Tim Bradner

Risks, rewards to state LNG stake

There are huge benefits for the state if Gov. Sean Parnell’s proposed state participation in a North Slope gas project goes forward: as much as $2 billion to $3 billion per year in new revenues. If the project were expanded, as the partnership deal anticipates, state revenues could increase by 30 percent or more. There are huge risks, too. Of the downsides to the deal, according to consultants to the state, number one is that construction costs now pegged at $45 billion to $65 billion will increase. It is certain there will be some increases, say industry and consultants to the state. Another risk is a dip in liquefied natural gas prices. A price drop to about $10 per million British Thermal Units, for example, could put the project under water, according to Deepa Poduval, lead consultant for Black & Veatch, the state’s top consulting firm on the gas project. To cover costs, a price greater than $12 per million BTUs is needed, Poduval said. Forecasting energy prices 50 years into the future with confidence is impossible. Also, who can foresee some radical new energy technology being developed, like the revolution in cheap shale gas that fatally undermined the plan for an all-land gas pipeline from the Slope to Canada. Another sobering possibility: If a buyer of LNG doesn’t pay, because of bankruptcy or by not taking as much LNG as much was contracted, the state could be caught, Poduval warned legislators in hearings. The same thing could happen if the state can’t deliver its contracted LNG to a customer because of some production upset on the North Slope, she said. The state can’t control production. Finally, once the state signs a “take or pay” contract with TransCanada Corp., its proposed partner in the pipeline, the state is on the hook, and this could be as much as $1 billion per year no matter what, according to studies by Black & Veatch. What the Legislature is considering this year is a bill that would give the state the authority to take its gas production royalty and production tax “in kind,” or in the form of gas, and then commit the state gas for shipping and sale, as liquefied natural gas, through the partnership. If the bill passes, the administration will have permission to continue negotiating a more definitive deal that would be back before the Legislature next year. The risks sound daunting, but there are strategies for mitigating them, said Poduval, of Black & Veatch. Were the state not to pursue the partnership, and if the project were to proceed somehow anyway, many of the downside possibilities would still be there to diminish state revenues. On a more positive note, the state will be able to get into the partnership without huge outlays of cash. The proposed deal with TransCanada is structured to lessen the state’s front-end capital requirements, a prime concern of legislators. By having TransCanada as a partner, the pipeline company makes the capital investments in the pipeline and gas treatment plant “upstream” on the North Slope. Also, having TransCanada’s expertise available to the state is important, not just to the state but also to the producing company partners, who don’t want to see the state suffer pains of a learning curve in owning and managing shares of a pipeline, company officials have said on background. In terms of financial exposure, however, the state will own its share of the LNG plant in Nikiski directly, and would be required to contribute capital to that. Parnell said during his State of the State address that the Alaska share in the fiscal year 2015 budget for preliminary work toward the Nikiski plant could be $70 million to $80 million. Legislators in Juneau are weighing the risks and benefits and most seem willing so far to go for the partnership. “I like the idea of our being a partner and I have confidence in our process, although there are still questions among many lawmakers,” said Sen. Lesil McGuire, R-Anchorage. TransCanada role Many plans for gas projects have been put forward, McGuire said, but, “This is different, because we now have alignment for the first time in years, with all three producing companies on the same page at the same time.” McGuire is a member of the Senate Resources committee, which has been holding extensive hearings on the proposal. A “companion” bill in the state House is in the House Resources committee, which has also been holding hearings. Sen. Peter Micciche, R-Soldotna, also a member of the Resources Committee, voices similar sentiments: “I’m not bothered by having a equity investment, although I have some questions about TransCanada’s involvement.” Some legislators are unhappy with the state having TransCanada as a partner because of the pipeline company’s involvement in Gov. Sarah Palin’s Alaska Gasline Inducement Act, or AGIA, license, which some see as having worked to the state’s disadvantage. The Senate Resources Committee will be doing amendments Feb. 21 to Senate Bill 138, which that would allow the state to begin more detailed negotiation with the industry partners. Some amendments may include “sideboards” to limit the state’s exposure, she said. “We don’t want to end up where we were with AGIA, where we were locked into a troubled marriage. We want off-ramps, with minimal exposure,” McGuire said. “We are still locked into AGIA (with TransCanada) and it will cost us $100 million to get that data (acquired by TransCanada partly at state expense). If we go a different route, working with TransCanada, our exposure at the first off-ramp is $67 million. I’m leaning toward that.” Although the bill is still in the Resources Committee, Sen. Pete Kelly, R-Fairbanks, will begin overview hearings on the proposal in the Senate Finance Feb 19. Kelly is co-chair of that committee. The current legislation would only give the state administration authority to continue negotiations toward a more comprehensive partnership agreement, and a proposed gas shipping contract with TransCanada, that would be before lawmakers next year. Fiscal terms Legislators also learned in hearings that a proposed state “fiscal stability” agreement will be part of that. An assurance by the state that taxes on the project won’t be increased is critically important, the industry partners have said, although some means of doing this will have to be found that fits within state constitutional requirements that do not allow limits to future actions by the Legislature. There is particular sensitivity by some legislators as to whether such an agreement will be extended to oil production taxes. Sen. Hollis French, D-Anchorage, raised this question in the Senate Resources Committee. Spokesmen for all three of the producing companies involved, which were before the committee at the time, said they could not answer that question now. Another twist in the fiscal agreement will be on how municipal property taxation is handled. The mayors of the Fairbanks North Star Borough, the North Slope Borough, the Kenai Borough and the city of Valdez wrote to Gov. Sean Parnell Feb. 11 expressing concern about a “Payment in Lieu of Taxes,” or PILT, that might be part of an overall agreement. The mayors are worried that effects on municipal property tax ability might be limited, and asked Parnell if they could be included in the negotiations. Meanwhile, the Legislature’s decision on the concept of a partnership this year is seen as a “go” or “no-go” vote on the big gas project moving forward. Poduval, of Black & Veatch, said the project is unlikely to move forward unless the state participates. A comprehensive study by the consulting firm, which is under contract to the state, shows that under the current state fiscal regime the “government take” on the project’s revenues is about 70 percent to 80 percent, and higher than the government take on most other competing projects, Poduval told the Senate Resources Committee in hearings. For example, the Black & Veatch study showed that government takes in two major competing nations with LNG projects, Australia and Russia, with Sakhalin LNG, are in the 50 percent range. “We looked at several ways of modifying the government take by reducing the production tax and royalty, and we concluded that this cannot ‘move the needle’ in making the project more competitive,” Poduval said. In contrast, an equity investment can make a big difference in reducing government take, mainly by reducing the federal tax part, she said. There the risks, however, “But those are there whether there is an equity investment or not. Prices (for LNG) are a risk, as well as the capital cost and schedule. LNG projects worldwide are experiencing costs increases and delays and we don’t see the Alaska project as being any different.” Risks can be managed, she said. As for capital costs and the schedule, the controls on the project execution are critical and the industry partners engaged all have good track records in project management, she said. “Also, large LNG projects that are integrated, as is this one, demonstrate a better ability to remain on schedule with minimal cost escalation, she said. On price risk, a common mitigation strategy is to negotiate sales contract for LNG before the final investment decision is made. “This is a very common, almost necessary step. It is typical for large LNG projects to have the majority of the LNG committed to customers from the start,” Poduval said. It is also not uncommon that some of the buyers have an ownership stake, typically a small share such as 5 percent, she said. Also not unusual, in large LNG projects, is for the host government to have a stake, such as is proposed with the Alaska project. LNG customers like to see such alignment, with the host government as having skin in the game. State participation also helps the industry partners by lowering the amount of capital they have to expose, Poduval said. “This is very important to them,” she said. State involvement also allows it to bring in a third-party partner with expertise, in this case TransCanada, in helping manage the operation of the project. “There is also transparency,” because the state will have access to information about the project management. In contrast, lack of transparency is seen as one of the key problems if the state were not to pursue a partnership. If the decision were made not to participate, and for the state to leave intact its current net-profits gas production tax and to take the gas royalty “in value,” or cash, the companies would manage the different parts of the project — the gas plant, pipeline and LNG plant — in ways that would be financially to their interest, and possibly to the state’s disadvantage.  The state’s only way to gain access to financial information will be through tax audits or, in the worst case, lawsuits, both avenues costly, cumbersome and time-consuming. Industry wants to avoid royalty and tax audits, and the possibility of disputes, by bringing the state in as a partner, the companies have said. There is still the memory within the producing companies of hundreds of millions of dollars spent in the Amerada-Hess lawsuits in the 1970s and 1980s over oil royalty disputes after North Slope oil production started in 1977. This has motivated the producing companies to avoid this with a gas project, where the margins are much narrower than with oil production. The Amerada-Hess lawsuit was finally settled.

Defense budget stabilizes Alaska forces

Things have returned to near-normal for Alaska’s military forces, but it has been a tough year of budget sequestration cuts, furloughs of civilian workers and cancelled military exercises and training, Air Force Lt. Gen. Russell Handy told state legislators in Juneau in a Feb. 13 briefing. The good news is that a budget has been passed by Congress and signed by the president. “We have some budget stability now, even if it is not what we wanted,” Handy told House and Senate members of the Joint Armed Services Committee. Handy did the briefing, an annual event for the Legislature, along with Army Major Gen. Michael Shields and Alaska’s Adjutant General, Major Gen. Thomas Katkus, who commands the Alaska Army and Air National Guard. Handy told the legislators that Alaska’s military population now includes 23,400 active duty personnel, the vast majority Air Force, Army and Coast Guard; 35,200 dependents; 4,800 civilian workers and 1,800 other Department of Defense personnel. There are still Alaska-based forces deployed, about 1,350 at present, Handy said. “We expect this to come down a little and be stable, but there will always be deployments, ranging between 1,000 and as many as 1,500,” he said. Air Force equipment now deployed include F-22 Raptors in the Middle East as well as E-3 AWACs aircraft. U.S. Army units are also in the Middle East. One item of interest from the briefing is on the potential basing of advanced F-35 fighters at Eielson Air Force Base near Fairbanks. Eielson is among the bases being considered. “We expect to hear something later this month on the bases listed as final candidates. I expect Eielson to be one of those. The selection for the final list will trigger an environmental analysis. The ‘mission capability’ of the location and the environmental effects will be key factors in the final selection,” Handy said. Other new developments from Handy’s briefing include that Clear Air Force Base, near Nenana, is being considered for installation of a new advanced-technology radar system for enemy missile detection. Clear is already being upgraded this year, Handy said. Those improvements signal the Pentagon’s intention of further developing Alaska’s capability in missile defense. New missile interceptors and other facilities are also being added at Fort Greely, the nation’s only ballistic missile interceptor launch site, Handy said. Alaska Army commander Major Gen. Shields said the approximately 12,000 Army troops based in Alaska, now split about equally between Fort Wainwright at Fairbanks and Fort Richardson in Anchorage, will shift somewhat to the advantage of Fort Wainwright. The troops at JBER will be reduced but those at Fort Wainwright will increase, he said. “We’re going to be growing Fort Wainwright,” Shields said, but a shortage of barracks is still a problem and getting new barracks is now the top priority for the Army post, he said. Handy also said the Air Force Thunderbirds, the aerial demonstration team, will return to Alaska for the Arctic Thunder air show now scheduled at Joint Base Elmendorf-Richardson on July 26 and 27. About 235,000 are expected at the air show, he said. Air shows and the Thunderbirds demonstrations around the country were shut down last year as a part of budget sequestration. They are now being resumed, along with training exercises, but the July demonstration by the Thunderbirds will be the team’s only show this year outside the continental U.S., Handy said. “We have very strict funding limits for the show, so we’re actively looking for partners,” as co-sponsors, he said. In another new development, Shields said his Alaska Army forces will step up Arctic climate and mountain warfare training this year with U.S. Middle East commitments winding down. That will allow Alaskan forces to resume their traditional focus on northern climate readiness, he said. This year will also see a first-ever parachute drop of troops with equipment on the North Slope, near Deadhorse, a unusual spectacle for oil field workers, Shields said. Handy said there is still a need for vigilance in watching Russian air activity near Alaska’s borders. “The Russians are very active in the Arctic and in long-range aviation, so much that we have to go out and look at what they are doing occasionally,” Handy said. On the other hand, U.S. and Russian forces still cooperate in a joint exercise that involve dealing with a simulated aircraft hijack that crosses the border between the two nations, he said. Handy said the federal budget sequestration was difficult for the military last year because the reductions, announced in March 2013, had to be absorbed in seven remaining months of the federal fiscal year. The effect on the Air Force in Alaska was a $14.2 million reduction for that period, he said. Although President Barack Obama has signed a new appropriations bill the measure did not restore any of the money cut during sequestration and also reduced Air Force operations and maintenance and minimized the ability to transfer funds within defense department agencies. Within Alaska, the Air Force had to temporarily ground fighters at Eielson Air Force Base near Fairbanks, do reduced flying with other units, cancel the big Northern Edge exercise, and two or three “Red Flag” aerial combat training sessions, which are done with air defense units from other nations. About 5,100 civilian defense workers had to be furloughed, Handy said. They are now back at work, but the experience “has created a lot of uncertainty. A lot of people are not quite as comfortable working for the federal government now,” he said. Despite all this, the Alaska-based units continue to be upgraded with new capabilities. The Alaska-based F-22 Raptors, for example, are now the most capable of any in the Air Force after having been equipped with new digital mapping technology that gives the aircraft the capability of delivering small-diameter bombs with precision. “No other (F-22) units have yet received these modifications, so this is a unique capability for us,” and is one reason why the Alaska-based F-22s are in so much demand in the Middle East. Another capability, actually devised by a group of active duty and reservist pilots, is the “Rapid Raptor” concept that is being tested in Alaska, Handy said. It involves the rapid deployment of Raptors to a “forward” airfield with support C-17s landing just behind the fighters. “This gives us the ability to turn the aircraft around,” quickly on missions in forward areas, Handy said. “We’ve done a proof-of-concept for this in Alaska with a full-wing exercise,” in early February, he said. “This gives us a new operational capability here to work with groups of six, 12 and 18 aircraft.”

30 days in, major decisions before Legislature

The state Legislature has passed the one-third mark of its 90-day 2014 session. House and Senate committees are working through the priority issues and, as usual, the big decisions are likely to come in early April as the April 20 adjournment date nears. Senate President Charlie Huggins, R-Wasilla, said he hope to see adjournment a day or two before April 20 because that day in Easter Sunday. “I really don’t want to be here on Easter,” Huggins said. Whether legislators get out early will depend on how high the log-jam of bills piles up as the end nears, and whether tempers fray over typical points of dispute like what to include in the state capital budget. In a Feb. 18 briefing by Senate majority leaders, Sen. Kevin Meyer, co-chair of the Senate Finance committee, said his goal is to have a capital budget up for consideration in the Senate by April 1. That would allow two weeks or so before adjournment for the House to review and make changes to what the Senate might propose, Meyer said. Gov. Sean Parnell has proposed a very lean capital budget with $426 million in state unrestricted funds, Meyer said. Legislators will undoubtedly add some to that, but legislators will have to be careful. “Every dollar we add comes out of savings,” Meyer said, because the state will run a deficit this year. Traditionally the Senate develops a first draft of the capital budget and sends it to the House for changes. The House traditionally originates the state operating budget, and Meyer said he expects that to be to the Senate by mid-March, which is the usual target for House action on that budget. On another important matter before legislators, Gov. Sean Parnell’s proposal for a $3 billion cash deposit into state pension funds to reduce an estimated $12 billion underfunded liability, Meyer said legislators are awaiting an analysis of options being prepared by Legislative Finance Director David Teal. That may take about a month to complete, Meyer said in the briefing. “The governor wants to make the deposit to reduce the liability and stablize the state’s annual payment toward the liability at $500 million a year,” Meyer said. “This is like a home mortgage. If you pay down the principle you reduce your payment.” If nothing is done the annual payment, now about $600 million, it will escalate to $750 million and then $1 billion yearly, which could put severe pressure on the state operating budget. Meyer said a number of options to fund the liability are on the table. “I’m not a fan of the big lump-sum payment,” because of uncertainties over the state’s overall finances. “We’re still in a state of transition with SB 21 (oil tax reform) and it will take a couple of years for the change to result in new revenues,” he said. In the meantime the state will have to dip into savings to fund budget deficits. The three big “drivers” in the state operating budget are education and Medicaid spending as well as the pension liability payment, he said. In other developments, the Senate Labor and Commerce Committee held its first hearing Feb. 18 on Sen. Lesil McGuire’s Senate Bill 140, authorizing the Alaska Industrial Development and Export Authority to partner in the development of an Arctic port. McGuire said her bill is modeled after an AIDEA program put in place by the Legislature to allow the authority to partner in energy projects, and which is now being used on the Interior Energy Project, a plan to build a natural gas distribution system for Fairbanks based on liquefied gas trucked from the North Slope. McGuire’s bill limits AIDEA’s participation in funding to one third of a port project, she said at the Feb. 18 Senate briefing. Tim Bradner can be reached at [email protected]

Buccaneer hits dry hole at West Eagle gas prospect

Buccaneer Energy hit a dry hole at its West Eagle gas prospect east of Homer, the company announced Feb. 17. The rig is still at the site to safely plug and abandon the well and will be moved from the location when that is completed, most likely within two weeks, Buccaneer spokesman Richard Loomis said. The well was drilled to a depth of 3,700 feet, and while the sandstone rock being targeted showed excellent reservoir properties there were no indications of hydrocarbons, according to a Buccaneer press release. “After having enjoyed discoveries at the Kenai Loop and Cosmopolitan fields, the results of the West Eagle well are disappointing. The company will now focus its efforts toward Tyonek Deep and Kenai Loop,” Buccaneer CEO Curtis Burton said in the release. Kenai Loop is an onshore gas field near the city of Kenai where Buccaneer has two gas wells in production, a third drilled and ready to produce, and more drilling is planned. Tyonek Deep is an offshore Cook Inlet prospect. Loomis said Buccaneer is still unsure where the drilling rig, which is owned by the company, will be sent. The unsuccessful West Eagle well will cause Buccaneer to revamp its capitalization plan. Financing extended by Meridian, which is also a Buccaneer shareholder, will be repaid by June 30, according to the release: “Discussions with major shareholders and third parties regarding financing are in progress.” Buccaneer said it will apply to the state Department of Revenue for eligible exploration tax credit payments. The company will also seek a refund of bonds filed with the state Department of Natural Resources. On other matters related to Buccaneer, the Alaska Oil and Gas Conservation Commission will hold a second hearing on April 8 regarding Cook Inlet Region Inc. protests of Buccaneer’s plan to bring its third Kenai Loop gas well into production. The well was drilled last year but the AOGCC has not allowed production to begin until the issue raised by CIRI — that the well may drain gas from land it owns adjacent to Buccaneer’s lease — is resolved. The commission is also investigating whether the two wells now producing in the Kenai Loop field may also be draining some gas from the CIRI lands. The AOGCC may also consider establishing an escrow fund to hold royalty payments until the matter is resolved. The Alaska Mental Health Trust is now the landowner on leases at Kenai Loop and the royalties now being paid are going to the mental health trust.

Exploration off 38%, producing mines strong

JUNEAU — Mining is good for Alaska’s economy, but while the state’s six producing mines are holding up well, and some even expanding, a sharp 38 percent drop in exploration spending last year is having ripple effects. Overall, mining employed 4,600 Alaskans directly last year and the overall employment impact totaled 9,100 including indirect jobs created by the spending. Direct payrolls of mining companies totaled $630 million in 2013. The 2013 total employment and payroll numbers are down a bit from employment in 2012, however, which is likely due to the falloff in exploration. Minerals companies spent about $180 million in exploration in 2013 compared with $275 million in 2012. The data was gathered by McDowell Group, a Juneau-based consulting firm, for the Alaska Miners Association and the Council of Alaska Producers, two minerals industry trade associations. The information was presented to the House and Senate Resources committees in Juneau Feb. 5, by Karen Matthias, director of the producers’ council, and Deantha Crockett, executive director of the Alaska Miners Association. McDowell Group’s 2013 figures were released that day. On an upbeat note, one of Alaska’s producing mines, the Fort Knox Mine near Fairbanks, achieved another milestone in December 2013, when the mine produced its six millionth ounce of gold, Matthias said. Fort Knox is a large surface mine northwest of Fairbanks that began production in 1996. In another development, the Greens Creek Mine in Southeast Alaska secured federal approval for an expansion of the mine tailings storage facility, Matthias said. It will be in construction this year and, when completed, will give the mine the capacity to store tailings if new resources are added to the mine, she said. Greens Creek is an underground silver mine on Admiralty Island near Juneau. Some more sobering news for the industry, however, was the decision by Anglo American, a large mining company, to withdraw as a partner in the large Pebble copper/gold project near Iliamna, southwest of Anchorage. Pebble’s owner, Northern Dynasty Minerals, is now looking for another partner to develop the mine. As for exploration, lower gold prices explain most of the drop, Matthias said. Prices for that metal have dropped from almost $1,800 per ounce in September 2012 to about $1,200 a year later, she said, and haven’t changed much since. Silver has also declined. Base metals like copper, zinc and lead have been more stable, at least in recent months, but it is gold that drives much of the Alaska exploration. Alaska isn’t alone in experiencing the drop in exploration. The trend is global, Matthias said, with world exploration spending at $15.2 billion in 2013 compared with $21.5 billion in 2012, a 29 percent decline. While metals prices are weak, costs for mining and mining equipment continue to climb. Crockett cited some examples: A 40-ton underground haul truck, of the type used in Alaska underground mines, climbed in cost from $560,000 in 2003 to $1.3 million in 2013, she said. The price for a 6-yard underground loader went from $570,000 in 2003 to $1.1 million in 2013. Labor costs are climbing also. In 2003, the average Alaska mining wage was $70,750 per year. In 2013 it was $100,000 per year, Crockett said. Fuel and other energy prices are high. Fort Knox spent about $4 million per month to purchase electricity from Golden Valley Electric Association, the Interior regional utility, and about an equal amount on fuel for equipment used in the mine, Matthias said. The Red Dog Mine, in northwest Alaska, has a hefty fuel bill, too. Teck Alaska, the mine operator, uses about 20 million gallons of fuel per year that must all be shipped in by barge during the summer and then trucked inland to the mine. The Kensington gold mine near Juneau is powered by diesel also, and has a huge fuel bill. Greens Creek has the benefit of being able to tap into Juneau’s electric grid with its inexpensive hydro power, but the mine must switch to diesel during periods when the hydro projects have low water and produce less power. Meanwhile, mines continue to be good taxpayers for local governments. In 2013, producing mines paid $16.8 million to municipal governments in Fairbanks, Juneau, Nome, the Northwest Arctic Borough and the Denali Borough, according to the McDowell Group data. About $100.2 million was paid to the state of Alaska in mining royalties, taxes, fees and rents, according to data from the consulting firm. This includes $21.1 million paid to the Alaska Industrial Development and Export Authority, the state development corporation, in fees for use of the Red Dog Mine road and port and the Skagway Ore Terminal, facilities which are owned by AIDEA. About $23.8 million was also paid to the state-owned Alaska Railroad for the movement of coal, sand and gravel. On final note, Mathias and Crockett noted the royalties paid by the Red Dog Mine continues to NANA Regional Corp., the landowner, which are shared with other Alaska Native regional and village corporations under terms of the 1971 Alaska Native Claims Settlement Act. From 1989, when its production started, through 2013, Red Dog has paid a total of $1.04 billion in royalties to NANA. About $609 million of this was shared with other Alaska Native corporations. Also, 56 percent of the employees at Red Dog are shareholders of NANA, and other NANA shareholders work for joint-venture companies that provide support and services to the mine. Tim Bradner can be reached at [email protected]

State LNG take could be $3B by 2024

JUNEAU — State legislators are continuing their review of the state’s proposed deal with North Slope producers and TransCanada Corp. on a major natural gas project. Legislation that would allow state participation in the project is before the House Resources and Senate Resources committees, which held several days of hearings last week. The proposal is for the state to become a partner in the project in ways that reduce risks for the industry participants but also enhance the state’s share of future revenues. Black and Veatch, a consulting firm working for the state, estimates potential profits to the state of $3 billion a year by 2024 from its share of the project. The agreement also provides terms under which the pipeline can be expanded if other companies, which do not own a share of the pipeline, find new gas supplies. Legislators are examining two documents, the Heads of Agreement with all the parties including the state and TransCanada, and a separate Memorandum of Understanding between the state and TransCanada that spells out terms of the partnership between those entities. Under the proposal, TransCanada would make the investment in, and own, a share of the North Slope gas treatment plant and pipeline sufficient to transport the state’s gas share, while the state would invest directly in, and own, a share of the LNG plant in Nikiski sufficient to convert the state gas into LNG for sale. The state would have an option to purchase part or all of TransCanada’s share of the project at certain points. BP’s Dave Van Tuyl, representing his company in a “roundtable” discussion held with the Senate Resources Committee Feb. 7, said the Legislature is being asked to take a first step this year with decisions in three areas: whether to participate in the project; the rate of participation, and setting the overall share between 20 percent or 25 percent, and agreeing to the next steps. Tony Palmer, representing TransCanada on the panel, said that if the Legislature approves the enabling legislation this year he anticipates a “Precedent Agreement,” this summer between the state and his company. A Precedent Agreement is the first step in a long-term, binding transportation agreement for the state’s gas share to be shipped by TransCanada through its share of the pipeline. The Precedent Agreement would be followed by a Firm Transportation Service Agreement (the shipping contact itself) that would be ready for legislative approval in 2015, Palmer said. This is the big step for the state because it is binding, but Palmer also said there are “off-ramps” for parties including the state, at different stages in the process, even at advanced points. These are covered in sections of the state-TransCanada MOU that cover “termination of participation,” and includes provisions for repayment to TransCanada of its costs with 7.1 percent interest, Palmer said. The state’s negotiation of the Heads of Agreement was pursued after the results of a consulting study were received from Black & Veatch. The firm outlined some major findings of the study for the Senate Resources Committee Feb. 10. In the study, Black & Veatch had focused on two main objectives in the study, one to find a way for the state to protect its royalty interest and a second to find a way that the state, as a landowner, could provide incentives for the project to move forward. “The bottom line is that we feel the project is feasible with some changes to the fiscal framework,” said Deep Poduval, who led the study team. Black and Veatch found this could be achieved most effectively by the state taking on some of the costs of the project by becoming a partner and by modifying the present terms of the oil and gas leases that give the state the ability to switch between taking of royalty from royalty in-kind to in-value at six months’ notice. The “Heads of Agreement” as it now stands, with the producing companies and TransCanada, provides for the state to take both its royalty and tax share in kind to achieve a 20 percent to 25 percent overall share of the gas production and to take a corresponding share of the project itself, but partnering with TransCanada Corp. on the gas treatment plant and the pipeline.  Poduval said the state’s other options to alter the fiscal framework include simply lowering the state’s royalty and tax, but that the taking of gas in-kind and equity partnership approach seemed better because the state would benefit far more in the long run. The industry’s objective is also for the state to benefit from the project so that the interests are aligned. “It’s a better way to achieve the objective,” she said. Another state objective achieved under the equity arrangement is the ability to assure third-party access to the “midstream” of the pipeline, for explorers who discover other gas. Last week, legislators heard from the state’s potential new partners in a wide-ranging discussion in the Senate Resources Committee held Feb. 5. Sen. Hollis French, D-Anchorage, asked about concessions the five parties had made to each other in reaching the Heads of Agreement. One difficult area, several on the panel said, was to agree on principles for expansion of the pipeline and how costs for expansion would be shared. Palmer, of TransCanada, said the final agreement does have a “pro-expansion” bias, though not as far as TransCanada would have preferred. Bill McMahon Jr., representing ExxonMobil, said a difficult area was in determining what would be agreed on in the initial HOA document and how much would be left to negotiate later. Pat Flood, of ConocoPhillips, said the companies had to come to grips with dealing with the state on a commercial basis and yet keeping the state’s role as a regulator in mind. “This was new territory for us,” in a commercial agreement, he said. Palmer said some terms relating to pipeline return on equity in the HOA are more beneficial to the state than was the case under the state’s AGIA license agreement with TransCanada. He didn’t elaborate on the point, however. Pipeline return on equity, which is regulated by the Federal Energy Regulatory Commission, is important because it affects the pipeline tariff, or shipping cost, which in turn affects the revenues to gas shippers including the state. Sen. Fred Dyson, R-Eagle River, raised a question that was not fully answered: If there can be no legal limit to the state’s tax authority, what if the state later decided to increase its gas production tax? Because the state would be taking its tax in-kind, would this increase the share of the state’s gas and therefore the state’s volume of gas to be shipped? ExxonMobil’s McMahon said, “That would be the result.” ConocoPhillips’ Pat Flood said, “The HOA as it is (agreed on) contemplates the state’s participation to be the same as its share of gas.” Dyson did not pursue the question further, but a state official familiar with the agreement said this is one of several important loose ends that have to be nailed down as the deal moves through future stages. If the state can increase its gas tax and its gas volume at the whim of the Legislature it would have practical effects on the project, because pipeline capacity is designed to handle a set volume of gas. It could also detract from the gas shares of the other shippers. Members of the panel also said that the agreement makes no change in the current state property tax or corporate income tax. However, the agreement also provides for a PILT, or payment-in-lieu-of-tax, on property taxes to local governments, while the project is in construction. In its overall analysis of the project Black and Veatch used a cost basis for the project of $39 billion to $54 billion, but that this differs from the estimates published by the industry team of $45 billion to $65 billion. That’s because the companies included Point Thomson production facilities and pipeline, while Black and Veatch looked only at the North Slope Gas Treatment Plant, the pipeline and the large Southcentral liquefied natural gas plant, said Peter Abt, another member of the Black & Veatch team. Based on those estimates, the study team calculated a “break-even” price for delivery of gas to customers, as LNG, of about $12.30 per million British Thermal Units, Abt told the Senate committee. Abt warned the committee, however, that cost escalation represents a key risk for the project. Costs have escalated sharply for major energy projects worldwide, particularly LNG. “We expect costs under continued pressure as this goes forward,” Abt said. However, the consultants also concluded that the efficiency gain of having the LNG plant located in a northern climate, on the Kenai Peninsula, was worth the equivalent of an extra 3 million tons of LNG per year in value gain, compared against competing LNG projects with their liquefaction plants located in warmer climates. The consulting firm identified an LNG supply “gap” in world markets, mostly Asia, of 250 million tons to 300 million tons of LNG per year by 2025, but that Alaska also faces significant competition from other projects that have lower costs. Compared against those, Alaska now appears “out of the money,” in being able to compete without changes in fiscal structure and state participation.

Flint Hills closure puts fuel in flux

Flint Hills Resources will cease refining operations at its North Pole refinery near Fairbanks this spring, the company announced Feb. 4 in a press release. The extraction unit at the refinery will be shut down on May 1, ending gasoline production. Crude Oil Processing Unit No. 2 will shut down shortly thereafter, depending on operational requirements, but no later than June 1, according to the company. Flint Hills will continue marketing activities in Interior Alaska, the company said. The closure of Unit No. 2 will end production of jet fuel and all other refined products. The company will continue to market fuels through its terminals in Anchorage and Fairbanks. Supply for those terminals will come from other sources, Flint Hills announced. The loss of refinery jobs will have an impact on Fairbanks. Flint Hills now employs 126 in Alaska and after the closure 35 will remain in Fairbanks and 10 in Anchorage to work at the company’s fuel terminal, Flint Hills spokesman Jeff Cook said. There will be major changes in Interior fuel markets, the refinery has been a major supplier of gasoline, jet fuel, diesel and other products, including to major military installations. Those fuels will have to be supplied from Southcentral Alaska. “This has been a difficult decision made after a long, thorough and deliberative process,” said Mike Brose, a company vice president and the refinery manager. The refinery has faced difficult economic conditions in recent years, mainly the loss of jet fuel sales to air carriers in Anchorage due to fuel imports and less demand. However, Brose said the financial liability of soil and groundwater contamination left by previous owners were a major factor in the decision. “Our company has spent an enormous amount of money and resources addressing soil and groundwater contamination that was caused when Williams owned the refinery and the State of Alaska owned the land underneath it,” Brose said in the press release. “So far, neither Williams nor the State of Alaska have accepted any responsibility for the cleanup. With the already extremely difficult refining market conditions, the added burden of excessive costs and uncertainties over future cleanup responsibilities make continued refining operations impossible.” Gov. Sean Parnell said he spoke with top company officials Feb. 4, the day the closure was announced. “I was told market forces were the major factor, but that contamination issues that seemed unresolvable played a big part. It was an accumulation of economic issues. It isn’t accurate to say it was any thing,” he said. The governor said had met with Flint Hills last fall regarding groundwater contamination issues at the refinery. “It is the state’s responsibility to ensure safe groundwater and Flint Hills has done a good job in supply drinking water to people who are affected.” In that meeting the company expressed displeasure that Williams Companies has not stepped up to its responsibility on contamination, but also displeasure at the state’s hard line on the groundwater contamination, the governor said. “I spoke to the Commissioner of Environmental Conservation, Larry Hartig, and the Attorney General to make sure we are being reasonable but also instructed them to ensure we are protecting the public from groundwater contamination,” Parnell said. One other small refinery operates in the Interior region, a plant owned and operated by Petro Star Inc. The state of Alaska has been supplying Flint Hills with state-owned royalty oil. The returned residual oil is a major source of heat for crude oil flowing through the Trans-Alaska Pipeline System to Valdez — the southern terminus of the pipeline. During the winter, the crude temperature in TAPS drops as it flows south of Prudhoe Bay, creating potential operating problems for the pipeline, but the oil is warmed when Flint Hills returns residual oil to the pipeline. The refinery near Fairbanks is approximately at the halfway point of the 800-mile pipeline. “We are not totally dependent on this (returned oil), however, as we have other ways of adding heat to the pipeline,” said Michelle Egan, a spokeswoman for Alyeska Pipeline Service Co. Alyeska is now warming the oil itself by recirculating crude at Pump Stations 7 and 9, and will soon add new capabilities to add heat at Pump Station 5, she said. The returned oil to TAPS from Flint Hills is of less benefit to Alyeska in any event because Flint Hills has installed facilities to extract much of the heat as a source of energy for refinery operations. “The oil returned is cooler than it was, so it is less important to them,” said Kevin Banks, commercial manager at the state Division of Oil and Gas, who monitors crude oil issues for state royalty purposes.  Flint Hills has been drawing about 82,000 barrels per day to 84,000 barrels per day from TAPS, with about 22,000 to 25,000 barrels per day used to make products, according to state documents prepared in September 2013 for sales of state royalty oil. The balance is returned to TAPS as residual oil. At those throughput volumes Flint Hills would produce about 143,000 gallons of gasoline per day, 41,000 gallons of home heating oil per day and 68,000 to 194,000 gallons per day of various products such as naphtha, asphalt, a small volume of high sulfur diesel and other products, according to the state documents prepared by the Division of Oil and Gas. The closure of the refinery has implications for the state-owned Alaska Railroad Corp. The railroad has recently been shipping about 3.5 million gallons of jet fuel per week on five trains, according to railroad spokesman Tim Sullivan. “(Flint Hills) has been a very important customer to us and we’re still trying to review what this means for the Alaska Railroad,” Sullivan said. Banks, at the Division of Oil and Gas, said that some of the fuel shipped south on the railroad by Flint Hills will be offset by fuel shipped north to replace the refinery’s supply in Interior markets, but that the northbound shipments of gasoline, diesel and jet fuel probably won’t offset the loss of jet fuel shipped south for the railroad. Ted Stevens International Airport manager John Parrott said that since 2009, Flint Hills-refined jet fuel has accounted for about one-third of the roughly 600 million gallons of fuel used by airlines in Anchorage annually. In 2007, before the recession slowed flight activity at the airport, Flint Hills fuel made up about 600 million of the 900 million gallons consumed at the airport during the year, he said. That 300 million-gallon drop equates almost exactly to the capacity of Tower 3 at the refinery, a unit that was shut down by Flint Hills, Parrott said. 

TransCanada role in LNG project scrutinized

State legislative committees continue to work their way through Gov. Sean Parnell’s proposed natural gas pipeline deal with North Slope producers and TransCanada Corp.  Some concerns are developing over the role of TransCanada as a partner for the state, however. “At this point we haven’t drilled very deeply into this. We’re still at the high-level overview stage,” said Senate Minority Leader Hollis French, D-Anchorage, who has been attending briefings as a member of the Senate Resources Committee. Under the proposal, the state would not invest directly in the pipeline and gas treatment plant and would leave that to TransCanada. The state would sign a long-term contract with TransCanada, however, to ship its state-owned royalty gas. TransCanada would use the state’s contract, which would be binding, to finance about three quarters of the capital it would contribute toward costs of its part of the project, estimated at $6 billion to $8 billion. The pipeline company would pay directly for one-fourth as an equity investment, however. TransCanada will not be an investor or owner in the large natural gas liquefaction plant planned for Nikiski, near Kenai. The state-owned Alaska Gasline Development Corp., or AGDC, would invest and own a share of the LNG plant sufficient to process the state royalty gas into LNG, and would finance mostly with revenue bonds. Legislators are asking why the state feels obligated now to go with the pipeline company as a partner if a license TransCanada holds under the Alaska Gasline Inducement Act is terminated, or whether proposals from independent pipeline companies should be solicited. There is a feeling that the AGIA contract results were not what had been hoped for, and a sour feeling over the $500 million the state committed as a subsidy to TransCanada, about $300 million of which has been paid out. “I think we should know what the costs are to go with TransCanada and what costs there are to go without them, and the benefit, if any, to go with someone else,” French said in an interview. A consultant to the Legislature, Janak Mayer, told the Senate Resources Committee Feb. 3 that having an experienced pipeline company as a partner in the project could be a real advantage to the state. The goals of the North Slope producers, as pipeline owners, will be to maximize overall profits from gas production, transportation and sales, but an independent pipeline company like TransCanada makes its money by transporting gas and earning a profit on its ownership of all or part of a pipeline, he said. Because of this a pipeline company is motivated to find ways to ship more gas and expand, while other owners, the producers, do not share that bias. The state, as a direct owner in the pipeline instead of TransCanada, could also push its partners for expansion but would not have the experience in this that a pipeline company has, Mayer said. Mayer also warned of potential delays in the project if the state has to take time to solicit and evaluate bids from other potential partners. “You might wind up with a better deal or you might not, and you may no longer be able to get the deal you have now,” with TransCanada, he warned. The year or two that this process could take might impair the current momentum for the project. Potential customers are now sensing real progress with the Alaska gas project and they are taking note of it, Mayer said. If there are delays as the state tries to find other partner those customers may see it as yet another setback for Alaska, and the project will lose credibility, he said. French said a big question he has is what the possible downsides of the overall deal might be for the state. “What’s our exposure? No one has quantified this yet,” he said. “Also, if the state has to make a direct investment at some point, will we have the cash to do this, given our revenue outlook?” There is a lot of caution about the long-term obligations. “We have learned some lessons from the AGIA deal. A lot of legislators who voted for the AGIA contract with TransCanada four years ago are now feeling a bit of buyers’ remorse,” and don’t want to repeat the experience, French said.

Report due in March on Canadian-Alaska oil railroad link

A preliminary feasibility study for a proposed1,600-mile rail link from British Columbia to Alaska will be completed in March, officials with G7G Railway Corp., a Vancouver, B.C-based company, told state legislators in Juneau Jan. 30. G7G hopes to ship Alberta oil by rail from Fort McMurray, Alberta, to Delta for export through the Trans-Alaska Pipeline System and the Valdez Marine Terminal, said its president, Matt Vickers. Eventually, as much as 1 million barrels per day could be shipped by rail and exported through Valdez, he said. Alberta’s provincial government is interested in the idea and is funding the $1.8 million pre-feasibility study through the Van Horne Institute at the University of Calgary, Vickers said. AECOM Canada Ltd. has been contracted to do the pre-feasibility study, he said. A key part of the G7G proposal is to include First Nation groups in Alberta, B.C., and Yukon Territory, as well as Alaska Native corporations, as partners. Vickers, who is himself Tsimshian with family connections to Haida in Southeast Alaska, said Canadian First Nations are opposing a plan by Enbridge and Kinder Morgan to build pipelines to B.C. and export crude oil by tanker. “We’re all opposed to supertankers operating off the B.C. coast,” Vickers said. The rail plan to Alaska is being offered as an alternative. Vickers said his company worked with scoping studies for an Alaska-Canada rail link that were sponsored by the state of Alaska and Yukon Territory that were done in 2006 and 2007. At that time the focus was on a railroad for exporting mineral ores from Alaska and Yukon and transporting general freight north. The concept of moving oil by a rail route to Alaska builds on that idea, Vickers said. Former Alaska Gov. Frank Murkowski, who initiated the Alaska-Yukon rail reconnaissance work while he was governor, said he still supports the idea. “We were very interested in a rail link but the challenge was finding a way to pay for it. This idea, of shipping crude oil, may be the way to do that,” Murkowski said in an interview. In an interview, Vickers said, “We were told by the Alberta government that they would be interested if we could a way to export oil for $10 per barrel or less. Our first scoping study indicated we might be able to do this for about $8.30 per barrel.”  Based on that, Alberta approved the $1.8 million for the pre-feasibility study, he said. Even if one of the pipelines to B.C. is approved and the Keystone XL pipeline goes ahead, G7G believes the growth of Canadian oil production will require more capacity in 10 to 15 years, and the big advantage of rail is that it can serve multiple customers. An initial estimate is that a single-track line to Alaska could be built for about $12 billion and that a double-track line might cost $16 blllion, Vickers said. More refined estimates are in the pre-feasibility study due out in March. If the pre-feasibility study shows the project to be possible, the next step is to raise several hundred million dollars to do a full-blown feasibility and engineering study. “The key to any of these projects is getting the social license to build,” he said. Kinder Morgan and Enbridge have failed to do that, and Vickers doesn’t think the federal government will trample over First Nations, forcing the issue. Alaskans have meanwhile long been intrigued with the idea of a rail connection with the B.C. rail system. The state now owns and operates the Alaska Railroad Corp. connecting Southcentral with Interior Alaska, and is planning an extension of the railroad east to Delta, in eastern Alaska, to support military missile defense facilities that are built there. Vickers said G7G’s conceptual studies show the cost of building and shipping crude by rail from Alberta to be about the same as by pipeline, and rail has the added advantage of being able to ship other bulk commodities from Alaska, particularly mineral ore. Passenger service could also be offered. Vickers said some contacts have been made with North Slope producing companies who own TAPS but he also noted that as a common carrier the pipeline accepts oil offered by third parties for shipment, subject to penalties for any effects on quality. TAPS owners, which include BP, ConocoPhillips and ExxonMobil, have said they are interested in shipping more liquids through the pipeline, which is now operating at about one-fourth of its design capacity. However, on company has expressed concerns over the quality differences of oil from Alberta. Trond Erik Johansen, ConocoPhillips’ Alaska president, said that if Alberta bitumen is to be shipped through TAPS it would have to be first refined and upgraded so as not degrade the value of North Slope crude now carried by the pipeline. Alaska itself would be concerned with any changes in quality and sales value of crude oil since state revenues could be affected, said Kevin Banks, a commercial manager at the state Dept. of Natural Resources. “Bitumen would have to be blended with lighter oil, and oil shipped north would have to meet TAPS specifications,” Banks said. “Also, payments would have to be made to the existing TAPS shippers to adjust for any qualify differentials. There are mechanisms in place to do this.”

Shell scraps its 2014 Chukchi drill season

Shell has scrapped its planned 2014 Chukchi Sea exploration program. The decision was made because of uncertainties raised by a Ninth Circuit Court of Appeals decision in a lawsuit over environmental reviews of a 2008 federal Outer Continental lease sale in which Shell and other companies won leases in the Chukchi Sea. “As a result of uncertainty raised by the recent Ninth Circuit Court decision that requires the Bureau of Offshore Energy Management to gather and synthesize additional data related to Chukchi Lease Sale 193, we have made the decision to stop the planned 2014 exploration program offshore Alaska,” Shell spokesman Curtis Smith wrote in an email. “The lack of a clear path forward and an associated timeline makes it impossible to commit the resources needed to explore safely in 2014,” he wrote.  A three-judge panel of the Ninth Circuit Court held that the U.S. Mineral Management Service, the predecessor agency to the U.S. Bureau of Offshore Energy Management, had used an improper, conservative estimate as a basis for environmental review in the environmental impact statement, or EIS, for the lease sale. The agency had assumed an initial find of one billion barrels of recoverable reserves in the Chukchi sale area. A coalition of environmental groups and two Alaska Native organizations filed a lawsuit claiming the agency should have used a higher figure in the EIS. ConocoPhillips spokeswoman Natalie Lowman said her company understands Shell's decision. “It is essentially the same one we made in April 2013. We remain concerned about the impact of ongoing litigation and its potential impact on our ability to operate in the Chukchi Sea. Gov. Sean Parnell reacted strongly to the announcement. “This news is extremely disappointing for Alaska, but certainly understandable given the recent Ninth Circuit Court ruling,” Gov. Sean Parnell said. “Multiple years of federal regulatory delay, litigation delay, and one year of operational issues have created barriers to Alaskans’ near-term economic prospects. “This is a textbook example of how the federal framework can negatively impact our economy, and how it can actually slow the progress of technology and innovation, harming key national interests,” Parnell said. Shell has made major investments in Arctic offshore exploration technology, Parnell said, but the court of appeals ruling applied to regulatory processes used in 2008 by the Department of the Interior in issuing leases to Shell.  Alaska’s two U.S. senators also voiced concerns. Alaska U.S. Sen. Lisa Murkowski, a Republican, said, “I am disappointed that Shell will not be able to move forward with exploration this summer, but am not surprised. I expect the administration to work quickly to address the deficiencies identified by the court in its analysis of lease sale 193.” Alaska’s other senator, Democrat Mark Begich, said, “It is simply unacceptable that judicial overreach is getting in the way of letting Alaskans develop our own natural resources.”  “I’ll be talking with Interior Secretary Sally Jewell today and expect her agency to move quickly to address the court's questions and concerns and do everything possible to get this process back on track. As Shell suggested in its announcement this morning, this is a temporary setback and I believe the prospects for Arctic development remain strong. I’m confident that this project will move forward.”  Environmental groups cheered Shell’s announcement, however. Greenpeace International Arctic oil campaigner Charlie Kronick said, "Shell’s decision to gamble on the Arctic was a mistake of epic proportions. The company has spent huge amounts of time and money on a project that has delivered nothing apart from bad publicity and a reputation for incompetence. The only wise decision at this point is for (Shell CEO Ben Van Beurden) to cut his company's losses and scrap any future plans to drill in the remote Arctic Ocean,” Kronick said in a statement.

Slope, Cook Inlet winter drill seasons underway

Winter exploration drilling on the North Slope is starting, with Repsol beginning work on three North Slope winter exploration wells near the Alpine field west of Prudhoe Bay and near the Kuparuk River field. There’s new exploration underway in south Alaska, too, with Buccaneer Energy started now on a gas exploration well east of Homer, the company announced. Most exploration begins on the North Slope in late January and this winter will be busy with Repsol, ConocoPhillips and Linc Energy all drilling test wells at remote sites. Exploration drilling is done only in the winter in northern Alaska because ice and snow roads can be built to remote well sites. Repsol’s program is similar to its exploration programs over the past two winters, spokeswoman Trish Baker said, and is in the same area of the west-central North Slope. Linc Energy, an Australia-based independent, has also mobilized its drill rig at Umiat, in the southeast National Petroleum Reserve-Alaska, or NPR-A. The company plans one to three horizontal test wells in its second year of test drilling at a known shallow oil deposit at Umiat. Linc now expends to begin drilling in early February, company spokesman Paul Ludwig said. “Warm weather has pushed our snow and ice road building back a little,” which has delayed the start of drilling, he said. ConocoPhillips also plans two exploration wells in the NPR-A in areas west of the Alpine field, in a partnership with Anadarko Petroleum Corp. Repsol made three discoveries on three wells the company drilled last winter and two of the wells planned this year, Q-5 and Q-7, are delineation wells aimed to get additional information on those discoveries, the company’s Alaska manager, Bill Hardham, said in an interview Jan. 24. The wells will be drilled just south of two discovery wells from last winter, Q-1 and Q-6, which are in the Colville River delta east of the producing Alpine field. Flow tests were done on the two wells last year, and flow tests are planned on the two delineation wells set for this winter, Hardham said. A third discovery well drilled last year, Q-3, was not flow-tested. Another well planned this winter, Tuttu No. 1, is an exploration well planned to be drilled inland and to the east, near the Kuparuk River field. Repsol is using three rigs on its winter program, all operated by Nabors Alaska Drilling. The project includes 30 miles of winter ice roads to the locations from existing year-around roads in the Kuparuk field as well an ice airstrip, Hardham said. North Slope explorers have to build ice roads each winter, a major expense. In 2013 Repsol built 38 miles of ice roads; in 2012 the company built 48 miles. Repsol is exploring 700,000 acres of state oil and gas leases. Armstrong Oil and Gas, of Denver, is a 22.5 percent partner in the onshore acreage, with GMT Exploration owning 7.5 percent. The company also holds offshore Outer Continental Shelf leases in the Beaufort Sea in partnership with Shell and Eni, as well as in the Chukchi Sea OCS, where the leases are 100 percent Repsol. Linc drilled at Umiat, in the NPR-A, last winter and stored the rig, operated by Kuukpik Drilling Co., over the summer. The project is being supported this winter by a 101-mile snow road built to Umiat from the Dalton Highway, a year-around industrial road the connects the North Slope oilfields with Interior Alaska. Umiat’s oil was discovered decades ago by U.S. government-sponsored drill crews. The deposit was shallow and of very good quality oil but too small to merit development. Linc believes it can exploit the deposit with new horizontal drilling production technology and also expand the known resources.  Winter exploration provides a big boost for service companies in Alaska, and activity levels this winter by Repsol and other companies may stretch the availability of skilled oil workers. ExxonMobil Corp. is also engaged in construction and pipeline building to the new Point Thomson gas and condensate field east of Prudhoe Bay, with over 700 employed there this winter. Hardham said Repsol’s drilling program will employ about 350 but the company is also planning two winter seismic programs, by SA Exploration and Global Geophysical, that will employ about 100 people each. The company’s total winter workforce will be around 500, he said. In the Cook Inlet Basin, Buccaneer Energy has finally started drilling its West Eagle natural gas exploration well east of Homer. The rig has been at the site for some time, but financing problems with a former partner delayed the start of operations. Drilling began Jan. 22, with the well planned to reach a depth of 8,500 feet. The location is 21 miles east of Homer, and has road access.

Shell Arctic plans at risk after 9th Circuit Court tosses EIS

A Jan. 22 U.S. 9th Circuit Court of Appeals ruling could invalidate a key section of the Environmental Impact Statement on the 2008 Chukchi Sea Outer Continental Lease Sale, throwing a wrench into planning by Shell to return to the Arctic this summer. The U.S. Interior Department, the defendant in the case, could ask the Ninth Circuit for a hearing before the full court, as the Jan. 22 decision was not unanimous among a three-judge panel. Alternatively, the case could be returned to the Alaska U.S. District Court, where Judge Ralph Beistline had earlier approved the EIS for the lease sale. A coalition of 13 environmental groups and two tribal groups, the Native Village of Point Hope and the Inupiat Community of the Arctic, had brought the lawsuit. Almost every legal option in dealing with the appeals court decision will take time, however, and Shell may be running out of time, for this year at least. The company must begin making commitments soon to contractors and suppliers if it is to get its drill fleet ready to move north in July. Approvals of an expenditure to mobilize a fleet of two drill ships and 20-odd support vessels must come soon, and it might involve a commitment of several hundred million dollars. Shell has already laid out about $5 billion on its Arctic exploration program including $2.3 billion spent to acquire the Chukchi Sea leases in 2008. If the decision of the three-judge panel isn’t reversed, the U.S. Bureau of Ocean Energy Management, the Interior Department agency which is responsible for OCS leasing, may have to prepare a new Environmental Impact Statement. That could take 18 months to 24 months. Any delay for Shell is also a delay for ConocoPhillips and StatOil, which also have plans to drill Chukchi Sea OCS leases those companies hold. What’s at issue now is the size of an oil field the Interior Department estimated was most likely in the Chukchi Sea as a first discovery. The agency concluded that a one billion barrel find was reasonable. Environmental groups contesting the sale argue that the agency should have used a higher figure, including the possibility that more than one field will be developed. The majority opinion of the 9th Circuit panel agreed, saying the federal agency used an “arbitrary and capricious” method for settling on one billion barrels in the lease sale EIS. The figure is important because all of the analyses of environmental effects of the lease sale are based on that assumption. Neither Shell or the BOEM would comment on the appeals court ruling, but the environmental plaintiffs were quick to offer their opinions.  “We think they should go back and do a full EIS, or redo the one they have. The flaw in the assumption infects the entire analysis,” said Erik Grafe, an attorney with Earthjustice, an environmental law firm helping represent the plaintiffs. “Right now the ball is in the agency’s court,” he said. Grafe said the Interior Department may be in a weak position to assert the one billion-barrel figure because the agency made estimates in 2006 that as much as 12 billion barrels might be developed in the Chukchi Sea at an $80 oil price. “The Interior Department should reevaluate its decision to offer leases in the Chukchi Sea in light of the higher risks,” he said. The lawsuit has been around a long time. Environmental plaintiffs won the first round in challenging the adequacy of the EIS in 2010. The Interior Department redid the document, which took about 15 months. The supplemented EIS got the approval at Judge Beistline’s court, but the plaintiffs appealed it to the 9th Circuit. Meanwhile, BOEM issued permits and Shell moved ahead with its 2012 drilling based on the U.S. District Court approval. Arguments were heard at the appeals court last March, and the decision was made by the three-judge panel on Jan. 22. Judge Ferdinand Fernandez and Judge William Fletcher agreed with the plaintiffs while Judge Johnnie Rawlinson dissented. Rawlinson reasoned that judges should not substitute their own opinions for the expertise of government agencies in scientific determinations. “We do not sit as a panel of super-scientists to dissect the agency’s analysis,” he wrote. “There is no such thing as a ‘perfect’ estimate and BOEM was not required to adopt a different benchmark in the face of its critics.”

Terms for Alaska LNG project go before state lawmakers

More details are becoming available on the agreement signed by officials of Gov. Sean Parnell’s administration with the North Slope producers and TransCanada Corp. on the proposed large natural gas pipeline and liquefied natural gas export project. Companies engaged in the project endorsed the agreement for the Alaska LNG Project. “This agreement integrates the resources of all parties behind this potential Alaska LNG project. It sets out guiding principles for the parties to negotiate project-enabling contracts once the Alaska Legislature passes the enabling legislation,” BP spokeswoman Dawn Patience said. The “Heads of Agreement,” or HOA, signed by the parties acknowledges the project is in the Pre-Front End Engineering and Design, or pre-FEED, phase, long a key goal sought by Parnell. However, before the $400 million pre-FEED work fully ramps up, the Legislature must pass bills enabling key terms of the state’s involvement in the project. “The intent of the HOA is to provide Alaskans with a roadmap for how the parties intend to progress the Alaska LNG Project,” according to a ConocoPhillips statement. “Consistent with the principles in the HOA, ConocoPhillips looks forward to working with the Parnell Administration and the Alaska Legislature to advance discussions on fiscal and commercial terms to help progress the project.” Legislation is expected to be introduced soon in the state House and Senate, sources in the state administration said. Lawmakers must approve the state’s taking of its production tax value of future gas in-kind, or in the form of gas, and to convert the state’s current net-profits gas production tax to a gross revenues tax. Another decision legislators must make is the amount of the gas tax that would be taken in-kind, or as gas, Deputy State Revenue Commissioner Mike Pawlowski said in an interview. The state’s royalty is 12.5 percent, which can now be taken in kind, as gas, or in value or cash, at the state’s discretion. If the state’s production tax on future gas production were converted to a share of gas production it would be equal to approximately 12.5 percent, bringing the total state share of gas to 25 percent. However, legislators could opt to take less of the tax share as gas and leave some production subject to the current tax. The agreement contemplates a combined state share of gas ranging from 20 percent to 25 percent, Pawlowski said. Lawmakers are expected to settle on the appropriate number in the 2014 session, he said. A smaller portion of tax taken as gas would mean the state would ship less gas through TransCanada’s part of the pipeline and would sign a shipping commitment for less gas, but in making that decision legislators will weigh potential revenues from sales of the gas, as LNG, against revenues from traditional tax payments. “TransCanada is pleased to continue working with the State of Alaska and North Slope producers to advance the Alaska LNG project,” said TransCanada spokesman Davis Sheremata. “We share the common goal of wanting to develop these important natural gas assets in a way that shows continued progress towards building Alaska’s energy future. “In terms of shipping gas, using a more traditional commercial approach where TransCanada acts as the transporter for Alaska’s portion of gas under a long-term shipping contract means that TransCanada provides billions in capital investment, rather than Alaska.” The TransCanada statement to the Journal said financing of the state share of the pipeline would amount to about $3 billion to $8 billion. Pawlowski said converting the current net-profit production tax to a gross revenues tax, which legislators must also approve, is important because a net revenues tax reacts quickly to gas prices and gas production costs and because of that variability, and uncertainty, it does not easily convert to a share of gas production. A gross revenues tax, on the other hand, does convert to a share of production just like the royalty, which is based on 12.5 percent of the gross revenues or one-eighth of production. The royalty can be converted to an in-kind share of gas. Meanwhile, on the work anticipated under the agreement, pre-FEED engineering work would begin in late spring if the legislative approval is given. “Pre-FEED is anticipated to take between 18 and 24 months to complete, with a determination on proceeding to the FEED, or full Front-End Engineering and Design, phase expected to occur within approximately 36 months after ramp up of Pre-FEED,” or by early 2017 at the latest, according to an analysis prepared by the Federal Gas Pipeline Coordinator’s office. The full FEED work would involve an expenditure of several billion dollars, the analysis said. Meanwhile, the industry consortium working on the project will conduct a major field season in the summer of 2014 with about 300 people in to gather additional geotechnical and environmental data. The summer program is about twice the size of the 2013 summer field program, which cost about $150 million. The expectation in the Heads of Agreement is also that by 2015 more definitive contract terms would be developed involving the state’s commitments to a shipping contract for the state share of gas production, which would be about 20 percent to 25 percent of the total. The state’s shipping contract would be with TransCanada Corp., which would invest in a portion of the Gas Treatment Plant and pipeline sufficient to ship the state-owned gas. State lawmakers would also have to ratify the shipping contracts. The state would have the option of buying 40 percent of TransCanada’s share of the project before the project moves to the full FEED stage, but by Dec. 31, 2015, at the latest. Alternatively, the state has the option of purchasing all of TransCanada’s ownership at the end of the shipping contract for the state gas. Shipping contracts are typically 20 years to 25 years in duration. TransCanada would have no involvement, however, in the large natural gas liquefaction plant planned to be built in Nikiski, near Kenai. A subsidiary of the state-owned Alaska Gasline Development Corp. would finance and own a share of the plant equal to the plant’s capacity used to manufacture LNG with the state-owned gas, again 20 percent to 25 percent. AGDC would issue revenue bonds to pay for its share of the plant capital costs. State officials involved with the project said that ADGC could invite other partners to join it in the LNG plant. Japanese companies like Mitsubishi Corp. and REI Alaska Inc., for example, have expressed interest in owning a share of an Alaska LNG project. The project anticipates transporting 3 billion to 3.5 billion cubic feet per day of gas from Alaska’s North Slope. After gas consumed in-state and at the liquefaction plant, it is anticipated that about 2 billion to 2.4 billion cubic feet per day, or 15 million to 18 million metric tons per year, would be exported as LNG to Asian markets, according to the federal coordinator’s analysis. Tim Bradner can be reached at [email protected]

Oil and gas operators still worried over fracturing rules

Alaska oil and gas operators are still unhappy with proposed new state rules on hydraulic fracturing, which they say go beyond what most other states are requiring in proposed or new regulations. The Alaska Oil and Gas Conservation Commission held another public hearing Jan. 15 on proposed new fracturing rules, the third hearing the commission has held. Modifications have been made in the latest proposal, such as increased trade secret protection for contractors working on fracturing jobs using their own formulas in specialized fluids. However, there are still concerns that the rules go beyond requirements in other states. “Our concern is that these proposed regulations will result in substantial costs without providing any real tangible benefits,” said Kara Moriarty, executive director of the Alaska Oil and Gas Association. “One of our main concerns lies in (water) well sampling,” proposed requirements, she said, which would require companies to obtain samples and do analysis of all water wells within a one-half mile radius of the well being fractured. Most other states require sampling only up to four water wells within one-quarter mile of a well. Sampling of wells both before and after the fracturing would be required. The Alaska conditions for water aquifers are also far different from other states. “The vast majority of fracturing jobs in other regions are targeted to areas within several hundred feet of fresh water aquifers. In Alaska, fractures are targeted at areas thousands of feet, as deep as 9,000 feet, below any fresh water aquifers,” Moriarty said. Another concern is that some of the water sampling parameters in the proposed rules do not correspond to current EPA-approved analytical methods. “This could lead to inconsistencies in testing,” she said. What could exacerbate the problem is a lack of testing facilities in Alaska for some chemicals, which would require samples to be sent out of state for analysis, steps that would take several days and pose delays for operators. In addition to the sampling rule, Alaska is also proposing a dual-reporting requirement. Operators would file reports with FracFocus, a national information clearing-house on hydraulic fracturing, as well file a separate state report, she said. The problem is mainly that the state reporting requirements may be different than those for FracFocus. The proposed rule isn’t clear on that. The concern is that a dual reporting rules adds more work for operators without any apparent benefit, Moriarty said. Conservation groups weighed in with criticism of the latest version of the regulations. The Wilderness Society says it objects to changes in the proposed rules, from earlier drafts, that allow more protection of trade secrets as to the chemical composition of fluids used in fracturing. “Public health and environmental concerns justify full disclosure of all hydraulic fracturing chemicals,” said Barrett Ristroph, the Wilderness Society’s Arctic Program representative. “We don’t allow food manufacturers to classify ingredients as trade secrets just because they’ve spent a lot of money developing them,” Ristroph said. “The oil and gas industry should be held to the same standard.”

BOEM asks Shell for more information on Chukchi plan

The U.S. Bureau of Ocean Energy Management is asking Shell for more information on its proposed 2014 exploration program in the Chukchi Sea. Shell submitted information in December to the agency’s first request after the company filed its plan in November, but BOEM needs to clarify certain points before it can make a determination that Shell’s exploration plan is complete. Once a “completeness” determination is made on Shell’s plan, the agency has 30 days to give it final approval, David Johnston, the agency’s supervisor for Alaska leasing, said during an interview with BOEM Alaska officials. Even after BOEM approves the plan, the company will still have to work with other federal agencies on permits, such as the U.S. Fish and Wildlife Service and the U.S. Bureau of Safety and Environmental Enforcement, or BSEE, Johnston said. One difference from Shell’s permitting for its 2012 exploration is that the company will be able to secure federal air quality permits through BOEM rather than the U.S. Environmental Protection Agency. BOEM issues these permits for oil facilities in the Gulf of Mexico but until a recent federal law change the EPA was given responsibility for the permits in the Arctic. The same standards for air quality will be applied because those are set in the federal Clean Air Act. However, BOEM may implement the federal law differently, requiring that the measurements for the presence of pollutants from emissions be taken in the nearest areas used by people, which would be subsistence harvest areas along the coast. That will be miles away from Shell’s drill location, which is about 60 miles offshore. EPA, in contrast, required the measurements to be taken in a zone immediately around the operating vessels. Shell has said it will decide on whether to mobilize its Arctic drill fleet for the 2014 summer season once permits are in place. The company has outlined its plans, which involve two drill vessels and about 27 support vessels, in its exploration proposal. In a statement, Shell spokeswoman Meg Baldino said, “Ours remains a methodical approach and we will only proceed in Alaska if the program meets the conditions necessary to operate safely and responsibly.”   On a related issue, Johnston said the U.S. Interior Department plans to finalize its new Arctic drilling regulations by the end of January but that the rules then go to the Office of Management and Budget for final review. That could push the final rulemaking to mid-spring, he said. However, Shell can proceed under existing offshore drilling rules, said James Kendall, BOEM’s Alaska regional director, in the interview. The general content of the pending new Arctic rules is known to industry and Kendall said he doesn’t expect Shell to wait on them. “We have rules and regulations out there for industry now. What’s in the new rule reflects what was in the 60-day report to the secretary (on Shell’s 2012 operations) so there are no surprises there,” Kendall said. Last summer Interior officials said the new rules will include requirements for containment domes and other special Arctic measures that the industry is now planning anyway. Shell’s plan for 2014, if it proceeds, includes returning to the Burger prospect in the Chukchi Sea where a “top-hole,” or upper part of a well, was completed in 2012. The drillship Noble Discoverer will again be used, according to the company’s plans filed with BOEM, although the ship will see substantial upgrades to solve operational problems encountered in 2012. A second drill vessel, the TransOcean Polar Pioneer, will be kept on standby in Dutch Harbor in case an emergency requires its use. Shell will not be drilling in 2014 in the Beaufort Sea, however. One top-hole well was also drilled there in 2012 but the Kulluk, a specialized drill vessel designed for the Beaufort Sea, was grounded and damaged in a storm in the Gulf of Alaska in December 2012 and will not be returned to the Arctic, Shell has said. Despite cutbacks in many federal budgets, Kendall said BOEM’s Alaska office has the staff in reviewing plans put forward by Shell and possibly other companies. “We have the resources to do what is necessary now,” he said. “We want to emphasize that we take our responsibilities for stewardship in the Arctic seriously, for all aspects, geology, engineering and oceanography. Working in the Arctic is serious business, so we are going through these plans with a fine-toothed comb.”

State, producers, TransCanada ink key agreement on pipeline

Gov. Sean Parnell and companies leading the North Slope gas pipeline project took a major step Jan. 14, signing a "Head of Agreement" statement that lays out terms for how the state could help facilitate the effort through an ownership stake and its fiscal terms. The next step is up to the state Legislature, which convenes Jan. 21 for its 2014 session. Parnell will introduce a number of bills soon that will make the state’s involvement possible. State officials made more details available Jan. 15 on how it could partner with North Slope producers and TransCanada on the project, which is estimated to cost $45 billion to $65 billion. The deal also changes a licensing agreement with TransCanada under the Alaska Gasline Inducement Act, or AGIA, but it keeps the pipeline company in the consortium as a partner. If the project moves forward, the state could earn $2 billion to $3 billion yearly in new revenues from gas sales, state Natural Resources Commissioner Joe Balash said in an interview. Under the plan the state would commit to take its one-eighth royalty share of gas production in kind, or in the form of gas, for the duration of the project, and also take state production taxes as a share of the gas, Balash said. The state Legislature will be asked to allow that change this spring, Balash said, and also to determine a percentage of the combined state share of gas production. The state royalty is 12.5 percent of production and adding the tax share would bring that to between 20 percent and 25 percent, with the number to be decided by the Legislature, he said. Separately, the state has entered into a deal with TransCanada to finance, and at least temporarily own, a share of the pipeline and LNG project equal to the state’s share of gas, Balash said. The state will then enter into a shipping contract with TransCanada to transport the state gas to the LNG plant in Southcentral Alaska at Nikiski. TransCanada would raise the estimated $6 billion to $7 billion needed for its share of pipeline construction, Balash said. One major concern for the state in the arrangement would be having to market its own gas. “Under that scenario, we might wind up with a lower price,” for LNG because the state lacks a marketing organization and experience and TransCanada would only ship the state’s gas. “However, the producers have agreed to a ‘disposition’ agreement, under which they will be prepared to market our gas,” Balash said. Under the agreement, the state also has the option of purchasing TransCanada’s share of the project when the contract to ship the state gas expires, which could be 20 years to 25 years, Balash said. Alternatively, the state can purchase 40 percent of TransCanada’s share prior to construction beginning, he said. The pipeline itself will be organized as a joint undivided interest pipeline, meaning that each gas owner will agree to finance and own a percentage equal to its gas production share, essentially a group of separately-owned pipeline entities using one pipe and an LNG plant. The Trans-Alaska Pipeline System was organized along similar lines when it was formed in the early 1970s to ship North Slope oil. Legally, each TAPS owner operates its own pipeline entity within TAPS, with Alyeska Pipeline Service Co. as the independent operating company. The LNG plant in Nikiski will be handled differently, Balash said. TransCanada will have no ownership in the plant, and the state’s ownership will be held through a new subsidiary of Alaska Gasline Development Corp., a state corporation formed to build a smaller gas pipeline from the North Slope in the event the large industry-led project stalls. Balash said AGDC will continue planning on its own project, which is a contingency to supply gas to Alaska communities. If the plan with the producer consortium moves forward, however, the state corporation would finance its share of the LNG plant with revenue bonds, state revenue commissioner Angela Rodell said. If the Legislature approves statutory changes to enable the plan, which also includes converting the state’s net profits gas production tax to a flat tax on gross revenues, the companies are prepared to begin Preliminary Front-End Engineering and Design work, or pre-FEED, a step that will involve an expenditure of several hundred million dollars, Balash said. Conversion of the net profits tax to a flat gross revenues tax is necessary because the net profits tax is volatlle, reacting quickly to price changes, which would make it more difficult to convert the tax to a share of gas and contract for capacity in a pipeline, Balash said. The flat-rate gross revenues tax simpler and more transparent, he said. Also, if the Legislature approves the statute changes, North Slope producers have agreed to begin organized marketing efforts to sell the Alaska LNG including the state’s share, Balash said. The project would produce 15 million to 18 million tons of LNG yearly. An important consideration in the deal with TransCanada — an element that is retained from the AGIA contract — is the pipeline company’s commitment to certain terms in financing that are to the state’s advantage in maximizing revenues. The pipeline company has agreed to fund its share of the pipeline and Gas Treatment Plant on the Slope using a 75 percent debt and 25 percent equity investment ratio. That combination results in a lower pipeline tariff, Balash said, which means less shipping costs for state-owned gas, and higher state revenues. The debt-equity ratio commitment was one of the state’s “must-haves” in its AGIA initiative in 2008 and 2009, and is one the producers have always balked at. It was one of the key obstacles confronting the current deal, too. As the arrangement now stands TransCanada will retain its commitment on the debt-equity ratio but the producers will retain the flexibility in using whatever financing ratio is most advantageous to them. Because the producers will be shipping their own gas, and not the state’s, and the state’s royalty and tax share would be converted to gas shipping by TransCanada, the matter is less important under the new deal.

Only 300 Alaskans signed up for insurance

By fits and starts Alaskans are beginning to be enrolled through the new federal health insurance exchange as startup glitches are resolved. “October was not our best month,” said Susan Johnson, Region 10 director for the U.S. Department of Health and Human Services. Johnson was in Anchorage Dec. 3 to give assurances that problems that virtually shut down the federal exchange website when it launched Oct. 1 are being solved. Johnson appeared with Tyann Boling, chief operating officer of Enroll Alaska, and Jon Zasada, development director at Anchorage Neighborhood Health Center, at a Dec. 3 briefing. Enroll Alaska is a private brokerage service, a subsidiary of Northrim Benefits Group, that is working through the federal exchange. Anchorage Neighborhood Health Center is one of several community health centers where assistance in enrolling is offered, mostly to low-income Alaskans. Boling said her group enrolled 14 people on Monday, Dec. 2, its best day yet. “Two weeks ago that would have been impossible,” she said, given the technical problems in the exchange. Overall, 86 people have been successfully enrolled by Enroll Alaska through the exchange and an additional 36 outside the exchange, Boling said, Almost all since mid-November, she said. Melanie Coon, spokeswoman for Premera Blue Cross, one of two companies competing in the Alaska federal exchange, said her company had enrolled 200 Alaskans through the exchange as of Nov. 30. The other company in the exchange is Moda Health. Representatives of Moda Health did not respond to inquiries before press time Dec. 4. In performance, Boling said the exchange merited “1” on a scale of 10 in October, the first month of its launch, she said, and by November had moved up to a 4. “As of today, we think we’re at 7,” Boling said. Johnson of HHS agreed 7 might be the right ranking, “but we would like to get it to 10 as quickly as possible,” she said. Boling said it is now taking about 45 minutes for people to complete the process through Enroll Alaska. Zasada said his clients at the Anchorage Neighborhood Health Center have been taking a little longer, taking about an hour with the help of “navigators” trained to provide assistance. “It’s a complicated process. Health insurance is complicated,” Boling said. A “subsidy calculator” in the exchange that was nonfunctional at first has been repaired and is functioning smoothly, she said. Also, Enroll Alaska is able to verify within days that a policy it purchased through the exchange for a customer has been accepted by an insurance company, she said. On a national level, insurance companies have had difficulties getting proper information to issue policies from many applications on the exchanges. Glitches remain in the “back ends” of the exchange, the systems that ensure the insurance company gets all the information it needs to issue a policy and take payment. Johnson admitted verification of insurance is still a problem for those enrolling through the federal exchange in Alaska. Until the problem is solved, people enrolling should contact insurance companies themselves to verify the policy, she said. Premera Blue Cross said it is getting information from people applying through the Alaska federal exchange but said the company is verifying data itself, Coon said.  But things are smoother, and Johnson expects a rush as people seek to complete enrollments by Dec. 23 so as to have insurance Jan. 1 and avoid a tax penalty. “We have made significant progress with the ‘fluidity’ of the exchange (its processing speed) and there are fewer shutdowns. We believe we will be able to handle 50,000 people using the exchange any given time, and up to 300,000 in one day,” Johnson said. Meanwhile, it’s still too early to determine just who is signing up for insurance, Johnson said, and whether the numbers include enough young people, who are healthier and lower-cost, in addition to middle-aged and older people who will have more health problems. Figures on demographics should be available by mid-December and they will be broken out by state, she said.

State closes fiscal 2013 in red; oil production drops almost 8%

The final numbers won’t be known for several more weeks, but it appears the state will dip into cash reserves to the tune of $384.4 million to pay the bills for state fiscal year 2013 ended June 30. A larger deficit, $667.9 million, is estimated for the current state fiscal year 2014, but that will surely change through the year as forecasts are refined for oil prices and oil production, state budget director Karen Rehfeld said. In another development, the state Department of Revenue said North Slope oil production dropped about 8 percent last year, to an average of 533,000 barrels per day. Oil and gas taxes and royalties pay for about 90 percent of the state budget. Fortunately, the state has ample cash reserves on hand. The Statutory Budget Reserve, from which state treasury officials can draw, was at $5.49 billion in market value as of June 30, according to the state Department of Revenue. A separate Constitutional Budget Reserve, which requires legislative approval for a draw, was at $11.56 billion on June 30. State revenues totaled $11.91 billion in FY13, while spending totaled $12.3 billion. In FY14, revenues are projected to total $10.66 billion, while spending approved by the Legislature last spring totaled $11.33 billion. The spending figure will change because there will be inevitable supplemental appropriations submitted to the Legislature next spring for unexpected expenses, such as an unusually heavy forest fire year requiring firefighting activity. Rehfeld said a better estimate for the FY13 deficit will be known in September when state agencies complete the accounting for reappropriations of funds made by the Legislature. The fiscal year ends June 30 but it takes several weeks for reappropriations to be sorted out. The final numbers come in December when the state publishes its annual financial report, Rehfeld said. State revenue officials said oil production declined 7.96 percent between fiscal year 2012 and the just concluded fiscal year 2013. The figures are still preliminary and may be adjusted, the department said. The higher rate of decline appears to be mainly due to an unusually heavy schedule of maintenance on North Slope production facilities during the summer of 2012, which required production to be reduced. Summer maintenance of facilities in 2013 appears more normal, so the production decline should be closer to the long-term average of 6 percent, the department said. Tim Bradner can be reached at [email protected]

Citizen group hands in petitions for voter referendum on oil tax change

A citizen group dissatisfied with the Legislature’s action to reduce oil taxes earlier this year handed petitions with 50,000 signatures to state election officials Saturday calling for a voter referendum to repeal the law. The signatures are more than enough needed to put a referendum on the August, 2014 state primary election ballot, supporters said.  The "Vote Yes - Repeal the Giveaway" group needed 30,169 signatures from registered voters, or 10 percent of the total turnout in the last statewide election, to get the question on the 2014 ballot. Critics of Senate Bill 21, a bill passed by the Legislature April 14 and signed recently by Gov. Sean Parnell, say the law reduces taxes on industry without adequate guarantees that new investments will be made. "This bill that they passed is against the interests of Alaska," said Vic Fischer, a former state senator and one of the prime sponsors of the signature-gathering drive, told a group of about 50 tax-cut opponents gathered outside state election offices. In petition drives organizers always push to have more than the minimum number of signatures because some are inevitably rejected after they are checked by elections officials. Signers must be registered to vote in Alaska. Signatures must be checked within 60 days under state law. With 50,000 signatures handed in, Fischer said he is confident there will be enough valid signers to quality for the ballot. Prior to passage of Senate Bill 21 Alaska had one of the highest tax rates on oil and gas in the world. Under the former law the “total government take” of taxes and state royalty on Alaska production averaged about 74 percent of net profits, consultants to the Legislature said. As a result, industry investment in new Alaska production has lagged in recent years while investment has boomed in other U.S. producing regions. The tax change made in the bill that passed lowers the effective rate to between 60 percent and 65 percent, the consultants told legislators. There would be short-term negative effects on state revenues of about $300 million a year, but if the tax change stimulates investment the negative effects could be easily offset by new production, state revenue officials have said. The state revenue department has estimated that $5 billion in new North Slope investment would stimulate enough production to pay for the tax and create over $1 billion a year in new revenues by 2019. One of the consultants, Barry Pulliam, with Los Angeles-based Econ One, said that “it would be a tragedy” if Alaskans voted to repeal the tax change. “It would be a long time before Alaska could dig its way out of that,” Pulliam told an oil and gas conference in Anchorage last week.

Race on to complete key bills as April 15 adjournment nears

The 2013 state legislative session is in its last week-and-a-half, with adjournment set for April 15. The state budget is the most important item of business for legislators, and House Speaker Mike Chenault and Senate President Charlie Huggins appointed conferees to the House-Senate conference committee April 2 for the state operating budget, in House Bill 65. The House and Senate passed versions of the budget that are down from Gov. Sean Parnell’s proposal of a $9.93 billion budget. There are differences between how the House and Senate handled agency budgets, however, and these will be reconciled in the conference committee. House conference members are Reps. Alan Austerman, R-Kodiak; Bill Stoltze, R-Chugiak, and Les Gara, D-Anchorage Senate conferees are Sens. Pete Kelly, R-Fairbanks, Kevin Meyer, R-Anchorage, and Lyman Hoffman, D-Bethel. The Senate Finance Committee is meanwhile working on the state capital budget, in SB 18. Public testimony was taken April 1 and 2 to allow constituent groups to argue for projects, and the first version of the Senate’s proposal capital budget appeared April 3. Besides the budget for fiscal year 2014, which begins July 1, a number of key bills are at critical stages. Two big items include Senate Bill 21, the oil and gas tax change, that has now passed the Senate and is in the House, and House Bill 4, a bill that facilitates an in-state gas pipeline, which has passed the House and is now in the Senate. Other major infrastructure items include a bill allowing the state to finance a $300 million-plus liquefied natural gas trucking project to get cheaper energy to Fairbanks, in SB 23 and HB 74, both in House Finance Committee; and legislation that would boost the proposed Knik Arm bridge, a $700 million project, with SB 13 in the Senate Finance Committee and HB 23, which the House Finance committee moved out of committee late April 2. Bills that would streamline state permit procedures for projects are at an advanced stage, with HB 77, affecting almost all general state land-related permits, having passed the House and now in Senate Finance committee along with the Senate version, SB 26. SB 59, streamlining oil and gas permit procedures, is now in Senate Finance and the House version, HB 129, is now in House Finance; SB 27, authorizing the state to assume administration of some federal dredge and fill activities now under the U.S. Army Corps of Engineers, passed the Senate and is now in the House Finance Committee. Of interest to general business, SB 12, which revamps the state’s procurement code in ways that will aid small businesses, passed the Senate with unanimous support and is now in House Rules Committee, awaiting placement on the House calendar for final passage by the Legislature. The bill also makes changes to the Alaska bidder preference in the procurement code. One bill that caused a real dust-up among supporters of the state’s infant film production support industry is Rep. Bill Stoltze’s HB 112, which would repeal the state’s film tax incentive program. After several hearings in the House Labor and Commerce and Finance committees the bill appears to be on hold in the Finance committee. However, things can happen quickly in the closing days of the session. The incentive encourages companies to produce films in Alaska by allowing them to offset some costs by sales of tax credits to companies with Alaska tax liability. Usually the tax credits have to be sold at a discount, however, because there is a limited market for the credits.


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