Tim Bradner

BLM tacks $8M fee onto GMT-1 project permit

The U.S. Bureau of Land Management has approved construction of the first oilfield access road into the National Petroleum Reserve-Alaska. But part of the deal announced Feb. 13 involves ConocoPhillips Alaska Inc. paying $8 million in additional mitigation into a fund for the petroleum reserve, although the payments would not be related to ConocoPhillips’ activities. BLM’s Alaska spokeswoman Lesli Ellis-Wouters said the agency signed a Record of Decision for its supplemental environmental impact statement, or SEIS, on ConocoPhillips Alaska Inc.’s development of the Greater Moose’s Tooth No. 1 project. GMT-1 is expected to produce 30,000 barrels per day when it is completed. Some of the money in the special mitigation fund may be used to clean up old well sites from early exploration wells drilled by the federal government, according to the decision approved by the BLM. Many of the wells were left in an unsafe condition, with some still causing pollution. Mitigation for ConocoPhillips’ direct activities, such as on wetlands affected by gravel placement, were previously agreed to by the company. NPR-A is a 23 million-acre federal reserve in Northwestern Alaska. It was created in 1923 for its oil and gas potential but despite exploration over several years no commercial-scale discovery was made until ConocoPhillips and its minority partner, Anadarko Petroleum Corp., explored the northeast part of the reserve in recent years and made discoveries. The BLM’s final approval of the SEIS clears the way for federal permits to be issued for the project, which is in the northeast NPR-A. However, it is not yet clear when, or even if, ConocoPhillips will proceed with GMT-1. ConocoPhillips hoped to begin construction this winter but said recently that it would not start work because of delays in the final SEIS and the Record of Decision, as well as low oil prices. On the North Slope, construction involving road or pads built with gravel is typically done during winter, when the land surface is frozen, because of summer restrictions in working on thawed tundra. One cause for the delay was differing opinions between the BLM and the U.S. Army Corps of Engineers over which of two roads routes were the least environmentally disruptive. The Corps favored one route because it was slightly shorter and would thus require less gravel placement on wetlands. BLM initially favored another, slightly longer route, Alternative B in the SEIS document, because it avoided an environmentally sensitive area identified in the agency’s long-range protection plan for the reserve. BLM switched its position, however, to side with the Corps on its route selection, Alternative A, which prompted criticisms from conservation organizations. Conservation groups had sided with BLM originally in its choice for Alternative B because the sensitive areas would be avoided. Approval of the road is important because it will provide access for additional exploration and development farther west. ConocoPhillips and Anadarko Petroleum have already explored to the west and have tentatively identified a second project dubbed Greater Moose’s Tooth No. 2 that could be developed after GMT-1 is in production. Under the additional mitigation measures agreed to by ConocoPhillips, $1 million to fund a BLM “Regional Mitigation Strategy” must be paid by the company within 60 days of the issuance of the ROD on Feb. 13 regardless of whether ConocoPhillips decides to move ahead with GMT-1. Payment of the other $7 million, which will be used to fund various projects, is contingent on construction proceeding, however. The projects, under the mitigation strategy, would compensate for “residual impacts” of the GMT-1 road and pipelines in the Fish Creek and Tinmiaqsigvik River setbacks, including major impacts on subsistence use, according to BLM’s decision document. However, “cleanup of previously disturbed sites (e.g. legacy well reserve pits, landfills, etc.)” could also come from the $7 million fund. Conservation groups, meanwhile, criticized the BLM’s decision to switch to the Corps-favored route because it infringed on protected areas. “We are disappointed that BLM’s final decision encroaches on a buffer zone that exists to protect the Fish Creek area and its valuable habitat for wildlife,” said Nicole Whittington-Evans, Alaska regional director for the Wilderness Society. The Fish Creek area had been set side for protection in BLM’s 2013 land management plan, she said. Kevin Harun, Alaska director for Pacific Environment, said the decision sets a terrible precedent. “This landscape should be managed to protect wildlife and their movements,” he said. U.S. Interior Department officials praised the agreement, however. In a statement, Assistant Interior Secretary Janice Schneider said, “The department looks forward to continuing to work with ConocoPhillips as it moves forward with safe and responsible development of the North Slope. “The strategic planning and mitigation measures agreed to by ConocoPhillips are important as we continue to support thoughtful and balanced development in this region and are critical to compensating for the impacts of this project.” Although the GMT-1 project is within the NPR-A, the royalties from oil and gas production will be paid to Arctic Slope Regional Corp., or ASRC, the Alaska Native development corporation for the North Slope. ASRC owns the mineral title under the ConocoPhillips leases under terms of the Alaska Native Claims Settlement Act passed by Congress in 1971. Ordinarily, 50 percent of the federal royalties would have been shared with the state of Alaska. However, the state’s oil and gas production tax does apply to production from federal and privately-owned lands, so some revenue from GMT-1 will come to the state. What may be more important is the additional oil provided to the Trans Alaska Pipeline System, which is moving just more than 500,000 barrels per day, and operating at about one fourth its original capacity of 2 million barrels per day. More oil moving through TAPS not only helps keep the pipeline economically viable but also lowers the tariff, or transportation charge, for all oil in the pipeline. A lower transportation charge raises the tax and royalty value of oil from other North Slope fields on state lands and increases state revenue.

One regulatory hurdle cleared for Arctic OCS drilling

Shell is officially one step closer to resuming exploration in the Chukchi Sea. On Thursday the U.S. Bureau of Ocean Energy Management released its final supplemental environmental impact statement for a 2008 Chukchi Sea Outer Continental Shelf Lease Sale. It is a move that is hoped to clear legal and regulatory hurdles facing Arctic offshore drilling. The document was published on schedule after the draft SEIS was completed last fall. A Record of Decision will likely be issued in 30 days, which will allow BOEM to resume work on Shell’s revised exploration plan for the Chukchi Sea, BOEM said in a statement.  “Alaska is a critical component of our nation’s energy portfolio, and the Chukchi Sea has substantial oil and gas potential, as well as sensitive marine and coastal resources that Alaska Native communities depend on for subsistence,” Interior Secretary Sally Jewell said in the statement. “The updated analysis is a major step toward resolving the 2008 oil and gas leases that have been tied up in the courts for years. We remain committed to taking a thoughtful and balanced approach to oil and gas leasing and exploration in this unique, sensitive and often challenging environment.” Environmental groups reacted harshly to the EIS release. “It is unconscionable that the federal government is willing to risk the health and safety of the people and wildlife that live near and within the Chukchi Sea for Shell’s profits Friends of the Earth climate campaigner Marissa Knodel. There is no such thing as safe or responsible drilling in the Arctic Ocean — Shell’s record of recklessness and the federal government’s own environmental analysis show that approval of Lease Sale 193 would be unsafe, dangerous and irresponsible.” Shell said it was encouraged by the action. “We appreciate the release of the Final SEIS and are reviewing it. It’s our understanding it will be posted to the Federal Register sometime next week,” Shell spokesman Curtis Smith said. “Our 2015 exploration plans for offshore Alaska remain dependent on a number of factors, including our own readiness and legal and regulatory certainty.” Shell drilled two partly-completed wells in 2012 on its Arctic leases, one in the Chukchi and one in the Beaufort Sea. After that, however, the U.S. Ninth Circuit Court of Appeals ruled that the environmental impact statement for Lease Sale 193 in 2008 was defective because its assumption of a possible discovery — 1 billion barrels — was unreasonably low. A coalition of environmental groups had filed suit earlier, challenging the estimate. Alaska U.S. District Court Judge Ralph Beistline ordered the BOEM to resolve the problem, triggering the agency’s action to do a supplement to the EIS with revised estimates. BOEM’s new estimate, release last fall in the draft SEIS, is that 4.3 billion barrels of recoverable oil and 2.33 trillion cubic feet of recoverable natural gas are likely to be discovered in the Chukchi. In the draft SEIS, BOEM said the agency’s geologists had the benefit of actual bids by companies in a lease sale, which it did not have in 2008, as well as access to more geologic data. The revised estimate assumes a discovery of one large field as well as a smaller “satellite” accumulation nearby. Based on a better understanding about existing geologic structures in the region and improved information about where industry operators are likely to focus their development activities, BOEM evaluated a higher exploration and production scenario than in its previous analyses, the Interior Department said in its statement. Shell and other companies bid more than $2 billion for the OCS leases in 2008 when Sale 193 was held, with the bulk of the bids tendered by Shell. The company has faced a series of setbacks including operational issues that prevented the drilling of complete wells in 2012. Shell has since given a higher priority to resumed exploration in the Chukchi Sea because of the greater potential for major discoveries in the area, the company has said. Shell now hopes to drill in 2015 but once its Sale 193 leases cleared legally with the new SEIS there could yet be other roadblocks. A set of new special Arctic OCS drilling rules from the Interior Department has yet to be issued, although those are expected soon. Meanwhile, there are other lawsuits pending from environmental groups including one challenging the Interior Department’s approval of Shell’s Arctic oil spill containment and cleanup plan. Also, other companies that bid in the 2008 sale, such as ConocoPhillips, have put their exploration plans on hold until they see Shell making progress in getting final permission to drill.

CH2M Hill calls off Alaska unit sale

Senior managers of CH2M Hill were in Alaska Feb. 4 meeting with the company’s employees. Their message: The company’s oil and gas business is no longer for sale and it’s business as usual. CH2M Hill Senior Vice President for Corporate Development Matt McGowan and Senior Vice President and Regional Managing Director Patrick O’Keefe said the company wanted to test the market’s reception on a possible sale when it was announced last October. There were a lot of inquiries and a lot of interest but the unexpected oil price plunge affected the outlook and increased uncertainty among potential buyers, McGowan said in a Feb. 4 interview with the Journal at the company’s Anchorage office. In mid-January, the company announced the sale was off. It was still a worthwhile exercise, McGowan said, because it validated CH2M Hill’s sense that its Alaska-based oil services division, the former Veco Corp., was a valuable business. CH2M is happy to continue owning it, he said.  “We’re back to business, developing our long-term strategy and making sure the Alaska division has the allocations of capital that it needs,” McGowan said. “We did a lot of work on the sale and we learned a lot about the business. Then, oil prices changed, dramatically. The price change has not affected us — our own (engineering and oilfield construction) business is holding up — but the price change caused a lot of turmoil among the parties we were dealing with. “There was a lot of interest, however, and it confirmed the value of the (Alaska oil services) business.” It was unusual for a company to announce in public that it was putting a major division up for sale, McGowan said, but CH2M Hill wanted to be as transparent as possible about it. Terry Bailey, the company’s Alaska manager, said it was also done to control the rumors that would inevitably have started among employees and customers. “We wanted to get ahead of this,” Bailey said. CH2M Hill is a major employer in the state and a big player on the North Slope as well as non-petroleum infrastructure projects in the state. Across the Slope, the company is now providing engineering services, construction and oilfield maintenance, from the ExxonMobil-led Point Thomson in the east to ConocoPhillips’ CD-5 project in the west. The company employs about 1,900 on the Slope and this will increase to 2,000 or more as work on the $4-billion Point Thomson project peaks this summer, Bailey said. CH2M Hill is playing a key role in that project as manager of the installation of four huge gas production and process modules that will arrive on the 2015 summer sealift. The company is doing a lot of other work on Point Thomson, too, including the fabrication of smaller “truckable” modules and facility components in fabrication shops in Anchorage, he said. Point Thomson will begin production of liquid condensates in 2016. Natural gas produced in the process will be injected back underground. CH2M Hill is also managing the installation of production facilities at CD-5, a $1-billion ConocoPhillips project near the Alpine field on the western North Slope. CD-5 is expected to begin production late this year. A large non-petroleum infrastructure project CH2M Hill is managing is the plan for completing the Port of Anchorage reconstruction. This is being managed by the Alaska Division, Bailey said, but the project teams are drawing on CH2M Hill divisions elsewhere that have special expertise in port development. Patrick O’Keefe, the company’s regional director, said CH2M Hill purchased U.K.-based Halcrow Group three years ago, a veteran engineering company specializing in port and harbor infrastructure. Halcrow already had a U.S. base but the acquisition strengthened the company in this country and added to CH2M Hill’s infrastructure work in Europe and the Middle East, where Halcrow was active. CH2M Hill acquired VECO Corp. in 2007, which now constitutes the oil services division, but the company has had a presence in Alaska for more than 50 years in its traditional water, sewer and power generation infrastructure projects. The company opened its office in 1964 to aid in earthquake reconstruction. In addition to the direct oil field services provided in Alaska and Sakhalin Island, Russia, it also does a lot of work in oilfield infrastructure worldwide. Using its water and wastewater expertise the company provides maintenance management in water and sewer utilities, for example in a Denver suburb. O’Keefe said the company’s work on nonpetroleum infrastructure in the state has been stable, and the company hopes to grow that segment of its work. Meanwhile, CH2M Hill is heavily engaged in natural gas project development. On the state-led 36-inch Alaska Stand-Alone Pipeline, or ASAP, CH2M Hill is the program manager, and is also engaged in pre-FEED engineering and design work for the larger Alaska LNG Project, the 42-inch pipeline,large natural gas liquefaction plant and marine terminal. The company’s share of that large project is the marine infrastructure facilities at Nikiski, which is the proposed site of the LNG plant.

State pitches budget plans to rating agencies

JUNEAU — Gov. Bill Walker and top state revenue officials were in New York Feb. 2 and 3, pitching Wall Street that Alaska is still a good financial bet even with a huge hole blown in state revenues by the plunge in oil prices. Walker and the state team met with credit rating agencies Standard & Poor’s, Moody’s Investor Services and Fitch Ratings, hoping to persuade the institutions not to downgrade Alaska’s Triple-A credit rating on bonds. Two of the rating firms, Standard and Poors and Moody’s, have put Alaska on their “credit watch” list but have not yet changed the ratings for Alaska or any state corporations or municipal governments. Walker touted the state’s strong financial position, the disciplined cut of $550 million from the upcoming fiscal year 2016 state budget and the continued investment in the state by oil and gas companies despite the dismal oil price environment. “The state is well positioned to manage this through time, but we’re taking steps now,” Walker told the rating agencies. Besides Walker, the state team included Revenue Commissioner Randy Hoffbeck, Revenue Deputy Commissioner Jerry Burnett, state debt manager Devon Mitchell, and Steve Masterman, the state geologist and director of the Division of Geological and Geophysical Services in the Department of Natural Resources, who spoke on the state’s undeveloped petroleum and minerals resources. “The governor led most of the discussion. Our key point is that we are doing exactly what we said we would do, save money when oil prices were high and then draw on those savings when commodity prices hit a slump,” said Burnett, who participated in the presentation. Walker told the credit agencies that the state is positioned to manage the revenue slump with $14 billion in liquid assets that are estimated to be available in savings funds as of next June 30. The administration has taken budget action, however, cutting spending next year by about 9 percent, or $550 million, compared with the current budget year, the state team told the rating agencies. The reductions are coming both in the operating budgets, which supports state agencies and most public services, and the capital budget, which mostly supports construction. Burnett said that even amid the slump the administration is taking care to preserve vital public programs, such as “forward funding” of education revenue funds for school districts (keeping a balance of one year’s funding in reserve), keeping an approximate $900 million endowment fund for rural Power Cost Equalization intact, and continuing support of actions to make energy more affordable, like state-assisted residential weatherization. Burnett said that these funds, which are technically available for appropriation, are not included in the $14 billion in liquid assets that will be used to cover budget deficits. Assuming the Legislature approves Walker’s cuts, the fiscal year 2016 state budget, not including federal pass-through funds, would be about $5.5 billion in unrestricted general fund expenditures compared with spending in the current year of about $6.1 billion. A key slide in the state’s presentation illustrated the administration’s strategy, that if the budget can be reduced to $5.5 billion and is kept at that level through 2023, the state’s savings can be stretched until that year. The first step in this will be achieved next year under Walker’s current budget reduction plan. The year 2023 is significant because the large natural gas pipeline and liquefied natural gas project in which the state is a 25 percent partner could be built and operating by 2024, bringing significant new revenues to the treasury from the sale of LNG made from the state’s share of gas production. Walker has vowed to work to keep the big project on schedule. However, what underpins the plan to 2023 is that the Department of Revenue’s long-term oil price and production forecast holds up, and that oil prices will gradually recover over the next 18 months to 24 months and the decline in North Slope production, historically at 6 percent until last year, is moderated by continued industry investment. If those things don’t happen, more drastic steps might be needed, the state team told the rating agencies. “In the event revenues remain subdued through fiscal year 2016, cumulative budget reductions of 25 percent will be targeted,” the state’s presentation said. In his Jan. 22 budget message to the Legislature, the governor said he has asked state agencies to prepare plans for a drastic 25 percent reduction that could be implemented in phases over four years. If the fiscal outlook does not improve this drastic plan may have to be put into action. However, the state administration is also discussing “how to increase available revenue,” according to the presentation. In the governor’s budget speech in which he said options are being researched to use the state’s “financial strength” in a new revenue-generated plan. No details were given as to what this might be, but the state’s strong investment earnings including income from the Permanent Fund were referenced in the presentation. “There are no current plans to revisit the state’s tax structure,” the state team told the credit agencies, according to the presentation. Still, the credit agencies are expecting to see a plan for new revenues as well as spending reductions in the state’s plan, Burnett said. “They want to make sure that we address the short-term shortfalls and that we do develop a longer-term plan to enhance revenues,” he said. The credit agencies are also well aware of the political problems in Alaska in any discussion of new revenues, particularly the use of any Permanent Fund earnings, Burnett said. “Some of these rating analysts have been following Alaska for years,” and are well aware of political sensitivities, he said. The state’s total reserve balance was $19.9 billion as of Dec. 31, 2014, but this figure does not include an obligation for another $1 billion to be transferred to state pension funds ($2 billion were transferred earlier) or appropriations by the Legislature to “inflation-proof” the principal of the Permanent Fund, or to provide for Permanent Fund dividends. The Permanent Fund itself earned $4.83 billion in “statutory net income,” or cash income, in fiscal year 2014, the budget year ending last June 30, according to the presentation by the state team. Fund cash earnings are expected to decline to $2.98 billion this year and to $2.7 billion in fiscal year 2016, but those are only estimates, according to the presentation. Burnett said the state’s credit ratings will likely come under more pressure next year if the oil revenue slump continues, the depletion of liquid reserves is underway and there is no move toward new revenues. “At that time they’ll be asking us what we intend to do,” Burnett said.

Medicaid expansion to add 26,523 insured by 2021

Gov. Bill Walker’s proposal to expand Medicaid in Alaska under terms of the federal Affordable Health Care Act is grounded in a new study done for the Department of Health and Social Services by Evergreen Economics, a Portland, Ore.-based consulting firm with experience in the health care field. Several critical assumptions underlie the governor’s plan, according to the Evergreen report. One is the estimate of the “expansion population,” or how many Alaskans would enroll under an expanded Medicaid program. Evergreen made estimates of new enrollees for fiscal year 2016 through fiscal year 2021, estimating 20,066 new enrollees in fiscal year 2016 and the number increasing to 26,523 in 2021. Another critical part of Evergreen’s analysis is the projection of the per-enrollee cost of the expansion. This is estimated at an average of $7,250 in fiscal year 2016, according toe Evergreen’s report, and growing to about $8,400 per year by 2024. The estimated health care costs varies by age group and gender, Evergreen found. For men, the estimate is $3,500 per year for those younger than 35 to just less than $7,200 per year for men ages 55 to 64. For women, the estimates do not range as significantly by age but do vary from $7,500 per year for women younger than 35 to just less than $8,200 for women ages 45 to 64. Evergreen estimates the expansion group will be 54 percent male with about 21 percent of men between 19 and 34. No figure was given for the age distribution of women in the estimate. Another factor in the analysis is the “take up rate,” or the percentage of the newly eligible adults who would actually enroll in Medicaid. In Evergreen’s report, this is 47.9 percent of the total eligible population in fiscal year 2016, increasing to 55.4 percent in fiscal year 2017 and stabilizing at 63 percent of the eligible population from fiscal years 2018 through 2021. This would put the potential eligible population increasing from 41,910 in fiscal year 2016 to 42,260 in 2021. Factoring in the “take up” percentages, Evergreen estimates the actual new enrollees would rise from 20,066 in fiscal year 2016 to 26,623 in fiscal year 2021. Including the medical spending per enrollee, which rises, on average, from $7,248 in fiscal year 2016 to $8,433 in fiscal year 2021, Evergreen estimates the total spent for Medicaid services, federal and state funds, would increase from $145.4 million in fiscal year 2016 to $224.5 million in fiscal year 2021. Under the formula of federal cost-share in the Affordable Care Act, the state’s general fund share of the expansion cost would be zero in fiscal year 2016, with the federal government picking up 100 percent of costs. However, the federal share declines in fiscal year 2017 and the state’s share of the cost would be $3.8 million in fiscal year 2017 and increasing to $19.6 million per year in fiscal year 2021.

Great Bear spuds well south of Prudhoe Bay

Great Bear Petroleum has resumed its North Slope exploration drilling. The company “spudded,” or started, its Alkaid No. 1 well Feb. 5 to test a prospect on the Great Bear’s leases south of Prudhoe Bay and plans to drill a second well nearby this winter, Talitna No. 1. The Nabors Alaska Drilling Co. Rig 106 is being used on the drilling, Great Bear vice president Pat Galvin said. About 60 workers are being employed on the rig. Both prospects are conventional oil and gas formations rather than the extensive shale formations that were the targets of two earlier wells Great Bear drilled in 2012, Galvin said. However, at least some of the shale formations will be penetrated by these wells, which will allow additional samples to be taken from the shale for more testing, he said. If the drilling is successful it’s possible that some production testing could be underway this summer, with the produced oil trucked to Prudhoe Bay on the Dalton Highway, Galvin said. Another 40 workers would be employed in production tests if they occur. Great Bear’s winter program is budgeted at $50 million, he said. The 2012 wells, aimed at testing the shales, were drilled in the summer on gravel extensions built on the Dalton Highway, an all-year gravel road that extends south of Prudhoe Bay to Interior Alaska. That drilling was primarily to extract core samples from the shale for analysis, although the company hoped at the time to drill one horizontal segment for a production test. That was not done, however. Great Bear still considered the drilling successful because valuable data was obtained. “The samples met or exceeded our expectations in terms of organic compounds (of hydrocarbons) and the right thermal maturity, which meant the rocks were prone to the formation of oil rather than, say, for natural gas,” Galvin said. The 2012 well results also showed a substantial presence of conventional oil prospects on Great Bear’s leases, which has now been affirmed by 3-D seismic testing the company did in 2013 and 2014. This has caused Great Bear to shift its plan to focus first on conventional oil, the hopes being that this will help pay the costs for a long-term evaluation and development of the shale oil resource, Galvin said. The prospects this winter are located a few miles off the Dalton, which has required the construction of short segments of ice road. The two well locations are close enough that one support camp is being used to support both wells, he said. If the results are encouraging the company will be able to do follow-up drilling this summer from well sites adjacent to the highway, as it did in 2012. Exploration wells are almost always drilled in winter on the North Slope because the tundra must be frozen before ice or snow roads can be built to locations off the road system. Because of its proximity to the highway, however, Great Bear can drill in the summer, an advantage because the contract rates for drill rigs should be less than in winter, the peak season for contractors, Galvin said. Great Bear is the first company to focus on potential shale oil on the North Slope, an unconventional oil resource. The company unveiled its strategy with an aggressive program of acquiring acreage in the state’s 2010 “area-wide” North Slope lease sale and followed up with additional leases added in the statewide sales held in the following years. The objective is to determine if the North Slope shales, which are very large and are known to be the source rocks for the region’s large conventional oil fields, can produce oil in the way that the Eagleford shales in Texas and the Bakken shales of North Dakota are now major oil producers. The North Slope shales are very similar to the Eagleford shales, Great Bear officials have said in the past. Scientists have confirmed that the oil found in the large producing fields such as Prudhoe Bay, Kuparuk River and Alpine, originated in the shale “source” rocks lying to the south. Over geologic time the oil seeped out of the source rocks and migrated upward, to the north, into large sandstone rock layers. When further migration was blocked by impermeable “cap” rocks, the large oil reservoirs were formed. Great Bear is betting that a large amount of oil remains in the source rocks that can be produced like companies are doing in the Eagleford and Bakken shales of the Lower 48. An additional advantage for Great Bear is that all three of the major shale formations on the slope, the Shublik, Kingak and Hue formations, are all present, even “stacked” on top of each other along with conventional oil reservoirs, Galvin said. Galvin said another possibility is that at least some of the North Slope shales might be produced without large-scale fracturing of the rock, which must be done in the Lower 48. If the Slope shales are naturally fractured enough, which could be the case, the amount of fracturing needed might be reduced. This could reduce costs, a key concern with any North Slope project. Galvin said another initiative by Great Bear is an aerial LIDAR survey (light detection and ranging) of surface terrain contour and tundra lake bathemetry on about 10,000 lakes that has given the company highly accurate information to use in securing permits. Two types of LIDAR were used in the lake surveys, one that is water penetrating and the other water reflecting so that the bottom contours of the lakes can be seen as well as the water levels. This allows for an accurate assessment of the water contained in the lakes.

Inlet rebound comes at cost to state during price plunge

The turnaround in Cook Inlet oil and gas production in recent years is one of the big success stories for Alaska. It has come at a hefty expense, however, to the state treasury. It turns out that Inlet producers are being heavily subsidized by the state of Alaska, consultants to the state Legislature say in a report. Since the state budget is 90 percent dependent on North Slope oil production revenues, this also means that, in effect, the big producing companies on the Slope are paying for the Cook Inlet producers. What matters most to Alaskans is that the Cook Inlet turnaround, no matter who pays for it, has increased natural gas production in Southcentral Alaska, easing a worry that gas supplies might run short and that utilities might have to import liquefied natural gas, at great expense. Still, the matter of who pays the bill is important with the plunge in oil prices and huge year-to-year state deficits looming. The Legislature’s oil and gas consultants, Janak Mayer and Nikos Tsafos, said the development incentive tax credits paid to Cook Inlet producers in fiscal year 2015, the state’s current budget year, constitute about half of the state’s cash outlays to companies under the credit program, or about $300 million. Mayer and Tsafos spoke to the Senate Finance Committee in Juneau on Jan. 27. Statewide, the total cash outlay for the credits are $625 million, according toDepartment of Revenue data, which actually exceeds state petroleum tax income by $101.4 million, according to the Revenue Department figures Mayer and Tsafos presented to legislators. The state’s total cash outlay for the tax credits are estimated at $625 million this year. “Since the state does not levy a profit-based production tax in Cook Inlet, these (tax credits) essentially constitute a subsidy to Cook Inlet producers rather than an investment in future tax revenue (and production),” Mayer and Tsafos said in a paper prepared for the Legislature. The state’s net profits production tax applies only to the North Slope fields. Cook Inlet fields are under a very minimal production tax. However, because Cook Inlet companies can take the same advantage of the state tax credit cash payments as do North Slope explorers, the result is a subsidy — more paid to the companies compared with production tax revenue paid. Cook Inlet companies do pay state royalty, although with some Inlet fields this is reduced, and state corporate income tax in some cases. The state’s tax credit program also allows companies with production who pay production taxes to credit their tax credits against production tax liability. This money never shows up in the state general fund because the companies do not have to pay it, although the state tracks the amount. A part of the tax credit program, however, also allows companies with no production tax liability, such as exploring companies who have not yet made discoveries, to turn in their credits for a cash refund from the state. This is money that must be appropriated from the state general fund because it is an actual expenditure by the state. Mostly the cash refunds are to help small independent companies who are aggressively exploring but often on shoestring budgets. But because Cook Inlet producers, even larger companies, do not pay production tax under the special tax provisions for the Inlet, they are also eligible for the cash refunds. Under state law the Department of Revenue cannot release information on which companies are applying for and receiving credits, but some small independents use the anticipated state cash refunds, and even boast about them, to raise financing including equity investment to fund their exploration. As to the Cook Inlet question, Mayer and Tsafos recognized the benefits of the industry’s surge of activity in the Inlet. “While these subsidies have played an important role in turning around investment and production in Cook Inlet, it may now be an opportune time to reconsider the future of these credits,” the consultants said in their report. “In particular, it may be worth examining whether financing solutions that leverage the strength of the state’s balance sheet to assist these companies in gaining access to reasonably-priced capital might present an alternative to credits that makes more efficient use of the state’s resources, at lower costs to the state.” One example of an alternative financing strategy is the possible $50 million equity investment by the Alaska Industrial Development and Export Authority in the Kitchen Lights gas development project being led by Furie Operating Alaska, a small independent. Furie’s project is a new gas production platform and connector pipelines to shore in Cook Inlet. AIDEA, the state economic development finance corporation, is studying the investment with Furie. AIDEA has also made an equity investment with Brooks Range Petroleum, an independent developing a small oil field on the North Slope.

Delegation vows fight after federal moves on ANWR, OCS

If tickets could be sold to Sen. Lisa Murkowski’s hearings in March on the Interior Department’s annual appropriation, it would be a sell-out crowd as Secretary Sally Jewell is sure to come in for a roasting. The Secretary has blocked a medical evacuation road for King Cove, in southwest Alaska, placed large areas of the Chukchi and Beaufort Seas off limits to oil and gas exploration, and has recommended wilderness status for the bulk of the Arctic National Wildlife Refuge, including its coastal plain that has potential for large new oil and gas discoveries. Meanwhile, the U.S. Bureau of Land Management, an agency of the Interior Department, is reported to be pressing costly mitigation measures on ConocoPhillips on the company’s planned Greater Moose’s Tooth-1, or GMT-1, oil project in the National Petroleum Reserve-Alaska. If BLM’s actions make the project uneconomic it will lose the 30,000 barrels per day of oil production that GMT-1 could produce for the Trans-Alaska Pipeline System, currently running three-quarters empty. The ANWR decision, however, had truly inflamed Alaska leaders and the state’s congressional delegation. “What’s coming is a stunning attack on our sovereignty and our ability to develop a strong economy that allows us, our children and grandchildren, to thrive,” Murkowski said in a statement. Murkowski chairs the Senate Energy and Natural Resources Committee as well as the appropriations subcommittee for the Interior Department. “It’s clear that the administration (of President Barack Obama) does not care about us, and sees us as nothing but territory. The promises made at statehood, and since then, mean absolutely nothing to them,” the senator said. Gov. Bill Walker said he was stunned that Jewell took her action at a time when the Trans-Alaska Pipeline System is running at one-fourth capacity and the state faces a two years of $3.5 billion budget deficits. North Slope Borough Mayor Charlotte Brower, who represents the Inupiuat people of the North Slope, damned the decision by Jewell. “Today’s announcement by the Department of the Interior represents the worst of Washington politics,” Brower said. “These types of paternalistic, executive fiats seem to be more appropriate for Andrew Jackson’s administration than Barack Obama’s. The people of the North Slope have been unequivocal in their opposition to further wilderness designations in ANWR.” Currently 7 million acres of the 19.8-million-acre refuge is given wilderness status, not including the coastal plain of the refuge, which encompasses about 1.5 million acres. Jewell’s proposal would extend wilderness status to 12.28 million acres, the majority of its area, including the coastal plain. In a statement issued Jan. 25, the Interior Department said, “Today’s action builds on years of public engagement by the U.S. Fish and Wildlife Service to revise the Comprehensive Conservation Plan and complete an Environmental Impact Statement for the Arctic National Wildlife Refuge, as required by law. The plan will guide the service’s management decisions for the next 15 years.” No further public comments are being taken for the plan but it is available for a 30-day public review, after which a Record of Decision will be published, the statement said. At that point the president will make the formal wilderness recommendation to Congress. Congress must approve the formal designation as wilderness but Jewell’s action makes an administrative decision that means it is de facto wilderness. State attorneys offered their perspective on Jewell’s decision: “The Comprehensive Conservation Plan, or CCP, is the completed wilderness review,” said Cori Mills, spokeswoman for the state Department of Law. “Only Congress can designate wilderness, but agency management policies dictate that land the agency recommends for wilderness designation be managed to preserve its suitability, which means that the agencies manage the recommended land as if it were already designated wilderness.” Meanwhile, it is unclear how the recommendation will affect the state’s proposal to conduct a limited winter-only exploration program in the coastal plain. The Interior Department has rejected the state’s proposal and the state has brought suit in federal court, arguing that the Alaska National Interest Lands and Conservation Act allows for exploration in the coastal plain that meets the wildlife service’s land management guidelines. “The (state’s) 1002 lawsuit and the CCP are generally separate issues,” Mills said. “If the State’s interpretation of the law is correct, the U.S. Fish and Wildlife Service is legally bound to accept the state’s exploration plan for review and the new CCP does not change that. “In particular, that is because the CCP does not fundamentally change the day-to-day ‘minimal management’ of the 1002 Area that has been in place for some time. The primary impact of the CCP is to direct a request to Congress for the 1002 Area to be formally designated as Wilderness. The CCP does not affect our legal arguments in the lawsuit until Congress says something different than what ANILCA currently says, or until the (U.S. District) Court issues a decision interpreting Section 1002.” Alaska U.S. District Court Judge Sharon Gleason is currently reviewing a request by the Interior Department to dismiss the state’s lawsuit. Interior officials defended Jewell’s recommendation: “The Arctic National Wildlife Refuge preserves a unique diversity of wildlife and habitat in a corner of America that is still wild and free,” said Dan Ashe, director of the Fish and Wildlife Service. “But it faces growing challenges that require a thoughtful and comprehensive management strategy. The incorporation of large portions of the refuge into the National Wilderness Preservation System will ensure we protect this outstanding landscape and its inhabitants for our children and generations that follow.” As for the inhabitants, the Department of Interior press release mentioned only the Gwich’in people of Arctic Village and Venetie in Interior Alaska, who have opposed any exploration in the refuge’s coastal plain, and made no mention of the Inupiat people of Kaktovik, who live on Barter Island at the northern edge of the refuge. The residents of Kaktovik are more open to exploration and in fact own lands within the coastal plain. About the Gwich’in, the Interior Department statement said, “The refuge holds special meaning to Alaska Natives, having sustained their lives and culture for thousands of years. The Gwich’in people refer to the coastal plain the refuge as ‘the sacred place where life begins,” reflecting the area’s importance to their community, maintaining healthy herds of caribou and an abundance of other wildlife.” Brower, who as North Slope Borough mayor represents the people of Kaktovik, took exception to the Interior Department’s regard for only the Gwich’in. “How ironic is this decision on the heels of this week’s earlier Executive Order calling for federal agencies to consult more with Alaska Native people over arctic issues,” the mayor said The North Slope Borough had expressed its opposition to any further Wilderness designations within ANWR thro ugh written comments submitted to the Wildlife Servicein 2011. “We would like to invite President Obama and Secretary Jewell to travel to ANWR and meet with the people who actually live there before proposing these types of sweeping land designations,” Brower said. “They might learn that the Inupiat people, who have lived on and cared for these lands for millennia, have no interest in living like relics in a giant, open-air museum. Rather, they hope to have the same rights and privileges enjoyed by people across the rest of the country.” OCS areas withdrawn Meanwhile, on Jan. 27 Barack Obama’s announced a new five-year offshore leasing program, from 2017 to 2022, that would withhold 9.8 million acres of environmentally-sensitive Outer Continental Shelf marine areas in the Beaufort and Chukchi Seas from leasing. The order would appear to have limited effect on currently exploration, however, because much of the acreage is already withdrawn in current lease sales. The new schedule, which begins in 2017, includes three Alaska OCS sales, a Beaufort Sea sale in 2020, a Cook Inlet sale in 2021 and a Chukchi Sea sale in 2022. Acreage to be offered will be determined later. The areas withdrawn include three areas of the Chukchi Sea, a 25-mile buffer area along the Alaskan coast, an additional subsistence use area near Barrow, and the Hanna Shoal, an environmentally-sensitive area. Two areas of the Beaufort Sea are withdrawn, a subsistence whaling areas near Barrow and Kaktovik, two Inuipiat villages along the northern coast. The coastal buffer and subsistence whaling areas are currently withheld from leasing but the Hanna Shoal is a new addition that would apply in the planned 2016 and 2020 Chukchi sale. The U.S. Bureau of Ocean Energy Management is currently planning a Chukchi Sea sale in 2016, sale 237, and a Beaufort Sea sale in 2017, sale 242, in the current five-year OCS schedule. BOEM is also planning a Cook Inlet OCS offering, sale 244, in 2016. In a statement, a senior White House official said the sensitivity of the Arctic region justifies the withdrawals. “Teeming with biological diversity, these areas in the Beaufort and Chukchi are part of one of the last great marine wildernesses left untouched by development,” said Mike Boots, head the White House Council on Environmental Quality, in a statement. “Endangered whales swim through the icy seas, walruses and bearded seals feed on the Hanna Shoal, and more than 40 species of fish like cod and herring grant fishermen their livelihoods. Each year, the bowhead whale hunt draws Native communities throughout northern Alaska, as essential for their sustenance as it is to their way of life and cultural history.” There had been industry reports in Alaska that the 2016 and 2017 Chukchi and Beaufort lease sales may not be held because of the uncertainties around whether Shell will be able to do exploratory drilling on its existing leases in the Chukchi. BOEM spokesman John Callahan said the sales are still planned, however. Shell’s drilling in the Chukchi, on leases the company acquired in 2008, has been delayed for a number of reasons including lawsuits by environmental groups and proposed new Arctic OCS drilling rules expected to be issued soon by the Interior Department. Alaska officials, including Gov. Bill Walker, are concerned about any further restrictions on oil and gas exploration. OCS development would, under current law, provide no direct revenues to the state but offshore oil would almost surely be piped ashore and would provide badly-needed oil to support the TAPS pipeline, which supports oil production from onshore state-owned lands. OCS activity is also an important source of new employment for the state.

Administration exploring spending cuts, investment revenue

JUNEAU — State legislators are still in a state of shock over the state’s rapidly worsening revenue situation. What appears now to be back-to-back $3.5 billion budget deficits for this fiscal year and next could be worse if crude oil prices stay low or drop further. Gov. Bill Walker and Revenue Commissioner Randy Hoffbeck say they will stick to a plan of modest budget cuts and riding out the slump by drawing on the state’s liquid cash reserves, now about $14 billion. But Walker also says that if the situation doesn’t improve other revenue options will have to be considered. One possibility is a mechanism for using the state’s large earnings from investments — which now exceed oil revenues — as some kind of financial bridge is under study, state officials say on background. Just what form it might take or its feasibility is still uncertain, but Walker mentioned it in State of the Budget speech Jan. 22: “I have asked the Revenue commissioner to explore ways to safely put the state’s wealth to work, without jeopardizing or spending the underlying financial assets,” the governor said. “Our state earned $2.4 billion more last year from its financial assets than it did from petroleum revenue. In fact, the investment revenue in fiscal year 2014 ($8 billion) was larger than the state’s entire general fund budget.” For now, the administration has laid out a financial roadmap that foresees the hefty deficits of this year and next starting to shrink, assuming oil prices and revenues pick up as the Revenue Department predicts, but continuing to 2023, the first year a natural gas project could be in production. Current savings would be sufficient to fund the deficits through those years, but the plan assumes cutting the current-year state budget of about $6.1 billion to $5.5 billion next year and keeping it at that level. In his budget message Walker said he would send the Legislature a proposed fiscal year 2016 operating budget with reductions of 6.5 percent in “non-formula” spending, meaning funds not linked to statutory formula programs like Medicaid, and 5.4 percent below a budget prepared by former Gov. Sean Parnell which Walker introduced as a template Dec. 15 to meet the legal deadline for submitting the budget.  Keeping the gas project on schedule for a 2023 completion is very important because of the revenue implications, Hoffbeck has said several times and Walker has agreed with that in several statements. However, maintaining the budget at $5.5 billion over the next seven years in dollars of the day is really a substantial reduction because it means inflation must be absorbed. However, Hoffbeck said the governor wants to go further, and to have a 25 percent reduction in the budget in four years. In his budget message Walker said he has asked state agencies to advise him how state programs would have to be restructured to accomplish that. The spending targets refer to unrestricted general fund spending, not federal dollars that are spent through the state budget, such as the federally-supported highway and airport programs, or rural sewer and water programs. There are also state funds required to match the federal programs, which are “restricted” in the sense that legislators have no option but to fund them if the state is to receive the federal funds. Walker said he would try to limit the impact of reductions on some important programs like education. “In my endorsed budget (soon to be presented) the K-12 formula funding remains intact but I’ve eliminated one-time funding added last year. This equates to a 2.5 percent funding reduction,” the governor said in the budget speech. “Forward funding” of education (funding a year in advance so school districts can plan budgets) will continue, “although at 90 percent of the current level,” Walker said. He clarified that: “This is not a 10 percent cut in education funding. It is just reducing how much is pre-funded.” The governor also said he is committed to maintaining revenue-sharing for small municipalities and communities, although there will be reductions. “In my budget for fiscal 2016, municipalities will receive $57 million in revenue sharing. That is $3 million less than last year,” Walker said. The governor also said he is open to adding “a few key priorities” back into a stripped-down capital budget that was submitted Dec. 15 as a template. “These include some projects that are under construction but not finished, limited critical maintenance and small programs that have demonstrated return on investment such as weatherization and energy monitoring,” Walker said in his budget speech. Overall, the governor felt the state’s economy can weather the slump. “Our economy is much better positioned than during past oil downturns. Compared to the late 1980s, our economy has 50 percent more jobs. Industries like tourism, fisheries, air cargo and mining have expanded greatly, and they actually benefit from low fuel prices,” Walker said. Legislators and the governor have more than the budget shortfall on their minds, however. The pending legalization of marijuana use and sales in February, following the passage of a voter initiative in the November general election, has legislators scrambling to put sideboards on the use of pot, trying to restrict it to adults 21 or over, for example, and to set guidelines for municipal regulation on sales and use of marijuana and its more powerful derivatives. A bill now in the Senate Judiciary Committee legislators hope to fast-track to clarify criminal provisions, such as the under-21 prohibition and restricting pot use in public places, has gotten bogged down in technical legal issues. One of the tricky issues is defining just what is a “public place.” Sen. Lesil McGuire, R-Anchorage, is chair of that committee. The bill is Senate Bill 30. Meanwhile, the Senate State Affairs Committee, chaired by Sen. Bill Stoltze, R-Chugiak, intends to spend much of the session working on issues of marijuana regulation, Stoltze said in a briefing by Senate leaders. There is not yet a bill in the committee, however. Sen. John Coghill, the Senate Majority Leader, warned that the pending legalization has caused a lot of confusion among people who work in industries and businesses that have strict “zero tolerance” rules, or that come under federal regulatory requirements. “There are a lot of people who think they won’t have to do drug-testing anyone,” Coghill said. They are in for a rude awakening, Coghill said in the briefing by Senate leaders, and added that he hopes employers and unions can work together in an educational effort to get the message out that drug-testing will continue.

Judge hears arguments over ANWR exploration

The first skirmish — some say it may be the main battle — in the state’s effort explore the coastal plain of the Arctic National Wildlife Refuge played out in U.S. District Court Judge Sharon Gleason’s courtroom in Anchorage Jan. 20. The issue before Gleason is whether the U.S. Department of the Interior should accept an application for a limited winter exploration program in a part of the coastal plain set aside for study of its oil and gas potential. The state submitted the exploration plan in July 2013. It was rejected by the Interior Department within weeks. The state filed suit in March 2014 to contest Interior Secretary Sally Jewell’s rejection and moved for a summary judgment in September. Following the hearing Gleason said she would rule on the issue but specified no timetable. “This is not about drilling. This is only about whether the Interior Department will accept our application for a limited non-drilling exploration,” State Assistant Attorney General Michael Schechter told Gleason during oral argument. Jewell rejected the state’s application on the grounds that the provision in the 1980 Alaska National Interest Lands and Conservation Act, or ANILCA, allowing for exploration of the so-called “1002 area” had terminated following completion of a report by the government on ANWR’s potential in 1987. Schechter said the state believes the federal law still allows for exploration done under U.S. Fish and Wildlife Service regulations, as is the case in other many other national wildlife refuges that are not designated wilderness. U.S. Attorney Rachel Roberts argued the opposite, that the agency’s authority is gone. The Fish and Wildlife Service decided that on its own after interpreting what it said were “ambiguities” in Section 1002 of ANILCA, which deals with the coastal plain of ANWR. When a statute is ambiguous, an agency is given deference to make its own interpretation under U.S. Supreme Court guidelines, Roberts said. She also contested the state’s interpretation of language in ANILCA requiring a “continuous evaluation” of the refuge’s oil and gas potential. Congress had asked for only one report in the law. The language about continuous evaluation applies to surface wildlife resources. “If Congress had wanted more information on oil and gas it would have asked for it,” Roberts said. Schechter disputed that. The statute is simply silent on a deadline, which implies the authority is still there. “In this case, silence is not ambiguity,” Schechter said. But Judge Gleason will decide that, he said. The statute does provide a deadline for a federally-sponsored exploration and only one is allowed and it was done in 1987 by U.S. Geological Survey. However, the statute also allows for non-federal exploration plans to be submitted, such as the state’s proposal, and there appears to be no explicit deadline on the Fish and Wildlife Service ability to accept such plans, Schechter said. “Congress did this to provide a way for others to conduct exploration, parties other than the federal government,” he told Gleason. As for deadlines and termination of authority, Congress routinely puts deadlines and “sunsets” of authority into laws for guidance to federal agencies, and the fact that there is no termination provided for in the law shouldn’t be interpreted by the agency to mean there is one, Schechter argued. Congress was also explicit in the statute as to the Fish and Wildlife Service’s responsibilities if and when an exploration plan is submitted, such as no exploration in a caribou calving area, which indicates that Congress anticipated that there would be exploration proposals. There is no ambiguity on the requirements: “These things were not left to the agency’s whim,” Schechter said. This first skirmish is important. If Gleason approves the state’s request and rules against Jewell, the Fish and Wildlife Service will have to accept the application for winter-only seismic and determine whether it meets the agency’s guidelines for protecting ANWR’s surface resources. If it does, the language in ANILCA is clear that the agency “shall” approve the state’s application, state officials have noted in the past. The Fish and Wildlife Service may contest whether the application does meet the guidelines, however, and that would set off another legal battle should it reject the state proposal. The proposal contemplates the state providing up to $50 million in state funds to finance a one-winter program and then solicit contributions from companies or others, such as Alaska Native corporations who own land in the area, for a second winter of seismic. That would occur if the results of the first winter season were favorable. An industry-sponsored two-dimensional seismic program was done in the coastal plain in the 1980s with that information provide to the U.S. Geological Survey, which was then preparing the resource report required by ANILCA.

Royalty reduction approved to advance Nuna development

Gov. Bill Walker made his first major oil policy decision Jan. 20, approving a temporary reduction in state royalty for Caelus Energy that will allow the company to develop its technically-challenged Nuna project on the North Slope. Under the deal, Caelus must formally “sanction” or commit to develop Nuna by March 30 but company officials said they will be undertaking some work this winter. Nuna is to be in production by September 2017 under the deal. It is expected to produce between 15,000 barrels per day to 20,000 barrels per day. “Our extensive review and analysis of the proposed Nuna project indicates that it will not proceed without royalty modification. The benefits to the state – in terms of increased revenue, production, jobs and new information that will spur additional North Slope projects – starkly outweigh the cost of the royalty modification,” said Marty Rutherford, deputy commissioner of the Department of Natural Resources. Although the company must begin production by Sept. 30, 2017, company officials told state legislators in a Dec. 2, 2014, briefing that they expect to actually have “first oil” by late 2016. Nuna will cost between $1.3 billion and $1.5 billion to construct, Caelus spokesman Casey Sullivan said. Nuna is onshore development near Caelus’ producing offshore Oooguruk field northwest of the Kuparuk River field on the North Slope. The royalty modification approved by the state Department of Natural Resources lowers the rate from 12.5 percent to 5 percent on five state leases held by Caelus for a period of years until the project receives $1.25 billion in revenues. After that the royalty will return to the 12.5 percent level. Caelus officials told a state legislative committee at the Dec. 2 briefing that they expect the revenue goal to be reached by about 2020. The state attached a condition to the modification that imposes penalties if the Caelus and its contractors do not hire 80 percent of the construction and operations workforce from within the state. The royalty reduction to 5 percent would result in a reduction of $44 million in state revenues compared with what would have been paid at the 12.5 percent rate, but the state will still receive about $1.3 billion in new revenues overall, according to documents released by the Oil and Gas Division. Without the modification it is doubtful the project would move forward, however. “Without royalty modification Caelus states it would be difficult to progress the project, or at least the project would be significantly delayed,” former state Oil and Gas Division Director Bill Barron told the Legislature’s Budget and Audit Committee in the Dec. 2 briefing. A key feature of the agreement is that Caelus will release a public report on new technologies to be employed at Nuna within 24 months of initial production, according to the state documents. Cealus officials told legislators in December that they intend to use large-scale hydraulic fracturing techniques to produce oil from the Torok and also to use fracturing to do water injection for waterflood, a new approach to tight-rock production. Barron said in December that the sharing of proprietary information is important because the Torok formation exists in other parts of the North Slope and it’s to the state’s interest that the experience gained by Caelus be available to other companies, and at no cost.

State officials to meet with credit rating agencies

In addition to being the state’s taxman, Revenue Commissioner Randy Hoffback is the state’s chief salesman on Wall Street. Hoffbeck, Deputy Revenue Commissioner Jerry Burnett and other state officials head for New York Feb. 1 to meet with the rating agencies that assess Alaska’s credit worthiness. As one of two deputy commissioners, Burnett is in charge of the Treasury Division, which includes matters relating to state bonds. Visiting the rating agencies is important because any change in credit worthiness that Moody’s Investor Services, Standard & Poor’s and Fitch Investor Services assign to bonds issued by the state will have a trickle-down effect on state corporations like Alaska Housing Finance Corp., the Alaska Industrial Development and Export Authority, and to municipalities. If the ratings are lowered, the interest rates on new bonds that are issued are typically higher, which makes borrowing more expensive. Right now the state has a AAA credit rating, the best available, and Hoffbeck aims to convince the rating agencies that this should be maintained. If the state is downgraded it would likely be AA+, which will make borrowing marginally more expensive. Both Moody’s and Standard & Poor’s recently issued letters putting Alaska on the “credit watch” list because of sharply lower oil revenues. This has created a lot of concern. The message Hoffbeck and Burnett will take to the rating is that Alaska has an issue with short-term cash but not overall revenues. “Even with oil prices low, we have a strong net worth. When we’re in New York we will stress that we intend to use our savings and that’s what they are for,” Hoffbeck said. Alaska has ample reserves to ride through this revenue crunch, he said. Hoffbeck isn’t overly concerned about the letters issued by Moody’s and Standard & Poor’s. “The letters won’t affect the ratings. They just means that they (the bond raters) are keeping an eye on us. It would be unfair for them to ding us for spending out of our savings. We don’t see any risk of a rate adjustment at this time,” he said. Any downward revision would affect only new bonds, and an increase in interest rates would be only marginally more expensive. The main effect would be a matter of pride, knocking Alaska out of the gold-plated AAA rating it has enjoyed for years. “We don’t want to lose that AAA rating,” Hoffbeck said. The state has a good credit rating not only because of the $12 billion in ready assets in reserve funds but also because of the $50 billion-plus in the Alaska Permanent Fund and the Fund’s annual earnings of several billion dollars per year. While the Fund itself cannot be spent without a constitutional amendment, the Legislature can appropriate some or all of the annual earnings at any time. So far the earnings have not been appropriated except for the annual Permanent Fund dividends, which typically tap only a part of the earnings. The rest of the earnings are either appropriated back into the Fund or simply held in an earnings reserve account. State corporations and municipalities ride the state’s coattails with good bond ratings because while the state is not legally obligated to cover debt issued by independent corporations and local governments, a default by any Alaska public entity would damage the credit rating for all state institutions and municipalities. If the state’s credit rating were to change it would likely affect state entities like the Municipal Bond Bank, which aggregates bonds for smaller municipalities, Burnett said. Larger municipalities like Anchorage may not may not be affected, he said. Likewise, state corporations like Alaska Housing Finance Corp. have a strong asset base in home mortgages and might not be immediately affected, he said. But other state entities might feel the effects. “We have a very good story to tell. We have a temporary revenue problem, although a big one. Oil prices will come back. We do have a longer-term structural problem,” an over-dependence on oil revenues, but there is also time to sort that out, Burnett said.

Industry is still buzzing about Walker firings

The state’s political and resource communities are still buzzing about Gov. Bill Walker’s sudden firing Jan. 6 of three Alaska Gasline Development Corp. board members and his order that new board members not sign confidentiality pledges. Besides the political theater, the concern is whether this might impair the state corporation’s ability to make decisions — and participate–— in the big Alaska LNG Project, where the state is a partner with industry and a 25 percent equity owner. Political transitions can be messy and firing people in government, particularly prominent citizens who are members of boards, is rarely done easily or smoothly. Each change of administration has its tales of fumbles and hurt feelings. One memorable example is that of how former Gov. Sarah Palin fired John Bitney, her legislative director. Bitney learned he was suddenly unemployed when he discovered his state-issued Blackberry wasn’t working — it had been disconnected — while he was driving the Alaska Highway en route to Juneau. Walker’s action Jan. 6 seemed hasty and even clumsy. The announcement went out while the board members were preparing for board meetings Jan. 7 and 8. Legislative leaders like House Speaker Mike Chenault, who are supporters of AGDC, were not informed in advance. Neither were AGDC board members who were retained, like former state Attorney General John Burns, who chairs of the board. Drue Pearce, one of the fired board members who is a former President of the Senate and U.S. Interior Department official, said she learned of her termination at 5:30 p.m. Jan. 6, three hours before the press release was published, when Walker’s Chief of Staff, Jim Whitaker, telephoned. “We had a pleasant conversation — we knew each other from having served together in the Legislature — and he told me ‘Drue, it’s not my choice, but the governor wants his own people on the board,’” Pearce said. “I told him I had enjoyed serving on the board, and said that if there was anything further I could do, I would be happy to help.” Al Bolea, a retired senior BP manager, didn’t get the courtesy of a phone call. He learned of his termination by email. Dick Rabinow, a 34-year top ExxonMobil official and former president of ExxonMobil Pipe Line Co., got his phone call the night of Jan. 6 as his plane landed in Anchorage. Rabinow was due to attend an AGDC technical working group meeting set for Wednesday, Jan. 7, in which new cost estimates for the ASAP 36-inch pipeline were to be finalized. Some of the information presented was confidential. Dave Cruz, another board member retained, and who previously signed a confidentiality agreement, attended the working group session. Two new members, Labor Commissioner Heidi Drygas and Acting Commerce Commissioner Fred Parady, could not attend the technical session because they were not allowed to sign the agreements. In his Jan. 6 press release Walker cited no reasons for firing the three board members but in an interview with a reporter the governor said wanted greater “geographic diversification” of the board. Grace Jang, Walker’s spokeswoman, said only Alaska residents are being considered for the new appointments. House Speaker Mike Chenault said Walker told him in a tense conversation that he would replace Rabinow, an experienced retired industry manager with extensive pipeline experience, with someone “of greater qualifications.” Walker said in the Jan. 6 press release he was already soliciting potential new board members. While no one argues the governor’s authority to hire who he wants for the AGDC board, there are concerns being voiced over the apparent lack of formal procedure to solicit names and vet applicants, which is customary in state government. The governor has possibly reached out to people he knew, perhaps from his tenure as manager of the Alaska Gasline Port Authority. Jang acknowledged the process is somewhat informal. “The governor’s office has received unsolicited applications for the positions, as well as recommendations. Governor Walker will review all of them,” she wrote in an email. Pearce said the big question now is what direction the governor wants to go on the gas project. “I look forward to knowing what it is,” Pearce said. Who is appointed to AGDC’s board may be less important that the issue over the confidentiality restriction of new board members. In the press release, Walker said, “I am committed to transparent government in which Alaskans are part of the conversation about our resources. I cannot allow my cabinet members to sign confidentiality agreements meant to keep information away from the public.” That sentiment is appropriate during the campaign but the day-to-day operation of government requires certain information to be held confidential and state laws provide for that, including for AGDC through its enabling legislation, House Bill 4 passed in 2013, which established the legal framework for the state gas corporation, and Senate Bill 138, which set out terms of the gas project partnership, passed in 2014. Walker’s directive creates an awkward situation where some continuing AGDC board members, Burns and Cruz, owner of a construction company, are still under previously-signed confidentiality agreements, while two commissioners who are board members, Parady and Drygas, have not signed, nor will the three new public members yet to be appointed by Walker. That means that currently some board members will be privy to information that other board members will not. A similar situation exists in the Department of Natural Resources where Deputy Commissioner Marty Rurtherford, the department’s lead person on gas pipeline dealings, has signed an agreement, but Commissioner Mark Myers has not. That means Myers, as commissioner and even Walker as governor, will be ultimately responsible for decisions without knowing the basis on which they must be made.  For the near term, however, the issue is unlikely affect day-to-day decisions and interactions between AGDC and the private partners in AK LNG, said Miles Baker, spokesman for the state gas corporation. Industry partners in the consortium led by ExxonMobil will not discuss any sensitive matters regarding the project with individuals who have not signed nondisclosure agreements, but the day-to-day contacts are handled by AGDC senior managers who are covered by agreement, Baker said. The corporation’s board has approved a work plan for AGDC for its share of the pre-front end engineering and design, or pre-FEED, activity through to the end of calendar year 2015, Baker said, so there is no need for board decisions unless there is a revision or an authorization is needed for certain work to extend into early 2016, he said. The AK LNG Project group hopes to have pre-FEED activity finished up in early 2016 so that a decision can be made to proceed to the full FEED activity, which will set the stage for a construction decision in 2018 or early 2019. In day-to-day interactions, budget decisions and the periodic “cash calls” from ExxonMobil, the project leader, are of most concern. When a cash call is issued, the partner, a company or the state, must make payment within 10 days or pay substantial penalties. Decisions on funding cash calls can be made by AGDC senior staff, Baker said. However, there are confidential negotiations underway now between the state and industry over the commercial structure of the project if it moves from pre-FEED into FEED. This is on the form of the governing structure, whether the FEED work will all be delegated to one company or some governing board of all the partners will be established. This is the kind of high-level decision that should involve AGDC’s board. Another commercial-type change could come if AGDC becomes a formal party to the export license application made to the Federal Energy Regulatory Commission, or FERC. The state is currently not a party to this application — it was made by the three producer companies who own gas — and the state may need to become a party to receive FERC approval to export state-owned LNG, which the partnership agreement provides for. Also, the land being purchased at Nikiski, near Kenai, by the AK LNG Project partners is being done by the three producers with AGDC not involved so far, although the state corporation will directly own 25 percent of the large LNG plant to be built there. TransCanada is involved only in the pipeline and North Slope gas treatment plant, not the LNG plant. Because land assets are being purchased to serve an LNG plant the state will partly own, AGDC will ultimately have to become a party to the transactions.

US demand slipping, Pacific market still strong for coal

Oil markets may be in the tank, but there’s another fossil fuel people often forget where the market situation is quite different: Coal. Demand for coal used in power generation is soaring on world markets, up 300 percent since 2000. However, the supply of coal has kept up with demand, so prices are soft, although nothing like what is being seen in crude oil. Despite that, potential to grow the Alaska’s coal industry is clearly there, Dan Graham, president of the Alaska Coal Association, told the Alaska Support Industry Alliance’s annual “Meet Alaska” conference Jan. 9. Alaska has huge coal resources and has long had a toehold in Pacific coal markets through steady exports from the Usibelli coal mine near Healy, he said. Coal doesn’t compare with oil and gas — at least yet — but 408 Alaskans work full-time now in the coal industry including 130 at the Usibelli Mine Inc. mine at Healy and others in coal-fired power plants or in support of the Alaska Railroad Corp.’s coal trains and coal terminal operations in Seward. When indirect jobs are added (jobs created by people directly employed) the job effect increases to 692, with a $52 million payroll. Alaska’s coal exports are small compared with exports from big players like Australia and Indonesia, but they are enough to keep Alaskans in the game and also to remind buyers of the superior environmental qualities of Alaska’s coal. The environmental advantages are mainly the low sulfur and mercury content of the Alaska coals, Graham said. Alaska coal has one-third of the mercury found in other coal being marketed in the Pacific rim, and an ultra-low sulfur content of 0.1 percent compared with 0.5 percent for most coal marketed in the Pacific and up to 6 percent for some bituminous-grade coals. Usibelli has been exporting a half-million to more than a million tons per year since the mid-1980s with coal shipped by rail to Seward where it is loaded on ships. The company has decades of coal reserves on its coal leases near Healy. Usibelli is also working on development of a smaller mine near Palmer, at Wishbone Hill. Graham himself is the manager of the Chuitna Coal Project, a large surface coal mine planned near Beluga on the west side of Cook Inlet. PacRim Coal, the developer of the Chuitna project, has been engaged in permitting and environmental studies for several years and a supplemental environmental impact statement, or SEIS, is nearing completion. A final EIS had been previously issued for the mine but a change in the development plan required a revision in an SEIS. If the mine proceeds, it would add another 350 to 400 direct coal mining jobs to the industry workforce, with an added payroll of about $70 million, Graham said. If Usibelli proceeds with the Wishbone Hill mine it would add up to 500,000 tons per year of coal production at maximum depending on purchases by customers, and employ 75 to 125. Alaska has a lot of room to grow as a coal state. Half of the nation’s coal resources and a third of world coal resources, Graham told “Meet Alaska,” and though many of those resources are located in remote areas like the western Arctic Slope a lot of it is easily accessible to ice-free ports, like Usibelli’s mine and the potential Chuitna mine, which is at tidewater, as well as Wishbone Hill. Much of the Arctic coal resources, which are vast, are owned by Arctic Slope Regional Corp. of Barrow, the Alaska Native regional development corporation for northern Alaska. Over time, Alaska’s resource base and geographic advantages will come into play. Indonesia, a big player in the Pacific coal markets, is increasingly concerned about meeting its own domestic energy needs, which are growing, Graham said. “Indonesia has been the top exporter in the Pacific but the volume is now tapering off. The government is now capping exports to protect coal for domestic use,” he said. Australia is another big exporter but there are infrastructure constraints, mainly access to ports for shipping. “Australia has great coal, but it is infrastructure limited,” Graham said. There are also concerns over export taxes levied by the government. Infrastructure bottlenecks have also become a challenge for U.S. coal exporters. Coal from the Powder River Basin in the western U.S., which has long been exported, is now being routed through Canada because of clogged U.S. rail lines and limited west coast port capacity. In terms of demand, the big customers are China and India. China imported 11 million tonnes in 2006 and India imported 23 million tonnes. In 2013, China’s imports had soared to 204 million tonnes and India’s to 140 million. Both are expected to import about 200 million tonnes this year. (A tonne is 2,200 pounds compared with the ton, which is 2,000 pounds.) While Asia coal imports are booming, U.S. demand is down partly because of new environmental rules and partly due to a surge of lower-prices natural gas due to shale gas production. Coal is mainly used in power generation. In Alaska, most power generation is still fueled with natural gas in Southcentral Alaska and in Southeast from large hydro projects, but Interior Alaska has a diversified mix of fuel that includes coal from the Usibelli mine. Recent rate filings by Golden Valley Electric Association, the Interior electric cooperative, show coal to be the least expensive fuel except for hydro, which in the Alaska railbelt comes from the Bradley Lake hydro project near Homer. “The absence of coal in Interior Alaska would raise energy costs $200 million annually,” Graham said. Capacity constraints on the railbelt transmission grid limit the efficient use of sending hydro power from Bradley north to Anchorage and Fairbanks, however. Golden Valley buys wholesale gas-generated power from Chugach Electric Assoc. in Anchorage but it also has a priority to have its own generation capability “north of the range” (Alaska Range) and coal-fired power is a key part of that. The co-op will be able to purchase more inexpensive coal-fired power when its 50-megawatt Healy Plant No. 2, now being restarted, comes online. That is expected in 2015.

BlueCrest, WesPac ink deal to develop Cosmo

BlueCrest Energy plans to resume drilling at the Cosmopolitan oil and gas deposit near Anchor Point this summer, BlueCrest CEO Benjamin Johnson said. The company, based in Fort Worth, Texas, has signed a Memorandum of Terms with WesPac Midstream LLC to help finance development of gas resources at Cosmopolitan oil. BlueCrest will move a land drill rig to an onshore pad this spring to begin preparations for drilling high-angle, or deviated, wells to the oil reservoir at Cosmopolitan, which is about three miles offshore. This summer the company also hopes to begin drilling offshore wells into the shallower gas reservoir with a jack-up rig, Johnson said. WesPac Midstream is working on a medium-sized liquefied natural gas, or LNG, plant at Port MacKenzie, in upper Cook Inlet, with a goal of supplying LNG to Alaska communities and industrial customers. The company is a “midstream” energy development company specializing in fuels. It is owned principally by a private equity investment fund managed by Oaktree Capital Management, LP. Oaktree is a global investment management firm with more than $93 billion in diversified assets under its management as of Sept. 30, 2014. The company has substantial experience in the energy, finance, and infrastructure industries. WesPac Midstream is developing several liquefied natural gas, or LNG facilities in major market areas in the US and Canada. The company recently inked a deal to supply LNG to Totem Ocean Trailer Express, or TOTE, from a first-of-its-kind LNG fueling facility in Jacksonville, Fla. TOTE will have two large ocean freight vessels operating between Jacksonville and Puerto Rico which, when completed, will be fueled by LNG from WesPac’s Jacksonville facility by late 2016. TOTE also operates ocean freight service to Alaska from Tacoma, Wash. Terms of the BlueCrest/WesPac arrangement are confidential but Johnson said it involved “several hundred million dollars” in capital commitment for the drilling of gas production wells and installation of two offshore production platforms at the field, which is near Anchor Point, south of Kenai. “The agreement is subject to definitive documentation and all necessary governmental approvals, as well as confirmation of underlying agreements and approval by the Boards of both companies,” Johnson said. BlueCrest would remain the operator of the field, he said. WesPac intends to sell the produced natural gas to markets in Alaska, either as LNG delivered by truck, rail, marine vessel or directly as natural gas delivered into the existing gas pipeline infrastructure. The WesPac partnership will allow BlueCrest to focus on development of the deeper oil deposit at Cosmopolitan, Johnson said. The company plans to begin drilling extended-reach production wells into the oil reservoirs with a shore-based drill rig this summer. BlueCrest plans to drill up to 20 new oil wells over the next five years and is currently completing the preparatory work for those wells. The shallower gas deposit will be produced using vertical production wells drilled with a jack-up rig, Johnson said. BlueCrest hopes to make arrangements to use the Spartan 151 jack-up rig now in Cook Inlet, although the rig is currently slated to be used by Furie Operating later in the summer to assist in that company’s construction of a gas production platform its Kitchen Lights project in north Cook Inlet. A second jack-up rig, the Endeavour, had been in Cook Inlet and was used by BlueCrest to drill an exploration well at Cosmopolitan in 2013. The Endeavour recently departed for South Africa, but in light of current market conditions, Johnson said he believes that BlueCrest will easily be able to find another suitable rig under very favorable terms. BlueCrest hopes to install the first gas production platform in 2016 and a second in 2017. Each platform will be capable of handling 35 million cubic feet per day of gas, or 70 million cubic feet per day total. Johnson said the estimate of oil and gas reserves at Cosmopolitan is confidential but the capacity of the production facilities gives an indication of the reserve size. “We had been focused mainly on the oil development with the gas as a secondary goal, but WesPac came in and will now fund and accelerate the gas development,” he said. The only published estimates of oil reserves at Cosmopolitan within the last several years were included in Buccaneer’s September 2013 quarterly report to investors and were based only on the earlier ConocoPhillips and Pioneer drilling (not accounting for the results from the 2013 drilling program). That report listed 31 million barrels of oil of proven reserves; 44 million barrels of oil of proven and probable reserves and 70 million barrels of oil estimated as proven, probable and possible resources. One new offshore well was drilled at Cosmopolitan in 2013 with Buccaneer, the 25 percent minority owner, as operator. Drilling began in May 2013. The first well, drilled to 7,599 feet, encountered productive gas sands from approximately 800 feet down to 5,600 feet deep and newly-found oil sands approximately 400 feet above those previously discovered by ConocoPhillips and Pioneer. No long-term production tests on the oil zones were conducted, because of limitations in storing oil produced from a flow test. However, two of the newly-discovered oil sands were flowed to the surface under carefully constrained conditions in order to confirm their productivity. A test of gas-bearing sands in the 2013 well at 5,500 feet depth flowed at a choked-back rate of 7.2 million cubic feet per day. In the second test, a gas-bearing sand at 4,300 feet was tested and flowed at a choked-back rate of 7.3 million cubic feet per day. BlueCrest has not announced what the gas sands would be capable of producing under a full production mode. Cosmopolitan was discovered years ago by ConocoPhillips, who at the time did not have access to an offshore drilling rig to vertically explore the entire productive interval. ConocoPhillips sold the prospect to Pioneer Natural Resources, which had planned to develop the oil reservoir using production wells drilled from shore. Pioneer drilled another test from shore but then decided to exit Alaska to focus on the company’s shale oil program in Texas. Cosmopolitan was sold to BlueCrest and a minority partner, Buccaneer Energy. BlueCrest itself has invested about $110 million in Cosmopolitan so far, Johnson said. The existence of the shallow gas reservoirs were always suspected, but they had not been confirmed until the 2013 exploration drilling by BlueCrest and Buccaneer. BlueCrest subsequently bought out Buccaneer’s minority interest. Rashah McChesney of the Peninsula Clarion contributed to this article.

New confidentiality policy for AGDC

Alaska Attorney General Craig Richards said the administration of Gov. Bill Walker understands the need for protection of certain private information in the state’s dealings with industry partners in the Alaska LNG Project, but that the current confidentiality provisions that cover the state gas corporation are too broad. Walker stirred a political tempest Jan. 6 when he fired three Alaska Gas Development Corp., or AGDC, board members and also ordered new board members not to sign a confidentiality agreement. Richards said in a Jan. 14 interview with the Journal that the current requirement keeps too much information from the public and that a new policy is being developed that will allow more open discussion of AK LNG issues in public while protecting certain private information. The new policy could be enacted through a new AGDC regulation, which the corporation has authority to do, or it could be through a new confidentiality agreement that board members can sign. “This is a two-month problem,” Richards said, meaning that the new policy will be in place by late spring. AGDC’s attorney, Ken Vassar, and Jerry Judah, a Department of Law attorney assigned to AGDC, are working on the new policy now, Richards said. The problem the governor and Richards have with the current situation is that AGDC is a party “by reference” to the very strict confidentiality agreements signed by the AK LNG industry partners among themselves that protects business information. These restrictions apply to AGDC’s staff and previously also to its board. The new policy will spell out information that can be provided in public to the board, such as during board meetings. “Our goal is to have information related to the AK LNG Project flow to the board in a more public way,” Richards said. All state agencies and Alaska public bodies, such as municipalities, have confidentiality provisions but the default, set out in the state Open Meetings Act, is that all meetings and discussions are public unless held confidential by specific references in statute. “For example, municipal assemblies can go into executive session to discuss personnel issues or litigation, and this is allowed under statutes,” Richards said. Similarly, the Department of Natural Resources is required to keep certain information confidential and the terms are set out in the Alaska Lands Act. “Our model going forward will be the DNR model,” Richards said, where the bias will be more toward information being public than held confidential. The AK LNG Project agreements are crafted so tightly, however, that information and agreements that should be public, in the administration’s view, are confidential, he said. For example, the Joint Venture Agreement signed last summer by BP, ConocoPhillips, ExxonMobil, TransCanada and AGDC is an important document that should be public, Richards said. “I don’t know what’s in it. No one has seen it (in public) and that’s unacceptable,” he said.  The state statutes that govern AGDC are too loose in this respect, with words that information “may” be public but not that it “must” be public, Richards said. Whenever the new policy, regulation or agreement is completed, the terms under which AK LNG information can be public in AGDC board meetings will ultimately have to be agreed to by the industry partners, Richards said. The underlying problem with the “DNR model” as a guiding principle is that the functions of the department in administering state lands are fundamentally different than a business partnership like that the state has entered into in the AK LNG Project. It’s a different paradigm. The state entity that comes closest to the AK LNG partnership are the equity investments made by the Alaska Industrial Development and Export Authority in various ventures, such as a new North Slope oil processing facility and a jack-up drill rig that operated in Cook Inlet. AIDEA’s board members do sign confidentiality agreements and frequently go into executive session in dealing with negotiations on these projects, and Richards said he is not familiar with AIDEA’s projects and procedures. The goal, however, is to have the new policy apply to all state agencies and corporations, he said.

Slope construction season still strong amid price plunge

It’s a seeming paradox: Oil prices are still sliding as North Slope crude closed at about $55 per barrel Jan. 6, but this year’s winter construction season is shaping up to be one of the strongest ever. Industry employment, the most reliable indicator of activity, set new records in October and November, according to data from the Alaska Department of Labor and Workforce Development. There were 15,100 at work in the industry in October and 15,000 in November, although the November data is still preliminary. That’s up by about 800 compared to the same months of 2013 and by 1,000 compared to October and November of 2012. Most of the 2014-15 winter activity has to do with projects previously launched, however, and capital spending decisions to be made by the North Slope producers in early 2015 may set a different tone. In 2014, ConocoPhillips announced a 50 percent increase in its 2014 Alaska capital budget and BP, the other major Slope operating company, announced a 25 percent increase for 2014. Those budgets will be reviewed in early 2015, however. For now the industry is still riding with the momentum from a surge of new activity following the Legislature’s approval of a revamped oil production tax in 2013. Work continuing this winter includes the $4 billion Point Thomson gas and condensate project east of Prudhoe Bay, where ExxonMobil Corp. is continuing construction. The company will be moving a drill rig back to the field as soon as a 50-mile winter ice road is finished. The company will also be moving “truckable” modules to the site this spring. The big part of the 2015 activity at Point Thomson will be the summer sealift with the planned arrival of four large production modules now being fabricated in Korea. These will have a combined weight of 10,000 tons. Point Thomson will begin production in 2016, producing and shipping 10,000 barrels per day of liquid condensates to the Trans-Alaska Pipeline System at Prudhoe Bay. Another big project underway is CD-5, a $1 billion new drill site near the Alpine field that is west of the Prudhoe Bay and Kuparuk River fields. ConocoPhillips has essentially completed three smaller bridges with only minor completion work to be done this winter. Meanwhile, construction of a larger span over the Nigliq Channel of the Colville River is nearing completion. Other work this winter and spring includes installation of the drill site facilities, power lines and the pipeline. Drilling of production wells will begin in May. About 700 people will be working on CD-5 this winter and spring. “First oil” is expected in December 2015, with production estimated to peak at 16,000 barrels per day. Another ConocoPhillips project underway is at Drill Site 2S in the southern part of Kuparuk River field, a $500 million project. This is the first new drill site built in the Kuparuk field in years. Production is also expected to start in late 2015, with an estimated peak production of 8,000 barrels per day. About 250 people will be employed on the Drill Site 2S project this winter and spring. In another development, independent Brooks Range Petroleum has started its drilling of production wells at its Mustang field project, also west of the Kuparuk field. Nabors Alaska Drilling Rig 16E was moved to the location in December. Brooks Range plans to award contracts for fabrication of field production facilities this spring and to have those built and moved to the Slope by late 2015. Meanwhile, another independent, Caelus Energy, plans to begin work this winter on its new Nuna project near the Oooguruk field, which Caelus also operates, but the company is still awaiting approval on a royalty modification deal with the state of Alaska.  If Caelus proceeds on Nuna, gravel installation will take place this winter and spring, and facilities and flow-lines will be installed in 2016. Production is targeted to begin in late 2016 but under terms of the royalty modification, if it is approved, Nuna production must be underway by March 31, 2017. Nuna has an estimated 50 million to 100 million barrels of recoverable reserves, Caelus’ senior vice president for Alaska, Pat Foley, told a state legislative committee in a Dec. 2 briefing. Caelus expects to have about 500 contract workers employed this winter in addition to its company operations staff of about 80, Foley said. Some of the contractors will be employed on projects other than Nuna, such as at the Oooguruk field itself and a large seismic program that Caelus will have underway east of Prudhoe Bay. That is where the company acquired new leases in the fall 2014 state areawide lease sale. Overall North Slope capital investments are estimated at $4.45 billion this year and are expected to increase to $4.88 billion in 2016, according to figures given by companies to the state Department of Revenue. The years are in state fiscal years, with the current fiscal year 2015 starting last July 1 and fiscal year 2016 beginning this July 1. By comparison, the industry spent $3.73 billion for capital projects in 2014, the fiscal year ending last June 30, according to the state data.

Hilcorp files plan for Liberty field development

Hilcorp Energy filed a Development and Production Plan Dec. 30 for the proposed offshore Liberty project in the Alaskan Beaufort Sea with the U.S. Bureau of Energy Management. The project would involve an artificial gravel island and a subsea pipeline to shore, company officials said. Hilcorp recently closed on the purchase of 50 percent of Liberty from BP along with three small producing North Slope fields. Hilcorp is the operator at Liberty with BP remaining as a 50 percent partner. Liberty is a long-known but undeveloped deposit in shallow waters five miles off the Beaufort Sea coast and east of the Endicott field, which is also now owned and operated by Hilcorp as a part of the acquisition of BP properties. The production island would be connected to shore with a subsea pipeline, and with a short overland pipeline segment to a tie-in with the existing Badami Pipe Line. Hilcorp’s North Slope Operations Manager Mike Dunn said the deposit has estimated recoverable oil reserves that range from 80 million to 150 million barrels. Based on what is now known, Hilcorp expects Liberty to produce about 60,000 barrels per day at peak, Dunn said. The company expects regulatory reviews and permitting to require about two years, which means that construction of the artificial island could be started in 2017. Construction is expected to take about two years, which would mean first oil in 2019 if everything stays on schedule, Dunn said. Hilcorp also purchased 100 percent of the offshore Northstar field in the deal with BP, which is similar to Liberty in size, along with 50 percent of the Milne Point field BP also developed with an artificial gravel island and subsea pipeline. Early on, BP had planned to develop Liberty with an offshore gravel production island and subsea pipeline, like it had done at Northstar, but switched to an alternative of drilling extended-reach, high-angle production wells from shore partly out of concerns for the permitting issues of building another artificial production island. Technical obstacles prevented that from happening, and BP switched back to the offshore island concept prior to the sale to Hilcorp. Dunn said his company will be able take advantage of BP’s experience in building and successfully operating at Northstar for 14 years as well as the experience of Pioneer Natural Resources and Eni Oil and Gas in constructing and producing the small Oooguruk and Nikaitchuq offshore fields west of Northstar. Liberty is in more benign offshore environment than Northstar. The area where the artificial island would be built is covered by stable “shore-fast” sea ice in winter, meaning ice that is fixed to the shore and has little movement. Liberty is within a belt of offshore barrier islands, which offers protection from the heavy, moving polar icepack. Northstar, in contrast, is in a location that has no barrier island protection and is exposed to moving winter ice. Northstar is west of Liberty and six miles north of Prudhoe Bay. Although it is more exposed the moving ice has never presented an operational or safety issue at Northstar in its 14 years of production. The filing of the development plan with BOEM is the start of an extended regulatory proceeding. “BOEM now has 25 working days to conduct a preliminary review to assess whether the application includes all required components,” BOEM spokesman John Callahan said in a statement. “By the end of that period BOEM must either formally deem the development plan submitted, which triggers further regulatory review and a review under the National Environmental Policy Act, or let Hilcorp know what additional information would be required in order to deem the plan submitted.”

Linc Energy won't need access road for Umiat field project

An independent oil and gas company working on development of a small oil field at Umiat, on the southern North Slope, said the state’s termination of permitting for a resources road into the area won’t affect its plans. The company, Australia-based Linc Energy, believes it can develop the field as a “roadless” project with surface access by winter snow road. A pipeline would still be needed, however, said company spokesman Paul Ludwig. The U.S. Army Corps of Engineers published a notice in the Federal Register Jan. 5 that it has halted work on a federal environmental impact statement, or EIS, for the road, and was requested to do so by the project sponsor, the Alaska Department of Transportation and Public Facilities. The Army Corps was acting as lead agency in supervising third party contractors working on the EIS but was taking a neutral position on the road, according to a statement from Corps spokesman John Budnik. “The Corps has suspending work and has closed the project file. After confirming on Oct. 21 that the agency (the state DOTPF) has no future plans to proceed with the project, the Corps determined that the appropriate action was to terminate the EIS,” according to the statement. Ludwig said Linc Energy is still in the process of evaluating reservoir data from drilling last winter. That evaluation will guide planning for potential production and the needs for infrastructure including roads, Ludwig said. The company has been doing its own evaluation of possible road routes including three other potential corridors in addition to those being studied by the state. “We are also evaluating whether we can develop the project using winter roads,” he said. Linc Energy built a 100-mile snow road from the Dalton Highway to Umiat two winters in a row to support winter drilling operations. Umiat is within the National Petroleum Reserve–Alaska and on the Colville River at the far southeast border of the reserve. It was a support site for 1950s-era U.S. Navy exploration in the reserve, then the Naval Petroleum Reserve No. 4 as well as further exploration by the U.S. Geological Survey and private companies from the 1970s on. The oil deposit at Umiat, which is small and shallow, was discovered in the early Navy drilling. The U.S. Bureau of Land Management ultimately sold leases in the area to private companies. Linc Energy acquired leases held by Renaissance Umiat, an exploration company. Seismic and drilling exploration by Linc Energy has confirmed the presence of 155 million barrels of reserves and 194 million barrels of potential reserves. The oil-in-place (oil held in the reservoir rock) is estimated at 1.2 billion barrels. The known resource at Umiat is small but also shallow — some of the oil is literally frozen into the permafrost layer extending down 2,000 feet on the North Slope — but the oil is also of very high quality, approximately 45 degrees of API gravity. Linc Energy had hoped to find additional oil resources below the known deposit in its first year of exploration drilling, but failed to do so. In the second year the company drilled test horizontal production wells in the shallow deposit and achieved a flow of oil but not at quantities hoped for. The drilling results are still under analysis, Ludwig said. Petroleum engineers familiar with Umiat have said that Linc Energy may be able to adapt technology that could boost production, such as with natural gas. There may be natural gas on the leases at Umiat but a known gas discovery was also made in early Navy drilling at Gubik, on state lands to the east of Umiat. Those resources are now owned by Arctic Slope Regional Corp. and are under lease to Anadarko Petroleum Corp. The state’s road plan had become a political issue on the North Slope. Inupiat villagers at Anaktuvuk Pass, in the Brooks Range, have expressed concerns over impacts that an east-west gravel road would have on seasonal caribou migrations. There were also concerns that access to the area would be opened to sport hunters driving north on the Dalton Highway, which is a public state road. The North Slope Borough, the regional municipality, has proposed an alternative route from the north that would link with existing oilfield roads in the Kuparuk and Alpine field areas. This would solve concerns over access by sports hunters because of controlled access and heavy security on the private oilfield road system.

Citing transparency, Walker fires three AGDC board members

Gov. Bill Walker’s already troubled relations with the new Legislature have just gotten a lot worse. Walker fired three board members of Alaska Gasline Development Corp. and instructed four remaining members not to sign confidentiality agreements on information related to projects the state-owned entity is managing. That includes the state’s interest in the large Alaska LNG Project, particularly the 25 percent share of the large liquefied natural gas plant at Nikiski that AGDC will own and manage directly, as well as the Alaska Stand Alone Pipeline, the 36-inch gas pipeline alternative that is in the planning stages as an alternative in case the Alaska LNG Project fails. Walker dismissed former state Sen. Drue Pearce and Al Bolea, a retired senior BP manager, from the ADGC board as well as Richard Rabinow, a former ExxonMobil senior pipeline project manager. Two public board members remain on the corporation board, attorney John Burns and Dave Cruz of Cruz Construction Inc. Heidi Drygas, Commissioner of the Department of Labor and Workforce Development, and Fred Parady, acting Commissioner of Commerce, also serve on the AGDC board. Walker said he intends to name potential replacements in 30 days. Rep. Mike Hawker, R-Anchorage, said no one is disputing Walker’s authority to fire board members, but restricting the board from having access to confidential information to make sound decisions will put the Alaska LNG Project at serious risk. That’s because industry partners need assurance that their own private information will be protected during negotiations with the state, as well as confidential state information being protected from disclosure to the private firms, or to groups leading competing gas projects elsewhere. Hawker is one of the sponsors of legislation creating AGDC. Walker said he instructed the AGDC board not to sign confidentiality agreements because he is seeking greater transparency. “I am committed to a transparent government in which Alaskans are part of the conversation about our resources,” the governor said in his Jan. 6 statement issued at nearly 9 p.m. “I cannot allow my cabinet members to sign confidentiality agreements meant to keep information away from the public.” Confidentiality protections are quite common in state government, however. For example, Natural Resources Deputy Commissioner Marty Rutherford, who has been chosen by Walker to head the state team in negotiations with industry on the Alaska LNG Project, has signed a confidentiality agreement to protect private and state information on gasline issues. Other state boards and commissions routinely deal with confidential information including the Alaska Industrial Development and Export Authority board in matters pertaining to AIDEA’s investments with private partners. In fact, state employees sign confidentiality agreements as a routine condition of employment. Hawker said he is unhappy that Walker has injected politics into the issue. “It’s not unexpected that the governor would make board replacements to get control of AGDC, but this is still of great concern because we went to great lengths to insulate the state corporation from politics, as was done with the Permanent Fund, and this runs counter to that,” Hawker said. “I believe this will put the AK LNG Project on hold because the industry partners will not negotiate or share their private information with the state, as a partner, unless there are protections in place.” Any final agreements between the state and industry come back to the Legislature for approval under full public exposure. Confidentiality is important mainly while negotiations are underway, Hawker said. House Speaker Mike Chenault, R-Nikiski, another prime sponsor of the legislation creating the AGDC, was more restrained but also expressed serious concerns. “I’m concerned about what delays this may cause the AK LNG Project and what message we are sending our industry partners,” Chenault said. “The governor certainly has the power to do what he did. The Legislature granted the governor that power in House Bill 4, which created and directed AGDC. I’m disappointed that Gov. Walker has chosen to eliminate these board members, who have proven their worth and commitment to Alaska in the progress made already. “It’s going to be hard to replace the 60 years of knowledge that these three board members bring — and in particular, the expertise of Dick Rabinow, who is the only board member to have actual gasline construction experience under his belt. My greatest concern is what delay is this action going to cost the AK LNG and ASAP projects? With a substantial turnover in leadership (at AGDC), how much longer will Alaskans wait for natural gas?” Walker said he is interviewing potential replacements for the three board members he fired but those candidates, when selected, will have to be confirmed by the Legislature. Chenault said those candidates will be subjected to the same rigorous examination by legislators as were the board members Walker fired. Hawker said the Legislature shouldn’t be “vindictive” in the confirmations because of the unhappiness over Walker’s actions. “We’ll have to see who he appoints. We have lost 60 years of combined experience and expertise in the board members we have lost,” he said. In his comments, Hawker said, “I’m deeply concerned that this signals a wholesale change of course for Gov. Walker on gas commercialization. An overwhelming majority of legislators approved creation of AGDC, and of its mission, which is clear in law: to pursue a natural gas project that delivers gas to Alaskans first, then to markets beyond. “In creating AGDC, the Legislature carefully weighed the need for confidentiality in some issues with the need for public accountability. The legislature struck a balance between transparency to Alaskans, and the need to protect commercially sensitive information, third-party private company information, and information that, if known, could adversely impact the price Alaskans receive for its gas. “All the key business agreements crafted by the state under confidentiality agreements will, by law, be brought back to the Legislature for a fully transparent, public vetting and approval.” The existing AGDC board was given legislative confirmation and two of the three board members Walker dismissed were confirmed by a majority of lawmakers. “Those votes were bipartisan as were the votes in favor of legislation establishing AGDC which contained authorization for confidentiality,” said one source in the Legislature, asking not to be identified. “The governor’s action certainly goes against the grain of the Legislature’s past support, so regardless of what a legislator might think of Walker, this kind of thing just doesn’t go over well.” Walker has himself supported confidentiality in gas negotiations in the past. Most proceedings of the Alaska Gasline Port Authority, an independent pipeline development group Walker headed, were kept confidential. The port authority is a nonprofit creation of municipal governments in Valdez, Fairbanks and the North Slope but rules of public disclosure that apply to government bodies do not apply to port authorities. Legislators asked Walker in hearings if he could divulge terms of negotiations with potential Japanese customers and Walker said no.

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