Elwood Brehmer

Unpacking House Bill 111

Once Gov. Bill Walker signs House Bill 111 into law, cashable tax credits to oil and gas companies working in Alaska will be a thing of the past. But the bill that became contentious in legislative debates — despite House Democrats, Senate Republicans and Walker agreeing on the major aforementioned policy change — has many other subtle but substantive provisions. For starters, it does not end all tax credits, or even all of them related to oil and gas projects. Capital expenditure and exploration credits applicable to work in the “Middle Earth” region of the state, which is pretty much anywhere other than Cook Inlet or the North Slope, continue until they expire on their own. The same can be said of credits for capital projects at the state’s three oil refineries or for entities looking to build natural gas storage, such as the Interior Gas Utility in the Fairbanks area. “We’re not changing the refinery credit; we’re not changing the LNG storage credit. We’re not changing a couple of these credits that people don’t think so much about that have these built in sunsets in 2020 or 2021,” Tax Division Director Ken Alper said in an interview. Companies earning certificates for those credits will just not get cash for them. The Middle Earth capital expenditure credit is applicable to production tax, while the small exploration credit for the region is applicable to corporate income tax, according to Alper. Interior-area Alaska Native regional corporations Doyon Ltd. and Ahtna Inc. have been the primary Middle Earth explorers, drilling for oil and natural gas to serve as a local heating fuel supply. Also, Cook Inlet operators can still earn transferrable production tax-applicable certificates that have not yet phased out after the passage of House Bill 247 last year, which eventually ends the credit program in that basin. The state just won’t refund them for work done after July 1. The Oil and Gas Tax Credit Fund is repealed Jan. 1, 2022, or sooner if the outstanding credit certificates are paid off by the state before then. The Legislature appropriated $57 million to the fund to pay down the state’s outstanding credit liability, which was expected to be nearly $1 billion by the end of the 2018 fiscal year before HB 111 passed. The Department of Revenue estimates repealing the cashable credits will save the state roughly $150 million per year over the long-term. There are also a few fine points surrounding the application of tax deductions and the “ring fencing” provisions that were sticking points in negotiations between House Democrats and Senate Republicans that seemed to confuse even some legislators involved in the HB 111 negotiations. Alper suggested the confusion likely stemmed from the multiple versions of the bill that were drafted during negotiations. The ring fencing provision prevents a company in a loss position from applying its 35 percent annual carry forward loss deduction to its production tax obligation until there is production from the project that caused the loss. Ring fencing was something the Democrat-led House Majority fought hard for to prevent a company from purchasing a non-producing project and using the deductions tied to it against their existing production taxes. It’s a scenario industry representatives dismissed as theoretical. However, ring fencing only applies to companies in a loss position; a producer can deduct 35 percent of its expenses from a development project against its current production tax obligation if it is profitable. The big win for Republicans and the Senate Majority was fending off the production tax increases in the version of HB 111 passed by the House. Additionally, HB 111 limits on the time a company can hold a deduction at full value, which was a win for Democrats and is intended to spur quicker development and ultimately production from a company looking to recover its expenses through tax deductions. A company without North Slope production can hold its deduction at full value for up to 10 years, after which the value of the carry forward deduction is reduced by 10 percent per year. While legislators have implied the annual deduction value reduction is 10 percent of the original amount per year, Alper said he interprets the bill language, which states the value decreases “by one-tenth of the value of the carried-forward annual loss in the preceding year,” to mean the loss deduction would be worth 90 percent of its original value in year 11; 81 percent of its original value in year 12, 73 percent in year 13 and so forth. It’s a point on which he said he would have to confer with Department of Law officials. For producing companies in a loss position, the deductions can only be held at full value for seven years before the “downlift” kicks in. Senate Resources chair Sen. Cathy Giessel, R-Anchorage, said the deduction downlift was one of the last pieces of the bill to be settled. “It’s a tight timeframe to have your full expenses deductible,” Giessel said. Alper said the clock starts the first year a company reports an annual loss, not when a lease is acquired, as some indicated initially. The July 1, 2017, retroactive effective date for the bill passed very late July 15 also caused some heartburn in the state Tax Division, at least when it was initially proposed by Senate leaders in a press conference a couple weeks ago, Alper said. That’s because while the State of Alaska works on a fiscal year starting each July 1, taxes are collected on the calendar year, and the immediate worry among auditors was that ending the cashable credit certificates July 1 would require two six-month tax returns for 2017. After a detailed reading of the bill, it was determined that it directs a company’s reported losses be bifurcated, meaning a company that posts losses to generate a $10 million net operating loss credit in 2017 will receive a $5 million cashable certificate for the first half of the year and a $5 million certificate that could be sold to another production taxpayer or held to offset future taxes but not cashed out, according to Alper. Finally, the credits are settled but oil taxes are not. The bill establishes a legislative oil and gas tax working group that — with the help of the three oil and gas consultants the Legislature now has on retainer — will examine the state’s fiscal regime for the industry and make recommendations in the 2018 regular session. ^ Elwood Brehmer can be reached at [email protected]

Bristol Bay study stands, but EPA moves to halt its finding

Is Environmental Protection Agency Administrator Scott Pruitt just putting the shoe on the other foot? The EPA announced July 11 that it was starting the process to withdraw the proposed determination reached under President Barack Obama’s administration to prohibit large-scale mining in Bristol Bay — a roundabout way of saying the Pebble mine project. A 90-day public comment period on the proposed withdrawal is now open through Oct. 17. Pebble Limited Partnership and its parent company Northern Dynasty Minerals hailed the decision as a major step toward returning to a normal and fair permitting process. “The current administration at EPA is closely focused on enforcing environmental standards and permitting requirements for major development projects like Pebble in a way that is both rigorous and robust, but also consistent in order to provide predictability and an even playing field for all resource developers,” Pebble CEO Tom Collier said in a formal statement. “It’s an approach all Alaskans and all Americans should support because it has the benefit of maintaining the high standards for environmental protection for which the state and country are known, while attracting investment in projects that create high-wage jobs and other much-needed economic benefits in our country.” Pebble has long held that the EPA’s push in 2014 to block mine development through its Clean Water Act Section 404(c) authority was a biased decision. That’s because the junior mining company contends the 1,000-plus page Bristol Bay Watershed Assessment, on which the 404(c) proposal was largely based, is an erroneous document developed over several years to be used as a means to reach a predetermined decision that the mine must be stopped. The Bristol Bay Watershed Assessment ultimately determined that large-scale mining in the region would irreparably harm Bristol Bay’s world-class salmon fisheries that currently support much of the areas economy. Pebble subsequently sued the EPA in 2014, alleging the agency had colluded with anti-mine activists and environmental-leaning scientists in drafting the assessment. Federal District Court of Alaska Judge H. Russel Holland saw enough validity to Pebble’s argument to issue an injunction in November 2014 halting the 404(c) proceedings until the lawsuit was resolved. A January 2016 EPA Inspector General report supported the validity of the assessment, but scolded the agency for months’ worth of missing emails and other procedural missteps related to evaluating the prospective Pebble project. Settlement talks in December 2016 that preceded President Donald Trump’s administration concluded this spring when the sides reached agreement, giving Pebble 30 months to submit its environmental permit applications for the mine at which point the 404(c) process could be resumed. However, the settlement also allows the Bristol Bay Watershed Assessment to stand. Pebble also contends the assessment’s conclusions are highly speculative, given the company has yet to submit a formal mine plan. Yet, despite the assessment being the only valid, on-the-record, scientific document upon which decisions regarding Pebble can be made at this point, Collier is confident the proposed determination to block Pebble will be withdrawn at the end of the comment period. Pebble spokesman Mike Heatwole said in an interview that a fair review of the project in a normal permitting process is all the company has ever wanted. In moving the 404(c) process prior to Pebble even applying for permits, the EPA broke from precedent, but Holland also dismissed another suit in which Pebble claimed the agency had overstepped its authority. Withdrawing the proposed determination “allows us to get an environmental impact statement on the record, which is a far more legitimate, fact-based and thorough document that has to be based upon an actual plan of development with actual science,” Heatwole said. “If you have that level of rigor it would probably make the watershed assessment moot. We have held all along that the process and that document is flawed on its premise.” Alannah Hurley, head of United Tribes of Bristol Bay, the Dillingham-based coalition that has led the fight against Pebble, said if EPA Administrator Pruitt appropriately considers all of the public comments that have been submitted supporting protections for Bristol Bay the withdrawal will be short-lived. “If they listen to the people and actually take the public comment seriously and they look at the immense amount of scientific work that went into that determination it will not be rescinded,” Hurley said in an interview. “If they choose to ignore that and ignore the scientific rigor and the will of the people — if they choose to ignore that and not take it seriously, it will be.” Hurley further argued “99.9 percent of the comments” submitted in 2014 supported the proposed determination. While a large majority of people who testified during August 2014 public meetings supported the EPA’s move, the agency’s Alaska spokeswoman Suzanne Skadowski said Holland’s injunction prevented the results of the 671,517 written comments submitted on the Federal Register from being tabulated. Heatwole contends many of the comments in support of the agency at the time were “postcards” or form letters from individuals without adequate knowledge of, or an appropriate stake in, the issue. A 2014 state ballot measure requiring legislative approval for a large mine in Bristol Bay — which Pebble argues is a blatant violation of the Alaska Constitution — was billed as a way to protect the region’s salmon and passed with 66 percent support among Alaska voters. It was supported by 72 percent of voters in Bristol Bay and greater southwest Alaska, according to Division of Election results. Skadowski called reversing course and moving ahead with the withdrawal despite the assessment being the only available science on Pebble “a policy call” made by Pruitt to see what Pebble’s plans are before making a decision. “We’ll use that existing science and whatever becomes available at that time,” Skadowski said. Heatwole cited a line in the EPA’s Federal Register notice about the withdrawal which states, “A withdrawal of the proposed determination would remove any uncertainty, real or perceived, about (Pebble’s) ability to submit a permit application and have that permit application reviewed.” The notice further reiterates that under the settlement the EPA retains the right to eventually use its 404(c) authority on Pebble if it is deemed necessary. Pebble leaders continue to say they intend to file permit applications this year for a smaller, less impactful mine than had previously been conceptualized. A recent investor presentation on Northern Dynasty’s website states the Pebble copper and gold deposit contains 1.9 percent of all the gold ever mined in recorded history. The company has been roundly criticized, even by some Republican lawmakers who have also criticized the EPA’s actions, for repeatedly stating over more than a decade that a mine plan and permit applications were coming soon, without making good on the promise. Elwood Brehmer can be reached at [email protected]

S&P joins Moody’s in downgrading state

S&P Global Ratings has made good on its warning, joining Moody’s Ratings Service in downgrading the State of Alaska’s credit ratings once again as legislators struggle to mend the state’s increasingly tattered finances. S&P knocked the State of Alaska-backed general obligation rating down one notch to AA from AA+ early July 18, citing a “continued lack of agreement on fiscal reforms to return the state to structural balance,” in a statement accompanying the action. On July 13, Moody’s also downgraded Alaska a notch on its scale, from Aa2 to Aa3 for general obligation debt, which translates to a final AA- rating. S&P also lowered its opinion of state appropriation-backed debt from AA to AA-. Alaska Energy Authority bonds, which are backed by the moral obligation of the state, were also lowered from A+ to A on July 18. The outlook on all the new ratings remains negative, according to the agency. Subsequently, S&P took the state off its negative CreditWatch list, where it had put Alaska June 20. At the time, analysts for the agency said the CreditWatch action was an indicator that S&P would be forced to downgrade the state if a long-term fiscal plan to dissolve the ongoing $2.5 billion-plus annual budget deficits was not approved very soon. “The negative outlook continues to reflect our opinion that if lawmakers fail to enact significant fiscal reforms to reduce the state’s fiscal imbalance during the 2018 legislative session for fiscal 2019 budget, Alaska’s downward rating transition will likely persist, possibly by multiple notches as its structural imbalance becomes more protracted,” S&P ratings analyst Timothy Little said in an agency release. Funding the budget with savings for another year has left Alaska with just about $2 billion in unobligated funds in the Constitutional Budget Reserve, or CBR, the state’s last liquid traditional savings account, an amount insufficient to cover another year of like deficits. The State of Alaska has spent about $14 billion from savings in less than five years. State debt manager Deven Mitchell said via email that the state has just more than $100 million in general obligation bonds left to sell from a $460 million bond package for construction projects that voters approved in 2012. The bond bank manages the state’s debt and has about $1.2 billion in outstanding bonds. Debt service for the fiscal year 2018 budget signed June 30 is $209.4 million. The latest downgrades could raise rates on future bond sales by 0.15 to 0.2 percentage points, according to Mitchell. But he also noted that the “relatively low impact” to state bond rates is due in part to a tight bond market, adding that the latest credit ratings could have up to 0.5 percentage points of impact in times of higher yield markets. It was only about a year-and-a-half ago that Alaska had perfect general obligation ratings from the “big three” raters: S&P, Moody’s and Fitch. When Alaska was going into the market to sell some of those 2012 general obligation bonds, S&P downgraded Alaska sooner than expected from its formerly sterling AAA bond rating in January 2016 and the other ratings agencies quickly followed suit with actions of their own. Gov. Bill Walker, who has spent the last two years pitching his fiscal plan for the state to legislators and Alaskans at large, noted in a July 17 press briefing that the state’s credit rating has quickly gone from as good as it gets to only better than New Jersey and Illinois, whose fiscal problems have persisted for years. “We’re better than that,” the governor said. Walker also said he would not continue to call legislators back into special sessions as a means to force a fiscal reform package unless a deal is imminent, but at the same time reemphasized the need for a fix this year. The Democrat-led House and Republican-led Senate passed similar bills to establish an annual percent of market value, or POMV, draw on the earnings of the $60 billion Permanent Fund during this year’s regular legislative session. Such a draw is the centerpiece to Walker’s fiscal plan, as it could reduce the deficit by nearly $2 billion per year. However, the majorities in the bodies have not been able to reconcile the differing contingencies each has tied to enacting a Permanent Fund POMV draw. The House Majority wanted an accompanying income tax to cover the budget deficit while the Senate was comfortable with a smaller deficit that could be sustained with minimal draws from the CBR. Elwood Brehmer can be reached at [email protected]

Unfinished business remains for Legislature

Gov. Bill Walker thanked legislators for repealing the state’s remaining oil and gas tax credits, discussed the highlights of a recent governors conference and outlined his view for getting the state to a long-term fiscal plan in a ranging press conference Monday. While Walker was in Rhode Island over the weekend attending the National Governors Association summer meeting, he said he stayed awake until about 4:30 a.m. Sunday to watch legislators do the clock limbo to pass House Bill 111 before the special session ended Sunday at midnight. The governor said he is pleased legislators were able to compromise finer points of the tax credit issue to get the big thing on which Republicans, Democrats and he agreed: ending the oil tax credit program. “I didn’t see anybody celebrating necessarily, and I think that was a true sign of what transpired; not everybody got what they wanted,” Walker said to Republican Sen. Cathy Giessel and Democrat Rep. Andy Josephson, who attended the briefing in Anchorage. As leaders of the Resource committees in their respective bodies, the two were at the center of conference committee negotiations on the tax credit bill. Passing a compromise version of HB 111 indicates the Legislature has some momentum and Walker said he’d like to see that translate to other issues like restructuring the Permanent Fund to fix the state’s $2.5 billion budget deficit, Walker said. “As much as I’d like to say ‘it’s over, everything’s fixed (with the state budget),’ we’ve got more work to do,” he said. “I say that with renewed optimism because of what I saw the other night.” Next on the list is for the House and Senate to pass the capital budget, which will allow the state to capture more than $1.2 billion in federal construction funds for a $120 million state matching contribution. However, the governor said he wouldn’t call more special sessions until it appears deals have been struck. “There’s no reason to call 60 people back when a committee is working on something,” he said, noting the expense checks legislators have collected in what has ostensibly been a continuous session since late January. “We’ve gone through a half a million dollars in per diem; we need to be careful about that,” Walker added. In the interim, the governor said he and his administration officials will continue working behind the scenes with legislators to hopefully facilitate agreements on the major outstanding fiscal issues, in particular new sources of state revenue. “It won’t be I’ll put more time on the clock and see what happens,” Walker said of the special session situation going forward. To that end, the Democrat-led House Majority and Republican Senate Majority caucuses both issued press statements emphasizing the need to get the generally nonpartisan capital budget done soon and that legislators might call themselves back to do it. Walker indicated he would like to see that happen by the end of the month. Walker also said he met with Canadian Prime Minister Justin Trudeau while at the governors meeting. Trudeau spoke to the gathering of 33 U.S. governors, but had a 20-minute conversation with Walker, in which the two discussed infrastructure issues and the concerns Alaskans have with prospective mines in British Columbia that could impact salmon in transboundary rivers. Southeast Alaska fishing, Alaska Native and conservation groups have pushed for federal intervention from the State Department on the matter with little success. “We have an opportunity on transboundary now at the prime minister level,” Walker said. Previously, Walker’s administration has met mostly with British Columbia provincial officials on the matter. Elwood Brehmer can be reached at [email protected]

Credit agency downgrades Alaska

As promised, the State of Alaska’s creditworthiness has taken another hit, just not from the latest raters to warn it was coming. Moody’s Investors Service downgraded the state’s general obligation debt rating from Aa2 to Aa3 late Thursday with a continued negative outlook — equivalent to a downgrade from AA to AA- on the scale commonly used by other agencies. It is the third time in less than two years that Moody’s has downgraded Alaska, each time citing the state’s continued multibillion-dollar annual budget deficits. On June 20 S&P Global Ratings put Alaska back on its negative CreditWatch list, a not-so-subtle hint that it would be forced to downgrade its rating for the state again if major budget reforms are not made soon, but Moody’s beat S&P to it. “The downgrade reflects the state’s ongoing structural budget imbalance, a small economy with concentration in energy production, large fixed costs, and heavy pension burden,” Moody’s analysts wrote in their associated report. “The rating recognizes that Alaska still has the means to solve its fiscal problems, and our baseline expectation remains that the state will do so before exhausting its still-considerable liquid reserves.” Aa3 is the lowest rating still considered a “high grade” by creditors. Officials in Gov. Bill Walker’s administration have stressed the fact that the Constitutional Budget Reserve, the state’s last remaining traditional savings account, will have about $2 billion left in it at the end of the current fiscal year next June, which would not be enough to cover another of similar-sized deficits. However, Moody’s considers the earnings reserve account of the Permanent Fund and its $8.5 billion in realized earnings to be liquid reserves. Utilizing Permanent Fund earnings in a sustainable fashion is the centerpiece to the budget solutions pushed by Walker and supported but not finished by the Legislature. To date, the Permanent Fund’s income has never been used by the state for anything but paying dividends to residents. The downgrade comes as legislators are headed back to Juneau to hopefully reach a deal on oil tax credit legislation in the last couple days of the special session called by Walker. And while a deal on the tax credits is far from the fiscal overhaul the credit agencies, the governor and most legislators themselves have said the state desperately needs, it is another step in that direction. Walker said in a statement from his office — which is quite similar to the quotes he offered the last time Moody’s downgraded Alaska last July 25 — that the downgrade is “concerning but not surprising.” “In spite of significant financial reserves and the lowest tax burden in the nation Alaska continues to operate with a structural budget imbalance that is, according to Moody’s, both unstable and unparalleled by any of the other 49 states,” Walker said. “In the last three years, Alaska has gone from the highest credit rating in the nation to the third lowest, better than only Illinois and New Jersey. We simply cannot afford to wait any longer to take our finances and budget issues seriously. Alaskans are depending on us. I will continue to work to resolve Alaska’s fiscal problems this year.” In concert with lowering the state’s general obligation rating, Moody’s lowered Alaska’s revenue bond rating from Aa3 to A1 and its moral obligation bond rating from A2 to A1, which are “upper medium grade” ratings. At the same time Moody’s affirmed the Alaska Municipal Bond Bank Authority’s A1 rating with a negative outlook. The bond bank manages the state’s debt and has about $1.2 billion in outstanding bonds. Its rating was not affected because of the Legislature’s continued willingness to replenish the bond bank’s funds when need be, according to Moody’s. Elwood Brehmer can be reached at [email protected]

ConocoPhillips putting LNG plant in deep freeze

Unable to find a suitable buyer, ConocoPhillips is preparing to fully shut down its once-renowned Kenai LNG plant. ConocoPhillips spokeswoman Amy Burnett wrote in a statement Wednesday that the company is preparing to put the plant into long-term shutdown mode this fall. “The reduced operations will focus on continued preservation of the facilities for future LNG exports,” Burnett wrote. How long the plant is mothballed will depend on market conditions and right now there are about 30 people working at the LNG plant, 18 of whom are ConocoPhillips employees, she added. Burnett said the company is currently assessing future staffing needs. The Kenai facility has been idle for nearly two years, with its last export in the fall of 2015, as depressed global LNG prices have simply pushed it out of the market. Spot prices for LNG cargos delivered to the East Asia countries the plant has historically supplied were about $5.50 per million British thermal units in May, according to the Federal Energy Regulatory Commission. That is less than the equivalent wholesale price for unprocessed Cook Inlet natural gas in local utility contracts, which is currently in the $7 range. Last fall ConocoPhillips said it was putting the plant and associated marine terminal up for sale; the company began actively marketing the facilities in January. Alaska Gasline Development Corp. officials working on the Alaska LNG Project that would put a massive LNG plant adjacent to ConocoPhillips’ said at the time they were interested in the plant but a deal has yet to materialize either with the state-owned corporation or a private party. Discussions with potential buyers are ongoing, according to Burnett. The federal Department of Energy export license tied to the Kenai plan expires in February 2018. The Kenai LNG plant was the world’s largest when it opened in 1969 and has served as a means to strengthen the trade relationship between Alaska and Japan, where most of its cargoes landed. According to ConocoPhillips, the plant has filled LNG tankers with more than 1,300 shipments of cargo over its nearly 50-year life. LNG exports from the plant were also suspended late in 2012 — despite record-high prices globally — when many state officials feared declining Cook Inlet gas production would not be sufficient to meet local heat and power needs. Exports resumed in May 2014 with a few shipments to Asian customers prior to the global LNG price collapse. Selling the LNG facilities would pretty much complete ConocoPhillips’ exit from the Cook Inlet gas market. Early in 2016 the company sold off its last stake in Inlet gas reserves when it sold its one-third share of the longstanding Beluga River gas field to Anchorage utilities for $152 million. Oil and gas industry majors left the Inlet over the past decade as production from maturing fields was declining. Hilcorp Energy and smaller independent companies able to turn profits from smaller fields have since — with the help of state tax incentives — stabilized the Cook Inlet natural gas market and increased production from the basin. Elwood Brehmer can be reached at [email protected]

House maneuver proposes no deductions on oil taxes

Despite being locked in a rhetorical battle over who can compromise more, House Democrats and Senate Republicans still can’t agree on what the state should offer in lieu of refundable oil tax credits. The sides held an overall rather odd conference committee meeting on House Bill 111 Wednesday afternoon with Democrat members in Anchorage and Republicans teleconferencing from Juneau, where the Senate has reconvened. A few dozen members of the Laborers’ Local 341 union rallied outside the Anchorage Legislative Information Office building before the meeting and crowded the meeting room to express their distaste for the House proposal to end carry forward annual loss deductions Jan. 1. House Resource co-chairs and Anchorage Democrats Reps. Andy Josephson and Geran Tarr stressed that they do not want to do away with the carry forward, or net operating, loss deductions, but rather proposed to end them as a means to push the Republican Senate Majority to continue the oil tax debate next year. “There’s no intent on our part to not allow the recovery of losses,” Tarr said. What the House Majority does want, according to Tarr, is at a minimum to close the gap between the effective production tax rate, which is between 8 percent and 12 percent for producing companies at current prices, and the deduction rate the Senate has proposed, which is 35 percent. Additionally, the Democrat-led House caucus wants more production tax reforms resulting in more tax revenue to help the state fill its $2.5 billion budget deficit. The deduction rate proposed by the Senate matches the current 35 percent base tax rate, which is reduced by a sliding scale per barrel of production that increases as prices drop. The Democrats’ version of House Bill 111 passed during the regular session eliminated the sliding scale credits, and set the net tax rate at 25 percent with a matching 25 percent deduction. “Our position is to have a serious discussion of the state’s tax structure,” Josephson said. “We’re willing to postpone that serious discussion until 2018.” Putting a sunset on the ability for companies to carry forward their loss deductions would put pressure on getting that reform done, Josephson said, because nobody wants to see that provision gone for good. In explaining the need for the pressure, he described the Legislature as “the people that shop for Christmas on Christmas Eve,” which is borne out in the fact that both sides have agreed on the need to end the state’s refundable tax credits since the first session started six months ago, yet it still hasn’t been done. And even with the group of upset but quiet union workers attending, the contentiousness in the meeting was between the legislators. At the outset Southeast Republican Sen. Bert Stedman questioned Tarr’s ability to hold the meeting given the House had not yet convened and resolved to take up HB 111 in the special session. To that, the Democrats produced a memo from legislative attorney’s that ostensibly said it’s ok for the Legislature to break its own rules. Stedman, who is rarely one to mince words, said, “one thing that’s certainly predictable is the unpredictability of the Legislature.” And he insisted the most unpredictable thing legislators could do would be repealing the credits without a replacement — tax deductions that are a basic part of most any profits tax — on just the promise that something will be done later. While Stedman has expressed his concerns over the sliding scale per barrel credit that reduces the tax rate as oil prices fall, he likened the proposal to “throwing industry into the freezer and shutting the door on them.” Tarr indicated another meeting would likely be held Thursday, but most progress towards an agreement will probably happen in negotiations outside of the conference committee meetings; and this special session ends Saturday. “I remain optimistic until there is no time left,” Tarr said. Elwood Brehmer can be reached at [email protected]

ExxonMobil working on plan for Point Thomson gas at Prudhoe

With the Alaska LNG Project far from a sure thing, ExxonMobil is preparing to stuff natural gas from its Point Thomson field into the Prudhoe Bay oil and gas pool in order to make good on its 2012 settlement with the State of Alaska. ExxonMobil outlined the major, long-term project concept in the 2017 Point Thomson unit plan of development it submitted to the Division of Oil and Gas June 30. Moving natural gas from Point Thomson for injection into the Prudhoe Bay field could be a way to further enhance oil recovery from Prudhoe. The reinjection of gas produced during oil production efforts at Prudhoe has been a primary driver behind BP’s ability to extract more than 30 percent more oil — currently about 12.5 billion barrels in total — from the massive field than was expected when it came into production 40 years ago. Production facilities at Point Thomson would first be expanded to handle production of more than 50,000 barrels per day of natural gas liquids, or condensates, and 920 million cubic feet per day of gas. Point Thomson is one of the highest pressure producing gas fields on Earth, at about 10,000 pounds per square-inch. A positive of the reservoir pressure is that it makes separating the liquids from the gas much easier. According to ExxonMobil officials, the liquids essentially “fall out” of the gas once the pressure is relieved. Overall, the field holds about 8 trillion cubic feet of natural gas, which is about 25 percent of the known gas reserves on the North Slope. The Point Thomson and Prudhoe gas reserves would be the initial resources to supply a gasline project, such as the $40 billion Alaska LNG Project the state is pursuing with assistance from BP. ExxonMobil, which operates Point Thomson, and BP, its primary working interest owner partner, spent roughly $4 billion developing the gas field since 2012. Production started in late April of last year. Currently, the Point Thomson facilities were designed with an expected production capacity of about 10,000 barrels of condensates and 200 million cubic feet of gas per day. The condensates are sent down the Trans-Alaska Pipeline System and the gas is reinjected. Fine-tuning the facilities allowed production to exceed 200 million cubic feet of gas and 10,000 barrels of condensate on Dec. 20, 2016, according to the planning document. Getting the gas from Point Thomson to Prudhoe would require construction of a 62.5-mile, 32-inch diameter gas pipeline between the fields and production would be ramped up with the drilling of three new wells, according to the plan of development. The two wells now used for gas injection would also be converted to production. ExxonMobil Alaska Production Manager Cory Quarles wrote in a letter attached to the plan that the preferred way to further develop Point Thomson would be through a gasline project, but the expansion plan the company submitted is necessary under the terms of the 2012 settlement because a major gas project was not sanctioned by June 1, 2016. Quarles additionally wrote that the company will continue to work towards making gas available to any gasline project, including the state-led Alaska LNG Project effort, “under bilateral, mutually-agreed and commercially reasonable terms.” The 2012 Point Thomson Settlement Agreement reached by former Gov. Sean Parnell’s administration ended a longstanding dispute between the state and ExxonMobil over developing the field. Moving Point Thomson gas to Prudhoe is one of a couple options Exxon had under the settlement once a gasline project was not sanctioned. The other was simply expanding condensate production by at least 20,000 barrels per day and continuing to reinject the gas. Some former state officials that worked on the Alaska LNG Project have questioned the economics of the concept. An ExxonMobil spokesman said the company could not provide a cost estimate for the project at this point. Development plans are usually annual documents but the Point Thomson settlement prescribes that ExxonMobil does not need to submit another for the gas field until 2019, which is when the company and its working interest owners have to commit to further development of some fashion — again if a gasline is not sanctioned by then. Alaska Gasline Development Corp. President Keith Meyer has said he hopes to reach a final investment decision on the Alaska LNG Project by early 2019. Last year and so far in 2017 Exxon and the working interest owners in Point Thomson and Prudhoe — primarily BP and ConocoPhillips — started work to identify the commercial agreements that would be needed to move gas between the fields, according to the development plan. ConocoPhillips sold its 5 percent interest in Point Thomson earlier this year. Next year the companies will work on a “Heads of Agreement” outlining the operating structure of the project while negotiating the potentially complex commercial arrangements that would be needed and start detailed engineering leading to a commitment decision at the end of 2019, the document states. Elwood Brehmer can be reached at [email protected]

Utilities pitch expansion at Bradley Lake hydroplant

Railbelt utility leaders want the Alaska Energy Authority to approve a $46.4 million expansion of the Bradley Lake hydroelectric plant. AEA management is on board with the proposal, but during the June 29 AEA board meeting, members questioned both as to why they should approve the project when transmission line constraints already prevent what is the lowest cost power source in the region from being used to its full potential. The Battle Creek diversion project would add about 37,300 megawatt hours per year to Bradley Lake’s current power production, which is nearly 10 percent of its average annual output. That would supply enough additional hydropower to meet the needs of about 5,200 households in the region, according to AEA Owned Assets Manager Bryan Carey. Specifically, the Battle Creek project consists of constructing a 16-foot high, 60-foot wide concrete dam to divert water into a five-foot diameter, high-density polyethylene pipe. The pipe — using natural elevation changes — would carry the water 1.7 miles to the Bradley Lake facilities. A 2.9-mile gravel road would be built to access the dam and most of the road would be built directly on top of the buried water pipe to make the most use out of the pipeline corridor. The water from Battle Creek would be stored in Bradley Lake, thus providing additional water to be run through the existing powerhouse, Carey said. AEA estimates the final cost of wholesale power from the Battle Creek diversion would be 7.35 cents per kilowatt-hour if it can be debt-financed over 30 years at 4 percent interest. AEA owns Bradley Lake, which is about 30 miles east of Homer at the head of Kachemak Bay, and would also own the Battle Creek project, thus the project needs to be approved by the authority’s board. The Railbelt electric utilities each purchase a prescribed share of power from Bradley Lake to cover its costs and would do the same for the portion of power attributable to Battle Creek. Chugach Electric Association CEO Lee Thibert said to the AEA board that the Battle Creek power would initially be slightly more expensive than some other generation options but over the life of the project it would provide rate stability that would be a benefit to Railbelt ratepayers. “(Battle Creek) is in our best interest for long-term energy needs,” Thibert said. Currently, there simply isn’t enough water behind the 125-foot high Bradley Lake dam to run the two 60-megawatt generators full-bore full-time, he explained. According to Thibert, the utilities want to get the project, which has gone through environmental reviews, out to bid this year. Aquatic monitoring found no fish within several miles of the proposed dam site, according to the authority, and it believes salmon habitat near tidewater could be improved because the dam would remove glacial water and moderate summer stream flow. The run-of-river Battle Creek diversion would be shut down in the winter when there is no water flow from Battle Glacier, Carey noted. AEA Executive Director Michael Lamb said federal interest rate hikes are the driving force for wanting to move quickly. “There is a sense of urgency because the cost of money is going up. That changes the dynamics of what the cost of (Battle Creek) is in the long run,” Lamb said. The board did not take any action on the Battle Creek proposal at its latest meeting, but a resolution to approve it will likely be put before the board soon, according to AEA officials. Bradley Lake has largely been a success story. As it stands, Bradley Lake supplies 9 percent of the Railbelt’s electric supply and is the lowest cost power in the region at about 4 cents per kilowatt-hour, according to AEA. The 120-megawatt hydro project, which was finished in 1991, has a cumulative cost of $328 million when post-construction capital improvements are added in. Carey said AEA estimates Bradley Lake’s replacement costs to be in the $500 million range. Overcoming constraints While expanding what has worked well would seem to be a sure-fire win, AEA board members expressed a little skepticism about the necessity of the Battle Creek project given authority management recently finalized a study that contends the Kenai Peninsula electric transmission system needs more than $400 million in upgrades to run at peak efficiency. Currently, there is just one 75-megawatt capacity transmission line connecting Bradley Lake to the Railbelt grid, meaning the 120-megawatt hydro project already can’t be utilized to full capacity. AEA board Vice Chair Dana Pruhs, owner of Anchorage-based Pruhs Construction, likened Battle Creek to building a four-lane bridge on a two-lane highway. However, the utility leaders said the benefits of the Battle Creek project could still be realized, even if the transmission situation is less than ideal, because of the options hydropower affords. Unlike most other forms of renewable energy, traditional hydropower such as Bradley Lake allows managers to schedule power production because the power is essentially stored in the water behind the dam. It is not dependent upon uncontrollable forces such as wind or sunlight; adding Battle Creek water would allow the Bradley Lake generators to be run at the maximum transmission capacity longer and displace some of the higher cost natural gas-fired generation the Railbelt relies on heavily, Chugach Vice President Paul Risse explained. “If that (transmission) constraint were lifted it would be of greater value,” Risse said, but operating under the constraint still allows the utilities to use all the power, just not to its maximum economic benefit. AEA’s Railbelt Transmission Study estimates that $885 million of investment in major electric upgrades from Homer to Fairbanks — including multiple segments of wholly new lines — could save the region’s ratepayers up to $80 million collectively by the time the work is done in 2030. The utilities don’t dismiss the fact that the upgrades would provide for a more efficient, reliable transmission system as a whole, but stress the economics simply don’t work out for entities that must answer to their own ratepayers first. Matanuska Electric Association holds rights to a 14 percent share of Bradley Lake power, which is about 10 megawatts, MEA General Manager Tony Izzo said. At the same time, the utility has a 171-megawatt high efficiency gas-fired plant that can reliably supply many times more power to his ratepayers without hundreds of millions of dollars in transmission investments. Battle Creek is an opportunity to diversify the utilities’ fuel supply and add to what is a long-term, low-cost power option, while the transmission infrastructure is a different debate entirely, Izzo said. “We prioritize things all the time,” he said. “In today’s economics with declining kilowatt hours (of demand) we’re focused on trying to find the lowest cost energy, not build a system that is as redundant as the Lower 48 without the ratepayer base to possibly afford it.” Chugach’s Thibert said that today’s economics, particularly with oil prices making diesel-fired generation competitive with natural gas in Fairbanks, don’t allow the transmission intertie improvements to pay for themselves. Brad Janorschke, general manager of Homer Electric, which serves most of the Kenai Peninsula, reiterated the sentiments of Izzo and Thibert. He said he would like to see some of the transmission improvements made, but a lack of load growth — from residents using power more efficiently and stalling economic growth — challenges those projects. “When it boils down to economics adding a more robust transmission system on the Kenai Peninsula, for my members, does not give me an opportunity to secure more less expensive power than what I already have today,” Janorschke said. “So for me the numbers don’t pencil out.” AEA board member and state Commerce Department Deputy Commissioner Fred Parady said the disagreement between AEA and the utilities over what needs to happen to the electric transmission system is a fundamental issue that needs to be settled. “Something’s missing here. The gap between the utilities and AEA over how the list (of transmission projects) gets prioritized or what we do have in common, that we agree with, that should be tackled. It’s just got to be resolved,” Parady said. “This is an engineering question, an economics question; the gap in perception of that is dysfunctional for all of us.” Elwood Brehmer can be reached at [email protected]

New year, same stalemate

It might be the peak of summer, but it feels a lot more like Groundhog Day in Alaska politics. Gov. Bill Walker held a press briefing at noon July 10 at which he again urged legislators to pass the bills needed to cure the state of its massive annual deficits. The budget deficit was about $2.5 billion for the 2017 fiscal year that ended June 30. “I know I’ve been critical of the Legislature as a whole; it’s about getting the job done,” Walker said at the state Atwood Building in Anchorage. One day short of a year earlier, the Legislature convened for a special session called by Walker to make cuts to the state’s North Slope oil and gas tax credit program, approve spending investment earnings from the Permanent Fund on government services and other revenue measures in the governor’s fiscal plan. “I am absolutely convinced that if we don’t fix this now, then our challenges next year will be even more magnified,” the governor said during a June 19, 2016, news conference shortly after the House Finance Committee shot down his Permanent Fund restructuring bill. As he spoke July 10 — somewhat through reporters to legislators — lawmakers were again hung up on North Slope oil and gas tax credit legislation in a summer special session. This year, the debate is not as much over ending the credits as both the Democrat House Majority and the Republican Senate Majority agree the shelf life on the refundable tax credit experiment has expired. The sticking point now is whether to raise oil taxes as well. Each caucus held a press conference in recent weeks to publicly pitch their version of House Bill 111, the tax credit legislation, once more. Republican Senate President Pete Kelly said at the time he would call the Senate back to order July 10 to work on finalizing the bill if House Majority leaders would schedule conference committee meetings. House Democrat leaders said they would call meetings if progress was made in private negotiations, which is how they said Senate leadership wanted to proceed. On July 11 the House Majority announced it would hold an HB 111 conference committee meeting July 12 in Anchorage. Walker did not specify if or when he would call legislators back for a third time this year if a comprehensive deal isn’t reached in the next few days but said he talked with legislative leaders over the weekend and was encouraged by what he heard. “We’re going to let this week play out,” Walker said. It is worth noting that legislators could call and set the agenda on their own special session with a two-thirds vote of the combined House and Senate. Both bodies have also passed differing versions of Walker’s Permanent Fund bill, which could provide up to about $1.8 billion per year in new General Fund revenue, but contingencies tied to its passage have stalled progress there. Simply put, the Democrats want an income tax and the Republicans don’t. Walker has supported a small state income or sales tax, but said Monday the state generally needs new revenue sources, through taxes, the Permanent Fund or something altogether different. “We do need new revenues,” he said, repeating a sentiment he has stressed virtually daily for almost two years. “I know people push back a bit on that but we need a way of funding government. When you lose 80 percent of your revenue you can’t live on savings forever.” On June 20, S&P Global Ratings made it known once again that credit raters are still anxious about the State of Alaska’s finances when the agency put the state back on “CreditWatch negative,” indicating if lawmakers don’t make major changes soon the ratings agency will have to downgrade the state’s credit rating. All three major credit houses downgraded Alaska early in 2016 for its budget problems. S&P also had the state on a negative CreditWatch last summer but pulled the warning after Walker made significant vetoes to the operating budget, which included the unprecedented move of halving the Permanent Fund dividend. However, the state’s savings are one marked difference between this year and last. Last year, the state had one more year’s worth of savings to fill the deficit, inevitably challenging the push by Walker and some legislators to overhaul the state’s finances then. Now, administration officials estimate the state will have about $2 billion left in the Constitutional Budget Reserve at the start of fiscal 2019. That means covering the deficit with savings next year is a long shot and would basically wipe out the CBR — the last available savings account — if it can be done at all. Walker noted the state has used about $14 billion in savings just since 2013 as a way to again emphasize the need for fiscal reforms. With the big pieces of such reform all in conference committee the governor once more asked legislators to finish the job. “Since you’ve done the hard work to take the tough votes and potentially unpopular votes — there’s no popular votes that are out there when you’re fixing a fiscal plan,” Walker said. “They’ve done that; you might as well get the product from it.” Capital budget still unresolved While the political debate, rhetoric and grandstanding of the last six months has focused on the legacy issues of fiscal policy, there is still one outstanding annual matter that has almost been forgotten about, and that’s the 2018 fiscal year capital budget. The capital budgets of recent years have been bare bones, with virtually no direct state appropriations to construction projects as spending has retracted. That has cut out a lot of lobbying from local governments and special interests to get their projects funded and ostensibly made passing capital budgets under the Walker administration a formality. However, the capital budget also authorizes the administration to receive and spend more than $1 billion each year in federal highway and airport maintenance funds that require only a 10 percent state match. The state is set to receive nearly $1.2 billion in federal funds in the 2018 capital budget. “That 90-10 match, that means a lot to everybody in Alaska and it’s an important part of our economy,” Walker said. Walker did not put it on the current special session call and said deciding whether to ask legislators to prioritize passing it or how to pay for the state’s portion — with a Permanent Fund or other revenue bills — has been a minor challenge. He did say, though, that his administration is watching the calendar to make sure being without the fiscal 2018 capital budget funds doesn’t impede engineering and design of next year’s road projects. State Management and Budget Director Pat Pitney said there is no definitive date that the state has to have a capital budget passed by, but getting it done before September would save folks in her office a few headaches. The Senate passed a capital budget with $120.5 million in unrestricted General Fund appropriations May 12. The House was prepping to pass a very similar bill June 14, but majority caucus leaders rolled the operating budget and a full Permanent Fund Dividend of some $2,200 into the capital bill in a last-minute political move that the Senate rejected at the end of the first special session. ^ Elwood Brehmer can be reached at [email protected]

House Majority counters Senate offer on oil tax credits

With less than 10 days left in the year’s second special legislative session and a laundry list of critical issues left to tackle, House Democrats offered Senate Republicans their own compromise to tentatively end the omnipresent oil tax debate. The Democrat-led House Majority coalition issued a statement Friday afternoon saying its members would agree to just end North Slope oil tax credits this year on the premise the Legislature would again revamp the overall production tax next year. The Legislature overhauled the production tax code in 2013 when both the House and Senate were under Republican control. That legislation, best known as Senate Bill 21, withstood an August 2014 voter initiative to repeal it by a 52-48 margin. House Majority members said during a Thursday afternoon press briefing in Anchorage that the caucus is open to compromise — just not the deal the Republican Senate Majority offered exactly a week earlier at a similar gathering. Republican legislators have urged their counterparts to pass legislation to end the state’s North Slope oil and gas tax credit program, the one thing on which both sides and Gov. Bill Walker agree. Fairbanks Republican Senate President Pete Kelly said he will reconvene the Senate July 10 to hopefully reach an oil tax and credit deal. The current special session called by Walker ends July 16. The Senate proposal to retroactively cut the payouts as of July 1 sounds good, but according to the House Majority it would not save the state the $1.5 billion over the next decade that Senate leaders purport. That’s because the version of House Bill 111 the Senate is pushing would simply switch the $150 million per year of tax credits the Revenue Department estimates North Slope operators will earn on average from direct cash payments each year to equal-value tax deductions, meaning about $1.5 billion less in future production tax revenue. The primary tax credit at the heart of the issue is the 35 percent net operating loss, or NOL, credit available to North Slope oil explorers and producers with less than 50,000 barrels per day of production. It can be earned by companies that end the year in the red as a result of exploration and development costs, low oil prices or a combination of those factors. House Resources Co-chair and primary drafter of the original HB 111, Rep. Geran Tarr, D-Anchorage, said swapping out the cashable tax credits for like tax deductions would just prolong the oil tax fight. “Our concern is the industry needs stability,” Tarr said Thursday. “They need to have whatever incentive program — something we actually can afford, which has not happened over the last few years. So if you replace it with something that’s the same amount of money I have every reason to believe that would not be affordable either.” A year ago Senate Republicans were dead-set against changes to the North Slope tax credits while reluctantly agreeing to phase out credits for Cook Inlet operators. But continued low oil prices translating to less state revenue and political pressures caused them to reverse course on their stance. The Senate Majority also floated the proposal to “ring fence” deductions, or require they only be used to offset production from the project through which they were earned, a provision suggested by Walker in his pitch for a broader fiscal plan compromise to alleviate the state’s $2.5 billion-plus annual budget deficits. However, they are still fighting the House Majority on changing the underlying production tax code. “Creating fair oil tax reform is a priority for our coalition and is vital to any comprehensive fiscal plan,” Anchorage Democrat and House Majority Leader Rep. Chris Tuck said Thursday. Republicans and industry representatives stress keeping the 35 percent tax deduction is critical to maintaining the viability of future North Slope developments, noting that the ability to deduct expenses or losses from a tax liability is a fundamental feature to nearly any net tax regime, whether it is a personal or corporate income or a severance tax. The problem with the status quo, according to the House Majority — particularly at current oil prices — is the effective production tax rate doesn’t come close to matching the 35 percent loss deduction. Therefore, the House coalition is pushing for a simple 25 percent net profits production tax with a corresponding 25 percent loss deduction. While applying deductions to a net profits tax is a nearly universal practice, the percentage of a loss that can be applied to reduce a tax obligation also usually matches the statutory tax rate. Alaska’s current oil production tax has a base rate of 35 percent, but that is only applicable to oil produced from the state’s large and mature fields at prices in the $150 per barrel range. As prices fall the major oil producers can apply per barrel credits that increase in value as the price falls to lower the effective tax rate. According to the state Tax Division, the effective production tax rate on legacy oil under current law is 20 percent at $90 per barrel and down to 8.1 percent at $70 per barrel. Producers operating more recent developments can apply a fixed $5 per barrel credit to reduce the taxable value of their oil regardless of price and are eligible for other tax reductions. The House Democrats contend their tax proposal would generate about $800 million in additional production tax revenue over the next 10 years and more closely resemble other profits-based tax systems. Republicans argue the lower tax rates at lower prices are necessary to offset the unavoidably high North Slope operating costs. They also point to increased North Slope production over the past two years — historical anomalies — as proof the current tax structure is working. According to the Democrats, the state isn’t seeing the benefit of the production boost and won’t in the future with the current tax and oil price regimes because the deductions will evaporate virtually all of the production tax revenue before it reaches state coffers. Tarr called the Senate’s idea to retroactively end the cashable credit certificates July 1 “unworkable.” The state fiscal year started July 1, but companies pay their taxes on the calendar year. Additionally, Republican legislators have long said tax changes need to be made prospectively and both version of HB 111 passed by the House and Senate have Jan. 1, 2018, effective dates, which made the July 1 idea a surprise. Tarr said she was also caught off-guard by the Senate Republican’s June 29 press conference and credit proposal because the sides were talking behind the scenes. “We had been in conversations and I thought the conversations were really productive,” she said. The senators stressed at the June 29 press conference that the state is currently accruing a credit liability of about $1 million per day; so ending the program six months sooner could save the state nearly $200 million. Tarr also chairs the conference committee on HB 111 and thus it is ultimately her decision as to when the committee meets because it is a House bill. Walker added the Senate’s version of HB 111 to the special session call after the two bodies agreed on an operating budget June 22. Tarr said in a brief interview that she thought there was agreement to raise the gross minimum tax floor to 5 percent from the current 4 percent, which would raise an estimated $45 million per year, as well as consensus on smaller provisions. The large producers are now paying the gross tax minimum at the current price of less than $50 per barrel. The net profits tax kicks in at about $70 per barrel. Ensuing negotiations will determine if House members join the Senate back in Juneau next week. “If we can see some progress in some preliminary discussions I think (holding meetings) would be worthwhile, but it’s very costly for people to go to Juneau and be there if we cant resolve those issues,” Tarr said. She indicated a desire to have the Legislature’s new suite of oil and gas consultants testify before the conference committee as a means to a public dialogue but said Senate leaders prefer to stick to tradition and use conference committee meetings to formalize what was agreed to in private negotiations. The Legislative Budget and Audit Committee has contracted with Houston-based oil and gas consultant firms Gaffney Cline and Associates and Palantir USA Inc. It also renewed its contract with Rich Ruggiero, a longtime industry engineer and founder of the oil economics consultant firm Castle Gap Advisors who testified extensively on HB 111 and legislators in both parties generally liked. Elwood Brehmer can be reached at [email protected]

Murkowski takes another crack at energy bill; OCS review opens

As promised, Sen. Lisa Murkowski is taking another shot at the major task of updating the country’s energy policy. Murkowski introduced the Energy and Natural Resources Act June 28. The omnibus energy reform bill is pretty much a continuation of the Energy Policy Modernization Act, which died last December when House and Senate conference committee negotiations stalled. “This new bill encompasses a wide range of Alaska priorities for energy, resource, innovation, infrastructure and land management policies. It will allow us to tap into more of our world-class mineral base, removes hurdles to the gasline, expand the use of hydropower and other renewables, reauthorize critical programs that provide vital funding, boost Alaska Native energy development, increase sportsmen’s access to federal lands and protect against natural hazards,” Murkowski said in a release from her office. “This is a bill written by and with Alaskans, for the benefit of our whole state and I’m eager to work with my colleagues to move it forward.” Murkowski, who chairs the Senate Energy and Natural Resources Committee, often stressed that last session’s Energy Modernization Act was also drafted in concert with Washington Sen. Maria Cantwell, the ranking Democrat on the committee and a co-sponsor of the current bill. Last year’s legislation passed the Senate with 85 votes and Murkowski blamed House leaders — who she accused of being more interested in leaving for the holidays than working on the bill — when it fell just short of making it to the president’s desk. This go-round, Murkowski got Senate Majority Leader Mitch McConnell to put the Energy and Natural Resources Act on the Senate Calendar right away, giving the bill an expedited timeline for a floor vote, according to a committee release. Among many other provisions, the bill federally classifies hydropower as renewable energy; gives route options for a natural gas export pipeline through Denali National Park; mandates the Secretary of Energy to rule on LNG export applications within 45 days after the environmental review of a project is finished; and directs a suite of permitting reforms for energy generation and distribution and mineral projects. Arctic OCS plan In between scolding President Donald Trump on Twitter for regular off-hand remarks on social media, Murkowski praised the Trump administration June 29 for working to reverse a ban on federal Arctic offshore oil and gas leasing instituted by President Barack Obama in the waning days of his presidency. In April, Trump issued his own executive order to reverse Obama’s moratorium on Arctic offshore leasing. On June 29, the Interior Department issued a request for information to revise the 2017-2022 outer continental shelf, or OCS, oil and gas leasing plan the Obama administration finalized in November sans a schedule for any Arctic lease sales. The request for information is the first step in what is likely to be a multi-year process to revise the leasing schedule. Interior Secretary Ryan Zinke also ordered onshore oil and gas resource evaluations for the Arctic National Wildlife Refuge and a new look at the management plan for the National Petroleum Reserve-Alaska during a trip to Anchorage May 31 with an eventual aim at more industry activity on federal North Slope lands. “I’m pleased the administration has wasted no time in starting the process for a new and better plan that could increase offshore development in Alaska and elsewhere,” Murkowski said. “With technological innovation, offshore development is now cheaper, easier, safer and farther-reaching than ever before. “What has not changed is that offshore development is a critical source of energy, jobs and security, so I look forward to working with Secretary Zinke to develop a strong plan for our state and nation.” Arctic development in near shore state waters to date has consisted of constructing manmade islands and Hilcorp Energy is currently in permitting for its Liberty prospect, which would be the first such manmade island project in shallow federal waters off the North Slope. The U.S. Geological Survey estimates the Beaufort and Chukchi Seas could hold 23 billion barrels of oil and another 104 trillion cubic feet of natural gas. Even with federal support to drill for those resources, it is unclear how much interest industry would have in green field development in such a high-cost arena with oil and prices expected to remain low for years to come. ^ Elwood Brehmer can be reached at [email protected]

State, Korean gas buyer agree to collaborate on AK LNG

The state gasline corporation reached a preliminary agreement with one of the largest LNG buyers in the world June 28 in Washington, D.C. Alaska Gasline Development Corp. President Keith Meyer and Korea Gas Corp. CEO Seung-hoon Lee signed a memorandum of understanding that puts in place a framework for the two state-run corporations on opposite ends of the LNG trade to work on development of, and possibly investment in, the $40 billion Alaska LNG Project. Under the MOU, AGDC and Kogas, as it is commonly known, will set up a joint committee that will have decision-making authority to collaborate on Kogas’ potential involvement in development and in some fashion operations of the project, according to AGDC. “This MOU between AGDC and Kogas is beneficial for both organizations. AGDC gains the opportunity to move Alaska LNG forward with an internationally recognized natural gas infrastructure company,” Meyer said in a corporate release. “Kogas gains the prospect of investing in Alaska LNG as well as participating in all aspects of project development and financing. The MOU is not exclusive and recognizes AGDC is in discussions with other parties to ensure timely development of Alaska’s energy infrastructure and export project.” Kogas is the main LNG buyer in South Korea and the second-largest corporate LNG buyer in the world. South Korea is also well established as the number two LNG importing nation in the world behind Japan. In 2015, South Korea imported 33 million tons of LNG, which was about 13 percent of the global LNG trade that year, according to the International Gas Union. The Alaska LNG Project is designed to produce up to 20 million tons of LNG per year at full capacity, but that would almost certainly be split amongst numerous buyers. AGDC’s top priorities this year are marketing the Alaska LNG Project to potential buyers and investors and subsequently establishing a commercial structure to underwrite construction of the trans-Alaska natural gas export project, Meyer has said. The corporation and Gov. Bill Walker ultimately hope to have the project up and running in the mid-2020s. While the AGDC and Kogas leaders posed for a handshake after signing the MOU, their bosses were also meeting in Washington, D.C., as part of President Donald Trump’s “Energy Week” initiative. Walker met with South Korea President Moon Jae-in June 28 after Walker participated in an energy roundtable discussion at the White House, according to a release from the governor’s office. “Korea has been one of the largest consumers of Alaska’s coal, timber and fish,” Walker said in a formal statement. “President Moon said he would like to add LNG to the list of imports and offered his government’s support of the Alaska LNG Project. I was pleased to hear President Moon say LNG will play a very important role in helping Korea combat climate change. I also told President Moon that during my meeting at the White House, President Trump had expressed deep support for the export of LNG from the United States to Asia, including Alaska’s LNG.” AGDC is also currently holding an open season to solicit customer interest in the natural gas and liquefaction tolling project, Meyer said at the corporation’s June board meeting. The open season will run from mid-June through August and AGDC’s goal with the marketing effort is to attract non-binding deals mainly from the state’s former partners in the project, the North Slope producers, to sell gas into it. Elwood Brehmer can be reached at [email protected]

Senate wants end to oil credits now, reconvening July 10

State Senate Republicans pitched their latest plan to once and for all end refundable oil and gas tax credits much sooner than later. Senate President Pete Kelly, R-Fairbanks, said at a Thursday morning press conference in Anchorage that a combination of lower-than-expected oil prices and fewer exactable budget cuts than Republican majority members wanted has made ending the program immediately an urgent matter. For those reasons Senate Republicans proposing the final version of House Bill 111 have an effective date that retroactively ends the credits for North Slope operators and explorers elsewhere in the state July 1. The differing versions of the bill that passed the House and Senate this spring have Jan. 1, 2018 implementation dates and would end the credit program then. The senators stressed that the state is currently accruing a credit liability of about $1 million per day; so ending the program six months sooner could save the state nearly $200 million. Those payments, which under current law are for up to 35 percent of a small producer or explorer’s annual losses, would be transformed to tax deductions that could be applied immediately or held to offset future liabilities. It would be similar to how the North Slope majors that are not eligible for the cashable credits use their carry-forward production tax deductions. Legislators are unofficially adjourned from the special session Gov. Bill Walker called June 16 to address a litany of budget and fiscal issues. Kelly said the Senate will convene in Juneau again July 10 with the hope of quickly resolving the differences in HB 111 with the Democrat-led House Majority. The 30-day special session ends July 16. Both caucuses and the governor have said since before the regular session started in January that ending the credit program was a priority. However, House leaders want structural changes to the underlying oil production tax code that would simplify it while increasing taxes at current, lower oil prices. “The entire fiscal regime of how we treat our businesses that drill for oil up north may be up for discussion, but not now; the Senate wants to stick to cash payments,” Kelly said. “This is so easy we think we can go down and in a day — that might be a little optimistic — but in a day, we should be able to end these things.” Kelly then called on House Resource Committee co-chairs Reps. Andy Josephson and Geran Tarr, the Anchorage Democrats who drafted the original HB 111 and are on the conference committee, to the conference table when the Senate reconvenes. Republican legislators have long emphasized stability and prospective changes in regards to oil taxes, but Senate Resources Chair Sen. Cathy Giessel said the retroactive effective date shouldn’t be a shock to industry because it’s generally been understood the cashable work credits were on their way out. Additionally, Gov. Walker's vetoes of $630 million in credit payments over the past two years have limited the value of the credits to companies, as it is now unclear when they will be paid, she noted. Walker vetoed portions of the previous two credit appropriations to save the state from immediate expenses while facing annual budget deficits approaching $3 billion. “It will have a negative impact on companies, we know that and we regret that but the fact of the matter is the state cannot afford this anymore,” Giessel said. Caelus Energy cited tax credit uncertainty as part of the reason it decided to defer drilling an appraisal well at its very large Smith Bay North Slope oil prospect. Giessel also said Senate Republicans are on board with Walker’s proposal in his fiscal compromise to “ring fence” deductions, or require they only be used to offset production from the project through which they were earned. The ring fencing provision is intended to prevent a company from purchasing a non-producing project and “cannibalizing” the tax deductions earned by the seller for use against taxes earned elsewhere, Giessel explained. “No deduction without production,” she said without starting a chant. Rep. Tarr said in an interview that the Senate’s proposal simply masks the credit problem by shifting away from cash payments now to forgone tax revenue in the future, when the 35 percent deductions are applied with her own slogan. “Quick reaction is — we don’t want to change the name to pay the same,” Tarr said. The House proposal would set a flat 25 percent production tax rate at prices up to $100 per barrel and offset it with a 25 percent loss deduction. Democrats say the problem with the current production tax law known as Senate Bill 21 is credits built into the system ramp the tax rate down from the 35 percent statutory rate to less than half that while companies can still get deductions at 35 percent. For those reasons, the Revenue Department projects the House’s HB 111 would take in about $800 million more than the Senate’s over the next decade. At current oil prices of about $45 per barrel, the state already takes 77 percent of the profit on an average barrel of North Slope oil, according to Giessel. Tarr said HB 111 is a key revenue component of the House Majority coalition’s overall fiscal plan. She also agreed with industry’s regular criticism that the State of Alaska consistently changes oil tax policy making it hard for companies to plan, saying settling oil taxes — and other fiscal matters — for several years would give the Legislature time to focus on other major issues such as health care and education. “We think now is the time for action,” Tarr said.   Elwood Brehmer can be reached at [email protected]

Despite delays, Brooks Range says Mustang will produce in ’17

The company developing a small North Slope oil field with the help of $70 million in funding from the State of Alaska says the project will finally come together this winter after years of delay. Anchorage-based independent Brooks Range Petroleum Corp. plans to have oil flowing from its stalled Mustang project in December, according to the development plan the company submitted to the Division of Oil and Gas. The Mustang prospect is in the Southern Miluveach Unit on the west edge of the large Kuparuk River field. Brooks Range expects it to produce up to 15,000 barrels of oil per day at its peak from about 22 million barrels of proven reserves. In December 2012, the state-owned Alaska Industrial Development and Export Authority invested $20 million of the $27 million needed to build a five-mile road to Mustang and a 19-acre pad for production and processing facilities. The gravel road and pad — in which AIDEA is an 80 percent owner — were finished in April 2013. At the time, Brooks Range leaders said they wanted to have the field in production by fall 2014 and credited incentives in the just-passed and industry-supported oil production tax structure under Senate Bill 21 for improving the economics of the project and spurring it forward. In April 2014, AIDEA committed another $50 million equity investment in the $225 million Mustang oil processing facility. Brooks Range Chief Operating Officer Bart Armfield said at the time that the project would start production in late 2015 and likely peak in 2017. To date, AIDEA has invested $49.8 million of the $50 million commitment in Mustang and spent another $670,000 on project management and other in-house expenses related to the project, according to the authority. Full development of the field was estimated at about $580 million and included drilling 11 production and 20 more gas and water injection wells. With AIDEA’s investment, the Mustang processing facility would be the first such open-access facility on the Slope and hopefully help in the development of other nearby fields. Historically, independent North Slope explorers have had difficulty negotiating access agreements with BP, ConocoPhillips and ExxonMobil, which own most of the processing capacity for basin’s producing fields. AIDEA’s equity was also key to Brooks Range’s ability to secure loans to finance the remainder of the project, authority and company officials said when the deal was made. By August of 2014, Brooks Range was changing hands. Houston-based Thyssen Petroleum LLC and two partners, JK Tech Holdings Ltd. of Singapore and MEP Alaska LLC, a New York-based firm, purchased the independent oil company. Armfield then told the Journal production would start in early 2016 at about 8,000 barrels per day and grow from there with additional drilling. Thyssen, JK Tech and MEP Alaska purchased Brooks Range from Alaska Venture Capital Partners and Ramshorn Investments. However, almost as soon as Brooks Range was sold oil prices started to tumble to the current $45 per barrel range. August 2014 was the last month the average daily price of Alaska North Slope crude exceeded $100 per barrel. That put a damper on Mustang. Engineering of the processing facility and associated infrastructure started in January 2015 but was put on hold by the third quarter of the year as low oil prices hampered financing and project economics, according to the Mustang development plan Brooks Range submitted to Oil and Gas last September. Armfield declined a request for an interview regarding the status of Mustang. Now president of Brooks Range, he wrote in a December 2015 letter to then-Natural Resources Commissioner Mark Myers that the company had spend $145 million on facility engineering, reservoir evaluation, permitting, drilling and other expenses to move Mustang forward. Brooks Range completed one injection well into the Kuparuk reservoir and started a second well, but drilling challenges prevented the completion of any production wells at the time, Armfield wrote. In addition to the oil price problem, Gov. Bill Walker’s veto of $200 million out of $700 million in state oil and gas tax credit payments in June 2015 forced the Mustang development schedule to be pushed back “to deal with unfavorable economic factors,” according to Armfield. According to the Mustang plan, facility modules will be arriving to the Slope in August and September for installation and start-up to lead to first oil by December. In November 2016 then-acting Oil and Gas Director Jim Beckham wrote in a letter to Brooks Range approving a term extension of the Southern Miluveach Unit that “the division remains concerned that BPRC will be successful” in getting to first oil by the end of this year. “Based on the materials BRPC provided, it appears possible for BPRC to meet this deadline,” Beckham wrote further. “But the schedule is extremely tight and leaves little room for deviation.” The slow development of Mustang also caused AIDEA and Brooks Range to rework their financing deals for the project. AIDEA’s $50 million was to be repaid with 10 percent annual interest within seven years after the start of oil production from Mustang, or by the end of 2022, according to memo from AIDEA staff to the board of directors when the investment was approved. That repayment plan has since been pushed back to start in 2018, according to documents on the authority’s website. AIDEA spokesman Karsten Rodvik wrote in response to questions that the authority made its investments understanding the project could be impacted by the price of oil. “We are taking steps to restructure our investment to reflect current market conditions, and given these comprehensive efforts, we believe that Mustang should move forward,” Rodvik wrote in an email. AIDEA executives declined direct interview requests. Similarly, the unpaid balance of AIDEA’s $20 million share of the Mustang road and pad is to be paid starting next year. In 2014 and 2015, the authority got $11.5 million back in state oil and gas tax credits transferred from Brooks Range for its $20 million. If the project ultimately is unsuccessful, AIDEA’s stake in MOC1 LLC, the company set up for the processing and production facility investors, provides the authority multiple forms of collateral, such as the equipment that would be used in the facility, according to Rodvik. “Additionally, MOC1 has real estate security interests in the Mustang oil and gas leases, and other North Slope oil and gas leases in which the owners of Brooks Range Petroleum Corp. have a working interest,” Rodvik wrote. “If Mustang were not to go into production and the other parties default on their payment obligations, MOC1 can foreclose on the lease positions to sell those to third parties.” Getting Mustang to first oil in 2017 is important because the company needs to drill and test a viable production well and either be in production or be working towards it by Dec. 31, according to Beckham, which is when the unit is set to expire. DNR officials referred questions about Mustang’s progress to Brooks Range. The department terminated the nearby Tofkat Unit held by Brooks Range in 2016 after the company held the acreage for years without doing much with it. In the case of Tofkat, Brooks Range allegedly was unable to secure an access agreement with Kuukpik Corp., the Alaska Native village corporation that holds surface rights to the state leases. ^ Elwood Brehmer can be reached at [email protected]

Interior Dept. grants state survey permit for King Cove road

The State of Alaska is preparing to build a long-debated road on the Alaska Peninsula as legislation authorizing the project inches its way through Congress. Gov. Bill Walker said in a June 26 statement from his office that Interior Secretary Ryan Zinke called him that morning to notify the governor that the Interior Department had granted the state permission to survey a route for a road between the communities of King Cove and Cold Bay. “For far too long, King Cove residents suffering medical emergencies have had to brave harsh elements just to get health care,” Walker said. “They travel by boat or helicopter — often in inclement weather — to access the Cold Bay airport in order to be medevaced out. Our fellow Alaskans deserve better than that. I’m grateful to Secretary Zinke for recognizing that need and doing his best to advance the process to build that life-saving road.” For the next few weeks Alaska Department of Transportation surveyors will be working to identify the least impactful route for the road through the Izembek National Wildlife Refuge. The work should be done by mid-July, according to the governor’s office. On June 27, the House Natural Resources Committee approved a bill introduced by Rep. Don Young to authorize an equal-value land exchange between the State of Alaska and the federal government to give the state the 206 acres of the Izembek refuge that it would need for the 11-mile road right-of-way to complete the roughly 30-mile, single-lane gravel road. The legislation, which was also introduced in the Senate by Sens. Lisa Murkowski and Dan Sullivan, would allow for up to 43,000 acres of state land to be added to the refuge and swapped for the 206 acres of refuge land. That is very close to the swap that passed Congress and President Barack Obama approved in 2009. In 2013, Interior Secretary Sally Jewell chose the “no action” alternative and rejected the exchange — preventing the road — after the Fish and Wildlife Service determined the road itself would damage critical waterfowl nesting areas and could lead to additional habitat damage through increased access to the refuge. True to form, Young pulled no punches in a press release statement when his bill moved. “Secretary Jewell’s heartless denial of the King Cove emergency access road was a willful and deliberate dismissal of human life in the name of wildlife; it represented one of the worst government actions I’ve seen in all my years in Congress,” Young said. “And since that decision, the community has experienced 53 medevacs in often treacherous conditions. This legislation is an important step to ensuring the people of King Cove have safe and reliable transportation during medical emergencies.” The 315,000-acre Izembek Refuge surrounds the village of Cold Bay and is home to entire populations of some waterfowl species, such as the Pacific black brant, at certain times of the year. The road would give King Cove residents in urgent need of medical care a reliable link in bad weather to the large World War II-era airport at Cold Bay. Conservation groups and the Yukon-Kuskokwim Delta-area Association of Village Council Presidents have pushed back against efforts by the state and the delegation to build the road. AVCP wrote to Jewell in 2013 about a worry it could impact the populations of geese western Alaska residents hunt for subsistence. In February the Alaska Legislature unanimously passed a resolution in support of the construction project. DOT has the road listed as a $30 million project in its Transportation Improvement Plan for fiscal year 2019 and differing state House and Senate versions of the fiscal 2018 capital budget each reappropriate $10 million of unspent DOT funds to start paying for what is known to most as the King Cove road. ^ Elwood Brehmer can be reached at [email protected]

Sun hasn’t set yet on ANWR

Alaska oil advocates lauded Interior Secretary Ryan Zinke’s order directing federal agencies to reevaluate the oil and gas potential within the National Petroleum Reserve-Alaska and the coastal plain of the Arctic National Wildlife Refuge, but what did it get them? The answer, unsurprisingly, will largely depend on how much money is willing to be spent and who will spend it. The secretarial order, signed May 31 in front of a cheering crowd during the Alaska Oil and Gas Association’s annual conference in Anchorage, directed resource evaluators in the U.S. Geological Survey and the bureaus of Land Management and Ocean Energy Management to send operational plans within 21 days of the order to execute the resource assessments up the chain of command. By all counts, those plans and budgets for them were submitted on time. Next, the Counselor to the Secretary for Energy Policy is supposed to collate the three plans into a document for Zinke — himself a geologist by trade — to review by July 1. While the USGS is the federal government’s collection of underground experts and their associated data and has done hydrocarbon resource assessments in the past, BOEM stores and interprets resource data for BLM, which manages the NPR-A, according to USGS Senior Research Geologist David Houseknecht. Houseknecht led or participated in the drafting of similar assessments of the NPR-A in 2002 and 2010 and the ANWR coastal plain in 1998, and is well-regarded by many geologists that have studied the North Slope. He declined to comment on the details in the USGS plan as it is still in the amendment phase, but said without additional funding it would be unlikely that his agency would be able to gather much new data. Key new information would almost certainly come in the form of 3D seismic data, the acquisition of which has in recent years pretty much become an industry standard prerequisite for nearly any investment in a prospect. A seismic program conducted from 1983 to 1985 in the 1.5 million-acre ANWR coastal plain collected 1,180 miles of 2D data, but geologists today often compare it to an X-ray of the earth; 3D seismic is likened to an MRI. During the winter of 1985-86 Chevron and BP partnered to drill the KIC-1 exploration well on ANWR in-holdings owned by Kaktovik Inupiat Corp. and Arctic Slope Regional Corp. It is the only well drilled in ANWR and what was found remains one of Alaska’s best-kept secrets. As for the NPR-A, Houseknecht hinted that Interior leaders might want to get the assessment done before much new data can be collected. “With the timeframe we have to work with it’s unlikely any new seismic will be acquired within the NPR-A, but certainly the workflow will include the USGS and BOEM together analyzing data that already exists,” he said. Zinke’s order states the joint assessment plan for the NPR-A and Section 1002 of ANWR “shall include consideration of new geological and geophysical data that has become available since the last assessments, as well as potential for reprocessing existing geological and geophysical data.” While that may not sound very exciting to those hoping for a comprehensive new look at the oil potential of the state-sized federal holdings on each end of the North Slope, Houseknecht said there is already a lot of 3D data available for the northeast portion of the NPR-A, which is the area closest to existing oil infrastructure. Companies occasionally provide seismic data to government geologists for licensing and evaluation on the premise the data itself remains private. The ANWR coastal plain is regularly called the “1002 area”, a reference to the section of the 1980 Alaska National Interest Lands Conservation Act, or ANILCA, that describes it. ANILCA established many of the designated federal areas in Alaska, including ANWR. Section 1002 of the exhaustive legislation called for the initial wildlife and hydrocarbon resource assessments and outlines the subsequent steps for oil and gas exploration and development if Congress were to approve it. Federal refuges are usually off-limits to such activity, but the proximity of the coastal plain to the mega fields of the central North Slope pushed Congress to make an exception regarding ANWR. When ANILCA was passed the country was also heavily dependent on imported oil and the 1973 OPEC embargo on exports to the U.S. was not a distant memory. Alaska’s congressional delegation has long led a Republican effort in Congress to pass legislation opening the 1002 for exploration. It passed Congress once as an amendment to a budget bill President Bill Clinton ultimately vetoed in 1996. President Donald Trump has $2 billion in revenue from an ANWR lease sale in his 2018 budget proposal. The Alaska delegation has again introduced legislation to open the coastal plain to exploration drilling. The bills in the House and Senate set a cap on impacted areas at 2,000 acres on the presumption exploration could be done in the winter and any development would fully utilize new long range drilling technologies. The USGS last updated its oil and gas resource estimate of the coastal plain in 1998 and leaned heavily on the data from the mid-80s to do it, according to Houseknecht. The agencies’ calculations were large but speculative; the mean estimate for technically recoverable oil in the ANWR coastal plain was 7.6 billion barrels, with another 3.5 trillion cubic feet of extractable natural gas. “I’m asked every year, ‘Why hasn’t the USGS not updated its 1998 assessment?’ My first answer is always, ‘There is no new information,’” Houseknecht said. “One thing that could be done would be to reprocess the old 2-dimensional data that were collected in 1984 and ’85 because in the last 20 years seismic processing has made leaps and bounds in terms of the capacity to enhance old data.” Integrating data from adjacent areas and a couple offshore wells that wasn’t available before could be of some benefit as well, he added. To attract bids, a lease sale would almost certainly require substantial 3D seismic data to be available to companies, Houseknecht said further. In 2013, former Gov. Sean Parnell’s administration, which included current Sen. Dan Sullivan as Natural Resources commissioner, submitted a work plan to the Interior Department that would’ve had the state fund up to a $50 million winter 3D seismic shoot in the 1002 area. The administration attempted to use a section of ANILCA that it believed allowed any entity to submit a qualifying exploration plan for the area, but then-Interior Secretary Sally Jewell rejected the proposal and ultimately had her decision upheld by the U.S. District Court for Alaska. Current DNR Commissioner Andy Mack said the Parnell administration had a solid plan. “Understanding the resource potential in that area is critically important,” Mack said in a June 14 interview. The Walker administration is open to resubmitting a winter seismic application for ANWR, according to Mack, and would be happy to partner with industry on an application as well. Mack also said the administration is willing to support the effort financially at some level, but neither he nor Houseknecht could say how far $50 million would go. “That was 2013 — different budget times,” Mack said. “But I think most Alaskans would look at this as a solid investment in the future.” Alaska environmental groups were not pleased with Zinke’s order, contending it is the first step towards drilling in the renowned refuge. However, Mack said he believes a very large majority of Alaskans want to see ANWR opened up. In early 2015 the state Revenue Department estimated large-scale oil production in ANWR could eventually net the State of Alaska upwards of $150 billion, but that was at $100 per barrel oil. Under current federal law the state would receive 90 percent of royalty revenue from production, but that could change in legislation to open it to drilling, if it were to pass. The state production tax would also apply. NPR-A Recent large oil finds in or adjacent to the eastern portion of the NPR-A mean it’s almost a given the resource estimate figures for the 22 million-acre parcel would go up significantly, according to Houseknecht. The NPR-A was last assessed in 2010 when the USGS estimated it holds about 900 million barrels of recoverable oil and a very large natural gas resource with a mean estimate of 53 trillion cubic feet. That was after a 2002 assessment put the expected mean oil resource at more than 9 billion barrels. “I was on everybody’s dirty list when I reduced the oil estimate, or we did, in 2010,” Houseknecht recalled. The 2002 estimate was based in part on the assumption that the oil in the Alpine formation found on the east edge of the reserve continued halfway into it, he added. But within two years ConocoPhillips had drilled exploration wells west of Alpine that found mostly gas and little oil. So the 2010 assessment was scaled back, and it put the largest NPR-A oil accumulations in the 250 million-barrel range and said the largest finds in the Nanushuk or Torok stratographic trap formations would likely recover about 10 million barrels. Last October Caelus Energy announced it discovered up to 2.4 billion recoverable barrels in the Torok formation in the state waters of Smith Bay, just offshore from the NPR-A. ConocoPhillips also revealed its discovery of 300 million recoverable barrels in the Nanushuk in the NPR-A in January. Repsol and Armstrong Energy are working a 1.2 billion-barrel-plus Nanushuk prospect just to the east of the NPR-A. The large number of bids in the 2016 NPR-A lease sale indicated renewed industry interest there, too. Zinke’s order also called for a review of the NPR-A Integrated Activity Plan, and the prospect of more oil in the reserve could be used as support for reopening areas closed to leasing under the last NPR-A plan in 2013. If the land-use plan for the NPR-A is overhauled it won’t happen quickly, as it involves a multi-year environmental impact statement. “As new data becomes available our perspective changes on these rocks and how much oil they may contain,” Houseknecht said. ^ Elwood Brehmer can be reached at [email protected]

BP: time of transition for energy markets

Improved efficiencies at nearly every level of the energy game has put markets in flux, according to BP’s Statistical Review of World Energy released in June. For Alaska, that has led to a buyer’s market in the global LNG trade, fading coal demand and oil prices that will be “lower for even longer,” BP Alaska Commercial Vice President Damian Bilbao said. Bilbao presented the highlights of the company’s annual report to the Anchorage Chamber of Commerce June 26. “The new normal in energy consumption is growth in consumption coming from developing countries,” he said. More than half of global economic growth in 2016 occurred in China and India, according to Bilbao. However, while China’s economy grew by about 6 percent last year, its energy consumption grew by just 1 percent. That is in line with a change in the general relationship between economic growth and energy consumption, he said. According to BP, global energy demand has historically grown about 2 percent per year. Inversely, the amount of energy needed to produce one unit of gross domestic product, known as energy intensity, has generally decreased by about 1 percent per year, as the world becomes more energy efficient. In 2016, global energy demand grew slower than normal, about 1 percent, and energy intensity remained at its usual 1 percent per year decline. “There’s something changing fundamentally about how energy demand is met globally,” Bilbao said. Increased use of natural gas and renewable energy, which has primarily displaced coal, kept global carbon emissions virtually flat for the third consecutive year, according to BP. The global oil trade largely rebalanced itself last year and as a result there was a modest increase in prices early this year. Lower 48 oil production declined by about 400,000 barrels per day, the first domestic production drop since 2008. Overall non-OPEC production fell by about 800,000 barrels per day, the largest single-year decline in nearly 25 years, according to BP’s data. Additionally, OPEC’s prescribed production cut of about 800,000 barrels per day that started in November has helped production more closely match demand, Bilbao said. At the same time, slower than historical demand growth and the oil supply buildup has kept global oil inventories higher than expected and prices lower. Bilbao also said lower drilling rig count figures don’t necessarily mean less production to come anymore. The report states that new well production among Lower 48 shale drillers increased 40 percent per rig per year in 2015 and 2016. That led to oil production growth from Texas’ Permian basin despite a 75 percent drop in the number of drilling rigs in the field. “A rig operating in the Permian today is equivalent to more than three rigs at the end of 2014,” the report states. Those operational efficiencies have led to a resurgence in shale production in 2017, which has partially offset OPEC’s output curbs and put prices that approached $60 per barrel early this year back to the mid-$40s. According to the Energy Information Administration, the 50-year average price for oil adjusted for inflation is just less than $50 per barrel. Bilbao said it also shows OPEC’s influence can tweak oil markets in the short-term, but the cartel cannot stop long-term structural market shifts. On natural gas, low prices led to just a 0.3 percent increase in production globally, which was the weakest such growth in 34 years, according to BP. However, global demand increased by just 1.5 percent, compared to the 2.3 percent 10-year average. U.S natural gas production fell by 2.6 percent in 2016 after growing 4.2 percent per year since 2005; but that was largely offset in the world arena by Australia, which had multiple LNG projects come online last year and increased its gas production by 25 percent. Also, for the first time in history, the U.S. is not the largest producer of renewable energy. While domestic renewable energy production grew by nearly 17 percent last year — and accounted for 19 percent of global renewables — China upped its renewable energy output by a full one-third in 2016 to become the global renewable leader. Renewable energy only makes up about 4 percent of global energy consumption, but Bilbao said its growth is primarily being driven by economics and not political motives. The economic viability of renewable forms of energy, and to a greater extent low natural gas prices, have put coal on the backburner. U.S. coal production fell by 19 percent in 2016 but still accounted for 10 percent of global output. China produced about 8 percent less coal in 2016, but still dominated the market with 46 percent of global supply. But according to BP, a move by the Chinese government to improve profitability of its coal mines could have hurt the global solid fuel market. Among other measures, China reduced coal production in 2016 by limiting the days its mines could operate from 330 to 276. That led to coal prices in China jumping from less than $60 per metric ton in January 2016 to roughly $100 per ton by the end of the year. “The events in China spilled over into global coal markets, with world prices taking their cue from China,” the BP report states. “This rise in global coal prices further depressed global coal demand, particularly in (the) power sector around the globe, with natural gas and renewable energy the main beneficiaries.” Global coal consumption fell by 1.7 percent last year and production fell “by a whopping” 6.2 percent, BP notes. Low demand for coal has caused Usibelli Coal Mine near Healy to scale back production. That has in turn hurt the Alaska Railroad, which has long hauled coal from the Interior mine to Seward for export to South American and Asian customers. In Britain, coal has pretty much come full circle, according to BP. The country’s last three underground coal mines recently closed, its coal consumption is back to levels last seen about 200 years ago at the start of the industrial revolution and U.K. electrical generators had their first-ever coal-free day in April. Elwood Brehmer can be reached at [email protected]

Hilcorp spends $3.95M on Inlet leases

Hilcorp Alaska LLC was the big, and only, winner in both the state and federal Cook Inlet oil and gas lease sales June 21. The company spent $3.95 million on combined 20 tracts on state land and in state and federal waters. Hilcorp was also the only bidder in both sales and is the primary producer of oil and gas in the Inlet. In the state Inlet sale it picked up six leases: two onshore tracts just to the north of the Beluga gas field it operates on behalf of the Anchorage electric utilities, another split onshore-offshore lease between the Ninilchik and Cosmopolitan units on the southern Kenai Peninsula and three more along the shore of Kalgin Island west of Kenai. State Division of Oil and Gas Director Chantal Walsh said it appears Hilcorp is mostly trying to fill in gaps in the state territory it holds. “We’re excited to see Hilcorp is interested in exploring Cook Inlet,” she said. Hilcorp kept its plans for its new acreage guarded in a statement to the Journal. "The leases we acquired today (June 21) help strengthen our ability to continue to provide energy and jobs for Alaskans," spokeswoman Lori Nelson wrote in an email. Hilcorp spent $922,000 on its state leases and $3.03 million on the federal tracts. The 14 federal leases Hilcorp won are just offshore from the Ninilchik and Cosmopolitan units, which are in state territory, and in the middle of the Inlet in front of Kachemak Bay. The state’s 2016 Inlet lease sale drew no bids and industry representatives said that was due in large part to the state Legislature debating whether or not to end its oil and gas tax credit program for work in the basin at the time, which it did. Companies used the credits to offset their exploration and development costs. There is also limited interest in Inlet natural gas, as production from the basin supplies the relatively small demand from Southcentral gas and electric utilities and low global LNG prices have killed the economics of exporting Inlet gas. This was also the first time in years the federal waters of Cook Inlet drew any attention from industry. According to the Bureau of Ocean Energy Management, the Inlet sale was the first federal offshore lease sale in Alaska since 2008. State and federal managers don’t hold sales if they don’t receive interest from industry prior to the public sale. Environmental groups have also lobbied the feds to quit proposing Inlet lease sales, citing the lack of interest and a fear activity could harm Cook Inlet’s endangered Beluga whales and other marine life. A state sale of Alaska Peninsula land and water did not draw any bids, which is common for the remote region. ^ Elwood Brehmer can be reached at [email protected]

ISER: State payments to local governments doubled over decade

State spending has grown to comprise nearly 30 percent of all revenue for Alaska’s local governments in recent years, according to a report from the University of Alaska Institute of Social and Economic Research published June 19. State support to Alaska’s 19 boroughs and municipalities grew from a near-term low of 12 percent of the average borough budget in 2004 to an average of 28 percent in 2015, the most recent year for which adequate data was available, study author and ISER economist Mouhcine Guettabi said. Guettabi and other ISER researchers examined audited borough financial reports to gather data for the study as a means of consolidating the most consistent, accurate figures possible. It ultimately shows that the State of Alaska’s spending habits have a dramatic effect on the amount of money available to its local counterparts. “Overall, state spending is very sensitive — or has been over the last few years — very sensitive to oil prices and that certainly makes its way down to borough government revenues,” Guettabi said in an interview. In 2000, the first year the study examined, state money paid for an average of 19 percent of borough budgets. At that time, oil prices averaged roughly half of what they are currently in nominal terms; however North Slope oil production was also more than double what it was in 2015. Unsurprisingly, the largest local governments in Alaska were generally the least dependent on state aid, as they have populations that are able to generate enough tax revenue to make them mostly self-sufficient. Between 2000 and 2015, state money made up just 4 percent of the Municipality of Anchorage’s budget, according to the study. For the Matanuska-Susitna Borough, the like figure was 11 percent, while Juneau and the Kenai Peninsula Borough each drew 14 percent of their revenue from the state over the period. The Fairbanks North Star Borough had the largest share of state support in its budget at an average of 15 percent. Conversely, the some of the smallest and remote regions of the state relied most heavily on the State of Alaska. The Bristol Bay Borough in Southwest Alaska, which doesn’t include the regional hub of Dillingham, used state funds for 31 percent of its revenue, and in the adjacent Lake and Peninsula Borough the figure was 37 percent. Haines in Southeast and the Northwest Arctic Borough each had the highest shares of state-sourced revenue in their budgets at an average of 38 percent over the study period. The outlier was the Ketchikan Gateway Borough. With about 13,700 residents in 2015, Alaska’s southernmost borough was the just the seventh-largest but state money averaged only 7 percent of its overall revenue since 2000. Ketchikan has local property, sales and lodging taxes, and the latter two capture revenue from the roughly 1 million tourists that visit the city in busy years. Guettabi said state appropriations for capital projects often made up the largest portion of state money in local budgets over the study period. Given that, it is worth noting that the 2015 fiscal year was the last year of significant discretionary spending in the state’s capital budget before oil prices and state revenue collapsed. The 2016 and 2017 capital budgets have subsequently lacked almost any purely state-funded projects. The study also examined how much boroughs would have to raise in taxes to replace the state dollars each received in 2015. Despite getting $74.3 million of state money in 2015 — more than double what any other borough received — the Municipality of Anchorage’s relatively large population means it would only have to come up with tax revenue equal to $248 for each of its nearly 300,000 residents to go state money free. The Fairbanks North Star Borough, which got $27.4 million from the State of Alaska in 2015, was the next lowest at $278 per person. To the contrary, the 887-resident Bristol Bay Borough would have to generate $4,874 per person to offset the state support it received in 2015. Many of the boroughs fell in the $1,000 to $2,200 per person range. “It makes it clear small places would have to levy very, very high taxes to replace how much (state) money they’re getting,” Guettabi said. What is the appropriate level of state support for local governments has become a conversation inside of the larger state budget debate as lawmakers have tried to resolve annual budget deficits that have been at least $2.5 billion annually over the last three budget cycles. Guettabi said ISER is also working on another report examining State of Alaska spending per capita and why it is generally the highest in the country. “The health of local communities is something that needs to be part of this conversation as we’re thinking about the right size of government and thinking about how to fund government,” he said. “I think that understanding the ramifications of those choices on these borough economies is paramount to the next few years.” To that end, Department of Revenue Commissioner Randy Hoffbeck said to the House Finance Committee in February that 46 percent of the total state budget is “cash out the door” to fund programs and services statewide. Currently, $1.6 billion of the state’s roughly $4.2 billion operating budget goes to assist communities in paying school debt, employee retirement obligations, education and general revenue sharing statewide, according to the Revenue Department. More than $1.2 billion of that is in the state’s base student allocation education funding formula. Alaska is unique in that the state constitution requires the state to fund public education. However, just eliminating the roughly $300 million in state payment assistance for school debt and retirements would “implode” the budgets of most of Alaska’s smaller communities, Hoffbeck said. He was testifying on state income tax legislation passed by the House that failed in the Senate, but that Gov. Bill Walker’s administration generally supports as part of a broad-based revenue fix to the deficit. Elwood Brehmer can be reached at [email protected]

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