Tim Bradner

Outlook: population, jobs will continue slow, steady growth

JUNEAU — Alaska’s economy seems in good shape and is continuing in a long-term, slow-growth trend, although questions around the national recovery hang over Alaska as well as the rest of the U.S., according to the Northrim Bank annual economic outlook report. The Anchorage-based bank held its annual economic outlook luncheons for business and community leaders in Fairbanks, Anchorage and Juneau on April 9, 10 and 11. Northrim Vice President and Economist Mark Edwards painted an overall picture of a state economy in sturdy shape, citing building permits statewide up 9 percent; loan delinquencies at 3.6 percent for 1-4 unit residential properties in the fourth quarter 2013, compared with the national rate at 6.7 percent; and a 1 percent foreclosure rate compared with 4.9 percent for the nation. In residential loan delinquencies, Alaska was third-best in the U.S, Edwards said. In foreclosures, Alaska was fourth-best. The increase in building permits statewide is the biggest gain since 2007, he said. In unemployment, the Alaska statewide rate of 6.5 percent is roughly on par with the national rate of 6.7 percent. However, the Anchorage unemployment rate of 4.7 percent and the Juneau rate at 4.6 percent reflect tight labor markets in those communities, Edwards said. One negative trend is that population growth appears to be slowing and an out-migration of people leaving may be influencing that. Edwards said population growth was 0.6 percent last year, to a total of 736,399, and was the slowest rate in 17 years. There was a natural increase (births) of 7,420 but an outflow of 2,848, likely due to improving economic conditions in the Lower 48, he said. “We may be also leaking retirees to other states,” Edwards said. As Alaskans retire they are more prone to relocate to other states, in contrast to the Lower 48 where retirees may stay closer to home. Other indicators are healthy but indicate an economy is a slower-growth mode. Per-capita income of $50,032 was ninth-best of the 50 states but the rate of income growth per capital, at 1.7 percent per year, was 47th in the nation, Edwards said. The U.S. average per capital growth rate was 2.6 percent. Edwards cited a rebounding tourism industry as one bright spot for the state. Two million visitors are expected this year, for the fourth year in a row. Visitors are up 7 percent from two years ago, and cruise ship passengers, a crucial driver for the visitor industry, are up 13 percent over the same period. “Employment (in tourism) was up 3 percent in the last two years, to 39,000. Labor income was  $1.3 billion and total (tourist) spending was $3.9 billion. Both numbers were up 6 percent over the last two years,” Edwards said. The visitor industry also generated $179 million in revenue for the state and local governments in Alaska, he said. Employment data from the state Department of Labor and Workforce Development affirms the modest growth rates Edwards cited. Statewide wage and salary employment was 319,200 in January, the most recent month for which confirmed data is available, compared with 314,300 in January 2013. Statewide employment has been gradually growing for many years and crossed the 300,000 mark in January 2008. The national economic trends that also influence Alaska include persistent government deficits and a concern that government agencies are crowding out private industry. Also, because of the heavy reliance on government in the economy, “it’s difficult to price assets and to see a forward path for companies in certain fields without knowing what the government is going to do,” Edwards said. Like most economists, Edwards expressed concerns over the slow “jobless” national recovery from the 2009 recession. The economy overall is on a gradual rebound but employment growth is not keeping pace, Edwards said. That means the powerful stimulus of consumer spending is still lacking in the recovery.

ConocoPhillips to reopen Kenai LNG plant, resume exports

ConocoPhillips is restarting its liquefied natural gas plant on the Kenai Peninsula and will resume shipments of LNG in May, the company announced April 14. Five shipments are planned this year, ConocoPhillips spokeswoman Amy Burnett said. The announcement came as the U.S. Department of Energy issued its approval of exports, also on Monday. DOE authorized the shipment of 40 billion cubic feet of gas over two years. “This is great news for the cradle of Alaska’s oil and gas industry on the Kenai Peninsula,” said Alaska U.S. Sen. Mark Begich, who worked with the DOE on the approval. “With plenty of gas available to meet local needs through at least 2018, we’re seeing the kind of job growth responsible oil and gas development can provide.” The federal agency had agreed earlier that ConocoPhillips could export to nations that are in Free Trade Agreements with the U.S., such as South Korea. Exports to those nations are approved by DOE with a streamlined process. The April 14 approval by DOE, however, extended that to countries who are not in free trade agreements, such as Japan. ConocoPhillips has mainly exported LNG to Japan in the past although there have been shipments to Korea. Begich had pushed the DOE to process the ConocoPhillips application to ship to non-Free Trade Agreement countries outside the queue DOE has set up for non-FTA LNG export projects. “DOE has approved only six applications from Lower 48 projects in that queue since 2012, and at least 24 applications remain in the queue,” Begich said in a statement. Except for Alaska’s project, LNG export proposals seeking DOE approval are all Lower 48 plants. Those have sparked sharp controversy over the possibility that exports could result in higher domestic prices for natural gas, and opposition to exports from U.S. industries, such as chemical manufacturers, that benefit from low-cost gas used as feedstock. Begich pressed the case for Alaska being treated differently “I asked Acting Assistant Secretary for Fossil Energy, Chris Smith, to visit the plant last summer, and familiarize himself with our industry, our workforce and the unique situation of our country’s only LNG export plant with a safe track record spanning four decades,” Begich said. “That visit is paying dividends today.” Burnett said the reopening will not result in any significant increase in employment at the LNG plant because most of its employees were retained when the plant went into mothball status. Exports were stopped in 2012 because of shortages of natural gas in Cook Inlet fields. The gas supply situation has now improved due to new drilling to the point that a surplus would be available for export during summer. In winter, however, gas production will be reserved for local utilities.

Production exceeds Revenue forecast

North Slope and Cook Inlet crude oil production estimates have been revised upward, according to an updated production and revenue forecast released by the state Department of Revenue on April 7. “Based on actual production data we have seen an increase of 13,600 barrels per day of North Slope oil in the current year compared to what we had forecast just five months ago,” state Revenue Commissioner Angela Rodell said in a statement issued with the revised forecast. That increase, plus a slightly higher average oil price now predicted for state fiscal year 2014, which ends June 30, is worth about $374 million to the treasury in additional income, compared with what was forecast in December. The additional revenues will mainly have the effect of reducing a projected large deficit for the current fiscal year previously estimated at about $1.8 billion. The new estimate is for production to average 521,800 barrels per day, or b/d, for the current state fiscal year. The previous estimate, released in early December, was for production to average 508,200 b/d for the period. Using the new estimate, North Slope production will decline 1.8 percent from the previous year, an improvement over the historic long-term decline of 6 percent from the North Slope fields. The Revenue Department estimated a 4 percent annual decline in its December forecast, assuming some increase in production activity, but the increased activity has exceeded predictions. As for the expected oil price, the revised forecast assumes an average price of $106.61 per barrel for the fiscal year, up from $105.58 per barrel predicted last December. Cathy Foerster, chair of the state’s independent oil and gas regulatory commission, verified the increase in North Slope activity. “Over the past year Prudhoe Bay has seen a 35 percent increase in well work activity and the Kuparuk River field has seen an 18 percent increase. Perhaps the best news is that the Prudhoe Bay and Kuparuk annual (production) declines appear to be slowing. The last time I looked at the rolling 12-month decline numbers Prudhoe was at 2 percent and Kuparuk was at 4 percent, compared to their usual decline of 6 percent,” Foerster said in comments April 7 to the state Senate’s special TAPS Throughput Committee. Estimates for Cook Inlet oil production were also revised upward to 14,500 barrels per day for the fiscal year compared with 13,500 barrels per day projected in the December forecast, according to the Revenue Department. The increased North Slope production, which has been measured in actual production tallied through February, or the first eight months of the fiscal year, is mainly a result of higher levels of drilling and major maintenance “workovers” on older producing wells, activity that picked up after the Legislature passed a revision in the state petroleum production tax last year. Major field operators BP and ConocoPhillips have both hired new drill rigs in the producing fields. The new estimate assumes some maintenance downtime for production facilities in June, the last month of the fiscal year, which would curtail some production, Rodell said. If the maintenance takes less time than expected, production rates could remain strong. Production from the Slope has been stronger than expected and if the current trend were to hold, without any production facilities downtime, the average would be about 526,000 b/d, Revenue officials have said. Rodell cautioned that the spring forecast is an update of the 2013 fall forecast that was assembled when the previous oil production tax, known as ACES, was still in effect. A revision on the tax, passed by the Legislature last year in Senate Bill 21, took effect Jan. 1. “The coming fall 2014 forecast will be the first under the new tax system and the first budget cycle companies can evaluate projects with tax certainty. I expect to see many questions answered between now and then, hopefully resulting in high enough levels of certainty to begin incorporating new production into our revenue forecast,” Rodell said in the statement.

Tug engine failure blamed on water in fuel

It is a mariner’s worst nightmare: At sea, in a bad storm, pulling a heavy load and working to keep control in a dicey situation.  Then, all the engines quit. And won’t restart. Precisely this event occurred in late December 2012 to the crew of the Edison Chouest vessel Aiviq as it struggled to keep towlines on Shell’s conical drill vessel Kulluk. The effort failed. The Kulluk went aground off Kodiak Island and was a total loss, which is now well known and documented. It was a miracle that there were no injuries or loss of life, and the evacuation of 18 crewmembers from the Kulluk’s heaving deck by Coast Guard helicopters during the storm was an exploit that should go down in maritime history. The grounding itself occurred on a small island off Kodiak’s southern shore as Shell was transporting the Kulluk from Dutch Harbor to Seattle for winter maintenance. But a big puzzle in the marine community since the grounding has been why all four of the engines on the Aiviq quit, particularly because the vessel was virtually brand new. Luckily the U.S. Coast Guard cutter Alex Haley and Crowley Maritime’s tug Guardian were able to get to the scene to lend assistance, although they couldn’t save the Kulluk. What immediately occurred to people in the marine industry was that some problem with the fuel supply to the engines occurred on the Aiviq. This has now been confirmed by the official U.S. Coast Guard report on the grounding, which was released April 3. Seawater had gotten into the fuel system through vents on the deck that were exposed to waves buffeting the Aiviq. There were times in fact when the rear deck of the vessel, including the vents, was submerged. The design of the newly-built Aiviq led to the vents being placed in a way that they would be exposed to water in rough seas, the Coast Guard report indicated. In describing circumstances that led to the engine failures, the Coast Guard said: “Due to the Aiviq design, water regularly washes onto the aft working deck area during high seas…particularly while towing. This seawater tends to be carried back and forth across the deck as the Aiviq rolls.” Very heavy weather encountered on Dec. 27, “created an environment where the tank vents…would be subject to water immersion, potentially being completely submerged at times. Any failure of the … vents would allow water into the common vent/overflow header,” from where it could enter the fuel system under certain circumstances. The Coast Guard also criticized Edison Chouest for operating the fuel system in a way that was different than the prescribed procedure but also added that “had the Aiviq operated under the approved fuel system configuration, it is not clear whether it would have mitigated or prevented the loss of the main engines,” because the vent system still offered a means for water intrusion into the tanks. The report was also critical of actions of the vessel’s chief engineer in gauging possible water intrusion. Also, “the Chief Engineer did not realize the potential for water intrusion through the vents,” the Coast Guard report said. “The Aiviq engineering personnel did not use the redundant fuel management systems aboard the Aiviq to protect the critical fuel system from contamination. Protective fuel system configurations, intended to segregate all engines and generators in approved guidance was not following. In addition, no formal fuel management procedures were onboard the Aiviq for crew use and reference,” the report said. The Coast Guard also said water contamination and other fuel purification issues were noted in engineering logs immediately prior to the casualty, or grounding. Also, tests at the Delta Western bulk fuel tanks in Dutch Harbor on the same ultra-low sulfur diesel loaded onto the Aiviq before its departure revealed no water contamination. However, “the tests did exhibit an unusual and unexplained characteristic wherein an emulsion formed when the fuel was mixed with fresh water or seawater,” the report said. The Coast Guard also found, “extensive corrosion on the main engine and generator injector internal parts. This corrosion contributed to a failure of the injectors of the main engines.” Although the fuel problems and engine failures were cited, the Coast Guard report mainly singled out risk management practices by both Shell and Edison Chouest for criticism. A senior Coast Guard official, Rear Admiral Thomas Ostebo, also cited the lack of experience of Edison Chouest in northern waters. Ostebo is the commandant of Alaska’s 17th Coast Guard District, and wrote a review of the report that is included with the document. In its report, the Coast Guard said, “A series of events contributed to the causal factors that resulted in the grounding of the Kulluk, with the most significant factor being the inadequate assessment and management of risks associated with a complex vessel movement during the winter in the unique and challenging operating environment of Alaska.”  Ostebo went further in his criticisms: “The most significant factor was the decision to make the voyage (with the Kulluk) in the winter,” the rear admiral wrote in his review of the report. He faulted Shell and Edison Chouest for risk management and also their application of towing measures. He said the master, chief engineer and third mate of the Aiviq, may have been negligent, and that the vessel Aiviq had experienced problems prior to the accident that were not reported to the Coast Guard, which are potential violations of law. The incidents are now under investigation. “Mariners who have experience working offshore in the Gulf of Mexico do not necessarily possess the knowledge of the unique hazards that exist in the Gulf of Alaska,” he wrote. Ostebo went on to recommend that Edson Chouest or other companies working in the Arctic develop specific guidelines, safety checklists and other procedures. Rear Admiral Joseph Servidio, the Coast Guard’s assistant commandant for prevention policy, agreed with the report’s major conclusion that there was, “Inadequate assessment and management of the risks by the parties involved (Shell and Edison Chouest). Vessels and the operations are growing more complex and the risks that accompany these operations increase, whether in Alaskan waters or not. The failure to (adequately) understand and not completely assume past practice to address new risks is critical both in company practice and culture,” Servidio wrote. “In this case the risks associated with a single vessel tow by a new purpose-built vessel of a unique conical-shaped hull, with people aboard, in winter Alaskan waters, where weather systems and sea are expected to rapidly develop, were extremely high.” The report itself made several safety recommendations including that the U.S. Coast Guard Commandant and the Towing Safety Advisory Council establish a working group to draft a statement addressing issues raised by the accident, and other issues related to towing offshore drilling units in the Arctic. The report also recommended a review of standards for ocean towing systems to include “inspections and non-destructive testing of towing equipment, detailed review of tow configurations to include history of towing equipment such as shackles, connector links and bridge chains.” In a written response, Shell said: “We are reviewing the Coast Guard’s report on the Kulluk towing incident. We appreciate the thorough investigation and will take any findings seriously.” “Already, we have implemented lessons learned from our internal review of our 2012 operations. Those improvements will be measured against the findings in the U.S.C.G. report as well as recommendations from the US Department of Interior.” Edison Chouest was not available to comment on the report. Alaska U.S. Sen. Lisa Murkowski said the Coast Guard report “has made a number of good recommendations to improve the safety of maritime activities as exploration of the Arctic moves forward. I believe that we can safely develop our energy resources in the Arctic, but it requires that we adhere to world-class safety standards.”

Rio Tinto gifts stake in Northern Dynasty to state charities

Rio Tinto, the London-based international mining company, will gift its 19.1 percent ownership in Northern Dynasty Minerals Ltd, owner of the Pebble mine prospect, to two Alaskan charitable foundations. The April 7 decision follows the review announced last year of Rio Tinto’s interest in Northern Dynasty, which concluded the Pebble project does not fit its strategy, according to the company. Rio Tinto’s decision is a disappointment for supporters of a mine at Pebble but the gifting of a major share of Northern Dynasty to the charities gives does give Alaskans a major stake in the project. Rio Tinto follows Anglo American in pulling out of the project. Anglo was a 50 percent owner in the Pebble Partnership with Northern Dynasty until last year, when it decided to withdraw after spending more than $540 million in exploration and planning work. Prior to the gift, Rio Tinto, through Rio Tinto Fer et Titane Inc., an indirect wholly-owned subsidiary of Rio Tinto plc, owned 18.1 million common shares of Northern Dynasty, about 19 percent of the outstanding shares. As of April 8, those shares were worth just less than $16 million at the price of 88 cents per share. In September, before Anglo American pulled out of the partnership, the share price was about $2.22. The day after the Anglo announcement, more than 4.1 million shares were sold, plunging the price to $1.50 and it has steadily decreased since then. Prior to the Anglo announcement, Rio Tinto’s shares were worth about $40 million. Pebble is a large deposit of copper, gold and molybdenum about 18 miles north of Iliamna Lake. The mine has become controversial because of concerns over potential impacts on salmon-rearing streams that feed into Bristol Bay. Under Rio Tinto’s plan for gifting, the company’s shares in Northern Dynasty will be divided equally between the Alaska Community Foundation to fund educational and vocational training and the Bristol Bay Native Corporation Education Foundation, which supports educational and cultural programs in the region where the mine is located. Rio Tinto Copper CEO Jean-Sebastien Jacques said, “Rio Tinto has long and historic ties to Alaska and we continue to see Alaska as an attractive location for potential future investment. By giving our shares to two respected Alaskan charities, we are ensuring that Alaskans will have a say in Pebble’s future development and that any economic benefit supports Alaska’s ability to attract investment that creates jobs.” The Alaska Community Foundation is a statewide philanthropy organization established in 1995 that is focused on strengthening Alaska’s communities. The foundation will use the gift of shares to create a new Vocational Fund for Alaska’s Future which will support programs that provide vocational training and skills development needed in the mining and extractive industries. The Bristol Bay Native Corp. Education Foundation, established in 1986, is a Native Alaskan charitable organization that supports education and cultural programs for Bristol Bay native youth. Both organizations have independent boards of directors and mandates to manage assets for the benefit of future generations. In a related development, Northern Dynasty and The Pebble Partnership, a wholly-owned Alaska limited partnership, are preparing to submit documents April 29 to the U.S. Environmental Protection Agency in response to a possible EPA action to foreclose development of a large mine in the Bristol Bay region. The responses are due April 29. The State of Alaska will also file a response because the Pebble deposit is located on state-owned lands. On the pending filing with EPA, John Shively, co-chair of Pebble Partnership’s board, said, “It’s a little unclear just what we are expected to respond to. Normally, a procedure like this involves a project where a developer has applied for permits and a project is described in the permit application.” Pebble Partnership has yet to publish a project description and to apply for permits, so there is no specific proposal to which the EPA would apply its veto authority. The EPA is considering exercise of a seldom-used authority under the federal Clean Water Act to prohibit a large mine like Pebble, a gold, copper and molybdenum project that has been under study by the Pebble Partnership for several years. In the few cases where EPA has used its Clean Water Act veto authority the cases have involved projects that have made actual applications. Pebble has not yet made an application, so an EPA action would be an unprecedented action in nature. Shively said that once the Pebble Partnership and state responses are filed, the EPA would have to put forward the specifics of what it intends to do, for example whether it would be a narrowly-written prohibition, for example, of tailings disposal at or near the Pebble mine site, or whether it would be a broad prohibition of a large mine in the Bristol Bay region, which is an area the size of many U.S. states.

State commission finalizes tough new rules on fracking

Alaska’s oil and gas regulatory commission has adopted new rules governing hydraulic fracturing, the chairman of the commission told a state legislative committee April 8. The final rule is being reviewed by the state Attorney General and must still be signed by Alaska Lt. Gov. Mead Treadwell, but those are formalities. The rules will require testing of all water wells within a half-mile radius of a well to be fractured, and mandate testing of the wells for contamination after the fracture job is completed, according to Cathy Foerster, chair of the Alaska Oil and Gas Conservation Commission, or AOGCC. In some cases testing of water wells prior to the fracturing may be required at the discretion of the commission. Foerster appeared before the state senate’s TAPS Throughput Committee, a special committee formed to review oil and gas technical issues, to discuss issued before the commission including the fracturing rules. The Alaska Oil and Gas Association, or AOGA, the industry’s trade group, said the new Alaska rules may be one of the most stringent in the nation, according to Josh Kindred, regulatory and legal affairs manager for the association, in an interview. Other states require water well testing within one-quarter of a mile of the well to be fractured or require only a set number of wells to be tested. “We’re not aware of any other state that will require all wells within half a mile to be tested,” Kindred said. The rule will also require disclosure of chemicals used in fracturing fluids and for the chemicals to be reported to FracFocus, a national website maintained for public disclosure of chemicals used in hyraulic fracturing. Foerster said the disclosure requirements are generally similar to other states require and will adequately protect the trade secrets of service companies working on “frac” jobs. One concern of the industry is that companies will have to report separately to FracFocus and to the state oil and gas conservation commission and it is not yet clear that the reporting requirements will be similar, which could lead to more administrative burdens on companies. Also, requirements for pre-approval by the commission, which some other states also require, could pose problems for companies in Alaska that may often face seasonal constraints if there are delays. Overall, the industry’s concern is that the rules go well beyond what is needed to protect the public. “Our concern is that these regulations will result in substantial costs without providing any real tangible benefit to the public, as most hydraulic fracture treatments in Alaska take place thousands of feet below any drinking water,” said Kara Moriarty, executive director of the Alaska Oil and Gas Association. Foerster told the senate committee April 8 that the AOGCC has regulated hydraulic fracturing in Alaska for years and that the update of its rules is being done to demonstrate that the state regulatory commission is on top of an issue that is now attracting attention in Alaska. “We’ve been hydraulic fracturing wells in Alaska for over 40 years. About a quarter of all wells drilled in Alaska have been fractured,” she said.  “The rule update has been a multi-year effort, first to keep up with technology advances, second to address fracturing fluids disclosure and water quality monitoring and third to gather all of our regulatory requirements into a section titled hydraulic fracturing to make it easier for the public to see how we are regulating hydraulic fracturing.” A few years ago a coal-bed methane exploration program in Southcentral Alaska sparked intense public controversy when homeowners complained about threats to water wells from fluids used in drilling into shallow coal seams. The program, and controversy, ended in 2004 when the company involved, Denver-based Evergreen Resources Inc. was purchased by Pioneer Natural Resources. Pioneer closed down the program due to poor results from the drilling and the public controversy.

Coast Guard report critical of Shell, contractor in Kulluk grounding

A U.S. Coast Guard report released Thursday on the 2012 grounding of Shells’ drill vessel Kulluk is highly critical of Shell and its marine contractor, Louisiana-based Edison Chouest. The grounding occurred on a small island off Kodiak’s southern shore during a storm in the Gulf of Alaska in December 2012. Shell was transporting the Kulluk from Dutch Harbor to Seattle for winter maintenance when the accident happened. Although the Kulluk was extensively damaged and was a total loss, there were no injuries or fatalities during the event. The report singled out risk management practices by Shell and Edison Chouest but a senior Coast Guard official, Rear Admiral Thomas Ostebo, also cited the lack of experience of Edison Chouest in northern waters. Ostebo is the commandant of Alaska’s 17th Coast Guard District, and wrote a review of the report that is included with the document. “A series of events contributed to the causal factors that resulted in the grounding of the Kulluk, with the most significant factor being the inadequate assessment and management of risks associated with a complex vessel movement during the winter in the unique and challenging operating environment of Alaska,” the Coast Guard said in a statement on the report. Ostebo went further in his criticisms. “The most significant factor was the decision to make the voyage (with the Kulluk) in the winter,” Ostebo wrote in his review of the report. He faulted Shell and Edison Chouest for risk management and their application of towing measures. He said the master, chief engineer and third mate of the Aiviq, the Edison Chouest vessel towing the Kulluk, may have been negligent, and that the vessel Aiviq had experienced problems prior to the accident that were not reported to the Coast Guard, which are potential violations of law. The incidents are now under investigation. Ostebo also noted Edison Chouest’s lack of experience in northern waters. “Mariners who have experience working offshore in the Gulf of Mexico do not necessarily possess the knowledge of the unique hazards that exist in the Gulf of Alaska,” he wrote.   Ostebo went on to recommend that Edson Chouest or other companies working in the Arctic develop specific guidelines, safety checklists and other procedures. Rear Admiral Joseph Servidio, the Coast Guard’s assistant commandant for prevention policy, agreed with the report’s major conclusion that there was, “Inadequate assessment and management of the risks by the parties involved,” which were Shell and Edison Chouest. “Vessels and the operations are growing more complex and the risks that accompany these operations increase, whether in Alaskan waters or not. The failure to (adequately) understand and not completely assume past practice to address new risks is critical both in company practice and culture,” Servidio wrote. “In this case the risks associated with a single vessel tow by a new purpose-built vessel of a unique conical-shaped hull, with people aboard, in winter Alaskan waters, where weather systems and sea are expected to rapidly develop, were extremely high,” Servido wrote. The report itself made several safety recommendations including that the U.S. Coast Guard Commandant and the Towing Safety Advisory Council establish a working group to draft a statement addressing issues raised by the accident, and other issues related to towing offshore drilling units in the Arctic. The report also recommended a review of standards for ocean towing systems to include “inspections and non-destructive testing of towing equipment, detailed review of tow configurations to include history of towing equipment such as shackles, connector links and bridge chains.” In a written response, Shell said: “We are reviewing the Coast Guard's report on the Kulluk towing incident. We appreciate the thorough investigation and will take any findings seriously.” “Already, we have implemented lessons learned from our internal review of our 2012 operations. Those improvements will be measured against the findings in the U.S.C.G. report as well as recommendations from the US Department of Interior,” Shell said. Edison Chouest was not available for a comment on the report. Alaska U.S. Sen. Lisa Murkowski said the Coast Guard report “has made a number of good recommendations to improve the safety of maritime activities as exploration of the Arctic moves forward. I believe that we can safely develop our energy resources in the Arctic, but it requires that we adhere to world-class safety standards.”

Former official recommends scrutiny for TransCanada role

JUNEAU — A former state revenue economist has recommended state legislators take more time with a proposal to partner with TransCanada Corp. as part of a deal for state financial participation in a large natural gas project. However, Roger Marks, now an independent consultant, endorsed the basic terms of state participation with North Slope producers on the gas project. Marks retired from the Department of Revenue in 2008. He spoke to the House Resources Committee March 27. Senate Bill 138, which has passed the Senate and is now before the House Resources Committee, would have the state own 25 percent of the project and also ship state-owned gas through its share of the gas pipeline and liquefied natural gas plant. “The administration has put forth a thoughtful proposal. My observations are just to offer some options, as suggestions,” he said. Most of Marks’ remarks were directed at a proposal for the state to partner with TransCanada on its 25 percent share of the pipeline and large gas treatment plant on the North Slope to lessen the financial burden for Alaska, although the state would finance, and own, all of its 25 percent share of the large LNG plant proposed to be built at Nikiski, near Kenai. Marks suggested the Legislature explore ways to go ahead with the deal with the producers, to keep the project on schedule, but take more time to review the relationship with TransCanada and possibly improve it. Some of the advantages to the state of the TransCanada partnership are being overblown, Marks told the House Resources Committee. For example, a motivation for the state to have TransCanada as a partner is the company’s experience, but Marks said he cannot find evidence that TransCanada has experience with large gas treatment plants, a major part of this project. In TransCanada’s original application to the state for its Alaska Gasline Inducement Act license in 2009, Marks said TransCanada did not want to take on the gas treatment plant part of that project. “They eventually agreed to do it, but hired a contractor to provide assistance,” he said. Marks said the TransCanada deal overall appears to have been engineered to get the state out from under a disadvantaged 2010 contract with the pipeline company under the Alaska Gasline Inducement Act, or AGIA, which could subject the state to a treble-damages claim from TransCanada if that contract was violated. “Treble damages” is a legal term that allows a court to triple a defendant’s liability. The Legislature should initiate an independent legal review of its liability under the treble-damages clause in the AIGA agreement, Marks said. Key terms of the treble-damages provision are unclear. So far TransCanada has spent $550 million on its work under AGIA with the state providing $350 million of that under an agreement to provide a subsidy and TransCanada itself investing $200 million, Marks said. What is not clear is whether the treble damages are for the gross amount expended, or three times the $550 million, or for TransCanada’s net investment, or three times $200 million, he said. Marks also believes the state doesn’t really need TransCanada’s help in financing and that it could be capable of financing all of its 25 percent share of in other ways, including all of it in debt financing. That opinion is based on consultations the state had with large financial firms on previous gas project proposals in which Marks was involved, and even a study by Citigroup, the nation’s third-largest commercial bank, in 2011 for the state-owned Alaska Gasline Development Corp., or AGDC, that concluded that 100 percent debt-financing for an $8 billion state-built “bullet line” might be feasible, and without a partner. The plan now before legislators contemplates the state financing its share of the large gas project with a combination of cash equity investment and debt, which would put pressure on the state budget between 2019 and 2023, years in which the state would have to make large cash contributions as equity. Taking on partners such as TransCanada would lessen that burden, administration officials have said. Marks said there should be more research on alternative financing packages that would lessen the needs for up-front cash payments by the state. Most important, any financing alternative that reduces the cost of capital for the state’s 25 percent share of the project would pay off handsomely in reduced costs for transporting state-owned gas, to the benefit of consumers who would receive gas through the system. “A 2 percent reduction of the state’s cost of capital can easily translate into several hundred dollars a year in savings in energy for consumers,” Marks told the House committee. One of the key arguments being presented for the TransCanada partnership is that the pipeline company would finance the 25 percent share of the Slope gas treatment plant and pipeline itself, so that this would not be a state obligation that would load up debt on the state and impede its finances. Marks said this is illusory too, because under the partnership arrangement the state would have to sign a long-term “take or pay” contact with TransCanada to ship the state’s gas through TransCanada’s part of the treatment plant and pipeline. The contract would represent a long-term multi-billion dollar commitment by the state that would itself be considered a form of debt by the rating agencies, Marks said. Moody’s Investor Services had advised the state that this would be the case in 2006, when the state proposed a similar pipeline ownership plan. “Debt is debt. You can’t avoid it,” by working through TransCanada, Marks said. Marks’ criticism of the partnership was countered by state Natural Resources Commissioner Joe Balash and Revenue Commissioner Angela Rodell in comments to the House committee March 31. “The value of having TransCanada is far more than financial. The state would be hard-pressed to have the human capital and the resources,” that TransCanada could provide during a time when critical negotiations with the producers will be underway, Rodell said. Balash agreed with that. “TransCanada is not just a bank,” he said. If the state went out to look for other offers, “how many pipeline companies are there in North America who can match TransCanada? Maybe three or four. Would any of them be interested?” Balash asked. The fact that TransCanada was the only qualifying bidder interested if the state’s solicitation under AGIA would seem to speak for itself. “We believe the opportunity to improve on the terms TransCanada has offered are very limited,” Balash said. TransCanada’s commitment to a financing structure of 75 percent debt and 25 percent equity is a huge benefit to the state, Balash said, because pipeline companies make their guaranteed profit on the equity portion and most pipelines have higher percentages of equity. A survey of new Federal Energy Regulatory Commission-regulated gas pipelines built or planned showed the lowest equity percentage at 60 percent. It is to the state’s advantage to have lower equity and more debt because that translates to a lower tariff for transporting gas and higher state revenues. In his remarks March 27 Marks did endorse the state administration’s basic approach. The concept of the state taking its royalty and production tax in kind, or in the form of gas, and taking an ownership stake in the project equal to the state’s share of gas, about 25 percent, is sound, Marks said. Having the state share in ownership is important to the producers because it lessesn the amount of the project they have to finance and better aligns the overall risks and rewards of the project, he said. “This helps the economics of the project considerably,” for the producers, Marks said. “It is possible that the proposal, as it is, is fine. But if it is possible to modify some of the terms (on the TransCanada partnership) you might want to take a little more time.” There are also uncertainties in how the would regulate the project and these should be fleshed out, Marks said. FERC normally regulates interstate pipelines and an LNG project that exports gas that is served by a pipeline all within one state is something new.  “The proposal in the Heads-of-Agreement (with the producers) is for FERC to regulate under Section 3 of the Natural Gas Act,” Marks said. “Section 3 is mainly designed for licensing the siting, construction, expansion and operation of LNG import or export terminals. Terminals include facilities to transport or process gas. However, this section is rarely used to include a large pipeline with local consumption,” of gas, he said. This needs consultation with the FERC, Marks said. It also would seem to leave regulation of an expansion of the project, to accommodate new gas or expansions related to in-state needs in limbo with no apparent regulation of tariffs or other protections for the public. Marks laid out a scenario where Enstar Natural Gas Co., supplied now with Cook Inlet gas, might need North Slope gas in the future. However, if all of the gas moving down the pipe, including the state’s gas, is committed under long-term LNG export contracts that must be served, the only way to accommodate Enstar would be with new gas delivered through an expansion, Marks said, most likely added compression. But who, he asked, will review terms of the expansion to protect consumers? It would be prudent to include a provision in the deal for the state to expand its capacity to serve local needs and for it to be clear that the state regulatory commission would have jurisdiction over this.

Reaction to refinery incentives proposal is mixed

JUNEAU — Alaska Gov. Sean Parnell has proposed tax credits, a form of a state subsidy, to help Alaska refineries hit by adverse market forces and penalties imposed for returning unused oil to the Trans-Alaska Pipeline System. Not all of the state’s refiners are on board with it, however. Tesoro Corp., owner of a refinery at Nikiski, near Kenai, said it is still studying the specifics of Parnell’s idea but has mixed views. “We urge caution in changes to the tax code that might affect the competitive playing field,” Tesoro spokesman Matt Gill said. The reference is to how tax credits proposed by Parnell would help a competitor, PetroStar, at Tesoro’s possible expense. PetroStar operates small refineries near Fairbanks and Valdez and is owned by Arctic Slope Regional Corp. The governor is resisting some proposals from refiners, however, including one that would have the state sell royalty oil at a discount. Alaska Natural Resources Commissioner Joe Balash said such a move would open up a Pandora’s box of problems and could result in the state losing more than $100 million dollars of annual royalty revenue. One proposal Parnell put forth in his March 31 announcement is allowing an in-state refinery a tax credit against state corporate income tax liability for qualified infrastructure expenditures and also a credit based on the volume of refined products produced and sold in retail markets. Parnell’s announcement stated his proposals could be added to pending legislation. The session is scheduled to end April 20 but lawmakers are aiming to adjourn by Good Friday, April 18. Parnell defended the move to help the in-state refineries in a statement issued March 31: “By creating a more favorable tax climate, we have the opportunity to keep an industry strong that provides jobs for Alaskans, adds value to Alaska’s oil, secures our military’s source of fuel, and helps make Alaskan resources accessible to Alaskans.” Balash said the credit linked to volume would kick in at a threshold of 17,500 barrels of product per day, which would be worth about $15 million per year to a refinery.  Also, the refiners’ tax credits would be transferable, Balash said, meaning they can be sold if the company does not have sufficient corporate income tax liability to use the credits. Alternatively, the refiner would be able to cash them in with the state and be paid, Balash said. A similar tax credit and state cash payment system is currently in effect for oil and gas explorers in Alaska, as an incentive. Parnell’s proposed incentives have a five-year sunset clause. A second proposal allows an oil producer on a state lease to sell crude oil to an in-state refinery, and to use the contract price to determine the royalty value owed the state. Tesoro said it supports this part of the proposal, Gill said. Balash said, “an important part of this is that we would relieve the lessee of a provision currently in leases that royalty payments are based on a ‘higher-of’ requirement, meaning that if other producers get higher values for crude oil in the market, the state royalty is paid by all producers based on that price.” The new proposal would set the value on the actual contract sales price with the in-state refiner, he said. It would be an inducement for Alaska producers to sell to refineries in the state. A similar procedure has been in place in Cook Inlet for sales of natural gas by producers to public utilities, in that the royalty value is linked to the contract sales price, Balash said. Jeff Cook, a spokesman for Flint Hills Resources, said the proposals, “will not change plans for Flint Hills Resources (to close its refinery) but they could be a factor in helping us find a buyer for our refinery.”  On Feb. 4, the company announced it would cease all refining operations at its North Pole refinery by June 1, which has thrown the state supply picture into flux on everything from jet fuel to asphalt. Flint Hills supports the initiative overall, however. “The governor’s proposed incentives should have positive impacts in maintaining an in-state refining industry,” Cook said. “I had a good conversation with Commissioner Balash regarding the governor’s refinery incentives and I’m encouraged,” said Rep. Doug Issacson, R-North Pole. “The incentives should improve the possibility of the sale of Flint Hills North Pole refinery, but more importantly at this moment, the incentives, if approved, could keep open the Petro Star and Tesoro refineries.” Parnell has been under pressure from Interior Alaska community leaders and legislators to do something to help Flint Hills. “It’s in the best interest of the state to retain local jobs and increase the economic and social stability of our communities. The incentives have a five-year sunset component that will give us sufficient time to evaluate their effectiveness.” “We must keep our focus on the strength and vibrancy of our businesses and our communities and not bleed either dry by having a complete fixation on getting maximum dollars into the state treasury,” a reference to the state’s policy of maximizing value in the sale of state royalty oil. The company has said its decision to close is linked mainly to economic pressures as well as the ongoing cleanup costs from a chemical leak inherited from the prior owners than is spreading underground from an aquifer and has led to competing claims over who is liable for the expense. Flint Hills and PetroStar have also been hit by penalties for quality differentials for unused portions of crude returned to TAPS. Both companies pay penalties to the Quality Bank, a financial accounting mechanism for TAPS shippers and the state that adjusts for quality differentials of crude oil moving through the pipeline. The two refiners take crude oil from TAPS and use part of the oil to make jet fuel, gasoline and diesel, and returning unused portions of the oil to the pipeline. Because the return oil has the effect of somewhat degrading the oil moving south to Valdez, payments are made to the Quality Banks to compensate other TAPS shippers and the state for differences in quality. Parnell has also so far resisted proposals from the refiners that he push for changes in the formulas that govern the Quality Bank, which is also regulated by the Federal Energy Regulatory Commission. Flint Hills has been under commercial pressure for several years due to the loss of its jet fuel market at Anchorage’s international airport. Air carriers there have moved to import less expensive jet fuel from overseas rather than buying from Flint Hills. Tesoro produces gasoline, jet fuel and ultra-low sulfur diesel at its Kenai Peninsula refinery. The company is supplied by Cook Inlet oil producers, but also purchases North Slope royalty oil from the state, which takes some of its oil royalty in-kind in order to supply in-state refiners. A bill is pending in the Legislature that would extend Tesoro’s royalty oil contract. Flint Hills produces jet fuel, gasoline and heating oil at its plant near Fairbanks. PetroStar produces jet fuel at both its North Pole and Valdez refineries as well as heating oil at North Pole and ultra-low sulfur diesel in Valdez.

Legislature hits homestretch with major bills pending

JUNEAU — The Legislature has entered the home stretch on its 2013 session, with a little over two weeks to go. Major legislation is moving but a lot of important bills are already being left on the sideline. House and Senate leaders hope to finish on April 18, Good Friday, two days before the Legislature’s required adjournment April 20, Easter Sunday. House Bill 266, the state operating budget that has passed the House, was on the Senate floor April 2 as the Senate worked to send its version of the budget to the House. A conference committee will be appointed to work out differences between the two bills. One important change being made in the operating budget is the start of a five-year winddown of state revenue-sharing with municipalities. The first impact of this won’t be felt until next year but by 2020 all state revenue-sharing to local governments, now about $60 million per year, would end. Meanwhile, work continues in the back rooms on a state capital budget, the first version of which is expected to appear soon. The Senate Finance Committee scheduled statewide hearings on the capital budget beginning April 3, but it isn’t clear whether there will be a proposed bill available or people will be asked to make conceptual comments. Sen. Kevin Meyer, R-Anchorage, co-chair of the Senate Finance Committee, said his own priority will be to finish major projects already under construction, such as the partly-built engineering buildings on the University of Alaska campuses in Fairbanks and Anchorage. Projects like the Susitna-Watana hydro project, which are still being planned, are lower on Meyers’ list, he said. Another key bill, Gov. Sean Parnell’s omnibus education bill, was also on the House floor April 2 but the House Finance Committee was working that morning to get its final version out. If that hits a bump, floor action by the House would be delayed until April 3. The bill contains most provisions originally proposed by the governor but also adds new state funding for schools through a larger increase in the base student allocation, or BSA, for fiscal year 2015, the state budget year beginning July 1, than Parnell had proposed. However, the bill also changes the state school-funding formula in ways that the benefits of the increased funding will go to the larger school districts. “We’re still working to understand what is in the new House education bill but it appears that most of the state’s school districts, the smaller ones, will see no increases,” Sen. Berta Gardner, D-Anchorage, said April 2 in a briefing by Senate Democrats. Two provisions originally in the bill, ending the state high school exit test and an increase in funding for rural boarding schools, are out of the bill because they are in separate legislation moving through the House and Senate. The Senate version of the education bill, SB 139, is in the Senate Finance Committee and will likely stay there until the House bill comes over, senate leaders say. Much of what the governor originally asked for in the bill remains intact in SB 139. Both versions are positioned so that passage by April 20 is highly likely, although further bumps in the road are always possible. A highly-controversial House bill adopting a new funding framework for the proposed Knik Arm bridge was up for more work in the Senate Finance Committee April 2. The bill passed the House last year. If the Senate committee moves the bill it is likely to move to the Senate floor soon, although it must still go back to the House for concurrence with the Senate changes. Another controversial bill is dead for this year, however. House Bill 77, the governor’s bill that made changes in state procedures for permits on state lands, appeals of permit decisions and state policy on water-rights reservations, will likely remain in the Senate Resources Committee. The Department of Natural Resources had proposed changes to the bill intended to meet objections raised by critics but the changes apparently did not go far enough. The controversial sections dealt with who has standing to appeal a decision made by the department, and a proposal to limit the authority to file for water reservations in streams to state government agencies or municipalities. Individuals and nonprofit groups like environmental organizations would not be allowed to file for water reservations under the governor’s original proposal. The bill was strongly supported by resource development groups because the water-rights reservations had become a tool for opponents of mines. Another important bill that will wait for another year is HB 340, which would have directed the Regulatory Commission of Alaska to facilitate a single electric utility operator system for the “railbelt” electric grid that is now operated by independent electric utilities, mostly co-ops, from Homer to Fairbanks. The major electric utilities, Chugach Electric Association, Municipal Light and Power, Matanuska Electric Association and Golden Valley Electric Association in Fairbanks, have long favored creation of a single operator group that would coordinate the efficient dispatch of power through the grid. The utilities now work together to dispatch power among themselves but work through informal Memorandums of Understandings, an imperfect system that leads to inefficiencies and higher costs. However, two railbelt utilities, Homer Electric Association and the City of Seward, have not signed onto the idea and without the support of all the utilities HB 340 will remain in the House Energy Committee, Rep. Charisse Millett, the committee co-chair, announced April 2. Millet said she strongly supports the idea of a single system operator but won’t run roughshod over HEA and Seward. She plans to work through the summer on getting a unified position by the utilities and try again in 2015, she said. On the governor’s proposal for state participation in a natural gas pipeline, the House Resources will finish its review of the legislation, Senate Bill 138, this week with the goal of taking amendments on April 4, and working on a proposed committee substitute next week, said its co-chair, Rep. Eric Feige, R-Chickaloon. The bill is expected to emerge from the committee with its basic framework intact but a lot of questions have surfaced over the participation by TransCanada Corp., a pipeline company, as the state’s primary partner. There may be provisions added by the committee dealing with TransCanada.

Buccaneer suspends CEO; Inlet strategy may be under review

Buccaneer Energy, an Australia-based independent company exploring for oil and gas in Cook Inlet, has suspended its CEO Curtis Burton and asked that trading of its shares on the Australian stock exchange be suspended while a restructuring of the company’s finances is accomplished. The events appear connected with a series of problems Buccaneer has encountered with its Cook Inlet program that were complicated when a major investor failed to provide money that had been promised last year. Buccaneer also announced March 14 that the company’s board will not be able to sign a half-year financial statement for the period ending Dec. 31 due to the restructuring now underway. Sources familiar with Buccaneer said the actions are not expected to have an immediate impact on Alaska operations — Buccaneer is now a natural gas producer at its small Kenai Loop field on the Kenai Peninsula — but since Burton is a key architect of the company’s strategic plan to focus on Cook Inlet, his suspension may signal a move by the company’s board to refocus assets elsewhere, such as the U.S. Gulf of Mexico where Buccaneer is also active. “Curtis Burton has been suspended with pay allowing for a (financial) review to be conducted. Mr. Burton has filed a lawsuit in the District Court of Harris County, Texas claiming improper termination of his employment contract,” Buccaneer announced in a March 6 press release. The company has appointed John Young Jr. as its Chief Restructuring Officer effective immediately, according to the press release. Buccaneer asked for suspension of trading of its shares Feb. 19. “The company will make further announcements as soon as it is able, but no later than April 30,” according to the March 14 press release. The shakeup at the top at Buccaneer follows a series of difficulties for the company. One financial hit came when an investor in Buccaneer’s planned Inlet offshore wells and its West Eagle gas exploration well east of Homer, EOS Petro, failed to come through with money. That left the company scrambling for funds to drill the wells. Money was advanced as a loan by Meridian Capital, which is also a part owner of Buccaneer, but the shortfall also led to a decision not to continue drilling late last summer at Southern Cross, an offshore prospect. Meanwhile, the West Eagle exploration well turned up dry, which exacerbated problems. Buccaneer has had its successes in Cook Inlet, though. The company was successful with 2011 natural gas exploration and has developed its small Kenai Loop field that now has two wells producing gas. However, an expansion of the field is stymied by a complex dispute with Cook Inlet Region Inc., which owns adjacent acreage. CIRI says Buccaneer’s existing wells may be draining resources from its land and has asked the Alaska Oil and Gas Conservation Commission, the state regulatory agency that sorts out such conflicts, to intervene. The commission held one hearing on the question Jan. 30 and plans a second hearing April 8. With that issue unresolved, the commission has not given Buccaneer permission to turn on a third gas well at Kenai Loop that was been drilled but it not yet producing. Ironically, Buccaneer had CIRI land under lease but the Anchorage-based Native regional corporation for Southcentral cancelled the lease in a dispute over terms. That issue is now in court.  Another success for Buccaneer, however, was drilling an exploration well at Cosmopolitan, an offshore prospect near Anchor Point, which found gas at shallower intervals that overlie a deeper oil deposit, which had been discovered earlier by ARCO Alaska, a previous owner of the leases. An estimate of new gas resources is still pending, but a second well, to delineate the discovery, is also needed. Buccaneer was the operator of the exploration program but held a 25 percent minority interest in Cosmopolitan with Fort Worth, Texas, independent BlueCrest Energy, which held 75 percent. When Buccaneer’s cash crunch hit in mid-2013, however, the company had to sell its 25 percent share to BlueCrest following the gas discovery along with a 50 percent ownership stake in the jack-up rig Endeavour, which was used in the drilling at Cosmopolitan. Ezion Holdings, a Singapore-based investment firm that held the other 50 percent, purchased Buccaneer’s share of the jack-up rig. The Alaska Industrial Development and Export Authority, which helped Buccaneer and Ezion finance the acquisition of the Eneavour, also holds an interest in the rig. Following the Cosmopolitan drilling, the Endeavour rig was moved into North Cook Inlet in late summer 2013 to begin drilling at the Southern Cross prospect, but then experienced problems setting the rig’s steel legs into the sea bottom due to unexpected soil conditions. An alternative nearby site was surveyed, but faced with funding problems due to failure of the EOS Petro deal, Buccaneer had to terminate the drilling and move the rig to Port Graham, a port in south Cook Inlet, for winter storage. That also meant the company missed a deadline with the state to drill the well, which prompted the state Division of Oil and Gas to terminate the unit late last fall. Buccaneer still has one lease within the former unit but the clock on a 2018 expiration is now ticking. Meanwhile, Buccaneer has a 2014 commitment to ConocoPhillips to drill a well in deep parts of the North Cook Inlet field, where gas is now being produced from shallower intervals. Buccaneer’s “farm-out” agreement is to test deeper parts of North Cook Inlet for oil. The company’s plan was to drill the deep intervals at North Cook Inlet, move the rig back to Cosmopolitan to drill a second well for BlueCrest, and to then return to North Cook Inlet to drill a second deep test. However, to accomplish those things, the Endeavour rig, still in storage at Port Graham, must be mobilized soon. Whether that happens will depend on if Buccaneer has the funding to drill the expensive deep tests at North Cook Inlet, and whether the company’s board decides to stick with the overall Cook Inlet strategy pushed by Burton, the CEO who is now suspended.

Former Gov. Murkowski criticizes TransCanada's LNG role

A former Alaska governor is questioning the wisdom of the state teaming up with pipeline company TransCanada Corp. in a deal with North Slope producers on a large natural gas project. Former Gov. Frank Murkowski said he believes the state is giving away too much to have TransCanada as a partner. Murkowski wrote a letter to state senators March 11. It is the first major criticism of the gas deal, or at least parts of it. Meanwhile, the Senate Finance Committee reviewed projections of how much the state will have to spend to fund its share of construction costs with and without TransCanada, and how this might eat into available general revenues at the time. Sen. Mike Dunleavy, R-Wasilla, said the information is sobering. His concern is how much that would leave for other public needs. One scenario presented to the Senate Finance Committee had the project costs taking up to 60 percent of the available unrestricted general fund revenue without TransCanada as a partner in the pipeline and Slope plant. However, State Revenue Commissioner Angela Rodell said the state would be financing at least part of the “cash calls” during construction with debt, as would the industry partners in the project. The debt would be secured by long-term contracts to sell liquefied natural gas, or LNG, not the state general fund, she said. By the time financing is secured and construction begins, the owners of the project, including the state, would have to have firm contracts in place for LNG sales, she told the Senate Finance Committee. Another possibility is that the state could bring in more partners to share the costs, and risks, she said, although that would also diminish the state’s future earnings. Murkowski isn’t happy with the deal, however. In his letter to state senators, the former governor said he does favor the “Heads of Agreement” reached by the state with North Slope producers but has real questions about a Memorandum of Understanding with TransCanada on a partnership with the pipeline company in the share of the gas project the state could take. Murkowski advanced a similar plan in 2006 that involved, as the current proposal does, the state taking its tax and royalty share in kind, or as gas, and similarly owning a percentage of the project sufficient to ship the state-owned gas. The 2006 plan did not include the state taking on a pipeline company as a partner, however. In his letter, Murkowski urged the Legislature to pass Senate Bill 138, a bill now pending in the Senate, and including in it the Heads of Agreement but not the MOU with TransCanada until more scrutiny is done. “Reports have noted that the MOU is a very complex document. Some of the lawyers who have appeared at the committee hearings of jurisdiction acknowledge that parts (of the MOU) are difficult to comprehend, let alone explain. Any legislator who takes the time to try to digest the document would agree,” the former governor wrote in the letter. The justification for the pipeline company’s involvement, Murkowski said, is that the company would finance the state’s share of the pipeline and gas treatment plant at a time when the state would be facing declining revenues, from 2015 to 2021. “TC (TransCanada) would get the state’s share of the gasline by fronting these costs,” Murkowski wrote in his letter. “Commissioner of Revenue Rodell stated that with TC’s (TransCanada’s) participation, the cost to the state would be $300 million in lost revenue annually once the gas started to flow,” the letter said. The former governor told senators that a more thorough review is needed that would compare costs and rewards to the state of TransCanada holding the state’s share of the pipeline and gas treatment plant compared with the costs and rewards of the state doing those parts of the project without TransCanada. There should be more thorough investigation of options for the state doing a full financing and without having to spend down its savings in the years before gas flows, Murkowski wrote. Before he was governor, Murkowski was one of Alaska’s U.S. senators for 20 years and was also a banker. “What is the alternative? There has been no discussion in the Legislature about going to the investment market to determine whether revenue bonds or other financing is available that would not require the state to pay down its savings and would not require the state to give up its equity interest in the gas line,” Murkowski said. The arrangement is akin to a loan to TransCanada by the state, he said. “The MOU would have the state pay for TransCanada’s services with what would otherwise be the state’s equity interest in the gas line. The tariff (paid by the state for shipping state in-kind gas) is fixed at 12 percent, which is inflation-proofed. This tariff is more than twice what the state could borrow at by issuing revenue bonds or tax-exempt bonds,” Murkowski wrote. The agreement now contemplated, which could be finalized in 2015 if the Legislature passes SB 138 this year, includes three options: One is for the state to allow TransCanada to build and own a percentage of the North Slope gas treatment plant and the pipeline sufficient to transport the state-owned gas, and with the state owning the share of the large LNG plant at Nikiski through the state-owned Alaska Gasline Development Corp. The deal would also give the state the right to buy 40 percent of TransCanada’s share of the pipeline and gas treatment plant at the time Front-End Engineering and Design work is started, which could be in 2016. The cash drawdown scenarios presented to the Senate Finance Committee March 9 were sobering for senators. An example illustrated for 2021, one of the peak years of construction, assumes a 25 percent stake in the project for the state. The required contribution would be $3.3 billion that year, although, as Rodell explained, part of this could be debt-financed. If the state were to do the partnership with TransCanada and not exercise the option to buy 40 percent, so that the state owns only 25 percent of the Slope LNG plant, the required contribution drops to $1.68 billion for 2021. If the 40 percent option were exercised, the requirement would be $2.18 billion. If the state takes a lower share of the project, such as 20 percent, the required contributions drop, to $2.6 billion in 2021 assuming the state does it on its own without TransCanada; and drops to $1.3 billion if the state lets TransCanada take 100 percent of the pipeline and gas treatment plant, but is $1.8 billion if the state takes the 40 percent option of TransCanada’s share or the pipeline and the gas treatment plant. Although the 20 percent partnership scenario requires less investment, and less risk, it also reduces the state’s future income by the same ratios, state Deputy Revenue Commissioner Mike Pawlowski pointed out. Rodell said debt can cover part of these requirements but the state would still have to put in cash, and how much depends on which option is chosen and how the financial community will rate the bonds, which will be influenced by the state’s overall financial condition at the time. The cash equity requirement could range from 25 percent to 75 percent of the investment depending how the bonds are rated — AAA to Triple B — with most options in the 40 percent to 50 percent range of the state’s share. Dunleavy said projections he has seen from Legislative Finance Division would have the state’s cash reserves drained by 2024, given the current trend in budget deficits and the upward spending pressures from schools, unfunded pensions and Medicaid costs. Rodell agreed with the concern. “Therein lies the challenge in this, the required modifications to the operating budget,” the commissioner said. However, the problem can be managed, she said. The scenarios presented are just examples, and when the time comes the debt can actually be structured in ways to minimize hardships. “We won’t issue debt unless we can sell gas, and we will schedule the debt to be available three to four years ahead of first gas. We would have sales contracts with buyers,” Rodell said. If there weren’t firm sales contracts, no one would buy the bonds, she said.

TAPS owners take series of setbacks in court

Things have not gone well for Trans-Alaska Pipeline System owners in the courts and key federal regulatory arenas in recent weeks, but the battles aren’t over. First, on the state level, Alaska’s Supreme Court upheld a $9.98 billion valuation of the pipeline for property tax purposes on Feb. 21, more than ten times the $800 million figure the pipeline owners originally sought. Second, in Washington, D.C., an administrative law judge with the U.S. Federal Energy Regulatory Commission, or FERC, issued a ruling Feb. 28 disallowing several hundred millions of dollars of investments in TAPS pump station upgrades, although the ruling will be contested and the full commission has yet to issue a decision. The TAPS owners, which include BP, ConocoPhillips, ExxonMobil and minority owners Koch Industries and Unocal (now Chevron), had filed tariffs that included the expenses for 2009 and 2010. The State of Alaska and Tesoro, who ships oil through TAPS but is not an owner, contested the tariffs. The TAPS owners had asked for $454.4 million in capital costs to be included in the tariff rate base for the two years, but FERC Administrative Law Judge Carmen Ana Cintron ordered that $397.1 million should be excluded, and approved only $57.3 million of what was requested. Cintron agreed with the state and Tesoro that the pipeline pump station upgrade project had not been managed well, and the owners had failed to prove the expenses were prudent. On the property tax case, the state high court’s ruling, on which the pipeline owners have filed a request for reconsideration, dealt only with fiscal year 2006 property taxes. However, it will set precedents that will affect the disputes over TAPS values that will be for the percolating through the courts for the following years. In the dispute over 2006, the state Department of Revenue, which under state law sets the value for oil and gas properties for taxation, concluded TAPS was worth $3.64 billion. Municipalities that were affected appealed the decision to the revenue department’s State Assessment Review Board, which reviews assessment disputes. The review board agreed with some of the municipalities’ arguments, and upped the value to $4.3 billion. Municipalities with pipeline property within their boundaries include the City of Valdez, Fairbanks North Star Borough and the North Slope Borough. Not satisfied with the board review, the municipalities appealed the assessment decision to state Superior Court. The municipalities were concerned that while replacement cost of TAPS was used as the basis for valuing the pipeline, a cost study provided to the state by TAPS owners of what the pipeline would cost, if rebuilt today, was obsolete. The municipalities had their own cost study done and Judge Sharon Gleason, then a state judge in charge of the case, agreed with it. She set the value at $9.98 billion, which has now been upheld by the Supreme Court. Gleason agreed with the municipalities that the value should be based on what it would cost to replace the pipeline with an allowance for depreciation to arrive at a $9.98 billion value. As the disputes roll along, the next phase is the Supreme Court taking briefs in April from the disputing parties on tax years 2007, 2008 and 2009, although the court’s decision on 2006 has sent a signal of how the judges are likely to rule. “We believe the court’s decision narrows many of the issues involved in the appeals of the superior court’s decision,” for the next three years, said Ken Diemer, a state attorney involved in the case. Prior to being elevated to the federal court system Gleason ruled that the TAPS value for 2007 is $8.94 billion; for 2008, $9.64 billion, and for 2009, $9.23 billion. The TAPS owners have appealed those decisions to the Supreme Court, however, and a decision will be made at some point for those years. Meanwhile, tax years 2010, 2011 and 2013 are now before the Superior Court, with the parties actually reaching agreement on 2012. Jim Greeley, the state oil and gas property assessor, has set a $5.5 billion value for the pipeline for tax year 2014. Municipalities have already said they will appeal that to the state review board. In what has become a sideshow, Gov. Sean Parnell recently fired one member of the board, Marty McGee, and appointed two retired oil and gas company managers to fill two of five seats on the board. One of Parnell’s appointments, Dennis Mandell, is under fire, however, for being a resident of California. Critics say state law required members of the board to be Alaska residents. Senate Democratic Minority Leader Hollis French, D-Anchorage, has asked Partnell to withdraw Mandell’s appointment, but Parnell has refused. Manell worked for ARCO Alaska when he lived in Anchorage. Another Parnell appointment to the board, Bernard Washington of Anchorage, is a former ConocoPhillips employee. French said Parnell fired McGee from the board because he was an advocate for higher valuations, which helped the municipalities. How TAPS is valued is very important to the three municipalities that are affected. Under state law the municipalities must use the state’s valuation for pipeline and other oil and gas production and transportation property. An approximate doubling of the pipeline value for 2006 from the state assessment review board’s determination means the municipalities will collect twice as much tax. It has a downside for state revenues, however, because the property tax payments are included in the tariffs, or transportation charges that the TAPS owners are allowed to charge for shipping oil. The pipeline tariff is one of several expenses allowed as deductions against the value of North Slope oil for state tax and royalty purposes. State taxes and royalties constitute about one fourth of the production value of North Slope oil, so indirectly the state pays a quarter of the higher taxes paid to the three municipalities. The effect of the change is value is not insignificant. As a rule of thumb, every billion-dollar increase in the pipeline valuation for tax increases the pipeline tariff by 10 cents a barrel, according to sources familiar with how the tariffs are calculated. Based on that, the $4 billion increase agreed to by Judge Gleason has effectively raised the tariff by 40 cents per barrel. TAPS tariffs were averaging $6.28 per barrel for the third quarter of 2013, according to the Department of Revenue, so an additional 40 cents per barrel is significant.

Balash plays point in pursuit of LNG project

Joe Balash says he’s often teased about being a 38-year-old point man for the state on a prospective multibillion-dollar deal for Alaska to partner with industry on one of the world’s largest gas projects. Balash makes light of it: “I’m young enough that I know I’ll be around to see the results of what I do.” That answer, however, has a serious aspect, because it reflects a sense of deep responsibility that what he does is the right thing. Balash isn’t the youngest of Gov. Sean Parnell’s commissioners — Department of Fish and Game Commissioner Cora Campbell was 31 when she was appointed in 2010 — but given the financial stakes the youthfulness of some on the state’s top gas team is striking. Deputy Revenue Commissioner Mike Pawlowski at age 36 is younger than Balash, who is the youngest DNR commissioner in Alaska history. This team epitomizes the new generation of talented public officials taking the helm in state government, although some legislators worry the youngsters will be taken advantage of by more seasoned, and gray-haired, executives in the major oil and gas companies. Balash does bring something else that’s unique, however. He is the ultimate state “insider,” having has worked in government since 1998 in the Legislature or in top policy positions in the state administration. Despite his youth, he brings institutional knowledge, historical context, and the ability to lend continuity. Balash has seen 17 legislative sessions and intimately knows the corridors of power in Juneau. Balash grew up in an Air Force family at Eielson Air Force Base near Fairbanks. He and his wife, Brenda, came to Juneau as newlyweds in 1998. Balash was a college intern manning the front desk in former state Sen. Gene Therriault’s office. Brenda Balash got a job in the office of Parnell, who was then a state senator. After graduating with a political science degree from Pacific University in Oregon, Balash returned to work for Therriault in Juneau and began a fast-track rise in government, going to the governor’s office and then to the Department of Natural Resources as deputy commissioner and now Commissioner. That career track brings a lot of value in state government, because turnover is frequent in the state capitol and institutional and historical memory are scarce. Lessons learned The current gas proposal offers a case in point: Having been involved in the Legislature’s review of Gov. Frank Murkowski’s Stranded Gas Act gas pipeline proposal in 2006 and Gov. Sarah Palin’s Alaska Gasline Inducement Act, or AGIA, plan with TransCanada Corp. in 2010, Balash has a sense of why those plans didn’t work and how to make the new proposal work. For example, while there are similarities between Murkowski’s 2006 plan and the current one — the state taking an equity interest, for example — there are important differences that are a result of lessons learned from 2006. The most important of those, Balash said, is the staged, step-by-step approach of this plan, which allows the Legislature, and the public, to take it in bite-sized chunks, a series of approvals up to a hoped-for final decision between the state and the industry partners in 2019. The 2006 plan was fairly well developed when it was presented to the Legislature and public, and the detail and complexity of it was overwhelming. While the AGIA proposal that followed under Palin was unsuccessful, it did help set the stage for the current proposal, Balash believes. He also turns aside criticism of AGIA, in which Balash was involved. “People quibble about AGIA, but having the state articulate what we want for the first time gave the producers something to work with. Having a counterparty know what it wants is essential to making a deal,” he said. Two of the AGIA goals were provisions to protect state revenues, through an agreed-on debt-equity ratio in financing, and mechanisms to facilitate expansions of the pipeline to encourage new companies to explore and find gas so that the North Slope, and the pipeline, would not be seen as a monopoly of three large companies. Those concepts are preserved in the state’s proposed new contract with TransCanada. AGIA also brought TransCanada officially to Alaska, as the licensee, and deepened the pipeline company’s commitment to a gas project. TransCanada would now be the state’s key partner in the new plan, which is the other main difference from 2006. Having a strong, experienced pipeline company partner is important because it is doubtful the state has the financial strength to take on a major equity stake on its own. Balash believes AGIA also set the stage for the breakthrough in the state’s relationship with the North Slope producers. That came in 2009 when ExxonMobil Corp. decided to join TransCanada as a partner in its project developed under AGIA. This was a watershed event. “It started the companies talking among themselves, and with the state,” Balash said. This led directly to a settlement of the contentious Point Thomson lawsuits, which had tied up the Point Thomson gas field, a fourth of the North Slope’s resource. Resolving the complex dispute over past work obligations was necessary for any gas project to move forward, Balash said. Balash was involved in the later parts of the settlement and he gives credit to former Natural Resources Commissioner Dan Sullivan, who Balash succeeded, for the heavy lifting. Under Sullivan’s leadership, the basic terms of the settlement had been agreed to by late 2010, although it was not signed off on by other lease owners at Point Thomson until a year later. Sullivan resigned as DNR commissioner to run for the Republican nomination for U.S. Senate. Under the settlement, companies agreed to begin development of Point Thomson in a first phase of a large gas project, which is now under construction. The settlement also led, however, to Chevron selling its leases at Point Thomson to ExxonMobil. That gave ExxonMobil the majority of North Slope gas ownership, and made it the leader today in the drive to develop a large project. Balash gives credit to others in negotiation of the current gas proposal. Angela Rodell, the state’s revenue commissioner, has played a key role, he said. “Her ability to quickly grasp the issues and her background in finance were really important as we wrestled with the equity investment issues. We could not have moved along as quickly without her,” he said. Not just the gas man Meanwhile, there are other things than the gas project on Balash’s plate. “I don’t want to be known as just the Commissioner of Natural Gas,” he said. “DNR is the premier state agency. It’s what makes our state go, and allows us to do what we want to do. This is where I want to be.” Balash sees his role as an asset manager rather than just a resource manager.  With the assistance of 1,100 employees and professionals in the DNR, he is responsible for 160 million acres of state land, which include the largest state parks in the nation, state forests and minerals and agricultural lands. Agriculture has historically been a stepchild in the Department of Natural Resources, Balash believes, and has suffered from a lack of attention within the commissioner’s office. He intends to change that. The state’s agricultural potential came home to him, he said, as the DNR was completing the regional area plans for state lands in the Yukon and Tanana regions of the Interior. Balash learned that the state lands west of Nenana, southwest of Fairbanks, are prime for agriculture in terms of soil thickness and quality. The area is no longer cut off from infrastructure. The city of Nenana is now engaged in a planned bridge across the Nenana River, providing access, and Doyon Ltd., the Interior Alaska regional Native corporation, has built an eight-mile gravel road west from the river crossing to a site for an oil and gas exploration well. Balash also believes the Division of Geological and Geophysical Surveys, or DGGS, a part of the DNR, can among other things expand its airborne minerals mapping program as a catalyst for minerals exploration. “Whenever the DGGS releases its airborne maps there is an uptick in exploration and mining discoveries follow,” he said. State parks and forests have untapped potential but both need attention. There is a $50 million backlog of deferred maintenance in the state’s park system, but the new South Denali visitor center taking shape in Denali State Park, south of Denali National Park, offers a template for new possibilities. DNR is working with the state’s major tour operators to develop South Denali as an alternative visitor experience to the congested “glitter gulch” strip of hotels and development adjacent to the national park, and Balash believes a revenue stream stemming from new vendors could help sustain other state parks. There are similar possibilities in other big state parks, like Chugach State Park near Anchorage and Wood-Tikchik in the Bristol Bay area.

Senators air concerns, potential as gas bill moves

With the 2013 legislative session about half over, the Senate Finance Committee continues to plow through Gov. Sean Parnell’s proposal for the state to partner in a large North Slope gas project. Expectations were for the committee to finish its work and consider amendments by March 7, but that wasn’t certain as of press time March 5. The Senate Resources Committee voted out Senate Bill 138, which gives the state administration authority to pursue the deal, on March 3, sending it to the Finance Committee. The House Resources Committee is meanwhile still conducting its own review of the House version of the bill, HB 277, but is mainly waiting on the Senate to send its bill over before taking action. So far no major obstacles have emerged for the bill, but members of the Finance Committee are still focused on several key issues. One is whether the project will make natural gas more available to Alaskans, and at an affordable price. Senate Finance co-chair Sen. Kevin Meyer, R-Anchorage, said his constituents are asking him whether the state’s involvement will make gas available at lower prices. “Do we get a discounted rate?” he asked during a meeting of the Finance Committee. State Natural Resources Commissioner Joe Balash, who was appearing before the committee, replied that state (royalty) gas could be sold at lower prices, “but there would be a cost,” in lost revenues to the treasury, he said. Another concern, said Sen. Anna Fairclough, R-Eagle River, is to ensure that the project will have good terms for expansion, which could greatly benefit the state if it is a part owner. “Future expansions of the project could be very profitable for the state, and we also have to remember than for every dollar we invest the industry partners invest $4 or $5,” depending on how much of a stake the state wants, she said. Fairclough, who is on the Finance committee and the Resources committee that reviewed the bill earlier, spoke along with other Senate leaders in a March 4 briefing. One another issue, Fairclough said, is “there is also a nagging question of why we need the state’s Alaska Gasline Development Corp., or AGDC, to stand up a subsidiary to own the equity share in the project.” The concern is about duplication of functions and whether the state corporation itself, which is also charged with planning a smaller state-led pipeline as a backup plan, would be more efficiently engaged in the larger project without having to form and work through a subsidiary. Fairbanks Republican Sen. Click Bishop, who is also on the Finance and the Resources committees, said his nagging question is simply a fear of the unknown. “This is a $45 billion to $65 billion project, and most of the experience I’ve heard on mega-projects is that they tend to run over budget. I want to make sure we’re not looking at this through rose-colored glasses. I want to make sure the state will be able to meet the cash calls,” as a partner, Bishop said. Despite the reservations, Bishop said he supports passing the bill so the state and its proposed industry partners can get on with the “pre-FEED” (Preliminary Front-End Engineering Design) work, from which a more definitive cost estimate can be derived. Bishop also said a big value of the deal, which is not yet widely recognized, is the possibility of “value-added” manufacturing, which having affordable gas available will make possible. “We have to look at what we get beyond just exporting the gas,” he said. Senate President Charlie Huggins, R-Wasilla, said that what gives him comfort now is that this is a staged, step-by-step processs of approvals over several years. “We don’t have to be bold at this stage but we have to show a little courage,” in getting the ball rolling, he said.  “What is exciting to me is that ExxonMobil is excited about this, and is being followed by the other two gas producers,” BP and ConocoPhillips. ExxonMobil is the largest single owner of gas reserves on the slope, followed by the State of Alaska. Fairclough was asked what the state gets out of the partnership deal that it couldn’t get with the status quo, if the state simply took its revenues in cash payments from the gas royalty and production tax. “It’s really about sustainability and durability of the tax structure,” she said. “The producers have always said that if a gas pipeline is going to happen there has to be durability,” of the tax terms. “Our equity stake does that. There’s great value in equity, and we’ll be on the inside,” with access to information, she said. “The producers need a partner to go with them to the (LNG) market, which is opaque (in terms of sales prices) and not transparent like Henry Hub,” where Lower 48 gas sales transactions and prices are widely posted. “With LNG there’s real benefit to us being on the inside,” with access to market information. With the royalty and tax taken “in value,” or cash, there wouldn’t be easy access to markets information and disputes would likely result, which the producers want to avoid. There are still legislators with concerns about the deal, however. In the state House, Rep. Chris Tuck, the Democratic minority leader, said he is concerned whether the state will have the staff and expertise to negotiate very complex contracts on the gas deal. “A decision like this could also complicate our responsibility to be a regulator. This would merge our roles, creating conflicts,” he said. “Also, why we being asked to help bankroll a project that could, in reality, bankroll itself, without us? There are just a lot of questions about this.”

State DEC wants Flint Hills to stop spill, file cleanup plan

A chemical spill at the Flint Hills refinery near Fairbanks has become a major headache for the company owned by Koch Industries. A spill of sulfolane, a solvent mostly used in making gasoline, is still spreading off the refinery site through an underground aquifer, state Department of Environmental Conservation officials say. The spill plume, first detected in 2001 under the refinery, now covers an estimated area of three miles by two-and-a-half miles and a half-mile underground. So far the contamination has affected 312 property owners near the refinery, DEC officials said in a Feb. 20 presentation to legislators in Juneau. Although the extent of a human health hazard is still unclear, Flint Hills has been delivering bottled water to the affected homeowners. Another 250 homes in the area have not been affected, but Flint Hill is also supplying bottled water to these homeowners. The delivery is costing the company about $2 million per year, said DEC Director of Spill Response Kristin Ryan. Flint Hills spokesman Jeff Cook said the water deliveries will continue until a long-term solution is found to ensure safe drinking water. “From day one our priority has been to protect people and worry about the liability later,” he said. Flint Hills has spent about $70 million so far on the problem, Cook said. Of that amount, $40 million was paid from a bond posted by the previous owner, Williams Cos., after Flint Hills bought the refinery in 2004. The bond was to pay for cleanup of contamination at the site. The sulfolane spill was known at the time but it was believed to be restricted to the refinery property. It soon became evident that the spill was seeping off the property, however. Despite the bond that was posted, Flint Hills feels Williams, and even the state, which owned the land before it was sold to Williams (who had leased it) share some of the liability. Williams disagrees with this. In a statement, Williams spokesman Tom Droege said, “We have worked and continue to work with the Alaska Department of Environmental Conservation, Flint Hills and other stakeholders on an appropriate path forward for the ADEC-directed cleanup and remediation of the North Pole site that Flint Hills owns and operates. “To be clear, Williams’ insurance carrier already has paid $40 million to Flint Hills Resources for overall remediation and cleanup of the site. “When Flint Hills purchased the property from Williams, the issues of contamination and ongoing responsibilities for remediation were clearly delineated in the agreement that both parties executed. With the $40 million in payments to Flint Hills, Williams already has exceeded the amount of the contingent obligation that the two parties agreed to at the time of the sale.” Flint Hills disputes this, arguing that Williams has responsibility for the contamination that had spread off the site prior to the sale, and went to court against Williams in 2010. However, Superior Court Judge Michael McConahy ruled in November 2013 that Flint Hills had waited too long to sue Williams and that the case exceeded a three-year statute of limitations that applies to contract disputes. That aside, in his decision McConahy agreed that the chemical that had migrated off the site prior to the 2004 sale was caused by Williams. The state is now stepping into this. State Attorney General Michael Geraghty said he will soon file a lawsuit against both companies to sort out the liability issues. It is clear, however, that at least Flint Hills is on the hook as the current owner of the property and operator of the refinery, DEC Commissioner Larry Hartig said. Also, Gov. Sean Parnell has asked Geraghty and Hartig to meet with parties involved to seek a settlement of the liability issues. In a March 3 letter to Flint Hills President Brad Razook, Parnell wrote, “Although it might be challenging to get all parties to agree to a quick and fair allocation of responsibility, I have directed the Attorney General and my commissioners to make every practical effort to reach an agreement that will protect the jobs of workers at the refinery, protect the property owners from environmental and related harm, and fairly allocate responsibility among the potential responsible parties.” The governor was responding to a proposal Flint Hills made informally to state legislators that the state indemnify the company from liability for the spill. As the responsible party, the state has asked Flint Hills for a plan to clean up the spill but a new point of contention is how much of the contamination has to be removed from soil before it is considered clean. Flint Hills, the U.S. Environmental Protection Agency and the state have different views on this. An administrative appeal on this point from Flint Hills is on Hartig’s desk now. He will not comment on  it as the decision-maker on the appeal, and he said it may take weeks or even months to get through the administrative process. There could be litigation after that, too. Cleanup conundrum Meanwhile, Ryan, director of DEC’s spill response division, said it’s uncertain whether the sulfolane can be economically or even technically cleaned up. Some of the chemical has been detected as deep as 300 feet. Sulfolane is not biodegradable underground, where it has no contact with oxygen, and it adheres chemically to water, Ryan said. That means that it is moving with the flow of water in the aquifer, seeping off the refinery site and spreading, she said. “There’s a lot of arguing (about liability) but the point is the sulfolane is still leaving the refinery. Flint Hills has not stopped it, so it’s their responsibility,” Ryan said. “The contamination was known when the refinery was sold. It was disclosed and known that it needed to be dealt with. There are arguments about who owns what molecules, what left (the property) when and where, and the parties disagree over liability, but Flint Hills has still not stopped it.” Much of the spill seems to have resulted from the sulfolane being stored in an unlined pit on the property, as well as many small spills of gasoline that contained the sulfolane over the years. Ryan said that in earlier years sulfolane was not a regulated chemical, although it now is. Even now it is not considered hazardous, she said, although the effects on humans are still unclear. In its Feb. 20 presentation to legislators DEC said that high doses of sulfolane can have acute effects on the central nervous system, causing hyperactivity and convulsions, and that chronic exposure of greater than seven years for a human may affect the liver, kidney and spleen. DEC said the chemical does not appear to be a carcinogen, however. As to cleanup, Ryan said, “the first step is for the responsible party, in this case Flint Hills, to complete a feasibility study of what options there might be.  This solvent seems to break down in the presence of oxygen (when underground it is not exposed) so exposing it,” to the air might be a possibility. “It would be expensive to get it out of the aquifer, however. It is deep in several places,” she said. If it is determined that a cleanup is not economically or technically feasible the contamination might have to be left. “This happens,” at old industrial sites, Ryan said. The important thing is to ensure that humans are not affected, and in this case the only solution to protect people is to build water lines to the area from the nearby City of North Pole water system, she said. There are as yet no cost estimates for that. However, Flint Hills has not yet provided the agency with a justification that it is unfeasible to treat the soil. “They say they can’t work on a feasibility study until the question of an acceptable level of contamination is settled,” Ryan said. “At DEC we have adopted a standard of a sulfolane content of 14 parts-per-billion (ppb) in the water. The EPA has a different standard, 16 ppb, but we decided to go lower as an extra margin of safety,” Ryan said. Flint Hills wants to use 362 ppb, however. The issues raised by the contamination go beyond providing safe drinking water, although that is most important, Ryan said. Presence of the sulfolane in the soil could degrade property values in the area, and DEC is also concerned about the watering of gardens in summer if well water is used because that might provide another way for humans to be exposed to the sulfolane Many of the facts of the case were laid out in Judge McConahy’s court ruling last November. Williams discovered the sulfolane under the refinery in 2001. At time of sale in 2004, Flint Hills agreed to take responsibility for the sulfolane that was “existing, known and disclosed at that time,” McConahy wrote in his decision. “As everyone is aware now, the sulfolane released prior to Flint Hills’ assumption of ownership of the refinery had migrated far beyond the contours of the sulfolane identified in the disclosure to the ASPA and the plume had already extended off the refinery property.” The argument made was that sulfolane that migrated off the premises prior to April 1, 2004, is attributable to Williams. However, there are no indications that Williams and Flint Hills were aware of that when they finalized the sale in 2004, the court decision said. The chemical has been used at the North Pole refinery since 1985 and is still being used today,” McConahy wrote. In his decision McConahy also chastised Flint Hills for its delays in drilling test wells to determine the extent of the spread from 2006 and 2008. Consultants to the company had recommended that additional test wells be drilled to identify the source of the new contamination, but the company delayed drilling the wells until 2008, McConahy wrote in his decision. Tim Bradner can be reached at [email protected]

Villagers seeking order to shut down CD-5 construction

Six Inupiat villagers from Nuiqsut are in federal court seeking an injunction to shut down construction of ConocoPhillips’ CD-5 oil project on the North Slope. Alaska U.S. District Judge Sharon Gleason accepted briefs Feb. 28 on a request for a Temporary Restraining Order in a lawsuit that was filed in early 2013 challenging a U.S. Army Corps of Engineers permit for the project. The suit claims the permit issued by the Corps was flawed, but no request for a restraining order was made at the time. ConocoPhillips started construction early this winter. The villagers, represented by Trustees for Alaska, an environmental law firm, argue that the placement of gravel on wetlands in the sensitive environment is an immediate threat to their subsistence activities. They said they were unaware of the exact location of the project activities until recently, according to the brief filed by Trustees for Alaska. The case is being watched closely by environmental groups. The Center for Biological Diversity has filed a similar suit against the Corps over the bridge permit, but did now join the request for a restraining order. CD-5 is an undeveloped oil deposit about eight miles west of the producing Alpine field. It is within the National Petroleum Reserve-Alaska, and the mineral rights are owned by Arctic Slope Regional Corp., the regional Native development corporation. ConocoPhillips and its minority partner Anadarko Petroleum Corp. plan to develop CD-5 with production expected to begin in late 2015. Peak production is estimated at 16,000 barrels per day, or b/d. Capital costs are estimated at about $1 billion, ConocoPhillips has said previously. In their lawsuit, the six villagers argue that the Army Corps failed to do an updated environmental impact statement, or EIS, to support the permits issued for the bridge and related roads and pads. The permits were issued in December 2011. The Corps was relying on an EIS done in 2004 for the Alpine field by the U.S. Bureau of Land Management, but the villagers argue that was outdated, and that the Corps should have done an updated supplemental EIS. The plaintiffs also contend the Corps failed to justify its decision to favor a bridge over a channel of the Colville River over an earlier plan favored by the agency itself for a underground pipeline crossing at the river and winter-only access to the CD-5 pad via ice road. There are other satellite pads in the Alpine field that are now served only by pipeline and winter ice roads. The Corps’ original permit, requiring the underground river crossing, was appealed and after a lengthy review process the agency reversed itself and approved the bridge crossing. The concerns raised by the Center for Biological Diversity in its suit is that the bridge and all-year gravel roads would set the stage for extensions of the roads further west to other NPR-A oil prospects, cutting through sensitive wetland habitat. If Gleason issues a restraining order, ConocoPhillips will have to demobilize construction contractors. The project would likely be set back for an extended period to allow a trial on the lawsuit or for the Corps to prepare a supplemental EIS for the bridge and gravel fill projects. A delay in CD-5 would have a broad ripple effect because it would also set back ConocoPhillips’ schedule to develop GMT-1, a drill site eight miles further west in the NPR-A, which will depend on the CD-5 bridge and gravel roads for access to move equipment to the site. GMT-1 is expected to be in production in 2017 if it stays on schedule, with peak production estimated at 30,000 b/d. In a rebuttal brief filed to the request for the injunction, ConocoPhillips argued that a draft EIS prepared for the GMT-1 project by the U.S. Bureau of Land Management covers issues that would be reviewed by the Corps if it were to do a new EIS for the CD-5 project. Brian Litmans, lead attorney for Trustees for Alaska, disagreed with that. For one thing, the GMT-1 EIS is still in draft form, and is not final. “Relying on the analysis in the GMT-1 draft to bolster the Corps’ lack of analysis on CD-5 is equivalent to providing an after-the-fact rationale for an agency decision by a different agency,” Litmans said in a statement. “Another agency’s draft analysis of a different project (GMT-1) several years after the Corps’ decision does not excuse the Corps’ failure to conduct its own environmental analysis for CD-5.” Although the lawsuit was filed in early 2013 the villager/plaintiffs said decided to pursue the Temporary Restraining Order when they learned the precise location of the bridge and that construction had started, he said. In its brief, ConocoPhillips replied that the plaintiff villagers had failed to participate in a lengthy public review of the Corps permits that did involve other villagers in Nuiqsut, that the claims of irrepairable harm are not justified, and that the plaintiffs waited untll the last minute to request the TRO. “ConocoPhillips is well into performing long-anticipated, broadly publicized, costly and logistically complex construction activities at a very remote Arctic location,” the company said in its brief. “The plaintiffs sat on their rights until the moment it would inflict the maximum possible damage and disruption,” after construction had started. The work underway now includes the placement of bridge pilings and the laying of gravel for roads and pads, ConocoPhillips said in its brief. “To date, materials have been fabricated and staged, and equipment and manpower have been contracted for and mobilized,” the brief said. “Approximately half of the requiring bridge pilings for three bridges have been installed. Gravel road and pad installation have begun with the work expected to be complete by mid-April.” The case has pitted Inupiat people in the region against each other. Kuukpik Corp., the Nuiqsut Alaska Native village corporation, has come down on the side of ConocoPhillips and the Corps. Although it is within the NPR-A, the land on which CD-5 is located is owned by the Kuukpik Corp. Arctic Slope Regional Corp., the regional Native corporation that owns the mineral rights at CD-5 and would receive royalties from development, has also intervened on the side of the Corps and ConocoPhillips along with the North Slope Borough, the regional municipal government.

State Democrats unveil another oil tax plan

Minority Democrats in the Legislature unveiled their vision of an oil tax system should voters this summer roll back the tax structure lawmakers approved last year. It includes the idea of the state getting directly into the oil business by allowing the Alaska Industrial Development and Export Authority, the state development finance corporation, to finance oilfield development with small independent companies and own an equity share in the field, not just a tax and royalty interest.  “There are (state) entities around the world that own a share of their oil industry (through state oil companies) and I have confidence that we have the ability to do this,” said Sen. Bill Wielechowski, D-Anchorage. The state is already proposing to own a share of a proposed large gas project through the state-owned Alaska Gasline Development Corp., Wielechowski said, and AIDEA itself has invested in oil drilling rigs. “I like the idea of AIDEA providing venture capital to oil and gas projects. There are independent companies coming to Alaska who lack capital,” Wielechowski said. “The governor’s giveaway is a pathway to poverty,” said Rep. Les Gara, D-Anchorage, said in the press conference “He throws two billion dollars out of an airplane and hopes it lands in the piggy bank. Our bill makes sure Alaska’s oil money goes into Alaska’s piggy bank, and that for every dollar we give back to the industry, we get more oil production in return.” Gara did not explain in the Feb. 24 press conference, however, how the Democrats’ bill ensures that tax reductions are reinvested in the state, or how the proposal was better than a targeted per-barrel tax credit for new oil allowed in SB 21, the tax change that was passed by the Legislature last year. The per-barrel credit in SB 21 replaced a general capital investment tax credit that was not targeted to new production. In the press conference, French acknowledged that, “targeted tax credits work better.” The Democrats’ proposal is similar to a plan they put forth last year as an alternative to the plan pushed by Gov. Sean Parnell that ultimately passed. Democrats say their plan also is aimed at ensuring Alaska gets its “fair share” for its oil. Senate Minority Leader Hollis French, D-Anchorage, called the Democrats’ plan a fair alternative. “Or, as we say, there’s a better way than the giveaway,” he said. Had SB 21, the tax-change bill passed by the Legislature in 2013, been in effect from 2007 through 2013 instead of the former tax system, Alaska’s Clear and Equitable Share, or ACES, the state treasury would be poorer by $8.5 billion, French said. The Democrats’ proposal would, among other things, provide time-limited tax breaks for oil from newer fields and new developments in legacy, or older, fields. It would provide tax breaks for future production of heavy oil and for future production in legacy fields greater than 2012 levels. It also would require minimum work commitments as part of lease terms and allow AIDEA to issue loans to build or improve North Slope oil processing facilities and other infrastructure. There is another bill pending in the Legislature, House Bill 230 by Rep. Paul Seaton, R-Homer, that would enable AIDEA to invest in oil processing facilities. Sen. Bert Stedman, R-Sitka, has also proposed legislation, in SB 192, that would reduce some of the tax benefits allowed to companies under the new tax law enacted by SB 21. French said he supports Stedman’s bill. The Democrat’s bill goes further than Stedman in proposing changes, however. Voters in August will decide whether to keep or repeal the oil tax structure passed by lawmakers in 2013. If the referendum is successful, the system will revert to what was in place before the change, ACES, French said. The Democrats’ proposal builds off ACES. That system featured a 25 percent base tax rate and a progressive surcharge triggered when a company’s production tax value hit $30 a barrel, which industry representatives said ate too deeply into profits, discouraging new investment. The surcharge also was credited with helping fatten the state’s coffers when prices climbed in recent years. The Democrats’ proposal — Senate Bill 202 and House Bill 338, in their respective chambers — would reinstate a progressivity formula that was in the ACES tax but reduce it at higher oil prices and cap it at about $192.50 a barrel under current estimates, according to a fact sheet. “We do bend the curve on progressivity at the high price levels,” French said. The law passed last year took an entirely different approach to oil taxes. It has a 35 percent base tax rate compared with 25 percent under ACES and per-barrel tax credits for what would be considered new oil and production. For legacy fields, there is a sliding-scale per-barrel credit that is higher at lower prices and decreases to zero at higher prices. Willis Lyford is a spokesman for the Vote No on 1 campaign, which opposes the referendum. He said in a statement that the Democrats’ measure should not be viewed as a serious policy proposal because they are advocating something different than the old system that they have urged voters to support. The Associated Press contributed to this report.

State will file lawsuit to sort out Flint Hills spill liabilities

The State of Alaska will file suit against Flint Hills Resources and Williams Cos., in an effort to sort out liability issues connected with a large underground spill of sulfolane, a chemical used in refining, at the refinery at North Pole, near Fairbanks, Alaska Attorney General Michael Geraghty said in a statement. “Flint Hills Resources was litigating its claims against Williams to allocate responsibility for the contamination but the trial court has ruled that the case is time-barred,” or beyond its statute of limitations, Geraghty said in the statement. “The state has been in the process of preparing a complaint to determine ultimate responsibility amongst the potentially responsible parties for the situation at the refinery and we expect to file that within the next 30 days.” The spill has contaminated drinking water in about 300 wells owned by local homeowners, said Kristin Ryan, spill response director in Alaska’s Department of Environmental Conservation. Jeff Cook, spokesman for Flint Hills, said the company is providing bottled drinking water to the residents who are affected, and that this will continue until a long-term solution for providing safe water is found. Flint Hills Resources cited ongoing costs over the sulfolane pollution when announcing Feb. 4 it would end all refining operations by June 1. The move is expected to cost about 80 employees their jobs. Cook said the spill occurred when the refinery was owned and operated by Williams Cos., of Tulsa, Okla., and that Williams shares the liability as a former owner. Cook also said the state owned and leased the land at the time to Williams, which makes the state at least partly liable. Ryan of the DEC said Flint Hills is a responsible party because it now owns the refinery and contaminated property. The spill is also continuing to spread onto lands adjacent to the refinery property and contaminating residential water wells, and this is happening under Flint Hills’ ownership, she said. Cook said Flint Hills has spent about $70 million so far on environmental remediation and supplying drinking water to local residents, but that $50 million of this came from an insurance policy that had been purchased by Williams at the time the refinery was sold. Ryan said there is no estimate of what it would cost to clean up the sulfolane or even if it can be removed from the soil. One of the technical challenges in that sulfolane adheres to water, which is possibly why it is spreading through underground aquifers in the area, which has a high water table. “We know that is has now spread in a plume at least three miles by two miles,” Ryan said. The effects of sulfolane of human health are not well known and the chemical is not considered a hazardous chemical, she said. Still, the state environmental agency is being cautious about possible effects. Ryan’s agency has asked Flint Hills to prepare a feasibility study for a cleanup but she acknowledge it may not be technically or economically feasible to remove the sulfolane. Lawsuits filed by Flint Hills against Williams in 2010 and 2012 were voided when a state judge ruled the company had waited too long, and had exceeded a three-year statute of limitations. To sort these issues out, the state itself will file a suit, Geraghty said. Flint Hills announced earlier this year that it would close the refinery, which has operated since 1977, due to deteriorating economic conditions. The plant produces mainly jet fuel and gasoline that is shipped by rail to Anchorage, and Flint Hills is a major supplier to air carriers operating from Anchorage’s international airport. In recent years the air carriers have been importing bulk jet fuel from overseas themselves, undercutting Flint Hills’ market share. The refinery takes crude oil from the Trans-Alaska Pipeline System, which is nearby, and purchases state-owned royalty oil.

Four bills aim to expand AIDEA role

The Alaska Industrial Development and Export Authority is pretty popular in the state capitol these days. Sen. Lesil McGuire, R-Anchorage, wants to expand powers for AIDEA, the state development corporation, to partner in the development of Arctic ports in a bill she is sponsoring, Senate Bill 140. Sen. Bert Stedman, R-Sitka, wants the authority to help finance the Bokan Mountain rare earth mine on Prince of Wales Island, which is in Stedman’s Southeast district. Stedman secured an amendment to another of McGuire’s bills, SB 99, that deals with technical amendments to AIDEA. Rep. Paul Seaton, R-Homer, wants the authority to be able to finance oil and gas processing facilities for small independent companies exploring on the North Slope. Seaton has introduced the proposal in House Bill 230. The newest and most ambitious development, however, is a proposal unveiled Feb. 24 by Democratic Sens. Hollis French and Bill Wielechowski, and Rep. Les Gara, D-Anchorage, for AIDEA to partner with small independent oil and gas explorers to take an equity stake in new oil and gas fields, in effect becoming a state oil company. “The idea is for AIDEA to supply venture capital to small independent companies coming to Alaska who lack capital. This ensures AIDEA would be a partner, and it would help bring more projects on line,” Wielechowski said in a press conference held with French and Gara to announce the plan. AIDEA has already invested in an oil drilling rig and mining access roads in the Brooks Range, and the state-owned Alaska Gasline Development Corp., is now proposed as an equity partner in the large gas pipeline project, he said. The Democrats’ bill, in HB 338, was introduced in the state House on Feb. 24. A Senate version was to be introduced Feb. 26. Senate Bill 140, McGuire’s Arctic infrastructure bill, would set up a special fund within AIDEA to participate with other parties in an Arctic port. The state authority’s share would be limited to one third of the financing needed with a maximum participation of $20 million and a period no longer than 30 years. SB 140 bill has had one hearing in the Senate committee and is expected to take up the measure again soon, and also adopt several technical changes suggested by McGuire. The U.S. Army Corps of Engineers is now finalizing its selection of three possible western Alaska port locations that could support increased Arctic shipping and offshore oil and gas support work. It is expected that financing for a port would have to come from a variety of sources including federal and state governments as well as private sources. The other AIDEA bill by McGuire, SB 99, was introduced to make technical changes in the Sustainable Energy Transmission Supply, or STES, program that was set up within the authority in SB 25, passed in 2012. The changes clarify the limits on AIDEA financing under SETS to those also in SB 140, on Arctic infrastructure, to one-third of an energy project funding. Those were to be reviewed when Senate Labor and Commerce committee took up the bill again on Feb. 27. Stedman’s amendment, which has been accepted for the bill, would allow AIDEA to participate in financing Ucore Rare Metals Corp.’s proposed $221 million rare earth mine at Bokan Mountain. The company has been engaged in exploration for several years at the prospect and plans to submit applications for permits in the first half of the year, Ucore officials have said. Rep. Paul Seaton’s HB 230, which had its first hearing in the House Labor and Commerce Committee Feb. 21, would change AIDEA’s statutes by giving the authority permission to help finance oil and gas oil processing facilities in partnership with small independents. AIDEA is in discussions with Brooks Range Petroleum, an Alaska-based company, on helping finance a processing plant for its small Mustang oil field on the North Slope. The plant would be available for other explorers and developed to use, under the plan. Seaton’s bill establishes an oil and gas infrastructure fund within AIDEA’s statute and provides that financing limits that apply to other, non-petroleum developments would not apply to the oil and gas projects. Specifically, current law provides that AIDEA’s bonding authority is capped at $400 million. HB 230 would allow up to $200 million in financing for oil and gas projects outside of the $400 million limit on other AIDEA developments.

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