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A special publication by
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2018 Meet Alaska Conference and Trade Show Dena’ina Civic & Convention Center Friday, January 19, 2018 301 Arctic Slope Ave. Anchorage, AK 99518 P: 907-561-4772 F: 907-275-2176 www.alaskajournal.com www.facebook.com/alaskajournal www.twitter.com/alaskajournal
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Managing Editor/Graphic Design Andrew Jensen (907) 275-2165 editor@alaskajournal.com Advertising Director Jada Nowling (907) 275-2154 jada.nowling@morris.com Reporter Elwood Brehmer (907) 275-2161 elwood.brehmer@alaskajournal.com Reporter Naomi Klouda (907) 275-2158 naomi.klouda@alaskajournal.com Account Executive Ryan Estrada
ALASKA DELEGATION SUCCEEDS IN SECURING ANWR OPPORTUNITY
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HILCORP BOOSTS INLET OUTPUT; ENI DRILLING LONGEST WELL IN STATE
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SEARCH FOR NEW PLAY LEADS OIL SEARCH TO SLOPE
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PEBBLE FINALLY FILES FOR WETLANDS FILL PERMIT WITH ARMY CORPS
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CONOCOPHILLIPS PLANS FOR BUSY EXPLORATION SEASON
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UNPAID TAX CREDITS, LOGISTICAL ISSUES SLOW INLET PRODUCERS
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PORT GETS NEW NAME, BUT PROBLEMS THE SAME
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ZINC PRICES HELP NANA REBOUND FROM OIL CRASH
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‘AGGRESSIVE’ TIMELINE FOR AK LNG NEEDS ONE YEAR FOR PERMITTING
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AIDEA APPROVES DEAL WITH GAS UTILITY FOR INTERIOR ENERGY PROJECT
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(907) 275-2114 ryan.estrada@morris.com Account Executive Ken Hanni (907) 275-2155 ken.hanni@morris.com
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Welcome to the 35th Meet Alaska Celebration! “It’s like déjà vu all over again.”
That’s our theme today, just like it was in 2013 for our 30th event, and it’s not hard to see why.
The Alaska Support Industry Alliance 3301 C Street Suite 205 Anchorage, AK 99503 Phone: (907) 563-2226 Website: www.alaskaalliance.com www.akheadlamp.com General E-mail: info@alaskaalliance.com CEO Rebecca Logan rlogan@alaskaalliance.com Communications Director Jill Schaefer jschaefer@alaskaalliance.com
• On January 14, 1984, the Alliance came together at the first Meet Alaska to educate and advocate for the positions of the support industry. • On January 19, 2018, our mission is the same. • In 1984 the support industry was worried about a stable tax structure and without one, what would happen to investment. I think those concerns are echoed by the support industry today. • In 1984 one of the big projects being considered by the state was a natural gas pipeline.
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We’re lucky enough to have a bound transcript of the 1984 Meet Alaska and reading through that you can’t help but see the similarities between then and now.
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Milton Byrd, then Vice President for Corporate Development at Frontier Companies of Alaska, Inc. was the President of the Alliance and he opened the first Meet Alaska, saying in part:
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“We are concerned about the health, vitality, viability and enhancement of mining and petroleum exploration and production in this state. We are concerned with influencing public policy.” There is one significant difference between then and now – a President that sees responsible resource development in Alaska as the road to energy independence for America.
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Enjoy the day and hold on for the ride in 2018! Sincerely,
Rebecca Logan Chief Executive Officer The Alaska Support Industry Alliance
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Alaska delegation succeeds in securing ANWR opportunity By Elwood Brehmer Alaska Journal of Commerce
President Donald Trump signed the federal tax overhaul into law and the coastal plain of the Arctic National Wildlife Refuge is now open to the oil industry. Most Alaskans are happy about it, some aren’t. In the Lower 48 the public seems more split on the issue, if not slightly against it. After 37 years of debate, what more is there to say? The members of Alaska’s congressional delegation, who got the last words on ANWR in Congress when the tax bill passed, wanted to add a little more in a Dec. 20 press briefing with Alaska reporters. “This is a pretty historic day,” Sen. Lisa Murkowski said, and in recognition of it being winter solstice, she added opening ANWR is an “opportunity for Alaskans that will bring many bright days for Alaska.” Rep. Don Young, noting it’s the 14th time he’s shepherded ANWR legislation through the House, compared it to the day in 1973 when Vice President Spiro Agnew cast the tie-breaking vote in the split Senate to authorize construction of the Trans-Alaska Pipeline System. He also gushed about his colleagues in the delegation. “The work these two senators put in is awesome,” Young said. Sen. Dan Sullivan said the ANWR victory should provide a psychological boost to Alaskans struggling through a two-year recession. In a broader sense, Sullivan also said the tax vote is proof that “elections have consequences,” as tax reform is something Republicans in Congress have been pushing for seemingly as long as the Alaska delegation has been stumping for ANWR. Young said the delegation got commitments from House Speaker Paul Ryan and Senate Majority Leader Mitch McConnell early in the year that opening the coastal plain would be a priority in Congress. Murkowski said technological advancements allowing more oil to be extracted via a smaller footprint and the industry’s diligent environmental practices on state lands on the North Slope helped overcome old arguments about how oil activity would damage the fragile
6 2018 Meet Alaska
Arctic ecosystem. “We heard the same tired rhetoric that we’re going to turn this into an industrial wasteland,” she said. “The way that we operate up there is second to none.” The ANWR rider directs the Interior Department to hold two oil and gas lease sales of at least 400,000 acres each in the coastal plain within the next 10 years, but it authorizes total development of just 2,000 acres in the 1.5 million acre area, the delegation again stressed. Sullivan went a step further, calling opposition arguments “dishonest” and saying, despite claims the oil industry spent millions of dollars supporting the effort, it was actually Outside environmental groups that spent money on the debate. “This was a grassroots effort; it was the three of us and Alaskans that came to testify, that was it,” Sullivan said. “People were tired of the stale talking points by (Washington Democrat Sen.) Maria Cantwell and others.” Young went all the way, calling anyone who criticized the plan to drill for oil in the wildlife refuge “very stupid.” Young has also said recently that current oil estimates in the refuge are probably close to 20 billion barrels of available oil. The most recent U.S. Geological Survey assessment of the oil and gas underneath the coastal plain, done in 1998, put the mean oil estimate at 7.6 billion barrels for the coastal plain-1002 area. The USGS additionally estimated there is a 5 percent probability the area holds nearly 12 billion barrels of technically recoverable oil, which says noting of the economics of extracting it. With the political battle for ANWR all but over — at least until Democrats eventually regain control in Washington — now comes the legal fight. Environmental groups will assuredly sue Interior at every turn to at least delay the lease sales. The law mandates Interior hold the lease sales after going through a lengthy National Environmental Policy Act review. It’s unclear what happens if the conclusions of the environmental study don’t support development. What appetite the industry will have for exploring in ANWR given the strong emotions it
evokes from much of the public is also unknown. That leads to questions about whether the 800,000-plus acres to be offered in lease sales can generate the $1 billion in federal revenue that’s expected — which is actually $2 billion because the State of Alaska gets half of all revenue from ANWR, per the legislation. Murkowski acknowledged “it will likely be a decade-plus” before ANWR oil production starts, but said the state has waited 37 years and can wait a little longer. “Now we at least have the opportunity we haven’t had,” she said.
Anatomy of the deal It took some last-minute technical adjustments to specific language in the ANWR legislation to keep it viable, which also led to
PHOTO/CAROLYN KASTER/AP President Donald Trump shakes hands with Sen. Lisa Murkowski as she speaks during an event on the South Lawn of the White House in Washington, DC, on Dec. 20, 2017, to acknowledge the final passage of tax overhaul legislation that included the long-sought opening of the coastal plain of the Arctic National Wildlife Refuge. To the left and right of Murkowski are her fellow Alaskans Rep. Don Young and Sen. Dan Sullivan. 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 state-
ment 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 nonBudget 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. Elwood Brehmer can be reached at elwood.brehmer@alaskajournal.com.
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Hilcorp boosts Inlet output; Eni drilling longest well in state By Elwood Brehmer Alaska Journal of Commerce
Most state officials are encouraged about the incremental increase in Alaska’s North Slope oil production because of the impact it could 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 in 2017 and, as a result, increased its Inlet oil production from about 12,000 barrels per day last January to more than 15,500 barrels per day by year-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
2018 Meet Alaska
PHOTO/MICHAEL DINNEEN/FOR THE JOURNAL
Hilcorp Alaska Vice President Dave Wilkins told the Resource Development Council of Alaska on Nov. 15 that his company plans to boost Cook Inlet oil production by 3,500 barrels per day by the end of this year 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, started drilling a diagonal exploration well in December that is planned to stretch more than 6.5 miles, according to Eni Alaska Vice President Whitney Grande. 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 — were completed so it could start drilling the first long exploration well. Elwood Brehmer can be reached at elwood.brehmer@ alaskajournal.com.
PHOTO/MICHAEL DINNEEN/FOR THE JOURNAL
Armstrong Energy CEO Bill Armstrong, left, and Oil Search President Keiran Wulff found mutual gain in the deal that’s brought the Australian-based company to the North Slope through the acquisition of Armstrong’s highly prospective discoveries in the Nanushuk formation.
By Elwood Brehmer
Search for new play leads Oil Search to Slope
Alaska Journal of Commerce
The search for a new oil play took Keiran Wulff almost as far from his home as it could before he finally found what he was seeking. The president of Sydney-based Oil Search Ltd. — a soon-to-be tenant on the North Slope — and Armstrong Energy CEO Bill Armstrong sat down with the Journal Nov. 6 in Downtown Anchorage to discuss their $850 million deal announced the week before. Oil Search issued a press release Oct. 31 declaring it had reached agreement with Armstrong Energy and Denver-based GMT Exploration Co., a silent partner in the Pikka Unit, to buy a 25.5 percent stake in the Nanushuk oil prospect the unit holds along with a 37.5 percent share of Armstrong’s prospective “Horseshoe” leases to the south for $400 million. Under the deal, Oil Search will become the operator of the Pikka Unit in June 2018 and take charge of developing the 1.2 billion barrel-plus Nanushuk field Armstrong discovered with the help of Spanish major Repsol. It also includes an option for Oil Search to fully buy Armstrong and GMT out of Pikka for another $450 million by July 2019, which Wulff said his company is “highly likely” to exercise.
2018 Meet Alaska
Currently, Repsol holds a 49 percent share of the Pikka Unit, while Armstrong has 38.25 percent and GMT Exploration the remaining 12.75 percent interest, according to the Alaska Division of Oil and Gas. Armstrong took the operator position at Pikka from Repsol in late 2015. The companies first partnered to explore the state lands between ConocoPhillips’ very large Kuparuk and Colville River fields in 2011. They have since drilled 18 primary and sidetrack wells to first discover and then delineate the Nanushuk play. This winter, while Armstrong is still the operator, the company plans to drill an appraisal well and sidetrack in the southwestern portion of the unit, which has not yet been explored. The exploratory Horseshoe well and sidetrack Armstrong drilled last winter about 20 miles south of the Nanushuk project area indicated the reservoir could hold more than 2 billion barrels of recoverable oil, Armstrong said in a prior interview with the Journal. However, the 120,000 barrels per day peak production estimate is based on the 1.2 billion barrels of proven reserves. First oil is expected in the early 2020s and full development of the field will entail 146 wells and cost up to $5 billion to bring online.
Now about two years into the roughly three-year environmental impact statement process to develop Nanushuk, Armstrong, a geologist by trade, said he realized early on that the prospect of raising capital, which possibly meant going public, and growing his Anchorage staff of less than 50 by five-fold or more was not something he could, or really wanted to, tackle. The ever-growing obligation was forcing his company to be the one to pump the brakes on the project while Repsol, State of Alaska officials and others were pressing for just the opposite. “We’ve hit the ball so hard here, it’s like, ‘let’s do more; let’s do more,’” Armstrong said. A highly energetic man who even talks at a breakneck pace (particularly for a Texan), slowing down is not in his makeup. “It was rapidly becoming apparent that I was going to have to alter my company substantially if I was going to take this project to full development,” Armstrong said. “(Sometimes) you’ve got to give it up for adoption. I imagine the rest of my company was coming to that realization sooner than I did.” At that point he and his leadership team began a fairly informal search to find a new partner. And as it turned out, Armstrong didn’t so much
find Oil Search as the two found each other. An old friend of Armstrong’s happened to be a geologist with Oil Search and the two reconnected via email, talking shop and catching up on other life happenings. Eventually, Armstrong was invited to stop by Oil Search’s offices and meet a few folks the next time he was in Sydney — where his daughter also lives. Some time afterwards Armstrong coincidentally found himself sitting next to Oil Search CEO Peter Botten at a dinner during the annual CERA Week industry mega-conference in Houston. The two quickly hit it off. Armstrong recalled Botten being attracted to his irreverent nature. On the other side of the equation, Repsol leaders mentioned to Wulff, who was on the lookout for a new opportunity for his company, that they had a major prospect in need of another partner. “Timing is everything,” Wulff said. “It’s sometimes better to be lucky than smart and frankly the confluence of circumstances where Bill’s friend works for Oil Search, I had a meeting with Repsol and they introduced me to the Alaska North Slope opportunity, and I thought, ‘gee, that meets a lot of our interests’ and when Bill met with Peter at CERA that really hollered at the fact that there might be something there and then poor old (Armstrong Director Ed Kerr) and I have been jousting for the last six months in terms of this asset.”
Search origins Oil Search was formed in 1929 and until about 20 years ago was focused mostly on exploring in Papua New Guinea, where most of its holdings still are. “We faced a very similar situation to what Bill and Ed faced 20 years ago when we had to make the decision: do we remain an exploration company or do we take that next move to a production company?” Wulff said. “We felt because we understood the country we would go to the next phase.” Oil Search eventually bought Chevron’s Papua New Guinea assets in a deal that closed in 2003 and then quickly went from a firm with a couple hundred employees to a workforce of nearly 2,000, he said. “Bill was exactly right; it’s a complete change in the dynamic of a company,” Wulff added. “You go from being a purely entrepreneurial, can-do company to having a lot more obligations and (being) much more process oriented. You can’t really afford to have mistakes.” Today, Oil Search has about 1,300 direct employees, another 800 long-term contractors and is the largest employer in Papua New Guinea, according to Wulff. The company, which had $1.2 billion in revenue last year on $10.1 billion in total assets, also operates much of ExxonMobil’s drilling activity in the country. Oil Search had been looking to grow outside of Papua New Guinea and supplement its primarily gas reserves with an oil play. However, company executives did not want to get into a project outside their familiar territory without an “in-country expert,” Wulff said. “Anyone coming to Papua New Guinea should come to Oil Search, and they do. But in coming to the North Slope we wanted to make sure we were working with someone who had a really great record and frankly was a cultural fit for the organization as well,” Wulff said. Prior to the Nanushuk project Armstrong also discovered the small North Slope Oooguruk field, now owned by Caelus Energy, in the early 2000s and later the nearby Nikaitchuq field developed by Italian major Eni. “It’s a great time in the commodity cycle to (grow),” Wulff said, as oil prices appear to be pulling out of the three-year, sub-$60 per barrel trough they have been in. Oil Search equated the deal to buying into Nanushuk for about $3.10 per barrel.
Safety doesn’t come in a box. It’s not a banner that goes on a wall. It’s not something you do now and then. Or when it’s convenient. It’s using state-of-the-art simulators to better prepare for any situation. It’s giving offshore teams 24/7 support from onshore experts. And it’s empowering anyone to stop a job if something doesn’t seem right. Safety is never being satisfied. And always working to be better.
North to Alaska While the contrasts between the tropical South Pacific island nation and Alaska are obvious, Oil Search leaders believe the more subtle similarities and the company’s philosophy will help them make the move smoothly. See OIL
bp.com/safetyUSA
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Pebble finally files for wetlands fill permit with Army Corps
By Elwood Brehmer
Alaska Journal of Commerce
The Pebble Limited Partnership has long been criticized for many things, but as of Dec. 22 that list no longer includes failure to file for environmental permits. Pebble and its Vancouver-based parent company Northern Dynasty Minerals filed for a Clean Water Act Section 404 wetlands fill permit with the U.S. Army Corps of Engineers. Alaska Army Corps officials said Dec. 21 that the wetlands fill permit application detailing the types and volumes of fill material the project will use and the area of wetlands it is expected to cover would first be subject to a 15-day completeness review. If the wetlands application is deemed complete the Corps will then issue a public notice saying as much and — given the size of the project — issue a subsequent determination that the project needs to go through the full, multi-year environmental impact statement process. Northern Dynasty leaders said early in 2017 they planned to start permitting for the wildly controversial project by the end of the year, a promise that was met with understandable skepticism. They made good on it with nine days to spare. Pebble Partnership and its ownership groups, which have varied over the years, had consistently been faulted for making numerous claims dating back to 2005 that they would soon start the environmental reviews. The permitting process is also seen as one way to eventually provide closure for those on each side of the contentious debate over whether the worldscale mine proposed at the headwaters of a worldscale salmon fishery is appropriate. “For the Pebble team, this day has been a long time in the making and is the result of a tremendous amount of hard work,” Pebble CEO Tom Collier said. “We have listened to our stakeholders, supporters and skeptics, and are presenting a much smaller mine with enhanced environmental safeguards. Since I have been with the project, my main focus has been to initiate the permitting process so that Pebble can be fairly and objectively evaluated by the independent experts hired by the Corp of Engineers.” In 2014, the Environmental Protection Agency proposed blocking Pebble based on a larger mine concept outlined in financial disclosure filings by Northern Dynasty. Shortly thereafter Pebble Partnership sued the EPA, claiming the agency’s actions were made on a biased, anti-mine premise and that
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SCREEN CAPTURE/YOUTUBE
Pebble Limited Partnership CEO Tom Collier, seen here testifying to Congress as opponents wear anti-Pebble buttons behind him, has said the company doesn’t yet have a cost estimate for the scaled-down version of the mine that was proposed last October.
it illegally colluded with opponents of the project. That suit was settled in May and because the EPA is currently evaluating public comments on whether to lift the proposed determination that would prohibit the project. With a total mine facilities footprint of 5.4 square miles, the new plan is less than half the overall size contemplated by the EPA but still larger than the 4.2-square mile footprint the agency said could be acceptable. In statements issued shortly after Pebble’s announcement, opposition groups said the permit filing changes little, other than renewing determination to stop the project. “It took Pebble Limited Partnership 12 years just to file the paperwork asking the Army Corps to look at this project,” Bristol Bay Economic Development Corp. CEO Norm Van Vactor said. “The bar is set very low, indeed, if merely filing an application is cause for celebration. Bristol Bay fishermen file paperwork for their permits every single year, without fanfare. And here in Bristol Bay, we will choose our sustainable commercial fishery that generates thousands of jobs over a short-term development project.” A few days earlier on Dec. 18, Northern Dynasty
issued a statement saying it is close to finalizing a deal with fellow Canadian mining firm First Quantum Minerals for investment in Pebble. Northern Dynasty is the sole owner of Pebble after previous partners Anglo American and Rio Tinto walked away from the controversial copper and gold project several years ago. In the case of Anglo American, the company ended its partnership on the project in 2013 after spending $541 million on exploration. Since then, company officials have acknowledged the need for a large investment partner to fund Pebble’s development. Under the terms released of the preliminary deal, First Quantum would contribute $150 million to Pebble over up to six years with a $1.35 billion option to buy a 50 percent stake in the project. In a Dec. 21 interview Collier said he expects to have the partnership finalized by the middle of next year. Collier said his company doesn’t yet have a solid cost estimate for the scaled-back mine plan he unveiled in October, but that would materialize as permitting plays out. Elwood Brehmer can be reached at elwood.brehmer@alaskajournal.com.
OIL SEARCH Continued from Page 11 Wulff said Papua New Guinea’s indigenous cultures play a very large role in working on the island, and generally in everyday life there, as they do in Alaska. Just for example, he said the nation has roughly 800 tribes and a full one-third of the world’s languages. That has led the company to work with a spirit of cooperation, with a goal of benefitting everyone in and around its projects, according to Wulff. “We’re very focused on shareholder return but at the same time we compliment that with a real strong social conscience,” he said. Oil Search is heading north with the intent to form cooperative relationships not only with its fellow Slope operators but also with the communities in the area — which is paramount if the company is going to stay on the Slope as long as its leaders hope. “We have a different style of operating,” Wulff said. “It’s not that we’re soft, we’re actually quite ruthless with respect to our strategy and pursuing our strategy but we see the only way to have that success long-term is that all your stakeholders are engaged.” Oil Search also has a partnership for support on the Slope with Halliburton, the large oil service company that assisted with operations after its deal with Chevron in 2003 and with a long history on the Slope as well. Tapping into Alaska’s homegrown oil workforce that has been hit by industry layoffs of late should also help make for a smooth transition into the state, Wulff said. After a few days of meetings with State of Alaska and other pertinent officials, the Oil Search executive said he has been reassured by the general support for the industry and the widespread goal of more oil production from the North Slope. Those meetings “enhanced” his confidence in Oil Search’s ability to be successful in the state.
And while many Alaskans often worry the state’s popular debate over the proper oil tax structure, Wulff added that after working in several Middle East countries in recent years Oil Search is excited to operate in a stable government environment. “There’s always a balance between having the right fiscal terms that encourage exploration and the fiscal terms that ensure the community and the state get the right taxes; that’s a decision for the state,” he said. The bottom line is “Oil Search is a company that’s focused on being here for a long time,” Wulff stressed. Looking ahead Over the next few months Oil Search will take over Armstrong’s Downtown Anchorage offices and likely staff up to 100 people or more in the coming year, according to Wulff, but that doesn’t mean Armstrong Energy is exiting Alaska. Rather, a key part of the deal is that the companies plan to partner on future projects that allow each to maximize its strengths. “I want to keep doing what I do best, which is explore,” Armstrong said. Armstrong Energy now holds about 800,000 acres of leases on the Slope, of which the Pikka Unit is only about 15 percent, according to Kerr. Over the next year to 18 months, the two companies along with Repsol will develop a strategy to evaluate the prospectivity of all those acres. Armstrong said his company will be looking to repeat the Nanushuk play but noted he sees other opportunities as well. “We’ve got a lot to do,” Kerr said. Elwood Brehmer can be reached at elwood.brehmer@ alaskajournal.com.
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ConocoPhillips plans for busy exploration season
By Elwood Brehmer
Alaska Journal of Commerce
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 nowdefunct 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,
14 2018 Meet Alaska
PHOTO/ELWOOD BREHMER/AJOC
ConocoPhillips has plans this winter to explore west of its producing operation at CD-5, seen here, into acreage in the National Petroleum Reserve-Alaska where it has made a significant discovery. The company also plans to drill one exploration well to the east in a highly prospective area of its Colville River Unit.
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 elwood.brehmer@ alaskajournal.com.
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Unpaid tax credits, logistical issues slow Inlet producers By Elwood Brehmer Alaska Journal of Commerce
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. Last July, 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. Walker made a proposal to pay off the credits using bonds when he released his budget Dec. 15, which administration officials estimate will require $900 million to fully pay off over the next couple years. Revenue Commissioner Sheldon Fisher said the state would sell subject to appropriation bonds to fund the payments and offer the credits at a discount of up to 10 percent, reflecting the decline in net present value companies would absorb if the state continued to pay the statutory minimum credit amount each
2018 Meet Alaska
PHOTO/MICHAEL ARMSTRONG/HOMER NEWS
The jack-up rig Randolph Yost is seen arriving in Cook Inlet in 2012 before Furie Operating Alaska used it to drill new wells in the Kitchen Lights Unit off Nikiski. That unit is now producing natural gas for Inlet utilities and Furie planned to drill with the Yost again this summer, but a combination of tax credit uncertainty and logistical issues led the company to postpone the effort. year and prolong the payments for many years. Department officials expect the state can borrow the money for less than 6 percent interest over 10 years. Fisher said his agency, in coordination with the Department of Natural Resources, could also work to lower the discount rate for companies with production through negotiating a slightly higher royalty rate on their leases. It’s a proposal he believes will be well-received after discussions with industry representatives. “We believe the discount we will offer these companies will be significantly less than their cost of capital,” Fisher said. While the state has technically followed the tax credit statutes by appropriating less than $100 million in the past couple years, the break in precedent from paying them in full each year has hurt Alaska’s credibility in the oil and finance industries, officials acknowledge. Lacking the payments has also kept small companies from leveraging the credit funds for larger private investments to pursue work in the state. 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 22,300foot 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 produc-
tion 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 elwood.brehmer@ alaskajournal.com.
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17
Port gets new name, but problems the same
PHOTO/ELWOOD BREHMER/AJOC
The Anchorage Assembly voted Oct. 24 to rename the Port of Anchorage as the Port of Alaska in a move to emphasize the importance of the infrastructure to the entire state rather than just its largest city. Corroding piles and decades of damage from Cook Inlet ice have weakened Terminal 1, where this past summer a 57,000-pound fender fell off the dock while a cruise ship was in port.
By Elwood Brehmer Alaska Journal of Commerce
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. 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 pilepatching 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. The problem is the steel jackets that are helping the port outlive expectations are only
18 2018 Meet Alaska
Ribuffo
Jager
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. 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.” See PORT Page 20
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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. 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 (TransAlaska 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.
2018 Meet Alaska
PHOTOS/COURTESY/PORT OF ALASKA
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. 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 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.
PHOTOS/COURTESY/PORT OF ALASKA
The Matson containership Kodiak is seen at the Port of Alaska alongside fenders making up the dock facing. At right, one of those fenders is seen being removed from Cook Inlet after the 57,000-pound structure fell off the dock because of corrosion.
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 publicprivate partnership options that are available instead of just a straight sale. See PORT Page 25
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Zinc prices help NANA rebound from oil crash
PHOTO/FILE/AJOC
Things are looking up at the Red Dog mine in Northwest Alaska, where rebounding zinc prices have led to increased production and helped NANA Regional Corp. recover from low oil prices of the past two years.
By Elwood Brehmer Alaska Journal of Commerce
Strong returns from the Red Dog mine are helping NANA Regional Corp. overcome oil and gas industry losses. NANA CEO Wayne Westlake said in an interview that the Northwest Alaska zinc mine is outpacing production forecasts at a time when zinc prices are high. The open-pit Red Dog mine sits about 90 miles north of Kotzebue, the largest community in the region. NANA, the Alaska Native regional corporation for the area, owns the mine that is operated by Vancouver-based Teck Resources Ltd. Teck expects production from Red Dog to be between 525,000 and 550,000 metric tonnes this year, according to a September release from the company. Output in that range would be about 10 percent above prior production forecasts. The uptick in production is the result of changes to mine sequencing and advancements in metallurgical recoveries, Teck states. It also comes at a time when zinc prices are more than double what they were less than two years ago.
2018 Meet Alaska
Zinc sold on spot markets for between 80 cents and about $1 per pound for several years before dipping to 70 cents per pound in early 2016. Since, the corrosion-resistant metal commonly used in steel coatings has steadily increased in value to its current spot price of about $1.45 per pound. For an owner of one of the largest zinc mines on Earth, like NANA, the production bump and price spike add up to a big deal. It’s also a positive equation for the other 11 Alaska Native regional corporations and the roughly 200 Native village corporations that share in the mine’s revenues. The Alaska Native Claims Settlement Act mandates Native regional corporations to share 70 percent of their timber and subsurface resource revenues with their fellow Native corporations in the state in a system known as 7(i) resource revenue payments. Much of the 7(i) revenue dispersed amongst the Native corporations has historically come via oil and gas royalties from production on Arctic Slope Regional Corp. holdings on the North Slope and Cook Inlet Region Inc. lands in Southcentral Alaska. NANA also became a significant 7(i) contributor
when Red Dog opened in 1989. However, when oil prices started to drop by roughly half in late 2014, 7(i) revenues fell accordingly as well. Westlake said Red Dog’s increased revenue of late has largely made up for the recent decline in 7(i) distributions brought on by $50 oil. He noted that the resource development payments are often one of few private cash flows going into rural Alaska communities. “It’s not coming from the state; it’s not coming from the federal government. It’s coming from another Alaska Native corporation,” Westlake said of the 7(i) funds. “It’s been very important to the state especially with the price of oil down.” While the oil price depression hit Native corporations through revenue sharing, NANA is among the group of corporations that is heavily invested in the business side of Alaska’s oil and gas, with seven subsidiary firms working on the support services side of the industry in Alaska, Colorado and the Gulf Coast. About 40 percent of NANA’s revenues come See NANA Page 24
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from the oil and gas sector in some fashion, according to company leaders. That led to NANA absorbing a $109 million loss in 2016 and its business operations company, NANA Development Corp., also had its credit rating downgraded last year as a result of its oil business struggles. “The good news is that we’re doing better than last year; we’ve taken a number of steps to make that happen,” Westlake said. NANA shuttered two of its challenged subsidiaries doing work outside Alaska — NANA Pacific and NANA Australia — and has sold other companies working Outside to refocus on its strong federal contracting businesses and in-state operations, according to Westlake. Which companies NANA has divested are still confidential at this point, he added. “You just got to keep cutting and trimming,” he said, given oil prices and Alaska’s associated recession. Another positive for NANA on the mining side this year came in April when Teck agreed to a 10year payment in-lieu of taxes, or PILT, deal with the Northwest Arctic Borough for the severance tax the borough levies on mineral production. The previous PILT agreement expired in 2015 and when a new deal couldn’t be reached the borough moved to impose a tax that would have increased Teck’s severance payments from $12 mil-
lion in 2015 to somewhere between $30 million and $40 million. Teck sued, contending the borough was singling out the mine operation, which is a primary economic driver in the region. The new PILT is about 30 percent larger than the prior agreement, according to Teck. Westlake said the 10-year deal provides NANA and Teck with greater business stability versus the PILT arrangements that had been made previously. “We can at least now have some ability to plan, to understand what the tax would be and in the past it was over five years and its seemed like in a few years you had to be thinking about planning for the next round of negotiations,” he said. Westlake further described the successful PILT negotiations as a “win-win,” not only because it settles a contentious issue for the companies and the local government, but also because the PILT payments go directly to fund services used by NANA shareholders. “It’s something that we look at as a cooperative exercise because of where the (PILT) benefits go,” he said.
Teck focused long-term While Red Dog is a current bright spot for NANA, its future is looking equally as positive.
Teck is in the midst of a $110 million upgrade to the mine’s mill, which should increase its production capacity by about 15 percent. That ultimately will help keep zinc production steady despite the declining grade and harder ore in the existing deposit. Red Dog’s current life is expected to expire in 2031, but with Teck describing the mill upgrade as having “robust economics” in a September release, the company is clearly looking further out with its investment. Teck also announced in September that the Aktigiruq deposit it has been exploring for several years on state land about 7 miles northwest of the mine could hold up to 150 million tonnes of 16 percent zinc ore with smaller amounts of lead as well. If the estimates prove out, the Aktigiruq deposit is another world-class zinc discovery near what is already a world-scale zinc mine. Westlake said the new find could potentially support Red Dog many decades to come. To date, Red Dog has milled 78 million tonnes of ore of 19 percent zinc and 5 percent lead, according to Teck. Elwood Brehmer can be reached at elwood.brehmer@alaskajournal.com.
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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.
We’re not saying by any stretch the state should pay for the whole darn thing. We know there are contributions we can make. 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. — Port of Alaska Director Steve Ribuffo
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 elwood.brehmer@alaskajournal.com.
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‘Aggressive’ timeline for AK LNG needs one year for permitting
By Elwood Brehmer
Alaska Journal of Commerce
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 frontend 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
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Alaska Gasline Development Corp. CEO Keith Meyer talks about the Alaska LNG Project to members of Commonwealth North in Anchorage on Aug. 24. Meyer briefed members of the Alaska House of Representatives on Dec. 4 about the Nov. 9 nonbinding joint development agreement signed in China with three major companies representing the potential buyer and investor in the project. 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 instate 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 elwood.brehmer@ alaskajournal.com.
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AIDEA approves deal with gas utility for Interior Energy Project
By Elwood Brehmer
Alaska Journal of Commerce
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. ASK US ABOUT THE NEW V-CONE INLINE DIFFERENTIAL PRESSURE FLOW METER
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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 highcost 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.
Keeping our oil
f lowing
How it works 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 See IEP Page 30
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IEP Continued from Page 29 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.
Thousands of Miles of
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.
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