach Fansler beat out incumbent Democrat Rep. Bob Herron by nearly a 15 percent margin. Despite both being Democrats, Nageak and Herron caucus with the Republican-led House Majority, a common practice among rural Democrats to gain committee appointments and leverage on budget items. Bahnke said “data entry mistakes” that appear to have led to the Newtok irregularity and the Chefornak precinct reporting 105 percent voter turnout are being corrected by the review board. The review board consists of 10 Juneau residents, two from each party and six undeclared voters, according to Bahnke. “If there were violations of law by election workers I don’t think they were intentional, but I think they were clearly from a lack of training and communication,” Stoltze said. “But nonetheless, it appears mistakes were made.” Legislative Legal Services attorney Alpheus Bullard testified to the committee that state courts —if a contested election gets that far — try “to honor voter intent, first and foremost.” However, the District 40 situation seems to be a rare one. “This is a novel situation in Alaska and I haven’t found another example of voters being supplied with two primary ballots in a very close election so I don’t know how a court would come down in this instance,” Bullard said. Bahnke added the division could do a better job educating voters about the two-ballot system in primaries, is going to reconvene its regional supervisors before the general election for a post-primary briefing and is considering holding training at the October Alaska Federation of Natives convention in Fairbanks. Outgoing Anchorage Republican Sen. Lesil McGuire commended Bahnke for taking questions from the committee while the division is facing challenges but added if the District 40 results are certified as they stand the impact on voter confidence would be “devastating and probably not recoverable for generations.” For her part, Bahnke said, “I’m committed to getting this right.”  

Walker’s budget vetoes placate S&P for now

  S&P Global Ratings analysts liked Gov. Bill Walker’s $1.3 billion in budget vetoes enough to back off of earlier indications the agency would continue to downgrade the state’s credit rating if lawmakers didn’t make major progress towards balancing the state’s budget this year. In a brief three-paragraph Aug. 22 statement, S&P affirmed the State of Alaska’s AA+ general obligation bond rating, its AA appropriation rating and its A+ moral obligation rating. The agency also removed the ratings from CreditWatch, where it put the state in early June. However, the outlook for the ratings remains negative. “The removal of the ratings from CreditWatch reflects our view that although the Legislature did not approve the fiscal reforms sought by the governor to address the state’s structural budget deficit, his nearly $1.3 billion in vetoes put the state on track to have similar fiscal results as if it had,” S&P analyst Gabriel Petek said in a release. On June 29 Walker unveiled the heavy use of his veto pen on the $4.4 billion budget passed by the Legislature. When combined with recovering oil prices, which adds royalty and tax revenue to state coffers, the vetoes took the 2017 deficit below $3 billion. “Although Gov. Walker’s vetoes provide additional time before the state’s reserves would be depleted, S&P will likely lower the state’s debt ratings in the absence of structural fiscal reform during the 2017 legislative session,” the Department of Revenue said in a statement. The sale of previously approved state bonds pushed S&P revisit the state’s fiscal situation and ultimately to downgrade the State of Alaska’s formerly sterling AAA bond rating in January, prior to the legislative session. Local governments and school districts also piggyback on the state’s rating and use the moral obligation of the state to secure lower interest financing for their projects. When S&P Global first downgraded Alaska in January, Walker likened to the downgrade to an additional $1,000 per year on every $1 million the state borrows. Fitch Ratings and Moody’s Investors Service eventually followed suit and downgraded the state over the winter, when oil prices bottomed out at about $25 per barrel and the prospective fiscal year 2017 deficit correspondingly grew to upward of $4 billion. When the state House ultimately failed to pass a bill to establish a structured draw from the Permanent Fund’s earnings income to pay for state government — which would have added revenue and cut the deficit by roughly half — S&P hinted it would be forced to further downgrade the state. The “Permanent Fund bill” was the centerpiece of the administration’s New Sustainable Alaska Plan to balance the state budget within three years. A bill to use Fund earnings passed the Senate by a 14-5 margin during a June special session. Moody’s eventually did downgrade Alaska a second time July 21 from Aa2, equivalent to the AA rating commonly used by other agencies. Petek added: “While the vetoes buy the state additional time, they do not represent a solution to the state’s structural deficit.”

State readies to take over AK LNG from Slope producers

A study commissioned by three of the four Alaska LNG Project participants suggests alternative financing options currently being investigated could improve the project’s global competitiveness amid today’s lower energy prices. Dave Barrowman, a vice president with the global energy consulting firm Wood Mackenzie, said during the Aug. 24 joint hearing of the House and Senate Resources committees that a state-led Alaska LNG Project backed with a third-party financing structure could drop the project’s all-important “cost of supply” by roughly 40 percent. Unsurprisingly, the current financing plan for the $45 billion-plus North Slope natural gas export plan, which has the state, BP, ConocoPhillips and ExxonMobil funding the project through debt and equity, doesn’t pencil out, according to Barrowman. That’s because upstream oil and gas companies typically require a higher return on their investments — Wood Mackenzie assumed a 12 percent return in its study — than do other potential investors. An Alaska LNG Project relying on producer and state funding alone could deliver LNG to Asian buyers for about $12 per million British thermal units, or mmbtu, if it could be built for about $45 billion. At $12 per mmbtu, Alaska LNG would struggle to clear return hurdles even at oil prices in the $70 per barrel range, according to the study. Barrowman said the current project has a cost of supply that is “significantly higher than other jurisdictions,” but also is not alone among prospective LNG projects with financial feasibility challenges. While not perfectly analogous to the long-term contracts Alaska LNG sellers would need to secure to backstop the project, the spot price for LNG delivered to East Asian buyers was about $4.50 per mmbtu this spring, according to the Federal Energy Regulatory Commission. Project leaders have continuously used a wide price range of $45 billion to $65 billion to bring Alaska LNG into production since the project structure took shape more than two years ago. Project Manager Steve Butt said during his Aug. 24 progress report to the committees that the overall cost has been driven to the “lower end” of the range, but a more definitive price hasn’t been settled. If the state-led project being promoted by Gov. Bill Walker and Alaska Gasline Development Corp. President Keith Meyer can secure outside investors to buy into the project infrastructure — the North Slope gas treatment plant, the 800-mile pipeline and the immense Nikiski LNG facility — for returns in the 8 percent range, the cost of supply could potentially fall as low as about $7 per mmbtu, Barrowman said. Echoing what Meyer has said since taking the helm at AGDC in June, Barrowman said equity and pension funds, pipeline companies and other utilities might be interested in a stake in Alaska LNG at sub-10 percent returns because the project would provide a stable, long-term income stream. Those investors would then act as “tollers” and provide access and use of the facilities to the producers and other potential customers for a tolling fee. The producers have all stated support for investigating a commercially viable state-led project. “Certainly moving to a tolling system could be beneficial, disproportionately beneficial, towards Alaska LNG,” Barrowman said. Anchorage Democrat Sen. Bill Wielechowski said to Barrowman after a presentation of the study that he “was expecting doom and gloom and I’m actually feeling a little optimistic at this point.” Barrowman added that he has confidence in assuming an 8 percent return for third-party infrastructure investors because the Alaska LNG Project has virtually no upstream risk; the Prudhoe Bay and Point Thomson fields are established and the gas is known and is already being recovered and reinjected. That is a big benefit many other competing LNG projects do not have. Under an ideal tolling structured project, “it may be possible to have a profitable project if the price rises, but it’s still going to struggle at $45 (per barrel of oil) — today’s prices,” Barrowman said. Meyer said repeatedly during his testimony to the committee that he was happy to see the results from Wood Mackenzie, as it mostly supports what he has been saying. AGDC, BP and ExxonMobil commissioned the study, but Barrowman said none of the Alaska LNG Project participants contributed to it. Wood Mackenzie relied on publicly available information about the project and its own expertise about industry standards to come to its conclusions, he said. Resources Committee chair Sen. Cathy Giessel, R-Anchorage, a skeptic of a state-led project, said in an interview that the high-level study just raises more questions. She questioned why other LNG projects around the world are not all using the third party tolling structure if the benefits are so obvious. Giessel also said that constituents she has talked to during her reelection campaign have sentiments similar to hers about the project path. “Universally, people are bringing up concerns about why is the state taking on a leadership role of a project the (producer) companies are saying is uneconomic right now?” she said. Wood Mackenzie tied the financial viability of the Alaska LNG project to oil because prices in LNG contracts have long been formulated as a percentage of the price of oil. Barrowman noted there was a push to de-link LNG from oil in long-term contracts and move to North America Henry Hub-based pricing several years ago when increased shale gas production dropped the price of domestic natural gas when oil was still above $100 per barrel. However, the subsequent fall of oil prices has buyers rethinking their strategy again, he said. BP backs administration Reaction to BP stating Aug. 25 it supports a state-led Alaska LNG Project was mixed among legislators that attended an update hearing on the project. BP Alaska Region Manager David Van Tuyl said to House and Senate members the North Slope natural gas the company holds is the largest undeveloped resource in its portfolio and it understands the state’s desire to move the economically challenged project forward. “BP is not giving up on the project,” Van Tuyl said. “Instead, we need to change gears and figure out how to reduce the cost of supply so that the project can be competitive. We believe that the best way to make that happen is with a state-led project and we support the state’s efforts.” He continued by saying mega projects such as the Alaska LNG Project regularly are restructured at some point. “We think a state project with state ownership could be the best structure to make the project more competitive,” Van Tuyl added. He cited the Wood Mackenzie study that indicated financially handling the Alaska LNG infrastructure — North Slope gas treatment plant, pipeline and Nikiski LNG facility — as a tolling utility with third party investment could lower the needed rate of return. Rep. Dan Saddler, R-Eagle River, asked Van Tuyl why BP didn’t propose state leadership in the first place. Van Tuyl responded that the major producer typically starts with an equity model in its projects first. When cost estimates and market conditions made it clear the original plan wouldn’t compete globally, the company became open to other ideas, he said. “We think this is a pathway worth pursuing because the stakes are worth it,” Van Tuyl said to Saddler. Meyer testified in the first day of hearings and has said numerous times prior that funds favoring long-term, predictable infrastructure investments would likely be willing to take substantially lower returns on investments than oil and gas companies usually are. Under Walker, the state Division of Oil and Gas has not accepted BP’s annual development plan for the Prudhoe Bay until the company includes in the plan what it has done to market the gas. BP has insisted the information is proprietary and could violate anti-trust laws and a Sept. 1 deadline to give the state what it is demanding was just a week away when Van Tuyl testified. In interviews, several legislators in attendance during the two days of hearings said BP’s enthusiasm towards a state-led project just breeds apprehension. Senate Finance co-chair Anna MacKinnon, R-Eagle River, said she appreciates the company’s cooperation with the administration to continue pursuing Alaska LNG, but she’s also not surprised by BP’s stance because state leadership inevitably means more financial risk to the state. “I’m just not enthused about state ownership,” MacKinnon said in an interview. House and Senate Finance Committee members were invited to participate in the two-day joint Resources Committee hearing. Anchorage Democrat and House Resources member Rep. Geran Tarr concurred with MacKinnon’s skepticism about BP backing the state plan. It should be expected that BP would be fine with allowing the state to build infrastructure that allows the company to sell a massive, stranded resource, she said. According to Tarr, to gain support for the plan, AGDC and the administration still need to establish what level of financial commitment the state would be facing, how many employees the corporation will need to hire to manage the megaproject and how much revenue can the state expect from a project that must accept lower returns to be economic. “I want to better understand the risks the state is going to take on,” she said. “I want to get into the details. Giessel noted that while the state-led proposal is still young — it came to the forefront during media interviews with Meyer in June — she’s not sure if enough weight is being given to legislators’ concerns. Wielechowski was more positive about BP’s position. “It’s good to see that BP is interested in this. They’re the operator of (the Prudhoe Bay Unit) and that’s where an enormous amount of the gas is, so it’s good to hear that,” Wielechowski said. ConocoPhillips’ Darren Meznarich said because of energy market conditions the company is unlikely to directly participate in ramping activity into the front-end engineering and design, or FEED, phase in 2017. At the same time, he reiterated that the company would make its share of North Slope natural gas available on agreeable terms and would “still be an active participant if this project goes forward,” through upstream infrastructure investments. ExxonMobil Senior Commercial Advisor Bill McMahon said the company, as the current project lead, would do its part to ensure a smooth transition to a state-sponsored project and is willing to explore all options to monetize the immense gas resource. Walker said in a release following the hearing that the state is looking at alternatives to continue the project because “the most common denominator for every growing economy is low-cost energy. Monetizing our gas on the world market makes it possible to deliver low-cost energy to Alaskan homes and businesses and to create thousands of construction and long-term operation jobs.” He also emphasized once again that the Permanent Fund will not be part of a state-led Alaska LNG Project. “Let me be clear, a project that is not economically viable will not be built. If economically viable, it will be financed by long-term purchase contracts secured before the first piece of pipe is laid, not by the Permanent Fund,” the governor said. “This is how projects around the world are financed and Alaska’s will be no exception.” Van Tuyl also referenced the possibility for federal tax exemption on at least a portion of a project with state ownership, another cost cutter. Financial attorneys, including former Revenue Commissioner and Permanent Fund Board Chair Eric Wohlforth, told House and Senate members prior to Van Tuyl’s comments that the prospect of getting state ownership of an LNG export project to pass multiple legal tests for tax exempt status is modest at best. Wielechowski added that a scenario in which the state could still benefit from a project the producers don’t prioritize is not unfathomable, as evidenced by the Wood Mackenzie analysis, he said. “You can very easily envision a scenario where (the producers) could still make a pretty decent profit but they would choose not to do it because they have so much other competition elsewhere and they would prefer to make money elsewhere. This is where we get out of alignment with the producers,” he said. “This project can still be profitable for the producers potentially and still be profitable for us and there can be a lot of reasons why the producers would say ‘No, we choose not to do this.’” Either way, Wielechowski and Tarr both said the Alaska LNG Project should not be politicized. “This project is going to outlive all of our political careers,” Tarr said. “We need to go with the Ted Stevens approach of ‘To hell with politics, let’s do what’s best for Alaska.’” Elwood Brehmer can be reached at [email protected]

Legislators lukewarm on BP support of state-led gas project

Reaction to BP stating Thursday it supports a state-led Alaska LNG Project was mixed among legislators that attended an update hearing on the project. BP Alaska Region Manager David Van Tuyl said to House and Senate members the North Slope natural gas the company holds is the largest undeveloped resource in its portfolio and it understands the state’s desire to move the economically challenged project forward. “BP is not giving up on the project,” Van Tuyl said. “Instead, we need to change gears and figure out how to reduce the cost of supply so that the project can be competitive. We believe that the best way to make that happen is with a state-led project and we support the state’s efforts.” He continued by saying mega projects such as the $45 billion-plus Alaska LNG Project regularly are restructured at some point. “We think a state project with state ownership could be the best structure to make the project more competitive,” Van Tuyl added. He cited a study presented at Wednesday’s hearing from international energy consultant firm Wood Mackenzie that indicated financially handling the Alaska LNG infrastructure — North Slope gas treatment plant, pipeline and Nikiski LNG facility — as a tolling utility with third party investment could lower the needed rate of return. Rep. Dan Saddler, R-Eagle River, asked Van Tuyl why BP didn’t propose state leadership in the first place. Van Tuyl responded that the major producer typically starts with an equity model in its projects first. When cost estimates and market conditions made it clear the original plan wouldn’t compete globally, the company became open to other ideas, he said. “We think this is a pathway worth pursuing because the stakes are worth it,” Van Tuyl said to Saddler. The proposal to shift project control to the state has been strongly advocated by Gov. Bill Walker and Alaska Gasline Development Corp. President Keith Meyer. Myer testified Wednesday and has said numerous times prior that funds favoring long-term, predictable infrastructure investments would likely be willing to take substantially lower returns on investments than oil and gas companies usually are. Under Walker, the state Division of Oil and Gas has not accepted BP’s annual development plan for the Prudhoe Bay until the company includes in the plan what it has done to market the gas. BP has insisted the information is proprietary and could violate anti-trust laws. In interviews, several legislators in attendance during the two days of hearings said BP’s enthusiasm towards a state-led project just breeds apprehension. Senate Finance co-chair Anna MacKinnon, R-Eagle River, said she appreciates the company’s cooperation with the administration to continue pursuing Alaska LNG; but she’s also not surprised by BP’s stance because state leadership inevitably means more financial risk to the state. “I’m just not enthused about state ownership,” MacKinnon said in an interview. House and Senate Finance Committee members were invited to participate in the two-day joint Resources Committee hearing. Anchorage Democrat and House Resources member Rep. Geran Tarr concurred with MacKinnon’s skepticism about BP backing the state plan. It should be expected that BP would be fine with  the state to building infrastructure that allows the company to sell a massive, stranded resource, she said. According to Tarr, to gain support for the plan AGDC and the administration still need to establish what level of financial commitment the state would be facing, how many employees the corporation will need to hire to manage the mega project and how much revenue can the state expect from a project that must accept lower returns to be economic. “I want to better understand the risks the state is going to take on,” she said. “I want to get into the details." Resources chair Sen. Cathy Giessel noted that while the state-led proposal is still young — it came to the forefront shortly after Meyer took the reins at AGDC in June — she’s not sure if enough weight is being given to legislators’ concerns. Resources member Sen. Bill Wielechowski, D-Anchorage, was more positive about BP’s stance. “It’s good to see that BP is interested in this. They’re the operator of (the Prudhoe Bay Unit) and that’s where an enormous amount of the gas is, so it’s good to hear that,” Wielechowski said. ConocoPhillips’ Darren Meznarich said because of energy market conditions the company is unlikely to directly participate in ramping activity into the front-end engineering and design, or FEED, phase in 2017. At the same time, he reiterated that the company would make its share of North Slope natural gas available on agreeable terms and would “still be an active participant if this project goes forward,” through upstream infrastructure investments. ExxonMobil Senior Commercial Advisor Bill McMahon said the company, as the current project lead, would do its part to ensure a smooth transition to a state-sponsored project and is willing to explore all options to monetize the immense gas resource. Walker said in a release following the hearing that the state is looking at alternatives to continue the project because “the most common denominator for every growing economy is low-cost energy. Monetizing our gas on the world market makes it possible to deliver low-cost energy to Alaskan homes and businesses and to create thousands of construction and long-term operation jobs.” He also emphasized once again that the Permanent Fund will not be part of a state-led Alaska LNG Project. “Let me be clear, a project that is not economically viable will not be built. If economically viable, it will be financed by long-term purchase contracts secured before the first piece of pipe is laid, not by the Permanent Fund,” the governor said. “This is how projects around the world are financed and Alaska’s will be no exception.” Van Tuyl also referenced the possibility for federal tax-exemption on at least a portion of a project with state ownership, another cost cutter. Financial attorneys, including former Revenue Commissioner and Permanent Fund Board chair Eric Wohlforth, told House and Senate members prior to Van Tuyl’s comments that the prospect of getting state ownership of an LNG export project to pass multiple legal tests for tax exempt status is modest at best. Wielechowski added that a scenario in which the state could still benefit from a project the producers don’t prioritize is not unfathomable, as evidenced by the Wood Mackenzie analysis, he said. “You can very easily envision a scenario were (the producers) could still make a pretty decent profit but they would choose not to do it because they have so much other competition elsewhere and they would prefer to make money elsewhere. This is where we get out of alignment with the producers,” he said. “This project can still be profitable for the producers potentially and still be profitable for us and there can be a lot of reasons why the producers would say ‘No, we choose not to do this.’” Either way, Wielechowski and Tarr both emphasized the Alaska LNG Project should not be a political tool. “This project is going to outlive all of our political careers,” Tarr said. “We need to the Ted Stevens approach of ‘To hell with politics, let’s do what’s best for Alaska.’”   Elwood Brehmer can be reached at [email protected]

BP backs Walker administration on AK LNG

BP put its support behind a state-led Alaska LNG Project Thursday during a legislative update on the project. The company’s Alaska Region Manager David Van Tuyl said the North Slope natural gas BP holds is the largest undeveloped resource in its portfolio and it understands the state’s desire to move the economically challenged project forward. “BP is not giving up on the project,” Van Tuyl said. “Instead, we need to change gears and figure out how to reduce the cost of supply so that the project can be competitive. We believe that the best way to make that happen is with a state-led project and we support the state’s efforts.” He continued by saying mega projects such as the $45 billion-plus Alaska LNG Project regularly are restructured at some point. “We think a state project with state ownership could be the best structure to make the project more competitive,” Van Tuyl added. He cited a study presented at Wednesday’s hearing from international energy consultant firm Wood Mackenzie that indicated financially handling the Alaska LNG infrastructure — North Slope gas treatment plant, pipeline and Nikiski LNG facility — as a tolling utility with third party investment could lower the needed rate of return. The proposal to shift project control to the state has been strongly advocated by Gov. Bill Walker and Alaska Gasline Development Corp. President Keith Meyer. Myer testified Wednesday and has said numerous times prior that funds favoring long-term, predictable infrastructure investments would likely be willing to take substantially lower returns on investments than oil and gas companies usually are. ConocoPhillips’ Darren Meznarich said because of energy market conditions the company is unlikely to directly participate in ramping activity into the front-end engineering and design, or FEED, phase in 2017. At the same time, he reiterated that the company would make its share of North Slope natural gas available on agreeable terms and would “still be an active participant if this project goes forward,” through upstream infrastructure investments. ExxonMobil Senior Commercial Advisor Bill McMahon said the company, as the current project lead, would do its part to ensure a smooth transition to a state-sponsored project and is willing to explore all options to monetize the immense gas resource. Under Walker, the state Division of Oil and Gas has not accepted BP’s annual development plan for the Prudhoe Bay until the company includes in the plan what it has done to market the gas. BP has resisted sharing the information it insists is proprietary and the disclosure of which could violate anti-trust laws. Van Tuyl also referenced the possibility for federal tax-exemption on at least a portion of a project with state ownership, another potential cost cutter. Financial attorneys, including former Revenue Commissioner and Permanent Fund Board Chair Eric Wohlforth, told House and Senate members prior to Van Tuyl’s comments that the prospect of getting state ownership of an LNG export project to pass multiple legal tests for tax exempt status is modest at best.   Look for updates to this story in an upcoming issue of the Journal. Elwood Brehmer can be reached at [email protected]

Study: Investors willing to take lower return could drop AKLNG cost 40%

A study commissioned by three of the four Alaska LNG Project participants suggests alternative financing options currently being investigated could improve the project’s global competitiveness amid today’s lower energy prices. Dave Barrowman, a vice president with the global energy consulting firm Wood Mackenzie, said during Wednesday’s joint hearing of the House and Senate Resources committees that a state-led Alaska LNG Project backed with a third-party financing structure could drop the project’s all-important “cost of supply” by roughly 40 percent. Unsurprisingly, the current financing plan for the $45 billion-plus North Slope natural gas export plan, which has the state, BP, ConocoPhillips and ExxonMobil funding the project through debt and equity, doesn’t pencil out, according to Barrowman. That’s because upstream oil and gas companies typically require a higher return on their investments — Wood Mackenzie assumed a 12 percent return in its study — than do other potential investors. An Alaska LNG Project relying on producer and state funding alone could deliver LNG to Asian buyers for about $12 per million British thermal units, or mmbtu, if it could be built for about $45 billion. At $12 per mmbtu, Alaska LNG would struggle to clear return hurdles even at oil prices in the $70 per barrel range, according to the study. Barrowman said the current project has a cost of supply that is “significantly higher than other jurisdictions,” but also is not alone among prospective LNG projects with financial feasibility challenges. While not perfectly analogous to the long-term contracts Alaska LNG sellers would likely secure, the spot price for LNG delivered to East Asian buyers was about $4.50 per mmbtu this spring, according to the Federal Energy Regulatory Commission. Project leaders have continuously used a wide price range of $45 billion to $65 billion to bring Alaska LNG into production since the project structure took shape more than two years ago. Project Manager Steve Butt said during his Wednesday report to the committees that the overall cost has been driven to the “lower end” of the range, but a more definitive price hasn’t been settled. If the state-led project being promoted by Gov. Bill Walker and Alaska Gasline Development Corp. President Keith Meyer can secure outside investors to buy into the project infrastructure — the North Slope gas treatment plant, the 800-mile pipeline and the immense Nikiski LNG facility — for returns in the 8 percent range, the cost of supply could potentially fall as low as about $7 per mmbtu, Barrowman said. Echoing what Meyer has said since taking the helm at AGDC in June, Barrowman said equity and pension funds, pipeline companies and other utilities might be interested in a stake in Alaska LNG at sub-10 percent returns because the project would provide a stable, long-term income stream. Those investors would then act as “tollers” and provide access and use of the facilities to the producers and other potential customers for a tolling fee. The producers have all stated support for investigating a commercially viable state-led project. “Certainly moving to a tolling system could be beneficial, disproportionately beneficial, towards Alaska LNG,” Barrowman said. Anchorage Democrat Sen. Bill Wielechowski said to Barrowman after a presentation of the study that he “was expecting doom and gloom and I’m actually feeling a little optimistic at this point.” Barrowman added that he has confidence in assuming an 8 percent return for third-party infrastructure investors because the Alaska LNG Project has virtually no upstream risk; the Prudhoe Bay and Point Thomson fields are established and the gas is known and is already being recovered and reinjected. That is a big benefit many other competing LNG projects do not have. Under an ideal tolling structured project, “it may be possible to have a profitable project if the price rises, but it’s still going to struggle at $45 (per barrel of oil) — today’s prices,” Barrowman said. Meyer said repeatedly during his testimony to the committee that he was happy to see the results from Wood Mackenzie, as it mostly supports what he has been saying. AGDC, BP and ExxonMobil commissioned the study, but Barrowman said none of the Alaska LNG Project participants contributed to it. Resources Committee chair Sen. Cathy Giessel, R-Anchorage, a skeptic of a state-led project, said in an interview that the high-level study just raises more questions. She questioned why other LNG projects around the world are not all using the third party tolling structure if the benefits are so obvious. Giessel also said that constituents she has talked to during her reelection campaign have sentiments similar to hers about the project path. “Universally, people are bringing up concerns about why is the state taking on a leadership role of a project the (producer) companies are saying is uneconomic right now?” she said. Wood Mackenzie tied the financial viability of the Alaska LNG project to oil because prices in LNG contracts have long been formulated as a percentage of the price of oil. Barrowman noted there was a push to de-link LNG from oil in long-term contracts and move to North America Henry Hub-based pricing several years ago when increased shale gas production dropped the price of domestic natural gas when oil was still above $100 per barrel. However, the subsequent fall of oil prices has buyers rethinking their strategy again, he said. Further cost reductions could be had if a state-owned project can avoid federal taxes, Barrowman said. The details of that prospect will be covered in Thursday afternoon’s hearing. Elwood Brehmer can be reached at [email protected]

Permanent Fund grew 1.35% in FY16

The Permanent Fund unofficially grew a modest 1.35 percent on a $52.8 billion portfolio in fiscal year 2016, the result of a volatile 12 months for public financial markets, according to Fund leadership. Alaska Permanent Fund Corp. Executive Director Angela Rodell said during an Aug. 18 meeting of the policy study group Commonwealth North in Anchorage that market fluctuations followed oil’s wintertime foray to less than $30 per barrel, the first time the dominant commodity had been that cheap for that long since the early 2000s. If there is change to the unaudited 1.35 percent return for the 2016 state fiscal year, which ended June 30, it would likely be an increase, Rodell said. The Fund’s Earnings Reserve Account, which holds realized and unrealized gains, finished fiscal year 2016 with $8.1 billion, according to Rodell. The fund held $54.2 billion in total assets as of Aug. 22. Private market assets, which comprise 44 percent of the Fund’s current investment portfolio, are where the best returns have been recently. “Real estate continues to be a very good area for us,” she said. About 12 percent of the Fund’s assets are in real estate holdings, which yielded nearly a 17 percent return in 2016, followed closely by infrastructure investments, which produced 14.9 percent returns for the year. Public equity holdings, about 40 percent of the Fund, lost 5.1 percent. Since 2011, the Alaska Permanent Fund Corp. has achieved an average return of 6.41 percent, which is 1.56 percent above the benchmark set by the APFC Board of Trustees for a similar portfolio managed passively, Rodell, a former Revenue commissioner under Gov. Sean Parnell, noted. “We think this is strong performance, but we can do better. We strive to be an excellent performer, not just a solid performer,” she said. The performance of the Permanent Fund has become a focal point of political circles, beyond simply what it means for fall dividend checks, as Gov. Bill Walker and some in the Legislature push to use the Fund’s earnings to fill half or more of the state’s $3 billion-plus annual deficits. The final “Permanent Fund bill” that passed the Senate by a wide margin but failed to reach a floor vote in the House this past spring would have established an annual 5.25 percent of market value, or POMV, draw from the Earnings Reserve Account. The trustees have in the past supported a POMV draw from the Fund of up to 5 percent. Revenue Commissioner Randy Hoffbeck, a current Fund trustee, said repeatedly during testimony to legislative committees that the 5.25 POMV draw is at the far upper limit of what could sustainably be pulled each year. Earlier versions of legislation to use Fund earnings had smaller percentage draws; the 5.25 percent figure was a political compromise that would really mean achieving 7.25 percent annual returns to maintain the Fund’s value after adjusting for inflation. Rodell said managers try to hold 6 percent of the overall value of the Fund in cash and liquid investments to make needed cash calls and that prospective liquidity challenges if draws are made to fund government “are a topic of discussion” but no decision to change investment strategy has been made because policy hasn’t yet changed. How the corporation handles future draws will depend on the size of the draws and whether Fund management needs to be adjusted to meet the new demand, she said. Rodell emphasized that the Permanent Fund Corp. is “not in a position to anticipate” what might happen politically. She also noted that POMV draws from other large endowment funds, such as those held by Harvard and Yale have historically been in the 5 percent range but some draws have been cut to 4.5 percent or 4 percent because anticipated returns weren’t materializing. “All we are tasked with is to manage the money and that’s it. I think it’s just really important to recognize that. This is a big debate (using Fund earnings for government services) and when I get asked about what is a sustainable draw I don’t address that question,” Rodell said. “It’s not important what I think is sustainable. If I know what the bogey is we’ll hit the bogey.” Unique about Alaska’s Permanent Fund, she added, is that the draw can only come from the realized gains in the Earnings Reserve, which based on statute that allows lawmakers to draw from the account with a simple majority vote, is nothing more than another savings account from the corporation’s perspective. “Just like we don’t talk about what’s sustainable for the Constitutional Budget Reserve and we don’t talk about what was sustainable for the Statutory Budget Reserve, the Earnings Reserve Account is an account that belongs to the State of Alaska that can be spent,” Rodell said.

Tustumena replacement accelerated to FY2017 funding

It’s looking like the M/V Tustumena could be headed for an earlier-than-expected retirement. The Alaska Department of Transportation and Public Facilities has moved up its federal funding request to pay for the 52-year-old Tustumena’s $237 million replacement from “after fiscal year 2019” to federal fiscal year 2017, which begins Oct. 1. The Seattle-based marine engineering firm Glosten finished designing the new 330-foot vessel in January. “It’s just a matter of awarding (the construction) contract and before we can do that we have to have funding for it,” Deputy DOT Commissioner Mike Neussl said. DOT made the change in the first amendment to its 2016-2019 Statewide Transportation Improvement Program document, which essentially prioritizes all of the department’s prospective construction projects and the plans to fund them. About $216 million of the $237 million for the new ferry will be federal money, with the remaining $21 million paid for with requisite state matching funds. The Alaska Marine Highway is part of the national highway system and therefore qualifies for Federal Highway Administration funds for road construction projects. Those federal dollars typically require a minimum state match of approximately 10 percent. The public comment period for the STIP amendment document ended Aug. 19, and barring changes will soon be incorporated into the overall construction plan, which was finalized last November. In the case of the Tustumena replacement, the funding request was advanced via a mechanism that allows the state to fund the project up front and be paid back over subsequent years if the project is approved by the FHWA. The STIP amendment calls for the state to fund the several-year project up front with $54 million in paybacks in federal year 2019 and another $108 million from the feds after 2019. Replacing the 296-foot Tustumena, which serves Homer, Kodiak Island and ports on the Alaska Peninsula and the Aleutians has become increasingly pressing as the aging ferry has shown more and more wear from years on the system’s most taxing route. Cracks near the bow in the structure of the vessel have forced the U.S. Coast Guard to put travel restrictions on the Tustumena, Neussl said. That means it won’t be hauling legislators and their wares from Whittier to Juneau this January. “The legislative cross-gulf run is not on the winter schedule, which was just released,” Neussl said. “We have an alternative plan to truck those vehicles to Haines and haul them from Haines to Juneau on the regular Lynn Canal ferries.” Replacing the Tustumena is all-but mandatory, despite the state’s $3 billion budget deficit, because it is the only vessel in the 11-ferry fleet with a vehicle elevator to match the docks on its route. “Nearly every port from Homer out to Unalaska-Dutch Harbor is a (privately owned) fixed-height dock,” AMHS General Manager  John Falvey said. “There are no floating docks out there. That would be a massive infrastructure change to keep all those communities in service with a new floating drive-on drive-off dock.” Additionally, the new vessel will carry 53 vehicles to the Tusty’s 34, which will add needed car deck space between Homer and Kodiak, Neussl noted. According to Glosten, the latest ferry design should reduce drag on the vessel’s hull by 20 percent and lead to notable fuel savings as well. Doug Ward of Vigor Alaska said during the MTAB meeting that the state’s twin 280-foot “Alaska class” day ferries being built at Vigor’s Ketchikan shipyard are about three to four months behind schedule for both to be done by October 2018. He attributed the setback in the nearly four-year build schedule to the contract employees the company hired not taking a liking to the Southeast Alaska community. “We had a lot of turnover in 2015,” Ward said. Vigor hired journeymen level shipbuilders from the Gulf Coast to teach generally younger, unskilled resident workers in the trade. However, the fair weather workers “don’t last very long in Ketchikan,” Ward commented. “We are a little bit behind schedule and I’m feeling pretty good that we’re going to be able to catch up and hopefully turn a profit,” he said. In May, Gov. Bill Walker’s office announced Port Alsworth 7th grader Malea Voran and Eagle River sophomore Taylor Thompson had won a statewide essay contest for Alaska students to name the Alaska class ferries, which will be the M/V Tazlina and the M/V Hubbard. State law requires AMHS ferries be named after Alaska glaciers. Elwood Brehmer can be reached at [email protected]    

Southeast Conference study aims for ferry system reforms

While new ferries are being built, others are being jettisoned or idled for lack of funding as a stakeholder group searches for ways to set the Alaska Marine Highway System on a more stable, long-term path. The Southeast Conference unofficially kicked off a two-phase study Aug. 20 that over the next two-plus years will hopefully identify structural changes to improve the operability and financial health of the state ferry system. The Southeast Conference was originally formed in 1958 to help residents of its namesake region of then-territorial Alaska lobby for a regional transportation system. It has since evolved into one of the 10 Alaska regional development organizations, or ARDORs, in the state. Executive Director Shelly Wright said the study process has been dubbed the Alaska Marine Highway Reform Project. “It’s our hope that we can define a governance strategy and reform the system with a strategic plan,” Wright told the state Marine Transportation Advisory Board during the board’s Aug. 19 meeting in Anchorage. The Southeast Alaska development organization held an Aug. 20 summit for stakeholders in the ferry system in Anchorage that coincided with the MTAB meeting. Wright said in an interview that Phase 1 of the study will focus on the governance portion in an attempt to de-link the state agency from politics, and turnover in leadership, as much as possible. The Southeast Conference has no interest in separating the ferry system from state government or the Department of Transportation, Wright emphasized. “The important thing that we are thinking of as the Southeast Conference is, first and foremost, finding a way to govern the Alaska Marine Highway with continuity,” she said. Jim Calvin, a principal at McDowell Group, the local research firm that is compiling data for the project and has authored numerous reports on the AMHS, said the foundational work for the governance phase should be done by the end of the year. The Southeast Conference and McDowell Group plan to examine governance models and operating structures of ferry systems worldwide, Calvin said, to see if there is a better fit for Alaska’s than its current status as essentially a division of a cabinet-level state department. The State of Alaska already has several “quasi-government” entities organized to run as public corporations with modest political interference including the Alaska Housing Finance Corp., the Alaska Industrial Development and Export Authority and the Alaska Railroad. They have boards comprised of governor-appointed public members and state commissioners and their budgets are not typically debated during the annual state budgeting process. However, those agencies are mostly self-sustaining, while the ferry system doesn’t come close to breaking even. In fiscal year 2015 the system generated a record $53.9 million in revenue and shaved $5.2 million off its operating expenses, but still needed more than $100 million in state budget support, making the AMHS inherently political. Funding for the Alaska Marine Highway System has been at the center of budget battles for the last several legislative sessions. The system’s budget has been cut by 15 percent since fiscal year 2013. At the same time, fares on many ferry routes have been raised twice to increase revenue and make the overall fare structure more equitable. Compiling information for the 25-year strategic plan, conversely, will be a deep look at the market forces, finances, economics and demographics that make the state ferries what they are, Calvin described. “The Marine Highway is woven into the fabric of coastal Alaska and has impacts all across the state and understanding how changing the system either from a governance perspective or from an operational perspective — how that unfolds is just a really complex, year-long exercise,” he said to the MTAB board. A final report on both aspects is expected near the end of 2018, according to Wright. In January, the McDowell Group published a report that concluded the state’s 11-ferry system generated $273 million of economic activity across Alaska for the $114 million in state support it received in 2014. The Alaska Marine Highway Reform Project spawned from a memorandum of understanding, or MOU, signed in May by Gov. Bill Walker and Southeast Conference leadership to develop ways to improve upon the 53-year old Alaska Marine Highway system from an organizational standpoint. “We’re here to find out what Alaskans need the Marine Highway System to be,” MTAB chair and Southeast Conference Energy Coordinator Robert Venables said. The Department of Transportation contributed $250,000 to the planning effort in conjunction with the MOU and the Southeast Conference is working to raise another $150,000 for what is expected to be about a $400,000 examination. DOT Commissioner Marc Luiken said at the MTAB meeting that he, Deputy DOT Commissioner Mike Neussl and AMHS General Manager Capt. John Falvey “all stand ready to support the effort with data, subject matter expertise or anything else we can provide.” Wright said numerous groups from areas beyond coastal Alaska have contributed to the $68,000 the Southeast Conference has raised for the effort so far. Implementing a finite, generational plan for who to serve and how to serve them will provide stability between state administrations even if a new governance framework cannot be established, she added. It will also give legislators something to budget on. “There’s not really any financial trust in the Alaska Marine Highway System because there’s nothing you can really look to and say, ‘What are you doing and why are you doing that?’” Wright said.

AGDC president lays out schedule for state takeover of AK LNG Project

Alaska Gasline Development Corp. President Keith Meyer laid out an ambitious list of “to-dos” the state needs to check off if it is going to lead the $45 billion-plus Alaska LNG Project to fruition at a board of directors meeting on Thursday. Before the calendar turns to 2018 the project must be restructured to capture any and all potential tax and financial benefits available to a government-owned project, he said. Meyer and Gov. Bill Walker have repeatedly said — although an official opinion from the Internal Revenue Service is still needed — they believe there is the potential to shave billions of dollars from the cost of the massive project with at least partial tax-exempt status that would be tied to having the state in the lead. Also over the next 16 months or so it is “absolutely critical” that the project secures customers before other key elements can be resolved, according to Meyer. “The sales process takes about a year if things go well,” he said. Those customers could be the state’s current partners, the North Slope producers, in a fee-for-service or tolling scenario in which they would pay to use part or all of the project infrastructure — the North Slope gas treatment plant, the 800-mile pipeline or the Nikiski liquefaction facility. Or they could be more traditional Asian utilities or global LNG traders, Meyer surmised. “At the end of the day we need customer contracts because those customer contracts are what underpin the financing,” he said. AGDC and the Walker administration began investigating the prospect of shifting from the current equity share model for the Alaska LNG Project after it became apparent earlier this year that the confluence of depressed oil and LNG markets worldwide had at least one of the producers — ConocoPhillips — publicly balking at the idea to move forward with the massive investments needed to build the project or to spend its share of the costs for final engineering and design, or FEED. That equity project structure has BP, ConocoPhillips, ExxonMobil and the state each owning a portion of the project equal to their share of North Slope gas reserves, which for the state would be 25 percent. A fiscal structure establishing the state share still has to be approved, and a decision has to be made whether to take the state share in gas (in kind) or in cash (in value). For the state to enter a long-term tax structure for its ownership share a constitutional amendment would have to be approved in a state general election. In its current iteration the Alaska LNG Project would be the largest infrastructure project ever built in the United States. The producers have all said to this point that they support efforts to commercialize North Slope gas, including the prospect of the state taking a larger role in the project. Meyer and Walker are pitching a shift to a state-led project that would use third-party financing from backers willing to accept lower returns than the producers in exchange for the security of a long-term, stable infrastructure investment. If sales contracts can be pinned down, Meyer said the next move would be to obtain equity investors, followed closely by secured lenders for non-recourse debt financing. “The debt parties really don’t want to be engaged until you’ve got some of these other pieces in place,” Meyer said to the AGDC board. The list concludes with finding an engineering, procurement and construction management, or EPC, firm to turn the more than 30,000 pages of environmental, technical and resource information the project has already gathered into a pipeline in the ground with massive facilities at each end. “We need quality construction management firms. AGDC cannot manage this project on its own in terms of the construction aspect,” Meyer said. He added that AGDC has already interviewed a couple firms over the last few weeks and will hold more meetings with “globally competent, large-scale (EPC) firms that have the competency not only to manage the project but to construct the project.” Only after all that would the formal decision to enter the FEED stage of the project be made, according to Meyer’s presentation. He has also emphasized a state-led project would not mean the full-fledged, $2 billion FEED first envisioned for the AK LNG Project, but would likely entail a “FEED light,” with work spread schedules relying less on the regimented stage-gate process preferred by the producers. While it has been the main Alaska LNG topic of discussion all summer, the official transition to a state-led project should start “around the Octoberish timeframe,” Meyer said, when an agreement resolving issues around land ownership for the LNG plant, all sorts of intellectual property and other matters is hoped to be signed. “It’s paperwork, basically, that has to be done,” he said, describing the transition. A quarterly project update to the joint House and Senate Resources committees has been scheduled for the afternoons of Aug. 24 and 25 at the Downtown Anchorage Legislative Information Office building. AGDC Houston office approved The AGDC board unanimously approved a resolution authorizing the corporation to open a Houston marketing office. The State of Alaska entity needs a Texas presence because the project’s prospective LNG buyers from Asia all have offices there, in what has become “the energy capital of the world,” Meyer said. Board member and Labor Department Commissioner Heidi Drygas said she supports the idea but noted a foremost need to “keep fiscal restraint in mind.” Currently, the Alaska LNG Project has a Houston office staffed with about 120 individuals. That office will shrink and potentially dissipate as the pre-FEED stage wraps up and the transition to the state lead occurs, according to Meyer. He said the Houston space would primarily serve as a simple meeting space with requisite video conferencing equipment to allow Alaska personnel to meet with potential customers without continually flying back and forth. The exact cost of the new office is unclear because the space has not been selected. “This is going to be a very austere office, not a downtown high rise office,” Meyer said. He added that it would likely have a “handful” of project management staff, a receptionist and the aforementioned meeting space. Some staff continuing to work on the project would be relocated to Alaska from Houston, Meyer said. Board vice-chair Hugh Short said AGDC should try to get as many of the project jobs in Houston to Alaska as it can. “Our presence in Texas should be less than it is in Alaska,” Short commented. Elwood Brehmer can be reached at [email protected]

CIRI, Golden Valley progressing on Fire Island Wind expansion

In about a year there could be a few more wind turbines dotting the horizon west of Anchorage, thanks to a Fairbanks utility. Golden Valley Electric Association and Cook Inlet Region Inc. jointly announced Wednesday that they have agreed to the framework of a deal that would double the number of wind turbines on Fire Island just off Anchorage in Cook Inlet. About a $50 million project, Phase 2 of CIRI’s Fire Island Wind project would add another 11 large turbines to the group that was installed in 2012. Golden Valley CEO Corey Borgeson said in an interview that his electric utility and CIRI have reached a term sheet but are still negotiating the finer points of what is ultimately an extremely complex purchase and sale agreement. He said he fully expects a contract to be finalized and added that he would “welcome the other utilities in joining” Golden Valley to purchase power from Phase 2 of the Fire Island project. “(The agreement) is not done yet but we’re very optimistic and committed to bringing this independent power producer online,” Borgeson said. CIRI, the Southcentral Alaska Native regional corporation, has been actively and publicly soliciting the Railbelt utilities to partner to expand its wind farm since the first 11 turbines came online in September 2012. Chugach Electric Association agreed to a 25-year deal to purchase power from Phase 1 of Fire Island for 9.7 cents per kilowatt-hour. The framework deal currently being discussed calls for a 25-year purchase agreement with an electricity price escalating from a base price potentially as low as 5.6 cents per kilowatt-hour, the joint release states. A final agreement would require approval from the Regulatory Commission of Alaska. CIRI’s push to get Phase 2 built is do in large part to its ability to capture a 30 percent federal Business Energy Investment Tax Credit for the capital cost of the project. CIRI Senior Energy Development Director Suzanne Gibson described the rough deal CIRI is working on with Golden Valley as “sort of our last gasp at getting (the tax credit) while the getting is good.” According to the joint release, CIRI expects to secure financing for the Fire Island expansion this fall and have the turbines up and running by October 2017. The Consolidated Appropriations Act signed last December, a federal spending bill, extended tax credits for numerous types and sizes of renewable energy projects, including Fire Island. Gibson said as long as it is completed by the end of 2017, CIRI expects to receive the incentive, as opposed to the original end of 2015 deadline. Phase 1 of Fire Island was also spurred by a $25 million state grant to fund most of the cost for the underwater transmission line to connect the wind farm to Anchorage. Gibson said the prospect of a significantly lower price for Phase 2 power is due in large part to infrastructure  — operations and maintenance buildings, roads, transmission lines — and personnel that are already in place from Phase 1. “It won’t be as expensive to add 11 more (turbines) from an operational standpoint,” she said. The 11 turbines on Fire Island today are 1.6-megawatt General Electric turbines. The new, more efficient turbines will be able to generate up to 1.85 megawatts each, if the project is seen to fruition, according to Gibson. The 15 percent increase in generating capacity should allow Phase 2 to provide about 54,000 megawatt hours of power per year, enough to power about 7,500 homes, she said. Borgeson and Gibson both said they believe CIRI and Golden Valley have gotten this far towards a deal now because several new gas-fired power plants in the Railbelt that have come online in the past couple years allow for better integration of highly variable renewable power. They also concurred that a general move towards better cooperation between the area utilities — power from Fire Island would have to move through the networks of three utilities plus the state-owned northern intertie before reaching Golden Valley — will help make the project possible. “We’ve created a (generating) system that’s robust and will allow for the expansion of renewable projects, which is great,” Gibson said. The Railbelt utilities presented their efforts to maximize efficiencies and minimize costs to the RCA during a Wednesday morning meeting when the Fire Island announcement was made.   Elwood Brehmer can be reached at [email protected]

Foreign-flagged oil tankers calling on Valdez raise eyebrows, but no issues

BP chartering two foreign tankers to export crude from Valdez has garnered attention for a couple reasons. First, while not unprecedented, Alaska North Slope crude oil exports are rare. ConocoPhillips sent a vessel operated by its subsidiary Polar Tankers to South Korea in 2014. Prior to that shipment, however, the most recent Alaska oil export was in 2004, according to the federal Energy Information Administration. Crude exports were banned nationally in 1975, but Congress and President Bill Clinton exempted Alaska oil from the restriction in 1995. Until 2000, exports to East Asia countries were relatively common after the exemption. From 1996 through 2000, more than 78 million barrels of Alaska North Slope crude was sent to China, Japan, South Korea and Taiwan, according to the EIA. However, as North Slope production declined, so did exports of oil. The national ban on oil exports was repealed last December. In July and early August, two Bahamas-flagged tankers, the Tianlong Spirit and the Cascade Spirit, departed Valdez en route to foreign ports. The second foreign vessel to pick up Alaska North Slope crude, the Cascade Spirit, left Valdez Aug. 6. A BP spokeswoman said the vessels were chartered and the oil was exported because of a scheduled dry-docking of another tanker and maintenance activities at West Coast refineries that are the typical landing place for Alaska oil. The domestic shipments from Alaska require American-built and crewed tankers by Americans to comply with the Jones Act, and the vessels and crews that call on Valdez are typically longstanding, repeat customers, according to U.S. Coast Guard officials. Donna Schantz, executive director of the Prince William Sound Regional Citizens’ Advisory Council, said news of the tankers flying flags other than the stars and stripes raised eyebrows in the area. “There was a lot of concern, anytime you have foreign flagged ships — unfamiliar — you know, that haven’t been in our waters, coming in,” Schantz said. 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. Schantz noted that BP was “very responsive” to the many questions posed by the advisory council, but added it was a very short time between when they were notified of the vessels impending arrival and when the landed in Valdez. Coast Guard Lt. Cmdr. Walner Alvarez, head of the Valdez Marine Safety department, said the foreign tankers must send a Notice of Arrival at least 96 hours before entering U.S. waters. From there, the requirements for them to call on Valdez are virtually identical to those for domestic vessels, he said. “Every vessel that comes into the U.S., or pretty much any other country that is a signatory to SOLAS; they have to abide by these international standards,” Alvarez said. SOLAS, or Safety of Life at Sea, is the set of operating standards agreed to by countries in the International Maritime Organization. Alvarez said of the many SOLAS requirements, one eliminates the potential of a language barrier. All crewmembers aboard international sailing vessels need to be able to communicate in a common language. The IMO recognizes three working languages — English, French and Spanish — for vessels flying flags of its participating countries. Schantz said a primary concern of the council was making sure the Tianlong and Cascade had the necessary bitts and chocks and other equipment for connecting to tugs. Since 2010, every tanker traveling in and out of Valdez must get a double-tug escort. It is her understanding that both vessels had to be equipped with new tow packages for their trips to Prince William Sound. “From what I understand there was a lot of conversation between Alyeska (Pipeline Service Co.), BP and the tanker crew to make sure there was an understanding of the process and procedures here, the escorting process, docking the tanker over at the terminal, basically the procedures for navigating ice from Columbia Glacier, just overall communications,” Schantz said. “It sounded like there was a lot of scrutiny on these ships by both the Coast Guard, Alyeska, the (Alaska) Department of Environmental Conservation and I feel like there was fairly good communication with us in terms of what was happening.” Alyeska spokeswoman Michelle Egan said the terminal operating company was mostly focused on making sure the vessels had the proper equipment to dock and take oil once they arrived. In a statement, BP emphasized that the ships met every state and federal requirement. “Our first priority is to safely operate the tanker(s) in compliance with the strict shipping rules and regulations,” a BP spokeswoman wrote. Before docking in Valdez, every tanker, foreign or domestic, must have a state marine pilot on board, Coast Guard Vessel Traffic Service Director for Prince William Sound Lt. Ben Bauman said. The pilots are there to provide localized advice to the vessel crews. “The same guy that’s coming on board these foreign vessels has seen this operation hundreds of times, most likely, on a domestic vessel, so from that perspective it shouldn’t look any different,” Bauman said. The marine pilots in Prince William Sound are from the Southwest Alaska Pilots Association, the same organization that guides ships in and out of Cook Inlet. Schantz said advisory council staff will brief the group’s board of directors on the procedures for foreign tankers at its Sept. 15 meeting in Cordova. “I think what’s in place today is a lot safer than it was before the Exxon Valdez oil spill, but at least from the citizens’ council, as long as there’s tankers taking oil out of Valdez you’re never going to completely eliminate the risk. There’s always that concern of having crews that maybe have never been in our waters and I think at least the citizens’ council probably has more concerns than other folks do with that,” Schantz said. “What we go by is ‘trust but verify.’” Elwood Brehmer can be reached at [email protected]

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