Tim Bradner

State board sets new method for workers’ comp payments

The state has adopted a new method for paying physicians and other health providers for services provided under Workers’ Compensation to injured workers. New regulations were adopted Oct. 29 by the Alaska Workers’ Compensation Board, which met in Anchorage. The change is aimed at slowing an annual rise in medical payments under workers’ compensation claims that result partly because of the payment formula. The new procedure, approved by the Legislature in 2014, replaces the previous system of paying medical service providers at the 90th percentile of “usual and customary” fees in the region with a new method that sets a value for a procedure that accounts for a provider‘s work, practice expense and malpractice insurance. The value is adjusted by a regional multiplier that adjusts for higher Alaska’s higher costs. Thirty-two other states have adopted the new payment system for workers’ compensation, according to Marie Marx, director of the Division of Workers’ Compensation. “Alaska has used the usual, customary and reasonable (UCR) fee schedule since 2004. The UCR rate was set at the 90th percentile, so for every procedure in workers’ compensation, the ninth-highest payer was considered the maximum allowable rate,” Marx said. “This schedule was inherently inflationary, because once a fee schedule was published charges tended to rise to and above the maximum level of payment, which guaranteed an annual increase in the UCR charge. “The new methodology, called the Resource-Based Relative Value Scale, assigns a relative value to each procedure, and then applies a multiplier (a fixed conversion factor). The value is multiplied by the fixed conversion factor set by the state to determine the amount of payment.” Marx acknowledged that not everyone is happy with the new system. “We received many public comments, and the reaction was varied,” she said. In a statement, the Department of Labor and Workforce Development said, “Alaska has had the highest workers’ compensation rates in the nation over the past decade although Alaska workplace injuries have declined significantly. The new fee schedule should reduce workers’ compensation costs.” That will result in lower workers’ compensation premiums paid by employers in the state. Other states have had to cut workers’ compensation, in some cases allowing companies to opt out, the department said. In contrast, “Alaska has sought to strengthen its system while also working to reduce costs for businesses that pay premiums.”

Positive reviews for fiscal plan, but budget gap remains

Gov. Bill Walker’s plan to revamp the state’s financial structure and narrow a huge budget deficit is getting good marks in the financial community. Standard and Poor’s likes it, but adds that it doesn’t go far enough. Standard and Poor’s is one of the state’s credit rating agencies and issued a warning in August that the state was facing rapid downgrades from its top “AAA” rating if action was not taken in the next legislative session to put the state on a more sustainable path. In Alaska’s financial community, Joe Beedle, CEO of Northrim BanCorp, sees it as very positive, but adds that Walker has to get a lot more aggressive on the state fiscal gap. So far no one is throwing bricks at it because of a likely reduction in Permanent Fund dividends. That’s a good sign. State Attorney General Craig Richards unveiled the plan, which has been in the works since last January, in a luncheon address to state legislators in Juneau Oct. 28. The plan has taken various forms over the last few months and at one time involved an arbitrage concept where large sums would be borrowed against the value of the combined state assets, something like a consumer borrowing against home mortgage equity. Walker ultimately backed away from that as being too risky, according to sources familiar with the working group the governor had assembled. The core of the current plan, as Richards explained it Oct. 28, is to bulk up the state’s Permanent Fund, now with a value of about $53 billion, by transferring in other state savings accounts like the Constitutional Budget Reserve, or alternatively putting funds now in the state Constitutional Budget Reserve into the Earnings Reserve account of the Permanent Fund. Richards said the combined value of the state’s liquid assets, counting the Permanent Fund, CBR and certain other funds, but not including pension funds, total about $60 billion. An important change in the plan is that oil tax revenues would flow directly to the Permanent Fund and additional oil royalty income. Currently, 25 percent of oil royalties and lease sale bonuses go into the Fund. Walker’s plan would increase that, so that all oil production tax revenue and half of state royalty oil income (in addition to the 25 percent now dedicated by the state constitution) flow into the Permanent Fund rather than the state’s general fund. The remaining 50 percent of oil royalties (net of those dedicated to the Permanent Fund), would finance the annual citizen dividends. Currently dividends are funded by earnings from the Permanent Fund itself, on a five-year rolling average. Other, non-petroleum tax revenue would continue to go to the general fund as well as certain oil taxes that are not as volatile as production taxes and royalties, Richards explained. These include the state corporate income tax on oil and the state property tax on oil production and transportation property, he said. If the plan were adopted, the estimated revenues for fiscal year 2017, the state budget year beginning next July 1, would be about $3.3 billion, according to preliminary estimates by the governor’s working group. In contrast, state oil revenues paid to the state general fund in the current fiscal year 2016 will total about $1.55 billion. Non-petroleum revenues would flow to the general fund as they do now and are expected to total $550 million, according to the estimates. Other petroleum revenue, the corporate and property tax income, would contribute $275 million, and would go to the general fund. These bring total state revenue under the plan to $4.125 billion, Richards said in his presentation. Assuming a fiscal year 2017 state unrestricted general fund budget close to the current fiscal year budget of $5.18 billion (the governor is expected to introduce his actual FY2017 plan soon) a $1.06 billion gap is still left. “That is manageable,” Richards told legislators Oct. 28. The combination of new budget cuts and possible new tax revenues could make up the difference, he said. Permanent Fund as shock absorber The theory behind the plan, which is being described as an endowment, is that placing oil revenues into the Permanent Fund rather than the general fund would allow the Fund to absorb the shocks of oil volatility rather than the state general fund, the attorney general said. In the general fund, sharp dips, or spikes, in revenues have direct effects on budgets. “During periods of high oil prices the state capital budget grows and so does the state operating budget. When there are drops in oil revenues capital spending is cut abruptly and the operating budget is also cut,” Richards said. Spikes and cuts in budgets have unsettling effects on state and municipal governments and there are also economic effects. With the large Permanent Fund smoothing out the effects of revenue shocks and sudden windfalls, a payout formula from the Fund could maintain more stable payments for the state budget, which would provide more stability, Richards explained. In operation, Walker’s plan maintains the current procedure of the earnings of the Fund flowing to the Earnings Reserve account. The Legislature can then appropriate funds from the reserve account to the general fund to support the state budget, following a set payout formula. The earnings reserve now holds about $9 billion. The state constitution prohibits spending money from the principal of the Permanent Fund, but money accrued in the Earnings Reserve can be appropriated, although the Legislature has never done so. Details of the plan are still being worked out, including the payout formula, Richards said. For the payout, the concept being looked at most closely is a set percentage of the total market value of the Permanent Fund. This approach, called POMV in shorthand, is used by most large endowments managed by major universities and charitable foundations. Other payout options are possible, Richards said, such as a fixed annual payment that could be inflation-adjusted. If POMV is adopted, most discussions of a sustainable payment percentage sustainable fall into the 5 percent range of the Fund’s total value, although some argue 4 percent or 4.5 percent might be a safer approach. The Permanent Fund’s long-term earnings average has been about 8 percent but that must be adjusted downward to account for inflation. One complication in operating the Permanent Fund like an endowment is that the payout money can come only from the earnings reserve unless the state constitution is amended. That’s because the constitution prohibits money from the principal itself from being spent. As long as there is sufficient money in the earnings reserve (it holds $9 billion now) there would be no problem making the annual cash draws. At this point the current balance of the reserve is sufficient to fund three years of $3-billion withdrawals, with the expectation that over three years the earnings of the Permanent Fund would replenish the reserve fund. “However, a large withdrawal (by the Legislature) or a series of bad investment years could draw the Earnings Reserve down,” a danger, Richards said. The governor’s team is still wrestling with the payout formula. Dividend would be vulnerable to oil shocks While Walker’s plan would insulate the state general fund from oil revenue shocks, it would also make the annual citizen dividend more vulnerable to shocks. It would also reduce the dividend, Richards said. If the plan were in effect in fiscal year 2017, the dividend payment would be about $1,000, down from the 2015 payment of $2,072. Mark Edwards, a Northrim Bank economist and vice president, said that if the 2015 dividend had been capped at $1,000 if would have reduced the $3 billion deficit by $500 million. Meanwhile, an immediate advantage of putting the CBR fund into the Earnings Reserve, which is managed the same way as the Permanent Fund, is that the CBR assets would be managed more for the long term and invested more aggressively, with higher returns expected, than the more conservative approach now used for the CBR because the fund must be kept liquid to fund state operations. Edwards said that if the CBR were invested like the Permanent Fund it might earn $500 million per year in additional revenues. The governor’s plan has drawn a positive reaction from Standard & Poor’s, the agency that sets Alaska’s credit rating for bonds. “Publication of the report itself is a favorable development because it illustrates to state lawmakers how a pathway to a sustainable fiscal structure for Alaska is possible,” the rating agency wrote in a Nov. 2 statement. “Our recent outlooks have noted that Alaska will need to find some way to address its fiscal imbalance if it is to prevent its credit rating from slipping.” On Aug. 18 the agency had revised Alaska’s financial outlook from “stable” to “negative,” although the state’s good AAA rating was not changed. However, the plan doesn’t go far enough, Standard and Poor’s said. “The proposed reform is significant. It would reduce the structural deficit by 65 percent. However, when it comes to the state’s credit rating, it may still be insufficient because it would leave the state with a $1.06 billion fiscal gap (based on FY 2016 expenditures),” the agency said. “Closing the remaining deficit would require some combination of additional spending cuts, reduced (oil) tax credits or other new revenue, including possibily introducing a new broad-based tax.” S&P also cautioned that the plan assumes a 6.7 percent rate of return compared to the 10-year average of 6.4 percent. Beedle said he sees positives in what Walker is proposing, except that the governor should be more aggressive in pushing it, along with other revenue measures. “We will need to use every tool before all the cash is gone,” meaning the CBR fund is depleted, Beedle told an Alaska Miners Association luncheon in Anchorage Nov. 3. The CBR is expected to be drained in 2019 if no action is taken. Using Permanent Fund earnings, restricting the growth of the PFD and use of revenue-anticipation notes will be needed to get the state through the new few years, Beedle said. “We believe broad-based taxes must be there, too. Everyone has to have skin in the game,” he said. Beedle also said Walker may not clearly understand, or is not communicating, the seriousness of the situation in his statements. “The governor says we’re wealthy and that we have $100 billion in assets. However, much of that including the Permanent Fund and pension funds is restricted and cannot now be used,” he said. The state’s annual financial report put unrestricted assets, which can be used, at $30 billion three years ago. In the most recent financial statement, for fiscal year 2014, the state’s unrestricted assets were $15 billion. “I agree with the governor that we have the potential for great wealth, particularly in natural resources, but our cash balance sheet is actually shrinking,” Beedle told the miners. Other criticisms Other critiques of the plan are beginning to emerge. One source familiar with the history of the Permanent Fund, the dividend and state government, who asked not to be identified, said the plans rests on a yet-to-be developed mechanism that would govern payout to the general fund from the Earnings Reserve. It is not yet clear just what kind of POMV or other mechanism will be proposed and the concern, the source said, is that a “black box” formula will be developed that will be complex and difficult for the public to understand. If that is the case there will be a lack of transparency and opportunities for state officials, or legislators to tweak the formula in ways that would generate more revenues. Legislators have been known to tweak formulas in the past, for example formulas used in estimating state oil revenues, to appear to predict more income that could be, and was, appropriated for capital projects. Another concern, according to the source, is in “de-linking” the dividend from the financial performance of the Permanent Fund by tying the dividend directly to oil income. This would dilute the public’s direct interest in financial management of the Permanent Fund, which was one of former Gov. Jay Hammond’s key goals in promoting the dividend in the early 1980s. Tim Bradner can be reached at [email protected]

Gas tax shelved, buyout still on agenda

The state Legislature is plodding through its special session on natural gas issues, although the hot-button questions like a deal on state fiscal terms are not yet on the table. Gov. Bill Walker pulled his controversial idea for a state tax on natural gas reserves off the special session agenda, which now leaves only the question of paying TransCanada Corp. for its investment to date in the Alaska LNG Project. Rep. Mike Hawker, R-Anchorage, said lawmakers have little role in the decision for the state to buy TransCanada’s share of the giant project. Under the state’s contract with TransCanada the governor has that sole authority, Hawker told the Alaska Support Industry Alliance in a briefing Oct. 22. Under the contract the Legislature must approve funds, with interest, to pay TransCanada’s costs to date, which are estimated at $67 million, Hawker said. If lawmakers balk at the payment TransCanada will sue under the contract, he said. A second appropriation of $36 million is also needed to pay the state’s share of costs to complete preliminary engineering on the pipeline and LNG Project. These are funds would have been paid by TransCanada if the pipeline company were to remain in the deal. The governor had hoped to have several agreements with producers ready for approval but delays in the negotiations led to only two items — the reserves tax and a buyout of TransCanada’s interest by the state — being placed on the special session agenda.  BP, ConocoPhillips, ExxonMobil and, for now, TransCanada, and the State of Alaska are in a partnership in the proposed $45 billion to $65 billion Alaska gas project. The state would hold a 25 percent equity stake if TransCanada is out of the picture. That percentage is equal to the state’s share of gas reserves under the terms of Senate Bill 138 that passed by combined vote of 52-8 in 2014 session. In a related development, Pat Pitney, the state budget director, told legislators Oct. 24 that the consortium’s cost for Alaska LNG Project preliminary engineering have increased from $511 million, which had been estimated, to $694 million. The new target date for completion of the preliminary front-end engineering and design, or pre-FEED, is mid-2016. The higher cost is partly due to additional engineering being done, at the governor’s request, on a 48-inch pipe diameter option in addition to the project’s current base case plan of 42-inch diameter pipe. TransCanada buyout There seems little doubt in Juneau at this point that the Legislature will approve the funds to pay TransCanada as well as appropriate money to Alaska Gasline Development Corp., the state gas corporation, to allow it step into TransCanada’s shoes. There is a lot of discussion among lawmakers gathered in Juneau, however, over the long-term cost implications of the decision. If the project continues into final engineering, or front end engineering and design, or FEED, the state’s cost for would be about $675 million. The state’s share of full construction, meanwhile, is estimated at about $13 billion. Assuming the state does acquire TransCanada’s share, the state would be obligated to $144 million for the pre-FEED costs, with part of that the state’s 25 percent share of the LNG plant engineering. Natural Resources Deputy Commissioner Marty Rutherford said the recommendation to withdraw from the TransCanada deal is based on aspects of the contract seen as disadvantageous to the state. Under the current terms the state must repay TransCanada’s investment with interest no matter what happens, even if the pipeline company terminates the contract, Rutherford told lawmakers. “We are always obligated, even if TransCanada opts out or if the project terminates (because of adverse economics),” she said. “The state bears all the risk, and TransCanada none.” Another reason for the state stepping in to fill TransCanada’s role is to have a more direct role in decisions that will affect state interests, Rutherford said. In decisions on design of the pipeline and gas treatment plant, for example, TransCanada now represents the state, but there may be circumstances where the state’s interests and those of the pipeline company may not align. For example, the state is an owner of resources that will move through the project while TransCanada is a “midstream” pipeline owner with no stake in the “upstream” resources. With the state assuming control of its 25 percent of the pipeline and gas treatment plant, the state will have 25 percent of all three parts of the project, including the LNG plant which the state now owns 25 percent directly. In the same briefing with Rutherford, Deepa Poduval, senior consultant with Black & Veatch, a firm advising the state, said it’s important for the state to now be at the table itself when certain decisions are made. There are decisions needed as to how certain gas byproducts will be handled in the gas treatment that affect the state’s resource interests, she said. Financing questions On the question of how the state would pay ongoing costs of its project share, consultants to the administration told the House Finance Committee in hearings that there are basically four options for the state pay the funds TransCanada would have provided. The state’s three main consultants on financing include Radislov Shillkoff of Greengate LLC, an infrastructure finance advisory firm; Steven Kantor, managing director of First Southwest, an investment bank; and Justin Palfreyman, director of Lazard LLC, an investment advisor. The three appeared in a panel before the House Finance Committee. One option the three presented is a straight appropriation from the Constitutional Budget Reserve, although that would deplete the CBR fund faster. It is now expected to be drained in 2019 and a draw to pay near-term costs would move the depletion data up by three to five months. A second possibility is a state general obligation bond for all or part of the funds needed, which is a possible solution although it would require a public vote. The third option is “project financing” where the state, or more properly the state’s Alaska Gasline Development Corp., sells revenue bonds based on anticipated income from sales of the state’s share of gas production.  The fourth option is to bring in new partners, which is essentially what the state has now with TranCanada but would be without the problems in the current contract with the pipeline company. The governor has spoken of interest by potential LNG customers in Asia in taking a share, although that could require some form of commitment that state-owned LNG would be supplied. Pulling the tax On the gas reserves tax, the governor said he would hold off on the idea after receiving letters from North Slope producers that they would commit gas to buyers through the proposed Alaska LNG Project if they withdrew. Walker’s decision was announced Oct. 23, the day before legislators began the special session. The governor has been concerned that if one of the three producers withdraws from the pipeline and LNG project at a critical point in planning it could stymie the other companies, and the state, in moving forward. Walker is pushing for a “withdrawn partners” agreement that would cover the contingency. It would require any party now in the gas deal to produce gas once the project moves forward. In a briefing to state legislators Oct. 24, Walker said he had received letters from two Slope producers, BP and ConocoPhillips, indicating they would commit to supply gas in the event of a withdrawal. Walker said a letter is forthcoming from ExxonMobil, the third major North Slope gas producer.  “They want fiscal certainty,” Walker said, referring to the producers’ request for a guarantee that state taxes and royalty terms won’t change. “Well, I want project certainty,” so that the project will continue even if a partner withdraws. The letters from BP and ConocoPhillips were essentially statements of intent that gas would be sold, and both companies said they would pursue a more definitive agreement. A mechanism for partners remaining in the consortium, including the state, to cover capital costs of the withdrawing party would presumably be part of the agreement. The state’s request for the withdrawn partners’ agreement had prompted a strong pushback from the producers, which prompted Walker to propose the state reserves tax as a lever in negotiations. Under the tax proposal, now withdrawn, a producer would be exempted if it was producing gas for the project. However, the producer would pay the tax if not producing gas, Walker told legislators Oct. 24 in a session-opening briefing. Walker’s shelving of the reserves tax is seen by some partly as a face-saving measure. The tax would not have been passed by the Republican-led Legislature, leaders in the House and Senate said.   Larry Persily, former federal gas coordinator and now the oil and gas advisor to the Kenai Peninsula Borough said the letters from BP and ConocoPhillips, which were conceptual in nature, took the governor “off the hook” by preventing an embarrassing defeat of his tax proposal in the Legislature. However, Walker may have scored points too, Persily said. “It can’t be denied that he got something (the commitments by the companies) by threatening the tax, although those letters are nothing you can take to the bank,” Persily said. In their letters, BP and ConocoPhillips said they hope to have an actual withdrawn-partners agreement by Dec. 4.

Miners seek bright spots on horizon

If you look around the Dena’ina Civic and Convention Center in Anchorage next week you wouldn’t believe there’s a slump in mining industry. The Alaska Miners Association holds its annual convention and trade show Nov. 1-7 and the convention’s massive trade show will be of record size, taking all of the convention center’s vast ground floor and a share of the second floor. About 1,000 people are expected at the convention, said AMA’s executive director, Deantha Crockett. That’s about the same as last year. The robust turnout belies the industry’s actual condition, which is down mainly because of low metals prices. A more somber mood will prevail compared with happier times, when gold prices were near $1,800 per ounce. They’ve been stuck at about $1,200 per ounce for an extended period. Still, people are still at work, some development-phase projects are still proceeding and the state’s seven operating mines are doing well. However even with those, capital budgets are tight and exploration budgets are very limited. If there are brighter spots on the horizon one is that fuel costs are down, and energy is a big-ticket cost item for mines. Another one, Crockett said, is that there appears to be a push-back developing on a national level against the encroachment of regulations by federal agencies like the U.S. Environmental Protection Act. There are still problems in the regulatory environment, but an order by a federal judge halting, at least temporarily, the EPA’s new “waters of the United States” rule is a sign of hope. “We’re starting to see a real examination of federal overreach, and it’s getting attention in Congress,” Crockett said. The ongoing dispute over Pebble is another example. As more information comes out about how the EPA developed its plan for a preemption of mining in the Bristol Bay region, with agency staffers working secretly with opponents to mining, the worse the agency looks, she said. At the convention itself, Crockett said the Tuesday luncheon talk on the state’s fiscal gap, by Northrim Bank president Joe Beedle and economist Mark Edwards, will be important. Lt. Gov. Byron Mallott will speak at noon Wednesday on Alaska-Canada trans-boundary issues, which affect mining projects in British Columbia that are near the Alaska border, and which can affect watersheds in Alaska. Wednesday is an all-day session on industrial safety, which is important in most industries. U.S. Sen. Dan Sullivan will address the AMA’s annual banquet on that night. On Thursday, four Alaska Native corporations, Sealaska Corp., Ahtna Inc., Doyon Ltd. and Eklutna Inc. will discuss mineral development on Native-owned lands. The full schedule is on the facing page.

Good news from the Slope: More oil, drilling

There’s some good news from the North Slope. First, oil is flowing at ConocoPhillips’ new CD-5 North Slope production drillsite on the North Slope, the company said in an announcement Oct. 26. Peak production is expected to be about 16,000 barrels per day. Anadarko Petroleum Corp. is ConocoPhillips’ minority partner, and mineral rights are held by Arctic Slope Regional Corp. Second, a small independent has “spudded” a new exploration well south of Prudhoe Bay, aiming to test the oil production potential of the large shale formations. The company is 88 Energy and its “Icewine” well, planned to drill to 11,600 feet with a goal of testing the HRZ Zone, one of three large shale formations in the area. 88Energy is the second company testing the North Slope shales, the other being independent Great Bear Petroleum. Thirdly, the U.S. Bureau of Land Management has approved drilling permits and access rights-of-way to ConocoPhillips and Anafdarko Petroleum Corp., after a lengthy regulatory proceeding. It doesn’t mean the estimated $900 million project will be built soon, but that approvals are in place so that when construction decisions are made, most likely when oil prices improve, the companies can move quickly. CD-5’s startup follows the Oct. 12 production start of another ConocoPhillips slope project, Kuparuk Drill Site 2-S in the Kuparuk River field. At peak, DS-2S will produce 9,000 barrels per day, ConocoPhillips spokeswoman Amy Jennings Burnett said. The new drill site is adjacent to the producing Alpine field and is on the west side of the Colville River, the boundary between state-owned lands and federal lands within the National Petroleum Reserve-Alaska. As such, CD-5 represents the first commercial oil production from NPR,-A, a large 23-million-acre federal land unit formed in 1923 for its oil potential. However, royalties from CD-5 production will go to two Native development corporations in the region, Arctic Slope Regional Corp. of Barrow and Kuupik Corp., of the Inupiat village of Nuiqsut, which is near the Alpine field. The two corporations received rights to subsurface and surface lands at CD-5 under the Alaska Native Claims Settlement Act, which was passed by Congress in 1971. In another recent development, the U.S. Bureau of Land Management approved a drilling permit and right-of-way for ConocoPhillips’ proposed Greater Mooses Tooth 1, or GMT-1, oil development project in the NPR-A. GMT-1 is about eight miles west of CD-5, and would be served by road and pipeline connections from the Alpine oil field. Natalie Lowman, a ConocoPhillips spokeswoman, said BLM’s approvals for GMT-1 were good news for her company and Anadarko but that there is not yet a timetable for sanctioning or final approval of the project, which is expected to produce 30,000 barrels a day at peak. The regulatory approvals are significant, however, because they set precedents on federal permits for future development in the NPR-A, 23-million-acre federal petroleum reserve. When it is eventually developed, GMT-1 will help the state offset production declines from existing North Slope fields. Alaska Gov. Bill Walker lauded the work by ConocoPhillips and BLM on the permit and right-of-way, following a lengthy regulatory procedure. “The NPR-A is estimated to hold more than 800 million barrels of oil,” the governor said. Rex Rock, CEO of Arctic Slope Regional Corp., the Alaska Native development corporation for the North Slope, was also pleased. ASRC owns the mineral rights at GMT-1, which were obtained through its land selection rights in the 1971 Alaska Native Claims Settlement Act. “After a long and trying permit process, BLM has now lifted a couple of the last regulatory roadblocks to allow ConocoPhillips to move forward to develop ASRC minerals from GMT1,” Rock said in a statement. “GMT1 is an important next development of ASRC’s oil and gas resources by ConocoPhillips west of the Colville River Unit.” GMT-1 is in the northeastern part of the petroleum reserve and about eight miles west of the producing Alpine field on state lands, which ConocoPhillips operates. The mineral rights at GMT-1 are split between ASRC and the federal government. ConocoPhillips has meanwhile been working on a “GMT-2,” another NPR-A drillsite a few miles further into NPR-A. 88Energy’s Icewine well is expected to take about 30 days to drill. The company was able to mobilize and begin drilling earlier than is normal for the fall/winter slope exploration season because the well location is adjacent to the Dalton Highway, an all-year gravel road from the North Slope to Interior Alaska. Because of that no ice roads are needed for access, which would have taken longer for the company and required regulatory approvals. In its press release, 88 Energy said some data will be available immediately after drilling, but the definitive testing of the HRZ shale potential will take several months of analysis. “The pivotal focus will be an extensive evaluation of core material by specialist laboratories, which will cover a number of parameters considered critical for the success of the play. Conventional potential may also exist in shallower (Brookian) and deeper (Kuparuk) horizons and the well has been designed such that testing of these horizons is possible, if warranted,” the press release said. Tim Bradner can be reached at [email protected]

NANA makes gold strike; work continues amid price slump

Things aren’t great for Alaska’s miners right now, but despite the extended downturn in metals prices some explorers are pressing ahead. NANA Regional Corp., which conducted its own exploration, announced what it termed a “significant” new gold discovery on state lands on the eastern Seward Peninsula. However, the overall number of new “grassroots” exploration projects is sharply down this year compared with previous years, and the suppliers and contractors who support explorers are feeling the effects. There was some good news for NANA, however. The corporation conducted a small program of six holes drilled totaling 3,100 feet. There were good results in the mineralization tested. One hole showed grades of 20.5 grams per ton, or gpt, of gold; 92 gpt of silver; 1.79 percent zinc and 2.63 percent lead. There was also thin, high-grade interval of 175 gpt gold and 470 gpt silver. Lance Miller, NANA’s vice president for natural resources, said the mineral values are encouraging. “With this summer’s drilling we have identified the lode source for the placer gold found in the northern Seward Peninsula area,” he said. Information from the drilling combined with geologic and soil sampling by NANA over several previous seasons have identified a belt of mineralization along a 40-mile trend, he said. The Kotzebue-based Alaska Native regional corporation is also involved in another exploration project, this one in the Ambler Mining District in the upper Kobuk River area in an alliance with NovaCopper Resources, an exploration company. NovaCopper has made significant high-value copper discoveries at the Arctic deposit in the area, where it holds mining claims. NANA owns lands in the region including at Bornite, another known copper discovery. The two companies are working together on exploration on both prospects, which NANA having an option to buy into Arctic and NovaCopper an option to buy into Bornite. In 2015, NovaCopper drilled 14 test holes at Arctic, extracting 3,056 meters of core in a $5.5 million program. The objective was to test the continuity of high-grade ore zones identified at Arctic, the company said in a press release. To date, NovaCopper and its predecessor company, NovaGold, have drilled 43 core holes in addition to 92 holes drilled by the previous owner, Kennecott. Indicated resources (measured by drilling) are estimated at 23.8 million tonnes and an additional 3.4 million tonnes of inferred, or estimated, resources. In the indicated resource category the metal values were measured at 3.26 percent copper; 0.71 gpt of gold; 53.2 gpt of silver; 0.76 percent lead and 4.45 percent zinc. NovaCopper also announced in July that it was beginning work on the pre-feasibility study of the Arctic deposit, an important step in the development program. Work on that is expected to take two to three years. Other mines progressing Exploration aside, there are a number of projects where discoveries have been made that are gradually working their way through the web of regulatory approvals. The big Donlin Gold mine in the mid-Kuskokwim River region, for example, may publish its long-awaited draft environmental impact statement by the end of 2015. Assuming regulatory hurdles are cleared, Barrick Gold and NovaGold Resources, the developers, must still make a decision to develop the mine. That is of real interest to Calista Corp., the Alaska Native regional corporation that owns mineral rights, and The Kuskokwim Corp., owned by local village corporations, which holds the surface lands. It was exploration by Calista’s geologists that led to the gold discovery although there had long been placer mining in the area. Another project in an advanced stage of development planning is International Tower Hills’ Livengood gold project north of Fairbanks. The gold resource is large and well-defined, but a construction decision will likely require an upturn in gold prices. The company is meanwhile working on ways to reduce costs. Early cost studies showed the project, as designed, would not be viable at current gold prices. “We’re still in the optimization stage, working to bring capital and operating costs down to where the project would be viable at lower prices,” said ITH spokesman Rick Soley. Meanwhile, environmental baseline monitoring and some other work continues at the mine site as well as metallurgical analyses at other locations, he said. If it is developed, Livengood would be a surface mine mining low-grade ore similar to Fort Knox, a producing mine also near Fairbanks, but larger. It would likely employ over 400 in operation, Soley said. Two Southeast mines in advanced stages of exploration and development planning include Bokan Mountain, a rare earths project, and Niblack, a multi-metals discovery. More ore reserves were discovered at Bokan Mountain this year and Niblack continues to work on a plan to process is ore in nearby Ketchikan, which would be an important economic boost for that community. Heatherdale Resources Ltd. is developing Niblack. Bokan is being developed by Ucore Rare Metals Inc. In 2014 the company added 1.04 million tons of ore to its resource base through deeper exploration drilling at the prospect. The company previously reported 4.88 million tons of resources. The large Pebble project near Iliamna is in a holding pattern. The company, Pebble Partnership, is in litigation against the U.S. Environmental Protection Agency over the agency’s attempt to preempt large mines in the Bristol Bay region. Improper procedures by EPA are being contested. If the lawsuit is won, or if a settlement is reached, Pebble may be allowed to apply to state and regulatory agencies for its permits. That would allow for a mine development plan to be made available to the public. Operating mines Meanwhile, the state’s operating mines are doing well. Near Juneau, the Greens Creek Mine, operated by Hecla Mining Co., is projected to produce 7.3 million ounces of silver, down somewhat from 7.8 million ounces in 2014. The mine holds substantial silver, gold and lead reserves and resources. An aggressive, three-rig drilling program was conducted in 2015, budgeted at $5.8 million. Over the last 11 years drilling efforts have replaced or added to resources at the mine. North of Juneau, at Berner’s Bay, the Kensington Mine continues at a steady production rate. Ore production totaled 165,198 tons in the third quarter of 2015 with 28,688 ounces of gold produced, compared with 145,097 tons of ore mine in third quarter 2014 and 30,773 ounces of gold produced. Kensington is operated by Coeur Alaska Inc. At the large Fort Knox surface mine near Fairbanks, Kinross Gold Corp. is on target to produce about the same amount of gold as in 2014, which was 379,064 ounces. The company is adding equipment, commissioning four new 793F haul trucks and completing a booster pump station in the mine process facilities. Coal production will be down in 2015 at the Usibelli mine at Healy, the state’s only producing coalmine, because of reductions in exports. Usibelli Mine Inc. will produce about 1.2 million tons of coal this year, down from almost two million tons per year a few years ago when export markets were stronger. Demand from Usibelli’s core Alaska markets, six Interior Alaska coal-fueled power plants, will hold steady or even increase somewhat when Golden Valley Electric Assoc.’s new Healy 2 power plant becomes fully operational in 2016.

BLM approves ConocoPhillips’ permit for NPR-A project

The U.S. Bureau of Land Management has approved a drilling permit and right-of-way for ConocoPhillips’ proposed Greater Mooses Tooth 1, or GMT-1, oil development project in the National Petroleum Reserve-Alaska, or NPR-A. ConocoPhillips spokeswoman Natalie Lowman said the agency’s approvals were good news for her company and its minority partner, Anadarko Petroleum Corp. However, she said there is not yet a timetable for sanctioning or final approval of the project, which is expected to produce 30,000 barrels a day at peak and cost $900 million to construct. The regulatory approvals are significant, however, because they set precedents on federal permits for future development in the NPR-A, 23-million-acre federal petroleum reserve. GMT-1 is in the northeastern part of the petroleum reserve and about eight miles west of the producing Alpine field on state lands, which ConocoPhillips operates. Alaska Gov. Bill Walker lauded the work by ConocoPhillips and BLM on the permit and right-of-way, following a lengthy regulatory procedure. “The NPR-A is estimated to hold more than 800 million barrels of oil,” the governor said. When it is developed, GMT-1 will help the state offset production declines from existing North Slope fields.  Rex Rock, CEO of Arctic Slope Regional Corp., or ASRC, the Alaska Native development corporation for the North Slope, was also pleased. ASRC owns the mineral rights at GMT-1, which were obtained through its land selection rights in the 1971 Alaska Native Claims Settlement Act. “After a long and trying permit process, BLM has now lifted a couple of the last regulatory roadblocks to allow ConocoPhillips to move forward to develop ASRC minerals from GMT1,” Rock said in a statement. “GMT1 is an important next development of ASRC's oil and gas resources by ConocoPhillips west of the Colville River Unit," Rock said. GMT-1 would be the first commercial oil development inside the NPR-A, a reserve established by the government in 1923 as a petroleum reserve although no commercial deposits of oil have been found until ConocoPhillips’ and Anadarko’s discovery.

Walker backs down on gas reserves tax, for now

A proposed state tax on natural gas reserves is off the table, at least for now. Gov. Bill Walker said he would hold off on the idea after receiving letters from North Slope producers that they would commit gas to buyers through the proposed Alaska LNG Project if they withdrew. The announcement came Oct. 23, the day before state legislators began a special session of the Legislature called by Walker to consider issues related to the Alaska LNG Project, a large gas project in which the state is a partner. BP, ConocoPhillips, ExxonMobil and TransCanada, along with the state of Alaska, are in a partnership in the proposed $45 billion to $65 billion Alaska gas project. The state would hold a 25 percent equity stake. The governor has been concerned that if one of the three producers withdraws from the pipeline and LNG project at a critical point in planning it could stymie the other companies, and the state, from moving forward. Walker is pushing for a “withdrawn partners” agreement that would cover the contingency. It would require any party now in the gas deal to produce gas once the project moves forward. In a briefing to state legislators Oct. 24, Walker said he had received letters from two slope producers, BP and ConocoPhillips, indicating they would commit to supply gas in the event of a withdrawal. Walker said a letter is forthcoming from the third major North Slope gas producer ExxonMobil.  “They want fiscal certainty,” Walker said, referring to the producers’ request for a guarantee that state taxes and royalty terms won’t change. “Well, I want project certainty,” so that the project will continue even if a partner withdraws. The letters from BP and ConocoPhillips were essentially statements of intent that gas would be sold, and both companies said they would pursue a more definitive agreement. A mechanism for partners remaining in the consortium, including the state, to cover capital costs of the withdrawing party would presumably be part of the agreement. The state’s request for the withdrawn partners’ agreement had prompted a strong pushback from the producers, which prompted Walker to propose the state reserves tax as a lever in negotiations. Under the tax proposal, now withdrawn, a producer would be exempted if it were producing gas for the project. However, the producer would pay the tax if not producing gas, Walker told legislators Saturday. The governor had hoped to have several agreements with producers ready for approval but delays in the negotiations led to only two items–the reserves tax and a buyout of TransCanada’s interest by the state–being placed on the special session agenda.   The only business for legislators in Juneau, now that the reserves tax is no longer on the agenda, the is approving a $67 million appropriation to pay TransCanada for its expenses to date, with interest, and a second appropriation of $36 million to pay the state’s share of costs to complete preliminary engineering pipeline and LNG Project. These funds would have to be paid by TransCanada if the pipeline company were to remain in the deal. In a related development, Pat Pitney, the state budget director, told legislators Saturday that the consortium’s cost for Alaska LNG Project preliminary engineering have increased from $511 million, which had been estimated, to $694 million. The new target date for completion of the Preliminary Front-End Engineering and Design, or pre-FEED, is mid-2016. The higher cost is partly due to additional engineering being done, at the governor’s request, on a 48-inch pipe diameter option in addition to the project’s current base case plan of 42-inch diameter pipe. Walker’s shelving of the reserves tax is seen by some partly as a face-saving measure. The tax would not have been passed by the Republican-led Legislature, leaders in the House and Senate said.    Larry Persily, oil and gas advisor to the Kenai Peninsula Borough, a regional municipality, said the letters from BP and ConocoPhillips, which were conceptual in nature, took the governor “off the hook” by preventing an embarrassing defeat of his tax proposal in the Legislature. However, Walker may have scored points too, Persily said. “It can’t be denied that he got something (the commitments by the companies) by threatening the tax, although those letters are nothing you can take to the bank,” Persily said. On the TransCanada buyout, the state has this option under a contract between the state and TransCanada agreed by the two in 2014. In the overall project partnership the state would own 25 percent, a share equal to the state’s ownership of gas on the slope. Similarly, the three major slope gas producers would own shares in the pipeline and LNG plant equal to their share of gas reserves. The state’s separate deal with TransCanada, which owns no gas, would have had the pipeline company investing in and owning the state’s 25 percent share of the 800-mile pipeline and large North Slope gas treatment plant, leaving the state with its 25 percent of the large LNG plant planned at Nikiski, near Kenai south of Anchorage. A provision in the contract allows the state to buy out TransCanada by repaying the pipeline company’s investment with 7.5 percent interest also paid, an option the governor has decided to take. Rep. Mike Hawker, an Anchorage Republican legislator who chairs the Legislature’s Budget and Audit Committee said the contract allows the governor to make the decision to buy out TransCanda. “Our only role is approving the money to do it,” Hawker said in an interview. “If we don’t approve the funds, TransCanada will sue us under the contract,” Hawker said, which means the Legislature actually has little choice. However, if the state steps to own its full 25 percent share it will have to pony up $675 million in 2016 and 2017 to pay its share of final engineering costs and later about $13 billion to pay 25 percent of construction costs, Hawker said. Coming up with that money won’t be easy, given the state’s current financial shortfalls due to low oil prices. Oil taxes and royalties pay for 95 percent of Alaska’s budget and oil revenues have dropped by half in the last year, creating $3-billion-dollar annual deficits for the state. Funding those deficits requires hefty drawdowns on state cash reserves, although Alaska still has a $53 billion “Permanent Fund” that could help in financing its share of gas project costs. 

Walker’s gas tax raises more questions

Gov. Bill Walker has offered his first explanation of his proposed tax on natural gas reserves in advance of a special session of the Legislature due to convene Oct. 24. But the letter written by the governor to legislators Oct. 19 seems to raise more questions than it answers, and if the tax was actually passed by the Legislature, which is doubtful, it would prompt lawsuits that would entangle and delay the planned Alaska LNG Project. Walker describes the proposal as an “incentive,” to get North Slope gas producers to agree to produce gas and commit it to the LNG project. “The property tax is not designed to be punitive,” the governor wrote in his letter. The letter describes the reserves tax in terms of the “lifting of a tax holiday” on property taxation of the value of state oil and gas reserves. Years ago the Legislature exempted unproduced oil and gas reserves from property taxes because the state also imposed a production, or severance tax, the governor explained in his letter. The new proposal is to change the law and make the reserves subject to property tax, but with exemptions if producers agree to commit gas to the LNG project, according to the letter. “Built into this legislation are several exemptions. Should the taxpayers qualify for any one of the exemptions, the property tax would not apply,” according to the letter. The proposed statutory language of how the tax would actually be structured will be in the bill to be introduced in the special session Oct. 24, but copies of the draft legislation were not made available. Among several questions not answered by the letter is who would impose the property tax: municipalities or the state? Walker’s letter described property taxes as traditionally a municipal function in Alaska, although the state does impose its only state property tax on the value of oil and gas industry surface facilities, including pipelines. The governor may have in mind amending the state oil facilities tax to include the value of unproduced underground gas reserves, but if that is not done the taxation would be done by local governments under their current tax authority. For the North Slope, that would be the North Slope Borough. Another uncertainty in the proposal, as it has been described in concept, is whether the state or municipal appraisals of underground reserves would include crude oil as well as natural gas, or if just gas, as the governor has described it, how the gas fluids can be appraised separately from oil fluids. Below ground gas and oil are often mingled, as is the case at the Prudhoe Bay field on the North Slope, and also typically exist in liquid form in the reservoir rock. What is considered natural gas, the lighter molecules of hydrocarbons, become gaseous when they are produced up a well and the pressure drops, allowing them to shift from a liquid to a gas. Sorting out the value of underground gas as separate from oil is an area ripe for conflict and litigation. Three other matters are being put on the Legislature’s special session agenda by the governor. One is a request for an appropriation to compensate TransCanada Corp. for its investments to date in the gas project and for the state to acquire TransCanada’s share of the project. “TransCanada has been a valuable partner (for the state) and I appreciate its efforts and contributions in progressing the pre-FEED (preliminary engineering) work on this project. However, at this point the state through AGDC (the state-owned Alaska Gas Development Corp.) should take a direct investment in the entire project to lower annual gas transportation costs after the project begins operations,” Walker wrote. “While this will mean that the state must make the project (engineering) and construction payments that TransCanada would have otherwise made, the state is better off in the long term.” Other items on the special session agenda include appropriations for the state to make required cash contributions to complete the preliminary engineering work on the Alaska LNG Project that is now underway, and funding for state agencies to continue in negotiations on needed agreements for the project. Overall, the governor described in the letter his frustration that the project agreements are not yet in place. “We are at a critical juncture,” Walker wrote. “The process we are currently working under has failed to produce any project-enabling agreements on the timeline that Alaska requested and that the state’s (industry) partners indicated was possible,” the letter said. “Unfortunately, instead of introducing project-enabling agreements to you in this special session, as was the goal of all the parties involved, I must instead ask you for measures necessary to advance the process with assurances it will not see similar delay in the future or actual process failure caused by the reluctance of one or more parties to move forward.” One other point not explained in the governor’s letter was that the reserves tax is not really an incentive for producers to commit gas to a project but to sell gas to a buyer at the other end of the pipeline and LNG project. The project itself does not purchase gas, but only transports it for a fee like a railroad does with freight. In reality, the tax would impose a penalty (the tax) if a producer, for example, fails to agree on an acceptable price for its gas from a buyer. This is one other area ripe for dispute and lawsuits because the state or municipal appraisers would in effect substitute their judgment of an acceptable price for that of the producing company in deciding to impose the penalty.

AOGCC approves additional gas offtake at Prudhoe Bay

The Alaska Oil and Gas Conservation Commission has approved an increased natural gas “offtake” rate of 3.6 billion cubic feet of gas per day from the Prudhoe Bay field on the North Slope to supply the planned Alaska LNG Project. The commission’s order, issued Oct. 15, amended a previous order from several years ago that allowed 2.7 billion cubic feet of gas to be produced. AOGCC’s action is one of several major regulatory steps needed for the Alaska LNG Project, the potential $50 billion-plus large gas project that is now being planned. Commercial gas production would start in 2025 under the current schedule for the Alaska LNG Project, which is still in its preliminary engineering phase and has not yet been approved for construction. In its decision, the state regulatory agency, which oversees development and production operations on oil and gas fields, sided with ConocoPhillips and Chevron, two Prudhoe Bay producers, and against a proposal by the two other major Prudhoe producers, BP Exploration and ExxonMobil, seeking a 4.1 billion cubic feet per day offtake rate. BP and Exxon had argued that the larger volume was needed to assure that sufficient gas production would be available to the gas pipeline and LNG project in the event that there were production problems at Point Thomson, another gas field that will be a second source of supply where the two companies own more than 90 percent of the gas. In written submissions and presentation at an Aug. 27 hearing of the commission, ConocoPhillips and Chevron argued that a lower gas production rate would be more prudent in assuring maximum oil recovery at Prudhoe, where the gas helps maintain reservoir pressure to produce oil, and that a production upset at Point Thomson that would be extended, as much as for several months, is unlikely. If that were to happen the AOGCC could amend its order to allow higher gas production rates, ConocoPhillips argued at the hearing. BP said at the hearing that having the higher rate approved is only a safeguard in case more gas is needed, but that having preapproval for a quick ramp-up without a regulatory proceeding is helpful to the companies in marketing LNG. Potential customers want all possible assurances that contracted volumes of LNG can be delivered even in the event of production problems. However, AOGCC chair Cathy Foerster said that the commission’s legal mandate is to ensure maximum efficient recovery of both oil and gas and that the agency has no responsibility for commercial considerations, in helping the marketing of the gas. Although taking a more conservative approach on gas production would seem to fit the agency’s mandate, the Oct. 15 order also acknowledged that simulation results from production modeling submitted by the companies show relatively little impacts on ultimate production from different production scenarios. One consideration for the companies is that the Prudhoe Bay field is well known and that the gas in the reservoir has been produced along with oil for years and then reinjected underground to maintain field pressure. Because of that there is a high degree of confidence in the Prudhoe field. Point Thomson is less certain, however, because it is not yet producing and its performance cannot be predicted with as much confidence that companies have at Prudhoe. Point Thomson is expected to begin production in 2016 in an initial phase that involved production of gas and liquid condensates, and with the liquids sold and the gas injected back underground. Fundamentally, allowing an offtake rate sufficient to support major sales of gas for the Alaska LNG Project would lead to overall greater recovery of both oil and gas, the commission said in its order. “The simulation results show that ultimate recovery from the Prudhoe oil pool could only be maximized with major gas sales as there are significantly more barrels of oil equivalent of reserves in the form of gas in the pool than there are in the (oil) liquids that remain within the pool,” the commission said in its order. The AOGCC also noted that sales of gas to the LNG project will also result in large quantities of nearly pure carbon dioxide to be made available for enhanced oil recovery. The CO2 will be separated from produced gas in a large gas treatment plant to be built at Prudhoe as a part of the pipeline and LNG project.

Voters reject rail lease, stalling Skagway port

In a surprise, Skagway voters rejected a proposed new lease for the White Pass & Yukon Route Railway on municipal-owned land in Oct. 6 municipal elections, and this has complicated a $23 million Skagway port redevelopment project planned to be underway in 2016. The new lease, had it passed, would have reduced the White Pass lease from 78 acres to 2.7 acres, giving the municipality control of uplands and tidelands needed for the port redevelopment. Under the plan, aging docks and upland facilities would be replaced and the port expanded. White Pass would also have contributed $2 million to a cleanup of known lead contamination in submerged soils in the port which is a human health hazard and an impediment to federal permits for the redevelopment, city officials said. The vote was two-to-one against the new lease, which caught municipal officials off guard, Mayor Mark Schaefer said. Schafer had campaigned for the new lease and was reelected, ironically against an opponent who campaigned against the lease. Before taking any steps to salvage the redevelopment, called “Gateway Skagway,” municipal officials plan a post-election survey to understand why the new lease, which would have greatly benefited Skagway, failed to such an extent. “We need to know why people were against it. Was it the term of the lease, or the monetary value, or just that people in the town were mad at White Pass,” Schaefer said in an interview. White Pass & Yukon Route Railway has been a major employer in the small Southeast Community virtually since the early 1900s and the Golf Rush, hauling ore from mines in Yukon Territory until recent years and now a popular tourist railroad and attraction. Over the years local citizens may have come to resent the company for varied reasons. However, the new lease negotiations brought the municipality and the railway together on terms that would have benefitted both parties, said Chad Gubala, a consultant to Skagway on the port project. Skagway owns lands around the port and leases to the railway, which then sub-leases to other tenants including industrial users. The new lease would have greatly reduced the size of the White Pass leasehold, which the company wanted so as to focus on its tourist operations, and would have given the municipality more say on the company’s management of its leases including environmental oversight of tenants. Under the current lease the municipality has limited influence over how the railway manages the leases, Gubala said. The company agreed to and supported the new lease terms, however. The old lease will expire in 2023 but had voters approved the revision the city would have gotten direct control of lands for the port project, and in return White Pass would have a new lease term, although with smaller acreage. Gubaba said it is possible that parts of the port project can still be done even with the current lease but that it will be more complex. Schaefer said the municipality will wait until the post-election survey is done and also work to clarify issues related to the contamination, an estimated 80 tons of lead, before sitting down with the railway. Dealing with the contamination and also controlling continued contamination from onshore sources is the top priority, the mayor said, because the municipality may become legally vulnerable if nothing is done. The contamination is the result of years of loading lead-zinc ore concentrates from Yukon mines into ships at the Skagway port.

Officials see positive in new flow rate estimate

State officials are cautious about Repsol’s agreement to relinquish part of a promising North Slope oil discovery to its minority partner, independent Armstrong Oil and Gas, but are still upbeat about the scale of potential reserves announced by the two companies Oct. 13. It was the first public release of potential reserves, and welcome news to Alaskan officials. “Repsol/Armstrong’s announcement about potential volumes reinforces that Alaska is a great place to explore, a stable sovereign with enormous resource potential with ample room for development growth,” said state Oil and Gas Division Director Corri Feige in a statement. In its reserve estimates Armstrong cited a report by consultant, DeGolyer and MacNaughton, that recoverable resources in discoveries by the two companies in the Colville River delta on the Slope could range from 497 million barrels of oil to 3.75 billion barrels. In the press release issued by the companies Oct. 13 potential production of 120,000 barrels per day was cited, which is up from earlier estimates of 60,000 barrels per day. Under the agreement, Armstrong now has 45 percent of the proposed development, up from 30 percent, and has an option to acquire an addition 6 percent, which would bring its ownership to 51 percent. The option must be exercised by Dec.1, 2016, Repsol spokeswoman Jan Sieving said. While the reserve figures are promising, the fact that a major company, Repsol, appears to be stepping back from its aggressive North Slope exploration program and potentially turning over operatorship of a multi-billion dollar development project to an independent is raising eyebrows in Alaska. Armstrong will pay Repsol $800 million for its expanded ownership in cash and other commitments, and has also acquired a larger share in a group of unexplored leases. But the overall project cost could be several billion dollars, according to sources, and funding half of that as well as dealing with complex regulatory issue could be a big bite for Armstrong, which is privately-held. Armstrong, based in Denver, would offer no comment on its financial capability. Meanwhile, a three-well exploration program planned for this winter to further delineate the discovery has been canceled, according Sieving. However, the companies are still proceeding with permit applications for development as well as preparations for a federal environmental impact statement, or EIS, which will be led by the U.S. Army Corps of Engineers. Sieving said the original application to the Corps would be updated to reflect the higher production estimates. “The EIS process allows for updates at its proceeds. We plan to update the application to 120,000 barrels per day in accordance with Army Corps of Engineers recommendation and guidance,” she said in a statement. “Repsol is currently working with the corps to define the EIS scope of work and select the third party independent contractor. From there, the timeline and the start of the scoping period will be determined. The corps sets the EIS schedule.” Becoming operator of the project may be a big bite for Armstrong but the company does have a long record of successful exploration drilling on the North Slope, and has made discoveries that led to the development of the Oooguruk and Nikaitchuq fields by companies Armstrong brought in as partners, Pioneer Natural Resources at Oooguruk (the field is now owned by Caelus Energy, a Dallas-based independent) and Eni Oil and Gas, at Nikaitchuk. “It’s important to remember that Repsol would still own 49 percent if Armstrong does exercise the option to take the added 6 percent,” said Dudley Platt, oil and gas liaison to the North Slope Borough, the regional municipal government. Platt said independent companies are already operating fields and developing new projects on the Slope, citing Hilcorp’s acquisition of former BP fields and its plan to develop Liberty, an offshore project. Also, independent Caelus is working on Nuna, a new project near the Oooguruk field, and Brooks Range Petroleum is working to develop Mustang, a small field, he said. Regulatory issues may present real challenges for Armstrong and Repsol. The project area in the Colville Delta is in ecologically sensitive river delta wetlands, which means that federal, state and local agencies will closely scrutinize development plans, along with environmental groups. Impact mitigation, which is already a contentious issue for ConocoPhillips in its proposed Greater Moose’s Tooth-1 development in the National Petroleum Reserve-Alaska, which is not too far away, will also become a factor. Platt said the North Slope Borough’s code mandates mitigation for impacts from oil and gas development. “The borough is very aware of the transition (from Repsol to Armstrong) and we will be monitoring this very closely, Platt said. “Everyone knows the area is sensitive and we know it will require mitigation.” Still, North Slope Mayor Charlotte Brower’s planning department has excellent relationships with Repsol and has routinely engaged with the company, he said. “We are hopeful that Armstrong will retain experienced people Repsol has employed,” Platt said. Scientists working with the borough’s wildlife department are well regarded and will be working with Repsol and state and federal agencies through the EIS process, he said. On the reserve estimates, sources familiar with the North Slope said it is likely that the oil Repsol and Armstrong have found is a combination of conventional “light” oil as well as viscous oil or resources trapped in tight rock that could be expensive to exploit. The two companies have not released information on the quality of the crude oil they have encountered or possible natural gas present.

Interior Dept. leaves Alaska in dark before canceling sale

Alaska Sens. Lisa Murkowki and Dan Sullivan were both at the Alaska Federation of Natives convention Oct. 16, at the Denai’na Center in Anchorage when U.S. Interior Secretary Sally Jewell dropped her bombshell. Without notice to the state’s two senators or state officials Jewell announced she would cancel two planned Arctic Outer Continental Shelf lease sales and deny requests from Shell and other companies to suspend their Chukchi Sea and Beaufort Sea leases. Those expire beginning in 2017, the clock having been nearly run out mainly due to environmental lawsuits and regulatory delays and before the companies have had a chance to drill more than Shell’s one 2015 well. Sullivan was incensed. “The announcement is another sign that the administration has caved into the demands of extreme environmentalists,” the senator said in a statement. Environmental groups were elated. “In cancelling these leases, the president and secretary have ensured that Alaska will not be at risk from the dangers of offshore drilling, that one of the last remaining pristine wild places (the Arctic) will not be sacrificed for the sake of corporate profits,” the Sierra Club said. In her statement on the lease sales Jewell cited Shell’s decision to quit its Arctic program after disappointing results on one Chukchi Sea well and apparent lack of industry interest in lease sales planned for 2016 and 2017. Sullivan called that duplicitous. “The administration cites lack of commercial interest and lack of a plan for commercial development, but that justification is duplicitous at best. First the administration creates regulatory obstacles under which success for any company would be nearly impossible. And then it creates lack of commercial interest as justification for locking up the resources,” the senator said. The president’s concerns for social and economic problems in Alaska’s rural northwest villages now ring hollow, Sullivan said, because the economic stimulus and jobs that offshore oil development would have brought in the long term to small coastal communities will be delayed for years. The biggest cause of rural social problems and suicide is lack of jobs and economic opportunity, the senator said. State Rep. Ben Nageak, a Democrat from Barrow who got to talk with the president during his Alaska visit, was dumbstruck by the lack of courtesy by Jewell not giving Alaska leaders a warning of the announcement. “No advance notice. No communication. No respect,” Nageak said in a statement. Nageak was also at AFN when the news was announced. The convention was uplifting, but Jewell’s announcement, “was like taking the air out of the room,” he said. He credited Shell for “offering new avenues of employment and training for our young people. They contributed greatly to our economy,” while drilling this summer, he said. In her announcement Jewell said companies had expressed no significant interest in the two upcoming lease sales, Chukchi Sea Lease Sale 237, scheduled for 2016, and Beaufort Sea Lease Sale 242, scheduled for the first half of 2017. Even before Shell made its decision to leave there were no nominations for tracts to be offered by industry for the Chukchi lease sale and only one expression of interest in the Beaufort sale, Jewell said. As for the lease extensions, Jewell said the U.S. Bureau of Safety and Environmental Enforcement, or BSEE, had concluded that, “the companies did not demonstrate a reasonable schedule of work for exploration and development under the leases, a requirement necessary for BSEE to grant an extension,” Jewell said. Murkowski was interviewed by the Journal of Commerce two days before Jewell’s announcement, and expressed hope the leases would be extended and the lease sales kept on track. Murkowski, who chairs the Senate Energy and Natural Resources Committee, said she was worried about the lease extensions because the companies had “heard absolutely nothing” from Interior about their requests, which had been made in 2014. “There was no communication, nada,” Murkowski said in the interview. The senator acknowledged that with Shell out of the game there are those in the administration who will question whether there is a need for lease sales. “I think the opposite is the case. We need to assure anyone who is even slightly considering exploration that they will have an opportunity,” to drill, Murkowski said. The senator said she had met with Jewell recently to stress five points on oil and gas development: to approve ConocoPhillips’ GMT-1 project in the National Petroleum Reserve–Alaska; to approve Hilcorp Energy’s application to develop Liberty, a nearshore Beaufort Sea project; to extend Shell’s leases; to keep the 2016 and 2017 OCS lease sales on schedule, and to allow for Alaska OCS sales in a new five-year OCS plan. Jewell’s Oct. 16 announcement knocked two items off that list.

Repsol reduces Slope holdings, winter season deferred

Mixed feelings greeted an announcement Oct. 13 by Spanish major Repsol and Denver-based independent Armstrong Oil and Gas that the latter will be taking a larger share and most likely operating control of the companies’ proposed North Slope oil development. That Repsol, a major oil and gas company based in Madrid, is shrinking its share of the project and turning over the keys to Armstrong, a company with an exploration, but not development, focus, is being viewed negatively. Also, a three-rig drilling program the companies had planned for this winter has been deferred, the two firms announced in a press release. However, that Armstrong is willing to put more money into the discovery, $800 million in cash and various commitments like drilling, is a sign of confidence by that company. Also, work on development permits for the project is continuing without interruption, said Repsol spokeswoman Jan Sieving. In their joint statement, the companies released the first estimates of potential reserves for the project as well as a revised projection of production. The estimated flow rate is now 120,000 barrels per day instead of a 60,000 barrels per day estimate included in Repsol’s application for a U.S. Army Corps of Engineers permit earlier this year. Armstrong said that its consulting firm, DeGolyer and MacNaughton, reported reserves of 497 million barrels of oil using a conservative “C-1” methodology, or one with a high degree of confidence, but also estimates of 1.438 billion barrels of resources and 3.75 billion barrels using “C-2” and “C-3” estimates, procedures that involve less degrees of confidence. “These ‘contingent’ reserve classifications would be converted to proven, probable and possible where appropriate on the final investment decision to develop the project,” the press release stated. Under the agreement Armstrong will increase its share of the initial development area from 30 percent to 45 percent with an option for an added 6 percent, which would give the company a 51 percent majority ownership. The agreement will also allow Armstrong to increase its ownership in an exploration area, or unexplored leases outside the initial development, to 75 percent, leaving Repsol with 25 percent of about 750,000 acres of leases. The two companies are doing development planning on a discovery in the Colville River delta between the producing Kuparuk River and Alpine fields. While the winter three-rig drilling program could have employed up to 500 people, Sieving said that because the drilling is seasonal these are people who are not yet working, so there are no “layoffs.” Sieving said the initial reserve estimates came from Armstrong and its consultant, and were not developed by Repsol. However, the 120,000 barrels per day production estimate is based on updated work, she said. “The project is now considered to be larger, and potentially more valuable, than was seen before,” Sieving said. On the permitting, Sieving said a decision has now been made that a federal environmental impact statement, or EIS, will be needed for the project, a process that could take two to three years, instead of a more streamlined environmental assessment that Repsol had hoped for earlier. The U.S. Army Corps of Engineers is the lead agency on the permitting, she said. “The permitting is continuing to move forward,” despite the pause in drilling, Sieving said. The pending operational change has created uncertainties for Repsol’s office in Anchorage, however, for its employees based in Alaska. “We are now working on the transition plan and that will determine the impacts. We anticipate that some of our employees will remain with the project while others will be offered positions elsewhere,” Sieving said. Despite the negative aspects, Armstrong struck an upbeat note in its press release. “Over the last four years the (joint) venture has drilled 16 wildcat and appraisal wells with a 100 percent track record of finding oil in multiple pay zones,” of each well, Armstrong said. “With each drilling campaign, the project has become more valuable, larger in scope and more capital intensive than the parties originally envisioned.” The realignment is really to bring the project more into line with the strategic plans of both companies. “For Repsol, the transaction aligns the Alaska project with the company’s new strategic plan to integrate its recently-acquired Talisman assets into its portfolio and realign legacy assets,” the press release said. “For Armstrong, the transaction concentrates the company’s activities on the North Slope and allows it to focus on its core strengths, which are the exploration and development of shallow conventional oil plays identified by advance 3D seismic stratigraphic techniques.” While it is not considered an operating company Armstrong has a history of using its exploration expertise to identify prospects and to bring in larger companies to engage in development and production. The company did this initially on the North Slope with Pioneer Natural Resources on the small Oooguruk offshore field, which is now producing and owned by Caelus Energy, and with Eni Oil and Gas on the Nikaitchuq project, also offshore. Armstrong’s initial work on the Colville Delta prospects also led to the entry of Repsol into Alaska, as a partner with Armstrong, in 2012.

Sparcks ready to grow 10 years after winning AFN Marketplace

If three Sparck sisters from Bethel fulfill their ambition to grow their small ArXotica Inc. into a large skin and health care products enterprise, a lot of credit should goes to the Alaska Federation of Natives “Marketplace” business competition. That’s something the sisters — Michelle, Amy and Cika — readily acknowledge. In 2006, the Sparcks landed grants for critical startup cash through the AFN Marketplace, where entrepreneurs, mostly from rural areas, present their ideas and business plans to a panel of judges. Since then it’s been a slow but gradual uphill grind for the sisters but they feel they’ve now proved themselves and their products and carved out a niche, small though it is, for a unique Alaska product. Michelle Sparck said: “We’re ready to grow.” Since securing their seed money through AFN and now with a product line, the Sparcks have tried to return the favor by becoming regular exhibitors at the federation’s annual convention. In fact, the convention has proved to be a place where new products can be tested and launched, and that will happen again this year at AFN, Michelle said. The three sisters parcel out the responsibilities differently. Cika is a graphic designer and handles the promotion and marketing. Michelle has a background in business consulting and has led the research and development work. Amy has a consulting background and works to put the company into contact with Native American groups. Cika and Michelle are essentially full-time with the company although Michelle calls it, “an expensive hobby.” Uniquely Alaskan The product is indeed unique: Health products like skin creams that take advantage of the medicinal qualities in Southwest Alaska tundra plants that have long been known to elders in Alaska Native communities in the region. The sisters, who are triplets, grew up in Bethel but their roots are in Chevak, a Cup’ik community of less than 800 people in Western Alaska, where their mother, Lucy, grew up. While growing up the sisters spent summers at Chevak doing a lot of the traditional subsistence work people in the region do at fish camp and picking berries and other plants out on the tundra. “Chevak is a place where people continue to live a traditional subsistence way of life, fishing, hunting and gathering from the land around us,” Michelle said. Those were wonderful days, Cika recalls. “We learned about these plants and how they were used for medicine and skin care and there were a lot of conversations in fish camp as to whether we could somehow make a business out of this. We were always sharing ideas and dreams,” she said. There was a social purpose, too, because if these natural products could be sold the activity could stimulate local income and jobs for people in the villages, Cika said. “But living in an area so remote (as Chevak) isn’t easy, the cost of living is high, and jobs are hard to come by. We hope to be an agent of change, to improve the quality of life and provide opportunities for our people so they no longer have to leave their homeland to find work,” Michelle said. Dream to reality Like a lot of young peoples’ dreams it remained just talk for a long time, and the sisters meanwhile went off to college, careers and starting families, but the idea always lurked in their minds. Enter AFN Marketplace. The idea became a plan when Cika, a graphics designer, was hired by AFN to design the identity-branding and other materials for the first Marketplace competition, and as she did her designs and learned more, the spark reignited. “I got the idea that we could join this contest,” she remembered.  Join they did, and win they did — they were among the finalists selected to win a $20,000 startup prize. That began a long journey to research and document the medicinal and healing properties of tundra plants. Elders in the region regularly used the plants but to develop commercial products the Sparcks had to have documentation. “In our backyard, you find hundreds of thousands of acres of tundra bursting with millions of pounds of uncultivated, potent, micronutrient botanicals. Berries, greens, herbs and flowers bloom with robust sugars and enzymes. The season of harvest is short, but luckily the days are long,” the sisters wrote on the company’s website. The documentation began with the hiring of an ethnobotanist, Tasha Goldberg, who came to the region in 2007 to interview elders and survey the plants and berries with potential. This was followed up with minerals analyses provided by the University of Alaska Fairbanks. “This showed us the minerals and vitamin content,” Michelle said. The sisters then contracted with further botanical investigations done by Olds College, in Canada, which specializes in northern botanicals.  Ultimately the sisters wound up at the research and development unit at Brunswick Laboratories in Massachusetts, which was instrumental in measuring the ORAC (Oxygen Radical Absorbance Capacity) of the plants. ORAC value is the measure of antioxidant value of foods and plants. Antioxidants with plant origins help protect and repair damaged skin cells, and basically help slow the aging process, Michelle said. Brunswick Laboratories’ work was significant because it firmly documented the values of the plants, which is information required by manufacturers when the sisters work with them. “The manufacturers need to know that our claims are valid and the products aren’t harmful,” Michelle said. Interestingly, the data also showed the Alaska plants’ nutrient content far higher than the only public published scientific work on ORAC values in natural foods and plants, done by the U.S. Department of Agriculture. “The work we had just blew this away,” demonstrating a much higher (health) potency than the USDA survey, Michelle said. “Our tiny company did this.”  Research and development continued through 2011 as the sisters experimented with processing techniques. “With every step of the way we picked the best way to retain nutrient values,” she said. “For example, when we dried the wet (tundra plant) material to dry flakes, which reduces weight from 10 pounds wet to one pound dry, we were able to retain the nutrient content.” The dry flakes were then refined into a resin to make high-value products, and with this the sisters worked with large out-of-state firms who specialize in manufacturing bath and beauty products. One company is Suite-K, a Massachusetts-based boutique contract manufacturer of perfumes and other products made with natural ingredients. The refining of 800 pounds of dry, flaked material makes 20 pounds of resin, which is enough for 7,000 units of serum for products. A unit is 1.7 ounces, or 50 milliliters of serum product.  The first product the sisters made was a soap, and this came when they realized the plant material left over from the refining process still had nutritional strength. The soaps are now some of the company’s main products. Making the bars of soap were contracted out to local commercial kitchens but Michelle and Cika are now learning the art of doing this work themselves, mixing bases and fragrances of bath and beauty products. TLC: Tundra loving care The Sparcks have only had one major plant-harvesting year when they gathered 900 pounds of biomass from the tundra, had it flown to Bethel and then Homer to a local firm, Denali Biotechnilogies, which has a special drying unit that company had used in making products from blueberries. The gathered material, however, was enough to make 7,000 units of serum after the manufacturing, which has been enough for the first manufacturing run. “The lessons learned in losses and overages (in the manufacturing) will help us refine the packaging, sizes and output for the future,” Michelle said. “We are now introducing an expanded line of facial moisturizers, body lotion, a foaming facial cleanser, botanical lip balms and a men’s shaving cream, at the AFN convention this year. “We are also finally rolling out our toiletries, aiming for the Alaska Native and Native American-owned hotel market. We may call this ‘TLC,’ a play on ‘tender loving care,’ but in our case, ‘tundra loving’ care.” So far the strategy of exhibiting in booths at events like AFN and selling through a few boutique retail outlets in Alaska and the Lower 48 states have worked for the company, as long as it has operated at a micro-level. But if the Sparcks can nail down larger orders they will have to scale up production. Finding capital to grow, with all the marketing and promotion that entails, has also been an issue, and while the Sparcks have talked with venture capitalists they have been advised to keep the company under their own control, at least for as long as possible.  “Sourcing our own botanical materials was a hard way to start a company. We hand-pick our herb, berry and flower blossoms from a largely undeveloped landscape of roadless terrain the size of Ohio,” Michelle said. “We want signature ingredients that will stand out, and be able to deliver high quality products while retaining an identity as an indigenous-owned and operated business.” Ensuring that requires maintaining control. That may mean the Sparcks will have to continue to scrape up capital a bit at a time and grow more slowly, but that may be worth it to maintaining the uniqueness of the brand.  

Another AK LNG issue: Who pays for state access to gas?

If the giant Alaska LNG Project is built, more than three billion cubic feet of gas will be flowing through the Matanuska-Susitna Borough every day by pipeline. Will it be available for local residents along the pipeline route? The answer to that is yes, but there are qualifications, and Mat-Su legislators say they are getting a lot of questions about gas availability from constituents. “There is a perception by people that they will be able to ‘get’ natural gas. Everyone believes that. But we’re not sure where the take-off points will be,” or what costs will be, said Sen. Mike Dunleavy, R-Wasilla, at a Sept. 9 legislative hearing in Palmer. Dunleavy said some form of state subsidy for local gas service may be needed. The industry-state consortium planning the big gas project has agreed that there will be at least five “off-take” points along the 800-mile route of the pipeline, and there could be more than five. Agreement on how many off-take points will be specified must come this fall so that the information can be incorporated into a series of regulatory filings the Alaska LNG group must file next spring with the Federal Energy Regulatory Commission, said Miles Baker, spokesman for the state’s Alaska Gasline Development Corp. Just where the connections will be can be decided later but the working assumption is that there will be one near Fairbanks and two in Southcentral Alaska: a “North Cook Inlet” connection (meaning in the Mat-Su) and a “South Cook Inlet” connection on the Kenai Peninsula, Baker said. AGDC has scoped out the cost of gas processing facilities that will have to be built at the off-take points. The costs range from $38 million for a larger-volume plant unit of 80 million to 330 million cubic feet per day, to “mini” plant units designed to handle 20 million cubic feet per day to 75 million cubic feet per day (the appropriate size for an off-take near Fairbanks), and smaller units, for small communities, that would cost about $15 million. Those costs do not include a spur pipeline to carry gas to the communities or the costs of local gas distribution systems. Costs and logistics What is unresolved, however, is who pays for the gas process facilities at the valve, or the spur pipeline. A processing facility is needed because the gas will be at high pressure in the pipeline and will contain some natural gas liquids to “enrich” the gas to a specification desired by potential LNG customers in Asia. For local use, however, gas taken from the pipeline must be de-pressured and then conditioned, with the liquids removed, to a specification usable by regional utilities. For the Matanuska-Susitna Borough there is also the matter of getting the gas from the big Alaska LNG Project pipeline — which will follow a route west of the Susitna River — to the population centers of the Mat-Su region east of the river and to Port MacKenzie on Knik Arm where municipal officials hope gas processing industries can be attracted. Crossing the Susitna River is a pricey matter both for the main pipeline as well as a smaller spur line. Much of the Mat-Su region is now supplied with Cook Inlet gas through existing Enstar Natural Gas Co. pipeline systems, but those have limits on how much gas can be moved, and having large volumes of North Slope gas available, and potentially at a lower cost than Cook Inlet gas, would be a big selling point in attracting industry. If the gas from the Alaska LNG Project is used mainly by local residents and businesses, including for local power generation, it is possible that the existing Beluga pipeline, which is also on the Susitna River’s west side, can be used, requiring only a short connection from the Alaska LNG main pipeline. Even with that, however, the cost of the processing facilities at the off-take point could total several tens of millions of dollars. It would be another matter for a large industrial project at Point MacKenzie, such as the medium-sized natural gas liquefaction plant proposed by REI Alaska, a Japanese group. REI’s proposed 1 million-ton per year LNG plant might need more gas than can be moved through the Beluga pipeline. A new spur pipeline might be needed, most likely about 40 miles in length. While the straight-line distance from the Alaska LNG pipeline to Point MacKenzie may be shorter than 40 miles, the need to cross the Susitna may add to the length because the crossing must be made where the river is relatively narrow.  The pipeline cost would be added to the cost of the processing facilities. As a frame of reference, the cost of the Fairbanks spur line, developed by the Alaska Gasline Development Corp. as a part of the state’s planning for a backup gas project, is estimated at $50 million to $60 million for a 29-mile, 12-inch pipeline. The Fairbanks spur, which was designed as part of AGDC’s work on a state-led backup pipeline plan, would be capable of moving about 60 million cubic feet of gas per day. But the final volume could be less, and the pipeline of smaller diameter, if there is insufficient demand for the gas in the Interior community comes below 60 million cubic feet per day. A spur line to Point MacKenzie would likely cost more than the Fairbanks spur because it would be longer but no estimate can be made until details on the gas demand are nailed down. Who pays? But who will pay for that? Under the current agreements, the Alaska LNG Project pays only for the connection, the valve. Everything else is the state’s responsibility. Gov. Bill Walker is working to get the industry partners in the consortium, BP, ConocoPhillips and ExxonMobil, to pay for more than a valve, the governor’s spokeswoman Katie Marquette said, but the matter is part of a broad range of issues being discussed and is not yet resolved. Walker is working to get the spur lines to Fairbanks as well as a line to Point MacKenzie paid for the by the project, according to Marquette. If Walker is unsuccessful in persuading the industry partners, the state could pay for the connections and spur lines with state funds, but those are scarce currently. What’s also possible is that a third party such as a utility, another company or a municipal entity, could step up to the plate. A complication, however, is that no matter who builds the facilities and spur lines, the state Regulatory Commission of Alaska will have jurisdiction, and the RCA’s rules require, unless the state can just write a check, that the consumers being served by the spur pay for it. That may not or may not be a big addition to the monthly gas bill for consumers depending on how many are served. However, if there are gas-based industries at Point MacKenzie, they are likely to be more open to paying the transportation cost with facilities’ cost built in, but the Regulatory Commission of Alaska will ultimately decide the matter. If the state is to be responsible for the spur line and gas facilities it isn’t yet clear which state entity will take responsibility. Senate Bill 138, the enabling legislation for the gas project approved by legislators in 2014, gives certain responsibilities to AGDC such as getting an estimate of potential in-state gas demand updated from previous studies. The state gas corporation has also sponsored preliminary engineering and cost estimates for the gas process facilities at the take-off points. But which state entity would actually undertake the financing and construction of spur lines hasn’t been decided. It could be AGDC or the Alaska Industrial Development and Export Authority, the state agency that is sponsoring development of gas distribution systems in Fairbanks. Or, it could be another state entity.

Indepdendent oil explorers have plans from NPR-A to Southcentral

Independent companies are gearing up to drill more exploration wells in Alaska this winter and next summer, defying low crude oil prices and uncertainties in a state oil and gas exploration incentive program. Dallas-based Caelus Energy plans to test its offshore prospect in Smith Bay, which is north of the federal National Petroleum Reserve–Alaska, but onshore tests by small independents are now planned in the southern North Slope and in Interior Alaska. Australia-based 88 Energy plans to begin drilling its Icewine No. 1 test in mid-October, Managing Director Dave Wall said. The well location is 39 miles south of the Prudhoe Bay field area and is near the Dalton Highway, an access highway connecting the North Slope oil fields with Interior Alaska. “We are now fully funded and with a rig. The last of the permits required are falling into place such that the ‘spud’ of the well remains on track,” Wall said in a statement; 88 Energy will use Kuukpik Rig 5, operated by Kuukpik Drilling Co. Wall said in previous interviews that 88 Energy will test the potential for shale oil production and will also assess conventional oil targets. Great Bear Exploration, an Alaska-based independent, is also testing shale prospects in the area. In southern Alaska, Athna Inc., an Alaska Native regional corporation, plans to drill a test well in the Copper River Basin near Glennallen this winter. The primary target is natural gas, Ahtna land manager Joe Bovee said. If there is a commercial discovery the gas could be used for regional power generation and space heating, or if large enough shipped by pipeline to the Matanuska-Susitna and Anchorage areas. Ahtna is working in partnership with Midland, Texas-based independent Rutter and Wilbanks. The new well location is on state lands about three miles from where Ahtna and Rutter and Wilbanks drilled earlier, on lands owned by Athna. A gas discovery was made but technical problems created by high-pressure water zones prevented development of the find. Bovee said precautions are being taken with the new well, mainly in the casing design, as a safeguard of similar geologic conditions are encountered. The prospect to be tested this winter covers about 12 square miles with the potential gas-bearing reservoir rocks at depths from 4,000 to 5,000 feet, Bovee said. This prospect is about 10 miles west of Glennallen and three miles off the Glenn Highway, so there is good access. “We’re looking at an $8 million to $10 million program,” Bovee said. Ahtna is funding most of the cost but Bovee would not say how much. In another test, Doyon Ltd., the Native regional corporation for the Interior, will drill an exploration well next summer on state lands in the Nenana Basin, about 50 miles west of Fairbanks. Most exploration in Alaska is done in winter when land surfaces are frozen and cross-country travel is possible but the Doyon site is near an all-year gravel access road Doyon built to support previous drilling. Jim Mery, Doyon’s vice president for natural resources, said his company estimates its chances of making a discovery at 50-50 given what is known of the geology from previous nearby drilling and a recently-conducted seismic work over the prospect. Finding gas is more likely than oil at this location, Mery said, but an oil discovery is also possible. Doyon is funding 100 percent of the cost, which are expected to be in the $20 million to $25 million range. Doyon’s exploration in the Nenana Basin as well as the large Yukon Flats Basin farther north has demonstrated the presence of an oil-generating system, which upended earlier views by government geologists that both basins were gas-prone. In recent years Alaska Native development corporations like Doyon and Ahtna have largely funded exploration in the large, unexplored Interior basins because it has been difficult to attract other companies. The Native corporations are large landowners — Doyon itself owns 12 million acres — and although both the Doyon and Ahtna wells are on state-owned lands a discovery in either effort would enhance prospects on nearby lands owned by the Native corporations. As planning proceeds for these exploration efforts state officials are working to revamp the state’s existing exploration incentive program, which allows companies to apply for tax credits that are refunded by the state in many cases. Earlier this year Gov. Bill Walker trimmed the current year appropriation for the incentives from $700 million to $500 million in a budget move. Walker said the program will continue in some form, and Revenue Commissioner Randall Hoffbeck said a proposal to reorganize it will be put before the Legislature next year. Hoffbeck said the revised program will likely involve an annual limit on the tax credit expenditures and pre-approval by the state on some costs for which credits may be applied.

AK LNG makes technical progress, economics still challenging

Alaska LNG Project managers presented an upbeat report on technical progress of the giant gas project in a Sept. 9 briefing to legislators, but also warned of the economic challenges faced. Steve Butt, an ExxonMobil official who is manager of the overall project, described the possible complications of an expansion of the pipe diameter requested by Gov. Bill Walker. However, if the expansion were done the goal would be to keep the project on schedule for a 2018 or 2019 construction decision, he said. Butt said there are about 1,000 people at work on the Alaska LNG Project and spending on the preliminary engineering now underway reached $243 million as of July, Butt told a combined meeting of the House and Senate Resources committees. The total budget for the preliminary front-end engineering and design, or pre-FEED, is about $500 million, and work is to be done in early 2016. “The third summer of field work is being completed and we are finalizing the project design and execution basis, including cost and schedule estimates,” he said. A revised cost estimate will narrow, and update, previous cost estimates that range from $45 billion to $65 billion. On the LNG plant at Nikiski, near Kenai, the project has acquired about 600 acres of 800 acres needed for the giant LNG plant, and offshore soils data is being gathered for the marine facilities and onshore for the plant itself. “So far there is encouraging data from the geotechnical work,” said Butt, which was managed by the state’s Alaska Gasline Development Corp., or AGDC, a partner in the Alaska LNG Project. “The state (AGDC) did good work on this.” Two immediate issues on the table for the project team, he said, include the decisions to be made by AGDC this fall on the location of gas off-take points for communities along the pipeline route and approvals by the project for a 2016 budget to complete the “pre-FEED” work. “Where the offtake points are located is very important to us because even though the in-state gas use will only be 220 million cubic feet a year (of 3.3 billion cubic feet the pipeline will move daily) where the gas is taken off will affect the hydraulics of the gas movement, which will require designing for that, Butt told the legislators. On the 2016 budget, the project managers need to know whether TransCanada will still be involved, and putting up its share of money, or whether the state will be buying out TransCanada’s share, a proposal being made by Walker that will cost the state about $110 million. The Legislature must approve the state taking a larger share, presumably with AGDC expanding its role, and appropriations must be made by lawmakers, Butt said. Alaska LNG Project managers must be assured that the funds for the state/TransCanada share will be available, and they must know it soon to plan for the 2016 work program, he said. On the proposed pipe upsizing, the project partners are considering the idea, at Walker’s request, but only one of the four partners — ExxonMobil — has agreed to do the feasibility assessment, which could cost several million dollars, Butt said. The decision basically involves an addition to the 2015 work plan, which has an approved budget, and all parties including the state must agree to amend the plan to do a 48-inch pipe study. Three other partners, BP and ConocoPhillips and, ironically, the state, have not yet decided on the plan change, Butt said. Decisions are expected in about two weeks (from Sept. 9), he said. Meanwhile, ExxonMobil has already agreed to spend $1 million itself to purchase several lengths of 48-inch, high-strength pipe for technical tests that must be done for federal agencies, Butt said. If the study of an expansion of the 48-inch pipe is agreed to, it could also delay the decision on moving to the final engineering by six to eight months, he said, although there will be great efforts made to keep the overall schedule on track for a Final Investment Decision. The decision on final engineering is to be made within one year after completion of preliminary engineering, which would put it in mid-to-late 2016 or early 2017 under the current plan with a 42-inch pipeline diameter. The bigger, heavier pipe would also add to the logistics challenges; 42-inch pipe weighs 5.8 tons per 40-foot length, or “joint,” Butt told the committee, and 48-inch pipe weighs 7.8 tons per joint. That means that a heavy truck trailer can carry six joints of 42-inch pipe but only four joints of 48-inch pipe. That limitation means that 150,000 truckloads of pipe estimated to move 42-inch pipe to locations along the pipeline route will increase to 225,000 truckloads, he said. How much this will add to the overall costs of the project wouldn’t be known until the engineering study is done (which hasn’t been decided on), but there are also pluses and minuses. It would involve higher capital costs (for the pipe) but also lower operating costs because fewer compression stations will be needed and less gas would be burned as fuel for compression. Expansions of the gas “throughput” would be less expensive, too, because of the larger pipe, with about half as many added compressor stations compared with an expansion with the current 42-inch pipe diameter. There are construction risks with the current design because even at 42 inches the pipe is 22 percent heavier than most pipe used in other gas pipelines in North America, but the 48-inch pipe would be 59 percent heavier than the pipe used elsewhere to ship gas. There is large diameter pipe used on gas pipelines, Butt said, but not of the heavy, thick-walled type that is contemplated for this project. Also, none of those pipelines are 800 miles in length. A more bottom-line concern with the added capital expense is that until more North Slope gas is found the same volumes of gas will move through either a 42-inch or 48-inch pipeline, so the “cost of service” for moving North Slope gas will be increased, possibly by 10 cents to 15 cents per million British Thermal Units, or Btus. In the dog-eat-dog competition for future LNG markets, that may not help Alaska. “LNG is now selling for about half of what it sold for three years ago when we started this project, so achieving the lowest-cost gas,” supplied to the market is critical, Butt told the legislators. State officials, however, believe potential customers will take the long view and see that the extra capacity of the pipe will mean lower-cost expansions as more gas is found, and lower costs of service in the long run. Although 33 trillion cubic feet of gas reserves are now proven in two large North Slope fields — Prudhoe Bay and Point Thomson —industry officials say that once a gas pipeline is built large-scale exploration for gas will begin on the slope, which hasn’t occurred before. Much of the slope, in the “foothills” area of the southern slope and in the National Petroleum Reserve-Alaska, is considered to be more gas-prone than prone to oil. State and federal geologists estimate that as much as 75 trillion to 100 trillion cubic feet of conventional gas will ultimately be discovered and produced on the Slope.

Producers still squeezing barrels out of middle-aged Prudhoe Bay

It has been almost 50 years since it was discovered and nearly 40 years since it started producing, but today the Prudhoe Bay oil field is still the engine that drives Alaska’s North Slope oil industry. The field produces about 250,000 barrels per day — one sixth of what it produced in the late 1970s — but that’s still about half of the state’s total production. Without it, it’s unlikely the Trans-Alaska Pipeline System could operate economically. Even in its maturity Prudhoe is still the largest oil field in North America. Prudhoe’s producing companies now say they now expect to ultimately recover approximately 14.1 to 14.2 billion barrels of oil from the giant North Slope field, about 60 percent of the estimated oil-in-place in the reservoir rock. That’s according to Bruce Laughlin, BP’s reservoir management team leader. BP operates the Prudhoe Bay field on behalf of itself, as a co-owner, and partners ConocoPhillips and ExxonMobil. When natural gas is produced commercially from Prudhoe — which is expected in about 2025 if a planned North Slope gas pipeline and liquefied natural gas export project is built — the equivalent of another 3.5 billion barrels of oil will be produced in the form of natural gas. Originally, the field was expected to produce approximately 9.6 billion barrels of oil, or 40 percent of the oil-in-place (the oil physically in the reservoir rock), when it was discovered in 1968, but over the years the field operators employed innovative new technologies including gas re-injection and miscible injectant for enhanced oil recovery, some of them invented or first applied on the Slope, to push the oil recovery rate much higher, Laughlin said. State Natural Resources Commissioner Mark Myers said the companies have done an excellent job of squeezing more oil out of the Prudhoe reservoir. “It’s a good quality reservoir and they are employing very advanced technologies.  We’re fortunate to have large, experienced companies working on the North Slope,” he said. The Prudhoe Oil Pool  (the largest oil reservoir in the Prudhoe Bay field) is now producing about 250,000 barrels per day and its wells once produced 10,000 barrels per day, or more. Many are now at 1,000 barrels per day or less. The field is in its middle age, but it is still the largest oil field in North America and it ranks among the 20 largest fields of the world, according to the Alaska Oil and Gas Conservation Commission, a state regulatory agency. Because of its size, however, Prudhoe has also become a laboratory for new production and drilling technologies because the expected return, the amount of additional oil recovery, is well worth the risk of experimentation.  New technologies Prudhoe Bay has fostered over the years include “multi-lateral” wells, or a single well from surface with several underground producing legs, in effect several wells, were first done on the Slope and now as many as six underground wells are drilled off a single surface well. There is also coiled-tubing drilling, a radical innovation where drilling and well completions — not just well repair jobs — are now done routinely with low-cost coiled-tubing units rather than large rotary drill rigs. This was also first done on the North Slope Extended-reach and horizontal producing wells were developed elsewhere but applied on a scale at Prudhoe Bay that had not been done before. Prudhoe Bay producers are also employing water injection into the Prudhoe Oil Pool reservoir “gas cap,” the layer of gas overlying oil, to boost pressure in the reservoir. That has not been done elsewhere at the scale Prudhoe Bay producers are doing it, Laughlin said. The gas-cap water injection has resulted in 100 million to 120 million barrels of additional Prudhoe Bay oil recovery so far and another 170 million to 200 million barrels of added production are estimated, he said Also, there is now one of the world’s largest gas cycling operations at Prudhoe Bay, with approximately eight billion cubic feet of gas produced daily, the gas coming up the wells along with oil, and water. The bulk of the gas is injected back underground after removal of gas liquids, which are injected into TAPS to mix with crude oil, or used as miscible injectant for enhanced oil recovery. The injected gas, now “lean” with liquids having been removed, circulates back through the reservoir rocks, soaking up crude oil molecules as it moves back toward producing wells. When the gas comes, again, up the producing wells, this process known as vaporization brings more oil with it. So far, about half of Prudhoe’s recovery to date, about 12 billion barrels, can be credited to production enhancements like waterflood and the other half by the gas-cycling and vaporization and the injection of miscible gas fluids, Laughlin said. Assuming continued availability of gas liquids for miscible injectant, another 200 million barrels of crude oil is expected from all reservoirs in the Prudhoe Bay Unit by 2024, he said. In producing and injecting about 8 billion cubic feet of gas daily, Prudhoe now has the world’s largest gas handling and injection plants. BP has also tested two new enhanced oil recovery, or EOR, techniques at Prudhoe Bay and is now applying them worldwide. One involved a polymer injected to aid conventional waterflood, called “Bright Star.” Prudhoe still has a long life ahead as an oil producer, but the producers are planning a new role as a gas producer. Prudhoe will be the lynchpin for a $50-billion-plus gas pipeline and LNG project now planned by the companies with the State of Alaska as a partner. Prudhoe holds about 23 trillion cubic feet of gas and would supply about 75 percent of the 3.5 billion cubic feet of gas needed daily for the planned Alaska LNG Project (the remaining 25 percent of gas will come from Point Thomson, a new gas field being developed east of Prudhoe Bay). Production of Prudhoe’s gas will result in an additional 3.5 to 3.6 billion barrels of oil equivalent (i.e. gas expressed in terms of equivalent energy as crude oil). Thanks to gas production there will be more oil recovery from the Prudhoe Oil Pool in the long run because infrastructure maintenance and operations will be shared between gas and oil production. Those costs are now being spread across a diminished number of oil barrels being produced that will decline further as production drops. After 2025, when the gas project is to start up, gas will help shoulder the costs, which will extend Prudhoe’s life as an oil producer. It’s a synergistic relationship, too. Gas production needs oil to share the infrastructure costs, because the economics of gas are thin and needs costs to be shared by oil. Conversely, sharing of the costs will extend Prudhoe’s life for decades, resulting in more oil recovery as operators figure out ways to tap bypassed pockets of oil. One pocket of bypassed oil is in the lower parts of the Prudhoe Oil Pool reservoir. There is an estimated 1.2 billion barrels in a tar layer at the bottom, and while not much of this is likely to be produced, there are accumulations of oil of higher quality just above it that might be economic to tap, Laughlin said. Overall, there’s about 10 billion barrels of oil-in-place remaining after the expected 14 billion barrels of recovery. “That a big target for future, assuming continued improvements in technology,” he said.

Walker touts AK LNG in Japan, responds to Exxon CEO

Gov. Bill Walker is in Japan to wave Alaska’s flag at a big liquefied natural gas conference in Tokyo. A team of state officials accompanies Walker including Deputy Natural Resources Commissioner Marty Rutherford; Audie Setters, an LNG consultant to the state, and Walker’s communications director Grace Jang. The meeting is the annual LNG Producers/Consumers Conference, one of the world’s largest and most influential LNG trade conferences, where Walker will speak Sept. 15. Before the conference the governor and his team met with senior officials at Itochu Corp., a trading company; Japan Oil, Gas and Metals National Corp., a government agency that finances Japanese companies; Tokyo Electric Power Co., Japan’s largest electric utility, and Tokyo Gas, which serves seven cities in Japan and 11 million customers. Walker was invited to make a presentation on Alaska’s gas resources and its planned large LNG export project at the LNG Producers/Consumers Conference. It will be a first time that a governor from the state has spoken at the conference, Walker said in a Sept. 11 press conference before departing to Asia. Sen. Dan Sullivan, the former state resources commissioner, has previously spoken on Alaska’s gas potential but having the state’s governor invited to appear carries more emphasis, according to people familiar with the conference. Walker said he is working mainly to raise Alaska’s profile as a source of reliable supply from a politically stable region and will not discuss any investments by Japanese or Korean firms in the Alaska project or any sales of LNG. “That would be premature,” the governor said in the press briefing.  Among companies Walker will meet with in separate sessions will be Tokyo Electric, and Tokyo Gas, two large LNG importers that purchased liquefied gas from the Alaska LNG export project for 40 years; Mitsubischi and Marubeni, large Japanese firms with a long interest in Alaska, along with Osaka Gas, KoGas, Korea’s national gas company and Japanese government institutions. “We’ve met with most of these people before, but not on this basis (as the state’s chief executive). This is a chance to reestablish old relationships,” the governor said. Rutherford, the DNR Deputy Commissioner, said she is talking about Alaska’s proven gas reserves in Japan. “In Prudhoe Bay and Point Thomson lie 33 trillion cubic feet of natural gas, and those are just the proven reserves,” Rutherford said in a statement issued Sept. 15. She went on to promote the governor’s idea of expanding the pipeline diameter to be able to handle more capacity. “Upsizing the pipeline from 42 inches to 48 inches lowers the overall operating costs and increases deliverability for our customers,” she said. Japan has one of the few steel plants in the world that are capable of manufacturing 48-inch high-strength, thick-wall pipe. There are no plants in North America with the capability, although there are plants that can make 42-inch diameter high-strength pipe. The state’s partners in the gas project, North Slope producers BP, ConocoPhillips and ExxonMobil, are still considering the expanded diameter, however. Walker said he doesn’t expect many questions about the current strained negotiations between the state and North Slope producers on agreements for the Alaska LNG Project. Customers in Asia will be mainly interested in the security and consistency of supply, to the point that the LNG price is almost a secondary issue. “We’re certainly not at any kind of impasse in the negotiations,” the governor said. “Their biggest issue is the resource itself. The structure of how we get it there (the project) is not the focal point. Our big selling point is that we have a long history of honoring contracts and making shipments on time, a 40-year history. That’s a 5-star rating. Companies in Japan tell me that the price is not as important as deliverability, and that’s critical.” Alaska’s other big advantage is that the gas is proven and in fact has been produced and reinjected many times by the North Slope producers to aid oil recovery. In contrast, there are risks with gas from other places, like shale formations of the Lower 48. “Our gas is proven and that’s a huge advantage,” Walker said. In reference to the current negotiations the governor lobbed a soft volley at ExxonMobil, the company leading the Alaska LNG Project. Responding to complaints made by ExxonMobil chairman Rex Tillerson in a natural gas trade publication about Alaska’s frequent changes of direction on the project, Walker said: “I know some companies are uncomfortable with what we’re trying to do, in taking a much more aggressive role in moving the project along. But we’re the second largest gas owner on the slope (after ExxonMobil) and we’ve got to start acting like an owner.” In a question-and-answer article in Natural Gas Week, published by the Energy Intelligence Group, Tillerson cited major shifts in the state’s positions with each change of administration and election cycle. This has been very disruptive, Tillerson said in the article. “I have a long history with this, and I always tell every governor of Alaska, ‘You are not waiting on us. You are waiting on you,’” he said. “And every governor that comes in decides they’ve got a different way of doing this, which is why it never happens. You can’t take a project that is going to take five-six-seven years to execute and require $50 billion-$60 billion of capital and decide every two years you’ve got a different way to do it. “We’ve had two good chances in the last 10 years to get it done, and as soon as you had an election that ended it. Alaska is their own worst enemy.” Tillerson was also referring to former Gov. Sarah Palin’s detour from a partnership approach to a gas project to one led by an independent pipeline company, which failed, but he also had Walker in mind. Walker said he had no apologies for his own efforts at changes to the project, although some of these, such as a possible late change in the pipe diameter, could delay the project moving into final engineering. The governor also complained about the companies’ slowness in coming to grips with key issues in the negotiations. He didn’t cite ExxonMobil directly but did so indirectly. He said the process he inherited from former Gov. Sean Parnell is captive to the “slowest moving” partner in the project. Walker said when asked who was moving slowest on the project “I’ve been very pleased with the pace of BP and ConocoPhillips,” in the negotiations. He did not mention ExxonMobil.

Pages

Subscribe to RSS - Tim Bradner