Meet Alaska by Morris Media Network

2014 Meet Alaska Conference & Tradeshow

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2014 Meet Alaska Conference & Tradeshow

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Meet Alaska Conference & Tradeshow Denaâ&#x20AC;&#x2122;ina Civic and Convention Center Anchorage, Alaska 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

PAGE 10

Managing Editor Andrew Jensen (907) 275-2165 editor@alaskajournal.com

LNG101

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 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 Account Executive Dustin Morris (907) 275-2153 dustin.morris@morris.com

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SEE INSIDE

Alyeska studying how to operate TAPS at low-flow levels..................PAGE 10

Donlin gold mine advances toward draft environmental impact statement.................PAGE 31

Alaskan independent NordAq Energy dominates North Slope lease sales . ..............PAGE 11

Prospect near Nome would be lone U.S. graphite producer...............PAGE 32

Brooks Range on track for Mustang production in mid-2015..................................... PAGE 12 Repsol plans three more wells................ PAGE 12 Unmanned aircraft industry taking off.............PAGE 16 Study recommends state consider equity stake in LNG project..............................PAGE 21 Tesoro joins Cook Inlet Energy plan to build oil pipeline across Inlet............................PAGE 24

Northern Dynasty vows to press on at Pebble.........PAGE 34 State agencies consider control of wetland permitting process.............PAGE 37 Workforce will double on large LNG project..............................PAGE 39 AIDEA signs deal to assist process plant for Niblack mine...........................page 41

BP taking a new look at longplanned Liberty project in Beaufort Sea ..........................PAGE 27

State promoting simpler, more efficient regulatory process.............PAGE 45

ConocoPhillips projects could add 55K barrels by 2018............................................PAGE 28

KOGAS keeping an eye on Alaska LNG project developments.........................PAGE 46

2014 Meet Alaska Conference & Tradeshow

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Welcome to The Alaska Support Industry Alliance 3301 C Street Suite 205 Anchorage, AK 99503

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Director of Operations Ann Northcutt anorthcutt@alaskaalliance.com

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Meet Alaska 2014!

On behalf of the Alaska Support Industry Alliance’s Board of Directors and Staff, thank you for joining us here today. 2014 marks the 35th Anniversary of our organization. The Alliance was formed in 1979 for the purpose of advocating to the producing and exploring companies the advantage of contracting with our members engaged in business here in Alaska. As an organization, we also work toward a favorable business climate in our state and help to educate the public on the issues relevant to our industries. And our efforts in these areas continue today. In recent years, the Alliance was very active in the fight for oil tax reform. I’m pleased to say that our work has paid off. Our member companies have seen an increase in business that promises to continue in the coming months and years. But, unfortunately, our fight is not over. Efforts to repeal SB 21 and revert to ACES are underway. We will make every effort to educate our employees, friends and neighbors about the adverse consequences of repeal to our industry, the jobs we create and the state we love. In 2013, the Alliance completed its first educational series for the public, LNG 101. In partnership with the Alaska Journal of Commerce, LNG 101 was distributed to our membership and throughout the state in the Journal’s weekly publication. For your convenience, the series in its entirety is printed in the center of this publication. We hope you found the information helpful and useful and that you encourage others to read it as well. Again, thank you for joining us here today. As we embark upon our 35th year, we are working every day to keep Alaska the place we all want to live and work. Thank you,

Fairbanks Membership Coordinator Jim Plaquet jplaquet@alaskaalliance.com

Grassroots Coordinator Jake Falldorf jfalldorf@alaskaalliance.com

Dave Lawer, President Alaska Support Industry Alliance Board of Directors

2014 Meet Alaska Conference & Tradeshow

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Alyeska studying how to operate TAPS at low-flow levels By Tim Bradner Alaska Journal of Commerce

Alyeska Pipeline Service Co. has launched studies on ways it can operate the TransAlaska Pipeline System at lower oil throughput levels and at colder temperatures. As production drops in North Slope fields, the company is working on ways to mitigate potential problems with wax and the freezing of water in winter. Dan Roberts, Alyeska’s flow assurance manager, said the pipeline company is now completing a test loop facility at the University of Tulsa, a small-scale model of the 48-inch TAPS, to simulate pipeline operating pipeline conditions at low levels of oil flow. Results are expected in late 2014, Roberts said in an interview. The pipeline is now moving about 540,000 barrels per day, or b/d, on average and Roberts said it is now equipped to handle a flow down to about 500,000 b/d without further modifications. That threshold is not that far off, however. With North Slope fields currently declining at about 6 percent yearly, production could be averaging 500,000 b/d in two years, according to estimates by the Alaska Department of Revenue. Alyeska spokesman Michelle Egan said the pipeline company is pursuing two paths to deal with lower flow: one being to add more heat to the pipeline in winter, in addition to heat now being added, and the second is to test whether removing water from the crude will allow TAPS to operate at colder temperatures and lower flow rates. Alyeska is already adding heat to the oil at four pump stations by recirculating oil through pipes. This was a step taken after an unexpected midwinter shutdown in 2011. The company is now considering a plan to add additional heat at Pump Station 5, Roberts said. Adding heat is only needed in winter, from October to April, Roberts said. Alaska winter temperatures can drop to 60 degrees below zero Fahrenheit in the state’s Interior region.

Alyeska works to keep the average temperature of the crude in TAPS at 40 degrees Fahrenheit or above, to prevent water dropping out and forming ice. Oil now enters TAPS at 105 degrees Fahrenheit at Pump Station 1 on the North Slope but the temperature drops rapidly because of the slow velocity of the oil. TAPS was designed with insulation to retain heat in the oil, but while it once took only four days for crude to get from the North Slope to Valdez, it now takes two weeks, Roberts said. Heat is now added at Pump Stations 3 and 4 south of Prudhoe Bay on the slope and at Pump Stations 7 and 9 in Interior Alaska. Heat is also added at the Flint Hills refinery near Fairbanks, which takes crude oil from TAPS and returns hot residual oil to the pipeline. If the project is done to add more heat at Pump Station 5 it would have to be done through typical combustion heaters using diesel fuel, Roberts said. Meanwhile, the studies on water removal could point to a way TAPS could be operated at temperatures below 32 degrees Fahrenheit. Alyeska’s specification for water in its crude is now 0.35 percent and the actual average is about 0.15 percent, Roberts said. There can be slugs of water coming in from North Slope field pipelines, however, with water sometimes 1 percent or higher in the oil, he said. “If we can get enough of the water out we may be able to let the pipeline run colder,” Roberts said. “The flow loop testing at the University of Tulsa facility will identify how low the water content must be. “Our modeling shows we could operate at much lower temperatures,” but there are other problems that compound the issue, like the wax. It’s not now known just how cold the crude could be and still flow, and the tests in Tulsa will help answer the question. In theory, North Slope crude oil would not “jell up” and become immovable until the oil temperature is about minus-20 degrees Fahrenheit, but in reality problems would develop before it reached that level, Roberts said. Wax is a big problem looming for the fu-

ture, Roberts said. As velocity of the oil in the pipe continues to slow more wax drops out of the crude. Some of it coats the inside of the pipe and has to be removed by pigging, which requires more “maintenance” pigging procedures. A “pig” is a device that is inserted into the pipeline to move along, pushed by the oil. Pigs are used for wax removal and also, with special “instrument pigs,” to do inspections of the pipe walls. Alyeska must now launch a pig for wax removal from the pipe walls every six days, so at a given time there are three pigs in the pipeline, Roberts said. However, other wax drops out of the oil and can accumulate as sludge at low points in the pipeline, Roberts said. At some point the sludge could accumulate to a point where it could be difficult to clean out with pigs moving at slower velocity. Alyeska’s studies show that problems with See TAPS, Page 15

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Alaskan independent NordAq Energy dominates North Slope lease sales By Tim Bradner Alaska Journal of Commerce

NordAq Energy LLC, a small Alaska-based independent, has emerged as one of the state’s most aggressive oil and gas explorers. The company dominated the North Slope state and federal lease sales held Nov. 6, walking away with large new acreage positions on the Slope. NordAq has been active in Cook Inlet exploration for some time and is now working to develop a natural gas discovery on the Kenai Peninsula. However, another Alaska-based independent, AVCG LLC, was the high-bidder in the state lease sale, paying $576,000 for a tract west of

the Kuparuk River field and narrowing beating out a bid by four major oil companies bidding together, ConocoPhillips, BP, Chevron and ExxonMobil, who also own the Kapruk field. AVCG has been exploring for several years in the area and is developing a small oil field, “Mustang,” through its operating subsidiary Brooks Range Petroleum. In its lease sale, the state auctioned off 90 North Slope tracts covering 162,163 acres, netting the state treasury $5.51 million in apparent high bids. The state had made about 4.6 million acres available for bids in the central North Slope and state-owned coastal portions of the Beaufort Sea, said Elizabeth Bluemink, spokeswoman for the

state Department of Natural Resources. In a separate lease sale held later the same day, the U.S. Bureau of Land Management sold 22 tracts covering 245,293 acres in the National Petroleum Reserve-Alaska, with a total of $2.89 million in high bids offered. BLM had put up 4.58 million acres up for bid in the sale. The state and federal North Slope sales are typically held on the same day every year, usually in November, so companies can bid more efficiently on state and federal lands that are adjacent in many areas. NordAq Energy was by far the most aggressive bidder in both sales, submitting high bids on 52 tracts of 92 offered by the state, and 17 tracts of 22 offered by BLM in the NPR-A sales. Most of NordAq’s leases were inland on the slope and southeast of the Prudhoe Bay field, and near the undeveloped Kavik gas discovery made decades ago. However, the large block of leases is also at the eastern end of large shale formations, leading some observers to think that NordAq may be planning to explore for shale oil. Great Bear Petroleum, also Alaska-based, was high bidder on 12 tracts in the state sale, adding to a substantial lease holdings the company also owns. Great Bear is promoting an oil shale play on its leases but has recently been exploring for conventional oil. ConocoPhillips was the only major North Slope operator to bid on leases, and was high bidder on 14 state tracts near the southeast boundary of the large Prudhoe Bay field, where the company is a major owner with BP and ExxonMobil. Other independents winning leases included Denver-based Savant Alaska LLC, which secured one tract near the border of the Arctic National Wildlife Refuge, and Burgandy Xploration LLC, a Houston-based company interested in unconventional resources and new to the North Slope. One surprise in the state sale was a close bid for one open tract west of the Kuparuk River field sought by Kuparuk field owners, ConocoPhillips, BP, Chevron and ExxonMobil. The large companies were beat out by another small Alaska-based independent, AVCG LLC, which bid $225 per acre for the tract, $5 per acre more than the bid by the four majors, who bid jointly. That bid, for Tract 1069, was also the highest total bid in the state sale at $576,000. Most bidding was in the $20 per acre range, near the state’s minimum bid. Only two offshore state tracts were bid on and sold, in a block of

See

LEASE SALES, Page 50

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Brooks Range on track for Mustang production in mid-2015 By Tim Bradner Alaska Journal of Commerce

Brooks Range Petroleum, a small Alaskabased independent oil and gas company, is on track to have its new Mustang field on the North Slope field in production in 2015 and also intends to announce new partners soon for the project, the company’s Chief Operating Officer, Bart Armfield, said in an interview. Mustang is west of the Kuparuk River field, and is located only 700 feet from the common carrier Alpine pipeline that carries oil from the ConocoPhillips-operated Alpine field west of Mustang. Development costs of the field are estimated at about $400 million, including field costs and a new oil and gas processing plant. Armfield said Brooks Range and its owners, Alaska Venture Capital Group, or AVCG, and Ramshorn Investments, a Nabors Industries subsidiary, are now negotiating with two and possibly three potential new partners to develop the Mustang field and other North Slope prospects. The agreements are expected to be concluded by the end of December, Armfield said. Besides Mustang, the group controls about 230,000 gross acres adjacent to the Prudhoe Bay, Kuparuk, and Point Thomson fields and is working on several other prospects. “These projects offer near term develop-

ment, near term exploration, and long term strategic exploration opportunities,” Armfield said. Mustang has 24 million barrels of proven reserves and 43.6 million barrels of proven and probable resources according to an independent appraisal by DeGolyer and MacNaughton, a consulting firm. The field is expected to produce 15,000 barrels per day. Brooks Range is also working with the Alaska Industrial Development and Export Authority, Alaska’s state development corporation, on plans for the crude oil processing plant for the field that would also be available for other companies, such as Repsol and Arctic Slope Regional Corp., which are exploring in the area. AIDEA would be an equity partner in the processing plant and under the plan being discussed invest $50 million of the estimated $200 million to $225 million capital cost for the plant. Jim Hemsath, AIDEA’s deputy director for development, told the authority’s board that the investment in the process plant looks attractive, and that the authority should be able to recover its investment, and earn a profit, even if oil prices drop to $70 per barrel. Brooks Range also partnered with AIDEA in the building last winter of a 4.5-mile gravel access road and pad for the process plant. The road is now complete. Brooks Range has meanwhile entered

into an agreement with Charisma Energy Services, a subsidiary of Singapore-based Ezion Holdings, to provide debt financing for the company’s share of plant development costs. Charisma has extended a $150 million shortterm loan to Brooks Range to fund the plant development, he said. The initial phase of Mustang would see 23 wells, 12 of them producers and 11 of them injector wells. “Our plan is to eventually expand to 35 wells,” Armfield told the AIDEA board in a Dec. 5 briefing. The company has already spent about $50 million on exploration drilling and engineering, Armfeld told the board. Mustang is the first of four projects Brooks Range hopes to bring into production in the area. Next on the schedule is Placer, a prospect to the north, where a test and delineation well is planned for 2014 and where oil production could start in 2016. Two other prospects, North Kachemak and Apaloosa, would see more test drilling in 2015 and 2016 with production beginning in 2018 and 2019, respectively. If test drilling is successful and all four projects are developed, Brooks Range could be producing almost 24,000 barrels per day in 2021, according to information Brooks Range presented to the state authority board Dec. 5.

Repsol plans three more wells By Tim Bradner Alaska Journal of Commerce

Repsol will drill three North Slope exploration wells this winter as part of its multi-year program to evaluate the company’s acreage, company officials said in an interview. Two of the wells, designated Q-5 and Q-7, will be in the Colville River delta area east of the producing Alpine field. They are in the vicinity of wells drilled last year by Repsol and where discoveries were made, said Repsol Alaska Manager Bill Hardham. A third well, named Tuttu 1, is further east near the Kuparuk River field, Hardham said. Tuttu is “caribou” in the Inupiat language.

Spain-based Repsol is one of the most active exploration companies in Alaska. This coming winter season will be the company’s third year of drilling. Two of the wells to be drilled in the Colville delta are to gather more information on oil and gas resources near wells drilled last year that were discoveries. Those were designated as Q-1, Q-3 and Q-6, he said. Repsol has not yet announced a decision on the commerciality of those discoveries, Hardham said. Oil was also found in a third well Repsol drilled last year that was farther south. “We are busy with this and we are working up some development scenarios. The wells

we’ll drill this year will add to our information,” about the area, he said. The company is still working on its drilling contracts but tentative plans are to use three Nabors Alaska Drilling Co. rigs for the winter season. A winter ice road will be constructed to the exploration area from the Kuparuk field roads, which are all-year gravel roads, and an ice airstrip and winter camp facility will be built near where the drilling will take place. The exploration in the Colville delta is focused on conventional oil. Tim Bradner can be reached at tim. bradner@alaskajournal.com.

2014 Meet Alaska Conference & Tradeshow

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TAPS

Continued from Page 10 managing the wax accelerate when the oil velocity drops to about 1 foot per second, which would occur if throughput drops to about 200,000 b/d. “The ability to pig the pipeline becomes the ultimate factor,” Roberts said. North Slope crude now contains about 2 percent wax and at any given time there are

9 million barrels of crude moving in TAPS, so if a large portion of the wax in the oil were to drop out it could be a problem, he said. “Our preliminary modeling shows we could operate at lower temperatures and throughput, but there are other problems that compound the issue, like the wax,” Roberts said. If the challenges with water and wax can

be resolved, at some point in the future Alyeska could also operate in “batch” mode at lower flow volumes, but that would take additional facilities like more storage tanks on the North Slope, he said. Tim Bradner can be reached at tim.bradner@alaskajournal.com.

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2014 Meet Alaska Conference & Tradeshow

Photo/Michael Dinneen/AJOC

Fairweather Tulugaq pilot and remote sensor operator Dan Wilkinson climbs aboard the companyâ&#x20AC;&#x2122;s Diamond Aircraft DA42 at Merrill Field in Anchorage. Earlier in the day Wilkinson and another pilot had flown to Glennallen to survey the Trans-Alaska Pipeline System using the DA42â&#x20AC;&#x2122;s infrared and high resolution camera systems. The plane can also be flown remotely.

Fairweather Unmanned aircraft industry taking off

See next page

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By Elwood Brehmer Alaska Journal of Commerce

The venerable Piper Super Cub isn’t being squeezed out, but the face of aviation in Alaska is changing. Once strictly a military tool, unmanned aerial vehicles, or UAVs, are now being used in civilian government work and the private sector. Fairweather LLC announced the formation of research subsidiary Tulugaq LLC Sept. 30. A joint venture between the resource industry support company and regional Native corporations Olgoonik Corp. and Kaktovik Inupiat Corp., Tulugaq’s work centers on its 21st Century aircraft, the Diamond Aircraft DA42. The word Tulugaq is Inupiaq for raven. Fairweather was founded in 1976 by Sherron Perry with an initial focus on providing aviation weather observation services to remote regions, and has since expanded into a wide array of industry support activities. “We make science happen,” Tulugaq Operations Manager Steve Wackowski said. “My boss, Sherron Perry, saw a niche for airborne remote sensing so we’re approaching it in two ways: manned and unmanned remote sensing. Part of our DA42 is the manned portion of that, but the kicker on the DA42 is it’s optionally unmanned.” By replacing the pilot seat in the DA42 with a remote control conversion kit, the $1.2 million aircraft becomes a UAV with a 44-foot wingspan. The dual-flight option is the reason Tulugaq bought the DA42, Wackowski said. And when the time comes, it will be taken advantage of, he said. Manned or not, the Tulugaq has about $400,000 worth of sensing equipment and cameras that can be swapped in and out of receivers on the nose and belly of the DA42. All of the equipment is operated with a Microsoft Xbox video game controller. Wackowski said it was developed with the Xbox controller so the controls would be as recognizable to operators as possible. Because the sensors are designed to fit into receivers built into the plane, Tulugaq does not need to get a certificate of airworthiness every time it changes them, he added. “The analogy I use, is, the plane’s kind of like an iPhone; you can build an app for that,” Wackowski said. Until recently the Federal Aviation Administration had banned commercial operation of UAVs in the United States. On Sept. 24, ConocoPhillips announced it had completed the country’s first commercial UAV (also known as an unmanned aircraft system, or UAS) flight

Photo/Michael Dinneen/AJOC

The Fairweather Tulugaq team from left, operations manager Steve Wackowski, staff scientist Willow Hetrick, pilot Mark Phillips and pilot and remote sensor expert Daniel Wilkinson, gathers around the state-of-the-art Diamond Aircraft DA42 turboprop research plane at Merrill Field in Anchorage. off of Northwest Alaska in the Chuckchi Sea. The roughly 40-pound ScanEagle UAV was launched from Fairweather’s Westward Wind research vessel during a week of flights, according to a ConocoPhillips release. “Airborne surveillance is often a component of offshore projects. The UAS could be useful in monitoring and data collection efforts, with the benefit of improved safety and lower noise levels as compared to using manned aircraft,” ConocoPhillips President Trond-Erik Johansen said in a formal statement. To operate a UAV, a certificate of authorization, known in the industry as a COA, must be approved by the Federal Aviation Administra-

tion. It is essentially a flight plan for unmanned aircraft. It designates where, when and at what altitude a UAV can be flown. ConocoPhillips can claim the first commercial UAV flight, but Alaska has also already seen unmanned craft used for noncommercial purposes. The National Oceanic and Atmospheric Administration Alaska Fisheries Science Center staff flew UAVs on Steller sea lion surveys in the Aleutian Islands in the spring of 2012 in conjunction with University of Alaska Fairbanks See FAIRWEATHER, Page 22

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Study recommends state consider equity stake in LNG project By Tim Bradner Alaska Journal of Commerce

State officials are mulling a plan to take an equity stake in a large Alaska gas pipeline and natural gas liquefaction project. Such a move could ease fiscal issues that the project sponsors, the North Slope producers BP, ConocoPhillips, ExxonMobil and pipeline company TransCanada have cited. That’s a conclusion of a major study of state royalty issues released Nov. 18. One legislative leader has signed on to the idea, so far. State Sen. Cathy Giessel, chair of the Senate Resources Committee, said she supports state equity ownership of the project. The state contracted earlier this year with Kansas-based Black & Veatch to do the study. State investment in the project is one major recommendation. GIESSEL “Having a direct stake could solve a lot of problems for us and the project sponsors,” said state Natural Resources Commissioner Joe Balash in an interview. “Direct state equity participation in the (gas) project can provide key benefits to the state including alignment of interests (among the parties), transparency through the midstream portion of the supply chain, facilitation of third-party access to the midstream and potentially improved state cash flows along with improved producer economics,” the report said in its conclusions. In her statement, Giessel said, “LNG projects are capital intensive, complex, multi-stakeholder investments. How a project is structured and how risk and reward are allocated can make or break a project.” Giessel said PFC Energy, a consultant used by the Legislature, has pointed out that “gas-producing jurisdictions around the world choose equity ownership as a very beneficial fiscal arrangement,” she said. In its report, Black & Veatch outlined options for the state in improving fiscal terms in its study and said that without changes in the terms a large LNG project may not be viable. Balash said one of the biggest problems the companies have with the state’s current terms

is the one-eighth royalty share and the state’s ability, under leases held by producers, to switch taking its royalty from in-value, or cash payment, to in-kind, in the form of gas, and to switch back and forth with six months notice. “The sponsors have complained that the present structure has them obligated to finance 100 percent of the project but get only 7/8 of the benefits,” because they have the obligation to ship the state’s one-eighth royalty gas share through a portion of the pipeline they would have to fund. If the state were to invest in and own a share of the project equal to its one-eighth share, or perhaps as much as 25 percent if the tax obligation was included, it could better align the interests of the parties, Balash said. The producers and the state would each finance a share of the project sufficient to ship gas each party owns, he said. It would also spread risks, like cost overruns, more equitably. Black & Veatch said the improved profitability of the overall investments could make the difference in making the project attractive enough for the producers to back it, Balash said. If the state having a stake in the project solves a problem for the companies, it helps the state with other difficulties, Balash said. As an owner the state would have to the inner workings of the project finances, which would help ensure the state’s tax and royalty collections wouldn’t be disadvantaged, he said. Ensuring fair payment for tax and royalty assumed even more importance after the project switched from the original plan for an all-land pipeline to the con- BALASH tinental U.S. to a pipeline and a large natural gas liquefaction project serving an export market. Much of the state’s previous work on royalty terms became obsolete when the plan switched to include LNG, Balash said. The gas treatment plant and pipeline will be regulated by the U.S. Federal Energy Regulatory Commission as far as tariffs and rates, but not so the LNG plant to be built on the Kenai Peninsula near Nikiski.

“FERC gives us a transparent process as far as it goes, but the LNG part of the project is more opaque,” Balash said. “The project sponsors are likely to operate this as an integrated venture, so we see opportunities for shifting profits in ways that could not be in our interest.” Having a seat at the table helps the state solve this, he said. One problem the arrangement would present, however, is it leaves Alaska with the obligation to market its royalty gas as LNG. That could be more than 1 billion cubic feet of gas per day if the state takes a one-fourth share. Arrangements could always be made with one or more of the producers to market the state’s gas under contract but there would likely be fees associated with this, Balash said. Alternatively the state could set up its own LNG marketing organization, but such a group would always be at a disadvantage in competing for sales with others in the project, like BP and ExxonMobil with long experience in LNG. Balash said one possible solution could be in working with TransCanada, which is now part of the project group but which does not have its own gas to ship, unlike other parties. “We could become TransCanada’s customer,” Balash said. The 191-page Alaska North Slope Royalty Study produced by Black & Veatch analyzes key issues that state agencies and legislators will consider before setting fiscal terms for a gas project. The study examines LNG market conditions and the global supply chain, reviews fiscal terms that have been established for successful LNG export projects around the world, and looks at the commercial risks of various business structures for an Alaska project. “The goal of the study is to inform near-term decisions about the fiscal aspects of an LNG project in Alaska — big decisions that involve our royalties, taxes, or even a potential equity stake in the project,” Balash said. The study demonstrates that an LNG export project can compete for a place in the Asian LNG markets, but it will likely take changes to Alaska’s See STAKE, Page 25

2014 Meet Alaska Conference & Tradeshow

Fairweather Continued from Page 18

Photo/Michael Dinneen/AJOC

Fairweather Tulugaq’s Dan Wilkinson prepares to hop off of the Diamond DA42. The plane can be flown traditionally or remotely unmanned by replacing the pilot’s seat with a remote operating system.

researchers at the UAF’s Geophysical Institute, which has become a leading research center for unmanned aircraft development. By hovering a small, quad-copter UAV above

the sea lions’ brooding grounds the researchers took infrared photos of the animals — listed as an endangered population — and were able to count them from an offshore vessel without

Photo/Michael Dinneen/AJOC

One of the numerous sensors and cameras Tulugaq has in its $400,000 arsenal for the DA42 pops out from under the nose of the plane. The technology can be swapped quickly for missions from seal counting to pipeline observation.

disturbing the sea lions or putting pilots and biologists in risky low-level flying situations. Unmanned craft will allow for monitoring shifting sea ice, marine mammals and birds as more companies from transportation to resource development enter the Arctic. While it will likely be another couple years before widespread commercial use of UAVs is approved, particularly for large aircraft like the DA42, it’s “dull, dirty and dangerous” missions similar to the sea lion counts that they are made for, Wackowski said. “Most clients won’t let you put a manned crew (in the Arctic) when you’re talking about going more than 20 to 30 miles offshore,” he said. Prior to his work with Fairweather and its subsidiary, Wackowski had experience as an unmanned aircraft pilot in the Alaska Air Force Reserves. He holds the record for the northernmost UAV flight at 88.5 degrees North for flying a hand-launched AeroVironment Raven RQ-11 off of a Canadian icebreaker in the summer of 2011. He was flying so close to the North Pole that the Raven’s compass was disrupted,

2014 Meet Alaska Conference & Tradeshow Wackowski said. “Things operate differently up in the high Arctic,” he said. While setting the record, Wackowski was able to find leads, or cracks, in the sea ice ahead of the ship with an infrared camera on the Raven, which ship pilots prefer to follow when traveling through an icepack, he said. He also searched for polar bears while a team off the ship installed a buoy under the ice. While he didn’t find any bears, he said the mission is an example of a simple task a UAV can perform to make Arctic work easier. The FAA is in the midst of developing operational guidelines for UAVs and was directed by Congress to have them complete by 2015. As part of the 2012 FAA Modernization and Reform Act, the agency was tasked with choosing six UAV test sites across the country. UAF Geophysical Institute Director Greg Walker is pushing for Alaska to be one of the test sites and has said that given the state’s areas of open airspace and potential for future UAV use, it is more a matter of whether Alaska is chosen first, rather than at all. The FAA is expected to choose the test sites by the end of the year. A test site would consist of airspace and a landing strip designated for UAV research. “We fully support the University of Alaska’s efforts to get the UAV test bed up here,” Wackowski said. “It would be huge — a boom for industry and Alaska.” Aviation industry experts have forecast UAVs will quickly become a $30 billion-plus business in the U.S. once the FAA clarifies its airspace and communication regulations for the aircraft subset. Anchorage-based Peak 3 Inc. is in the business of prepping other companies for the FAA standards rollout. Peak 3 President and CEO Jen Haney said her company has worked in Alaska and the Lower 48 consulting with businesses and government agencies on how UAVs can benefit their operations and how to be ready to fly when the FAA says, “cleared for takeoff.” Part of the UAF team pushing for an Alaska test site, Haney said the culture of UAV operators needs to be similar to that of traditional aviation for safety reasons. “I don’t think it’s unreasonable for (UAV) pilots to be required to have their pilot’s license,” she said. The FAA is the “biggest roadblock” to ex-

Photo/Courtesy/Fairweather llc

The Diamond DA42 soars through Alaska on a sunny day.

Photos/Courtesy/UA Fairbanks

A quad-rotor drone was used by UA Fairbanks researchers in 2012 to conduct surveys of Steller sea lion populations in the far western Aleutian Islands.

panding the unmanned industry, Haney said, but the slow careful nature of the agency is necessary to safely integrate a whole new

realm of aircraft into the skies. Elwood Brehmer can be reached at elwood.brehmer@alaskajournal.com.

2014 Meet Alaska Conference & Tradeshow

Tesoro joins Cook Inlet Energy plan to build oil pipeline across Inlet

Photo/File/AP

The tanker Seabulk Pride that broke loose while being loaded with fuel in Nikiski is seen aground in Cook Inlet in this 2006 file photo with the Tesoro refinery in the background. The tanker loaded with about 4.9 million gallons of gasoline and other petroleum products broke free of its moorings and only spilled about 100 gallons of fuel, but avoiding this kind of mishap is why Inlet conservation groups are supporting a proposal to build a pipeline to transport crude oil across the Inlet to the Tesoro facility.

By Tim Bradner Alaska Journal of Commerce

Cook Inlet Energy is now working with Tesoro Corp. on its plans for a new 8-inch pipeline across Cook Inlet, a company official said. An agreement with Tesoro on how the project would be owned and financed is being negotiated by the two companies, said David Hall, CEO of Cook Inlet Energy LLC, a subsidiary of Miller Energy Resources, a Tennessee-based independent. The project would allow Cook Inlet Energy to move crude oil by pipeline from the company’s producing wells on the Inlet’s west side to Tesoro’s refinery at Nikiski, on the Inlet’s east side. The company now ships its oil by pipeline to the Drift River terminal on the west side, from where Tesoro moves it by shuttle-tanker across the Inlet to the refinery. Tesoro spokesman Matt Gill confirmed his company’s interest but said no final decisions have been made. A revised application to build the project by Trans-Foreland Pipeline Co. LLC was filed in late October with the Alaska State Pipeline

Coordinator’s office, with Tesoro listed as applicant. A two-month public review of the application is now underway, said Allison Iverson, acting director of the agency. The new application revises the application filed a year ago by Cook Inlet Energy, she said. Hall said that although Tesoro is taking the lead on the permit application, the agreement on how the pipeline ownership will be structured is still pending. If that comes together, “we hope to begin construction sometime in mid to late 2014,” Hall said. Cook Inlet Energy is interested in lowering transportation costs and improving safety for moving crude oil from west to east, Hall has said previously. The company also believes there is substantial potential for new oil to be found on the west side of Cook Inlet, and that a pipeline is a best long-term method to move that oil, Hall said. The pipeline would be 29 miles in length and would run from the Kustatan Production Facility on the Inlet’s west side to the Kenai Pipeline Co. tank farm and Tesoro’s refinery on the east side.

Hall said Cook Inlet Energy now produces about 2,100 barrels per day at its Osprey offshore platform on the Inlet’s west side and an additional 700 barrels per day of oil equivalent (oil and gas combined) at onshore wells the company operates in the West MacArthur River field. Meanwhile, Hilcorp Energy, which is also a west Cook Inlet producer and also operator of the pipeline and Drift River terminal, says it isn’t yet ready to be part of the cross-Inlet pipeline. “There are still too many commercial and regulatory uncertainties for Hilcorp to join the project,” with Tesoro and Cook Inlet, said Lori Nelson, Alaska spokeswoman for Hilcorp. Hilcorp brought the 40-year-old Drift River terminal and two large crude oil storage tanks there back into operation in late 2012 after it had been shut down since being flooded in 2009 after the eruption of the nearby Redoubt volcano, which is still active. Hilcorp took the terminal over from Chevron See PIPELINE, Page 49

2014 Meet Alaska Conference & Tradeshow

Stake

Continued from Page 21 fiscal terms to ensure a successful project. “We have some work to do, but the good news in this report is that we don’t have to sacrifice our royalty revenue in the future to get a project going,” Balash said. The study also demonstrates that a misalignment of interests between the State and project sponsors could lead to diminished value for the State’s royalty. North Slope lessees pay a minimum of 12.5 percent royalty on all hydrocarbons produced and sold. The value of that royalty is measured at the lease after transportation costs are deducted. Depending on the business and financing structure chosen by project sponsors, those transportation charges can be higher or lower — with the opposite impact on royalty values. “If we can find a way to better align our interests with the project sponsors, we can ensure Alaskans get the full value of their ownership of the resource,” Balash said. The study looked closely at the state’s royalty rates and terms, which are managed by DNR. Royalties paid by the producers are the primary

way the state benefits from its ownership of the North Slope’s hydrocarbon resources, and they are the foundation of revenue deposited to the Alaska Permanent Fund. While in some parts of the world, governments have chosen to reduce or zero out their royalties to improve the economics of an LNG project, state officials are concerned that this option could undermine payments to the Permanent Fund and limit the amount of gas available to Alaskans. A 20 percent to 30 percent equity investment in the project can provide the same or better revenue than collecting taxes and royalty alone, according to the study. “If we do it right, direct state participation in the project (through an equity investment) can allow the other project sponsors to structure their business and financing in whatever way benefits them. That would leave us free to structure our share of the business in whatever ways maximize the benefits to Alaskans,” Balash said. The study also indicates that taking the state’s royalties for gas production “in value” may pro-

tect the state’s interests better than taking the royalties “in kind.” If the state were left to market LNG itself, it could end up receiving lower prices overseas for its share of the gas. The study details the pros and cons of either approach. The Black & Veatch analysis focused on revenues, but Alaskans will benefit in multiple ways from a successful project. In the coming weeks, DNR will publish additional work regarding the value of in-state energy opportunities and expansions of the pipeline and/or the LNG plant. The LNG project — one of the largest projects of its kind in the world — would pipe gas from the North Slope to a tidewater port in Southcentral Alaska with the Kenai Peninsula identified as the preferred destination. Gas would be available to Alaskans at several off-take points and also shipped to Pacific Rim markets. The 30-year project would provide cheaper in-state gas supplies, billions of dollars in annual state revenues and new economic opportunities for thousands of Alaskans. Tim Bradner can be reached at tim.bradner@alaskajournal.com.

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The Alaska Support Industry Alliance 1 This LNG Series brought to you by the Alaska Support Industry Alliance

G N L 101

The Alaska Support Industry Alliance

The Alaska Support Industry Alliance 3301 C Street, Suite 205 Anchorage, AK 99503

Phone: (907) 563-2226 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 Fairbanks Membership Coordinator Jim Plaquet jplaquet@alaskaalliance.com Grassroots Coordinator Jake Falldorf jfalldorf@alaskaalliance.com Photo/File/AJOC

301 Arctic Slope Ave. Ste. 350 Anchorage, AK 99518

P: 907-561-4772

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Regional Vice President Lee Leschper lee.leschper@morris.com Managing Editor Andrew Jensen editor@alaskajournal.com Production Manager Maree Shogren maree.shogren@morris.com Cover and Layout Designer Nadya Gilmore nadya.gilmore@morris.com

Terminal at the LNG export plant operated by ConocoPhillips in Nikiski.

The Alaska Support Industry Alliance

Chapter 1. . . . . . . . . . . . . . . . . . . . What it is, who uses it and why Chapter 2. . . . . . . . . . . . . . . . . . . . . . . . Global Demand on the Rise Chapter 3. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Upstream Chain Chapter 4. . . . . . . . . . . . . . . . . . . . Shipping LNG around the globe Chapter 5. . . . . . . . . . . . Regasification Process and Terminals Chapter 6. . . . Terminals: Operating & Under Construction Chapter 7. . . . . . . . . . . . . . Role of LNG in World Energy Supply Chapter 8. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Buyers and Sellers Chapter 9. . . . . . . . . . . . . . . . . . Spot Market Pricing & Economics Chapter 10. . . . . . . . . . . . . . . . . . . . . . . . . . . Outlook for the Future

op-

The Alaska Support Industry Alliance

What it is, who uses it and why Liquefied natural gas, or LNG, is natural gas converted to its liquid form. When natural gas is cooled to minus-259 degrees Fahrenheit, it becomes a clear, colorless, odorless liquid. LNG is produced by taking natural gas from a production field, processing it to remove impurities, and then liquefying the processed gas. LNG isn’t corrosive or toxic. It doesn’t explode or burn as a liquid. Natural gas is primarily methane, with low levels of other hydrocarbons, water, carbon dioxide, nitrogen, oxygen and some sulfur compounds. During the process known as liquefaction, natural gas is cooled below its boiling point, removing most of these compounds. The remaining natural gas is primarily methane with only small amounts of other hydrocarbons. LNG weighs less than half the weight of water so it will float if spilled on water. Converting natural gas to LNG, a process that greatly reduces its volume — similar to reducing the volume of a beach ball to the volume of a Ping-Pong ball — allows it to be transported on cargo ships. Once delivered to its destination, LNG is warmed back into its original gas state so that it can be used just like existing natural gas supplies, sending it through pipelines to be distributed to homes and businesses. Natural gas transported as LNG is used for residential, commercial and industrial purposes like heating and cooling homes, cooking, generating electricity and manufacturing paper, metal, glass and other materials. LNG is also being used on a small scale to fuel heavy-duty vehicles. Because it is easy to transport, LNG makes previously stranded natural gas economical. These are typically natural gas deposits where the construction of a pipeline is uneconomical. LNG is usually transported by specialized tanker with insulated walls, and is kept in liquid form by auto refrigeration, a process in

which the LNG is kept at its boiling point. Any heat additions are offset by the energy lost from LNG vapor that is vented out of storage and used to power the vessel. Imported LNG makes up a little bit more than 1 percent of natural gas used in the United States. LNG imports represent an important part of the natural gas supply picture in the United States, especially to areas where there are limited pipelines delivering from US natural gas basins. LNG takes up much less space than natural

tive to propane for facilities that aren’t connected to a grid. Liquefaction also provided the opportunity to store natural gas for use during high demand periods in areas where conditions are not suitable for underground storage facilities. For example, in New England and the coastal area of the MidAtlantic states where underground storages is lacking, LNG is a critical part of the regions’ supply during cold snaps. In regions where pipeline capacity from supply area

The Nikiski plant’s Department of Energy export license expired in March 2013 and was not renewed. With new discoveries in Cook Inlet, the state asked ConocoPhillips to restart the plant and the company applied for a new export license Dec. 11, 2013. With lower domestic gas prices, several US import terminals have sought approval to build liquefaction facilities for exporting LNG. Depending on gas supply and price, these facilities will be able to import LNG when it is needed in

Existing LNG import/export terminals EVERETT, MA

COVE POINT, MD NIKISKI, AK

ELBA ISLAND, GA PASCAGOULA, MS FREEPORT, TX SABINE PASS, TX

LAKE CHARLES, LA CAMERON, LA SABINE, LA

PENUELAS, PR

Source: Federal Energy Regulatory Commission gas, which again, allows it to be shipped much more efficiently. Interest in LNG imports for the US had increased with higher natural gas prices during the 2000 to 2009 period. Technology advances have lowered costs for liquefaction and regasifying, shipping and storing LNG. Companies have announced plans to construct over a dozen LNG import facilities to serve the US markets. LNG storage facilities will also continue to be important in meeting the demands of local utilities as a way to store gas until needed. There is also a need for LNG for vehicular fuel and as an alterna-

can be expensive and seasonal, liquefaction for storage occurs during off-peak periods in order to reduce expensive pipeline capacity commitment. With the recent large increase of shale gas development in the US, domestic natural gas prices have declined, domestic gas is abundant and the need to import LNG into the US has diminished. Nikiski, Alaska, is home to the first LNG export terminal built in the US. It received natural gas from production wells near Cook Inlet. Natural gas was sent to the plant in Nikiski where it is liquefied and then exported, primarily to Japan.

the US and export LNG when it is economical. There are several existing import LNG terminals in the United States, including a terminal located in Puerto Rico. These facilities are located in Everett, Mass.; Cove Point, Md.; Elba Island, Ga.; Lake Charles, La.; Gulf Gateway Energy Bridge, Deep-water Port, Gulf of Mexico; Penuelas LNG, Bahia de Guayanilla, Puerto Rico, and Sabine Pass LNG, Cameron Parish, La. LNG is imported to these facilities from Trinidad and Tobago, Algeria, Egypt, Malaysia, Nigeria, Qatar and Oman. The current world market for

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Global Demand on the Rise Why is there a global demand for LNG? The answer is simple. The world needs more energy and wants clean energy, safe energy and affordable energy. The global population is predicted to rise from 7 billion to 9 billion in 2050 and the world will obviously need more energy. LNG is a safe, clean, and efficient energy source and is already part of the global energy mix. According to the International Group of Liquefied Natural Gas Importers, since 2006, China, Brazil, Chile, Dubai, Kuwait, the Netherlands, Canada and Mexico all became first-time importers of LNG. These countries joined LNG consumers from Japan, South Korea and Taiwan. In 2012, 25 different countries imported LNG. While natural gas demand has grown by about 2.7 percent per year since 2000, LNG demand has risen by about 7.6 percent per year in the same time period — almost three times faster. Since 2001, the total volume of LNG shipped has doubled to reach 496 million cubic meters, the equivalent of about 1.5 billion barrels of oil. Between 2009 and 2010 alone, world LNG trade grew by 22.6 percent.  That trend is expected to continue, even though there was a downward trend in LNG trade in 2012. The International Energy Agency (IEA) forecasts a growing need for natural gas in the world’s energy mix, with the natural gas share growing from 21 percent in 2010 to 25 percent in 2035. It is important to note that natural gas was the only fossil fuel whose share was growing. The IEA sees global natural gas demand growing at about 1.6 percent per year through 2035, more than twice the expected growth rate for oil. Other forecasters put the growth rate for gas even higher. LNG demand growth is, however, expected to be even stronger, particularly through 2020. While a wide range of forecasts exist, a majority of industry analysts see average annual growth of around 5 percent to 6 percent per year.

After 2020, demand growth is expected to continue, at a slightly slower pace — around 2 percent to 3 percent per year. Many industry experts agree the increase in LNG demand has been driven by a strong need from Asia, currently 60 percent of

build an LNG import terminal in 2010, global LNG supply was strong and it was priced well below what Lithuania is currently paying for gas. But LNG prices rose after the Fukushima disaster, when Japan shut down most of its nuclear

was approved. Export permits for Lake Charles, La., and Cove Point, Md., were approved in August and September 2013, respectively. Alaska producers and the State of Alaska are also looking at exporting gas from the North Slope as LNG. Current timelines show

LNG buyers LNGLNG buyers 25 nations imported in 2011, led by Japan

LNG buyers

25 nations imported LNG in 2011, led by Japan

25 nations imported LNG in 2011, led by Japan Other Asia1,2 10% Other Asia1,2 10%

China2 5% 2 China 5%

Americas 8% Americas 8% Middle East 2% East Middle 2%

Europe 27% Europe 27%

South Korea 15% South Korea 15%

Japan 33% Japan 33%

India, Taiwan, Thailand Demand in India grew 37% and demand in China was up 36% last year India, Taiwan, Thailand 2 Source: International Gasgrew Union 37% and demand in China was up 36% last year Demand in India 1 2 1

Source: International Gas Union

the total demand, and by political pressure to guarantee energy supply security, improve energy infrastructure, and reduce the world’s carbon footprint, by replacing coal with natural gas, while economies and population grow. In addition, the nuclear plant explosion in Fukishima in 2011 has led to rising popular opposition to nuclear power generation and more emphasis on LNG. The impact of the Fukushima disaster on global LNG need was highlighted as recently as last week when Lithuania announced their plans to reduce dependence on Russian gas by importing LNG could come at a higher-than-expected cost. This was reported by the firm negotiating the country’s first LNG supply deal. Lithuanian officials had been expecting imported LNG to help lower gas prices by 20 percent to 30 percent from what the country pays for Russian gas. When Lithuania decided to

reactors and had to start importing more LNG to generate power. LNG costs are expected to remain high as new Asian and South American importers compete for limited supplies. And over the next few years, the number of LNG importers is expected to grow, as countries like Bahrain, Croatia, El Salvador, Jamaica, Pakistan, the Philippines, South Africa, and Uruguay join the ranks. Even Indonesia, once the largest LNG exporter in the world, is considering importing natural gas to meet growing domestic demand. New export projects in Australia and the United States are scheduled to come online after 2015. The U.S. Department of Energy has approved four LNG projects to export gas to countries that don’t have a free trade agreement with the U.S. Sabine Terminal in Louisiana received approval in 2011; in May, the Freeport LNG project in Texas

that North Slope LNG exports would not occur before 2020. Outside North America, some African countries may also have strong LNG export potential. Chevron recently shipped its first cargo from their Angola LNG plant. In addition to Angola, longer-term facilities are in the works in east African countries, such as Mozambique and Tanzania. Russia and Israel have also been identified as having significant gas export potential. New technology, new markets and new sources of natural gas have impacted the current global need for LNG. What does the future hold for LNG? Every analyst/expert of the LNG markets seems to have a different answer to that question. The answer seems to depend on their view of supply and demand. It is certainly a rapidly changing dynamic with the number of new importers and new exporters entering the market.

The Alaska Support Industry Alliance

The Upstream Chain The LNG process, one that is much more complex than pipeline transportation, is often referred to as the “LNG chain.” It is made up of distinct parts: upstream, liquefaction plant, shipping, regasification and gas distribution. In this issue, we’ll discuss the gathering and processing aspects of the chain (upstream), as well as the liquefaction plants. Of course, the entire process begins with a decision to develop a gas field. That decision is typically related to the distance from the gas field to market, if a pipeline is available or if LNG shipment is required. Other considerations include the amount of recoverable gas, the cost to produce the gas that is delivered to the liquefaction plant in the removal of any impurities from the gas, a port that is close enough to the gas field for a liquefaction plant to be built, a political situation that supports long-term investments and a market price that is high enough to support the entire process and provide a good return. The upstream section of the LNG chain is very similar to regular gas systems. It includes drilling exploratory wells and eventually drilling and operating wells that recover the natural gas and bring it to the surface. The exact placement of an exploration well depends on the nature of the formation to be drilled, what the geology of the formation looks like, and the depth and size of the deposit. After a geophysical team chooses the best location for a well, the drilling company works to ensure that it completes all the necessary steps so that it can legally drill in that area. Securing permits for the drilling operations is a critical part of this phase. Once a natural gas well is drilled, and it has been confirmed that a large enough quantity of natural gas is there to commercially develop, the well must be “completed” to allow the natural gas to flow out of the formation and up to the surface. This process

includes evaluating the pressure and temperature of the formation, running casing and tubing, and using the proper equipment to ensure an efficient flow of natural gas out of the well. A piece of equipment, referred to as a “Christmas tree” fits on top of the well, and contains tubes and valves that control the flow of gas and other fluids out of the well. It contains many branches and is shaped somewhat like a tree. The

“Christmas tree” is the most noticeable part of a well, and allows people on the surface to monitor and regulate the production from a producing well. A typical “Christmas tree” is about six feet tall. A gas field is developed with sufficient wells to produce gas as an economic project. Field pipeline and separation and dehydration facilities are installed and gas is delivered to a transmission pipeline that can transport gas

to market, or in the case of LNG transports, the natural gas to an LNG processing plant. A typical LNG processing plant includes the following major parts: a gas handling and treating section, a liquefaction section, a refrigerant section, a fractionation section, an LNG storage section, an LNG loading section and a utility section. The three basic steps of the liquefaction process are the re-

Gas production wellhead, also known as a “Christmas tree” Tree cap and gauge Kill wing valve

Tree adapter Production wing valve Surface choke

Kill wing connection

Upper master valve

To production facilities

Lower master valve Tubing-head adapter Production string

The Alaska Support Industry Alliance moval of impurities and recovery of natural gas liquids (NGLs), the refrigeration of the gas until it liquefies, the movement of the LNG to storage and eventually into a tanker. After the liquefaction process, the LNG is pumped into a storage tank. These tanks are typically double-walled, with an outer wall of reinforced concrete and lined with carbon steel and an inner wall of nickel steel. Between the two walls is insulation to prevent air from warming the LNG. The LNG is stored in these tanks until a tanker is available to take the

LNG to market. The capital cost of a liquefaction plant is a critical component of the overall cost of an LNG delivery chain. In fact, total costs of a facility can run into the billions. This is obviously a huge expense, but costs have dropped significantly in the last 20 years. The reduction in costs is due to a number of influences. New technology has helped to gain economies of scale. In addition, organizational learning, research and development, project management, and supplier competition have had a hand in reducing the

cost of liquefaction. A June 2013 article with the headline “Liquefaction plant single largest cost for Alaska LNG project” was posted on the website of the Office of the Federal Coordinator for Alaska Natural Gas transportation Projects. Author Stan Jones provides the following description: “The biggest building on Earth is Boeing’s wide-body assembly plant in Everett, Washington. It covers an area as large as 18 Manhattan city blocks, stands 11 stories tall, and encloses almost 500 million cubic feet of space.”

He then suggests that the reader, “Imagine you have six of those buildings, all filled with natural gas from Alaska’s North Slope.” Jones suggests that, based on early estimates from energy experts, “the gas plant being considered for Alaska by Exxon Mobil, BP and Conoco Phillips could cost $20 billion or more to construct.” Jones also points out that a 2012 CNN Money survey of the 10 most expensive energy projects in the world included five LNG projects expected to cost more than $30 billion each. Photo/File/AP

A massive tank at the Sempra liquefied natural gas plant in Hackberry, La., is seen under construction in 2007. LNG processing plants and storage are among the most expensive energy projects underway around the world. The LNG processing plant proposed for North Slope gas is estimated to cost $20 billion.

The Alaska Support Industry Alliance

Shipping LNG around the globe Natural gas is normally shipped by pipeline, but it is impractical to build a pipeline from the Middle East or Africa to the United States and other locations. This logistical challenge has led to the creation of special ships capable of carrying the liquid form of natural gas — LNG. LNG carriers are “tank ships” — merchant vessels designed to transport liquids in bulk. The first LNG carrier was launched from the Calcasieu River on the Louisiana Gulf coast in January 1959 with the world’s first ocean cargo of LNG and it sailed to the UK where the cargo was delivered. The expansion of the LNG trade has led to a large expansion of the fleet. Hundreds of vessels have been built and today, giant LNG ships are sailing worldwide. Every single LNG ship that is seaworthy is active. There is not much spare capacity anywhere in the world. Early LNG ships were made with independent aluminum cargo tanks, with a capacity of 27,000 cubic meters and were used in the Algerian LNG trade in the late 1960s. Today, the International Maritime Organization (IMO) rules specify that all LNG ships must be one of three types. Type A are those built according to standard oil tank design. Type C refers to those that have a pressure vessel design. Type B refers to tanks that are neither of the first two types. In the eyes of the Coast Guard, all LNG tanks are Type B because Type B tanks must be designed without any of the general assumptions that go into designing the other tank types. There are three general Type B tank designs for LNG. The first type of design, the membrane tank, is supported by the hold it occupies. The other two designs, spherical and prismatic, are self-supporting. Membrane tanks are composed of a layer of metal, a layer of insulation, another liquid-proof layer, and another layer of insulation. These layers are then attached to the walls of the hold. In the case of the first design, the primary and

secondary barriers are sheets of nickel steel. Unlike regular steel, this nickel steel barely contracts upon cooling. All membranes are built up from the surface of a hold using units of insulation, called panels, that are anchored to it. Special insulation is inserted around the anchors. A membrane design is

nickel steel. The sphere is installed in its own hold of a double-hulled ship and it is supported by a steel cylinder called a skirt. The second type of selfsupporting tank is the prismatic tank. These tanks are similar to the tanks on old oil tankers; the framing is internal to the tank. The material for tank construction can

to keep the cargo at subzero temperatures, LNG tankers are more expensive to build than oil tankers. LNG tankers are usually ordered for specific liquefaction plants to carry the LNG on a specified route. A current inventory chart of all LNG carriers with 10,000+ cubic meter capacity shows more than 400 ships that are either in Photo/File/AP

A massive BP LNG tanker is seen delivering at the terminal for the Dominion Natural Gas Facility in Lusby, Md. Industry data indicates more than 700 LNG tankers will be needed to meet global demand by 2030. About 400 tankers are now in service or under construction.

very complex with many design elements. The year was 1969 when Phillips Petroleum and Marathon Oil began shipping natural gas from Cook Inlet to Japan. The Polar Alaska and the Arctic Tokyo, identical LNG carriers, were specially designed Rendering/Courtesy/VeKa Group pressure vessels just A rendering of a new shortsea LNG tanker transport to for this purpose. The be constructed by the Netherlands-based VeKa Group. tanks on these LNG ships were of the membe aluminum, nickel steel, or stain- service or under construction. brane design. The alternative to a membrane less steel. Only ships with alumi- The chart is dominated by China, tank is a self-supporting tank. The num tanks have been trading to Japan and Korea. Finland, France, Germany, most well-known is the spherical U.S. ports. The tanks are installed tank that most people equate with in the hold of a double hull ship Italy, Norway, Poland, Spain, Swethe appearance of an LNG carrier. and are insulated with covered den and the US each have small listings. Korea shows the largest The large spherical tanks, almost polyurethane foam. LNG ships tend to ride high in number of ships under construchalf of which appear to be above a ship’s deck, is often what people the water, even when loaded. A tion. According to industry data, visualize when they hear “LNG typical LNG ship is 950 feet long more than 700 LNG tankers will be carrier.” The early sphere designs and 150 feet wide, and many new needed to satisfy the global market were made with nickel steel. Alu- ships being built are even bigger. by 2030, almost twice the current minum is now used in place of Because of the equipment needed fleet of LNG ships in operation.

The Alaska Support Industry Alliance

Regasification Process & Terminals The LNG chain ends with the unloading, storage and vaporization of the gas in a regasification terminal. Liquefied natural gas is received and offloaded from an LNG carrier into storage tanks ranging in capacity from 100,000 to 160,000 cubic meters. These maintain the gas in the liquid state at -163°C. Regasification involves gradually re-warming the liquefied gas until its temperature rises above 0°C. The process takes place at high pressure through a series of evaporators, the most energyefficient technique when the right water quality is available. In other cases, some of the gas is burned to provide the necessary heat. The gas returns to its original state. In other words, it recovers its gas form and its initial volume, almost 600 times greater. Evaporators of various output volumes, constructions and heating methods are the basic equipment used in the LNG re-gasification facility. The location, intended use and fuel availability are the main factors considered in selecting the type of evaporators and the LNG re-gasification facility layout. LNG evaporators are divided into the following groups: • Evaporators that heat to a temperature equivalent to the temperature of the surroundings • Evaporators that heat to a temperature higher than the temperature of the surroundings • Evaporators with direct heating. On its way out of the terminal, the gas is treated as necessary to meet the specifications of regulators and end-users. For example, its heating value can be modified by adjusting the concentrations of nitrogen, butane or propane or by blending with other gases. The gas is then injected into a gas pipeline connected to a distribution network and, in this way, it reaches the end user, whether household or industrial. One hundred LNG regasification terminals are now operating in 21 countries worldwide, nearly

20 more are under construction, and approximately 30 more have been proposed. The largest receiving and regasification terminal in the world is the Sabine Pass LNG terminal in Cameron Parish, La. The terminal is spread over an 853-acre site. The terminal is owned and operated by Cheniere Energy. The Federal Energy Regulatory Commission, or FERC, approved the project in December 2004. Ground breaking for phase 1 of the terminal took place in March 2005. This phase came on stream in April 2008. The facility can handle 400 LNG vessels a year and features two unloading docks and four dedicated tugs. A major development in the LNG industry has been floating regasification and liquefaction terminals. The first Floating Storage and Regasification Unit was launched in January of 2005. Excelerate Energy was the owner. A regasification vessel is an LNG carrier with LNG vaporizers

onboard. Depending on the port location, availability of storage, total transport distance and volumes, the regasification vessel can be stationary and receive cargos from conventional LNG carriers. It can also be a shuttle vessel that picks up its own cargo and goes to the receiving location and regassifies the cargo. Initially, there was a clear distinction between a stationary vessel and the shuttle vessels. Today, users prefer flexible vessels that can act in both modes of operation. Vessels used primarily in stationary mode may either be moored dockside, then natural gas is discharged via a high line; or the vessel may be moored offshore. If moored offshore, the natural gas will be discharged from the vessel through a mooring and unloading buoy. A regasification vessel may be a conversion of a standard LNG carrier or a completely new vessel. For a conversion project it will typically take two years from construction to operation. A new vessel project can have a lead time of about three years, depending on yard availability.

According to Hoegh, LNG, a Norwegian company that owns and operates two floating regasification vessels, there are many benefits with floating vessels. The lead time and investment is smaller than for a land based terminal. The lead time for an offshore terminal is in the range of three years, while the land-based terminal may be in the range of four years. For small to medium LNG volumes it is also more economical as the investment costs are moderate compared to a land based terminal. A land based terminal will require space and access to harbors and traffic lanes that may be congested and provide an obstacle for the LNG carriers. An offshore based terminal can be located away from major shipping lanes and will only require a small area onshore for conditioning of gas before connecting to the gas distribution network. Finally, a floating regas solution is also very flexible as the vessel can be relocated or used as a conventional LNG carrier and operate in any market.

Photo/Courtesy/Petrobras News Agency

One of the first Floating Storage and Regasification Units, or FSRU, was the Golar Spirit, which is chartered by Petrobras and began operating in Brazil in January 2009. A regasification vessel is an LNG carrier with LNG vaporizers onboard and represents a major development for the industry.

The Alaska Support Industry Alliance

Terminals: Operating & Under Construction As of October 2013, there are 32 on-stream LNG liquefaction plants in the world, with 13 under construction and 17 others planned. There are 96 on-stream regasification terminals, with 18 under construction and 25 others planned. The global list of regasification terminals in the planning stage has shrunk from an all-time high of 47 to 25 in the last year, as several potential projects have either been suspended or canceled. Liquefaction plants in the planning stage were reduced from 21 to 17 in the same time period. Australia and Malaysia each have three on-stream LNG liquefaction plants. Qatar leads the way with six. Australia is poised to surpass Qatar with seven new plants under construction and six more in the planning phase. New Australian projects have been getting approved at a quick pace. More than $180 billion worth of LNG export projects are now being built, putting the country on track to quadruple its LNG exports by the end of the decade. Upon completion of the $34 billion Ichthys project, Australia is positioned to overtake Qatar as the world’s top exporter of LNG by 2017. Australia’s first LNG project began in 1980 when six major producers united to form the North West Shelf Venture, or NWSV. Located north of Perth, and with capital expenditures of about $27 billion, the project was commissioned in 1984 for domestic supply, followed in 1989 by the first shipment of LNG to Japan. The NWSV project represents Australia’s largest oil and gas resource development and currently accounts for more than 40 percent of Australia’s oil and gas production. Japan leads the way for onstream regasification terminals with 28. They also have three under construction and two others in the planning phase. China has six on-stream regasification terminals with eight under construction. The United States has 11

According to the FERC website, “there are more than 110 LNG facilities operating in the U.S. performing a variety of services. Some facilities export natural gas from the U.S., some provide natural gas supply to the interstate pipe-

on-stream regasification terminals with none currently under construction and only two in the planning phase. Eleven U.S. projects that were in the planning phase have either been canceled or suspended.

chief executive of Cheniere Energy, told the Financial Times, “This is the beginning. It is the dawn of the global significance of North America as a gas exporter,” in regard to their Sabine Pass project on the Gulf of Mexico.

Australia LNG Projects

projects

18 projects

Existing/under construction Under development (FEED) Proposed

Source: BG Group data: public reports, Wood Mackenzie In the United States, the Federal Energy Regulatory Commission, or FERC, is responsible for authorizing the location and construction of onshore and near-shore LNG import or export facilities under Section 3 of the Natural Gas Act. The Commission also issues certificates of public convenience and necessity for LNG facilities engaged in interstate natural gas transportation by pipeline. As required by the National Environmental Policy Act, FERC prepares environmental assessments or impact statements for proposed LNG terminals.

line system or local distribution companies, while others are used to store natural gas for periods of peak demand. There are also facilities which produce LNG for vehicle fuel or for industrial use. Depending on location and use, an LNG facility may be regulated by several federal agencies and by state utility regulatory agencies.” LNG terminals that are approved and built are subject to FERC oversight for as long as the facility is in operation. FERC currently regulates 24 operational LNG facilities in the United States. In April 2012, Charif Souki, the

Cheniere has already signed deals with companies in the United Kingdom, Spain, India and Korea to take a total of 16 million tons of LNG per year, equivalent to about 89 percent of Sabine Pass’s planned maximum capacity. Cheniere is expecting Sabine Pass to deliver its first LNG cargo late in 2015. The push for more LNG terminals in some countries, while others are suspending or canceling projects is certainly one indicator of the sensitivities surrounding the LNG market.

The Alaska Support Industry Alliance

Role of LNG in World Energy Supply International Energy Outlook 2013 projects that world energy consumption will grow by 56 percent between 2010 and 2040. Much of the growth in energy consumption is projected to occur in countries outside the Organization for Economic Cooperation and Development known as non-OECD. In these non-OECD countries, demand is driven by strong, longterm economic growth, and is expected to increase by 90 percent. In OECD countries, the increase is predicted to be 17 percent. China accounts for the largest share of the growth in global energy use, with its demand rising 60 percent by 2035, followed by India — where demand doubles. A recent headline in Reuters proclaimed “India’s future lies in liquefied natural gas.” Imports of LNG by India “will soar in the next decade to fuel an expanding economy; pitting India against China and Japan for supplies as its domestic gas output struggles and overland delivery remains a dream.” India’s trillion-dollar economy is already one of world’s largest importers of LNG. The rapid increase in LNG

demand from Japan will limit the ability of emerging markets such as India to obtain LNG at an affordable price. The extra supplies that India needs are more likely to come from Qatar and Australia. Qatar already supplies India on long-term contracts. According to a 2012 study done by Wood Mackenzie Ltd., China may need to boost imports of liquefied natural gas by about 80 percent from current contracted volumes to meet their demand for the fuel. The world’s biggest energy user may need to purchase an additional 37 million metric tons of LNG by 2030 on top of current contracted volumes of 46 million metric tons. Imports of LNG by China rose 34 percent from 2011 to 2012. Two years after the Fukushima earthquake, Japan’s energy market remains in transition. As the world’s biggest LNG consumer, this has global implications for the LNG market. Only 5 percent of Japan’s nuclear capacity is operational as of January 2013. Power generators have switched to alternative fuels, most notably natural gas. This has intensified global competition for

LNG, led to cargo diversions from other markets and contributed to rising prices for flexible LNG. So it’s no surprise that fossil fuels are projected to supply almost 80 percent of world energy use through 2040. Natural gas is the fastest-growing fossil fuel in the outlook. Global natural gas consumption is expected to increase by almost 2 percent per year. According to the Energy Information Administration, or EIA, “large‐scale investment in energy‐ supply infrastructure is required to replace existing supply capacity and expand to meet growing energy needs. Some industry analysts believe that a cumulative investment of $37 trillion is needed in the world’s energy supply system between 2012‐2035. Of that total, non‐OECD countries require 61 percent. Oil and gas supply are predicted to account for $19 trillion of the total.” In our second issue on LNG we asked the question, “why is there a global demand for LNG?” The answer is simple. The world needs more energy and wants clean energy, safe energy and affordable energy.

The global population is predicted to rise from 7 billion to 9 billion in 2050 and the world will obviously need more energy. LNG is a safe, clean, and efficient energy source and is already part of the global energy mix. This expanded role of LNG in the world energy supply will also have significant impact on the American economy. On Friday, Nov. 15, American Petroleum Institute Director of Upstream and Industry Operations Erik Milito highlighted the authorization by the Department of Energy, or DOE, for exports from the Quintana Island, Texas, LNG facility and urged the agency to quickly process the remaining 21 applications. According to Milito, “LNG exports will significantly reduce our trade deficit, grow the economy, and support thousands of U.S. jobs. The DOE has every reason to quickly approve these applications, and we’re pleased that they seem to be moving ahead.” The demand for LNG from China, India and Japan is growing rapidly and the number of potential suppliers is also increasing.

China Natural Gas Production and Consumption

10 Trillion Cubic Feet

Production 8

Consumption

6 4 2 0

2008

2015

2020

2025

Source: U.S. EIA-International Energy Outlook 2011

2030

2035

The Alaska Support Industry Alliance

Buyers and Sellers Buying LNG is usually accomplished through a short-, mediumor long-term contract. LNG may be purchased as an “individual cargo” — also called a spot transaction. Buyers and sellers each can handle the shipping of the LNG once a contract is in place. “Free on Board,” or FOB, describes a sale where the buyer arranges for the shipping. CIF, or Cost, Insurance, Freight, describes a transaction where the seller arranges for shipping. DES, or Delivered Ex Ship also describes a transaction where shipping is arranged by the seller. In 2012, there were 27 countries buying LNG. Asian countries bought 70 percent of the total with Europeans buying 20 percent, North and South America at 4 percent each and the Middle East at 2 percent. Projections for 2030 show South America growing to 6 percent, the Middle East to 4 percent and North America dropping to 2 percent. The fastest growth is projected to come from the smallest market

— the Middle East and Africa, with Kuwait being the biggest driver. In Asia, Japan is the largest destination for LNG. Buyers include utilities like Tokyo Electric and Tokyo Gas. South Korea is also an active buyer of LNG for companies like Korea Gas Corp. or KOGAS, and manufacturing companies who import LNG for their own use. Chinese companies like PetroChina and Sinopec add to the growing demand for LNG in Asia. While demand for LNG is rising, big supplies are not expected before 2015. Major Australian projects are expected to enter the market in 2014, but most of the new projects, many from North America, are projected to come online in 2015. With a rise in demand of 7 percent a year through 2020 this gap between supply and demand will result in a narrow market. New sellers are slowly emerging. In Russia, the government recently passed legislation that allows LNG exports to Asian markets. LNG

exporters in East Africa and the East Mediterranean are scheduled to enter the market before 2018. The complex nature of LNG transactions demands that the buyers and sellers who are negotiating LNG contracts, which are typically long-term, understand every detail of the global LNG market. Understanding methods for determining prices in this fluid market is critical to avoiding wrong sourcing decisions and significant negative financial impacts as well as legal liabilities. In an Oct. 4 Energy Inc article entitled “LNG contract sales are ripe for a Shakeup,” Jason Burner highlights the first LNG ProducerConsumer conference that was held in Tokyo last year. The conference was held to provide Asian LNG buyers an opportunity to lobby for lower prices and more flexible contract terms. A second conference was held in Tokyo in September of this year with more than 1,000 delegates. The tradi-

tional LNG contract model with pricing linked to oil is a target of Asian buyers who see it as inflexible and outdated. A contract signed by the BG group underscores the importance of “safeguarding your interests as circumstances change” in the LNG market. In a July 2012 Financial Post article, Edward McAlister refers to the contract as the “world’s sexiest LNG contract.” McAlister notes that “In signing up to buy all of Equatorial Guinea’s liquefied natural gas for 17 years, Britain’s BG Group unknowingly sealed one of the most lucrative LNG deals ever. The 2004 contract generates nearly $1 billion a year for BG, and lets it keep almost all profit from gas it sells at five times the price in Asia…” A lesson was learned, and McAlister adds, “Exporting countries are becoming increasingly knowledgeable and are pressing for better returns for their resources.”

Global LNG trade grows fast

Trillion Cubic Feet per year

12 10

As of 2013, 17 countries export LNG and 25 countries import it

8 6 4 2 0

1975 1980 1985 1990 1995 2000 2005 2010 2012 Source: BP Statistical Review of World Energy

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Spot Market Pricing & Economics like Japan, Korea, Taiwan and China. The main LNG suppliers for the market have been Qatar, Australia, Indonesia, Trinidad and Nigeria. Some multi-national oil companies and investment banks are developing trading houses in places like London and Houston to serve the LNG spot customers from Europe and Asia. A snapshot of today’s LNG spot market shows that spot LNG prices are climbing in Asia due to strong winter demand from China, Japan and South Korea. China’s LNG

in the spot market trade is the “Master LNG sale and purchase agreement” (Master Agreement) accompanied by a “Confirmation notice/memorandum” (Confirmation Notice) The Master Agreement lays out the terms and conditions of LNG trading with no firm commitment from the seller or the buyer. The Confirmation Notice is usually attached to the Master Agreement and sets out the purchase and sale of the spot cargo. Details of the Confirmation Notice

by a confirmation notice is the time saved by negotiating a master agreement rather than a one-time sale and purchase contract. The spot market for LNG may be small relative to the long-term contract market, but it is important because pricing impacts the flow of flexible LNG. The spot market is driven by the LNG supply that is not under contract and LNG that is under long-term contract that has the flexibility to be used against spot prices (cargo diversions).

Spot Market, Pricing and Economics

North America and East Africa expected to capture the majority of incremental Asian demand 300 205 250

MMt/y

Spot Market: A public financial market in which financial instruments or commodities are traded for immediate delivery. Spot markets can operate wherever the infrastructure exists to conduct a transaction. The LNG spot market began to develop in the 1990s. Extra capacity caused by the start-up of new projects and the expiration of old contracts at existing facilities led to LNG cargo becoming available for purchase on a short-term basis. The use of LNG to meet seasonal demand by countries like Spain and Korea also contributed to the growth of the LNG spot market. Due to the flexibility of the LNG product, the history of its growth in the spot market has been affected by many things including plant shutdowns and natural disasters. Hurricane Katrina and the Fukishima disaster both caused LNG cargoes to be diverted, leading to significant price increases in European gas. LNG spot trading typically takes place when there is extra capacity in the infrastructure (liquefaction, LNG tankers and regasification facilities) and a large number of players buying on the market. The LNG spot market is made up of both short-term deals of less than 1 year (though some participants in the LNG market consider anything less than 4 years a “short-term deal”) and trades that involve only one cargo. The LNG spot market is beginning to take a share of the overall LNG trading market, currently about 20 percent of the total. In 2012, the total volume of LNG traded globally was 223 million tons. Some industry analysts are projecting that shortterm LNG trade will increase by 11 percent per year through 2015. Even though there has been significant growth in the LNG spot market, long term contracts still dominate the LNG market since these contracts finance the infrastructure that is required. In the last few years, the main markets where LNG is traded over the spot-market are the United Kingdom and Asian countries

East Africa

Total Asian LNG Demand

North America Others

225 200

Supply Under Construction

175 150 125

Existing Supply

2010

2015

2020

2025

Source: Poten & Partners imports are increasing rapidly as several of their new LNG receiving terminals come on line. At the same time, South American demand has decreased. Argentina and Chile are demanding less as they enter into their summer season. A common contract used

include price, quantity, LNG ship, arrival time, loading and discharging ports, and other requirements specific to a unique transaction. Once this document is signed it constitutes a binding contract. One of the benefits of a master agreement that is supplemented

Many industry analysts believe that the volatility of the spot market will lead to pressure from long-term contract buyers to re-negotiate contract terms for flexibility. But in the short term, LNG spot price volatility is likely to continue.

The Alaska Support Industry Alliance

Outlook for the Future The future of LNG can be looked at from a global, national and Alaskan perspective. As we have discussed in many of the previous issues, the global demand for LNG has risen very quickly. From 1990-2010, gas rose from 19 percent to 22 percent of global energy supply. LNG is the fastest growing segment within gas. In that same time period, the gas share of the global electric supply has risen from 15 percent to 24 percent. The advantages of LNG as a fuel are more pertinent now than ever before. Japan needs new sources of power generation after shutting down most of its nuclear plants. China is anxious to reduce their coal consumption, and LNG offers a clean, reliable alternative. Asia has made up the majority of the growth since 1990 and is projected to make up the majority of the new demand. In Europe, countries like Poland and Lithuania see LNG as a tool that allows them to reduce their dependence on Russia. As a result, the number of countries looking to buy LNG has increased from 11 in 2000, to 27 in 2013. Analysts expect that number to increase to 42 by 2020. With regard to the supply of LNG, Qatar has been the largest contributor over the past decade, but in this decade, it will be Australia. Other strong prospects for more production are the U.S., Canada and Africa. 40 percent of proposed liquefaction plants are in the U.S., with 17 percent in Canada and 14 percent in Australia. If you added together the capacity of every proposed plant, there would be an over-supply of LNG on the world markets in the mid-2020s. Many of the variables in the LNG market, however, are very difficult to assess, and the prospect of less LNG supply being developed is real. A tight market for exporters could lead to improved returns. For those looking to import LNG,

other sources of energy may need to be used to fill the gap. The United States is in a very strong position for more production. Terminals, loading docks and storage tanks that were built for the purpose of importing LNG can be reconfigured for exporting. The US has a strong pipeline infrastructure as well as a solid engineering industry. After years of delay over permits for sale to countries that don’t have a trade agreement

to capture this market. The opportunity is real, and it has begun to dominate the discussions in the Alaska State legislature as they begin to ask questions about the investment climate for companies who are proceeding with the Alaska LNG project as well as determining why an LNG buyer would choose to purchase LNG from Alaska. At an August 2013 North Slope Gas & LNG Symposium held in Anchorage, legislative consultants

outlets for their capital.” • “An Alaskan LNG project can be competitive with other projects seeking to supply Asian markets…” and • “There are multiple ways to structure an LNG project and it is important to develop a structure that aligns all the different parties and project participants and meets their risk-reward appetites.” Alaska has a role to play in the LNG market; Alaska has major

Outlook for the Future

Comparative Advantages of Alaska LNG Alaska to Asia B.C., Canada to Asia

U.S. Gulf of Mexico (via Panama Canal) to Asia

Qatar to Asia Australia to Asia

U.S. Gulf of Mexico to Asia

Chart via Richard Zeits with the US, the Department of Energy has recently given approval for four projects in addition to Sabine Pass. Twenty-one other applications are awaiting approval from the Department of Energy. Buyers from Japan, Korea and India have already signed deals to buy US LNG. The demand for gas and LNG that is coming from Asia gives Alaska a geographical advantage

PFC Energy provided a comprehensive look at LNG that included a look at the role Alaska can play in the global market. PFC Energy noted that: • The companies that are involved in the Alaska LNG project have “substantial experience in LNG. As such, the question is not whether they can do an LNG project, but rather will they choose to given competing priorities and

companies with significant experience and expertise involved in the Alaska LNG project. The Alaskan legislature will have the opportunity to develop competitive fiscal terms for the project. Alaskan residents have the opportunity to educate themselves on LNG and the opportunity for Alaska. We hope this series has helped.

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2014 Meet Alaska Conference & Tradeshow

BP taking a new look at long-planned Liberty project in Beaufort Sea By Tim Bradner Alaska Journal of Commerce

BP is once again working on development of its offshore Liberty prospect in the Alaskan Beaufort Sea, federal agency officials said. Liberty is a long-known, but undeveloped, oil discovery five miles offshore the North Slope in federally-owned waters. The deposit holds an estimated 150 million barrels of recoverable reserves, BP spokeswoman Dawn Patience said. Sharon Warren, deputy Alaska director for the U.S. Bureau of Ocean Energy Management, or BOEM, said BP has told the federal agency it will present a development plan by the end of 2014 and has plans to have the field producing by 2020. Patience said Liberty is expected to produce about 40,000 barrels per day once it is developed. “We are still identifying development options,” she said. “During the initial project planning for Liberty, BP examined an island connected to land by a subsea pipeline similar to the Northstar design,” Patience said. Northstar is an almost identical small offshore field BP developed in the Beaufort Sea in 2000. It is six miles offshore and several miles west of Liberty. An artificial gravel island and subsea pipeline, the first in the Arctic, was built at Northstar in 1999 and 2000. The field began producing in 2001. At Liberty, BP’s initial approach was for a similar artificial gravel island, but the company switched to an alternative concept of drilling ultra-long-reach extended wells from a drill rig on shore. Some of those wells were to be as long as eight miles from the onshore location of the rig.

BP contracted with Parker Drilling Co. to build a specialized rig to drill the wells, but problems with the rig delayed the plan. Patience said needed modifications to the rig now make it likely that drilling from onshore would be uneconomic. BP hasn’t said it is back to an artificial gravel island plan but Warren said that appears to be the only reasonable alternative for Liberty development at this point. Northstar, which is in about 40 feet of water, attracted a great deal of attention from government agencies because it was the first Arctic offshore producing field. Its production island is also outside the protection of natural barrier islands, so that it is exposed to moving winter pack ice and summer storms. Liberty, in contrast, is inside the barrier islands and is sheltered from moving ice and storms,

and is in shallow 20-foot water depths. In winter the possible island site would be typically surrounded by stable ice that freezes out from the shore. Northstar has performed safely despite the moving winter ice and storms. That record, plus the more the benign conditions at Liberty, should things easier for that project to secure permits than at Northstar. However, Warren said she still expects the full range of issues to be brought up including offshore oil spill risks and effects on migrating bowhead whales. Construction the artificial gravel island and the six-mile, buried subsea pipeline at Northstar involved some firsts for Arctic construction. Construction of the production island really involved reconstruction and reinforcement of an artificial gravel island built earlier at the site by Shell, for ex-

ploration drilling. Shell called it “Seal Island.” BP renamed the site after acquiring the field from Shell and Amerada Hess Corp. The innovation at Northstar involved building the subsea pipeline, which required trenching the sea ice in winter and then trenching the seabed to lay in the pipeline. Several leak-detection systems were also installed in the Northstar pipeline including systems to monitor pressure loss and volume changes that could indicate a leak, but also the first application of a high-tech system designed to detect very small leaks of oil. The systems are tested annually, and so far there have been no leaks. If Liberty is developed using techniques similar to Northstar, similar pipeline leak-detection systems would be employed.

Photo/file/calvin hall

The BP Liberty project at the Alaska Beufort Sea is getting a fresh look, and company officials plan to present a development plan for the field before the end of 2014. The field is expected to produce 40,000 barrels per day.

2014 Meet Alaska Conference & Tradeshow

Photo/Judy Patrick/ConocoPhillips

Two ConocoPhillips employees overlook pipelines on the West Sak oil field on Alaskaâ&#x20AC;&#x2122;s North Slope. Projects now in development for ConocoPhillips on the Slope could add 55,000 barrels of production per day by 2018, according to company estimates.

ConocoPhillips projects could add 55K barrels by 2018 By Tim Bradner Alaska Journal of Commerce

ConocoPhillips is pushing ahead with projects that could add about 55,000 barrels per day of new North Slope oil production by 2018, the company said. This will help dent the current decline in production, which averages about 6 percent yearly, from existing North Slope fields The 55,000 barrels per day estimate includes 16,000 barrels per day expected from the new CD-5

project; 8,000 barrels per day from a new drill site in the Kuparuk River field, and 30,000 barrels per day anticipated from a new production site in the National Petroleum Reserve-Alaska. In addition, a new drill rig put into service in the Kuparuk River field earlier this year has resulted in about 1,800 barrels per day of new production, ConocoPhillips said. The CD-5 project has been long-planned but work on the other projects was accelerated after the

Legislature approved Senate Bill 21, which modified state oil production taxes, ConocoPhillips has said. BP Exploration, which operates the large Prudhoe Bay field, is also planning new projects in that field Construction will begin this winter on the CD-5 project, with Anadarko Petroleum Corp. is a minority owner. Preliminary placement of gravel will also be done this winter for the new drill-site Kuparuk 2-S in the Kuparuk field, ConocoPhillips spokeswoman

Natalie Lowman said. The company must still give final approval for construction of the drill site and its related infrastructure. That will be requested of ConocoPhillipsâ&#x20AC;&#x2122; board in late 2014, Lowman said. BP is also an owner in the Kuparuk field and is a partner in the new project. At CD-5, contractors will begin mobilizing for construction late this fall. The project involves a bridge over the Colville River, a production pad in the west side

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of the river as well as related roads, pipelines and utilities. “Construction of CD-5 is planned to begin in January 2014 and continue in winter 2014-2015. First production is expected in late 2015 and the initial gross production rate is estimated in the range of 16,000 barrels per day,” of oil, Lowman wrote in an email. CD-5 will be the first commercial oil production from the NPR-A. The small field is west of the producing Alpine field, which is on state of Alaska lands, but because CD-5 is on the west side of the Colville River it is within the federally-owned NPR-A. ConocoPhillips has also released cost and production estimates for the Kuparuk 2S drill site which is in the southern part of the Kuparuk River field, and the GMT-1 project in the National Petroleum Reserve-Alaska. Kuparuk 2S is planned for construction in late 2014 with first production is expected in 2015. Costs are estimated at $595 million and peak production is expected to be 8,000 barrels per day.

The GMT-1 project in the petroleum reserve is estimated to cost $890 million to develop and is expected to produce 30,000 barrels per day with first production in 2017, Lowman said. GMT-1 is within the Greater Moose’s Tooth Unit a few miles further west in NPR-A, and would be the second oil producing project within the reserve. ConocoPhillips is the operator and majority owner of GMT-1 and CD-5 with 78 percent interest, with Anadarko owning a 22 percent interest. The 30,000 barrels-per-day estimate for GMT1 represents an increase over earlier estimates of its potential production. In a 2011 presentation to financial analysts in New York the company had put the production estimate at 15,000 barrels per day to 20,000 barrels per day. Lowman would not comment on the revised estimate but said 30,000 barrels per day is the number the company is now working with. CD-5 and GMT-1 will provide the first oil produced on a commercial basis from NPR-A but gas has been produced for several years at Barrow, in the far northern part of NPR-A. The gas field there is owned and operated by the North Slope Borough, the regional municipality. It supplies Barrow Utilities, the local electric and gas co-op, which serves the Inupiat community of Barrow. The 23 million-acre NPR-A covers the western part of the North Slope. It was created as a naval petroleum reserve in 1923 but did not see exploration until the 1950s and 1960s, which resulted in the gas discovery at Barrow and an oil discovery at Umiat, in the southeast part of the reserve. The Umiat discovery was not economic when it was found but Australian independent Linc Energy began drilling last winter to delineate the field and will continue this winter. Linc hope to eventually produce 50,000 b/d from Umiat. Meanwhile, CD-5, near the Alpine field, is within the federal reserve but the subsurface mineral rights are owned by Arctic Slope Regional Corp. of Barrow. That means ASRC will receive royalties from production at CD-5. Under terms of the Alaska Native Claims Settlement Act of 1971, the federal law under which ASRC obtained the mineral holdings, 70 percent of the royalties must be shared with other Alaska Native corporations. Also, Kuukpik Corp., the village corporation for Nuiqsut, the nearest Inupiaq community, is reported to hold a small overriding royalty interest in ASRC’s royalty share of the CD-5 subsurface, but the details of that are confidential. ASRC also owns some mineral rights on state of Alaska leases on the Alpine field, which is in the Colville River delta east of the NPR-A.

Third quarter earnings down vs. 2012 ConocoPhillips earned $494 million from its Alaska oil and gas production in the third quarter of 2013, the company announced Oct. 31. This is down from $585 million in earnings in the second quarter, mainly due to lower oil production. The company’s Alaska production was down about 20,000 barrels per day during the quarter, much of its due planned turnarounds at its Prudhoe Bay and Kuparuk River fields and the natural decline of aging oil fields. Production averaged 178,000 barrels per day in the third quarter, down from 197,000 barrels per day in the second quarter. However, ConocoPhillips’ third quarter production was roughly on par with third quarter 2012 with 176,000 barrels per day in production. Its net income for Alaska was down 7.6 percent, from $535 million to $494 million, compared to the 2012 third quarter while its overall net income as a company increased 7 percent in the same period. ConocoPhillips is the only Alaska oil and gas producer that breaks out its Alaska earnings separately when it issues a financial report for worldwide activities. As has been the case in previous quarters the company paid nearly twice as much in government taxes and royalties as it earned. Total taxes and royalties were about $900 million in the third quarter, with about two-thirds of this, or $652 million, paid to the State of Alaska during the third quarter. “As we have reported historically, under the ACES production tax regime we pay almost twice as much in taxes and royalties as we keep,” said Bob Heinrich, ConocoPhillips’ Alaska vice president for finance. “The recent oil tax change passed by the Legislature, with Senate Bill 21, improves the business climate in Alaska. As a result of these improvements we are now looking forward to increasing our North Slope investment.” Alaska is a significant source of income for ConocoPhillips because most of the company’s earnings in the state are from crude oil, while in the Lower 48 states a good portion of income is from natural gas, which has experienced low prices. Still, the company’s Lower 48 oil producing fields have seen significant increases in production, up 54 percent in the third quarter, compared with a 15 percent decline in Alaska oil production. Tim Bradner can be reached at tim.bradner@alaskajournal.com.

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Donlin gold mine advances toward draft environmental impact statement

Photo/Courtesy/Novagold

Core samples are logged at the Donlin gold prospect in Western Alaska. Permitting is advancing for the mine that has an initial operating life of 27 years producing as much as 34 million ounces of gold.

By Elwood Brehmer Alaska Journal of Commerce

The permitting process is ongoing for what would be largest gold mine in the world if it were developed. James Fueg, study manager for Donlin Gold at its prospect near Donlin Creek in Western Alaska, said the company completed its scoping and baseline data acquisition in late May in preparation for compiling a draft environmental impact statement, or EIS, for the project. With the second year of permitting complete in a process that is expected to take four years, Fueg said the draft EIS could be expected in late 2014 or early 2015. The sheer scope of the estimated $6 billion open-pit gold development separates it from other proposed mines. Donlin Gold’s current plan is to power the mine with natural gas from Southcentral, meaning a 314-mile, 14-inch pipeline would need to be built from Cook Inlet to the mine site. Subsequently, a large power plant would be needed to turn the gas into electricity.

On the other end, Donlin Gold has proposed an access road to the Kuskokwim River some 10-plus miles from the mine site where goods barged to and from Bethel on the Kuskokwim could be offloaded. “What makes this project challenging is just its complexity with the amount of infrastructure that needs to be built to develop the project,” Fueg said. “It runs all the way from Anchorage out into Kuskokwim Bay — so halfway across Alaska.” The mine itself would be approximately two miles long and one-mile wide, according to Donlin Gold. It would have an initial operating life of 27 years to extract the 34 million ounces of gold estimated to be available. Donlin Gold estimates an average of 59,000 tons of ore would be processed daily at the mine over its life. In March, Donlin Gold spokesman Kurt Parkan said the company’s equal-share parent corporations Barrick Gold and NovaGold Resources have spent $329 million on the project since 2005. Fueg said in a November interview that an updated project cost was unavailable.

“(Permitting) is going to cost what it’s going to cost. We’re committed to funding the project through the permitting phase,” he said. Geotechnical drilling surveys were done at the mine site and along the proposed pipeline and access road corridors this summer, Fueg said. The mine site is on land owned by The Kuskokwim Corp., a Native village corporation. The subsurface rights are owned by Calista Corp., the regional Alaska Native corporation. Once permitting is complete, construction of the mine is expected to take another three to four years, Fueg said. It’s estimated that construction of the mine would employ about 3,000 people; and 600 to 1,400 employees would be needed once the mine is up and running. To get a head start on hiring such a large workforce, Fueg said Donlin Gold has held summer internships and teacher externships at the remote exploration camp to train prospective employees and give industry instructors insight into what training Donlin Gold mine employSee DONLIN, Page 32

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Prospect near Nome would be lone U.S. graphite producer By Elwood Brehmer Alaska Journal of Commerce

In the coming years Alaska may have the country’s only producing graphite mine. Graphite One Resources, a Vancouverbased exploration company, has begun permitting on 129 graphite claims at its Graphite Creek prospect on the Seward Peninsula. The mineral deposit is on the northern slope of the Kigluaik Mountains about 40 miles north of Nome and about 10 miles from spur-road access off of the Taylor Highway. Graphite One Vice President and Director Dean Besserer the company conducted a $5.5 million drilling campaign in 2012 that showed great promise for the prospect from its 18 drillcore sites. He called the 16,800-acre property a “world-class flake (graphite) deposit,” during a Nov. 6 presentation at the Alaska Miners Association convention in Anchorage. “We are the United States’ only advanced, high-grade flake graphite deposit,” Besserer said. In an interview he said the company is in the early stages of an expected three-year permitting process and hopes to start developing the site as soon as late 2016. Its estimated development cost of the mine could be from $120 million to $150 million. Besserer said at that price it could have as little as a 1.5-year initial payback window. The graphite deposit has inferred resources totaling 23.4 million short tons, according to a December 2012 Graphite One report. A highlight

of the deposit is 8.6 million tons of near-surface material with a 13.5 percent mineralization. Another subsurface portion of 27.9 million tons of base has a 9.7 percent flake graphite base. The near-surface deposit runs for approximately 1.3 miles along the base of the mountain range, and the entire host formation is continuous over about 10 miles, according to the report. At an average long-term production rate of 20,000 tons of graphite per year, the mine would almost certainly have a 50-year life, but additional finds could extend that out to 100-plus years, Besserer said. A final drill season is needed to pin down exactly where to start site development, he said. To relate the deposit to gold in terms of value, he said the 8.6 million-ton, high-density deposit would equate to more than 1 million ounces of gold at current gold prices of about $1,300 per ounce and a conservative flake graphite price of $1,200 per ton. The large flake graphite present at Graphite Creek that Besserer said makes the prospect especially promising has traded at $1,400 to $1,500 per ton late last year after hitting a near-term bottom of about $1,200 early in 2013. Through much of 2011 it was trading at more than $2,500 per ton after being less than $1,000 as recently as 2007. Comparatively, the more common amorphous, or lump, graphite trades for about $400 per ton. Because of the relatively high concentration of graphite necessary to make a deposit viable when compared to copper or precious metals,

he said less ore needs to be processed in graphite mining. As a result, the Graphite Creek mine will have a much smaller footprint than some of the other surface mines in the state, he said. He projected ore processing at 200,000 tons to 400,000 tons per year. He added that graphite operations don’t use chemicals such as cyanide like some metal mines do to leach material from the ore. “We’re going to be a glorified gravel pit,” Besserer said. The deposit’s location along the continuous mountain slope would make for a “bench” mine along the slope as opposed to an open-pit dug on levels beneath the surface, he said. Without an operating graphite mine, the United States imports all of its graphite. Canada currently has two small graphite mines and a third scheduled to begin production sometime in 2014. In recent years China has produced about 70 percent of the world’s graphite, but depletion of the country’s flake deposits has hurt its quality, while demand for flake graphite has doubled since 2000, Besserer said. Aside from being a popular lubricant, graphite is increasingly used in lithium-ion batteries and fuel cells, when in flake form. It is also considered one of the best-know thermal conductors. It’s those technical applications, Besserer said, that will continue to grow demand and price particularly for flake graphite.

forward as planned, Fueg said. One note Donlin Gold is particularly proud of, Fueg said, is that through the summer its employees had worked a total of 1.75 million manhours without a lost time incident. He said the feat is particularly remarkable considering inherent challenges associated the mine camp’s remote location. “Given the nature of the work the guys do in the wilderness — we’ve got extreme weather, bears, there’s a lot of aviation, helicopters, draw rigs — it’s a difficult environment to work in,”

he said. “The guys have done it in an incredibly safe and professional manner.” In September, Donlin Gold was named the National Employer of the Year by the National Association of State Workforce Agencies. The Alaska Department of Labor and Workforce Development nominated the company, citing its community outreach and local-hire efforts.

Elwood Brehmer can be reached at elwood.brehmer@alaskajournal.com.

Donlin

Continued from Page 31 ees would need. The programs will continue through the permitting process, he said. Additionally, the company has presented at area village schools to inform teachers and high school-age students about the job opportunities the mine could provide and the training needed for those jobs. Donlin Gold has put together a jobs booklet that identifies positions in barge operations, finance, mechanical and heavy equipment maintenance and hospitality fields that will need to be filled outside of the mine if the project goes

Elwood Brehmer can be reached at elwood.brehmer@alaskajournal.com.

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Northern Dynasty vows to press on at Pebble By Tim Bradner Alaska Journal of Commerce

The Northern Dynasty Minerals Ltd. CEO says the company is continuing its efforts to develop the giant Pebble minerals project southwest of Anchorage, and is encouraged about prospects for bringing in a new partner to replace Anglo American, which withdrew from the project in September 2013. The company is in talks with several major minerals companies, Northern Dynasty CEO Ron Thiessen told the Resource Development Council’s annual conference in Anchorage. Pebble is about 200 miles southwest of Anchorage and about 18 miles north of Iliamna Lake. Thiessen said work is now underway to finish applications for federal and state government permits and those are about 90 percent complete. The company’s management team in Alaska is being kept intact, he said. “We are now focusing on completing the 10 percent needed to finish the applications, and we expect to have this done in early 2014,” Thiessen said. However, the company would like to wait until a partner is on board before actually filing the applications. “But we will be ready,” he said. Thiessen told the Associated Press separately that the process of finding a partner could take six to 12 months and will start in earnest soon. He said if it appears the U.S. Environmental Protection Agency is moving to take pre-emptive steps to restrict permitting for the project, the company will probably launch the permitting process on its own without waiting for a partner. Anglo American had invested nearly $600 million in the project before withdrawing, and Northern Dynasty itself has contributed $180 million to date, Thiessen said. The massive prospect is a world-class asset and Thiessen said he expects interest from a number of major mining companies. “We are seeking the right kind of partner to advance this project,” he told the RDC conference. When the AP asked how optimistic he was about finding a new partner and having the project in permitting this time next year, he said: “If I said 100 percent that would be a little less than what I really feel.”

Photo/Mark Thiessen/AP

Ron Thiessen, president and CEO of Northern Dynasty Minerals Ltd., addresses the lunch crowd in Anchorage during the annual Resource Development Council conference. Thiessen’s company is seeking a new partner for the proposed Pebble Mine in southwest Alaska after Anglo America PLC backed out of the project in fall 2013.

The company is now organizing the massive set of technical and environmental data that has been acquired over the last six years and will open a data room for prospective investors, Thiessen said. Northern Dynasty began getting calls from interested companies last fall, when reports were made that Anglo American would initiate an asset allocation review. “Anglo’s portfolio was rich in long-term projects, of which Pebble was one, and the company’s decision was to refocus on shorterrange projects,” Thiessen said. The decision had nothing to do with the quality of the Pebble prospect, which is one of the world’s largest undeveloped metals deposits. Pebble contains a copper-gold-molydenum ore with 5.9 billion tonnes that are in the measured and indicated category and 4.8 billion tonnes of additional resources that are inferred. The deposit is one of the world’s largest undeveloped copper prospects and the largest undeveloped gold prospect, Thiessen said. While Thiessen said Anglo’s departure from the project was a purely business decision, Pebble does face a host of local political problems, and opponents enlisted the U.S. Environ-

mental Protection Agency to do an assessment of regional environmental impacts. The assessment included a hypothetical large mine project and said it would lead to losses of valuable salmon-rearing habitat. Thiessen said the agency made no allowance for fisheries habitat restoration and enhancement that mining companies do routinely in Alaska and elsewhere in North America. Many of those are techniques endorsed by Trout Unlimited, one of the environmental groups opposing the mine. A large mine at Pebble would impact 16 square miles in a 42,000-square-mile region, an area the size of Ohio, he said. “We have identified many opportunities to enhance habitat and we believe we can not only offset any negative effects but leave fisheries habitat in an improved situation,” Thiessen said. The mine is located at the headwaters of two streams that flow into two of seven of the major salmon-bearing rivers in the Bristol Bay region. “Being at the headwaters is actually an advantage because the water flows are low, the See PEBBLE, Page 37

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State agencies consider control of wetland permitting process By Elwood Brehmer Alaska Journal of Commerce

A group of state agencies is evaluating what it would mean for the state to manage wetlands permitting for development projects. Wetlands permitting has largely been controlled by the Environmental Protection Agency under Section 404 of the Clean Water Act since it was passed in 1972. It is overseen by the U.S. Army Corps of Engineers. Section 404 requires “anyone discharging dredged or fill material in waters of the United States” to obtain a permit to do so from the Corps of Engineers. The state currently has a similar Certification of Reasonable Assurance granted it under Section 401 of the Clean Water Act that gives states the ability to review federal wetlands permit applications. In its last session, the Legislature passed Senate Bill 27, which directed the state to begin the process of filing the necessary applications with EPA and the Corps of Engineers to obtain wetlands oversight, or primacy. SB 27 also allocated resources to add staff to the Department of Natural Resources and the Department of Environmental Conservation to undertake the task. DEC Division of Water Director Michelle Hale told the Alaska Miners Association during a Nov. 7 presentation that DNR has five people working full-time on the effort and her agency has two with further help from Department of Law staff. Right now the agencies are going through a cost-benefit analysis to see if taking on

more permitting responsibility is worth it for the state, she said. Since the Clean Water Act was amended in 1977 to give states the option of wetlands primacy, only Michigan and New Jersey have taken advantage. DNR Deputy Commissioner Ed Fogels has said obtaining wetlands primacy would add about 30 full-time positions to the agency group and that cost is something that must be considered. Hale said the move would be right for Alaska, given the fact that the state holds 65 percent of the nation’s wetlands, which make up 43 percent of the state. Being the only state with permafrost, Alaska has wetlands that aren’t found anywhere else in the country, she added. “Decisions in Alaska — if we assume the 404 program — made by Alaskans, accountable to the State of Alaska,” Hale said. The state has recent experience in shifting permitting jurisdiction since it fully took over the Section 402, the National Pollution Discharge Elimination System program, in 2012. The application process for the primacy in NPDES began in 2003, Hale said, and the federal to state transition began in 2008. The Section 404 primacy process should be expected to take just as long as both require “many binders” worth of paperwork being sent to the Corps of Engineers and EPA, said Ruth Hamilton Heese, a senior assistant attorney with the Department of Law. Because the state already has primacy over Section 402 permits it could potentially combine the permits and issue one public no-

tice period, Hale said. “It provides us an opportunity to create clear and consistent regulations and there’s a real opportunity for regulatory integration,” she said. Regardless of who controls Section 404 primacy, the federal standards those working in wetlands must adhere to likely won’t change, and if they do, it would be to the side of environmental protection. The Clean Water Act requires state standards to be “no less stringent” than federal guidelines. The state also would not assume primacy over all wetlands inside its borders. Waterways considered navigable for commercial use and adjacent wetlands would remain under Corps of Engineers jurisdiction. Defining “adjacent” will be part of the back-and-forth of the primacy process, Hamilton Heese said. An area of the Section 404 permit that often causes consternation for project managers is its wetlands mitigation requirements. Anyone disturbing wetlands is required to improve an equal area elsewhere or pay the federal agencies for wetlands disruption. Hamilton Heese said the state would look at creative ways to “maximize the flexibility we can get in terms of (wetlands) mitigation” and still meet federal requirements. She suggested solutions such as fixing “perched” culverts in salmon streams to allow fish easier passage as a mitigation tool the state could allow that hasn’t been previously considered.

near Fairbanks, Red Dog Mine north of Kotzebue and the Greens Creek Mine near Juneau. Despite the world mining industry’s current problems, Thiessen is optimistic about Pebble. He believes major companies will shift back toward North America because of the investment environment is secure from threats like nationalizations. “There is the rule of law here, and Alaska offers a strict, but stable regulatory environ-

ment,” he said. Despite opposition from some local communities Thiessen believes people can be won over. The mine offers the prospect of being a major employer and taxpayer in a region of Alaska that is very economically depressed, he said. The Associated Press contributed to this article. Tim Bradner can be reached at tim.bradner@ alaskajournal.com.

Elwood Brehmer can be reached at elwood.brehmer@alaskajournal.com.

pebble

Continued from Page 34 streams are small and some actually dry up in winter. The streams are not highly productive habitat, either,” he said. Given that, there are many opportunities to minimize habitat impacts at the mine. If a mine were developed 21st-century water treatment processes would be involved, Thiessen said. He pointed to other modern Alaska producing mines as examples of successful water treatment management including the Fort Knox Mine

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Workforce will double on large LNG project By Tim Bradner Alaska Journal of Commerce

There will be another large field season to gather data for a proposed large North Slope gas pipeline and liquefied natural gas project, the company group working on the project said. The effort will put more than 300 people into the field next summer, and is about twice the size of the 2013 season, which included about 150, said Steve Butt, an ExxonMobil official who is project manager for the group that includes North Slope producers BP, ConocoPhillips, ExxonMobil, and pipeline company TransCanada. Exxon Mobil is leading the effort. Butt said work is also continuing on engineering, design and regulatory issues. Costs of the project are estimated at $45 billion to $65 billion, which will include a large Gas Treatment Plant on the North Slope, a 42-inch pipeline of about 800 miles, and a large LNG plant at Nikiski, on the Kenai Peninsula. Meanwhile, engineering and planning is continuing on a state-led 36-inch gas pipeline project on a route from the North Slope to Southcentral Alaska. Dan Fauske, president and CEO of the stateowned Alaska Gasline Development Corp., or AGDC, said his project is working toward a planned “open season” for potential gas shipping customers in early 2015. Of course, if the large gas project moves forward the AGDC project would not be built, as it is planned as a contingency to get North Slope gas to Alaska communities if the large project is delayed or cancelled. As for the larger project, Butt said that unstable discontinuous permafrost soil conditions along the pipeline route through Interior Alaska remain a serious concern and that work is underway on pipeline designs that will keep the 42-inch buried pipeline stable through the freeze-thaw cycle of soil temperatures. “Having TransCanada as part of our team offers a big benefit in addressing this. TransCanada has a long history in building gas pipelines in northern soil,” Butt told the conference. He said nothing, however, on whether the companies involved are close to agreements among themselves as to how to proceed with the project. Gov. Sean Parnell had asked the group earlier this year to reach such a commercial

agreement and to begin the Pre-Front End Engineering and Design, or pre-FEED, a step that would require a commitment of several hundred million dollars. The companies missed a milestone Parnell had set to reach the agreement and begin the pre-FEED work in June. In an earlier interview, however, new state Natural Resources Commissioner Joe Balash downplayed this, saying the design and engineering work the companies are now doing involve elements of work that would be done in a pre-FEED, and that he believes the companies are making progress toward the commercial agreement. “In some ways this is semantics. They are doing a lot of the work, but don’t yet want to call it pre-FEED,” Balash said. “What they may be waiting for is some signal from the state on a long-term fiscal agreement,” on tax and royalty terms for gas production, which the companies say they need. “There may be kind of a dance going on, with them taking incremental steps and waiting for us to respond,” he said. The state took a major step toward this Nov. 18 with release of a study by Black & Veatch, a consulting firm, outlining fiscal issues the project faces and steps the state can take to address those, including a possible state equity investment in the project. Butt defended the pace of the project in his Nov. 21 briefing, saying careful planning is needed in project management. “Good project management is all about reducing uncertainty and ensuring the project will work as expected for at least 35 years. This kind of assurance is needed to get customers to sign long-term contracts, and who have to have absolute confidence you will deliver every day,” he said. Butt outlined key accomplishments of the group so far including agreement on design concepts for a 42-inch pipeline, a three-train LNG plant at Nikiski that would ship 16 million tons to 18 million tons of LNG annually, and a Gas Treatment Plant at Prudhoe Bay that would be integrated into existing gas handling plant infrastructure. A “train” is a production module. “On previous efforts to build a gas pipeline the parties never gotten this far,” on technical aspects, Butt said.

One noteworthy accomplishment is agreement on how the large Gas Treatment Plant on the North Slope, itself a mega-project, can be built. “Detailed studies of how to integrate gas treatment facilities into the Prudhoe Bay gas plants, have never been done before,” he said. The GTP work required an integrated effort with the Prudhoe Bay producers, which involve the same companies with also others minority owners. That coordination between the gas project and the producer companies will continue because a key problem facing the project is finding some use for carbon dioxide that will have to be removed, which amounts to one-eighth of the raw gas. Using the CO2 in enhanced oil recovery in Prudhoe or other North Slope fields is currently being explored, Butt said. A major step for the project was the selection, this summer, of the site for the LNG plant at Nikiski, on the Kenai Peninsula south of Anchorage. The pipeline would now be parallel to the existing Trans Alaska Pipeline System from the North Slope to the state’s Interior and then branch off on a new route to Southcentral Alaska. At the Resource Development Council annual conference last fall, Butt mentioned more details about the LNG plant, that it would include three large LNG storage tanks, two loading berths and that an LNG tanker would be loaded every two days. On Cook Inlet marine conditions and navigation issues, Butt said, “We are still doing a lot of study on this but we believe we can it work. The ice is different in the Inlet. It is shore ice, and it is broken (by tides) and moves around,” but the group is satisfied that the ships can be moored safely. Marine pilots from several parts of the world are being consulted on the navigation issues, and the St. Lawrence River seaway in eastern North America is being studied as an analog, he said. Large crude oil carriers navigate the St. Lawrence seaway, where there is also ice similar to Cook Inlet, and tides. In addition to permafrost soils in the Interior, construction challenges for the pipeline include crossings of two major rivers, the Yukon See LNG, Page 50

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AIDEA signs deal to assist process plant for Niblack mine By Tim Bradner Alaska Journal of Commerce

The Alaska Industrial Development and Export Authority has signed an agreement with developers of the planned Niblack mine in Southeast Alaska to evaluate a mineral ore process facility in Ketchikan. The Memorandum of Understanding was signed between AIDEA, the state’s development finance corporation, and Niblack Project LLC, a subsidiary of Vancouver-based Heatherdale Resources Ltd. The Niblack project has been pursuing a plan to develop a multi-metals underground mine on southern Prince of Wales Island, and that includes shipping ore by barge to a plant near Ketchikan for processing. Typically a mine developer would locate the ore processing plant near the mine, but the location being considered near Ketchikan, at an industrial site on Gravina Island, would allow the plant to take advantage of lower-cost hydroelectric power that is available.

If the plant were at the mine site electricity would have to be generated with diesel. “The Niblack project has tremendous potential economic benefit to Southeast Alaska communities residents and businesses,” said AIDEA executive director Ted Leonard. “This is a unique opportunity to generate employment and economic activity on Prince of Wales Island and the greater Ketchikan area. We are pleased to work with Heatherdale in evaluating the responsible development of this project,” Leonard said in a statement. The mine would produce a mixture of copper, gold, zinc and silver metals and would employ about 150, if developed. The mineral processing plant near Ketchikan would employ about 80, AIDEA said in a press release. Niblack is a historic mine in Southeast Alaska, producing for several years in the last century. Heatherdale acquired the property and began a new round of exploration drilling in 2009, with the most recent drilling in 2012. The company is now planning another round

of drilling to prove up additional resources, with this work planned in 2014, according to Patrick Smith, president and CEO of Heatherdale. The company in working to attract additional investment capital to support the 2014 drilling, Smith said. Following that the project could move to a pre-feasibility study. “AIDEA’s involvement could be a great benefit to us,” Smith said in an interview. “The authority is looking at several alternative ways of helping finance the process mill including straightforward financing or a possible equity investment. AIDEA is also interested in infrastructure that could assist other users, he said. Heatherdale’s drilling to date has identified 5.6 million tonnes of ore in a category indicated by drilling, at certain cutoff grades for the ore, and 3.4 million tonnes of ore in a resource category inferred by drilling at certain cutoff grades. A tonne is a unit of measurement typically used in the mining industry that equals 2,200 pounds. A conventional ton is 2,000 pounds.

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State promoting simpler, more efficient regulatory process By Elwood Brehmer Alaska Journal of Commerce

The Department of Natural Resources is doing its part to promote simplified environmental permitting. Deputy agency commissioner Ed Fogels said he and other DNR staff have given upwards of 20 presentations in recent months explaining the state’s push to revise policy at an Alaska Support Industry Alliance meeting last fall. Gov. Sean Parnell initiated the push by directing former agency commissioner and current Republican Senate candidate Dan Sullivan to secure the state’s future oil and strategic mineral resources. Changes to the environmental permitting structure are essential to increasing resource investment and achieving the governor’s objective, Fogels said. “We believe the continued quest to improve on the permitting side is key to improving our investment climate,” he told the Alliance. DNR has highlighted five facets to improving environmental permitting: First on the list is maximizing efficiency in agency divisions. Fogels said there was a backlog nearly 2,500 permits awaiting adjudication in the Division of Mining, Land and Water when Parnell took office in 2011 — a number that has been cut roughly in half. Enhancing coordination between stakeholders in the permitting process of development projects is a key goal as well, according to Fogels. “We’ve learned over the years that one way that we can really help permitting move forward is to make sure everyone is in line and talking to each other as a team,” he said. A vital part of any government process is ensuring agency transparency and providing ample opportunity for public input and taking time to inform the public on how permitting is conducted, he said, to dispel common and detrimental myths and rumors. Improving coordination between the state and federal governments can aid in moving permitting along by reducing the amount of redundant requirements. Fogels said encompassing mandates such as the National Environmental Policy Act, or NEPA, can make it difficult to determine what state requirements need to be implemented. Lastly, he said the state needs to look ahead and prepare for prospective resource develop-

ment sites and techniques. Fogels specifically cited shale oil extraction and underground coal gasification as two things the State of Alaska needs to familiarize itself with so it can have appropriate environmental regulations in place if they become common activities in the state. To further standardize environmental permitting, the Division of Mining, Land and Water is taking steps to implement an automated permitting system, Fogels said, something he thinks can be used by other state agencies as well. The fear that reducing the time it takes to obtain permits and simplifying the process will result in haphazard development is unwarranted, Fogels said. The state’s primary goal is to eliminate unnecessary requirements and save money wherever possible to improve its business model, he said, common steps in the private sector. Fogels noted several times in his presentation that responsible resource development remains DNR’s top priority and said he’s proud of the agency’s ability to meld economic growth and environmental protection. “If you’re going to build a resource project or mine anywhere in the world and you’re concerned about protecting the environment, you should do it in Alaska,” Fogels said.

Legislation Parnell’s administration will be pushing several pushing several statute changes in this legislative session that, if passed, will alter future permitting activity, Fogels said. House Bill 77, currently in the Senate Rules Committee, has drawn criticism from interest groups, he said. If passed, HB 77 would restrict who is eligible to apply for a water reservation permit from DNR. Existing law allows for anyone capable of paying the $1,500 associated agency fee to apply. According to DNR, water reservations are designed to retain water in streams, rivers and lakes for the “public good” — uses including navigation, recreation and fish and wildlife habitat. “The change in HB 77 that we’re proposing simply deletes the word ‘person’ from the list of who can apply for and hold water reservations,” Fogels said. By limiting who can apply for water reservations to local, state and federal governments and

agencies, he said private interests would not be able to hold water “hostage” from other uses for the roughly five years it takes to collect data to adjudicate reservation permits. Rural village and tribal governments would still be able to apply for water reservations under HB 77. The legislation would not affect water rights or temporary water use permits regularly issued by the state, Fogels said. In an Oct. 14, 2013, state court ruling DNR was ordered to rule on three water reservations applications for the Chuitna River drainage by the Chuitna Citizens Coalition, a group that opposes development of a surface coal mine near the river on the west side of Cook Inlet. Chuitna applied for the reservations in 2009. The Superior Court decision does not dictate how DNR must rule on the applications, just that it must begin the process within 30 days. According to court documents, 51 of the 52 water reservations that the agency has granted have gone to the state Department of Fish and Game. Additionally, HB 77 would limit parties wishing to appeal a DNR decision from those are “aggrieved” to “substantially and adversely affected” by the decision. Fogels said too many parties currently appeal decisions simply do not agree with them, and that the appeals process takes up time that agency staff could use to expedite decisions on other cases. House Bill 129 would consolidate rulings in DNR’s Division of Oil and Gas exploration and development permits. Fogels said the bill would ensure timely approval of predictable permits. It would also allow for a comprehensive review of oil and gas activities prior to exploration or development, depending on a project’s phase, by looking at how actions might impact broader geographical areas with like characteristics rather than limiting review to each individual lease. Another oil and gas-centered proposal, House Bill 198 would empower the DNR commissioner to grant a one-time lease extension on oil and gas leases of up to 10 years if it is found to be in the best interest of the state. Extensions would be limited to leases with original terms of less than 10 years. Elwood Brehmer can be reached at elwood.brehmer@alaskajournal.com.

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KOGAS keeping an eye on Alaska LNG project developments By Bob Tkacz For the Journal

SEOUL — KOGAS, the national gas company of this resource-poor country, is watching Alaska’s natural gas pipeline construction efforts with interest in investing in the project as well as buying the fuel, according to senior company officials. “We are interested in the Alaska project but at this moment, actually, the timing is a little bit far away. We are willing to keep our eyes on the Alaska projects,” said Kwon Young, Korea Gas Corp. executive vice president and resources business division chief operating officer. In an exclusive interview at KOGAS headquarters here Nov. 26, Kwon and other company officers also said Alaska state officials and senior executives of the state’s three major energy producers have also visited, some repeatedly, in recent months. “They’ve already visited our company to propose something in the Arctic, such as LNG imports, said Lee Sung Wook, senior manager of the KOGAS Arctic Resources Project Team. In addition to Gov. Sean Parnell’s South Korea/Japan trade mission last September, ExxonMobil executives “visited KOGAS many times, two or three times,” in the past year while ConocoPhillips sent a delegation in April and BP in September, according to Lee. Kwon added, without specifics, that former Natural Resources Commissioner and current U.S. Senate candidate Dan Sullivan was also “very active.” The Alaskan producers suggested they could begin LNG production as soon as 2022, according to Lee. He declined to comment on the likelihood of meeting that timeframe. However, various ongoing transitions in the Korean energy scene also leave some of KOGAS’s near-term plans uncertain. A government owned corporation with revenues of $31.9 billion in 2012, KOGAS is the country’s exclusive importer and distributor of natural gas for home and commercial uses. A handful of large-scale industrial users like POSCO, ranked as the world’s fifth-largest steel producer, import natural gas for their own uses. A proposal from a previous national administration to privatize the country’s gas import and distribution died without a vote in the National Assembly.

“Most of the Korean people, they have big objection to open the market because if we go for the market as one entity we can get a big buying power for the procurement of energy. That was the background why the bill couldn’t have passed,” Kwon explained. South Korea, which has virtually no domestic energy resources, is also nearing completion of a reassessment of its future energy sourcing and use plans, partly driven by the ongoing mess at Japan’s Fukushima Daiichi nuclear power plant. Korea now produces some 11.2 percent of its electricity from nuclear generation, according to the Korea Energy Economics Institute, a government research agency. Pre-Fukushima plans called for an increase to nearly 41 percent. The draft version of the “Second Energy Basic Plan,” expected to be finalized by the end of this year, will recommend a contribution of 22 percent to 29 percent, according to Kwon. That increase would allows for the continuation of ongoing nuclear generation plans, but no increase. Korea’s demand for natural gas increased by an annual average of 8.07 percent over the decade through 2012 and accounted for 17.5 percent of Korea’s energy mix that year, also according to KEEI. The Korean people also opposed plans for high voltage transmission lines delivering power from centralized generating facilities. “Many people objected to lines near their villages,” Kwon said. “In order to mediate that the Korean government will try to build power plants just around the consumption area. “That means in order to disperse the power system we need to build LNG power plants.” Coal, now providing 28.6 percent of Korea’s energy, “is a problem in terms of environmental issues,” Kwon added. He said projections to increase renewable energy generation from the current 3.1 percent to 11 percent are unrealistic. As the country’s natural gas supplier, these developments suggest a bright future for KOGAS. “As a buyer, as a consumer we are willing to discuss and we are willing to keep eyes on any other energy projects,” Kwon said. Despite these developments, KOGAS, as of August, halted any new exploration and pro-

duction investments under orders from President Park Geun-hye, South Korea’s first woman president elected last year to the single fiveyear term allowed under its political system. “In the last four or five years we invested too much,” Kwon said. Lee, the Arctic resources manager, said his team, which have been focused on Russian and Danish/Greenland opportunities to date, has not been affected by the moratorium partly because most of its current activities are research-focused and partly because of the long lead team for project development in the northern latitudes. In response to the president’s directive, Kwon said KOGAS is re-evaluating its investment strategies after significant cost overruns in Australian gas projects in which it held a stake. That concern is also causing KOGAS to watch its significant investments in British Columbia. “There are so many projects on West Coast of Canada so we are worried about cost overrun like Australia,” Kwon said. Some 10 natural gas infrastructure projects are on B.C. drawing boards including the massive “LNG Canada,” nearing its first phase final investment decision. Korea, PetroChina, Mitsubishi and Shell Canada Ltd. are partners in the export terminal, planned to export 12 million tons of LNG annually from facilities near Kitimat, British Columbia, some 380 miles southeast of Juneau. LNG Canada, planned to allow double the start-up volume in future phases, is the most advanced of the B.C. projects. B.C. recently announced that its natural gas reserves are 2,900 trillion cubic feet, double previous estimates, and Premier Christy Clark made her second visit of the year to South Korea in late November as part of a major push for energy and other investment and other business partnerships. “Our natural resources and innovations make us your perfect partners,” Clark said at a luncheon following a three-hour presentation by B.C. government, labor and business leaders in Seoul on Nov. 29. Lee said the investment moratorium See KOGAS Page 50

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Pipeline

Continued from Page 24 Corp., the previous owner. Nelson said some of Hilcorp’s questions about the project are: • Will it reduce transportation costs for the shippers? • Does it reduce the risk of business interruption? • Will it affect Hilcorp’s ability to sell its product to a competitive market? Nelson said her company also has yet to see any “hard-line studies” that prove a pipeline would be a safer transportation method than a tanker. She noted that Hilcorp has a safe track record with transporting oil in the Inlet. “We’re being very cautious in involving ourselves in this process because we do want it to be based on sound science and research rather than a knee-jerk reaction to what may be a better option for the company,” Nelson said. However, Hilcorp’s door is open for conversation with Tesoro and Cook Inlet Energy, Nelson said. The pipeline has the support of local communities and conservation groups. The Cook Inlet Regional Citizens Advisory Council, or CIRCAC, a federally-chartered watchdog

group of municipalities and citizens, feels the pipeline is a safer alternative than the terminal and tanker shuttle operation because of the possibility of tanker spills and future volcanic activity at Redoubt, the council said in a report. CIRCAC supports the project, and sees it as a safer method of oil transportation than by tanker across the Inlet, said Jerry Rombach, director of the organization. He noted collisions with docks or ice as safety concerns that could force a tanker off a dock during loading or unloading. Such incidents have happened in Cook Inlet. Rombach also mentioned onboard fires and tank ruptures that as additional concerns with tankers. “Anything we can do to eliminate or reduce that risk, we want to see happen,” Rombach said. Following a Hilcorp June 2012 presentation to return up to two Drift River Oil Terminal storage tanks to normal service at the Christy Lee platform, CIRCAC responded with a July 2012 paper. The council stated it would prefer the company replace its terminal and tankers with a pipeline. CIRCAC supported the request to reopen the ter-

minal with conditions that the requested pipeline is constructed within five years. “We fully support the negotiations that would bring Hilcorp into some kind of partnership or some user relationship when the pipeline is built so that we don’t have that trans-foreland navigation issue any longer,” Rombach said. The 8-inch pipeline is designed with a transport capacity of 62,600 barrels per day. It is estimated to last 30 years, in coordination with the proposed lease, after which it would be evaluated for useful life, according to the project description. In its application, Trans-Foreland estimates about 130 construction jobs would be filled and 12 positions would be created to run the pipeline. Materials for the pipeline are estimated to cost $15 million and construction and installation is estimated at $35 million. Operation and maintenance is estimated at $5.2 million annually. Tim Bradner can be reached at tim. bradner@alaskajournal.com. Kaylee Osowski of the Peninsula Clarion contributed to this article.

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Lease sales

Continued from Page 11 state-owned submerged lands extending offshore, to the state’s three-mile territorial limit. Those tracts, near Eni Petroleum’s producing Nikaitchuq offshore field, were acquired by an affiliate of Denver-based independent Armstrong Oil and Gas, which has been active on the North Slope onshore. Jonne Slemons, deputy director of the Division of Oil and Gas said state officials were encouraged by the turnout by industry. “We were very pleased to see this much response in a well-developed area,” Slemons said. “There are very few ‘doughnut’ holes of unleased land left in the central North Slope

area. Now we’ll see what the companies so, and hopefully our rental rates will encourage them to get busy.” The state has an escalating schedule of lease rental rates that increases substantially in the ninth and tenth years of a 10-year lease, an incentive for companies to explore early, Slemons said. In the federal NPR-A sale independent NordAq dominated but ConocoPhillips bid on and won two tracts adjacent to acreage the company already holds with Anadarko Petroleum Co. in the Moose’s Tooth Unit in the reserve. In addition to NordAq’s bidding, individuals bid on

and won three NPR-A tracts. “We’re pleased that this sale came off in the context of our new NPR-A land management plan, which was adopted in February. Now we have a road-map for future lease sales in the reserve,” said acting U.S. BLM director Neal Kornze, who attended the Wednesday sale. BLM’s sale is the 13th lease sale BLM has had in the NPR-A since the reserve was opened to private leasing in the 1980s, Alaska Deputy BLM director Ted Murphy said. The NPR-A covers a 23-million-acre area of the western Alaska North Slope but only the central and northeast part of the reserve is open for leasing.

assumes that the bigger industry-led group fails, AGDC has estimated the cost of a 737mile, 36-inch pipeline and gas treatment plant at $7.7 billion, which includes $2.8 billion for the gas plant at Prudhoe Bay; $3.03 billion for the 36-inch pipeline to Dunbar, near Nenana in Interior Alaska; $70 million for a 12-inch, 35-mile lateral line to Fairbanks, and $1.8 billion for a remaining 36-inch pipeline from Dunbar to the Matanuska-Susitna region north of Anchorage where the pipeline could connect with existing pipelines owned by Enstar Natural Gas Co. The pipeline would operate with an operating pressure of 1,480 pounds per square inch, which is sufficient to transport some volumes

of propane along with methane, the component of natural gas used for fuel, Fauske said. The propane would find a ready market in Alaska. However, AGDC’s project is still limited to moving 500 million cubic feet per day of gas under the state’s current contract with TransCanada Corp., under the state Alaska Gasline Development Act, or AGIA. The current in-state demand for gas, mostly for utilities, is estimated at about 240 million cubic feet per day, so large industrial customers would have to be found to purchase the remaining gas.

settles regulatory, tax and other fiscal terms, and offers a good price is a glutted international gas market. “If the price is attractive, for instance, tax break for the project and some procedure (laws and regulations) adopted by the legislative body, and a clear policy and consistency of the LNG policy needed to make project attractive,” Kwon said. Kwon said Alaskan officials promoted investments in Prudhoe Bay and Point Thomson, but were not clear on the opportunities for the latter. “Frankly speaking, we have no clear idea,”

Kwon said when asked if Point Thomson was an attractive investment opportunity. Referring to Alaska’s unsettled natural gas tax terms Kwon said B.C., “has the same problem. They didn’t decide the tax structure but they said very soon they will fix the tax structure for LNG projects.” B.C. officials described “soon” as meaning “maybe one month later or two months later,” Kwon said.

LNG

Continued from Page 39 and Susitna rivers, a corridor through or near Denali National Park, and a crossing of Cook Inlet to the Kenai Peninsula. In previous interviews, Butt said Nikiski was chosen mainly because sufficient vacant land is available near existing industrial sites and infrastructure, and because weather conditions will allow year-round construction. In his presentation on the state-sponsored AGDC project, Fauske said his group has spent about $70 million on engineering and permitting to date and that the Legislature’s appropriation of $355 million earlier this year will allow the state corporation to complete engineering and design work that will be sufficient for the open season. If the project were to proceed, which

Tim Bradner can be reached at tim. bradner@alaskajournal.com.

kogas

Continued from Page 46 should be lifted around 2018, which fits Korea’s forecast energy demands and current contract schedules. Kwon said KOGAS expects to have new, long-term contracts in place by 2022 and that his personal opinion was that the Alaska gasline is unlikely to be operative before 2025, at the earliest. “We are focused on projects that can produce in 2018, 2019 ... The Alaska project, frankly speaking, there is nothing at this moment,” Kwon said. That the timeframe does not diminish KOGAS’s interest in Alaska gas if the state

Bob Tkacz is a correspondent for the Journal based in Juneau. He can be reached at fishlawsbob@gmail.com.

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