Elwood Brehmer

Budget consensus forms near session end

How quickly things can change. Despite the House passing the operating budget over to the Senate about three weeks later than planned after getting bogged down in lengthy debates over the size of this year’s Permanent Fund dividends, legislative leaders are now again talking about wrapping the session up soon — likely totaling just a little more than 90 days in Juneau this year. That’s because Senate Republicans appear to have generally conceded to the Democrat-led House Majority coalition on the size of this year’s operating budget. The budget numbers coming out of the Senate Finance Committee are in line with the budget plans from the House and Gov. Bill Walker that mostly call for flat funding of about $4.5 billion of unrestricted state general funds in the fiscal year 2019 budget. “There has been some high-level cooperation to get us to this point on the budget,” Republican Senate President Pete Kelly said during an April 9 press briefing. The apparent agreement to flat-fund the operating budget is somewhat of a surprise given it comes just a few weeks after the Senate passed a Finance Committee-sponsored $4.1 billion UGF spending cap. “The big, heavy stuff, I think, is out of the way,” Democrat House Majority Leader Chris Tuck said April 10. In exchange, the House Majority appears to be backing off on its push for a broad-based tax or oil tax increases to further close the budget deficit this year. The House Resource and Finance Committee’s have proposed oil tax increases to keep that option on the table for an end-of-session compromise package, but major changes to the production tax structure appear unlikely. Tuck also acknowledged — in spite of his coalition’s prior resistance — the Legislature is headed towards a “POMV only” deficit-reduction plan this year. “We did send a comprehensive (fiscal) package over to the Senate last year,” he said. “Unfortunately it didn’t get a fair chance so we’re backed into a corner right now of doing a (Constitutional Budget Reserve) draw… and then using the Earnings Reserve.” There is also agreement to institute a 5.25 percent of market value, or POMV, draw from the Permanent Fund currently valued at about $64 billion. And with similar consensus around a $1,600 dividend, the state could be left with a deficit in the $500 million range in 2019 after the POMV draw is split between funding the dividend and government services. It remains unclear whether the Legislature will order the POMV draw via language in the operating budget — a method Alaska Permanent Fund Corp. leaders have cautioned against for the year-to-year instability it could insert in managing the Fund — or a longer-term separate piece of legislation. Both the House and the Senate passed a POMV mechanism last year in Senate Bill 26, but differences over contingencies to correspondingly implement a tax or spending cap have kept the bill from being sent to Gov. Bill Walker, the original proponent of SB 26. Senate leaders have insisted on passing SB 26 or similar POMV legislation but they are not committing to holding out for such a bill. Senate Finance co-chair Sen. Lyman Hoffman, D-Bethel, said regarding putting the POMV in the budget that, “I don’t know if I would be uncomfortable, but I wouldn’t be a happy camper. I think at this stage in our history we need to move down the road to have the tools to address our deficit.” Tuck and others in the House Majority have downplayed the necessity for putting a Permanent Fund POMV draw in statute long-term. He noted the Legislature has gotten into the habit of ignoring its own statutes lately, particularly when it comes to paying dividends, and there is no assurance it would stick to POMV legislation any tighter. “Whether (a POMV draw) is in statute or not, it’s really the behavior,” Tuck said. “We’ve seen things in statute that have been violated and with the constraints we have right now I think our behavior is more important.” The Senate Finance Committee has also proposed a 5.25 POMV draw for the current 2018 fiscal year to backfill the CBR to $4.2 billion, which would give the state more financial breathing room for cash flow management and in the case of a large emergency, according to Hoffman and fellow Finance co-chair Sen. Anna MacKinnon. If the operating budget passes out of the Senate more or less as it is in the Finance Committee there will undoubtedly be spirited debate in the budget conference committee over oil tax credit payments and Medicaid funding, which are two of the larger differences in the House and Senate budget plans. The House — based on a different interpretation of the tax credit payment formula — appropriated $49 million for tax credits, while the Senate is proposing $184 million, which is in line with the administration’s calculation. “When you get two oil tax lawyers in a room they’re going to have five different opinions,” Finance member Rep. Scott Kawasaki, D-Fairbanks said during an April 10 press conference. “I think that will be hammered out in conference committee.” The tax credit payments could also be resolved if the governor’s proposal to bond for roughly $800 million to pay the credits off entirely is passed. The tax credit bonding legislation has moved slowly in both bodies but with general agreement that it’s at a minimum not a bad idea, the possibility remains that it could move quickly in the remaining days of the session. Under the bonding plan companies would accept a discount rate of up to 10 percent on the credits they are owed to get the money up front, which would shift the state’s borrowing costs to the credit holders and prevent the state from spending more on the politically sensitive oil tax credit program. The Senate also cut roughly $70 million from Medicaid funding — a move similar to what the Legislature did last year — which led to a large supplemental budget to cover those expenses afterwards. House Health and Social Services Committee chair Rep. Ivy Spohnholz, D-Anchorage, criticized the Medicaid cut, noting it does not change the state’s obligation and would just lead to another large supplemental budget next year. “Given that the requirements for Medicaid are defined by law it doesn’t seem worth going to battle over when we’re going to pay for it whether it’s included in this budget or the supplemental, we’re going to pay for it,” Spohnholz said.

Alaska Railroad returned to profitability in 2017

The Alaska Railroad was back in the black in 2017 with a $22.4 million profit after 2016 saw its first net loss in more than 15 years. The state-owned railroad corporation increased its overall revenue by 13 percent last year while cutting expenses by 3 percent, according to its 2017 Annual Report issued April 2. Alaska Railroad CEO Bill O’Leary said the improved financials are the result of the railroad’s resolve to forge ahead through making difficult but necessary decisions. In February 2017 O’Leary announced the railroad would be eliminating 49 positions as part of an internal restructuring effort to save $5.7 million. Since 2008 the railroad has eliminated more than 300 year-round positions as freight business has declined. The Alaska Railroad currently has 544 full-time employees with another 130 seasonal positions, according to the report. The stronger 2017 revenue figures were driven by continued growth in the railroad’s passenger service — largely attributable to Alaska’s burgeoning tourism industry. Ridership hit 506,000 passengers in 2017, which continues a general upward trend since bottoming out at 405,000 passengers in 2010. The report also notes that winter and “shoulder season” ridership has nearly doubled since 2013, going from 6,300 passengers to nearly 11,200. On top of its own regular passenger service, the Alaska Railroad also operates numerous trains for tour companies during the summer months. Passenger service has historically accounted for about 20 percent of the railroad’s total revenue. While technically a state corporation, the Alaska Railroad does not receive state funding as part of its normal business operations. A boom in gravel demand from Southcentral road construction projects also helped the railroad increase its total freight hauled by more than 1 million tons, according to the annual report. Until hauling nearly 4.8 million tons of cargo last year, freight tonnage had steadily declined from 6.3 million tons in 2010. The Alaska Railroad moved just 3.7 million tons of freight in 2016. The declining trend in freight business reflects Alaska’s overall economic recession as well as the 2014 closing of the Fairbanks-area Flint Hills Resources oil refinery, which was a major customer of the railroad. Other lines of freight business — the railroad’s barge service, petroleum and domestic coal transport — all fell by 8 to 14 percent. The railroad did not haul any coal for export in 2017, according to the report. Freight accounts for roughly 40 percent of the railroad’s revenue. The railroad ended 2017 with $6.4 million in operating income after absorbing an $11.2 million operating loss in 2016. Also a large landowner with title to about 37,000 acres across the state, roughly half of which is revenue-generating real estate properties, the railroad netted $12.5 million in real estate income last year compared with $11.7 million in 2016. Other acreage is used by the railroad in its business, such as for right-of-ways. The Alaska Railroad held a net position of $338.7 million at the end of 2017. Railroad leaders are expecting a $13.5 million profit in 2018, according to the annual report, which would be in line with the several years of profits prior to the $4.4 million loss in 2016. Aside from the improved operating and real estate financials, the railroad was also able to capture formula-derived grant funds from the Federal Transit Administration that were off-limits in 2016 due to a disagreement with the Municipality of Anchorage over how the FTA grants were split. Anchorage Mayor Ethan Berkowitz’s administration in 2016 pushed for a larger split of about $15 million in annual FTA funding, which is shared by the railroad and the city. Berkowitz argued that while the railroad generates much of the federal grant money through its passenger service, the money is intended for supporting public transit in urban areas, which is not what the railroad provides. Without agreement between the city and the railroad the FTA would not release the funding to either. As a result, railroad leaders attributed the $4.4 million loss in 2016 to not getting the $11 million in expected FTA grants that year. The two sides reached an agreement last August to settle the dispute in which the funding would be split as it historically has been with the railroad getting the majority of the grants — equal to what it generates. However, the agreement also includes the railroad selling a 20-acre parcel adjacent to the Port of Anchorage to the city for $1.5 million. The property is viewed as an important piece to the city’s much-needed work to overhaul and modernize the port’s dock infrastructure. Related to that, on April 9 the state Senate passed legislation to allow the railroad to sell land without approval from the full Legislature. Instead, Senate Bill 86 would give the railroad the ability to sell land with a corresponding public notice; authorities similar to what other state land management agencies and the University of Alaska have. The authority would sunset after three years, according to the railroad. Elwood Brehmer can be reached at [email protected]

Corps of Engineers extends Pebble scoping period

Stakeholders who want to weigh in on the potential impacts of the Pebble mine project will have two more months to do so. The U.S. Army Corps of Engineers Alaska District announced Friday morning that it will be extending the public scoping period to 90 days from the statutory minimum of 30 days for the project’s environmental impact statement, or EIS. The Pebble EIS scoping period, which began April 1, will now run until June 29 instead of the original April 30 closing date. Scoping, as the name implies, is when the public and cooperating government agencies are asked to submit the scope of potential environmental and socioeconomic impacts that should be studied in a proposed development’s EIS. The Corps of Engineers has also had an invitation out to 35 recognized Tribes for government-to-government consultation during the Pebble EIS process since Jan. 12, according to a March 30 press release. The extension comes after repeated calls for such an action from not only opponents to the project but also Sen. Lisa Murkowski and Gov. Bill Walker’s administration. Murkowski wrote to Corps of Engineers Alaska leaders April 3 in part requesting they consider the concerns of those who feel 30 days for scoping “may be insufficient for a project of this magnitude and potential impact.” Murkowski also emphasized that she remains neutral on Pebble, but she strongly objected to the Environmental Protection Agency’s move in 2014 to preemptively stop the project. Walker has repeatedly stated he is against the Pebble project, going back to his 2014 campaign for governor. When Pebble Limited Partnership unveiled its scaled-down mine plan in October Walker stopped short of wholly denouncing the plan, but said in an interview with Alaska Public Media that the company still has a exceedingly high burden to clear and he is very skeptical it can be developed responsibly. Murkowski additionally asked Corps officials to hold more scoping meetings in communities in the Nushagak River drainage where the mine would be located. The Corps originally scheduled one scoping meeting in Dillingham April 17, which is the regional hub community at the mouth of the Nushagak about 100 miles southwest of the mine site. However, a public meeting in New Stuyahok, a village along the middle reaches of the Nushagak, was recently added for April 13, according to the Corps’ website for the project. The other meetings are in communities near the project’s other proposed facilities — the gas pipeline, a deepwater port, an Iliamna Lake ferry and associated roads. Murkowski also asked that Alaska Native corporations be consulted on the project. Bristol Bay Native Corp., which is the regional Native corporation for the area, has long been an ardent opponent of Pebble. Department of Natural Resources Commissioner Andy Mack sent a similar letter to Corps Alaska leaders March 28 asking for 90 to 120 days of scoping for the Pebble EIS. Pebble spokesman Mike Heatwole wrote via email that the company supports the Corps’ decision to extend the scoping period “as we want a thorough, comprehensive, robust EIS. We remain confident that once all of the technical information has been subjected to this level of scrutiny and review we will secure permits for a responsible mine at Pebble.” Heatwole downplayed the importance of the public input period when the 30-day scoping plan was released. He suggested the public comment period following the release of the draft EIS is far more important, as it is when the public can critique the work the Corps’ has done evaluating the project and suggest changes for the final draft. When the Corps released its initial two-year schedule to reach a record of decision on the Pebble EIS with a 30-day scoping period March 20, it immediately drew sharp criticism from groups fighting the project. While the EIS schedule and drafting for each project is different because no two developments are the same, they noted the Corps has regularly taken upwards of five years to complete the EIS process on other large projects in the state; some with scoping periods in excess of 100 days. Shane McCoy, the Pebble Project Manager for the Corps, said in an interview after the Pebble timeline was released that it is a “straw man schedule” and stressed that the agency understands the strong emotions that surround the project. The Corps has taken more than five years to reach a final EIS on the Donlin Gold mine project, which is roughly similar to Pebble’s plans. Donlin Gold is an open-pit mine project in the Kuskokwim River drainage north of the Pebble deposits in Western Alaska. Both projects, as proposed, call for large surface mines in the upper reaches of large salmon-bearing watersheds with commercial and subsistence fisheries, as well as natural gas pipelines from Cook Inlet to power the operations. Mack noted in his letter that the Donlin scoping period lasted 105 days with 14 public meetings — at a rate of about one per week — and wrote that the state requests a similar process for Pebble. There are nine public meetings currently scheduled over 11 days in mid-April during Pebble’s scoping period. Donlin Gold applied to initiate an EIS in December 2012 and a final EIS is expected soon, according to the Corps’ schedule for the project. Elwood Brehmer can be reached at [email protected]

Tourism group looks inward to replace state funding cuts

The leaders of Alaska’s largest travel industry trade group are looking for ways to fill a void in their marketing budget left from budget cuts by lawmakers. The tourism industry has been a bright spot in an otherwise struggling Alaska economy of late, growing consistently along with the national economy over the past decade since the 2008 financial crisis. Historically, about 85 percent of Alaska visitors come from the Lower 48. Alaska Travel Industry Association President Sarah Leonard said that despite a record number of roughly 1.86 million visitors to Alaska last summer, the 2017 peak season for the industry was “a little bit underwhelming.” That’s because it indicates a leveling-off of prior growth as most travel segments across the state were flat or grew by just a percentage point or two over 2016 figures. Alaska’s summer tourist volume has grown by 21 percent since bottoming out in 2010 when 1.53 million travelers came to the state. Most of the growth was in the cruise industry — primarily in Southeast — which brought 7 percent more visitors to Alaska last year compared to 2016, according to Leonard. The number of Alaska cruise visitors is expected to continue to grow significantly to more than 1.3 million cruise ship passengers over the next two years, according to Cruise Lines International Association Alaska officials. Leonard attributed the overall slowing growth not to an image problem, but to a lack of an image for Alaska in the industry brought on by steep cuts to the association’s marketing budget. The state has long funded marketing for the ATIA; in 2013 the program received $16 million of state support. However, multibillion-dollar budget deficits since the 2015 fiscal year have led to cuts across the state budget and by fiscal 2017 the tourism marketing program got just $1.5 million after Gov. Bill Walker vetoed part of the annual appropriation. The annual marketing funding was back up to $3 million in the current budget despite a directive from the Legislature for the association to wean itself off state support completely. Walker’s capital budget proposal includes another $3 million for 2019. “In 2017 Alaska had no television ads, no print ads in national magazines and for the first time in 40 years last year we didn’t have a printed vacation planner — a main printed piece we can distribute to potential visitors,” Leonard said in describing the consequences of the marketing program cuts. Leonard discussed the status of the tourism industry leading into the upcoming peak summer season at the April 2 Anchorage Chamber of Commerce “Make it Monday” luncheon. The $3 million of state support puts Alaska 49th — just ahead of Delaware — in terms of state tourism marketing funding nationwide, according to Leonard. “We’re asking for a reasonable reinvestment back into tourism marketing,” Leonard said. But with renewed state support a long shot, she characterized the legislative intent language as “a wake-up call” to the association’s more than 600 member organizations and companies that an alternative funding source is needed. ATIA leaders settled on what they call a tourism improvement district as a means to self-assess a fee that could be used to fill the marketing budget hole. “Now is not the time to cut back on an industry that already contributes to the state economy,” she contended. Every dollar the state spends on tourism promotion translates into $58 in visitor spend, $21 of local income and $3 of state and local tax revenue, Leonard said. The tourism improvement district, or TID, revenue would be collected by the state and returned to the industry through annual appropriations. According to the association, a 1 percent fee on gross revenue from lodging, tour activities and attractions could generate more than $7 million for the tourism marketing program. Leonard said a key aspect of the improvement district is that the fee could be passed through to the customers to avoid impacting the businesses it is supposed to help. There are some 150 tourism improvement districts nationwide, she said further. Separate but similar bills sponsored by Senate Labor and Commerce Committee chair Sen. Mia Costello and Rep. Jason Grenn, both of Anchorage, would authorize the state to collect the fees. However, Leonard noted that the legislation would just set up the framework for the TID and not fully implement it. Doing that would require a vote from potential industry participants, she said. Senate Bill 110 and House Bill 383 have received hearings recently; Costello moved SB 110 out of her committee to Senate Finance on April 2, but whether or not either will pass this year while larger budget issues continue to dominate the Legislature’s focus is unclear. Either way, Leonard said the TID revenue would have to be augmented by appropriations from the state’s 10 percent car rental tax to support a robust tourism marketing program long-term. The state collected $12 million from the car rental tax in 2017, according to the Tax Division. That money was once intended to support tourism development but has gone into the General Fund instead, according to Leonard. Elwood Brehmer can be reached at [email protected]

Messy House vote on budget a prelude to extended session

The House finally managed to pass the state’s operating budget April 2 with money for $1,600 Permanent Fund dividends, but the three weeks of messy debate leading up to the vote were likely more of a preamble to what’s in store for the remainder of the legislative session than a resolution to the big issues of the day. The $4.5 billion unrestricted General Fund budget passed by the slimmest of margins on a 21-19 vote, with majority coalition member Rep. Gabrielle LeDoux, R-Anchorage, breaking from her caucus and voting against the budget. Total General Fund spending in the House budget was $5.35 billion when including nearly $1 billion being moved to the Permanent Fund principal for inflation-proofing. The budget is also underfunded by $700 million because the 18-member House minority Republican caucus refused to agree to fund the balance from the Constitutional Budget Reserve, which requires a supermajority of 30 votes. Democrat House Speaker Bryce Edgmon said in an April 3 press briefing that he was disappointed with LeDoux’s vote, but added that she told caucus leadership of her intentions prior to the vote. The House Majority coalition is a non-binding caucus, meaning LeDoux won’t be kicked out as other House and Senate Republicans have been in recent years for breaking from caucus ranks on budget votes. LeDoux also chairs the Rules Committee and Edgmon indicated she would probably retain the leadership position. House leaders had said they wanted to move the budget to the Senate in the customary mid-March timeframe but addressing 84 amendments — most from minority caucus Republicans aimed at cutting the budget — followed by a weeklong snarl over how big this fall’s PFD checks should be threw the whole process way off track. House Majority Leader Chris Tuck, D-Anchorage, authored the amendment to increase the PFD amount to the projected statutory formula that amounted to about $2,700 per Alaskan. That amendment narrowly passed, also with 21 votes, and split both House caucuses with half of each voting for Tuck’s amendment. The budget that passed out of the Finance Committee funded a roughly $1,200 PFD. Republicans in the minority argued full PFDs should be paid until the budget is cut further. On the other hand, some Democrats have pushed for historically calculated dividends until a tax is enacted to diversify the state’s revenue streams. They also contend a broad personal tax would more fairly spread the burden of the budget situation away from strictly cuts to the PFD, which is more important to low income individuals. The leaders of both caucuses — Edgmon and Minority Leader Rep. Charisse Millett, R-Anchorage — voted for the larger PFDs — despite acknowledging that historical full dividends are likely unsustainable long-term. “We need to have the difficult discussion on new revenues; I think that’s very apparent to anyone that can peel back the layers of the budget,” Edgmon said. “That, based with the fact that if I have to choose between the lowest tax rate for the oil industry or taking half the dividend to solve a fiscal gap that’s the largest in the country and I’m going to ask my constituents — many of whom are below the poverty level — to give up half of their Permanent Fund dividend so that we can grant the economic advantages to other entities around the state, I’m going to defer to my constituents and I’m going to support a larger dividend.” Millett said in a press briefing that she voted for the $2,700 PFD because that is in line with the statute that is on the books and it should be paid until the law is changed, which she has submitted legislation to do. The $1,600 PFD amendment passed narrowly March 30. It quickly became evident that the budget could not move out of the House with it as well, so the members of the majority — minus LeDoux — agreed to vote together and approve it despite the earlier votes. On the budget itself, it is largely similar to the current budget in terms of overall state spending, with slight increases to Public Safety, Corrections, state retirement payments and a $19 million increase to the University of Alaska budget. The UA budget bump drew criticism from some Republicans on the House floor, but it received bipartisan approval when added in the Finance Committee. The governor’s budget would have kept state spending on the university system flat for the first time in several years after significant cuts. It also gives the Alaska Gasline Development Corp. authority to receive and spend up to $1 billion in fiscal year 2019 from outside investors to advance the Alaska LNG Project. Walker requested open-ended receipt authority, but legislators scaled that back to allow the project to advance without state funds while assuring they keep come oversight of AGDC. The biggest change in the 2019 budget is a formulaic draw on the Permanent Fund Earnings Reserve, which is written in the budget as a 5.25 percent of market value, or POMV, appropriation from the $64 billion Permanent Fund to provide $1.7 billion for government services and another $1 billion for PFDs. House Finance co-chair Rep. Paul Seaton, R-Homer, originally proposed a more conservative 4.75 POMV draw in committee, but the larger draw, which is at the very high end of what Fund managers have said is acceptable, allows for a larger dividend while still paying down the deficit at the same amount. Walker’s request to inflation-proof the principal of the Fund with $942 million from the Earnings Reserve was also pulled out in House Finance, as Seaton contended the 4.75 POMV draw was small enough for the Fund’s remaining earnings to cover inflation. However, with the 5.25 percent draw, the inflation-proofing transfer was added back in. It would be the first time in three years that the Legislature inflation-proofed the Fund, which the Alaska Permanent Fund Corp. Board of Trustees has advocated for. Walker and the Republican Senate Majority have insisted on the 5.25 POMV draw for the first three years of Fund draws before eventually shifting to a 5 percent draw long-term. The Senate also recently passed a $4.1 billion operating budget spending cap, which would appear to be the level at which the Republican-dominated body will shoot for in its version of the budget. That would set up another round of difficult budget negotiations with the House in late April and May. Day 90 of the session is April 16, but the prospect of ending the session within that time has long since passed. Oil taxes reemerge House Majority members have made it clear they would accept an increase in oil taxes as an alternative — at least in the interim — to an income tax, which the Senate rejected last year. House Resources co-chair Rep. Geran Tarr, D-Anchorage, introduced a new version of House Bill 288 April 3, which would gradually increase the gross minimum production tax from 4 percent to 7 percent depending on oil prices. The original version of the bill raised the “tax floor” from 4 percent to 7 percent at all prices. It would have collected about an additional $90 million per year at $70 per barrel and $205 million to $256 million at average prices between $50 and $60 per barrel — where the delta between the current 4 percent and proposed 7 percent minimum tax would be realized. Now, HB 288 would increase the minimum tax to 5 percent at prices above $40 per barrel; 6 percent at prices above $55; and 7 percent at prices above $65 per barrel. The state has a net profits production tax at higher prices and a gross tax when prices are low. Currently, that “crossover” price, where the applied tax switches from the gross to the net tax calculation, is just less than $70 per barrel, according to the Department of Revenue. The crossover price has been falling in recent years as companies have cut costs to stay in business while prices have been mostly less than $70 since late 2014. Republicans and industry representatives insist the tax increase would hurt companies that have just adjusted their spending to be profitable in the $60 per barrel price range, which is expected to persist for some time. Tarr said the graduated minimum tax acknowledges the challenges companies face at very low prices but that the current 4 percent tax is one of the lowest in the country. Additionally, Seaton said the Finance Committee is likely to revisit the straight 25 percent oil profits tax the House passed last year as part of House Bill 111, which ended the refundable oil and gas tax credit program. The Senate stripped out the tax increase portion of HB 111; however, the House Majority hopes an oil tax increase can be part of an overall end-of-session budget deal with Senate Republicans. Elwood Brehmer can be reached at [email protected]

Federal tax cut boosts BP’s Alaska bottom line by $500M

BP netted $830 million from its North Slope operations in 2017 but the company’s Alaska leaders contend the net income figure shrinks to $118 million when all of the work it does in the state is factored in against a backdrop of $543 million in taxes and royalties paid to the State of Alaska. Most of the $830 million in upstream Alaska profits reported March 29 — on the back of $3.2 billion in operating revenue — is due to a roughly $500 million federal corporate tax accounting benefit stemming from the tax reform Congress passed in December. A major component of the tax overhaul was a cut of the federal corporate tax rate from 35 percent to 21 percent, which many companies have been able to apply to deferred tax obligations. BP Alaska held a deferred tax liability of nearly $1.3 billion in 2016; that liability fell to $838 million in 2017, according to the report. Companywide, BP made $3.4 billion in 2017. BP Alaska Controller David Knapp said the $543 million is the state’s “total government take” including royalty oil, property, income and production taxes. The company similarly paid $464 million to the state in 2016 when it lost $358 million in Alaska overall, with operating expenses combined with low prices more than erasing the $85 million North Slope upstream profit, according to BP Alaska President Janet Weiss. “On the financial front, I am very proud of the progress that BP Alaska, and indeed the entire Alaska industry, has made in adapting to the lower for longer oil price environment,” she said. BP operates the large, iconic Prudhoe Bay oil field and has interests in the producing Milne Point, Kuparuk River and Point Thomson units on the North Slope as well. The North Slope profits are outlined in BP’s 2017 annual report, which is the only financial document the London-based company is required to break out its upstream Alaska business segment on what’s called the “20-F” form. The midstream costs of transportation through the Trans-Alaska Pipeline System and marine tankers are not required to be reported separately, nor was BP required to report its net income $118 million for the Alaska segment of its business, but Knapp said the company’s Alaska leaders provided the in-state tax and royalty figure of $543 million because of a commitment to transparency. BP’s annual report lists an $18 million tax benefit for Alaska under the Production and Similar Taxes line item, but Knapp said that is due to noncash provision adjustments and changes to internal estimates because of future tax liabilities. BP owns 48.4 percent of the Trans-Alaska Pipeline System, the largest single share of the oil transport network. The company also has four oil tankers dedicated to its Alaska operations. However, those costs of getting the oil to market are deductible from the state’s production tax even when it is calculated as a 4 percent gross tax at lower prices — as has been the case for several years. In 2017 North Slope operators deducted an average of $9.70 per barrel in oil transportation costs from the wellhead value of the oil before calculating the production tax. According to the state Revenue Department, the collective average “break even” price for producing a barrel of North Slope oil dropped from $43 per barrel in 2015 shortly after prices fell from the $100 per barrel-plus plateau to about $27 per barrel in 2017. The primary driver behind the cost per barrel decline is a significant reduction in capital expenditures by operators that have drastically cut back on non-essential spending. Lower production costs then translate into growing profitability. The improved yearly financials are also due to stronger oil prices, which averaged $54 per barrel in 2017 compared to $43 per barrel in 2016. The company also had no production decline for three years at Prudhoe Bay with a daily average of about 280,000 barrels. “We also had a positive cash flow for the year at about $619 million following two straight years of losses,” Weiss said in a release accompanying the annual report. BP is also spending money to support the state-owned Alaska Gasline Development Corp. in developing the $43 billion Alaska LNG Project, according to Weiss, though company officials declined to disclose how much BP has spent on Alaska LNG since the state took over the project in January 2017. A cooperative agreement with AGDC for the company’s assistance in 2017 has been extended through June 30 of this year. Elwood Brehmer can be reached at [email protected]

ConocoPhillips gets good news on second NPR-A project

ConocoPhillips received good news March 22 when the Bureau of Land Management announced it had finished a long-awaited draft of the environmental impact statement for one of the company’s oil developments in the National Petroleum Reserve-Alaska. Publication of the draft supplemental EIS for the Greater Mooses Tooth-2 project means ConocoPhillips could sanction the roughly $1 billion development later this year if BLM issues the company a favorable record of decision, according to ConocoPhillips Alaska spokeswoman Natalie Lowman. Lowman wrote in an email that the permitting process for GMT-2 has taken significantly longer than expected, which pushed the startup timeframe the company’s had pegged from late 2020 to the fourth quarter of 2021. “We believe that permitting is now proceeding on a reasonable schedule,” Lowman wrote. That would also have the company starting construction next winter, just after production is supposed to commence from nearby Greater Mooses Tooth-1. The very similar “GMT” oil projects are just inside the eastern boundary of the NPR-A. Each is expected to produce up to about 30,000 barrels of oil per day at its peak with a cost of nearly $1 billion to get there. GMT-2 would be an eight-mile step out from GMT-1 and the two would be connected via gravel road. GMT-1 will be the first producing oil and gas project on federal lands in the NPR-A. ConocoPhillips’ CD-5 oil development, which started producing in 2015 and since has exceeded expectations, is located on Kuukpik Corp. land within the reserve boundary. Kuukpik is the Native village corporation for Nuiqsut, the closest community to the project. ConocoPhillips submitted its proposal to develop GMT-2 to the Bureau of Land Management, the agency that oversees the NPR-A, in August 2015. However, BLM did not publish a notice of intent in the Federal Register to officially restart the environmental impact statement, or EIS, for the project until 11 months later in July 2016. In January 2017 a BLM Alaska spokeswoman said the agency was anticipating a record of decision on the project between January and May of this year, which now will be pushed back. Release of the draft EIS triggers a 45-day public comment period. Residents of the Nuiqsut were concerned about the potential impacts GMT-2 could have on their subsistence activities, according to BLM, and the agency took time to address those concerns. Deputy Interior Secretary Dave Bernhardt said while in Anchorage March 8 that he had directed all Interior agency officials to have environmental impact statements done within a year whenever possible. Additionally, secretarial orders from Interior Secretary Ryan Zinke directed BLM to rescind its climate change policy established in 2012 and other development impact mitigation policies set in 2015 and 2016, according to the EIS. In May 2017 Zinke directed BLM to begin the lengthy process of revising its land management plan for the NPR-A with an eye on further oil development. The supplemental EIS for GMT-2 that BLM is working on now is a follow-up from one done in 2004 when the project was first proposed as a satellite to the company’s large Alpine field on state acreage just to the east of the NPR-A. The footprint of Conoco’s updated plan for GMT-2 is larger than what it got approval for in 2004, with an oil pipeline paralleling an 8.2-mile access road and a 14-acre drill pad capable of holding up to 48 wells, according to the proposal submitted to BLM. The agency has selected the company’s plan as its preferred alternative, but other alternatives include an option with a longer road of 9.3 miles and one with a 47-acre airstrip in-lieu of a road. The alternative with the longer road would have the road and pipeline follow the high ground between the Fish Creek and Tinmiaqsiugvik River drainages on the prospect it would keep traffic and oil further away from the water bodies and hopefully reduce the impacts of a major spill if one were to occur. The 5,000-foot airstrip option would eliminate the gravel road but allow for winter ice roads, likely limiting the movement of drill rigs and other equipment to and from the site. With no year-round surface connection, the third alternative would also require a larger 19-acre gravel drill pad to and an 18-acre camp pad to accommodate workers unable to leave each day. The oil pipeline would follow the company’s desired route. Elwood Brehmer can be reached at [email protected]

Delegation divides over $1.3T omnibus spending bill

Alaska’s all-Republican congressional delegation was split during voting on the $1.3 trillion federal spending plan covering the remainder of the 2018 fiscal year. Sen. Lisa Murkowski touted the omnibus appropriations bill in a press release as doing far more for Alaska than simply keeping the lights on in federal offices across the state. “I am proud of the work we have done in this bill to empower Alaskans to build our economy and create safe and healthy communities. This bill provides Alaskans with much needed fiscal certainty, stability and opportunities for communities across our state,” Murkowski said. “It directs federal resources where they are needed, while blocking unreasonable regulations.” Murkowski is a member of the Senate Appropriations Committee and chairs the Appropriations subcommittee covering the Interior Department, Environmental Protection Agency, the Forest Service and other environment-related agencies. H.R. 1625 passed the House by a wide margin March 22 and garnered 65 affirming votes in the Senate March 23 and was then quickly signed by President Donald Trump to avoid another government shutdown despite the president’s criticism of the legislation and Congress for not having an associated deal on immigration issues. Rep. Don Young also supported the appropriations package but Sen. Dan Sullivan did not. Sullivan said his decision to vote against the legislation, which garnered strong bipartisan support in both chambers of Congress, was a particularly difficult one to make in a lengthy statement from his office because it contains several provisions he feels are important. “While this legislation contains many critical spending priorities — necessary increases for our military and national security, safeguards for our schools and local communities, and investments to encourage job creation and economic growth — I could not in good conscience vote for it. Over 2,200 pages of legislative texts, hundreds, if not thousands, of pages of accompanying documents — all with huge implications for our economy and our citizens — deserves far more than 28 hours of review,” Sullivan explained. “My commitment to Alaskans to give legislation, particularly something of this size and magnitude, the appropriate level of due diligence and attention simply could not be met under these circumstances.” He went on to note the bill contains critical funding for the Secure Rural Schools and Denali Commission programs, as well as investments for rural public infrastructure and fighting addiction and mental health challenges, but said the hurried process that has become the norm in Congress was unacceptable. “Sadly, this process was business as usual; an all-or-nothing deal, without a single opportunity for amendments or ample time for review. The Alaskan and American people deserve better. I’m committed to continuing work with my colleagues on both sides of the aisle to bring a more predictable and transparent budget process back to the U.S. Senate,” Sullivan added. Last fall Sullivan voted in favor of legislation to repeal primary aspects of the Affordable Care Act and Murkowski, while generally against the ACA, cast a key vote to kill Republicans’ attempt to scrap the health care law. She cited a lack of normal process without committee hearings to flesh out the potential impacts of the repeal bill. Specifically for Alaska, the bill provides $10 million to cleanup legacy exploration oil wells in the National Petroleum Reserve-Alaska. The funding will cover remediation of nine of the remaining 26 wells in need of cleanup that were drilled between 1944 and 1982. It also directs the Bureau of Land Management to draft a strategy to complete the remaining work, according to Murkowski’s office. It also funds the federal Payment In-Lieu of Taxes, or PILT, program with $530 million. That money is paid to local governments with significant chunks of federal lands within their boundaries that are exempt from traditional property taxes. It is a key source of revenue for many rural Alaska communities, particularly those in Southeast that are surrounded by the Tongass National Forest. Local Interior Alaska officials should be pleased to know it also increases the funding to EPA for the agency’s Targeted Airshed Grants program to $40 million. Bad winter air quality in the Fairbanks area often does not meet EPA standards so the local governments eligible for the Airshed Grants that are used to fund efforts — such as woodstove change-outs in the Interior — to improve air quality. The competitive grant program had been funded with about $20 million in prior years and the Fairbanks North Star Borough had received about $2 million of that, so doubling the money available could offer more resources to the FNSB. Major provisions to overhaul management of Alaska’s national forests that Murkowski included in her Interior Appropriations Subcommittee report last November did not make it in the final spending bill, but it does include money for federal foresters to partner with state agencies on forest inventories nationwide. Murkowski had added language that would have exempted the Tongass and Chugach National forests — the two largest in the country — from the controversial Roadless Rule, which has limited logging and development in national forests for nearly 20 years. Murkowski also attempted to scrap the Forest Service’s 2016 Tongass Management Plan, which calls for a quicker transition to strictly young-growth timber harvests in the forest than Southeast’s remaining loggers would like. Murkowski and Alaska timber industry representatives have said they are in favor of a gradual transition to second-growth only harvests, but the Tongass Plan limits available timber sales and further hurts the struggling industry. Conservation and commercial fishing groups insist the Tongass should be managed for the growing tourism industry in the region and prioritize salmon habitat in the Tongass, which provides fishing-related employment. It is an evolution of the region’s economy that should be embraced, they contend. Murkowski spokeswoman Karina Peterson wrote in an email that the senator will continue to work on gaining greater access to the forest’s resources for all stakeholders. ^ Elwood Brehmer can be reached at [email protected]

Oil tax credit bill moves on to Senate Finance

Gov. Bill Walker’s plan to end the state’s roughly $800 million obligation to small oil and gas industry companies is suddenly on the move. The Senate Resources Committee quickly moved Senate Bill 176 out of committee March 23 with little fanfare, particularly given the consternation the oil and gas tax credit program has stirred in the capitol the past couple years. SB 176, which authorizes the state Revenue Department to issue bonds to pay off the liability in a lump sum rather than continuing to pay it down incrementally over the coming years. It would also require credit holders to accept up to a 10 percent discount on the amount they’re owed to cover the cost of the state’s borrowing and avoid spending additional state money on the all-but defunct tax credit program. Credit holders could also opt for a lesser discount rate in the 5 percent range if they agree with the Department of Natural Resources to negotiate a higher state royalty in future oil and gas production or commit to reinvest a portion of the payment back in Alaska projects. The bonds would be paid off over 10 years. The annual debt payments would be up to $115 million, according to the Revenue Department, and would be smaller than the largest projected payments the state would make paying off the debt under the current statutory formula. Revenue Commissioner Sheldon Fisher characterizes the legislation as a way to restart activity in the state’s oil and gas basins. Numerous small companies working in Cook Inlet and on the North Slope have delayed projects and cited the delayed tax credit payments as the cause. The state’s largest producers — BP, ConocoPhillips, ExxonMobil and Hilcorp — are not eligible to receive cash for their credit certificates, but instead can deduct the amount from their annual production taxes and can purchase the certificates from small companies to use them to lower tax payments. Several investment banks also lent money against the credit certificates on the presumption the state would always pay off the accumulated credits in full at the end of each fiscal year, which happened every year until Walker vetoed $200 million worth of the credit payments in 2015. Those banks, according to industry and state officials, have largely quit lending in Alaska, a situation the administration hopes to remedy. A few months after oil prices had collapsed as Walker took office in December 2014, he vetoed $200 million of the state’s $700 million credit bill, contending the state could not afford the open-ended program any longer. He subsequently submitted a plan to the Legislature in early 2016 to end the refundable tax credits and pay off the obligation as part of a broader overhaul of state finances, but when little of his plan passed he vetoed another $430 million of credit payments along with half the appropriation for the Permanent Fund Dividend. At the time, the state’s budget deficit was near $4 billion; it has fallen to about $2.5 billion since then with spending cuts and relatively recovered oil prices. Last year, the Legislature ended the last of the large credits but still appropriated just the formulaic statutory minimum payment of $77 million to the Oil and Gas Tax Credit Fund amid larger battles over spending cuts and taxes to solve the state’s fiscal problems. SB 176 has not garnered nearly as much attention from legislators as oil tax and credit bills have the last two years. Republicans have directed ample criticism towards Walker for creating the backlog of owed credits with his vetoes, but haven’t offered a solution of their own other than attempting to appropriate more money than the statutory minimum in order to reduce the credit balance. Those efforts have failed without the votes to clear the Democrat-led House majority. Senate Republicans are generally supportive of Walker’s measure and House Democrats are lukewarm on the idea but not wholly against it. The tax credit issue has also taken a backseat to other, larger state finance matters regarding the Permanent Fund. But given legislative leadership’s familiarity with the tax credit debt issue, SB 176 could move quickly through the Legislature in the coming weeks and be part of an end-of-session compromise. Alaska Oil and Gas Association spokesman Brandon Brefczynski called the plan “an innovative approach” to resolving the messy issue, but said the group is still concerned about the level of the discount rate and other provisions in the bill. That said, “AOGA is committed to working with the administration and the Legislature to finding an equitable solution; it’s simply too important,” Brefczynski said. “AOGA does applaud the administration for acknowledging that refunding these payments is a critical step this year.” Anchorage Democrat Sen. Bill Wielechowski, who serves on the Resources Committee, questioned the legality of the plan when it was first heard in February because the Alaska Constitution gives the state limited bonding powers aimed mostly at capital projects and revenue bonds. Revenue officials dismissed Wielechowski’s concerns at the time, saying they are confident the subject to appropriation bonds would clear the hurdle and the state has done similar maneuvers in the past. Wielechowski said Feb. 21 that he had requested an opinion from Legislative Legal Services on SB 176, but his staff said March 26 that they were still waiting for the legal analysis. The three years of less-than-full payments grew the state’s credit liability to $806 million at the start of 2018, according to Revenue officials. That liability is expected to ultimately grow to about $1 billion in the next couple years as certificates are claimed for prior work. However, the department is anticipating roughly $100 million of refundable certificates will be purchased by the majors, cutting the state’s final estimated tally to about $900 million. The credits were essentially rebates on company spending on Alaska projects that were designed to lure smaller companies to explore both Cook Inlet and the North Slope; under a standard 35 percent credit, if a company spent $100 million in qualifying expenses and had no production tax liability it would receive $35 million in cash from the state. Fisher said in testimony to Senate Resources that the Revenue Department would sell bonds in July or August to pay for the initial $800 million and sell another smaller tranche when the last of the certificates are received. ^ Elwood Brehmer can be reached at [email protected]

AGDC gets help soliciting investors for LNG Project

The Alaska Gasline Development Corp. has secured two of the world’s largest banks to help raise funds for the $43 billion Alaska LNG Project. Goldman Sachs and the Bank of China will assist AGDC in raising multiple rounds of debt and equity investment, according to a late announcement March 27 from the state-owned corporation. Equity offerings will be made to Alaska municipalities, Native corporations and all Alaska residents in addition to more traditional private equity investors, as required by Senate Bill 138, which set up the initial commercial framework for the project in 2014. “Bank of China and Goldman Sachs are well-positioned to provide AGDC with world-class institutional knowledge and resources required to arrange the equity and debt financing to build Alaska’s natural gas infrastructure and LNG export project,” AGDC President Keith Meyer said in the release. The first rounds of equity solicitation will be used to provide working capital for AGDC until the corporation has secured sufficient funding and regulatory approvals for full-scale development. Before AGDC can accept any money from outside investors, however, the Legislature must first give the go-ahead. Gov. Bill Walker’s fiscal year 2019 state budget proposal included language allowing AGDC to accept unlimited third-party funds but the House Finance Committee limited the corporation’s receipt authority to $1 billion per year. Such receipt authority is required for state corporations to accept non-state money. Spokeswoman Rosetta Alcantra denied a public records request for the corporation’s contracts with the Bank of China and Goldman Sachs citing the broad authority the Legislature gave AGDC to sign confidentiality agreements and withhold commercial documents that would otherwise be public. “Both Goldman Sachs and Bank of China will serve as AGDC’s financing arrangers, underwriters and placement agents for Alaska LNG. Bank of China will focus on raising funds from Chinese sources and Goldman Sachs will focus on U.S. and other international investors,” Alcantra wrote. “The two companies will be paid a reasonable fee for services provided. Additionally, they will receive a success fee upon procuring necessary financing for Alaska LNG.” The contracts other state-owned corporations enter into are generally public documents and AGDC has selectively released other contracts it has signed to media outlets upon request. The Journal is appealing the denial of the records request. Authorizing AGDC’s funding is the Legislature’s primary source of control over the project that the Walker administration is pursuing. Securing the outside working capital will likely be necessary for AGDC to keep the project moving because additional state funds will be exceedingly difficult to come by, but not just because the state continues to struggle through annual budget deficits in the $2.5 billion range. Many legislators on both sides of the aisle are also skeptical of AGDC’s ability to pull the massive project together with a staff of less than 40 individuals; there are also questions about the project’s economics, regardless of the entity leading it. AGDC officials expect the corporation will have about $43 million on-hand by the end of June, which is also the end of the state’s fiscal year, according to documents presented at the March 8 board of directors meeting. The corporation spent nearly $37 million in 2017 and has been operating with funds remaining from prior legislative appropriations when a consortium of BP, ConocoPhillips and ExxonMobil led the Alaska LNG Project until the start of 2017. The producers estimated the period when the project’s designs are being finalized and materials and equipment are being ordered would cost roughly $2 billion before actual construction commenced, also known as full front-end engineering and design, or FEED. However, that was also when the project was operating under a different management structure and the overall cost estimate was still between $45 billion and $65 billion. The state and the three producers spent about $650 million combined in the pre-FEED stage before the state took the lead on the project. The nationalized Bank of China is one of three large Chinese companies — oil and gas giant Sinopec and the country’s sovereign wealth fund managers China Investment Corp. are the others — to sign a nonbinding framework deal with AGDC last November that in broad terms exchanges 75 percent of the project’s 20 million tons per annum of LNG capacity for financing 75 percent of the $43 billion Alaska LNG price tag. “Under the witness of both President Xi (of China) and President Trump, Bank of China was one of three China-owned entities to sign a joint development agreement with the State of Alaska and AGDC. We believe it is a very important project for China-U.S. economic ties. Joint development agreement parties are advancing the economic analysis of the project in order to lay (a) more solid foundation for investment and financing,” Bank of China said in a statement issued by AGDC. Goldman Sachs Managing Director Kevin Willens said simply that he is pleased the bank is working with AGDC and the Bank of China on the project in the AGDC announcement. Meyer has said he hopes to have firm agreements in place with the Chinese companies by the middle of the year to continue rapidly progressing the project. AGDC is also pushing to start construction shortly after receiving regulatory approval, the lion’s share of which is tentatively scheduled to happen in March 2020 — when the Federal Energy Regulatory Commission earlier this month said it plans issue a record of decision on the project’s environmental impact statement — presuming a favorable ruling from FERC. However, the corporation could begin contracting for long-lead items before then, according to Meyer. Elwood Brehmer can be reached at [email protected] AGDC hires consultants The state agency leading Alaska’s gas line megaproject has brought on a pair of well-connected consultants to pitch its message to policymakers in Washington, D.C., and to the Alaska public. The Alaska Gasline Development Corp., a public entity whose board is chosen by the governor, has hired the Virginia-based firm of Mike Dubke. He worked for three months last year as communications director for President Donald Trump and has also worked as a campaign strategist for both of Alaska’s U.S. senators. The gas line corporation has also hired Kevin Sweeney, who recently left his job as a top aide to one of those senators, Lisa Murkowski. Sweeney, formerly Murkowski’s state director, is now working as a subcontractor for Dubke’s communications firm, Black Rock Group. While both Sweeney and Dubke have close ties to Alaska’s congressional delegation, neither is formally lobbying on AGDC’s behalf, Dubke said in a phone interview last week. Instead, they’re effectively advising AGDC on its own lobbying — on how best to communicate with Congress, the White House, federal regulators, Alaska policymakers and the public. “There’s a big difference between helping them craft their message in a way that Washington would understand — which is what I do — and what a lobbyist would do, which is setting up meetings and pressing for certain pieces of legislation,” Dubke said. “I’m just helping them frame their arguments in a way that people will understand.” Part of Dubke’s job, he added, is monitoring to make sure that Trump’s administration and Congress don’t adopt policies that could inadvertently damage the project, known as Alaska LNG. Trump this month ordered steep new taxes on steel and aluminum imports, which Murkowski said could add as much as $500 million to the project’s cost. And Trump’s tough stance against Chinese imports has prompted fears that he could start a trade war — just months after China’s state-owned enterprises announced they’d partnered with Alaska on the pipeline project. AGDC’s $15,000-a-month contract with Black Rock Group was signed in November and runs through June. Sweeney’s company, Six-7 Strategies, was hired last month as a subcontractor to Black Rock Group at the same monthly rate, also through June. Sweeney’s wife, Tara Sweeney, has been tapped by Trump for a top job at the U.S. Department of the Interior, though her appointment has been held up by questions about her ownership of shares in an Alaska Native corporation. An AGDC spokeswoman, Rosetta Alcantra, provided copies of the contracts in response to a records request from ADN. Asked to discuss them, she provided a prepared statement. “The Alaska LNG project is on an aggressive timeline and we need contractors who are familiar with Alaska, the White House and the Trump administration to assist us in building the project awareness in Washington, D.C.,” she said. — Nathaniel Herz, Anchorage Daily News

Corps of Engineers releases two-year schedule for Pebble EIS

The U.S. Army Corps of Engineers is looking to fast-track the environmental review of the proposed Pebble mine and the project’s opponents, to put it mildly, aren’t happy about it. The Corps released a schedule March 20 of roughly two years to complete the Pebble environmental impact statement, or EIS, and reach a record of decision on the project. A 30-day scoping period, in which the public can submit comments to the Corps regarding what they believe should be evaluated for potential impacts from the project, is set to start April 1. Alannah Hurley, executive director of United Tribes of Bristol Bay, called the Pebble timeline “outrageous.” UTBB is a consortium of 15 Alaska Native governments from the region. Hurley contends that while it is legal — 30 days is the minimum time for an EIS scoping public comment period — public scoping for a single month is well outside the bounds of precedent the Corps and other federal agencies have set for projects the size of what Pebble Limited Partnership is proposing. “There is no way you can get meaningful comment in 30 days,” Hurley said. A statement from Trout Unlimited Alaska notes the Corps of Engineers is currently leading the EIS for three other large projects in Alaska: the state-sponsored Alaska Standalone Pipeline, or ASAP, project, the Nanushuk North Slope oil development, and the Donlin Gold mine in the Kuskokwim River drainage to the north of Pebble. The scoping comment periods for those projects were from 75 to 106 days. The Corps’ Pebble Project Manager Shane McCoy in an interview called the EIS timeline “a strawman schedule.” He said the Corps is required to publish the schedule, but the agency will know much more about how long the Pebble review will actually take after scoping is complete and the comments are analyzed. McCoy acknowledged the two-year schedule is “aggressive” but said Pebble also has provided substantial baseline information to support the work. He added that agency leaders will also decide soon whether or not to extend the scoping period after receiving requests to do so. “We understand the emotions surrounding this project,” McCoy said. Hurley said a longer 60- or 90-day scoping comment period would run up against the annual time when countless area residents are busy prepping for the salmon season that starts in mid-June; however, that would also allow individuals who fish in the region but live elsewhere an opportunity to have their voices heard directly. Hurley also said it’s particularly concerning to her that the only public hearing in the Nushagak River watershed is in the local hub of Dillingham, with no meetings scheduled for upriver Nushagak villages closer to the mine site. The Nushagak is one of two large salmon-producing drainages the project straddles; the Kvichak River-Iliamna Lake system is the other. While fungible, the overall two-year EIS timeline, from March 2018 to early 2020, also comes as a surprise to those monitoring the project closely. When Pebble submitted its Clean Water Act Section 404 wetlands permit application in late December, Corps of Engineers Alaska regulatory officials noted the average EIS for a large project in the state usually takes four to five years. Pebble CEO Tom Collier said at the time he hoped the review could be done in three. According to the schedule, Corps officials hope to have a draft EIS finished by next January with the final EIS published late next year leading to the early 2020 record of decision, according to the project website. The Corps manages Clean Water Act wetlands activity permits for the Environmental Protection Agency and large wetlands fill applications such as Pebble’s usually trigger a full EIS. The mine site north of Iliamna Lake would fill 3,190 acres of wetlands, according to Pebble’s Section 404 application. In January, Pebble’s adversaries got a bit of welcomed but unexpected news from EPA Administrator Scott Pruitt, who declined to remove the Obama administration’s proposed prohibitions on developing a large mine in the Bristol Bay region. Pruitt indicated the agency is still highly skeptical the project can adequately coexist with the area’s fisheries, but also stressed his decision “neither deters nor derails” Pebble’s environmental permitting process because nothing has been finalized. The entire project stretches over 187 miles from the start of a natural gas pipeline near Anchor Point on the Kenai Peninsula, across Cook Inlet to a deepwater port that would be built on the edge of Kamishak Bay on the west side of the Inlet 53 miles of roads plus a ferry leading to the mine itself. Hurley noted that residents near the Donlin project — similarly a large open-pit mine proposal with a gas pipeline from Cook Inlet — were afforded 16 public scoping meetings by the Corps. The Donlin Gold EIS was initiated in December 2012; a draft EIS was published in November 2015 and a final EIS is expected soon. Pebble spokesman Mike Heatwole said the company is pleased with the schedule the Corps has put forth. “I think they’ve laid out a fairly comprehensive and transparent approach to what they’re hoping to accomplish,” Heatwole said in an interview. “We certainly hope, as we’ve said for quite a while, it’s an expeditious permitting review process for the project. There’s a lot of material to cover and we hope that we get a comprehensive review through that.” He also stressed that scoping is the time when the public can weigh in with what they feel the Corps should evaluate relating to Pebble — much of which have been aired for years — and those issues “are pretty well known.” “Once the draft EIS comes out, that’s when you really get into the comprehensive look at what the Corps has put forward,” Heatwole added. The minimum public-comment period after a draft EIS is published is 45 days. For Pebble, eight scoping meetings were originally planned: seven in Bristol Bay-area communities and one each in Homer and Anchorage. However, a March 22 release from the Corps’ Alaska District indicates a meeting planned for Igiugig, a community at the outlet of Iliamna Lake has been cancelled, leaving seven scoping meetings. Those meetings are set for the period from April 9 in King Salmon to April 19 in Anchorage. The Corps also translated a condensed version of the Donlin draft EIS into Yupik, which is the first language for many of the region’s Alaska Native residents, but no action has been set for Pebble, Hurley contended. “It’s the Corps’ mandate to make sure people can engage whether they’re English speaking or not,” she said. Donlin Gold translated additional project information on its website into Yupik on its own, according to a company spokesman. Heatwole said the Pebble Partnership is still evaluating the best ways for it to engage with communities near the project. Elwood Brehmer can be reached at [email protected]

Legislators on all sides concerned about receipt authority for AGDC

Gov. Bill Walker’s administration is not asking for more state funding to advance the $43 billion Alaska LNG Project, but some legislators are concerned allowing the gasline developers to accept outside money could sign away much of their remaining control over the project. Included in the governor’s 2019 fiscal year budget proposal is language giving the Alaska Gasline Development Corp. the authority to accept third-party funds from potential Alaska LNG investors. The provision would cover the remaining months of fiscal year 2018, which ends June 30, and fiscal year 2019. Resources Committee chair Sen. Cathy Giessel, R-Anchorage, said legislators generally like to guard their appropriation authority, which is one of the most fundamental powers they are granted by the state constitution. “Receipt authority is a lot like giving a blank check,” she said. Giessel, who has monitored AGDC’s work as close as anyone in the Legislature, said at this point the Senate Majority still has a lot of questions about what the state-owned corporation would do with the third-party funds — or what it would have to offer to receive them. The House Finance version of the 2019 operating budget released March 19 capped the receipt authority at $1 billion per year to give AGDC financial headroom to keep working without the freedom to commit to building the whole project without further review by the Legislature. Giessel said the House concept might not be a bad idea. She also noted that the Federal Energy Regulatory Commission published a schedule for the Alaska LNG environmental impact statement March 12 that likely would not have the project receive regulatory approval until early 2020 or possibly later. “We wonder if perhaps, based on the new FERC timeline, if (AGDC) wouldn’t have enough money through next year anyway,” Giessel said. The administration had been pushing FERC to have the EIS done by early 2019, but the extra year could slow the need for money to advance the project quickly. AGDC President Keith Meyer has said ideally he would like to start construction in late 2019 or at least be contracting for long-lead time items in preparation for construction by then. Meyer and Walker said when the state took control of the project from the producers in early 2017 that AGDC would rely on the roughly $100 million it had left from prior gasline appropriations for the foreseeable future. Corporation leaders expect to have about $43 million left when fiscal 2019 rolls around in July, according to a financial summary from the March 8 AGDC board of directors meeting. As the proponents of the project, AGDC is responsible for funding work on the EIS and officials said it’s unclear if the corporation currently has enough cash available to finish the environmental review because the extent of additional work FERC will require isn’t yet known. Spokesman Jesse Carlstrom said via email that the corporation can continue advancing Alaska LNG on its current pace with no new funds through 2019. “AGDC is preparing to engage investors. Authority to accept funds from third-party investors will enable AGDC to build Alaska LNG without the necessity of additional state funding,” Carlstrom wrote. Absent sure-fire success on the project there likely won’t be additional state funds to support AGDC as long as the state is struggling through continued budget deficits. Legislators have exuded bipartisan skepticism in the project since AGDC took it over but have allowed the administration to keep working on it with the remaining funds. They are now wondering what role the three Chinese nationalized mega corporations, Sinopec, Bank of China and China Investment Corp., could have in the project if they also end up being the primary funders. The nonbinding joint development agreement Meyer and Walker signed with them Nov. 8 would have the Chinese consortium provide debt and equity to cover 75 percent of the gasline development costs in exchange for 75 percent of they system’s LNG capacity. There is concern design and construction work that could otherwise go to in-state companies and Alaskans might be offered to Sinopec, one of the world’s largest oil and gas companies, instead. As Giessel said she understands it, if legislators were to give AGDC unlimited receipt authority the only control they would have over the corporation and the project — short of disbanding AGDC — would be in approving the Department of Natural Resources to take the state’s royalty share of North Slope natural gas “in-kind.” “The rest of the authority, the approvals, that were in SB 138 (passed in 2014) really went by the wayside when the state took over,” she said. Elwood Brehmer can be reached at [email protected]

Southcentral community leaders want in on AKLNG site selection studies

Nearly five years after Nikiski was chosen as the terminus for the $43 billion Alaska LNG Project, the leaders of other Southcentral communities are now questioning the process behind that decision. On Jan. 9, the Matanuska-Susitna Borough sought intervener status in the Federal Energy Regulatory Commission’s drafting of an environmental impact statement, or EIS, for the Alaska LNG Project. The state-owned Alaska Gasline Development Corp., which is leading the project, did not object to the borough’s intervener petition even though it came well after the formal May 2017 deadline for intervener petitions on the EIS. FERC granted the borough request Feb. 27. Mat-Su officials contended to the regulatory agency that not only were years of requests to have the borough-owned Port MacKenzie considered as an alternative to Nikiski humored and then dismissed, but a location fictitiously dubbed “Point MacKenzie” was instead evaluated and ruled out. Mat-Su Borough Internal Auditor James Wilson, tasked by Manager John Moosey to be the borough’s point-person on the project, said in an interview that he came across a photograph last fall when reviewing documents AGDC submitted to FERC that revealed the discrepancy in locations. Wilson said that AGDC President Keith Meyer met with borough officials shortly after he was hired in spring 2016 and told them that the state corporation would evaluate the port and resolve the borough’s concerns. ExxonMobil — part of a consortium including BP, ConocoPhillips, pipeline company TransCanada and the State of Alaska — led the project from its informal inception in 2012 until AGDC took over management early in 2017. Mat-Su officials were told for several years that project managers were using “Point” and “Port” MacKenzie interchangeably and the actual port would be given a fair shake, according to Wilson. He detailed what he found in a Dec. 29 letter to FERC’s Dispute Resolution Service. “To MSB’s astonishment and surprise, the aerial photograph showed that ‘Port’ MacKenzie was NOT ‘Point’ MacKenzie. This photograph completely contradicted what MSB had been told for several years that Port MacKenzie was included in the FERC Alternative Analysis,” Wilson wrote to the federal agency. “This revelation leads to the decision by MSB to make a formal request to include ‘Port MacKenzie’ in the Screening and Feasibility Analyses.” AGDC leaders and others that have closely followed the project note the map Wilson saw and the associated site evaluation information has long been publicly available. However, it is part of 13 voluminous Resource Reports and other documents — roughly 60,000 pages of environmental, engineering and socio-economic data — gathered over several years by the ExxonMobil-led Alaska LNG team and submitted to FERC for the 800-mile long project. The project team studied more than 20 sites across Cook Inlet, Resurrection Bay and Prince William Sound. Mistaken identity Borough Manager Moosey said the map in Resource Report 10 confirmed what he and others at the borough had been worried about since Nikiski was selected in 2013. “Every time (AK LNG managers) came back they came back with information that just didn’t jive with the details of our port. At practically every turn they said, ‘We’ll look at it’; We’ll make adjustments’ or ‘We have experts on this who really understand this so there’s some things you just don’t know,’” Moosey said in an interview. The site evaluated and dismissed by the Alaska LNG consortium is private land about three miles north of Port MacKenzie. It has extensive tide flats that would require a 1.6-mile trestle or a massive dredging operation to access water that is continuously 50 feet deep, which is necessary for the large LNG tankers that would berth at the dock. Borough leaders have long touted the naturally 60-foot deep water at the end of the 500-foot Port MacKenzie dock trestle as a major selling point for the port they hope can be an industrial center. Additionally, the borough owns 8,940 acres of adjacent uplands. The Alaska LNG Project plant will need roughly 800 acres for facilities that would produce 20 million tons per year. The geographical feature more commonly known as Point MacKenzie is about another three miles south of the port, or six miles from the “Point MacKenzie” evaluated for the Alaska LNG Project. “After we had these conversations (with project managers) and then we see the documents it was like ‘You got to be kidding me,’” Moosey said. “At least that was my attitude. We’ve asked for this stuff to be corrected in their reports for seven years. If they would’ve taken any time along the way I don’t think we’d be where we are right now.” Interestingly, the maps submitted to FERC as official documents detailing potential LNG plant sites near Anchor Point and on Kalgin Island in west Cook Inlet site the plant in a state game refuge and critical habitat area, respectively. FERC assigns work On Feb. 15, FERC and cooperating federal agency officials asked AGDC to respond to 570 questions or data requests; that was after the state corporation announced Jan. 22 it had finished answering the first round of 801 questions. Among the February queries were directives to do environmental and engineering analyses for locating the plant at Port MacKenzie and Valdez. The two are likely alternatives to be evaluated in the environmental impact statement FERC is drafting but at this point there is little reason to believe the pipeline will end somewhere other than Nikiski if it is approved. FERC issued a schedule for the project March 12 indicating the agency expects to have the draft EIS out for public comment in about a year, with the final document published in December 2019. AGDC has advocated having the final EIS done this year to stay on the fastest-possible construction schedule. Meyer, who took over at AGDC after the data gathering was largely complete, said in an interview the corporation would evaluate Port MacKenzie as requested by FERC, but added the Mat-Su port is not an ideal place for large-scale LNG operations, in part because of its proximity to the Port of Anchorage and its designation as a multi-use facility in the borough’s master plan. “You can’t really put an LNG terminal in the middle of a multi-use port,” Meyer said. “No one will argue that you can’t build an LNG terminal in Nikiski.” The Mat-Su Borough was working to develop Port MacKenzie into an industrial district back in 2012 and 2013 when the Alaska LNG Project team was evaluating LNG sites. The port was also a site of interest to other, smaller LNG projects such as an export effort proposed by Japanese consortium Resources Energy Inc. that was courted by borough officials. At the same time, the state’s budget deficit led to slashed capital spending and funding stopped flowing for the half-finished Port MacKenzie rail spur intended to spark further development. Today, the port remains mostly quiet. AGDC regulatory Vice President Frank Richards noted being farther north in Cook Inlet would add miles to tanker trips and the area is also listed as critical habitat for the Inlet’s endangered population of Beluga whales, who feed on the salmon and herring that return to the area’s many large rivers. Wilson, of the borough, said space and 10,000 feet of shoreline could be dedicated to the plant. “We’re still open for business but the bottom line is the area is 1,000 acres along what we call the waterfront dependent area — that acreage is 100 percent exclusive Alaska LNG,” he said. As for the “point” versus “port” confusion, ExxonMobil’s Steve Butt, who led the project until 2017, would not provide any information beyond what was in the public filings, according to Wilson and Moosey. Likewise, AGDC was only working on a portion of the LNG plant at the time, when the producers and TransCanada owned a majority of the project, and there was what Richards referred to as a “Chinese firewall” between the project groups. He said specific questions beyond what can be answered by the Resource Reports should be directed to the producers. Former Gov. Sean Parnell, whose administration created the original Alaska LNG framework in parallel with reaching a settlement of the Point Thomson lawsuit on the North Slope, wrote in an email similarly that the state approved Nikiski after receiving a briefing from the producers’ team, which drove the site selection work. Representatives for BP and ConocoPhillips said there were no individuals in the Alaska offices with that knowledge given the time that has passed and suggested contacting AGDC. ExxonMobil did not respond to a request to speak with Butt. Butt said in 2013 that Nikiski was chosen largely for its terrain and the ability to provide natural gas to the state’s four largest population centers along the pipeline route. Former Federal Alaska Gas Pipeline coordinator and Kenai Peninsula Borough oil and gas advisor Larry Persily — often a critic of the state-led LNG effort — mostly concurred with Meyer and Richards on Nikiski versus Port MacKenzie. “You cannot use a public dock for fuel tankers; for security purposes that’s not going to work,” Persily said. He added that Nikiski is already a heavily industrial area with the smaller legacy ConocoPhillips LNG plant nearby that was recently purchased by Andeavor (formerly Tesoro). The town is also in a flat area with acceptable geotechnical characteristics and by Alaska standards is close to a suitable workforce and easily accessible by road, Persily noted. At the same time, he said it would not be unreasonable to expect the state to have information on why the wrong site was evaluated in the Mat-Su Borough. “You’d like to think that as a 25 percent partner you’d have paid attention to that decision,” Persily said. The producers have also purchased about three-fourths of the roughly 800 acres the plant is expected to span and the state Department of Transportation is drafting a plan to reroute the Kenai Spur Highway, which currently bisects the property. Next steps Meyer said March 8 that a resolution to drawn-out negotiations with the producers over acquiring access to that acreage in Nikiski was “imminent.” AGDC — with an uncertain funding future from the Legislature and expected to have only about $42 million in cash on hand by July 1 — would not purchase the land immediately but rather would get an option to acquire it at the appropriate time in the future. Frustrations aside, Moosey and Wilson said the project’s success is their number one priority; they just want correct the misinformation they believe did not follow the National Environmental Policy Act process and prevented the borough from getting a fair shake. “We think a lot of our port but this project is so important to the state that if it pencils out it’s got to go, regardless,” Moosey said. “The last thing we want to do is, if it doesn’t come to us, is to kick and scream and cause problems.” He pitched Port MacKenzie as a staging and assembly area for the project if it is not built there. Richards said Mat-Su officials have offered the extensive data set the borough has acquired on the port’s geophysical characteristics — down to borehole samples — which should expedite the site review FERC is requesting and hopefully prevent delaying the EIS. AGDC asked for a public meeting to discuss the specifics of what FERC wants in its latest round of questions. The meeting is on March 22, in Washington, D.C., at 5 a.m. Alaska time. For example, Richards said he hopes to find out if a GIS-based analysis for Valdez-route options around the Scenic and Wild River-designated sections of the Delta and Gulkana rivers will suffice, or if a more costly and time-consuming survey must be done. Even if the Mat-Su Borough makes a New England Patriots-esque comeback and Port MacKenzie is ultimately chosen by FERC as the Alaska LNG endpoint, it would not be an insurmountable challenge to reroute the project because the smaller, in-state Alaska Standalone Pipeline, or ASAP, project is planned to end 12 miles from the port, according to Richards. Being able to use almost the entire ASAP route should preclude another major round of data collection. The long-awaited ASAP final supplemental EIS is expected from the U.S. Army Corps of Engineers soon. While AGDC did not object to the Mat-Su Borough intervening late because the borough is a major landowner along the Alaska LNG Project, the Kenai Peninsula Borough did. Mayor Charlie Pierce wrote to FERC Jan. 29 that Kenai Borough officials could find nothing in the docket until the Jan. 9 intervener motion to support Port MacKenzie as the LNG plant site. “Although we do not doubt that the Matanuska-Susitna Borough believed Port MacKenzie would receive further review, the lack of any earlier comment in the docket is a reminder to all of us the value of participating in the public record of the NEPA process,” Pierce wrote. Aside from the obvious economic benefits getting the LNG plant would offer the surrounding communities, it could also be a boon for local tax rolls. The plant and associated marine terminal account for nearly half of the cost of the estimated $43 billion project and Meyer has said repeatedly AGDC would allocate $450 million per year for payments in-lieu of property taxes to the local governments the project crosses. Exactly how the PILT money would be divvied up amongst the cities and boroughs along the Alaska LNG route has not been settled. Valdez chimes in For their part, local government officials in Valdez don’t want FERC to forget about their town, either. Valdez Mayor Ruth Knight sent a letter to FERC March 13 urging the commission to deny AGDC’s request to allow it to apply methods for wetlands assessment, mitigation and constructing the 36-inch ASAP line to the 42-inch Alaska LNG pipeline. The ASAP project is generally seen as a backup plan if the large export project does not pan out, as it would provide a long-term supply of North Slope natural gas for in-state users. At 733 miles long, the ASAP line would be shorter than the Alaska LNG pipeline because it would tie into the existing Beluga gas pipeline near Point MacKenzie and not go all the way south to Nikiski. It would also be substantially cheaper without the need for the large LNG plant to convert the gas into a shippable liquid; cost estimates for the first, 24-inch iteration of ASAP done in 2012 were up to roughly $10 billion. However, whether or not there would be enough demand for gas to make ASAP economically feasible is uncertain. While the current plans for ASAP and Alaska LNG follow the same corridor across most of Alaska, they would diverge in the upper Susitna Valley where ASAP would cross the river and continue south along the Parks Highway on the east side of the river and Alaska LNG is planned to parallel the Susitna to the west. Knight noted, among other issues, the 130 miles of differing route, the need for a wider Alaska LNG right-of-way and ASAP’s lack of compressor stations, which are needed to transport the roughly six times more gas the Alaska LNG line would carry. “These and other differences in pipeline design will result in the AK LNG Project impacting 68,290.94 acres during construction and the ASAP Project impacting 21,237 acres during construction,” Knight wrote. She continued to contend that AGDC has not provided any evidence that the different pipelines will have similar impacts to wetlands. AGDC has urged FERC to apply the wetlands requirements the Corps of Engineers deems necessary for ASAP to the Alaska LNG Project because the Corps is drafting the ASAP supplemental EIS and is the lead federal agency for issuing wetlands fill permits under the Clean Water Act. The Corps also has well-established policies for mitigating construction impacts to wetlands. Richards said the Corps has determined it has jurisdiction over roughly half of the ASAP corridor due to the existence of wetlands in those areas but to what degree the Corps will require construction mitigation in those areas is unclear. Knight said in an interview that city officials are very happy FERC directed AGDC to study the Valdez option more thoroughly. The Alaska Gasline Port Authority, once managed by Gov. Bill Walker, first petitioned FERC to consider Valdez for Alaska LNG in February 2017. AGPA is a longstanding municipal port authority formed by the City of Valdez and the Fairbanks North Star Borough to promote an export project for North Slope natural gas. Following the Trans-Alaska Pipeline System, or TAPS, corridor from the North Slope to Valdez would be the most economical and least environmentally damaging gasline alternative because of the existing pipeline development, according to Knight. “The ASAP corridor is like apples and oranges so throwing the ASAP corridor in there sort of muddies the waters,” she said. “(FERC) needs to look at the line as the state has filed it and keep the ASAP corridor out of the mix.” She added that AGDC has touted the environmental benefits of following the TAPS corridor until the two split under current plans near Livengood north of Fairbanks. A gasline to Valdez has been studied extensively in the past but AGDC officials contend crossing over Thompson Pass just north of Valdez presents engineering challenges. They also note the different engineering requirements for the oil-carrying TAPS, much of which is above ground, and a gasline that would be completely buried. Whether there is nearly 1,000 acres of mostly undeveloped, flat land suitable for an LNG plant near Valdez is another question that has been raised. “We want what’s most economical for the state. I don’t want to make it the political choice,” Knight said. Elwood Brehmer can be reached at [email protected]

Oil legislation could come off the back burner in a budget deal

Bills to raise oil taxes and pay off the state’s $800 million refundable tax credit obligation have stalled for weeks but legislators say both could be part of what is sure to be a strenuous lift at the end of a session in which the festering $2.5 billion annual deficits are coming to a head. House Resources Committee co-chair Rep. Andy Josephson, D-Anchorage, said during a Majority Coalition press briefing that House Bill 288, which would raise the minimum production tax, could be part of a package of legislation to settle end-of-session negotiations with the Republican Senate. Josephson held several hearings on HB 288 early in the session and took unfavorable industry testimony over raising taxes, but it hasn’t been addressed formally since Jan. 29. Sponsored by Resources co-chair Rep. Geran Tarr, D-Anchorage, it would raise the gross minimum production tax rate from 4 percent to 7 percent and generate up to about $250 million in additional revenue at current prices, according to the Revenue Department. Tarr and others in the Democrat-led Majority have said they felt the need to propose an oil tax increase as some sort of additional revenue measure after the Senate wholly rejected income and payroll taxes last year. Revenue officials said the bill becomes revenue-neutral at a price of about $72 per barrel, which is when the state’s net profits tax rate takes effect. Government take of Alaska’s oil is at its lowest level in state history at roughly 54 percent, according to Finance co-chair Rep. Paul Seaton, R-Homer. Josephson suggested the bill could have a tiered gross tax as well to make it more palatable to Republicans averse to another oil tax change. Industry representatives said the tax increase would come at a time when many companies have just righted their balance sheets after the $26 per barrel bottom of the oil market in 2016 and are ready to start growing again with more stable prices. Tax credit bonds Senate Resources chair Cathy Giessel, R-Anchorage, said in an interview that there is a fair chance that Gov. Bill Walker’s plan to pay off the $800 million-plus refundable tax credit debt could move out of her committee by the end of March. Senate Bill 176 would have the Revenue Department sell 10-year, subject-to-appropriation bonds in two tranches to pay off the outstanding tax credit certificates expected to total $900 million when the last credits sunset in a couple years. The debt has accumulated since 2015 when Walker made the first of two vetoes totaling $630 million for the tax credits, and the 2017 and 2018 fiscal year budgets passed by the Legislature have contained only the statutory minimum payments. Prior to Walker’s veto in the early throes of the current budget crisis, the credits had been paid in full every year since 2006. The Legislature has since ended both the Cook Inlet and North Slope credit programs. The generally small companies owed the money — and some bigger ones such as Repsol that have no production — would need to agree to take a haircut on the tax credits of up to 10 percent on the full amount they’re owed in order to get the vast majority of the money immediately. The administration hopes the plan could jumpstart industry spending in the state again as banks that lent on the credits as collateral — expecting they would be paid in full each year — now have nonproducing loans and have stopped lending to oil companies in the state. Numerous companies such as Caelus Energy, Blue Crest and Furie Operating Alaska have cited unpaid tax credits as a reason for delaying previously announced work. It would also clear the state’s books of the obligation without costing the state additional money, Revenue Commissioner Sheldon Fisher emphasizes, because the state’s expected cost to borrow the money is in the 5 percent range and credit holders would need to accept a discount rate. That discount could be lowered to 5 percent if companies commit to reinvesting the money in the state or agree to make seismic data public sooner. Republicans have generally indicated at least modest support for the bill, but some on the Resources Committee suggested the state should cut the bond terms and pay the debt off quicker. Giessel indicated the bill could come up again after amendments are drafted to that effect. Democrat Sen. Bill Wielechowski of Anchorage questioned whether or not the bill fits within the constitutional limits of the state’s ability to bond as a means to pay off other debt. House Democrats are mixed on the idea but there is a belief it could gain traction if SB 176 makes it over from the Senate. It is scheduled for Senate Finance after the Resources Committee. Elwood Brehmer can be reached at [email protected]

Revenue forecast up on oil prices, but production short of forecast

Income will be up but oil production will be down, according to the state’s Spring Revenue Forecast released March 16. Department of Revenue officials project the State of Alaska will take in roughly $2.3 billion in unrestricted General Fund revenue during the current 2018 and 2019 fiscal years, which would be an increase of $256 million and $212 million per year, respectively, from the financial forecast issued last fall. A new state fiscal year starts each July 1. The Revenue Department issues a comprehensive analysis and projection of the state’s financials each December and, for budgeting purposes, updates the forecast with revised projections during the legislative session. The department is anticipating unrestricted revenue to increase by between $124 million and $213 million from 2020 to 2026 from the Fall 2017 forecast as well. “Expected revenue has increased $125 million to $250 million per year across the forecast period,” Revenue Commissioner Sheldon Fisher said in a statement accompanying the forecast release. “This is good news for all Alaskans. Unfortunately, even after this additional revenue Alaska continues to face a budget deficit in excess of $2.3 billion. The (Walker) administration will continue to work with the Legislature to address the fiscal gap during the legislative session.” Realized earnings from the Permanent Fund — likely to support government services starting with the fiscal 2019 budget currently being debated in the Legislature — are expected to be $4.4 billion in 2018 and nearly $4 billion in 2019. The Fund’s performance is highly dependent on how domestic and international stock markets fare. Higher than anticipated oil prices are behind the unrestricted revenue bump. Petroleum-derived revenue from taxes and royalties usually accounts for between 75 percent to 90 percent of the state’s unrestricted General Fund revenue in most years. Last fall, the Revenue Department estimated Alaska North Slope crude would average a price of $56 per barrel during fiscal 2018, but as of March 14 North Slope oil was averaging exactly $60 per barrel for the year, which is 7.1 percent above the fall forecast price. Daily prices have hovered between $64 and $66 per barrel in March. The revised forecast projects a final average ANS price of $61 per barrel when the 2018 fiscal year ends June 30. Alaska oil sold for $49.43 per barrel in 2017. For 2019, the price estimate was increased to $63 per barrel from $57 per barrel. The forecast for North Slope oil production, however, is not as positive. Department of Natural Resources officials, who oversee the production projections, estimate North Slope production will fall from an average of 526,500 barrels per day in 2017 to 521,800 barrels per day in 2018 but rebound to average 526,600 barrels per day in 2019. North Slope production has averaged 518,517 barrels per day so far in fiscal 2018, which is 2.8 percent below the fall estimate of 533,400 barrels per day. Had that forecast come true, it would have been a third straight year of production increases. Fisher said in a March 19 Senate Finance Committee detailing the revised forecast that an unusually warm North Slope winter has curbed production efficiency and is largely to blame for the production drop this winter. North Slope temperatures have been about 14 degrees above the long-term average this winter. Deputy DNR Commissioner Mark Wiggin noted in an interview that Slope oil production is still tracking very close to the Fall 2017 forecast even though the daily numbers are not as high as hoped. “It’s within the margin of error,” Wiggin said of fiscal 2018 production numbers. He also explained that the production facilities on the Slope are designed run most efficiently at very cold winter temperatures. The natural gas compressors that help reinject gas at many wells to enhance oil production are not as effective at warmer ambient temperatures — which is the primary reason for less summer production each year — and can lead producing companies to focus on extracting oil from wells that have a lower gas-to-oil ratio when things warm up, according to Wiggin. Longer term, North Slope production is expected to grow to a peak of 536,100 barrels per day in 2020 and gradually decline from there, before stabilizing at about 494,000 barrels per day from 2024-27. ConocoPhillips’ Greater Mooses Tooth-1 oil development in the National Petroleum Reserve-Alaska is expected to come online late this year with about 30,000 barrels per day at its peak and provide a production boost, as is Brooks Range Petroleum’s Mustang project near Kuparuk, which could provide more than 10,000 barrels per day of new oil. Oil prices over the period are forecasted to gradually climb to $75 per barrel by 2027. With that in mind, Fisher noted in a cover letter to Gov. Bill Walker with the forecast that the price increase over the next decade would still have Alaska oil in the low $60 per barrel range in today’s terms as inflation will likely degrade the real value. Fisher also acknowledged, “predicting future prices is inherently uncertain.” Republican legislators have cited the improved oil price and production prices as proof the state does not need to implement a broad-based tax to resolve the deficit, but instead can rely on reduced spending and drawing from the Earnings Reserve of the Permanent Fund to balance the state budget within a few years. Walker and the Democrat-led House Majority Coalition insist a tax is needed to balance the budget sooner and provide revenue stability in the event oil prices — which Fisher acknowledged projecting is “inherently uncertain” in his letter to the governor — and production do not meet expectations. The state’s remaining savings will almost assuredly fall below $2 billion at the end of the current fiscal year regardless of what revenue and budget-cutting measures are adopted this session. ^ Elwood Brehmer can be reached at [email protected]

As habitat initiative debate swirls, ADFG outlines current best practices

The Alaska Supreme Court will still have its say, but there’s a good chance voters will be asked whether or not the state should overhaul its permitting regime for construction projects impacting salmon habitat. It’s the latest battle in the ongoing debate over how far the state should go to protect its prized fish resources while at the same time promoting development of the state’s renowned petroleum and mineral resources. The sponsors of the Stand for Salmon ballot initiative — Alaskans with commercial, sport and subsistence fishing interests — contend Title 16, the state statute for permitting projects in fish and wildlife habitat that has not been updated since statehood, needs serious strengthening to continue protecting anadromous fish as the state continues to grow. They argue the ambiguous wording of the law, which directs the commissioner of Fish and Game to approve projects that provide for the “proper protection of fish and game,” is too open for interpretation by political appointees who could be swayed to overlook stringent construction requirements for potentially profitable developments. Opponents of the initiative — led by trade groups for the state’s oil and gas and mining industries and Alaska Native corporations with huge land holdings that are also heavily involved in those industries — point to Alaska’s generally prosperous salmon runs as proof the significant changes to Title 16 the initiative would institute are unnecessary and would debilitate an economy dependent on resource development. They have formed their own campaign group, Stand for Alaska. The Supreme Court will hear arguments in April over whether the initiative is unconstitutional after conflicting opinions have been handed down from the Alaska Department of Law and Superior Court. The sponsors, who collected enough signatures to place it on this November’s general election ballot, retort that to date Alaska has for the most part been “lucky” that large developments have occurred outside of major salmon fisheries so the inadequacies in Title 16 haven’t been exposed. Gov. Bill Walker is among the opponents of the Stand for Salmon initiative. He insists such fundamental law changes should be left to the legislative process so the statute can be crafted with input from all impacted parties. The initiative would apply to all waters that support anadromous fish — those species that migrate freely between fresh and salt water — that, in addition to salmon, include everything from steelhead to smelt and lampreys. However, salmon are king in Alaska and therefore dominate the discussion. It should be noted that the Stand for Salmon sponsors did not stir this political hornets’ nest on their own. In January 2017 the Board of Fisheries wrote a letter to legislative leaders requesting revisions to Title 16. The seven-member board is comprised of individuals first appointed by pro-development Govs. Frank Murkowski, Sean Parnell and Walker. “Additional guidance is warranted for the protection of fish, to set clear expectations for permit applicants and to reduce uncertainty in predevelopment planning costs,” the letter states. “To strengthen ADF&G’s implementation and enforcement of the permitting program, the legislature may want to consider creating enforceable standards in statute to protect fish habitat, and to guide and create a more certain permitting system.” Kodiak Rep. Louise Stutes, who chairs the House Fisheries Committee, is currently working on a new draft to House Bill 199, which she submitted last year and originally mirrored the initiative. She decided to rework HB 199 after hearing testimony from supporters, detractors and regulatory agencies involved in development projects. What’s in it? Specifically, the eight-page initiative would start by setting up a two-tiered permitting regime for projects in salmon habitat. “Minor” habitat permit applications could be issued quickly and generally for projects deemed to have an insignificant impact on salmon waters. “Major” permits for larger projects such as mines, dams and anything determined to potentially have a significant impact on salmon-bearing waters would require the project sponsor to prove the project would not damage salmon habitat. Supporters assert upwards of three-quarters of the habitat development permit applications Fish and Game currently adjudicates would fall in the minor category and what exactly constitutes unacceptable or “significant adverse affects” on anadromous fish habitat would still be up to the Legislature and Fish and Game commissioners to determine. Additionally, the project sponsor would have to prove that impacted waters are not salmon habitat during any stage of the fish life cycle if the waters are connected to proven salmon habitat in any way but not yet listed in the state’s Anadromous Waters Catalog. Among other changes, it would also limit mitigation of habitat impacts by major projects to the impacted watershed, thereby eliminating offsite compensatory mitigation to other anadromous waters, and require sufficient fish passage be maintained throughout the life of the project. Finally, it would provide for public comment periods on major project permits, a provision the Board of Fisheries advocated for in its letter that is not part of the current permitting process. What’s the standard now? So, other than lacking public participation, which initiative opponents note is usually available through other permits developments need, what does the current anadromous waters permitting process consist of? That’s the question Ron Benkert with the Department of Fish and Game attempted to answer for the Journal during an hour-long interview. A fisheries biologist by trade, Benkert has been with the Habitat Division for 10 years after many years of salmonid experience through various research positions in the Pacific Northwest and California. In discussing what it takes to design, dig and develop in salmon habitat in Alaska, Benkert likes to start with what goes into the seemingly simple task of installing culverts in small salmon streams, which he refers to as one of the “bread and butter” projects the department oversees. “It’s one of the things we do an awful lot of because we have assessed a lot of the culverts in the state and obviously DOT and the boroughs and other entities have all got a lot of bad culverts out there,” he said. “We all recognize the problem out there and I think DOT and the boroughs are really stringently trying to correct those as funding becomes available.” The problem often lies in what work originally went into culverts set in road and rail beds decades ago — but under the same Title 16 — before rigorous design standards were applied that allow for fish passage. If not in the original installation, the issue is likely because of erosion or a changing stream channel that has made a once-suitable culvert impassable. ADFG has a catalog of “bad pipes,” as Benkert calls them, which officials reference each time there is roadwork scheduled, he said. “Every time DOT conducts some kind of maintenance or road construction DOT has been very responsive, as well as the boroughs, at recognizing that (a culvert) needs to be fixed as part of the project,” Benkert said. Installing a fish-friendly pipe is more than burying a culvert big enough for a few chinook salmon to squeeze through. In 2001, the departments of Transportation and Fish and Game signed a memorandum of agreement, or MOA, detailing how the former will ensure the culverts it puts in its roads are compatible with the species in a given stream. The 33-page document delves into the particulars of how to design a culvert to simulate stream water flow conditions as well as the sustained and burst swimming performance at varying water temperatures of 15 fish species common to Alaska. ADFG has enforcement authority over DOT projects despite the two being equal state agencies. Benkert said he considers the agreement to be a prime example of how Fish and Game works with project proponents to achieve specific but important characteristics of a project under the broad “proper protection” mandate. And while a culvert replacement isn’t the kind of project that garners headlines, the cumulative effects of restoring the ability of fish to move through small, seemingly insignificant braids of water can’t be overstated, according to Benkert. “Connectivity is huge,” he stressed. “You reconnect fish to habitats they haven’t been able to access; especially up in the headwater areas that are big rearing areas (for juvenile salmon). You’re just really expanding fish habitat or at least reestablishing fish habitat that was available to them before urbanization occurred.” At the same time, habitat regulators must be pragmatic and evaluate the practicability of improving fish passage. Benkert said in some instances — for example when the upstream portion viable fish habitat is particularly small, as can be the case where roads parallel mountainsides — the department won’t apply the MOA standards if the added costs are into the millions of dollars to restore access to a couple hundred feet or less of stream. “We like to put our money where it’s going to get the best bang for the buck,” he added. Large projects On larger projects things can get increasingly more complex. That’s where the department’s habitat impact mitigation sequence of avoid, minimize, rectify and reduce or, as a last line of defense, compensatory mitigation comes into play. It’s also why project plans rarely look the same after applying for an anadromous fish habitat permit. “That’s our first line of defense, if you will, as far as negotiating with an applicant. How can we change the project footprint or how you’re operating so that you’re not even having an issue with an anadromous water body,” Benkert said. In Feb. 15 testimony before the House Fisheries Committee, he said the department rarely denies a habitat application because proponents usually withdraw them first if it becomes clear that the project won’t be able to meet the department’s thresholds. “We have mid-sized placer miners that want to relocate anadromous streams all the time and I’ve still to this day not had one come in with a plan that’s good enough for us to permit,” Benkert said. “They usually withdraw their application because of that high bar.” Such small business miners simply don’t have the financial wherewithal or the “quiver of biologists and bioengineers” needed to succeed in that type of work, he added. However, on the largest projects such as major mines, dams or oil developments, significant restoration or mitigation can become viable. Real world examples Habitat Division Operations Manager Alvin Ott wrote in a Sept. 27 Superior Court affidavit for Stand for Salmon’s appeal of Lt. Gov. Byron Mallott’s rejection of the initiative that Donlin Gold — in the upper Kuskokwim River drainage — is proposing to destroy two anadromous streams, American and Anaconda creeks, to build the tailings dam and impoundment for its proposed gold mine. In exchange, the company would offset the loss of that habitat by restoring coho salmon rearing habitat damaged by historic placer mining activity in the nearby Crooked Creek watershed, according to Ott. He wrote further that he believes such offsite compensatory mitigation would not be permitted under the initiative language. Benkert acknowledged that constructing or restoring anadromous fish habitat is a tremendous undertaking that’s as much an “art form” as it is science. “It doesn’t matter how good the design looks, if you’ve got an operator that’s saying ‘that’s good enough;’ it’s a very precise thing. You’re talking (bank) elevations within tenths of an inch; making sure everything’s just right so when a big storm hits it doesn’t just unravel,” Benkert said. “It’s a very rigorous process if we’re going to try to replace some kind of anadromous habitat with something that’s artificially created that’s supposed to be able to maintain itself into perpetuity.” As a result, Fish and Game rarely agrees to a 1-1 tradeoff during mitigation negotiations; project proponents are expected to replace more than is damaged, according to Benkert. However, he was enthusiastic to discuss the artificial wetlands complex built similarly from what was placer mine waste below the tailings dam to the Fort Knox gold mine near Fairbanks. It’s not an anadromous system, Benkert conceded, but the department has been monitoring it for nearly 15 years and has many positives to report. “It went from a place that was fairly low density population of fish and wildlife because it was just trashed landscape,” he said. “Now we have huge numbers of grayling and burbot in that system; all kinds of wildlife that’s associated with that habitat.” He noted there are ospreys nesting in the area because there are enough fish — ospreys’ almost exclusive prey — in the system to support them. Whether a simple culvert replacement or a total rebuild to a former salmon stream, Fish and Game relies on best practices learned in Alaska or elsewhere and a lot of professional judgment to determine what activities will be permitted and what mitigation will be deemed sufficient, he said. It’s for that reason that the department has no regulations to accompany the Title 16 statute; the best way to do things is in constant evolution. Benkert said Fish and Game codifies in its own way what is “proper protection” through the information department officials rely on to make decisions. “There’s not a list of things in regulation that says you have to do this, this, this and this but we’ve got all kinds of guidance documents, technical reports, working guidelines and then we go to the literature, too,” he explained. “We always look to see what’s happening in the Pacific Northwest because there’s a lot of new technology out there and it keeps changing.” The 2001 agreement with DOT, for example, specifies culverts should be 0.9 bank full widths of the stream channel in diameter. Benkert described the rule as “old school now,” noting the latest recommendations out of Washington and Oregon call for culverts equal to 1.2 bank widths plus two feet, which DOT has agreed to abide by. Beyond advancing technical standards for development projects, the Habitat Division has expanded the areas it classifies as anadromous waters in the state’s catalog to wetlands in recent years as well. Wetlands, now understood to often be critical juvenile salmon habitat, can be afforded the same protections as well-known rivers under the Anadromous Fish Act if Fish and Game confirms a wetlands area to be anadromous fish habitat. The entire Colville River delta on the North Slope, which includes ConocoPhillips’ Alpine oil field and the large Nanushuk oil project that is in permitting, is officially anadromous territory, according to the state. Though the Department of Fish and Game has considerable leeway in how far it can go to demand fish protections, Benkert noted the state is obligated to accept all factors and utilize, develop and conserve “all natural resources belonging to the state, including land and waters, for the maximum benefit of its people.” “The wrinkle we always have to remember here is our constitutional mandate. It doesn’t say you’re just going to protect fish; you need to protect fish but consider the economic welfare and development of the state, too. Our mandate here is specific. We are supposed to figure out how to allow development in the stat with minimal or avoiding impacts to the fish. That’s something we need to consider all the time,” he continued. “We can’t just say no because the fish may have the potential of being impacted by it; that’s why we have this whole process. That’s the tricky part. The fish come first at the end of the day but we try really hard to get the project to the point where it can be environmentally acceptable.” It all comes back to differing views as to what’s acceptable. Elwood Brehmer can be reached at [email protected]

Interior leaders talk progress on priorities after year under Trump

Interior Secretary Ryan Zinke introduced himself and his department’s priorities to Alaskans in person last May when he said the state is a lynchpin to achieving American energy dominance. Deputy Interior Secretary Dave Bernhardt and Assistant Secretary Joe Balash, a former Alaska Natural Resources commissioner, were back in Anchorage March 8 to report on the progress of Interior’s work during the first year of the Trump administration. “We had a very, very productive year if you compare our policy development to prior administrations,” Bernhardt told the biweekly breakfast gathering of Alaska Support Industry Alliance members. A key piece of that policy has been issuing executive orders and working with Congress through the Congressional Review Act to rescind orders and rules issued under the Obama administration, which Bernhardt referred to as a “wide-ranging deregulatory agenda.” He estimated the administration was able to cut about half of the regulations it wants to in its first year. “I think you can capsulate our regulatory vision in a couple of sentences,” he said. “We’re not willing to sacrifice health, safety or the environmental standards but we are committed to being a good neighbor, respecting the role of other governments and being passionate about ensuring people have access to our public lands.” Bernhardt served in the Interior Department during the George W. Bush administration as the Interior solicitor in charge of the U.S.-Canada International Boundary Commission, among other roles. The Interior leaders were in Alaska in part for meetings on the Bureau of Ocean Energy Management’s push to revise the 2019-24 Outer Continental Shelf Lease Sale Program and prepare for onshore lease sales of the coastal plain of the Arctic National Wildlife Refuge. The draft OCS lease sale plan would reopen many areas nationwide that were previously closed to oil and gas leasing by Obama, including the Beaufort and Chukchi seas. “We have an opportunity as Alaskans to get a lot done and see a lot done,” said Balash, who oversees the bureaus of Land Management, Ocean Energy Management, Safety and Environmental Enforcement and the Office of Surface Mining. “Every day I get to work on something related to Alaska.” Bernhardt said Balash’s work will likely continue to be Alaska-centric as the Bureau of Land Management should be publishing a Notice of Intent to initiate the environmental impact statement process for ANWR lease sales within several weeks. A component of the tax cut bill passed by Congress in December mandates the Interior Department to hold two oil and gas lease sales with at least 400,000 available acres for the 1.5 million-acre ANWR coastal plain within the next decade. And while the U.S. Fish and Wildlife Service typically manages refuge activity, the rider also directs the lease sales to be managed similarly to the National Petroleum Reserve-Alaska, which means BLM, under Balash, is the lead agency. When asked how long the ANWR leasing environmental review will take, Bernhardt noted that he sent out a memo to Interior agencies stressing that he expects environmental impacts statements done in a year. “We’re starting this process very, very soon and I take my memos very, very seriously,” he said. Balash said he is also working to increase the acreage available to industry in the NPR-A to the west of Prudhoe Bay. The U.S. Geological Survey in late December updated its assessment of the recoverable oil in the NPR-A to a mean estimate of 8.8 billion barrels in the 23 million-acre reserve and adjacent state lands. The new assessment was directed by Zinke during his May trip to Alaska and is largely based on recent oil discoveries in the area sourced from the Nanushuk and Torok geologic formations by Armstrong Energy, Caelus Energy and ConocoPhillips. A 2010 assessment of the NPR-A pegged the mean oil estimate at just 896 million recoverable barrels. The BLM offered all 900 lease tracts covering 10.3 million acres in its fall 2017 NPR-A lease sale, but bidding was subdued other than ConocoPhillips purchasing acreage around its declared discoveries. The management plan for the NPR-A, finalized in 2013, removed many of the most prospective oil and gas areas in the northeast corner of the reserve from leasing in order to protect the Teshepuk Lake caribou herd and other subsistence resources in the area. Balash acknowledged that expanding the leasable acreage in the NPR-A is “something that’s going to require a lot of care and consultation with the North Slope Borough.” However, he mentioned to ConocoPhillips Alaska leaders in the audience that he has a copy of the draft supplemental EIS for the company’s Greater Mooses Tooth-2 development, indicating it should be out for public review soon. GMT-2 is a roughly $1 billion oil project the company expects will have peak production upwards of 30,000 barrels per day. GMT-1 is currently under construction and expected to start production next year, also at about 30,000 barrels per day at peak. In January 2017 ConocoPhillips executives said the EIS, being evaluated by the BLM, was moving slower than expected. A spokeswoman for the agency said then that a record of decision for GMT-2 was expected in early 2018, which would have made for an EIS process of about two-and-a-half years. On the broader issue of what is at times an arduously slow EIS process when managed by Interior agencies, Bernhardt said he has given guidance to agency officials at the state level that EIS planning and business processes need to move faster — aside from changing environmental regulations or other requirements. Bernhardt linked part of the problem back to 2001 when the then-Interior secretary chief of staff ordered all Interior-related Federal Register notices be sent to him as a means of monitoring the department’s activities. It ended up spurring what Bernhardt referred to as a “surname process.” “Let me tell you that if you don’t know what a surname process is you should just know that it’s evil,” he quipped. The process grew into up to 30 officials in some cases demanding they be able to sign off on Federal Register notices, according to Bernhardt, which in the case of an EIS usually means three times — once each for the Notice of Intent to file an EIS and the Notice of Availability for both the draft and final versions of the document. As a result, the surname process often leads to upwards of 90 days of delay each time a notice is issued, or 270 days in total. BLM took 11 months to publish the Notice of Intent for the GMT-2 EIS, according to ConocoPhillips. Bernhardt said he is trying a pilot process in which state agency directors and an attorney sign off on such documents and agency and department leaders then collectively have about two weeks to approve them. “The purpose of (the National Environmental Policy Act) is to make sure we take a hard look at issues — that we’ve looked at a reasonable range of alternatives, that we have had public participation to ensure that we as federal decision-makers are more fully informed before we make our decision, whatever it’s going to be,” he said. “And the documents that are written today, when they’re 8,000, 10,000, 25,000 pages, I can tell you that no one on the planet reads them so they’re not serving the purpose they’re intended to.” Elwood Brehmer can be reached at [email protected]

FERC sets December 2019 deadline for AK LNG review

Federal officials analyzing the plans for the Alaska LNG Project issued a timeline March 12 that would extend the review about a year beyond what state officials were hoping for. Federal Energy Regulatory Commission Secretary Kimberly Bose signed off on the environmental impact statement schedule that calls for the agency to issue a Notice of Availability for the final Alaska LNG Project EIS by Dec. 9, 2019. The subsequent record of decision would then be made by March 8, 2020, within the required 90-day period after the final EIS is published. FERC plans to have the draft EIS out for comment next March, according to the filing. Alaska Gasline Development Corp. leaders in mid-November requested the schedule be published by Dec. 15. President Keith Meyer has said repeatedly he wanted the final EIS out late this year to match the corporation’s proposed timeline of having commercial agreements in place for an early 2019 final investment decision with construction starting late next year. The schedule is still fungible depending on how the EIS drafting plays out, but the self-imposed timeline does set a significant precedent. Meyer said at the March 8 AGDC Board of Directors meeting that a slower schedule, such as the one FERC just published, would set back actual construction but the agency and its contractors could start ordering numerous long-lead items in anticipation of a favorable decision ahead of official final approval to build the $43 billion project. On AGDC’s ideal timeline the first train of the three-train 20 million tons per year LNG plant would be in service in 2023 and production would ramp up over the next couple years as the other trains would be constructed and brought online by 2025, according to Meyer. However, AGDC officials said in formal statements March 13 that they are happy to have a schedule to work from. “Achieving clarity on the permitting timeline is another critical step forward for the project; AGDC is appreciative to FERC and to the (Trump) administration for their continued commitment to keeping this project on the fast track,” Meyer said. “A draft EIS in March 2019 with availability of a final EIS in December 2019 will allow us to keep Alaska’s gas export project on track for a 2024-25 in-service date. FERC’s expeditious and comprehensive analysis of our application is a testament to the hard work and dedication of commission staff.” Gov. Bill Walker thanked FERC for issuing the schedule and said it’s a “major step forward that establishes clarity and predictability in the federal permitting process, which is critical for investors.” AGDC filed its EIS application last April — nearly 60,000 pages of environmental, engineering and socioeconomic data believed to be the largest EIS filing in history. It was hoped the immense amount of data, along with the fact that the U.S. Army Corps of Engineers is preparing a final supplemental EIS for the smaller, backup Alaska Standalone Pipeline project, which largely mirrors the AK LNG route, would allow FERC to meet the agency’s aggressive schedule. On Jan. 22 AGDC announced it had responded to all 801 of FERC’s questions regarding the initial filing information, but on Feb. 15 the regulators followed up with 288 more; directing AGDC to further examine routing the pipeline to Port MacKenzie or Valdez instead of the Nikiski, the LNG site chosen by the producers in 2013. AGDC leaders insist the new round of questions is not uncommon in the often back-and-forth process, and they expect more as FERC continues to evaluate the tremendous amount of data for the project. EIS public scoping meetings to determine what all regulators should evaluate were held in late 2015 under the former ExxonMobil-led project structure. The next major step under a standard EIS development would be for FERC to issue a preliminary draft EIS for cooperating federal agencies to review and comment on. Subsequent to that, the resulting draft EIS would be issued, initiating a public comment period of at least 45 days — on very large or contentious projects it is often longer — and associated public meetings. FERC would then respond to the appropriate comments and incorporate them into the final EIS publication, after which a minimum 30-day waiting period must be held before a record of decision on the project is reached. Elwood Brehmer can be reached at [email protected]

Feds change course, pick Alaska’s choice for Sterling Hwy re-route

There finally appears to be a resolution to the saga over how best to avoid Cooper Landing. Gov. Bill Walker was joined Wednesday in the Capitol by Kenai Peninsula legislators Sen. Peter Micciche and Rep. Gary Knopp, to watch DOT Commissioner Marc Luiken and Alaska Federal Highway Administration head Sandra Garcia-Aline sign a final environmental impact statement for the Cooper Landing bypass project and bring the project one big step closer to reality. Walker said he is among the countless Alaskans to have navigated the winding, narrow stretch of the Sterling highway through Cooper Landing in an oversized RV, adding that he has never talked to a group of residents from the area and not had the issue come up. “This is a safety issue,” the governor said. “This is a milestone that’s been long-awaited.” State and federal officials working to advance the Cooper Landing bypass project have said they believe it to be the longest running EIS for a transportation project in the country, if not the most drawn out EIS overall for any type of development. The transportation agencies are on the third iteration of an EIS for the project since publication of the first draft in 1982. Micciche and Knopp expressed their appreciation for the agencies’ efforts to listen to stakeholders concerns and address the longstanding public safety problems the current highway presents during the summer. “This project began when my voice cracked with puberty and today we’re signing the EIS,” a gray-bearded Micciche quipped. A major hang-up has been over what route to choose through the challenging mountainous terrain and the sensitive Kenai River watershed. Sentiment is mixed amongst Cooper Landing residents and business owners as to whether the project should be built at all, as some fear it will steer potential customers away from their businesses that rely on the traffic. The state recently completed work to straighten and add passing lanes to the Sterling Highway east of Cooper Landing and is preparing for similar work on the stretch of highway west of the Cooper Landing bypass area over the next two years. Publication of an EIS last year left the state at odds with the Federal Highway Administration, which chose a route different than that preferred by many on the Kenai Peninsula and Gov. Bill Walker’s administration and the congressional delegation. The final EIS signed Wednesday selects the Juneau Creek alternative route favored my most Alaskans who have formally voiced their opinions on the project. The Juneau Creek corridor would take the highway north of Cooper Landing and add 10 miles of new road, with a cost estimated at $205 million, before reconnecting with the existing highway west of the community and the Kenai-Russian River confluence area that draws thousands of anglers each summer. The FHWA originally chose a route known as the G South alternative, which also would take the highway north of Cooper Landing, but would reconnect to the current road after about five miles and not avoid the busy Kenai-Russian area. At $250 million, the G South option is also estimated to cost more because it would require a new bridge over the Kenai and reconstruction of the existing Schooner Bend Bridge at the west end of the project. Walker and the members of Alaska’s congressional delegation sent a joint letter to leaders of the federal Agriculture, Interior and Transportation departments last July urging them to reconsider the G South selection and work to reach agreements that would facilitate the Juneau Creek alternative. They contended the Juneau Creek route provides better protection for the Kenai River and its sought-after trout and salmon because it pulls more of the highway away from the river, thus reducing the likelihood of tanker truck spills or other potential hazards damaging the river. The letter was sent to Interior and Agriculture because the Sterling Highway project would impact the Kenai National Wildlife Refuge and the adjacent Chugach National Forest, which had been a complicating factor. Transportation Secretary Elaine Chao subsequently visited Alaska in August and committed to reexamining the Cooper Landing bypass decision by reopening the Least Environmental Harm Analysis portion of the EIS. Luiken said the fact that the governor and delegation took up the issue together helped get Chao's attention on the matter. Chao also announced at the time that the U.S. Fish and Wildlife Service, an Interior Department agency, agreed to consider a swap with Cook Inlet Region Inc. of Kenai National Wildlife Refuge acreage for some of the Alaska Native corporation’s property that would aide the Juneau Creek route. FHWA Alaska Administrator Garcia-Aline said the new choice was made in partnership with CIRI and the local Kenaitze tribe. “This sets an example for the nation as to how we can move some of these projects forward and get them into construction,” Garcia-Aline said. She added that a public comment period on the final EIS will commence soon and likely end in mid-April, setting the project up for a record of decision in early May. A state DOT spokeswoman said, barring additional delays, construction is expected to start on the first phase of the three-phase project in 2020, as about two years of design work will be needed after the record of decision is published. The bypass should be completed around 2026 if all goes as planned.   Elwood Brehmer can be reached at [email protected]

Oil sector leads construction spending rebound

The last couple years have been tough for Alaska contractors. While it took about two years to really be felt as money on large multi-year and preplanned projects continued to be spent, the precipitous fall of oil prices in late 2014 led to construction spending declines of 18 percent in 2016 and 10 percent in 2017 year-over-year. Not only did the price collapse hit contractors working in the state’s oil fields, but state capital spending has all-but disappeared since the oil revenues the State of Alaska relies on dried up as well. Similarly, Alaska’s construction industry workforce has declined by 17 percent since peaking in 2014 with a year average of 17,800 jobs, according to the state Labor Department. Last year the industry averaged 14,900 workers. It’s worth noting that those figures do not reflect construction jobs classified within the oil and gas sector, which has seen its workforce shrink by 5,000 jobs, or more than 30 percent, over the same period. However, there are signs of a turnaround. The 2018 Alaska Construction Spending Forecast, compiled by the University of Alaska Anchorage Institute of Social and Economic Research estimates “on the street” spending will increase 4 percent to more than $6.5 billion this year. Authors Scott Goldsmith and Linda Leask wrote in the report for the Association of General Contractors-Alaska that the modest increase will be driven by a rebound in spending by oil and gas companies that will more than offset continued declines in infrastructure investment by other sectors. At more than $2.5 billion, oil and gas company spending will be up about 15 percent from 2017 on the back of improved and stabilized, if not robust, oil prices in the $65 per barrel range, as well as continued work on a burst of potentially large oil discoveries in recent years and more favorable federal policies. For reference, Alaska oil and gas capital spending peaked in 2014 at $3.9 billion, according to ISER. “Perhaps the most significant recent federal policy change affecting Alaska is the decision to open the 1002 (coastal plain) region of the Arctic National Wildlife Refuge to exploration,” Goldsmith and Leask wrote. “That decision — along with the opening of federal offshore lands to leasing — will not immediately lead to spending, but it does demonstrate a renewed federal interest in the petroleum industry in Alaska.” ConocoPhillips has led greenfield activity on the Slope of late and is drilling five exploration and appraisal wells this winter, the company’s busiest exploration season in 15 years. Additionally, the company is finishing work on its roughly $1 billion Greater Mooses Tooth-1 development, which is scheduled to start producing oil late this year. Industry leaders in Alaska have said spending has been cut to the point where company’s budgets are again stabilized and at least incremental investment is a possibility. Further, Gov. Bill Walker has a bill in the Legislature to pay off the state’s $800 million-plus oil and gas tax credit liability in one lump sum, which administration officials believe could spur additional oil and gas activity if it passes. Walker has also proposed an $800 million capital projects plan to address the state’s deferred maintenance backlog, estimated at roughly $2 billion, and provide a small economic stimulus across the state. However, the funding source for the plan is a proposed temporary payroll tax that is politically unpopular and it’s unlikely the plan will pass this session. The mining industry is also projected to be on the rebound with $239 million of capital projects, up 6 percent from 2017 after years of subdued activity worldwide, according to the forecast. Teck, which operates the Red Dog mine north of Kotzebue, is exploring a large new zinc deposit and Trilogy Metals is continuing work on its prospects in the Ambler Mining District, also in Northwest Alaska. The U.S. Army Corps of Engineers is also expected to release a final environmental impacts statement for Donlin Gold’s massive gold project along the Upper Kuskokwim River later this spring. A favorable decision for Donlin will not mean more spending this year and company leaders have acknowledged the economic viability of the remote mine is very sensitive to gold prices, but if it goes forward Donlin likely represents $5 billion of work over several years of development. Another positive will come from the federal government in the form of Defense spending, which with six large military installations in the state is a significant contributor to the construction industry. The feds are expected to spend $630 million on Defense projects in Alaska this year, an 11 percent increase from 2017, according to the forecast. Missile defense work at Fort Greely will eventually add to the number of interceptor missiles at the Army base. The Air Force is in the midst of $325 million of work to install a long-range discrimination radar system at Clear Air Force Station near Nenana. Further work is also ongoing at Eielson Air Force Base in Fairbanks to prepare for the 2020 arrival of the first squadron of F-35 fighters that will be stationed at the base. The 2018 National Defense spending bill signed by President Donald Trump in December approved nearly $170 million in projects for the F-35 bed-down and $200 million for a new missile field at Fort Greely. Surface transportation spending, particularly on roads and highways, should be up about 6 percent to $667 million, Goldsmith and Leask project. While most surface transportation funding comes from the federal government with a small state match and is generally pretty stable year-to-year, the increase this year is due in part to money from a $453 million state bond package approved in 2012 finally “hitting the street.” “It can take considerable time for transportation appropriations to become cash on the street, so state funds from past capital budgets and bond sales are still contributing to current spending,” the forecast states. “Consequently, the level of spending this year will be a little higher than last.” Much of that money will fund major projects on the Glenn, Seward and Sterling highways. Capital spending in other sectors and industries is generally expected to fall by up to 20 percent year-over-year as bare-bones state capital budgets and the third year of Alaska’s ongoing recession continue to constrain investment. ^ Elwood Brehmer can be reached at [email protected]

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