Tim Bradner

Dispute resolved over gas for Southcentral winter storage

Marathon Oil and Cook Inlet Natural Gas Storage Alaska resolved a contract dispute that had threatened gas supplies for a new gas storage facility in Alaska, the companies announced late Friday. CINGSA, which operates the facility behalf of utility customers, said the dispute over a 2011 contract with Marathon had left it short of “pad” gas needed to pressurize the reservoir so that gas can be withdrawn this winter at rates customers need. In an Aug. 13 letter to the Regulatory Commission of Alaska, CINGSA said it believed the gas had been sold to export markets for higher prices. Marathon said there was no breach of the gas sales agreement, but that the company would make additional gas available to CINGSA. “I’m pleased that Marathon is able to make available additional supply from our storage,” from a Marathon-owned storage facility in the Kenai gas field that is nearby, said Wade Hutchings, Marathon’s Alaska asset manager. Marathon has already begun transferring gas to CINGSA, Hutchings said in the statement. CINGSA has a capacity to store 11 billion cubic feet of gas and is owned by Semco Energy and MidAmerican Energy Holdings. Semco subsidiary Enstar Natural Gas, the gas utility serving Southcentral Alaska, is one of three utility customers that will store gas in the new facility. Other customers are Chugach Electric Association, the state’s largest electric utility, and Municipal Light & Power, Anchorage’s city-owned utility. Gas producing fields in Southcentral Alaska are declining and can no longer supply enough gas on a daily basis at peak demand during cold weather. CINGSA built the storage facility to allow utilities to store gas for withdrawal in winter. CINGSA was 2 billion cubic feet of gas short of 7 billion cubic feet needed for pad gas by the winter, but the resolution of the dispute with Marathon will now assure that supply. “We appreciate Marathon’s offer to sell additional gas volumes that help CINGSA meet our ‘base gas’ requirements, said Colleen Starring, vice president of CINGSA. “Given the nature of the two companies’ storage facilities, these gas transfers will result in a net increase in gas deliverability for the winter peak demand period thus increasing confidence in meeting winter peak energy needs this year,” Starring said. She is also president of Enstar Natural Gas.

UAF needs $200M power plant replacement, sooner rather than later

The University of Alaska Fairbanks coal-fired power plant is almost half a century old and badly needs to be replaced soon. It’s going to be a big-ticket item, though. Preliminary cost estimates are in the $200 million range, according to Bob Shefchik, UAF’s executive officer. Permits are major concern, too, given the Sierra Club’s national campaign to shut down coal-fired power plants. The restart of the Healy Clean Coal Project, a 50-megwatt coal new-technology plant at Healy that could cut Interior Alaska electric bills by 20 percent, has been bogged down in permit issues mainly due to opposition by the Sierra Club and other groups. Shefchik hopes the UAF power plant replacement will navigate the regulatory system without opposition from environmental groups. UAF has already engaged local conservation groups on the plant, he said, but has yet to talk with the Siera Club. The new plant will be a replacement rather than a new coal plant, Shefchik said, and the newer-technology coal-burning systems to be put in place will generate less pollution than the existing plant. “That’s turn-of-the-century technology,” he said. The reference is to 1900, not 2000. The blunt fact is the university needs more power, and soon. The existing coal-fired plant has an 8-megawatt capacity and given the growth of buildings on the campus the UAF is short 1 to 2 megawatts, Shefchik said. The gap has to made up by using diesel, which can be done by the plant but it is expensive. Because the aging coal plant can’t meet the campus power demand the university has to buy 1.2 million gallons of fuel oil yearly to generate additional power and also buy electricity from Golden Valley Electric Assoc., the regional utility. The replacement plant would have a 17 to 20 megawatt capacity. Because the plant and its systems are aging there are also more breakdowns, maintenance and spot outages. Reliability is critical in Fairbanks, where winter temperatures can drop to minus-60 degrees F. As for fuel, coal is only alternative that is practical. The wind doesn’t blow much in Fairbanks, particularly in winter, so wind is out. It’s dark in winter in the Interior, so that takes out solar. All-electric would be wonderful if the proposed Watana dam is built on the Susitna River, but that’s uncertain and Watana wouldn’t be in operation until 2022 or later. Plus, the price of power would have to be 5 cents a kilowatt hour to beat coal, which is unlikely. Oil is really off the table, cost-wise. Coal costs the university $4 per million British Thermal Units. Oil costs $30 for the same amount of energy. “If we fueled with oil our annual fuel bill for the campus would rise from $8 million to $34 million a year, Shefchik said. Natural gas is a good option if there were gas, but none is yet available in the Interior that is affordable for UAF. If and when gas could come from the North Slope is unknown, and natural gas that is now trucked from Anchorage as liquefied natural gas, or LNG, is typically priced just under heating oil in cost per unit of energy. However, the advantage of natural gas, Shefchik said, is that gas turbines cost less than coal turbines and is cleaner and therefore easier to permit. A gas-fired plant might be half the cost of a coal-fired plant, Shefchik said. But there’s a risk: “No one knows when gas will be available, or what it will cost,” he said. Biomass is an intriguing possibility, but the scale of what’s needed for UAF is beyond the ability of Interior forests to provide on a practial basis. What can be done is to design the replacement coal plant boilers to be able to burn biomass as well as coal, Shefchik said. This is being done. The plant will be designed so that as much as 20 percent of its fuel could be biomass, which could include municipal waste, Shefchik said.

Alaska's delegation scolds Interior Secretary

Alaska’s Congressional delegation sent a sternly-worded letter to Interior Secretary Ken Salazar on Aug. 22 protesting the Interior Department’s selection of a preferred management plan for the National Petroleum Reserve-Alaska that would put about half the 23-million-acre reserve into special conservation areas. “The selection of Alternative B-2 in the National Petroleum Reserve Environmental Impact Statement represents the largest wholesale land withdrawal and blocking of access to an energy resource in decades,” the letter stated. Alaska Sens. Lisa Murkowski, a Republican, Mark Begich, a Democrat, and the state’s one congressman, Republican Rep. Don Young, signed the letter. In a related development, Arctic Slope Regional Corp. of Barrow, the largest private landowners on the North Slope, weighed in with additional criticisms of Salazar’s plan. “The Department of the Interior is locking up the most prospective areas for increased domestic energy supply, while proposing lease sales on tracts of land with low oil potential,” ASRC president Rex Rock said in a statement. Richard Glenn, ASRC’s vice president for lands and natural resources, said, “The alternative preferred by Secretary Salazar would restrict areas that have already been leased, where commercial potential has already been discovered. “In addition, Salazar’s choice would lock up large swaths of land with little or no additional benefit to wildlife resources found there.” The plan unveiled by Salazar in Anchorage on Aug. 13 creates special protected areas along the western coast of NPR-A, the northern coast outside of Native-owned lands and the eastern border of the reserve along the Colville River. This has created worries that not only will half the reserve be off-limits for leasing, but that it would be difficult for companies to secure corridors to build pipelines. “Given the significant new acreage put into Special and Deferral Areas in the NPR-A we do not see how the Department of the Interior could meet the stated purpose and need of the land management plan which includes the orderly development of the petroleum resources and construction of ‘necessary infrastructure, primarily pipelines and roads, to bring oil and gas resources from the Chukchi Sea to the Trans Alaska Pipeline System,” the letter from the delegation stated. However, U.S. Bureau of Land Management officials in Anchorage said the preferred alternative would allow a pipeline to come ashore and cross any of the protected lands, although there may be stipulations to provide additional protections. “There is not an inch of shoreline that a pipeline would not be able to come across,” including the Colville River protected corridor, said Jim Ducker, BLM’s coordinator for the NPR-A management plan. Ducker said there is confusion because the Alternative B in the environmental impact statement, or EIS, would indeed have blocked access from the north, although access from the west would be allowed. In the modified Alternative B-2 the land designations have changes do that there would be no impediment, although special conditions would apply, he said. Murkowski, Begich and Young are still suspicious, however, said Murkowski spokesman Robert Dillon. “The delegation sees this as creation of de facto wilderness, where we have a ‘no more wilderness’ guarantee in the Alaska National Interest Lands and Conservation Act,” Dillon said. ANILCA is the 1980 Alaska lands act that established new parks, refuges and wilderness areas in Alaska. “This is a violation of that,” Dillon said. Murkowski has previously voiced concern that if restrictions on a pipeline corridor are too costly it would encourage Shell and other companies exploring the Chukchi Sea to pursue at-sea loading in ice-strengthened tankers. An additional concern of the delegation, the letter said, is that the new preferred alternative places two new production drill sites in NPR-A, CD-6 and CD-7, within protected areas. These are discoveries in the northeast NPR-A made by ConocoPhillips and Anadarko Petroleum that are not yet developed. They would be connected by a pipeline and road to the Alpine oil field just east of the Colville River, which is on state-owned lands.

A whole lot of hydrates, potentially

Government and industry scientists say they are making good progress toward production of methane gas from hydrates, a potentially vast hydrocarbon resource. Methane is the main component of natural gas. This is still a science project, but knowledge is being gained step-by-step, researchers with the Department of Energy, the U.S. Geological Survey and industry said in interviews with the Journal. Hydrates are frozen lattice-like structures that form at shallow depths in certain combinations of pressure and temperature offshore or within onshore permafrost areas of the Arctic, including the North Slope. They are capable of holding immense amounts of methane. The question has always been whether methane can be extracted and at rates that are economical to produce. “It has been only been in the last 10 years, through drilling and coring programs, that we’ve started to get a better understanding of hydrates in their different settings,” said Tim Collett, head of the USGS hydrates program. This is giving industry more confidence that extracting resources from hydrates might be someday practical, and that it’s not some exotic form of energy, he said. Some breakthroughs now point toward ways hydrates can be produced. It’s now understood, for example, that the geologic systems that generate conventional petroleum also produce the methane that winds up in hydrates. “The factors that control the formation of petroleum traps, source rock, migration, a link to sandstone — are all the same as with conventional natural gas,” Collett said. “We know now, for example, that the methane in hydrates in the Prudhoe Bay field leaked out of the Prudhoe and Kuparuk conventional fields, as well as the Ugnu,” heavy oil field. Another accomplishment, Collett said, is that it has been shown that methane can be produced from hydrates with conventional producing wells and drill rigs. It has also been demonstrated that production can be done from hydrates in sandstone formations, which is important because sandstone has permeability, allowing the methane to flow. In contrast, scientists have yet to understand how permeability can be established in the unconsolidated clay and mud formations where most offshore hydrates are commonly found. Collett said hydrate saturations in sandstones are also typically much greater and therefore more likely to be economically produced than hydrates in the unconsolidated clay and mud.   Production tests The Ignik Sukumi test well drilled and tested by ConocoPhillips on the North Slope in 2011 and 2012 represented the third production test of methane from a hydrate, and the first to feature testing of methane production initiated by chemical injection followed by depressurization, said Ray Boswell. Boswell heads the hydrates program at the U.S. Department of Energy’s National Energy Technology Laboratory. In addition to ConocoPhillips, The Japan Oil, Gas and Metals National Corp. and the U.S. DOE were partners in the Ignik Sukumi and contributed funds. The test well produced for about 30 days. “Production was erratic at first but stabilized in the last 18 days,” which was encouraging, Boswell said. The previous sustained hydrate production was from the Mallik well in Canada’s MacKenzie Delta, which flowed about 6 days based on direct well depressurization. There were two separate production tests at Mallik done at different times, making Sukumi well the third test. Boswell said the next step should logically be a longer production test of at least 12 months to 18 months. Prior to the most recent Mallik test in 2007 and 2008, and the Ignik Sukumi well was the BP-operated Mt. Elbert test drilled in 2007 in the Milne Point field on the Notrh Slope. This wasn’t drilled to test production but to extract core samples for testing and to confirm the ability to even find hydrates through existing seismic data. An attempt to test production from a hydrate in 2003, Anadarko Petroleum Co.’s Hot Ice No. 1, also on the North Slope, failed because the hydrate that had been predicted wound up not being at the location predicted by seismic. Following that result, industry and the government agencies stepped up development on seismic procedures to better predict hydrates. The 2007 Mt. Elbert well confirmed those worked — the hydrate was where it was supposed to be, and was even thicker than was predicted. This success was demonstrated again at a larger scale in 2009 in a drilling program conducted by a Chevron group, including the DOE and USGS in the Gulf of Mexico. Gas hydrate-bearing sands were discovered in accordance with predictions in 6 out of the 7 wells drilled, Boswell said.   Commercializing hydrates Figuring out how to produce a hydrate commercially is now the challenge. Temperature and pressure are both factors in hydrate formation, and an initial thought, tested at the Mallik site in 2002, was that the hydrate could be gradually warmed to allow methane to come out, Collett said. “We looked first at thermal methods but concluded they would require a great deal of energy — you essentially heat the rock around the hydrate — so that brought us to depressurization, which is now the favored approach,” he said. Depressurization is fairly straightforward because it can be done by drilling into the hydrate and creating a lower pressure zone in the well, just as in any conventional well, said Boswell. The technique was shown to be workable in the Mallik well in Canada. One complication is that depressurization also has a cooling effect, creating a “freezeback.” Methane can flow briefly but then it freezes up again, Collett said. A solution to this might be a system to provide limited heat right at the well bore to prevent freezing, he said. More production testing will allow researchers to do the modeling needed to show the right balance. The goal is to control the thermal exchange and predict the rate of gas flow, Collett said. Meanwhile, ConocoPhillips and the University of Bergen in Norway have developed a third approach — a methane-CO2 “exchange” mechanism. The idea is to inject carbon dioxide into the hydrate so that the C02 molecules replace — and eject — the methane molecules. The well is then depressurized to enable the released gas to flow. The technique had been demonstrated in the laboratory but ConocoPhillips had been looking for a place to field-test it and chose the North Slope. What was intriguing about the exchange concept is that the CO2 molecule appears to be preferred by the hydrate over a methane molecule, said, David Schoderbek, ConocoPhillips’ manager for the Ignik Sukumi test. “This leads us to believe the carbon dioxide hydrate will be more stable than the methane hydrate,” Schoderbek said. A site for the Ignik Sukumi well was found in the western part of the Prudhoe Bay field. Several hydrate intervals were found by prior industry drilling but only one was tested, a 30-foot-thick zone at 2,200 feet. The gas mixture injected included nitrogen and CO2. The project was an operational and scientific success, Boswell said. “We injected nitrogen and C02 as planned without fracturing the formation,” he said. “On subsequent depressurization, we recovered primarily methane with production being very stable over the final two-plus weeks of the test.” Over the 30-day test, about 210,000 cubic feet of the CO2 and nitrogen mixture were injected in the two weeks prior to the flowback test, and in the following flowback test nearly 1 million cubic feet of methane mixed with some of the CO2 and nitrogen was produced. “Most of it was methane,” Schoderbek said. “We are encouraged by results but relative to these numbers it is important to remember that the actual field trial tested both exchange and depressurization.” Boswell said, “We won’t really know what the (production) mechanism was until our analysis is complete — how much of production was due to the exchange and how much from other factors. It’s encouraging but we’re still unsure just what process took place, an exchange or something else. Not all the CO2 came back, so it is likely that there was some exchange.” An initial analysis won’t be available until the end of the year or early spring, he said. The C02 exchange has possible advantages over depressurization. One is that it could preserve the hydrate structure, where depressurization essentially dissolves the hydrate. This has implications for preventing surface subsidence where hydrates are shallow, as they are on the North Slope. Also, exchanging CO2 for methane in the hydrate provides a place to potentially sequester C02. That could be important on the North Slope because the known Prudhoe Bay and Point Thomson conventional gas accumulations contain C02, which must be disposed of when commercial gas production begins. If Arctic hydrates are to be tested further the work is best done on the Alaska North Slope because of the presence of infrastructure. The Ignik Sukumi and Mt. Elbert wells were both drilled on temporary ice pads but near the all-year road systems and support facilities of the oil fields. Further testing on temporary pads is still an option the next steps will need a place with year-around access.   Whole lot of hydrates Hydrates are spread widely across the Arctic in permafrost regions, which cover vast onshore areas of Alaska, Canada’s Mackenzie Delta and Arctic Islands, and Russia. Where there are sedimentary basins, hydrocarbon source rocks and conventional oil and gas reservoirs overlain by permafrost, it’s likely that methane escaping from the conventional traps will accumulate in hydrates just below or within the permafrost, Collett said. Hydrates are found offshore on continental shelves. Although the majority of marine hydrate is found at low saturations in the unconsolidated clay and muds, substantial deposits have been discovered offshore Japan, where initial offshore production testing is expected to begin next year, and in the Gulf of Mexico during the 2009 drilling program. Collett said the understanding gained of the North Slope hydrates from the 2007 test was key to enabling the USGS to make its first assessment of technically-recoverable methane from hydrates in 2008. That assessment indicated 85.4 trillion cubic feet across the North Slope. Despite the potential, North American markets are saturated with inexpensive shale gas, which dampens the enthusiasm for U.S. producers to tackle a future source of unconventional gas, Collett said. Given that, Japan, South Korea and India, may lead the next steps with hydrates. Those countries lack domestic oil and gas and are therefore more motivated, he said. DOE and the U.S. Geological Survey hope to stay engaged. It’s probable that at least one North Slope producer would be involved if further tests are done on the Slope, however.

Ballot Measure 2 goes down by wide margin

The ballot proposition that would have reestablished a state coastal management program in Alaska was heavily defeated by voters in the state’s primary election held Aug. 28. The measure was being closely watched by natural resource industries. Had Ballot Measure 2 passed, the new coastal management program would have added new layers of complexity to permitting for projects in the coastal zone, which has been broadly defined. As of Aug. 29, data from the state Division of Elections showed that 64,210, or 61.8 percent, had voted against the measure and 39,624, or 38.1 percent, had voted for it. The count showed a total vote of 103,384. The final tally may change with absentee and challenged ballots counted, but not enough to change the result. It was a low turnout election, with about 25 percent of registered Alaska voters showing up at the polls. The measure was controversial because the program being proposed would have given coastal communities, who are opposing Outer Continental Shelf, exploration more influence over federal and state permits for projects in the coastal zone. “We’re very pleased with the vote, and we’re all sorry this even had to come up,” said Judy Brady, a former state natural resources commissioner who co-chaired the “Vote No on 2” campaign against the ballot initiative. “All of the resource development groups had supported an extension of the coastal management program through a bill the Legislature had reached a compromise on. We were very disappointed when all of the issues that destroyed the compromise were included in initiative,” Brady said. “People who believe in coastal management were told that the initiative was the same as the former program but they were given misleading information. This was in no way a fight against coastal management but was a reaction to very poorly crafted initiative that would have turned management of state resources over to a coastal policy board not elected nor approved by the Legislature.” Supporters of Ballot Measure 2, primarily municipal leaders in small coastal communities, argued that having a coastal management program would give local residents a say in federal and state decisions in coastal regions. Bruce Botelho, the chairman of the Alaska Sea Party, the group pushing for the initiative, said that while he was disappointed with the outcome of the race, he took heart in being able to raise awareness among Alaskans about coastal management and hearing from the opposition that they didn't oppose coastal management generally, just this specific approach. "I look forward to being able to work with them in fashioning a viable coastal management program," Botelho said. "Hopefully the Legislature, when it convenes in January, will see this as one of its highest priorities." Opponents to the measure heavily outspent proponents, raising about $1.5 million to defeat the measure compared with about $200,000 raised by supporters of the ballot proposition, according to reports filed with the Alaska Public Offices Commission. Alaska is now the only coastal U.S. state that does not have a coastal management program. A previous coastal management program expired in 2011 when the state Legislature did not extend it. The program required a periodic review by state lawmakers. Alaska adopted its coastal management program in the 1970s when the federal government put a national coastal zone management program in place and invited coastal states to enact state-level coastal management regimes to link with the federal program. Alaska’s program was unusual in that it was decentralized, allowing regional “coastal districts” to adopt their own plans. Other states took a more centralized approach, with the state government managing coastal management. In 2006 former Gov. Frank Murkowski changed the program to bring it more under state control, arguing that the previous program effectively gave coastal communities a form of veto over state and federal permits for projects of statewide significance.  Minerals explorers also became concerned because the reestablished program would have defined “coastal region” as including areas far inland in Alaska where developments such as mines could affect the watersheds of major streams flowing to the coasts. When the Legislature took up the possible renewal of the program in 2010, however, rural legislators pushed to have the earlier version of the program reestablished. This led to an extended deadlock on the issue through 2011, when a compromise bill agreed to between the governor and the House died after rural state senators opposed it. After the bill failed and the program ended, Botelho, Juneau’s mayor, organized the Alaska Sea Party to draft an initiative and gather signatures to put it on the ballot.

With six drill rigs at work, it's a busy summer at Livengood

FAIRBANKS — International Tower Hills Mines is continuing development planning on the company’s Livengood gold project on the Elliott Highway north of Fairbanks. Engineering and other work continues on a development plan for the mine that is now due in mid-2013. Normally, a mining company does a “pre-feasibility” study to initiate permitting, followed by a “feasibility” study following the obtaining of permits. But at its Livengood project, ITH is combining the two into one feasibility study. “This study will provide our first good look at the project we would like to take to permitting,” said Karl Hanneman, the company’s general manager for Alaska. No figures are available yet on the required capital investment, but Hanneman said it will be, “substantial.” To gather information necessary to support permit applications, ITH is doing baseline environmental monitoring and is now in its fourth year of that, said Rick Solie, ITH Community and Government Relations manager. Six drill rigs and about 85 people are working at the Livengood project site this summer on additional drilling, Solie said. Hanneman said ITH also selected 11 tons of ore samples from core last January and shipped it out for metallurgical tests, the results which will help the company design an optimal process for milling the ore to extract gold. The Livengood project is on about 50,000 acres of mining claims but the known deposit covers just a few hundred acres, Hanneman said. If it is developed, Livengood would be a large surface mine with a mill to extract gold from the mined rock. It would be similar to the Fort Knox mine that is now in production near Fairbanks, although probably larger. Recent developments In a June 21 press release, ITH board chairman Don Ewigleben said the company has postponed its district-wide exploration drilling program to focus on the development plan. However, 18 condemnation and exploration holes and additional geotechnical holes are still being completed in the “Gertrude Basin” area of the mine. The primary purpose of the condemnation program is to define site facility locations, but it also has the potential to outline additional resources immediately east of the currently proposed mining operation. “While exploration programs have been deferred this year so we can focus on the more important goal of completing a feasibility study that would greatly de-risk the Livengood project technically, there still exists tremendous exploration potential in the Livengood district,” Ewigleben said in the company’s statement. On Aug. 12, ITH announced drill results for 45 geotechnical and condemnation drill holes at the Livengood project, and assay results from four of the holes showed intersections with multiple grams of gold content. The location of the intercepts do not affect the current conceptual plan for the locations of mining-related infrastructure contemplated in the ongoing feasibility work, but they do show the potential for new discoveries in the area. Another target is potential resources below the known ore body. “Exploration holes in the Money Knob deposit were generally terminated at 200 meters to 300 meters below the surface due to limitations of the drilling technology used,” Ewigleben said in the June 21 press release. “To date, almost all the drill holes in the Money Knob have bottomed out in the gold deposit and six holes extending below the proposed pit bottom at the 300 meter depth penetrated intervals with similar gold grades to the main deposit.” Additional resources in this area, below the proposed pit bottom, may be identified by drilling done as the mining operation proceeds,” the release said. Irwin to lead project In an important personnel announcement, ITH named former state Natural Resources Commissioner Tom Irwin as Alaska vice president and president of Tower Hill Mines Inc., the U.S. operating subsidiary. Separately, Hanneman was named as the company’s Alaska General Manager, taking over the position previously held by Irwin. The appointments were announced Aug. 16. Irwin has 35 years of experience in natural resources in Alaska, Nevada and Colorado, and played a major role in the development of the Fort Knox mine near Fairbanks for Kinross Gold Corp. He also served as state resources commissioner for six years. Hanneman has 30 years of experience in Alaska mining and was regional manager for Teck Alaska during the development of the Pogo gold mine, then operated by Teck, and in the resolution of permit issues on the expansion of the Red Dog lead/zinc mine in northwest Alaska, which is operated by Teck. In one other development, ITH announced Aug. 3 that it closed a $29.6 million private equity placement to finance its continued exploration and development work. Significantly, the purchasers in the offering include existing institutional investors who are now shareholders but also AngloGold Ashanti (USA) Exploration Inc., an existing shareholder that is also an operator of major mines. “We’re very pleased that our investors are showing continued confidence in the project,” by participating in new rounds of investment, Solie said.

Drilling vessel Kulluk is now finally en route to the Arctic

Things are starting to break for Shell. The drilling vessel Kulluk is now finally en route to the Arctic from Dutch Harbor, and will arrive in the Alaskan Beaufort Sea is about two weeks, Shell spokesman Curtis Smith said. The second drilling vessel in Shell’s fleet, the Noble Discoverer, will likely depart Dutch Harbor for the Chukchi Sea on the weekend, Aug. 25 or 26, Smith said. The Kulluk departed Dutch Harbor Aug. 20. It is a conical mobile drill structure built for Arctic offshore drilling that is owned by Shell. The Noble Discoverer is a conventional drillship that has been modified for Arctic summer conditions. “Once in the Beaufort Sea, the Kulluk will remain on standby until the fall subsistence whale hunt is over,” for Inupiat Eskimo whalers, Smith said. The Kulluk is being towed by two tugs, the Guardian and the Warrior. Meanwhile, a spill response barge chartered by Shell to support its drilling is still in Bellingham, Wash., undergoing U.S. Coast Guard and American Bureau of Shipping inspections, Smith said. “We are making progress with the barge but we are still days away from sailing,” he said. Completion and final inspections of the spill response barge has been plagued by delays, partly over uncertainties within the Coast Guard and the ABS over the standards to apply to new equipment on the barge for certification, according to marine industry sources speaking on background. The barge, leased by Shell and retrofitted with spill cleanup and containment equipment, must be on station in the Arctic before Shell can drill and complete exploration wells. It would be stationed at a location between the two exploration areas in the Chukchi and Beaufort seas. Shell will have to wait until the spill barge is on location and final federal permits are issued before doing any drilling. “It’s possible we could do mud line cellar work before it (the barge) arrives. That’s something we will seek to confirm with DOI (Department of the Interior). We would not proceed without having that conversation,” Smith said. Shell hopes to have the barge on location in time to drill completed exploration wells that would penetrate hydrocarbon-bearing zones. The company also plans to drill “top holes,” or partially drilled wells, in other locations to speed the completion of the wells in 2013. There is uncertainty as to whether Shell could drill the top-holes without the spill barge, however. “The top hole well (drilling) would be continent on APD’s (Approvals to Drill permits). Whether the containment system would need to be in proximity to the rigs to drill top holes would be up to DOI. We know we can’t drill into hydrocarbon zones without the Arctic Challenger (the spill barge),” Smith said. Shell has spent over $4.5 billion on its Arctic exploration program since 2007 but has been plagued by setbacks, initially by litigation and then by a revamping of government rules following the Deepwater Horizon disaster. With the new government rules in place, Shell mobilized its fleet of two drillships and support vessels that exceed 20 ships, but was then delayed by the late breakup of Arctic ice and most recently by the inspection delays on the barge. The ice is now clearing in areas where Shell wants to drill.

Both sides of Pebble find fault with EPA study

Scientists and attorneys on both sides of the Pebble mine controversy are voicing starkly different opinions of the U.S. Environmental Protection Agency’s Bristol Bay watershed study. A panel of 12 independent scientists concluded three days of meetings on the study in Anchorage Aug. 7. A report to EPA by the group will be made late this fall, the scientists said. Bill Riley, a retired EPA mining specialist asked by Bristol Bay Native Corp. to review the agency’s assessment, said that a key challenge facing Pebble is a very large flow of wastewater, many times the volume of other Alaska mines. “There will be no opportunity for dilution, unlike all other Alaska mines, prior to discharge,” to the environment, Riley told the independent review panel. The receiving waters, where the wastewater would be discharged, have wild salmon, he said. Riley also said the annual precipitation, from rain and snow, is what will drive the water management problem at Pebble, and that there is evidence from others that the EPA review document may have underestimated precipitation by 50 percent. “The design of wastewater collection, conveyance and treatment facilities must be designed to handle extreme flows,” but the assessment document only considers average flows, Riley said. A key problem is whether, given the lack of dilution, the state standard for water quality can be achieved for water discharges at the “end of the pipe.” “Can such treatment be sustained and maintained in perpetuity?” Riley asked. Riley is very familiar with Alaska mines and their permitting requirements. At EPA he was involved in all major mines successfully permitted by the agency from 1984 to 2004, including the Red Dog, Fort Knox, Kensington, Greens Creek and Pogo mines. Another scientist weighing in was Susan Luetters, a senior environmental scientist and project manager for Bristol Engineering Services Corp., a subsidiary of Bristol Bay Native Corp. “In my professional opinion the (EPA) watershed assessment is a well thought-out and presented document with its conclusions carefully stated,” Luetters told the review panel. “It is also my opinion that EPA has underestimated the potential impacts from mining, including the direct and indirect impacts to wetlands and aquatic systems.” EPA estimates of its mine scenario impacts on wetlands were based on aerial photo interpretation of high altitude imaging in National Wetland Inventory maps and had very little, “ground-truthing,” Luetters said. Pebble Limited Partnership field studies indicated the reach and extent of wetlands in the mine area as shown in the National Wetland Inventory maps were too low. Luetters said she believes the Pebble Partnership’s own studies put the wetlands figures too low. The groundwater flow through a wetland system is “critical to maintaining water temperature, flow and chemistry which are key to supporting the benthic organisms that are major food sources for rearing salmon,” Luetters told the review panel. On the other side of this were comments critical of the EPA’s assessment. These included remarks by Michael Kavanaugh, with Geosyntec Consultants, a consulting firm. Kavanaugh was retained by Northern Dynasty Minerals to review technical aspects of the EPA assessment. Northern Dynasty is one of the mine owners, and a partner in Pebble Limited Partnership with Anglo American. Kavanaugh told the review panel that the assessment “fails to meet widely accepted quality standards that must be satisfied to produce a credible scientific and technical assessment. The report both significantly exaggerates both the probabilities of failures of all engineered mining components and the environmental consequences of these failure scenarios.” Three specific shortcomings were pointed out by Kavanaugh: • Erroneous assumptions based on literature data not relevant to a modern mining scenario, such as culvert failure statistics developed from culverts that were never permitted in the first place; • Inaccurate calculations that significantly overestimate consequences of those hypothetical system failures, such as using inappropriate geometry in a dam breach analysis, that over-predicts velocity and distance of sediment transport. • General lack of any attention to mitigation measures for all engineered systems which would be designed with appropriate safety factors, be accepted by regulators, and be designed to minimize the consequences of unlikely failure events, such as placing pipeline shutoff valves immediately before stream crossings instead of 14 kilometers away, thereby limiting the amount of material that would escape if there were a failure. In his remarks to the review panel Tom Collier, an attorney retained by Northern Dynasty, said the EPA included scenarios of possible tailings dam failures based on 135 past incidents. “Yet 126 of them involve dam construction of a type not now contemplated by Pebble,” he said. Of the remaining nine incidents, state-of-the-art technological, engineering and construction improvements have made them “irrelevant,” as examples to use, Collier said. He also criticized EPA for not considering any data from Pebble Partnership’s $120 million program to gather environmental data.

CINGSA scrambling for gas as contract dispute emerges

A contract dispute has impaired gas supplies for the new $180 million gas storage facility being developed on the Kenai Peninsula, the operator of the facility, Cook Inlet Natural Gas Storage Alaska, or CINGSA, said Aug. 20. “We are seeking to buy 2 billion cubic feet of gas,” to bring the “pad gas” needed to pressurize the storage reservoir to 7 billion cubic feet by this fall, CINGSA spokesman John Sims said. CINGSA had contracted with a Cook Inlet producer to supply gas in March 2011 but the producer may instead have opted to sell the gas to Japan as LNG for higher prices, CINGSA said in an Aug. 13 letter to the Regulatory Commission of Alaska. The producer was not identified in the letter. However, Marathon Oil acknowledged in an Aug. 18 email that it is the producer that signed a agreement with CINGSA in March 201l, but said it did not contract with the storage company on an exclusive basis and is not required to supply all of CINGSA’s base gas requirement. “We have complied fully with the terms of the agreement and will continue to do so,” Marathon spokeswoman Lee Warren said in the email. In its letter to the regulatory commission, CINGSA said the contract was to supply 3.24 billion cubic feet and that the supplier “now asserts that the contract is only an option and that it has no obligations to actually supply the gas. CINGSA disagrees with this contention,” CINGSA’s director of regulatory affairs Dan Dieckgraeff said in the letter. Alaska utilities that have contracted for gas storage and who will need the gas this winter are concerned. Gas deliverability from producing gas fields in Southcentral Alaska has declined to levels below what utilities need, and the gas storage facility, set to go into operation this winter, would have provided assured supplies at peak demand periods. Brad Evans, CEO of Chugach Electric Association, said his association, the state’s largest electric utility, is an anchor customer for the storage facility. Having sufficient pad gas to pressurize the storage reservoir is critical for Chugach and other utility customers being able to withdraw gas at rates they will need during cold weather, Evans said in an interview with the Journal. Seven billion cubic feet of pad gas is needed to provide enough pressure for withdrawals of stored gas to be done efficiently, Evans said. The facility can operate with less pad gas but its performance will not be optimal. Lee Thibert, Chugach vice president for planning, said the utility will need to withdraw about 30 million cubic feet per day this winter to meet its needs for gas-fired power generation. The storage facility, located near the city of Kenai, is designed to hold a maximum of 11 billion cubic feet. The facility has five wells for both injection and production of gas. It is located within the Cannery Loop gas field, which is operated by Marathon Oil. Besides Chugach Electric, Anchorage’s city-owned Municipal Light and Power, Chugach Electric and Enstar Natural Gas, the regional gas utility, are CINGSA customers. CINGSA is owned by Enstar’s parent, Michigan-based Semco Energy, and Mid American Energy Holdings. Sims said that besides the 2 billion cubic feet needed for pad gas for CINGSA, Enstar itself has not yet secured all the gas it needs for 2013. Most space heating for homes and buildings in Southcentral Alaska is done with natural gas. CINGSA is a regulated storage facility and must report any changes that will affect its operation to the state regulatory commission, which prompted the Aug. 13 letter. Marathon said it cannot export LNG itself, according to Warren its spokeswoman. “Marathon sold its interest in the LNG plant in 2011, and we no longer have an export license. We honor our contractual obligations and during peak demand have helped meet the energy needs of customers in Southcentral Alaska. The terms of our contracts are confidential,” she said. ConocoPhillips Alaska, which operates the LNG export plant at Kenai, said it cannot comment on the matter. ConocoPhillips is reported to occasionally purchase gas for LNG from other producers, and holds a federal license for export shipments of LNG from Alaska. The dispute has prompted a strong reaction from Alaska government leaders. “While this is a contractual dispute that will have to be worked out in the courts, I am disappointed that a company would let Alaskans down at the time when their energy security is most in question,” said state Rep. Mike Hawker, an Anchorage Republican who sponsored legislation leading to creation of the storage facility, in a statement issued late Friday. “I support free market principles that allow those with a commodity to sell it at the highest price they can. However, there has long been an informal understanding between Cook Inlet producers, utilities and the state that local needs must be met. I am deeply disappointed that a producer would disregard what I see as a responsible corporate citizen’s obligation to the people of Alaska.” However, Rep. Les Gara, D-Anchorage, said he and six other Democratic legislators tried in 2010 to get Gov. Sean Parnell to seek explicit assurances that local gas needs would be met in the most recent renewal of the federal license allowing exports of LNG from the ConocoPhillips plant in Kenai. Parnell declined to do so, despite the fact that his predecessor, Gov. Sarah Palin, had succeeded in getting the local-needs language in a 2008 LNG federal export permit for the plant, Gara said. Parnell never gave a detailed answer as to why he would not seek the language other than to say he had assurances from ConocoPhillips that local needs would be taken care of. “We want to be clear that we supported the permit and LNG exports because if a large gas discovery is made in Cook Inlet the discoverer has to have a market. We just wanted local needs met,” Gara said.

Gold find adds 1.2M ounces at Pogo

FAIRBANKS – Drilling crews are busy on new exploration this summer at the Pogo gold mine near Delta, east of Fairbanks. It is the biggest exploration season since the mine opened, says Lorna Shaw, external affairs manager for Sumitomo Metal Mining, which owns and operates the mine. Efforts this summer are focused on defining the new “East Deep” discovery, a gold ore deposit discovered last year that is near the main Pogo ore body. The new discovery has added an estimated 1.2 million ounces of new gold resources to Pogo, a major increase from the current 2.6 million ounces of reserves. There could be more gold, too. ”East Deep has very high potential and we’ve really only touched part of it. We’re looking for the limits this summer,” Shaw said. The discovery is not likely to result in increased production but would instead extend the operating life of the time. This summer, three drill rigs are at work drilling from the surface and three rigs are drilling from underground locations in the mine, testing the East Deep deposit. Sumitomo plans to do 94,000 feet of exploration drilling this year, with 86,000 feet drilled from the surface and 8,000 feet drilled underground. Last year the company did 79,672 feet of exploration drilling. In other developments, Pogo reached a milestone recently in exceeding the two-million-ounce production threshold. The mine produced 325,708 troy ounces of gold in 2011, a bit below the annual production average of 350,000 ounces to 380,000 ounces in recent years. Typically, 2,545 tons of ore per day are mined and processed at Pogo. Based on the current reserves the mine is expected to operate through 2019, but with new discoveries like East Deep the mine life could be extended. Pogo employs 335 workers directly and there are about 150 contractor employees at present, Shaw said. Bed space at the camp is tight this summer. “We have 376 beds on site and we are near capacity this summer,” Shaw said. “Making sure there is room for everyone, with increased construction and exploration, can be a bit of a jig-saw puzzle.” Sumitomo is now building added camp capacity, with 79 new beds, that will be available by the end of the summer, Shaw said. In operations, Pogo experienced high turnover rates among its employees after the mine first started in 2007, but turnover is now reduced to levels that are normal for the industry, Shaw said. “Things have stabilized, but it’s still an issue,” the company is concerned about, she said. “Experienced underground miners tend to be transient,” Shaw said, because there is a high demand for them. The company likes to hire in Alaska, but the Alaskan recruits tend to come in with entry-level skills for undergoing mining. Underground crews must all include some experienced miners. “We can’t have an underground crew with all entry-level people,” she said. Sumitomo is considered several ideas in training including possible programs with the University of Alaska Fairbanks similar to those operated by in Juneau by University of Alaska Southeast for the Greens Creek and Kensington underground mines. Pogo is the only operating underground mine outside of Southeast Alaska except for the small Nixon Fork mine near McGrath. Other producing mines like the Fort Knox Mine near Fairbanks, the Usbelli coal mine at Healy and the Red Dog Mine north of Kotzenue, are surface mines. While the skill sets for miners in underground and surface mines are different – surface mines require experience and skill in operating heavy equipment – many jobs are similar in the mines, such as operators in the ore processing mills, mechanics, maintenance and other support people, Shaw said.

Natural gas for Southcentral storage facility may be Japan-bound

A contract dispute has impaired gas supplies for the new $180 million gas storage facility being developed on the Kenai Peninsula, the operator of the facility, Cook Inlet Natural Gas Storage Alaska, or CINGSA, said Aug. 20. “We are seeking to buy 2 billion cubic feet of gas,” to bring the “pad gas” needed to pressurize the storage reservoir to 7 billion cubic feet by this fall, CINGSA spokesman John Sims said. CINGSA had contracted with a Cook Inlet producer to supply gas in March 2011 but the producer may instead have opted to sell the gas to Japan as LNG for higher prices, CINGSA said in an August 13 letter the company wrote to the Regulatory Commission of Alaska. The producer was not identified in the letter. Marathon Oil acknowledged in an Aug. 18 email that it is the producer that entered into the sales agreement with CINGSA in 2011, but said it did not contract with the storage company on an exclusive basis and is not required to supply all of CINGSA’s base gas requirement. “We have complied fully with the terms of the agreement and will continue to do so,” Marathon spokeswoman Lee Warren said in the email. In its letter to the regulatory commission CINGSA said the contract was to supply 3.24 billion cubic feet and that the supplier “now asserts that the contract is only an option and that it has no obligations to actually supply the gas. CINGSA disagrees with this contention,” CINGSA’s director of regulatory affairs Dan Dieckgraeff said in the letter. Alaska utilities that have contracted for gas storage and who will need the gas this winter are concerned. Gas deliverability from producing gas fields in Southcentral Alaska has declined to levels below what utilities need, and the gas storage facility, set to go into operation this winter, would have provided assured supplies at peak demand periods. Brad Evans, CEO of Chugach Electric Association, said his association, the state’s largest electric utility, is an anchor customer for the storage facility. Having sufficient pad gas to pressurize the storage reservoir is critical for Chugach and other utility customers being able to withdraw gas at rates they will need during cold weather, Evans said in an interview with the Journal.   Seven billion cubic feet of pad gas is needed to provide enough pressure for withdrawals of stored gas to be done efficiently, Evans said. The facility can operate with less pad gas but its performance will not be optimal. Lee Thibert, Chugach vice president for planning, said the utility will need to withdraw about 30 million cubic feet per day this winter to meet its needs for gas-fired power generation. The storage facility, located near the city of Kenai, is designed to hold a maximum of 11 billion cubic feet. The facility has five wells for both injection and production of gas. It is located within the Cannery Loop gas field, which is operated by Marathon Oil. Besides Chugach Electric, Anchorage's city-owned Municipal Light and Power, Chugach Electric and Enstar Natural Gas, the regional gas utility, are CINGSA customers. CINGSA is owned by Enstar's parent, Michigan-based Semco Energy, and Mid American Energy Holdings. Sims said that besides the 2 billion cubic feet needed for pad gas for CINGSA, Enstar itself has not yet secured all the gas it needs for 2013. Most space heating for homes and buildings in Southcentral Alaska is done with natural gas. CINGSA is a regulated storage facility and must report any changes that will affect its operation to the state regulatory commission, which prompted the Aug. 13 letter. Marathon said it cannot export LNG itself. “Marathon sold its interest in the LNG plant in 2011, and we no longer have an export license. We honor our contractual obligations and during peak demand have helped meet the energy needs of customers in Southcentral Alaska. The terms of our contracts are confidential,” Warren said. ConocoPhillips Alaska, which operates the LNG export plant at Kenai, said it cannot comment on the matter. ConocoPhillips is reported to occasionally purchase gas for LNG from other producers, and holds a federal license for export shipments of LNG from Alaska. The dispute has prompted a strong reaction from Alaska government leaders. “While this is a contractual dispute that will have to be worked out in the courts, I am disappointed that a company would let Alaskans down at the time when their energy security is most in question,” said state Rep. Mike Hawker, an Anchorage Republican who sponsored legislation leading to creation of the storage facility, in a statement issued late Friday. “I support free market principles that allow those with a commodity to sell it at the highest price they can. However, there has long been an informal understanding between Cook Inlet producers, utilities and the state that local needs must be met. I am deeply disappointed that a producer would disregard what I see as a responsible corporate citizen’s obligation to the people of Alaska.”

Barge, not ice, now delays Shell's Arctic drilling program

Pity Shell. If it’s not one thing, it’s another. For five years the company has been trying to drill exploration wells in the Arctic offshore. First there were lawsuits. Then permits delays after the Gulf of Mexico offshore well blowout in 2010. Then Arctic sea ice. Now, a barge delay. Interior Secretary Ken Salazar seemed to take the company to task in an Aug. 13 press conference in Anchorage. “It’s not the ice,” the Secretary said. “It is Shell’s delay in completing (inspections) of its response vessel.” The company has had difficulty in getting final inspections completed on an Arctic oil spill response barge. Ice conditions at Shell’s prospect site appear good. Salazar said he flew out over offshore waters from Barrow over the weekend and over the Burger prospect that is Shell’s initial target, and found the area free of ice. However, there was still heavy sea ice in waters north of Barrow, the Secretary said. The response barge is still in a Pacific Northwest shipyard, meanwhile. “This is the world’s first Arctic containment system, and there are a number of major systems that have recently been completed,” Shell spokesman Curtis Smith said. “These systems must now be thoroughly inspected, deployed and certified. It’s a process that takes time and one that can’t be rushed. “The barge is not new but all of the ‘topsides’ including separating systems, fire suppression systems, modules, and living quarters, are brand new and state of the art.” Salazar is holding the company to the requirement to have the spill barge in the Arctic. “Shell must demonstrate that it can meet regulatory requirements with its oil spill containment system. If it can’t meet them there won’t be a Shell program this year,” Salazar said in the press conference. “The Deepwater Horizon is a stark reminder,” of the need for strengthened rules on drilling and preparations for spills, Salazar said. “I will hold their feet to the fire on the standards we have set.” Under the Interior Department rules, Shell must have the spill response barge in the Arctic and in position between the areas Shell will drill in the Chukchi Sea and the Beaufort Sea. Once the barge completes its U.S. Coast Guard and American Bureau of Shipping inspections it will take 12 to 18 days to move the barge to Arctic waters, Shell said previously. “We’re running out of time,” Salazar said. The company has only until Sept. 21 to complete the drilling of exploration wells in the Chukchi Sea although it has longer in the Beaufort Sea. All operations must cease by Oct. 31. “It’s a dynamic situation for Shell. I have not heard if the company has an alternative plan, but if they do we would consider it,” Salazar said. The deadlines apply only to wells completed to hydrocarbon-bearing zones. The company plans also to drill “top holes,” or partially completed wells, in preparation for completion of the wells in 2013. Most of the Shell drilling fleet is still in Dutch Harbor but Smith said the company has deployed two support vessels to the Chukchi Sea drill sites. The Aiviq, an icebreaker anchor-handling vessel, is on site deploying anchors for the Noble Discoverer, Shell’s drillship. The Fennica, another support vessel, is nearby installing hydrophones to do subsurface acoustic recordings, Smith said. Salazar said he was less concerned now, however, about an oil spill from one of Shell’s exploration wells because of the rigor of new rules put in place. He is more concerned, he said, about the needs for new infrastructure in the Arctic if Shell or other companies are successful, and about funding for the U.S. Coast Guard to provide security and rescue services in the region. The Coast Guard now has a limited presence with two rescue helicopters stationed in Barrow this summer, but there is a dramatic increase in all types of vessel traffic in the Arctic this summer, and that is a concern, Salazar said. “There were 30 research vessels in the Arctic this summer and many of them are still there, as well as cruise ships offering adventure tours,” the Secretary said. “China also has a significant presence in the region this year. They are taking a look at the region.” Earlier this summer Salazar noted the presence of a Chinese icebreaker in the Arctic this summer. That the U.S. has not yet ratified the Law of the Sea treaty, which would give it influence beyond the 200-mile Exclusive Economic Zone limit “is a terrible shame,” the Secretary said. Shell has spent more than $4.5 billion in its Arctic program so far and no drill-bit has yet turned. The company’s recent efforts began in 2007 when a 20-ship Arctic drill fleet was mobilized for the Beaufort Sea and then stopped by environmental lawsuits. Those were resolved – the U.S. 9th Circuit Court of Appeals ultimately approved Shell’s exploration plans unanimously – but the company meanwhile lost three summer drill seasons. Then the Deepwater Horizon disaster hit in the Gulf of Mexico, and the federal government suspended all offshore exploration until new rules where in place including the requirement for oil spill containment systems Shell is now struggling with. Ironically, Shell and other companies have previously explored Arctic offshore waters with no accidents, and in the same locations where wells are now planned. In the early 1990s Shell drilled at the Burger prospect in the Chukchi Sea, its prime target for 2012, and found natural gas and indications of oil. The discovery was not economic at the time, and the company abandoned the leases, as did other companies that had also drilled. Shell and others also explored in the Beaufort Sea in the 1980s and 1990s, and Shell made several near-shore discoveries including Northstar, a field now owned and being produced by BP. In the eastern Beaufort Union Oil of California (now Chevron) and ARCO Alaska drilled offshore test wells and made discoveries, also then uneconomic. Two discoveries, Hammerhead by Union Oil and Kuvlum by ARCO, were made near Shell’s targets in the Beaufort Sea. Shell has acknowledged good prospects in the areas, and said that its 2012 drilling is aimed at proving up the commercial potential.

Delegation slams NPR-A plan; greens pleased

Interior Secretary Ken Salazar announced Aug. 13 he has chosen a preferred alternative for a land management plan for the 23-million-acre National Petroleum Reserve, although details of the plan remain sketchy. The newly-proposed “Alternative B-2” management plan would open 11 million acres of the reserve to oil and gas leasing but would also place 13 million acres in special conservation areas, Salazar said. Details of the new alternative aren’t yet available, but state of Alaska officials aren’t happy about it. “We’re still looking at it but off the cuff we have significant concerns about what they are trying to lock up,” state Natural Resources Commissioner Dan Sullivan said. “The petroleum reserve is supposed to be for oil and gas.” An overriding concern, Sullivan said, is that the state wasn’t given any advance notice of the new alternative. “We are not brought in as a participating entity. It seems like they consult more with the Center for Biological Diversity (an environmental group) than they do with the legally-elected state government,” Sullivan said. What reinforced Sullivan’s belief is that the Wilderness Society and National Audubon Society issued press releases minutes after the Department of the Interior announcement, an indication that the groups were informed in advance of the action. A major concern in the pending NPR-A plan is whether a pipeline crossing would be allowed across NPR-A to bring any oil discovered in the Chukchi Sea to the Trans Alaska Pipeline System. In his press conference, Salazar said a pipeline corridor would be allowed although the specifics of a route must await an application from industry. A pipeline crossing of a special use area or other industry will be subject to special stipulations to protect the uses of the special areas, the Secretary said. “Our plan will not foreclose a pipeline, but when one is proposed it will have to go through the full regulatory process including an environmental impact statement,” the Secretary said. The Interior Department has been considering several alternatives for managing the reserve, one an Alternative A continues the status quo; a second, more environmentally restrictive Alternative B that establishes large special conservation areas; an Alternative C that is less restrictive, and an Alternative D that essentially opens all of the reserve to oil and gas development. Until Monday the department had not selected a preferred alternative. The new B-2 plan is now the preferred one, Salazar said. It combines elements of the other plans, but Salazar did not provide details Aug. 13 in Anchorage. The preferred alternative will now be incorporated into a final environmental impact statement for the NPR-A. The EIS is expected to be finalized in November and the Record of Decision, the final step, in December, U.S. Bureau of Land Management Director Bud Mike Pool said at the briefing. “In the next few weeks we will be meeting with the state of Alaska, the North Slope Borough and other concerned Alaska stakeholders to go through the details,” Salazar said. U.S. Bureau of Land Management spokeswoman Ruth McCord said the agency is still working out details of the preferred alternative, but a lot of information is provided on the BLM Alaska website. Alaska’s congressional delegation was quick to criticize the plan. Sen. Lisa Murkowski said: “The administration has picked the most restrictive management plan possible. The environmentally-sensitive Teshepuk Lake area was already under a 10-year deferral for additional study, but this (new) alternative goes vastly beyond that, putting half the petroleum reserve off limits. The decision denies U.S. taxpayers both revenue and jobs at a time when our nation faces record debt and unemployment,” Murkowski said in a statement. In his statement, Rep. Don Young said: “While this administration is touting today’s announcement, it’s crucially important for us to see the details, especially since it appears this is simply a minor revision of an older plan that places many areas off limits while also designating new areas as so called ‘Wild and Scenic Rivers.’ This is unacceptable and as long as I’m in Washington, D.C., these recommendations will never see the light of day.” Democratic Sen. Mark Begich was less harsh than his Republican colleagues, but said, “I am very concerned about this choice by the Department of the Interior. The new preferred alternative still seems to close off several options for building a pipeline across the NPR-A.” Begich continued, “We’ve known since the beginning that a pipeline across the NPR-A is a critical piece of the puzzle for successful Arctic development. I was pleased by Secretary Salazar’s statement that the United States cannot be left behind in the Arctic. However, today’s decision creates many more questions than answers about how we are going to get billions of barrels of oil from the Chukchi Sea into TAPS.” Conservation groups praised the alternative, however. “If adopted, the preferred management strategy would protect the calving grounds of the Teshepuk Lake and Western Arctic caribou herds,” the Wilderness Society said in a statement issued Aug. 13. “Essential nesting habitat for thousands of shorebirds, molting habitat for geese, and coastlines used for walrus haul-outs and polar bear dens would not be developed under this plan.” The Audubon Society voiced similar sentiments. “The Secretary’s plan shows that Americans can protect nature even on lands designated for energy production. It would be a great victory for birds, wildlife and common sense,” Audubon president David Yarnold said in the statement.

Reviewers say EPA's Pebble study needs work

Scientists reviewing a U.S. Environmental Protection Agency assessment of a potential large copper and gold mine in an environmentally sensitive area near Iliamna Lake said Aug. 8 that the agency’s draft watershed assessment needs work, and should not be based on hypothetical mine scenarios. Some of the scientists said the agency is too pessimistic in its assessment of risks. The EPA asked 12 scientists to review its Bristol Bay watershed assessment last May as an independent review panel. “As a risk assessment, I would like to see more ‘bracketing’ of the scenarios and performance. This assessment goes more toward the pessimistic outcomes. I’m not comfortable with how it is put together,” said Dirk van Zyl, of the University of British Columbia, one of the scientific reviewers. Another reviewer, Steve Buckley of WH Pacific, agreed: “I would like to see a broader range of potential impacts,” he said. Most of the scientists, however, agreed EPA’s document is still a good start toward a risk assessment and that the proposed Pebble mine does pose risks. The panel held three days of meetings in Anchorage Aug. 7 to Aug. 9. There were comments from the public Aug. 7, including the mine developers, with discussion Aug. 8 among the scientists themselves, but in a session that was open to the public. The scientists continued discussions Aug. 9 in closed-door sessions. Final recommendations by the panel to the EPA won’t be completed until later this year, said its chair, Roy Stein of Ohio State University. Anglo American and Northern Dynasty, working through a joint-venture company, Pebble Limited Partnership, have identified more than 10 billion tons of ore containing copper, gold and molybdenum at a site near Iliamna Lake southwest of Anchorage. The mine, still in a preliminary planning stage, is controversial because it would be in a watershed of rivers that support salmon spawning. This has prompted fierce opposition from sports fishing groups like Trout Unlimited and Alaska Native communities around Bristol Bay, where salmon fisheries are important. In the Aug. 8 public discussions by the scientists, most of the review panel said the assessment was incomplete. “I see this as a screening-level assessment, a good start in identifying areas where additional information is needed,” said William Stubblefield, of Oregon State University. Paul Whitney, a wildlife ecology consultant based in Portland, Ore., agreed: “This is good as a screening study but it’s incomplete, for one reason that it looks at all wildlife impacts from the perspective of fish only.” The interactions are really much more complex, he said. “We know the scenarios were taken from those developed early by Northern Dynasty Minerals for investors,” and that there are alternatives, said David Atkins, a scientist with Watershed Environmental and a member of the review board. “There are many ways this mine can be developed, and it may be that a smaller mine will be permitted. But the components are still there, an open pit, tailings disposal and all the infrastructure that will be needed. “The scenarios in the assessment document are plausible at a gross level, but how they would be implemented is unclear.” Buckley, of WH Pacific, agreed: “I don’t feel the scenarios are sufficient. Three or four in addition would be helpful.” Dirk van Zyl said the scenarios were not realistic but that he also doesn’t see any regulatory agency as having the appetite to permit or a financial institution to fund a 78-year mine. “A 30-year mine, yes,” he said. Buckley highlighted another shortcoming in that the importance of surface water and groundwater in sustaining habitat were discussed in the assessment but that there was little about how the two are connected in the area where the mine would be developed. Phyllis Weber, an ecology consultant with Scannell Scientific Services, said, “The assessment has provided a good overview but it’s incomplete. More is needed on the specific habitats including how marine nutrients are distributed.” Charles Slaughter, of the University of Idaho, said the assessment is incomplete because it does not address the full range of future developments that would result from the Pebble mine, including other mines. “The assessment gives short-shrift to that,” Slaughter said. “There will be a lot more affected that by the footprint of this one mine.” In a separate comment, Slaugher said the EPA failed to reference work that other federal agencies have done, including studies by the U.S. Bureau of Land Management in the 2005 BLM area plan, which closed parts of the region to mineral entry. “That’s not even mentioned,” by EPA, Slaughter said. More scenarios needed Some on the panel said the assessment needs more “bracketing” with scenarios across a wider range of possibilities. The scenarios chosen appear more pessimistic outcomes, they said. Stein, the panel chair, said he felt the assessment needed a discussion of climate change effects, which will occur over a project like Pebble that could produce for a century. He also said he was gravely concerned about the size of the mine and that water from the mine area will need treatment in perpetuity. That was mentioned in EPA’s assessment in three places, Stein said. “We have no example today of a mine with very long-term treatment of water,” he said. “I am very concerned that the promises of today’s mine developers may not carry forward to future mine operators.” John Stednick, of Colorado State University, said the mining industry’s treatment of water goes back to the mid-1980s. “We’re talking about something that could be producing acid drainage for 40,000 years,” he said. Mining companies traded publically have only recently been noting the financial liability of maintaining long-term water treatment in their financial statements. One that Stednick is aware of is Teck, which noted liabilities stretching to 120 years in its 2010 and 2011 statements. Steve Buckley, of WH Pacific, said the Red Dog Mine near Kotzebue, although smaller than Pebble, is valuable to look at as an example of a mine with water treatment operating in an upland Arctic environment. Stein said he is concerned whether there will be sufficient long-term oversight of the project by government agencies. The mine is on state lands, so the primary regulatory responsibility is with the state of Alaska. “Will the state be able to appropriate funds sufficient for oversight and monitoring?” he asked. Tailings dam There was also discussion among the scientists of the scenarios of catastrophic failures of the tailing dam. Dirk van Zyl questioned whether the scenarios of failures laid out in the assessment are representative of facilities being built today. The practice now is to establish independent tailings dam review boards to oversee regulatory procedures and monitoring. “I do not know of a failure at any facility where such a review board was put in place,” he said. “The failure likelihood (in the EPA assessment) is overstated.” There was disagreement about that, however. Paul Whitney, another of the reviewers, said he was aware of sediment transport as far as 600 miles downstream after problems developed at hydroelectric dams in British Columbia. “A sediments transport study should be required to understand the impact of a dam failure in this environment,” he said. Phyllis Weber said she is less concerned about catastrophic failures of the tailing dam than low-level seepages over extended periods. “There could be seepage from pit walls, or waste rock that is not quite as benign as thought. This is a problem that should be addressed.” Stednick, of Colorado State, said the higher altitude and cold climate of the Pebble region may make post-mine reclamation difficult. “Restoration will take a very long time and we’re talking about more than the mine, but road corridor as well. This is multi-generational,” Stednick said. However, Paul Whitney, a consultant and a member of the review panel, said there are many examples of reclamation using modern techniques, and that the EPA’s assessment relied on outdated examples. “Why use the older examples? We’ve moved forward,” Whitney said. Off-site mitigation for any restoration that cannot be done in the mine area could be difficult. “Is mitigation even possible? This is a large pristine area, and it will be difficult to find enough non-pristine areas to bring back,” said Paul Whitney. Whitney also pointed out, however, that the area may not be as pristine as it first appears. “If 70 percent of the organic nutrients go to fish that are harvested, is the area really ‘pristine’?” he asked. “If that is the case, could one way to accomplish mitigation be to restrict commercial fishing,” of salmon spawned by the streams in the Pebble area. Whitney said he is concerned about the loss of marine nutrients in the uplands of the watershed, where the mine would be located. He said there should be more focus on this, and that the Alaska-based marine scientists with the university and the state have done a lot of work on the loss of marine nutrients in ecological systems. Developers satisfied The mine developers were generally pleased with the direction the panel appeared to be taking. “They clearly heard our message Tuesday (Aug. 7),” during public comments, said Thomas Collier, an attorney working with Northern Dynasty Minerals. “Seven out of the 12 opening remarks (in the Aug. 8 open session) indicated the panel members don’t see how a risk assessment can be done using only hypothetical assumptions.” Several of the scientists said the EPA assessment is more of an initial screening study rather than a true risk assessment, which involves a much more detailed review. “That is the correct way to view this document,” Collier said. Collier said he doesn’t believe the assessment is sufficient to support a preemptive veto of the Pebble project under the Clean Water Act 404(c) action. “It’s likely they will just throw it back into the normal process,” where a formal environmental impact statement is done after the mine developers apply for permits with details of an actual project. Pebble spokesman Mike Heatwole said the developers are at least a year away from finalizing the proposed mine design and permit applications. One the permits are applied for a formal environmental impact statement process will begin, he said.

In a deal with the EPA on emissions, TOTE will convert to LNG

Totem Ocean Trailer Express Inc., or TOTE, will convert its two large ocean cargo vessels to use liquefied natural instead of conventional bunker fuel, the first such conversion for large general cargo vessels in the U.S. maritime industry. Liquefied natural gas tankers, such as those that call at ConocoPhillips’ LNG plant at Kenai, have used LNG as fuel for years but general cargo and other marine vessels have been fueled by conventional bunker fuel and diesel. TOTE’s decision is part of an agreement with the U.S. Environmental Protection Agency on a waiver for TOTE from new emissions requirements that went into effect Aug. 1. The waiver will exempt TOTE from the requirements until September 2016, to allow the conversion of the company’s two Orca-class cargo vessels, TOTE president John Parrott said Aug. 6. TOTE operates the vessels on scheduled service from Tacoma, Wash., to Anchorage, a distance of 1,400 miles each way and 2,800 miles round-trip. They are both 840 feet in length. The ships will be able to carry enough LNG in on-board tanks to make a round-trip from Tacoma, Parrott said. “Our two vessels are already the ‘greenest’ ships in the U.S. domestic fleet,” Parrott said in separate statement. “When they were delivered in 2003 they were purpose-built to serve the Alaska market and exceeded all regulatory and environmental standards. Post-LNG conversion, the Orca vessels will again set a new standard for environmental responsibility.” EPA imposed the new rules requiring use of low-sulfur fuels effective Aug. 1 on ocean shippers and cruise ships in an Emissions Control Area that extends from the U.S. west coast to Alaska and 200 miles offshore. The requirement is for vessels to use fuel with no more than 1 percent sulfur as of Aug. 1, and 0.1 percent sulfur after 2015. Parrott said the estimated capital cost of for conversion of both vessels is $80 million. Each vessel has six engines, four main engines and two auxiliary engines. TOTE has signed a preliminary agreement with an LNG supplier but Parrott said he could not identify the firm at this time. The plan calls for a small gas liquefaction plant at the Tacoma port, and for the LNG to be delivered to the ships by barge. “The shoreside LNG infrastructure planned to support the new fuel systems will help other transportation industries in Puget Sound follow TOTE in converting to LNG. This could result in a significant increase in air quality throughout the Puget Sound region,” Parrott said. Parrott said the use of LNG as fuel will not affect the operations of the ships, including their speed and schedules to and from Alaska. The vessels are rated to cruise at a 24-knot speed but typically operate at about 22 knots on average. TOTE currently uses a heavy high-sulfur fuel in its two vessels. Prior to the LNG agreement the company had planned to use a blend of its heavy oil with ultra-low sulfur diesel made by refiners for trucks and heavy equipment onshore to meet the requirements. The blending would have required special handling by fuel suppliers and would have added about 25 percent to fuel costs, Parrott said in a previous interview. That would have translated to about an 8 percent increase in general freight rates. Parrott could not estimate how the capital cost of the LNG conversions could affect rates because capital costs are handled differently than operating cost increases, such as those for the higher fuel costs had the special fuels been required. It cannot be assumed that a capital cost will increase rates, Parrott said. As an example, when TOTE made the $320 million investment in the two new ships there was no significant change in rates, he said.

Suit over Arctic spill plan will test agency standards

Environmental groups filed a lawsuit July 10 in an Alaska federal court against the U.S. Bureau of Safely and Environmental Enforcement over the agency’s standard of review in approving Shell’s oil spill cleanup plans for exploration drilling planned this summer in the Chukchi and Beaufort seas. The action isn’t intended to stop Shell but rather to force the BSEE to adopt a tougher standard in reviewing future spill plans filed if Shell is successful, according to Michael LeVine, Pacific senior counsel for Oceana, one of the plaintiffs. Other plaintiffs include Greenpeace, the Alaska Wilderness League, the Sierra Club, Earthjustice, the Center for Biological Diversity, Natural Resources Defense Council, Audubon, Ocean Conservancy, Pacific Environment, and Resisting Environmental Destruction on Indigenous Lands, or REDOIL. LeVine said the case in important because it would be the first legal test of the spill cleanup provisions in the Oil Pollution Control Act of 1990, which are linked to standards in the Clean Water Act. “OPA ‘90 requires offshore facilities like drilling rigs to have spill response plans that comply with standards in the Clean Water Act. The CWA standards require operators to be able to recover and remove oil from a ‘worst case’ discharge to the maximum extent practicable,” LeVine said in an interview. “Shell’s oil spill response plans claim the ability to remove 95 percent of spilled oil, which we know cannot be accomplished based on experience with the Macondo well in the Gulf of Mexico and the Exxon Valdez spill in Alaska. “We feel the BSEE did not adequately test Shell’s assumption, and also allowed the company to preposition shoreline cleanup equipment based on the assumption that 95 percent of the spilled oil would be recovered at sea,” through equipment like the undersea well-capping device Shell will have on hand and offshore skimming systems, LeVine said. The Oil Pollution Act of 1990 requires holders of offshore leases to have approved oil spill response plans. The law also amended the federal Clean Water Act to require federal agencies to enact regulations that require spill plans to demonstrate the ability to “respond, to the maximum extent practicable, to a worst case discharge, and to a substantial threat of such a discharge.” Federal regulations say the term “worst case discharge” means, “the largest foreseeable discharge in adverse weather conditions.” The spill plan submitted by the operator, in this case Shell, must show that resources are on hand to deal with the spill. Shell’s Chukchi Sea spill plan assumes a worst-case discharge of 25,000 barrels a day, based on what is known about reservoir conditions at the “Burger” prospect the company will drill. In the Beaufort Sea the worst-case discharge is assumed to be 16,000 barrels per day at the prospect Shell will drill. The plan essentially assumes that 90 percent of the oil will be captured by Shell’s subsea containment system, which would result in 10 percent escaping to the open ocean and drifting with wind and currents. In the case of the Chukchi Sea, this would be about 2,500 barrels per day. About half of this would be captured by ocean skimming and containment systems, leaving about 1,250 barrels per day drifting toward shore, where Shell would have shoreline cleanup crews and equipment. The assumptions are similar at Shell’s “Sivulliq” prospect in the Beaufort Sea, where again 90 percent of the “worst case” spill of 16,000 barrels of oil per day is expected to be captured by the containment system, leaving 1,600 barrels per day escaping to the sea. Again, half of this is expected to be recovered by at-sea skimmers, leaving about 800 barrels per day drifting toward the shore. The new lawsuit joins several other actions pending in the Anchorage U.S. District Court, before judge Ralph Beistline. Among these are actions filed by Shell earlier this spring asking the court to grant approval to the spill plans and other federal approvals prior to any lawsuit being filed. The BSEE approved Shell’s Chukchi Sea plan last Feb. 12, and the Beaufort Sea plan on March 28. In the lawsuit, the environmental groups claim Shell’s cleanup assumptions are too optimistic, and that BSEE should not have approved the plans without greater scrutiny. The BSEE’s own internal studies say mechanical skimming efforts typically recover 5 percent to 30 percent recovery in the open ocean without ice being present. Recovery rates drop to 1 percent to 20 percent when ice is present, the agency’s study concluded, according to the lawsuit. Experience with large oil spills has been similar. After the Exxon Valdez spill in 1989, subsequent research found that 8 percent of the oil spilled was recovered. In the 2010 Deepwater Horizon spill in the Gulf of Mexico only 3 percent of the oil was recovered. The suit also cited offshore response exercises by Alaska Clean Seas, the industry’s North Slope spill cooperative, that showed that offshore mechanical recovery systems like skimmers lose their effectiveness at 10 percent ice coverage and, during the fall “freeze-up” at ice coverage as low as 1 percent. Levine, Oceana’s attorney, said these recovery rates do not square with what Shell has put in its spill plans, and that BSEE’s approval of them amounts to a “rubber stamping.” Beistline has not yet ruled on those requests but did turn down a motion by the environmental groups including Oceana to throw out Shell’s suits.

Great Bear drilling first North Slope shale test wells

Great Bear Petroleum is now drilling its first North Slope test well to assess potential for production of oil from shale formations in the region, similar to the way oil is being produced in the Bakken and Eagleford shale formations of the Lower 48 states. The company’s first well is now being drilled about 15 miles south of the Prudhoe Bay field on the North Slope, said Ed Duncan, Great Bear’s president. The first core samples were taken July 1. “We intend to take cores from three shale formations the well will penetrate,” Duncan said. Duncan said it will take about three more weeks for the well to reach its planned target depth of about 10,500 feet. Great Bear will then move its rig, Nabors 105, operated by Nabors Alaska Drilling Co., to a second location about three miles farther south. Drilling will continue to move farther south, Duncan said. “Our plan is to drill four wells this year and we believe we can achieve at least three,” he said. The company will also do a multi-stage fracturing of the shale to test the flow of oil, Duncan said. Normally, North Slope exploration wells are drilled in winter on ice pads but Great Bear is working this summer using previously-built gravel pads adjacent to the Dalton Highway, a road connecting oil fields in the area to Interior Alaska. Halliburton, the oil services giant, has joined Great Bear as a partner in the North Slope shale test but Duncan declined to describe the natural of the companies’ relationship. He did say Halliburton is “participating” in the current tests but that Great Bear, an Alaska-based independent company, is the operator of the project. The shale formations being tested by Great Bear are the source rocks for the large conventional oil fields a few miles north, including the giant Prudhoe Bay, Kuparuk, Alpine and other fields that are now producing. Great Bear’s belief is that there is a substantial amount oil left in the rocks. If the 2012 tests of the shale are successful, Duncan said the plan for 2013 is to drill several wells in a production pad along with a pilot processing facility. Oil produced would be shipped to Prudhoe Bay by truck and injected into the Trans Alaska Pipeline System. Bob Swenson, Alaska’s state geologist and director of the Division of Geophysical and Geological Survey, said he believes substantial amounts of oil remain in the source rocks. Paul Decker, chief of the resource evaluation section in the state Division of Oil and Gas, said in a recent presentation that Great Bear must test the brittleness of the North Slope shale to see whether it will fracture like shales in the Bakken and Eagleford, and also test the permeability of the rock, and how easy fluids can flow. There are high hopes for Great Bear and its experiments with shale oil. If it works, it could lead to a major shale oil development across an east-west “fairway” of lands across the central North Slope, through an area south of the Prudhoe Bay and Kuparuk fields. Conceptually, what Great Bear is planning, if the tests are successful, are gravel pads with several producing wells on each pad spaced several miles away and connected with roads and pipelines. Potentially the development could be very large, requiring several pads and roads. One unknown is whether the traditional high costs of the North Slope will make shale oil development uneconomic, however.

BP again delays development of Liberty field

BP has deferred development of the small Liberty field in the Beaufort Sea northeast of the Prudhoe Bay and Endicott fields, this time indefinitely. The company would give no timetable on when the project could be developed. BP spokeswoman Dawn Patience said June 29 that technical problems with the company’s plan to produce the field with ultra-extended reach production wells drilled from shore have caused the company to revamp the project after an 18-month review of the development plan and a heavy drill rig was built to drill the wells. “Our review showed that the project cost would be substantially higher than the $1.5 billion we had estimated, and that it would take several years longer to complete,” she said. Liberty has estimated reserves of 100 million barrels and is five miles offshore in shallow water. If developed, BP believes it would produce about 40,000 barrels per day at peak, Patience said. The current plan, now on hold, is to drill extended-reach wells to the reservoir from a satellite gravel production island that is part of the Endicott field, which is two miles offshore and connected to shore by a gravel causeway. The wells that were planned would be as long as eight miles in horizontal departure from the drill rig, and set world records, BP has said previously. The specialized, special-purpose rig for the Liberty project has been constructed and is now on the North Slope at the Endicott field production island. BP owns the rig but it was built by Parker Drilling Co. Patience said discussions are under way with several companies who were involved with the rig, but those are confidential. BP and other companies had hoped that development of Liberty with wells drilled from shore would demonstrate that capability and possibly open other near-shore deposits to development using similar techniques. Other options for developing Liberty will be discussed with federal and state regulatory agencies, Patience said. A decade ago BP developed a similar small offshore field west of Liberty, the Northstar field, with an artificial gravel island and a subsea pipeline to shore. Northstar, which is six miles offshore at Prudhoe Bay, has been in production since 2001, but with Liberty BP had rejected the artificial gravel island approach because Northstar wound up costing more and taking longer to build than expected. One reason for the delays at Northstar was the extraordinary scrutiny by regulatory agencies because it was the first true offshore production island in the Arctic. Federal and state agencies, and the North Slope Borough, are very sensitive to any oil production installation built in the ocean because of worries of problems with ice and an oil spill. The Endicott field, built in 1986, is technically an offshore field but it is close to shore, about two miles out, and water depths are so shallow, two to five feet, that there is virtually no moving ice present in winter. Northstar, however, was a first because its production island was built beyond the protective barrier islands along the northern Alaska coast, so that the island is fully exposed to winter icepack movement and summer storms. Another first was the construction of the first buried subsea oil pipeline, and although the distance was short – six miles – there were still concerns about gouging of the sea bottom by the “keels” of heavy packice that extend down in the water. In the last 10 years, the island and the pipeline have withstood those natural forces, however. Liberty is almost the same distance offshore as Northstar but is in a more benign ice environment because of barrier islands further offshore which block the heavy polar icepack. There is mostly stable “shorefast” ice at Liberty’s location.

Alaska officials cautious on Court ruling

Gov. Sean Parnell and state Health and Social Services Commissioner Bill Streur are cautious in their assessment of effects on Alaska of the U.S. Supreme Court’s 5-4 ruling on the federal health insurance reform act. “The federal health care act will be implemented. The Supreme Court said so. But we do not intend to see Alaska saddled with costs,” Parnell said in a press briefing June 28, the same day the court’s decision was announced. The court upheld a basic tenent of the federal Patient Protection and Affordable Care Act, a requirement that individuals purchase health insurance, but struck down a section requiring states to expand Medicaid coverage to cover more lower-income people or suffer penalties. A number of states are saying that, given the choice, they will resist expanding Medicaid rolls because of added expense to state budgets that are already hard-pressed. Parnell said he is still undecided. Alaska can afford the expansion, for now, but the governor and Streur are focused on the longer term, with continuing declines in oil production and state oil revenues. Streur said that if the state decides to expand coverage, adding an estimated 36,000 lower-income Alaskans to state Medicaid rolls in 2014, the federal government would pick up most of the cost. However, administration of the program, the enrolling of new people and the processing of the claims, would be paid for under the existing Medicaid program of which the state pays 50 percent. It will probably be a number of months before a decision is made on expanding Medicaid, Parnell and Streur said. Even if the state pays only a small part of the cost, “this is still real money,” Streur said. Parnell said he is also concerned about the federal government continuing to pay the larger shares of the cost of expanded Medicaid coverage, given the government’s longer-term financial situation. Alaska has already seen the federal government reduce funding from 60 percent of the program costs to 50 percent, Parnell said. Another decision that will have to be made is whether to implement a state version of a health insurance exchange in 2014. The Affordable Care Act requires the creation of exchanges, which will be web-based systems intended to help people find more affordable insurance, but gives states the option of creating and running their own exchange instead of having an exhange created by the federal government. Parnell said the state has contracted with a consulting firm to study the creation of a state exchange that would be fine-tuned to Alaskan conditions but said the consultant’s report is being finalized and that he hadn’t seen it. The governor also said it is possible the state may decide not to create the exchange, and just let the federal government do it. One of Streur’s concerns, expressed previously, is the health condition of people who would be added to Medicaid rolls in 2014. These are people in lower-income ranges who are now just above the level at which they would be covered or are single males, who are mostly not now eligible for Medicaid. Many of these people may be coming into the program with untended health issues, which could lead, to a short-term spike in utilization and costs Reactions from Alaska’s political leaders generally took on a partisan tone, with Parnell and Alaska’s U.S. Sen. Lisa Murkowski, both Republicans, focusing on the individual health insurance mandate and its noncompliance penalty being interpreted by the Supreme Court as a tax. Alaska’s Democratic U.S. Senator Mark Begich pointed out the benefits of the act, such as the ban on denials of insurance for pre-existing conditions. For their part, Parnell and Murkowski agreed the law has some good points, including the extension of insurance coverage. “There are benefits to individuals who have not had health coverage before,” the governor said. “But this is also about who pays the benefit and whether it can be sustained. If there are less costly ways to do this, we will explore them.” Murkowski said she will work with other Republican senators in efforts to repeal the federal health care law or change parts of it. Parnell said he would like for the law to be altered to give states more flexibility on the administration of Medicaid, so that lower-cost options can be explored. States are already given some latitude to pick specific services that will be paid for by Medicaid as well as the reimbursement rates for health care providers. Because it is a wealthy state Alaska has always had a relatively generous suite of services paid for by Medicaid in comparison with other states, and also reimbursed health providers at rates higher than the reimbursement rates of most other states. Streur has said previously that Alaska’s higher rates of reimbursement for Medicaid helps ensure that Medicaid patients get care, while in many other states Medicaid patients have difficulty getting care because of the low reimbursements. Insurance companies generally support the new law, but express reservations. “Federal health care reform will significantly expand access to coverage in 2014. We believe that’s a good thing. Yet, the law unfortunately does little to address the critical issue of rising medical costs, which remains the largest driver of the rising cost of health care coverage, Premera Blue Cross, a major provider of health insurance in Alaska, said in a statement.

ExxonMobil gears up as Point Thomson probe continues

ExxonMobil is gearing up to resume work this winter on the Point Thomson natural gas cycling and liquid condensate project, but state legislators are continuing to scrutinize the settlement the state reached with the company and its partners over a long-standing dispute. The Senate Judiciary Committee held a hearing on the settlement June 12 and on June 22 Democrats in the state House weighed in with a detailed letter to State Natural Resources Commissioner Dan Sullivan raising questions on certain points in the agreement. The settlement resolved a long-standing dispute over failure of ExxonMobil and its partners, which include BP, ConocoPhillips and previously Chevron, to perform on previously-agreed work obligations, mainly drilling. The state had moved to reclaim the leases, triggering lawsuits from the companies. Chevron has since sold its interest to ExxonMobil. At the June 12 hearing, Senate Judiciary chairman Sen. Hollis French, D-Anchorage, said that the committee needed to look at the settlement as to any precedents it would set or whether there could be unintended consequences. “We’re not questioning the legality of the settlement, but whether this deal negotiated in secret with Exxon is in the public interest,” French said. The letter written June 22 and signed by nine House Democrats, led by House Democratic leader Rep. Beth Kertulla, D-Juneau, raised questions over differences in timelines between the settlement and the Point Thomson Plan of Development, and on possible “loopholes” in the agreement. Kerttula is a former natural resources attorney in the state Department of Law. One line of questioning by French and others on the Judiciary Committee was whether the state administration had adequate authority to agree to the Point Thomson settlement, which has multi-billion-dollar ramifications and also affects the taking of the state royalty from Point Thomson, without legislative approval. Legislative attorney Don Bullock, as well as the state Attorney General Michael Geraghty, said that there is authority for the executive branch to settle lawsuits, even with high dollar values. Bullock said there is a clear separation of powers between the legislative and executive branches that includes settlement of lawsuits by the attorney general, but that there have been cases where the executive branch voluntarily agrees to legislative approvals. Approval of the Alaska Gasline Inducement Act contract negotiated with TransCanada Corp. is an example of that, Bullock said. French also questioned the settlement agreement’s definition of a “major gas sale” as one with more than 500 million cubic feet per day of gas, which is different than the definition of a major gas sale in the Prudhoe Bay Unit agreement, which is 1.7 trillion cubic feet of gas per day. “I’m looking for mousetraps,” in the agreement, French said. State Deputy Resources Commissioner Joe Balash told the committee that the number was chosen because it corresponded to the limit of 500 million cubic feet per day for an in-state pipeline that was in the state’s AGIA contract with TransCanada. The major gas sale is an event in the settlement that would allow ExxonMobil and its partners to retain leases on the gas field. Alternatives for the companies to the major gas sale include agreement to expand the gas cycling and condensate project that is now under construction, or producing and transporting Point Thomson gas 60 miles by pipeline to the Prudhoe Bay field, where it could be used to re-pressure that field and produce more oil. French and others legislators said they were puzzled by the 500 number, and still not satisfied with Balash’s explanation, because the amount of daily gas production needed for a gas pipeline and liquefied natural gas project, Gov. Sean Parnell’s goal, is much larger, 2 billion cubic feet a day or more. “I’m just suspicious that they (the companies) are putting one over on us,” French said at the hearing. In his presentation, Balash responded to questions raised earlier in the spring by Mark Myers, a former Division of Oil and Gas director, about loss of condensate liquids if gas production were allowed prematurely at Point Thomson. Myers felt the gas cycling and condensate project needed to be much larger and more robust than small project being built now or even an expanded project provided for as an option in the settlement. Balash replied that recent technical studies done by the Department of Natural Resources indicate that the loss of condensate liquids will not be as serious a problem as once thought, and that the studies relied on by Myers were outdated. “There will be significantly less liquids lost,” than earlier forecast, Balash said. French asked him for a way the statement could be independently verified, but Balash said the more recent analysis was by consultants to the DNR and the work was confidential. The earlier studies relied on by Myers was public, in contrast. In the House Democrats’ letter to Sullivan, questions were raised about the broad definitions of “forces beyond the control” of the field owners that could block the state’s attempts to regain the acreage if the goals of the agreement were not met. “One such ‘force’ is described as ‘circumstances addressed by Section 25 of the Point Thomson Unit Agreement.’ Since we do not have access to the Unit Agreement, this appears to be broad enough to give us concern,” the letter from Democratic representatives stated. A more fundamental criticism is that the actual work obligations in the settlement, and the specific schedules, are much more limited than activities described in the Point Thomson Plan of Development for the leases, a plan the DNR approves. However, there are few timelines or schedules in the Plan of Development, the Democrats’ letter said. The project now under way at Point Thomson will involve the production of natural gas and the “stripping,” or separation, of the condensates, a natural gas liquid. The gas is to be injected back underground and the liquids would be transported by pipeline to the Trans-Alaska Pipeline, where they will be mixed with crude oil and shipped to market.


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