Tim Bradner

Exploration, expansion strategy at Pogo will extend mine life

The Pogo gold mine, near Delta east of Fairbanks, keeps growing. More gold is being found, and it’s sufficient to replace what is being produced each year. “Our strategy is based on steady production and sustainability,” said Lorna Shaw, spokeswoman for owner and operator Sumitomo Metal Mining Pogo. So far there seems no limit to how far gold-bearing quartz veins might extend around the present mine. The company keeps finding more gold. “The current mine life is planned through the first quarter of 2019 but we are confident that will be extended,” she said. The company is a venture of two Japanese companies, Sumitomo Metal Mining Co., at 85 percent, and Sumitomo Corp., at 15 percent. The mine is about 85 miles east of Fairbanks and is northeast of Delta, with 50-mile private road connecting Pogo with the Alaska Highway. Sumitomo Metal Mining operates and maintains the road.  Pogo produced 337,393 troy ounces of gold in 2012. Production in 2014 is expected to be about the same, Shaw said.  In 2012, the mine reserves were listed at 13.6 million short tons of ore with an average gold grade of 0.366 ounces per short ton, with an estimated gold content of 4.97 million ounces. The mine began producing from the Leise zone, the first ore zone developed, in 2008, and from a second nearby deposit, East Deep, in 2013. This year another ore deposit, North Zone, is being explored although it is not yet producing. Two exploration “drifts” or tunnels, have been built into the North Zone to allow its deeper sections to be explored, and also to explore for gold mineralization between East Deep and North Zone. The drifts provide access and serve as a platform for exploration drilling done underground. Additional gold veins are being discovered, and explored, at North Zone and it is possible that this gold, now classed as “resources” could become “reserves,” a more strictly-defined category, by the end of the year, according to information provided by the company. Pogo is spending $17 million on exploration this year although $5 million of that is for the two underground drifts for North Zone and the North Zone-East Deep connection, Shaw said. The company’s overall 2014 capital budget is more than $30 million, including improvements to surface facilities as well as the exploration. Pogo is also exploring “South Pogo,” a mineralized area south of the ore zones now producing. A drift, or tunnel, has been built to South Pogo to support the underground exploration drilling there and two helicopter-supported drill rigs are conducting surface drilling this year. Gold resources at South Pogo are likely to be converted to reserves by the end of 2014, just as at North Zone, the company said. Another nearby deposit of gold mineralization, the “4021 area” has also been identified although it is some distance from the areas now being produced. The company not doing exploration this year so as to focus efforts on targets nearer the existing production, but the presence of 4021 indicates that the mineralization extends at least that far. “Eventually we will get there as we expand in that direction,” Shaw said. Pogo has an active construction program this year including an expansion of the mine water treatment plant and construction of a new underground adit, the “2150” that will provide additional ventilation to the underground mining areas as well as an alternative for vehicle access. The “portal” or entrance has been completed and work on the adit has been advanced 2,200 feet to date, Shaw said. “It is not yet connected to the existing tunnels, but it is getting close,” she said. On the water treatment plant, the excavation is completed and contractors have done the back-fill. “Currently we have permits that allow us to process up to 600 gallons per minute but our existing plants don’t allow us to treat more than 540 gallons per minute,” Shaw said. The expansion, which will span two years, will provide additional capacity. Rainy weather in Interior Alaska this summer has slowed some of the surface construction work, Shaw said. The general contractor on the project is M2C1 of Delta with several subcontractors including T&D, of Fairbanks. The company currently employs 314 with about 100 seasonal contractors. Although Pogo is not within a municipality it regularly makes donations to the nearby City of Delta, including $360,000 volunteered in June to help the city purchase new fire-fighting equipment, Shaw said. Fifteen of Pogo’s employees live in Deta and four live in Tok. Two hundred and twenty seven of Pogo’s 314 employees live in 24 Alaska communities, Shaw said.

Fort Knox gold output dips, but will still be top producer

The Fort Knox gold mine near Fairbanks is likely to keep its place as the state’s No. 1 gold producer in 2014. The mine, northeast of Fairbanks, is expected to produce 390,271 ounces of gold in 2014, including 245,286 ounces from the mill at the mine and 144,985 ounces from a heap leach processing facility also at the mine. Gold production in 2013 was 421,641 ounces. In comparison, the state’s No. 2 gold producer, the Pogo underground gold mine east of Fairbanks, produced 337,000 ounces of gold in 2013 and will produce a similar amount in 2014. Fort Knox employs about 630 people, the vast majority who live in Fairbanks and commute daily to the mine. Fort Knox mines a gold ore that is low grade, so large volumes of ore must be mined and taken to the process facilities to extract the gold. In 2013 about 63 million tons of rock were mined, a daily average of 173,000 tons. The figures are from the mining company’s presentation last March at the Alaska Miners Association annual Fairbanks conference. Of the ore that was mined, 14 million tons were processed in the mill at the mine, a facility that uses a mechanical equipment to crush ore that is supplemented with a chemical process to extract gold. An additional 33 million tons of ore were placed on the heap leach, a facility that involves a controlled circulation of a cyanide solution to extract gold. Fort Knox began producing in 1996 with its first gold “pour” in December that year. Last December the mine reached the 6 million-ounce mark in gold production. Fort Knox is proud of its safety record, with 1.8 million hours worked with no lost-time incident at the time of the March presentation. Operating the mine takes a vast fleet of equipment, including three 35 cubic-yard “shovels” and one 24-cubic yard shovel; three 24-cubic yard Caterpillar 994 loaders and one 16-cubic yard Caterpillar loader; 19 240-ton haul trucks; 9 190-ton haul trucks; 10 150-ton haul trucks; seven specialized drllls for drilling blast holes, and miscellaneous equipment including tracked bulldozers, rubber-tired “dozers,” graders, water trucks, excavators and loaders. Running the operation and providing fuel and power requires a large budget, with $54 million spent in 2013 for fuel, for about 40,000 gallons used per day; $43 million spent for electricity, and about $120,000 per day purchased from Golden Valley Electric Assoc., the Interior power cooperative. The mine also uses about 33 tons of explosives per day to break up rock for mining, 21 tons per day of grinding balls to crush ore (the balls wear out), and 31 tons of lime per day as part of the gold-extraction process. Fort Knox paid $5.2 million in property tax to the Fairbanks North Star Borough in 2013 and about $18 million in state taxes and fees, according to the March presentation.

Pipeline consortium files LNG export license application

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

Clock stopped for Shell in Chukchi Sea

The clock is ticking on Shell’s Outer Continental Shelf leases in Alaska’s Beaufort Sea. A large number of the company’s leases are set to expire in October 2017, federal officials said, although the leases on Shell’s two top prospects, Sivulliq and Torpedo, have been extended to July and October 2019. Meanwhile, the U.S. Bureau of Ocean Energy Management, or BOEM, has stopped the clock on federal offshore leases held by Shell, ConocoPhillips and Statoil in the Chukchi Sea due to an ongoing lawsuit. The Chukchi Sea has been Shell’s top priority in the Alaska OCS since 2013. ConocoPhillips and Statoil only have leases in the Chukchi Sea, and not the Beaufort Sea. Shell drilled two partially-complete exploration wells in 2012, one in the Chukchi Sea and one in the Beaufort Sea, and had planned to return to both exploration areas in 2013 until the specialized drilling vessel Shell used in the Beaufort, the Kulluk, was damaged in a grounding near Kodiak in December 2012. The Kulluk had been designed for Beaufort Sea conditions and had been given air quality permits by the U.S. Environmental Protection Agency. Partly because it lacked a suitable vessel that had its permits, Shell put the Beaufort Sea on the back-burner for its proposed 2013 drilling, and focused on the Chukchi Sea. The company was unable to return to the Chukchi for the 2013 and 2014 open-water drilling seasons because of pending new federal regulations on drilling. OCS leases have 10-year terms and the Chukchi Sea sale was in 2008, but the lease clock for all three companies with leases in the Chukchi has been frozen until BOEM completes a supplementary environmental impact statement, or SEIS, for the 2008 Chukchi Sea OCS Sale 193, according to U.S. Bureau of Ocean Energy Management officials. The revamp of the original environmental impact statement for the sale was challenged in court by environmental groups who argued the assumed size of a discovery, and the size of a possible oil spill, were underestimated in 2008 by the U.S. Minerals Management Service, the predecessor agency to BOEM. The agency is now redoing the estimates. A draft SEIS is expected this fall and a final document by next March, BOEM has said. “All of the Chukchi Sea leases, including the (Shell) Burger prospect, were put into suspended status. This status will remain in effect until the Bureau meets its obligations to correct the Sale 193 EIS consistent with the U.S. Ninth Circuit’s opinion and the direction of the (federal) district court,” said a BOEM official, who asked not to be identified because of agency procedures. The revamp of the 2008 EIS, the more recent development, was ordered by a U.S. District Court judge in Anchorage after the U.S. Ninth Circuit Court of Appeals agreed with the environmental plaintiffs. The U.S. Mineral Management Service had originally used an assumption that a 1 billion-barrel discovery could be made in the Chukchi, and further assumptions on a possible oil spill were based on that. Environmental groups said the figure was too low, and that the assumptions for the oil spill were also too low. With the standard 10-year term leases sold in Sale 193 would have expired in August 2019. The new expiration date is unknown and will not be established until the SEIS is issued and approved, the BOEM official said. The delay in drilling Shell’s top prospects in the Beaufort Sea has implications for Alaska. Oil from any discoveries in the Beaufort could be brought ashore to bolster Trans-Alaska Pipeline System, or TAPS, oil “throughput” much more quickly than oil from any Chukchi Sea discoveries. The Sivulliq and Torpedo offshore prospects are in the eastern Alaskan Beaufort Sea about 15 miles north of the Point Thomson onshore oil and gas development east of Prudhoe Bay. A pipeline to shore could be built more quickly than a 60-mile Chukchi Sea pipeline to shore, and once ashore the Beaufort Sea oil could be shipped to TAPS through the existing Point Thomson and Badami liquids pipeline. Chukchi Sea oil, once ashore, would still require a new pipeline across the National Petroleum Reserve-Alaska to the TAPS line. It would take more than a decade for Chukchi Sea oil, once drilled and discovered, to be brought into TAPS, state officials have said. Beaufort Sea oil, once discovered, could possibly be brought to TAPS in about half the time, they said. Getting more oil into TAPS is important because TAPS throughput has been declining to the point that there could be operating problems during very cold winter conditions. More oil volumes, no matter from what source, will ease these. Also, although OCS oil pays no royalty or production tax to the state of Alaska it indirectly increases state revenue because the higher volumes in TAPS lowers the pipeline’s per-barrel tariff for shipping oil. Since that applies to all oil shipped in the pipeline it results in a higher value of oil from state leases on the North Slope, resulting in higher royalties and production tax payments.

Production decline erased in first year under oil tax reform

What have the North Slope producers done since Senate Bill 21 passed the Legislature? They’ve ramped up drilling and ended a 24-year decline in North Slope oil production, that’s what. As recently as last December the state estimated a 4.4 percent decline for this year. That’s now history. The companies have also announced $8.5 billion in new projects that could add more than 100,000 barrels per day in new oil over the next eight years. This is in addition to $5 billion in new projects, mainly the Point Thomson gas project east of Prudhoe Bay and the CD-5 oil project near the Alpine field, that are already underway. But for now — and most important immediately — production from the North Slope fields will result in about the same amount of oil this year as last year. The decline will have essentially stopped, at least for this year. For the fiscal year 2014, production averaged 530,939 barrels per day compared to average production for the previous fiscal year of 531,639 b/d. The state fiscal year runs from July 1 through June 30. Were it not for typical summer maintenance that reduced output by about 40,000 barrels per day in June compared to May, production would have exceeded the prior fiscal year. The figures are subject to adjustment, said Cherie Neinhuis, a petroleum analyst with the state Department of Revenue, but the data indicates the state ended the 2014 fiscal year on June 30 with North Slope output roughly on par with the previous year. This is a significant achievement because the average decline in production has been about 6 percent per year in recent years and was 8 percent between 2012 and 2013, according to the Revenue Department data. A lot of new projects are being announced, but the real action, for now, is in big producing fields, the “legacy” Prudhoe Bay, Kuparuk River and Alpine fields, where the companies have ramped up drilling and “workovers” of wells. All of this has happened since the Legislature passed SB 21 in April 2013. ConocoPhillips and BP, the two major North Slope field operators, have added four drilling rigs to their operations. BP decided to add two rigs before the tax change was made, spokeswoman Dawn Patience said. However ConocoPhillips’ two rigs were added after the tax change, said Scott Jepson, ConocoPhillips’ vice president for external affairs. BP will have two additional rigs working by 2016, Patience said. The best way to add new production, and to sustain it, is to get more rigs drilling wells, said Jepsen. “If you want to see real progress, get more rigs working. New projects will enhance production at the margin but to really sustain production, new oil has to come from the legacy fields and drilling more wells is the best way to achieve that,” Jepsen said. Jepsen said one of the two workover rigs put to work mainly repairing older wells has so far resulted in 3,000 barrels per day of new production. That rig went to work in mid-2013. Production results from the second rig, which was started up this spring, are not yet available because it has been drilling new wells that are not yet hooked up. BP has also increased its well work aimed at stimulating new production by 20 percent this year and has increased its spending on this kind of work by 40 percent, Patience said. The company is doing “rate-enhancement” projects on 500 wells this year, an increase of 100 from last year. When rigs are drilling new production wells in the fields, the added production can be significant. Ed King, an economist with the state Department of Natural Resources, said in a previous interview that each working drill rig on the North Slope typically completes six new producing wells a year, and each new well can add 800 to 1,000 barrels per day of new production. It’s a rule of thumb, King said, because each drilling situation is different. Also, some drill rigs work on workovers as well as new wells. Drilling and working over wells in the legacy fields can add production relatively quickly, Jepsen said. The uptick in production over the last year, reversing the production decline, illustrates that. What is most important, Jepsen said, is that the bulk of the remaining known undeveloped oil resources of the Slope that are known are actually within the currently producing fields. That is about 4.5 billion barrels out of 5 billion barrels in total of known resources. The companies have also announced new North Slope projects since SB 21 was passed, and those are also significant. Projects announced by ConocoPhillips alone could add 40,000 barrels per day to production by 2018, Jepsen said, although those are subject to final approval by the company’s board in December. This includes the new Drill Site 2S and North East West Sak project in the Kuparuk field and GMT-1 in the National Petroleum Reserve-Alaska. BP is also working on its large Prudhoe Bay west-end development project that could add another 40,000 barrels per day after 2018, the company has said. Other companies are at work also. Brooks Range Petroleum, a small independent company, intends to have its small Mustang field in production in 2016 producing 8,000 to 10,000 barrels per day and increasing in 2017 to about 12,000 barrels per day, company officials have said. Caelus Energy, the new owner of the Oooguruk field, plans to develop Nuna, a satellite to the existing field, with preliminary construction beginning this winter. Nuna could produce between 15,000 and 20,000 barrels per day, Caelus has said. Repsol, a major company, is exploring in the Colville River delta area near the Alpine field and has made new oil discoveries. The company is now engaged in evaluating the discoveries and is doing environmental and engineering studies for possible development, although that has not been announced. Tim Bradner can be reached at [email protected] Fiscal year   Average Daily North Slope Production barrel Decline year-to-year 1987   1,890,722.90     1988*   2,004,100.85   6.00%   1989   1,951,480.25   -2.63%   1990   1,827,459.59   -6.36%   1991   1,803,828.65   -1.30%   1992   1,772,916.98   -1.70%   1993   1,733,269.74   -2.20%   1994   1,660,158.31   -4.20%   1995   1,597,542.75   -3.80%   1996   1,482,354.56   -7.20%   1997   1,363,355.41   -8.00%   1998   1,242,900.58   -8.80%   1999   1,108,183.66   -10.80%   2000   995,446.18   -10.20%   2001   978,701.94   -1.70%   2002*   1,001,875.47   2.40%   2003   982,739.43   -1.90%   2004   970,375.86   -1.30%   2005   908,189.04   -6.40%   2006   837,142.49   -7.80%   2007   732,208.25   -12.50%   2008   714,447.75   -2.40%   2009   692,706.41   -3.00%   2010   642,540.89   -7.20%   2011   599,919.03   -6.60%   2012   579,357.64   -3.40%   2013   531,639.15   -8.20%   2014   530,939.03   -0.13%   *Increase Note: FY 2014 is preliminary data, subject to change, based on 11 months of  finalized data from monthly production off-take report and June  derived from daily run tickets. Source: Department of Revenue, July 1

State, producers, TransCanada agree on gasline engineering

The North Slope gas producers, pipeline company TransCanada Corp. and the State of Alaska signed a long-awaited agreement July 2 to jointly fund preliminary engineering for a large-diameter North Slope gas pipeline and large liquefied natural gas export plant at Nikiski. “Environmental and pipeline engineering fieldwork has officially begun,” Gov. Sean Parnell said in a statement. “I am pleased all parties continue to make progress on building an Alaska gasline project that will create thousands of Alaska jobs and fuel Alaska homes and businesses.” Costs of the overall project, which would export 15 million to 18 million tons per year of LNG, have been estimated at $45 billion to $65 billion. However, the Preliminary Front-End Engineering and Design, or pre-FEED, process that has now begun will produce an updated cost figure. Under the Joint Participation Agreement that has been signed, parties engaged in the project agreed on how to share costs of the pre-FEED, which will involve expenditure of several hundred million dollars and will take about a year to complete. Updated costs are expected to be available in late 2015, state officials have said. State legislators who worked to pass the enabling legislation for state participation in the pipeline also expressed optimism. “I am very encouraged by this LNG opportunity for Alaskans,” said state Sen. Cathy Giessel, R-Anchorage. “Affordable gas, abundant job opportunities and prospering families — it’s bright future.” Sen. Anna Fairclough, R-Eagle River, said, “We are another step closer in this long process to deliver affordable energy to Alaskans. I appreciate the collaboration and hard work by all parties to move this important project forward.” However, Bill Walker, former Valdez mayor who is running for governor against Parnell as an independent, dismissed the signing as “another study.” “This pre-election announcement is nothing more than electioneering at its worst and risks the future of this state. It places control in the boardrooms of Houston, London and Calgary where decisions will be made that are best for these companies and their shareholders,” Walker said in a statement. Walker has supported a state-built pipeline that should be in construction now. “Alaskans are rightfully concerned that we are entering into another doomed study while the market opportunities continue to pass us by,” Walker said. The deal was expected to be signed by June 30, but concerns expressed by ConocoPhillips delayed the signing until July 2, according to sources familiar with the negotiations. BP, ExxonMobil, TransCanada and the Alaska Gasline Development Corp., a state corporation, had agreed earlier on the joint-funding arrangement. ConocoPhillips is now pleased with the agreement, company spokesman Natalie Lowman said. “The signing of the JVA (Joint Venture Agreement) brings the state, through AGDC, into the project as a full participant. This is a significant milestone,” she said. Parnell said work will now also begin on preparations to secure an LNG export license from the U.S. Department of Energy and on permits needed from the Federal Energy Regulatory Commission. “Each producer party, in addition to the state, will begin to engage the LNG sales market,” Parnell said in his statement. Primary markets are expected to be in Asia. If the project is built, it could be in operation in 2024. It would be one of the world’s largest LNG export projects, state officials said. The overall project is structured so the three producers and TransCanada will own the large gas treatment plant planned for the North Slope and the 800-mile, 42-inch pipeline that would be built to Southcentral Alaska. The state, through its Alaska Gasline Development Corp., or AGDC, has an option to acquire 40 percent of TransCanada’s interest in the pipeline and treatment plant, but the option must be exercised in 2016, according to the state’s agreement with the pipeline company. For the large LNG plant planned at Nikiski, AGDC would own 25 percent with the three producer companies owning the remaining 75 percent. TransCanada would own no part of the LNG plant. Earlier, the state signed three other agreements with TransCanada. One gives the state the right to acquire 40 percent of the pipeline company’s holding in 2016. The second is a “Precedent Agreement” for the state to ship state-owned royalty gas through TransCanada’s share of the Slope conditioning plant and pipeline. The state will take its royalty and tax share of gas, about 25 percent of expected gas production from the Slope, and ship it through TransCanada’s capacity in the pipeline. The state share will be 750 million cubic feet to 850 million cubic feet of the 3 billion to 3.5 billion cubic feet that would be shipped daily through the pipeline. A third agreement with TransCanada was the formal termination of the state’s “AGIA” (Alaska Gasline Inducement Act) contract with the pipeline company that the state had entered into in 2010. Termination of the AGIA contract brought closure to a difficult, controversial chapter in the gas pipeline effort. TransCanada had initially focused on an overland pipeline to ship Alaska gas to Alberta and, eventually, the U.S. Lower 48 states. By 2012, the rapid development of shale gas in the U.S. and Canada made an overland pipeline increasingly doubtful, and effort switched to a pipeline across Alaska and a large LNG export project. The state had been unhappy with terms in its 2010 contract with TransCanada, however, as the state was required to pay a subsidy to the pipeline company, which totaled more than $300 million before the AGIA agreement was terminated. A negotiation of a new contract, as part of the overall joint-venture with the producing companies, ended those concerns.

Builders Choice busy with new housing for Slope

You may not think of Builders Choice Inc. as an oil services company, but it is, and the Anchorage-based modular housing construction company has a big stake in the future prosperity of the state’s petroleum industry. It’s for that reason the company has a large red-and-white “Vote No on 1” sign at the entrance to its plant on 104th Street in South Anchorage, said Mark Larson, who owns Builders Choice, or BCI, with his wife, Sandi. Two-thirds of BCI’s revenues come from projects directly related to the oil and gas industry, Larson said. The company hopes to diversify this year with a new business in lumber and building-related hardware, but for now, $40 million of BCI’s annual earnings of about $60 million are linked to the industry, Larson said. The company has about 200 full-time employees “Passage of Senate Bill 21, the oil tax reform bill, has created an enthusiasm in the industry to keep working here, and when new projects are developed the industry’s workers need housing,” he said. BCI operates a 50,000-square foot modular housing construction facility in south Anchorage that builds housing units mainly for industrial and commercial customers, along with a truss plant in the Matanuska-Susitna Borough that serves homebuilders. The Larsons have steadily built their business since taking over the company in 2001. Revenues have multiplied six-fold since then and much of that was due to the Larsons refocusing the company away from building modular units for residential construction and toward commercial and industrial clients such as the oil and gas industry. Today, the company’s roster of customers reads like a “who’s who” list in the natural resource industries, but new hotels and other large buildings, particularly in remote areas, have been important for BCI. The new Barrow hotel built for Arctic Slope Regional Corp., which opened last spring, is one recent commercial project. The building, which replaced an older ASRC-owned hotel that was damaged by fire, was built in a joint-venture with SKW Eskimos, Inc. A new commercial store for Hooper Bay along with teacher housing was built when a large fire destroyed existing housing in that Bering Sea community, and BCI also built units for a new school at Kalskag, a village in the Yukon-Kuskokwim region near Bethel. Most recently, the company built the modular operations and housing facility for the Point Thomson project east of Prudhoe Bay, and previously built operations facilities for the Eni Oil and Gas Nikaitchuq field as well as facilities for BP and two large Deadhorse facilities built to house service company workers, the 426-bed Aurora Hotel and 190-bed Brooks Camp. BCI also built the camps and operations centers for the Greens Creek and Kensington mines near Juneau, which are both producing. Other previous commercial customers have included Alyeska Resort near Girdwood, for an employee housing facility, and modular units that were used to construct the Denali Canyon Lodge, built for Westmark Hotels. BCI builds its housing units in a controlled environment in its Anchorage plant which ensures better quality control compared with the traditional approach of “stick-built” structures where workers and materials are more exposed to weather and temperature variations, Larson said. The units are “stackable,” meaning that two- and three-story complexes are quite feasible. The modules are trucked to the North Slope 80 percent to 90 percent complete including the inside electrical, plumbing and even furnishings. The structures can be built, moved to the North Slope and put in use quickly. “With the Brooks Camp phase one (at Deadhorse), we began fabricating in Anchorage in August and had the units moved to the Slope and occupied in December,” Larson said. The schedule was possible because site work at Deadhorse was being done while the modules were being built in Anchorage. That allowed the units to be hooked up quickly when they were moved to the Slope. Larson feels confident he can compete with Lower 48 and Canadian module fabricators because the costs of moving completed units, which are bulky, outweigh the lower costs of building outside Alaska. He knows this because BCI also operates a small modular construction plant in South Dakota that is serving the booming shale oil industry in North Dakota. Labor and other costs are 25 percent lower in South Dakota than Anchorage but the location advantage is more important. There have been times when the company’s Alaska plants were at maximum use and some units had to be built in South Dakota and moved north but that did raise costs, Larson said.

Producers erase decline for FY 2014

In a dramatic development, North Slope oil producers have essentially erased a long-term decline trend that has existed for all but one year since 1989 when two new oil fields began producing in 2002. An intensive effort in “workovers” of producing wells, to stimulate production, and drilling of new producing wells in the large producing fields, has hiked production over what was expected by the state Revenue Department. The estimated daily average for fiscal year 2014, which ended June 30, is 530,939 barrels per day compared with the average of 531,639 barrels per day in fiscal year 2013. With production through May confirmed for eleven months of fiscal year 2014, and preliminary data from June based on daily production tickets, the estimated decline for the North Slope for the fiscal year is calculated at 0.13 percent, or essentially zero, said John Tichotsky, chief economist in the Department of Revenue. The 2013 fiscal year had a decline of 8.2 percent. The 0.13 percent decline estimate is the second-best annual performance since 1989. There was a 2.6 percent increase in fiscal year 2002 when the Alpine field operated by ConocoPhillips and North Star field operated by BP began producing. Passage of a change in the state’s oil production tax in 2013, in Senate Bill 21, is being credited for increased activity on the Slope, but a leading critic of the tax change, State Sen. Bill Wielechowski, D-Anchorage, dismissed the new data. “While the industry may be successful in slightly increasing production before the referendum vote (to repeal the new tax) in August, the fact is that the long-term projections by the (Gov. Sean) Parnell administration show a 45 percent decline in oil production over the next decade,” Wielechowski wrote in an email. However, the state’s official long-term production estimates, published annually in November, were put together before the new tax law took effect and do not reflect the level of response shown by the companies recently. Alaska voters will decide whether to repeal SB 21 on the Aug. 19 primary ballot, with a yes vote to repeal and a no vote to keep it in place. “The number one statistic that matters most to Alaskans is production, not forecasts or projections. The news that we have ‘stopped the drop’ in our oil production for the first time in more than 10 years is no surprise to those of us who believe creating a competitive investment climate will bring more rigs, more jobs, and more oil to the state. “Proof of this concept is now out for everyone to see; oil tax reform is working,” said Kara Moriarty, president and CEO of the Alaska Oil and Gas Association. “More production also means more royalties going into the Permanent Fund, as a result of the change. It’s also another compelling reason to vote no on ballot measure 1 on Aug. 19.” On June 10, in a press release, Wielechowski also said he would drop his opposition to SB 21 if the industry produced one barrel of new production above the 2013 average of 531,000 barrels and it resulted in new revenue. “If SB 21 produces new oil, even ONE new additional barrel, and this production results in new revenue to the state, we will drop our support for revising oil taxes, Wielechowski said in the June 10 release. State Sen. Hollis French, D-Anchorage, joined Wielechowski in issuing the release. The revenue picture will take some time to finalize, but the first estimate shows the producers missed Wielechowski’s challenge by only 701 barrels in the per day average. State agencies monitor oil production closely because about 90 percent of state revenues come from oil royalties and taxes. The Alaska Oil and Gas Conservation Commission, an independent state regulatory agency, supervises and tests the meters that measure the flow of oil. The long-term average decline from the North Slope fields has been about 6 percent since 1989. Last December, forecasters in the Department of Revenue, anticipating better performance from producers based on the tax change, estimated that the fiscal year ending June 30 would see a 4.4 percent average decline. The buildup of production surprised state officials. By March and April it appeared there might even be a slight net increase over last year but June production rates are somewhat down because of maintenance on production facilities. That results in a lower production rate for that month, although the barrels will eventually be produced. Tichotsky said the figures may look a little better when the official June production numbers come in. “The production for June and all of 2014 will be officially finalized sometime in the first week of August, when the June production off-take reports come in, and will likely be slightly higher and bring us closer to one-tenth of a percent of a zero decline,” he said. By comparison, one-tenth of a percent is within the 0.25 percent margin of error range for the meters that measure the oil production. Tichotsky said state economists Loren Crawford and Tim Harper, in the Revenue Department’s Economic Research Group, compiled the production numbers. A number of new oil development projects have been announced for the North Slope since mid-2013, when SB 21 passed the Legislature, but it takes time for new projects to be approved by company boards of directors and to secure permits for construction. ConocoPhillips, one of two major North Slope operators, has three new projects planned that will result in a net addition of 40,000 barrels per day of new Slope production by 2018, according to Scott Jepsen, the company’s vice president for external affairs. BP Exploration Alaska, which operates the large Prudhoe Bay field, is planning a major development project in the western part of the field that will eventually add 40,000 barrels per day of production, the company has said. In the short-term, however, both BP and ConocoPhillips have boosted production through more intensive drilling and workovers of existing wells. Both companies have added more drilling rigs and boosted activity levels. BP’s work on projects to boost well production is up 20 percent over last year, and spending on “production-enhancement” work is up 40 percent, company spokeswoman Dawn Patience said.

Exploration to resume at Cosmo prospect

A drill rig will likely be starting work again later this year near Anchor Point. BlueCrest Energy Inc. plans to begin drilling later this year at the offshore Cosmopolitan oil and gas discovery in Cook Inlet, company officials say. Wells will be drilled from onshore, at high angles, to reach the Cosmopolitan deposit that is about 2.5 miles offshore. BlueCrest, based in Fort Worth, Texas, wants to begin a multi-year program to drill “extended-reach” production wells to tap a known oil deposit at Cosmopolitan, company president Benjamin Johnson said in an interview. Meanwhile, the Endeavour jack-up rig will be coming back to Cosmopolitan, too. BlueCrest will use the jack-up rig to drill vertical gas production wells into a shallow gas deposit that overlies the deeper oil reservoir, Johnson said. The company would like to get the Endeavour drilling by late summer but some extended maintenance work on the rig may delay that until next spring, he said. “We would like to begin drilling with the Endeavour this summer but it is unlikely to be available until later in the fall, which is too late to drill and complete wells in Cook Inlet,” due to the onset of winter weather, Johnson said. “We’ll take it as soon as it is available, however.” The rig is, owned by Singapore-based Ezion Holdings and the Alaska Industrial Development and Export Authority, a state agency, is now undergoing maintenance at Port Graham, south of Homer. The Endeavour was also used in 2013 to drill at Cosmopolitan, where it confirmed the gas discovery. At that time, Buccaneer Energy was the operator of the project. Buccaneer held a minority ownership in Cosmopolitan, with BlueCrest as the majority owners, but has since sold its 25 percent interest to BlueCrest. Buccaneer filed for Chapter 11 bankruptcy protection May 31 in Houston. The company had also previously sold its interest in the Endeavor to Ezion and AIDEA as part of a financial restructuring. BlueCrest has meanwhile filed a plan with the state Division of Oil and Gas outlining the new development plans, division spokeswoman Kathleen King said. According to the plan, BlueCrest will use the jack-up rig to drill three gas wells to delineate the shallow gas discovery made in 2013. The first well drilled with the Endeavour would also drill deep enough to gather reservoir data from the southern part of the oil deposit at Cosmopolitan, according to the plan. The well would then be cemented off and would later be used to produce gas from the shallow gas reservoir. Johnson said enough data is available on the northern part of oil reservoir to begin drilling the first production well later this year. On natural gas, BlueCrest’s current plan is to produce from two offshore gas production platforms when a market is found for the gas, the plan said. Johnson said the two-platform plan is tentative and could change as more is learned about the reservoir. Previous drilling at the discovery, which including wells by previous owners ARCO Alaska and Pioneer Natural Resources, indicate the presence of 44 million barrels of proven and probable oil reserves and 96.6 billion cubic feet of proven and probable gas, according to estimates by Buccaneer, which operated the exploration program in 2013. A new estimate including the results of the 2013 drilling has not been released. Cosmopolitan has a complex history. The discovery was first made in 1967 in early Cook Inlet drilling but was not considered economic. ARCO acquired the prospect and drilled horizontal test wells from onshore in 2001 and 2003 and conducted production tests. Technical problems in flowing the oil through the horizontal wells led ARCO to sell Cosmopolitan to Pioneer Natural Resources, which drilled its own horizontal oil production tests and also encountered problems with flowing the oil. BlueCrest and Buccaneer acquired the property in 2012 and secured the Endeavour jack-up rig to drill vertical well to test the gas prospect overlying the oil, and made the gas discovery. Johnson said BlueCrest has studied the technical problems encountered by ARCO and Pioneer and has developed solutions. “Most of these were mechanical in nature and we believe we can solve them,” partly through the use of new technology, he said.

Parnell signs bill to boost Bokan, Niblack mine projects

Two mine projects in Southeast Alaska got a boost after Gov. Sean Parnell gave final approval June 16 to state financial assistance for the projects through the Alaska Industrial Development and Export Authority, or AIDEA. At a ceremony in Ketchikan, Parnell signed Senate Bill 99 into law. The bill authorizes $145 million in infrastructure and construction financing for the Bokan-Dotson Ridge rare earths mine and $125 million in similar funding for the Niblack multi-metals mine. Both are prospective underground mines on Prince of Wales Island near Ketchikan. Ucore Rare Earth Inc.’s Bokan-Dotson Ridge project contains a significant amount of the heavy rare earth elements dysprosium, terbium and yttrium, Ucore has said. About 40 percent of the rare earth oxides, by weight, that have been identified at the property are heavy rare earths, an unusual concentration for a North American prospect. The company plans to begin its feasibility study for the mine this fall, which will take nine to 12 months to complete, according to Ucore Chief Operating Officer Ken Collison. The plan is for an underground mine producing 1,500 tons of ore per day. Ucore also plans to develop on-site ore processing facilities that will produce rare earth compounds at the mine. As many as 16 to 17 products may be produced on site, Collison said. Bokan-Dotson Ridge is about 37 miles southeast of Ketchikan.  The Niblack project, being developed by Heatherdale Resources, holds copper, zinc, gold and silver. It is 27 miles southwest of Ketchikan. If Niblack is developed it would be similar to the Hecla Mining Co. Greens Creek underground mine now operating on Admiralty Island, near Juneau. Greens Creek produces silver, zinc, lead and gold. Karsten Rodvik, spokesman for the state development authority, said the AIDEA financing options include direct equity investment as well as financing. “Under this legislation we could own portions of the project, or do direct financing. Before any involvement by the authority the project would go through a rigorous due diligence process, just as with any project that involves AIDEA financing,” Rodvik said in a statement. Sen. Lesil McGuire, R-Anchorage, said an important part of the Niblack project is the plan to locate the ore processing plant for the mine near Ketchikan. If developed the project would create 200 permanent new jobs for the southern Southeast region, she said at the SB 99 signing ceremony. On the rare earths project, McGuire said, “The United States used to be almost self-sufficient in rare earth elements, but now we almost completely rely on foreign sources for these important minerals.” Rare Earth Elements are needed to make a wide variety of things including high-tech military equipment, wind turbines, solar panels, advanced batteries, and high-tech consumer goods like flat-screen TVs, computers, tablets and cell-phones, McGuire said. “China currently controls 95 percent of the world’s rare earth elements, but reduced the exports of those elements by 54 percent between 2005 and 2010, and again by 50 percent from 2010 to 2011,” she said. The legislation also approves a loan from the Alaska Energy Authority, another state agency, for the Blue Lake hydro expansion project at Sitka. If the loan is made, the bill approves $18.6 million in financing from the state power project development fund. Tim Bradner can be reached at [email protected]

Houston company takes stake in Brooks Range

Another small independent company is taking a stake in new North Slope development. Thyssen Petroleum Corp. of Houston has taken an equity position in Brooks Range Petroleum Corp., an Alaska-based company active in exploration and development on the Slope. Thyssen Petroleum’s investment was confirmed by Brooks Range Chief Operating Officer Bart Armfield. Thyssen will buy the equity shares of Brooks Range that are now held by Alaska Venture Capital Group, a consortium of small Kansas-based independents, and Ramshorn Investments Inc., a subsidiary of Nabors Industries. There may be additional investors in Brooks Range announced soon. Brooks Range has been exploring on the Slope for more than a decade and is now developing one of its discoveries, the small Mustang oil field west of the Kuparuk River field. The company plans to have first production in early 2016, Armfield said. Mustang is expected to initially produce between 8,000 barrels per day and 10,000 barrels per day in 2016, its first full year of production, and about 12,000 b/d in 2017 as development drilling in the field is completed, Armfield said. An oil gas processing facility being built at the field will have to capacity to process 15,000 b/d and will be available for other companies developing nearby prospects to use, he said. Armfield said drilling on three production wells will begin this fall with drilling of six to eight additional wells in 2015 to provide the initial production. Another eight to 10 wells are planned in 2016, he said. Two test wells were drilled at Mustang in 2011 and 2012. Total costs for the project, including the plant and drilling, are estimated at $580 million, Armfield said. The Alaska Industrial Development and Export Authority is investing $50 million in the process plant, which is estimated to cost between $200 million to $220 million. AIDEA has also invested about $20 million in a $27 million gravel access road and pad to support the Mustang project. Other partners in the project including Brooks Range also contributed to the road and pad construction. The authority’s investment in the processing plant, as in the road and pad, are structured so that AIDEA is a preferred member in the two limited liability companies created for the projects. The agreements provide for AIDEA’s share to be purchased by the other parties. Over time Mustang will generate about $300 million in new state tax and royalty revenues and North Slope Borough tax revenues, according to estimates developed by AIDEA. Mustang’s resources are estimated at 24 million barrels of recoverable reserves but there are additional prospects nearby that Brooks Range intends to pursue after the initial project is producing, Armfield said. Its investment in Brooks Range will be Thyssen Petroleum Corp.’s first venture into Alaska. The company is now focused on production onshore in the U.S. Gulf coast states. Thyssen was not available for comment. The company is the latest of a number of small companies becoming active on the slope. Miller Energy, a small Tennessee-based company active in Cook Inlet, through its subsidiary, Cook Inlet Energy, recently purchased Savant Alaska, a majority owner and operator of the small Badami field east of Prudhoe Bay. Earlier this year Caelus Energy, a newly-formed independent, completed the acquisition of Pioneer Natural Resources’ Alaska assets, which include the producing offshore Oooguruk field near the Kuparuk River field. Another new entrant on the North Slope will be Hilcorp Energy after that company’s deal is approved to acquire properties now owned by BP. Hilcorp will acquire two small producing offshore fields, Northstar and Endicott, as well as 50 percent of the Milne Point field, whch is onshore. Hilcorp would be the operator of all three fields. Hilcorp would also become 50 percent owner in Liberty, a small offshore project that is not yet developed. BP would remain as operator of that project, however. A development plan is to be submitted for Liberty to the U.S. Bureau of Ocean Energy Management by the end of the year. The Hilcorp acquisition of the BP properties is expected to be given final approval by the end of the year.

Parnell terminates state's AGIA contract with TransCanada

A much-criticized 2010 agreement between the State of Alaska and TransCanada Corp. to pursue a large North Slope natural gas pipeline is now in the past. Gov. Sean Parnell signed documents June 17 terminating the contract with TransCanada, negotiated under the state’s Alaska Gasline Inducement Act, or AGIA. This sets the stage, Parnell said, for a larger joint-venture agreement with the pipeline company and North Slope producers BP, ConocoPhillips and ExxonMobil. The new partnership is focused on a large gas pipeline from the North Slope and a large plant to export liquefied natural gas, or LNG, at Nikiski, TransCanada and the state, as well as the producers, were originally focused on an all-land pipeline to Alberta but the development of abundant shale gas in the Lower 48 ended that project, for now. TransCanada has accepted the termination as a step toward the larger LNG export agreement, state Natural Resources Commissioner Joe Balash said. The next step is for the parties to sign the joint-venture agreement spelling out responsibilities and cost-sharing to ramp up the next phase of the process, which is expected to include preliminary engineering and design and getting a more specific estimate of costs. Balash said discussions surrounding these issues have been going on for months and he saw no reason for the agreement and associated documents to not be signed. The state itself will be a signatory to the part of the agreement on the LNG plant through the Alaska Gasline Development Corp., a state corporation that would hold the state’s 25 percent share of the plant. Both ExxonMobil Corp. and BP are ready to sign, spokeswomen for those companies said June 17. TransCanada spokesman Shawn Howard, by email to the Associated Press, said his company has resolved its issues with the joint-venture agreement. Howard declined to say what those issues were, saying they were part of the discussions between parties that he could not discuss publicly. ConocoPhillips spokeswoman Natalie Lowman said there were still “open issues” that needed to be resolved from the company’s perspective. Lowman did not specify the issues, saying negotiations are confidential. She said by email to the Associated Press that the company continues to support moving the project forward and all parties were “working closely to bring these agreements to closure.” State officials expect the Joint Venture Agreement to be signed before July 1, said Elizabeth Bluemink, spokeswoman for the state Department of Natural Resources. The 2010 AGIA contract with TransCanada had become a thorn in the side for Alaskans because it obligated the state to pay` $500 million in subsidies to the pipeline company for its efforts to put together a pipeline project on its own. The contract provided for the state to pay 50 percent of TransCanada’s costs until an “open season” in 2010 and 90 percent of its costs after 2010. The Lower 48 pipeline effort was unsuccessful and led eventually to the larger effort now underway focused on a LNG export project, but not before the state had paid TransCanada $300 million under the AGIA deal. Any future refunding obligation is voided, however. The AGIA contract also limited the state’s ability to pursue alternative gas projects, mainly a smaller in-state gas pipeline that could be built if the larger project does not move forward. Those limits are now also lifted. Signing of the new Joint Venture Agreement will launch a Pre-Front End Engineering or Design phase for the pipeline and LNG project, although parts of the pre-FEED are already underway, Balash has said previously. The pre-FEED will generate updated cost estimates for the project, now estimated at between $45 billion and $65 billion. The new estimates are expected to be available in late 2015, the commissioner said. The Associated Press contributed to this article.

Umiat results promising but more work needed

Linc Energy has achieved one important thing at its Umiat oil development project: the company got oil locked in shallow permafrost to flow through a horizontal production test well. What Linc has to do now is get the rate of production up. In tests conducted this spring, the test well flowed at a sustained average rate of 250 barrels per day and peak rates of 800 barrels per day in four separate flow-tests. The company believes it can increase those rates to about 2,000 barrels per day by applying a “gas drive” boost to the production, and hopes to eventually produce 50,000 barrels per day overall at Umiat. However, the company is now looking for a partner to help make that happen, Linc Energy spokesman Paul Ludwig said in an interview. Overall, the company is pleased with the results so far, although more geologic modeling is needed and possibly more test drilling. However, just getting the shallow oil to flow from the permafrost is considered a technical feat. This is the first time crude oil has been produced in significant quantities at Umiat since 1952, Linc’s CEO said in a statement. “The success of flowing oil at Umiat is a great milestone for Linc Energy and its team,” company CEO Peter Bond said. “We have now proved that the oil flows easily from the Umiat reservoir with very good permeability (the microscopic pathways for the oil to flow through the rock) and that the drilling process of using horizontal wells. With this success and the knowledge gained from last year’s drilling, we now have a clear path for the commercial development of the Umiat oil field,” Bond said. What helped is that the oil is very light, 38.5 API gravity, and contains no water. There are other examples of technically-challenged North Slope oil, such as the West Sak viscous oil, that initially flowed at rates as low as 250 barrels per day but where the production rates were boosted, over time, with research and the application of new technology. Just drilling a horizontal production well through permafrost presented other challenges for Linc. A prototype drilling fluid was used that was designed to not damage the reservoir. Using conventional drill fluid might have warmed the permafrost, causing damage. The logistics problems were also substantial. Linc had to build a 99-mile snow road in both winter seasons to move the drill rig and other equipment and supplies to the site. The rig, owned and operated by Kuupik Drilling, was left at Umiat between the two winter seasons but has now been taken back to the Prudhoe Bay area. Umiat is a long-known oil discovery that was made in the late 1940s as the U.S. Navy and U.S. Geological Survey carried out early exploration of the then-Naval Petroleum Reserve No. 4 (now the National Petroleum Reserve–Alaska). The Navy’s discovery was not large enough to merit development and there was then no pipeline from the North Slope. However, that oil was discovered and its high quality — it could be used to fuel diesel engines right out of the wells —caught the attention of many in industry, spurring further interest, exploration and eventually the large Prudhoe Bay discovery farther north. Some in the industry have expressed caution about Linc’s results last winter, however. “The company should have gotten higher rates out of a horizontal section of well-bore drilled a thousand feet through the reservoir,” said one consulting petroleum engineer familiar with the North Slope, asking not to be identified. He agreed that production stimulation could help, however. There is gas in the vicinity of Umiat that could be tapped to aid oil production. The horizontal well section drilled last winter was 2,000 feet in length but only half of this, 984 feet, was drilled through productive reservoir in the Lower Grandstand Formation, according to a statement issued by Linc. The oil was produced from reservoir section only 950 feet below surface, which is within the permafrost layer under Umiat. As for a source of natural gas that could be tapped to boost oil production, a gas discovery was made decades ago in early North Slope exploration at Gubik, 10 miles east of Umiat, and was confirmed in a recent exploration well drilled by Anadarko Petroleum Corp., which holds leases at Gubik. There has been no recent activity by Anadarko and the company has not released information on possible resources. Umiat’s known oil reserves are estimated at 154.5 million barrels based on estimates of proven and probable resources, and when possible resources are added the estimate is increased to 194 million barrels. These are within a total resource of approximately one billion barrels of oil-in-place in the reservoir, Linc has said in statements. If the deposit is developed, a pipeline would be built to a connection with the Trans-Alaska Pipeline System, along with a permanent gravel road. Several routes for the road and pipeline are still under study, Linc has said, including a route for the pipeline and road directly east that would connect with TAPS and the Dalton Highway. An alternative that is being studied is a road and pipeline route to the north that would connect with existing field pipeline and road infrastructure in the Kuparuk River field area.

New gas platform for Cook Inlet now en route from Texas

The new Furie Operating Alaska platform planned for Cook Inlet is en route to from a Texas fabrication facility towed by a Crowley Maritime Corp. tug. Meanwhile, pipe for subsea pipelines to connect the platform with onshore gas facilities is also being shipped, although Crowley is not handling that movement. Craig Tornga, a Crowley vice president, said Crowley’s tug Ocean Wave, which is towing a barge loaded with the platform, has departed Ingleside, Texas, and is now headed to Cristobal, Panama, for a Panama Canal transit. Furie Operating Alaska will install the platform in July and August for the company’s planned Kitchen Lights gas production project. Two 10-inch subsea pipelines will also be built. Furie is a Houston-based privately-held oil and gas company that does not release its gas reserve estimates or potential production. However, the facilities being installed have the capability of handling 30 million cubic feet per day, according to plans filed by Furie with the Alaska Division of Oil and Gas. The platform will be located about 20 miles northeast of Nikiski and about 15 miles southwest of the ConocoPhillips Tyonek platform, which serves that company’s North Cook Inlet gas field. Furie drilled its first exploration well, KLU No. 1, at the site in 2011 using the Spartan Offshore Drilling Spartan 151 jack-up rig. The company drilled three other wells in 2012 and 2013 using the jack-up rig to confirm the discovery and test other prospects. State officials said the company is obligated under its lease work commitments to drill two more exploration wells in the area. Furie’s platform will be the first new offshore production facility installed in Cook Inlet since the mid-1980s when Forest Oil Corp. installed the Osprey oil production platform at the Redoubt Shoal field on the Inlet’s west side. The company’s quest to drill and develop the Kitchen Lights prospect has had its ups and downs over several years. In exploring the prospects, Furie has also had to overcome challenges that have included skepticism by state agencies that the company would be able to pull off the project. Escopeta Oil and Gas, Furie’s predecessor company, has worked for almost a decade to raise funds and move a jack-up rig to Cook Inlet to drill the Kitchen Lights prospect. The company had some bad breaks. In 2006, the initial financing to move the rig from the U.S. Gulf coast to Alaska fell through. In 2010, when the financing was put back together, the federal government denied a renewal of an exemption to the U.S. Jones Act that would allow Escopeta to use a foreign heavy-lift ship to move the rig. In a decision that smacked of politics, the federal government, by then headed by President Barak Obama, a Democrat, said there were no energy security issues in Cook Inlet that justified the Jones Act exemption, even though in 2010 a serious gas supply situation seemed to exist in Southcentral Alaska. The Jones Act requires all voyages between American ports to be conducted by U.S.-built ships and manned by U.S. crews. In contrast, in 2006, the administration of Republican President George W. Bush granted the Jones Act exemption to bring the rig on a foreign ship on the grounds of regional energy security and national defense. Former U.S. Sen. Ted Stevens had provided assistance. Stevens was gone from the Senate by 2010, and the national administration had changed. In 2010 the Southcentral Alaska regional gas supply situation had actually worsened compared with 2006, as there had been no new drilling, but the Department of Homeland Security provided no explanation for its reasoning in changing its position on the waiver. Danny Davis, Escopeta’s colorful president, continued to work that year with the federal agency to secure the renewal of the exemption. Faced with drilling deadlines on the Kitchen Lights leases, Davis decided to take a chance that the exemption would come through. He loaded the rig on a Chinese heavy-lift ship and sailed for Alaska. By then U.S. shipping interests who defend the Jones Act had also swung into action, vigorously lobbying the federal administration against the exemption. By the time the ship and rig neared Alaska the exemption had not come through. The vessel diverted to Vancouver, B.C., and dropped off the rig and departed. The stop in Vancouver also allowed repair work to be done. The rest of the voyage to Alaska was by Foss Maritime tugs, which are U.S.-built and operated. The rig made it to Cook Inlet and began drilling what is now the Kitchen Lights discovery. Although the rig had stopped in a Canadian port for repairs, breaking its journey from the U.S. Gulf to Alaska, the Department of Homeland Security still asserted that a violation of the Jones Act had occurred and slapped the company with a $15 million fine. At that time, however, Davis was ousted as president by his investors, who reorganized the company as Furie and continued the exploration program. Furie has appealed the fine and the matter is still unresolved. Furie would not comment on the matter and a telephone inquiry by the Journal of the Department of Homeland Security was not returned.

With CD-5 half-built, judge faults Corps permit

A U.S. Alaska District Court judge has ruled that the U.S. Army Corps of Engineers did not provide an adequate rationale for its decision to allow ConocoPhillips to proceed with road and bridge construction at its $1 billion CD-5 project in the National Petroleum Reserve-Alaska. The ruling by Judge Sharon Gleason issued May 27 did not suggest a remedy for the decision and asked for briefings from the plaintiffs and defendants on how to proceed. She did not require the preparation of a supplemental environmental impact statement or issue an injunction that would stop construction now underway at CD-5. The bridge and roads, meanwhile, are about half-built. CD-5 is scheduled to begin production in late 2015. In March, Gleason denied plaintiffs’ request for an injunction to stop construction at CD-5, finding that, “based on the Court’s determination that the balance of the equities was then tipped sharply in favor of ConocoPhillips and the other Intervenor-Defendants and that a preliminary injunction would not be in the public interest. The March 2014 Order did not address the Kunaknana Plaintiffs’ likelihood of success on the merits.” Gleason also tossed a lawsuit filed separately by Center for Biological Diversity, finding that the Outside environmental group lacked standing in the case.  The other plaintiff is Sam Kunaknana, who is represented by environmental law firm Trustees for Alaska. The CBD and Kunaknana cases had previously been merged by Gleason. Gleason made no decision on the plaintiffs’ Clean Water Act claims. The Corps of Engineers was joined in its defense by Arctic Slope Regional Corp., the North Slope Borough, Kuupik Corp. and the State of Alaska. Kuupik owns the surface rights at the proposed CD-5; ASRC owns the subsurface rights. “The Kunaknana Plaintiffs’ Motion for Summary Judgment will be granted on their (National Environmental Policy Act) claim to the extent they assert that the Corps failed to provide a reasoned explanation in the record for its decision not to conduct a supplemental NEPA analysis,” Gleason wrote. “This Order does not determine whether a supplemental NEPA analysis is required, nor does it determine the appropriate remedy for the Corps’ NEPA violation. This Order also does not resolve the Kunaknana Plaintiffs’ (Clean Water Act) claim. Instead, the Court requests further briefing from the parties as to how this case should proceed at this juncture.” ConocoPhillips’ initial application to build the road and bridge at CD-5 was rejected by the Corps in 2010, and subsequently appealed by the company. The Corps granted ConocoPhillips permit in 2011 with modifications based on the appeal. The Kunaknana plaintiffs filed the first lawsuit Feb. 27, 2013, and CBD filed its lawsuit June 5, 2013. Briefings on Gleason’s order are required within 21 days of her May 27 order. The controversy over the bridge for CD-5 has a long and twisted history. The project was first proposed in 2005 by ConocoPhillips but was delayed after Nuiqsut villagers contested the location proposed for the crossing, arguing that it could impair subsistence fishing. After extensive consultations and discussions, in 2008 ConocoPhillips agreed to move the bridge and to also meet other requests by the village, mainly to extend a road to connect the community with the oilfield road system. The next twist came, however, when the company actually applied to the U.S. Army Corps of Engineers in 2009 for the permit to build the bridge. The Corps rejected the permit, arguing that the company could avoid a bridge by building an underground river crossing for the pipeline and supporting CD-5 with a winter ice road and by air in summer, which is done now with two other drill sites in the Alpine field that are located on the Colville River delta where there are several river channels. In making its rejection, the Corps was acting on behalf of other federal agencies, such as the U.S. Fish and Wildlife Service, which was worried about the effects of large gravel fill for the bridge and CD-5 roads on the local wetlands and the water flow through the wetlands needed to support waterfowl habitat. In summer the Colville River delta is supports one of North America’s major migratory waterfowl nesting areas. The agency was also concerned about future extensions of the CD-5 road west to subsequent developments. If the decision were made to reject all-year road access to CD-5, the effect would be to preclude the extension of the road further, which is now, in fact, being planned for ConocoPhillips’ Greater Moose’s Tooth project, or GMT-1, eight miles west. ConocoPhillips appealed the Corps rejection of the bridge permit and was joined by Arctic Slope Regional Corp., which owns the subsurface rights at CD-5, and ironically by Kuukpik Corp., the Native village corporation for Nuiqsut. There were two key arguments made in support of the bridge, and against the underground pipeline crossing. One was that inspections for corrosion, and detection of leaks, are difficult with an underground pipeline but much easier for an above-ground pipeline, such as is planned with the bridge. The second was that all-year road access was important for safety and maintenance at CD-5 and drill sites further west that could be served by a road. If an emergency occurred at a drill site it would be faster to get equipment, material and personnel to a site by road than by cross-tundra winter travel or by air. The Corps ultimately accepted those arguments and in 2011 reversed the rejection of the bridge permit. In filing the lawsuit in 2013, the litigants said that the Corps never fully explained its reversal in issuing the permit, and relied on a 2004 environmental impact statement for the Alpine field satellites that was done by the U.S. Bureau of Land Management. What the corps should have done, the plaintiffs argue, was to do a supplemental environmental impact statement, or SEIS, for the bridge and road plans, which have changed since the 2004 EIS was prepared. The federal district court has not bought that argument so far but clearly intends that the Corps must do something. What happens next, other than a wrist-slapping for the Corps, remains unclear. The BLM currently has an SEIS process underway for the GMT-1 project and there is thought that Gleason’s decision could affect that. ConocoPhillips is hoping for a final EIS on GMT-1 by this fall.

A dozen incumbents to run unopposed

Alaskans love to complain about their politicians, but when push comes to shove, at election time, there aren’t a lot of people willing to step up to replace them. Four state senators and eight state House members, the bulk of them Democrats, have no opponents in either the primary or general elections, although there may be two unaffiliated candidates approved for the general election in one House race and one Senate race. The Division of Elections must still have signatures approved for those to be official. Otherwise there were few surprises in the filings for 2014 Alaska elections on June 2, the deadline for candidates to put their names on the ballots. In the high-stakes race for U.S. Senate, the contest remains mainly between Sen. Mark Begich, the Democratic incumbent, and three Republicans vying to face him: current Lt. Gov. Mead Treadwell, former state Natural Resources Commissioner and Attorney General Dan Sullivan, and Joe Miller, a Fairbanks attorney who won the GOP nomination over Sen. Lisa Murkowski in 2010 but lost to her write-in campaign that November. There had been speculation that former Gov. Sarah Palin might jump into the race but Palin did not appear June 2. There are two Libertarians, two Alaska Independence Party candidates, two other Republican and one other Democrat in the U.S. Senate fray. In the governor’s race, it still mainly seems a contest between incumbent Gov. Sean Parnell, a Republican, and his Democratic challenger, Byron Mallott, an Alaska Native leader. Former Valdez Mayor Bill Walker is also in the race as an independent and will appear on the November ballot. Among the filing for legislative races, what’s interesting is how many incumbents are unopposed or virtually unopposed, and that most of them are Democrats. In the state House, eight incumbents for 40 seats up for grabs have no opponents in primary or general elections. They include seven Democrats and one Republican. In the 20-member Senate, three Democratic state senators and one Republican senator have no opponents in either election, although a “nonaffiliated” (or independent) candidate will oppose the Republican senator in November general election. Among the unopposed senators are Democratic Sen. Berta Gardner, in her midtown Anchorage Senate District I and Republican Sen. Peter Micciche, in Senate District O on the Kenai Peninsula. Micchiche is unopposed in the primary election but Eric Treider, a Soldotna resident, has filed as a non-affiliated candidate for the general election. The Division of Electrics is awaiting his signature verification before making it official. Democrat Sen. Lyman Hoffman, in Senate District S in Southwest Alaska and Sen. Donny Olson, a Democrat, in Senate District T, in Northwest Alaska, are unopposed. In state House races, Rep. Lynn Gattis, R-Wasilla, has no Republican or Democratic opponent in either election but Verne Rupright, a Wasilla resident and a non-affiliated candidate, has filed to have his name appear on the general election ballot opposing Gattis. The Division of Elections is awaiting a signature verification before making this official, however. Democratic incumbents in three Anchorage districts, Rep. Andy Josephson in District 17, Rep. Harriet Drummond in District 18, and Rep. Chris Tuck in District 23, have no opponents in either primary or general elections. In Homer, Rep. Paul Seaton has no opponent in his District 31. Rep. Bryce Edgmon in District 37, in Dillingham, faces no opponent. In Bethel, Democratic Rep. Bob Herron, in District 39, faces no opponent, and neither does Rep. Neal Foster, Democrat, in District 39 based in Nome. Two interesting races are shaping up in Interior Alaska, where incumbent Republican Sen. Click Bishop has a strong primary election opponent, former state senator and Senate President Mike Miller, a North Pole businessman, in his reelection bid in Senate District C. In Interior District 3, mainly the east Fairbanks and North Pole areas, two Republican incumbents were put together in the 2013 redistricting — Reps. Doug Isaacson and Tammie Wilson. Both are now opposing each other in bids for reelection. A Democrat is contending for that seat also, Sharron Hunter of North Pole. In Northwest and Northern Alaska District 40, incumbent Rep. Ben Nageak of Barrow, a Democrat, is opposed by Dean Westlake of Kotzebue, also a Democrat. This district spans the North Slope and Northwest Alaska regions and the legislative races are generally between candidates from the two population centers, Barrow and Kotzebue.

Alaska proves potential of resource development

Alaska is the nation’s best proof that natural resource development, particularly in oil and gas, translates to a vibrant economy and public well-being, the president of the nation’s oil and gas trade group said May 29 in Anchorage. “You and your predecessors have demonstrated that developing energy resources to promote economic growth and to improve the lives of your citizens need not come at the expense of your state’s stunning natural beauty or other natural resources,” American Petroleum Institute President Jack Gerard told business and community leaders at a luncheon during the Alaska Oil and Gas Association’s annual meeting. Although the state has now slipped behind other states in oil production, Gerard said a revival of industry activity on the North Slope and Cook Inlet, thanks to the state’s shift in of its tax structure, could change that. Overall, the state has set a dramatic example that new energy states like North Dakota are copying. “Alaska is one of the best examples of how energy policy can change not just the trajectory of energy production, but how it can greatly improve the enhance the lives and livelihoods of its citizens,” Gerard said in his prepared remarks. Texas has always understood this connection and North Dakota does so now, but Washington, D.C., hasn’t gotten the message. Industry activity is booming on private and state-owned lands but lagging on federal lands, Gerard said. “According to the Bureau of Land Management, from 2008 to 2013 the number of drilling permits issued on federally-controlled onshore land dropped by 40 percent while the actual number of wells dropped 50 percent, which of course further decreases production. “A Congressional Research Service study has found that in federal areas, production from 2009 through 2012 was down 6 percent for oil and 21 percent for natural gas.” Activity on private and state lands showed a sharp contrast. “Where development does not need permission from the federal government, oil production is up 31 percent and natural gas production is up 24 percent. “This difference is not due to geologic science, but rather political science. “Nationally, the right energy policies could result in an increase of 1 million jobs in seven years,” he said. In 2011, the petroleum industry provided a $528 billion boost to the U.S. economy, he said. Gerard called on President Barak Obama to show more leadership on energy and cited the stalled Keystone Pipeline project as an example of federal policy in a muddle. The government’s consideration of the project is now in its sixth year, “with no end in sight,” Gerard said. He pointed to construction of the Trans-Alaska Pipeline System in he 1970s, a project just as controversial as Keystone in its time, as an example of what can be done when industry, regulators and politicians work together, “for the common good to advance a vital energy infrastructure project,” he said. TAPS was built in 38 months. “For perspective, this administration has been evaluating, studying and otherwise delaying the Keystone XL pipeline for almost twice as much time as it took to build the Trans-Alaska Pipeline System,” Gerard said. There are now 80 pipelines that carry oil and gas across the U.S.-Canada border. Keystone is the only one that has become bogged down. In an interview separate from his address, Gerard said the delay in Keystone has resulted in a shift of crude oil movement from Alberta and North Dakota to rail, which the U.S. State Department now acknowledges will result in more carbon emissions than would the Keystone pipeline. In Alaska, Gerard said in the interview that his organization and others on the national level are closely watching federal initiatives like the U.S. Environmental Protection Agency’s move to preempt minerals development in a huge area of Southwest Alaska. It is a dangerous precedent with national implications, Gerard said. The industry is also closely watching for the U.S. Interior Department’s final special rules on Arctic drilling, which Shell and other companies interested in the Arctic are waiting for. On a national level, API is best known for its advocacy and education work on behalf of industry but one of the organization’s main functions, and its original purpose, is to set technical standards. API was founded in 1919 in New York partly at the request of the federal government after World War I showed that the nation’s defense and military capabilities will be heavily influenced by the ability to efficiently produce and supply fuel. That’s still a main function of API and its various standards and certifications are now considered the international standards for most oil and gas producing nations, Gerard said. Even China is working to match its own standards with those of API, mainly so Chinese manufacturers can sell petroleum-related equipment in international markets where API standards and certifications are observed. Most of API’s 400-odd employees are in the U.S., and most of those in Washington, D.C., but the organization also has offices in Dubai, Beijing and recently opened in Rio de Janeiro. An office is planned soon in Milan. Most of the work these offices do is related to certifications to API technical standards, he said. API conducts a review of its standards every five years so there is a constant effort to keep them up to date. Another important task for API is to form industry task forces to tackle certain problems. After the Macondo well blowout on the Gulf of Mexico in 2010, API convened a joint industry task force to review industry practices related to offshore drilling and safety. The task force recommendations were subsequently relief on by regulations in their review of the accident. “As issues arise we are able to put these groups together, and to also include the regulators and the academic community to get the best thinking,” on the problem, Gerard said.

Slope drilling reached record level in 2014

A record number of drill rigs were at work on the North Slope this winter. According to weekly working rig data compiled by Baker Hughes Inc., drilling reached a peak of 17 rigs during the week of Feb. 28, traditionally the busiest time for the North Slope. Baker Hughes, which has compiled national working rig data since 1987, confirmed the 17 rigs at work in a single week was a record for Alaska. The weekly average for the December through April winter season was 11 rigs compared to an average of 7.8 rigs working last winter. Alaska Oil and Gas Association President Kara Moriarty credited the increase in activity to the Legislature’s passage in April 2013 of Senate Bill 21, which changed the state’s oil and gas production tax. “The North Slope rig numbers from Baker Hughes provide proof that oil tax reform is working,” she said. “The whole purpose of drillings rigs is to drill for oil; they are oil-seeking by design. As we saw firsthand, the old tax structure did not encourage oil production. The increase in oil company investment and new drill rigs we are experiencing now is beyond encouraging. “Senate Bill 21 (tax reform) provided the framework companies were looking for to hire more employees, put more drill rigs into action, and, ultimately, put more oil in the pipeline.” The Baker Hughes data analyzed by the Journal of Commerce shows that drilling during this winter season on the Slope was almost double the number of rigs active in the winter of 2010-11, when the weekly average was just 6. During that period the previous state oil production tax known as ACES, or Alaska’s Clear and Equitable Share, was in effect. The data indicates that prior to the Legislature’s enactment of ACES in 2007, the number of working rigs averaged about 10 per week during the 2006-07 winter. After ACES was enacted, the weekly rig count average dropped to 8 in the winter of 2007-08, rose to just more than 9 in 2008-09, dropped again to 8.6 in 2009-10, and declined further to an average of 6 working rigs in the winter of 2010-11. Activity increased to a weekly average of 7.8 rigs in the winters of 2011-12 and 2012-13, and then increased sharply to an average of 11 working rigs in the first season following the passage of SB 21. The slight increase in 2012 and 2013 winters under ACES can mainly be attributed to an aggressive exploration program by Repsol on the North Slope, which employed three rigs for an program during those two winters and again in 2014. Although Repsol’s program was underway before the Legislature passed SB 21, the company has said it was attracted to Alaska in 2011 because of the proposed tax change. Repsol wanted to get its exploration underway before the Legislature passed the tax change so as to be “ahead of the herd,” of an expected surge of companies entering Alaska after the tax change, Bill Hardham, Repsol’s Alaska manager, has said in briefings. Drilling peaks during winter on the Slope because that is the only season in which rigs and heavy equipment for exploration wells can be moved overland on ice and snow roads to remote locations. But rigs are also busy year-around in the established producing fields that have gravel roads and pads to allow movement of equipment at any time of the year. These rigs are busy drilling new production wells and doing repairs and maintenance work on wells. Each rig typically employs 100 directly and several hundred additional workers indirectly in various service and support work, ConocoPhillips president Trond-Erik Johnansen told the Anchorage Chamber of Commerce May 12. Since passage of SB 21, ConocoPhillips has put two additional rigs to work, Johnansen said. The Nabors 7ES rig went to work in the Kuparuk River field in May 2013, just weeks after the Legislature’s April 20 passage of the tax bill. In February 2014, the Nabors 9ES rig also went to work in the Kuparuk field. Scott Jepsen, ConocoPhillips’ vice president for external affairs, told state legislators in an April 9 briefing that together the two rigs will drill about 10 new wells per year. New projects announced by the companies in recent months include plenty of new assignments for rigs. One project by ConocoPhillips is the North East West Sak, or NEWS, a viscous oil project in the Kuparuk River field. It will need 19 wells. The Moose’s Tooth project in the National Petroleum Reserve-Alaska will require eight wells. Drill Site 2S, a new production pad in the southern part of the Kuparuk field, will also require new wells. The CD-5 project, a satellite to the producing Alpine field, is now under construction and will require 15 wells. CD-5 was approved by the ConocoPhillips board of directors prior to the tax change, however. BP has meanwhile put two new Parker Drilling Co. rigs to work in the Prudhoe Bay field, which it operates and the company’s rig count will climb higher. BP plans to add two more rigs, one in 2015 and one in 2016, according to Janet Weiss, BP’s Alaska president. Weiss spoke at the Anchorage Chamber on Feb. 10. BP’s plans for its two new rigs will add 30 to 40 new wells per year each year in the Prudhoe Bay field. At Milne Point, a nearby field BP also operates, the company has put a coiled-tubing drill rig to work and plans seven new wells there in 2014. BP also plans new production wells in the Sag River formation, a thin, technically difficult reservoir section that overlies part of the Prudhoe Bay field. A 15-well program in the Sag River formation in 2015 and 2016 will test new strategies BP has developed for this prospect. “If we are successful this particular program could enable a possible 200 wells and 200 million barrels of new resources at full development,” Weiss told the Anchorage chamber in February. A large Prudhoe Bay project BP is planning, though not yet decided on, is a development in the field’s west end. It involves and 130 new wells on a new well pad, the first at Prudhoe in more than a decade, and expansion of two other well pads, plus expansions of processing facilities. One other BP project, Weiss said, is a potential north-end Prudhoe Bay development that could see another 30 wells and 55 million barrels of new oil resources. While drill rigs do different kinds of work on wells in the field including maintenance, their main function is the drilling of new wells. Ed King, a petroleum economist with the state Department of Natural Resources, said that as a rule of thumb each rig working in a producing field on the slope can be expected to drill about 12 new wells per year. Typically about half of them are producing wells and half are injectors to put water or gas back down into the reservoirs to aid production of oil. Each pure production well typically adds 700 to 1,000 barrels per day of new production, which helps offset the natural decline of the fields.

Alaska Native corporations join to oppose oil tax reform repeal

Six Alaska Native regional corporations have launched their own campaign to defeat Ballot Measure 1 on the August primary election ballot. The ballot measure would repeal Senate Bill 21, a bill restructuring the state oil production tax passed by state legislators in 2013. “We are a coalition of local Alaska companies with our eye on the future as Alaskans, our businesses, our economy and opportunities for our shareholders and residents, said Rex Rock, president and CEO of Arctic Slope Regional Corp., at the May 28 initiative kickoff. “No One on One,” will funded and operated separately from other campaigns organized to combat the initiative. Rock joined five other Native corporation leaders in founding the “No One on One” initiative, including Aaron Schutt, president of Doyon, Ltd.; Sophie Minich, president of Cook Inlet Region Inc.; Helvi Sandvik, president of NANA Development Corp.; Jason Metrokin, president of Bristol Bay Native Corp. and Gail Schubert, president of Bering Straits Native Corp. Rock and others announced the campaign at the ASRC Energy Services oilfield fabrication shop in South Anchorage. Schutt, of Doyon, said his Fairbanks-based corporation is heavily invested in oil services and owns seven drill rigs now at work on the North Slope. When the Legislature passed the previous oil tax, which imposed high taxes on the industry, the corporation felt an immediate hit to its business. “We saw two of our rigs go down right away. Each rig has about 80 employees, and 95 percent of our employees are Alaskans and about half are Doyon shareholders,” he said. Business picked up when the Legislature replaced the previous tax, he said. In a statement, Sophie Minich of CIRI said, “CIRI’s top priority is to maintain strong dividends for our shareholders, and a strong, vibrant Alaska economy is essential to our success.” “We’ve witnessed the industry’s commitment to new investment and have seen for ourselves the rebound in jobs and activity in the oil and gas industry and we want to see that trend continue.” In her statement, Sandvik, of NANA, said her corporation had 4,000 employees in 2013 including 1,000 shareholders, working in industry. “We need more investment in the oil industry. The state’s new tax structure encourages that,” she said. In the event at the ASRC Energy shop Schutt said one part of SB 21 that is not well known is a section that grants special incentives for exploration in “frontier” basins in Interior and Northwest Alaska where there has been little drilling. Doyon spent $50 million last year to fund the drilling of a test well in the Nenana Basin near Fairbanks and the first “3-D” seismic program in the Yukon flats, Schutt said. “This program, which is intended to help find new energy sources in rural Alaska, was possible only because of the special incentives in SB 21. If the law is repealed, Doyon won’t be able to sustain the program,” he said.

Playing TAPS: Annual dispute turns political

A state tax assessment board concluded four days of contentious hearings May 15 on valuation of the Trans-Alaska Pipeline System for state and local property taxes. A decision by the board is expected any day, but the value chosen almost surely will be appealed to the courts.  The tax assessment fight over the 800-mile pipeline is an annual event when the state sets a value for TAPS. Under Alaska law, the state’s value must be used by municipalities along the pipeline route for their own property taxes on the pipeline.   The municipalities involved, the City of Valdez, the Fairbanks North Star Borough and the North Slope Borough, must certify their tax rolls by June 1 and mail notices to taxpayers. The oil and gas property tax on oil transportation and production facilities is the state’s only property tax. Each year the state Department of Revenue sets the tax value for TAPS, and set it at $5.7 billion for 2014. The three municipalities, who are working together, claim the pipeline is worth $13.7 billion. TAPS owners, mainly the large North Slope producers, meanwhile have their own estimate of $2.7 billion. The municipalities want a high figure because that maximizes their tax revenue. TAPS owners want the number low because it minimizes the tax they pay. In its hearings, the State Assessment Review Board listened to presentations by all three parties, the pipeline owners, the municipalities and the Department of Revenue, and must pick a number within these ranges. No matter what the board decides, one or the other of the disputing parties will appeal to the courts, as they have almost every other year. Big dollars are at stake. If the tax value is $13.7 billion, as the municipalities argue, the pipeline owners would pay $274 million in tax. If the TAPS owners’ view prevails, the bill is $54 million. If the state revenue department’s $5.7 billion number is used, the tax is $114 million. This year the dispute has become a political cause célèbre and has played into election-year politics. Gov. Sean Parnell is being criticized for firing one member of the tax review board who arguably leaned toward the municipalities’ views in past decisions. To replace him Parnell appointed a former oil industry executive who might favor TAPS owners’ arguments, critics argued.  Parnell is also being criticized for deciding last year to  allow the pipeline owners to make estimated tax payments for 2013 that are below the state assessment review board value for that year. The companies should have paid $113 million based on the state assessment board’s determination but Parnell chose to let them pay only $66 million. Although that decision was made a year ago, Alaska Revenue Commissioner Angela Rodell said she supports it because the courts will make the ultimate decision on the pipeline value. Such “tax in abeyance” agreements are common where there is a dispute. “Both sides recognize there is an obligation. It is just set aside until the dispute is resolved,” she said. If the value estimated by the appeals board is upheld, the industry taxpayers will pay the difference plus interest, which is 11 percent compounded quarterly, she said. There’s uncertainty about this, however. The value could also be lowered by the courts and the state wants to avoid a situation of having to refund taxpayers at 11 percent compounded quarterly, Rodell said. In this case there may be a good chance of that happening because the value set by the review board for 2013 was high relative to the values accepted by recent state Superior and Supreme court decisions on the issue. Both matters have become political footballs, however. Parnell is running for reelection this year and is opposed by Bill Walker, lead attorney for the City of Valdez, which is deeply engaged in the TAPS value dispute. No matter what figure the assessment board picks for 2014, the dispute will be appealed to state Superior Court and, ultimately, the state Supreme Court. In February, the state Supreme Court rendered its first decision on a TAPS tax dispute, for 2006. The high court is still looking at years 2007 through 2009. Subsequent tax years are still in state Superior Court, on their way to the Supreme Court. “You’d think that after a decade of litigation and Superior Court decisions and now a Supreme Court decision we’d have more certainty, not less,” said Jim Greeley, the state’s chief property tax assessor. Disputed value Meanwhile, why the huge differences in the estimates? Property tax assessors use several methods to set values, Greeley said. The most common method used is market value, based on actual sales, as in real estate. This is the approach municipal appraisers typically use with residential and commercial property. But there is no other 800-mile Alaska pipeline on the market, so other methods are used, Greeley said. For TAPS, the disputing parties have agreed to use an estimate of pipeline replacement, or what it could cost to build TAPS anew, with an allowance for depreciation.  To arrive at their replacement estimate, the municipalities hired a consulting firm, Pro Plus Inc. TAPS owners hired another firm, Stantec. Not surprisingly, the firms rendered estimates supporting their clients’ opposite positions of $13.7 billion and $2.7 billion, respectively. Greely said he based the state’s valuation on a TAPS replacement estimate from 2006 that has now been approved in the Supreme Court’s February decision, but indexed to 2014 using the Marshall & Swift Petroleum Index, a widely-used industry cost index. “We based our estimate in what the court has approved,” Greeley said. “The other two (owners and municipalities) started from scratch.” Estimating a replacement cost is more complicated that it would seem. If they agree on little else, the disputing parties do agree that a brand-new TAPS would be built a lot differently than it was in the mid-1970s. It would take advantage of new technologies in pipe welding, for example, and it would certainly be built at a smaller scale, to accommodate lower volumes of oil. Stantec and Pro Plus arrived at sharply different conclusions as to what a modern version of TAPS might look like, but one big factor in dispute was a construction cost contingency factor in the Pro Plus estimate that was much larger than the Stantec contingency. That factor alone, which is a subjective estimate, added a several billion dollars to the Pro Plus valuation, industry officials, speaking on background, said. The parties are also miles apart on what depreciation to apply once a valuation is determined. The municipalities want a “straight-line” depreciation beginning in 1977, when TAPS started, that stretches to an end-of-life estimate for the pipeline in 2067. That approach creates gradual slope supporting the claim of a $13.7 billion value in 2014. TAPS owners use a different approach loosely based on “units of production value” which corresponds roughly to throughput. TAPS throughput was steady at 2 million barrels per day through the 1980s but has now declined to about 520,000 barrels per day. North Slope production began dropping in 1989 and has dropped at a long-term average of 6 percent per year. That approach creates a steeper depreciation slope, which reinforces the TAPS owners’ $2.7 billion estimate of 2014 value. The state Revenue Department, in its estimate for 2014, basically used the units of production value approach but started from a higher replacement cost and thus arrived at a higher value of $5.7 billion. Production projections A key point in the depreciation dispute, however, is the municipalities’ view that TAPS will operate until 2067, verses a 2047 end-of-life assumption used by pipeline owners and the state. Greeley said he uses 2047 because the date, and the assumptions behind it, link to Superior Court decisions that are now affirmed by the Supreme Court. The key assumptions in the court decisions to date is that TAPS can operate down to 100,000 barrels per day and that this limit would be reached in 2047. The date is based on long-term estimates of production from the North Slope that are developed each year by the state Revenue and Natural Resources departments. The state’s estimates rely on assumptions of reserves that can be produced that are “proven” under standard industry-accepted definitions of the term, mainly that of the Society of Petroleum Engineers, that they are economically, technically and legally capable of bring produced. State statutes require proven reserves to be used in the Revenue Department’s long-range forecasts. The municipalities, however, argue that a different approach might be justified in this case. Relying on only proven reserves is appropriate if the estimate used for forecasting state revenues, in which case being conservative is proper, the municipalities argue. However, there are also “probable” reserves, they said, and even oil that will likely be produced from discoveries that are now unknown, or oil that is known but of a type that cannot now be technically produced, like heavy oil. History has shown that over time industry finds ways to produce resources that are now ranked as probable or technically challenged, and that some factor for these resources should be considered. In her decision, Superior Court Judge Sharon Gleason seemed to agree with this, which is why the municipalities now assert a larger number for oil resources. However, whether TAPS can economically operate at 100,000 barrels per day is highly problematic. It might be operated mechanically at that volume but whether the costs can be borne is another matter. The pipeline now carries about 500,000 barrels per day but Alyeska Pipeline Service Co., the pipeline operator, has said only that TAPS could technically be operated down to about 300,000 barrels per day, but then only with certain modifications. Whether it can economically operate is another question. The modifications needed will require additional investment, which means the per-barrel transportation cost will go up. Also, the pipeline’s fixed costs, spread across fewer barrels, will result in a higher per-barrel cost. Operating at less than 300,000 barrels per day might be possible if there were radical changes in the way TAPS operates, such as a “batching” operation where the pipeline would shut down periodically with oil stored at Prudhoe Bay, and then shipped in batches down the pipeline as it is restarted at intervals. Whether this mode of operation is technically, much less economically, possible is uncertain, Alyeska has said.


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