Elwood Brehmer

‘Aggressive’ timeline for AK LNG needs one year for permitting

State gasline officials have made headway of late with potential buyers and investors in the Alaska LNG Project, but progress on the regulatory side has been harder to come by. The Alaska Gasline Development Corp. filed an environmental impact statement application with the Federal Energy Regulatory Commission, or FERC, for the $43 billion project in mid-April. At nearly 60,000 pages, AGDC leaders said they believed it to be the largest EIS filing in the history of the National Environmental Policy Act process, which became the federal permitting standard in 1970. The size of the EIS filing could end up being a mixed blessing for the project. The 13 exhaustive resource reports that comprise the bulk of the material are the end product of the $600 million the state, BP, ConocoPhillips and ExxonMobil spent evaluating the project during the preliminary front-end engineering and design, or pre-FEED, period, when the companies were equity partners with the state. That arrangement ended last year as the producers handed off the lead role to the state as global LNG prices bottomed out. AGDC emphasizes that the massive filing illustrates the comprehensive nature of the pre-FEED work and limits regulators’ needs for supplemental information; that should help speed the EIS along. President Keith Meyer is targeting a final investment decision on the Alaska LNG Project by early 2019, and, as a result, a record of decision on the EIS by the end of 2018, which he acknowledges is “aggressive.” However, whether AGDC’s regulatory timeline is feasible is still an unanswered question simply because of the project’s size and the need for statutory public comment periods. Also, the municipally-owned Alaska Gasline Port Authority has urged FERC to evaluate routing the Alaska LNG Project to Valdez as opposed to AGDC’s planned Nikiski terminus, but how much consideration the request will receive and how that could affect the EIS timing is also unknown. FERC is generally regarded as one of the most expeditious federal agencies when it comes producing environmental permits but has yet to publish a schedule — which is fungible regardless — for the EIS. Meyer said AGDC can still sign the many binding commercial agreements it needs for the project before FERC issues its record of decision; those agreements would just need clauses indicating they are contingent on a favorable decision from regulators. “If we don’t (get a decision in time) we can deal with it,” he said. AGDC regulatory Vice President Frank Richards wrote a letter to FERC commissioners Nov. 16 requesting, among other things, that the commission publish the Alaska LNG schedule by Dec. 15. AGDC leaders originally hoped FERC’s timeline would be published sooner. “The issuance of a schedule will provide valuable assurance to the market that the regulatory process, and particularly commission review of Alaska LNG, is on track and consistent with Alaska LNG’s (2025) targeted in-service date,” Richards wrote. He said during the corporation’s Dec. 7 board meeting that AGDC is hopeful a final EIS is published by mid-2018 to stay on its desired timeline. Meyer and Richards have stressed the support the project has received from Trump Administration and actions the White House and federal agencies have taken to streamline infrastructure permitting, but to get there it seems FERC would really have to get moving soon. EIS public scoping meetings to determine what all regulators should evaluate were held in late 2015 under the former ExxonMobil-led project structure. The next major step under a standard EIS development would be for FERC to issue a preliminary draft EIS for cooperating federal agencies to review and comment on. Subsequent to that, the resulting draft EIS would be issued, initiating a public comment period of at least 45 days — on very large or contentious projects it is often longer — and associated public meetings. FERC would then respond to the appropriate comments and incorporate them into the final EIS publication, after which a minimum 30-day waiting period must be held before a record of decision on the project is reached. Richards also asked FERC to publish the schedule before getting responses to all of its questions in his Nov. 16 letter, noting the commission could adjust the schedule if AGDC is too slow in responding to stay on track. His team has responded to 584 of FERC’s 801 questions and requests for additional data stemming from the application filed in April as of the Dec. 7 meeting, Richards said. AGDC was waiting for questions on the last of the 13 resource reports at that time as well. Additionally, he urged FERC to adopt or otherwise incorporate the supplemental EIS that the U.S. Army Corps of Engineers is in the midst of finalizing for the smaller $10 billion Alaska Standalone Pipeline, or ASAP, project and defer to the Corps on wetlands issues. “The Alaska District of the Corps of Engineers has regulated the construction of infrastructure projects through Alaska’s continuous and discontinuous permafrost for many decades, and construction planning in Alaska has centered on the application of the Corp of Engineers’ guidance,” Richards wrote. He continued: “The commission should rely on the experience and expertise of the Alaska District of the Corps of Engineers and require a duplicative demonstration justifying a waiver of the Office of Energy Projects’ wetlands procedures. If not waived, these procedures will have a significant impact on project construction planning, schedule and cost.” Such a waiver would lift wetlands construction and mitigation requirements from FERC’s Office of Energy Projects that are more restrictive than those the Alaska District of the Corps uses, according to Richards. AGDC notes the pipeline corridors for Alaska LNG and ASAP are virtually identical and therefore evaluation of the route does not need to be duplicated. The primary differences in the two pipelines is the line for the ASAP project, meant for in-state gas use, is 36 inches versus the 42-inch Alaska LNG pipe and would stop near Big Lake in the Matanuska-Susitna Borough. The Alaska LNG line would continue south, cross beneath Cook Inlet and end at the LNG plant in Nikiski. Experts have said EIS for the Alaska LNG is basically three separate evaluations in one document; one each for the North Slope Gas treatment plant, the pipeline and the Nikiski plant. ASAP decision delayed While AGDC wants FERC to use the Corps’ ASAP work, the Corps added public meetings to the supplemental EIS for ASAP and thus has pushed back its schedule for issuing a decision on the backup gasline project to July, according to Richards. Prior to the adjustment AGDC had been expecting a final supplemental EIS in December with a record of decision in March. In late 2012, the Corps approved an EIS for a smaller version of ASAP with a 24-inch pipeline but when the state upped the size of the proposed gasline to 36 inches, the Corps determined differences between the in-state plans — changes to the gas conditioning modules, a North Slope barge dock, pipeline route and a smaller overall footprint with fewer pipeline compressor stations — necessitated an SEIS. The draft SEIS was once expected to be out in mid-2015 but wasn’t published until July of this year. Yukon designation pulled In an unsurprising move, the Environmental Protection Agency’s Region 10 has dropped its push to designate the Yukon River an aquatic resource of national importance, or ARNI, as it relates to the ASAP project. EPA Region 10 officials wrote a letter to the U.S. Army Corps of Engineers Alaska District in late August detailing the agency’s concerns with AGDC’s approach to building the ASAP project through wetlands in the Yukon watershed. Roughly half of the 737-mile pipeline corridor is through the massive river drainage. They did not feel AGDC’s compensatory mitigation plan for filling wetlands in the Yukon drainage was sufficient. Gov. Bill Walker responded with an early October letter to EPA Administrator Scott Pruitt contending Alaska’s wetlands — 43 percent of the state’s acreage — are so vast “it would not be practicable, nor environmentally justifiable, for this project to mitigate for all wetland impacts along the entire pipeline route.” Region 10 officials did not send the Corps a second letter as called for under the 1992 agreement between the agencies that established the process for designating an ANRI, rendering the issue moot, according to Richards. Also, Walker’s former Commerce Commissioner Chris Hladick took over as Region 10 administrator earlier this month after being appointed to the post by Pruitt in October. Elwood Brehmer can be reached at [email protected]

AIDEA approves deal with gas utility for Interior Energy Project

The Interior Energy Project is finally on its way to Fairbanks. After nearly five years of analysis, negotiations, debate and a wholesale route change, the Alaska Industrial Development and Export Authority on Dec. 7 transferred control of the project to the Interior Gas Utility. The IGU is owned by the Fairbanks-North Star Borough and will take over the plan to expand natural gas use in the area. Transfer of the unfinished project mostly means handing off the responsibility to fulfill the $331.2 million development plan the two organizations jointly crafted to complete the IEP. It also includes the $54 million sale of Pentex Alaska Natural Gas Co., which, through Fairbanks Natural Gas and its other subsidiaries, is already trucking Cook Inlet-sourced LNG to supply its group of customers in the core of Fairbanks; the IEP builds on that model. The AIDEA board of directors previously approved the IEP plan and Pentex sale Oct. 26, but technical changes to the finance agreement meant the AIDEA leaders had to approve the amended document again. The Interior Gas Utility board approved the deal Dec. 5. The two first signed a memorandum of understanding establishing the framework of the deal about a year ago. While the MOU first set a deal deadline date of March 31, 2017, it was extended to allow negotiations to continue and give AIDEA project officials time to secure a new gas supply contract needed to support the other aspects of the plan. AIDEA announced success on the gas contract in September. “This represents the culmination of nearly a year of in-depth due diligence and negotiations between ADIEA and IGU. AIDEA welcomes this approval of the sale and financing package that we anticipate will create a unified, locally controlled gas utility for the Interior by next spring,” AIDEA board chair Dana Pruhs said in a formal statement. The Regulatory Commission of Alaska must still approve the agreement by May 31, at which point AIDEA and IGU can officially close the deal. Until then, AIDEA’s lead IEP manager Gene Therriault said the authority will continue to advance the plan under the terms of the MOU while getting concurrence from IGU on all decisions. When the deal closes the authority will resume its more normal role as a financier and loan administrator, Therriault said, adding, “AIDEA will be involved (in the IEP) if and when IGU needs to access bonds.” Additional gas is expected to start flowing from the expanded LNG trucking plan sometime in 2020. AIDEA and Gov. Bill Walker absorbed criticism from some Republican lawmakers in the state when the authority worked out a deal to buy Pentex from its private investors in January 2015. Critics argued it was inappropriate for a state entity to buy the one private utility that had managed to do what the IEP proponents wanted — albeit on a smaller scale and at a higher cost to customers — and ostensibly killed the prospect of a private sector-generated solution to Fairbanks’ energy problems. However, AIDEA leaders contended the move was intended to facilitate consolidation of Fairbanks Natural Gas and IGU to avoid duplicative costs and achieve the operational efficiencies possible through running one utility versus two in a relatively small service area. Some also noted the call for a private solution to Fairbanks’ energy needs had gone unanswered for decades and AIDEA’s purchase of Pentex was the state’s attempt to fix what was for years a problem of high-cost fuel oil and has morphed into primarily an air quality quandary. Fairbanks Natural Gas CEO Dan Britton has long said his utility repeatedly tried to expand its service but could not secure a long-term gas supply contract from Inlet producers to do so. In 2013, leaders of the utilities sparred in front of the RCA over service territory rights for the areas surrounding FNG’s existing business in the core of Fairbanks. The RCA ultimately sided with IGU; setting up the scenario where two gas utilities would operate in the Fairbanks area. Also in the spring of 2013, the Legislature approved a $332.5 million package of grants, loans and bond financing to spur the IEP and tasked AIDEA with managing it. The legislation included a requirement for North Slope-sourced natural gas. At the time there were fears of a gas shortage in Cook Inlet, which drove gas prices higher and left no gas available for the Interior at a viable price. Through much of 2013-14, AIDEA evaluated the feasibility of a North Slope LNG plant to capture potential savings afforded the IEP by cheaper Slope feedstock natural gas. However, the high cost of building on the Slope forced AIDEA to scrap the plan late in 2014 and falling oil prices — a mixed blessing for the project — gave Fairbanks-area residents a reprieve from high fuel oil prices and project leaders additional time to review alternatives. They eventually turned south for a solution as the Southcentral natural gas market stabilized into 2015 and lawmakers agreed to open the IEP financing legislation to an Inlet-sourced option. The pending deal between ADIEA and IGU is the culmination of the second try at the IEP. The structure of the financing exemplifies the complex nature of the project and the unavoidably challenging economics it must overcome. Anatomy of the deal IGU will buy Pentex for the $54 million AIDEA spent on the utility company in 2015, but the purchase also includes the interest ADIEA is required by law to recoup on its in-house investments. Therefore, the final price will be closer to $59.6 million, according to the financing agreement. AIDEA bought Pentex with funds from its own Revolving Fund and did not use the state IEP funds it was given management of in 2013. Currently a start-up utility with no customers or revenue, IGU will use $42.4 million of state IEP grants and other low-interest project loans, which AIDEA now holds and will supply the utility, to buy Pentex. Buying the working utility will also give IGU a revenue stream it can leverage to finance the gas supply and distribution infrastructure buildout set forth in the agreement. The infrastructure financing will also come from the state through AIDEA in the form of about $83 million in Sustainable Energy Transmission Supply Fund loans and $150 million of state-backed bonds. The 50-year loans will be used more as an active line of credit IGU can call upon when needed and defers interest and payments for 15 years after which a 0.25 percent interest rate kicks in. According to AIDEA, IGU can also defer principle payments on the SETS loans if future gas demand doesn’t meet expectations. AIDEA leaders have also been criticized for continuing ahead with a project that needs such favorable financing terms to work. While lower oil prices eased heating fuel prices for Interior consumers, it also meant lowering expectations about how many residents and businesses would make the personal investments needed to convert from fuel oil to natural gas heating systems. It should also be noted that AIDEA — with it expertise in financing and investing in projects above managing them — is complying with its directive from the Legislature in keeping the IEP alive. Doyon offers gas alternative On Nov. 28, Doyon Ltd., the Alaska Native corporation for the Interior region, announced via press release its plans for next summer to drill another oil and gas exploration well in the Nenana area it has been exploring for a decade. A significant gas find near Nenana could be a long-term energy solution for Fairbanks because it is only about 60 miles from the city. Doyon leaders noted as much in their press release, calling it “unfortunate timing” for IGU and AIDEA to commit to their IEP plan. Doing so straps IGU to the $46 million Southcentral LNG plant expansion, $52 million Fairbanks LNG storage and regasification facilities and associated LNG tankers and trucks at least until the state loans on the infrastructure are paid off decades later, Doyon Natural Resources Vice President Jim Mery said in an interview. That, in turn, discourages IGU from buying gas from other sources in the future that could include a North Slope gasline or Nenana if a discovery is made, he said. An AIDEA spokesman noted the gas supply contract recently inked with Hilcorp only runs through 2020 at the request of IGU leadership on the hope the utility can secure a more favorable contract once the is system proven and in place. Doyon has drilled three exploration wells in the Nenana basin with mixed results. While the company is targeting oil first, a 2013 well hit substantial zones of gas-saturated reservoir rock and if not for a faulty geologic trap could have been a commercial find, according to Doyon leaders. Most recently, a well drilled in the summer of 2016 was unsuccessful. IGU General Manager Jomo Stewart said in an interview that the utility wants Doyon to be successful; he emphasized the notion that the LNG trucking portion of the IEP is a placeholder until another gas source is available. “This was always envisioned as a starter project meant to get more gas here. You’re building infrastructure so people could access gas, but then create the utilization of that infrastructure through expanded deliveries of gas,” Stewart said. More than $140 million of planned expenses in the overall project are for gas distribution infrastructure — street-level gaslines for residents and businesses to tie into — regardless of supply source, according to the financing document. Stewart also said the refined designs of today’s small LNG plants makes them mobile enough to be relocated to where they are needed most. “It’s not as simple as backing up tractor-trailers, unbolting and driving away, but it is modular enough that it could be relocated,” he described. “Under a large volume scenario, particularly via pipeline, the expectation is that you could be able to take this LNG facility — you would move it to Fairbanks — the gas to the consumer would go directly into the pipelines that feed the consumer, but you would also have a line that would go to this LNG facility and you would use this LNG facility as peaking capacity and (gas) security.” It could also be used in conjunction with the 5.2 million-gallon LNG storage tank planned for Fairbanks to supply other road system communities that are out of economic reach of a large gasline, Stewart noted, in much the same way the smaller Southcentral plant is currently used for Fairbanks. AIDEA leaders have discussed the possibility of such a scenario, but it is still a hypothetical one. Finally, Stewart said the IEP plan, even if the infrastructure stays put, only feeds the most densely populated areas of Fairbanks and North Pole and additional gas from any source could supply many more customers in the region. Elwood Brehmer can be reached at [email protected]

AGDC gets interest from Tokyo, questions from lawmakers

Legislators got their first chance to publicly question Alaska Gasline Development Corp. officials about a recent agreement with Chinese companies to advance an LNG export project during a Dec. 4 hearing. Meanwhile, AGDC executives in Japan were busy putting the finishing touches on the state-owned corporation’s latest pact to cooperate on developing the $43 billion Alaska LNG Project with potential customers. Shortly after AGDC President Keith Meyer told the House Resources Committee and other legislators in attendance that his team was close to signing a letter of intent with Tokyo Gas Co., the corporation issued a release announcing just that. “Tokyo Gas and Alaska have a special relationship in LNG and I was pleased to host (company President Michiaki) Hirose for meetings and a project update in Juneau this past August to help continue that kinship,” Gov. Bill Walker said in an official statement. The Japanese utility, with more than 11 million customers, was itself a customer to ConocoPhillips’ Kenai LNG plant, which first exported to Japan in 1969. The plant has seen little use in recent years as down prices globally have challenged the competitiveness of Cook Inlet-sourced LNG. “Alaska is a trusted source of LNG. For more than 40 years Tokyo Gas Co. Ltd. received shipments of LNG from Alaska. As the closest source of North American LNG to Japan, with a shipping time of as little as seven days point to point, Alaska LNG is naturally an economic and reliable source of LNG for Tokyo Gas Co. Ltd.,” Hirose said, reiterating AGDC talking points, in the release. The letter of intent is for the sale and purchase of LNG but it also includes a commitment by Tokyo Gas to look at other ways to support the Alaska LNG Project, according to AGDC. Corporation leaders have stressed the distinctions between how its different agreements with potential gas customers and project investors are characterized, highlighting the fact that the Asian utilities and companies AGDC has targeted follow a prescribed schedule in the courtship and very rarely back out from a letter of intent. Spokeswoman Rosetta Alcantra wrote in an email that the Tokyo letter sets the basic principles for the two to “collaborate on exploration of potential purchase of LNG from AGDC; and to evaluate other opportunities to advance Alaska LNG.” That includes potential upstream investment. It is a nonbinding agreement. How the letter differs from the joint development agreement signed Nov. 9 with three giant nationalized Chinese companies or memorandums of understanding with PetroVietnam Gas Corp. and Korea Gas Corp. is unclear. Walker and Meyer said in a press call after announcing the China development agreement that it went beyond the significance of a letter of intent because it involves all parties needed to put the project together — Sinopec, the gas buyer; the Bank of China, a project lender; and the China Investment Corp., an equity investor. The joint development agreement, released by Walker’s office, is a nonbinding document that expires Dec. 31, 2018. AGDC has kept the other letters of intent and memorandums of understanding confidential, citing business considerations in the highly competitive LNG industry. The Legislature afforded AGDC the right to keep its deals private in the 2013 legislation that made it a standalone entity. AGDC was originally a branch of the Alaska Housing Finance Corp. Questions on price, dealing with China Legislators’ questions in the Dec. 4 hearing largely focused on Chinese involvement in the Alaska LNG Project should the joint development agreement come to fruition and whether the North Slope producers are on board with the state’s expectations for the project. AGDC’s Meyer has long said Gulf Coast LNG projects are Alaska’s primary competitors in Asian import markets because of the continued low cost of Lower 48 Henry Hub indexed feedstock natural gas and political pressures that have killed LNG export plans in Canada and Oregon. LNG can be produced and delivered to Asia from Texas and Louisiana for about $8 per million British thermal units, or mmBtu, the standard unit measurement in the industry, according to AGDC. That is assuming a generally static Henry Hub price of roughly $3 per thousand cubic feet, or mcf, of raw gas. One mmBtu of LNG is roughly equivalent to 1 mcf of unprocessed natural gas. Meyer said liquefaction, shipping and other costs total about $5 per mmBtu to deliver Gulf LNG for a minimum customer cost of $8 per unit. While Alaska’s proximity to East Asia makes LNG shipping costs from the state about one-third of that from the Gulf Coast and colder temperatures improve liquefaction efficiency — meaning less gas must be burned to produce the LNG — the cost of the 800-mile pipeline off the Slope is the big cost snag. AGDC estimates the 42-inch pipeline will cost about $8 billion in the larger $43 billion project. As a result, the bundled costs to deliver Slope-sourced LNG to any of AGDC’s prospective customers is about $7 per mmBtu, leaving a $1 netback to the producers for their gas if the project is to compete, Meyer described. He acknowledged the $1 per mcf price is what’s “left over” after accounting for other costs if trying to meet the $8 delivered price threshold, but added the method to arrive at the wholesale gas price is more common in the industry than not. The Lower 48, where gas exported as LNG is priced based on a market index, is the exception, he added. “All these producers deal with a netback throughout the world,” Meyer said. “It’s the standard.” Anchorage Republican Rep. Lance Pruitt asked whether BP, ConocoPhillips and ExxonMobil were on board with the $1 per mcf for gas. Meyer said the producers have not committed to the plan but haven’t rejected it either in preliminary discussions. The $1 per thousand cubic feet price equates to about $1 billion per year for gas, given the project would process about 1 trillion cubic feet per year at full production. “I think we’re going to find that $1 billion a year upstream, compared to nothing, looks pretty good,” Meyer commented. LNG contracts have historically been linked to the price of oil and he said Alaska LNG deals could as well if both sides are comfortable with market volatility. Pruitt and other legislators also noted the state would get about 25 percent of each $1 through its royalty and presumed taxes on the gas. ConocoPhillips still supports the Alaska LNG Project and is in negotiations with AGDC but pricing and numerous other terms have yet to be finalized, according spokeswoman Natalie Lowman. ConocoPhillips Alaska leaders have said the company would prefer to sell its North Slope gas reserves into the Alaska LNG infrastructure and not take a larger role in the state-led project. Similarly, BP spokeswoman Dawn Patience said via email that the company looks forward to better understanding the role of gas owners, such as BP, in AGDC’s customer agreements. Also, AGDC and BP have extended an agreement for the producer to assist the state corporation in developing the project, she added. That agreement, signed about a year ago, is set to expire Dec. 31. Rep. Dan Saddler, R-Eagle River, questioned China’s possible involvement beyond financing and buying LNG, asking if Sinopec would get construction jobs on the project. Meyer said the oil and gas giant won’t have majority involvement, noting some labor will have to come from outside of Alaska simply because the state does not have the workforce to fill the 10,000-plus jobs that will be available. A large construction management firm will oversee the 800 miles of work but smaller Alaska subcontractors will certainly get a lot of work, he said. “I would expect Alaska contractors to have a degree of priority,” he added. Saddler and Palmer Republican Rep. DeLena Johnson also wanted to know if the administration is comfortable working with a communist regime with a long history of human rights violations. “On a moral basis, does it bother you to be dealing with China?” Saddler asked. For his part, Meyer reminded legislators that the country is already the state’s largest export customer; it bought 27 percent of Alaska’s $4.4 billion of exports last year. About half of it was seafood. “This is an extension of that relationship,” he said. Meyer has emphasized the LNG would help China move off of coal as well. He also said the LNG trade could be a tool to improve the country’s geopolitical position because it’s a critical commodity. Pruitt said he’s not concerned about partnering with China but is worried about “what seems like China coming in and letting them own our state.” Meyer stressed that there is no scenario under which the Chinese will have majority ownership in the project; AGDC is looking for up to 25 percent equity investment. “They’ll be a good customer, a good partner, but they’re not going to have a controlling interest,” he said. Pruitt and Saddler sit on the House Finance Committee but were invited to participate in the Resources meeting. Elwood Brehmer can be reached at [email protected]

ANWR clears Senate, Young named to conference panel

The northern edge of the Arctic National Wildlife Refuge is almost open for business after some late maneuvering by Sen. Lisa Murkowski. With the inclusion of Murkowski’s provision to open the ANWR coastal plain to oil exploration in the Senate’s tax reform bill, the Alaska congressional delegation is as close as it has ever been to what would be a landmark victory for the Republicans. In statements following the Senate’s Dec. 2 early morning vote, they described it as a way to jumpstart Alaska’s economy and improve national security by producing more oil domestically. However, it took some last-minute technical adjustments to specific language in the ANWR legislation to keep it viable, which also led to Murkowski having to do an about-face on a longstanding policy stance. The issue arose during initial Senate floor debate on the tax bill Nov. 30, when the Senate parliamentarian deemed the language relating to the regulatory steps needed before holding an ANWR lease sale required consideration from the Environment and Public Works Committee and not just the Energy and Natural Resources Committee chaired by Murkowski. Specifically, the original language directed the Interior Secretary to manage ANWR lease sales under the 1976 Naval Petroleum Reserves Production Act — the law that transferred what is now the 23 million-acre National Petroleum Reserve-Alaska from the Navy to Interior — and follow the requisite regulations. Because an environmental impact statement is required to put together a management plan and hold lease sales in the NPR-A, the decision to lease the coastal plain should’ve also gone through Environment and Public Works, the parliamentarian concluded. Murkowski’s Energy and Natural Resources Committee had been the only non-Budget committee tasked with reviewing her proposal to generate at least $1 billion in deficit-reducing revenue over the next 10 years. The Budget Committee’s directive to find the $1 billion was a nod to Murkowski to introduce the ANWR option as part of the tax bill that needed only a simply majority vote and not meet the filibuster-proof, 60-vote threshold standard for non-budget legislation. The revised language broadened the ANWR management guidelines away from the indirect National Environmental Policy Act reference to “a manner similar to” how NPR-A sales are managed, but Sen. Dan Sullivan said in Dec. 1 press briefing that the technical correction doesn’t eliminate the NEPA process prior to holding ANWR lease sales. In floor debate, Murkowski said the extensive oil production on nearby state lands is proof that Arctic oil development can be done with minimal environmental impact, a point proponents of opening the coastal plain have often made. “Environment and local wildlife will always be a concern, that’s why we didn’t waive NEPA,” she said. Democrats argued that Murkowski’s legislation ostensibly renders environmental reviews of ANWR leasing meaningless because it states the Interior secretary “shall” hold two lease sales, each offering at least 400,000 acres of the 1.5 million-acre coastal plain, regardless of what the reviews conclude. The technical wording change did, though, create uncertainty over what exactly the regulatory process would entail and whether the lease sales would still generate the $1 billion. To offset that, a 5 million-barrel sale from the Strategic Petroleum Reserve authorized in the Energy Committee rider was upped to 7 million barrels on the Senate floor. A Strategic Petroleum Reserve oil sale — something Murkowski had previously been steadfastly against — was first approved in the Energy Committee Nov. 15 as an add-on amendment by Louisiana Republican Sen. Bill Cassidy. He asked for the oil sale amendment to offset his proposal to appropriate $300 million more to Gulf states through the Land and Water Conservation Fund in 2020 and 2021. Murkowski voted for the amendment, which passed out of her committee on a party-line vote, saying the increased revenue to states would help them mitigate the impacts of offshore oil and gas activity. The Land and Water Conservation money is derived from offshore lease revenue and Cassidy said the extra $300 million would go back into restoring damaged coastline. His amendment capped the oil sale at either 5 million barrels or no more than $325 million in revenue. When the Senate voted on the tax bill, the sale limits had been increased to 7 million barrels or up to $600 million to the Treasury; however, Cassidy’s Land and Water Conservation Fund appropriation did not grow. In 2015 Murkowski opposed a Strategic Reserve sale to help pay for a federal highway bill. A Senate Energy Committee press release at the time stated: “Murkowski has long cautioned against calls to sell crude oil from the reserve to pay for unrelated legislative initiatives” because she considers it a “vital national security asset.” Spokeswomen for Murkowski did not respond to questions regarding her stance on the oil sales from the SPR. The ANWR provision isn’t home free quite yet, as it was not in the House version of the tax bill. Therefore it must be approved in a conference committee, which is expected to resolve the differences in the House and Senate bills before the holiday break. Rep. Don Young, picked by House Speaker Paul Ryan Dec. 4 to sit on the tax bill conference committee, said in a statement that there is still a lot of work left for the delegation in its effort to maximize Alaska’s energy resources but he is looking forward to securing a final victory on ANWR. “It’s been over 40 years since this battle began — a generations-long battle that is finally coming to a head,” Young commented. “I thank Speaker Ryan and the House leadership for recognizing my role in this important debate and for entrusting me to be part of the effort to craft an agreement that will positively improve the lives of Alaskans and Americans for generations to come.” While Republicans hold a 240-194 majority in the House, 12 of them sent a letter on Nov. 30 to Ryan and Senate Majority Leader Mitch McConnell pleading for the refuge’s protection. They cite legacy bipartisan support for leaving ANWR intact since Republican President Dwight Eisenhower established its predecessor area in 1960. The Republicans further note the oil under the coastal plain is not worth the troubles likely to accompany it. The U.S. Geological Survey’s mean estimate for oil in the coastal plain is about 7 billion barrels of technically recoverable reserves. In May, Interior Secretary Ryan Zinke ordered the USGS to update the rough 1998 estimate. “If proven, the estimated reserves in this region would represent a small percentage of the oil produced worldwide,” the House Republicans wrote. “Moreover, the likelihood that lawsuits would accompany any development is high. Business-savvy oil companies are more likely to turn to the National Petroleum Reserve, a 23.5 million (acre) area in northwest Alaska specifically allocated for energy development, which is closer to infrastructure and significantly less controversial.” The letter concludes with the representatives stating that on behalf of their constituents they “look forward to working with (Ryan and McConnell) to maintain this longstanding balance that protects and preserves the refuge’s incredible natural resources and wildlife habitat and allows for responsible American energy development elsewhere.” Native corporations, CDQ provisions The final Senate tax bill would also included a deduction for Alaska Native corporations, but an amendment for Western Alaska fishing groups did not make it. Under the bill, Alaska Native corporations would be allowed to deduct either cash payments made into settlement trusts or the market value amount of land contributed to such a trust in the year the contribution was made. The legal and financial implications of putting Native lands into trusts have generally not been an issue until recently as it hasn’t been a common practice. Over the last couple years the Alaska Department of Law in Gov. Bill Walker’s administration has worked to clarify the process for putting Tribal lands in the state into trust status to provide an avenue for Alaska Native Tribes wishing to do so. Nonprofit Bering Sea fishing groups, on the other hand, did not get the clarification they were looking for in the tax overhaul. The six Community Development Quota groups established in 1992 by the North Pacific Fishery Management Council were hopeful the Alaska delegation would be able to add a provision noting the income received from their subsidiary companies is tax-exempt. The CDQ program was intended to be a way to increase local ownership in Bering Sea fisheries. Collectively, the six nonprofit CDQ groups representing 65 communities within 50 miles of the Bering Sea coast receive 10 percent of the annual total allowable catch in most of the fisheries. The profits derived from the harvest quota the groups own is supposed to be invested into economic development programs in their regions. Norm Van Vactor, CEO of Bristol Bay Economic Development Corp., said he is disappointed the tax-exempt language didn’t make the Senate bill, but added that the delegation has assured the groups it is a priority they will keep working. “Everything we do flows back to our communities, so we stressed to (Murkowski) that this provision would be very helpful towards securing our future,” Van Vactor said. The Aleutian Pribilof Island Community Development Association got a private letter ruling from the Internal Revenue Service in 2014 stating subsidiary income derived from fish harvests is not taxable, but BBEDC has taken a more conservative stance and thus has led the push to get the clarification in law, according to Van Vactor. Being on solid tax ground would make it easier for the groups to purchase additional shares of quota from individual quota holders getting out of fishing and turn that into more community investment without the worry about tax implications, he said. “We just want real clarity that our understanding is in fact what the IRS intends because we don’t want to do anything at all that at a later date might come under scrutiny or jeopardize the investments that we might otherwise make,” Van Vactor described. Elwood Brehmer can be reached at [email protected]

Ahtna subsidiary gets reduction in huge fine at Tolsona well

(Editor's note: This story has been updated to include a response by Ahtna Inc.) State regulators substantially reduced the penalty issued to an Ahtna Inc. drilling subsidiary to $92,000 in a final order issued Wednesday morning after company leaders admitted to the gas well violations and rectified them. The Alaska Oil and Gas Conservation Commission initially imposed a fine of $380,000 on Tolsona Oil and Gas Exploration LLC in late May for the company’s prolonged failures to install pressure gauges on its natural gas exploration well, monitor the well casing pressure and to even respond to repeated demands by the commission to do so. The wholly-owned Ahtna subsidiary spudded the Tolsona-1 well near Glennallen in September 2016, but technical challenges with the 5,500-foot well led the drilling to take about 54 days, according to Ahtna, about twice as long as originally expected. By mid-December, the company was preparing to suspend the well when pressure began to build between inner well casings. Tolsona notified the AOGCC of the issue, bled the pressure and the commission required the company to monitor the pressure for four weeks, according to the order. In January, the commission further required Tolsona to install a pressure gauge on an outer well casing and similarly report monthly pressure readings. The company said in February it would meet the requirement. However, Tolsona officials did not follow through with the pressure reports or return subsequent emails and phone calls from the commission. That led the AOGCC to issue a proposed enforcement action in mid-April, to which the company again didn’t respond. As a result, the AOGCC issued the $380,000 proposed penalty May 24. The Alaska Oil and Gas Conservation Commission is a technical state regulatory body responsible for oversight of subsurface oil and gas activity. Ahtna did not dispute the commission’s timeline of events during a Sept. 12 hearing on the matter. Tom Maloney, CEO of Ahtna and Tolsona, said at the time that the company manager responsible for the project never relayed issues to him, despite the fact that the two communicated daily. According to the documents, Maloney called the commission May 25 and said the company had not received the enforcement notice and the commission sent copies to him. Tolsona installed the outer pressure gauge June 1. Maloney apologized to the three-member commission at the Sept. 12 hearing for the company’s errors and said an internal investigation revealed problems in its communication chain, which have been rectified. Brewster Jamieson, an attorney for Ahtna, also said at the hearing that because the company was not “simply blowing the commission off” and leaders didn’t know about the problems the fines were excessive also not in line with similar previous cases. The original fines were $10,000 for not installing the pressure gauge and another $10,000 for not submitting the first pressure report in March. Additional fines of $5,000 per day were levied for each of the 50 days the gauge wasn’t in place before the April enforcement notice and $5,000 per day for each day the pressure report was past due. The final $92,000 penalty includes both the $10,000 fines for the initial violations but the accumulating daily penalties were reduced from $5,000 to $1,000 per day. “Tolsona’s demonstrable disregard for regulatory compliance precludes any finding that it acted in good faith,” the final order states. “The unmonitored over-pressured annulus is deemed a serious violation which poses a serious and significant risk to public health. Although there was no injury to the public, the seriousness of the violation, the absence of any effort by Tolsona to correct the violation and the need to deter such behavior weigh strongly in the penalty imposed. “However, the steps Tolsona has taken to ensure compliance with AOGCC regulations on future work, and Tolsona’s statement that it plans to plug and abandon the Tolsona-1 well, warrant reduction of the proposed civil penalties.” The company has 30 days to appeal the ruling to the Alaska Superior Court but issued a statement Thursday morning saying it "appreciates the substanital reduction in penalties from the AOGCC and does not plan to appeal the penalty." "We are proud that the Tolsona project delivered a perfect safety record, provided a boost to the local and statewide economy, created new employement opportunities for Ahtna shareholders and Alaskans, and that we were able to reach and evaluate the targeted zone," the Ahtna statement continues. "We are actively pursuing additional gas exploraiotn opportunities with operators on Ahtna lands in the Copper River basin." Elwood Brehmer can be reached at [email protected]

Doyon keeps up Nenana drilling; touts gas alternative to Cook Inlet

Doyon Ltd. is sticking with its oil and gas exploration program near Nenana. Despite past challenges, the Interior Alaska Native regional corporation announced Nov. 28 that it plans to drill another exploration well in the frontier basin west of Fairbanks next summer. The Totchaket-1 well will be drilled based on the results of a 64 square-mile 3D seismic program shot early this year, according to a Doyon release. Company leaders think their years of exploration around Nenana are close to paying off. “We are especially excited about the recent seismic results because for the first time in this basin we see trapped hydrocarbons,” Doyon CEO Aaron Schutt said in a formal statement. “This could be a game-changer.” Doyon has drilled three exploration wells in recent years on the roughly 240,000 acres of state leases it holds in the area and conducted several seismic shoots. The Native corporation also owns land around Nenana. The results of that drilling have mixed. A well drilled in 2016 did not turn out to be successful, but one drilled in 2013 hit several hundred feet of natural gas-saturated sandstone, according to company officials. If not for a faulty geologic trap, Doyon believes it could’ve produced up to 180 billion cubic feet of gas, or bcf, from the formation and potentially supplied the Fairbanks market for decades. Doyon Vice President Jim Mery said the trap was full of water and the gas in place was under pressured as a result of the fault. “We think the building blocks have been there and that’s why we’ve kept at it. We learn from every project and it informs us as to what we should do next,” Mery said. The Totchaket well will be drilled to 12,500 feet and be about 20 miles north of Nenana and on the east side of the Tanana River, according to Doyon. Prior drilling was done closer to Nenana and west of the Tanana. “Although our primary target is oil, our gas prospects are greater, so it is unfortunate timing to see the Interior Gas Utility ready now to commit to a course of action with (the Alaska Industrial Development and Export Authority) which will tie Fairbanks for at least a generation to imported LNG by truck at much less favorable price projections,” Mery said in the release. He added that by committing to the Interior Energy Project plan to expand natural gas distribution in Fairbanks, the borough-owned utility would kill “the option for use of future Nenana gas as well as foreclosing future opportunities to tap into any North Slope gas export line.” AIDEA spokesman Karsten Rodvik said via email that after the three-year gas supply contract the authority reached with Hilcorp for the project earlier this year expires, IGU can purchase gas from any source. That contract, which kicks in Jan. 1, is included in the $331 million package for IGU to purchase Fairbanks Natural Gas and finance gas infrastructure build out in the Fairbanks area with low-interest state loans, bonds and grant money. IGU leaders have expressed concerns with some of the finer points of the financing terms in the tentative deal with AIDEA, but the start-up utility board is expected to make a decision on it soon. Since its inception in 2013, the Interior Energy Project has been intended as an interim solution to Fairbanks’ high energy costs until a gasline from the North Slope is built. While high fuel oil costs subsided along with oil prices in late 2014 — which has also challenged the economics of the IEP by reducing the incentive for residents to switch to gas — getting more natural gas to the city would also help improve its at-times dangerously poor winter air quality. Mery said in an interview that the gas contract is not the issue; rather, it’s the investment in the LNG supply chain — expanding the Mat-Su LNG plant, tankers and LNG storage in Fairbanks — that will tie the utility to Cook Inlet-sourced gas for years. “Once that entity commits to hundreds of million of dollars of debt they’re wedded to that project. How can they abandon that project to buy cheaper gas? Somebody has to pay for those assets that have been acquired,” he said. “We’re just saying there might be another option; there might be a better option in the relative near term. We’re just throwing that out for the public to consider.” IEP leaders have discussed the possibility of using the LNG supply chain to fuel other communities on the road system if another gas supply for the Fairbanks area is found, but their primary focus has been on getting the project up and running first. Mery has said in the past Doyon could start supplying natural gas about three years after a commercially viable discovery is made. On its current schedule, additional gas is expected to start flowing from the IEP in 2020. IGU leaders could not be reached for comment in time for this story. Mery noted Doyon would have to beat fuel oil prices with its natural gas if it is successful, which the company thinks it can do. Elwood Brehmer can be reached at [email protected]

Walker touts trade relations with China after gasline talks

Gov. Bill Walker is hopeful the inroads his administration has made with top-level officials in the Chinese government through cooperation on the Alaska LNG Project can be parlayed into partnerships for other industries. The governor outlined his plans to bolster Alaska-China trade during a Nov. 21 press conference mainly focused on the state’s gasline Nov. 9 agreement with three government-owned Chinese companies. The non-binding joint development agreement sets an outline for Sinopec, the world’s largest integrated oil and gas company, to purchase up to 75 percent of the LNG from the Alaska LNG Project. The Bank of China and the China Investment Corp., the country’s $813 billion sovereign wealth fund, would finance and directly invest in portions of the $40 billion megaproject. Walker described the gasline work, which included Alaska Gasline Development Corp. President Keith Meyer in the country for at least six weeks this year, as “just the beginning” of growing trade with China. “The relationships we have built at the highest level in China can benefit many other areas of business in Alaska,” Walker said. If Alaska is to expand its business dealings with China, it will undoubtedly be helpful that the most-populous country on Earth is already the state’s largest foreign trade partner. Alaska companies exported nearly $4.4 billion worth of goods and raw materials last year, of which almost $1.2 billion worth went to China, according to the state Office of International Trade. A broader trade mission to China coordinated by the International Trade Office is being planned for sometime next year, Walker said, but the details are still being worked out. Japan is the state’s next largest export destination. The country bought $816 million of Alaska products in 2016, followed by South Korea at $730 million. The 2016 export values were all down to varying degrees over prior years; however, because Alaska exports are primarily seafood and other raw materials or commodities with often-volatile market pricing, the year-over-year value of the goods is not always indicative of the amount sold. The state’s total exports have grown substantially in recent years from just more than $3 billion in 2009, according to the International Trade Office. Walker said his team’s discussions with Chinese leaders, including China President Xi Jinping, that led to the Alaska LNG joint development agreement also touched on the state’s additional potential offerings. Xi met with Walker this past April in Anchorage as he passed through on a refueling stop heading home after meeting with Trump in Washington, D.C. “We talked to them about other resource we have and they’re certainly interested in other resources in Alaska. Certainly interested in oil; very interested in mining; but they said ‘let’s get the gas one taken care of first,’ and I couldn’t agree more,” Walker said. Aside from possible direct investment in the Alaska LNG Project by the China Investment Corp., members of the Walker administration have said Chinese companies are also potential upstream investors in North Slope oil projects. At $2.1 billion, seafood was the Alaska’s top export overall in 2016 and similarly was the top single export to China, valued at $626.3 million, or more than half of the state’s total exports to the country. The Alaska Seafood Marketing Institute estimates that 80 percent to 90 percent of the state’s exports to China are reprocessed and sent on to Europe and Japan, which are the top final consumption destinations for Alaska seafood. China also imported $321 million of Alaska minerals last year, a close second to Canada, which bought $323 million of minerals from Alaska. Additionally, China dominated the market for Alaska timber; it bought nearly $75 million worth of forest products from the state in 2016 out of $98.6 million of total timber exports for the year, according to the Trade Office. The vast majority of timber exports currently consist of shipping whole “saw logs” because Alaska’s large lumber and pulp mills used to refine forest products have closed as the state’s timber industry has declined. And beyond traditional table-fare seafood, the Chinese also bought $53.8 million of Alaska fish meal products, which again accounted for roughly half of the total $110 million export market. While Alaska’s business with China has historically been in traditional goods, Walker noted the growth in the country’s middle class could bode well for the state’s tourism industry, one of the few growing sectors of the Alaska economy. “1.4 billion people in China, of which 100 million a year go on holiday. Boy, we sure would like to get a slice of those going on holiday to come to Alaska,” Walker commented. According to the state Commerce Department, approximately 23,000 Asian travelers came to Alaska last year, accounting for only about 1 percent of the roughly 2 million visitors to the state overall. Of those, about 5,000 were from China. Walker said state officials are also working on getting direct scheduled flights between Asia hubs and Alaska to encourage more tourism here. Japan Air Lines has operated charter flights between Tokyo and Fairbanks since 2004, but those flights are in winter and part of group tours planned specifically for aurora viewing. Attracting more international tourists to Alaska could also mean bringing disproportionately more money to the state. The average Alaska visitor spent $1,057 once in the state, while international travelers — Canadians excluded — spent $1,322 per person in Alaska and those coming from Asia spent $1,442 during their stay, according to the Commerce Department figures. Elwood Brehmer can be reached at [email protected]

Murkowski adds Tongass timber, Roadless rule repeal to budget bill

Sen. Lisa Murkowski has made headlines of late for her push to open part of the Arctic National Wildlife Refuge to oil and gas exploration but she’s also using her position in the Senate to angle for more resource activity in Southeast Alaska. Murkowski chairs the Appropriations subcommittee covering the Interior Department, the Environmental Protection Agency and the Forest Service, which released its $32.6 billion discretionary 2018 budget for those agencies Nov. 20. The budget bill also includes provisions that would force the Forest Service to, at least temporarily, stop its transition to young-growth timber harvest in the Tongass National Forest and once-and-for-all exempt Alaska from the Roadless Rule. “This bill will empower Americans to build our economy and create healthy communities for our families,” Murkowski said in a formal statement. “As chairman, I’ve worked hard to address key priorities, from ensuring our parks are adequately staffed, to prioritizing health care through (the Indian Health Service) and focusing on public safety. In this draft bill, we direct federal resources where they are needed by investing in programs aimed to protect people and our lands, enable new infrastructure projects to boost the economy, and help communities provide vital, basic services.” Specifically, the Tongass provisions would require the Forest Service to start the process to amend the 2016 Tongass Land and Resource Management Plan by Jan. 31 of next year. The current Tongass plan — an environmental impact statement — took effect last December and directs forest managers to fully transition to only young-growth timber harvests in the Tongass within 16 years. It was spurred by a 2013 memo from then-Agriculture Secretary Tom Vilsack directing management of the forest to be more ecologically, socially and economically sustainable, while accelerating the transition to predominantly young-growth timber harvest by the region’s remaining timber industry. Managers would revert back to the 2008 Tongass plan while the 500-plus 2016 plan is amended. As part of the management plan changes, the budget bill also directs the Forest Service to conduct “stand-level” inventory of the roughly 360,000 acres of young-growth timber stands in the 17 million-acre Tongass to determine which stands are mature and harvestable and incorporate the results of the survey into the 2016 plan revision. It authorized $1 million to the Forest Service to conduct the fieldwork and another $700,000 to amend the Tongass management plan. Tongass Forest Service spokesman Paul Robbins said via email that the agency couldn’t speculate on the pending legislation, but said the Forest Service spent $5.5 million over multiple years developing the 2016 management plan. Murkowski and Alaska logging industry leaders have consistently said they support moving to strictly young-growth harvests in the Tongass but doing so would require a gradual shift over 30-plus years to allow young-growth stands to mature. Loggers contend the trees in many of the young-growth stands simply aren’t large enough for Southeast’s remaining mills — originally designed for large, old growth logs — to process. Currently, much of the timber harvested from the Tongass and state and private lands in Southeast is exported to Asia as whole, saw logs and is not processed in state. Murkowski has said if the federal government is not going to subsidize the millions of dollars of equipment changes mills would need to make to accommodate smaller logs the young-growth transition needs to be slowed to allow the trees to grow. Accordingly, her bill states that changes in the forest plan must “ensure that any transition to a timber sale program based on young-growth management be accomplished in a timeframe and in a manner that maintains an economically viable timber industry in Southeast Alaska.” According to Alaska Forest Association Executive Director Owen Graham, it takes roughly 90 years for a timber stand in the Tongass to reach harvestable size and the management plan in place now would kill off what’s left of Southeast’s timber industry. At its peak in the 1980s, logging in Southeast supported nearly 4,000 jobs in the region, according to Graham. Today, there are about 300 timber-related jobs in the region. Conservation and commercial fishing groups insist the expedited young-growth transition more aptly matches the reality of Southeast’s current economy. Limiting the new areas available for logging protects salmon habitat and also benefits the region’s visitor industry — one of the few growing sectors of the state’s economy — which markets the pristine environment of the Tongass, the contend. “The (2016) Tongass plan amendment is the product of years of collaboration by Alaskans from across the political spectrum that were able to overcome their differences and form a shared vision for the Tongass based on tourism, fishing and sustainable young-growth forest products,” Trout Unlimited Alaska Legal Director Austin Williams said. “It is disheartening that Sen. Murkowski is turning her back to the thousands of Alaskans that support the Tongass plan amendment and threatening to return the region to the conflict and divisiveness of the past. “The Tongass plan amendment was created by Alaskans that decided to work together and cooperate so that all could benefit and should not be cast aside through a closed-door process in Congress.” In 2016, the commercial fishing and tourism industries collectively supported 21 percent of the jobs in Southeast, according to the Southeast Conference, the region’s lead economic development organization. Roadless Rule rollback With the State of Alaska and timber industry supporters so far unable to reverse the Roadless Rule after years in court, Murkowski’s budget bill would nullify it in Alaska. The Roadless Rule, enacted by the Forest Service in 2001 under President Bill Clinton, prohibits development on roughly 58 million acres of previously undisturbed national forest lands nationwide. In the Tongass, the nation’s largest national forest, the rule set aside about 9.6 million acres, according to the Southeast Conference. While the Roadless Rule does not explicitly prohibit logging in the qualified areas, it limits loggers to using helicopters to remove felled timber, which can be exceedingly expensive and therefore ostensibly prohibits activity in Roadless areas. Much of the focus is on its impacts to the Tongass and Southeast Alaska, but the exemption would also apply to the 5.4 million-acre Chugach National Forest, the second-largest national forest behind the Tongass. Comparatively little logging has occurred in the Chugach, but Roadless opponents note the rule also prevents isolated rural Alaska communities in the forests from developing hydroelectric projects that could supply cleaner, lower cost energy. Alaska’s congressional delegation has long sought an exemption from the rule for the state if it couldn’t be repealed entirely. In 2003, George W. Bush’s administration did exempt Alaska from the Roadless Rule to settle a lawsuit brought by the state. However, in 2011, a U.S. District Court of Alaska ruling overturned the exemption in a lawsuit filed by Alaska Native and conservation groups against the Forest Service. The state intervened and appealed the ruling to the 9th Circuit Court of Appeals and won in a three-judge panel ruling in March 2014 to have the exemption reinstated. But in July 2015, a full, 11-judge 9th Circuit ruling reversed the 2014 decision and again put the Roadless Rule in effect in Alaska. The U.S. Supreme Court declined to hear the state’s appeal in the case last year. Most recently, on Sept. 21 a federal District Court judge for the District of Columbia dismissed with prejudice a separate State of Alaska lawsuit claiming the rule was enacted illegally. The state Department of Law appealed that ruling to the D.C. Circuit Court of Appeals Nov. 6. “This rule has an enormous negative impact on the Tongass National Forest and Southeast’s economy,” Gov. Bill Walker in a statement accompanying the appeal. “It’s important we keep fighting to preserve Alaskans’ livelihoods and options for responsible development.” So to end the legal fights, Murkowski added one sentence to the appropriations bill that starts by identifying the Roadless Rule and ends by stating it “shall not apply the respect to any national forest system land in the State of Alaska.” Elwood Brehmer can be reached at [email protected]

Effort to open ANWR clears one more hurdle

Sen. Lisa Murkowski’s legislation to open the coastal plain of the Arctic National Wildlife Refuge to oil exploration cleared another hurdle as expected Nov. 28, but one more big jump remains. The ANWR provisions passed the Senate Budget Committee as part of the Republicans’ tax overhaul on a 12-11 party-line vote. The next and final stop for the controversial legislation is the Senate floor, where debate is sure to be lengthy and contentious. The House passed its tax and budget plan Nov. 16. With a 52-48 majority in the Senate, Republicans inserted opening the ANWR coastal plain into budget measures that only require a simple majority vote and not the filibuster-proof, 60-vote majority needed for standalone bills. Lease revenue from the two lease sales prescribed in Murkowski’s legislation is expected to generate $1.1 billion, which would go towards offsetting a small part of the $1.4 trillion of tax cuts over 10 years in the Republican tax reform plan. Murkowski chairs the Senate Energy and Natural Resources Committee, which the Budget Committee earlier this year tasked with finding $1 billion in new revenues over 10 years to support the budget-tax plan. The directive was a nod to Murkowski to introduce the ANWR option. Specifically, Murkowski’s plan would direct the Bureau of Land Management to hold at least two oil and gas lease sales for 400,000 acres or more of the 1.5 million-acre ANWR coastal plain— the first within four years and the second no later than seven years after the legislation passes. It sets federal resource royalties at 16.67 percent and would evenly split royalty revenue with the State of Alaska. Finally, as has been the case with all the recent versions of ANWR legislation the delegation has introduced, it would limit permanent development to 2,000 acres in total. Because the ANWR action is being used as a revenue offset to the tax cuts it is linked to the fate of the tax bill, which is far from a sure thing even among Senate Republicans. Wisconsin’s Ron Johnson and Tennessee’s Bob Corker both voted to move the budget reconciliation out of the Budget Committee but have not yet thrown their support behind the tax plan. Johnson has said he has concerns with how corporate tax changes could affect small businesses and Corker has worries over growing the national debt if the economic growth presumed to grow the tax base and mitigate the impact of the tax cuts on the annual deficits doesn’t materialize. While most of the Democratic criticism of the plan in comments after the committee vote focused on proposed corporate tax cuts, Washington Democrat Sen. Patty Murray referred to the larger tax bill as “a backdoor attempt to drill for oil in one of our planet’s most pristine places.” Regardless, if Murkowski can finally be the one to lead ANWR-opening legislation through Congress — and to a president that will sign it — she will likely achieve legend status in Alaska political history for an accomplishment that long eluded her former colleague the late Sen. Ted Stevens. Republicans are trying to replicate what the House did while George W. Bush was president in 2005, when it included opening the ANWR coastal plain to industry activity in the fiscal year 2006 budget; however, much to Stevens’ consternation, it stalled in the Senate due to a filibuster and failed to make the final budget. Rep. Don Young regularly notes that he has led ANWR-opening legislation through the House more than a dozen times during his tenure, but nearly each time it has failed in the Senate. President Bill Clinton vetoed the one ANWR bill to reach a president’s desk in 1996. Elwood Brehmer can be reached at [email protected]

Report shows Medicaid savings largely from travel cost-shifting

Reforms to Alaska’s Medicaid program are producing savings but state budget officials still expect costs to rise up to $75 million next year. Provisions in the state Medicaid reform legislation that passed in 2016 with overwhelming bipartisan support saved the state more than $30 million in fiscal year 2017, according to companion reports issued Nov. 15 by the departments of Health and Social Services and Law. The annual status updates on the effectiveness of the reforms were mandated in the bill itself, Senate Bill 74, in part so legislators could track anticipated cost savings. Various other portions of the omnibus legislation were aimed at studying broader health care systems and models and the long-term potential benefits of applying them in Alaska. Fiscal year 2017, which ended July 1, was the first full year SB 74 was in effect. SB 74 was projected to save the state up to $365 million over six years when Gov. Bill Walker signed it into law in June 2016. Annual cost savings were supposed to increase each year as the numerous changes in the bill are gradually implemented. As expected, the primary savings to the State of Alaska totaling $24.7 million came from shifting costs for Medicaid-covered health care travel to the federal government, according to the DHSS report. Overall Alaska Medicaid travel costs increased by 18 percent in fiscal 2017 to total $100.2 million, the report states. However, the state’s share of those expenses fell by 69 percent from $35.5 million in 2016 to $10.9 million in 2017 despite the larger travel cost growth. That’s because in February 2016 the federal Centers for Medicare and Medicaid Services expanded what the federal government would fully reimburse to include services “received through” Indian Health Service Facilities and tribal health organizations for Alaska Natives, according to the report. Capturing the higher reimbursement rate requires care coordination agreements between Tribal and non-Tribal health organizations. While health costs for Alaska Natives are generally 100 percent covered by Indian Health Services, travel and other arrangements made through non-Tribal care providers had previously been covered half by the state and half by the feds. “The department worked with Tribal health organizations to initiate care coordination agreements with non-Tribal organizations to achieve the enhanced federal match,” the DHSS report states. It also notes the department saved more than $35 million by refinancing claims made between after the February 2016 CMS ruling until March 31, 2017, paid with a 50 percent state match that were found to be eligible for 100 percent federal reimbursement because of preexisting coordination agreements. There are currently 751 such agreements between 18 Tribal health organizations and 64 non-Tribal providers in the state. “In fiscal year 2018, with the additional of one more tribal health organization as a travel services provider, the count will increase to well over 1,000 travels per week financed at 100 percent federal match,” the report notes further. State Medicaid spending, matched by the federal government through a 50-50 split of costs from most recipients, went up by $19.3 million, or about 3 percent, year-over-year in 2017. Yet, the cost increase did not match the corresponding enrollment, which went up by 14 percent to 201,925 Medicaid recipients during the 2017 fiscal year, according to the report. As a result, the state spent 9.9 percent less on each recipient in 2017 than it did in 2016. DHSS officials surmised in the report that the per-capita spending decrease could be attributed to more Tribal care coordination agreements and the resulting growth in federal contributions. According to Office of Management and Budget Director Pat Pitney, the state’s Medicaid costs will increase another $75 million in the upcoming 2019 fiscal year. During a presentation to Commonwealth North, a state policy nonprofit, Pitney said that about half of the cost increase would be due to the gradual ramp-down of federal reimbursement for recipients enrolled under Medicaid expansion, which Walker accepted in 2015 despite challenges by the then-Republican controlled Legislature. The federal government paid for 100 percent of claims in 2016 by expansion-class recipients — low-income adults with no dependents — but the federal funding rate steps down to 90 percent by 2022. Pitney added that the administration attributes about half of the growth in Medicaid enrollment to Alaska’s poor economic situation. “We believe the recession has really created an increase in traditional Medicaid eligibility,” she said. Comparatively, the Legislative Finance Division expects Medicaid costs to grow slower, by $32 million, in 2019, based on flat enrollment expectations, Pitney noted. Fraud control Heightened scrutiny of Medicaid fraud and abuse saved the state another roughly $8 million, according to the joint Law and Health department report. SB 74 added positions to the Medicaid Fraud Control Unit in the state’s Criminal Law Division with the aim of catching additional improper Medicaid claims from patients and providers. Like Medicaid itself, the attorneys and support staff tasked with investigating fraud reports are funded through a state-federal split. In fiscal 2017 the Medicaid Fraud Control Unit reviewed 79 sets of allegations that led to criminal or civil investigations and charged 24 individuals criminally. The division also recorded eight criminal convictions and another civil settlement, which could relate to cases originally filed in prior years, the report acknowledges. When combined with the DHSS Program Integrity system, which among other things audits Medicaid claims, the departments recovered $2.3 million in illegitimate Medicaid expenses and avoided paying out another $5.7 million in potentially troubled claims, according to the report. Elwood Brehmer can be reached at [email protected]

Hilcorp boost Inlet output; Eni preps long well

Most state officials are encouraged about the incremental increase in Alaska’s North Slope oil production because of the impact it could have on state finances, but Hilcorp Energy is drilling to produce more from the state’s original oil basin as well. Hilcorp Alaska Vice President Dave Wilkins said the company drilled nine oil wells into its Cook Inlet fields this year and, as a result, expects to increase its Inlet oil production from about 12,000 barrels per day in January to more than 15,500 barrels per day by year’s end. “2017 was the year of stepping out and drilling wells mainly on the oil side,” Wilkins said Nov. 15 to attendees of the annual Resource Development Council for Alaska conference. “It was a big, bold move in a downturn.” Hilcorp, which is the primary operator in Cook Inlet, drilled three horizontal wells into the upper West Foreland field from its King Salmon and Steelhead platforms across the Inlet from Nikiski, according to Wilkins. Farther to the north along the western shore the company brought another well online in its Granite Point field in early November that has produced 1,100 barrels per day of oil from the Tyonek formation with no residual water. “We think there’s future development in the Granite Point field in the tighter formations to go horizontal in,” Wilkins said, adding the company believes there are still “tens of millions of barrels” of oil recoverable from both the Granite Point and West Foreland fields. Hilcorp is also in the midst of spending $75 million to convert a cross-Inlet natural gas pipeline to an oil carrier, a project it plans to finish in about a year, company officials have said. With other requisite work to adjust gas and oil flow on the west side of the Inlet, the project will allow Hilcorp to close the Drift River oil tank farm, which has been a lingering environmental concern to many because of its location at the base of Mt. Redoubt, an active volcano that most recently erupted in 2009 and caused flooding at the facility. The oil transport line will also reduce oil tanker traffic in the Inlet. On the gas side of Hilcorp’s business, Wilkins said the company drilled eight wells this year simply to replace burned reserves. Inlet gas storage facilities have ample reserves and are at higher pressures this fall than a year ago, he added. “We feel we are ready for this winter. Bring it on, turn up your heat, hope it’s cold,” he quipped. On the Slope, Hilcorp is continuing to build out Milne Point, one of the fields it bought into as part of a $1.25 billion deal with BP in 2014. The company recently drilled 10 wells at Milne Point that are just starting to come online, Wilkins said, and its up to $400 million Moose Pad project at Milne is on schedule. With $80 million of gravel road and pad work finished the company will start drilling between 50 and 70 wells next fall and peak production from the development is expected to hit 16,000 barrels per day in 2020, according to Wilkins. Hilcorp believes the Moose Pad project will produce 30 million to 50 million barrels overall. “Bringing on new oil in Alaska needs to be competitive with other things going on in Hilcorp, so bringing on new oil at $10 or less per barrel cost is very competitive,” Wilkins said. The company will also be running a pilot polymer flood project at Milne Point to improve heavy oil recovery over water floods that have been inefficient at the field, he said. Adding polymers to injected water increases the water’s viscosity and helps it “push” oil out of the reservoir more effectively by preventing the heavier oil pool from dispersing and comingling with the water as easily. Wilkins said the polymer flood should improve heavy oil recover by up to 50 percent over standard water floods. The company is also in the environmental impact statement process for its Liberty development, a plan for a manmade island in federal Arctic waters that has potential to produce 60,000 to 70,000 barrels per day at peak. Eni’s long exploration Italian major Eni, which produces about 20,000 barrels per day from the Nikaitchuq field off of Oliktok Point, will start drilling a diagonal exploration well in the coming weeks that is planned to stretch more than 6.5 miles, Eni Alaska Vice President Whitney Grande told the RDC. The roughly 35,000-foot well will be drilled from its manmade Spy Island drill site in state waters off of Oliktok Point into formations beneath federal waters further offshore. “It’ll be the longest extended reach well in the state,” Grande said at the RDC conference. The company has previously drilled several wells up to 25,000 feet on its state leases, according to Grande. It’s important for the Eni to start drilling by Dec. 31 because its federal leases are set to expire then, he noted. “We’re not foreign to the concept of extended reach (drilling); we have some good best practices around ERD and we’re looking to apply those to Nikaitchuq North,” Grande said. If successful, Eni plans to drill a second, similar exploration well next winter. The company currently believes the offshore reservoir it’s targeting could double the 180 million barrels of reserves the Nikaitchuq field originally held when it started producing in 2011, according to Grande. Upgrades to Doyon Drilling’s Rig 15 — which has done all the drilling at Nikaitchuq — are being finished now so it can start drilling the first long exploration well next month. Elwood Brehmer can be reached at [email protected]

More exploration approved at Icy Cape

Alaska Mental Health Trust Land Office officials are spending the winter reviewing the results of last year’s drilling campaign and preparing for another at their Icy Cape heavy mineral prospect. Those results were promising enough for the Alaska Mental Health Trust Authority Board of Trustees to approve $3 million in October to spend on more exploratory drilling next year, according to Trust Land Office Executive Director Wyn Menefee. The Icy Cape prospect is a long stretch of coastline about 75 miles northwest of Yakutat in Southeast Alaska owned by the trust at the entrance of Icy Bay that appears to hold world-class deposits of several heavy minerals. The entirety of the area is roughly 48,000 acres and stretches for more than 30 miles along the Gulf of Alaska coast. “We have a lot more to do in the sense that we didn’t cover any of the western portion of the property,” Menefee said in an interview. “We also need to do some more on the eastern side of the property. There’s just more to do before you have a better picture of where everything’s located.” Trust Land Office leaders have stressed that they are still in the preliminary exploration phase of evaluating the prospect but early drilling samples from the broad delta at the point of the cape indicate the ore there could be up to 40 percent heavy minerals. Overall, an average of 26 percent of the sands are heavy minerals, according to the Trust Land Office’s 2016 annual report. The minerals of value in the “ore” — which is mostly old beach sands — are roughly equal portions of epidote and garnet in the areas of highest concentration with small amounts of zircon and even gold. Epidote and zircon are semiprecious gemstones. Garnet has also been used as a gemstone for hundreds of years, but more recently the hard mineral has been put to use as an industrial abrasive on sandpapers and in sandblasting applications. It is also used in water filtration; garnet’s small pores allow for the passage of liquid while catching some contaminants. If developed, the Trust property would be the only source for garnets on the West Coast, Land Office officials have said. The Trust Land Office manages roughly 1 million acres of land across Alaska for real estate and resource development purposes, the proceeds of which go to fund the Alaska Mental Health Trust Authority’s work to benefit Alaskans with mental health and addiction challenges. Menefee said there is a misconception about the project that mining Icy Cape heavy minerals would literally mean digging up the beach. Much of the area is forested, he added, and portions of it have been logged. “It’s the course of time that creates these sandy forelands; so even though they are considered beach sands, it’s not the beach,” he said. The sands that comprise the substrate are the result of two sediment patterns coming from opposite directions, those materials that have eroded and washed down from the steep mountain faces above and sediments that tidal and wave action have pushed up to the shoreline. Most of that drilling has been done right from the logging roads that are already there, Menefee said. The area also has an airstrip. The drilling activity — and any future mine — doesn’t and won’t resemble the hard rock mines many people associate with the industry. Most of the drilling is to less than 100 feet down and it’s done with a sonic drill rig that uses vibration, not water, to make its way down. “It just vibrates its way down. We may go 75 to 100 feet, something like that, and then we take out the sand core samples,” Menefee described. “It’s a pretty low-intensity drilling program.” Because it’s a placer deposit, the mine would be “much more akin to gravel operations,” he added. Accordingly, the minerals would be sorted either using water, gravity, vibration, magnets or a combination of the processes, Menefee said, noting there is no need for chemical leaching. Trust Land Office revenues have varied greatly over its 22 years of existence, as money from timber and land sales and other resource projects has come and gone. Since 2011, its annual revenue has been between about $9 million and $16 million. Income from an Icy Cape mine — either as a royalty-collecting passive landowner or an active partner — could multiply the Trust Land Office’s annual revenue several times over and continue for decades, leaders have said. Menefee also emphasized that development is still a long ways off, saying it’s “way too preliminary” to even forecast a development or partnership structure and what role the trust would play in that. “I think that likely we are going to have anything from a few to several more years (of exploration) and a lot depends on the results of our drilling, the distribution of what we find,” he said. “It’s hard to tell right at the moment how long that (drilling) program will last before we would move towards an actual mine.” Between exploration and development the Trust Land Office might also demonstrate the viability of the prospect with prototype sorting equipment, depending on what potential mining company partners want to see, Menefee said as well. The simplicity of the operation and the fact that it’s all on trust, or state, land means federal permits and the often lengthy and costly environmental impact statement review process won’t be needed, according to Menefee. However, he again noted that permitting a full mine operation is a long ways off. “We are attempting to keep the communities and the public informed of where we’re going. We just held public meetings in Cordova and Yakutat and we intend to keep doing that after each field season to let people know where we’re at,” Menefee said. Elwood Brehmer can be reached at [email protected]

Mixed reaction to AK LNG-China letter

Gov. Bill Walker and his gasline team touted an agreement signed Nov. 8 with three Chinese mega-corporations as the largest step the state has ever taken towards finally putting together a North Slope natural gas project. After a few days to digest the situation, legislators’ reaction has been more subdued. Senate Resources Committee Chair Sen. Cathy Giessel, R-Anchorage, said she first sought out LNG industry experts to determine exactly what the arrangement, characterized as a joint development agreement by Walker and Alaska Gasline Development Corp. President Keith Meyer, substantively is. Walker stressed the joint development agreement between the state, AGDC and the integrated Chinese oil and gas giant Sinopec, the Bank of China and the $813 billion sovereign wealth fund China Investment Corp., includes all the pieces needed to make the $40 billion Alaska LNG Project a reality: a gas seller, buyer, and project financiers and investors. Meyer said in a briefing following the signing that the substance of the joint development agreement goes beyond what would be found in a letter of intent from a prospective gas buyer or project investor. AGDC Board of Directors Chair Dave Cruz emphasized during an October project update to legislators that the state-owned corporation was seeking to have a letter of intent by the end of the year. Meyer has repeatedly said letters of intent are paramount for gas sellers because while they fall short of being a full-fledged take-or-pay contract, Asian gas customers do not back out of them. The joint development agreement keeps AGDC on schedule to make a final investment decision on the project at the end of 2018, Meyer said further Nov. 8. On the other hand, Giessel described it as “another in a line of (memorandums of understanding)” with potential Asian LNG customers or investor companies. “I’m not sure it was more significant than other things we have seen in the past,” she added. In June, AGDC announced it had reached a non-binding MOU with Korea Gas Corp., to establish a framework for Kogas, as it is commonly known, for the government-owned utility to participate in developing and possibly investing in the Alaska LNG Project. It was also widely reported at the time that Kogas had entered into similar agreements with competing LNG projects around the world as well. Most recently AGDC announced a similar MOU with PetroVietnam Gas Nov. 12. Meyer said in a press release that the agreement with PetroVietnam complements the Chinese deal because a portion of the Alaska LNG Project’s capacity — designed at up to 20 million tons per year of LNG — remains available. South Korea and Japan have traditionally been the region’s primary LNG importers, with China joining them of late. Other East Asia countries have not participated in the LNG trade on a large scale, but the downturn in global LNG prices that has challenged the Alaska LNG Project has some countries in need of energy looking more at LNG as a viable option. “Vietnam is a new entrant into the LNG industry but has the potential to be a rapidly growing customer of LNG and we look forward to participating in the growth of the Vietnamese economy by providing reliable and stable natural gas supply,” Meyer said. Regardless of party, many legislators have been skeptical of the Alaska LNG Project since it became clear last year that Walker’s administration would take the lead of the megaproject from the state’s former producer partners. Some have questioned the state’s ability to succeed in the cutthroat LNG industry with worries about what it might end up costing. Others have asked why the state would want to move ahead when the presumed expert entities — BP, ConocoPhillips and ExxonMobil — sought to slow down the Alaska LNG until market conditions improve. BP subsequently signed on to assist AGDC behind-the-scenes in developing the project this year. Still others have more quietly commended the governor for trying to make something happen. The announcement from Beijing doesn’t seem to have changed those sentiments much. Giessel noted the state hasn’t fully secured a right-of-way through all of the federal lands the 800-mile pipeline would traverse and hasn’t yet gotten thorough feedback from financial advisors, among other necessary tasks. At this point, she said the potential buyer-investor agreements are to her “incredibly premature.” If Walker and Meyer can get a firm commitment from the Chinese corporations Giessel said she would still be apprehensive about the resulting deal, calling the Chinese firms “experienced and very strategic” negotiators, while describing AGDC officials as “clearly amateurs in comparison.” “The very first goal the Legislature had (for Alaska LNG) is gas for Alaskans,” she said. “That gets lost in a lot of these discussions.” Based on general market projections Meyer has said gas sales from the project would generate about $1 billion annually, of which the state would be privy to about $250 million through royalties and taxes. If Alaska were to raise the cash to be a primary equity investor, the Alaska LNG Project could return $2 billion per year or more to the state during the 20-year debt service period. Once the debt is paid would be the potential to return upwards of $6 billion per year to Alaska LNG investors, according to AGDC’s calculations. The corporation bases the figures on a broad 75 percent-25 percent debt-to-equity financing plan with an 8 percent average equity return through the debt term. Finding investors for the project’s infrastructure willing to accept a smaller return than major oil companies would in exchange for a long-term, stable investment has been Meyer’s primary counter to concerns about the producers wanting to wait on development. Another issue legislators have raised is to what level would AGDC allow gas customers to invest in the project. Large, often government-owned utilities and companies signing up to buy billions of dollars worth of LNG over decades also reliably want a small equity stake in the project so they have access to and can vet all of the other financing and construction contracts. If a gas buyer is allowed too large an investment stake in Alaska LNG it could exert leverage on AGDC and prevent the corporation from negotiating the best deals it could for the state. The Legislature would ultimately have to approve any deal involving state money AGDC would agree to. As of Nov. 14 Giessel had not seen a copy of the joint development agreement, which Meyer said would be made public within about a week after the Nov. 8 signing. One of her counterparts in the House, Resources Committee Co-chair Andy Josephson, D-Anchorage, said he is optimistic about the progress AGDC has made while acknowledging no one has made a firm commitment to Alaska and numerous important terms remain cause for speculation. He said the significance of the agreement being signed in front of President Donald Trump and China President Xi Jinping shouldn’t be forgotten. “One does get the sense that, notwithstanding all the competition in the world, that President Trump and President Xi want something to happen,” Josephson said. The AK LNG agreement was part of a much larger collection of trade deals between U.S. and Chinese firms totaling $250 billion — which Trump promoted as a big step towards balancing trade between the countries. While noting the Chinese government’s human rights violations as a concern for doing business on the government-to-government level along with the U.S. adversaries China does business with, Josephson said country is already Alaska’s largest trade partner (mainly through seafood exports) and the state’s natural gas could play a part in solving the China’s massive coal-driven pollution problem, which the government is finally acknowledging. “I think there’s reason to applaud what happened and I’m glad the House chose not to join the Senate in stripping away $50 million from AGDC’s budget,” he added, in reference to a capital budget amendment and political message to the administration quietly approved by the Senate in May to move about half of the corporation’s available funding to other state functions such as education and public safety. The House reversed the move and it was not part of the budget compromise passed in July. Elwood Brehmer can be reached at [email protected]

ConocoPhillips plans for busy exploration season

It’s going to be a busy winter for ConocoPhillips. The company that has led exploration into the National Petroleum Reserve-Alaska west of the existing North Slope oil fields is heading back into the federal lands to drill four more greenfield wells early in 2018, according to spokeswoman Natalie Lowman. Last January ConocoPhillips announced the Willow discovery in the NPR-A that the company’s Alaska leaders believe contains 300 million barrels of recoverable oil and is capable of producing up to 100,000 barrels per day with the right production and processing facilities. With another exploration well planned for state acreage recently added to the Colville River Unit just east of the NPR-A, the five wells make for the company’s largest North Slope winter exploration program since 2002, Lowman said. “There’s three to help us further appraise Willow and Putu and then this other one that we’re calling Stony Hill,” she said further. The Putu well could be ConocoPhillips’ last chance at developing a prized chunk of state land around the Native village of Nuiqsut just south of the company’s Alpine oil field in the Colville River Unit. It’s on the southern edge of the Pikka Unit, which holds the 1.2 billion barrel-plus Nanushuk oil prospect that operator Armstrong Energy just sold to Australia-based producer Oil Search Ltd. ConocoPhillips took control of the area surrounding Nuiqsut — the now-defunct Tofkat Unit — in 2016 in a transfer from Brooks Range Petroleum Corp. after Brooks Range was unable to work out an access agreement with Kuukpik Corp., the Native village corporation for Nuiqsut that jointly holds surface rights to the area with the state. The lease transfer was originally contingent upon the company drilling Putu last winter, as it’s an area Department of Natural Resources officials also see as highly prospective and want developed. However, ConocoPhillips held off on drilling Putu last winter after Nuiqsut residents raised concerns about the possible impacts of drilling the well roughly three miles from the village. After going back-and-forth with the state in a regulatory fight that lasted several months DNR Commissioner Andy Mack ruled in August that the company could keep the leases for another year as long as it paid the state $7 million in lease bid replacement payments and drilled the well into the Nanushuk geologic formation by May 31, 2018. The Willow prospect is similarly a Brookian Nanushuk oil play, according to ConocoPhillips. It could start producing as early as 2023 if development plans move ahead smoothly, company officials have said. The Stony Hill exploration well will be drilled southwest of Nuiqsut and just inside the eastern NPR-A boundary, Lowman said. To get all the work done the company has contracted for three exploration drilling rigs this winter, she added. ConocoPhillips, along with bidding partner Anadarko Petroleum, was the winning bidder on nearly 600,000 federal acres in the NPR-A during the December 2016 lease sale. The large exploration program, which Lowman noted is still subject to final budget approvals, is planned despite an announcement by ConocoPhillips executives during the company’s late October quarterly earnings report that its capital spend will likely end up being $4.5 billion worldwide in 2017, down about 10 percent from initial expectations. Despite that, company leaders said Nov. 8 that capital expenditures should average $5.5 billion per year for the next three years as long as crude stays above $50 per barrel. Armstrong Energy also plans to drill an appraisal well and sidetrack in the southwest portion of the Pikka Unit this winter before handing the operating reigns to Oil Search in June 2018. The appraisal wells will be in a portion of Pikka that has not been drilled and is nearby the Putu area. Armstrong also has an agreement with ConocoPhillips to receive the drilling results from the Putu well, according to documents the company submitted to the state. Elsewhere in the NPR-A, ConocoPhillips will be continuing work on its Greater Moose’s Tooth-1 and -2 oil developments. The mid-sized oil projects will collectively cost roughly $2 billion to develop and each is expected to produce up to about 30,000 barrels per day. First oil is should flow in late 2018 from GMT-1 and from GMT-2 late in 2021, according to the company. Elwood Brehmer can be reached at [email protected]

Unpaid tax credits, logistical issues slow Inlet producers

A pair of small companies working in Cook Inlet are trying to overcome funding shortfalls stemming from the State of Alaska not yet making good on promised tax credit refunds. Furie Operating Alaska and BlueCrest Energy, both Texas-based independents, had to interrupt their 2017 work plans because expected tax credit repayments from the state did not come through. BlueCrest CEO Benjamin Johnson said in a prior interview with the Journal that the state owes his company roughly $90 million in tax credits for drilling and development work done at its Cosmopolitan oil project before legislation passed to kill the tax credit program July 1. The state has paid BlueCrest $27 million for its refundable tax credits since the company purchased the “Cosmo” project in 2012, according to Johnson. BlueCrest is the sole owner and operator of the Cosmo oil project on the edge of the Inlet near Anchor Point on the Kenai Peninsula. He said in August the company hoped it would have to pause its drilling program only for a month or two after a well was finished in September, if private financing could be secured. Oil industry backers have roundly criticized Gov. Bill Walker for vetoing $630 million worth of appropriations in 2015 and 2016 to pay the industry tax credits. Walker has been steadfast in his assertion that the state cannot afford to make the large credit payments while still in the midst of $2.5 billion-plus annual budget deficits. On the other hand, the governor has also insisted he would like to see the state pay down on the obligation as soon as the Legislature passes fiscal reforms to balance the state budget. Walker’s original fiscal plan proposed in early 2016 included $1 billion to pay off the credits entirely. This year the Legislature passed House Bill 111, which ended the program, but also appropriated just the $77 million minimum for credit payments in the operating budget while still at an impasse over a fiscal solution. State statute outlines an oil price-based formula for the minimum amount the state should pay towards the credits in a given year should lawmakers chose to not pay them off entirely. Office of Management and Budget Director Pat Pitney told the Senate Finance Committee Oct. 31 that the 2019 fiscal year minimum payment would be $118 million. The 2019 fiscal year begins next July 1. The Revenue Department estimates the state will owe $736 million in credits at the end of the current fiscal year and the balance — if continually paid at the minimum — should be paid off in 2024 or 2025. BlueCrest’s 2018 plan of development for the Cosmopolitan Unit submitted to the state Division of Oil and Gas states the company finished drilling the 22,300-foot Hansen 14 well from its onshore drill pad Sept. 25. The company has been producing a little more than 300 barrels of oil per day from Hansen 16, an exploration well drilled by ConocoPhillips prior to BlueCrest’s purchase of the project, according to state production data. Once plugs are removed from the initial well and both are ready for production each should pump more than 1,000 barrels per day, according to Johnson. The above ground portion of the Cosmo project is onshore; however the angled oil wells are aimed at an oil pool that is about three miles offshore and 7,000 feet underneath Cook Inlet. In the coming year BlueCrest will be evaluating the drilling results from lateral wells off of the Hansen 14 and prior exploration well, company President John Martinek wrote. Martinek wrote further that “BlueCrest’s plan is to drill at least one well in the 2018 drilling program.” At this point that well is most likely to be another lateral off of Hansen 16 targeting a higher geologic formation, according to the plan document. Johnson has said the Cosmo oil pool is confirmed to hold “many hundreds of million of barrels of oil” and could support seven years of continuous drilling. The Cosmopolitan field also contains a large natural gas cap, but limited local demand and shifting state tax policy have delayed BlueCrest’s plans to develop it via an offshore platform, company officials have also said. Kitchen Lights Furie had big plans for the summer of 2017 when Vice President Bruce Webb spoke to the Journal in April, but a combination of unpaid credits and logistical challenges put much of the company’s plans on hold. Furie operates the middle Inlet Kitchen Lights Unit from the Julius R natural gas production platform it installed in 2015. It currently produces about 14 million cubic feet of gas daily to fill the gas contracts it has with to local electric utilities. Another contract to supply Enstar Natural Gas Co. commences next April. Furie leaders had intended to do a workover of the KLU-3 well, finish drilling its A-1 well and then drill another gas well and a deep oil test well, according to Webb. However, the Legislature did not approve the state’s operating budget for fiscal year 2018 — which started July 1 — until June 22. “Although the Randolph Yost jack-up rig was 100 percent staffed to commence drilling operations in April of this year, Furie was forced to delay its 2017 drilling plans — including purchasing tangible items with substantial lead times — until additional funding for the purchase of tax credits was approved by the Legislature and the governor,” Furie’s 2018 Kitchen Lights development plan states. The document was sent to the Division of Oil and Gas Oct. 6. Further, the tugboat needed to handle the large drilling rig’s anchor left the state for dry dock repairs in Singapore in mid-July, according to Furie. Given it was the only vessel in Alaska capable of handling the Randolph Yost anchor system and the lack of funds, the drilling program went awry. Furie did manage to do maintenance work and upgrades to its platform and onshore facilities and had divers install supports to the 15-mile subsea pipeline that connects the two during the summer work season. Going forward, “development will focus on additional wells for increased reserves and deliverability,” the plan states. “However, existing natural gas market constraints through 2019 may have an impact on the necessity of multiple wells.” If the local gas market warrants, Furie will finish the A-1 well in 2018 and drill another gas well similar to the KLU-3. The company may opt to drill another exploration well or re-enter and deepen its KLU-4 exploration well, according to the plan. “Looking beyond 2018, Furie intends to continue diligent exploration, delineation and development activities throughout the Kitchen Lights Unit,” the plan states. Elwood Brehmer can be reached at [email protected]

Brooks Range Petroleum seeks more time as Mustang delayed again

Brooks Range Petroleum Corp. leaders are asking state regulators for another year to bring their small and long-delayed North Slope oil project to fruition. Bart Armfield, CEO of Anchorage-based Brooks Range wrote in the 2018 plan of development document for the company’s Mustang oil project submitted to the Division of Oil and Gas Oct. 23 that first oil is not expected now until early 2019. The 2017 plan, submitted to and approved by the division last fall, pegged first production for this December. According to what Armfield wrote, that isn’t close to happening. He explained in the most recent Mustang development plan that: “In general, the (2017) plan remained in ‘Warm Standby’ during the term of the 4th POD due to continued low oil prices and difficult economic conditions.” Brooks Range had hoped to finish the remaining engineering for production facilities; connect to ConocoPhillips’ Alpine oil transmission pipeline; install the modular facilities and begin producing oil in 2017, based on the planning documents. Full development of the oil field has been estimated to cost $580 million and includes drilling 11 production wells to go along with another 20 gas and water injection wells to reach expected peak production of about 15,000 barrels per day. On the west edge of ConocoPhillips’ large Kuparuk River oil field, Mustang holds about 22 million barrels of proven reserves. Brooks Range did manage to further its evaluation of oil formation data and refine its drilling plans this year and requested and receive proposals to conduct the facility installation work. Additionally, the company has reentered one of its Mustang exploration wells and is currently fracking and testing the well, according to the plan of development. Armfield said via email that the ongoing evaluation should provide information that will be key to determining the future of the project. Brooks Range was unable to commission a drill rig for development wells this year because a processing facility was not available. Further, the company did not tie into the Alpine pipeline, advance facility engineering, solicit proposals for fabricating facility modules and subsequently get the modules fabricated and moved to the Slope all “due to adverse economic conditions,” Armfield wrote. Engineering of the processing facility and associated infrastructure started in January 2015 but was put on hold by the third quarter of the year as low oil prices hampered financing and project economics, according to the Mustang development plan Brooks Range submitted to Oil and Gas last September. The most recent Mustang plan submitted Oct. 23 — which the Division of Oil and Gas has 60 days to review — states that Brooks Range will do basically everything in 2018 that didn’t and won’t happen this year to be ready for first oil in the first quarter of 2019. Getting production from Mustang this year was a particularly key milestone because the Southern Miluveach Unit of state lands that contains the prospect is set to expire Dec. 31. The Southern Miluveach Unit’s original five-year term was set to expire March 31, 2016. However, former Department of Natural Resources Commissioner Marty Rutherford granted a request to extend the unit term to Dec. 31, 2017, on the hopes Brooks Range would have Mustang up and producing before the extension ran out. When acting Oil and Gas Director Jim Beckham approved the 2017 Mustang plan in November 2016, he wrote that completing the scope of work it outlined and getting to production seemed possible, but called the schedule “extremely tight.” At the time, Beckham informed Brooks Range that it would “need to drill and test a well that is capable of producing in paying quantities, apply for and receive certification of that well, and either produce from the unit or be working towards production by Dec. 31, 2017.” He added at the time that the state wants to see the company succeed but the tight schedule, pending unit expiration and financing and other issues caused state officials to question the likelihood of success. The Alaska Industrial Development and Export Authority is also keenly interested in seeing Mustang be a success because it invested $70 million in two installments in December 2012 and April 2014. A $20 million investment in 2012 from the state-owned finance authority supported a five-mile gravel road and 19-acre facility pad. AIDEA is an 80 percent owner in that base infrastructure that was finished in April 2013. Then, Brooks Range leaders said they were shooting to have the field in production by the fall of 2014. In April 2014, AIDEA committed another $50 million equity investment in the $225 million Mustang oil processing facility. Armfield said at the time that the project would start production in late 2015 and likely peak in 2017. With AIDEA’s investment, the Mustang processing facility would be the first such open-access facility on the Slope and have the potential to help in the development of other nearby fields. A spokesman for AIDEA said in a prior interview that the authority’s interests in the road, pad, yet-to-be constructed facilities and North Slope lease holdings give it multiple forms of collateral in Mustang should the project fail. DNR terminated the nearby Tofkat Unit held by Brooks Range in 2016 after the company held the acreage for years without doing much with it. In the case of Tofkat, Brooks Range allegedly was unable to secure an access agreement with Kuukpik Corp., the Alaska Native village corporation that holds surface rights to the state leases. The Tofkat leases have subsequently been transferred to ConocoPhillips in exchange for commitments to drill exploration wells this winter and to make a total of $7 million in bonus bid replacement payments to the state. Elwood Brehmer can be reached at [email protected]

Port gets new name, but problems remain

The Port of Anchorage is no more. No, it did not slough off into Cook Inlet overnight, though parts of it have. Rather, the Anchorage Assembly changed its name to the Port of Alaska on Oct. 24, a gesture intended to emphasize the importance of the ailing infrastructure to all of Alaska, not just its largest city. Regardless of the name, the price tag to keep it in service for the next 75 years remains at upwards of $700 million. Steve Ribuffo Port Director Steve Ribuffo and External Affairs manager Jim Jager said in a joint interview shortly before the name change that while it has been known for close to 20 years the port needs a massive overhaul, the clock is ticking on the status quo. Officials at the city-owned port began casing the most corroded steel piles that support the dock with steel jackets in 2004. The pile-patching program has since ramped up to a $3 million per year operation, according to Jager. To date, about 600 of the piles have been jacketed, which is just less than half of all the piles. Jim Jager The problem is the steel jackets that are helping the port outlive expectations are only useful for about 10 years themselves. “If you do the math, basically 10 years from now we are going to be closing docks because of load-bearing capacity,” Jager said. And that’s if an earthquake doesn’t knock it offline sooner.   Starting in 2004, the most corroded steel piles that support the dock have been encased with steel jackets. The pile-patching program has since ramped up to a $3 million per year operation and to date, about 600 of the piles have been jacketed. That’s just less than half of the piles at the port. (Photos/Courtesy/Port of Alaska) Roughly 2,400 containers cross the Anchorage docks every week, according to Jager, and either finding alternative places to offload them or new ways to get the groceries and other consumer goods they hold to Alaska in a timely fashion is just part of the challenge almost everyone in mainland Alaska would face if the port closes. The Port of Seward has just one large ship berth and employing it for jobs now taken up by Anchorage would also mean relying on the Seward Highway to get freight to Anchorage and north to the Fairbanks area. Whittier’s port is equipped for rail barges and handles industrial materials and equipment destined for the North Slope and other project destinations. There is also only one way in and out of the small town through a 2.5-mile tunnel that doubles as a railroad and roadway. “Ninety percent of freight in the state comes via water and half of that crosses this dock and half of what crosses this dock keeps going outside of Anchorage, so we have got a responsibility of being able to maintain that supply chain,” Ribuffo said from the port’s administrative building, which sits on the dock. Jager described the situation another way. “We have marine connects to road. We have marine connects to rail. We have marine connects to air. We even have marine connects to pipeline because we have pipelines to JBER and to Ted Stevens (International Airport) and down to Nikiski,” Jager said. “The dock rust issue is a mass disruption issue. The disruption that (the port closing) is going to cause is huge. I don’t think we can even begin to describe what it is.” Ribuffo added that the Anchorage port is the state’s critical hub — not only for cargo but also disaster response — because it was the only piece of usable infrastructure like it left standing after the 1964 earthquake. As it stands, load capacities on the port’s Terminal 1 have already been reduced because of weakened piles, Jager said, meaning Matson Inc. could not move its container cranes to Terminal 1 and offload there if need be. Matson and TOTE Maritime each provide twice-weekly service into Anchorage; Matson with containerships and TOTE with roll-on/roll-off trailers made for truck transport. “We can’t even use the big fork lift that they use for setting the gang plank on all of this dock, much less offload containers,” Jager added. Alaska’s military installations add another layer to the port’s importance. It is one of 19 commercial ports across the country classified as a National Strategic Seaport by the Department of Defense. About 20 percent of the cargo, much of it jet fuel, that crosses its docks is Defense related, according to Jager. The Matson containership Kodiak is seen at the Port of Alaska alongside fenders making up the dock facing. Below, one of those fenders is seen being removed from Cook Inlet after the 57,000-pound structure fell off the dock because of corrosion. (Photos/Courtesy/Port of Alaska) In June, a cruise ship was docking at the port when a 57,000-pound fender fell off the dock because the steel supports gave way due to corrosion. Luckily, that was the worst of it. “On the one had it was a nothing event. It was a nothing event that cost us $30,000 but it was a nothing event in terms of nobody got hurt, no trips got missed, nothing was delayed,” Jager said. “On the other hand, guess what, that is one of more than 100 fenders we have and it’s not the only one that has that problem.” In concept, rebuilding the port is a fairly straightforward, albeit very large, construction project: Replace the pilings and the docks they support in phases to allow the freight vessels, fuel tankers and cement ships that commonly call on the port to — with some inconvenient shuffling — continue to provide Alaskans with the things they need. In reality, of course, everything is much easier on paper. While the need to do something soon is clear, Ribuffo, Jager and their colleagues must also convince the skeptics of the new rebuild program that it will not be a repeat of the first Port of Anchorage construction and expansion project, which, depending on who’s talking, failed miserably because of design flaws or construction incompetence. “It’s a dock replacement project; it’s not an expansion project and we can’t stress that enough,” Jager said. The Port of Anchorage Intermodal Expansion Project started in 2003 but came to a halt in 2010 after extensive damage to the Open Cell Sheet Pile being installed to support the new docks was discovered. That work, much of which has been or will be removed as part of the new plan, cost roughly $300 million from a consolidated pool of local, state and federal dollars. The plan for the Port Modernization Program is to stick with a more traditional pile-supported dock. Built to modern standards, it is expected to last at least 75 years. The first of the current docks were commissioned in the early 1960s and the pile jackets have acted as life support to keep the port going well beyond their 35-year design life. “Back then — late ‘50s through the mid-‘70s — the piling were 7/16s of an inch thick, hollow, and some of it was left over pipe from the (Trans-Alaska Pipeline) days even, and that was what was used to finish the place over here,” Ribuffo described. Cook Inlet’s ice sheets and general ice buildup on the supports literally rip cathodic corrosion protection systems off the dock, so the designers of the new dock have decided to quit fighting the corrosion battle, which in salt water is almost always a losing battle anyway. The new piles will be up to one-inch thick steel and 48 inches in diameter as opposed to the hodgepodge of smaller piles put in years ago. More importantly, they will be filled with reinforced concrete that will act as the main load-bearing structure, meaning the dock will not be compromised as the ocean eats away at the outside steel, Ribuffo said. The piles will also be driven deeper — up to 180 feet down — into the compacted layers of glacial sediments that act as bedrock to keep the port intact should a severe earthquake effectively turn the topsoil to mud, according to Jager. Most of the damage caused by the 1964 earthquake in Anchorage was not because of the ground shaking things apart; rather the top layers of soil, comprised mostly of glacial muds, ostensibly liquefied and washed some structures away and left others with no foundational support. Bigger, stronger piles also means fewer of them are needed, which in a worst-case earthquake means soil, and everything it carries with it, will hopefully flow through the dock and down to the ocean without taking the port with it. “For the environment up here it makes sense to go bigger and wider and deeper and fewer and you get the same level of support,” Ribuffo said. Phased construction The first phase (PDF) of the modernization project entails building a new petroleum and cement terminal on the south end of the port to replace the weakened Terminal 1, where tankers and cement ships currently offload. On the north end, a portion of the backlands created during the expansion project and held back by the sheet pile will be removed to open space for TOTE at Terminal 3 and improve current flow past the docks to ease sediment fill issues. Ribuffo said port officials are hopeful phase one can be done with the $127 million left unspent from the first construction project. The Municipality of Anchorage also got $19 million from seven different settlements in the lawsuit it filed in 2013 against contractors and design firms in the first project. That suit closed in January and the settlement money is being put into rebuilding the port. A separate suit against the U.S. Maritime Administration, or MARAD, which managed the failed expansion project, is ongoing in federal court. Municipal attorneys have said they are seeking about $300 million spent on the project under MARAD’s watch. Bringing the Anchorage port up to modern standards does mean widening the docks to about 100 feet and pushing them out 150 feet to reach 45-foot water depths. However, that is all to simply accommodate the larger vessels and dock cranes that are standard equipment in the shipping industry these days. “It’s not more dock, but it’s more capacity,” Jager said. “We’re hurting our competitiveness by forcing them to use smaller equipment.” Subsequent construction phases will rebuild terminals 1 and 2; remove the rest of the northern extension from the prior work; rebuild the second tanker dock and demolish Terminal 3. With a plan in place, the challenge becomes paying for it. “Once you’ve started this you’ve got to finish it. There’s no running out of money halfway through,” Ribuffo said. Preliminary price estimates based on a 15 percent design in late 2014 when the concept was unveiled put the rebuild at nearly $500 million. The price is now up to roughly $700 million at a 30 percent design largely because of issues that have arisen as work has progressed, he said. It also accounts for inflation between now and the end of the work years into the future. For example, port officials have determined they will have to contract for an additional tug to help the vessels longer than 900 feet that call on Anchorage safely maneuver around the work barges that will be in the water during construction. That will cost about $25 million during the seven-year project, according to Ribuffo. His team is also negotiating with the U.S. Army Corps of Engineers for at least partial funding to dredge a channel in front of the new cement dock. The Corps pays all the costs for annual dredging of previously dug areas at the port, but first time dredging is usually the owner’s responsibility, he explained. However, the first design concept had the cement dock farther out in an area that is regularly dredged and for multiple reasons the Corps asked for the dock to be pulled back into shallower water in need of dredging. Whoever ends up paying for it the first round of digging is an unplanned-for $13 million, he added. The port users, Jager noted, could pay for some of the necessary equipment upgrades included in the $700 million and those discussions are ongoing. At the time of this writing the Anchorage Assembly had not taken up the matter of deciding on the construction management firm recommended by port officials, so the company remains confidential. Ribuffo said the Assembly was expected to discuss the issue in November, at which point the firm would become public. The Assembly and both former Mayor Dan Sullivan’s and current Mayor Ethan Berkowitz’s administrations have leaned on the Alaska Legislature to pay for most of the project as most of the state relies on it in some way, but to no avail. In December 2016 the Assembly requested $298 million from the Legislature, but got silence in response. With the State of Alaska still in the throes of $2.5 billion-plus deficits annually and the last savings accounts dwindling, there is little appetite for capital spending, even on a project recognized to be as vital as rebuilding the port. Gov. Bill Walker floated the idea of a $500 million state general obligation bond package in early 2016 to address the state’s most pressing needs, but it didn’t get far. Some legislators have said municipality needs to resolve its litigation with MARAD so it’s known what’s needed before the state contributes. Ribuffo said he is hopeful the suit can be settled soon, but if not it could drag into late next year or beyond. That could challenge the window port officials are up against to get the project done before the port rusts away too far, so other funding avenues are being examined. “Everything is on the table for consideration as par of the solution,” Ribuffo said. “Do we hang a ‘For Sale’ sign on the Port of Anchorage and potentially find a buyer that will come in and take this risk and responsibility off the city’s hands?” Third parties own other major ports around the country, but who would buy something needing $700 million of work is an open question. Ribuffo said municipal leaders are also open to the myriad of public-private partnership options that are available instead of just a straight sale. To this point, years of federal grant applications hasn’t yielded much, he acknowledged, but they keep trying. Day-to-day the port is self-sustaining financially, but it has only $3 million to $4 million at most to chip in per year, Ribuffo said. Looking at the port’s fee structure is one partial option. “We’re not saying by any stretch the state should pay for the whole darn thing. We know there are contributions we can make,” he said. “We still don’t know what any settlement with the federal government would amount to. We do know that in the world of ports we’re a pretty cheap date right now. We’ve got a little bit of room to help ourselves and not scare too many people away. All of that has to be in the package, if you will, that makes this thing happen.” Jager added that paying for the port through a combination of revenue or general obligation bonds or tariff increases roughly equates to a $1,200 to $1,500 “tariff” on each Alaska household over the next 25 years, or the life of a bond. That presumes a tariff hike on the port users would be passed on to consumers through higher freight fees. The alternative is drastically higher costs and longer waits on everything if the port has to be shuttered. Current business Ribuffo expects business to be down about 5 percent in 2017, which is roughly on par with the average decline in Alaska’s major industries as the state works its way through the current recession. Total tonnage across the docks was down about 7 percent in 2016 from a year prior to nearly 3.5 million tons of cargo and petroleum products, according to port records. “This is a meat and potatoes kind of business that we do here and there’s fewer mouths to feed now, so that kind of thing is going to happen,” he said of the decline in activity. However, increased demand for jet fuel from the state’s military bases and strong cargo business at the Anchorage airport have helped keep the losses from being more severe, according to Ribuffo. Those factors, combined with the closing of the Flint Hills North Pole oil refinery, which mainly produced jet fuel used in-state, have nearly tripled the petroleum imports to Anchorage since 2014. Tankers coming into the port now make up nearly half of the port’s business, he said. Elwood Brehmer can be reached at [email protected]

Walker, AGDC sign gasline agreement with 3 China cos.

Gov. Bill Walker’s administration announced a big step forward for the $40 billion Alaska LNG Project late Wednesday in the form of a multi-level agreement with three Chinese mega-corporations to advance the project. President Donald Trump and China President Xi Jinping attended the signing of the joint development agreement in Beijing, according to a press release from the governor’s office. Walker said there is still work to be done before a final investment decision is reached but the agreement has the five key players to make the trans-Alaska gasline project go. The Alaska LNG development partnership includes the state; the state-owned Alaska Gasline Development Corp.; Sinopec, an integrated oil and gas giant with more than $450 billion in annual revenue and potential gas purchaser; the Bank of China; and the China Investment Corp., the country’s $813.5 billion sovereign wealth fund. “The gasline is key to building a stronger Alaska,” Walker said in a formal statement. “I thank President Trump for the full support he and his administration have shown for this project, as it brings the United States one step closer to energy dominance. When President Xi visited Anchorage six months ago, he shared with me his desire for deepening the mutually beneficial ties between China and Alaska. I thank him for expediting that vision to reality.” The governor also thanked the Legislature for not pulling funding from AGDC while the state is in “in difficult and uncertain times” with multibillion-dollar budget deficits. Additionally, he recognized BP, ConocoPhillips and ExxonMobil for helping the state take the lead in the project when LNG markets forced a change in the structure of the project in early 2016. “It’s the beginning of what we hope is a long relationship between Alaska and these companies,” he said in a press briefing from China late Wednesday. Walker has often stressed the need to get Alaska’s natural gas export project out to potential customers. “This is the market responding,” he added. AGDC Keith Meyer called it an “engagement” following the courtship that began in April when after Xi visited with the Walker during a stopover in Alaska on his way from the Lower 48 to China. It keeps AGDC on schedule for a late 2018 final investment decision on the megaproject, according to Meyer. Alaska legislators said through press releases that they are encouraged by the announcement and look forward to hearing more from the Walker administration. Former House Speaker and candidate for governor Rep. Mike Chenault, R-Nikiski, recognized the Trump administration in a statement but did not mention Walker or his leadership team. “This is once again the kind of news we hoped to see under the Trump administration. In less than one year Alaska has seen leaps and bounds towards developing resources beneath our soil and waters. I’m eager for a gas pipeline to become part of Alaska’s legacy. I look forward to seeing all the details in this joint development agreement,” Chenault said. The agreement should be made public in the next week, Meyer said in the briefing.   Look for updates to this story in an upcoming issue of the Journal. Elwood Brehmer can be reached at [email protected]  

House sends crime bill back to Senate; budget hearings commence

The House made headway Nov. 7 on both of the agenda items on Gov. Bill Walker’s special session call However, there still does not appear to be any interest from the Republican-led Senate Majority in approving the governor’s proposed employment tax, or any tax for that matter. In the early morning hours of Nov. 7 the House passed Senate Bill 54 by a 32-8 vote with a bipartisan group of Fairbanks and Matanuska-Susitna area representatives voting against it after long days of floor sessions throughout the weekend. The amendment process was rigorous with nearly 50 proposed changes but most of them were voted down. SB 54, which the Senate passed last spring, is a tightening of some of the sentencing guidelines for misdemeanor and low-level felony crimes relaxed the omnibus criminal justice reform legislation passed early in 2016 under Senate Bill 91. The bill will cost the Department of Corrections an additional $3.6 million to account for additional incarceration time, according to the fiscal note. The changes the House made to SB 54 will require a concurrence vote from the Senate. If the Senate doesn’t concur it could add a couple weeks of work closer to the end of the 30-day session. Later Nov. 7 the House Finance Committee heard from Office of Management and Budget Director Pat Pitney on the state’s fund balances and budget reductions in preparation for beginning hearings on the administration’s tax proposal. The 1.5 percent payroll tax would be capped at either a $2,200 payment or twice the previous year’s Permanent Fund Dividend and would raise about $320 million per year once fully implemented in 2020, according to the Revenue Department. Walker has stressed it would leave Alaskans the lowest-taxed people in the country and is necessary to link government’s ability to provide services with economic growth. Walker and Senate President Pete Kelly, R-Fairbanks, exchanged jabs through newspaper editorials in which Kelly questioned if the administration’s low oil production and associated revenue forecasts released this past spring were artificially low to justify the need for a tax. An updated production forecast for the current fiscal year raised the spring estimate from 459,000 barrels per day to a projected third straight year of increases at 531,000 barrels per day. The governor responded that he shares Kelly’s excitement over increased oil production but is “sorely disappointed that he continues to issue statements that rationalize ignoring our fiscal crisis.” As of this writing the Senate Finance Committee had a hearing scheduled for the governor’s tax bill Nov. 9, but that is just as likely a courtesy review of the bill as a signal the Senate Majority will act on it. The Finance committees can also use this time to gather background information ahead of the budget process during the regular session, which figures to be another tough battle and continue to feature the same fiscal issues dealing with multi-billion dollar annual deficits. SB 54 could also end up taking a majority of the remaining time in the special session. The Senate Finance Committee also had a hearing tentatively set on that bill for Nov. 10. The special session ends Nov. 22, the day before Thanksgiving. Elwood Brehmer can be reached at [email protected]

Optimism abounds in advance of annual RDC gathering

There is plenty for the players of Alaska’s extraction industries to be positive about and that should translate into a cheery Resource Development Council for Alaska conference. The annual gathering for some of the state’s largest industries will be held Nov. 15-16 as it usually is at the Dena’ina Civic and Convention Center in Downtown Anchorage. RDC for Alaska Executive Director Marleanna Hall said some of the good vibes are being sent all the way from Washington, D.C. Last year’s conference convened shortly after President Donald Trump was elected and while there was anticipation about what a Trump White House would mean for Alaska businesses, no one knew quite what to expect. “There’s some optimism out there and a lot of it is coming from the changes in the energy outlook for America; it’s coming from opportunities to revise and revamp federal regulatory processes and a lot of it is coming from the top down,” Hall said. “It’s good to see that because instead of spending a lot of our energy pushing back against new bureaucracy we’re making changes to streamline processes that are in place already.” Additionally, the Department of Natural Resources revealed a couple weeks ago that it expects North Slope oil production to continue to rise over the coming year; oil prices have jumped back to more than $60 per barrel of late and Congress, led by the Alaska delegation, appears as close as ever to opening the Arctic National Wildlife Refuge to oil and gas exploration. The RDC conference will open as it often does with a panel report by key players in the fishing, forestry, mining, oil and tourism industries. Popular state economist Neal Fried will follow with the first look at his Alaska economic forecast for 2018. “We thought it would be a good opportunity for (Fried) to hear a little bit about what the panel’s perception is because I think he’ll be able to add some of his own comments during his presentation in response to what these industry representatives say,” Hall added. The rest of day one will be oil heavy, with an emphasis on what it will take to continue growing production from the North Slope. DNR Commissioner Andy Mack will join industry leaders in that discussion. Attendees will also be able to hear from Eni Vice President Whitney Grande. Eni is an Italian-based major oil company that quietly operates the small Nikaitchuq field on the North Slope and has a unique plan to explore its federal offshore leases from the manmade Spy Island in state waters via long reach horizontal drilling. Day two will be highlighted by the lunch speaker, acting federal Assistant Energy Secretary Daniel Simmons. “He, of course, is going to continue the message of (American) energy dominance and Alaska’s role in that,” Hall said. She acknowledged that legislators scheduled to speak during the day — Senate Resources Chair Cathy Giessel and House Resources Co-Chair Geran Tarr — might still be preoccupied with the ongoing special legislative session that could run through Nov. 22. The conference will close with a message from the leaders of Stand for Alaska, the political action group formed to oppose a ballot initiative aimed at strengthening state permitting requirements for salmon habitat they believe could prohibit projects both large and small in the state. The Stand for Alaska panel will include Alaska Gasline Development Corp. President Keith Meyer, who will also give a report fresh off an Alaska LNG Project marketing trip to China with Gov. Bill Walker. “There’s a lot going on right now in China,” Hall said, adding Meyer might just have an agreement or two to announce that could be big news for the future of a gasline. Elwood Brehmer can be reached at [email protected]


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