Elwood Brehmer

Slope producers rebuff state demand for gas sale info

The major North Slope producers and state regulators have considerable differences of opinion regarding what information the state can demand in oilfield development plans. BP sent a letter to the Division of Oil and Gas May 2 contending that its Prudhoe Bay Plan of Development for 2016 satisfies the requirements in the 1977 Prudhoe Bay Unit Agreement and all state regulations regarding unit development plans. The company did not provide the detailed technical and marketing information about potential “major gas sales” — a gasline project — that Oil and Gas Director Corri Feige wrote in an April 11 letter that the division would need to approve the plan. “The division’s (April 11) letter seeks extraordinary additional information concerning ‘the timing and type of activities that will be conducted to prepare for major gas sales,’” BP Alaska Reservoir Manager Scott Digert wrote. “These new requirements asserted by the division are contrary to the terms of the (Prudhoe Bay Unit Agreement) as well as the division’s regulations and the division’s own interpretation of its regulations over many decades.” ConocoPhillips Prudhoe Area Manager Jon Schultz wrote to the division May 4 that the company supports BP’s May 2 letter. BP is the operating company for Prudhoe Bay; ConocoPhillips and ExxonMobil are working interest owners in Prudhoe. Schultz wrote that the company proposes to meet and discuss the requests to “avoid potential confusion and miscommunication between ConocoPhillips and the division, which could conceivably impact other confidential discussions between ConocoPhillips and the DNR and give rise to other issues.” The ConocoPhillips letter concludes, “At this point, our goal is to understand the context, intent and purpose of the Division’s request.” BP’s March 31 development plan told the division the company could not speak about efforts made to market Prudhoe natural gas by the other working interest owners. Prudhoe Bay and Point Thomson, which is operated by ExxonMobil, are the fields from which the proposed $45 billion-plus Alaska LNG Project would draw natural gas. The companies and the division use the generic term “major gas sales,” referring to any potential gasline project. The division forwarded the BP and ConocoPhillips letters to the Journal after a records request for all responses to the April 11 letter. ExxonMobil appears not to have responded to the division. Now-retired DNR Commissioner Mark Myers wrote a letter to all oil and gas unit operators in the state notifying them that the department would be asking for new information in future development plans. When a brief general reference to BP’s work on major gas sales in the Prudhoe Bay plan did not suffice, Feige responded with the more specific April 11 request. She said in an interview that the division expected the new information to be “pretty broad-brush responses” to help the state establish baseline knowledge about how the operational transition from oil production to major gas sales from the Slope fields would work. Unit operators typically must submit development plans 90 days prior to the annual plan expiration date. The 2015 Prudhoe Bay plan expires June 30. Development plan years start and end based on when the unit in question was formed and thus do not align with the calendar year. Look for updates to this story in an upcoming issue of the Journal. Elwood Brehmer can be reached at [email protected]

BP corrects 20K-barrel error in Prudhoe production estimate

BP is asking the state to correct a 20,000-barrel per day error in its 2016 production estimate for the Prudhoe Bay oil field. The company submitted a letter to the Division of Oil and Gas May 2 stating the production forecast range included in the 2016 Prudhoe Bay Plan of Development submitted March 31 is off by 20,000 barrels per day for what BP actually believes its average daily production from the field will be this year. BP is the Prudhoe Bay operator for the field’s other working interest owner companies, primarily ConocoPhillips and ExxonMobil. The original development plan stated the average total crude and condensate production rate from Prudhoe is estimated at 137,000 to 176,000 barrels per day in 2016, which would be a 20,000 to 60,000 barrel decrease from the more than 196,000 barrels per day the field produced last year, according to the plan document. The corrected 2016 forecast in the May 2 letter is 157,000 to 196,000 barrels of oil and condensate per day — a forecast range of flat production to a decline of 40,000 barrels per day year-over-year. Additionally, BP asked to amend its expectation for natural gas liquid, or NGL, production from Prudhoe from 29,000 to 37,000 barrels per day in the original plan to 36,000 to 45,000 barrels of NGLs per day. BP declined to comment on how the error occurred; however, sources close to the situation said it was simply a “typo” and that the lower forecast numbers were in prior year development plans and mistakenly were not revised in the 2016 plan. The development plan states BP’s active rig time will be “significantly reduced compared to 2015 due to the sharp reduction in oil prices” over the past couple years. Well workover activity will be cut as well, from 27 workovers in 2015 to just 4 this year, according to the development plan. BP announced in March that it would be cutting the number of drill rigs working in the Prudhoe Bay field from five to two this year because of the sustained oil price drop. Elwood Brehmer can be reached at [email protected]

AG hires lawyer who advised threatening leases

A former Alaska Gasline Port Authority legal consultant with historically hard line views on producers’ obligations under state oil and gas leases is now working for the Department of Law on those issues. Mark Cotham, a Houston-based attorney, was hired by the Department of Law in July 2015 as a contract attorney with expertise “in obligations of oil and gas lessees to develop leases,” according to his contract with the department. His original contract, not to exceed $65,000, ran through June 30, 2016; it was amended earlier this year to run through June 30, 2017, with a $130,000 limit. Cotham testified to the Legislative Budget and Audit Committee in 2005 that he was “struck” by the lack of discussion about the producers’ requirement to develop and sell natural gas from state leases in his research into the relationship between the State of Alaska and the North Slope producers. At the time, the state was working to advance an ultimately unsuccessful North Slope natural gas project under Stranded Gas Development Act. In November 2006, Cotham wrote an opinion column for the Juneau Empire entitled “My turn: Speaking in terms Big Oil can grasp: Lease cancellation threats may get companies talking.” With the state administration in flux during the 2006 election season, he described his views on how the companies should be treated by whomever led a gasline project for the state. “The central point that the new gas pipeline negotiator must make to the oil companies is that they do not have the legal, let alone the moral, right to hold Alaska’s gas hostage to their own profit targets,” Cotham wrote. “If getting that point across involves a lawsuit to cancel their leases, so be it. If it takes a few years to get a court determination, that is certainly shorter than the oil companies’ proposed ‘study’ under the current proposal. And after that wait, Alaska stands a very good chance of owning, ‘lock stock and barrel,’ the North Slope leases and 100 percent of the gas.” Gov. Bill Walker is a former project manager and general counsel for the Alaska Gasline Port Authority, which Cotham was representing in his 2005 testimony to the Legislature. The authority was formed to develop a gasline from the Slope to Valdez for in-state use and export. Attorney General Craig Richards is a former attorney in Walker’s law firm and for the authority. Walker’s chief of staff Jim Whitaker is a former mayor of Fairbanks and former chair of the authority. Whitaker also co-authored the sponsor statement for a 2006 ballot measure to institute a reserves tax on North Slope gas as a means to spur development. Walker floated a gas reserves tax before last November’s special session but withdrew the idea soon after. In a Jan. 14 letter, now-retired Department of Natural Resources Commissioner Mark Myers wrote a letter to BP Alaska officials informing the company that the department wanted information regarding efforts to market oil and gas from the Prudhoe Bay unit included in future unit development plans. Division of Oil and Gas Director Corri Feige said in an interview that similar letters were sent to all unit operator companies in the state because it is a priority of the administration’s to have the information for possibly developing gas for instate use. BP’s Prudhoe Bay Plan of Development submitted March 31 focused mainly on immediate drilling plans and included a general statement that, “Major gas sales (MGS) from Prudhoe Bay remains depended upon a number of factors, including market demand and the availability of an acceptable offtake project. In the meantime, the Prudhoe Bay unit working interest owners will continue to use gas to enhance and accelerate oil recovery and for (natural gas liquids) production for shipment through TAPS or use in enhanced oil recovery operations.” Feige followed with an April 11 letter to BP stating the Prudhoe Bay development plan is “not sufficient to allow the division to understand how the (working interest owners) plan to achieve an MGS.” The letter also stated that the division could not consider the plan complete from a regulatory standpoint until it received additional information. The letter subsequently requested detailed information regarding commercial agreements being negotiated for natural gas sales from the Prudhoe unit as well as “the commercial terms under which each (working interest owner) is offering to make resources available for long-term sale, including: the estimated volumes to be delivered, the pricing terms, the location at which title to the gas and the associated risks of loss will change, and the condition of the gas at the time of delivery.” In recognition of BP’s statement that the working interest owners preferred to do their marketing individually, the Oil and Gas Division asked for responses to the April 11 letter from BP as the Prudhoe operator and ConocoPhillips and ExxonMobil to be submitted by May 1. That deadline was extended one day to May 2. The Journal submitted a public records request to the division for the publicly available portions of the producers’ responses May 3; the request was not granted as of press time for this story. State agencies have 15 business days to respond to such requests. Look for updates to this story in an upcoming issue of the Journal and at www.alaskajournal.com. Elwood Brehmer can be reached at [email protected]  

LIO saga continues with vote to buy Midtown office space

Would the Legislature make for a good landlord? Most of the Legislative Council seems to think so. The council voted 12-1 on May 2 in favor of purchasing a Midtown Anchorage office building owned and occupied by Wells Fargo bank for $12.5 million and turning it into the Anchorage Legislative Information Office. According to documents from the meeting, which was mostly held in executive session, Wells Fargo would lease-back space on the ground floor of the four-story office building after the sale. The bank currently runs a branch out of the first floor and occupies space on the third and fourth floors of the 1500 West Benson Blvd. address. Legislative Council Chair Sen. Gary Stevens, R-Kodiak, now has 60 days from the vote to negotiate a deal with Wells Fargo, per the council motion to approve the purchase. Barely a month prior, the council voted 13-1 to purchase the current Downtown Anchorage LIO for $32.5 million, a vote that seemingly signaled an end to the self-inflicted political melodrama that has been fueled by public outcry over the terms of the rental agreement approved in 2013 by then-Legislative Council chair and now outgoing Anchorage Republican Rep. Mike Hawker. Minority caucus members in both chambers of the Legislature have also jumped on the criticism bandwagon, contending the $3.3 million per year lease rate for the Downtown LIO is exorbitant at a time when the state is cutting services from nearly every agency to mitigate a $4 billion budget deficit. Ample criticism has also stemmed from the procurement process used to reach the deal that spurred construction of the Anchorage LIO. While a formal competitive-bid process was not used, Anchorage real estate developer and managing member of the building owner group Mark Pfeffer has repeatedly noted that the council requested proposals for LIO space numerous times over several years. When office space compatible with the Legislature’s needs for size, location, public access and parking among other requirements was not offered, the six-story, $44.5 million building custom-made for legislators was erected. Wells Fargo funded the part of the construction loan for the LIO built in 2014 along with Northrim. The construction loans were eventually consolidated into a single longterm note by EverBank based in Jacksonville, Fla. If Wells Fargo would stay as a tenant in the Legislature’s building it could generate up to $225,000 per year in rent and moving Legislative Audit staff into the building when the agency’s lease expires in 2022 could save another $53,000 per year, according to council documents. At the same time, buying the building for $12.5 million means the Legislature would eat its $7.5 million equity investment in the current LIO. Including the first year’s rent through May 31, the Legislature’s outlays for LIO space Downtown and at the Wells Fargo building would top $24 million. Staff for Stevens circulated an informal memo to all 60 legislators dated April 7 that included a dozen “bullet points” as to why the council agreed to buy the current Anchorage LIO for $32.5 million. Among the reasons for the deal are the points that it would meet the criteria of a December motion because it is financially comparable to the cost of moving to the nearby state-owned Atwood Building, which houses executive branch agencies. The memo also states that, “Buying the building honors our commitment with the owners of the building,” and “It alleviates the concerns by the business community and investors about the state backing out of a lease and a possible downgrade of the state’s credit rating.” When the council first considered moving from the LIO to the Atwood Stevens and other legislators said they believed they could do so without recourse because contracts with the state contain a “subject to appropriation” clause that essentially voids the contract if the Legislature does not fund it. Administration Commissioner Sheldon Fisher told the council March 31 that much of the space legislators thought they could move into at the Atwood would not be available until January 2018. The sudden about-face was spurred by Gov. Bill Walker threatening to veto a purchase of the Downtown Anchorage building, which was included in the Senate version of the capital budget as a $32.5 million line item appropriation. The Legislative Council’s May 2 motion to move on the Wells Fargo property directly cited Walker’s veto stance on the $32.5 million LIO purchase. The Associated Press reported April 14 that Walker said buying office space doesn’t jive with the state’s financial situation. He was less definitive during an April 27 press briefing, saying he had been talking with legislators about the LIO situation and that it was “too soon to respond” to a question regarding whether he would veto any proposed building purchase. An Alaska Superior Court judge voided the Legislature’s 10-year lease on the building in late March, ruling the council violated state procurement code by not opening the project — deemed by the court to be new construction and not a remodel of the former smaller LIO on the site — to bids. However, the state has been found liable for government contractors’ expenses in historical cases in which agencies breached procurement procedure and private firms executed work on the reliance that the state handled its business properly. Pfeffer has indicated that the LIO building owner group, 716 West Fourth Avenue LLC, would sue the Legislature if it walks away from the building. 716 first proposed to sell the property for $37 million to recover its cost in the project, according to Pfeffer, but ultimately agreed to a $32.5 million price. “We did what the Legislature asked us to do. Now we’re just asking them to honor their commitment,” Pfeffer said in an interview. A December 2014 subordination and non-disturbance agreement needed for EverBank to approve long-term financing for the LIO and signed by Pfeffer, Hawker and Legislative Legal Services Director Doug Gardner states that the “tenant shall not consent to any termination or cancellation of the lease without lender’s prior written consent.” Rep. Sam Kito, D-Juneau, who voted to approve the Downtown Anchorage LIO purchase and penned an op-ed in his hometown newspaper the Juneau Empire justifying the decision, was the only “no” vote on the Wells Fargo purchase motion. Before the vote he stated concerns about taking action on one property while possibly being exposed to a lawsuit over the Legislature’s possible financial obligation on another. The Anchorage Downtown Partnership, a non-profit focused on generally improving the economic and livability qualities of the city’s core, sent a letter to Stevens May 2 urging the council to keep the LIO where it is because moving elsewhere would not match the city’s land use plan to have local, state and federal offices in the Downtown business district. The Midtown Wells Fargo location would put the state in conflict with local planning policies and subsequently violate state statute as well, “which directs the State of Alaska to ‘comply with local planning and zoning ordinances and other regulations in the same manner and to the same extent as other landowners,’” the letter states. The LIO is the home office for 25 Anchorage legislators and is often the de-facto meeting place for hearings when the Legislature is not in session. It substituted as the capitol building last spring when the Republican-led Legislature ignored Walker’s demand that a special session to resolve budget issues be held in Juneau. Instead, legislators “gaveled out” of the Juneau special session called by Walker and reconvened in Anchorage.  

Delegation wants repeal of regs aimed at Native contracts

Rep. Don Young is trying again to make a small change to federal code that he says will have a big impact on many Alaska Native corporations doing business with the federal government. The changes Young is seeking would repeal special criteria the federal agencies are required to consider when justifying sole-source government contracts totaling more than $20 million to Alaska Native corporations and other small businesses. That language would be replaced by existing and widely used criteria found in the 1984 Competition in Contracting Act, which Young contends is better understood and easier to apply. Young’s proposal was included as an amendment to the 2017 National Defense Authorization Act, which moved out of the House Armed Services Committee April 28. The current five-step justification process requires federal agencies to cite their authority and need to go outside the standard competitive bidding process was added to the 2010 Defense spending authorization as Section 811 of that bill. Young said in an April 29 release from his office that Section 811 has led to “major inequities” for Native contractors. “What was sold as a good governance measure in the Senate has led to the discrimination and mistreatment of Native community-owned businesses. The heightened level of scrutiny required by Section 811 is found nowhere else in the federal government, and has resulted in the net loss of jobs, more than 60 percent decline in revenue from these contracts and a frightening layer of bureaucratic red tape,” Young said. Among the regional corporations, 28.5 percent of their total revenue was from 8(a) contracting in 2014 compared to 42.9 percent in 2010. Subsidiaries of Alaska Native regional corporations and Native village corporations are often first in line for government contracts under the Small Business Administration’s 8(a) Business Development Program. The program aims to help “socially and economically disadvantaged” small business owners by allowing them to receive sole-source government contracts generally capped at $6.5 million, according to the SBA. However, agencies are allowed to award sole-source contracts of any size to Native-owned corporations. It is Young’s third attempt to clarify or repeal Section 811 since 2013. His amendments to the 2014 and 2016 Defense spending bills were pulled during negotiations with the Senate. Alaska Native Village Corporation Association Director Keja Whiteman said in a formal statement that the group supports Young’s effort to repeal Section 811. “The passage of Section 811 has been detrimental to the already heavily regulated and highly scrutinized Alaska Native corporations and Native 8(a) businesses,” Whiteman said. Sens. Lisa Murkowski and Dan Sullivan echoed Young’s sentiment in statements from their offices. “Section 811 was ‘air dropped’ in the dark of night into a non-amendable conference report to accompany the 2010 National Defense Authorization Act,” Murkowski spokeswoman Jenna Mason wrote in an email. “The full Senate was never given an opportunity to debate, amend or cast an up or down vote on the provision. This is the worst sort of process and was undertaken deliberately to silence the voice and vote of Indian Country supporters in the House and Senate.” Sullivan’s spokesman Mike Anderson noted the sole-source justification provision was implemented before he was in the Senate and said he supports language to mitigate the “harmful effects” Section 811 has had on Native 8(a) contracting opportunities. “Sen. Sullivan is committed to using his position on the Senate Armed Services Committee to attempt to correct this problem,” he wrote. Missouri Democrat Sen. Claire McCaskill has led a push in Congress in recent years to get increased oversight of Alaska Native regional corporations, particularly in regards to the companies’ business with the federal government. She argues that much of the money awarded to the corporations through the 8(a) program does not reach the corporate shareholders as intended. The 12 Alaska Native regional and smaller village corporations were established as part of the 1971 Alaska Native Claims Settlement Act. Many corporation subsidiaries have been established as small businesses to specialize in government contracting for construction, IT and operations management services among others. A comparison of Section 811 sole-source justification requirements and those in the Competition in Contracting Act by a 2012 Government Accountability Office report found the criteria to be rather similar; the biggest difference was that Section 811 requires “a determination that the use of a sole-source contract is in the best interest of the agency concerned.” The same December 2012 GAO report concluded the number of $20 million-plus 8(a) contracts issued declined after the justification requirement change because apparent confusion among agencies as to exactly when the Section 811 criteria applied. According to the report, the number of sole-source contracts to 8(a) businesses fell from an average of about 50 per year from 2008-2010 to about 20 per year after enactment of Section 811 in 2011. Another GAO report requested by McCaskill and released March 21 — titled “Alaska Native Corportions: Oversight Weaknesses Continue to Limit SBA’s Ability to Monitor Compliance with 8(a) Program Requirements” — found that 344 Alaska Native corporations and subsidiaries were still awarded roughly $4 billion in 8(a) federal contracts during the 2014 fiscal year, or nearly a quarter of the $17 billion in total government spending that went to almost 5,600 businesses in the program nationally. Of that $4 billion, about $3.1 billion went to six Alaska Native corporations and their subsidiaries according to Bloomberg’s annual list of the 200 leading federal contractors in fiscal year 2014. The six Alaska Native regional and village corporations in the top 200 were: Arctic Slope Regional Corp., No. 75 at $793 million; NANA Regional Corp., No. 85 at $707 million; Afognak Native Corp., No. 107 at $491 million; Chenega Corp., No. 119 at $441 million; Chugach Alaska Corp., No. 138 at $384 million; and Bristol Bay Native Corp., No. 142 at $363 million. Elwood Brehmer can be reached at [email protected]  

Credit legislation hearings canceled as negotiations continue

It has been three weeks since legislation to scale back Alaska’s oil and gas tax credit program took a big step backwards to the House Rules Committee. In the meantime Rules chair Rep. Craig Johnson, R-Anchorage, has put forth two very similar versions of House Bill 247 that would all but eliminate the state’s refundable credit program. However, with no committee hearings on the bill since early April, little has been heard from legislators and the public has not had an opportunity to comment on legislation changes on the issue that has constipated the entire legislative process. Majority and Minority caucus leaders in the House have said they believe a tax credit compromise could jumpstart activity on the budget and other revenue proposals, but not much more. The Rules versions of HB 247 are the fifth and sixth iterations of the legislation first introduced by Gov. Bill Walker and, compared against adaptations from other House and Senate committees, most resemble what the administration had in mind at the start of the session. What started as concessions by the Republican-led Majority to appease Minority members and a group of Republicans that have joined them in believing prior committee versions did not cut the program far enough could have swung the other way if the concessions went too far for some in the Majority to support. Walker’s plan would have raised taxes and cut the state’s annual credit obligation by upwards of $500 million per year by fiscal year 2018, according to the Revenue Department. The Rules Committee’s proposal could have nearly a $300 million per year benefit to the state — or detriment to industry — by the time it is fully implemented in 2020, the department estimates. Drastically cutting the oil and gas tax credit program that has become the state’s third largest budget line item is a foundational piece of the administration’s New Sustainable Alaska Plan to solve the $4 billion budget deficit by fiscal year 2019. Regardless of the prospective savings from cutting the industry incentive program, the state is still expected to owe about $775 million during fiscal 2017 for credits currently being earned by companies. The operating budgets passed by the House and Senate currently fund just a fraction of that obligation, meaning hundreds of millions of dollars more will have to be added to the final budget whenever the credit stalemate is resolved. Alaska Oil and Gas Association CEO Kara Moriarty said in an interview her trade association has answered questions from legislators that have asked for feedback on the latest bills and that she is just waiting to testify whenever the next committee hearing on HB 247 might be. The industry has pushed back against changes to the program at a time when oil prices are at best near the current cost to produce a barrel of North Slope crude — about $46 per barrel, according to the Revenue Department. Moriarty said the numerous changes to oil tax policy, whether supported or opposed by the industry, have at least been rooted in a principle with an ultimate goal in mind, which is missing this time. “(Lawmakers) are trying to set a policy to fill a budget gap and for us, we’re just waiting,” she said. Increasing taxes when companies are already laying off significant chunks of their workforce will do little more than lead to decreased oil and gas production in the state, industry representatives continue to emphasize. The administration and legislators pushing for the changes need to ask, “What do you want Alaska to look like five years from now, 10 years from now?” Moriarty said. “It’s not a political issue for us. Whatever the policy is, we will make an economic decision.” Released May 2, the latest Rules HB 247 would close the Cook Inlet credit program to new entrants at the end of 2016. Companies with oil and gas production in the Inlet basin during 2016 would still be eligible for fading capital expenditure credits that would be terminated at the end of 2018. State subsidies for natural gas exploration and development in the Inlet have largely been credited with securing Southcentral’s energy supply in recent years. Leaders of several of the region’s utilities Credits for exploration in “Middle Earth” Alaska— areas of the state other than Cook Inlet or the North Slope — would be maintained. The North Slope refundable Net Operating Loss credit would also terminate at the end of 2016 for all companies except the smallest producers. Companies with less than 20,000 barrels per day of production could continue to receive the 35 percent NOL credit through 2019. Ending the refundable NOL credit would push companies to deduct annual operating losses from future tax liabilities, thus establishing a true tax “floor” by not allowing deductions to reduce a company’s tax obligation below the 4 percent minimum production tax. The Department of Revenue estimates a 4 percent minimum production tax could raise $100 million or more per year in tax revenue once the NOL is fully eliminated. Legislators on both sides of the debate have conceded the impact of refundable NOL credits on the minimum tax during low oil price periods — such as now — was not considered while the industry-supported oil tax reform known as Senate Bill 21 was vetted and passed in 2013. At that time oil prices were consistently near $100 per barrel. Elwood Brehmer can be reached at [email protected]

MEA inks deal with Hilcorp for flat rate, opt out

Matanuska Electric Association’s latest natural gas supply contract has two unique characteristics designed to benefit the utility. The contract with Hilcorp Energy, the dominant producer in Cook Inlet, is for all of MEA’s projected gas demand from April 2018 through March 2023. At an estimated annual demand of a little more than 6 billion cubic feet, or bcf, of gas per year, the contract covers about 32 bcf of gas sales over the five-year term. It was submitted to the Regulatory Commission of Alaska April 19 and is a tentative deal pending the commission’s approval. MEA General Manager Tony Izzo highlighted in an interview that the $7.55 per thousand cubic feet, or mcf, of gas price not only should save the co-op utility’s members $3 million in the first year, but also that the price is consistent regardless of how much gas MEA needs on a given day. “What I’m excited about in this contract is I pay $7.55 for everything. I have no swing gas premium,” Izzo said. “Our customers will pay that price for the lowest demand day and the highest demand day.” It has basically been standard practice for recent Cook Inlet gas supply contracts to include a base load price for the majority of a utility’s demand. Additional gas needed mostly during cold weather and dark winter months is then sold at a premium price that can be as much as 50 percent higher than the base load price for emergency, or needle peak, supply. Hilcorp Energy declined to comment on the terms of the gas supply contract with MEA. Enstar Natural Gas Co., the region’s largest natural gas buyer, agreed to a contract in February through early 2023 with Hilcorp for a first year weighted average price of $7.56, which includes premium sales. That deal will save Enstar customers $14 million in the first year of the contract. Izzo said MEA’s deal provides price certainty to its customers who won’t see feedstock fuel prices go up at the same time they are using more electricity. The cost savings are the result of a price drop from the $8.03 per mcf base load price MEA and most Cook Inlet gas customers will be paying under contracts with prices set by the 2012 Consent Decree that expires at the end of 2017. The Consent Decree deal was reached by the Attorney General’s office and Hilcorp and capped Inlet gas prices through 2017, thus allowing Hilcorp to purchase gas and oil interests from Marathon and Chevron and become the majority gas supplier in the basin in late 2012. MEA and Hilcorp agreed to a 2 percent annual price escalator after the first year $7.55 per mcf price. The Consent Decree allows for a 4 percent annual price increase. The deal also gives MEA a partial “out clause” that it can exercise on up to 20 percent of its gas demand. “For about 20 percent of my supply, if the market changes and hopefully (another producer adds supply) and the price is attractive I can notify Hilcorp at any time before or during this contract and say, ‘I’m going to exercise the turndown option,’” Izzo said. However, he noted the price from a new supplier would have to be substantially less than the current contract price because Hilcorp has the right to add 25 cents per mcf to MEA’s remaining contracted demand if the turndown option is used. Similar to what Enstar officials said when their contract went to the RCA in February, Izzo said the five-year term is a compromise between supply security and encouraging diversity among producers. He thanked Hilcorp for its work to increase gas supply from mature Inlet fields and noted that just a few years ago utilities couldn’t any contracts for longer than two years. The leaders of both utilities said Hilcorp was willing to agree to longer-term contracts. “I’m real happy with the price but at the same time I really want the market to grow; I want to have an alternative supplier; I want to diversify the portfolio and I want to see prices go down so how do I do that?” Izzo surmised. “I stick with a five-year term. It’s not forever but I was able to get this turndown option and hopefully one of these (other producers) will get some cash flow off that.” Elwood Brehmer can be reached at [email protected]  

State wants gas sale info for Prudhoe plan; owners estimate 20K-60K barrel decline

Editor's note: BP submitted a letter to the Division of Oil & Gas May 2 correcting its decline estimate from 20,000 to 60,000 barrels per day to 0 to 40,000 barrels per day. The state Division of Oil and Gas wants significantly more information from Prudhoe Bay field operator BP and its fellow working owners on how a scaled-back work plan for this year could impact prospects for a gasline down the road. Oil and Gas Director Corri Feige wrote a letter to senior BP Alaska officials April 11 asking more than a dozen technical questions related to a major gas sales project including drilling plans, management of carbon dioxide pulled from Prudhoe natural gas, gas balancing agreements and efforts to market the gas. BP’s 2016 Prudhoe Bay Plan of Development, or POD, submitted to the division March 31 included its estimates for production decline after it idles several rigs and reduces its well workovers this year. BP stated the lost drilling time could result in a production decline of between 20,000 barrels and 60,000 barrels per day. The Plan of Development focuses on drilling work for oil recovery but only briefly and very generally touches on preparing for gas offtake, currently planned to support the Alaska LNG Project. AK LNG is a $45 billion-plus project involving the State of Alaska and major North Slope producers BP, ConocoPhillips and ExxonMobil who are the working interest owners at Prudhoe. “The (Prudhoe Bay Unit) working interest owners will continue to evaluate viable plans and incorporate into the current plan of development to further optimize gas and oil recovery, and to address facilities, equipment, wells and operational changes to position for major gas sales,” the development plan states. Feige indicated that the division wouldn’t approve the plan without the additional information it requested, writing that “absent this further detail, the Division cannot evaluate whether the POD meets regulatory critieria.” The letter asked for responses by May 1. Oil and gas unit annual development plan deadlines are based when the unit was originally formed and therefore do not follow a strict calendar year. Now-retired Department of Natural Resources Commissioner Mark Myers sent a letter to unit operators across the state in January notifying them that future unit development plans will need to include the additional information. Myers wrote that DNR is “working proactively to ensure maximum development and monetization of Alaska’s energy resources.” Consequently, the state needs to understand how all hydrocarbons available for offtake are being used, sold within the state or prepped for future sale, according to Myers. Feige said in an interview that it is the administration’s priority to use that information to determine if there is gas that could be captured for in-state use. Commercially sensitive information would be kept confidential, she added. Anything learned from Cook Inlet basin natural gas producers could be used to “think outside the box” about how the state can possibly help find or generate new markets for Inlet gas, according to Feige. Limited demand for Inlet gas has been the primary impediment to increased production from the basin in recent years and led to fears of supply shortages in 2012. The division is anticipating “pretty broad-brush responses” to set a baseline of information that can be added to each year, she said. “For the state and certainly for the division it’s about understanding the resource in a unit that may be available, timeframes, maximizing the oil and when do we start looking at and thinking about those future production resources,” Feige said. The Journal obtained the letters and development plan late April 26 and a BP Alaska spokesperson could not be reached for comment in time for this story. Regarding marketing, the state asked BP to provide “the identity of the parties with whom the current commercial agreement(s) are being negotiated, or with whom each WIO intends to have substantive discussions regarding the marketing of unit hydrocarbons including unit gas, and the commercial terms under which each WIO is offering to make resources available for long-term sale, including: the estimated volumes to be delivered, the pricing terms, the location at which title to the gas and associated risks of loss will change, and the condition of gas at the time of delivery.” Feige called specific references in the April 11 letter to marketing efforts for major gas sales an “unintended consequence” of wording, noting that the original state lease forms grant lessees rights for exploration, development, production, process and marketing of oil and gas from the lease area. DNR and the division attempted to stay consistent with the lease language in their request and are not trying to use regulatory authority to gather information for the state’s role in the Alaska LNG Project. “The existence of that firewall between the Division of Oil and Gas and the AK LNG project is absolutely rock solid and it has to be,” Feige said. “We are absolutely prohibited from discussing, sharing information, etcetera and we obviously at the division, we’ve got to live hard and fast by that firewall because the work that we do is built on relationships and it’s built on a whole lot of trust.” The correspondence between the state and BP references “major gas sales” but not a specific project to sell gas. She said the division has been in contact with unit operators to clear confusion about exactly what information it wants going forward. “It’s an iterative process and what (BP) submitted the first time just lacked a bunch of that technical information about how do we manage the field to get (to major gas sales)” Feige said. Prudhoe production drop The Prudhoe Bay development plan also lays out BP’s expectations for how its idling of three drill rigs will impact production from the country’s largest oil field. BP projects the reduced drilling time — 3.8 rig years in 2015 to 1.6 rig years in 2016 — will result in a production decline of 20,000 barrels to nearly 60,000 barrels of oil per day from the Prudhoe Bay field. The nearly 40 year-old field produced an average of 196,400 barrels of oil per day in 2015. A rig year is the cumulative time drilling rigs are operating in a given field. Two rigs operating for 182 days each, for example, would roughly equal one rig year. Well workover activity will be cut as well, from 27 workovers in 2015 to just 4 this year. Unsurprisingly, BP cited the current price environment as the reason for reducing activity in the field. The company announced in early March that it would reduce the number of rigs working at Prudhoe from five to two this year. Companywide, BP reported a $1.2 billion loss from production activities in the first quarter. It’s average first quarter sale price for Alaska North Slope crude was $34 per barrel. The current average cost to produce and ship North Slope oil is about $46 per barrel, according to the state Revenue Department. The Department of Revenue’s latest production forecast released April 7 does not appear to include the expected Prudhoe decline detailed in the development plan submitted to the Division of Oil and Gas March 31. The preliminary spring forecast released March 21 projected daily North Slope production to average 517,700 barrels per day in fiscal year 2016 and 507,100 barrels per day in 2017. The revised April 7 forecast actually increased expected 2016 production to 520,200 barrels per day and kept the 2017 forecast at 507,100 barrels. The 2017 state fiscal year starts July 1, so a drop in calendar year 2016 production would likely show up in both fiscal year forecasts. Department officials said they could not discuss specifically what information the forecast is based on to air on the safe side of confidentiality requests from the companies, but said the forecast is an aggregate of what companies expectations are. Elwood Brehmer can be reached at [email protected]

Tax credit rewrite hits fifth iteration amid impasse

Make that five distinct versions of oil and gas tax credit legislation this session. The House Rules Committee took its swing at hitting the “sweet spot” on a tax credit bill when Rules chair Rep. Craig Johnson, R-Anchorage, released the latest iteration of House Bill 247 on April 26, day 99 of the 90-day session. The Rules bill makes the most drastic cuts to the credit program of the various legislation introduced in committees. It could save and generate up to $365 million annually by fiscal year 2021, according to a Department of Revenue analysis. That is second only to the original bill put forward by Gov. Bill Walker’s administration, which is projected to improve the state’s balance sheet by about $500 million at most. Milder committee versions of credit revisions put forth in the House and Senate would cut $50 million to $150 million from the program after several years of phased reductions. Regardless of prospective savings, Johnson and administration officials have noted the state is still on the hook in fiscal 2017 for about $775 million in refundable credits companies are expected to earn prior to any program changes taking effect. The vast majority of that sum also still needs to be added to the operating budget. An impasse between the Majority and Minority caucuses in the House centered on the tax credit overhaul has essentially stalled all other important work in the Legislature, even in the Senate where that Majority holds 16 of 20 votes. Without an amenable credit bill, the Democrat-led Minority will not approve a draw from the Constitutional Budget Reserve savings account, which requires a three-quarters vote from both chambers of the Legislature, needed to pay for the fiscal year 2017 budget. Visible progress on the budget and this session’s biggest single project —establishing a sustainable budget draw from the Permanent Fund Earnings Reserve account — has slowed as well. Minority members have stressed that the state should not continue to pay upwards of $700 million per year to the oil industry while significantly cutting education and rural assistance programs to shrink a $4 billion deficit. They have gained support from some Republicans as well, notably Homer Republican Rep. Paul Seaton, who is leading a caucus of Majority members bucking the leadership. More conservative — at least in regards to this issue — Republicans have noted that any money the state still has to spend is thanks to the oil industry, which historically has funded nearly 90 percent of the state’s budget. Seaton mostly sided with Minority Democrats when amendments to the House Resources version of HB 247 were considered. He also led the push to oppose a Finance Committee version HB 247 on the House floor earlier in April. Enough House Majority members didn’t think the bill that reached the floor cut the program far enough that the bill would not have passed. House Speaker Rep. Mike Chenault then moved the bill to the Rules Committee for another try. House leaders on both sides have said an oil and gas tax credit compromise could trigger quick action on those remaining bills needed to finish the session. Industry representatives from companies and trade associations insist any change to the state’s tax credit system or underlying tax structure will hurt production and increase job losses in the industry at a time when the average cost of production and transport for North Slope oil — about $46 per barrel, according to the Department of Revenue — exceeds market prices. The Labor Department estimates Alaska has lost about 1,800 oil and gas industry jobs over the past year. Walker said at an April 27 press briefing that he met with the Slope majors on April 25 to discuss the issues each side has with the proposed changes. The administration has also met with independent companies to find ways to incentivize their growth while reducing the expense to the state throughout the process, he said. “We’re in some big changes as far as what we can and can’t do, and what was business as usual not that many years ago is going to be very difficult this year,” Walker said. “We’re looking very closely at how to advance and make (tax credit) changes with a minimal impact, but we know there will be impact across the board with all companies.” Statewide, the Rules Committee version of HB 247 would annually cap the credits each company is eligible to receive at $85 million, on par with limits proposed in House Finance and Senate Resources committees. It would also end the transfer or sale of credits to companies with a production tax liability. Transferring credits between companies without production tax liabilities, namely small producers and explorers, would still be allowed. The Rules version is also the first since the administration’s to make public the companies getting refundable credits and how much they receive each year. Industry has railed against a more transparent credit program contending it could quickly devolve into disclosing confidential tax information that might even violate federal law. Minority legislators rebut that the state does not require companies to accept the credits they are eligible for; therefore allowing companies to choose if they want to take the incentives and subsequently disclose some information. Cook Inlet The Rules Committee took the ramping down of Cook Inlet capital expenditure credits in other committees a step further and eliminated them entirely by calendar year 2019. In the interim, only companies with oil or natural gas production from the Inlet basin by the end of 2016 would be eligible for the slowly vaporizing credits. Tied to that is language in the bill calling for a new Inlet oil and gas tax regime, and possible credit program, to be implemented by January 2019. Legislators have discussed the need to reexamine Cook Inlet oil and gas taxes in several years throughout the credit debate. While they do pay the state’s 12.5 percent royalty share, Inlet producers pay no oil production tax and a minimal production tax on natural gas. However, Inlet production is largely viewed as a means to a secure energy supply for Southcentral and not as revenue stream for the state. Oil production is about 17,300 barrels per day in Cook Inlet. The latest HB 247 would also eliminate the Cook Inlet Net Operating Loss credit at the end of 2017. North Slope There are two major changes for companies on the Slope pertaining to the Net Operating Loss, or NOL, credit and the Gross Value Reduction credit for “new oil.” The Rules Committee eliminated the 35 percent NOL credit right away at the end of 2016 for large producers and explorers. Small producers pulling less than 20,000 barrels per day would get the NOL credit through 2019. At that point the refundable NOL credit would shift to a more traditional deduction against future tax production tax liability. Changing the NOL credit to a deduction would truly “harden” the 4 percent production tax floor because deductions can take a liability to, but not through, the minimum tax like the refundable credit could. Legislators and their tax consultants have said Senate Bill 21 was intended to have a minimum 4 percent production tax, but oil prices low enough to allow NOL credits to pierce the floor were not even considered during the SB 21 debate of 2013. The administration’s proposal hardened the floor, but also raised it to 5 percent. House Finance reset the production tax floor at 2 percent. The other versions from the House and Senate Resources committees did not address the minimum tax for fears that hardening the floor would increase net operating loss obligations in future years. Revenue Commissioner Randy Hoffbeck said April 27 that there are concerns about how the Rules Committee addressed the NOL — that it would allow large producers to eventually deduct losses at low price points but leave explorers to absorb their full losses until they have production. Shifting the NOL to a simple tax deduction would also seemingly quell some of the fears about publicly reporting what companies are getting refundable tax credits. With the NOL credit as a refundable credit, it would be fairly simple to calculate a company’s yearly performance if its application of a 35 percent NOL credit is made public. Pulling the NOL from the list of refundable credits closes that avenue; a company’s deductions remain confidential. The 20 percent Gross Value Reduction for oil produced from new development would also sunset after 10 years of production. Currently, there is no statute of limitations on the GVR for new oil. Elwood Brehmer can be reached at [email protected]

Alaska Air Group adds to record profits with $184M quarter

Alaska Air Group Inc. didn’t miss a beat in the first quarter, posting yet another record profit of $184 million while hashing out a deal to buy Virgin America airlines. The Seattle-based parent company to Alaska Airlines and regional carrier Horizon Air grew its net income by more than 20 percent over the then-record $149 million profit it posted in the first quarter of 2015. The first quarter is traditionally the slowest quarter in the airline industry, but Air Group’s $184 million profit nearly matches the $186 million it netted in the last quarter of 2015, also a record. Its $842 million net income for 2015 was a full-year record as well. Overall, Alaska Air Group has defied the odds in a hyper-competitive and volatile business and posted six consecutive years of record profitability. Each quarter within those years has also been a record with very few exceptions. On April 4, the company announced a $4 billion deal to purchase San Francisco-based Virgin America, which Air Group executives hope will make Alaska Airlines the dominant carrier on the West Coast. Air Group CEO Brad Tilden said in an April 21 conference call with investors that Virgin and Alaska “share similar philosophies about building alignment with and taking care of our people and about putting customers first.” A vote by Virgin America shareholders on the deal is expected sometime in the second quarter, Tilden said. The parties hope to close the deal by the end of the year. The $184 million first quarter profit translates to diluted earnings of $1.46 per share. Alaska Air Group stock closed April 27 trading at $74.35 per share. Tilden said the company’s earnings per share are expected to outperform all but 36 companies in the S&P 500. Air Group’s 12-month return on invested capital, or ROIC, is 25.6 percent, which is more than three times its cost of capital, he noted. “As we look forward, our 15,000 employees are operating safely and they are taking care of our customers and each other,” Tilden said. “Our core business is strong and we’re seeing robust demand for our product. As a result, our business is producing the sort of returns you should expect from high-quality industrials.” Operating revenue was more than $1.3 billion for the quarter, up 6 percent year-over-year; fuel costs — the largest expense for most airlines behind personnel costs — were down 29 percent. Airlines worldwide have benefitted from continually falling fuel prices over the past 18 months and Alaska Air Group’s companies are no exception. However, Alaska Air Group has additionally focused on reducing costs to improve its balance sheet regardless of fuel prices, Chief Financial Officer Brandon Pedersen said during the April 21 call. This year will be the seventh year in a row that Alaska Air Group will reduce its operating expenses, according to Pedersen. Further, the company continues to improve its fuel efficiency by 1 to 2 percent each quarter, as it upgrades its Alaska Airlines fleet of Boeing 737s. Alaska Airlines’ 20 remaining and aging Boeing 737-400s will be replaced with 737-900ERs (extended range), which are 25 percent more fuel efficient, by the end of 2017. The company’s operational cash flow was $527 million for the quarter, Pedersen said, and it finished with nearly $1.6 billion in cash. “Even after adjusting for leases, we’re in a net cash position of almost $600 million,” he said. “Our (debt-to-capitalization), including leases, now stands at 26 percent. Our net cash position, the 95 unencumbered aircraft in our fleet, our investment-grade balance sheet, and our long track record of conservative financial management put us in a strong position to raise the capital necessary to fund the proposed acquisition of Virgin America.” Pedersen added that the company is working with potential lenders to finance the deal and initial results are “very encouraging” both to the number and diversity of interested lenders. The $2.6 billion cash deal also includes Air Group assuming nearly $1.5 billion of Virgin debt — collectively making a roughly $4.1 billion transaction. Even without the Virgin America deal, Alaska Air Group is growing. Tilden said as a whole the 41 markets its airlines have added over the past two years are profitable and producing returns higher than investment costs. Alaska was also one of the first domestic airlines to request federal authorization to start service to Cuba. In state, Alaska Airlines has announced plans to spend more than $100 million over the next couple years on a new hangar in Anchorage to house the larger 737-900s, as well as remodels to 11 terminals the airline owns across Alaska. Alaska Air Group also formed McGee Air Services in March. A wholly owned Alaska Airlines subsidiary, McGee will initially operate as a vendor to Alaska Airlines and compete for its service contracts in some markets. The plan is to expand to serve other airlines as the company develops. The name pays homage to Linious McGee, who, in 1932, founded McGee Airways in Anchorage — the company that ultimately became Alaska Airlines. Elwood Brehmer can be reached at [email protected]  

Point Thomson produces first condensates for TAPS

After a decade, a lawsuit that reached the Alaska Supreme Court, and $4 billion, Point Thomson is producing. ExxonMobil Alaska announced Friday morning via social media that the large North Slope natural gas field “is now officially online.” A $4 billion development located about 60 miles from Prudhoe Bay on the far eastern edge of the developed North Slope, Point Thomson holds about 8 trillion cubic feet of natural gas. It is for this reason that the field is a lynchpin to the $45 billion-plus Alaska LNG Project; it accounts for nearly one-fourth of the North Slope natural gas the project partners hope to export. “The successful startup of Point Thomson demonstrates ExxonMobil’s project management expertise and highlights its ability to execute complex projects safely and responsibly in challenging, remote environments such as the North Slope in Alaska,” ExxonMobil Development Co. President Neil Duffin said in release. “Our strong partnership with Alaskans and Alaska-owned companies played a critical role in helping to complete this major project. It further reinforces our commitment to pursuing the development of Alaska’s natural gas resources.” About 100 Alaska companies contributed to the development of Point Thomson, according to ExxonMobil. Point Thomson facilities will initially produce about 5,000 barrels per day of natural gas liquids, or condensates, that will ultimately flow through the trans-Alaska Pipeline System. Full condensate production is expected to reach 10,000 barrels per day after several months when an additional well is brought online, a release states. There are about 200 million barrels of usable condensates, which are products similar to kerosene or diesel. The natural gas condensates can be captured because Point Thomson is a high-pressure gas reservoir. When the pressurized gas is expanded in facility separators the liquids “fall out” and are easily collected, according to ExxonMobil project leaders. About 200 million cubic feet of natural gas per day will also be recycled and re-injected at full production as it waits for an export project. ExxonMobil is the field operator and majority owner; BP holds a 32 percent working interest and ConocoPhillips has a 5 percent interest in Point Thomson. First discovered in 1977, Point Thomson’s development is a saga that stretches back to former Gov. Frank Murkowski’s administration. The Murkowski administration pulled ExxonMobil’s Point Thomson leases in 2006, contending the company did not uphold its responsibility as a leaseholder to develop the field at the time. A subsequent lawsuit reached the state Supreme Court in 2012, but the state settled with the company in 2012 under former Gov. Sean Parnell before a court ruling. That settlement laid out the schedule that ExxonMobil developed the project under, which required first production by May 2016. Look for updates to this story in an upcoming issue of the Journal. Elwood Brehmer can be reached at [email protected]

MEA gets flat-rate deal with Hilcorp; members to save $3M in first year

Matanuska Electric Association’s latest natural gas supply contract has two unique characteristics designed to benefit the utility. The contract with Hilcorp Energy, the dominant producer in Cook Inlet, is for all of MEA’s projected gas demand from April 2018 through March 2023. At an estimated annual demand of a little more than 6 billion cubic feet, or bcf, of gas per year, the contract covers about 32 bcf of gas sales over the five-year term. It was submitted to the Regulatory Commission of Alaska April 19 and is a tentative deal pending the commission’s approval. MEA General Manager Tony Izzo highlighted in an interview that the $7.55 per thousand cubic feet, or mcf, of gas price not only should save the co-op utility’s members $3 million in the first year, but also that the price is consistent regardless of how much gas MEA needs on a given day. “What I’m excited about in this contract is I pay $7.55 for everything. I have no swing gas premium,” Izzo said. “Our customers will pay that price for the lowest demand day and the highest demand day.” It has basically been standard practice for recent Cook Inlet gas supply contracts to include a base load price for the majority of a utility’s demand. Additional gas needed mostly during cold weather and dark winter months is then sold at a premium price that can be as much as 50 percent higher than the base load price for emergency, or needle peak, supply. Hilcorp Energy declined to comment on the terms of the gas supply contract with MEA. Enstar Natural Gas Co., the region’s largest natural gas buyer, agreed to a contract in February through early 2023 with Hilcorp for a first year weighted average price of $7.56, which includes premium sales. That deal will save Enstar customers $14 million in the first year of the contract. Izzo said MEA’s deal provides price certainty to its customers who won’t see feedstock fuel prices go up at the same time they are using more electricity. The cost savings are the result of a price drop from the $8.03 per mcf base load price MEA and most Cook Inlet gas customers will be paying under contracts with prices set by the 2012 Consent Decree that expires at the end of 2017. The Consent Decree deal was reached by the Attorney General’s office and Hilcorp and capped Inlet gas prices through 2017, thus allowing Hilcorp to purchase gas and oil interests from Marathon and Chevron and become the majority gas supplier in the basin in late 2012. MEA and Hilcorp agreed to a 2 percent annual price escalator after the first year $7.55 per mcf price. The Consent Decree allows for a 4 percent annual price increase. The deal also gives MEA a partial “out clause” that it can exercise on up to 20 percent of its gas demand. “For about 20 percent of my supply, if the market changes and hopefully (another producer adds supply) and the price is attractive I can notify Hilcorp at any time before or during this contract and say, ‘I’m going to exercise the turndown option,’” Izzo said. However, he noted the price from a new supplier would have to be substantially less than the current contract price because Hilcorp has the right to add 25 cents per mcf to MEA’s remaining contracted demand if the turndown option is used. Similar to what Enstar officials said when their contract went to the RCA in February, Izzo said the five-year term is a compromise between supply security and encouraging diversity among producers. He thanked Hilcorp for its work to increase gas supply from mature Inlet fields and noted that just a few years ago utilities couldn’t any contracts for longer than two years. The leaders of both utilities said Hilcorp was willing to agree to longer-term contracts. “I’m real happy with the price but at the same time I really want the market to grow; I want to have an alternative supplier; I want to diversify the portfolio and I want to see prices go down so how do I do that?” Izzo surmised. “I stick with a five-year term. It’s not forever but I was able to get this turndown option and hopefully one of these (other producers) will get some cash flow off that.” Elwood Brehmer can be reached at [email protected]

ConocoPhillips to add wells at CD-5, will reach 16K b/d goal this year

Despite low oil prices, ConocoPhillips keeps drilling. The company announced Thursday morning that it has approved a plan to spend about $190 million to add another 18 wells and associated infrastructure to fully build out its new CD-5 oil development. ConocoPhillips has completed 10 of the 15 wells laid out in CD-5’s initial development plan. Production from the site began in October of last year. The more than $1 billion overall project was designed to accommodate 33 wells, meaning the latest approved drilling program will add another 18 wells. CD-5 is the company’s latest project in the Alpine field — on the western fringe of the established North Slope. ConocoPhillips expects CD-5 will hit its production target of averaging 16,000 barrels per day this year. “The additional drilling opportunities we’ve identified at CD-5 are a positive development that should increase oil production at Alpine,” ConocoPhillips Alaska President Joe Marushack said in a release. “The competitiveness of this next phase of CD-5 drilling was improved due to the investment climate resulting from the passage of (Senate Bill 21 in 2013). We want to continue to invest in production-adding projects like this.” The company expects first oil from the next phase of drilling to begin flowing in the fall of 2017. Oil and gas industry representatives in the state have emphasized during discussions in the Legislature about trimming the state’s oil and gas tax credit program that the cost of producing North Slope crude and getting it to market — approximately $46 per barrel — means companies are losing money at today’s prices. Alaska North Slope crude was selling for about $43 per barrel at the time of ConocoPhillips’ announcement. Earlier this year BP announced it is idling three drill rigs working in the Prudhoe Bay field and several smaller independent companies have slowed or delayed development projects, citing cash flow issues and the current price environment. Development work is also continuing on ConocoPhillips’ $900 million Greater Mooses Tooth No. 1 project, expected to bring another 30,000 barrels online at peak production, with first oil scheduled for late 2018. The company sanctioned GMT-1 late last year. Farther west than CD-5, GMT-1 would be the first production on federal land within the National Petroleum Reserve-Alaska. While within the NPR-A boundary, CD-5 is on an “island” of land owned by Kuukpik Corp. an Alaska Native village corporation. ConocoPhillips has a 2016 Alaska capital budget of $1.3 billion, down 5 percent from 2015 spending. That’s the smallest reduction of any area the company operates after it lost $4.4 billion in 2015, and is greater than its cap-ex spending in Alaska in 2012. Elwood Brehmer can be reached at [email protected]

Salaries spotlighted as session continues

Most state employees will give up some, but not all, pay increases in the latest round of union contracts before the Legislature for approval. Nearly 75 percent of executive branch employees will forgo cost of living allowance, or COLA, raises under the three-year agreements negotiated with the Labor, Trades and Crafts, Alaska State Employee, Confidential Employee and Mount Edgecumbe Teachers bargaining units. However, annual merit pay increases averaging 3.5 percent for an employee’s first five years of service and biannual “step” increases of about 3.25 percent for long-term employees remain under the proposed new contracts. The current bunch of contracts expire June 30, the end of the current fiscal year. The Department of Administration is also negotiating with the Alaska Public Employees Association, sometimes referred to as the supervisors union, which covers about 2,300 of the roughly 16,600 State of Alaska executive branch employees covered by collective bargaining. Administration Commissioner Sheldon Fisher said to the House Finance Committee April 19 that he feels the agreements are fair to both sides given the state’s $4.1 billion budget deficit. The total payroll for executive branch workers is roughly $1.2 billion per year, he said. “I do feel like each of these bargaining units came to the table prepared to make concessions,” Fisher said. “We as the state gave very little in turn to get those concessions.” The contracts, which generally have similar frameworks for the major components, also require employees covered by the contracts up for approval to take 15 hours of furlough time, which is equivalent to two working days per year. State workers will have the option to cash in accrued leave time to offset the furloughs, which will likely reduce the final savings. In a March 14 presentation to the House Finance Committee, the Department of Administration calculated the net savings per year from the furloughs minus the use of leave time spread over about 7,100 employees would be $1.4 million. Additionally, they require employees on the “economy” health insurance plan — about half of eligible state employees, according to Administration — to begin paying a portion of their premium costs. Those contributions gradually increase from 5 percent to 9 percent of premium costs over the three years of the contract. Health insurance for the nearly 9,000 employees in the State Employees Association, also known as the general government unit, is paid through a health trust and the state’s contribution to that trust is reduced for fiscal year 2017. The 27 Mount Edgecumbe state boarding school teachers are exempt from the furlough and insurance contribution changes. All told, Fisher said the health care contribution changes and furloughs should save the state about $6.5 million in 2017 over the previous contracts. If the contracts are rejected by the Legislature, the existing agreements remain in place and the projected savings would be lost, he said. Republicans on the committee questioned why the state agreed to continue the merit and step raises, which cost upwards of $20 million per year, given the budget situation. Fisher said the contract changes are usually incremental; the unions agreed to kill the COLAs, add furloughs and increase insurance payments in this round of contracts. He conceded, though, that the state needs to scrutinize who receives merit-based raises, which are awarded to all employees that achieve at least “acceptable” work performance reports. “This is an area (where) as an administration we need to do better,” Fisher said. “The reality is that as a state we’re not very effective in our performance management of our employees and it tends to be that a very, very high percentage of our employees, and I don’t know what it is but I would guess it’s over 95 percent of our employees earn their merit and step increases.” Still, Fisher noted that the state has succeeded in “flattening the curve” of pay increases above inflation. COLA, merit and step raises increased an average state employees’ pay by two-thirds under the contracts approved over the last 10 years, while inflation increased about 30 percent over that time. Without the COLAs — that are eliminated in the new contracts — average pay would have increased about 40 percent over the same period, according to the department. Fisher also emphasized that the general pay for state employees, particularly highly skilled or specialized employees, is below the market rates. More generous benefit packages tend to bring overall state compensation in line with market conditions, he said. Rep. Les Gara, D-Anchorage, said most everyone understands the state can’t be “very generous” with raises right now, but contended that just keeping up with inflation would likely drive away the state’s best workers. Anchorage Republican Rep. Craig Johnson introduced legislation April 18 that would eliminate merit and step raises until the price of Alaska North Slope crude oil averages $90 per barrel for a full fiscal year and subsequently limit the raises only to employees that receive “good” or higher performance ratings from their supervisors. A March 12 memo from Legislative Legal Services responding to a question from Finance co-chair Rep. Steve Thompson, R-Fairbanks, examining the role of the Legislature in collective bargaining, states that both the Alaska and U.S. constitutions limit the Legislature’s ability to insert itself into executive branch employee contract negotiations, likely making Johnson’s bill unconstitutional if passed. Union leaders have sent letters to their labor groups asking employees to speak out against the proposal, House Bill 379. Minority legislators have also said the do not believe the bill will move. “It is the Legislature’s role to review monetary terms agreed on by the parties and presented to the Legislature and either fund or not fund those monetary terms. If the Legislature does not fund the terms, the parties must renegotiate and present new terms at a later date,” the memo states. “Beyond this, there are legal and constitutional limitations on the Legislature’s role in collective bargaining. The state and federal constitutional prohibition of impairment of contracts may be the most substantial limitation. There may be other legal obstacles as well.” The funding of COLAs was a topic of debate during last year’s marathon series of special budget sessions. The Legislature ultimately agreed to fund the raises but cut state department budgets by roughly the same amount, $30 million. Departments decided to pay the raises and “ate” the difference through other budget cuts, according to Administration officials. Elwood Brehmer can be reached at [email protected]  

Audit: Port towns mostly handled state cruise tax properly

A state audit report released this month concludes more than $270 million in cruise ship passenger tax money collected since 2007 has been used appropriately by the vast majority of Alaska communities the ships visit, with one small exception in Skagway. The audit, conducted by Legislative Budget and Committee staff, uncovered an instance in the summer of 2013 when the Skagway Borough used $114,000 of cruise passenger tax funds to buy playground equipment for the borough’s elementary school. The auditors only examined how the state tax money has been handled; the separate taxes imposed by Juneau and Ketchikan were not reviewed. Those taxes are the subject of a lawsuit filed by Cruise Lines International Association Alaska against the City and Borough of Juneau in Alaska U.S. District Court on April 13 alleging the city has spent $35 million of its own head tax revenue on since 2001 on general government expenses and capital projects that don’t directly benefit cruise vessels or passengers. Because the cruise passengers are out-of-state visitors, the Commerce Clause of the U.S. Constitution requires that the local and state head tax money be spent on industry-related projects and expenses. The audit concluded that the Skagway spending on playground equipment was a misuse of the state tax revenue. The report states local officials believe purchasing the playground equipment was an appropriate use of the funds because it is used by visiting cruise passengers and the children of seasonal tourism industry workers. Skagway Borough Manager Scott Hahn, who did not hold the position in 2013, wrote in an April 7 letter responding to the report that Skagway intends to continue to be good stewards of the cruise passenger tax funds and that “the comments about our playground project will be kept in mind for the future.” Sen. Anna MacKinnon, R-Eagle River, requested the audit early in 2015 to determine if local governments were spending the state tax money properly or stockpiling it for other purposes. The State of Alaska levies a $34.50 per person “head tax” on each of the roughly 1 million passengers that disembark from a cruise ship in the state. However, vessels stopping only in Juneau or Ketchikan are essentially exempt from the state tax because the local head taxes levied by those communities can be credited against the state tax. State head tax revenue is then distributed to cruise port communities based on the number of cruise passengers that visit each coastal town, with few exceptions. The state head tax has generated $16 million to $18 million annually in recent years and $14 million to $15 million of that has been shared with local governments each year. In its lawsuit, CLIA Alaska is seeking an injunction to prohibit Juneau from imposing its head tax. Association leaders have indicated the group does not have an issue with how Ketchikan has handled its head tax funds. The complaint specifically cites a $10 million manmade island and life-sized whale statue Juneau is building partially with head tax funds as the latest example of misspent money, as well as $22 million in government operating expenses. The city touts the artwork as a tourist attraction, while the cruise association notes it will be nearly a mile from the cruise ship docks. Private contributions are funding a portion of the project, which is being built in conjunction with a $54 million overhaul of the city’s Downtown waterfront that includes two new floating docks to accommodate larger cruise ships. The City and Borough of Juneau has yet to file a response with the court. The state audit found communities have generally used the tax revenue shared by the state for allowable projects, but that some communities lacked the necessary documentation to easily assure the tax expenditures complied with state law. It also reports that the unspent balances of the shared tax funds held by communities to be reasonable based on efforts to complete the projects the tax money was appropriated to fund. Gov. Bill Walker introduced legislation this year that would eliminate the local head tax exemption from state law. The administration agreed not to push for the bills until the audit was released. At this point, the legislation appears dead this session, as it has not moved through the committee process. Cruise industry representatives have said the tax change would be pointless because the additional $15 million or so it would generate could not be used to pay down the state’s $4 billion budget deficit. The audit report concurs with administration officials who have said something needs to be done to at least close a potential funding gap created by the current tax law, which directs the state to share $5 with each of a vessel’s first seven ports of call, meaning the $34.50 tax could eventually be insufficient. The Commercial Passenger Vessel Fund has remained solvent since the tax was instituted in fiscal year 2007 because not all vessels call on seven ports. The report also notes that while the $8 per person Juneau and $7 per person Ketchikan local head taxes combine through the state tax exemption to reduce actual state revenue to $19.50 per passenger, the state is still required to share the $5 per passenger with those communities. Nearly all of the state’s cruise visitors stop in Juneau and Ketchikan and thus the state can share a combined total approaching $10 million per year in good years when Alaska sees about 1 million cruise visitors. “To date, (Commercial Passenger Vessel) receipts have been sufficient to fund the amounts required to be distributed to port communities,” the report states. “However, significant increases to the number of passengers that visit a high number of ports would threaten the solvency of the CPV Fund.” Elwood Brehmer can be reached at [email protected]

Mental Health Trust exploring Icy Cape prospect

The Alaska Mental Health Trust Land Office is evaluating a heavy mineral prospect near Yakutat that could change the course of the agency for generations. Icy Cape is a long stretch of beach owned by the trust at the entrance of Icy Bay that appears to hold world-class deposits of several heavy minerals, according to Trust Land Office Executive Director John Morrison. “It’s difficult to quantify the value of (Icy Cape) in terms of heavy minerals; it’s just mind boggling,” Morrison said in an interview. “There’s enough heavy minerals there to run a really large mine operation for over 100 years and we’re talking about hundreds of millions of dollars every year.” The minerals are literally grains in the beach sand on a parcel of coastline that stretches for more than 30 miles and totals roughly 48,000 acres, Morrison described. Trust officials stressed that the resource evaluations are preliminary, but early drilling samples of the “ore” — sand, really — indicate up to 40 percent of the ore is heavy minerals in the broadest delta area near the point of the cape. Specifically, the samples are roughly comprised of 20 percent epidote, 19 percent garnet and 0.5 percent zircon. Epidote and zircon are semiprecious gemstones. Garnet has also been used as a gemstone for hundreds of years, but more recently the hard mineral has been put to use as an industrial abrasive on sandpapers and in sandblasting applications. It is also used in water filtration; garnet’s small pores allow for the passage of liquid while catching some contaminants. “We would be the only source for garnets on the West Coast,” Morrison said. “Specifically, there’s all sorts of metrics and parameters that the buyers of those types of materials would want and our garnets are the best you could have in terms of the size of the crystals and the way they’re fractured.” The Icy Cape sands also contain gold concentrates of about 1.4 grams per metric ton, according to the early exploratory results. The sands are comprised of two sediment patterns coming from opposite directions, those materials that have eroded and washed down from the steep mountain faces above and sediments that tidal and wave action have pushed up to the shoreline. If the preliminary resource indications are proved on a larger scale, the minerals and metal in a tonne of Icy Cape sand could be worth $190 at current market prices, the Trust Land Office estimates. The Trust Land Office manages roughly 1 million acres of land across Alaska for resource development, the proceeds of which go to fund the Alaska Mental Health Trust Authority’s work to benefit Alaskans with mental health and addiction challenges. Morrison said the trust is conservatively projecting that a full-scale mining operation could process up to 250 tonnes per hour for 270 days each year; that adds up to more than $300 million in gross revenue per year for 100 years, he said. The operation would likely start on a much smaller scale, however, of about 50 tonnes per hour, Morrison said, which would require about a $50 million investment. As a passive landowner the trust could expect to see about 20 percent of the gross revenue from any mine, but Morrison said he would hope to retain control as a more active investor and take “substantially more” risk and subsequent reward from the project. Trust Land Office revenues have varied greatly over its 20-year existence, as money from timber and land sales and other resource projects has come and gone. Since 2011, its annual revenue has been between about $10 million and $16 million; even a minority share of a $300 million per year mine would dwarf that. The City and Borough of Yakutat would also see a bump in its tax revenue from an Icy Bay mine operation, he noted. The processing, or relative lack thereof, required of the sand adds to the positivity of the prospect. Extracting the gold and heavy minerals doesn’t necessitate the intensive milling or chemical leaching common in large metal operations, meaning Icy Cape should theoretically be relatively simple to permit, according to Morrison. “It’s the sand. It’s placer mining. You literally just take a backhoe and scoop the sand into your separator as fast as you can and you get these various compounds,” he described. The Trust Land Office has held the Icy Cape property for almost all of its 20-year existence and held a timber sale there last year. Morrison said it has received interest from individuals wanting to placer mine gold at Icy Cape, but the plans were too small to entertain them. It was only recently when Icy Cape drilling samples from the 1990s were unearthed at the Alaska Geologic Materials Center in Anchorage that the Trust Land Office was spurred to do its own drilling last summer. This year the trust plans to conduct a low-altitude airborne magnetic survey and collect bulk ore samples to further delineate the resources. Then in 2017 the plan is to drill the magnetic anomalies to prove the high-grade, mineable zones, Morrison said. He added that the trust has already gotten interest from international mining companies that are supporting some of the exploration work and want to be a part of the larger development project. “I would say by the end of next summer we should be really headed down the path, depending on the results we get, of forming a joint-venture (partnership) to start the process of permitting a mine,” Morrison said. In the end, he forecasts small-scale production to start in five to eight years if all goes well. Elwood Brehmer can be reached at [email protected]

Bokan mine development slowed as rare earth prices dip

Development of the Bokan Mountain rare earth mine is on hold as the company leading the project focuses on a new processing technology and waits for rare earth metal prices to rebound. Nova Scotia-based Ucore Rare Metals Inc. finished infill drilling and drilled groundwater monitoring wells in 2014, leaving it at a natural stopping point before moving towards the next steps of development. Ucore Vice President Randy MacGillivray said in an interview the company has delineated a resource of approximately 5 million tons that is 0.65 percent total rare earth metals. Bokan, located on the southern part of Prince of Wales Island in Southeast, would be an underground mine. Rare earth metals are used in small amounts in countless technology applications. Their prices have softened in recent years along with other, more well known metals and commodities. MacGillivray said because the mine would harvest up to 15 rare earth metals it is hard to set a definitive price point at which Ucore would initiate a full-fledged feasibility study or jump into the environmental impact statement process. “Certainly a movement towards increased metal values in the rare earth metal sector and or us being able to tie up an end user agreement with defined prices would encourage development,” he said. However, there is no timeline for starting permitting. Instead, Ucore has invested in molecular recognition separation technology that has been used for other metals but not with rare earths, according to MacGillivray. Generating a revenue stream from that investment could also help the junior mining company fund Bokan, he said. Based on Ucore’s preliminary economic assessment, the mine would cost $220 million to construct over two years and employ up to 300 people during that period. Ucore has “drilled off” a resource base to support operation for 10 years, which would require about 190 jobs, he said. MacGillivray said Ucore continues to strengthen its baseline environmental work for the project. In 2014, former Gov. Sean Parnell signed legislation authorizing the Alaska Industrial Development and Export Authority to finance up to $145 million for Bokan’s construction. Elwood Brehmer can be reached at [email protected]  

Credit cuts move over industry objections

The legislation tree sprouting from Gov. Bill Walker’s oil and gas tax credit revamp grew again April 11 when the Senate Resources Committee introduced its own tax credit rewrite. Meanwhile, the House continues to grapple with the third version of House Bill 247, which barely resembles what the administration planted in the Resources committees back in January. The Senate Resources version of Senate Bill 130, now on its way to the Finance Committee, would ramp down the size of refundable capital expenditure and operating loss credits and available for Cook Inlet producers and explorers over the next two years. It would roughly cut available state support — estimated at 55 percent for developing companies and 30 percent for producers under current law — in half starting January 2017, and eliminate refundable credits entirely from the Cook Inlet basin starting in January 2018. It is assumed that by 2018 much more will be known about the future of the Cook Inlet natural gas market, which has temporarily stabilized, and current prospective purchasers of Inlet gas could be more solidified and open more opportunities for producers to sell gas in what is now a very constrained market. The iteration of HB 247 being debated on the House floor at the time of this publication would keep state support for companies working Cook Inlet beyond 2018 at average rates of 25 percent for developers and 15 percent for producers. Walker’s original proposal would have kept credits in place long-term to support about 25 percent of a company’s project development costs but also immediately end state support for Inlet producers. The governor pushed for changes to the complex oil and gas tax credit program to lessen the state’s annual obligation to pay refundable credits at a time when Alaska is facing budget deficit of about $4 billion. What started as a small, $10 million per year industry incentive program in 2003 has ballooned to a $700 million obligation this year and could eventually exceed $1 billion if left untouched, the Walker administration contends. The administration’s plan also would have raised taxes by increasing the minimum tax “floor” for North Slope production from 4 percent to 5 percent. Further, it would have “hardened” the floor to prevent companies from using operating losses during times of low oil prices or after significant capital expenses to take their tax liability below the minimum tax. How a sustained low oil price environment, such as today with prices hovering in the $40 per barrel range, would impact the minimum production tax was not understood or even considered when the overarching production tax law known as Senate Bill 21 was enacted in 2013. The House would harden the floor at a 2 percent minimum tax rate. SB 130 would not harden the floor, despite a recommendation to do so in a December Oil and Gas Tax Credit Working Group report led by Senate Resources chair Sen. Cathy Giessel. Further evaluation by the Tax Division found that the state could be stuck paying more than $1 billion in deferred Net Operating Loss credits when oil prices recover because they couldn’t be used to take a tax liability before the floor when prices were particularly low. The Department of Revenue forecasts Alaska North Slope crude prices will recover to average about $50 per barrel in fiscal year 2019, at which point the state would be on the hook for nearly $1.1 billion in Net Operating Loss credits that companies were forced to hold under both the administration and House credit bills. Under current law and SB 130, that obligation would be closer to $700 million. The progressing HB 247 would cap the amount of refundable credits each company is eligible for at $100 million per year; SB 130 sets an $85 million per year limit. It is largely believed those caps will have little impact unless a small producer or new entrant to Alaska begins an exceptionally large project. Walker proposed a $25 million per company per year refundable credit cap. Both bills contain a proposal by the administration to stop the 20 percent Gross Value Reduction credit to create or increase a net operating loss. The GVR immediately reduces the value of “new” North Slope oil before a tax liability is calculated. (Editor's note: This story has been corrected to accurately reflect that HB 247 and SB 130 would end the Gross Value Reduction credit for current oil production eligible for the credit in 2021. A previous version of the story incorrectly stated that the Gross Value Reduction credit would be eliminated entirely in 2021 under the bills.) They also put a five-year limit on the Gross Value Reduction credit and end it for current GVR-eligible production after 2021; that was not proposed by the Walker administration. The bottom line savings to the state projected from HB 247 and SB 130 start small at up to $15 million to $20 million in fiscal 2017 because most of the changes take effect Jan. 1, 2017 — halfway through the fiscal year. The 2018 savings are projected at up to $155 million from HB 247 and up to $75 million from SB 130. By 2022, the savings from HB 247 could hit the $200 million to $300 million-plus range depending on oil prices and tax credit applications; 2022 savings from SB 130 could hit $175 million, based on Revenue Department projections. The administration’s proposal was projected to save and generate nearly $500 million almost immediately through significantly reducing refundable credit expenses and adding about $100 million in revenue by hardening and raising the tax floor. A sharp response The industry, to put it mildly, is unhappy that any tax change is progressing. Alaska Support Industry Alliance General Manager Rebecca Logan took the Senate Resources Committee to task in public testimony April 12. The Alliance, as it is commonly known, represents about 600 contractor businesses in the state’s various resource development industries — primarily oil and gas contractors. Logan said the Alliance started the session with goals for the state to increase throughput in the Trans-Alaska Pipeline System and pass a sustainable budget. “You guys didn’t do your job,” she told the Resources members. “On March 15, when the (operating) budget came out of the Senate and was at $4.6 billion I knew that we were going to get to a point where you were going to have to come to the oil industry because you didn’t do your job on the budget, and so here we are. “Our position on this bill from day one has been we oppose this bill. We oppose any changes to the current tax structure but there was nowhere else for you to go because you didn’t do what you should have done with the budget.” Increasing taxes or reducing incentives will further damage an industry that is already “hemorrhaging” money with oil prices in the $40 per barrel range, she said. The average cost to produce and transport North Slope crude to market is currently about $46 per barrel before any taxes are applied, according to the Revenue Department. Alaska Oil and Gas Association President Kara Moriarty was more measured in her testimony, but noted the state is looking to change its oil and gas tax policy for the sixth time in 11 years.  Some of the most recent of those changes, in SB 21, were requested by the industry. “The industry is not asking for a tax decrease or for tax or royalty relief while we struggle through extraordinarily low prices and we asked that you proceed with caution,” Moriarty said. “The tax policy you have proposed will not encourage new entrants to come to Alaska, will not ensure current producers will remain committed to Alaska, will not lead to more jobs or more production, will not lead to more long-term revenues to the state, and will not improve Alaska’s long-term fiscal future.” Jim Musselman, CEO of Dallas-based independent and small Slope producer Caelus Energy wrote in a frankly-worded letter to Walker April 8 that a change to the current tax credit system will be successful in reducing the state’s near-term cash outlays at the long-term expense of fewer oil industry jobs and less revenue associated with lower production. Caelus leaders have called the company, which entered Alaska in 2014 by purchasing Pioneer Resources’ assets, the “poster child” success story for the state’s oil and gas tax credits. The company has delayed further work on its $1.2 billion Nuna development, which was scheduled to start production in the second half of 2017 because of low oil prices, but drilled exploration wells this winter at its large, long-term western Slope Smith Bay prospect. Job loss tally Musselman also wrote to inform the governor that low oil prices have forced Caelus to cut its full-time Alaska workforce of about 80 employees by 25 percent and suspend formerly year-round drilling at its producing Oooguruk development. Stopping infill drilling at Oooguruk also means laying off nearly 300 contractor employees, according to a Caelus spokesman. All told, the Caelus announcement brings the number of reported layoffs from producing companies to about 500 since ConocoPhillips announced last September cuts to about 120 positions in the state. The Alliance estimates roughly 1,000 industry support positions had been lost before the Caelus revelation, which brings the total to about 1,300 jobs.  The Alaska Department of Labor estimates the state has lost 1,800 oil and gas industry jobs in the last 12 months.

Capital budget sliced to $80M in UGF; federal match raises total to $1.5B

Just when it appeared Alaska’s capital budget couldn’t get smaller, the Senate Finance Committee found ways to cut state further. The committee version of the 2017 fiscal year capital budget, introduced April 11, contains just $79.7 million in new unrestricted general funds, which is more than $100 million less than Gov. Bill Walker’s original capital budget request. Combined with an expected $1.3 billion in federal matching funds, the capital budget totals about $1.52 billion. Staff for Finance co-chair Sen. Anna MacKinnon, R-Eagle River, said during a committee meeting that the budget attempts to capture and reappropriate unspent funds from previous capital appropriations to minimize the General Fund outlay in this year’s budget. “We have done everything — working with legislative finance and our team — to be able to place out into Alaska projects that will help sustain the items that we have, that we’ve invested in, but it is a reduced capital budget,” MacKinnon said. More than $20 million of the state’s match for Federal Highway Administration funding, for example, is a reappropriation of lapsing funds from projects funded in prior years, according to MacKinnon staffer Laura Cramer. A plan to issue general obligation bonds for up to $500 million in capital projects over the next two years was floated by the administration late last fall and initially had a positive reception from legislators but fell apart as the state’s fiscal situation has continued to worsen and the appetite for taking on more debt was lost. The state’s projected 2016 fiscal year deficit increased from about $3.5 billion to $4.1 billion as oil prices fell lower than expected over the winter. The bond package could have funded many millions of dollars still needed for the University of Alaska Fairbanks engineering building, the Matanuska-Susitna Borough’s rail extension to Port MacKenzie and the Port of Anchorage Modernization Project, all of which are unfinished and unaddressed in the budget. The Senate Finance capital budget is still expected to capture more than $1.3 billion in federal matching funds primarily for highway and airport projects. Cut from the governor’s request was $7 million for the Kivalina School replacement, a project that received about $40 million last year, as well as $8 million for Department of Transportation and $10 million for University of Alaska deferred maintenance projects. Cramer said the funding for DOT and university was eliminated because each had unspent funds from previous deferred maintenance appropriations. The University of Alaska estimates its total deferred maintenance bill to be roughly $700 million for its 400 or so facilities statewide. Nearly $11.3 million of general funds was also removed for school boiler replacements and energy efficiency upgrades in Kake, Petersburg and the Bristol Bay School District because those projects qualify for a public building energy efficiency improvement low-interest loan program through the Alaska Housing Finance Corp. The budget includes intent language directing school project proponents to determine if their given projects qualify for the loan program that has been in place for several years but has not been used because state grants have largely been available previously. The committee, through the capital budget bill, is also asking DOT to provide the House and Senate Finance committees with an additional list of highway projects that qualify for up to $170 million of federal funding beyond the state’s typical federal aid level for the 2018 fiscal year budget. That money went was not used by other states and it could be available for repurpose in Alaska if matched with state funds. The one notable addition to the capital budget is $32.5 million line item to pay for the Legislature’s tentative purchase of the Anchorage Legislative Information Office building. The money comes from the Capital Income Fund, not from the unrestricted General Fund. After months of debate over whether to break the $3.3 million per year lease for the Anchorage offices and move elsewhere, the Legislative Council voted March 31 to buy the building for $32.5 million and hopefully end what had become a prolonged melodrama and self-induced political headache. The building owner has tentatively agreed to the purchase price pending the details of the deal. AEA project funding The Senate Finance capital bill would appropriate about $2.7 million to the Alaska Energy Authority for its rural Bulk Fuel and Power System Upgrade programs with unspent earnings from the Power Cost Equalization Fund administered by the authority. Repurposing the excess earnings from the endowment-style PCE Fund, which subsidizes expensive diesel-generated power costs for rural residents, follows the intent of Senate Bill 196 that would direct unspent PCE money to support AEA’s popular Renewable Energy Fund grant program and other capital project programs the authority manages. The Renewable Energy Fund, which supports rural energy infrastructure projects, has historically been paid for with direct General Fund appropriations. A $5 million request was cut out of the governor’s amended fiscal year 2017 budget. Introduced by Finance Committee member Sen. Lyman Hoffman, D-Bethel, the bill passed the Senate on April 13. The $970 million PCE Fund often earns more in investment returns than the roughly $30 million to $40 million it has paid out in subsidies each year, leaving it with excess earnings available for appropriation. SB 196 would cap the annual power cost assistance payout at $30 million and the rural energy program payout at $25 million, while lowering the maximum annual PCE payout from 7 percent of the fund balance to 5 percent. Some reconciliation with the House’s version of the operating budget will likely be needed if SB 196 passes and is signed by the governor because the current House budget diverts $24.7 million of excess PCE money to one-time fund part of the University of Alaska budget.   Elwood Brehmer can be reached at [email protected]  

Alaska Airlines starting to spend its record profits

Alaska Airlines keeps making news, seemingly for all the right reasons. The company announced a $4 billion deal to purchase Virgin America April 4, a deal that when finalized will make Alaska the fifth largest domestic carrier. Spokesman Tim Thompson said to Anchorage Chamber of Commerce members April 11 that Alaska will “leapfrog” JetBlue — the airline Alaska reportedly outbid to buy Virgin — to take over the spot as the fifth-largest U.S. airline. Specifically, the deal breaks down to $2.6 billion in cash and Alaska Air Group Inc. will assume roughly $1.5 billion in Virgin debt. Seattle-based Alaska Air Group is the parent company to Alaska Airlines and its regional carrier Horizon Air. Alaska Airlines leaders have emphasized the deal will solidify the company’s stronghold on the West Coast, with Virgin being headquartered in San Francisco. Thompson said Virgin’s network out of San Francisco and Los Angeles will also give Alaska more “east-west connectivity” to the mid-Atlantic seaboard, adding to Alaska’s traditionally north-south routes along the West Coast. The state of Alaska currently accounts for about 20 percent of the airline’s overall market share. When the deal closes, which is expected by the end of the year, the combined airline will have about $7 billion in annual revenue, a fleet of more than 280 aircraft and 18,000 employees. Alaska Airlines will have two years to decide whether to keep the Airbus fleet operated by Virgin, with possibly of returning 31 leased aircraft by 2021. Virgin’s order for 40 Airbus A320neos reportedly has favorable cancellation provisions. In January, Alaska Air Group announced its sixth consecutive record annual profit. The reported $842 million 2015 net income was a 47 percent improvement over 2014. Air Group CEO Brad Tilden said at the time that while low fuel prices for going on two years now have greatly benefited the airline industry as a whole, Alaska Airlines performance is based on operational reliability and efficiency and customer growth and satisfaction. At the end of 2015, Air Group’s debt-to-capitalization ratio stood at 27 percent. A corporate emphasis to reduce the company’s debt load, before the Virgin purchase, has significantly cut its debt-to-cap ratio, which was as high as 81 percent as recently as 2009. Alaska Air Group’s first quarter 2016 earnings call is scheduled for April 21. Air Group stock closed April 12 trading at $79.25 per share, up 25 percent over the past year. The company has split its stock twice since March 2012. Alaska Airlines is also in the midst of updating its branding for the first time in nearly 25 years. The look of its aircraft and the recognizable Eskimo tail logo are largely staying the same, with refinements coming to typeface and a new-look website. In March, Alaska Airlines also applied to the U.S. Department of Transportation for license to fly to Cuba, proposing twice daily, nonstop service between Los Angeles and Havana. Horizon Air announced April 12 that it plans to purchase 30 new Embraer E175 jets that will be delivered from 2017 to 2020. The total order includes 33 options and is valued at $2.8 billion. The 76-seat E175s will fly routes for Alaska Airlines that are too long for Horizon’s fleet of Bombardier Q400 turboprops but don’t have the demand to necessitate mainliner service, according to a company release. Horizon currently services Alaska Airlines routes between Fairbanks, Anchorage and Kodiak with its Q400s. “The E175s position Horizon for growth beyond our current West Coast destinations while providing better customer utility in the growing Alaska Airlines network,” Horizon President David Campbell said in a release. “The spacious E175 offers a passenger experience that’s on par with much larger jets. This aircraft opens up tremendous new opportunities to fly to places that would not have been feasible with our existing aircraft.” Alaska Airlines also has plans to spend nearly $100 million just in, and for, Alaska over the next couple years. The airline is in the early planning stages of building a new, $50 million maintenance hangar at Ted Stevens Anchorage International Airport to accommodate Boeing’s latest 737-900s. The new hangar will fit two of the largest 737s, according to Alaska spokesman Thompson. Alaska is also decommissioning its five-plane, freighter-passenger “combi” fleet flown primarily to rural parts of the state. The combis and one dedicated 737-400 freighter will be swapped out for three all-freight 373-700s. The three larger 737-700s will add about 20 percent more cargo capacity to the small Alaska freighter fleet, Thompson said. Finally, it is investing about $30 million in its 11 rural Alaska terminals over the next three years. Thompson said expanding the footprints of the terminals mostly built before 2001 will provide more space for Transportation Security Administration officials as well as a better customer experience. Barrow, Kotzebue and Kodiak are the first terminals on the to-do list.   Elwood Brehmer can be reached at [email protected]  

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