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2014 Kenai Industry Update Forum

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Kenai Industry Update Forum Challenger Learning Center of Alaska Kenai 301 Arctic Slope Ave. Ste. 350 Anchorage, AK 99518 P: 907-561-4772 F: 907-563-4744 www.alaskajournal.com

Regional Vice President Lee Leschper (907) 275-2179 lee.leschper@morris.com Managing Editor Andrew Jensen (907) 275-2165 editor@alaskajournal.com

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Production Manager Maree Shogren (907) 275-2162 maree.shogren@morris.com Cover and Layout Designer Nadya Gilmore (907) 275-2163 nadya.gilmore@morris.com Reporter Tim Bradner (907) 275-2159 tim.bradner@alaskajournal.com

Terrain, access to population ConocoPhillips applies centers drove Nikiski for export LICENSE selection............................ PAGE 9 to restart LNG plant.... PAGE 22

Reporter Elwood Brehmer (907) 275-2161 elwood.brehmer@alaskajournal.com

Hilcorp to spend $300M on Cook Inlet assets in 2014.................................. PAGE 10

Photographer Michael Dinneen (907) 275-2105 michael.dinneen@morris.com

Cook Inlet sees sharp increase in oil production, gas drilling..................... PAGE 13

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

Furie proceeds with plans for new Inlet platform, pipeline in 2014................. PAGE 16 Agrium applies for key permit to REOPEN plant . ........... PAGE 19 State: Don’t blame SB 21 For revenue decline.............. PAGE 20

ConocoPhillips hikes North Slope capital spending by 50%.............. PAGE 23 State forecasts big drop in revenues, oil production................ PAGE 26 AVTEC plans nation’s first ice navigation program ............................ PAGE 31 Parnell budget cuts spending as oil prices fall.................. PAGE 33

Cover illustration/nadya gilmore/ajoc

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Terrain, access to population centers drove Nikiski selection By Tim Bradner Alaska Journal of Commerce

North Slope producers and pipeline company TransCanada Corp. have selected a site at Nikiski on the Kenai Peninsula as the proposed terminus for a 42-inch North Slope gas pipeline and a large liquefied natural gas project. Nikiski is also the location of a smaller liquefied natural gas plant owned by ConocoPhillips that suspended operations when it allowed its export license to expire in 2012 because of lack of gas supplies from Cook Inlet fields. North Slope producers ExxonMobil, BP, ConocoPhillips and TransCanada, a pipeline company, selected Nikiski as the preferred site after evaluating 20 possible locations, the companies announced in fall 2013. Although numerous sites were being studied, Nikiski and Valdez were considered the lead contenders for the LNG plant. Valdez is the terminus of the TransAlaska Pipeline System and location of the Valdez Marine Terminal, and many Alaskans had expected Valdez to be chosen because of the existing terminal infrastructure and navigation advantages of Prince William Sound over Cook Inlet, which has winter ice and strong tides. The companies had a different conclusion, however. “The work we have put into the site selection process gives us confidence that the Nikiski site is the lead location for the LNG plant and terminal,” said Steve Butt, an ExxonMobil manager who is senior project manager for the gas pipeline and LNG project, in the release. “The Nikiski site also results in a pipeline route that provides an access opportunity to North Slope gas by the major population centers in Fairbanks,

Gas Treatment Facility Prudhoe Bay

Illustration/Nadya Gilmore/AJOC

The proposed route of a gas pipeline from the North Slope to Nikiski was chosen over the existing route followed by the TransAlaska Pipeline System that terminates in Valdez. The dotted line to Nikiski represents the portion of the pipeline that will pass under water through Cook Inlet.

the Mat-Su valley, Anchorage and the Kenai Peninsula.” In a later interview, Butt said he hopes the decision on Nikiski isn’t seen as a win-lose among Alaskan communities who were contenders to be the site, an indirect reference to Valdez. “It’s really a win for all Alaskans because we (the North Slope producers) have never been so close to an actual project, to the point that we will start acquiring assets, such as land,” Butt said. Valdez Mayor Dave Cobb said he was disappointed that his community wasn’t selected but if the decision moves a large 42-inch gas pipeline closer to reality, he’s all for it, he said. Valdez will continue to work with the producers’ group, he said. Cobb said his focus will now shift to the possibility of a spur pipeline so that gas can be brought from the main line to Valdez, Glennallen, Delta and other communities that now heat and generate power with fuel oil. “We’re still paying 38 cents a kilowatt hour and $4.90 a gallon for diesel here in Valdez,” he said. Butt said the simplicity of the geography at Nikiski, as well as better weather and access, were prime factors that also swung the decision to that location. “It’s flat land, which means less civil work to be done. The weather allows construction 12 months of the year, and the existing infrastructure allows for good access,” he said. Nikiski has been home to major industrial plants since 1969 when Unocal Corp. develop an ammonia and urea fertilizer plant, Phillips Petroleum and Marathon Oil developed an LNG plant to export Cook Inlet gas, and Tesoro Corp. See NIKISKI, Page 14

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Hilcorp to spend $300M on Cook Inlet assets in 2014

Photo/File/AJOC

Ships line up along the Cook Inlet shore at the Tesoro refinery, the ConocoPhillips LNG plant and the Agrium Inc. fertilizer plant in this Journal file photo. Existing infrastructure and an easier route near Alaska population centers drove the decision to select Nikiski as the terminus for a proposed 42-inch gas pipeline from the North Slope.

2014 Kenai Industry Update Forum By Elwood Brehmer

Alaska Journal of Commerce

Photo/File/AJOC

Production platforms at work in Trading Bay in northwest Cook Inlet. After taking over the assets of Chevron and Marathon, Hilcorp has helped boost Inlet oil production to more than 16,000 barrels per day and has signed natural gas contracts to supply local utility needs into 2018.

Renewed oil and gas investment in Cook Inlet has temporarily stabilized the Southcentral energy picture and Hilcorp Energy LLC Midstream Alaska Vice President Kurt Gibson laid out his company’s view of what must happen to ensure a stable future at a December Commonwealth North meeting. State investment incentives have helped push Hilcorp and other companies to increase activity in Cook Inlet, Gibson said. Oil production on Hilcorp’s properties was up 66 percent year-to-date in December 2013, he said. “I think most people looked at Cook Inlet as a depleted, dead oil basin and certainly from the perspective of Jeff Hildebrand, the guy that runs our company, that’s not the case,” Gibson said. Overall Inlet oil production was at 16,247 barrels per day in August 2013, up 32 percent year-over-year, according to the state Revenue Department. Hilcorp currently produces about 37,000 combined oil and gas barrels per day using an industry standard 6-to-1 gas equivalent ratio, Gibson said. From 2012-13, Houston-based Hilcorp acquired oil and gas parcels from Chevron Corp. and Marathon Oil Co. in Cook Inlet. Last July, within months after finalizing the purchase of its assets from Marathon, Hilcorp announced agreements with regional utilities to supply them with roughly 100 billion cubic feet, or bcf, of natural gas through the first quarter of 2018. Gibson said Hilcorp’s consent decree with the state is good through 2017 and that it affected the length of the supply contracts. It was then decided gas supply contracts shouldn’t end in the middle of winter and they were extended to early 2018, he said. “We’re ready to start having conversations with folks about 2018 and beyond when they’re ready to do that,” Gibson said. About $100 million of the $300 million worth of capital investment the company has planned for Cook Inlet in 2014 would go towards gas production, he said. In 2013 Hilcorp invested $300 million in the Inlet, making it the region’s largest investor, he said. “Ramping up investment has the desired effect,” Gibson said. “It’s not rocket science — you’ve got to turn the bit to the right in order to make gas come out of the rocks and we’ve been able to do that.” The independent company is able to get production out of waning oil and gas fields that wouldn’t move the “economic needle” for maSee HILCORP , Page 13

2014 Kenai Industry Update Forum

Oil production, gas drilling up in Inlet By Tim Bradner Alaska Journal of Commerce

Cook Inlet producer Hilcorp Energy LLC has seen its oil production increase sharply, from about 6,300 barrels per day in January 2012 to approximately 10,400 barrels per day in November 2013, the company’s president told the Resource Development Council’s annual conference in Anchorage. The company would not give specific numbers but the approximate ranges of the production increase were on graphics displayed by Hilcorp President Greg Lalicker in his presentation. Meanwhile, new natural gas development is on the upswing due to new drilling, according to Pete Stokes, with Petroleum Resource Associates, or PRA, a consulting firm that tracks Cook Inlet gas for regional utilities. In the 12-month period ending in August there were 11 new gas development wells drilled in the Inlet adding a total of 28.1 million cubic feet per day of production, with an average of 2.5 million cubic feet per day for each new well. “That’s a very good uptick in activity,” Stokes told the RDC. The wells tracked by PRA do not include new exploration wells drilled because those have not yet resulted in confirmed new gas reserves, although the explorers have made discoveries. The increase in oil production cited by Hilcorp, the Inlet’s biggest oil producer, gener-

ally matches the trend seen in total Cook Inlet oil production data reported by producers to the state Department of Revenue. The Revenue Department data shows total Inlet production at an average of 16,247 barrels per day in August 2013, up from an average of 11,000 barrels per day in August 2012. Inlet oil production had averaged 8,900 barrels per day for fiscal year 2010, which ended June 30, 2010, according to the Department of Revenue. Lalicker said much of the Hillcorp oil production increase came from the Swanson River and Trading Bay oilfields, two mature fields acquired from Chevron Corp. by Houston-based independent Hilcorp in 2012. Swanson River was discovered in 1957 and is still producing. It was Alaska’s first oil field in the modern era, and it ushered in an era of petroleum exploration and development in Cook Inlet, including the discovery of the Trading Bay field. “Some people say the Cook Inlet oil fields are dying. That’s not true — they’re just middleaged. There’s a lot more life left in them,” Lalicker told the RDC. Hilcorp initiated aggressive field redevelopment programs after acquiring Cook Inlet producing assets of Chevron Corp. and Marathon Oil Co. in 2012 and 2013. The company invested about $300 million in drilling and well workovers in 2013 and will likely invest a similar amount in 2014, Lalicker told the conference. The company brought four new rigs to Cook

Inlet in 2013, two drill rigs and two workovers rigs. Well workovers were increased to 70 so far in 2013, up from 48 in 2012. New well completions increased from 10 so far this year compared with 8 in 2012, he said. The new rigs arrived in the Inlet in mid-2013, so the well figures reflect only six months’ activity by the rigs, Lalicker said. Hilcorp has also been able to increase gas production in several mature producing fields acquired from Marathon. One example is the small Deep Creek field where production was approximately doubled from the time Hilcorp acquired the property earlier this year, Lalicker said. Gas production from Hilcorp-operated fields has generally tracked the seasonal swing in demand from regional utilities, he said. Cook Inlet was the center of industry activity in Alaska until the discovery of oil on the North Slope in 1969. The region saw little exploration until the mid-1980s and 1990s when independent companies began moving in. The region has seen a spike in new activity in the last two years with Hilcorp buying the mature producing fields and other independents like Armstrong Oil and Gas, Buccaneer Energy, Furie Operating Alaska and Alaskabased NordAq Energy exploring and making new gas discoveries. Apache Corp. is also exploring, with a focus on oil.

have happened in the past,” he said. The initial hope is to have approval from the Regulatory Commission of Alaska to make changes to the pipeline system by fall 2014, Gibson said. Hilcorp has tried to strengthen the relationship between Southcentral producers and utilities, he said, by opening up a “candid” dialogue with its customers. Longer term, Gibson said Hilcorp would welcome new markets for Cook Inlet natural gas. He noted that the mothballing of the Agrium Inc. fertilizer plant and ConocoPhillips liquefied natural gas export facility at Nikiski has capped gas demand at the roughly 90 bcf per year utilities need. That demand limit is something that also limits price and investment, Gibson said.

“Reserve numbers are also a direct consequence of price. Some reserves exist at certain price levels and when the price levels go up reserves that were otherwise technically but not economically recoverable suddenly become economically recoverable,” he said. An LNG export facility that allows multiple producers to sell gas could lift the current demand and investment constraints in Cook Inlet, Gibson said. When asked if he felt Cook Inlet producers could also supply in Interior Alaska’s gas demand, Gibson said, “Yes.”

hilcorp

Continued from Page 11 jor industry companies, he said. In January, Hilcorp plans to begin talks with stakeholders in its Inlet gas pipeline system about the best way to simplify the pipeline grid, Gibson said. Hilcorp’s pipelines include the Kenai-Kachemak, Kenai-Nikiski, Marathon Beluga and Cook Inlet gas gathering systems. Consolidating the pipeline system is a way to reduce overhead and regulatory burden for the companies that transport gas in it, he said. The goal is to limit regulatory rate cases to once every four years, but Gibson said no action would be taken without having everybody involved in agreement. “We’re not going to go through an arduous and uncivil (regulatory) process like those that

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

2014 Kenai Industry Update Forum

nikiski

Continued from Page 9 Photo/File/AJOC

Ships line up along the Cook Inlet shore at, from top to bottom, the Agrium Inc. fertilizer plant, the ConocoPhillips LNG plant and the Tesoro refinery in this Journal file photo. Existing infrastructure and an easier route near Alaska population centers drove the decision to select Nikiski as the terminus for a proposed 42-inch gas pipeline from the North Slope.

developed a refinery to make fuel products. The fertilizer and LNG plants are shut down because of gas shortages from Cook Inlet fields but new gas is being discovered in the Inlet there are discussions underway about reopening both plants. Tesoro’s refinery is still operating. The Valdez site has advantages, such as access to the ice-free Prince William Sound, but the topography is mountainous and winter brings very large snowfall, which would complicate construction. Butt said his group has done substantial ice modeling for Cook Inlet and feels any problems can be handled. The St. Lawrence Seaway was studied as a waterway that supports substantial tanker shipping and ice very similar to Cook Inlet, he said. Also, LNG tankers have operated safely for decades from the existing ConocoPhillips LNG plant. About 600 to 800 acres will be needed for the plant but Butt said the industry group would actually need about twice that amount of land to ensure safety and room for expansion. There is land available in the Nikiski area, some of it private land and some it municipal land, he said. Discussions have already started with some property owners. The most attractive site appears to be to be just the south of the closed Agrium Corp. fertilizer plant. The announcement raises questions, meanwhile, as to the future of the Alaska Gasline Devel-

opment Corp.’s plan to develop a state-led pipeline project along a similar route to Southcentral Alaska. The AGDC, a state corporation, is pursuing its project as an alternative to the larger industry-led pipeline, in case that project is delayed. Dan Fauske, CEO of the state corporation, said the announcement by the industry-led consortium is good news because it could lead to the AGDC folding its effort in with the producers-TransCanada project. “Obviously we’re not going to see two pipes laid side by side,” Fauske said. The state corporation could also become a vehicle for the state investing in and owning an equity stake in the larger pipeline, he said. The state laws governing the state gas corporation allow for that possibility. Meanwhile the ADGC is continuing its work, Fauske said, because it’s not yet certain that the larger industry-led pipeline will really go forward. Nothing changes for now in the state corporation’s scope of work or budgets, he said. ADGC is studying a possible 36-inch gas pipeline that would move 500 million cubic feet of gas per day, a smaller project than the industry pipeline, which would move about 3.5 billion cubic feet per day. Meanwhile, Butt said several engineering and technical, commercial and regulatory issues remain to be settled for the producers and TransCanada. “While Nikiski is the lead site for the LNG

plant, the project team continues to consider other, secondary locations. Pipeline routing definition work also continues based on the summer field work activity, which will be extended south of Livengood,” in the Alaska Interior, Butt said. Fiscal terms for gas production, which include production tax and royalty, also need to be settled before the large pipeline plans can be finalized. After the producers missed one of Gov. Sean Parnell’s benchmarks by not advancing to a pre-feasibility, engineering and design stage by June 30, he said he wouldn’t bring the topic of gas tax terms to the Legislature in 2014. The companies are continuing to refine the agreed project concept that includes a gas treatment plant on the North Slope, an 800-mile, 42-inch gas pipeline with up to eight compressor stations, and at least five gas take-off points for in-state gas delivery, and a liquefaction plant and terminal. The pipeline would transport about 3.5 billion cubic feet of gas daily to the LNG plant, which would manufacture and ship 16 million to 18 million tons of LNG yearly primarily to markets in Asia, the companies have said previously. Construction costs are estimated from $45 billion to $65 billion, and possibly more, the companies have said. Tim Bradner can be reached at tim.bradner@alaskajournal.com.

2014 Kenai Industry Update Forum

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By Tim Bradner Alaska Journal of Commerce

The U.S. Army Corps of Engineers has issued a key permit for a new natural gas production platform in Cook Inlet planned by Furie Operating Alaska, a Houston-based independent company exploring for oil and gas in the Inlet. Under the permit, which was issued Nov. 27, 2013, Furie will be allowed to proceed with its plan to install the platform in the summer of 2014 and to build a subsea gas pipeline to connect with existing onshore pipelines on the east side of Cook Inlet. State permits and a right-of-way for the pipeline must still be secured from the Alaska Division of Oil and Gas. Furie Operating Alaska is the operator of the Kitchen Lights Unit, which included leases on 83,000 acres of state-owned submerged lands in Cook Inlet. Cornucopia Oil and Gas Co., which owns the leases, is Furie Operating’s parent company, according to information on Furie’s website. Duetsche Oel & Gas AG, based in Stuttgart, Germany, acts as holding company for Cornucopia and Furie Operating. Furie would not comment on its exploration and development activity, which is its policy, but persons familiar with the company’s plans said the platform is now being fabricated in Corpus Christi, Texas, and that it will be brought to Cook Inlet in late spring for installation during the summer. The Corps “Section 10” permit, issued under the federal rivers and harbors act, has stipulations regarding disturbances to endangered beluga whales and Steller sea lions, according to Heather Boyles, project manager in the Corps Alaska regulatory affairs group. The platform will be the first new offshore production facility built in the Inlet since the mid-1980s when the Osprey platform was built by Forest Oil Corp. at the Redoubt Shoal field in west Cook Inlet. State officials said they have reviewed Furie’s preliminary plans for its platform and pipeline. “They have been talking with us informally for several months, discussing different aspects of the platform and pipeline designs. We’re looking carefully at the level of expertise they are bringing to bear on the project,” said Dave Norton, director of the state Petroleum Systems Integrity Office, a group that oversees production facilities. A particular focus has been on the platform’s ability to withstand the combined forces of tides, moving winter ice and winds in Cook Inlet.

Furie proceeds with plans for new Inlet platform, pipeline in 2014 Cook Inlet has long been dominated by major companies that built high levels of construction and operating expertise over several decades, but independents like Furie are now exploring and making discoveries. Given the limited experience and thin finances of smaller companies compared large firms, state regulatory agencies like the Division of Oil and Gas and the Alaska Oil and Gas Conservation Commission closely monitor work by independents, particularly on offshore projects. Furie, Buccaneer Energy and Cook Inlet Energy are three small companies now engaged in offshore development in the Inlet. According to information in the Corps permit, Furie’s platform would be installed near the location of the company’s Kitchen Lights Unit No. 3 well, which is near the company’s KLU No. 1 gas discovery drilled in 2011. Furie drilled three other wells in 2012 and 2013, including

KLU No. 1 and KLU No. 3 to confirm the discovery and also test nearby prospects. The company has been using Spartan Drilling Co.’s Spartan 151 jack-up rig in its exploration and will also use the jack-up rig to assist with drilling production wells for the platform, although a small rig will also be located on the platform. The installation itself will be done with a conventional support equipment including a derrick barge. The platform would rise 62 feet above mean sea level, and would support a 64.5-foot by 72foot production deck and main deck. Two 10inch pipelines would be built from the platform to shore following the corridor of the Cook Inlet Gas Gathering System, two cross-Inlet 10-inch pipelines now used to carry gas. Furie’s exploration attracted a great deal of attention in 2011 when it released initial results of its KLU No. 1 well that indicated that as much

2014 Kenai Industry Update Forum

Photo/File/Peninsula Clarion

Tugs pull the Spartan 151 jack-up drilling platform near Nikiski after it arrived in Cook Inlet in 2011. Furie Operating Alaska used the Spartan 151 to explore in the Kitchen Lights Unit in 2012 and 2013, and now has applied for a permit to build the Inlet’s first offshore production facility since the mid-1980s when when the Osprey platform was built by Forest Oil Corp. at the Redoubt Shoal field. Furie plans to install the platform this summer.

as 3 trillion cubic feet of gas could be present in the Cook Inlet reservoirs it was targeting. The company, which is privately-owned, later revised the estimate of possible recoverable resources downward to a lower number and has since released no estimates or results of its drilling. Furie also attracted attention as the first company to bring a jack-up rig to the Inlet after years of efforts by its predecessor company, Escopeta Oil and Gas. Escopeta had arranged with Spartan Drilling Company of Texas to bring that company’s rig to Alaska on a heavy-lift vessel, a specialized ship designed to carry heavy and bulky cargoes. The move sparked controversy because the Department of Homeland Security had refused to renew an exemption from the U.S. Jones Act, a reversal of the position the agency took in 2006 when an exemption was issued when Escopeta made an earlier attempt to bring a

jack-up rig north. When the latest effort was made, in 2010 and 2011, there were no U.S.-built heavy-lift vessels available that could safely navigate stormy waters during a transit around the Cape of Good Hope, Escopeta claimed. This was disputed by some U.S. marine transportation firms like Crowley Maritime, but Escopeta loaded the rig. It changed its plan and made the voyage to Vancouver, B.C., using a Chinese-owned heavy-lift vessel chartered for the trip. The jack-up rig was offloaded in Canadian waters for maintenance and a month later was transported to Alaska by U.S.-owned tugs. Nevertheless, the Department of Homeland Security charged that a violation of the U.S. Jones Act had occurred. Even though the Chinese ship went from the U.S. Gulf to a Canadian port, the jack-up rig was destined to ultimately

arrive in Cook Inlet. The Jones Act requires cargoes shipped between U.S. ports to be on ships that are U.S.-built and manned. The agency assessed a penalty against Escopeta. Meanwhile, in 2012 another independent, Australia-based Buccaneer Energy, brought a second jack-up rig to the Inlet from Singapore, also using a Chinese-operated heavy-lift ship. Because the rig, the Endeavour, was transported from a foreign port, there was no violation of the Jones Act. Both jack-up rigs have been busy since arriving in the Inlet, however. Buccaneer drilled at its “Cosmo” prospect near Anchor Point earlier this year made a natural gas discovery. The company is now working on plans for further drilling and possible development. Tim Bradner can be reached at tim.bradner@alaskajournal.com.

2014 Kenai Industry Update Forum

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2014 Kenai Industry Update Forum

Agrium applies for key permit to reopen plant Photo/File/AJOC

The Agrium Inc. fertilizer plant at Nikiski is seen in this Journal file photo. The company has applied for a key air permit, a necessary step should the plant be restarted now that natural gas supplies are increasing in Cook Inlet. The plant closed in 2007 after operating for several years at partial capacity.

By Tim Bradner Alaska Journal of Commerce

Agrium Inc. has applied for an air quality permit for a restart of its closed fertilizer plant at Nikiski. The company has been researching the possibility of a restart for some time and says the application, made Oct. 24, 2013, to the state Department of Environmental Conservation, is to get the permit procedure underway so the company can move quickly if a decision is made to reopen the plant, Agrium spokesman Adam Diamond said. “At this stage we have made no decision, but the PSPD (air permit) can take a year or more to secure, so we thought it prudent to go ahead and start the process so we’re in a position to move,” Diamond said in an interview. “There are a lot of moving parts to this, but having the air quality permit in hand will give us a jump.” John Kuterbach, program manager in DEC’s air quality division, confirmed that the application had been made. “Agrium has submitted an air quality ap-

plication for restarting the ammonia and urea plant and supporting utility portions of the Nikiski fertilizer plant,” Kuterbach wrote in an email. “Because the plant was permanently shut down (in 2007), this restart is being permitted as a new facility, and it requires preconstruction monitoring data before a permit can be issued. Agrium is currently collecting this data. We expect to complete permitting by next fall.” Diamond said the air quality permit is needed before any construction activity at the plant can occur. The permit is required by the federal Clean Air Act and it is administered in Alaska by the Department of Environmental Conservation. Diamond also said Agrium has recently completed an initial technical screening of the plant’s condition, and that the company will likely initiate further engineering reviews next spring. If the plant is restarted, it would likely involve one of two ammonia and urea production units, or “trains” that are in the plant. Mostly likely a newer unit that was built in 1977 will be targeted for restart. The older unit, built when the plant began operation in 1969, is not part of

the restart plan, at least for now. The capacity of the newer train, when it operated, was 630,000 metric tonnes of ammonia and 608,000 metric tons of urea annually (a tonne is 2,200 lbs). Agrium was a major employer and taxpayer in the Kenai Peninsula Borough in the years the plant operated. For many years it was also one of the largest fertilizer plants in the world and sold mostly in export markets. In the final years it operated Agrium began having difficulty securing enough natural gas to manufacture at full capacity because Cook Inlet gas reserves were being depleted. For a period the plant limped along at partial-capacity, operating seasonally so that regional utilities could get the gas available in winter. Eventually the plant closed in 2007. Since then Agrium has continued with certain critical maintenance, however, with a small skeleton staff of maintenance technicians. Tim Bradner can be reached at tim.bradner@alaskajournal.com.

2014 Kenai Industry Update Forum

State: Don’t blame SB 21 for revenue decline

AP Photo/bill ross/Anchorage daily news

Gov. Sean Parnell signs the oil tax reform Senate Bill 21, the More Alaska Production Act, into law during a special meeting of the Anchorage Chamber of Commerce at the Dena’ina Center May 17, 2013. Oil revenues are forecast to drop sharply in the 2014 fiscal year, but the state Revenue Department points to increasing production and transportation costs along with decreasing prices per barrel as the cause. The revenue effect of SB 21 is essentially neutral compared to the previous tax regime known as ACES.

Analysis by Tim Bradner Alaska Journal of Commerce

The oil tax law touted as guaranteeing Alaska a bigger slice of the profits pie when oil prices rise may well have boomeranged. A “progressivity” formula in the current law, known as ACES, ratchets up tax rates on oil profits sharply when prices rise. But it works the other way too. When oil values fall, the tax rate falls fast, and so do revenues. That has now happened. The ACES tax with the progressivity formula was replaced by a new state oil tax, without the formula, in Senate Bill 21 passed by the Legislature last April. It took effect Jan. 1, meaning ACES was in effect for the first six months of the current fiscal year that began July 1, 2013. Critics complained the tax change would result in big revenue drops. The $2 billion revenue drop this year is now being blamed on SB 21. It isn’t actually working out that way, however. Under current oil prices and costs, the ACES formula actually imposes a lower tax rate on oil than does the new law in Senate Bill 21.

For this year and next, at least, the tax change appears to be largely neutral. Former state tax director Dan Dickenson, who served under several Alaska governors, said he has not yet had time to study the revenue estimate in detail but that he knows the mechanics of ACES and can understand what is likely to be happening. “I don’t endorse the governor’s interpretation of the tax effects, but the situation doesn’t surprise me,” he said. Here are some specifics: According to the latest state revenue forecast released Dec. 5, 2013, the effective tax rate under ACES is 34.9 percent of the per-barrel net income. That’s compared with a 35 percent base tax rate when SB 21 took effect Jan. 1. The base tax rate under ACES is 25 percent, with the effective tax rate increasing under the progressivity formula. Under SB 21, the base tax rate was increased to 35 percent and the progressivity formula was dropped. For fiscal year 2015, the budget year beginning July 1, 2014, the tax rate under SB 21 remains at 35 percent while the tax rate that

would have been imposed by ACES, were it to remain in effect at the price and cost forecasts by the Revenue Department, would drop to 32.6 percent of per-barrel net income. The implication of this is that even if the Legislature had not passed SB 21 the $2 billion slide in revenues from last year would have happened anyway, says Deputy Revenue Commissioner Bruce Tangeman. Critics of the tax change are having a hard time with this. In a press release, the Alaska Democratic Party said: “The governor’s office claimed that falling oil prices were primarily responsible for reductions in revenue. However, DOR (the Department of Revenue) projects a mere 4 percent reduction in oil prices compared to a 31 percent reduction in General Fund revenue, meaning that oil prices are not responsible for the lion’s share of lost revenue.” Things are more complicated, however. The Democratic Party is correct that oil prices are not by themselves responsible for the $2 billion revenue drop, but what isn’t mentioned are other factors at work: the rising production and transportation costs and that oil production is declining sharply. Documents provided by the Department of Revenue show that the oil price assumption in the revenue forecast issued last spring dropped from $109.61 per barrel to $105.68 per barrel in the fall 2013 forecast. However, the estimated production costs rose $454 million for fiscal year 2014 between spring and fall forecasts and the per-barrel transportation cost (pipeline and tanker fees) rose $1.24 per barrel between spring and fall, from $8.87 per barrel in the spring to $10.11 per barrel in the fall. What can drive up transportation costs fast is declining volume, because the fixed costs of operating a pipeline or a tanker are spread over fewer barrels. All of these factors combined have sharply reduced the average net revenue per barrel — the value on which the net profits tax is applied — which was reduced between the spring and fall forecasts by $9.23 per barrel for fiscal year 2014 and $14.90 per barrel in fiscal year 2015. It is the lower per-barrel value of the oil, under the forecast, that results in a lower effecSee SB

21 , Page 26

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ConocoPhillips applies for export license to restart LNG plant By Tim Bradner Alaska Journal of Commerce

ConocoPhillips Alaska Inc. has filed an application with the U.S. Department of Energy to resume LNG exports from Alaska, the company announced in December. The company plans to reopen its mothballed liquefied natural gas plant at Nikiski, on the Kenai Peninsula, to operate on a seasonal basis, spokeswoman Natalie Lowman said. The company has also installed equipment at the plant to allow trucks to be loaded with LNG for delivery within Alaska, she said. “With support from many local stakeholders, and in consideration of a request from the State of Alaska, ConocoPhillips Alaska has submitted an application to the U.S. Department of Energy to resume exports of LNG from

the Kenai Facility. The application was submitted Wednesday, December 11, 2013,” Lowman said in a statement. “We do not anticipate having gas available for export in the winter,” she said, because regional utilities will be given a priority. The company has applied for a two-year export authorization to export about 20 billion cubic feet of gas per year as LNG, Lowman said. Responding to warnings of gas shortages, the state Legislature enacted oil and gas subsidies that pay up to two-thirds of the cost of new exploration and development, which attracted several new players to Cook Inlet. Given the recent discoveries made in the Inlet by the independent companies, State Natural Resources Commissioner Joe Balash wrote a letter in September 2013 to ConocoPhillips asking the plant be restarted to provide a mar-

ket for companies exploring for natural gas. Balash also asked for the plant to be equipped with the equipment to load trucks, which ConocoPhillips has done. Independent oil and gas companies exploring in Cook Inlet said they were pleased at the announcement. Buccaneer Energy and Furie Operating Alaska, two independents, have made gas discoveries and Furie is confident enough in its discovery that the company plans to install a gas production platform and a pipeline next summer. Buccaneer Energy has also made a gas discovery offshore from Anchor Point, on the east side of Cook Inlet. The discovery is still being evaluated for possible development, however. See lng

plant, Page 25

2014 Kenai Industry Update Forum Photo/File/Peninsula Clarion

The liquefied natural gas tanker Polar Eagle is seen in Cook Inlet in this file photo. ConocoPhillips announced in December that it was seeking a new permit from the U.S. Department of Energy to resume LNG exports from its plant in Nikiski. The previous export license was allowed to expire in 2012 based on low supplies of gas in Cook Inlet. The Alaska Department of Natural Resources asked the company to restart the plant in a September 2013 letter, citing increased supplies and a needed market for producers.

C-P hikes North Slope capital spending by 50% By Tim Bradner Alaska Journal of Commerce

ConocoPhillips is ramping up its Alaska investments sharply. The company increased its 2014 Alaska capital budget by more than 50 percent, to $1.7 billion, and will drill two new exploration wells this winter in the National Petroleum Reserve–Alaska, company spokeswoman Natalie Lowman said. Spending this year will be on projects that

are expected to add about 54,000 barrels per day in new North Slope production by late 2017. About 38,000 barrels per day would be produced by projects approved since the Legislature amended the state’s oil production tax last April. Lowman said one development in the 2014 budget that is now under construction, the CD-5 project in the National Petroleum Reserve-Alaska, was approved by the company before state lawmakers made the tax change in

Senate Bill 21. “Alaska projects will get about $600 million more than in 2013, when our capital budget was about $1.1 billion, Lowman said. “Our capital spending next year will be more than double the $828 million spent on projects in 2012.” The company’s 2014 capital budget was approved by its board and announced Dec. 6. ConocoPhillips credited the state’s new oil production tax law, which went into effect Jan. 1, for stimulating overall new investment. “Higher allocation of capital to Alaska compared to 2013 reflected improved fiscal terms from passage of the More Alaska Production Act (SB 21),” the company said in a Dec. 6, 2013, press release. While much of the 2014 budget is allocated to the CD-5 project, preparations on several other new projects are also underway, Lowman said. The company has also authorized two new drill rigs to drill additional development wells in the Kuparuk River field since the passage of SB 21. One rig started work last May and the second is set to begin drilling in February. CD-5 is expected to begin producing in late 2015 and is expected to produce about 16,000 barrels per day, or b/d. The project will cost about $1 billion and includes a bridge across a channel of the Colville River and new roads, pipelines and a production site on the west side of the river. CD-5 will be also the first commercial oil production project in the NPR-A. ConocoPhillips is also laying gravel and making other preparations for a planned new drill-site in the Kuparuk River field, Drill Site 2S. Formal approval for that is expected in late 2014. Production is estimated at 8,000 b/d, starting in late 2015. Permitting and other preparations are also continuing on GMT-1, a $900 million project in the NPR-A. It is expected to be producing 30,000 barrels per day by late 2017, Lowman said. Overall, the new projects planned by ConocoPhillips are expected to add 54,000 barrels a day of new production by late 2017 but only part of this is net to ConocoPhillips because some of the new production will be shared with partners in the new projects. ConocoPhillips owns 55 percent of Kuparuk, with BP, ExxonMobil owning most of the remainder, as well as 78 percent of CD-5 and GMT-1 with Anadarko Petroleum owning the remainder. The two new NPR-A exploration wells are planned to be drilled in ConocoPhillips’ Greater

See

CONOCOPHILLIPS, Page 29

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LNG

Continued from Page 22 Hilcorp Energy, another independent which now operates former Chevron and Marathon Oil producing wells, has invested and developed more gas from the aging fields, as has Cook Inlet Energy, also an independent, which is redeveloping wells on the Osprey platform and West MacArthur River field on the Inlet’s west side. Additional markets for Cook Inlet gas are needed because Hilcorp has signed supply contracts with local utilities that run into 2018. One new Hilcorp supply contract is with Matanuska Electric Association, an electric utility serving the Matanuska-Susitna Borough north of Anchorage. It begins in 2015 and would supply up to 7 billion cubic feet of gas per year, MEA general manager Joe Griffith said. The price has been set at $7.13 per thousand cubic feet, or mcf, for the first year and would escalate at 4 percent per year through the end of the contract in March 2018, with a price of $8.03 per mcf in 2018, according to Tony Izzo, MEA’s gas supply manager. The gas would supply a new, 170-megawatt power plant MEA now has under construction that is to begin operation in January 2015. Until now the utility has not secured a supply of gas for the plant, although it is duel-fuel and can also operate on oil. “Securing this contract represents the ability to keep the lights on at the lowest cost to our members, which is our goal for everything we do,” Griffith said. Meanwhile, Hilcorp spokeswoman Lori Nelson said a second contract has been concluded with Chugach Electric Association, the state’s largest electric utility, to supply 2.5 billion cubic feet to 8.5 billion cubic feet per year. The Chugach contract begins in 2014 and also terminates in March 2018, for a total volume of 17.6 billion cubic feet, utility spokeswoman Sarah Wiggers said. The price terms are the same that Hilcorp has agreed to with MEA. Enstar Natural Gas Co.’s new contract with Hilcorp provides for the supply of volumes of gas ranging from 10 billion cubic feet in the first year of the contract to 21.5 billion cubic feet in the last year. The new contract runs from April 1, 2014, to March 31, 2018. In a statement, Buccaneer CEO Curtis Burton, said he was pleased: “ConcocoPhillips applying to the U.S. Department of

Photo/File/Peninsula Clarion

An aerial view of the ConocoPhillips LNG plant in Nikiski is seen in this Peninsula Clarion file photo. After ceasing operations in 2012, ConocoPhillips has applied to the US Department of Energy to export 40 billion cubic feet over two years.

Energy to resume LNG exports from Alaska is a very good move for them, for the State of Alaska, and for independents in the Cook Inlet. Assuring a market for natural gas near term is critical to ensuring that the Cook Inlet has enough gas to satisfy local needs both now and in the future.” Although production of LNG and exports were suspended the plant has been maintained for a possible restart and no reductions of per-

sonnel were made, ConocoPhillips has said. The plant was built in 1969 by Phillips Petroleum and Marathon Oil Co. Phillips merged with Conoco to become ConocoPhillips and, more recently, Marathon sold its share of the plant to ConocoPhillips. The plant operated until 2012 when the export license expired and declining gas production in Cook Inlet limited amount of gas available.

2014 Kenai Industry Update Forum

State forecasts big drop in revenues, oil production Journal of Commerce The state Department of Revenue released the fall 2013 state revenue estimates Dec. 4, 2013, and predicted a $2 billion decline in state unrestricted general fund revenues in fiscal year 2014, the current budget year. Unrestricted general fund revenues are those available to the Legislature for appropriation. The reduction is driven mainly by lower oil prices, oil production that is falling faster than expected, and higher production and transportation costs for oil. A new state oil production tax passed by the Legislature last spring appears to have little impact, Gov. Sean Parnell said. “At these lower oil prices, the More Alaska Production Act (the new oil tax) produces revenue streams to the state similar to the former oil tax system, ACES,” Parnell said in a statement. Revenue Commissioner Angela Rodell acknowledged the reduction: “This is a significant revision to our unrestricted revenue from the previous forecast,” she said. “It is clear that the single-most influential contributor to the revision is a reduced oil price

expectation. The elimination of progressivity (a formula in the oil tax law) and capital credits are roughly offset by the increased 35 percent base rate and new per-barrel credits under the More Alaska Production Act. Alaska will see, at forecasted prices, a similar revenue stream between the current and previous oil tax systems.” The Department of Revenue reports that the state received a total of $15.8 billion in fiscal year 2013, he budget year ending this past June 30, from all sources. Of this total, General Fund unrestricted revenues totaled $6.9 billion, with oil revenues accounting for approximately 92 percent of all unrestricted revenue. The revenue department is now forecasting unrestricted revenue of $4.9 billion and $4.5 billion for fiscal year 2014 and fiscal year 2015, respectively. The revenue forecast is based on an Alaska North Slope oil price of $105.68 per barrel for fiscal year 2014 and $105.06 per barrel for fiscal year 2015. While North Slope oil production declined 8.2 percent in fiscal year 2013, the department is forecasting a 4 percent decline in the current

year, fiscal year 2014, and a 2 percent decline next year, fiscal year 2015. The flattening of the production decline assumes, however, a certain amount of new production resulting from new industry activity on the North Slope spurred by passage of the new tax law. BP and ConocoPhillips, the two major North Slope field operators, are putting four new drill rigs to work in the Prudhoe Bay and Kuparuk River fields and are pursuing other in-field work that the state believes will result in new production in the near-term. The companies have also announced about $4.5 billion in new projects that are expected to add about 55,000 barrels a day in new production by 2018. That new production is not included in the production forecast, however, because the investments have not yet been made, state revenue officials said. Rodell said that “while we see longer, more extensive summer maintenance projects, in-

Meanwhile, the production decline is happening faster than the revenue forecasters predicted. Last year North Slope oil production dropped 8 percent compared with the year prior. Revenue Commissioner Angela Rodell said the lower productivity of the aging North Slope wells, longer periods of plant shutdowns for maintenance and the diverting of some natural gas liquids for enhanced oil recovery were factors in last year’s decline. Many of the gas liquids are mixed with crude oil and shipped through the Trans-Alaska Pipeline System but last year more of them were used in the fields to produce more oil. Some of the liquids may be returned to the TAPS oil stream this year, she said. Tuck said last year’s decline was not a normal case because there was an unusually heavy facility maintenance program in the summer of 2012, and the pipeline shutdowns related to that had big effects on the annual production numbers. The long-term averages

have been closer to 5 percent or 6 percent per year, he said. The new production forecast calls for a flattening of the production decline to 4 percent this year and 2 percent next year, but that assumes that the recent surge of development work in the fields, resulting from the tax change, translate into new oil bring shipped through TAPS. The new forecast is for production to average 508,000 barrels per day for the current fiscal year. That’s down from an average of 527,000 barrels per day estimated in the spring forecast. For fiscal year 2015, the new forecast is for an average of 498,000 barrels per day, the first time the production average has dipped below 500,000 barrels per day. This is down from 513,000 barrels per day estimate for fiscal year 2014 in last spring’s forecast.

See forEcast, Page 29

revenue

Continued from Page 20 tive tax rate under ACES than under SB 21. State Rep. Chris Tuck, D-Anchorage, argues that the cost data being used in the forecast should be viewed with caution because these are provided by industry and cannot be verified. “ACES has a steep curve (of progressivity) and the only way to bring revenues down sharply is to over-inflate the costs,” Tuck said. “The fact is that we have never had a completed audit of tax returns under ACES. The last audit we’ve had was under the Petroleum Profits Tax, the tax system that preceded ACES.” While audits check past expenditures claimed against taxes and the future cost estimates provided by industry to the department are forward-looking, having the past audits done would give the revenue department some kind of trend to truth-check information being supplied by industry, Tuck said. “We just can’t take industry’s word. Every time we’ve done that we get into trouble. We have to have a way to verify it,” he said.

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

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conocophillips Continued from Page 23

Moose’s Tooth Unit in which the GMT-1 project is located, Lowman said. The drilling is aimed at establishing new resources in the unit. The company is planning a second NPR-A production project in the unit, GMT-2, sometime in the future, ConocoPhillips officials have said. Overall, six exploration wells are now planned for the North Slope this winter. Two will be drilled by ConocoPhilllips; three by Repsol in the Colville River delta region and one by Linc Energy at Umiat, in the southeast NPR-A where a small oil field was discovered decades ago but not developed. ConocoPhillips Alaska president TrondErik Johansen told the Resource Development Council annual conference in Anchorage in November that his company plans about $1.5 billion in new capital investments over the next few years. Separately, BP has announced about $3 billion in new projects in the Prudhoe Bay field along with plans to put two new drill rigs to work in the field.

CP gets busy at CD-5 Things are getting busy at the Alpine oil field on the North Slope. Alpine is the staging area for ConocoPhillips’ construction of its CD-5 project six miles west of

the field, and a lot of activity there ramped up at the start of the new year “These are exciting times. My business unit is in a full-hiring mode,” said ConocoPhillips Vice President for Development Nick Olds. Olds outlined several projects ConocoPhillips is working on for the Alaska Support Industry Alliance Dec. 12. He gave full credit to the state of Alaska for enacting a revamped state petroleum tax last April in Senate Bill 21. CD-5 is a billion-dollar new oil production site that has been long-planned by ConocoPhillips and its partner, Anadarko Petroleum Co. that was underway before the passage of the tax change. The building of new camps and deliveries of material for CD-5 have been accomplished, Olds said. Ice road construction to allow crews to reach the construction sites is now underway, he said. As soon as the ice roads are complete, which is expected in January, contractors will begin moving gravel for six miles of new road and materials for four bridges, including a 1,400-foot span across the Niqlik channel of the Colville River, he said. Three of the smaller bridges and six miles of road to the CD-5 pad will be built this winter along with installation of piling for the long bridge span. Construction of the long span over

the Niqlik Channel is planned to be completed next fall, Olds said. Five hundred construction workers will be employed at the peak of the project. “CD-5 is on schedule. Fabrication of the bridge materials is on schedule and we are marshalling the material on the Slope. We have 36 of 56 contracts now executed and all of the long lead-time materials and equipment are on order,” Olds told the Alliance. Key contracts for installation of the CD-5 modules and the pipelines will be let this spring, he said. The modules are being built in fabrication plants in Anchorage and Fairbanks, he said. CD-5 is expected to produce about 16,000 barrels per day from wells located on an 11.7acre gravel pad. Initially there will be 15 wells including seven producer wells and eight drilled to inject water and miscible gas fluids for enhanced oil recovery. First oil is expected in December 2015. The bridges are critical infrastructure that will support development of drill sites further west in the NPR-A, such as the GMT-1 project now planned by ConocoPhillips and Anadarko, Olds said.

As production declines, the cost of transportation is spread among fewer barrels of oil, causing increased transportation costs per barrel. While Alaska will incur a revenue reduction of approximately $250 to $300 million this fiscal year, the Revenue Department reports that this is primarily due to the closing out of Alaska’s Clear and Equitable Share capital credit liabilities. In fact, for fiscal year 2015, the department reports that the current tax system, the MAP Act, and the former system, ACES, generate similar revenues at the forecasted price, expenditure and production levels. “Fundamentally, future growth in unrestricted state revenue will require higher oil prices and/or stable or increased production,” Rodell said. “Fortunately, with the More Alaska

Production Act, we have a tax regime that can address the one factor we can influence – increased production.” Parnell said the new tax law offers better protection in a lower price environment. “Alaskans will be better protected with the More Alaska Production Act if oil prices continue falling and the state finds itself in a lower price environment,” the governor said. “For much of the past 10 years, steadily rising oil prices have masked our declining production volume. With the More Alaska Production Act (the new tax), Alaska is not only better positioned for revenue at lower oil prices, but we also see new investment dollars flowing into Alaska, leading to new jobs, new production, and new opportunities for Alaskans.”

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

forEcast

Continued from Page 26 creased use of natural gas liquids for reinjection and decreased production in legacy fields we also see the companies responding enthusiastically to the More Alaska Production Act and have increased our projections of industry investment on the North Slope by $10 billion over the next 10 years.” “Our department is pleased with the increase in investment that we are seeing on the North Slope. However, in the short-term this is another factor that contributes to reduced revenue.” Lease expenditures are a tax deductible activity that reduces taxes paid in the present, which reduces near-term total revenue. The cost of transporting oil is another expense that becomes deductible against taxes and royalty payments, reducing revenue, she said.

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2014 Kenai Industry Update Forum

AVTEC plans nation’s first ice navigation program

Image/Courtesy/Alaska Maritime Training Center

An offshore supply vessel breaks ice near an oil rig on the full mission ship bridge simulator at the Alaska Maritime Training Center in Seward on the AVTEC campus.

By Elwood Brehmer Alaska Journal of Commerce

The White House is setting Arctic policy. The U.S. Army Corps of Engineers is investigating locations for an Arctic port. Hundreds of ships per year are passing through the Northern Sea Route over the Russian Arctic. And, until the Kulluk grounding, oil exploration in Arctic waters was ramping up. The Arctic is becoming a busy place. Officials at the Alaska Vocational Technical Center, or AVTEC, in Seward hope to do their part in helping the State of Alaska lead Arctic activity by starting the nation’s first ice navigation program for marine pilots and captains. The program’s development is not only in response to the region’s growing popularity among industries from tourism to energy, but in preparation for the International Maritime

Organization’s release of its Polar Code, expected in 2016, AVTEC Executive Director Fred Esposito said. The Polar Code will set training and operational requirements for Arctic travel. “Right now there is no requirement to have an ice navigator or an ice manager on vessels that are operating in the Arctic, but its coming, and folks will definitely be behind the eight-ball if the (Polar Code) requirements are dropped on top of an industry and folks are caught flatfooted without anybody trained and licensed in this field,” Esposito said. Retired Alaska Marine Highway Captain and AVTEC Marine Training Department Head Scott Hamilton said the vocational school is “about 85 percent there” in terms of staffing and finalizing the course. He said their plan is to begin offering ice training in Spring 2014. “It’s going to be a simulator-heavy course,”

Hamilton said. Coast Guard navigation requirements, while more than adequate in most situations, are seen as an industry minimum, Hamilton said. AVTEC’s course will delve into ways of maneuvering vessels around and through ice that are not being taught in the U.S. When AVTEC begins offering ice navigation training it will be the only training facility in the country to offer that type of U.S. Coast Guard approved course in the country, he said. “The Polar Code will address 60 degrees (latitude) and north, so that’s most of Alaska,” Esposito said. The school spent roughly $2 million on three vessel bridge simulators in 2001, and has conSee avtec , Page 33

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2014 Kenai Industry Update Forum

Parnell budget cuts spending as oil prices fall By Elwood Brehmer Alaska Journal of Commerce

Gov. Sean Parnell revealed his $12.4 billion 2015 fiscal year state budget plan Dec. 12, 2013, which includes a $3 billion pension payment and significant cuts to state spending. The proposal calls for $5.6 billion in state general fund appropriations for fiscal year 2015, which begins July 1, 2014. That’s down from $6.9 billion in fiscal year 2014 (which ends next June 30) and about $8 billion in fiscal year 2013 (which ended this past June 30). “I have consistently led with the principle that the state should live within its means, just like we all have to and should in our own households,” Parnell said in his address to the Anchorage Chamber of Commerce. He said a decline in forecasted Alaska North Slope oil prices for the upcoming fiscal year — from $111 per barrel in spring to $105

avtec

per barrel in a Department of Revenue report issued Dec. 4 — anticipates a $1.4 billion decline in revenue, which weighs heavily on budget numbers. “The state builds its budget base on forecasted oil prices,” Parnell said. Oil revenues account for more than 90 percent of all unrestricted state revenue. In legislators’ reactions to the governor’s proposal, Republicans were supportive and Democrats critical. Sen. Kevin Meyer, R-Anchorage, co-chair of the Senate Finance Committee, said he was pleased at the direction the governor is going on the operating budget. “With oil production down, our revenue is down and our corresponding spending must do the same,” Meyer said. Sen. Pete Kelly, R-Fairbanks, the other co-chair of the Finance Committee, voiced

similar feelings: “This is the second year of budget constraints and I appreciate the Governor ’s and the Legislature’s willingness to cut back. State government has been eating a pretty high-fat diet the last 10 years and its pants are getting pretty tight. We have no choice to but to put it on a diet,” Kelly said. House Democratic Minority Leader Rep. Beth Kerttula, D-Juneau, had a different view: “With a two billion revenue decline, we knew the budget would be tight this year. It would be worse if we didn’t have the savings we’ve accumulated, and as long as we are no longer getting a fair share for our oil, it’ll be harder to get out of this hole in the future. It doesn’t have to be this way.” See budget, Page 34

Continued from Page 31

tinuously upgraded them with the latest software, Esposito said. They are equipped with the latest generations of all of Alaska’s major ports, he said. According to Esposito, AVTEC’s bridge simulators can mimic nearly the entire range of ocean-going vessels, from large freighters and containerships down to 75-foot fishing trawlers. “I have a problem with people getting sick in our simulators,” because of their realism, Hamilton said. Image/Courtesy/Alaska Maritime Training Center

An offshore supply vessel breaks a lead in ice while another ship follows in an interactive exercise on the full mission ship bridge simulator at

The simulators are linked so trainees can interact with one another as they would on the water, like an oil tanker being assisted by two tugs for instance, he said. AVTEC asked for and received input for the ice navigation curriculum, Esposito said, from the oil support industry, the state’s marine pilot associations and the Coast Guard. “The captains of the ships, the captains of the tug boats that are assisting and the (marine) pilots are all supportive and involved,” he said.

The first round of ice training classes will be filled with experienced industry professionals who can offer insight on the courses’ strengths and weaknesses, Hamilton said. Those things could be gone over now but those captains and pilots — also AVTEC staff — are off manning vessels around the world. When the program is up and running Esposito hopes the school can train upwards of 60 pilots and captains per year, he said. The three simulators have room for up to 18 people to train as a group. The Marine Training Center staff asks captains to “check their typically large egos at the door,” during standard upgrade or license renewal training, Hamilton said, and the policy will be no different with ice navigation training. “We tend to operate on the Vegas policy, what happens here stays here,” Hamilton said. He said simulator work their “pushes the envelope” in an attempt to provide trainees experience in extreme situations, so they will be as prepared as possible when in a real vessel bridge. Training is the time for mistakes, Hamilton said, not on the water. Elwood Brehmer can be reached at elwood.brehmer@alaskajournal.com.

2014 Kenai Industry Update Forum

budget

Continued from Page 33

Photo/Chris Miller/AP

During his 2013 State of the State address to the Alaska State Legislature in Juneau, Gov. Sean Parnell gestures to illustrate his opinion that if Alaska will fall into fourth place behind California in oil production if it doesn’t change its oil tax policies. The Legislature reduced oil taxes through Senate Bill 21, but falling prices will end up taking a bigger toll on the budget than the tax cut after the most recent Revenue Department forecast released in December 2013. Kerttula was referring to the Legislature’s passage of Senate Bill 21 last April, which revamped the state’s oil production tax. Democrats blamed the reduction in revenues on the oil tax change, but Parnell said SB 21 will have no effect on revenues next year. Rep. Les Gara, D-Anch., a member of the House Finance Committee, was more specific in his criticism. “A sustainable budget is necessary, but Alaskans should know that more proposed education layoffs, the failure to implement the state’s own child abuse prevention study, and the cuts to the renewable energy fund which will hamper our ability to lower the cost of energy, were all avoidable,” Gara said. Parnell’s 10-year budget plan calls for general fund spending to be capped at $5.6 billion per year through fiscal 2024, with projected budget shortfalls ranging between $464 million and nearly $1.6 billion. Under the governor’s plan to shore up its obligation to retired workers, a $3 billion lumpsum transfer from the state’s Constitutional Budget Reserve, which currently has about $12 billion, to the state retirement systems would stabilize growing pension costs in future operating budgets, he said. The state is paying $629 million this fiscal year for employee retirement costs and is projected to pay $703 million next year, according

to the Office of Management and Budget. With the proposed $3 billion payment in fiscal year 2015, future payments would hold steady at $500 million for the next 20 years, Parnell said. He likened the current retirement payment system to an adjustable rate mortgage with a continuously increasing rate. Parnell said the Legislature took a step towards managing its unfunded pension liabilities in 2006 when it closed defined benefit plans and switched to defined contribution plans to new employees, but he said further action needs to be taken. “We still owe about $12 billion for these earlier pension systems,” he said. “It’s a debt we lawfully owe for past contracts and it’s currently unfunded.” OMB projects the state would need to pay more than $1 billion per year towards its pension liabilities by 2025 to keep the Public Employees’ Retirement and Teachers’ Retirement systems funded. By paying $3 billion down now on pensions, the state would save more than $4 billion by 2030 at its current contribution rate, according to OMB figures. The state’s retirement accounts would be fully funded by 2037 under his plan, Parnell said. Including the $3 billion pension payment, Parnell’s overall operating budget grew 24 percent from the final fiscal year 2014 budget, to $11.4 billion.

However, the unrestricted general fund portion of the proposed operating budget shrunk 13 percent year-over-year, from $5.9 billion to $5.1 billion. Already designated general funds and federal contributions make up the rest of the $12.4 billion proposal. The governor’s capital budget saw a bigger cut — 66 percent to its unrestricted general fund appropriations and nearly 32 percent overall. Parnell proposed $429.6 million in general fund appropriations for fiscal year 2015, down $846 million from the current capital budget. His total capital proposal is for $1.6 billion, with nearly $1.1 billion in federal funds that go primarily towards highway and airport maintenance. As is common practice for governors, Parnell said his budget is a guideline for legislators and leaves room for them to add some appropriations where they see fit. He said overall education spending stayed flat in his budget and he looks to put $5 million towards the Alaska Digital Teaching Initiative to help students in rural villages participate in classes held in other areas of the state through interactive software. “We’re going to continue focusing on education as a priority,” Parnell said in his budget speech. Parnell appropriated $10 million to the Alaska Energy Authority’s study work on the Susitna-Watana Hydro project and $20 million for AEA’s Renewable Energy Fund. He put $19.5 million towards his ongoing Roads to Resources initiative and $10 million towards chinook salmon research — part of a five year, $30 million commitment to fisheries study. The 32-mile Port MacKenzie rail extension project from Houston to the port got $5 million from the governor. Matanuska-Susitna Borough officials have said the $270 million-plus project will need approximately $100 million to finish on schedule in 2016. The under-construction engineering buildings at the state universities in Fairbanks and Anchorage received $10 million each. In November, the board of regents requested a total of $78.9 million to complete both projects. Absent from Parnell’s budget were appropriations for a proposed $245 million combined heat and power plant upgrade at the University of Alaska Fairbanks and funding for Port of Anchorage construction.

2014 Kenai Industry Update Forum

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