Tim Bradner

Individual insurance pool to see sharp premium hikes

Health insurers have filed for substantial increases in allowable premiums on individual non-subsidized health insurance plans issued through the federal Affordable Care Act, or ACA. Under state law the state Division of Insurance approves increases in health premiums. Permission for as much as a 37 percent increase in 2015 has been granted, according to the division. Premera Blue Cross of Alaska, one of two companies filing the request, said the increase is needed to cover large losses the company suffered in 2014 in its Alaska individual insurance plans. The extent of Premera’s losses are severe. “Between Jan. 1 and June 30, 2014 we had more than $7 million in medical claims from only 33 members (of the plans). That’s roughly one third of all the medical claims costs for the 7,000 members in the individual plans,” Premera said in a statement. “We’re currently paying an average of $723 (per member) in medical claims per month and receiving an average of $540 a month (per member) on premiums. We expect to lose $3.7 million in 2014 serving the individual market on those claims. “At the rate of those payments, the company would have to have a 71.5 percent average increase to break even in 2015. We have instead filed for and received approval for a 37.5 percent average rate increase,” the company said. Even with that increase Premera expects to lose $5 million in 2015, it said. The increases will generally not affect lower-income Alaskans receiving federal subsidies for their individual health insurance plans. The other company that filed for the increase is Moda Health. Premera and Moda Health are the only companies selling individual health insurance under the ACA plans. “The problem is really the very small size of the Alaska individual market and the fact that we’ve had a number of people with significant health issues joining the plan and not enough healthy people to spread those costs,” said Premera spokeswoman Melanie Coon. In contrast, states with large numbers of people in the individual plans are seeing decreases in premiums in 2015, Coon said. The average premium in Washington is expected to decline 1.9 percent, and in Oregon an 11.3 percent decrease is expected, she said. Those are average premiums filed by all insurers in those markets and not just Premera Blue Cross. Competition among many insurance companies selling the plans, in contrast to just two in Alaska, may also result in lower rates but the effect of that can’t be predicted yet, Coon said. More companies are signing up to sell insurance in 2015 than were selling in 2014, she said. What allowed the premiums to drop was simply the very large numbers of people signing up under the ACA metallic plans in those two states in sharp contrast to Alaska. In both Washington and Oregon there are several hundred thousand people in the plans, which makes them big enough to absorb the costs of people with health problems. About 16,000 Alaskans in total are covered under individual health insurance policies issued under the federal health care act, the state Division of Insurance said. Coon said about 7,000 of those are Premera’s customers. There are also a number of Alaskans with individual plans issued before Janurary 2014 that are “grandfathered” and not subject to the rate increases, for 2015 at least. What aggravated the situation is that a large number of people with serious health conditions who were formerly enrolled in the state and federal high-risk pools opted to drop that coverage and enroll in one of the ACA “metallic” plans where premiums would be lower. In the state high-risk pool the members paid premiums that were high but even those covered only part of the total costs of medical care. The remainder was paid, in effect subsidized, by all health insurance companies selling in Alaska through a “reinsurance” mechanism. Coon said Premera believes a similar reinsurance mechanism to cover losses in the Alaska individual health insurance market is solution, and that has been proposed to the Division of Insurance.

NordAq secures $90M investment to develop Alaska leases

A Chinese investment group has taken an investment position in NordAq Energy, an Anchorage-based independent oil and gas company working to develop gas discoveries in Cook Inlet and oil discoveries on the North Slope. NordAq and Chinanx Investment Group, of Beijing, made the announcement Sept. 9. This is the first equity investment by a Chinese company in a special oil and gas project although companies with links to China have bid recently in state oil and gas lease sales, according to the Alaska Department of Natural Resources. Chinese companies also have holdings in some Alaska mining projects. A favorable investment climate in the state created by recent changes in state oil and gas tax laws helped Chinanx make its final investment decision, both NordAq and Chinanx said. “These tax and credit policies were recently ratified by the people of Alaska (in the Aug. 19 vote against a repeal of the tax law) signaling to the financial markets that Alaskans are committed to a stable tax regime,” NordAq and Chinanx said. Under the deal, Chinanx will provide up to $90 million to fund the development of NordAq’s Alaska portfolio of assets, NordAq said. The first part of this, $20 million, was made available Sept. 9, according to the announcement. Chinanx will also provide a debt facility for up to $150 million in further financing. NordAq holds state and federal oil and gas leases in Alaska along with leases on private lands, particularly those of Cook Inlet Region Inc., or CIRI, the Southcentral Alaska Native regional corporation. The press release cited an estimated 1.2 billion barrels of potential recoverable oil and a potential 115 billion cubic feet of natural gas on leases held by NordAq. “We are delighted that Chinanx has chosen to make a significant investment not only in NordAq but in Alaska,” NordAq’s chairman, John Kidd, said in a statement. “The resource potential of Alaska is tremendous and this transaction highlights the prospectivity of the state.” Chinanx’s investment will also put its representatives on NordAq’s board. Doris Cheng, honorary chairman of Chinanx will become Vice Chairman of NordAq. “We are pleased to launch this partnership and to be joining NordAq for the next stage of its development. The first of its kind, this deal will help forge a closer union between China and Alaska, a region that is not only politically stable and close to Asia but is also highly prospective,” Cheng said in a statement. NordAq is working to develop a gas discovery on the Kenai Peninsula south of Anchorage but the development planning and permitting has is taking a long time because the project is within the Kenai National Wildlife Refuge. The subsurface mineral rights are owned by CIRI, but the surface lands are owned by the U.S. Fish and Wildlife Service. Because of that the project must adhere to an extensive rules to protect the refuge. The agency cannot prevent production but it can impose stipulations that guide development, U.S. Fish and Wildlife officials have said. On the North Slope, NordAq holds federal leases in the National Petroleum Reserve-Alaska where a previous company, FEX Alaska, made discoveries in exploration drilling. NordAq is still engaged in evaluating the acreage and in exploring other leases in the petroleum reserve and on state leases in state submerged lands north of NPR-A.

Keithley puts money where mouth is on state budgets

Brad Keithley is deeply worried about the unsustainable course the state is on with its finances. With billion-dollar budget deficits and core parts of the state budget still growing, state cash reserves could be drained in a few years, Keithley says. Legislators, however, seem to only give lip service to the problem, and Keithley wants to change that before it’s too late.   Keithley is an oil and gas consultant and an attorney. Out of his own pocket, $200,000 or so, he has started a one-man campaign to raise awareness on the issue during the fall legislative elections. “This is not a PAC (political action committee). I’m not making contributions to candidates or necessarily even targeting candidates. I’m exercising my right of free speech in certain districts where people are running, using mailers and radio, urging voters to ask the candidates about the budget,” Keithley said. He has also mailed out questionnaires to candidates. The Nov. 4 election won’t be the end of this, Keithley said, because he will then watch whether those who are elected live up to campaign promises. Keithley isn’t concerned if he eventually has to report expenditures through the Alaska Public Offices Commission — it’s all his money anyway, so far — but APOC doesn’t come into the picture unless Keithley decides to talk about specific candidates, which he hasn’t ruled out. “I decided to do something about this after the end of the 2014 legislative session. I was extremely frustrated. There are strong Republican majorities in both the House and Senate, and in November 2012, the new Senate Majority listed ‘Develop sustainable capital and operating budgets for current and future generations’ among its top three priorities,” Keithley said. Republicans in the state House made similar comments on their priorities. “So what happened?” Keithley said. The first (2013) session of the two-year Legislature ended with the highest budget deficit, which Keithley puts at $1.9 billion, in the state’s history followed by a $1.6 billion deficit. “I was willing to give them some time to get this under control, but at the end of the second session (2014) there was the second highest deficit in our history,” he said. To be fair, legislators were blindsided with an unexpected large drop in oil revenues and spending was somewhat reduced from pre-2012 levels, but not enough for the budget to be sustainable, Keithley said. “Although the passage of Senate Bill 21 (oil tax reform) holds the promise of increasing revenues in future years, not even the most optimistic predictions of increased revenues justify current spending levels,” he said. What to do? Keithley said that the University of Alaska Anchorage’s Institute of Social and Economic Research has laid out the problem in a series of reports authored by Scott Goldsmith, the ISER’s senior economist. Goldsmith publishes an annual report on state fiscal trends, in December prior to the January start of the legislative session. The conclusion of the ISER analysis has previously been that state general fund spending must be reduced to about $5.5 billion, including operating and capital spending, to be sustainable. After the record deficit in the 2013 session, the sustainable budget number contracted to $5 billion. “With continued deficits and the transfer of $3 billion in state reserves to the public employee pension funds, the number is now likely to be even lower,” Keithley said. How out of whack is the actual spending? In the budget for fiscal year 2014, the state’s last financial year that ended June 30, ISER said spending should be limited to $5.5 billion to keep the budget sustainable. Instead, the total expenditure of state unrestricted general funds was $7.2 billion, according to data from the state Office of Management and Budget. That does not include any Permanent Fund expenditures, such as for the dividend, or Permanent Fund revenue either. Cutting the budget to bring spending down to $5 billion a year — more than a billion dollars — seems draconian but it must be done, Keithley said, or the state is headed for a future of new taxes on citizens, tapping Permanent Fund income, which will affect the dividend, and sharp budget reductions in any event. “We make a mistake if we start quibbling about what to cut. If we go that route we’ll always compromise. You have to just say you can’t afford to spend more than $5 billion,” Keithley said. Discipline has to start with the public, too. Keithley pointed to the new $100 million University of Alaska Anchorage sports complex which local sports enthusiasts pressured legislators into financing with state capital grants. “In other states these kind of projects don’t get built unless there is at least a 50 percent match from private donors,” he said. The UAA sports complex will have to be maintained, as will the university’s two new engineering buildings, one at UAA and the other, still needing funds, at the University of Alaska Fairbanks. When the state builds new facilities like the university buildings, the ongoing maintenance costs of those have to be provided for, and this is not being done now. “You have to go back to the basics of what the state constitution requires for core services, which is education, public safety, public health and welfare,” he said. “Health care costs have been a major driver of increases, I agree, and we need to find ways to reduce those. But at the end of the day we can’t spend more than $5 billion.”

Shell now hopes to use two drill rigs for Chukchi exploration in 2015

Shell is now planning to bring the TransOcean Ltd. semi-submersible drill rig Polar Pioneer to the Chukchi Sea in 2015 to explore along with the drillship Noble Discoverer. The company had previously planned to have only the Noble Discoverer exploring in the Arctic. A revised Plan of Exploration was filed Thursday with the U.S. Bureau of Ocean Energy Management that proposes to have the semisubmersible drilling along with the Discoverer, Shell spokeswoman Meg Baldino said. In a statement, Shell said, “Today we submitted revisions to our previously approved Chukchi Sea exploration plan to the Bureau of Ocean Energy Management; this step is necessary to keep our 2015 exploration options viable. The plan details our exploration plan for the Chukchi Sea.” The new plan supersedes a previous Chukchi Sea exploration plan filed by Shell, Baldino said. Previously the company planned to have the Polar Pioneer kept on standby at Dutch Harbor. Having both rigs in the Chukchi Sea would allow either to respond faster to each other in an emergency, Baldino said. The Polar Pioneer is designed for Arctic conditions, according to information about the rig on TransOcean’s website. The rig was built in 1985 and has worked off the coast of northern Norway. “We have not yet made any formal decisions,” Baldine said. “We submitted the revised exploration plan to have options open to us. Our final decision will depend on a lot of things, such as successful permitting and a resolution to litigation,” she said. Shell’s plans are currently bogged down in a lawsuit brought by Native tribal and environmental groups that argued the Interior Department’s assumption of oil spill risks are unrealistic based on its estimate of what would constitute an economically developable discovery in the Chukchi Sea. BOEM is now revising the assumptions and will publish a draft supplemental environmental impact statement this fall, the agency has said. Meanwhile, Shell is also waiting on new Arctic OCS drilling rules to be put in place by the Interior Department. A draft set of rules has been developed and submitted to the Office of Management and Budget for review but are not yet public, an Interior spokesman said. Shell’s 2012 drilling program was only partly successful. The company was able to drill one partly-completed exploration well in both the Chukchi and Beaufort Sea, where Shell also holds leases. Shell could only drill “top holes” because its spill recovery barge was never cleared to leave its Washington port and the company was not allowed to drill to oil-bearing depths. After its Beaufort rig the Kulluk lost its tow and grounded off Kodiak in late 2012, the company did not return to the Arctic in 2013 and 2014 and hopes now to resume drilling in the Chukchi Sea only in 2015, Baldino said. The Burger prospect in the Chukchi Sea remains Shell’s top priority, she said. Under the revised plan filed with BOEM the two rigs would be operating in proximity to each other but Maldino did not have details of how close. One rig will certainly focus on Burger. Details of other prospects targeted are described in the exploration plan, which would be released by the BOEM, she said.

After tax vote, what should Alaskans watch for?

With the divisive debate over oil taxes behind us, for now at least, what should Alaskans watch for? Getting new oil into the Trans-Alaska Pipeline System is the most important thing. Alaskans should also closely watch how the new tax performs in terms of revenue. A recent decline in oil prices has raised some concern for revenues although this would have affected revenues under either the former ACES tax or the new tax law passed as Senate Bill 21. Alaska North Slope oil prices have been trending down, closing at $99.80 per barrel on Aug. 27, down from $111 per barrel July 1. Oil producers have said that retaining oil tax reform, enacted in 2013 and which took effect Jan. 1, would lead to new investment and more oil into the pipeline to offset the production decline. New investment and some new production, over what was forecast, is already happening, but what additional milestones are there? Mainly, those would be the several new oil projects announced in the last year. Alaskans should watch to see if they are actually built. An important milestone will be later this year when the ConocoPhillips board of directors meets to approval the company’s capital investment budget for next year. There are three new North Slope products up for approval. These include two on the Kuparuk River field, Drill Site 2S, a new production pad in the south part of the Kuparuk field, and the North East West Sak, or NEWS, a project to expand the existing West Sak viscous oil project in the Kuparuk field. Assuming the NEWS project is given a go-ahead, it is expected to produce 9,000 barrels per day with a startup in 2017. ConocoPhillips did preliminary gravel placement for the DS 2S project last winter but final development must be approved by the company’s board. It is expected to begin production in 2016, with a peak of 8,000 barrels per day. The third project is Greater Moose’s Tooth 1, or GMT-1, ConocoPhillips’ planned new oil project in the National Petroleum Reserve–Alaska. A federal supplemental environmental impact statement being prepared by the U.S. Bureau of Land Management is due to be finalized later this year. GMT-1 is expected to produce 30,000 barrels per day. With new production from these three projects laid over the existing fields’ output, and accounting for some decline in the existing fields, ConocoPhillips said that it expects to add 40,000 barrels per day of new production to its North Slope production by 2018. BP is also working on its Prudhoe Bay west end development, although formal approvals from the board must also be given for that project. If it proceeds, it will add 40,000 barrels of new production beginning in 2018, the company has said. There are two other, smaller projects to keep an eye on. One is Brooks Range Petroleum’s small Mustang field development, which is to begin producing at an initial rate of 9,000 barrels per day in 2016 and increasing to 12,000 barrels per day in 2017. It is likely that other small oil deposits near Mustang will be developed once the field infrastructure is in place. The oil processing facility being built for Mustang will have a capacity of 15,000 barrels per day. Another project is Caelus Energy’s Nuna development near the Oooguruk field, which Caelus purchased from Pioneer Natural Resources earlier this year. Nuna is expected to produce about 15,000 barrels per day. The company has not released a timetable for development but some preliminary gravel work is expected this winter. Meanwhile, two other large projects were underway before the vote on the production tax are ConocoPhillips’ CD-5 project and the Point Thomson gas and condensate project east of Prudhoe Bay. These will be producing by 2016. CD-5 is to begin production in late 2015 with a peak production of 15,000 barrels per day. Meanwhile, Point Thomson will begin producing 10,000 barrels per day of liquid condensates in 2016. Not including BP’s west Prudhoe project, which will produce after 2018, the projects listed above total to about 100,000 barrels per day of new oil by 2018. However, there will also be continued decline in the existing fields, although that may be mitigated by “workovers” of older producing wells and the drilling of new wells in the older fields. Based on these announced projects, state officials are cautiously optimistic that the production from the North Slope can be held level and perhaps increased by a small amount. The decline was actually halted last year due to increased activity on the slope. Production averaged 531,000 barrels per day in fiscal year 2014, the state financial year ending June 30, which was about the same as it averaged the previous year. Historically production has been declining at rates of about 6 percent yearly. On the revenue impacts of the new tax, the important milestone is the Department of Revenue’s next revenue forecast due out in late November or early December. That will be the department’s first estimate under the new tax after it has been in effect for nearly a full year. It will forecast revenues for the current fiscal year and the 2016 fiscal year. Revenues will be most affected by three factors that are very dynamic: oil prices, the estimated per-barrel production cost and the number of barrels expected to be produced. If oil prices are lower, and production costs higher, the per-barrel net value of the oil will be reduced, resulting in lower revenues. This would happen under the new and oil tax as both are based on the net value per barrel. However, this would be offset by more barrels being produced over what was previously estimated. More barrels means not only more production tax revenue but also higher royalty payments to the state. How these would balance out would be displayed in the revenue department’s forecast later this year.

Tate, fellow veterans, make transition from war to work

Not long ago, Joe Tate was in Afghanistan and Iraq wielding a 50-caliber machine gun. Now he’s welding steel at ExxonMobil’s big Point Thomson project on the North Slope. He’s pretty happy about it. Instead of shooting at bad guys — and them shooting at him — Tate is helping build something that’s pretty big, phase one of a possible $50 billion-plus Alaska gas project, and working for CH2M Hill, a major North Slope oil service company. Tate took a medical retirement from the U.S. Air Force in April after multiple deployments in Iraq and Afghanistan. He is a holder of a Purple Heart and Bronze Star. In the Air Force, Tate was an equipment operator but once on the ground in Iraq and Afghanistan he did combat escort, manning a machine gun while escorting convoys that sometimes came under fire. Tate returned to Alaska, the place he wanted to live after serving at Elmendorf Air Force Base, and was able to take advantage of special training to help veterans, particularly those who were wounded, make a transition back to civilian live. The training is actually provided by firms or institutions, in Tate’s case Northern Industrial Training in Palmer, and funded with federal grants coordinated through the state Department of Labor, and employers monitor the progress of prospective employees. “We’re very pleased to hire veterans, first in appreciation for their service but secondly because they make very good employees,” said Tom Maloney, Alaska Area Manager for CH2M Hill. “They are mature and disciplined, and many are familiar with working in remote locations. Many are also used to periodic rotations to field assignments which are the norm for North Slope jobs and many military assignments.” At Point Thomson, Tate will work a four-and-two schedule, a month on with two weeks off. It is a typical North Slope construction schedule. Tate is part of a group of 15 veterans and one dependent of a qualified veteran who were hired by CH2M Hill after successfully completing the training, according to Sara Gould, the company’s staffing resource manager for its work on the Point Thomson project. The group includes two pipe welders, of which Tate is one, four pipefitters, one driver/equipment operator, and nine carpenters and skilled laborers, Gould said. Trainees applied to CH2M Hill for the jobs and were then placed in the training. All those who successfully completed the courses were hired, she said. Two groups helped the company find veterans with the right qualifications for the jobs, “Hero to Hired,” a program for veterans operated by the Alaska National Guard, and “Alaska Human Hearts,” a nonprofit that help wounded veterans find jobs. “The training is valuable in helping veterans bridge the gap between their military skills and skills they will need in civilian jobs,” Gould said. In Tate’s case, the training provided a valuable upgrade to skills acquired in the Air Force. Manning a 50-caliber might not be a skill transferable to many civilian occupations, but vehicle operation would be. But welding was better, Tate said. “Once I got into the training I found I liked it, and I was good at it. If I hadn’t been able to do this I would probably have wound up being a truck driver,” he said. Welding also pays better, and that was important given that Tate was down to his last $67 by the time he went on CH2M Hill’s payroll, after completing the training. “I sold my motorcycle to help pay some of my expenses,” he said. Gould said that while these new recruits will be working in CH2M Hill’s construction support division, many who work on the construction projects are able to supplement the company’s North Slope operations support when the construction projects are complete. But there are many who just prefer working on in construction because of the periodic time off between jobs, she said. CH2M Hill has previously offered training, also supported by the state Department of Labor, as part of an effort to recruit employees from rural communities, but the most recent program was aimed solely at veterans. “This was dedicated training for people who had served in some of the most dangerous places in the world,” Maloney said. “We believe, with the voters’ recent rejection of Ballot Proposition One, that there will be a lot more drilling and other projects. It’s very positive for the oil and gas industry, and for LNG. We’re finding that previously deployed military are an outstanding source of people with the right kinds of training to meet our workforce needs.”

Cook Inlet oil production increases 25% in last year

Cook Inlet oil producers have boosted output 25 percent in the last year, data from the state Department of Natural Resources indicates. Production averaged of 16,288 barrels per day, or b/d, compared in the first half of 2014 compared with 13,087 b/d in the same period of 2013. Information from the Department of Revenue, which also tracks production, shows a similar growth trend, with an average of 15,800 b/d in fiscal year 2014 that ended June 30, compared with 12,200 b/d in the previous fiscal year. In fiscal year 2010, production in Cook Inlet was 8,900 b/d after five years of decline from 20,300 barrels per day in fiscal year 2005, according to the Revenue Department data. Alaska Natural Resources Commissioner Joe Balash credited the growth to increased investment by Inlet oil producers, mainly independents Hilcorp Energy and Cook Inlet Energy. The two companies have been drilling new wells and upgrading platforms acquired from others. “Increased capital investment in the Cook Inlet fields has yielded higher employment and increased oil royalty revenue,” Balash said in a statement The increase in activity has also led to new natural gas reserve additions, providing energy security for electric and gas utilities in the region and allowing ConocoPhillips to restart the idled LNG export plant near at Nikiski. Because virtually all Cook Inlet oil is sold to Tesoro Corp.’s refinery near Kenai, the increased production helps maintain the viability of that plant, which produces most of the gasoline in the state as well as jet fuel and diesel. The increases in production have also allowed the state to phase out reduced royalties that were granted for some of the Inlet’s aged platforms. The reductions were granted under a program that allows reduced royalty when platforms are near their economic limit of production. The Monopod Platform in the Inlet, operated by Hilcorp, has increased to 2,900 b/d, up from 820 b/d in the first quarter of 2013. The Osprey platform, operated by Cook Inlet Energy, saw an increase from 226 b/d to 1,221 b/d in the same period. As a result, state royalty rates were increased from a reduced rate of 10 percent to the normal 12.5 percent on the two platforms. The full royalty is 12.5 percent on most state oil and gas leases. The combination of increased production and higher royalties being paid have increased Alaska’s royalty collections from $14 million in the first half of 2013 to $24.9 million in the first half of 2014, an increase of nearly 78 percent. Cook Inlet oil and gas fields have been producing since the 1960s and 1970s and the current renaissance is typical when new companies, particular independent companies, enter a producing basin that was pioneered and initially developed by large oil companies. Over time, as production declines, the large companies find the remaining oil in the region to be unattractive compared with other, larger opportunities elsewhere, and tend to move on. Independent companies like Hilcorp, which specialize in taking over mature producing fields and aggressively redeveloping them, typically buy the producing assets. In Cook Inlet, Hilcorp purchased assets of Chevron Corp. and Marathon Oil Co. Cook Inlet Energy, a subsidiary of Miller Energy Resources of Tennessee, bid on and took over the bankrupt assets of Pacific Energy, which was operating the small Osprey platform and onshore wells on the Inlet’s west side. Another major independent, Apache Corp., is meanwhile exploring on its own in the Inlet with a major seismic program and one exploration well drilled so far.  Oil and Gas Division Director Bill Barron echoed Balash’s comments: “Increases in production from mature fields are not possible without significant investment by the operators,” he said.

Focus turns to revenue as oil prices fluctuate

Now that the state’s oil production tax has been retained following the rejection of Ballot Measure 1 in the Aug. 19 primary election, what are the implications for state oil income? It’s an important question because oil revenues pay for about 90 percent of Alaska’s budget. In the aftermath of the intense Ballot Measure 1 campaign, the performance of the new tax, enacted in Senate Bill 21 in 2013, will be closely watched and measured against what the former tax, known as ACES, might have brought in. Estimates by the state Department of Revenue, which uses oil price and production assumptions in the Spring 2014 revenue forecast, show that at current oil prices and investment levels, SB 21 and ACES would bring in about the same amounts of revenue. The estimate showed that in the current year, SB 21 brings in a bit more income. This is consistent with similar comparisons made by the department last November. If oil prices were to drop to $90 per barrel, for example, the analysis from April shows that SB 21 would bring in more revenue ($3.22 billion) compared to ACES ($3.08 billion). At higher prices, $120 per barrel for example, ACES would have brought in more revenue ($6.1 billion) in comparison to SB 21 ($5.89 billion.) These effects are generally consistent with other forecasts of the two tax systems, such as those prepared by the University of Alaska’s Institute of Social and Economic Research. However, these estimates do not reflect the revenue effect of added production over the Spring 2014 forecast. The Department of Revenue’s last full production forecast, published in Fall 2013, has yet to take into account much of the activity announced by oil companies since the tax change took effect. If SB 21 results in new production on the North Slope, enough to essentially stop the decline for the next five years, the new tax law would result in more revenue compared with ACES. Department of Revenue Commissioner Angela Rodell said given the annual 6 percent decline in oil production, “even a flattening of the decline curve under MAPA could be considered an increase in production over the path we were on.” The ‘what ifs’ At the request of the Juneau Empire, the Revenue Department looked at how a percentage of production increase would impact state revenues over a five-year period, from fiscal year 2015 through fiscal year 2019, at two price oil levels. The analysis, and the revenue estimates compiled from it, should not be considered an official revenue forecast, the department said. According to the figures, if the current $105 per barrel oil price is assumed as well as the production estimated in the Spring 2014 revenue forecast (which assumes continued decline), ACES slightly outperforms SB 21 over the next five years through fiscal year 2019. Using those assumptions, from fiscal year 2015 through fiscal year, ACES would bring in about $22.6 billion compared with about $22 billion under SB 21, over the five years. However, if more production is factored in, so that oil production averages about 500,000 barrels per day, SB 21 brings in more money, or about $23.6 billion compared with $22.6 billion under ACES, according to the figures. If oil prices were to increase to $110 per barrel, but still assuming the continued production decline in the fiscal year 2014 forecast, ACES would outperform SB 21 by about $900 million over the five years. Increased oil production changes things, however. If oil production remained relatively flat, around 500,000 barrels per day, SB 21 would bring in about $1 billion more over the five years, or $26.05 billion in tax collections compared with $25.1 billion for ACES. Additional production would also bring in about $170 million more in royalties over the five-year period, part of which would go to the Alaska Permanent Fund.  What the future may hold Deputy Revenue Commissioner Mike Pawlowski said the investment-stimulus effect of SB 21 will be felt more substantially beyond 2019. “As investment increases in the near term, in response to the more predictable, competitive climate created by SB 21, we expect any difference between tax revenues raised by the system (compared with ACES) to be minor, especially if (oil) prices continue to decline,” he said. “Over the medium to long term, additional production we expect to be generated from these investments will raise additional production tax, corporate income tax, property tax and royalties for the Permanent Fund and General Fund.” Pawlowski and other revenue officials are keeping a wary eye on oil price trends. North Slope crude oil is currently selling for about $103 per barrel, down from $110 per barrel in early July. The forecast for fiscal year 2015 is $105 per barrel, but there are concerns that increased rail shipments of light Bakken shale oil to the west coast, where Alaska’s oil is sold, could undercut prices. “I think it’s easy to imagine an oil price scenario that stays flat or actually declines in the next five years or more,” Rodell said. “Currently, ANS (Alaska North Slope) crude oil enjoys a premium in the price of the crude over WTI because of its west coast location delivery point. The influx of Bakken crude on the west coast via rail could put downward pressure on crude prices on the west coast in the future.” Another factor, according to Rodell, is the increase in shale and tight oils in the Lower 48 coming from states such as Oklahoma, Texas and Colorado, which have also seen oil booms due to the practice of fracking. The oil being pumped from those states may increase domestic supply, Rodell said, “prompting calls for the U.S. to export oil for the first time in many years.” “Such increases in supply could also contribute to keeping oil prices at the current level or below,” she said. There is so much oil available currently being produced in domestic and international markets that recent turmoil in the Middle East hasn’t had much of an effect on oil prices, unlike in July 2008 when oil prices spiked at nearly $150 per barrel. At that price, the progessivity factor of ACES taxed oil at 51.6 percent. When the cost of oil dropped months later, so did the tax rate. From November 2008 through April 2009, companies paid a 25 percent tax, not including adjustments for tax credits. Even though a scenario of flat — and possibly even declining — oil prices is a possibility, the state is projecting oil prices will continue to climb through 2022, reaching $133 per barrel. The forecast also projects a decline in production from 520,000 barrels per day in 2014 to 342,000 barrels in 2022. Those numbers can be misleading, Rodell notes, and doesn’t include several known projects expected to come online. “The Department of Revenue has issued only one full production forecast since the passage of MAPA – that being the Fall 2013 forecast,” she said. “That forecast was prepared less than eight months after the passage of SB 21 and prior to the act taking effect with the 2014 tax year. We expect after a full year of corporate budget cycles to see many of the announcements made recently incorporated into our Fall 2014 forecast this December. “The department’s production forecast follows a strict standard for inclusion in the forecast. To be incorporated in our forecast, all future production projects must have known reserves and some reasonable certainty of completion. The projects with the most risk are classified in our production forecast as ‘under evaluation.’” Rodell said that projects already approved and budgeted are often classified as “under development” in production forecasts are assigned risk factors. Risk factors are based on any “uncertainties surrounding the timing and the amount of future production volumes.” “As these projects become more certain,” Rodell said, “they will be fully incorporated into our production forecast, with less or no risk factors.” State projection confirmed The Revenue Department’s prediction of increased oil production through SB 21 proved true this year. The department finalized its fiscal year 2014 production numbers Aug. 8. The fiscal year ended June 30.  Production was virtually even compared with the previous fiscal year at an average of 531,074 barrels per day compared with a 531,639 barrels the previous year. In December, the department had projected 508,200 barrels per day. Pawlowski said the state will be able to better forecast under SB 21 than ACES because there are fewer moving parts. “Small movements in any of the factors has a significant change,” he said of ACES, referring to the progressive tax scale that varies month to month. SB 21 has a flat 35 percent tax rate for existing wells. Actual fiscal year 2014 production was about one-tenth of 1 percent down from the previous year, said John Tichotsky, the state’s chief petroleum economist.  “The difference is within the error range in equipment used to meter the oil flow,” Tichotsky said. The oil producers’ achievement compares with the 8.2 percent decline between fiscal years 2012 and 2013. The long-term decline has been about 6 percent annually, Tichotsky said.  The production increase is a result of increased drilling and well “workovers” on older producing wells over the last year in the large producing fields of the North Slope. All sides in the debate agree that getting addition production into the Trans-Alaska Pipeline System is crucial. At an average of 530,000 barrels per day, TAPS is carrying about one-fourth of the 2 million barrels it was designed for. That’s how much oil flowed through TAPS until 1989 when the rapid decline began. Without additional production, there will be increasing strains on the state budget, which is already running $1 billion-plus deficits. In a yearly analysis of state budget and revenue trends, Professor Scott Goldsmith, senior economist at the University of Alaska Anchorage’s Institute of Social and Economic Research, predicted last January that if the 6 percent decline were to continue and only very modest additions of 2 percent yearly were allowed for state general fund spending, the state’s savings accounts, excluding the Alaska Permanent Fund, would be depleted by 2024. The Legislature has since converted $3 billion from budget reserves to pay down state pension funds. In a revised estimate not yet published, Goldsmith calculated that with the $3 billion taken from reserves, the depletion of the savings account would be accelerated to 2020. However, if oil production were increased by 1 to 2 percent, yearly savings accounts would not be depleted, Goldsmith said, and a 3 percent annual growth of oil production would retain a healthy surplus in the state’s savings through 2023. Charles L. Westmoreland, managing editor of the Juneau Empire ,contributed to this story.

Energy Dept to streamline export review for Alaska LNG

U.S. Energy Secretary Ernest Moniz told business leaders in Anchorage that the Department of Energy will streamline the federal LNG export license application process for Alaska’s North Slope gas project.  That’s good news, U.S. Sen. Mark Begich said, because it means that the public interest test for the Alaska project won’t get bogged down in controversy as has happened in the Lower 48, where business and community groups worry about the price effects of domestic gas being exported as LNG. Begich was with Moniz at the meeting with stakeholders hosted at Cook Inlet Region Inc. in Anchorage, which was closed-door, and at a following press conference. A consortium of the three major North Slope producers, TransCanada Corp. and the State of Alaska filed an application July 18 for a project to export up to 20 million tons per year of LNG from Alaska. “We want to be very explicit to say that we will treat Alaska differently. The public interest is not an issue for us,” Moniz said at the press conference. That’s because the export of Alaska’s gas will not affect markets in the continental U.S. A public interest determination will still be done but it will be largely a formality. In another development, DOE has exempted the Alaska project from a new U.S. Department of Energy rule that LNG export projects complete their environmental reviews before a federal LNG export licenses is issued. The rule, published June 4 and made effective Aug. 15, ends DOE’s practice of issuing of conditional licenses for continental U.S. LNG export projects and also its practice of processing applications in the order they were filed, Moniz said. “There will no longer be a ‘queue’ for applications,” he said. Those will be processed when applicants complete national environmental impact statement, or EIS, typically with the Federal Energy Regulatory Commission. Alaska, however, is again to handled separately, Monitz said. A “conditional” export license for Alaska will be granted when the project moves further along in its development. Lower 48 LNG export projects previously were able to get conditional approvals but no longer, under the new rule. Alaska will still be able to get one, however. That will aid Alaska in efforts to market LNG in Asia, which are beginning this year. “The Alaska project has been in a gestation stage for a long while,” Moniz said, and DOE feels it important to get huge stranded gas reserves on the North Slope onto world markets. “This is a private sector project and we want to do all we can to facilitate it, and not be seen as an obstacle.” Moniz said completion of the National Environmental Policy Act process, which includes the EIS, will still be required for a final Alaska export license, however. Larry Persily, federal natural gas coordinator for Alaska, said that the requirement for completion of the NEPA review, had it been applied to the Alaska project, it would likely have slowed the project and added costs, now estimated at $45 billion to $65 billion. Persily said the knowledge that DOE is treating Alaska in a streamlined manner and allowing a conditional export license will help the marketing efforts. Moniz said in an interview that the Lower 48 queue and conditional permit process had become cumbersome for both DOE and applicants alike and in some ways a hindrance because an applicant’s position in the lineup had little relationship to its actual chance of success in clearing environmental reviews, permitting and financing hurdles. DOE now intends to process applications in the order that they complete the NEPA process, he said. In other comments, Moniz said DOE is moving to strengthen its efforts to aid renewable energy projects in Alaska, mainly through its loan programs. The agency will continue to seek partnerships with entities in the state on geothermal and wind-diesel integration projects, he said. The agency is interested in Alaska as a demonstration test-lab for advanced control systems to increase the efficiency of power generation when wind and diesel are combined in a small grid, Moniz said. These are technologies that, once demonstrated in remote settings in Alaska, could be exported internationally to places like Africa, where they are multitudes of small villages isolated from large power grids.

Oil production tax repeal fails, tax reform upheld

A referendum to roll back an oil production tax change made in 2013 was defeated by voters in the state’s primary election held Aug. 19. Ballot Measure 1, which would have reinstated the state’s previous tax known as ACES that was repealed in 2013, was voted down 52 percent to 48 percent, or a margin of about 6,800 votes, the Division of Elections reported in late results with 98.6 percent of the votes counted. Earlier in the evening of Aug. 19 the “yes” votes had a thin majority of a few hundred for repeal with about 25 percent of the first counts, but later returns steadily reversed the trend as the night wore on. Anchorage, Eagle River, the Kenai Peninsula and Matanuska-Susitna Borough voted heavily against the rollback, while Fairbanks and Southeast largely favored the repeal. Among Anchorage districts, 9 of 13 were won by the “no” votes. Every district in the Mat-Su and Eagle River was carried by the “no” vote. The “no” votes also carried in rural Alaska, with the North Slope and Northwest upholding tax reform by more than 900 votes compared to only small margins for “yes” in the Bristol Bay/Aleutians and Kuskokwim Delta districts. With 98 percent of the votes cast counted, 79,980 voted against the tax rollback and 73,184 voted for it. There are still absentee and challenged ballots left to be counted but to overcome the current margin, the “yes” votes for the rollback would have to capture about 10,000 of estimated 13,000 absentee ballots. The election, closely watched by the oil and gas industry, had stirred intense debate through the summer. In a statement, BP Alaska President Janet Weiss said, "Alaskans have made clear they are interested in moving forward and improving Alaska's long-term economic future. We agree with the voters that oil tax reform is working, and BP is committed to doing its part to make sure that continues." ConocoPhillips voiced similar sentiments: “We are encouraged by the election night results that indicate Alaska voters support retaining More Alaska Production Act,” spokeswoman Natalie Lowman said in a statement. “MAPA has improved the investment climate in Alaska and provides the basis for a more positive long term outlook for Alaska’s economic future. Since MAPA was passed, ConocoPhillips has added rigs to its operations and announced plans to invest in projects that will add production, create jobs and business opportunities for Alaskans, increase the taxable revenue to the state and increase contributions to the state’s Permanent Fund.” After the Legislature adopted the tax change in April 2013, critics of the change immediately organized an initiative drive to get the repeal the law with a ballot referendum. The revised tax passed as Senate Bill 21, also called the More Alaska Production Act, eliminated a progressivity formula in the previous tax that hiked tax rates sharply as oil prices rise. It also eliminated a 20 percent investment tax credit, replacing it with a tiered system of per-barrel production tax credits as an incentive for producers to develop new resources. Opponents to SB 21 objected particularly to production tax credits to oil produced in existing fields. However, many opponents of the tax change supported tax reductions for new fields. The previous tax put Alaska’s production taxes among the highest in the world, consultants told the Legislature in 2013. The revised tax puts Alaska’s take in the upper middle tier of comparable producing regions. Since the tax was changed in 2013 North Slope producers have intensified field activity, brought on new drill rigs and essentially halted the decline in production from the Slope for the first time since 2002. If the “no” vote prevails in the final election results, it will likely settle the oil tax question for some time, and most expect the upward trend for activity and production to continue. State Rep. Les Gara, D-Anchorage, an ardent supporter of the repeal, said, "This election had $15 million dollars of corporate donations compared with less than $1 million of donations from real people. This shows the power of corporate money, but also that Alaskans are tough to fool. It was a close election." Gara predicted that under the new tax oil production will fall, there will be less revenue to the state and in a few years people will demand another change. "All the companies did is buy themselves some time," he said. The ConocoPhillips board of directors will meet later this year to give final approval to projects that will add 40,000 barrels per day of new production by 2018, and BP is considering a new projects In the west end of the Prudhoe Bay field that will add 40,000 b/d beginning in 2018.  In the Democratic U.S. Senate primary incumbent U.S. Sen. Mark Begich received 84 percent of the votes cast against six challengers. Begich won 47,631 votes in his primary compared with Sullivan’s 36,293, so in the November general election it would be important for Sullivan to appeal to those who voted for Miller and Treadwell. The Alaska U.S. Senate rate is one of a handful of contested seats where Republicans hope to prevail, tipping the balance of control in the Senate from Democrats to Republicans. Meanwhile, incumbent Rep. Don Young easily outdistanced three challengers to net 74 percent of the Republican vote for U.S. Representative, although one who contested Young, John Cox, received 13.5 percent. In the Democratic contest for U.S. Representative Forrest Dunbar received 63 percent of the vote against two opponents. Dunbar netted 31,555 votes in the late count against Young’s 64,445, so the longest-serving Republican in Congress has his usual advantage going into the general election. In the governor and lieutenant governor races, incumbent Gov. Sean Parnell easily outdistanced three Republican challengers with 75.5 percent of the vote in the Republican governor’s primary; Democrat Byron Mallot received 66 percent of the vote against two challengers in the Democratic governor’s primary. State Sen. Hollis French netted 62 percent of the lieutenant governor’s Democratic primary against two challengers; Anchorage Mayor Dan Sullivan received 70.5 percent of the vote against one challenger in the Republican lieutenant governor’s primary. In key state legislative races where the primaries were contested, state Rep. Bill Stoltze, R-Chugiak, beat back a challenge from DeLena Johnson to win the Senate District R GOP nomination; in House District 3 in North Pole, near Fairbanks, two incumbant Republicans, Reps. Tammie Wilson and Doug Isaacson, were pitted against each other through redistricting. Wilson is the apparent winner. An apparent upset is in the House District 9 Republican race, Palmer-Glennallen-Valdez, where challenger Jim Colver of Palmer has apparently defeated incumbent Rep. Eric Feige, of Chickaloon. In House District 22, in Anchorage, Liz Vazquez has apparently defeated her Republican challenger, Sherri Jackson. In House District 21, also in Anchorage, Anand Dubey has apparently defeated Republican challenger Matt Fagnani. In House District 32, Kodiak, Louise Stutes has apparently defeated two Republican challengers. In House District 40, northern and northwest Alaska, incumbent Rep. Bennie Nageak, of Barrow, is leading his challenger, Dean Westlake of Kotezebue, in late results.

DOE to streamline export license review for Alaska LNG project

U.S. Energy Secretary Ernest Moniz told business leaders in Anchorage that the Department of Energy will streamline the federal LNG export license application process for Alaska’s North Slope gas project.  That’s good news, U.S. Sen. Mark Begich said, because it means that the public interest test for the Alaska project won’t get bogged down in controversy as has happened in the Lower 48, where business and community groups worry about the price effects of domestic gas being exported as LNG. Begich was with Moniz at the meeting with stakeholders hosted at Cook Inlet Region Inc. in Anchorage, which was closed-door, and at a following press conference. A consortium of the three major North Slope producers, TransCanada Corp. and the State of Alaska filed an application July 18 for a project to export up to 20 million tons per year of LNG from Alaska. “We want to be very explicit to say that we will treat Alaska differently. The public interest is not an issue for us,” Moniz said at the press conference. That’s because the export of Alaska’s gas will not affect markets in the continental U.S. A public interest determination will still be done but it will be largely a formality. In another development, DOE has exempted the Alaska project from a new U.S. Dept of Energy rule that LNG export projects complete their environmental reviews before a federal LNG export licenses is issued. The rule, published June 4 and made effective Aug. 15, ends DOE’s practice of issuing of conditional licenses for continental U.S. LNG export projects and also its practice of processing applications in the order they were filed, Moniz said. “There will no longer be a ‘queue’ for applications,” he said. Those will be processed when applicants complete national environmental impact statement, or EIS, typically with the Federal Energy Regulatory Commission. Alaska, however, is again to handled separately, Monitz said. A “conditional” export license for Alaska will be granted when the project moves further along in its development. Lower 48 LNG export projects previously were able to get conditional approvals but no longer, under the new rule. Alaska will still be able to get one, however. That will aid Alaska in efforts to market LNG in Asia, which are beginning this year. “The Alaska project has been in a gestation stage for a long while,” Moniz said, and DOE feels it important to get huge stranded gas reserves on the North Slope onto world markets. “This is a private sector project and we want to do all we can to facilitate it, and not be seen as an obstacle.” Moniz said completion of the National Environmental Policy Act process, which includes the EIS, will still be required for a final Alaska export license, however. Larry Persily, federal natural gas coordinator for Alaska, said that the requirement for completion of the NEPA review, had it been applied to the Alaska project, it would likely have slowed the project and added costs, now estimated at $45 billion to $65 billion. Persily said the knowledge that DOE is treating Alaska in a streamlined manner and allowing a conditional export license will help the marketing efforts. Moniz said in an interview that the Lower 48 queue and conditional permit process had become cumbersome for both DOE and applicants alike and in some ways a hindrance because an applicant’s position in the lineup had little relationship to its actual chance of success in clearing environmental reviews, permitting and financing hurdles. DOE now intends to process applications in the order that they complete the NEPA process, he said. In other comments, Moniz said DOE is moving to strengthen its efforts to aid renewable energy projects in Alaska, mainly through its loan programs. The agency will continue to seek partnerships with entities in the state on geothermal and wind-diesel integration projects, he said. The agency is interested in Alaska as a demonstration test-lab for advanced control systems to increase the efficiency of power generation when wind and diesel are combined in a small grid, Moniz said. These are technologies that, once demonstrated in remote settings in Alaska, could be exported internationally to places like Africa, where they are multitudes of small villages isolated from large power grids.

GOP candidates square off one more time as Aug. 19 primary nears

The three Republican U.S. Senate candidates squared off against each other in the KTUU Channel 2 debate Aug. 14, touching mostly on old and familiar themes. On most issues there were only shades of differences, and all three took opportunities to take shots at Sen. Mark Begich, the Democrat incumbent one of them will face in the November general election. Mead Treadwell, currently the lieutenant governor; Dan Sullivan, former state attorney general and natural resources commissioner, and Joe Miller, a Fairbanks attorney and the Republican Senate candidate in 2010, met in what may be their last face-to-face confrontation before the Aug. 19 primary. There were a few barbs: Treadwell asked Sullivan when he first legally caught a salmon in Alaska, a way of drawing attention to the first Alaska fishing license received by Sullivan, which Treadwell said was in 2009. Sullivan didn’t answer the question and complained that of all three candidates he was the one exposed to a huge negative campaign funded mostly from out-of-state. “Why are they so afraid of me?” he said. “Is it because I’m the mostly likely to defeat Begich?” On immigration, all three candidates opposed “amnesty” for illegal immigrants. Sullivan endorsed efforts to reunite children migrating to the U.S. with families, “back home.” “We are a nation of immigrants, but also a nation of law,” he said. Treadwell said his priority would be to make U.S. borders secure. He supports humanitarian and private volunteer efforts to help immigrants but not the creation of more federal programs. “That doesn’t make a lot of sense to me,” he said. Miller said illegal immigration is something that could rip the nation’s fabric apart. “People are coming here illegally and if they become citizens they will vote,” he said, adding his concern that most illegal immigrants wind up favoring Democrats. “I believe lawful immigration is great, though,” Miller said. On veterans’ affairs, Treadwell said although Begich in on the Veterans’ Affairs Subcommittee in the Senate has been, “asleep at the switch,” on the issue. “We need a senator who will be vigilant in protecting veterans’ rights,” Treadwell said. His father and grandfather were veterans who often had to drive long distances for care right past large, modern hospitals and health facilities to get care. “Veterans should be able to get care where they live, not hundreds of miles away,” he said. Miller went after Treadwell on his long support of the long-pending Law of the Sea Treaty, a prime target for conservatives. It was an indirect way of questioning Treadwell’s conservative credentials. Treadwell responded: “When I came to Alaska there were foreign fishing fleets off our coasts taking our fish, and it took a law of the sea (the U.S. 200-mile limit legislation) to gain control of these resources. The Law of the Sea Treaty does the same thing. It will extend U.S. ownership of resources out into large areas of the Arctic,” north of Alaska, over which the nation now has no jurisdiction, Treadwell said. Miller wasn’t convinced: “This is a path to opening the Arctic by compromising our sovereignty,” through provisions of the treaty that grant authority to international bodies. The U.S. can gain every benefit and every protection of the treaty through bilateral agreements, “without giving up our rights,” Miller said. Treadwell asked Miller what he would do about the 60 ocean vessels carrying oil and gas that transited the Bering Straits last year along a coastline that is completely unprotected from oil spills. Miller sidestepped, using the question to drum his basic themes. “The greatest threat to our national security is the national debt. It is preventing us from building the icebreakers we need and giving more resources to the Coast Guard,” he said. On energy issues, Sullivan said America is starting to see a renaissance in energy and that Alaska should be leading it. Alaska is seeing is own renaissance in oil and gas, at first in Cook Inlet and now on the North Slope, he said. Sullivan noted his own role as state resources commissioner in encouraging the Cook Inlet rebirth and negotiating the Point Thomas gas settlement, which helped get things moving on the Slope. “Alaska can lead the nation in energy but we need the federal government to be a partner, not an obstacle,” Sullivan said. Miller said he supports changes in federal laws to allow oil export and opposes any law that would limit natural gas exports. “If there is ever a resource security issue we can stop exports quickly. This is an issue of preserving jobs in energy and our energy-producing capability,” which is also important to national security, Miller said. In closing, Treadwell said, “I’ve lived here 40 years and I think Alaska needs to send someone to Washington who knows Alaska.” “I’m ready to support the dream of statehood, in bringing decisions back to Alaska.” Miller said, “For too long we’ve sent people to D.C. who wind up bending. We’ve got to be firm,” on principles. He emphasized his conservative credentials, noting he is the only candidate in the primary endorsed by American Right to Life and groups protecting the rights of gun owners. Sullivan said he has met too many people through the campaign, “who have lost hope in our government and our country. We can turn this around,” he said. “My whole career has been one of taking action,” as we have in turning around Alaska’s petroleum industry, he said. “We can do the same for the nation.”

Federal delay may scuttle season at GMT-1

ConocoPhillips could lose a year in starting work on its Greater Moose’s Tooth No. 1 project in the National Petroleum Reserve-Alaska due to a possible U.S. Bureau of Land Management delay in completing an environmental impact statement for the project, state Commissioner of Natural Resources Joe Balash says. The state has been informed by BLM that the EIS will now be done in October. Given that, “it may be December before a Record of Decision can be done, and that could make it very difficult for the Corps of Engineers and other agencies to issue permits in time for a start of gravel work this winter on the project,” Balash said in an interview Aug. 4. Previously, BLM was working to get the EIS completed and a Record of Decision by October, which would have allowed ample time for the Corps to issue its Section 404 dredge and fill permit for gravel work. If GMT-1 is to stay on schedule for a late 2017 startup, ConocoPhillips must begin laying gravel this winter for an eight-mile access road and the gravel production pad because the gravel must “settle” over a summer before final contouring and completion the following winter, the commissioner said. ConocoPhillips spokeswoman Natalie Lowman underscored that. “We are working with BLM and cooperating agencies on GMT-1 permits, and part of that work involves explaining the importance of year-round road access for potential emergency spill response as well as environmental, safety, operational and economic reasons,” she said in a statement. “We need a BLM Record of Decision as soon as possible and a Corps of Engineers permit by mid-January to stay on schedule; otherwise we risk significant delays to the project.” U.S. Sen. Lisa Murkowski also voiced concerns over the schedule. BLM officials appear to be “slow walking” their review of the GMT-1 application until after the November election, she said. “The Army corps requires a minimum of 120 days to review an application for the dredge-and-fill permit,” Murkowski said. However, Alaska Sen. Mark Begich has been told by BLM that things are on track. “Our staff spoke with DOI staff today (Aug. 5) and we were assured that the Supplemental EIS is on track to be finalized no later than October. We are also working to make sure the Army Corps of Engineers permitting process is on a parallel track so there won’t be any additional delays there either,” Begich spokeswoman Heather Handyside said. That may be difficult to do, Murkowski said. “The Army corps requires a minimum of 120 days to review an application for the dredge-and-fill permit,” Murkowski said in a statement. The dredge-and-fill permit, issued under Section 404 of the Clean Water Act, is typically processed after the Record of Decision is issued on the EIS. In a Aug. 5 statement Begich said, “I have been in constant contact with the all the parties involved, including DOI, the White House, ConocoPhillips, and Alaska Native corporations, and I’ve made it clear that delaying the project is not an option. It’s been studied to death and DOI needs to get off the dime, conclude the studies, and approve the permit.” BLM director Neil Kornze earlier told the senator in a hearing that one of the agency’s alternatives being considered includes “roadless.” “Such a restriction would erase the project’s economic viability,” Murkowski told Kornze. GMT-1 would produce 30,000 barrels per day beginning in late 2017. The state has a stake in the project because it would receive production tax revenue from GMT-1 even though the project is on federal land. Balash also said he is concerned that BLM is considering a “roadless” alternative in the EIS along with at least two routings of the road connecting the project to the CD-5 drill site and to the producing Alpine oil field which is also operated by ConocoPhillips. “We are concerned as to their intentions. We’re a little perplexed because it appears none of the ‘cooperating’ agencies on the EIS, such as the state or the North Slope Borough, has asked for roadless access. The idea appears to have been generated internally within BLM,” Balash said. There is also no record, so far, of any other federal agency asking the BLM to consider a roadless alternative. On one hand it is understandable that the agency will scrutinize every option carefully in view on the ongoing litigation by environmental groups of the corps of engineers’ permit for a bridge and access road to CD-5, Balash said. “They obviously want to produce an EIS that is bullet-proof from lawsuits, but we would be very concerned if they are working hard on a ‘roadless’ option,” he said. “ConocoPhillips has been very clear that no road means no project. It just won’t work for them.” The company has said that it needs year-around road access to GMT-1 and to possible other drill sites that could be developed if there is an emergency at any time of year and heavy equipment must be moved. Sara Longan, director of the state’s Office of Project Management and Permits, said BLM is considering four alternatives along with the standard “no action” option. These include one road route that ConocoPhillips says it prefers along with two routes with alternative routing and a “seasonal” road option, meaning a winter ice road. This is the “roadless” option. Longan said the key decisions by BLM have yet to be made and that Balash, working with the state’s office in Washington, D.C., is considering what options the state might have in pushing things along. The concern over “roadless” is that such an option, if selected by BLM, may effectively preclude NPR-A development in the near-term because the road, like the CD-5 bridge across the Colville River, is an essential part of long-range infrastructure needed for development. Conservation groups are likely to push for the roadless option, and federal agencies like the U.S. Fish and Wildlife Service and the U.S. Environmental Protection Agency may promote it informally. Murkowski said the projects and the road are supported by both the regional and village corporations for the North Slope. Kornze told Murkowski he had been told directly by North Slope villagers, in his visit to the Slope, of their support for the road. Without a road the only access to GMT-1 would be by aircraft, which could have a greater impact on the behavior of wildlife, like caribou, on which local people depend for subsistence. In a years-long fight over the Corps permit for the CD-5 road and bridge, the Fish and Wildlife Service and the EPA pushed strongly for roadless access to that production site, arguing that a pipeline crossing could be built below the Colville River in lieu of the bridge. The Corps initially chose the roadless option for CD-5, but on administrative appeal from ConocoPhillips and the State of Alaska, the agency reversed its decision and allowed the bridge. Construction began last winter, but a challenge by environmental groups to the Corps decision led to a judge ruling that more justification was needed. The Corps has since submitted a plan to explain its decision and Alaska U.S. District Judge Sharon Gleason accepted the proposal as possible remedy on July 22.

Shell, Slope Native corps. sign royalty deal for Chukchi leases

Shell has negotiated an option for seven Alaska Native corporations in the Arctic to purchase a royalty interest in its offshore leases in the Chukchi Sea. The percent of royalty and the financial terms not disclosed. The deal was announced July 31. Rex Rock, Sr., president of Arctic Slope Regional Corp. will be president of the Arctic Inupiat Offshore LLC, a joint-venture company formed by ASRC and six Native village corporations. The agreement applies to all of Shell’s 275 federal Outer Continental Shelf leases in the Chukchi Sea but does not include Shell’s leases in the Alaskan Beaufort Sea. Rock said the deal could create a sustainable economy for communities in the region. “This does three things: It creates alignment with the offshore development; it gives us a seat at the table in decisions on offshore development, and it can create an economic base,” he said. However, an oil and gas royalty owner normally plays a passive role in the management of an oil producing asset. The royalty owner has no direct role in a project, unlike a working interest partner. Inupiat people on the Arctic have supported onshore oil and gas development because of the industrial tax base it creates for the North Slope Borough, the regional municipality, and the local jobs it creates. Also, ASRC is a royalty owner in the producing Alpine oil field and will have a royalty interest in future production from certain lands in the National Petroleum Reserve-Alaska. There is opposition in the region to offshore development because of the threat pose by oil spills to subsistence resources, mainly migrating bowhead whales. One Inupiat tribal group, the Native Village of Point Hope, is still the lead plaintiff in a coalition with environmental groups suing the U.S. Department of the Interior over the Chukchi Sea lease sale, which was held in 2008. The U.S. Bureau of Ocean Energy Management is now redoing part of the environmental impact statement for the 2008 sale in response to a judge’s order in the lawsuit, and until that is completed Shell cannot resume its exploration in the Chukchi Sea. The company hopes to do exploration drilling in 2015 if the EIS issues are cleared up and if the Interior Department completes work on new Arctic drilling regulations.  “This is important for our Alaskan venture. A regional alliance with so many respected Alaska Native corporations provides Shell the opportunity to collaborate with savvy and experienced North Slope business partners going forward,” said Pete Slaiby, head of Shell’s Alaska operations. “It also underscores our commitment to provide opportunities for North Slope communities to directly benefit from Shell’s activities offshore Alaska.” U.S. Sen. Lisa Murkowski said she was pleased at the deal in a statement. “Shell’s decision to invest in the future of the region and its people should be applauded,” she said. “This announcement ensures that the people of the North Slope Borough share directly in the oil and gas bounty off their coast. It also gives locals a say in what happens near their communities. I think that’s a wise decision on Shell’s part.” The lack of a direct financial link between offshore development and coastal communities, which bear the risk on an oil spill, has long been a point of contention in Alaskan OCS leasing. In the U.S. Gulf of Mexico, coastal states share in federal OCS royalties but the same provision does not apply to Alaska. Joe Balash, Alaska’s Commissioner of Natural Resources, said the state and the North Slope Borough, the Arctic regional municipality, are pushing for revenue-sharing of federal OCS royalties with the state and coastal communities, but Congress must pass legislation for that. The royalty agreement between Shell and the communities will not change that, he said. Shell has spent almost $6 billion in exploration and leasing in the Chukchi and Beaufort Sea.

New companies close deal to acquire Brooks Range project

Citing improvements in the state’s investment climate and Alaska’s good oil prospects, three new companies are investing in the North Slope. Thyssen Petroleum LLC, of Houston, and two partners have completed the acquisition of Brooks Range Petroleum, an Alaska-based independent company, Thyseen said Aug. 5. Brooks Range is developing the small Mustang oil field on the North Slope, and has explored other nearby prospects. Thyssen’s bid to acquire Brooks Range was previously reported by the Journal but the Aug. 5 announcement was that two other companies, JK Tech Holdings Ltd. of Singapore and New York-based MEP Alaska LLC, have joined the venture. The three companies purchased the holdings in Brooks Range formerly owned by AVCG LLC (Alaska Venture Capital Partners) and Ramshorn Investments Inc. AVCG is a venture of several Kansas-based independents and is best known in Alaska as being led by Ken Thompson, a former ARCO Alaska president, who was its managing partner. Ramshorn is a subsidiary of Nabors Industries, which owns Nabors Alaska Drilling Co. a major Alaska contractor. Brooks Range president Bart Armfield said his company will now proceed with plans for drilling and construction and will have Mustang in production in early 2016. The field will initially produce 8,000 barrels per day in 2016 and will expand to 12,000 b/d in 2017, Armfeld said. Drilling will begin on production wells at Mustang later this fall, and the company will also proceed on finalizing plans for construction of an oil processing plant, Armfield said. Brooks Range is also working with the Alaska Industrial Development and Export Authority, the state development finance corporation, on financing and construction of road infrastructure and the processing facility for Mustang, which will also be available to other companies exploring in the area, which is west of the producing Kuparuk River field on the slope. Brooks Range is also planning to explore several prospects near Mustang on leases that it owns, Armfield said. “Alaska represents a huge opportunity for our company and we are delighted to have made this acquisition together with our partners,” Thyssen Chairman Lorne Thyssen said. Company CEO Hamid Jourabchi said, “Alaska attracted us because it remains a world-class hydrocarbon basin with considerable untapped potential, near existing infrastructure, and because the administration of Gov. Sean Parnell has created a very attractive investment climate for independent oil and gas companies.”

Shell, Slope Native corps. sign royalty deal for Chukchi leases

Shell has negotiated an option for seven Alaska Native corporations in the Arctic to purchase a royalty interest in its offshore leases in the Chukchi Sea. The percent of royalty and the financial terms not disclosed. The deal was announced July 31. Rex Rock, Sr., president of Arctic Slope Regional Corp. will be president of the Arctic Inupiat Offshore LLC, a joint-venture company formed by ASRC and six Native village corporations. The agreement applies to all of Shell’s 275 federal Outer Continental Shelf leases in the Chukchi Sea but does not include Shell’s leases in the Alaskan Beaufort Sea. Rock said the deal could create a sustainable economy for communities in the region. “This does three things: It creates alignment with the offshore development; it gives us a seat at the table in decisions on offshore development, and it can create an economic base,” he said. However, an oil and gas royalty owner normally plays a passive role in the management of an oil producing asset. The royalty owner has no direct role in a project, unlike a working interest partner. Inupiat people on the Arctic have supported onshore oil and gas development because of the industrial tax base it creates for the North Slope Borough, the regional municipality, and the local jobs it creates. Also, ASRC is a royalty owner in the producing Alpine oil field and will have a royalty interest in future production from certain lands in the National Petroleum Reserve-Alaska. There is opposition in the region to offshore development because of the threat pose by oil spills to subsistence resources, mainly migrating bowhead whales. One Inupiat tribal group, the Native Village of Point Hope, is still the lead plaintiff in a coalition with environmental groups suing the U.S. Department of the Interior over the Chukchi Sea lease sale, which was held by 2008. The U.S. Bureau of Ocean Energy Management is now redoing part of the environmental impact statement for the 2008 sale in response to a judge’s order in the lawsuit, and until that is completed Shell cannot resume its exploration in the Chukchi Sea. The company hopes to do exploration drilling in 2015 if the EIS issues are cleared up and if the Interior Department completes work on new Arctic drilling regulations.  “This is important for our Alaskan venture. A regional alliance with so many respected Alaska Native corporations provides Shell the opportunity to collaborate with savvy and experienced North Slope business partners going forward,” said Pete Slaiby, head of Shell’s Alaska operations. “It also underscores our commitment to provide opportunities for North Slope communities to directly benefit from Shell’s activities offshore Alaska.” U.S. Sen. Lisa Murkowski said she was pleased at the deal in a statement. “Shell’s decision to invest in the future of the region and its people should be applauded,” she said. “This announcement ensures that the people of the North Slope Borough share directly in the oil and gas bounty off their coast. It also gives locals a say in what happens near their communities. I think that’s a wise decision on Shell’s part.” The lack of a direct financial link between offshore development and coastal communities, which bear the risk on an oil spill, has long been a point of contention in Alaskan OCS leasing. In the U.S. Gulf of Mexico, coastal states share in federal OCS royalties but the same provision does not apply to Alaska. Joe Balash, Alaska’s Commissioner of Natural Resources, said the state and the North Slope Borough, the Arctic regional municipality, are pushing for revenue-sharing of federal OCS royalties with the state and coastal communities, but Congress must pass legislation for that. The royalty agreement between Shell and the communities will not change that, he said. Shell has spent almost $6 billion in exploration and leasing in the Chukchi and Beaufort Sea.

New Chukchi report due by October

The U.S. Bureau of Offshore Energy Management has developed a revised exploration and development scenario for Chukchi Sea oil and gas development that will be part of a new draft supplemental environmental impact statement, or SEIS, to be issued this fall. The scenario is confidential for now while being reviewed by other federal agencies, the State of Alaska and the North Slope Borough, the regional municipal government, the BOEM said in an update submitted to the U.S. Alaska District Court in Anchorage. The agency is now working on revised oil spill scenarios using the draft exploration and development plan. A new SEIS for the lease sale, held in 2008, was initiated by BOEM after the 9th Circuit Court of Appeals remanded the case to the U.S. Alaska District where it originated for review of the agency’s earlier assumption on a possible discovery in the Chukchi Sea. The agency used an estimate that a one-billion-barrel find might be found in the Chukchi, which environmental groups challenged, arguing it was too low. The 9th Circuit Court of Appeals agreed with the plaintiffs that the figure was “arbitrary and capricious” and remanded the case to the U.S. Alaska District Court, which ordered a further review. BOEM subsequently decided to do an SEIS with an eye toward revising the figure. An Alaska Native tribal group from Point Hope, a coastal village, is part of the lawsuit. Shell, ConocoPhillips, Statoil and Repsol bid more than $2 billion for leases in the 2008 sale. In its report to the court, BOEM also said it is on track to publish the new draft SEIS in early October and expects to have a Final EIS in late February and a Record of Decision by the U.S. Interior Department giving final approval by March. Under court order the agency must submit bimonthly reports on progress with the SEIS. The assumed size of discoveries is important because it provides the basis for the oil spill scenarios and environmental impact estimates in the environmental impact statement. The figure for a possible discovery in the SEIS is different than an estimate also filed with the government for a specific drilling prospect. The second estimate is based on geological and seismic knowledge of the prospect and leads to a “worst possible” oil spill estimate for that prospect. It is this number that leads to requirements in permits for a company to have a certain amount of spill containment and cleanup equipment on hand. Shell, ConocoPhillips and Statoil are planning exploration in the Chukchi Sea OCS leases and Shell drilled a partially-complete exploration well in 2012, and now hopes to return in 2015. The companies have been waiting, however, for the Department of the Interior to complete revised offshore drilling rules, and must now also wait for the legal issues over the original EIS to be settled. BOEM said it expects to have a final SEIS in early February 2015, and a Record of Decision in March. If Shell is to drill in the 2015 open-water Arctic season it must begin mobilizing its drill fleet in March and April.

Livengood owners focused on costs, optimizing production

International Tower Hills Ltd. is continuing its work on the large Livengood gold project about 70 miles north of Fairbanks. The focus now is on reducing costs and optimizing the production process. “We are proceeding towards a reevaluation of the capital and operating costs as we optimize the project,” said International Tower Hills CEO Tom Irwin. Gold in the Livengood district has long been known. Early-day placer miners were active in the area. The hardrock deposit that has now been outlined is large and low-grade, and would be mined with a large surface mine similar to the way gold is mined at Fort Knox, another large operation near Fairbanks. The Livengood project is on the Elliot Highway north of Fairbanks, and having year-around road access is a key advantage if a mine is developed, company spokesman Rick Solie said. Livengood is one of the world’s largest undeveloped gold deposits with about 20 million ounces of gold identified through drilling, 16 million ounces in the “measured and indicated” category and 4 million as “inferred” resources, Solie said. Measured and indicated refers to gold estimated through closely-space drill holes while inferred resources are those estimated by drill holes that are more widely-spaced. About 800 test holes have been drilled at Livengood so far, enough that the amount of gold can be estimated with reasonable certainty. There is likely more gold present, Solie said. The deposit is still “open” at its sides and bottom, meaning that the limit of the gold-bearing geologic formation has not yet been determined and there are exploration prospects close to the existing resource. There’s clearly enough gold for a mine, he said. The challenge now is to find a way to mine it economically. ITH completed a feasibility study in 2013 based on a 100,000 ton-per day mine but the study results showed that total capital and operating costs were higher than the gold price at the time.  Gold prices have recovered somewhat but are still not robust, so the focus of the current effort is on cost reduction and a possible rescoping of the mine. “A big area of our work is on scale. The feasibility study was done on the basis of a 100,000 ton-per day mine. That’s about twice the size of Fort Knox (another gold mine near Fairbanks), so we are considering whether that is still the best size,” Solie said. It’s a tradeoff, though. “If we lower the mill size and throughput we lower our capital costs but our operating costs may go up. So, we’re still working to find that sweet spot,” where costs and revenues are optimal, he said. A lot of other work is being done including continued work on metallurgy. The ore at Livengood is more complex than at Fort Knox, so the mill process is an area of interest, he said. Work is being done on the reagents, or chemicals, used in the extraction of gold, and ITH is reviewing both the costs and the gold recovery compared with what was estimated in the feasibility study. The ongoing environmental baseline monitoring is another priority. “We’re now in the sixth year of monitoring,” to compile the large amount of data that will be needed to support state and federal permits for the project, Solie said. “The data shows that we can build this project in an environmentally responsible manner.” “Energy is another focus of our work, because power will be 30 percent of our operating costs.” The company’s current plan is to purchase power from Golden Valley Electric Assoc., the Interior electric co-op, and to build a transmission line parallel to the Elliot Highway to bring power to the mine. With that in mind, ITH is closely monitoring the possibility of reduced electricity prices in GVEA system if liquefied natural gas, or LNG, is trucked from the North Slope to Fairbanks for space heating and power generation. The company will also consider options of on-site power generation because the LNG trucks from the Slope will pass very near the mine, Solie said, but there are pluses and minuses to on-site power generation. It may raise capital costs compared with purchasing power from a utility, and it can also pose a risk of “stranded investment” in an on-site power plant, when mine production ceases in the future. Solie said ITH has sufficient funds on hand to keep its team of about 12 people working on project design well into 2015. “However, we’ll have to raise more funds to advance the project,” to development, he said. The company has a strong management team. Tom Irwin, a former state Natural Resources commissioner and a 40-year mining industry veteran who also led development of the Fort Knox mine, is the ITH Chief Executive Officer. Karl Hanneman is general manager of the project. Hanneman is a 30-year industry veteran who led development of the Pogo underground gold mine near Delta, east of Fairbanks, and who played a key role on the team resolving permit issues for an expansion of the Red Dog lead-zinc mine in Northwest Alaska. ITH has its company headquarters in Fairbanks and is listed on the Vancouver, Toronto and New York stock exchanges. The majority of ITH’s stock is owned by U.S. based shareholders.  The company’s three largest shareholders, Tocqueville Asset Management, L.P., Anglo Ashanti LTD, and Paulson & Company, Inc. have been owners since the early days of the company and have continued to invest as the development needs of the project have required additional capital.  As ITH considers its financial needs to support the future development of the the Livengood project, the company said it is considering all appropriate financing options, including a strategic alliance with another company. The size of the gold resource, the favorable location, and the proven team are some of the reasons that ITH believes it will attract a strategic partner with a long term development horizon.         “With its excellent fundamentals and strong leverage to gold price, ITH remains a credible investment opportunity,” said Irwin.

Alaska LNG Project buying land, securing access

The Alaska LNG Project LLC has purchased 120.4 acres of from private landowners for a large liquefied natural gas plant at Nikiski, has an additional 97 acres under contract for purchase and is also working with the Kenai Peninsula Borough on conveyance of 29.9 areas of borough-owned lands. That’s according to the export application the project developers have filed with the U.S. Department of Energy. BP, ConocoPhillips and ExxonMobil Corp. are identified as the partners in the Alaska LNG Project LLC but the overall project will also include the state-owned Alaska Gasline Development Corp. and pipeline company TransCanada Corp in its ownership. “The project would be the largest integrated gas/LNG project of its kind ever designed and constructed,” the applicants wrote in their filing with the U.S. DOE. One of the requirements of the federal agency is that proponents of an LNG export project specify what property rights have been established in an application for an export permit. About 400 acres are needed for the plant but the project would like to have additional lands because of the requirements for equipment and material storage, project manager Steve Butt of ExxonMobil has said in interviews. The purchasing of land is in addition to $500 million committed to do pre-Front End Engineering and Design work on the large gas pipeline and LNG export project, estimated now to cost $45 billion to $65 billion. The bulk of the land purchased so far is small parcels typically just larger than one acre, but one 40-acre tract has been bought along with a 15- and 9-acre parcels, according to documents filed with the application. Most of the purchases were done in May and June, according to the application. The transactions are on file in the Kenai Peninsula Borough Recorder’s Office. “Approximately 10 contract land brokers are continuing to work in the Nikiski area to acquire additional land rights for the LLC, both for fee title land for the liquefaction facility site and shorter-term land access rights for studies within a corridor surrounding the lands anticipated to be acquired for project facilities,” the application stated. Land access rights have also been acquired for environmental, geological and geophysical surveys along the 800-mile pipeline corridor, including about 460.5 miles of state lands, 234.2 miles of federal lands managed by the U.S. Bureau of Land Management; about 33.8 miles of land owned by municipalities and approximately 31.6 miles of privately-owned lands. “ExxonMobil (the company managing the project) is in the process of acquiring additional land access rights for conducting further environmental and geological/geophysical due diligence studies at specific locations along the pipeline and transmission line routes,” the application stated. The company is also working with BP Exploration Alaska, one of the participants in the LLC and the operator of the Prudhoe Bay Unit, to gain access rights for environmental and geological/geophysical studies within the unit that are related to the large gas treatment plant that will have to be built on the North Slope. The application requests permission from the government to export up to 20 million tons per year of LNG for 30 years. The applications have previously said exports might total 15 million to 18 million tons per year but 20 million tons was used in the application so that the project has room to expand under an export permit, Butt said in an interview. The Alaska LNG group has also asked the DOE to handle its application in a separate process from the DOE’s consideration of Lower 48 projects. “The proposed Project is unlike any lower 48 export project and should be processed differently,” the companies’ filing stated. “Due to the unique factors facing this Project, a conditional authorization will facilitate Alaska LNG Project LLC’s ability to continue the ongoing substantial commercial and engineering activities and expenditures necessary to develop and construct the Project.” Since 2010, amid the rise of North American shale-gas production, the department has been deluged with applications for LNG exports from Lower 48 sites, according to an analysis of the application by the Office of the Federal Coordinator. As of mid-June, the Energy Department had approved 36 applications for exports to free-trade countries, and seven of 33 applications for non-free-trade exports. The remaining 26 are pending. So far, of the seven approved projects, just one is under construction, according to the analysis. In May, the department also proposed a new procedure for handling export applications for projects in the Lower 48 states. Rather than processing applications in the order in which they are filed, the department would deal first with those projects that have completed federal environmental reviews, according to the Federal Coordinator’s analysis. In its June 4 notice of the proposed change, the Energy Department said it had not decided whether it would apply the policy to an Alaska LNG export application. An exemption for Alaska from that policy would be important, said Larry Persily, the federal coordinator, because if the Alaska project was required to complete its EIS and secure other major permits before receiving an export permit it could add costs and possibly complicate financing. The coordinator office’s analysis also said the project sponsors are expected to “pre-file” this year with the Federal Energy Regulatory Commission to begin that agency’s multi-year oversight of the project. FERC is responsible for siting, construction and operation of LNG plants and related facilities, and would take the lead in crafting an environmental impact statement on behalf of multiple federal agencies. Pre-filing would include developing a work plan with FERC for filing the baseline “resource reports” that FERC uses as a foundation for the environmental review, the analysis said. The project developers already have started gathering information for many of those required reports. In addition to Department of Energy approval required for all U.S. gas exports, shipments of North Slope gas to somewhere other than Canada or Mexico, under a 1976 law, need a presidential finding that the exports “will not diminish the total quantity or quality nor increase the total price of energy available to the United States.” In 1988, President Ronald Reagan issued such a finding, without referring to any specific Alaska export project. In its July 18 application to the Department of Energy, Alaska LNG said it believes the 1988 finding is still valid and applies to its project, Persily said in his statement.

Permit filed to export Alaska LNG

KENAI — The consortium planning the North Slope gas pipeline and liquefied natural gas export project has reached another milestone. An application was filed July 18 for the U.S. Department of Energy export permit for the project. North Slope producers, TransCanada Corp. and the state of Alaska asked for permission to export up to 20 million metric tons yearly of liquefied natural gas, or LNG, from Alaska, the group announced in a press release. Larry Persily, the federal Alaska gas coordinator, has reviewed the 212-page filing and said the consortium has purchased about half the property it needs for a large LNG plant at Nikiski, or about 200 acres. The filing application seeks permission for exports over a period of 30 years to countries that have existing free trade agreements with the U.S., as well as to non-free trade agreement countries, according to the announcement, which was released July 21. “This is a significant milestone for the Alaska LNG project and demonstrates continued progress toward developing Alaska’s resources,” said senior project manager Steve Butt of ExxonMobil. “Filing of an export application is a critical step in commercializing North Slope natural gas.” Butt said in an interview earlier that the project specifications of exporting 15 million to 18 million tons per year haven’t changed but that the consortium is asking for permission to ship 20 million tons per year to leave a margin for growth. The project would process 3 billion to 3.5 billion cubic feet of gas produced on the North Slope and would convert 2.2 billion to 2.5 billion cubic feet per day into LNG. The difference between the gas produced and the gas converted to LNG is the amount used for fuel and for supply of gas to Alaska communities, which is estimated at about 400 million to 450 million cubic feet per day for maximum winter demand, which is the amount the project designers must use for planning, Butt said. The filing follows the signing of a Joint Venture Agreement among the parties on July 2 to fund $500 million for pre-front end engineering and design, or pre-FEED for the project. The overall project is now expected to cost $45 billion to $65 billion. The pre-FEED study, which is expected to be completed in late 2015 or early 2016, would provide an updated cost estimate, Butt said in an interview. If the results of the pre-FEED are favorable the parties would proceed in 2016 to the full Front-End Engineering and Design, which could cost between $1 billion and $2 billion. Final investment decisions on construction could come in 2019, which would have the project in operation in 2024 if it proceeds, he said. An economic study by NERA Economic Consulting was submitted in support of the application citing “unequivocally positive” economic impacts in Alaska and the United States. Benefits to the nation must be quantified if the government is to allow the exports. The project is anticipated to create up to 15,000 jobs in Alaska during construction and would require about 1,000 for operations, according to the announcement made July 21. The proposed project facilities include a liquefaction plant and terminal in the Nikiski area on the Kenai Peninsula, an 800-mile, 42-inch pipeline, up to eight compression stations and at least five take off points for in-state gas delivery, and a large gas treatment plant on the North Slope. On other activity Butt said the consortium has purchased property at the Nikiski site for the LNG plant. “We’ve purchased quite a bit of what we need but we would like to have more,” he said in a July 17 interview. “We’ve said we would like to have 400 to 500 acres for the plant but we would really like more because we will need ‘laydown’ (storage) space for materials and equipment and also an area for fabrication.” About 3,500 to 5,000 construction workers might be needed depending on how the plant is designed, Butt said, and “several hundred” for operations once the LNG plant is built and operating. The operations workforce will depend on how decisions are made to configure the plant, he said. The North Slope gas treatment plant will be another mega-plant built as a part of the pipeline and LNG project. The treatment plant might require as many as four summer “sealifts” to move modules and other equipment by sea to the slope, Butt said. Some of the modules will be very large, up to 8,000 tons. Modules shipped to the Slope in prior sealifts have usually ranged in the 3,000 tons to 5,000 tons in weight. Although the large modules would be built outside Alaska and shipped by barge to the Slope, a great number of smaller module units will also be needed and many of those would be built at Alaska fabrication sites, he said. Meanwhile, about 250 people are employed this summer in field work to gather data along the planned pipeline right-of-way with most of the effort focused on the southern half of the proposed line from Livengood near Fairbanks to Cook Inlet, Butt said. The work includes archeological and cultural surveys. “People are literally walking the right-of-way,” Butt said.  Eighty percent of the people hired for the summer field program are Alaskan, he said. The major pipeline river crossings at the Yukon and Susitna rivers are still technical challenges. However, depending on which of three planned southern routes is chosen the Susitna crossing might be avoided so that the pipeline remains on the river’s east side. That would require a Cook Inlet crossing further north, however. The Inlet crossing itself does not pose a major construction problem because there are already many pipelines in the Inlet and a great deal of knowledge within the industry. However, endangered Beluga whales in the Inlet are a concern and construction would have to be timed so as to have a least impact, he said. The State of Alaska is participating in the project through the state-owned Alaska Gasline Development Corp. The project agreement is structured so that the three major gas producers, BP, ExxonMobil, ConocoPhillips as well as TransCanada, a pipeline company, would own the large North Slope gas treatment plant and the gas pipeline. However, the state has an option to purchase 40 percent of TransCanada’s share, although that option must be exercised in 2016. The state will meanwhile own 25 percent of the LNG plant at Nikiski through the AGDC, the state corporation, with the three producers owning the other 75 percent. TransCanada will have no share of the LNG plant.

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