THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013 1
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THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013
Fairbanks Industry Update Forum
Westmark Fairbanks Hotel & Convention Center 301 Arctic Slope Ave. Ste. 350 Anchorage, AK 99518 P: 907-561-4772 F: 907-563-4744 www.alaskajournal.com
Regional Vice President Lee Leschper (907) 275-2179 lee.leschper@morris.com Managing Editor Andrew Jensen (907) 275-2165 editor@alaskajournal.com
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Production Manager Maree Shogren (907) 275-2162 maree.shogren@morris.com Cover and Layout Designer Nadya Gilmore (907) 275-2163 nadya.gilmore@morris.com Reporter Tim Bradner (907) 275-2159 tim.bradner@alaskajournal.com Reporter Elwood Brehmer (907) 275-2161 elwood.brehmer@alaskajournal.com Reporter Molly Dischner (907) 275-2158 molly.dischner@alaskajournal.com Photographer Michael Dinneen (907) 275-2105 michael.dinneen@morris.com Advertising Director Tom Wardhaugh (907) 275-2114 tom.wardhaugh@morris.com Account Executive Ken Hanni (907) 275-2155 ken.hanni@morris.com
AIDEA’s board approves funding for Slope LNG plant equipment ..................PAGE 7
ExxonMobil lets new contracts for Point Thomson work..........PAGE 20
Drill, BP, Drill: New president outlines aggressive investment plans . ...............PAGE 8
Repsol gets one-time extension for North Slope leases......PAGE 23
State closes fiscal 2013 in red; oil production drops almost 8%.................. PAGE 10
International Tower Hill still confident Livengood gold mine can be developed..................PAGE 24
ConocoPhillips, independents making moves.........................PAGE 10 Fairbanks gas territory up for grabs as LNG plan advances.......................PAGE 13 UAF to press again for funding to replace aged power plant............................PAGE 14
Pogo still state’s top gold mine, boosting Interior economy.................PAGE 26 Golden Valley completes financing to purchase mothballed Healy coal plant................................PAGE 29
¡Éxito! Spanish major Repsol finds success on Slope . ...PAGE 16
Wind power producers ask regulators for rate certainty................PAGE 30
Pioneer sees good results from North Slope fracturing wells...........................................PAGE 19
ConocoPhillips applies for permits for new NPR-A project.........................PAGE 33
Cover Photo/Kevin G. Smith/AlaskaStock.com
Cover illustration/nadya gilmore/ajoc
THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013 5
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THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013
The Alaska Support Industry Alliance 3301 C Street Suite 205 Anchorage, AK 99503
Phone: (907) 563-2226
Website: www.alaskaalliance.com
General E-mail: info@alaskaalliance.com
General Manager Rebecca Logan rlogan@alaskaalliance.com
Director of Operations Ann Northcutt anorthcutt@alaskaalliance.com
Director of Communications Renee Limoge rlimoge@alaskaalliance.com
Welcome! Thank you for joining us for the 3rd Annual Fairbanks Industry Forum. This is an exciting time for the Alaska Support Industry Alliance and our members. We have been more active than ever before in working to educate our members and the public about the issues that matter to the oil, gas and mining support industry and this event is just another example of those efforts. In developing our agenda for today’s Forum, we worked hard to ensure we were addressing the topics that matter to the Fairbanks community. The Alliance is well aware of the challenges faced by this area and we hope the projects and issues discussed are important to you. The Alaska Support Industry Alliance continues to grow. We have over 500 member businesses that employ nearly 30,000 people in the oil, gas and mining support industries. It remains crucially important that our voices be heard — the voices of the men and women across the state whose jobs are dependent on a vibrant economy. Your support helps to ensure that we remain active in our efforts to educate the public and work with government officials to create a business climate where we can responsibly develop our resources to the maximum benefit of Alaska’s people. Again, thank you for being here today.
Rebecca Logan
General Manager Alaska Support Industry Alliance
THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013 7
AIDEA’s board approves funding for Slope LNG plant equipment By Tim Bradner Alaska Journal of Commerce
The Alaska Industrial Development and Export Authority’s board has approved $7 million for the purchase of long lead-time equipment for a North Slope natural gas liquefaction plant to serve an LNG-trucking operation to Fairbanks. Meanwhile, the state authority has received proposals for joint ventures with AIDEA in developing the LNG plant at Prudhoe Bay. There are also two proposals to build a new gas distribution systems for Fairbanks, with one to be selected for licensing by the Regulatory Commission of Alaska. In an Aug. 29 memo to AIDEA’s board, the authority’s executive director, Ted Leonard, said he expects to conclude negotiations on forming a limited liability company that would include AIDEA and one or more private participants, and to bring a proposal to the board in late October or early November. Gov. Sean Parnell has set of a goal of having the “Interior Energy Project” up and running by the fourth quarter of 2015. Last spring, the state Legislature approved $275 million in state financing for the project. The North Slope plant would process 9 billion cubic feet of gas per year and ship 300,000 gallons per day of LNG 500 miles by truck to Fairbanks for use in space heating and power generation. Karsten Rodvik, an AIDEA spokesman, said proposals made to AIDEA on the LNG plant include two from Interior Alaska utilities, Golden Valley Electric Association, the regional electric cooperative, and the Interior Gas Utility, a new utility formed by the Fairbanks North Star Borough to build a regional gas distribution system. Two private firms making proposals include Fairbanks Natural Gas LLC, which now operates a small gas utility in Fairbanks with LNG trucked from Southcentral Alaska, and Spectrum LNG, a company that operates a small LNG plant in Arizona supplying fuel to truck fleets, Rodvik said. Since the proposals were submitted, the Interior Gas Utility has withdrawn to focus its efforts on the gas distribution system. That leaves GVEA and the two private firms as possible partners with AIDEA. In full operation, the plant would ship about 50 truckloads of LNG per day to Fairbanks,
Photo/Courtesy/Office of Gov. Sean Parnell
Gov. Sean Parnell chats at the Fountainhead Auto Museum in Fairbanks after signing legislation for a state financing package to build an LNG plant on the North Slope and truck the fuel to Fairbanks.
which has raised some concern because it would increase truck traffic on the Dalton Highway, a gravel industrial road serving the North Slope, by about 50 percent. Because of the seasonal swing in energy demand between winter and summer, LNG production at the plant would be cut back during summer, so that the plant might operate at 60 percent capacity, or less, for part of the year. The assumed 9 billion cubic feet per year of gas converted to LNG assumes only gas used for space heating and, for now, not used for power generation by GVEA or by Flint Hills Resources, which operates a refinery east of Fairbanks, AIDEA’s board was told in a briefing by its staff July 25. GVEA and Flint Hills have not indicated they will purchase LNG from the plant, although the power co-op has made a proposal to be the state’s partner and is likely to ultimately be a customer. Flint Hills says it will weigh the cost of the LNG against energy it can produce within its own refinery at North Pole. If additional LNG is purchased by GVEA and Flint Hills, the plant at Prudhoe Bay can be expanded in increments.
The plan calls for the state to invest in and own part of the plant, possibly as much as twothirds, and to finance the $207.7 million plant cost with a combination of a $50 million state investment and low-interest loans to the jointventure company to be formed with partners, who would be expected to invest $33 million in equity, according to a finance plan presented to AIDEA’s board. In addition, the state would also help finance development of LNG storage and a gas distribution system in Fairbanks with $150 million in loans and $30 million in tax credits for a storage facility. The entire state finance package, including cash investment, low-interest loans and tax credits approved by the Legislature last spring, totals $355 million. Rodvik said the authority’s board has authorized its staff to negotiate an agreement with one or more of the entities responding to a Request for Proposal. Parnell, a Republican, is backing the LNG trucking plan despite its poor economics and heavy subsidy because of a dire energy situaSee AIDEA, Page 13
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THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013
Drill, BP, Drill:
New president outlines aggressive investment plans By Tim Bradner Alaska Journal of Commerce
More than 900 people crowded into the Dena’ina Center in Anchorage June 26 at the Resource Development Council’s annual meeting, most coming to hear BP’s new Alaska President Janet Weiss talk about the company’s plans for investment on the North Slope. Weiss was appointed Jan. 29 to replace former president John Minge, but this was her first public address. Her selection to lead the company is significant because she is the first BP Alaska president to have spent her entire career in the state, most of it with BP. That gives here first-hand experience with the company’s operations and with the state as well. “I’ve just celebrated my 28th anniversary with BP and ARCO, and I’ve spent nearly 20 of those years right here in Alaska … right where I want to be,” Weiss said. She takes over BP at a pivotal time. The state Legislature passed Senate Bill 21 in midApril, reshaping and reducing the state’s oil production tax with the hopes for the change to spur renewed oil investment. Most of that would have to come from BP and its partners ConocoPhillips and ExxonMobil, who own the large producing fields on the Slope where the bulk of the near-term potential for new production is located. BP is operator of two of the biggest fields, Prudhoe Bay and Milne Point. In her speech, Weiss described her hands-on background with the North Slope: “I’m an engineer by background. I came to Alaska in the mid-‘80s when times were tough. I’ve seen North Slope production climb to more than 2 million barrels a day and decline (now) to half a million barrels a day. I was here to live through single-digit oil prices and to experience prices well over $100 a barrel,” Weiss said. “I’ve seen companies go through mergers and acquisitions. From small independents to some of the largest oil companies in the world, I’ve seen new entrants to the Slope come, and I’ve seen some companies go.” She made personal observations: “Troy and I raised our two kids mostly in Alaska. Alaska is stunning. Our family is attracted by its beauty and the spirit of adventure among Alaskans.
“For me, Alaska’s vastness and sense of adventure apply to the North Slope as well. The extent and quality of the reservoirs are world-class, and the lure of innovation is infectious. Conditions are challenging; innovation and technology are imperative to tap the vast resource potential that’s there. That’s what makes it great.”
Coming together Weiss cited examples of Alaskans coming together with shared vision: statehood, economic recovery from the 1964 earthquake, and construction of the Trans-Alaska Pipeline System. She put the Legislature’s passage of SB 21 in the same category as a historic point
cent and 65 percent under the revised tax approved by the Legislature in April, getting to a mid-range of producing jurisdictions. Within days after the Legislature passed SB 21 on April 14, North Slope companies including BP began making announcements on projects. ConocoPhillips announced new work in the North Slope fields it operates, the Kuparuk River field and leases in the National Petroleum Reserve–Alaska, where it is operator. BP announced shortly after it would invest $1 billion in new work in fields it operates.
Project plans In her June 26 speech, Weiss elaborated on this initial announcement to discuss new projects including a potential $3 billion devel-
“SB 21 signaled something important to industry: that Alaska wants to be a globally attractive place for investment. This is already having a profound impact on the pace and scale of projects we’re pursuing as a company with our co-owners and as an industry on the North Slope.” — BP Alaska President Janet Weiss. where people decided to change the economic fundamentals that underlie a major state industry, petroleum. “I’m inspired by the challenge of ensuring BP does our part to build a strong and sustainable future for Alaska now that you’ve provided us with a more competitive investment climate,” she said. “I believe our 2,300 employees in Alaska feel the same way. “SB 21 signaled something important to industry: that Alaska wants to be a globally attractive place for investment. This is already having a profound impact on the pace and scale of projects we’re pursuing as a company with our co-owners and as an industry on the North Slope.” The tax change made by the Legislature in SB 21 effectively lowers the “government take” (federal, state and local, most of its state) share of Alaska oil production from about 75 percent under the previous tax law to between 60 per-
opment in the west end of Prudhoe Bay and a new project in the Milne Point field with an estimated investment of $1 billion to $2 billion. If the new projects being planned and evaluated by the major North Slope producers go forward, it would total more than $5 billion in new investment. A separate slate of projects are meanwhile planned by independent companies, including Brooks Range Petroleum, a small Alaska-based company, and Pioneer Natural Resources, a large independent based in Dallas. Companies are also exploring. Repsol, the Spain-based major oil company, made three oil discoveries in three exploration wells it drilled this past winter season, two of them very encouraging, the company has announced. Repsol’s drilling has been underway for two winter seasons — and prior to the passage of SB 21 — but the company says that the prospect of a tax change encouraged it to come
THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013 9 to Alaska in 2011 when the governor first proposed the reduction. What the companies have said they will do for certain, so far, is: • put three new rigs to work; • develop one small new field outside the producing fields (the Brooks Range “Mustang” field); • develop a small, economically-marginal reservoir within the Prudhoe field. BP said it would put two new drill rigs to work in the fields it operates, Prudhoe Bay and Milne Point. Weiss, at the RDC, said the company is now soliciting proposals to build the rigs and that they will be drilling by 2015 and 2016. The two rigs will add 30 to 40 new production wells per year for at least five years in the BP-operated fields and about 200 new drilling jobs, Weiss said. They will increase BP’s rig fleet to nine. A new Prudhoe Bay project BP will tackle soon, she said, is development of the Sag River formation, a thin, technically-challenged reservoir that overlies the main Ivishak producing formation of the Prudhoe field. The first phase of Sag River development involves 16 wells, with drilling to begin in 2015. Ultimately there could be 200 new production and injection wells, and about 200 million barrels of new oil production. BP will also evaluate the Northwest Schrader prospect in the Milne Point field, Weiss said. Technical hurdles must still be overcome, but the project would require $1 billion to $2 billion in new investment, construction of two new well pads and 70 new wells, with about 80 million barrels of new production added. “These were projects that were sidelined by the state’s tax policies,” prior to the change made by the Legislature in April, Weiss told the RDC. Weiss added more details on the potential Prudhoe Bay west end projects also being evaluated. If these proceed they will include “debottlenecking existing facilities and field infrastructure, expansions of existing well pads, construction of one new pad and 100 new wells,” she said. “We expect appraisal work to last two to three years. Development could last at least a decade. These projects would create thousands of direct and indirect jobs, access hundreds of millions of barrels of additional oil at Prudhoe, and eventually generate tens of thousands of barrels of new production per day.” T im Bradner can be reached at tim.bradner@alaskajournal.com.
Photo/Courtesy/BP
Janet Weiss was appointed president of BP Alaska in January, succeeding John Minge. She announced major investment plans for the North Slope following the passage of oil tax reform during the 2013 legislative session.
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THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013
State closes fiscal 2013 in red; oil production drops almost 8% By Tim Bradner Alaska Journal of Commerce
The state dipped into cash reserves for about $384.4 million to pay the bills for state fiscal year 2013 ended June 30. A larger deficit, $667.9 billion, is estimated for the current state fiscal year 2014, but that will surely change through the year as forecasts are refined for oil prices and oil production, state budget director Karen Rehfeld said. In another development, the state Department of Revenue said North Slope oil production dropped about 8 percent last year, to an average of 533,000 barrels per day. Oil and gas taxes and royalties pay for about 90 percent of the state budget. Fortunately, the state has ample cash reserves on hand. The Statutory Budget Reserve, from which state treasury officials can draw,
was at $5.49 billion in market value as of June 30, according to the state Department of Revenue. A separate Constitutional Budget Reserve, which requires legislative approval for a draw, was at $11.56 billion on June 30. State revenues totaled $11.91 billion in FY13, while spending totaled $12.3 billion. In FY14, revenues are projected to total $10.66 billion, while spending approved by the Legislature last spring totaled $11.33 billion. The spending figure will change because there will be inevitable supplemental appropriations submitted to the Legislature next spring for unexpected expenses, such as an unusually heavy forest fire year requiring firefighting activity. Rehfeld said a better estimate for the FY13 deficit will be known in September when state agencies complete the accounting for reappropriations of funds made by the Leg-
islature. The fiscal year ends June 30 but it takes several weeks for reappropriations to be sorted out. The final numbers come in December when the state publishes its annual financial report, Rehfeld said. State revenue officials said oil production declined 7.96 percent between fiscal year 2012 and the just concluded fiscal year 2013. The figures are still preliminary and may be adjusted, the department said. The higher rate of decline appears to be mainly due to an unusually heavy schedule of maintenance on North Slope production facilities during the summer of 2012, which required production to be reduced. Summer maintenance of facilities in 2013 appears more normal, so the production decline should be closer to the long-term average of 6 percent, the department said.
ConocoPhillips, independents making moves ConocoPhillips has announced new projects in the Kuparuk River field, where it is operator, along with the prospective development in the National Petroleum Reserve–Alaska. In the Kuparuk field, ConocoPhillips said it will add one drill rig and begin evaluation of a new production pad in the southern part of the field. The new Kuparuk production pad being considered is Drill Site 2-S at the southern edges of the known Kuparuk reservoir. ConocoPhillips had earlier drilled an exploration well there, “Sharktooth,” to test for potential oil accumulations. In the NPR–A, ConocoPhillips holds federal leases along with Anadarko Petroleum Corp., a minority owner. ConocoPhillips said it has started work there on permitting and engineering for the development of GMT-1, one of two discoveries made by the company several years ago in the northeast part of the petroleum reserve. GMT-1 is 17 miles southwest of the Alpine field, which is operated by ConocoPhillips. The company submitted permits to the U.S. Bureau of Land Management, which administers the NPR–A, in July (See page 33). ConocoPhillips’ other discovery in the area is GMT-2, which is eight miles further west, and which is not being developed at this time. Even though NPR-A is federally owned, under federal law half of the NPR-A royalties are shared with the state and production taxes to the state are paid just as if the production were from stateowned or private lands. That means the changes made by SB 21 also benefit the economics of potential NPR-A projects.
Independent moves While most attention is focused on the companies operating the large producing oil fields, independents are also moving aggressively on new projects. Brooks Range Petroleum is now constructing its new “Mustang” project west of the Kuparuk River field. This is a small field that will produce about 15,000 barrels per day at peak, and will be in operation by 2015. While Mustang was in development before the tax change, SB 21 has improved its economics and has encouraged Brooks Range to begin work on other nearby prospects that are similar to Mustang, the company has said. Pioneer Natural Resources, a major independent company, is meanwhile working on a potential new project near its existing Oooguruk field. Pioneer’s “Nuna” prospect has been drilled and evaluated, and the company is expected to make a decision this fall on whether to develop the project. If it moves ahead Nuna could produce about 15,000 barrels per day. (See more, page 19) These are relatively small fields, but together they could add an amount of new production for TAPS. While there have been many oil discoveries on the North Slope, the geology is still attractive for the finding of many small to medium-sized fields, Brooks Range and Pioneer have both said. — Tim Bradner
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Fairbanks gas territory up for grabs as LNG plan advances By Elwood Brehmer Alaska Journal of Commerce
A competition has emerged between Fairbanks Natural Gas Co. and the Interior Alaska Natural Gas Utility over who will serve the Fairbanks North Star Borough with natural gas. Fairbanks Natural Gas, or FNG, filed an application with the state Regulatory Commission on April 5 to expand its service area to include nearly all of the populated areas of the Fairbanks North Star Borough. The area runs south and east from the Fairbanks to North Pole and the area surrounding Eielson Air Force Base. FNG’s initial application outlines a plan for $27.5 million worth of private infrastructure investment through 2016. On April 22, the Interior Alaska Natural Gas Utility, or IGU, filed with the Regulatory Commission to serve a similar area. IGU’s application said the Borough-owned gas utility has a $484.7 million plan for a full infrastructure build out to reach an estimated 13,000 customers by 2019. FNG, which currently serves about 1,100 natural gas customers in Fairbanks, later re-
vised its plan to meet the needs of 8,000 customers by 2021. FNG President and CEO Dan Britton said his company’s full plan takes advantage of $150 million in state bonds available through the Alaska Industrial Development and Export Authority and private debt and equity financing through the financial backing of its parent company Pentex Alaska Natural Gas Co. Regulatory Commission hearings to review the plans against each other were scheduled for Sept. 16-20 in Anchorage. A final decision should be expected by Oct. 19, according to Commission procedure. AIDEA is the state development corporation leading the overall effort to get natural gas from the North Slope to the Interior. Britton said the disparity between customer numbers is a matter of FNG being conservative with its estimates in an effort to mitigate costs if the customers don’t materialize once the gas lines are buried. The Fairbanks North Star Borough formed IGU in late 2012 with a goal to spur investment in natural gas transmission lines through the
borough’s populated core. In its application, IGU reports that the average borough household spends about $5,000 per year on fuel oil for heat. It claims the ability to provide natural gas to residents for $15 per thousand cubic feet, or mcf. That’s about half the cost of fuel oil per British thermal unit. In its Regulatory Commission filings, FNG estimates a customer cost of $13.90 per mcf of gas in 2021. IGU Chairman Bob Shefchik said the utility’s plan includes $120 million for 20 million gallons of gas storage in the region to stabilize demand and availability swings. FNG is in the midst of building a 5.25 milliongallon gas storage facility near Fairbanks. As far as transmission costs are concerned, Shefchik said AIDEA recently gave IGU a revised study on the overall pipe needed to serve its desired area. IGU’s proposal calls for about 1,000 miles of pipe at a cost of $370 million. AIDEA’s study uses slightly more than
lution when particulates from combustion concentrate during cold weather. About a third of the households and buildings in Fairbanks use wood heat as a main or supplemental heat source due to high oil prices, and the particulates in wood smoke combined with those from burning heating oil combine to create dense pockets of polluted air, according to the state Department of Environmental Conservation. The U.S. Environmental Protection Agency has classified Fairbanks as a non-attainment area, and penalties including cuts to funds for federal projects will kick in unless the community develops a plan to deal with its air quality problem. Natural gas is the solution, and trucking LNG is the quickest way to get it used, Fairbanks mayor Luke Hopkins said. Reliability is a concern for the trucking project, however. About 470 miles of the 500-mile highway distance is on gravel road and the road also traverses the difficult
and narrow Atigun Pass in the Brooks Range. Winter road closures are not uncommon. The solution to this is building enough LNG storage capacity to give the community 10 days to two weeks of LNG supply in the event of a road closure. However, other emergency supply options might be explored, said Gene Therriault, deputy director of the Alaska Energy Authority, a sister agency to AIDEA that will assist the build-out of a gas distribution system. One idea is making a standby arrangement with ConocoPhillips to supply LNG from its plant on the Kenai Peninsula, in Southcentral Alaska, Therriault told AIDEA’s board in a briefing. ConocoPhillips’ plant is not operating at present after allowing its export license to expire due to shortages of gas in Cook Inlet. With regional utilities’ needs now met through 2018 with Hilcorp Energy, the state has asked the company to reopen the plant to create a market for other companies developing Cook Inlet gas.
See FAIRBANKS, Page 34
AIDEA
Continued from Page 7 tion in Fairbanks where the community is mostly dependent on fuel oil for space heating and power generation. In the extreme cold of Interior winters, homeowners can spend more than $1,200 per month on heat. Electric bills are also high because power generation is mostly oil-fired. A feasibility study of the LNG trucking by AIDEA estimates that LNG can be delivered to Fairbanks from the North Slope for $11.59 per thousand cubic feet, or mcf, and sold to consumers for $14.09 to $17.09 per mcf. That is about half the cost of the equivalent energy delivered with fuel oil. Annual household savings are estimated at $2,500 to $3,000 per year, according to AIDEA’s analysis. The assumed price for gas paid to producers at Prudhoe Bay is $3.30 per mcf, according to information presented to AIDEA’s board. What is driving the fast pace of the project is an urgency for cleaner fuel in Fairbanks to ease winter health hazards caused by air pol-
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THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013
UAF to press again for funding to replace aged power plant By Tim Bradner Alaska Journal of Commerce
There is something that keeps University of Alaska president Pat Gamble and UA Fairbanks Chancellor Brian Rogers awake on a winter night. Say it’s a typical cold night in Fairbanks. Thirty, maybe fifty degrees, below zero. A pipe breaks in the university’s 50-year-old coal-fired plant. The university’s campus heat, which the plant provides, goes down. Having to empty out the university’s buildings and find shelter for hundreds of students is bad enough, but a freeze-up could also put at risk hundreds of millions of dollars in university buildings and infrastructure. The existing plant heats about 3 million square feet of building space on campus including dormitories, classrooms, research facilities and other buildings. New construction now underway on the campus will add about 270,000 square feet of space. The entire campus freezing up is a nightmare scenario, but it could happen. In a pinch, Golden Valley Electric Association, the Interior electric co-op, could provide electricity to the campus, which it does now to meet winter peak demand, but having the lights on doesn’t help if the buildings go cold and pipes freeze. The fact is there’s no backstop for steam in the heating system. That has to come from the power plant’s coal-fired boilers. Those are half a century old, and the combustion technology in the old plant is more than a century old. UAF needs a new power plant. The price tag for a new coal-fired plant, which is the only realistic option, is an estimated $245 million. Where will the money come from? The university itself can cover about $45 million of the cost through borrowing with revenue bonds but the other $200 million has to come from somewhere, and the state Legislature is the only realistic option. UAF has also looked at the possibility of a public-private partnership, which is being done for the first time on another campus building project, the Wood Center expansion. This involves a private company investing in, and owning, part or all of a project. While this is a possibility, the investor would have to earn a profit and this could drive up the
Photo/Todd Paris/University of Alaska Fairbanks
The University of Alaska Fairbanks’ aged coal power plant relies on obsolute technology and UAF wants to replace the plant with modern, more efficient combustion systems. As much as $200 million may be needed from the state Legislature to replace it.
long-term costs of the project to levels that could be unaffordable. One factor is that a privatelyowned power plant would have to pay local property taxes, which could be considerable. So once again, the university’s Board of Regents will likely ask the Legislature later this year for funds to replace the aged power and steam heat plant. Last year legislators said no. The year before they gave $3 million to allow preliminary engineering and permitting work, which are critical to the project. The new plant would be more efficient because the technology to be employed — a circulating fluidized boiler — burns coal more completely and efficiently than in the current system, which essentially transports coal on a conveyor and lays it on a grate for burning. Right now, what’s on the critical path is a federal air-quality permit for the project. The current plant has an air quality permit but the new plant should be able to qualify for a modification of the existing permit because the new plant would have lower emissions of pollutants using new coal-burning and emission-control technology. Carbon dioxide emissions with the new plant will be about the same as the current facility, but other pollutants such as particu-
lates — a major concern in Fairbanks — will be much lower. There would be a 60 percent decrease in nitrogen oxide, a 42 percent decrease in carbon monoxide, and a 71 percent decrease in sulfur dioxide. There will be a 69 percent decrease of total particulates, including, within this, a 75 percent decrease of coarse particulates and a 53 decrease of fine particulates, compared with the current plant emissions. Particulates are a major concern in Fairbanks during winter cold weather because they concentrate at low levels due to temperature inversions. Still, the idea of using coal again isn’t popular on the campus, and UAF Chancellor Rogers has had some difficult conversations with students and faculty explaining why coal is still best in an era of concern for climate change. However, when students realize the effect that a switch to a renewable fuel, say biomass, would have on tuition rates, they understand the dilemma the university is in. There really aren’t any other fuel options other than coal. Although Fairbanks may See UAF, Page 19
THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013 15
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THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013
Photo/Michael Dinneen/AJOC
Bill Hardham, the Alaska manager for Spanish oil major Repsol, said the company objectives were met after three test wells drilled on the North Slope this past winter found oil.
¡Éxito!
Spanish major Repsol finds success on Slope
THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013 17 By Tim Bradner Alaska Journal of Commerce
Repsol’s winter exploration program on the North Slope was a stunning success: oil was found in all three test wells. “We met our objectives. We drilled three wells and three ‘sidetracks’ at each location,” making six separate penetrations into the reservoir rocks, said Bill Hardham, Repsol’s Alaska manager. A sidetrack is a separate well drilled underground off the wellbore of a well drilled from the surface. The company announced its drilling results April 23. Repsol’s entry into Alaska is significant because it is a major international company with substantial resources, and because it is on schedule to evaluate the acreage it has acquired. The company has done its homework, too. Finding oil in the locations drilled this winter wasn’t a surprise, Hardham said. “We found what we expected,” he said. There is oil all over the northern Colville River and delta area near where the company was drilling. Test wells have been drilled since the 1960s in the area, many by companies like Gulf, Sinclair and Texaco, now long since a part of industry history. Some were drilled by BP, interestingly, before Prudhoe Bay was discovered. Most of these wells were unsuccessful. Repsol had the benefit of all that knowledge because data from most of the earlier wells has long been public, and the company also knew that ConocoPhillips had developed its successful field at Alpine, near where Repsol was exploring. Pioneer Natural Resources had also developed its Oooguruk field to the northeast. Repsol also had the benefit of modern exploration tools, like three-dimensional seismic, that were not available to the earlier explorers. One other advantage for Repsol was its partnership with Armstrong Oil and Gas, the Denverbased independent which brought the Spainbased company to Alaska and retains an interest in the leases Repsol purchased from Armstrong. Armstrong subsidiary 70&148 LLC has a 22.5 percent interest, and GMT Exploration Co., another independent, has 7.5 percent. Repsol has 70 percent. Armstrong has its own substantial knowledge of the North Slope and has a track record for spotting opportunities larger companies had missed or passed over for other reasons, and for bringing new companies as partners to the Slope. One of Armstrong’s successes was bringing Pioneer Natural Resources to Alaska, which
led to the development of the Oooguruk field, and in bringing Eni Petroleum, the Italian major company, which developed the Nikaitchuq field that is nearby Oooguruk.
Next steps For now, however, Repsol is in a period of assessing the results of its three wells, Hardham said, and the company is having internal discussions on its next steps. Repsol conducted production tests on wells “Q-1” and “Q-6,” a few miles apart from each other in the northern part of the Colville Delta, and Q-6, the westernmost well of the two, is about five miles from Fiord, a satellite of the Alpine field that ConocoPhillips is now producing. One way to produce the oil found at Q-1 and Q-6 would be to tie into the existing infrastructure, the nearest located at Fiord. Hardham said that option could be explored with ConocoPhillips to see if there is mutual benefit for both companies. It is one of several options the company will consider. The river delta area is also a sensitive environmental region, with river channels, and these will have to be considered in any development plan. The third well, Q-3, was drilled further south near the Colville River, and its results were also encouraging, with multiple oil-bearing zones encountered. Hardham said Repsol may go back and drill another well at or near Q-3 next winter to get more data and a more complete picture of its potential, but that decision hasn’t yet been made. Hardham could not comment on volumes produced during the tests at Q-1 and Q-6, or even the geologic formations tapped, but he said both wells had a 1,000-foot horizontal well section through which the tests were conducted. Horizontal wells are commonly drilled on the North Slope to tap thin or lower productivity sections of oil-bearing reservoir rock, and the volumes produced from short-term production from test sections like these can only indicate the potential of how actual production wells would produce, he said. Most production wells in the nearby fields have far longer horizontal sections, some out to 5,000 and 6,000 feet in lateral reach. Repsol’s exploration wells were drilled just to gather data, and would not be used for actual production, Hardham said. The company had only planned to do production tests on two wells. “We will likely need to test the Q-3 well, but for this year two production tests were enough, given the short drilling season and availability of crews and equipment,” he said.
There was no repeat of the mishap that occurred the previous winter when one rig, at generally the same location as Q-6, hit a shallow gas pocket. Gas was safely vented and there were no injuries, but drilling fluids from the well coated the rig, froze and the drilling operation had to be suspended. The incident disrupted Repsol’s plans last year to the point that only two of four planned wells were drilled. This year the only mishap was a hose rupture resulting in a release of fluids almost entirely into containment on the pad. January did see some rough weather — whiteout conditions and wind — which occurred at a vulnerable time when ice roads were being built and rigs moved. “We lost about half of the month of January to weather,” Hardham said. The previous winter, Repsol’s first in Alaska, there were periods of minus-60 degrees Fahrenheit, which were very difficult to work in. But those were not repeated this winter. Repsol had planned to build about 30 miles of ice road but wound up building 38 miles when the side roads to water sources were included. There were ice pads built for the drill rigs and one for staging equipment and a camp near DS2M pad on the west side of the Kuparuk field where the ice road was initiated. An ice runway was also built on a frozen lake nearer the exploration locations. Repsol contracted with Era Aviation for DASH8 flights to the airstrip from Anchorage and Fairbanks. The flights operated five days per week.
Looking ahead For now, things are looking good for Repsol in Alaska. “We will continue to study Q-1 and Q-6 and are very optimistic as we evaluate plans for the development phase,” Hardham said. “The Legislature’s approval of production tax reform has helped move the needle for this project. It will really help encourage additional investment and takes the pressure off having to find giant fields to go to development.” Repsol played its cards well in timing its entry into Alaska just when the state was about the change the tax. The company decided to come to Alaska when Gov. Sean Parnell first started talking about changing the oil tax. “We expected a lot of other companies would be coming to Alaska when the tax changed, so we wanted to get in ahead of the herd,” Hardham said in an interview in 2012. Parnell’s first proposal, House Bill 110, See REPSOL, Page 23
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THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013
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THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013 19
Pioneer sees good results from North Slope fracturing wells By Tim Bradner Alaska Journal of Commerce
Pioneer Natural Resources is pleased with results of its large-scale fracturing of producing wells at the Oooguruk field on the North Slope. Three producing wells were fractured in the first half of 2013 with production doubling in two wells and tripling in a third. “We’re very pleased with the results, and we plan to fracture four more wells next year,” Pioneer spokesman Casey Sullivan said Aug. 30. The three production wells were fractured following a successful test fracturing in late 2012 in a production test of an exploration well near Oooguruk. The production figures were presented by Pioneer to financial analysts Aug. 1, Sullivan said. All three wells are producing from the Nuiqsut formation, one of two formations that are tapped at Oooguruk. Prior to fracturing, the Oooguruk wells produced in the range of 500 barrels per day to 800 barrels per day. Following the fracturing, two of the wells fractured in the early spring increased output to an average of 1,500 b/d and a third well fractured in late spring increased output to 3,000 b/d and sustained the rate for 40 days, according to information presented to analysts.
Photo/File/AJOC
Three producing wells at the Pioneer Resources Oooguruk were fractured in the first half of 2013 with production doubling in two wells and tripling in a third.
The well is currently shut-in for maintenance. A 2012 test of large-scale fracturing on a test well drilled into the Torok formation, which Pioneer hopes to produce from in its planned Nuna development. The well flowed at 2,800 b/d, according to data given the analysts. Nuna is a potential new project near Ooguruk that is onshore, in the Colville River delta northeast of ConocoPhillips’ producing Alpine field. Ooogouruk is owned 70 percent by Pioneer and is field operator, with 30 percent owned by Italian major Eni. The field produced 4,000 barrels per day net to Pioneer in the second quarter of 2013, according to the information presented to analysts.
Nuiqsut formation wells have had mixed results at Oooguruk, while production from the Kuparuk and Torok formations, being produced, has met expectations, Pioneer official told a meeting of the Alaska Geological Society last April. The Oooguruk field is offshore, in shallow water, just north of the shore and Nuna’s location. Pioneer will make a decision on whether to develop Nuna later this fall, Sullivan said. Smaller-scale fracturing has been done for years in North Slope fields but Pioneer’s tests were the first large-scale, multi-stage fracturing jobs. The company adapted the technique from similar procedures used by Pioneer in drilling of wells in the Eagleford shale and similar formations in Texas.
million yearly for about 71,000 tons of coal from Usibelli Mine Inc., owner of the coal mine at Healy south of Fairbanks. More coal would be used in the new power plant, about 85,500 tons yearly at a projected cost of $5.3 million, because the new plant would generate enough new electricity to displace power now purchased from Golden Valley Electric to supplement the current plant. UAF now purchases about 1 to 3 megawatts of power from GVEA at an annual cost of about $2 million. A backup arrangement with GVEA will be kept in place, and the university may opt to purchase wind power as a supplement to coal from the regional utility. GVEA generates renewable power at its Eva Creek wind project. Meanwhile, Alaska Department of Environmental Conservation officials released a draft
of the permit modification in September. While this is a federal permit required by the U.S. Clean Air Act, the state DEC administers the program in Alaska under guidelines set by the U.S. Environmental Protection Agency. EPA makes the final decisions, and whether the new plant will qualify for a modification of the current permit or a brand new permit will be required is up to the EPA. Conservation groups like the Sierra Club will be weighing in with their opinions when DEC releases the draft permit and solicits comments. The Sierra Club has a national “no new coal” campaign, but whether it is willing to make an exception to the UAF plant isn’t known yet. Tim Bradner can be reached at tim.bradner@ alaskajournal.com.
UAF
Continued from Page 14 soon get liquefied natural gas trucked from the North Slope, this would be much more expensive than coal, UAF spokeswoman Marmian Grimes said. Biomass isn’t a practical option either at the scale of wood-cutting that would be needed, although both gas and wood biomass can supplement coal. The university has looked closely at a variety of fuels including natural gas as a primary fuel for the new plant and has concluded that coal, burned in an efficient, modern plant, is the best financial option, she said. However, Grimes said the new power plant design, with some tinkering, would allow the use of other fuels including biomass as a supplemental fuel. Municipal waste could even be used, she said. The university currently spends about $4.4
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THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013
ExxonMobil lets new contracts for Point Thomson field construction
Photo/Courtesy/ExxonMobil
A heavy crane moves across the ice road at the Point Thomson project during the 2013 winter construction season. ExxonMobil reported it completed all of its planned work in its first season at the field, and that workers at the project were 90 percent Alaskans.
By Tim Bradner Alaska Journal of Commerce
ExxonMobil Corp. announced Sept. 13 that major new contracts for the Point Thomson field construction have been let. Contracts were awarded to CH2M Hill for installation of production system modules and also to manufacture and install a standby power generation module for the gas and condensate field on the North Slope. The contracts were let by Worley Parsons Group Inc., the primary construction management contractor for ExxonMobil on the field. Point Thomson is a large gas and condensate field 60 miles east of Prudhoe Bay. ExxonMobil, majority owner of the field, has been leading development of a gas cycling and condensate production project at the field which is expected to begin production in late 2015 or early 2016, according to spokeswoman Kim Jordan. BP and ConocoPhillips are minority owners in Point Thomson leases. CH2M Hill, a major oil field services company, will work in a partnership with ASRC Energy and Delta Construction on the project. CH2M Hill is best known for its civil engineering work but the company made a major expansion into oilfield service and construction when it acquired Veco Corp., an Alaskan service company. Veco has been involved in most of the installation and hook-up of large North Slope oil field production modules over the years and has also constructed large field production modules in Alaska, as has ASRC Energy.
Construction started at Point Thomson last winter with completion of gravel pads and roads at the site along with vertical support members for a new pipeline that will connect the field to the Trans-Alaska Pipeline System at Prudhoe Bay. The permanent camp for the field was completed this summer, along with telecommunications links, ExxonMobil announced in a press release. “ExxonMobil is strongly committed to hiring Alaskans and, with its contractors, employed more than 1,100 Alaskans during the 2013 winter construction season,” said Gina Dickerson, senior project manager at Point Thomson. This summer, about 500 were employed at the peak of activity, she said. Alaska Frontier Constructors was involved in completing the site airstrip last winter and finishing construction of a service pier. A permanent camp, providing meals and housing to project workers, was built and is now fully operational. Telecommunications and power systems at Point Thomson are now complete. More than 35 Alaska companies worked on the project this summer, Dickerson said. This winter, the 22-mile pipeline will be built, providing a connection to an existing 25-mile pipeline at the Badami field that will allow liquid condensates from Point Thomson to be transported to Prudhoe Bay. More than 2,200 vertical support members for the pipeline were installed last winter by the pipeline subsidiary of Doyon Ltd. based in Fairbanks. When Point Thomson is finished, about
10,000 barrels per day of condensates will be moved from Point Thomson to TAPS Pump Station One where the condensates will be blended with crude oil for shipment to market. The project now under development is considered phase one of Point Thomson development, ExxonMobil has said previously. If the gas cycling project works as expected, the condensate production could be increased in an expansion. Alternatively, the project could be converted to straight gas production with gas shipped to Prudhoe Bay to help maintain reservoir pressure for oil production. Point Thomson could also supply gas for a future North Slope gas pipeline that is proposed, if it is built. Point Thomson has about 8 trillion cubic feet of proven reserves of gas, about 200 million barrels of condensate, and holds additional conventional oil resources. The deposit was discovered in the 1970s and explored in the 1980s and 1990s, but development has been delayed because of the lack of a gas pipeline and because of technical and economic challenges. The gas cycling approach, which involves production of gas and liquid condensates with the gas injected back underground, was studied in the late 1990s, but the conclusion was that it would not be economic. The State of Alaska pressed the Point Thomson leaseowners to reconsider the plan and the companies agreed to develop a scaled-down version of the cycling project envisioned in the late 1990s. This is now under construction. ExxonMobil would not release cost estimates for the current Point Thomson development, but did say it will total several billion dollars. Aside from production of the condensates, development of the field is significant because it will extend pipeline infrastructure to the eastern North Slope, which will aid in development of conventional oil resources in the area. Shell is also exploring offshore north of the Point Thomson area. “Point Thomson’s infrastructure can help unlock the eastern portion of the North Slope for expanded exploration and development activity,” Dickerson said in a statement. “Along with our contractors and partners, we’re very proud to be building a project on the North Slope that will significantly contribute to realizing Alaska’s full energy potential.”
THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013 21
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THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013
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ConocoPhillips Plans New Work on the North Slope With the recent improvements to Alaska’s severance tax system, ConocoPhillips has announced new work on the North Slope, including: • Bringing an additional rig to the Kuparuk field that supports 95 direct jobs and will generate approximately 700 indirect jobs. • Initiating engineering and design for new Drill Site 2S at Kuparuk. ConocoPhillips already filed permit applications for this project and plans to seek project sanctioning in the third quarter of 2014. • Entering the regulatory/permitting activities phase and engineering for GMT1, a drill site in the Greater Moose’s Tooth Unit in NPR-A. ConocoPhillips filed permit applications for this project on July 23, 2013, and plans to seek project sanctioning of GMT1 in the second half of 2014. These are examples of the activities ConocoPhillips has kicked off to help bring new investments and produce more oil from legacy and satellite fields.
We are looking at additional opportunities in the near future. ConocoPhillips is here for the long term. The new oil tax bill makes the North Slope a more attractive business environment and should lead to more investment in oil-producing projects than has been seen in recent years.
THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013 23
Repsol gets one-time extension for North Slope leases By Tim Bradner Alaska Journal of Commerce
The state Department of Natural Resources has given Repsol E&P a two-year extension to five key leases adjacent to discoveries the company made earlier this year in the Colville River delta of the North Slope. The extensions are allowed under a provision of a new law enacted by the Legislature earlier this year that allows one-time extensions of leases in situations that benefit the state as well as the leaseholder. Repsol’s lease extensions are the first done under the new law. “There are times when a lessee, having invested significant funds and work in a shortterm lease, needs just a little more time to bring the lease into production,” said Bill Barron, director of the state Division of Oil and Gas. “A one-time extension can buy the operator that extra time, but they have to show they¹ve been diligently working to explore and develop the lease, they have to be willing to commit to completing additional work to prove up the
lease, and they may have to be willing to post a performance bond,” Barron said. Repsol has spent more than $200 million in exploration so far in the area. Barron said the lease extensions also had to have the approval of Arctic Slope Regional Corp., the Alaska Native regional corporation for the North Slope, which shares the ownership of mineral rights and royalties with the state. The deal requires Repsol to drill an exploration well on the acreage within the next two years. Barron said the company plans to drill new wells anyway, aside from the lease condition, so that would meet the qualification of the extension. Repsol drilled three exploration wells earlier this year and announced discoveries in all three of them. Two of them, in the Colville delta area, might be deemed commercially viable without follow-up drilling, Repsol said last spring. The five leases being extended are in the delta near where Repsol drilled the two wells with the best results, Barron said. Repsol has meanwhile said separately it
will drill three new North Slope exploration wells this next winter as a follow-up to drilling done last winter and the winter before. House Bill 198, sponsored by Rep. Kurt Olson, R-Soldotna, allows DNR to grant a one-time extension for the primary term of an oil and gas lease if the commissioner finds the extension is in the best interest of the state, and if the initial term of the lease is shorter than 10 years. DNR must consider the funds expended to explore and develop the lease, the types of work completed by the lessee, and other relevant information. If approved, DNR may require a work commitment and a bond, and may set rental as high as $250 per acre. “This new tool is already helping to drive exploration and development, just as intended,” Barron said. “It’s a win-win. It accommodates short drilling windows, allows the state to require work programs during the primary term of the lease, encourages ongoing work to be completed, and increases the probability of bringing leases to production.”
REPSOL
Continued from Page 17 didn’t pass in 2011 when it was first introduced, or the following year, either. However, a new bill that made the changes in a different way was passed in 2013 under a reconfigured Legislature following the 2012 election that broke up the Senate majority that had blocked Parnell’s tax reform. By that time Repsol was established in the state and had gone through its first winter exploration season. “As a new entrant we had to do a lot of work to get to the point where we could make informed decisions,” Hardham said. “We timed this well. By the time the tax change finally passed we had spent two years doing our work.” He said If a development decision is made near the end of this year it would still take several years to build the project and infrastructure and to get the new wells in production. What is likely for next year, however, is a drilling season about the same as the past winter, Hardham said. “We have always said we’re in a multi-year program of appraising our acreage, and our pace is very appropriate for the amount of acreage we have,” he said. Repsol’s holdings are 170 state leases, or about 500,000 acres, the maximum allowed any one company by state law. Repsol’s leases are all west of the Prudhoe Bay and Kuparuk River fields, in the vicinity of the Colville River and its delta.
Photo/Michael Dinneen/AJOC
From left to right are Mark Harlan, Development Logistics Lead for Repsol, Development Interface Lead Marco Terracciano, and Facilities Engineer and Construction Manager Federico Giannangeli.
The company also has an interest in offshore Beaufort Sea leases that are to the north of its onshore acreage. Those are held in partnership with Shell.
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THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013
Photo/Courtesy/International Tower Hill
An aerial photo of the Money Knob Hill shows where the gold resource is concentrated at the Livengood prospect 70 miles north of Fairbanks on the Elliot Highway.
International Tower Hill still confident Livengood gold mine can be developed
By Tim Bradner Alaska Journal of Commerce
International Tower Hill Mines is back at the drawing board refiguring how to economically produce the large gold resource the company has identified at its Livengood prospect about 70 miles north of Fairbanks on the Elliot Highway. In a feasibility study, which found higher costs for parts of the mine, International Tower Hill Mines, or ITH, found the project would be uneconomic at current gold prices and under the development assumptions used. Don Ewigleben, CEO of the company, is still upbeat, however. “While the large project feasibility study results are not economically robust in today’s gold market, the Livengood gold project remains a very significant gold deposit in one of the most favorable jurisdictions in the world,” Ewigleben said in a statement. The company is already evaluating several other cost-saving opportunities identified in the feasibility study. Livengood has an estimated gold resource in the proven category of 15.7 million ounces and in the probable category 4.4 million ounces for a total of 20.1 million ounces.
At $1,500 per ounce, the reserve contains more than 10 million ounces of gold with 9.62 million ounces in the “proven” category and another 454,000 ounces in the “probable” category. Proven and probable are categories of resources determined by drilling, extensive sample evaluation, assaying and modeling identifying economic minable ounces at a given gold price. Based on those estimates, the mine could produce 577,600 ounces of gold per year over an estimated 14-year mine life, but the producing lives of most mines are longer that what is initially estimated because there are likely to be resources in the area that are undiscovered. ITH, controls a 75-square-mile land block through state mining claims. “Yes, operating and capital costs did go up (in the feasibility study) but it is essential that we use the most accurate numbers based on all the information collected through the feasibility process,” said Tom Irwin, vice president of ITH and a veteran miner who managed development of the Fort Knox mine. He is also a former commissioner of the Alaska Department of Natural Resources. The assumption in the feasibility study included a mill design that would process 100,000
tons or ore daily. The feasibility study assumed a mill requiring just less than 100 megawatts of electricity and employing about 450 workers. Irwin said “they are evaluating whether a scaled-back ore processing mill and changes to the mining plan will improve the project’s economics enough to offset the decreased economies of scale.” The original plan would process 100,000 tons per day and would produce more gold than a smaller mill. In both the large and smaller mill scenarios, higher grade would be mined in the early years to increase the project economics. This process is typically used in most mines particularly in large, low-grade mines including Kinross’s Fort Knox mine. There are other opportunities identified in the feasibility study that ITH is evaluating that include: increasing the in-pit resource, exploring new targets, lowering reagent costs and reagent usage, and improving recovery with intensive gravity concentrate leaching. “One of ITH’s priorities is to reduce power costs since the power cost is approximately 30 percent of the mill’s operating cost” Irwin said. Energy costs, for example, were estimated at the current price of power charged by
THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013 25 Golden Valley Electric Association, the regional electric co-op, under the assumption that ITH would pay for a 50-mile power transmission line to connect the mine to GVEA’s system. GVEA currently generates much of its power with oil. However, the co-op, along with the Fairbanks North Star Borough and other Interior groups, are working with the State of Alaska on a plan to truck liquefied natural gas to Fairbanks from the North Slope. The belief is that trucked LNG would provide energy for power generation for about half the cost of fuel oil. Irwin said ITH separately considered the option of on-site power generation, but there are pluses and minuses with this even with LNG trucks from the North Slope rolling right past the mine on the highway, which connects to the Dalton Highway to the Slope. “The ‘con’ is that we would have to build a power plant, and incur the capital costs. The ‘pro’ is that we might have cheaper power,” he said. The feasibility study used power generated by Golden Valley and included capital costs for generating capacity, substations and a 50-mile transmission line, Irwin said. “Fort Knox has had a good experience with GVEA,” in purchasing power for operation of its mine, he said. The Pogo gold mine, near Delta, also purchases power from GVEA over a long-distance transmission line. Trucked LNG as envisioned by the state with the current price assumptions would improve the project economics. One additional factor that might improve the outlook for the mine is that the amount of gold in the ore might turn out to be greater than initially estimated. The content of the ore was actually higher in large bulk samples of ore that were mined and shipped to Lower 48 facilities for metallurgical studies than was measured in smaller rock core samples extracted during test drilling. The gold resource estimates used in the feasibility study, and those published by the company in its financial report, are those from analyses of the rock cores from drilling. However, the gold content in the bulk samples was about 10 percent higher than was measured in the cores. The company is still evaluating this, Irwin said. The feasibility study also had to include higher costs for some parts of the mine that were originally not contemplated, Irwin said. One big change came from geotechnical drilling and permafrost analysis and other studies that showed the tailings facility needed to be lined to ensure the environment is protected
Graphic/Courtesy/International Tower Hill
This rendering shows the proposed open pit gold mine at the Livengood prospect.
Photo/Courtesy/International Tower Hill
A truck passes by the Trans-Alaska Pipeline System on the Elliot Highway not far from the Livengood prospect. The mine location on the road system is one of the advantages for the project’s economics.
with the ITH design and to meet the strict standards set by the state. The feasibility study, considered thorough by ITH, was developed over 18 months and included a major drilling and metallurgical test programs, several engineering design firms, reviewed by three independent parties and signed by Independent Qualified Persons. Summing up the project status, Irwin said, “there are current gold price challenges and this project is highly leveraged to gold price, but gold has always been cyclical. The Livengood Gold Project is significant: with the large gold resource, the project is located adjacent to the Interior highway system, Alaska is a secure political and legal environment and ITH has a great team.” T im Bradner can be reached at tim.bradner@alaskajournal.com.
Photo/Courtesy/International Tower Hill
Shane Crum of Frontier Drilling takes a pause while working an exploration rig at the Livengood prospect.
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THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013
Pogo still state’s top gold mine, boosting Interior economy By Tim Bradner Alaska Journal of Commerce
The Pogo mine near Delta, east of Fairbanks, is still Alaska’s top gold producer, and has also become an important stimulus to the Interior Alaska economy. In 2012, the mine, owned by Sumitomo Metal Mining Co., employed 329 workers not including contractor employees on site, and had a $38.5 million payroll. The company also spent $127.2 million with Alaska vendors and suppliers. The figures comes from a newly-completed study by McDowell Group, the Juneaubased economic consulting firm. The Alaska spending for supplies and services represented 50 percent of Pogo’s overall spending for support in 2012. Lorna Shaw, Pogo’s public affairs manager, presented details of the study to the Delta Junction Chamber of Commerce Aug. 15. Pogo is about 85 miles southeast of Fairbanks and 38 miles northwest of Delta. The mine is an underground mining operation. McDowell Group found the bulk of Pogo’s spending with vendors and suppliers, about 65 percent, was in the Fairbanks North Star Borough and in Delta, the nearest community to the mine, according to the McDowell Group study. Eight percent of the vendor and supplier spending, or $10.1 million, was in Delta. “That’s pretty significant for Delta, which isn’t very big,” said Shaw. About 57 percent, or $72.6 million, was spent with other suppliers in the Fairbanks North Star Borough, McDowell Group said in the study. Also, 34 percent of the mine’s spending, or $43.5 million, went to suppliers in Anchorage. The mine paid top wages, too. Average annual pay per worker at Pogo was $116,916 per employee, McDowell Group said in the study. That is over twice the statewide average income of $50,100 per year and the $47,616 average income per year for the Fairbanks North Star Borough, the study said. It is in the range of what other mines in Alaska pay their workers, however. Meanwhile, the total employment and payroll effect of the mine is greater than that of the people employed directly in the mine because of the indirect effects of employment, through the spending of wages in the state’s economy.
McDowell Group estimated an additional 215 jobs and $18 million in additional payroll were created indirectly. In payments to government, Pogo paid $24.2 million in taxes and fees and an additional $4.8 million in mine royalties to state government in 2012, as well as corporate tax payments, the study said. Pogo is still new as Alaska mines go. Exploration began in 1990 and production started in 2006. By 2008 the mine had became the state’s top gold producer with annual production of about 340,000 ounces of gold.
are likely to extend the mine life beyond 2019 and there are a number of untested prospects in Pogo’s block of mining claims, which covers about 85 square miles. Shaw said Pogo is currently producing from its main deposit, the Liese deposit, but that new resources have been found in East
PPhotos/Judy Patrick/Sumitomo Metal Mining Co.
The Pogo gold mine near Delta is the state’s top producing gold mine at about 340,000 ounces annually. The company is exploring adjacent mining claims to push the mine life beyond 2019.
Production so far in 2013 is slightly ahead of the amount planned, Shaw said in an interview, with about 208,000 ounces produced through the end of July. Reserves and resources at the mine are currently estimated at 4.973 million ounces of gold in 13.5 million tons of ore, with an average grade of 0.366 ounces per ton. The company is exploring potential new gold resources, which
Deep, a separate deposit about 1,000 feet northwest of the Liese. Development and permitting for East Deep have now started following the mining of a test batch of ore for testing, and drilling programs in 2013, operating from April through November, are testing for extensions of the East Deep mineralization to the northeast, north and west of the prospect now identified.
THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013 27
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Golden Valley completes financing to purchase mothballed Healy coal plant
Photo/Adam Elliott/For the Journal
Golden Valley Electric Association of Fairbanks has its financing in place to complete the purchase of the 50-Megawatt Healy Clean Coal Project from the State of Alaska. The entire financing package for Golden Valley could total $150 million to $180 million.
By Tim Bradner Alaska Journal of Commerce
Golden Valley Electric Association of Fairbanks has its financing in place to complete the purchase of the 50-Megawatt Healy Clean Coal Project from the State of Alaska, according to Cory Borgeson, president of the Interior electric co-op. GVEA will rename the plant “Healy Unit 2” because it sits alongside Healy Unit 1, a longoperating 25-Megawatt coal plant owned and operated by GVEA, Borgeson said. Final approvals on financing by the federal Rural Utilities Services, or RUS, a unit of the U.S. Department of Agriculture, have come through along with an agreement concluded with the Cooperative Finance Bank, a finance cooperative that specializes in loans to rural and small community utilities, Borgeson said. The Cooperative Finance Bank will finance the purchase of the plant from the Alaska Industrial Development and Export Authority for $42 million, and certain additional costs will
increase the amount financed to between $44 million and $45 million. The RUS loan, meanwhile, will finance new emissions controls systems for the plant agreed to by GVEA as a part of a Consent Decree worked out with the U.S. Environmental Protection Agency last November. The cost of this is still uncertain, but it is expected to range between $50 million and $80 million. EPA and Golden Valley agreed to the consent decree to forestall litigation from environment groups opposing coal-fired power plants. New pollution-control systems will include Selective Catalytic Reduction systems to reduce nitrogen oxide and sulfur dioxide emissions. In addition, GVEA will spend about $35 million to upgrade certain components of the plant, which was built in the late 1990s and began to test pollution-control systems that were new at the time. Due to commercial disputes between AIDEA and Golden Valley, the plant was never operated commercially, and in 2009 AIDEA agreed to sell
the facility to Golden Valley. Although the entire financing package for Golden Valley could total $150 million to $180 million, those costs won’t substantially affect the expected cost of power because the costs will be spread out over many years of service by the plant, Borgenson said. Coal is by far the cheapest fuel for power generation in Interior Alaska. Golden Valley now generates much of its power with naphtha, which is made from fuel oil, purchased from the Flint Hills Resources refinery near Fairbanks, has some wind power from its Eva Creek wind project also near Healy, receives a share of Bradley Lake hydro power and has also purchased gas-fired power from Chugach Electric Association. The Chugach power purchases are expected to end in 2015, about the time the new Healy Unit 2 will come on line, Borgeson said. Borgeson said he hopes to see the work on Healy Unit 2 plant completed in time for a start of operation in early 2015.
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THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013
Wind power producers ask regulators for rate certainty
Photo/Courtesy/Alaska Environmental Power LLC
The Alaska Environmental Power wind farm near Delta Junction is seen in this 2010 photo. AEP Owner Mike Craft has filed an informal complaint with state energy regulators alleging regional utility Golden Valley Electric Association’s proposed purchase agreement for independent power providers like him will shut them out of the Interior electric market.
By Elwood Brehmer Alaska Journal of Commerce
Independent sources of Interior electricity are in the hands of the Regulatory Commission of Alaska. Alaska Environmental Power LLC, a small wind farm near Delta Junction, filed an informal complaint Aug. 23 with the commission against Golden Valley Electric Association’s proposed power purchase agreement. Golden Valley filed its template contract with the commission, or RCA, in July as a guide for future agreements with independent power producers. Alaska Environmental Power owner and founder Mike Craft said Golden Valley’s filing does not give independent producers an op-
portunity to enter the Interior electricity market on a level playing field. Golden Valley serves Interior railbelt communities with power generated mostly from the burning of coal, fuel oils and natural gas. It also has rights to power from the state-owned Bradley Lake hydropower plant on the Kenai Peninsula and about 1 percent of its power last year came from its just-completed Eva Creek wind farm near Healy. Since 2008, Golden Valley has been purchasing up to two megawatts of power from Craft’s wind farm under an agreement through the Experimental Renewable Resource Purchase Program. Golden Valley’s average load is between 150 megawatts in summer and more than 200
megawatts at peak winter draw. Craft contends that by averaging its cost of power over all of its generation sources, Golden Valley has been able to avoid buying power from independent producers. Rather, he said, the cost should be broken down incrementally, which would allow his wind power to effectively displace expensive fuel oil-produced power. An incremental cost would allow Craft to sell electricity to Golden Valley at the 12.5-cent per kilowatt-hour rate he needs to be viable, he said. Golden Valley updates its “cost of power” quarterly to adjust to market demands, President and CEO Cory Borgeson said. Its current See WIND, Page 34
THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013 31
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THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013
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ConocoPhillips applies for permits for new NPR-A project By Tim Bradner Alaska Journal of Commerce
CononoPhillips has applied for permits to develop a new production site in the National Petroleum Reserve–Alaska, the 23-million-acre federal reserve in the western North Slope. The company also has a second project on the drawing boards. The application to develop the first project, GMT-1, was made in late July to the U.S. Bureau of Land Management, which administers the NPR-A. ConocoPhillips submitted the permits on behalf of itself and Anadarko Petroleum Corp., a minority partner, BLM spokeswoman Erin Curtis said. GMT-1 was one of several projects ConocoPhillips announced it would pursue in the days following the state Legislature’s action April 14 to reduce the state production tax. Although NPR-A is federal land the state tax applies to oil and gas produced there. The company also said it is evaluating a new production site in the Kuparuk River field and will accelerate drilling and well “workover,” or major maintenance, work. In the NPR-A, ConocoPhillips owns 78 percent interest in federal leases in the Moose’s Tooth Unit with Anadarko holding the remaining 22 percent. ConocoPhillips spokeswoman Natalie Lowman said her company will seek corporate approval to develop the GMT-1 project in the Greater Moose’s Tooth Unit of NPR-A in the second half of 2014, assuming the permits are issued by BLM. If all goes as planned, construction would begin in early 2016 and first production in late 2017. No estimates of cost or production were included in the BLM application. “We are still doing the preliminary engineering and design to determine cost and the estimated production,” of GMT-1, Lowman said. The application also said the company also plans the second project, GMT-2, that would be 8 miles west of GMT-1. “Upon the successful permitting and construction of GMT-1, ConocoPhillips intends to submit permit applications for development of GMT-2. The exact dates for these applications is unknown,” ConocoPhillips said in its filing with BLM. GMT-1 is approximately 17 miles west of the producing Alpine field, which is on State of
Alaska lands and is also owned by ConocoPhillips and Anadarko in the same 78 percent-22 percent shares as the NPR-A leases. The two companies are also now developing CD-5, an Alpine field satellite unit a few miles west of the field but which is within the NPR-A because it is west of the Colville River channels that forms the boundary between and federal lands. Construction of CD-5 is scheduled to begin in late 2014 and continue through 2015, with first production in 2015. An issue that could complicate the CD-5 schedule and possibly GMT-1 are two lawsuits challenging the CD-5 permits. A lawsuit brought in federal court last February against the U.S. Army Corps of Engineers was filed by six residents of Nuiqsut, a nearby Inupiat village. In June, the Center for Biological Diversity, an environmental group, filed a second lawsuit challenging the CD-5 permit, also in the U.S. Alaska District Court.
ConocoPhillips spokeswoman Natalie Lowman said her company will seek corporate approval to develop the GMT-1 project in the Greater Moose’s Tooth Unit of NPR-A in the second half of 2014, assuming the permits are issued by BLM. The villagers’ lawsuit claims a Colville River bridge and related roads planned for CD-5 will adversely affect wetlands that support subsistence hunting and fishing, and that the Corps did not properly consider tunneling under the river for a pipeline and air-supported access as a reasonable alternatives to the bridge and roads. In its intervention in the case, ConocoPhillips claimed an underground tunnel for the pipeline creates environmental risks because corrosion and oil leaks are more difficult to detect and repair in a buried pipeline than a surface pipeline. In its separate lawsuit, the Center for Biological Diversity claims that threatened and endangered species are affected. The State of Alaska, Arctic Slope Regional Corp., and Kuupik Corp. have intervened in the villagers’ lawsuit on the side of the Corps, but a motion to intervene by the North Slope Bor-
ough is being opposed by the village plaintiffs represented by Trustees for Alaska, an environmental law firm. ConocoPhillips has also been granted intervenor status on behalf of the Corps in the Center for Biological Diversity lawsuit. The case presents a new uncertainty over the CD-5 bridge permit, which was held up by an extended Corps of Engineers review before a Corps permit for the bridge and roads was finally issued. If the permit is overturned the schedule for CD-5 could be disrupted, which could also affect the NPR-A site developments because they will depend on the bridge and roads built for CD-5. The schedule for GMT-1 outlined in the permit application calls for the ordering of long lead-time materials for the project, such as steel, in the fourth quarter of 2014. One year later, in fourth quarter of 2015, the first ice roads would be built to support construction. Gravel mining and construction of gravel roads, pads and bridges would occur in the first quarter of 2015. Pipeline vertical support members, the pipeline, production facility and power and telecommunications cables would be installed in first quarter, 2017. The first production would be in late 2017. The project would include 7.8 miles of road to the project from the CD-5 drillsite now in construction; 8.4 miles of pipelines to connect GMT-1 to CD-5, and 8.4 miles of power and telecommunication lines built on horizontal supports from the pipeline. There would be an 11.8-acre gravel pad at the project site with sufficient space to support 33 production wells. Several pipelines would be built to support the project including a 20-inch produced fluids pipeline that would move a mixture of crude oil, natural gas and water from GMT-1 to the Alpine field oil and gas processing facilities. There would also be a 14-inch pipeline to carry seawater or produced water (water produced from the oilfields) from Alpine to GMT-1 for reservoir pressure support, and two separate 6-inch pipelines, one to carry gas from Alpine to GMT-1 to support “artificial lift,” or below-surface pumps, to help bring oil to the surface, and a second 6-inch line to carry a miscible injectant fluids from Alpine that can be used for enhanced oil recovery.
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THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013
fairbanks
Continued from Page 13 500 miles of pipe totaling about $170 million, Shefchik said. Shefchik noted a difference in the models being that IGU’s cost estimate runs pipe all the way “to the meter” on the side of a potential customer’s house. AIDEA’s model runs gas line “street-side” and relies on customers to pay for the final transmission lines to their homes, he said. Britton said he wonders how IGU will fund its project, claiming it is “based on a financial plan that will never exist.” IGU’s application states it plans to finance its project with $481.7 million in loans from the state’s Sustainable Energy Transmission and Supply, or SETS, fund. “It is expected that these loans will have a 50-year term and carry a one percent interest rate,” the filing states. Further, IGU anticipates a state-funded capital reimbursement for gas storage of $60 million, which it would use to pay down debt, according to the application. The financing plan could be revised with a higher interest rate or a shorter loan term, Shefchik said, depending on what the final cost for infrastructure is determined to be. Shefchik questioned FNG’s ability and de-
sire to serve residential and small commercial customers — what he called the primary goal of IGU. He said FNG’s application focuses on serving the Flint Hills oil refinery and Golden Valley Electric Association with gas. Flint Hills officials have said their demand for gas has faded as their operations have shrunk because of a lack of demand for products such as jet fuel. Golden Valley is openly seeking gas for its power production and has proposed a plan opposite FNG to operate a gas liquefaction plant on the North Slope. “We think there’s lots of building to be done in the city of Fairbanks — that FNG could build for five years until they reach a 90 percent penetration rate just up and down the streets of Fairbanks,” Shefchik said. Britton said any utility needs large customers to support its small ones and that a limited gas supply has kept FNG from expanding beyond its current service area. “The borough utility has criticized FNG by saying we have not done enough for residential customers, that we’ve cherry picked customers. The facts are half of our customers are residential,” Britton said. “When an efficient utility system is built you utilize large users to justify the expense to build more pipe out fur-
ther to more areas.” In 2012, FNG served 458 residential customers, 621 small commercial customers and 28 large commercial customers, according to their figures. The large customers accounted for 33 percent of their total gas sold. FNG’s application states under its plan a transmission line will run from a storage facility to the Flint Hills and Golden Valley facilities. When the dust settles, Shefchik said he foresees the possibility of FNG being a partner in a gas system with IGU. “There are only two main gas players in the state and we would look to FNG or Enstar (Natural Gas Co. in Anchorage) to bring them on as a managing partner in the project,” he said. Britton said he has a hard time believing FNG would be working with IGU in the future, based on the differences in the groups’ applications for expanded service. “Our plan’s based on a defined and realistic source for the gas and it’s also based on a defined and realistic ability to build out a system with a defined and real financing plan, and the other plans are not,” Britton said. “That’s about as cut and dry as it gets.” Elwood Brehmer can be reached at elwood.brehmer@alaskajournal.com.
Borgeson said that Golden Valley cannot justify buying wind power from Craft if it doesn’t beat the average production cost under current regulations. “We would love to have Mike Craft’s wind (power). It’s in the right spot, at Delta, to have power generated there,” he said. “It’s just got to be a fair economic deal — it’s got to work for both of us.” At an average cost, Craft said he is unfairly forced to compete with coal and hydropower, when his power is cheaper than that produced with fuel oils. Borgeson said the process of dispatching power is not as simple as turning off the fuel oil and offsetting it with wind power. He added that wind power is the least reliable of all the power sources available. Cook Inlet Region Inc., the Native corporation for Southcentral Alaska, owns the 17.6-megawatt capacity Fire Island Wind Project and filed comments with the RCA asking it
to decline approval of Golden Valley’s proposed purchase agreement. CIRI requested the ruling because it claims the quarterly updated rate prevents independent producers from having a “certainty of revenue, and thus no ability to assure a lender that the (producer) will be able to repay its debt.” Craft said in the past he has had investors ready to support a $54 million expansion of his wind farm, if he could have gotten a firm purchase agreement. The uncertainty of what the future holds for energy production in Alaska means Golden Valley can’t allow itself to be committed to long term purchase agreements, Borgeson said. “Mike wants us to enter in to a contract with a guaranteed price and that may be a good arrangement for our members and that may be a bad arrangement depending on what happens to our cost of power over 20 years,” he said. “The question is: Who’s going to take the risk?”
WIND
Continued from Page 30 average to purchase or produce power across generation methods is 10.5 cents per kilowatthour, or kWh. Administration fees are added to that cost for a final retail rate. That 10.5-cent rate is set in congruence with RCA regulations, Borgeson said. According to Golden Valley, 43 percent of the power it produced in 2012 was from fuel oils. That power ranged in production cost from 15.8 cents per kWh to 60.2 cents per kWh. The agreement Golden Valley filed with the RCA calls for rates to continue to be updated quarterly. Given a fixed price, Craft said he would increase his power generating capacity to 25 megawatts. He said his 380-acre farm, which has two wind turbines, is ready for expansion. “I had days out here last year where I would have saved (Golden Valley) $52,000 a day between the 12.5-cent rate that I was asking for and the incremental avoided cost on what I would have been displacing,” Craft said from his wind farm.
THE PERFECT STORM: FAIRBANKS INDUSTRY UPDATE 2013 35
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