Tim Bradner

Flint Hills refinery unit to shut down sooner than expected

Flint Hills Resources will have its North Pole refinery crude oil processing unit No. 1 shut down Aug. 1, about a month earlier than the company had said. The closure will leave the refinery’s crude processing unit No. 2 still operating. The refinery’s crude processing unit No. 3 was shut down in 2010. The plant at North Pole is near Fairbanks. Flint Hills takes crude oil from the nearby Trans-Alaska Pipeline System to manufacture fuel products. Flint Hills spokesman Jeff Cook would not provide estimate of the production capability of the remaining unit but said that it is capable of manufacturing gasoline, diesel, asphalt and jet fuel for Flint Hill’s current customers as well as a naphtha that is used for power generation by Golden Valley Electric Association, the Interior Alaska regional electric cooperative. Meanwhile, the company is working to find jobs for employees affected by the shutdown of the unit, Cook said. “This will affect about 37 to 38 of our employees but fortunately we have been able to place many of these people with other refineries and facilities operated by our parent company, Koch Industries,” Cook said. The company now employs about 170 between the refinery and a bulk fuel storage and distribution center in Anchorage, he said. Fairbanks community leaders are concerned that Flint Hills’ action to move skilled employees to other plants is a signal that the company sees no possibility of restarting the unit in the near future, nor a third processing unit at the refinery that was shut down in 2010. Jim Dodson, president of the Fairbanks Economic Development Corp., said his organization is focused on helping the refinery alleviate problems that affect its profitability, mainly a less expensive source of energy for refinery operations than the crude oil Flint Hills must now burn. The company is now in a joint study with Golden Valley of a plan to truck liquefied natural gas from the North Slope to Fairbanks. The LNG would be regasified to power the refinery, removing the need to burn costly oil. Fairbanks leaders are also pressing the state of Alaska to offer Flint Hills better terms on its state royalty oil contract when the contract is renewed in 2014, Dodson said. The refinery is now totally dependent on the state for a supply of crude oil, and the state charges Flint Hills a premium for royalty crude on top of the value the state receives from producers who pay the state royalty in cash. “It makes absolute zero sense for the state to charge Flint Hills a bonus on the royalty oil,” Dodson said. “Our state should be focused on helping our industries and retaining jobs rather than maximizing revenue to the treasury,” particularly when Alaska is running billion-dollar revenues surpluses at current oil prices. The Flint Hills cutback in August will further reduce shipments of fuel from Fairbanks to Anchorage on the state-owned Alaska Railroad Corp. Bill O’Leary, the railroad’s vice president of finance, said fuel shipments have been reduced by half since Flint Hills operated all three of its crude units and shipped gasoline and jet fuel to Anchorage. Officials at Ted Stevens International Airport in Anchorage said fuel suppliers bringing jet fuel from overseas have been able to replace the jet fuel made by Flint Hills, although a Tesoro Corp. refinery in Kenai, south of Anchorage, also supplies some jet fuel. Anchorage’s airport is a major refueling point for air cargo operators flying between North America and Asia. About 800 million to 1 billion gallons of jet fuel is purchased annually by air carriers in Anchorage.

Permanent Fund holds its own despite market turbulence

Alaska’s Permanent Fund has been riding the roller coaster of financial markets and will probably end its fiscal year on June 30 in basically a break-even position, according to the Fund’s executive director Mike Burns. The monthly performance report prepared for the Fund’s trustees for April 30 showed a 0.76 percent gain in value over the prior 12 months, although the fiscal-year-to-date (July 1 to April 30) was little better, a gain of 2.03 percent. A target set by the Trustees is for the Fund to achieve a 5 percent real, or inflation-adjusted, return, but this goal won’t be met this year due to the market turbulence. “The markets have been incredibly emotional in the last 18 months. Sometimes it seems like things are coated with Teflon, so bad news just rolls off. Other times it’s Velco, so that everything sticks,” Burns said. Not surprisingly, the value of the Fund’s stocks and other liquid assets have taken a beating, with values down 12.78 percent for the 12-month period prior to April 30, according to the report to the trustees. On the other hand, “illiquid assets” like real estate, infrastructure and some private equity investments have performed much better, Burns said. As of April 30, returns from real estate, as an example, were 13.48 percent up for the 12-month period. “We’re really quite pleased at how well real estate has stood up all through the downturn. We’re invested mainly in high quality properties and these have never really lost their value, although some of this could also be the lenders just kicking some of the problems down the road, but we don’t think do,” Burns said. The Fund’s managers are quite proud of some of the real estate investments. For example, 299 Park Ave. in New York is a $1.2 billion office building owned 50-50 with the Fisher Brothers, a long-established and well-known property investment group. The Fund’s investment in its 50 percent share is $300 million. Another high-quality property is Tysons Corner Center in Washington, D.C., a major retail center. This is 50 percent owned by the Permanent Fund with the Macerich group as a partner. Macerich is a well-established U.S. firm specializing in major retail properties. A major expansion at Tysons Corner is now under way that will add a 550,000-square-foot office building, a 450-unit apartment complex and a 300-room hotel, but these additions are mainly seen as adding value to the retail complex. “The retail is the key. We’re excited about the additions of the apartments, hotel and offices but mainly as they enhance the retail,” Burns said. The Permanent Fund has $500 million invested in Tysons. Another major investment is Simpson Housing, based in Denver, which owns and manages 17,000 apartments in several parts of the nation. The Permanent Fund owns 48 percent of this, Burns said, with the State of Michigan’s public employee retirement system as a partner. Burns said the Fund will invest with partners in real estate in certain cases but the preference overall is to own 100 percent of a property. An example is Parc Huron, a large, high-quality apartment property in Chicago, a $120 million investment for the Fund. One recent real estate decision of the Fund which has prompted some criticism, mostly in the form of letters to the editor following articles in local newspapers, is an investment in groups of distressed U.S. homes which were foreclosed by banks. The investment is in American Homes 4 Rent, a group that buys foreclosed homes from banks. Critics feel the Fund is taking advantage of peoples’ misery in foreclosures, “but we’re buying these after the foreclosures. The misery has already happened,” Burns said. These days the Alaska Permanent Fund’s ability to invest for the long-term and in illiquid assets like real estate and infrastructure is an advantage because many other institutional investors, like public pension funds, are now more focused on short-term cash needs and must pursue an investment strategy that is more short-term, Burns said. That puts the Permanent Fund in a class of investors more like sovereign wealth funds of countries like Norway and Abu Dhabi. In fact, there is now an association of sovereign wealth funds that Alaska has joined. Having a line of communications with these groups is very important and could someday lead to cooperative investments, Burns said. Market outlook Meanwhile, for financial markets today, attention is now focused on the situation in Europe, which Burns describes as “a slow-moving, controlled train wreck.” If there’s anything good about it, it is that things are moving at a slow enough pace that the markets have time to adjust, he said. ““I don’t think there are any surprises left in Europe. It’s not like we wake up in the morning and Lehman Brothers has gone down,” he said in reference to the debacle in 2008 when that major U.S. financial institution came apart and triggered tumult that helped spark a recession. Burns is optimistic that the financial markets will manage to sort through these problems eventually, if left to their own. However, some unexpected major event could upset things, something like a major terrorist attack, he said. The U.S. meanwhile has its own problems to deal with, which mainly have to do with business confidence. “A lot of companies have strong balance sheets and are sitting on cash, but there is a lot of uncertainty. People are unwilling to let go of cash,” he said. Much of the uncertainty is politically created by the impasse in Washington, D.C., over federal taxes and debt, although Burns said the agreement by Congress to extend tax-cuts has had a soothing effect. But the pending elections, the effect on the elections of an expected Supreme Court decision on President Obama’s health care law, and the return to intense debate over the debt ceiling and federal spending cuts next January will continue to add to the uncertainty. A similar cautious dynamic affects U.S. hiring, and more than anything else it is continued high unemployment that has slowed the recovery. Firms are reluctant to staff up if they may have to let people go again. “People lose sight of how difficult it is for companies to reduce their workforce and how hard it is for them, as well as for communities,” Burns said. This is why so many firms are outsourcing work, like major oil companies are doing in Alaska. “If they have to lay people off, they push this off on their contractors,” he said. China is, of course, a wild card, but Burns points out that recent news of an economic slowdown is only reduced rate of growth, not a move into negative territory. There are important fundamentals behind China’s growth, such as an improved diet, that will continue to put pressure on world resources and commodities, Burns said. When this is combined with the economic and population growth of other developing countries like India, there will be continued pressure on sources of energy, protein and water. Water is really important,” and it may become the most scarce resource, Burns thinks. “When you think about it, the U.S. exports a lot of food but what we’re really exporting is water,” because of the water it takes to grow food. Improving diets in China is expect to lead to per capita consumption of beef and pork increasing to 20 kilograms a year in the next five years, up from 10 to 12 kilograms. “The amount of water it will take to create that additional supply of beef and pork per year is about the same as Europe consumes in a day,” he said. Burns is thinking a lot about these long-term trends, and possible scarcities in natural resources, not only because of how they will affect the world and Alaska, a natural resource-producing state, but also as a guide to potential long-range investment by the Fund. “This is something we’re just thinking about. We haven’t developed it into a strategy in any sense,” Burns said. “If you think about something like water scarcity, how do you position yourself? Do you invest in water-related technologies like companies specializing in water treatment and desalinization, or should you invest in water rights? “If you do this, you have to keep in mind the security of the investment. If there is water scarcity a government may decide to give its citizens priority access to water over any ownership claims of an investor.” The Fund is investing in technology firms including those working in water quality, but not yet as part of an overall theme. The same is true in protein, he said. “We really like to invest in farmland but you have to do it in scale,” which means that acquiring farmland in North America is problematic because land units of sufficient acreage is less available, he said. “There is tremendous potential for farmland in places like Brazil and southern Africa, but there is no infrastructure, no ports or railroads.” Agriculture investments like these will have to be part of a broader plan that includes the infrastructure.

ExxonMobil set to begin Point Thomson construction

ExxonMobil Corp. is set to begin construction this winter on its multi-billion-dollar gas cycling and condensate production project at Point Thomson on Alaska’s North Slope. That’s if a federal environmental impact statement, or EIS, is finalized by the U.S. Army Corps of Engineers, as is expected, ExxonMobil’s senior project manager Lee Bruce said. Materials for Point Thomson construction also started arriving at Seward the night of June 12, Bruce said. The company presented its plans to legislators at a meeting of the Senate Judiciary Committee in Anchorage June 12. The lineup of contractors on the project is like a “who’s who” in the oil support industry, because there’s not a lot of other construction happening on the slope this year. Assuming the final EIS and record of decision are issued in schedule, ExxonMobil will begin construction of roads and an expansion of a central process facility and well pad now at the site, as well as installation of Vertical Support Members, or VSMs, for a 22-inch liquids pipeline. A 2,500-foot gravel airstrip will also be built this winter, Bruce said. To do the work, a winter ice road must be built first from the Prudhoe Bay field 60 miles to the west, because there is no year-around road access to Point Thomson, Bruce said. Point Thomson has about 8 trillion cubic feet of natural gas and about 300 million barrels of hydrocarbon liquids, mostly condensate liquids in the main gas reservoir, but also some conventional crude oil at the bottom of the reservoir and in nearby, separate oil deposits. The plan for the following winter, the 2014-15 winter construction season, is for the pipeline to be built from Point Thomson to connect with an existing pipeline from the Badami field to Prudhoe Bay, Bruce said. Field pipelines will also be installed in Point Thomson itself, he said. In the following two years a drill rig will be brought back to the field to drill more gas production wells and gas process and compression facilities will be installed. Production is scheduled to start in April, 2016, Bruce said. “I’ve challenged my team to beat that schedule, but all of this will depend on permits being issued this fall,” Bruce told the legislators. Key challenges at Point Thomson for ExxonMobil and its partners, which include BP and ConocoPhillips as major leaseholders, are the very high pressure in the main gas reservoir, which is over 10,000 pounds per square inch, and the need to build large and study gas compression facilities to inject produced gas back underground at a higher pressure, Bruce said. The remote location in the eastern North Slope, with no current transportation access, is another challenge, he said. The companies have spent more than $1 billion in development of the project so far, “and we have several more billion to go,” Bruce said. The companies have not released the total expected capital costs of the project. State Sen. Hollis French, D-Anchorage, who chairs the Judiciary Committee, said he was surprised at the magnitude and complexity of the project and that it will produce only 10,000 barrels per day of condensates. Bruce said the cycling project is intended as the first stage of Point Thomson development. Depending on how the reservoir performs after the initial project starts up in 2016, the cycling and liquids production could be scaled up or the project converted to conventional gas production to support a major North Slope gas pipeline if one is built, or alternatively the transport of gas to the Prudhoe Bay field provide pressure for more oil production in that large oil field. The legislative committee was conducting an oversight hearing of litigation settlement between the state and the Point Thomson leaderowners reached earlier this year. A commitment by the companies to proceed with the gas cycling project and Point Thomson development was made as a part of the settlement. French said the hearing was done as part of the Legislature’s responsibility for oversight of executive branch actions. “This settlement has multi-billion-dollar implications for the state, and we are reviewing it as part of our due diligence responsibility,” French said in comments before the hearing. “We want to determine if the settlement is in the state’s best interest. The departments of Natural Resources and Law say it is, but we have the normal citizen’s interest to look at this and kick the tires a bit.” A former state oil and gas director, Mark Myers, has raised questions about parts of the settlement during a committee hearing in Juneau in late April as the Legislature was concluding a special session on oil and gas taxes. Among other criticisms, Myers said in April that he felt the agreement left too much control over development of the state leases with the companies, and that it weakens the state’s influence. The companies were working on the gas cycling project before the settlement, as part of an interim settlement of the legal dispute, but the final agreement requires them to finish the project or lose leases in the Point Thomson field. The dispute arose in 2006 and 2007 when the state felt the companies were not moving fast enough toward development of Point Thomson. The state moved to terminate the Point Thomson unit and the leases, which triggered a lawsuit from the companies. The settlement is also part of a broader agreement between the companies, which also own the majority of leases in the Prudhoe Bay field, to pursue a gas pipeline and liquefied natural gas project built at the southern Alaska port. Feasibility studies on that project are now underway and a report on progress is due to Gov. Sean Parnell in September.

ExxonMobil set to begin Point Thomson construction this winter

ExxonMobil Corp. is set to begin construction this winter on its multi-billion-dollar gas cycling and condensate production project at Point Thomson on Alaska’s North Slope. That’s if a federal environmental impact statement, or EIS, is finalized by the U.S. Army Corps of Engineers, as is expected, ExxonMobil’s senior project manager Lee Bruce said. Materials for Point Thomson construction also started arriving at Seward the night of June 12, Bruce said. The company presented its plans to legislators at a meeting of the Senate Judiciary Committee in Anchorage June 12. The lineup of contractors on the project is like a “who’s who” in the oil support industry, because there’s not a lot of other construction happening on the slope this year. Assuming the final EIS and record of decision are issued in schedule, ExxonMobil will begin construction of roads and an expansion of a central process facility and well pad now at the site, as well as installation of Vertical Support Members, or VSMs, for a 22-inch liquids pipeline. A 2,500-foot gravel airstrip will also be built this winter, Bruce said.  To do the work, a winter ice road must be built first from the Prudhoe Bay field 60 miles to the west, because there is no year-around road access to Point Thomson, Bruce said. Point Thomson has about 8 trillion cubic feet of natural gas and about 300 million barrels of hydrocarbon liquids, mostly condensate liquids in the main gas reservoir, but also some conventional crude oil at the bottom of the reservoir and in nearby, separate oil deposits. The plan for the following winter, the 2014-15 winter construction season, is for the pipeline to be built from Point Thomson to connect with an existing pipeline from the Badami field to Prudhoe Bay, Bruce said. Field pipelines will also be installed in Point Thomson itself, he said. In the following two years a drill rig will be brought back to the field to drill more gas production wells and gas process and compression facilities will be installed. Production is scheduled to start in April, 2016, Bruce said. “I’ve challenged my team to beat that schedule, but all of this will depend on permits being issued this fall,” Bruce told the legislators. Key challenges at Point Thomson for ExxonMobil and its partners, which include BP and ConocoPhillips as major leaseholders, are the very high pressure in the main gas reservoir, which is over 10,000 pounds per square inch, and the need to build large and study gas compression facilities to inject produced gas back underground at a higher pressure, Bruce said. The remote location in the eastern North Slope, with no current transportation access, is another challenge, he said. The companies have spent more than $1 billion in development of the project so far, “and we have several more billion to go,” Bruce said. The companies have not released the total expected capital costs of the project. State Sen. Hollis French, D-Anchorage, who chairs the Judiciary Committee, said he was surprised at the magnitude and complexity of the project and that it will produce only 10,000 barrels per day of condensates. Bruce said the cycling project is intended as the first stage of Point Thomson development. Depending on how the reservoir performs after the initial project starts up in 2016, the cycling and liquids production could be scaled up or the project converted to conventional gas production to support a major North Slope gas pipeline if one is built, or alternatively the transport of gas to the Prudhoe Bay field provide pressure for more oil production in that large oil field. The legislative committee was conducting an oversight hearing of litigation settlement between the state and the Point Thomson leaderowners reached earlier this year. A commitment by the companies to proceed with the gas cycling project and Point Thomson development was made as a part of the settlement. French said the hearing was done as part of the Legislature’s responsibility for oversight of  executive branch actions. “This settlement has multi-billion-dollar implications for the state, and we are reviewing it as part of our due diligence responsibility,” French said in comments before the hearing. “We want to determine if the settlement is in the state’s best interest. The departments of Natural Resources and Law say it is, but we have the normal citizen’s interest to look at this and kick the tires a bit.” A former state oil and gas director, Mark Myers, has raised questions about parts of the settlement during a committee hearing in Juneau in late April as the Legislature was concluding a special session on oil and gas taxes. Among other criticisms, Myers said in April that he felt the agreement left too much control over development of the state leases with the companies, and that it weakens the state’s influence. The companies were working on the gas cycling project before the settlement, as part of an interim settlement of the legal dispute, but the final agreement requires them to finish the project or lose leases in the Point Thomson field. The dispute arose in 2006 and 2007 when the state felt the companies were not moving fast enough toward development of Point Thomson. The state moved to terminate the Point Thomson unit and the leases, which triggered a lawsuit from the companies. The settlement is also part of a broader agreement between the companies, which also own the majority of leases in the Prudhoe Bay field, to pursue a gas pipeline and liquefied natural gas project built at the southern Alaska port. Feasibility studies on that project are now underway and a report on progress is due to Gov. Sean Parnell in September.

EPA names review panel for Bristol Bay watershed study

The U.S. Environmental Protection Agency has appointed an independent scientific review panel for a draft watershed assessment of the Bristol Bay region in Southwest Alaska, where a joint-venture of Anglo American and Northern Dynasty Minerals are planning the large copper and gold Pebble mine, a senior EPA official said June 4. Notice of the panel, with its members identified, was published June 5 in the Federal Register. Dennis MacLerran, Administrator of EPA’s Region 10, spoke at a public hearing the EPA held in Anchorage on June 4, the first of seven Alaska hearings the agency will hold on the assessment. If developed, the Pebble project, west of Iliamna Lake southwest of Anchorage, would be a combination underground and surface mine and would be one of the largest copper/gold mines in the world. MacLerran said the agency chose to do the watershed assessment last year after Native tribal groups in the region petitioned the agency to initiate a 404 (c) process under the Clean Water Act to block the mine development. Section 404(c) allows EPA to veto developments that impair the environment regardless of other federal agency decisions. “We chose not to proceed with the 404 (c) process and to do the watershed assessment instead,” MacLarren said. The EPA is sensitive to its trust responsibilities to Native Americans, he said. The assessment is not regulatory in nature, but is intended to “inform” the agency on potential impacts of large scale mining in the region, which hosts the world’s largest wild salmon fishery on which Native people depend, he said. EPA did no scientific fieldwork on the assessment other than a literature review and interviews in the region with 54 tribal elders to gather traditional knowledge on the salmon fisheries, agency officials at the hearing said. The State of Alaska has meanwhile objected to the watershed assessment, arguing it is premature and unprecedented because the two companies planning development of the Pebble have not yet developed a mine plan and filed applications for permits. “We’re looking closely at the data, methodolgies and assumptions used, whether the assessment is based on appropriate modeling for that region and whether it contains any unfounded bias for or against any particular development,” Ruth Hamilton Heese, state senior assistant attorney general, said in a statement June 5. “We believe the assessment is premature and that any consideration of impacts should be made within the context of an actual proposal and Clean Water Act Section 404 application,” she said. Several hundred people attended EPA’s first hearing in Anchorage, about evenly split between opponents of the mine, which include Alaska Native people from areas near the mine where salmon could be affected, and others who are more supportive, including Native residents of villages near the mine which could benefit from jobs. Two state legislators, state Sen. Cathy Gissel and Rep. Charisse Millet, both of Anchorage, criticized the EPA assessment as done in haste and without a scientific base. “You spent five years on the last regional watershed assessment in Chesapeake Bay. You spent a year on this, which covers an area the size of Virginia,” Millet said. “As a legislator, I’m concerned about the precedent you’re setting. You’re scaring away every potential investor in a new Alaska mine.” Gissel objected to EPA appearing to pre-judge the project, which is on state-owned lands. “Alaska is a sovereign state with our own competent permitting program,” she said. Others at the hearing welcomed EPA’s action. Bella Hammond, widow of former Alaska Gov. Jay Hammond, who is from the Bristol Bay region, said she grew up in the area of the proposed mine and opposes it. “I’m very familiar with the area and I’m concerned about it, and about what people could lose,” she said, if fisheries are affected by downstream pollution from the mine. Hammond’s remarks were echoed by other mine opponents from the region who stressed the importance of protecting the major salmon fishery. Not all from the region opposed the mine, however. Abe Williams, a Bristol Bay commercial fisherman, said, “We all love our salmon but our communities are seeing drastic reductions in population and school closures,” and the economic stimulus the mine would bring is needed badly. Williams urged EPA “not to extinguish” the economic future for communities in the region through an action stimulated by “fear and emotion,” of some people. Lisa Reimer, representing Iliamna, the village nearest the Pebble project, said she and her community oppose EPA’s watershed assessment because of the uncertainty it creates on the use of Native-owned lands near the mine. The Pebble Partnership, the joint-venture company, thinks the agency is premature in its assessment. In a statement issued earlier, Pebble CEO John Shively said, “We believe that the EPA has rushed its assessment process, and that this is especially problematic in light of the large size of the study area. “We have taken several years and expended considerable resources to study the ecosystem in a small area around the Pebble deposit, while the EPA has, in only one year and with limited resources, completed a draft assessment in relation to an area of approximately 20,000 square miles. We believe that this explains why the EPA’s work has not yet approached the level of rigor and completeness required for a scientific assessment.” The peer review panel named by the EPA follows: David Atkins, Watershed Environmental LLC, (mining and hydrology); Steve Buckley, WHPacific/NANA Alaska (mining and seismology); Courtney Carothers, indigenous Alaska cultures; Dennis Dauble, Washington State University (fisheries biology and wildlife ecology); Gordon Reeves, USDA Pacific Northwest, (fisheries and aquatic biology); Charles Slaughter, University of Idaho (hydrology); John Stednick, Colorado State University (hydrology and biogeochemistry); Roy Stein, Ohio State University (fisheries and aquatic biology); William Stubblefield, Oregon State University (aquatic biology and ecotoxicology); Dirk van Zyl, University of British Columbia (mining and biogeochemistry); Phyllis Weber Scannel (aquatic biology and ecotoxicology); Paul Whitney, wildlife ecology and ecotoxicology.

State blasts Interior for old, leaking wells

Alaska’s Oil and Gas Conservation Commission, a state agency that regulates well safety, is criticizing the U.S. Department of the Interior for leaving open and leaking exploration wells in the National Petroleum Reserve-Alaska. The wells were drilled by the federal government between 1944 and 1981. There were 136 drilled, none resulting in a commercial-scale discovery. “The Interior Department is willing to spend tens of millions of dollars rehabilitating the grass on the National Mall in Washington, D.C., but it won’t do anything to clean up the mess in NPR-A,” Cathy Foerster, chair of the AOGCC, said in an interview. Foerster said few of the wells have been properly closed. Many are leaking and also pose a danger to wildlife and humans from extensive surface debris left around well sites, she said. “Proper plugging and abandonment of well includes sufficient down-hole cement and plugs to ensure that underground fluids can’t migrate. With few exceptions, none of these wells comply with that requirement,” Foerster said. Several of the wells were also left filled with diesel. Of the 136 wells, 53 are of high concern to the state commission, Foerster said. Most have no wellheads and some have open casing that are likely to be leaking fluids to the surface. Some are underwater in tundra ponds and one has simply been lost, with the BLM unable to locate it, she said. “There is one, Iko Bay No. 1, we call the ‘whistling well,’ because it is leaking gas,” Foerster said. The condition of the wells violates state regulations and very likely federal rules as well, she said. The state conservation commission is responsible for well safety on state and private lands in Alaska but its jurisdiction does not include federal lands like the 23-million-acre petroleum reserve. “All I can do is make a fuss and embarrass them,” Foerster said. “It’s okay for the federal government to dump all over Alaska lands and then tell us we can’t drill and disturb the pristine environment. That is hypocrisy.” Alaska U.S. Bureau of Land Management officials said they are concerned about the problem but can only get funds to clean and close about one well a year. BLM is the Interior Department agency responsible for administering the 23-million-acre NPR-A. BLM spokeswoman Artelia Gilliard said her agency aware of the problem and wants to cooperate with the state of Alaska. “We are working with the state of Alaska to come to a common understanding as to the status and condition of the wells,” she said in a statement. The BLM is now updating a 2004 report on the status of the wells. The next old well to be rehabilitated by the BLM will be in 2013. “BLM’s Alaska people are as frustrated as I am,” Foerster said. “I think they’d like to clean this mess up, but their hands are tied by the meager budget the federal BLM office parses out to them.” Foerster said she had attempted to meet with Interior Secretary Ken Salazar on the issue but has been do far unsuccessful. “I’m not going to cut them any slack,” she said. “They take in billions of dollars in federal leases sales in Alaska. Some of that money should go to fixing this mess.” Some wells the BLM claims to have plugged were found to be done improperly. State regulations require multiple plugs to safely abandon a well, but the BLM had only installed one, Foerster said. Twelve of the old wells are lands near the Barrow gas field that has been transferred to the North Slope Borough, the regional municipality. The borough has cleaned and plugged six of 12 wells and is working on the rest, Foerster said. There are 32 wells the BLM classifies as “revegetated,” which actually means that the abandoned well bores have eroded and collapsed, but the commission found that one of these, near the Umiat oil field, was actually still live. “That tells me we have 32 more wells, supposedly revegetated, to be worried about,” Foerster said. There are 18 unrehabilitated wells the BLM says it is using to collect data related to climate change but Foerster has doubts about this given the state of the wells and the surface debris at the site. “What’s frustrating is that the way the BLM is going about the cleanup they are doing is the most expensive way to do it. Rather than mobilize to clean up just one well they should bring do 5 or 6 wells in the area and pay only one mobilization and demobilization,” she said. No commercial-scale oil and gas fields were found in the NPR-A government exploration, which spanned over three decades, although a small oil field was found at Umiat on the southeast border of the reserve and a small gas field at Barrow, in the north. NPR-A was established as a naval petroleum reserve in 1923 and the first drilling in the 1940s and 1950s was done by the Navy itself. In 1975 it was transferred to the Department of the Interior and a second wave of government exploration drilling followed, led by the U.S. Geological Survey and done by Husky Oil under contract. In the 1980s the Interior Department began leasing to private companies and in recent years small discoveries have been made, though none are yet developed.

Oil falls, but state expects a rebound

State officials are warily watching market prices for North Slope crude oil, which dropped to less than $100 per barrel June 1 as markets reacted to slumping demand and a buildup of supply. An average price of $104 per barrel is needed to balance the state budget for Fiscal Year 2013, the state financial year that begins July 1, according to state budget director Karen Rehfeld. After trading at less than $100 on June 1 and June 4, Alaska North Slope crude edged back to $100.09 on June 5. It had been more than a year since Alaska North Slope crude traded for less than $100. High oil prices have offset production declines that saw North Dakota surpass Alaska in March for the No. 2 spot in daily domestic oil production. The U.S. dollar has also strengthened lately as investors hedge their bets against the turmoil in the eurozone, which brings down the price of all commodities priced in dollars. If prices do remain low the state could technically experience a deficit but there is no immediate financial problem because the state has about $15 billion in liquid assets, mostly in two reserve accounts: the Constitutional Budget Reserve and Statutory Budget Reserve. The oil price needed to support the state budget has increased gradually in recent years as oil production has declined and the state budget has edged up despite efforts by state legislators to contain it. Steve Revenue Commissioner Bryan Butcher said oil market analysts are split in their views. “Some see prices going down further, to the $80 or $90 per barrel range while others think we’ve bottomed out at $98, that the European factor (worry of recession) is already factored it, and that we could see a rebound quickly,” Butcher said. For the long term the consensus is still that prices will remain above $100 per barrel, that demand will rebound in the U.S. and Europe, and that China will rekindle its economy with stimulus moves, Butcher said. The state is still sticking with its projected FY 2013 average price of $110.44 per barrel and an average daily North Slope production of 563,000 barrels per day from the spring 2012 forecast, Butcher said. The next revision in the forecast will come late this year as the state prepares its November revenue estimate, he said. The state prepares two revenue forecasts annually, one traditionally issued in November that includes an updated production forecast, and one in late March or April that focuses mainly on updated price and revenue estimates. State revenue economist Dan Stickel said state revenues for the 2012 fiscal year-to-date were on track with estimates through April, but that revenue officials noticed a softening in May. June numbers will not be available until next month. The total state budget for the current year, Fiscal 2012, is $13.48 billion including federal and state funds. Revenues for the year are estimated at $14.347 billion. For Fiscal 2013, beginning July 1, the budget as approved by Gov. Sean Parnell is $12.07 billion of all funds, with $12.59 billion in total revenues. The 2013 budget will inevitably increase to some degree with supplemental appropriations, which are made necessary by unexpected expenditures, such as costs of an unusually intense summer fire season. Because of the estimated large surplus from Fiscal Year 2012 revenues the Legislature appropriated $1.8 billion to the Statutory Budget Reserve. The projected FY 2013 surplus is smaller, and for that year legislators made a smaller appropriation to the reserve fund of $250 million. North Slope crude oil is sold mainly on the U.S. west coast. About 50 percent of the fuels used in Washington State are made from crude oil from the North Slope, and about 25 percent to 30 percent of fuels in California are derived from North Slope oil.

Hilcorp has big plans for renewal of aged Inlet fields

Hilcorp Energy Co. plans an aggressive program of well workovers and remediation in aging Cook Inlet oil fields and platforms acquired from Chevron Corp. earlier this year, Hilcorp’s Alaska manager said May 24. “We see shut-in wells as an opportunity, not a liability,” John Barnes, Hillcorp Alaska’s manager, said. “This company has a long history of purchasing and rejuvenating mature, old producing assets,” he said. Barnes is an Alaska industry veteran and former Alaska manager for Marathon Oil. In the Chevron acquisition, Houston-based Hilcorp purchased eight producing oil platforms in several Cook Inlet fields along with two platforms that are in a suspended status. Hilcorp employs about 260 in Alaska, mostly former Chevron employees, Barnes said. Cook Inlet now produces about 10,000 barrels per day. The bulk of that is from Hilcorp-operated fields. The company is also purchasing Cook Inlet gas-producing assets owned by Marathon Oil Co. and that acquisition is expected to close later this year, Barnes said. Marathon’s production is mainly from onshore gas fields on the Kenai Peninsula, on the east side of Cook Inlet. Barnes said Hilcorp’s near-term plan is to pull and replace old tubing on about 20 aged oil production wells on the platforms and replace older gas-lift equipment on the wells with more efficient electric submersible pumps, or ESPs. The company will also be removing old drill rigs from the platforms this year and in 2013 will bring in a new, mobile rig that can move from platform to platform to rework old wells, Barnes said. Most of the platforms have two rigs and none have been used in recent years. “Many of these are more than 50 years old. They were old when they were installed on the platforms in the 1960s an 1970s,” he said. There is now a small workover rig working on wells at the Swanson River oil field on the Kenai Peninsula, and that work will continue, Barnes said. Swanson River, discovered in 1957, was a Chevron-owned field included in the purchase of the offshore field. The company is also drilling at the Steelhead platform, an offshore platform that mainly produces gas. The oil reservoir tapped by Steelhead was Chevron-owned and the gas reservoir is owned by Marathon, but all of that will be consolidated when the Marathon purchase is closed, Barnes said. Other Marathon fields being acquired include the large onshore Kenai gas field and the Ninilchik field, both on the Kenai Peninsula. Chevron owned a minority interest in Ninilchik now owned by Hilcorp, along with a nearby smaller gas field, Happy Valley. Barnes said Hilcorp is optimistic that it can boost production on the aged Inlet platforms. Most of the platforms have production in the hundreds of barrels a day and some wells produce about 100 barrels per day, but this can be boosted with a strategy of well workovers and some new equipment like ESPs, Barnes said. On Cook Inlet’s west side the company is working on reopening the closed Drift River oil terminal, which was closed in 2009 when it was damaged by floods related to a nearby volcanic eruption. When the terminal closed, west Cook Inlet producers — which include Hilcorp and Cook Inlet Energy, a small independent — developed an interim plan to store crude oil in smaller tanks at the Trading Bay and Granite Point fields, shipping oil through the 42-mile pipeline and loading it from the pipeline directly on tankers. This has resulted in more frequent tanker shipments and higher costs. The cost of west Inlet production could be lowered substantially if the large tanks at Drift River are brought back into service and a more efficient tanker schedule can be instituted, Barnes said. Hilcorp is working to have two tanks at the terminal operational by October, he said.

Latest NPR-A plan could impede OCS pipeline

There are new worries that National Petroleum Reserve-Alaska management plans proposed by the U.S. Department of Interior could preclude or impede a pipeline across the NPR-A for oil and gas discovered in the Chukchi Sea. Shell is exploring in the Chukchi this summer and hopes that any oil and gas discovered would be brought to shore by pipeline and across NPR-A to the Trans Alaska Pipeline System, officials told the U.S. Bureau of Land Management in a hearing May 24. Interior is considering three management plans for the 23-million-acre reserve and the environmental impact statement, or EIS, process is now under way. One plan being considered, Alternative B, precludes exploration and facilities along coastal areas of the reserve, Lon Kelly, BLM’s Arctic field office manager, said at the May 24 hearing in Anchorage. “It’s clear that under Alternative B there would be no way to get across the NPR-A,” for a pipeline from the Chukchi Sea to TAPS, Kelly said. ConocoPhillips’ Alaska land manager, Dave Brown, said the Alternative B and an Alternative C, which allows more land for leasing and facilities, are of concern to his company. ConocoPhillips has done extensive NPR-A exploration and now plans drilling in the Chukchi Sea in 2013, Brown said. The company favors an Alternative D being considered that allows virtually the entire reserve to be leased, he said. State officials criticized Interior’s focus on conservation rather than oil and gas in the reserve. “The statement of purpose and need for the Plan and EIS includes determining the appropriate management of all BLM-managed lands in the Reserve ‘in a manner consistent with existing statutory direction,’ yet the plan selectively disregards Congressional direction provided under the Naval Petroleum Reserves Production Act; the Alaska National Interest Lands Conservation Act; and the Federal Land Policy and Management Act,” said Ed Fogels, state Deputy Commissioner of Alaska’s Department of Natural Resources. “We believe the Plan inappropriately applies administrative policy to the Reserve. Instead of planning for the Reserve for the purpose for which it was established, as a Petroleum Reserve, the draft plan implies the area should instead be managed as a conservation system unit.” Even where NPR-A tracts can be leased there are complex setback requirements from numerous lakes and rivers that would make siting of surface facilities or pipeline planning difficult to impossible, several people said at the hearing. The same restrictions along NPR-A’s coasts that could impede a Chukchi Sea pipeline could also block onshore facilities and pipelines serving a discovery in state-owned submerged lands immediately north of the federal onshore lands, several at the hearing said. Carl Portman, public affairs manager for the Resource Development Council, said RDC is concerned about state resources being “stranded” because of an inability to gain access to potential shore sites for facilities and pipelines. Environmental groups testified in favor of the most restrictive Alternative B. Wendy Loya, an ecologist with the Wilderness Society, said even the most protective Alternative B could result in a 10 percent loss of habitat for calving caribou and the most liberal Alternative D could result in a loss of 30 percent of habitat. The estimates were based on studies of Prudhoe Bay-area oil development impacts on habitat, Loya told the BLM at the hearing. “Alternative B would preserve most of the habitat, would allow some leasing and would encourage the industry to find ways to minimize habitat loss when drilling and developing fields,” Loya said. Most criticism from state and industry officials focused on Interior’s exclusion from leasing in two of the three management plans of highly-prospective areas near Teshepuk Lake in the northeast NPR-A coastal area. Even the most liberal Alternative D leasing plan, which in theory would allows leasing along the coast, restrictions around lakes and streams in the Teshepuk Lake area would make development difficult. Environmental groups have successfully pushed Interior to exclude the area because of its extensive use by migratory waterfowl. Richard Garrard, a petroleum geologist with extensive industry experience in NPR-A, said geologic conditions along the Barrow Arch, a broad geologic feature that extends along the northern Alaska coast, are optimal for oil and gas, as evidenced by the large discoveries further east at Prudhoe Bay and Kuparuk. “Most of the significant oil and gas discoveries on the North Slope and all of the production to date are associated with this structural feature. In the NPR-A the Barrow Arch follows a trend approximately parallel to the present day coastline,” Garrard told the BLM. Two features about the Barrow Arch are important: “The south flank contains subtle stratigraphic and combination traps that only recently have become identifiable on modern 3-D seismic,” Garrard said. “Many of the primary reservoir targets associated with these traps rapidly deteriorate to the south and are no longer valid at distances greater than 25 miles from the coast.” The acreage that would be offered for leasing is south of the coast. Garrard has also said previously that estimates for oil discoveries in NPR-A by the U.S. Geologic Service are low because the data used by the USGS do not include results of exploration wells drilled in recent years. BLM’s Kelly said the Interior Department has not chosen a preferred alternative but will do so by the time the EIS is finalized in mid-November. A Record of Decision on the EIS, and the selection of a management plan, will be done by mid-December, he said. There is a long, tangled history to the NPR-A. The reserve was created as Naval Petroleum Reserve No. 4 in 1923 but saw no exploration until after World War II, when the U.S. Navy drilled and found a small oil field at Umiat and a small gas field at Barrow. In 1975 the reserve was transferred to the Department of the Interior and a fresh round of exploration followed, first government-sponsored and conducted by the U.S. Geological Survey, and then by a program of conventional leasing and exploration by industry. No discoveries were made by the USGS or industry. Recent exploration began in 1998 with new leasing and a fresh focus by industry after the discovery of the Alpine oil field on NPR-A’s northeast border. ConocoPhillips and Anadarko Petroleum made small oil discoveries in the area. The first of these, at CD-5 near the Alpine field, will be developed in 2014, ConocoPhillips has said.

Fuel regs will raise costs, but by how much?

Correction: This article originally referred to Marvin Buchanan as an employe of Totem Ocean Trailer Express Inc. Buchanan works for Horizon Lines Inc. New U.S. Environmental Protection Agency rules on fuel standards for ocean cargo carriers go into effect in August and the requirements will add to fuel costs for companies that ship consumer goods to Alaska, sources in the industry say. There are also more stringent requirements effective in 2015 that are likely to result in additional costs. On Aug. 1 the companies will be required to use fuel with no more than 1 percent sulfur, according to Richard Berkowitz, with the Transportation Institute, an industry trade association. “This won’t be cheap. It will be significant,” Berkowitz said. In 2015 the standards will be tightened further, with a requirement to use fuel with no more than 0.1 percent sulfur. Berkowitz said he had heard estimates that the 1 percent rule in effect in August could add 25 percent to fuel costs for major carriers operating to Alaska but other estimates have been as high as 40 percent for fuel. Officials with shipping companies serving Alaska are being cautious on estimates. Higher fuel costs will translate to higher costs for shipping goods, but the companies can’t yet say what the increase might be. “We are still researching the cost impact of the (rule) implementation on Aug. 1 and are not ready to provide any estimates at this time,” said Marvin Buchanan of Horizon Lines Inc. The company hopes to have more information available soon, he said. One of the problems shipping companies are wrestling with is how to get the special fuels, according to sources in the industry. Ultra-low sulfur diesel with 15 parts per million sulfur is now available because it is required by EPA for trucks and other equipment operating onshore, but a different requirement for ocean vessels, mainly the 1 percent sulfur limit required in August, may require blending of fuels or custom-processing by refineries, which will add costs. “The uncertainty is over what the cost of blending the fuel will be,” Berkowitz said. Alaska Sen. Lisa Murkowski said she has been told by industry executives that the increases may result in a 25 percent increase in overall shipping costs. Murkoswki made the comment in a meeting with EPA Administrator Lisa Jackson May 15. Most groceries and many other goods for retail sale are shipped from the Port of Tacoma to Anchorage on Totem Ocean Trailer Express Inc., or TOTE, and Horizon, so higher shipping costs will affect the price of groceries and other consumer goods. EPA has imposed similar sulfur restrictions in recent years for trucking companies and off-road equipment using diesel engines, but this will be the first time low-sulfur rules are applied to large ocean freighters. The agency is acting to reduce sulfur in the fuels because of studies showing a relationship between air pollution resulting from fuels with higher sulfur and human health problems. The new EPA rules will apply to all vessels operating out to the 200-mile limit from the U.S. and Canadian coasts, as Canada is adopting similar rules, but U.S.-flagged vessels that operate in coastal shipping, like TOTE and Horizon, are affected more than foreign-flagged ships which must switch to the low-sulfur fuels only when they approach the U.S. closer than 200 miles. Interestingly, the area covered the rule does not include western Alaska or the Aleutians, so Unalaska and Dutch Harbor are not included. The estimated 4,000 foreign ships a year that pass through Umnak Pass near Dutch Harbor are not covered by rule. Neither are the U.S. Great Lakes, which are exempted under a special provision secured by Congress. In her meeting with Jackson, Murkowski expressed concern over the effect of the increases on shipping costs as well as cruise ships. “These vessels carry four-fifths of the visitors that come to Alaska every summer,” Murkowski said, and added that increases to fuel costs will be passed on to passengers, which will discourage tourism. Murkowski told Jackson that she has been told that the marine industry has been trying to work out an alternative compliance plan with the EPA that would give companies more flexibility and provide a different way to meet or even exceed EPA’s goals, but that EPA has not responded. The issue has been developing for several years. Environmental groups have been pushing EPA hard to enact the low-sulfur rules to ships calling at U.S. ports to reduce harmful air pollution in port areas. Most of the effort is aimed at foreign ships calling at U.S. ports but EPA’s jurisdiction is currently limited to U.S.-flagged ships. An analysis of the foreign vessel traffic, however, led EPA to conclude that only 15 percent of ship traffic are U.S.-flagged ships that would be covered by the rule, Berkowitz said. California, meanwhile, asserted state authority to require all ships approaching California ports to use low-sulfur diesel but that was successfully challenged in court by a shippers’ association. Following that, EPA then stepped in to impose its own rule to cover U.S. ships, as well as foreign vessels out to 200 miles once a similar rule under the International Maritime Organization is agreed upon. Canada has also adopted similar emissions restrictions for vessels off its coasts, but has delayed its rule. Ships traveling to and from Alaska on a route within 200 miles of shore will fall under the EPA rule. The routes traveled by TOTE and Horizon ships are rarely if ever more than 200 miles offshore.

9th Circuit gives final approval to Shell exploration plan

A federal appeals court upheld the government’s approval of an exploration plan filed by Shell to explore its outer continental shelf leases in the Arctic in 2012. The unanimous May 25 decision was by a three-judge panel of the 9th Circuit Court of Appeals. Greenpeace, the Sierra Club, the Wilderness Society and two Alaskan Inupiat groups had appealed the approval of the Beaufort Sea and Chukchi Sea drilling plans given by the Bureau of Ocean Energy Management last August. The challengers had claimed that Shell's proposal for a well-capping stack and containment system in the event of an oil spill was incomplete and that it had failed to fully inform the government about its oil spill response plan. Shell spokesman Curtis Smith said the company was expecting a favorable decision by the court. “There are other appeals still pending, such as those of our air quality permits, but the favorable ruling on the exploration plan is a substantial boost for us,” Smith said. A similar exploration plan by Shell had been before the same judges on the appeals court in 2010, and was approved. Shell is now mobilizing its fleet to do exploration in both the Beaufort and Chukchi seas this summer. The drillship Noble Discoverer and the Kulluk, a conical, mobile drilling structure, are both in a Seattle shipyard undergoing final refitting and preparing to depart to Dutch Harbor in mid-June along with support vessels. Smith said the air emissions systems for the Kulluk were upgraded in Seattle. The Kulluk is actually owned by Shell and is, interestingly, the only drilling unit owned by the company. Similar upgrades to air emissions system of the Noble Discoverer were made in a Singapore shipyard, but in Seattle additional “winterizing” modifications, such as the addition of wind shields, are being done. An oil spill response vessel and a second support ship have been in Valdez where crews are undergoing spill response training. Plans are for all the vessels to be in Arctic waters in August to begin drilling, which must be completed by late fall, when ice moves into the exploration areas. Environmental groups have also filed appeals to the 9th Circuit court of final government approvals of federal air quality permits for the drillships, but Smith said Shell expects those to all be approved as well. The permits were issued by the U.S. Environmental Protection Agency and withstood appeals by environmental groups to the EPA’s internal Environmental Appeals Board. Traditionally, courts defer to the executive branch in regulatory matters as long as the agency decisions were  within the scope of law, and normal procedures were followed.

State scolds feds for withholding best areas from NPR-A sale

Alaska officials and industry players expressed disappointment May 17 over acreage proposed for a federal lease sale in the National Petroleum Reserve-Alaska in November. “It’s unfortunate that a lot of acreage with high potential or where modern seismic work has been done has been excluded. This doesn’t send a good message to the state or industry,” state oil and gas director Bill Barron said. A notice calling for tract nominations was published May 16 in the Federal Register by the U.S. Bureau of Land Management, which administers the NPR-A. The notice outlines what areas BLM will consider for leasing and which areas will be closed. Areas being considered for leasing are inland and south from a coastal region in the northeast NPR-A that is considered to have high potential. Environmental groups have focused an intense lobbying effort on the U.S. Department of the Interior to exclude the areas because of its use by waterfowl in the summer month. This would be the BLM’s second sale in the NPR-A in two years. A similar sale was held last year. President Barack Obama has promised to hold annual lease sales in the reserve. There was criticism from industry over the acreage selection. “Yet again the BLM has totally ignored the geology and those areas most likely to contain commercial accumulations of hydrocarbons by including only the less prospective and geological high-risj tracts,” said Richard Garrard, a consultant to companies working in NPR-A and a vice president of the Alaska Geological Society. Most areas considered high potential by federal, state and industry geologists are off-limits, Garrard said, particularly the Teshekpuk Lake region and areas to the west, which are also habitat for waterfowl. Dan Seamount, a commissioner of the Alaska Oil and Gas Conservation Commission, noted the irony that the Interior Department is not offering the best NPR-A acreage for lease but has also refused to budget funds for the closure and cleanup of old exploration wells drilled by the government itself years ago, some of which are still open and leaking. BLM Alaska officials confirmed that some old wells are within the areas that have been excluded but could not identify how many are open and not sealed off. In its notice, BLM listed 630 tracts on 7.1 million acres in the 23-million-acre reserve for consideration in the November sale. Decisions on which leases will actually be offered will be made later, the agency said. Interested parties have 45 days to offer nominations for leases to be offered after the May 16 date of publication in the Federal Register, BLM said in a press release. In a related development, Barron, the state oil and gas director, said the state will conduct is annual North Slope “areawide” lease sale of unleased lands of state-owned acreage simultaneous with the federal NPR-A sale in November so that companies can bid on adjacent federal and state acreage along the Colville River eastern boundary of the NPR-A. A similar simultaneous lease offering strategy was pursued by the state and BLM in the areawide sales late last year. BLM officials would not specify a specific date for the November sale but Garrard said he was told that the sale is now planned for Nov. 7.

Pebble study cheers foes, draws fire from state

The U.S. Environmental Protection Agency’s release of a draft watershed assessment of the Bristol Bay region in Southwest Alaska on May 18 has given new ammunition to groups opposing the large copper-gold Pebble mine being studied for development. Environmental organizations, sports fishing groups and some local communities are opposing the mine because of possible damage to fish-bearing streams caused by chemical releases from the mine, and prompted EPA to undertake the study in early 2011. The assessment, which discussed a number of potential effects of the mine, prompted a sharp reaction from state officials and companies working to develop the Pebble project, however. In a statement, Alaska Attorney General Micheal Geraghty expressed concerns that EPA, “could be setting the stage for actions that would block the state’s rights to develop resources on state-owned lands, and for companies holding valid mining claims and permits.” John Shively, CEO of the Pebble Partnership, the joint-venture company working to develop Pebble, weighed in as well: “We believe that the EPA has rushed its assessment process, and that this is especially problematic in light of the large size of the study area.” Pebble Partnership is a joint-venture company between Anglo American and Northern Dynasty Minerals. Mine opponents, however, said the agency is on the right track. “The EPA is taking the right steps with its comprehensive assessment of Bristol Bay,” said Gordon Robertson, vice president of the American Sportfishing Association, in a statement “This deliberate and careful action will lead to an objective decision that conserves the fishery and related resources of the Bristol Bay region. The sportfishing industry and anglers strongly support the EPA’s actions to protect Bristol Bay.” Pebble contains an estimated 80.6 billion pounds of copper, 107.4 million ounces of gold and 5.6 billion pounds of molybdeum. If developed, it would be one of the largest mines of its kind in the world. The state attorney general questioned the EPA’s authority to do such a wide-ranging assessment ahead of the review of state and other federal agencies of an actual project application. In a letter written in March, Geraghty said EPA’s assessment reaches, “well beyond any process or authority contemplated by the Clean Water Act … neither a petition process (which triggered the review) nor EPA’s process in developing a response are described in the CWA or its associated regulations.” The assessment affects an area of about 15 million acres, an area about the size of West Virginia, that is mostly state-owned, Geraghty wrote. The attorney general said EPA’s assessment was rushed and could undercut the U.S. Army Corps of Engineers’ detailed Section 404(c) review, as well as the state of Alaska’s own review. Opponents of the Pebble project had petitioned EPA in 2010 to invoke its authority under the Clean Water Act to veto projects that have wide-ranging environmental effects. The agency initiated the assessment as a result of that request. Shively, of the Pebble Partnership, said the EPA review will have no near-term effect on the company’s evaluation of the project and its work in preparation of applications for permits. “We’ll just keep on what we’re doing,” Shively said, but he acknowledged the assessment could create additional hoops for the developers to jump through. EPA said the assessment itself is only an informational tool. In its press release the agency said, “The assessment, when finalized following the important public comment and independent peer review, could help inform future decisions on any large-scale mining in Bristol Bay by both federal and non-federal decision-makers.” But Shively warned the document could set the stage for an attempt to preempt development. “We are concerned that the EPA may use this rushed process as the basis or an unprecedented regulatory action against the Pebble Project,” he said. “We believe it would be unprecedented and entirely inappropriate for the EPA to take steps to stop our project before it has been fully designed,” Shively said. Northern Dynasty Minerals’ President and CEO Ron Thiessen supported Shively’s comments. “To suggest that the EPA over a course of a single year can meaningfully study a region of some 20,000 square miles and assess the effects of a project for which a final design is not yet complete, and for which key environmental mitigation strategies are yet being developed, is pure folly. We have every expectation that the deep flaws in the draft Bristol Bay Watershed Assessment report will be exposed during the scientific peer review and public comment processes to come over the next several months,” Thiessen said in a statement. EPA, however, said it doesn’t have to have a detailed description of the Pebble proposal to do an assessment, and that “conceptual” models developed with regional stakeholders were sufficient. “This is not an in-depth assessment of a specific mine, but rather an examination of the impacts of mining activities at the scale and with the characteristics realistically foreseeable in the Bristol Bay region, given the nature of the mineral deposits in the watershed and he requirements for successful mining development,” the EPA said in the summary of the assessment. “The assessment largely analyses and mine scenario that reflects the expected characteristics of mining operations at the Pebble deposit,” and was developed to understand the potential impacts in the Nushagak and Kvichak River watersheds, which could be affected by the mine.” EPA’s analysis considers scenarios of blocked streams, reduced flow of water and removal of wetlands even if there is no failure of environmental protection systems on the mine, but is also considers the effects of four types of mine failures that have occurred with other large mines after they were closed. These include failure of the tailings impoundment dam, a spill from a slurry pipeline moving concentrates of copper and other metals to a tidewater port, water collection and treatment failures, and problems like failures of culverts on roads. The assessment also included cumulative effects which could occur if there are other large mines like Pebble that are eventually developed in the region, and it noted exploration activities of other companies in the region at the Groundhog, Big Chunk and Humble prospects.

DHS slaps Furie with $15M fine for Inlet jack-up rig

The U.S. Department of Homeland Security has slapped a $15 million fine on Furie Operating Alaska LLC for a violation of the U.S. Jones Act over transportation of a jack-up rig to Alaska in late 2011, and has given the company 30 days to pay from May 9, the date of a letter notifying the company of the decision.  Furie CEO Damon Kade said May 18 that the action would not impact Furie’s exploration operations now under way in Cook Inlet, however. Furie is back on location of an exploration well started last fall with the Blake 151 jack-up rig, and has resumed drilling of the well. Kade said he could not comment on the fine or possible further appeals. Furie, formerly Escopeta Oil Co., transported the Spartan Drilling Co. jack-up rig to Alaska last year on a Chinese-owned heavy-lift vessel in violation of the Jones Act, which requires shipments between U.S. ports to be on American-owned vessels The Department of Homeland Security asserted the violation occurred and notified Furie of the fine earlier. Furie appealed the decision, but the appeal was denied. The agency decision was spelled out in a document signed by Glen Vereb, director of the Border Security and Trade Compliance Section of the Homeland Security department. A $7 million dollar fine had been recommended by agency officials in Alaska but the decision was made in Washington, D.C., to apply the agency’s normal procedures for assessing Jones Act penalties, which are linked to the value of the cargo transported, in this case the jack-up rig, according to the decision signed by Vereb. Escopeta, now Furie, said it used the Chinese vessel because no U.S. vessel suitable for moving the Blake 151 around the tip of South America was available. However, the agency said that a U.S. vessel was available. At the time the company argued the U.S. vessels available were not capable of navigating rough waters at the tip of South America. A route around South America was needed because the heavy-lift vessel with the jack-up rig loaded was too large to transit the Panama Canal. In the decision document Vereb said, “The petitioner admits that its violation of the Jones Act was deliberate, intentional and committed for commercial expediency,” to meet deadlines for drilling set by the state of Alaska. The agency could have seized the drill rig but opted to levy the fine instead, according to the decision. Shipping industry sources said penalty against Furie may be the largest fine ever levied for a Jones Act violation. Meanwhile, Kade said Furie has resumed operations with the jack-up rig on a Cook Inlet offshore exploration well started late last summer but suspended for the winter. The rig was stored in a harbor in lower Cook Inlet and towed back to the well-site last week. Cade said Spartan Drilling has completed preparations to resume drilling and will conduct tests on a gas discovery made last fall at the 8,000 foot level before drilling on to the target depth of about 16,000 feet. There are additional targets to be tested at deeper intervals including possible oil prospects, Kade said. The rig will then be moved to a nearby location to drill a second well, according to plans filed by Furie with the state of Alaska, he said.

Modest bids in Cook Inlet sale; none for Alaska Peninsula leases

There was only modest bidding May 16 in a Cook Inlet oil and gas areawide lease sale, and an offering of leases on the Alaska Peninsula in southwest Alaska at the same time brought no bids in the sale. State oil and gas director Bill Barron said the total of apparent high bids was $6.86 million with 44 tracts sold to three independent companies and one individual submitting bids. All 44 tracts offered in the Cook Inlet sale received bids, which covered 200,320 acres. Most of the bids were near the $25 per acre minimum bid price but Cook Inlet Energy offered several bids substantially higher than the minimum, the highest at $82 per acre. Barron said the sale results reflected a continued interest by the industry in the Inlet. “It has been very busy in the last couple of years, with new companies like Apache, Hillcorp, Cook Inlet Energy and Buccaneer exploring,” Barron said at the lease sale. Cook Inlet Energy, subsidiary of Tennessee-based Miller Energy, is the apparent winner on most leases sold with high bids on 18 tracts acquired followed by Texas-basd Hillcorp, which submitted high bids on 17 tracts. Apache Corp. submitted high bids on eight leases. Tracts receiving high bids were mostly near existing producing areas on the east and west side of Cook Inlet. William Crawford submitted the lone by an individual for one tract in the Matanuska-Susitna Borough north of Anchorage. There were seven leases that brought more than one bid. On six of them Cook Inlet Energy beat out Apache Corp. On the seventh contested lease Hilcorp beat out a bid by Buccaneer Energy, another independent exploring in the Inlet. Buccaneer submitted only one bid for a lease. All three independent companies submitting bids are current leaseholders in the region. Hilcorp acquired producing assets Chevron Corp., mainly offshore oil and gas producing platforms. Cook Inlet Energy is producing oil and gas from the small field on the west side of the Inlet. Apache is not a current producer but is now the largest owner of leases in the Cook Inlet region and is engaged in a major multi-year exploration program. Barron said all high bids are apparent at this point and that final results will be published on the Division of Oil and Gas website Thursday. The lack of bids in the Alaska Peninsula region was no surprise. The acreage is offered every year as part of the annual Cook Inlet areawide sale, and there have been no bids for Alaska Peninsula leases in recent years.

Winter exploration includes discovery, disappointment for Pioneer

Pioneer Natural Resources Co. has made a modest oil discovery in an exploration well drilled this winter but results of another well are still uncertain and a third well was a disappointment, according to the company. Pioneer CEO Scott Sheffield announced the drilling results during an analysis of Pioneer’s first quarter results given to investment groups. The Nuna No. 1 well drilled into the Torok geological formation that is part of the Ooogurk Unit flowed at 2,000 barrels per day. The company estimates that the find will add 50 million barrels of recoverable reserves estimates at Torok. A second well drilled into the Nuiqsut formation, one of the formations in the Oooguruk field now producing, flowed at 4,000 barrels per day but tapered off during a production test, Pioneer spokesman Casey Sullivan said in an interview following Sheffield’s remarks. A third well, Sikumi, was at an offshore location but found water instead of oil, Sullivan said. Sikumi was drilled into the deeper Ivishak formation, which is the main producing formation in the large Prudhoe Bay field southeast of Oooguruk. The Oooguruk field is now producing about 5,820 barrels per day. Sheffield said Pioneer used a new technique, “mechanically diverted fracture stimulation,” in the exploration wells. Sullivan said the technique enhanced the effectiveness of fracturing the tight reservoir rocks being tested, and the results of the trials were positive. Pioneer is still reviewing the results of the Nuna well and may drill a second well to appraise the discovery, Sullivan said. That decision may come soon because of the time needed to contract for support services as well as permits for drilling next winter, he said. No decisions have been made as to how the discovery might be developed. “The next step may be the appraisal well but to get fund this we must compete with other Pioneer projects,” Sullivan said, which is a challenge given the high state production tax. Pioneer is very active in drilling in Lower 48 shale oil projects in states where taxes are lower than Alaska and where the geologic and permitting risks are fewer. The Torok is now estimated to have about 650 million barrels of oil in place, or oil physically in the reservoir rock, of which about 15 percent to 20 percent might be commercially produced. Much of the formation lies under leases held by Pioneer but part of it extends into adjacent leases, according to sources familiar with the prospect. The 50-million barrel addition resulting from the Nuna will be to the commercially produced estimate from Pioneer’s leases on Torok, however. The quality of the oil in the three known Oooguruk formations including Torok varies but average about 24 degrees API, according to data presented by Pioneer to government agencies.

Brooks Range moves to develop Mustang discovery on Slope

Alaska-based independent Brooks Range Petroleum Corp. has made a discovery at its “Mustang” oil prospect west of the Kuparuk River field on the North Slope, a company official said April 18. Meanwhile, Repsol is finishing up its first winter North Slope exploration season. The company was able to drill two of three wells that were planned for the winter. Drilling was cancelled for the season at the third well, where a shallow gas blowout forced the suspension of operations. Brooks Range believes Mustang will produce about 13,000 barrels a day at peak and that more than 40 million barrels of oil will be recovered, Bart Armfield, Brooks Range Petroleum’s chief operating officer, said in an interview. Plans are for first production in early 2014, Armfield said. Development costs are estimated to be between $600 million and $800 million. “We’re now moving toward development. There’s just a lot of paperwork to do with permits for gravel work with the Corps of Engineers, the Environmental Protection Agency,” and other government agencies, he said. Mustang is located within 700 feet of the existing Alpine field pipeline, however, which will enable Brooks Range to do a fast-track development by North Slope standards. Armfield said Brooks Range is also evaluating a nearby prospect it calls Appaloosa, which could add to reserves. The company is talking with the Alaska Industrial Development and Export Authority, a state development corporation, on possible participation in a small oil and gas processing facility for the field, Armfield said. Brooks Range is jointly owned by Alaska Venture Capital Group, itself jointly owned by a group of small Lower 48 independents, and Ramshorn Investments, owned by Nabors Industries. The company has been exploring on the North Slope for several years and is working with a number of other prospects in addition to Mustang and Appalosa. A small oil discovery was made at Beechey Point just north of the Prudhoe Bay field but reserves so far are too limited to justify development. Another prospect, Telemark, is near the Point Thomson gas and condensate field east of Prudhoe. Brooks Range is now evaluating Telemark, Ken Thompson, managing director for AVCG, said in a previous interview. Repsol had planned for a more ambitious first exploration season on the slope but plans were stymied by a shortage of drilling rigs and, finally, by the shallow gas blowout at the company’s Qugruk No. 2 well on the Colville Delta. Qugruk No. 4, an offshore test north of the delta and to the northwest of Qugruk No. 2, was completed and demobilization activities were under way in late April, according to Repsol spokesman Jan Sieving. The second well that was completed was Kachemak No. 1, an onshore well south of the Kuparuk River field and east of Tarn, a small “satellite” field to Kuparuk, Sieving said. Work on another test, Qugruk No. 1, was done but the well was not completed this year, he said. Plans are to return to Qugruk No. 1 next year. Repsol has not released any results of its winter drilling.  

Flint Hills to close another crude oil refining unit

Flint Hills Resources announced April 10 it is closing its No. 1 crude oil refining unit at the company’s refinery at North Pole due to challenging economic conditions faced by the refinery, company officials said in a press release. The company will be required to cut 35 to 40 jobs, officials said. “This is the most difficult decision we have had to make in operating this refinery,” Mike Brose, vice president of Alaska operations and manager of the Flint Hills refinery, said in a statement. “We value our employees very much; they are all dedicated professionals who have worked very hard to help us compete in what is an extremely difficult economic climate.”     The refinery has the capacity to process 220,000 barrels per day of crude oil taken from the Trans-Alaska Pipeline System. It extracts a portion of the crude barrel to make jet fuel, diesel, some gasoline and naphtha. The amount of product produced has varied but it has been about 60,000 barrels per day in the past when all three crude oil refining units were operating. Flint Hills will continue operating its remaining No. 2 crude unit to produce jet fuel, gasoline, asphalt and some specialty fuels for Alaska markets while continuing to meet all its contractual commitments, Flint Hills said in its statement. The refinery previously idled its No. 3 crude unit, which produced mainly jet fuel. Flint Hills said the current economics of refining is challenging for refineries across the world. Over the last several years 16 refineries in North America and Europe have shut down. Because of the isolated location of the Flint Hills Resources Refinery and the dependence on one source of crude oil, the North Slope, Flint Hills faces greater economic challenges than many other refineries.  “The North Pole refinery was designed to use crude oil as a source of energy to power operations, which is a considerable disadvantage,” Brose said. “Crude oil prices and Alaska North Slope Crude prices in particular are very high and are expected to remain that way for the foreseeable future. In addition, the calculations associated with the Quality Bank place our refinery in a disadvantaged position. We need to solve these two problems in order to survive, and a single crude unit configuration gives us the best platform to work on these problems.” The Quality Bank is an adjustment mechanism for crude oil shippers in the TAPS pipeline. Flint Hills pays a fee to the Quality Bank to compensate other shippers for the effects on the crude oil quality of the refinery’s return of unused portions of crude oil to the pipeline.  The affected employees will have an opportunity to apply for other positions within the company. Employees who do not receive other positions in the company will receive severance packages. Flint Hills Resources will also provide placement support for employees seeking job opportunities outside the company. Another problem the refinery faces is that it must burn crude oil to provide energy, which is very costly at current crude prices. Flint Hills is now in a joint study with Golden Valley Electric Association, the regional electric cooperative, of a possible plan to truck liquefied natural gas from the North Slope, to provide energy to the refinery and reduce the need to use expensive crude oil as fuel. A decision on this is expected at the end of this year, Golden Valley President Brian Newton has said. It would take two to three years to build the LNG plant at Prudhoe Bay and the regasification and tanks at the refinery, however. The state Legislature is considering a set of tax credits that would assist in the development of community LNG storage tanks such as those that could serve Golden Valley and the refinery.

Legislators rush to resolve key bills

With about a week left in the 2012 state legislative session, bills are piled up in the Finance committees of both the state House and Senate and, typically, the most pressing business is left to the last minute. As is customary, some bills that are priorities of leaders in the House and Senate are being held “hostage” in the other body to gain negotiating leverage. For example, the House has Sen. Johnny Ellis’ bill extending the state film tax credit in its Finance Committee, where lengthy hearings are being held in a subcommittee. The bill passed the Senate last year. Similarly, the Senate has House Speaker Mike Chenault’s bill to expand powers of the Alaska Gasline Development Corp., a state corporation planning an in-state gas pipeline, on a slow track. That bill passed the House March 27 but was assigned to three committees in the Senate. A hearing in the first committee, the Senate Community and Regional Affairs Committee, was set for April 3 but was cancelled. The Senate Finance Committee hopes to finish work, at last, on its version of an oil tax reform bill the weekend of April 7 and 8, but there seems little prospect that the House will be able to give the bill adequate review before the adjournment deadline at midnight, April 15. House Speaker Chenault expressed that view in a briefing April 2. The Senate bill is very different than the oil tax bill passed by the House last year but House leaders said the form of the bill isn’t as important as whether the Senate bill would reduce taxes sufficiently to encourage investment. There’s talk that the Legislature may go into overtime to complete work on the oil tax, but that’s speculation at this point. Meanwhile, another important bill, the state capital budget — which pays for construction work — is due to emerge from behind closed doors soon, according to Sen. Bert Stedman, R-Sitka, co-chair of the Senate Finance Committee. Unlike the oil tax, there likely will be a rough consensus already in place between the House and Senate on the capital budget before it appears to the general public.   In a March 2 briefing by Senate leaders, Stedman said informal talks are being held with House leaders on the capital budget bill. The House Finance Committee, meanwhile, has been holding hearings and working on its approach to the capital budget, but will wait, as is the custom, to work on the Senate bill when it comes over from that body. The normal legislative procedures will take place with the capital budget once it surfaces, with hearings held in the Finance committees. The Legislature’s tradition, however, is that the key decisions are made in private and these late-session hearings are largely a formality, mainly a forum for advocates to make last-minute pitches for projects or programs that have been left unfunded in the capital budget. If there are big differences between the House and Senate over projects to be funded, and this isn’t yet known, the capital budget could go to a conference committee. There’s always a chance that could happen, but with time so short, Stedman and his House capital budget counterpart, Rep. Bill Stoltze, R-Chugiak, will likely try to resolve differences informally to speed things along. Stedman said there is an agreement with Gov. Sean Parnell — who can veto line items from the budget bill — for spending not to exceed about $2.9 billion, including federal funds, an amount roughly similar to what legislators approved last year in the capital budget. The senator also said there is agreement not to exceed $450 million on a port projects general obligation bond package that would appear on the state general election ballot in November. If approved by voters, the bonds would fund a variety of port projects around the state, including more work on the Port of Anchorage expansion. The port bonds authorization bill is still being worked on. Operating budget The operating budget bill is moving along smartly. The House has passed its version of the bill and the Senate approved its version April 4, which is close to the House plan that passed March 15. With this bill, which funds state agency operations, a conference committee is customary to work out differences between the bills, which appear to be relatively minor this year, said Sen. Lyman Hoffman, D-Bethel, the Senate Finance co-chair in charge of the operating budget. One difference is that the Senate is proposing $12 million for state funding for tourism promotion while the House has proposed $16 million, Hoffman said. This shouldn’t be difficult to resolve, the senator said. The Senate version of the operating budget is $22 million below Parnell’s proposal for operations spending, Hoffman said, but the bill assumes status quo in school funding, an issue yet to be resolved. Overall, the Senate has held agency operating increases to about 3.6 percent, compared to the 7 percent annual agency spending growth in recent years, Hoffman said. The governor’s proposed operating budget is about $8.86 billion, including federal funds and agency increases similar to those allowed in the Senate version of the bill. If the House agrees to increased funding for education in some form, it would add to the total in the operating budget. School, retirement funding On the school funding proposals, the House Finance Committee is still working on bills passed by the Senate that would grant a three-year, $33 million annual increase in the Base Student Allocation, a formula under which state funds are distributed to school districts. School districts around the state are pushing hard for increases in the BSA to offset inflation and higher fuel costs. House leaders are sympathetic but may want to provide targeted funding, one year at a time, rather than put an increase into the formula itself. The final form of a House proposal on school funding has yet to emerge and this will be another critical end-of-session issue to be resolved. Hoffman said the Senate operating budget also includes special appropriations to state pension funds to deal with the estimated $11 billion-plus unfunded liability for pensions to current and future public employee retirees. So far the bill provides a $500 million appropriation to the Public Employee Retirement System, or PERS, for state and municipal workers, and $500 million for the Teacher Retirement Program, or TRS, for teachers and school district workers, Hoffman said. “These are significant amounts but they are not enough to address the problem,” of the unfunded liability, he said. These amounts are likely to be increased before adjournment. There is hallway talk of the PRS appropriation being increased to $2 billion and the TRS funding to $1 billion, Hoffman said. After all the budget work is done, there is still likely to be a healthy surplus in the state treasury, both from the current fiscal year 2012 budget, which ends June 30, and projected for next year. Some of this is likely to be appropriated to the two state pension funds to deal with unfunded liability and the remainder will likely be deposited in the two state reserve accounts, the Constitutional Budget Reserve and the Statutory Budget Reserve. These funds already hold about $12 billion in liquid assets, and deposits of fiscal 2012 and 2013 surpluses would add to the reserves.

Slope producers align on LNG project

Gov. Sean Parnell announced Friday that the long-running Point Thomson litigation has been settled in an agreement featuring ironclad production requirements with North Slope producers, who also told the governor they have reached alignment on pursuing a major liquid natural gas pipeline to facilitate exports from Southcentral Alaska. “The news keeps getting better for our state,” Parnell said at a press conference at his Anchorage office. “We’re assuring significant new investment at the field, hydrocarbons into (Trans-Alaska Pipeline System) and a timetable for full-field development.” Under the settlement, the companies must be producing gas liquids from Point Thomson by the winter of 2015-16 or significant acreage at the field will automatically return to the state. The objective is to reach 10,000 barrels per day in production, Department of Natural Resources Commissioner Dan Sullivan said. The settlement also requires major infrastructure investment, most notably in a 70,000-barrel capacity “common carrier” pipeline from Point Thomson to TAPS that Sullivan said would utilize the economies of scale and open up the Eastern Slope for production. “The primary goal was to end the warehousing at Point Thomson of Alaska’s fields and get near-term commitments for production,” Sullivan said. “They must lay out a path for full production and the settlement incentivizes progress toward North Slope gas development.” Settlement of the Point Thomson litigation, which affects the 8 trillion cubic feet of gas and 200 million barrels of liquid condensates in that field, was necessary before any large gas project moves forward. Point Thomson’s reserves constitute almost one-fourth of the 35 trillion cubic feet of gas reserves identified on the Slope that could underpin a large gas project. The litigation, which has been under way for seven years and spanned three administrations, revolved around the state’s claims that major Point Thomson leaseowners ExxonMobil, BP and ConocoPhillips and Chevron did not perform on development obligations under the leases. The state had moved to void the leases. “This is clearly a win for Alaskans,” Parnell said. “Alaskans don’t win when their resources are tied up in litigation. This settlement has real work commitments, real production and real consequences.” Parnell shared the letter he received Friday from CEOs Rex Tillerson of ExxonMobil, Jim Mulva of ConocoPhillips and Bob Dudley of BP said the three companies have reached agreement on assessing the LNG export project as an alternative to the pipeline to Alberta called for in the Alaska Gasline Inducement Act, or AGIA. “A southcentral Alaska LNG approach could more closely align with in-state energy demands and needs,” the letter stated. “We are now working together on the gas commercialization project concept selection, which would include an associated timeline and an assessment of major project components including in-state pipeline routes and capacities, global LNG trends and LNG tidewater site locations, among others.” The alignment between ConocoPhillips and BP with ExxonMobil and TransCanada, the latter two companies who have been exploring the Alberta gasline under AGIA, may require a project plan amendment. TransCanada, which had $500 million worth of its expenses covered under AGIA, is currently required to file its export permit with the Federal Energy Regulatory Commission by October. Sullivan said such an amendment to delay that requirement could be done administratively with the approval of him and Department of Revenue Commissioner Bryan Butcher. The Slope companies have additional benchmarks to achieve by the third quarter of this year on the gasline project, and within the settlement is a provision that the producers can earn additional acreage at Point Thomson if they sanction an LNG project between now and 2016. If the producers don’t agree on a gasline concept before then, they will be required to increase liquids production at Point Thomson. “The agreement does not guarantee a major gasline, but moves us a significant step forward,” Sullivan said. Parnell said part of his commitment to the CEOs in exchange for their alignment on commercializing Slope gas through an LNG export project was to address natural gas taxes in the 2013 legislative session. The letter from the CEOs states, “Unprecedented commitments of capital for gas development will require competitive and stable fiscal terms with the State of Alaska first be established.” This would be the fourth time companies have worked on an Alaskan LNG project. The first, in the 1970s by El Paso Natural Gas, was intended to ship LNG to the U.S. West Coast. El Paso did not proceed with the project. The second was an effort by Yukon Pacific Corp., a subsidiary of CSX Corp., in the 1980s to build a gas pipeline parallel to the existing Trans Alaska Pipeline System and an LNG plant at Valdez, the terminus of the TAPS line. Yukon Pacific eventually dropped the project when it could not get commitments of gas supply from producers, the company said. Also in the 1980s the Alaska Natural Gas Transmission System consortium led by Salt Lake City-based Northwest Energy and Foothills Pipe Lines did extensive work on a land pipeline to Alberta following essentially the same route proposed today by Foothills and ExxonMobil. U.S. gas deregulation and the resulting gas supply glut ended the project. Following the demise of ANGTS, a third LNG effort, in the 1990s, was led by two North Slope producers, ARCO Alaska and BP, that also included a Japanese company, Marubeni and Foothills Pipe Lines (now TransCanada) that also would have had the LNG plant at Valdez. This project was dropped when the group concluded the Asia LNG market could not supply large enough quantities of gas, in competition with other suppliers, to make the Alaska project viable. As that project wound down in 1999, the producing companies, this time including ExxonMobil, turned their attention to an overland pipeline. Their work led to the current TransCanada and ExxonMobil overland project, and the competing BP and ConocoPhillips Denali project that those companies dropped in 2011.

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