Elwood Brehmer

Delays continue to beset Interior gas project

Long challenged by unavoidably thin economics, the Interior Energy Project is now facing other pressures that are starting to force the hands of its developers. The Environmental Protection Agency recently changed its classification of winter air quality problems in the Fairbanks North Star Borough from “moderate” to “serious.” Additionally, the waning availability of a state tax credit for construction of a liquefied natural gas storage facility will require construction of the 5.25 million-gallon LNG storage tank to start this fall for it to be eligible for the tax credit at all, according to project leaders. Finally, there is the ongoing need for a natural gas contract not only to supply future customers that will hopefully be attracted to the project, but also for Fairbanks Natural Gas’ existing customer base. On top of all that, the Alaska Industrial Development and Export Authority and the Interior Gas Utility are still working to finalize the sale of Pentex Alaska Natural Gas Co., FNG’s parent company, from the state investment authority to the borough-owned utility. That deal, which would ostensibly transfer the IEP management from AIDEA to IGU, was announced in January and was initially supposed to be done by March 31. IGU General Manager Jomo Stewart said in an interview that AIDEA and the utility are still moving towards integrating Pentex-FNG and IGU as quickly as possible. “You’ve got complex scheduling to work on a complex suite of documents to work on a highly complex project with lots of moving parts and frankly a number of mission critical elements that are complex in amongst themselves,” Stewart said. Combining the startup and existing Fairbanks-area gas utilities has largely been viewed as the natural course of action since AIDEA purchased Pentex for about $52 million in 2015. It would provide numerous operational efficiencies and allow the utilities to source gas from a single contract. Expanding Pentex’s small Southcentral LNG plant — from which it trucks LNG to its Fairbanks customers now — and getting the associated LNG storage underway in Fairbanks are a couple of those mission critical elements. FNG first proposed building the LNG tank, estimated to cost about $42 million, several years ago before being purchased by AIDEA. But actually building the additional LNG storage has been unnecessary to this point as the project lacks a gas contract to fill it. However, the project should be eligible for a state tax credit of up to $15 million if it’s up and running by the end of 2019 to beat the sunset date of the credit; and it’s expected to take about two years to complete. “We’re not going to miss another build season,” Stewart said. “There is a full, solid commitment that that storage is going to get started this fall.” Whether or not IGU is ever reimbursed for the tax credit is another matter — it’s part of the state’s larger oil and gas tax credit program to which Gov. Bill Walker has vetoed funding the last two years as the state grapples with massive budget deficits. But Stewart said the utility does not want to lose “the very opportunity to be in line” for the credit payment. Adding 3 billion cubic feet, or bcf, of liquefaction capacity to the LNG plant that currently processes about 1 bcf of gas into LNG per year should take about 18 months. AIDEA’s Interior Energy Project team has also been trying to get a natural gas supply from Cook Inlet producers on terms favorable enough to keep the project viable for more than a year. The desire to secure a long-term gas contract is still there, but Stewart said the reality of the situation could amend what is accepted. “The mindset is evolving that we’ll be doing it in increments — that it’s ok to do things on an incremental basis,” he said. The challenges with the gas contract have always been that it is for a relatively small amount of gas, which makes it harder to secure a favorable price, and will require the producer to rely on the expectation that gas demand will grow over time. Challenging the gas contract even further is the fact that low oil prices have lessened the price of fuel oil to the point where it is price-comparable with what AIDEA and the utilities hope to deliver natural gas to customers for, thus eliminating the major impetus for residents to invest in converting their homes from fuel oil heat to natural gas. However, FNG’s gas supply contract for its existing customers expires next April, exacerbating the urgency of the situation. FNG reached a $15-million deal in late 2014 for a 10-year gas supply from Hilcorp Energy, the major Cook Inlet producer, that included selling the LNG plant to the producer. But it was rejected by then-Attorney General Craig Richards over concerns Hilcorp would control the entire gas supply chain to Fairbanks and could manipulate pricing to its benefit. The economic hurdles the IEP faces have morphed the project from one primarily aimed at lowering energy costs in the Interior to one focused on improving the region’s winter air quality, which can be the worst in the country when ultra-cold and dense air traps emissions from vehicles, home furnaces and woodstoves — all running full bore to keep their owners warm. The EPA, to that end, has long been watching the IEP and efforts by the Fairbanks North Star Borough to improve winter air quality in the region. AIDEA’s IEP manager Gene Therriault said during a May 18 AIDEA board meeting that the EPA’s Region 10 officials ask for a project update each time they visit Fairbanks. Therriault noted that the latest omnibus spending bill passed by Congress includes $30 million in competitive EPA grants for communities not in compliance with federal air quality standards, up from $20 million in the last budget cycle. The Fairbanks Borough won $2.5 million last year to fund residential woodstove change-outs to cleaner burning heating options. Fairbanks-area AIDEA board member Gary Wilken questioned whether the borough could use any future grant funds for residential natural gas conversions, which will underpin the entirety of the project. Therriault said the EPA wants the funds to go towards immediate steps to improve winter air quality, but that the relationship the borough is building with the EPA could lead to conversion assistance or incentive funding when the time comes. Wilken, worried the project could still be stuck in the same chicken-and-egg scenario, said the help is needed now. “$5 million or $10 million goes a huge way in our project when we finally turn the valve on gas, so that’s not the time to start getting money out of the federal government; now’s the time to do it,” he said. Elwood Brehmer can be reached at [email protected]

$37 million claim against Legislature gets day in court

The owners of the former Downtown Anchorage Legislative Information Office building contended in a May 19 state Superior Court hearing that legislators did not afford them appropriate recourse on a $37-million contract claim after the Legislature decided to leave the six-story building last year. Jeffrey Feldman, attorney for 716 West Fourth Avenue LLC, argued to Superior Court Judge Mark Rindner during the nearly two-hour hearing that because then-Legislative Council Chair Sen. Gary Stevens of Kodiak did not hold his own hearing on the matter in which 716 was allowed to present its case, Stevens’ decision to deny 716’s contract claim was based on incomplete evidence and therefore faulty. Stevens and the full Legislative Council followed “nothing that would seem to reflect our common notion of due process,” Feldman told Rindner, adding that Alaskans denied a Permanent Fund Dividend are entitled to a hearing and thus have more recourse in disputes over much less money. Legislative Council attorney Kevin Cuddy responded that 716 — the LIO building owner group led by longtime Anchorage developer Mark Pfeffer — provided 50 pages of single-spaced briefings and another 70 exhibits to Legislative Council as evidence and could have provided anything else it wanted for Stevens to base his decision. “I understand that every plaintiff is going to want another bite at the apple,” Cuddy said. He argued further that any new facts that could be brought to light in a trial de novo, or evidentiary hearing, would be immaterial because at its core the case is about the contract between 716 and Legislative Council and that contract was followed, just to the detriment of 716. “716 has received exactly what it could’ve expected based on the terms of the contract,” Cuddy said. Last October, Stevens denied 716’s claim for $37 million on the basis that it was not in the public’s interest for the Legislature to pay out the purported damages. When 716 appealed Stevens’ decision to the full Legislative Council, the 14-member committee deferred to Stevens’ ruling and denied the appeal without hearing from 716. Legislators moved out of the Downtown Anchorage building late last September and into Midtown office space purchased for $11.8 million from Wells Fargo via the state capital budget. In late 2015, public pressure over the unpopular 10-year $33 million lease pushed the council to start looking for a way out of the building, which was custom-built for the Legislature in 2014. Before voting to leave the LIO, however, the Legislative Council agreed in principle with 716 to buy the building for $32.5 million. At the time, legislators said it was a way to get out of the lease that would in the long-term save the state money and give it a marketable asset as well, while avoiding the potentially costly legal battle that has since ensued. That deal evaporated quickly when Gov. Bill Walker said he would veto the capital appropriation to buy the building, saying it would be inappropriate for the state to spend that much on office space when government services — and eventually PFDs — were being significantly to solve a nearly $3 billion budget deficit. Lacking the Legislature’s monthly lease payments of about $280,000, 716 has since defaulted on its $28.6 million loan on the building with Florida-based EverBank, according to the court appeal document. The lease, as is common in government contracts, contained a “subject to appropriation” clause, meaning it is only valid if the full Legislature funds it. When the Legislature, at the recommendation of the council, decided not to pay the lease, a termination letter was sent to 716 by Legislative Affairs Agency officials citing the appropriation clause as the reason why. That should pretty much end the case, according to Cuddy. However, 716 appealed the administrative rulings to the Superior Court on an estoppel claim — that the developers invested large sums of money and made good on their end of the deal based on assurances that the Legislature would reciprocate. To that end, Feldman highlighted a May 2016 letter from Cuddy to EverBank, in which Cuddy wrote that a separate Superior Court ruling invalidating the lease would force the Legislature to vacate the offices and find alternative space. The dueling reasons for leaving indicate legislators could have been disingenuous in why they moved and necessitates discovery of more evidence so Rindner can rule with a complete set of facts, according to Feldman. During what was a fairly informal oral argument proceeding that could be likened to a discussion between the attorneys and the judge, Feldman told Rindner: “You’re trying to tease out answers from a record that simply doesn’t exist.” Rindner responded that administrative appeals lacking facts are usually remanded to the administrative officer for further discovery, to which Cuddy agreed. “I don’t recognize this process,” Feldman said simply. Rindner also pondered whether potentially subpoenaing legislators’ emails and other documents to allow the court to get to the bottom of why they ultimately walked away from the offices could violate the fundamental separation of powers between branches of government. Rindner said he would take the arguments under advisement, but did not give a timeline for a ruling. If the case is remanded to the Legislative Council, Juneau Rep. Sam Kito, who also served on the committee last year, now chairs the council. Kito was often the lone “no” vote against taking steps to leave the Downtown Anchorage LIO, citing legal concerns and a worry that invoking the “subject to appropriation” clause would damage the state’s credibility in future deals. The Alaska Bankers Association, Alaska Housing Finance Corp. officials and other state finance leaders have said leaving the LIO in the manner the Legislature did could lead to higher interest rates on state debt, fewer contractors and landlords willing to work with state agencies and other financial consequences as well; Feldman repeated those points in his argument. Elwood Brehmer can be reached at [email protected]

Senate passes its version of oil tax credit reform

Now the oil tax debate in the Legislature can really start. The Republican-led Senate passed House Bill 111, this year’s oil tax credit legislation, on May 15 by a 14-5 vote along caucus lines. On May 16, a concurrance vote in the House failed 17-22, setting up a conference committee process for the bill. The Senate version of the bill ends the cashable tax credit “experiment,” Anchorage Republican Sen. Cathy Giessel said in the floor debate, along with preventing companies producing oil in the state’s largest fields from using deductible credits to take their tax obligation below the 4 percent gross minimum tax. Amendments by Anchorage Democrat Sen. Bill Wielechowski to increase the minimum tax, decrease deductible tax credits and require producers to disclose additional financial information to the state were shot down. “By hardening the (tax) floor, by moving what was a cash credit to an obligation, it is an increase on companies,” Giessel said. It is less of a tax increase than the version of HB 111 the Democrat-led House Majority sent to the Senate. That House legislation also increased the production tax at oil prices less than $100 per barrel largely by eliminating the per-barrel credit on the large legacy oil fields, which is currently employed to significantly lower the effective tax rate, while lowering the base tax rate from 35 percent to 25 percent. Senate Republicans have said all session that they were open to cutting the state’s remaining refundable tax credits for explorers and small producers, mostly on the North Slope, but that rewriting the underlying production tax was off the table. Gov. Bill Walker and the House Majority share the Senate Republicans’ sentiment about ending the refundable tax credit program while the state still struggles with budget deficits exceeding $2.5 billion per year. But House Democrats also contend that the current oil tax code supported by Republicans was written when oil prices were greater than $100 per barrel and doesn’t provide the state adequate revenue at $50 to $70 per barrel, which most industry experts expect will continue into the foreseeable future. The House’s version of HB 111 would raise between $80 million and $100 million per year in new North Slope production taxes in the near term, according to Department of Revenue projections. House Resources Co-chairs and primary authors of the original HB 111, Anchorage Democrat Reps. Geran Tarr and Andy Josephson, commended the Senate for culling out the state’s remaining cashable tax credits, which Tarr said was “long overdue” in a caucus release, but said the Senate’s bill was rejected because it largely ignores the state’s current fiscal situation. “The Senate Majority took our good bill that was developed in the open, with advice from the experts and the input of Alaskans, and replaced it with a bad bill that continues many of the flaws that have placed Alaska in our current precarious financial position,” Josephson added. “The best course of action is to take this bill to a conference committee where an acceptable compromise can be reached that protects the state during these low oil prices, while still keeping Alaska competitive as a place for future oil industry investments.” The Senate version saves the state from paying out future refundable tax credits, expected to accrue at about $150 million per year, which the House bill does, too, but doesn’t change the base production tax. Still, the industry isn’t thrilled about it. “Today, the Alaska Senate passed the seventh change to Alaska’s oil tax structure in 12 years. It eliminates cash payments to companies and adds $1.2 billion to the State of Alaska’s treasury over the next 10 years,” Alaska Oil and Gas Association CEO Kara Moriarty said in a formal statement. “Alaska’s oil and gas industry has played a large part in contributing to the state’s fiscal solution for more than 40 years. With this bill, the industry will contribute even more to the state’s fiscal solution.” While the state will keep the projected $1.2 billion it would have spent on some tax credits in its coffers as Moriarty noted, the formerly refundable credit certificates will be converted to deductions companies can apply against future production taxes in the bills passed by both bodies. Allowing a company to deduct expenses and losses against a tax liability is common for profits-based taxes such as Alaska’s oil production tax, but it does mean there will be foregone future production tax revenue. The Department of Revenue estimates turning the credits into deductions, along with some existing carry-forward lease expenditures, could allow Slope operators to generate up to $1.4 billion in production tax deductions over the next 10 years based on the Senate’s legislation. How much revenue the state is willing to forego and whether or not there will be an increase to the base production tax paid by producers will be the basis for the HB 111 House-Senate conference committee debate, presuming the House Majority holds together and rejects the Senate’s version of its bill. Other outstanding bills With the exception of the capital budget, which passed the Senate May 12 and is now in House Finance, the House and Senate each passed versions of this year’s major pieces of legislation by May 17. Conference committees have been appointed and met on the operating budget and on Senate Bill 26, Gov. Walker’s Permanent Fund bill; however, significant action to resolve the bodies’ differences in the pieces of legislation has not taken place, at least publicly. The Senate folded legislation to allow the state to comply with the controversial federal Real ID Act into a bill establishing training for police officers to better manage situations involving individuals with non-apparent disabilities. The bill, House Bill 16, passed the Senate May 15 despite concerns from some that adding the Real ID provisions could violate a clause in the Alaska Constitution requiring legislation be limited to a single subject. The move was made to fold the two together in order to allow the House to bypass the committee process for a standalone Real ID bill — a process that could have caused the state to miss a May 17 federal deadline to try to comply with Real ID — and instead simply concur via floor vote with the Senate’s version of HB 16, which the House passed previously. ^

House Finance co-chair: Committee will restore AK LNG funds

A last-minute move by the state Senate to pull $50 million dedicated to the Alaska LNG Project and spend it on other state services will be reversed in the House Finance Committee, according to committee co-chair Rep. Paul Seaton. The Homer Republican, who is a member of the Democrat-led House Majority, said in an interview Friday that he and fellow Finance leader Rep. Neal Foster, D-Nome, have no interest in de-funding the Alaska Gasline Development Corp., which is leading the project, at this point. An amendment by Sen. Mike Dunleavy, R-Wasilla, to the capital budget bill that passed the Senate Thursday reappropriated half of the $50 million from the Alaska LNG Project Fund to the departments of Law, Public Safety and Transportation to hire district attorneys, state troopers and support road maintenance. The other $25 million was redirected to the state Public School Trust Fund. AGDC President Keith Meyer has said the state-owned corporation plans to operate on its previously appropriated funds — about $102 million at the beginning of the year — through the end of fiscal year 2018, which is June 30, 2018, in recognition of the state’s major budget problems. When the AGDC board of directors approved the spending plan in early February the corporation had about $76 million in the Alaska LNG Project Fund and another $26 million in the In-State Natural Gas Pipeline Fund. Meyer and Gov. Bill Walker have repeatedly said AGDC will spend 2017 initiating the project’s voluminous environmental impact statement, or EIS, with the Federal Energy Regulatory Commission; determining if there is a global appetite for Alaska’s North Slope natural gas; and securing gas customers and construction financing to pay for the estimated $40 billion gas pipeline and LNG export project. “We are committed not to interrupt the FERC process and the solicitation of investors” in Alaska LNG, Seaton said. AGDC submitted its EIS application to FERC last month and Meyer is currently on a marketing trip to China, according to an AGDC spokeswoman. Finishing the approximately two-year FERC EIS will likely cost the state upwards of $100 million, meaning AGDC could need a cash infusion from the Legislature during next year’s session, but by that point the corporation hopes to have deals in place that it can prove to legislators it is worth funding. Pulling the funding would undoubtedly challenge AGDC’s efforts and there has been ample bipartisan skepticism in the Legislature towards the project over the past year since the state’s former partners in the project, BP, ConocoPhillips and ExxonMobil early in 2017 indicated a desire to slow the project and hope global LNG prices improve. BP signed a one-year memorandum of understanding through the end of 2017 to assist AGDC with marketing and other aspects of the project. Global LNG prices, historically linked to oil markets, have fallen dramatically over the past two years and hampered the economics of Alaska’s and other LNG projects worldwide. Seaton was critical of the lack of public vetting of the amendment to strip the AK LNG funding, as the details of the amendment were not read on the Senate floor. Dunleavy simply proposed what was the fourth amendment to the budget and it was adopted without objection, discussion or a vote. Seaton also said reversing the funding transfer will not impact the departments in line for the cash because the prosecutor and trooper positions were already separately funded in the House and Senate versions of the operating budget, where those types of expenses are usually addressed. Additionally, he noted the trooper and district attorney funding in the capital budget is a one-time spend, meaning those positions would be eliminated next year unless more money was added either to the base operating budget or again to the capital budget as one-off appropriations. The House and Senate also approved a nearly $10.4 million allocation to pay for AGDC’s fiscal 2018 operations and personnel expenses in its operating budget. That money would come out of the $102 million in gasline funds as it has for several years. However, the Senate’s capital budget did not include a request by AGDC to transfer $14 million from the In-State gasline fund to the Alaska LNG Project Fund so the corporation can legally spend the cash on the large project. Seaton said he couldn’t comment on the House Majority’s plans for the $14 million request because he hadn’t yet discussed it with Foster, who chairs the capital budget in the House. Elwood Brehmer can be reached at [email protected]

New life for North Slope 100 million years in the making

All of a sudden, Alaska has more than 400,000 barrels per day of new oil potential. The North Slope, dismissed by many in recent years as a has-been conventional oil basin unable to keep up with the hip-now-with-it-and-wow shale mania of the Lower 48, is on the verge of reinvention. In just the past year, Caelus Energy, ConocoPhillips and the Armstrong Energy-Repsol partnership have all announced oil discoveries capable of producing up to, or well in excess of, 100,000 barrels per day. And they’re all related. To find the link, one only needs to look back about 150 million years or so when the nearby Brooks Range began to grow, according to state petroleum geologist Paul Decker. The billions of barrels of oil the companies believe they have found are all located in the Brookian geologic sequence: layers of sandstone carried off the then “new” mountain range by wind and water between 90 million and 105 million years ago. “The Brookian sequence is all that matter that was shed by erosion from the Brooks Range,” Decker explained in an interview. It’s very similar to what the Colville and Sagavanirktok and Canning rivers are doing farther to the north today. The weight of the rising mountains — oldest to the west — pressed a trough in the Earth’s crust at their base, providing a place for the first Brookian sediments to settle, explained Mark Myers, a renowned Slope geologist, former Alaska Department of Natural Resources Commissioner and U.S. Geological Survey Director further. That trough, or geologic foreland basin, was also filled with ocean water and river deltas when the Arctic coast was farther south than it is today, Myers added. During those prehistoric times of higher sea levels, the Brooks Range sediments were settling to the ocean floor that is now the plain of the North Slope. The smallest sediment particles were naturally carried the farthest, to the then base of the continental shelf, before stopping. The larger sands fell out upstream and on top of the deltas, above the shelf edge, or fore set, according to Decker. Those first sediment layers make up the base of the Brookian sequence and the two zones targeted in the latest North Slope oil prospects: the Nanushuk and Torok formations. “The sands in the Torok tend to accumulate at the basin of the floor, right where the fore sets kind of run out of slope angle and there’s nothing to keep propelling those sediments, so they drop out there at the basin floor,” Decker said. The larger, Nanushuk sands came to rest above the Torok and as sea level retreated rivers carried the sediments farther and farther out to meet the ocean, eventually forming the sandstone layers found today, Decker and Myers said. This is where the oil companies come in. Dallas-based independent Caelus Energy came to Alaska in early 2014 with its sights set on the Torok sands. The finer Torok sandstone has smaller gaps between its grains making it less permeable than the Nanushuk. For that reason, Caelus hydraulic fractures its North Slope wells to create pathways for the oil to travel. Myers said the Torok at Caelus’ Smith Bay discovery is part of a large “submarine fan play,” or the edge remnants of a former river delta. Last October, Caelus Energy CEO Jim Musselman announced his company had discovered upwards of 6 billion barrels of oil at Smith Bay, a near shore prospect in state waters on the edge of the National Petroleum Reserve-Alaska and more than 100 miles from existing North Slope oil infrastructure. Caelus estimates full development of Smith Bay could produce up to 200,000 barrels of oil per day at its current projected size, but Musselman said he could foresee Smith Bay growing to 10 billion barrels once all of his company’s leases in the area are better examined. “Giant fields get bigger with time,” Musselman said when the Smith Bay find was made public. Caelus plans to drill an appraisal well next winter to get a better idea of what exactly it has. The Nanushuk Project, now operated by Armstrong Energy, is not named that by coincidence. It is targeting the Nanushuk formation, which generally sits above the Torok. With 16 wells drilled in the formation since 2011, the Nanushuk Project is better delineated within the Pikka Unit than Smith Bay at this point; and Armstrong CEO Bill Armstrong has told the Journal he believes it could produce up to 1.5 billion barrels of light crude at a peak rate of 120,000 barrels per day. “The (prospect) that we just found is the first of its kind on the Slope, but mark my words, it’s going to be the new hot play,” Armstrong said in a September interview. By January it was repeated for the first time, when ConocoPhillips made news with its Willow discovery, another Nanushuk play in the National Petroleum Reserve-Alaska to the southwest of Armstrong’s and Repsol’s work. ConocoPhillips declined to comment further on the Willow prospect for this story, but the company’s Alaska leaders said when the discovery was announced that it contains about 300 million barrels of recoverable oil that could be pulled at a rate of up to 100,000 barrels per day. The fact that ConocoPhillips, a typically conservative oil major, is willing to go public with a 300 million-barrel projection for Willow off of the results from just two exploration wells drilled in early 2016 could indicate the reservoir is on the scale of that found by Armstrong and Repsol, Myers surmised. “We’re not looking at little small plays; we’re looking at very large plays,” he said. “You’ve got two of these now and there’s more running room for that (Nanushuk) play.” Not long after, in mid-March, Repsol and Armstrong revealed very promising results from the Horseshoe well, an exploration well drilled last winter about 20 miles south of their Nanushuk Project. Armstrong said then that the Horseshoe well confirmed the oil-bearing Nanushuk reservoir they tapped into was much larger than first thought and could double the confirmed size of the original prospect. Repeatable discoveries Decker said the Brookian plays are likely repeatable beyond those already found because the Nanushuk and Torok formations extend west to east across most of the North Slope. The state Division of Oil and Gas has a long seismic cross-section chart of the Slope that shows numerous buried fore set breaks that formed as the ocean retreated over millions of years. The seismic fore set marks — called “shazams” by geologists, at least according to Decker — can be a starting point for oil hunters in search of the subtle stratigraphic traps that hold oil in the Nanushuk and Torok sands. That’s because those fore sets are a better than average place for the sandstone to peter out; and if there are shale or other impermeable rock layers above and below the sandstone formation, the oil can become trapped in the long, fading sliver of reservoir-quality rock. “It’s the stratigraphic subtleties of how are the sands and the intervening shales distributed and do they actually completely seal at the top,” Decker said. The fact that the North Slope coastal plain — and the edge of the continental shelf — developed in steps mostly from west to east with a slight northerly component could mean the Nanushuk oil fields will generally be long north to south and narrow east to west, he added. That feature can be seen in the Nanushuk Project. Armstrong said the Horseshoe well delineated an oil field more than 20 miles long north to south and about 3 miles across. Caelus also holds large tracts of mostly uninspected state leases to the east of Prudhoe Bay that company officials are excited about and also has the smaller Oooguruk and Nuna developments near Armstrong’s Pikka Unit, which holds the large Nanushuk Project. Another positive of the Brookian formations is that they are younger and shallower than the more commonly exploited Beaufortian formations on the Slope, making them somewhat easier, and cheaper, to drill. The Beaufortian sands that generated the giant Kuparuk field are up to about 135 million years old and can be found at depths between 6,000 and 7,000 feet, according to Decker. And Prudhoe Bay wells often have to go to 9,000 feet before finding oil, while Nanushuk sands usually start appearing at about 4,000 feet. Hidden in plain sight Averse to and lighter than water, oil and natural gas always run up from their source rock, and thus require a tight seal rock layer to collect the hydrocarbons and prevent them from continuing upward. “Where it’s not saturated with hydrocarbon, any pore space in the subsurface is saturated with water,” Decker said. Historically, North Slope explorers — and oil drillers worldwide, for that matter — have looked for large, structural oil traps, or “bumps” in seismic data as the best places to start drilling. These bumps in a layer of seal rock usually appear as an upside down bowl on a seismic printout and are a prime place for oil or gas to accumulate on its voyage upward. However, the North Slope is almost as flat underground as it is above, which means the large, obvious irregularities in the rock formations that stored oil for the big fields of Prudhoe Bay and Kuparuk have mostly been exploited, Armstrong said in a previous interview. Enter the stratigraphic trap. “It’s traps that form because of changes in the layers horizontally. You have a sand; that sand thins out and goes away and meanwhile the shale below it and above it are still there,” Decker said. “With a wedge of shale below and shale above that’s going to make a nice permeable sort of wedge for (oil) to build up and that’s the nature of these stratigraphic traps.” Targeting subtle linear stratigraphic traps is not new, Decker said. It’s been done in other basins with other formations, but those holding the cash have long been scared of testing the unproven play in Alaska by employing an expensive North Slope drilling rig. “The concept of stratigraphic traps has really been known to be a viable concept in a very general sense for 60-plus years. I had a college professor who tried to get Shell to drill one in Wyoming back in the 1950s and they’re like, ‘Nah, we’ll stick to our domes,’ and the concept was proven up by another company a few years later,” Decker recalled. He noted several of the wells the Navy drilled in the NPR-A in the late 1940s hit Nanushuk oil and gas, but in quantities too small and in places far too remote to make development worthwhile. Other oil basins are simply at a more mature stage of exploration, Myers and Decker concurred. Armstrong acknowledged the Nanushuk formation he and Repsol struck was not their primary objective when they first began exploring, too. “It was a secondary objective and it was almost invisible on the seismic, so you can see why everybody missed it,” Armstrong said. The Nanushuk Project is tucked between the large Alpine and Kuparuk fields operated by ConocoPhillips. To that point, a top ConocoPhillips Alaska official told the Journal that “we ask our geologists every day” how they did not see what Armstrong found. The big change really came in the form of 3D seismic mapping. Myers and Decker almost identically likened the 3D images to “an MRI of the Earth” juxtaposed against the X-ray-like 2D seismic oil and gas explorers relied upon for decades. “Good seismic made all the difference in being able to prospect at a lower risk for stratigraphic traps. It’s the subtlety of the traps” that necessitates the detailed data, Decker said. Extending the play Finally, with Caelus expanding Slope exploration to the north and west with its Torok find at Smith Bay, a couple other small companies are working to complete the Brookian chain far to the south. Australian-based 88 Energy Ltd. and Houston independent Burgundy Xploration Inc. are currently drilling an appraisal well into the HRZ shale zone on acreage about 60 miles south of Prudhoe adjacent to the Dalton Highway. The Icewine-2 well was spudded April 24 and hit 10,715 feet the morning of May 8, according to an 88 Energy release. The partners plan to flow test the well in late June. If the Icewine Project is developed, it could be Alaska’s first foray into the shale fracking that has turned the petroleum industry on its head. “We think that for a lot of the Brookian system, until we have better information, the assumption is that the HRZ shale is the most likely, most readily explainable source rock.” Decker said. “At the same time the Brooks Range was going up, this Colville basin was going down and the first deposits out there were pretty well starved. You didn’t have sands coming in; all you had was organisms dying in the water column and raining down and clay particles raining down so that makes really good source rocks.” Eventually, those source rocks were covered with millions of years of sediments to form what is the Slope today. While the economics of North Slope shale production seem sketchy to many, particularly at today’s oil prices, estimates from the first Icewine well indicate nearly 1 billion barrels of oil and natural gas condensates could be there for the taking, and a resource of that size would do nothing but help the project’s economics. If the second Icewine well is successful, the 400,000 barrels per day-plus of prospects figure will have to be revised upward soon. Elwood Brehmer can be reached at [email protected]

Senate Finance OK’s capital budget including tax credit funds

With the oil tax credit bill on the backburner, the Senate Finance Committee approved a capital budget bill May 9 that includes $288 million to pay down the state’s growing tax credit obligation. Finance Co-chair Sen. Anna MacKinnon, R-Eagle River, said the appropriation, if agreed to by the House and Gov. Bill Walker, would cover roughly one-third of the about $900 million in refundable tax credits the Department of Revenue is projecting the state will owe by June 30 at the end of fiscal year 2017. The $288 million appropriated to the Oil and Gas Tax Credit Fund is the last cash left in the Statutory Budget Reserve Fund, or SBR, savings account. Last spring, state budget managers discovered the SBR still had $288 million in it because the 2015 fiscal year deficit was slightly smaller than expected — but still more than $3 billion. The Democrat-led House Majority has sharply criticized the state’s refundable oil and gas tax credit program. However, House Democrats have agreed to appropriate hundreds of millions of dollars to the Tax Credit Fund in the past two budget cycles, acknowledging that, like it or not, the credits are a debt the state must pay at some point. Walker has ultimately vetoed portions of those credit appropriations — $200 million out of $700 million in 2015 and all but $30 million out of $460 million in 2016 — before signing the budget bills. Walker contended the state cannot afford the payments without separate substantial deficit reduction measures and new revenue. The current version of House Bill 111, the legislation to repeal the refundable tax credit program that is currently sitting in Senate Finance, would eliminate the Tax Credit Fund come Jan. 1, 2018. But because the capital budget takes effect July 1, the first day of the 2018 fiscal year, the Department of Revenue would have six months to pay out the $288 million if the bills pass the Legislature looking like they do now. The credits are paid on a first-in, first-out basis, meaning companies holding the oldest credit certificates would be paid first. According to Revenue officials, there were $477 million in certificates awaiting repurchase on Jan. 1 and the state has issued $600 million in refundable certificates this fiscal year. About $132 million of those issued certificates have been paid, sold to another company to be used against tax liability or repurchase had not been requested as of Dec. 31, 2016. The big provision in the Senate’s version of HB 111 would switch current, cashable 35 percent net operating loss, or NOL, credits, to a more traditional carry forward tax deduction for small producers and explorers when they have production tax liability. It would also allow small producers — those with less than 50,000 barrels per day of production — to use the $5 per barrel tax credit on oil from new fields to take their production tax obligation below the 4 percent gross minimum tax. The Revenue Department projects that provision would cost the state between about $20 million and $40 million per year in forgone revenue at forecasted oil prices. Overall, the bill is expected to save the state about $115 to $150 million per year by eliminating the directly refundable tax credits, according to Revenue projections. An inverse provision to prohibit loss deductions from taking a producer’s tax liability below the minimum tax on oil from the large legacy fields would increase tax revenue at market prices of about $40 per barrel or less, prices at which the major producers would be expected to start incurring losses. The “hardening” of the tax floor is not expected to have a revenue impact at current and forecasted oil prices, however.

Alaska Air Group posts $99M profit in first quarter

Alaska Air Group Inc.’s impressive run of record earnings came to an end to start 2017, but the company still turned a $99 million profit in its first full quarter after acquiring Virgin America. The Seattle-based parent to Alaska Airlines, regional carrier Horizon Air and now Virgin America reported quarterly net income of $130 million excluding merger and fuel hedging costs, according to an earnings report released April 26. By comparison, Alaska Air Group earned $184 million in profits in the first quarter of 2016, just before announcing the deal to purchase San Francisco-based competitor Virgin America in a deal that totaled approximately $4 billion in cash and assumed debt. The deal closed this past Dec. 14 after a lengthy Justice Department review. “We are pleased to report a solid profit for the first quarter,” Alaska Air Group CEO Brad Tilden said in a formal statement. “With the biggest integration decisions behind us, the hard work of executing the plan now lies ahead. We’ve laid a foundation for growth with our recent announcements of 37 new routes, and the leadership team is fully focused on running a great airline and doing the things we do well — taking care of our guests, building loyalty and operating on time.” In January, the company reported a $911 million profit for 2016, its seventh consecutive record earnings year. The $99 million first quarter profit equated to net earnings of 79 cents per diluted stock share. Alaska Air Group stock sold for $84.93 per share on the New York Stock Exchange at the close of trading April 27. That was down from an early March high of more than $99 per share and down from an April 25 close of $91.42 per share just before the first quarter results were made public. The company paid a dividend of 30 cents per share in the quarter. Alaska Air Group generated about $470 million in operating cash flow for the quarter and spent about $215 million of it on capital projects for a free cash flow of $255 million. Alaska Airlines is spending about $100 million in Alaska to expand and remodel its rural terminals in the state and build a new $40 million hangar at Ted Stevens Anchorage International Airport to accommodate its new larger Boeing 737s. Overall operating revenues were up 30 percent for the quarter to about $1.75 billion and total operating expenses were up a full 50 percent to $1.58 billion year-over-year. That led to a 43 percent decline in year-over-year operating income, which was at $166 million for the quarter. Alaska Air Group ended the quarter with a debt-to-capitalization ratio of 58 percent, largely due to financing the Virgin America deal and taking on Virgin’s $1.4 billion of debt. It ended 2015 with a 27 percent debt-to-cap ratio and Air Group Chief Financial Officer Brandon Pedersen said the company will focus on getting its debt-to-cap back near 40 percent with a less aggressive share repurchase program. “Overall, our first full post-acquisition quarter was solid,” Pedersen said during an April 26 conference call with investors. “There’s a ton going on right now, and I want to credit our frontline folks for taking great care of our guests. But I also want to give a shout out to all the back-office folks who are working so hard to put these two companies together. This is really hard work. But having said that, I hope everyone listening to the call today or reading the transcript can sense the optimism that we have here.” In the first quarter Alaska Air Group added new 20 nonstop market flights from San Francisco, San Jose and San Diego. Through most of 2016 company executives highlighted the desire to capture more of the California market to go with Alaska Airlines dominance in the Pacific Northwest as the primary driver behind the Virgin America purchase. In March, Alaska Airlines announced it would retire the Virgin brand, likely in 2019. It remains to be seen what Alaska Air Group will do with Virgin’s fleet of Airbus jets in the long-term. Alaska Airlines flies Boeing 737s exclusively, a decision that has led to operational efficiencies and Tilden has said the company wants to maintain its strong relationship with aircraft manufacturing giant Boeing, a fellow Seattle resident. Horizon Airlines also announced a tentative amendment to the contract it has with its pilots union, the International Brotherhood of Teamsters, April 14. The specific terms of the new deal were not disclosed, but it would be amendable again in December 2024, according to a Horizon release. On Jan. 27 the union filed for a federal court injunction, claiming the airline was using sign-on bonuses of up to $10,000 without signing a contract to attract new pilots and that violated its existing contract with the Teamsters. “I commend the negotiations team for their efforts to reach a deal that allows us to increase our pilot recruitment efforts and offer generous entry level wages for new first officers,” Horizon Vice President of Flight Operations Brad Lambert said in the April 14 release. “This deal will allow us to successfully compete for talent and grow our airline.” Hiring and retaining pilots has become a challenge for airlines nationwide, particularly for smaller carriers. In Alaska, the state’s Air Carriers Association is working with the state and federal Labor departments to establish an apprenticeship program for pilots and other airline trade careers. Elwood Brehmer can be reached at [email protected]

Murkowski: Health care concerns heard ‘wherever I go’

With an opportunity to discuss nearly anything on their minds, a gathering of Anchorage realtors consistently steered an April 20 conversation with Sen. Lisa Murkowski back to health care. Murkowski said the chief issue of concern raised at the Anchorage Board of Realtors lunch continued a trend among the many Alaskans she talks to. “(Health care) is the issue wherever I go in Alaska and I don’t care what group I’m talking to, whether it’s fisherman, whether it’s Tribal leaders, whether it’s bankers, the conversation comes back to health care and health care costs,” Alaska’s senior senator said. That’s because her state has the dubious distinction of having the highest-cost health care in the country, and oftentimes it’s not even close. The State of Alaska, with a roughly $4.5 billion unrestricted general fund budget, spends upwards of $1.5 billion per year on Medicaid, employee and retiree health benefits. Additionally, the stories a few in the crowd of independent contractors and small business owners told of monthly health insurance premiums in excess of $1,000 per month “are exactly why the (Affordable Care Act) has failed us,” Murkowski said. She said the sweeping insurance law has undeniable positives such as allowing children to stay on a parent’s health plan longer, prohibiting denial of coverage over preexisting conditions and others. However, individuals that do not qualify for insurance subsidies through the federal or state have had a hard time realizing those benefits as insurers try to offset thecosts incurred by frequent utilizers of care in the individual market with higher premiums on the overall pool of insurance recipients. For those in the realtors’ situation — people whom mostly work for themselves — there is no employer to help share the premium burden. “Absolutely unsustainable, the cost that the individual pays,” Murkowski said. “It is cheaper for you to forgo insurance to basically have a policy that says, ‘I pray that myself and my family remain healthy and that’s going to be my policy, and pay the penalty.’” Alaska’s small individual health insurance market of about 18,000 people, for one, simply isn’t large enough to absorb the premium costs associated with frequent utilizers of the state’s also ultra-expensive care. By comparison, the Washington’s individual market has about 300,000 participants. Individual market insurers had been forced to increase premiums by 25 percent or more per year in recent years in an attempt just to recover costs, which was not always successful. As a result, Moda left Alaska last year after losing money in the state. Premera Blue Cross Blue Shield lost $7.7 million in the Alaska individual market over three years before the cash-strapped state last year approved a one-time $55 million individual market reinsurance program to stabilize the market and keep Premera, Alaska’s last individual health insurance provider in the state, company Alaska President Jim Grazko said in a March interview with the Journal. The subsidy helped Premera keep its 2017 individual premium increase “down” to 7.5 percent. The insurer had requested a 42 percent premium hike before the reinsurance fund. The federal Department of Health and Human Services is now debating whether to support the state’s reinsurance program, which would likely lessen, but not eliminate, the need for future state subsidies. Grazko said other states intrigued by Alaska’s individual reinsurance experiment are watching closely to see if it is worth replicating elsewhere. “It’s about stability right now,” Murkowski said of the reinsurance work going on between state and federal health officials. Murkowski, a skeptic of the failed attempt earlier this year by House Republicans to quickly push ACA repeal legislation through Congress, said she was surprised to hear reports that the effort had been renewed and House leaders would try again to vote on health care reform before the end of April. She was particularly caught off-guard because despite claims they had support to pass it, the actual legislation had yet to surface. “I don’t know how you can count votes without letting people see what’s in it. They tried that before — (Former House Speaker) Nancy Pelosi, her famous quote, ‘We’ve got to pass the bill in order to find out what’s in it.’ As Republicans, we don’t want to make that same mistake,” Murkowski said. She criticized the ACA and House Republicans’ American Health Care Act for dealing with health insurance but largely ignoring the underlying cost drivers of health care and again warned against forcing legislation through Congress just to claim a political victory. “When the president says, ‘gosh, health care is complex,’ yes sir it is and we’ve got an obligation to get it right because it is not functioning right now for the average Alaskan,” Murkowski continued. “Let’s not rush to something that doesn’t fix the problem.” The senator’s views as to what will cure skyrocketing individual market health insurance premiums have changed over time, she acknowledged. Once a firm believer in the need to allow individuals to purchase health coverage across state lines — as can be done with other forms of insurance — Murkowski said she now thinks expanding consumer access could help lessen premium increases in other states with like demographics, but realizing significant benefits in her state will be harder. That’s because Alaskans buying an insurance plan in another state will still be billed based on Alaska’s situation. “In Alaska, it’s not just our geographic isolation, it is the fact that we are so far out of whack compared to any other state out there in terms of our cost for coverage and for our health care risk factors. We’re just a higher risk state — our access issues,” she said. “We’re not attractive to anybody.” One place she does see opportunities for cost reductions is in drug prices. Murkowski supports allowing the importation of pharmaceuticals from Canada. She also said she generally believes there are ways Congress can influence drug prices. “There is much, much more that can be done through the negotiation of drug prices and I do think this is where, with this administration and this president, we might see some breakthrough there,” she said. “If you can better afford the cost of your drugs and your medical devices then perhaps, just perhaps, you can afford the coverage.” Elwood Brehmer can be reached at [email protected]

Referendum effort looms over plan to use Fund earnings

JUNEAU — Getting a bill passed to use Permanent Fund income to pay down Alaska’s multibillion-dollar budget deficits might be only half the battle. Both houses of the Legislature have now passed a version of Gov. Bill Walker’s plan to restructure the Permanent Fund and reduce the amount available for dividends. If Walker signs such a bill, one of Alaska’s political icons is prepping to repeal it. “The greedy eyes are out,” former Republican Senate President Clem Tillion said in an interview. “If they change the law, we will change it back.” Tillion, now 92, is getting financial commitments now to back a petition to repeal Senate Bill 26 on the assumption it will eventually pass, he said. “We’re not all that well-organized but we are well-financed,” Tillion added. He declined to specify how much he has raised, or who has committed, but said the group will form a nonprofit to manage the funds and the petition movement shortly after the governor signs the bill. In December 2015, Walker proposed devoting a large chunk of the now $58 billion Permanent Fund’s annual investment earnings to help the State of Alaska pay down what was then a nearly $3.5 billion budget deficit. Budget cuts, slightly increased oil prices and improved North Slope production levels have trimmed that deficit down to about $2.5 billion currently. However, with the forecast calling for continued $2 billion-plus annual deficits with the state’s current fiscal structure still reliant almost entirely on oil taxes and savings, Walker and House and Senate leaders all agree employing the Permanent Fund’s earning power to pay for government services is a necessity. The fight extending the legislative session now is over whether increased taxes or budget cuts should fill the last few hundred million dollars of deficit that the Permanent Fund can’t. Tillion, who was in the state Senate in 1976 when the constitutional amendment establishing the Fund was approved, said Walker, current legislators and others who insist it was intended as a “rainy day” government fund are misguided in their view. “Taxes belong to the government,” said Tillion, who was the lone vote against repealing the state income tax in 1980. “The Permanent Fund is the people’s money. We set up a system where the Legislature was not involved. This is the people’s Permanent Fund.” Tillion, and fellow former Republican Senate President Rick Halford joined current Anchorage Democrat Sen. Bill Wielechowski last September in suing the Alaska Permanent Fund Corp. for following Walker’s directive and transferring only about half of the formula-driven dividend total for 2016. Walker vetoed the PFD appropriation from more than $1.3 billion to $695 million — enough to pay $1,022 PFDs — as a sort of wake-up call to Alaskans and legislators about the need to revamp the state’s financials as savings wane. Wielechowski argued in his suit that Walker’s veto was meaningless because the statute establishing the PFD directed the Permanent Fund Corp. to transfer the money to the dividend fund regardless of the governor’s action. A Superior Court judge disagreed, and Wielechowski, Halford and Tillion have since appealed to the Alaska Supreme Court. Halford said Tillion is a little premature in his efforts to repeal legislation that hasn’t yet passed, but said he supports the principle. He also agrees that today’s politicians and the many Alaska business leaders and groups that support using the Fund for government are twisting its intention. “The people who want to destroy use the word ‘restructure,’” Halford said in an interview. He called Walker’s SB 26, dubbed the Permanent Fund Protection Act, “a scam,” and said business groups support it to avoid contributing more to state services themselves. The three all emphasized that SB 26 does not include language to ensure the Fund’s constitutionally protected principle is inflation-proofed, but instead relies on organic growth to retain its real value. They contend that ensures the Fund will fail under the plan. Halford and Tillion also pointed to the late 1990s and early 2000s when low oil price-induced budget deficits pushed many Alaska politicians to promote using the Fund’s earnings for government. The state survived without reaching into the Fund then and can do so now, they contend. The former legislators suggest Alaska fund its government with a broad-based tax and start to look more like other states in that regard instead of relying solely on oil revenue. While Walker and many in the Legislature contend such a tax is not feasible to fill the large deficit, Tillion and Halford say they are trying to protect the people’s share of Alaska’s resource wealth from those in power who gain and hold their positions by spending money. “There’s always a constituency to spend; it’s hard to save,” Halford said. Those opposed to such a tax say it makes no sense for the state to pay a dividend with one hand while taxing with the other, but Halford, Tillion, Wielechowski and Wasilla Republican Sen. Mike Dunleavy insist the Permanent Fund, and particularly its annual dividend, are the people’s, not government’s. One of Alaska’s most conservative legislators, Dunleavy opposes a broad-based personal tax, contending that reorganizing a much smaller state government and getting politics out of the way of the private sector will spur investment and solve the budget problem. “Clem and Rick and Mike Dunleavy and I all have very different political philosophies on many things but this is what we agree on,” Wielechowski said. They all also agree that repealing a Permanent Fund restructure bill won’t be difficult. Getting a public referendum on a general election ballot — the current schedule would put a Fund bill-repeal on the August 2018 primary ballot — requires 30,000 signatures. “We’ll get the 30,000,” Tillion said. “I have no doubt that there will be a recall on any (Permanent Fund) bill,” Dunleavy added in an interview. “The vast majority of people in Alaska don’t want government meddling” with their money. Dunleavy also said that while he didn’t join Wielechowski’s lawsuit, he supports it. “When it comes to the Permanent Fund, the government of Alaska is merely a vehicle of convenience to take a check and get it to the people where it belongs,” he said. A January poll of 7,000 Alaskans by the Senate Majority concluded 54 percent support using the Fund to fund government, but when posed with a ballot question of whether or not to lower their dividends, the senators all feel the public will vote to put the money in their own pockets. The same poll found 68 percent of those surveyed prefer an income tax or sales tax over using Fund earnings for government when ranking the options. Walker said he takes what Tillion and Halford are saying about the Fund very seriously. “They’re both friends of mine and I don’t minimize what they say at all,” Walker said in an April 26 interview with the Journal. The majority of people working on and watching the state’s budget battle recognize that “restructuring of Permanent Fund earnings is a cornerstone of any solution.” And not having that makes the other pieces of a full fiscal plan that much more challenging, Walker said. The governor said the threat of repealing a Fund bill makes passing a full fiscal plan this year all the more important. He is urging the Legislature to approve a broad-based tax and has proposed other industry tax increases along with a Permanent Fund measure and modest ongoing budget cuts, which is generally in line with the Democrat-led House Majority’s position. The strong Republican Senate majority insists a Fund bill and deeper cuts are all that is needed. Walker said the Senate’s plan increases the likelihood a Fund referendum will make the 2018 primary ballot, but he has no idea if it will pass. The governor added he has acknowledged the possibility of a repeal. “I met with Clem Tillion a few weeks ago because he is a friend, and he certainly brought that up,” he said. “I don’t know why more people aren’t talking about it, but the way I’m addressing it is to continue to push for a full fiscal plan.” Wielechowski said while campaigning last fall he heard an “overwhelming” consensus from his constituents to protect the dividend — the only issue of agreement. “It confirmed what I thought,” Wielechowski said. He added that he doesn’t know why politicians in Juneau aren’t talking much about the prospect of a Fund bill repeal. His best explanation is that the legislative session puts the people involved in a sort of “bubble” that insulates them from what’s happening in the rest of the state, Wielechowski said. The Fund “is the future’s share of a large non-renewable resource that’s going to be gone,” Halford said, adding that, “The Permanent Fund is an odd creature in that it’s not regressive enough for hard-line conservatives and it’s not progressive enough for hard-line liberals. It’s equal.” Wielechowski said he spent hundreds of hours researching the history of the Fund and its original intent. “In ’76 the only thing people could agree on was, ‘let’s set (the money) aside so we don’t spend it all,’” he said. “It was a real politically fascinating discussion. I think the real concern was special interests could come in and get more money for themselves and the Fund was the best way to get the money to the people equally.” Tillion noted the government can already access the earnings of the Fund with a simple majority vote. “If you change the wording of the law you destroy the system. If the government just steals some money I’m not going to like it but that’s legal,” Tillion said. He and Halford emphasized that when it comes down to a real fiscal crisis, Alaskans will be willing to pay for the services they want from their government through taxation. “I was the lone vote against repealing the income tax (in 1980),” Tillion said. “If you don’t want an income tax do a sales tax or a payroll tax. I don’t care what, I don’t care if you cut government down to where there is no government; you don’t touch the people’s fund.”

Senate rewrites House oil tax bill

JUNEAU — Senate Republicans have a new way to get the State of Alaska out from under its $700 million oil and gas tax credit obligation and it’s based on oil companies paying each other. The Senate Resources Committee, chaired by Anchorage Republican Sen. Cathy Giessel, sent a version of House Bill 111 to the Senate Finance Committee on April 24 that would try expand the secondary credit market by allowing companies with additional, late-arriving production tax liabilities stemming from state audits to purchase unpaid credit certificates from small companies and apply them to the audit amount due. The plan would require companies to accept their audit findings from the state without appeal to be eligible for applying purchased credits against their audited liability. The hope is it can be a way for the state to settle its oil tax scores on both sides of the ledger. Republican legislators have rarely missed an opportunity to criticize Gov. Bill Walker for vetoing $630 million in oil and gas tax credit payments over the past two fiscal years, but those on the Senate Resources Committee were more diplomatic with their comments in the April 24 hearing. Walker vetoed appropriations to the state’s Oil and Gas Tax Credit Fund on the contention the state could no longer afford the industry incentive program while running annual budget deficits in the $3 billion range. “The governor’s vetoes of the earned cashable credits in 2015 and 2016 exemplified the issue” of needing to end the ongoing liability, Giessel said. While conservative Republicans contend low oil prices simply exposed bloated state budgets, Democrats jumped on the fact that current oil markets have turned the oil production tax and related tax credit program upside down. Production tax revenue, which was more than $2.7 billion in fiscal year 2014, fell to $259 million in 2016, according to the Tax Division’s 2016 annual report. “When oil was $100 per barrel (the annual credit payment) wasn’t so noticeable,” said Sen. Kevin Meyer, R-Anchorage. “When oil is $40 to $50 a barrel, it’s problematic.” Before Walker’s partial veto, the Legislature appropriated $700 million to pay the refundable tax credits the state was estimated to owe in 2016 alone. Some of the unpaid tax credit certificates held by small producers and explorers have been purchased at a discount by Alaska’s large volume producers — BP, ConocoPhillips, ExxonMobil and Hilcorp Energy — to apply against their annual production taxes and the Senate Resources version of HB 111 would try to build on that. “For the small producers, they can make money now,” Sen. Natasha von Imhof said of the tax audit liability-repurchase option. “It will not solve the problem tomorrow or next year but it begins the process of removing that liability,” Giessel added. Production tax revenue from audits of producers’ prior tax years tax filings totaled $193 million this year, $132 million in 2016 and $264 million two years ago, according to Tax Division Director Ken Alper. Tax audit revenue has historically been deposited in the Constitutional Budget Reserve Fund. Underlying the push for production tax-paying companies to buy competitors’ credits is the elimination of the Oil and Gas Tax Credit Fund and eventually every oil-related cashable tax credit the state offers. The Democrat-led House Majority and Senate Resources cut the refundable 35 percent Net Operating Loss, or NOL, credit, which many feared could put the state on the hook for billions of dollars in tax credits if recent large oil finds by Caelus Energy and the Repsol-Armstrong Energy partnership are developed, but left lesser-used credits for refineries, natural gas storage and Interior Alaska explorers in place. Doing away with the refundable NOL would bring explorers and small producers that have earned cashable credits for years in line with the large North Slope producers that have not been eligible for the direct tax refunds but instead have deducted losses incurred from development projects or low price periods from their annual production taxes — a common tax practice. The state’s current tax credit bill of about $700 million is expected to grow to about $1 billion by this time next year if the program is not cut in some fashion. Senate Resources turned the “Middle Earth” exploration refundable credits into deductions against corporate income taxes, while the refinery and gas storage credits would still refundable until they expire, but that would require separate legislative appropriations. Alaska Native corporations Doyon Ltd. and Ahtna Inc., in search of natural gas in their regions, are the primary companies to use the Middle Earth credits of late. Giessel commented that completely scrapping the fund to pay the credits would prevent legislators from adding other credits in the future that could unintentionally balloon state expenses as the current program did. The House Resources Committee, which spawned HB 111, included a new 15 percent refundable “dry hole” credit to help small companies offset the cost of well-prescribed but ultimately unsuccessful exploration programs. The after-the-fact dry hole credit was removed in later versions of the bill. The Senate Resources Committee also added a 10 percent annual “uplift” provision to the 35 percent deductible NOL credit for up to seven years after the loss was incurred. Some form of uplift was recommended by legislative consultants to help retain the real value of the tax deduction over time until a production tax liability is earned from a project and the deduction can be employed against taxes. The seven-year timeframe is a rough average of the time it takes to bring North Slope developments into production. The Democrat-led House Majority said immediately after the 2016 elections that gave them control of the chamber that cutting oil tax credits was, and still is, a fundamental part of their plan to balance the state budget. Republicans are often quick to note the program worked — in the end maybe too well — as it helped refill Southcentral Alaska’s natural gas stocks and brought new players to the Slope. However, they, Walker, and even some industry leaders in the state have acknowledged the program as unsustainable. House Bill 247, passed last year, will phase out Cook Inlet tax credits over the next couple years. When HB 111 passed the House it did as much to overhaul the production tax as it did to end the credits and roughly doubled the effective tax rate at low prices on the largest North Slope oil fields. It also included a “ring fencing” provision to tie operating losses to specific exploration or development projects as a way to make sure that losses incurred from one project can’t be used against the tax liability of another. Ring fencing is a way to protect the state from forgoing tax revenue if a project generates losses but never produces oil, according to House Democrats. The Senate Resources Committee scrapped the tax increase and ring fencing sections of HB 111. Many Republican legislators willing to curb tax credits have been adamant about leaving the underlying tax structure of Senate Bill 21 in place, pointing to current increased Slope oil production levels for the past two years as proof the tax is working for the long term. “I’m glad this (version of HB 111) refocuses the attention where it needs to be,” Meyer said. Wasilla Republican Sen. Shelly Hughes said the Senate is focused on the long-term revenue increased production will bring and not increasing taxes for a short-term gain. House Resources Co-chair Andy Josephson, D-Anchorage, commended Senate Resources for the abolition of the cash credit program, which would take effect Jan. 1, 2018, noting it is a starting point for an overall fiscal compromise to end the extended legislative session. “It’s great that we’re suspending or ending these cash credits because frankly we weren’t paying them anyway and so no one was prevailing under this system and those cash credits were not something that was sustainable,” Josephson said in the Majority’s April 25 press briefing. But he said that he is “pretty gravely concerned” about the provisions the Senate committee pulled from the bill, adding “they’ve made significant changes to (HB) 111 that I don’t think my caucus will accept.” Josephson, who has consistently harped on the need to pay off the credit obligation if a broader, long-term fiscal solution is reached, questioned the viability of relying on oil companies buying and selling the credits amongst each other to eliminate the state’s bill. “My plan, and I think a place for settlement, would be to pay them faster than that,” he said. The latest iteration of HB 111 also “hardens” the gross minimum 4 percent production tax floor on the large, legacy North Slope fields to prevent deductions from taking a producer’s liability below the minimum tax. It amounts to a small tax increase, Giessel acknowledged, noting it was one of several conclusions drawn in a tax credit working group she formed in 2015 to evaluate the effectiveness of the program. The minimum tax floor “is still flexible for new or small producers,” she added, that operate under different tax provisions. Republican Resource Committee members Sen. John Coghill of Fairbanks and Bert Stedman of Sitka voiced concerns that the bill does not resolve a major point stressed by the Legislature’s oil industry consultants, that Alaska’s production tax, which varies between gross and net systems depending on the market price, is unnecessarily complex. Castle Gap Advisors Managing Partner Rich Ruggiero repeated over many days of House and Senate committee testimony that the production tax with rates set on oil price and not profitability will likely need continuous adjustment as market conditions and production costs change. “We did not address the complexity of our tax system and that’s probably going to be an issue for a long time,” Coghill commented. Stedman added, “I would be hesitant to say Senate Bill 21 is a success when its important components are flawed.” Elwood Brehmer can be reached at [email protected]

Chugach kills Snow River hydropower study

Public pushback persuaded Chugach Electric Association to punt on its proposal to build a $500 million-plus hydropower project at the headwaters of the Kenai River less than four months into a decade-long process. The Anchorage electric cooperative announced late Thursday that it is canceling further study of a concept to dam the Snow River near Seward, which is the feeder system to Kenai Lake and the upper reaches of the Kenai watershed. The Chugach board of directors had allocated $200,000 for very preliminary study work of the concept this year, but heeded a recommendation from management to stop the work after a series of meetings with stakeholder groups, according to a utility press release. Chugach voluntarily held informational public meetings in Anchorage and Moose Pass earlier in the week and received significant criticism from individuals concerned about the downstream impacts the project could have on the system’s prized salmon fisheries. “As a member-owned cooperative that values the opinions of Alaskans and the communities we serve, we have decided to end the Snow River study. We are committed to sustainable energy, but we’ve heard from many Alaskans who do not want us to study this option, and we appreciate and respond to those voices and concerns,” Chugach CEO Lee Thibert said in a formal statement. On Dec. 23 Chugach submitted a preliminary permit application with the Federal Energy Regulatory Commission to give the project standing with the agency and allow it to carry out the requisite studies before advancing to more detailed and costly development phases. The utility’s initial idea was to dam the Snow River several miles upstream of where it crosses under the Seward Highway and dumps into Kenai Lake to produce 75 megawatts of hydropower. Chugach and other Southcentral utilities that rely on Cook Inlet natural gas for the majority of their fuel supply have not been able to secure long-term supply contracts of late and a hydro project could provide a stable-priced power source for upwards of 100 years, Chugach officials said. They also noted the three-dam system and associated 5,000-acre reservoir would be well upstream of salmon habitat and not impede fish passage but skeptical sport and commercial fishermen emphasized other impacts such as changes to downstream water flow rates, temperature and turbidity that could upset the Kenai’s immensely popular fisheries. Chugach officials also stressed that the proposal was in its infancy and would be at least 10 years out from electric generation. In February the Chugach board adopted the “triple bottom line” decision-making process that demands all business decisions be socially and environmentally responsible in addition to being a sound economic move. Thibert said at the April 17 Anchorage meeting that strong public opposition to the Snow River project would cause the utility to drop the idea as a result. “Our public engagement process worked,” Chugach Board Chair Janet Reiser said. “Sustainability is very important to us, and we want to find long-term supplies of energy that will allow Chugach to provide electricity to Alaskans for decades to come. Thank you to our members and other Alaskans who took the time to express their concerns to us.” Elwood Brehmer can be reached at [email protected]

Senate on offense to start overtime

The Senate is starting overtime with all the balls. It took all session, but the Democrat-led House Majority got the final pillar of its four-part fiscal plan — an income tax — passed on the 90th day of the regular legislative session. With that, the majority Republicans in the Senate now have the House’s version of a broad-based tax, the 2018 fiscal year operating budget, a government draw on the Permanent Fund and an oil tax and credit bill to consider, none of which they like at all. The majorities’ opinions on the four big bills are basic differences in political philosophy; Democrats pushing for taxes to support current spending and Republicans demanding less spending to promote industry investment and keep Alaska the last personal tax-less frontier. However, the fact that the differences are so fundamental makes finding an avenue to compromise so difficult. House Majority Leader Chris Tuck, D-Anchorage, exemplified the divide in a sharp comment about how he sees the rest of the session going during an April 18 press conference. “The only compromise I see right now is the Senate accepting a fair and balanced budget,” Tuck said. “What more can we do on our side?” he added later. “If the Senate thinks that we’re going to get out of here with just a (Permanent Fund bill) they got another thing coming,” Rep. Gabrielle LeDoux chimed in. LeDoux is one of three Republicans in the House Majority coalition. Senate President Pete Kelly, R-Fairbanks, called the House’s income tax proposal “absurd on its face,” given the state is already in a recession. House leaders have shared a sentiment similar to Kelly’s regarding the Senate’s goal to cut $750 million from the budget over the next three years, particularly after multiple economists testified that major additional cuts to government budgets would be the most damaging to the state’s economy of the deficit-reduction options. “If we’re trying to get out of a recession you don’t take money out of the economy,” House Finance Co-chair Rep. Paul Seaton, R-Homer, said of the Senate’s plan to cut. On general principle, Gov. Bill Walker is on the House Majority’s side. He also said he hopes to act as a mediator of sorts between House and Senate leaders and has offered to meet with them several times a week until a resolution is reached. Walker proposed a more modest income tax last year to generate about $200 million. The House income tax would raise nearly $700 million per year to fill most of the remaining deficit after drawing on Permanent Fund earnings, which juxtaposes the Senate’s budget cuts also aimed at closing the left over gap. Walker emphasized in an April 18 press briefing that the need for a broad-based tax is not about a wish to start growing the size of state government again. “It’s about fixing government,” the governor said, noting the state is sitting on about $2 billion of deferred facilities maintenance. “We will continue to root out government inefficiencies,” he added. Annual state spending has dropped more than 40 percent since its peak several years ago, with most of the cuts coming under Walker’s watch. However, much of the reduction was the elimination of discretionary spending in the capital budget, which will have to resume again on some level to fix state infrastructure and help revitalize the state’s struggling construction industry. As he has said since introducing his fiscal plan in December 2015, the state’s ongoing multibillion-dollar annual budget deficits and dwindling savings require unsavory decisions — taxing yourself and limiting the size of PFDs, for example. “I didn’t run for governor to reduce the Permanent Fund (dividend),” Walker said. “It’s not about what we want to do it’s about what we have to do.” While the controlling interests in the House and Senate are nearly aligned on a vision for restructuring the Permanent Fund, it is contingency language in the bill requiring the Senate to approve a personal tax and the House-passed version of the oil tax bill, House Bill 111, before the Fund action takes effect that is the big hang-up. Walker also said he supports the current version of HB 111 because “it’s the only one on the table that addresses the oil tax credit issues.” Legislative leaders also agree that the state needs to eliminate its exposure to refundable North Slope tax credits after doing so for Cook Inlet last year. But HB 111, currently in the Senate Resources Committee, also roughly doubles the state’s effective production tax at current prices and that’s a nonstarter for Senate Republicans. Walker stopped short of endorsing the House’s tax increase. He proposed production tax changes that led to a smaller tax increase last year.

State files largest LNG permit application ever

The Alaska Gasline Development Corp. was ahead of schedule April 17 in checking a big “to-do” off its long list of steps to get natural gas off the North Slope. AGDC filed its formal license application with the Federal Energy Regulatory Commission more than two months before the end of June goal set by corporation President Keith Meyer. The AGDC board of directors unanimously passed a resolution at its April 13 meeting authorizing management to submit the Natural Gas Act Section 3 permit application. The license application is FERC’s version of the National Environmental Policy Act environmental impact state process for the energy projects over which it has jurisdiction. Meyer and other AGDC leaders characterized the filing as a “huge milestone” for the state-led project. “The FERC filing validates the realness of this project,” AGDC board chair Dave Cruz said April 13. The sheer volume of information dumped at FERC’s Washington, D.C. door appropriately matches the all but unprecedented scale of the roughly $40 billion Alaska LNG Project. While FERC oversight — in the natural gas realm — is typically limited to LNG plants, the commission considered the Alaska LNG Project’s linked 800-mile gas pipeline and North Slope gas treatment plant to be part of an integrated LNG system. That allows the entire project to be permitted in a single environmental impact statement instead of two or three, according to AGDC Vice President Frank Richards. He said April 13 the corporation had prepared nearly 58,000 pages of environmental, socioeconomic and engineering data to give to FERC. It all adds up to the largest LNG project application the federal agency has ever reviewed, he added. “We hope that we’ve met every single requirement,” Richards commented. Meyer said AGDC had answered about 2,000 of the 3,000 questions FERC and other federal energy and environmental regulators raised after reviewing the 30,000-plus pages of Alaska LNG resource reports. Draft resource reports are sent to FERC prior to submitting a project license application to ensure the project proponents have gathered sufficient information before leaping into the expensive application process. Many of FERC’s remaining questions are best answered by other state agencies, according to Meyer, and shouldn’t impact the licensing timeline. “We want to get this FERC process going; it’s on a critical path for the (final investment decision) date,” Meyer said. Meyer has a plan for AGDC to operate on the funds from previous appropriations for about the next year, but the $100 million-plus licensing process will require additional funding from the Legislature in early 2018, at which point he hopes to have customers lined up to prove the project’s viability. Richards elaborated that the state-owned corporation is asking FERC to finish the licensing process by the end of 2018 — on the short end of the 18 to 24 months it usually takes the commission to finalize an LNG environmental impact statement. For one, FERC has the reputation of turning around environmental impact statements much quicker than other federal agencies. Additionally, Meyer said the tremendous amount of baseline data compiled in the resource reports will hopefully help FERC make its determinations quicker. Cruz emphasized that AGDC couldn’t have done the work it submitted April 17 on its own. Most of the data was gathered, analyzed and organized by the Alaska LNG consortium led by ExxonMobil with support from BP, ConocoPhillips and AGDC. The producers combined to put up three-quarters of the roughly $600 million that has been spent studying and designing the megaproject since 2013. The state funded the remaining 25 percent. Even with the State of Alaska now leading the Alaska LNG effort, the producers would see a return on their investments in the project to-date by way of being able to sell their collective 26 trillion cubic feet of North Slope natural gas if the project is built. LNG Summit, financing Meyer said AGDC’s closed-door Alaska LNG Summit in early March was a success, with 23 individuals in attendance from 14 LNG buyers, traders and investment firms. He also noted all but about $8,000 of the $264,000, weeklong event was covered by sponsorships and registration fees. The attendees also paid their own way to Alaska. Corporation leaders further described the capital structure that they envision will fund the Alaska LNG Project during the April 13 board meeting. AGDC Commercial Vice President Lieza Wilcox laid out a financing outline with about $10 billion in equity and another $30 billion of non-recourse debt for the $40 billion construction. The corporation expects to attract equity investors with an 8 percent return, which Wilcox said AGDC has heard from multiple sources is a “very reasonable” expectation. The equity would combine with the majority debt financed at 5 percent for a 5.75 percent blended cost of capital. Wilcox added that the banks issuing the debt would act as de-facto “auditors in the system” to assure AGDC had not only structured the financing correctly, but also to vet the LNG buyers and related gas sales and tolling contracts that will underwrite the debt. Meyer has long said take-or-pay type contracts will backstop the debt and keep the project’s massive liability off its equity owners. The 75-25 debt-equity ratio is indicative of how other large infrastructure projects are often funded, he said in an interview; it’s not specific to AGDC’s particular wants or needs. Finally, once the project is paid off after about 20 years, it could generate upwards of $5 billion in free cash flow for equity investors each year, according to AGDC. A paid-in-full Alaska LNG Project built for $40 billion has the potential to be monetized for up to $50 billion in today’s dollars if more North Slope gas reserves are found, Meyer estimated, making it more attractive to equity investors. The U.S. Geological Survey estimates there is at least another 200 trillion cubic feet of natural gas yet to be discovered on the North Slope and “only a small portion of that would have to be developed to supply the project for another 25 years,” Wilcox said. The 35 trillion cubic feet of available gas reserves at the Prudhoe Bay and Point Thomson fields is expected to supply the project for its first 25 years. Elwood Brehmer can be reached at [email protected]

Snow River hydropower concept meets immediate skepticism

The Kenai River always draws a crowd. A standing-room only audience of more than 100 gathered April 17 in Anchorage at an informational public meeting put on by Chugach Electric Association to discuss the utility’s concept to dam the Snow River, which feeds Kenai Lake. The crowd of largely commercial and sport fishermen — sworn opposition in most other settings — peppered Chugach officials with questions regarding the scale of the proposal, how far along the utility is with the idea and what weight their skepticism would carry in the decision-making process. Several Chugach representatives spoke to the crowd, all emphasizing that the idea is little more than that at this point, as evidenced by the fact the Anchorage utility’s board of directors so far has approved spending just $200,000 to study the concept, according to CEO Lee Thibert. To that end, Chugach government affairs manager Phil Steyer said the utility is not sure if it will fund the project beyond the $200,000 allocated for this year. The basics of the proposal entail constructing a 300-foot-high primary dam on the main stem of the Snow River and two smaller auxiliary dams to hold back a roughly 5,300-acre reservoir. That would all be done to feed three electric turbines capable of producing up to 75 megawatts of power. By comparison, Chugach’s peak load can exceed 400 megawatts during the coldest, darkest winter days. A rough estimate puts the cost of the Snow River hydro project at between $500 million and $600 million, said Paul Risse, Chugach’s vice president of engineering. The utility applied for a preliminary permit from the Federal Energy Regulatory Commission last December. The commission approved the Federal Power Act Section 4(f) permit March 22. Securing the permit gives Chugach standing with FERC; it allows the utility to study the project for up to three years or more without the worry that another organization will advance a similar hydro project in the area before Chugach can apply for a license to construct the project. Steyer said the Snow River site — several miles upstream from the Seward Highway bridge where the river dumps into Kenai Lake — would provide for a large enough reservoir to provide power year-round and is closer to existing infrastructure than other hydropower possibilities. Steyer added that at a minimum the finished project is 10 years out. “This is a project we’re looking at to meet our commitment to our customers 10, 20, 30, 50 years into the future,” he said. Particularly in Southcentral Alaska, where utilities currently rely on local natural gas with an uncertain long-term supply, a large hydro project is often as close to an ideal power source as there is. The dams and turbines supply reliable, schedulable power for upwards of 100 years as long as it keeps raining and snowing, with no fuel costs or emissions. The locale is also upstream of salmon habitat, so it wouldn’t interfere with fish passage, Chugach personnel highlighted. However, the group gathered at the Lakefront Hotel in Anchorage April 17 was quick to point out the other impacts dams have on watersheds even if they don’t directly impede upstream-bound salmon. Dams provide a place for sediment to settle, thus changing water turbidity. The impoundments they create typically result in higher downstream water temperatures; and especially on highly variable glacial-fed systems such as the Kenai watershed, they change water flow cycles, which Risse acknowledged. The latter would be of particular importance on the Snow River, which contains a glacier-dammed lake at the base of the glacier that feeds it. The lake fills and releases remarkably reliably every two or three years in fall in a phenomenon called a jokulhlaup. The Snow River can rise as much as six feet over the span of a few days when the glacial dam gives way. Risser said how the jokulhlaups would impact the viability of the project is just one of the many things Chugach still needs to study. “If there’s a negative impact on fishing, it’s not going to happen,” Risser said, noting he among many Chugach employees fishes the Kenai each summer. “We have a personal interest in protecting the Kenai.” A second meeting was scheduled in Moose Pass April 18. The Chugach officials stressed the public meetings were the utility’s way of offering full disclosure to its members and the public at large about its activities; they were not mandated by FERC’s permitting process. Thibert also noted in an interview that in February the Chugach Electric board of directors passed a resolution to adopt the “triple bottom line” decision-making philosophy, which demands all business decisions to not only be economically viable, but also socially and environmentally responsible. Because of that, Thibert said, if Chugach cannot ultimately get public buy-in on the Snow River hydro project, it will not move ahead with the proposal. Elwood Brehmer can be reached at [email protected]

Oil production up for second year in a row

Don’t spend it all in one place. Better than expected oil production and price figures mean the State of Alaska should have an extra $191 million when the 2017 fiscal year ends June 30, according to Revenue Commissioner Randy Hoffbeck. While the extra $191 million equates to about a 20 percent increase in the spendable portion of the state’s overall petroleum-sourced revenue — including royalties, corporate, property and production taxes — in the big budget picture it means the state will likely finish the fiscal year with a budget deficit of about $2.6 billion instead of the previously estimated $2.8 billion gap. The 2017 Spring Revenue Forecast projects an average Alaska North Slope oil price of $50.05 per barrel, up from $46.81 in the 2016 Fall Forecast, which was released in December. Alaska North Slope crude has sold for about $55 per barrel in recent days. Daily production in fiscal 2017 is now pegged to average 523,700 barrels per day, up from 490,300 barrels per day in the fall forecast. Coincidentally, both the revised price and production numbers are 7 percent greater than the fall predictions. If the new 523,700 barrels per day forecast is correct, it would mark the second consecutive year of increased production on the North Slope, the first time production has increased in consecutive years since it peaked at more than 2 million barrels per day in 1988. Producers pulled an average of 514,900 barrels per day in fiscal year 2016. Prior to 2016, 2002 was the only year of increased production — when ConocoPhillips brought its large Alpine field online — after the late 1980s peak. The current daily production average for 2017 is 525,900 barrels. However, daily production typically slows in spring and summer each year as companies perform maintenance on North Slope facilities and other infrastructure. Additionally, Hoffbeck said during an April 14 morning Senate Finance Committee hearing that North Slope oil producers also reported a $348 million, or 7 percent, decrease in their actual deductible lease expenditures for the entire fiscal year versus what was reported to the Revenue Department last fall. The lease expenses — estimated now at $4.5 billion in 2017 — are what it costs the companies to extract the oil and therefore are deductible from the state’s net profits production tax calculation. Fewer deductions means more taxable revenue to contribute towards the state’s final revenue calculation. ‘Stale’ production forecast Much was made by legislators that the spring forecast still contains the fiscal 2018 production estimate of 459,800 barrels per day found in the fall forecast despite the fact that 2017 production has not only outpaced expectations, but last year as well. A 2018 daily production average of 459,800 barrels per day would equate to a 12 percent decline rate from this year. Finance Co-chair Sen. Anna MacKinnon, R-Eagle River, noted that even if the historical average North Slope production decline of about 5 percent resumes in 2018 the fiscal year-end average would still be well above the official spring estimate. “We had always been wrong on the high side and now we’re a little concerned that we’ll be on the low side in distorting that (production) number,” MacKinnon said. DNR provides the production estimates that Revenue incorporates into the annual fall Revenue Sources Book, which serves as a guideline for legislators to budget off of. For many years DNR hired a private consultant to come up with the production forecasts and for many years those forecasts were consistently higher than what played out. Last fall, in an effort to save money and produce a more accurate — therefore conservative — North Slope oil forecast, DNR did its own forecasting in-house. Senate Majority Leader Sen. Peter Micciche, R-Soldotna, emphasized the importance of the role production estimates play in the Legislature’s budgeting — particularly this year, given the House and Senate majorities have diametrically opposed views on the need to impose a state income tax this year. Hoffbeck and Department of Natural Resources officials acknowledged the fiscal 2018 production estimate is “stale” because current numbers are outpacing the fall forecast, but DNR has not typically revised the longer-term production figures in its spring updates. Division of Oil and Gas Director Chantal Walsh said the fact that current production is outpacing not only the state’s official forecast, but also last year, will play a major role in how the department prepares future forecasts. The decline was expected because of decreased drilling activity in the large legacy fields of Kuparuk and Prudhoe Bay due to low oil prices, Walsh explained, but it didn’t happen. “The major oil companies also outperformed their forecasts,” she said. “These are anomalous years we’ve been through.” Ed King, a special assistant to DNR Commissioner Andy Mack said anecdotally that the actual fiscal 2018 daily production average would likely come in closer to the original 2017 estimate of about 490,000 barrels per day. King and Walsh also said DNR would provide a production estimate range incorporating realized production figures for the upcoming fiscal year in future spring forecast updates. A full production estimate includes technical well data reviews and takes several months. Some Republican legislators have alluded to the possibility that administration officials are trying to use the closely tied state revenue and oil production forecasts as subtle political leverage by making the state’s fiscal picture look worse than it is; Gov. Bill Walker supports a state income tax to help balance the budget. Micciche discredited that notion, saying he is not suspicious of the administration’s motives, but added it is just “a rough time to use a stale number.” “I think we’re all sort of saying the same thing,” Micciche said to Walsh and King. “You have work to defend and I have to come up with a number that helps fund this government and the right answer is somewhere in between.” Elwood Brehmer can be reached at [email protected]

In email, BP Alaska president details 2016 losses

BP Alaska President Janet Weiss has offered additional financial information about the company’s 2016 income after a reported $85 million profit became part of the political debate over oil taxes this week. In an email obtained by the Journal dated April 12, Weiss wrote that the $85 million profit earned BP (Exploration) Alaska Inc., and the $464 million it paid to the state, reflected only one portion of BP’s overall Alaska business in the company’s 2016 financial report published April 6. “Unfortunately, the 20-F form only tells part of our BP Alaska business story which has caused some confusion and a number of questions that I want to help address,” Weiss wrote. “Let me be very clear, the BP Alaska Region did lose money (negative cash flow) in 2016 to the tune of about $1 million a day (a loss of $358 million for the year). And, the entire Region had a net income loss of $184 million. A BP spokesperson confirmed Weiss authored the email and said it was a personal message to several Alaska community leaders. The $85 million profit relates specifically to its upstream business, but does not account for BP’s midstream business, which includes the Trans-Alaska Pipeline System, of which BP is part owner, and its marine shipping businesses, which are accounted for separately, according to Weiss. The upstream, or North Slope, operations are parsed out in accordance with federal Security and Exchange Commission requirements related to the Prudhoe Bay Royalty Trust, which is traded on the New York Stock Exchange, she explained. “The 20-F (SEC reporting form) is an income statement and does not reflect cash flow,” Weiss wrote. “It is based on what our finance folks call ‘accrual accounting’ which does not include ~$600 million of capital we invested in our Alaska business in 2016. “Looking at only one piece of our business is like a restaurant only considering the cost of the food it buys and not taking into account the equipment need in the kitchen, transportation costs to get the food to your restaurant or the marketing needed to attract customers. Weiss concluded, “It’s important to note that even in this low price environment, BP invested $1.8 billion in Alaska ($1.2 billion operating expense, and $600 million capital) in 2016. As a community leader, I wanted to provide you with the complete story directly from me.”

Big bills finally on the move as Legislature hits crunch time

Now we’re getting somewhere. The House and Senate majorities still have large philosophical gaps to bridge, but the procedural pieces are being put in place to make that happen. With less than a week to go in the voter-prescribed 90-day session on April 16, the House brought to the floor its version of Senate Bill 26, Gov. Bill Walker’s legislation to spin off Permanent Fund income to fund government, on April 12. An amended version of the Senate bill was passed out of the House Finance Committee April 11. The House passed the bill 22-18 along caucus lines. For most of the session, the Democrat-led House Majority coalition was pushing House Bill 115, Finance Co-chair Rep. Paul Seaton’s proposal to draw earnings from the Permanent Fund and make dividends a direct income tax credit for individuals with a tax liability. With HB 115 and SB 26 being the foundational fiscal plan elements for the House and Senate, respectively, the bodies had been on parallel paths without a foreseeable means of resolution. The move by the House Majority to split their income tax in HB 115 from a Permanent Fund plan and forward an amended SB 26 at least gets the two trains moving toward each other on the same track. While the resulting conference committee collision — if SB 26 passes the House — will undoubtedly be a messy one, it will provide a way to reconstruct a Permanent Fund plan from the political wreckage. The basis of the House version of SB 26 is similar to the Senate’s in that it starts with a 5.25 percent of market value, or POMV, draw annually on the Fund that is decreased to a 5 percent draw after several years. The divergence comes in the details, where the House would guarantee $1,250 PFDs for two years instead of the Senate’s $1,000 dividend pledge for three. Additionally, the House plan starts to reduce the Fund draw when spendable state oil revenues exceed $1.4 billion, as opposed to the Senate’s $1.2 billion trigger, which amounts to a simple difference in how much cash each body wants the state to have at its disposal long-term. The House, among other changes, also cut out the Senate Republicans’ $4.1 billion unrestricted general fund spending cap. Senate leaders have acknowledged the statutory appropriations limit is basically unenforceable; it is a philosophical statement and a stepping-stone to drastically tighten the current constitutional spending limit, which would require voter approval. Finally, the House added contingency language to SB 26 that would require the Senate to approve a broad-based tax and the House’s oil tax increase before the Permanent Fund draw portions take effect. House Majority leaders said in an April 11 press briefing that their decision to split the Permanent Fund POMV draw from the income tax and make HB 115 an income tax-only bill was a show of compromise to the Republican-heavy Senate that has insisted a broad-based tax should be left for future sessions if it is to be considered at all. However, the linked Permanent Fund-income tax version of HB 115 drew criticism that it could violate the state Constitution’s single subject rule for legislation, a technical but major detail. As of April 12, HB 115 was also on its way to the House floor. Meanwhile, the stage is set for another sticks-and-gloves-all-over-the-ice brawl over the operating budget. The House voted down the Senate’s version of the budget 10-30 on April 11, with minority Republicans splitting their votes. The Senate’s operating budget cuts about $330 million from the current fiscal year budget. Some Republicans are uneasy about Senate reductions to K-12 education and university funding, while others contend the overall budget cuts don’t go far enough. The House-approved budget is on par with current spending levels, leaving a gap of several hundred million between the two bodies. Elwood Brehmer can be reached at [email protected]

DNR approves Pebble permit, with conditions

Natural Resources Commissioner Andy Mack approved Pebble Limited Partnership’s long-awaited land-use permit April 11 with stipulations that include a $2 million bond to backstop exploration cleanup. The permit is for 12 months; Pebble had sought a permit through 2018. Pebble applied for the miscellaneous land-use permit, or MLUP, last Oct. 13. MLUP approval for most activities is often little more than a formality, but next to nothing about Pebble is normal either, from the size of the project to the fervor it generates. That DNR received more than 2,000 comments on the annual Pebble MLUP lends credence to that fact, which Mack acknowledged in a department release. A vast majority of the commenters supported, at a minimum, increased oversight of Pebble’s activities. “It is unusual for a state land-use permit to get so much public attention, but it is not unusual for DNR to add stipulations to a land-use permit,” Mack said. “We have carefully considered and applied new stipulations to this permit that are reasonable, comply with our legal requirements and address concerns we heard in the comment period.” It is also unusual for DNR to hold a formal public comment period for an MLUP application. However, a 2015 Alaska Supreme Court decision in one of the numerous court cases surrounding Pebble requires the department to hold a 30-day comment period on permits for the project until DNR drafts regulations in accordance with the decision. Some level of financial surety typically accompanies an MLUP unless DNR waives the requirement, according to department spokeswoman Elizabeth Bluemink. Similar performance guarantees have been required for some mining operations in the state and are often sought for non-mining activities on state land as well, Bluemink said. Pebble spokesman Mike Heatwole described the $2 million guaranty as “very workable,” adding it was not a surprise and had come up in discussions with DNR officials. Mack wrote in a letter approving the permit that the $2 million figure equals what DNR estimates it would cost for the state to remove Pebble’s on-site equipment and temporary storage facilities and otherwise restore the area should the company for some reason fail to meet its obligations. The money will eventually be returned to Pebble if the company completes the restoration work. Heatwole said other stipulations in the permit approval, such as an expectation Pebble will appropriately abandon 138 boreholes this year and inspect at least 300 of the 612 exploration holes that are to remain open, were part of a summer work plan the company submitted to the department about a month ago. The 612 holes will stay open for ongoing monitoring and additional data collection. More than 1,300 boreholes have been drilled on the claims by several companies since 1988, according to DNR. “We’re focusing on getting a (MLUP) permit and continuing our summer work program,” Heatwole said in a brief interview. That work program will largely resemble what Pebble has done in recent years — monitor and maintain drill sites and equipment, according to Heatwole. No further exploration is planned at this point. Bluemink also noted that the performance guaranty is not a reclamation bond, which Pebble is not required to post for its work to date. The State of Alaska generally requires mining project operators to post a reclamation bond if the activity disturbs more than five cumulative acres. Because Pebble chose to conduct operations via helicopter, thus reducing its footprint, and all of its temporary facilities were placed on “tundra mats” to limit impacts to vegetation that will grow back once the equipment is removed, the company has yet to meet the five-acre threshold, according to DNR officials. Pebble Partnership holds title to mining claims covering 266,300 acres of state land near Iliamna Lake at the headwaters of the Bristol Bay drainage. The location of the proposed gold and copper mine in the midst of one of the world’s most prolific salmon-rearing watersheds has naturally made it an extremely controversial project. A study released last November and commissioned by the United Tribes of Bristol Bay, a Dillingham-based nonprofit that has led the charge against Pebble, alleged the company had neglected many of its work sites leading to limited but unnecessary environmental damage. The report led to increased public interest in the usually low-key MLUP review. At the time DNR officials said Pebble was in compliance with its state permits and the Montana-based Center for Science in Public Participation, which conducted the study, may have misinterpreted some of Alaska’s regulations in drawing its conclusions. United Tribes of Bristol Bay and other environmental and fishing groups lauded DNR’s permit contingencies as needed oversight protections. A short press release from Pebble’s parent company Northern Dynasty Minerals Ltd. says Pebble is closely reviewing the MLUP approval. “The Alaska Department of Natural Resources and other state agencies have had an active oversight presence at the Pebble project site for more than a decade and have confirmed that Pebble is a well-managed exploration project. We will continue our site operations in 2017 in full compliance with the state’s permit conditions, and in a manner that protects the broader public interest in the lands and resources surrounding the Pebble property,” Pebble CEO Tom Collier said in a formal statement. Heatwole added the permit approval checks off the first of several “high level” goals Pebble Partnership has for 2017. Next on the list is settling its lawsuit against the Environmental Protection Agency, which is on hold for ongoing negotiations. After that, Northern Dynasty hopes to secure another large investment partner to help fund the expensive, multi-year federal Clean Water Act and National Environmental Policy Act permitting processes that will require additional field study. He said Pebble still plans to apply for the environmental permits this year if its parent can find another partner for the project, as Collier indicated in a January investor presentation. Northern Dynasty’s previous partner in Pebble, London-based Anglo American Plc, pulled out of the project in 2013.

House sends oil tax rewrite to Senate

While many Alaskans were busy taking advantage of a warm spring weekend, House Majority coalition members were making up for lost legislative time by whisking their oil tax proposal onto the House floor. A Finance Committee rewrite of House Bill 111 was introduced on Friday, moved from committee Saturday and voted on Monday. It passed the House on a 21-19 vote. Anchorage Independent Jason Grenn was the lone majority caucus member to vote against the bill. Cutting the state’s future oil and gas tax credit obligation was an expected topic this session and a foundational goal of the Democrat-led majority. Once reluctant to curb the industry incentive credits, Republican legislators have also acknowledged a need to limit the state’s exposure to additional cash outlays while the Legislature overhauls the rest of state finances to close an ongoing budget deficit that this year is about $2.8 billion. It does that. However, HB 111, particularly the version that emerged in the House Finance Committee Friday, April 7, is an overhaul of the underlying oil tax code. To that end, Grenn said during the floor debate that the bill tinkers with too much of the oil tax code and he would support legislation that more narrowly addressed the state’s outstanding tax credit obligation, which is expected to be nearly $1 billion in about a year. According to Tax Division Director Ken Alper, HB 111 would raise taxes at mid-range oil prices between about $50 and $100 per barrel and generally be a wash compared to current law at higher prices. The bill now eliminates the sliding scale per barrel credit applicable to the large, legacy oil fields such as Prudhoe Bay and Kuparuk, and reduces the base tax rate from 35 percent to 25 percent. The impact of the base rate tax change and elimination of per barrel credits is to make the effective rate equal to the statutory rate at the $50 to $100 range; the current law has been criticized by members of the House Majority for never collecting 35 percent of net profits unless prices reach more than $150 per barrel. Varying with market price by $1 in $10 increments — from zero at prices above $150 per barrel to $8 at less than $80 per barrel — the credit’s inverse relationship to price is a mechanism to add progressivity to the base 35 percent production tax rate on company profits. Previous iterations of HB 111 reduced the per barrel credit at low prices but kept the 35 percent base rate. At prices above $100 per barrel, HB 111 would add a 40 percent personal income-like tax bracket on profits earned above the $100 price. Roughly, the first $60 in production tax value would be taxed at 25 percent; additional profit above $60 would be taxed at 40 percent. While killing the sliding per barrel credit is undeniably a significant policy change, supporters of the move note it mirrors what former Gov. Sean Parnell proposed in 2013 in the first version of Senate Bill 21, the vehicle for Alaska’s current oil tax law. It is also a step to simplify the layered provisions of the current tax system, which the Legislature’s tax consultant urged be done in some form, proponents contend. That same consultant also noted Alaska would be one of very few oil-producing regimes to raise taxes during a period of low prices if the Legislature chooses to do so this year. Additionally, the bill would keep the current 4 percent gross minimum tax, but “harden” it by preventing credits or deductions from taking a company’s production tax liability below the 4 percent minimum. The House Resources Committee had hardened and raised the minimum tax to 5 percent. The change to the 25 percent tax rate combined with eliminating the sliding per barrel credit amounts to shifting the price at which the minimum gross tax kicks in from about $75 per barrel to $55 per barrel, according to the Revenue Department calculations. That’s because of the increase in the effective net production tax rate at lower prices makes it greater than 4 percent above $55 per barrel, and current law calls for the state to tax at the higher of the two — gross or net tax rates. Overall, the HB 111 headed to the Senate raises North Slope oil taxes by between $80 million and $100 million per year in the near term, according to Revenue projections. Language to require state approval for lease expenditures from development projects that could result in operating losses and thus carry forward deductions, as well as creation of a new, after-the-fact 15 percent “dry hole” cashable credit to lessen the burden on small companies with failed exploration projects was cut out of HB 111. The provisions were added in the House Resources Committee. The lease expenditure review concept caused particular consternation from industry over the fear the Department of Natural Resources would final say over every investment companies planned to make. Resources Co-chair Rep. Geran Tarr, D-Anchorage, stressed the intent of the provision was to give the state a one-time avenue for input on developments it would likely be an indirect investor in through tax revenue forgone by way of accumulated tax deductions; however, it was written broadly in the bill and left much up to regulator interpretation. Net operating losses As it stands, HB 111 would leave the current 35 percent net operating loss, or NOL, credit rate in place, but shift it from a cashable credit to a tax deduction held by explorers until a production tax liability is earned. The key changes relate to NOLs held for the long-term. It would automatically cut the value of NOLs by 10 percent each year they are held beyond seven years, a provision aimed to expedite production from greenfield projects. A previous iteration of HB 111 that came out of the Resources Committee cut the NOL to 17.5 percent but then added an annual interest “uplift” to increase the value of the NOL back to nearly 35 percent of the original expenditure. The current bill also includes a “ring fencing” provision that ties a net operating loss to the project from which it is accrued. Finance Co-chair Rep. Paul Seaton, R- Homer, said the provision is intended to prevent a producing company from buying NOLs stockpiled by an explorer and using them to offset production tax liability without ever getting to production on the project that generated the losses. Minority caucus Republicans in floor debate expressed worry that ring fencing fields would prevent the NOLs from being transferred in the sale of a promising exploration project, for example. Seaton clarified that the buyer could use the carry-forward NOLs as long as production is realized from the sold project. On to the Senate If history is any indication, the four hours of debate over HB 111 on the House floor Monday likely did little more than provide the requisite political theatre, as the bill still needs to pass the Republican-dominated Senate, where leaders have indicated no interest in changing the base production tax. Senate Republicans — who have said they want to see an end to cashable tax credits and have their own legislation ready to make that happen — largely neutered the non-credit provisions of House Bill 247 last year. HB 247 phased out tax credits for Cook Inlet operators, which primarily produce natural gas for Southcentral energy needs but do not provide substantive production tax revenue to the state. The more meaningful House floor vote will come after HB 111 is approved by a House-Senate conference committee, assuming it gets that far. Elwood Brehmer can be reached at [email protected]

Changes at Anchorage operation won’t hurt rural utilities, AEA says

Rural utility operators are worried changes to how the Alaska Energy Authority handles their powerhouse projects will hurt the reliability of electrical service in communities across the state, but AEA officials say the fears are the result of a simple misunderstanding. The usually quiet public testimony portion of the authority’s March 30 board of directors meeting was dominated by utility managers and local government administrators from small bush communities pleading with AEA directors to not close the authority’s north Anchorage warehouse. The 6,100 square-foot building just off of Commercial Drive is called a warehouse, but it has long served as a shop for AEA staff to assemble the tiny, modular diesel-fired power plants that are then shipped to many of the state’s smallest towns and villages. A March 1 internal memo from new AEA Executive Director Michael Lamb directed closure of the warehouse within 30 days as a means to reduce the authority’s operating costs, maximize private sector contracting and consolidate it operations with the Alaska Industrial Development and Export Authority. Those goals follow legislative intent language in the 2017 fiscal year budget directing AEA to wean itself off of unrestricted general funds by 2019. AEA also administers federal grants and other state funds designated for specific programs. Unrestricted general funds are the discretionary spending portion — and the majority — of the state budget. The authority got about $870,000 of the roughly $4.3 billion unrestricted general fund budget for 2017, according to Lamb. That money mostly goes to AEA’s general rural energy support work, which provides technical assistance to rural utilities and can be a parts or expertise backstop for small utility operators when the power goes out in their community. About half of Alaska’s 200 rural communities have their electrical needs covered by larger cooperatives, such as the Alaska Village Electric Cooperative, or other groups. Many of the remaining communities don’t have a customer base to stand up a self-sustaining electric utility and also lack the technical expertise to maintain electric infrastructure, which is a fundamental issue AEA has been working to improve over the years. To that end, AEA has upgraded electric reliability and generation efficiency in 81 communities and is in the development phase on another nearly 20 projects through its Rural Power System Upgrade program, which has been funded through a variety of means depending on the project. All of the testifiers at the AEA board meeting said the five authority staff that had worked at the warehouse were invaluable for the round-the-clock service they provided. White Mountain Mayor Daniel Harrelson said simply, “Without your support and guidance we wouldn’t have electricity in White Mountain.” An electrician by trade, Pelican power plant operator and Mayor Walt Weller said he has worked directly with AEA’s field and warehouse staff to upgrade the small Southeast town’s diesel and hydro plants. “I can’t imagine any changes to their operations that could make it more efficient,” Weller said. Other supporters of AEA’s rural utility work said the authority is driven not by profit but to do what’s best for communities and noted its mission is to lower energy costs in Alaska, not push money to private contractors. AEA leaders said they were pleased to hear of the deep appreciation for their efforts, but the internal changes could actually improve the service many are afraid of losing. “The core services discussed in testimony by the utilities that called in at the board meeting, those services will not change,” spokeswoman Katie Conway emphasized. Chief Operating Officer Kirk Warren said in an interview that the warehouse staff has been moved into AEA’s main Midtown Anchorage office building, which it shares with the Alaska Industrial Development and Export Authority. That will actually give them more time to respond to utilities’ needs as they won’t also be spending time assembling powerhouses, he said. Warren stressed that the circuit rider, community assistance and emergency response programs among the “fundamental reasons that AEA exists” and all that is really changing is where the technical experts will spend their days and who how AEA contracts for work. He added that the warehouse — which is state-owned and therefore has no monthly lease payment — will still keep emergency generators and other power plant parts. “The savings will come, as de minimus as it is, in reduced utility costs and our ability to actually make (warehouse staff) feel like they’re a part of our organization,” he said. The private firms that AEA will contract with to assemble the powerhouses will even be able to use the warehouse space if they choose, according to Warren, and an AEA employee will be on-site when that occurs. The only things really changing are that AEA will not be acting as a parts expediter when it contracts for utility repair services and staff will not be turning the wrenches on the electrical generation units. “We’re statutorily obligated to abide by what the Legislature has told us to do and there’s language — to the maximum extent possible we will contract with the contracting community,” Warren said. He also said AEA hopes to have internal policy evaluations and changes finished by the end of the state fiscal year, which is June 30, to know how much unrestricted funding support it will need in the future. Elwood Brehmer can be reached at [email protected]


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