Tim Bradner

Alaska receives $14.2 million in North Slope lease sales

The State of Alaska received $14.2 million in high bids in its annual North Slope areawide sales held Nov. 7. Companies bid in separate offerings of tracts for unleased state lands in the central North Slope, the foothills region of the southern Slope, and state-owned offshore tracts in the Alaska Beaufort Sea. State Oil And Gas Director Bill Barron said most of the bidding was for onshore tracts in the central North Slope where 12 companies bid $11.48 million for 88 tracts varying in size from 5,000 acres of 1,440 acres. The offshore Beaufort Sea tracts brought $1.78 million in high bids from 6 firms. In the southern North Slope foothills region one company — Anadarko Petroleum Corp. — bid $962,000 for rights to 8 tracts covering 46,080 acres, Barron said. All of Anadarko’s newly-acquired tracts are near an area where Chevron has explored previously, industry sources say. Repsol E&P USA also bid and acquired 17 tracts in the central Slope area near where the company drilled its “Kachemak” exploration well last year west of the Kuparuk River field, which had encouraging results according to sources in industry. Repsol also acquired a state Beaufort Sea offshore tract near where it drilled a shallow-water exploration well last winter. Great Bear Petroleum, an Alaskan independent working on a potential shale oil development on the North Slope, acquired 15 tracts in the area near where the company is exploring. Great Bear drilled two shale oil test wells earlier this fall and is now analyzing results, its president, Ed Duncan, has said. Another Alaskan independent, NordAq Energy, acquired 15 offshore tracts in Smith Bay, north of the National Petroleum Reserve–Alaska, around a block of leases currently owned by the company. NordAq has not yet drilled an exploration well on its leases but the bay is very shallow, with approximately 10-foot waters depths, which would mean drilling and development with an artificial gravel island would be possible. One surprise in the sale was joint bidding by ConocoPhillips, BP, Chevron and ExxonMobil for 3 tracts west of the Kuparuk field, with the highest per-acre bids in the sale of $451.77 per acre. ConocoPhillips also bid separately on its own on 6 tracts, with per-acre bids up to $161 per acre. Most bids in the sale were in the $21 per acre sale. Dudley Platt, an oil and gas analyst working with the North Slope Borough, the regional municipality, said the percentages of the three major companies bidding together were similar to their percentages of ownership in the nearby Kuparuk field, which is producing. “I think what they are after is a portion of the Kuparuk reservoir that could extend into the unleased state acreage,” Platt said. What may also have prompted the major companies to bid is the discovery of several smaller oil accumulations by independents in the area, such as “Mustang,” a recent discovery by Brooks Range Petroleum. Repsol is also exploring in the area, Platt said.

AIDEA may finance infrastructure at Mustang

The Alaska Industrial Development and Export Authority, the state development corporation, is working on a plan to finance production infrastructure for a small North Slope oil field being developed by Brooks Range Petroleum LLC, an Alaska-based independent company. It is the first time the state authority has invested directly in oil production support infrastructure, although AIDEA has long invested in infrastructure for mining. Brooks Range is developing its 44-million-barrel Mustang discovery west of the Kuparuk River field and hopes to have the field in production in early 2014, company COO Bart Armfield said. The company is jointly owned by Alaska Venture Capital Group, a consortium of U.S. independents, and Ramshorn Investments Inc., a subsidiary of Nabors Industries. Brooks Range has worked out an agreement with AIDEA to finance and own a 4.1-mile gravel access road and gravel pad for production facilities. AIDEA’s board has approved initial steps in the financing, which is to be for $20 million. The board will give a final approval to the project at its December meeting, according to Karsten Rodvik, spokesman for the authority. The road and pad would be built this winter and be ready for construction of field facilities in late 2013 and early 2014, Armfield said. The plan is for AIDEA to own the road and pad and charge Brooks Range, or other companies working in the area, fees to use the facilities. The state authority now owns and operates infrastructure that supports mining, such as a port on the Chukchi Sea and a 57-mile access road to the Red Dog lead-zinc mine in northwest Alaska, but this is the first time the state will have invested in oil industry production infrastructure. AIDEA also owns an ore terminal and loading facility in Sakgway that is used by mining companies shipping ore from Yukon Territory. In the oil sector, the authority has also invested in a jack-up rig that is now in Cook Inlet, in southcentral Alaska. AIDEA invested 30 million of an $80 million project to purchase and refurbish the Endeavour jack-up rig in a partnership with Buccaneer Energy of Australia and Ezion Holdings of Singapore. Armfield said a second phase of the Mustang development being discussed with AIDEA that would have the authority finance and own a proposed $180 million oil processing facility that would process oil from the field. Capital expenditures for the total project are estimated at $550 million. If the project goes ahead, AIDEA’s rules would require it to make the facility available to other companies exploring in the area. Repsol, for example, is now drilling exploration wells nearby. Brooks Range itself will be drilling a delineation well further west this winter to test a discovery made in 2008 at its Tofkat well, Armfield said. Mustang would produce an estimated 15,000 barrels per day at peak and is located near the existing Alpine pipeline, a common carrier crude oil pipeline. That is convenient for any companies using the proposed plant to process produced oil. Access by independent explorers to processing facilities has been a major problem on the North Slope for companies. Most of the existing production plants and industry infrastructure on the North Slope is in the large producing fields and gaining access to the facilities has required lengthy and complex negotiations. This was a particular problem for Pioneer Oil and Gas when it developed its Ooogururuk field near the large Kuparuk field, Pioneer has said previously. ConocoPhillips, operator of the Kuparuk field, has said that making facilities available for third parties makes sense in some cases but it must be gone without causing complications for operations of the plants. Another company new to the slope, Eni Oil and Gas, opted to build its own small processing facility for Nikaitchuq, another small field, to avoid having to work with owners of the major fields even though spare capacity was available in processing plants in the large fields. Having AIDEA own a plant and make it available will be a help to independent explorers, particularly small ones. Armfield said that the plant will be designed to be expanded in modular increments.

State deal with Hilcorp will cap gas prices and limit sales for LNG

Cook Inlet gas producer Hilcorp Energy LLC has agreed to terms of a consent decree that will cap the price of gas sold to utilities and industrial customers for five years and not allow gas to be sold into LNG export markets until local utility needs are met, a state attorney said Thursday. The consent decree, if agreed to by an Alaska Superior Court, will clear the way for Hilcorp to complete its acquisition of Marathon’s Alaska assets, most likely in early January. Assistant State Attorney Ed Sniffen said the decree applies only to Hilcorp and not to Marathon. Even though the decree is not yet in effect, Hilcorp agreed Wednesday to abide by its terms between now and the time it is approved, Sniffen said. The U.S. Federal Trade Commission meanwhile agreed to drop its own investigation of the Marathon-Hilcorp sale and has deferred to the state of Alaska and the pending consent decree, the FTC said in an announcement Wednesday. The parallel federal and state investigations have been under way for most of 2012. Sniffen said the state of Alaska is are concerned because Marathon and Hilcorp today produce about 70 percent of the Cook Inlet gas sold to regional utilities, and having that much production controlled by one company could put utilities at a disadvantage in negotiations. Terms of the proposed decree will be made public when notices are published, probably early next week. The court will take comments from the public and interested parties for 60 days. Following that, a state Superior Court hearing will be held and a decision made on the consent decree he said. Final resolution of the matter will likely come in January, clearing the way for the Marathon asset sale, Hilcorp spokeswoman Lori Nelson said. Marathon disclosed last month to investors that the Cook Inlet assets were sold to Hilcorp for $375 million. Sniffen said the deal freeze gas prices sold by Hilcorp to utility and industrial customers at prices existing when the decree is official, likey in January, but those prices are expected to be similar to the average price of Cook Inlet gas today, about $6.52 per mcf, Sniffen said. The deal has an escalator allowing a 4 percent annual increase, he said, and this would likely result in an allowable price of about $7.72 per mcf at the end of five-year period in 2017, he said. “This was a very difficult balancing act for us because we want to protect the local consumers and at the same time give Hilcorp enough of a price incentive to explore for gas,” Sniffen said. The provision prohibiting Hilcorp from selling gas for export as LNG until local utility needs are met also applies to sales to companies “who intend to resell the gas for LNG export,” Sniffen said. This issue may be moot if ConocoPhillips, which owns and LNG plant near Kenai, south of Anchorage, fails to renew the LNG export license for the plant that is due to expire next March. Sniffen said the state has not been informed by ConocoPhillips of any plans to apply for a renewal, but if an application is made it would likely come in January, he said. There is increasing sensitivity to the Cook Inlet gas supply situation because existing fields are declining in production and local utility demand is expected to exceed annual production by the 2014-15 winter, requiring gas to be imported as LNG or compressed natural gas, utility officials told the state regulatory commission in a recent briefing. Several companies are exploring for oil and gas in Cook Inlet but no major discoveries have been made yet. Even if they are it is unlikely they can be put into production in time to meet the projected 2014-15 shortfall.

Bureau of Land Management nets $898,000 in its annual NPR-A lease sale

The U.S. Bureau of Land Management received 14 bids on 160,080 acres of federal oil and gas leases in the National Petroleum Reserve–Alaska in a lease sale held Nov. 7. Cash bonus bids totaled $898,900 from two companies, said Ted Murphy, associate state director for the BLM. The agency is responsible for management of the reserve. A state lease sale netted $14.2 million earlier in the day. Twelve of the bids were submitted by Alaska independent NordAq Energy for tracts in the central part of the petroleum reserve. The other two bids were from Houston-based independent Woodstone Resources in the northeast part of NPR-A. In a state of Alaska lease sale held earlier Wednesday NordAq acquired 60,000 acres of offshore state leases in Smith Bay, just north of the NPR-A. Company president Bob Warthen said his company is working on an integrated exploration program for the Smith Bay acreage and the company's onshore federal leases in the reserve with a target for drilling in 2014. The Smith Bay state leases are in shallow water. NordAq would build an artificial ice island to support the drilling, Warthen said. BLM typically holds its annual NPR-A sale orn the same day as the state's North Slope areawide sale, Murphy said. This year the state sale was also help Nov. 7.

Key state legislative contests highly volatile as races go down to the wire

Outcomes of key state House and Senate races are highly uncertain in the final days of Alaska’s general election, and Democrats are raising and spending more money in the heated final weeks leading up to Nov. 6. In Southeast Alaska, a closely-watched state House race is in House District 34, which includes Sitka and Haines. Republican Rep. Bill Thomas, an influential Alaska Native legislator, has a thin lead over his Democratic challenger Jonathan Kreiss-Tomkins, according to a poll by Hellenthal & Assoc that was released to the Journal. In most parts of the state the reorganization of legislative districts by a Republican-appointed state board revamped district boundaries to favor Republicans, Democrats charge, but in Thomas’ case the board included Sitka in his district, which leans Democratic. The survey shows Thomas with 47.9 percent of the vote in the new district compared with 45 percent for Kreiss-Tomkins. In the old district, small and heavily Alaska Native communities that did not include Sitka, Thomas traditionally won by larger percentages. Sitka is Kreiss-Tomkins’ hometown. The state House is virtually certain to be Republican-led and possibly by a wider margin than in the current Legislature, but the outcome of Thomas’ race is being watched because Native legislators may be fewer in the new Legislature due to redistricting. Another race being watched is the Southeast Senate race between Sen. Al Kookesh, D-Angoon, and Sen. Bert Stedman, R-Sitka, where two incumbents in formerly separate districts face each other due to redistricting. Stedman is leading in that race by a comfortable margin, however. The key Senate races in Anchorage and Fairbanks are a real toss-up. Polls by different sides and survey firms are showing conflicting results. Races to watch include that between Democrat Hollis French and Republican Bob Bell, and between Republican Bob Roses and Democrat Bill Wielechowski, both in downtown Anchorage. In Fairbanks, the toss-up races are between Democrat Joe Paskvan and Republican Pete Kelly in one Senate district, and between Republican John Coghill and Democrat Joe Thomas in another senate district. In other Senate races being watched, Republican Anna Fairclough appears to be leading in her bid for the senate against Democrat Bettye Davis, who is the incumbent senator in a district that was changed to include Fairclough’s Eagle River House district, which leans heavily Republican. Campaign spending reports from the Alaska Public Offices Commission show heavier spending in the contested state Senate races by Democrats compared with Republicans.

Major discovery at Bornite prospect

Minerals companies exploring the western Brooks Range say they have identified as much as 9 billion pounds of copper in high-grade ores and additional resources of zinc. The Arctic and Bornite copper deposits have been explored for decades but a new discovery at Bornite by Vancouver,B.C.-based NovaCopper Resources this summer may push the known higher-grade copper resource to up to a critical mass where development may be possible. “It’s not hard to see how a 10 billion pound copper resource could be identified in this district soon,” said Rick Van Nieuwenhuyse, CEO of NovaCopper Resources, the company most active in the region. There are also 9 billion pounds of zinc and 2.3 billion pounds of lead resources identified. Van Nieuwenhuyse briefed the Alaska Industrial Development and Export Authority’s board Oct. 30 on the exploration. AIDEA could play a role in developing a road to the mine area, much like the state development corporation did in the 1980s to aid development of the Red Dog zinc and lead mine north of Kotzebue. Copper was discovered at Bornite in 1957 and exploration by Kennecott Resources, which acquired rights to the property, continued for several years. Kennecott defined a large resource and but one that was still economic. In 1964 Kennecott built an exploration shaft down to 1,075 feet but never explored below that level, Nieuwenhuyse said. The mineshaft flooded, which caused Kennecott to turn its focus to exploring other areas nearby, resulting eventually in the Arctic discovery. Last year NovaCopper, working in a joint venture with NANA Regional Corp. of Kotzebue, which owns Bornite, decided to explore deeper. In 2012 the companies announced discovery of a new, larger and richer ore deposit at about 1,500 feet. Where the shallower deposit found by Kennecott had ore values with about one percent copper the deeper deposit has richer ore with drill test results that ranging from 2 to over 5 percent, Nieu told AIDEA’s board. NovaCopper and NANA are also exploring the Arctic deposit about 25 miles northeast of Bornite, which was discovered and also explored by Kennecott, and acquired by NovaGold Resources (now NovaCopper). In 2011 NovaCopper and NANA formed their joint-venture and merged the minerals lands owned by both. The region, known as the Ambler Mining District, has several other promising deposits. One is the Sun deposit, east of Arctic and Bornite, that is being explored by Andover Resources. Ted Leonard, AIDEA’s executive director, told the authority board that he expects Andover to soon announce positive results of its new exploration at Sun. Another deposit in the area is Smucker, to the west, which is owned by Teck Resources, which also owns and operates the Red Dog Mine. Van Nieuwenhuyse said the Arctic deposit looks attractive on its own. A preliminary economic assessment has outlined the potential for a 4,000-ton-per-day mine that could be built with a $262 million initial capital investment. Another mine developed nearby at Bornite would allow for the sharing of critical infrastructure, particularly an access road from the Dalton Highway 200 miles to the east. Over several decades several mining companies including Kennecott and firms that no longer exist as companies, like Anaconda, Noranda and Cominco, spent about $150 million in exploration in the region. NovaCopper itself, however, accounts for about half of this, or $75 million, including the amount paid to Kennecott to acquire the Arctic deposit and other properties, Van Nieuwenhuyse said. NovaCopper spent $15 million in its 2012 exploration, Van Nieuwenhuyse said. A road is key to development, however. “Without a road there will be no mine,” Van Nieuwenhuyse told the authority’s board. NovaCopper and NANA need about three years of further exploration to define an initial project. Another one to two years would be needed to complete a feasibility study and prepare the project for permitting, Van Nieuwenhuyse said. Permitting the project, which would include a federal environmental impact statement, and construction, depending on the mine developed, would require about two years. There is also the 200-mile access road built from the Dalton Highway that would likely total $300 million to $500 million. Van Nieuwenhuyse said the mines developed in the area would ultimately pay for the road similar to the way the Red Dog Mine road was paid for, although it was built by AIDEA, the state authority.

Mishaps and permit delays stall plans for Inlet exploration

A series of mishaps and regulatory winkles with a jack-up rig have caused Australian independent Buccaneer Energy to give up hopes to drill two oil offshore exploratory wells in Cook Inlet in 2012, a company official told an Alaska agency on Oct. 30. Buccaneer Energy Vice President Mark Landt told the board of the Alaska Industrial Development and Export Authority, or AIDEA, that the jack-up rig Endeavour will be moved in the next two weeks from the port of Homer to its Cosmopolitan oil prospect offshore Anchor Point, on the Kenai Peninsula north of Homer. AIDEA owns one third of the jack-up rig along with Buccaneer and Ezion Holdings of Singapore. Landt said a series of problems delayed final certifications for the rig after its arrival in Alaska from Asia, including the need to replace a defective lifeboat and make repairs to the rig’s fire alarm system, which performed when the rig had departed Singapore but failed tests after arrival in Alaska. Other equipment on the rig had suffered minor damage during the ocean transit from Asia and is being repaired or replaced, he said. There have been other regulatory wrinkles, such as disagreements by inspectors in Alaska over approvals for certain rig systems given by inspectors in Singapore before the rig departed there. Buccaneer had hoped to drill an offshore prospect in north Cook Inlet after arrival but the delays caused that well to be rescheduled to 2013. The company shifted to a secondary goal to drill an oil prospect in the southern part of the Inlet that is outside of the winter Cook Inlet ice zone, but other delays are now complicating that plan. Landt said Buccaneer must secure an amendment to an oil spill contingency plan approved by the Alaska Department of Environmental Conservation to drill its second target, the Cosmopolitan prospect. Securing that is expected to take about 90 days. An official with the state DEC said that Buccaneer had requested the change as a minor amendment to its spill plan, which would have allowed streamlined processing, but the agency determined it to be a major amendment, which means it must go out for public comment. The DEC also raised several issues with Buccaneer in a request for more information, said Graham Wood, an official with the agency’s spill response group. Landt told AIDEA’s board that a fallback plan is to ask for state permission to drill only to a gas zone at Cosmopolitan that is at approximately the 6,000 foot level and above the oil zone. This could be allowed without having the amended oil spill plan. The Alaska Oil and Gas Conservation Commission must rule on that request, he said. “If we can start drilling for gas before we get the oil spill contingency plan approval we can deepen the well once we get it,” Landt said. Reaching the oil zone will require drilling an additional 1,000 feet, he said. In another development on Cook Inlet offshore exploration, state officials said Furie Operating Alaska, a Texas-based independent, is finishing up work on its Kitchen Lights No. 2 exploration well in north Cook Inlet. The company is using the Blake 151 jack-up rig, which was brought to Cook Inlet last year. Furie completed work on its first Inlet exploration well, Kitchen Lights Unit No. 1, earlier this summer. That well was started last fall but not finished before the company was requires to halt drilling for the winter under conditions set out in its permit. Furie was required to stop drilling by Oct. 3 in 2012 but is being given an additional few days to wrap up operations before moving the jack-up rig off the location, the Department of Environmental Conservation said. No information has been released by Furie on results of its exploration other than an initial estimate last year that the first well encountered gas zones with the potential for producing about 800 billion cubic feet of natural gas. In other Southcentral Alaska exploration developments, Buccaneer has essentially completed drilling of a second onshore gas production well at its Kenai Loop gas field near the city of Kenai. The well was drilled to a location about 2,000 feet from the company’s first well in the field, which is now producing 6 million cubic feet a day. Potential producing sandstone layers were encountered in the second well that are similar to the first well, Buccaneer said in a press release, but the company has not yet said that it will put the well in production.

Managing partner sees bright future for Patton Boggs

Patton Boggs LLP, one of the nation’s leading law firms and long a presence in Alaska’s legal community and the state capitol, celebrated its 50th anniversary in October. Ed Newberry, the firm’s managing partner in Washington, D.C., was in Alaska for the occasion, to meet with Patton Boggs clients and help its attorneys and staff celebrate the event. Patton Boggs is well known for its lobbying practice as well as legal work, and the firm’s connections with Alaska go back to the early 1970s when Patton Boggs represented Alyeska Pipeline Service Co. in Washington, D.C. Bill Foster, an attorney with the firm, helped steer legislation through Congress that cleared the way for construction of the Trans Alaska Pipeline System. Patton Boggs has 12 attorneys in the Alaska office, a number that has been stable for several years, and about 550 attorneys nationwide. “We’re among the top 100 law firms in the nation in size, but we’re best known for our work in the government-business-law intersect,” Newberry said in a visit with the Journal. The firm’s focus is on the range of complex problems that arise for businesses dealing with government, either agencies or the Congress. There are offices in Dallas, Denver, New York and New Jersey as well as in Washington, D.C., and Anchorage. There are now three offices in the Middle East with the opening this year of an office in Riyadh, Saudi Arabia. Two other Middle East offices are in Doha, in Qatar, which opened in 2003, and in Abu Dhabi, which opened in 2008. There is also a project office in Dubai. However, in the Middle East most of the firm’s work is for governments working on financial and commercial contract details of large infrastructure projects. In Alaska, Patton Boggs specializes in work in the energy industry — ExxonMobil Corp. is a major client — as well as a range of legal and lobbying work for Alaska Native corporations, according to Walter Featherly, the firm’s managing partner in Alaska. Featherly has a long history of working with Alaska Native corporations, beginning in Southeast Alaska in 1981. The firm is also a fixture in the state capitol, where Bob Evans, one of the state’s leading lobbyists and a Patton Boggs attorney, is well known. Patton Boggs’ strong connections in the nation’s capitol are a particular asset for Alaska clients, particularly in the post-Ted Stevens age. A new client for the firm is the University of Alaska, where Patton Boggs will represent the university in its work to secure federal research grants. Other clients are Alaska Native corporations who are extensively engaged in government agency contracting, Featherly said. Interestingly, many of the Alaska Native government contracting firms are also engaged with U.S. agencies in the Middle East, and Patton Boggs has been able to support that work with its offices there, Featherly said. “We’ve been able to keep pace with our clients here as they expand their reach,” he said. Newberry said the firm’s connection with the Middle East goes back to the late 1970s when one of the partners with an interest in the region began travelling there to establish connections. This predated the huge run-up in oil prices after the 1979 revolution in Iran and the emergence of the Persian Gulf as a major world major oil and gas provider. The real breakthrough for Patton Boggs came when the ruler of Qatar hired the firm to help it recover a large sum of money that had been embezzled from the government. The effort was successful, and a grateful Qatari government rewarded the firm with permission to open the first office for a U.S. firm in Qatar. Similar permission had been given to a British law firm. The office in Doha, Qatar, opened with Susan Bastress, the first non-Qatari lawyer licensed to practice in that nation, as managing partner. Like a lot of the Washington-based law firms with major government practices, Patton Boggs has had senior government figures among its partners. Ron Brown, later appointed as Commerce Secretary by President Bill Clinton, became a Patton Boggs partner in 1981. In 1989 Brown became chairman of the Democratic National Committee. In 2010, Patton Boggs acquired the Breaux-Lott Leadership Group including its founders, former senators Trent Lott, a Mississippi Republican, and John Breaux, a Louisiana Democrat. Although not a former official himself, Thomas Hale Boggs Jr., one of the firm’s earliest partners, had solid Washington connections. Newberry sees a bright future for firms like Patton Boggs that specialize in solving government problems for clients, particularly in the regulatory arena. Mergers and acquisitions that require Federal Trade Commission approval are just one example. “The size and scope of government activity will continue to grow, no matter who gets elected Nov. 6,” Newberry said.

Gold operations in rural areas pick up the pace

High gold prices have stimulated Alaska mining projects including several in remote areas. The small Nixon Fork underground gold and copper mine near McGrath on the upper Kuskokwim River continued operations in 2012 according to its owner, Canada-based Fire River Gold Corp. In late October the mine was producing 3,800 tons of ore daily, twice the rate from earlier in the year, and had reached a stable production rate, according to Fire River spokeswoman Kimberly Ann. What is encouraging is the performance of the ore mill at the mine, which is now achieving about 85 percent recovery of gold, she said. Nixon Fork produces both a gold concentrate and gold bars, with the copper as a byproduct. Concentrates and gold bars are flown from the remote site. Fire River began operations at Nixon Fork in mid-2011. The mine had produced previously but there was a history of operating problems. The target rate for gold production is 30,000 ounces by the end of 2012, according to information on Fire River’s website, with a projected increase to 40,000 ounces in 2013 and 50,000 ounces in 2015. The company will attempt to replace reserves that are mined with new resources added by exploration drilling, extending the life of the mine. There are now two drill rigs working on exploration drilling at the mine, on underground as well as above-ground targets, Ann said. Nixon Fork has a long history. The mine was previously owned by Nevada Goldfields Inc., from 1993 to 1999, and St. Andrew Goldfields until 2008. From 2004 through 2008 the previous owners spent over $50 million in upgrades to processing facilities, mine infrastructure, permits and bonding. In 2008 Fire River Gold purchased the project in 2009 for $3.1 million in cash and shares. The company moved to reevaluate 9,381 meters of definition drilling that had been done in 2007 and 2008, but which was never fully evaluated. The property encompasses 11,000 acres. The land, facilities and infrastructure have an approximate replacement value of $150 million, Fire River said on its website.   Terra could produce 1M ounces Another remote gold mine project in Interior Alaska is in advanced exploration. WestMountain Gold Inc. of Denver reported it has concluded its summer 2012 exploration program at the company’s Terra gold project in Alaska, with four diamond-drill holes involving 3,782 feet of core drilling. The project is about 125 miles northwest of Anchorage in the Alaska Range. “The Terra project continues to produce bonanza gold intercepts and we are confident that the resource will reach 1 million ounces. We are also enthusiastic about the positive gold intercepts and the completion of the on-site gold plant,” WestMountain CEO Greg Schifrin said in an Oct. 25 press release. The drilling has extended the known vein system 200 meters north, WestMountain said. The company also said a bulk sample mill at the site is now operational and that concentrates were produced in a one-week test run this summer. Production of bulk samples will be expanded next summer with ore from several vein systems at the deposit, Schifrin said. Bulk concentrate samples will be flown from the site from an airstrip that has been constructed. In other developments, Gustavson & Assoc., a consulting firm, will complete a third party independent technical report on the project when assay work from 2012 drilling is completed. The report will include an updated resource estimate. The Terra Gold project is being developed in a partnership with Corvus Gold, Inc. Terra Gold has the right to earn 51 percent of the project by spending $6 million on exploration and related work by December 2013.

Southcentral utilities plan to import gas to meet projected shortfall

Utilities in Southcentral Alaska have asked for proposals for liquefied natural gas or compressed natural gas imports to help ensure local gas supplies, a utility group told the Regulatory Commission of Alaska Oct. 24. Gas fields in the region, which date from the 1960s, are being depleted, and production will be inadequate to meet local demand for space heating and power generation by as soon as 2014, said Lee Thibert, vice president for strategic planning for Chugach Electric Association, the state’s largest electric utility. Thibert was speaking for group of five regional Alaska utilities and Donlin Gold, a mining company which needs natural gas to power a large gold mine the company plans in Southwest Alaska. Besides Chugach and Donlin Gold, the group includes the regional gas utility, Enstar Natural Gas, and three other electric utilities, Homer Electric Association, Matanuska Electric Association and Anchorage’s city-owned Municipal Light & Power. There is new exploration drilling under way in south Alaska and some gas discoveries are being made, but permitting requirements and lead-times for construction, particularly offshore, will prevent gas being available to meet the projected 2014 shortfall, said Colleen Starring, CEO of Enstar, the gas utility. The electric utilities have some ability to switch to oil but Enstar is totally dependent on gas. “If gas is not available our only choice is curtailment,” she said, a gloomy prospect if it happens during the Alaskan winter. Assuming no substantial reserve additions the gas supply gap in the region begins at about 10 percent of current demand in 2014 and grows to a 50 percent shortfall in 2019, according to an analysis by Petrotechnical Resources Alaska, a consulting group hired by the utilities. Total gas use is about 110 billion cubic feet per year, with utilities using about 70 billion cubic feet annually. Gas is also used as fuel for a Tesoro Corp. refinery near Kenai and offshore oil producing platforms in Cook Inlet. Even with an optimistic reserve additional assumption of 20 million cubic feet per day of new production added per year the gap is still 25 percent of demand by 2019, according to the PRA study. New exploration in the region could result in more substantial new supply by 2017, however, and a state corporation working on a 24-inch gas pipeline from the North Slope could meet the shortfall by 2020, but a gap between 2014 and 2017 remains under almost any scenario. Thibert said the utilities working issued Solicitations of Interest for LNG or CNG supplies two years ago and have already met with one group of potential suppliers, he said. The utilities have hired an Alaska economic consulting firm, Northern Economics, to help them decide between LNG or CNG. They will make the decision by the end of the year and are planning to spend $5 million next spring on engineering for facilities in Alaska needed for LNG regasification or CNG depressurization. The utilities will ask permission from the Regulatory Commission of Alaska to include that expense in their rate base, Thibert said, along with, eventually, an undefined larger amount for construction of facilities. The group has also been in discussions with ConocoPhillips on converting its LNG plant at Kenai to a regasification and import facility. The plant is still making LNG and shipping it to Japan, but the LNG export license for the plant expires next March. ConocoPhillips has made no statements on its plans for the facility, but in their planning the utilities assume exports will cease. Thibert said gas imports would likely be in small increments at first so as to not disrupt exploration efforts underway. If those are unsuccessful the imports can be expanded. The group has been working on import options for some time but did not seriously consider compressed natural gas until recently because of the lack of a licensed vessel for transporting CNG as well as an ability to get gas to tidewater in the Pacific Northwest. Recently, however, the group has been in contact with three shipbuilders who are able to build CNG vessels, Thibert said. Once built, the vessels would have to be licensed by the American Bureau of Shipping as well as the U.S. Coast Guard if they are to operate in U.S. waters. Citing confidentiality, Thibert said he could not identify the shipbuilders. The utility group has also been in contact with Pacific Northern Gas in British Columbia, which currently delivers gas from Canadian producing areas to two ports, Prince Rupert and Kitimat, B.C. Thibert said the LNG options being considered include conventional ships like those now carrying LNG from the Kenai plant, LNG vessels with ship-mounted regasification and LNG barges that would be towed by tugs. Ironically, there are large resources of stranded gas on Alaska’s North Slope, about 800 miles north of Anchorage, which is on the state’s south coast. Unfortunately, there is no pipeline now available to bring gas south from the slope, although producing companies and the state are working on a pipeline plan.

AFN convention packs 'em in – thousands jam Dena'ina

The annual Alaska Federation of Natives convention brought thousands of visitors to Anchorage Oct. 17 through Oct. 20, packing the Dena’ina Center in the city’s downtown and restaurants and retail stores. Besides its main events – an annual review of issues and problems facing rural Alaskans, with a dose of cultural reinforcement – the convention is a huge social event for friends from around the state who often see each other only at the annual convention. Visit Anchorage estimated 3,500 to 4,500 attended the 2012 event, with economic impact of about $6 million. The location of the 2013 convention will be either Fairbanks or Anchorage, with a decision to be made in December. AFN is also a premier shopping event for those attending. Retail cash registers were ringing around Anchorage as visitors stocked up for the year with items hard to get in remote communities. As for issues, the convention discussions this year, among other topics, centered on subsistence, maintenance of Alaska Native health services, rural justice and public safety and tribal affairs, and rural energy. There is a huge concern in the Alaska Native community that federal budget cuts are eating into the Indian Health Service budgets and the ability of the big nonprofit tribal health organizations to provide services. A lot of worry is also focusing on the “fiscal cliff” Congress faces in January, and whether Indian health services would be exempted from across-the-board spending reductions. “Indian Health Service isn’t just another federal program. This is a trust responsibility that the federal government has assumed,” said Valarie Davidson of the Alaska Native Tribal Health Consortium. Sen. Lisa Murkowski told AFN delegates she thinks the fiscal cliff can be avoided. “My sense is that there will be no sequestration (across-the-board cuts). There will be a concentrated effort in the Lame Duck (post-election) session of Congress to find a solution. Health services are already underfunded,” the senator said. But there are also important wrinkles in health care administration that are of concern to Native leaders and the state’s congressional delegation. One is an interpretation of language in the federal Affordable Health Care Act over the definition of “Indian” that could have the effect, unless corrected, of forcing about 20,000 Alaska Natives out of Indian Health Service coverage and into the private health insurance market. Murkowski is the ranking minority member on the Senate Appropriations Committee and reviews the budgets for U.S. Department of the Interior agencies responsible for Native American programs. Alaska’s congressman Don Young sat at the podium with Murkowski in the discussion of general concerns with federal programs. Young has represented Alaska in Congress since the early 1970s, and is from Fort Yukon, a rural community. His wife, Lu, was a respected Athabascan who passed away recently. Young also sits on U.S. House committees and subcommittees that have jurisdiction over the Interior Department. On health issues, Young said Alaska Natives have to assume more responsibility for looking after their own health, and particularly that of children. “You can’t let your kids drink 8 to 10 cans of soda a day and expect them to be healthy,” Young told the delegations. “And if you drink, it will affect your kids,” he said. “We can build the most wonderful health facilities, but the Native community has to its part. Health care is a two-way street. It’s not just the federal government,” Young said. Alaska’s other U.S. Senator, Mark Begich, returning from a trip to Israel, was unable to get to Anchorage in time to sit at the podium with Murkowski and Young Oct. 19 but spoke to the convention the following day, Oct. 20. Begich acknowledged challenges facing the Indian Health Service but cited a big accomplishment this year in getting the U.S. Veterans Administration to allow Native veterans to get treatment in Alaska’s extensive network of tribal health facilities. “There’s no reason to send our veterans all the way to Anchorage, or Seattle, when they can often get the care they need in their home community,” Begich said. The VA has now signed agreements with 25 tribal health organizations from Ketchikan to Kotzebue, which not only improves access to care for veterans but will provide a new source of revenue for the tribal organizations, allowing them to improve care to all they serve, Begich said. In her speech to the convention, Murkowski said she felt shamed that Native veterans in rural communities have experienced difficulties getting care. Alaska Natives have always served with distinction in the Armed Services and continue to do so, she said. “There is one, only one, elite airborne brigade in the Alaska National Guard, and a company of this brigade is based in Bethel. It has been deployed for the last year in Afghanistan,” Murkowski said. On subsistence, the actions by federal fish and wildlife agents to enforce fisheries closures and block subsistence fishing in western Alaska last summer has left sour feelings among rural Alaskans, who no longer believe federal agencies will treat them fairly on subsistence. Agents seized fishing gear, and fish. The actions were taken in connection with widespread failures of salmon runs this summer. Murkowski said she believes the time is now right for a Senate oversight hearing on federal subsistence, to create a public record that can be used to improve the system. Federal agencies had asked Murkowski to hold off on a hearing until more time had passed, but the senator said the recent western Alaska actions, and the seizure of Native art using feathers from a nonendangered species – a raven and a deceased one at that – means the time for a hearing is now. “These are well-intentioned people going out to provide for their families and to create art, but these laws are being interpretated in ways that make them criminals,” Murkowski told the AFN delegates. The unraveling of Native support for federal subsistence management is the latest chapter of this issue. For years Native leaders have pressed for rural and local Alaska Native preference on hunting and fishing but urban sports hunting and fishing groups blocked a state constitutional amendment that would have done that, leading to the federal takeover of fisheries management on federal lands across the state. Alaska Natives supported that, until this year at least.

Final environmental impact statement coming for gasline

The U.S. Army Corps of Engineers is scheduled to publish the final environmental impact statement for a 737-mile, 24-inch in-state gas pipeline from the North Slope to Southcentral Alaska on Oct. 26, according to the Alaska Gasline Development Corp., or AGDC, the state corporation planning the project. Notice of the FEIS will appear in the Federal Register Oct. 26. It is an important milestone for the project, said Leslye Langla, spokeswoman for ADGC, although it is not a guarantee that the project will be built. So far AGDC has spent $64 million on the project, mostly in engineering and permit-related work, Langla said, The group will be coming to the Legislature next year with a request for $300 million for engineering and other work, she said, that will take the project through an “open season” for solicitations to ship gas, and to the point where a construction decision can be made. Two years ago the Legislature set aside $200 million for the project but an appropriation of funds is still needed. The pipeline is planned to be 737 miles in length and would parallel the trans-Alaska Pipeline System to Alaska’s Interior and then follow the Parks Highway to Southcentral Alaska, terminating near Anchorage. It would operate at a pressure 2,500 pounds per square inch so as to be able to transport natural gas liquids like propane along with methane, the main component of natural gas. “We will also receive a 100-mile right-of-way across federal lands as soon as the FEIS is issued. We already have an unconditional right-of-way across 604 miles of state-owned land,” Langla said. The pipeline must also cross a small amount of private land. Langla said that once the FEIS is published, the Corps can be expected to issue a final Record of Decision in about 30 days. The next milestone would be a Corps of Engineers Section 404 permit to cross wetlands along the pipeline right-of-way. One area of wetlands that would be crossed is Minto Flats, west of Fairbanks. AGDC expects to receive the Section 404 permit in the first quarter of 2013, Langla said. At this point the project cost is estimated at $7.52 billion in 2011 dollars with about a 30 percent confidence in the number, Dan Fauske, AGDC’s CEO, has said in previous briefings. The estimate will be refined and the uncertainty reduced as engineering work proceeds. Decisions on the project final ownership and financing have yet to be made, but one possibility is state ownership and financing through state revenue bonds, with construction and operation would be contracted to private firms, Dan Fauske has said. That form of organization would result in the lowest cost for moving gas through the pipeline because the tariff structure would not contain an equity component with a profit paid to an investor. Another possibility is for one or more private firms make take an equity ownership in the project and finance and own the pipeline privately, which would take the state out of ownership but also have the tariff structured to allow for profits for the investor. There are also combinations of the two, one being some form of joint-venture between the state and private parties, with the state providing financing through bonds. There are precedents for this: The Alaska Industrial Development Corp., a state development corporation, is allowed to invest in a project in partnership with private firms and to provide financing. Alaskans shouldn’t be wary of state ownership of a large infrastructure project if they are done right, Fauske has said. There are many successful examples of this including state ownership of large hydro projects like the Bradley Lake project near Homer through the Alaska Energy Authority; the Red Dog Mine road and port, through AIDEA; the Skagway ore terminal and Ketchikan shipyard owned by AIDEA; or smaller projects like the Federal Express hanger at Ted Stevens Anchorage International Airport, which is owned by AIDEA but leased to Federal Express Corp. AGDC will be asking the Legislature to decide on the most appropriate organization for the in-state pipeline as the project moves forward, Langla said. The current design capacity for the 24-inch pipeline is for 500 million cubic feet per day, which is based on a commitment the state has made in a contract with TransCanada Corp. under the Alaska Gasline Inducement Act. This limits the amount of gas the state can take for a state-sponsored project other than the larger project TransCanada is working on, which is designed to move about 4 billion cubic feet per day. The state is also supporting that with a $500 million grant under the AGIA contract. The limit on gas volume has caused some heartburn among state legislators who believe larger amounts of gas being shipped are needed for the pipeline to be viable. Fauske said he agrees that a higher volume would be better but the state is currently limited by the AGIA contract. AGDC began work on the 24-inch pipeline as an alternative three years ago when there was great uncertainty about a large-diameter pipeline. The goal would be to move at least some North Slope gas south to the state’s Interior and Southcentral communities in case the large project encounters long delays or is not built. TransCanada has already encountered one setback when its plan for a 48-inch pipeline from the North Slope to Alberta had to be shelved because of the glut of inexpensive shale gas in North American markets. The pipeline company is now working with North Slope producers BP, ConocoPhillips and ExxonMobil on a large-diameter pipeline to a south Alaska port and a large liquefied natural gas export project, but that is in a very early stage of conceptual planning and is highly uncertain. ADGC hit a setback itself earlier this year when the state Legislature failed to appropriate all funds requested by the corporation for advanced engineering, although $21 million was made available. ADGC was hoping to have its project in construction by 2016 and in operation by 2018 but that has now been set back a year, and possibly more. The large gas project being considered by TransCanada and the gas producers, estimated to cost from $45 billion to $60 billion, couldn’t be operational until 2024 at the earliest. If that project is built the smaller AGDC pipeline could be used as a spur line to carry gas to Anchorage, Fauske said, or converted to other uses.

Mariculture industry small but growing in Alaska

A small mariculture industry for Alaska – oyster farming for the most part – has been developing in fits and starts for years, and a small group of dedicated seafood entrepreneurs are working away at it, convinced the business can succeed. Consumer demand in Alaska and the Lower 48 is steadily increasing among people who see oysters as healthy food, and who are becoming more sophisticated in their tastes. Yes – Alaska oysters do taste better. They’re sweeter, for one thing, due to a higher sugar content and a greater exposure to salt water in Alaska gives them a slight tangy taste, says Ray RaLonde, an aquaculture scientist with the University of Alaska Fairbanks Sea Grant advisory program . Weatherly Bates, a Kachemak Bay shellfish farmer, says Alaska oysters are more uniform in size, typically have more meat for their size than many Lower 48 oysters and are free of grit because they are grown in the water column with no contact with the ocean bottom. Alaska itself is a big seller for oysters grown here, said Rodger Painter, a Southeast Alaska shellfish farmer and long-time industry advocate. The superior taste and Alaska’s image of having clean, pure waters have put oysters from the state at the top of the menu at trendy East Coast oyster bars like Grand Central, in New York. Alaska oysters are at the top of the menu in price, too. Painter said Alaska oysters now have enough of a reputation to command a price advantage over Lower 48 oysters, which helps offset higher costs in growing them here. Bates and her husband, Greg, operate their farm in Halibut Cove, in Kachemak Bay near Homer. They see shellfish farming as helping reinforce the economies of small coastal communities, like hers, that are subject to volatile seasonal fisheries. Greg Bates fishes commercially for cod part of the year, but the couple, who have two young children, hope to combine that with shellfish farming to make a good living in Halibut Cove. They are also working to develop a new farmed shellfish product, mussels. Earlier this year the state awarded a $300,000 grant to the Halibut Cove Community Organization, a nonprofit, for the Bates to develop mussel-producing rafts as a demonstration. The rafts are being built this year. Married to mariculture Weatherly and Greg Bates have a lot of experience in shellfish farming. They’re both New England-raised, and on farms; Weatherly has a degree in aquaculture and fisheries technology from the University of Rhode Island. The two raised oysters in Maine for four years including a stint managing an oyster farm at a nonprofit affiliated with Jamie Wyeth in Maine. This involved a 16-acre oyster farm and hatchery, where the couple increased production from 10,000 to 200,000 oysters a year. Intrigued by Alaska, they pulled up stakes, headed north, and became interested in Kachemak Bay when the state began leasing tracts for oyster farms in the area. In 2010 the two secured their own 9-acre farm site in Halibut Cove, across the bay from Homer. Oysters from Alaska Shellfish Farms, owned and operated by the Bates, are sold in the Homer area and in Anchorage. The two also operate an oyster nursery, a facility that matures young oyster seeds from spat, or oyster eggs, brought in from specialized oyster hatcheries. Weatherly sees oyster farming at this point as “kind of a hobby” for many growers, but she sees possibilities particularly when other shellfish like mussels are brought into the mix. “We see huge possibilities,” for mussels, she said. Penn Cove Shellfish, in Washington State, is the biggest mussel farmer in the U.S., producing more than 2 million pounds per year. There are also farms in New England and the eastern maritime provinces of Canada, regions the Bates are familiar with, that produce tens of millions of pounds a year. There’s no reason why Alaska can do this in mussels and other shellfish, particularly since good sites for new shellfish farms are becoming scarce in establishing producing regions, like the Pacific Northwest, Bates said. In contrast, there are many good potential sites in Alaska coastal communities from Southeast to Southcentral. Salmon farms are now a fixture in many parts of the world (they are illegal in Alaska) but Bates feels oysters and other shellfish have strategic advantages over salmon farms anywhere. Free feed, spendy seeds The main advantage is that farmed salmon have to be fed in their pens, a cost shellfish farms don’t bear because oysters and mussels don’t have to be fed. They consume algae and other natural nutrients in the water. They don’t pollute, either, a second key advantage as far as Bates is concerned. “Shellfish farming is so much better for the environment. They filter the water and make it cleaner,” she said, in contrast to salmon farms, which can cause pollution.  Long hours of summer daylight in the north is also an advantage in that the light creates more phytoplankton nutrients in the water, which helps shellfish grow faster. There are challenges, however. For oysters, the main one is that oysters are not native to Alaska. They grow well, but Alaska waters are too cold for them to propagate and make spat, or seed. To deal with this oyster farmers have to buy seed from hatcheries. Unfortunately, the one spat hatchery in Alaska, in Seward, is engaged in a retooling and is not currently operating. Spat can meanwhile be purchased from hatcheries on the west coast, but production at these are being curtailed because of an upwelling of acidic ocean water off the coast. Hatchery operators are working on ways to deal with this and the Seward hatchery will be back in production at some point (Alaska waters are so far not affected by acidity), but the shortage of spat is now a major problem for the industry all over the west coast. Mussels, in contrast to oysters, are native to Alaska and prolific. The big challenge for mussel farmers is that sea otters love to eat mussels. The solution is enclosures around the mussel rafts to keep the sea otters out, Bates said. One of the goals at the first commercial mussel rafts Bates is developing at Halibut Cove is to see what kind of otter-protection enclosures work best. There are other unknowns, too, Bates admits. “We could find unexpected fouling organisms, or problems with starfish and barnacles. It will take some time to figure it out, through trial and error, just like any farming,” she said. Rodger Painter said there is still a lot of tinkering with the technology used in producing oysters. Most oyster farms involve rafts anchored in a cove with wire-mesh trays stacked down into the water column. Water circulates through the tray stacks, bringing nutrients. Variations on this are in use, such as a Japanese device that looks like a shrimp pot. A third approach being experimented with, Painter said, involves a type of plastic bag mesh that can be placed at or near surface in the inter-tidal zone. The advantage of this is that there are more nutrients at the surface, and tidal action keeps water circulating. Front-end capital costs are lower, and there is typically less labor. The disadvantage is that water movement can damage the bags, Painter said. Most oyster farmers may wind up using some combination of technologies, he said. The economics of oyster farming are meanwhile linked to how long it takes to produce a marketable batch. In the Pacific Northwest, where waters are warmer, it takes one to two years, Painter said. In Southeast Alaska’s cool waters it usually takes three years. Water temperatures in Kachemak Bay are cooler yet, and it can take four to five years. Bates said this is a key problem with oysters that faces her. Smaller-size oysters be produced in three years in Kachemak Bay but consumers and restaurant owners in the Anchorage area have to be educated that these are just as tasty as older, larger oysters. Painter said consumers in the Pacific Northwest, who are more sophisticated about shellfish, prefer the smaller oysters. The human side is important, too, because shellfish farming isn’t for everyone. Shellfish farms are typically small “Mom and Pop” operations. Painter believes it has a lot of potential, “but you have to be smart in what you are doing, do your homework and make the right decisions to avoid investing in the wrong technology at the start.” A typical small oyster farmer will need about $200,000 to get into operation but a lot depends on who the farmer is, whether he or she has assets at hand like boats or a place to live or stay near the site. Supporting the operation is relatively low-tech, “but it’s 24-7 for seven months of the year,” Painter said. Commercial fishermen are ideally suited for oyster farming because they have experience on the water and with boats, and have marine equipment at hand. Painter said he knows oyster farmers who successfully run farms as a sideline to commercial fishing, the challenge being that the sites have to be tended while the owner is away fishing. Some communities are embracing shellfish farming to create a local economy. In Naukagi, a small community on Price of Wales Island in Southeast, community leaders organized a facility to people develop small rafts and learn about oyster farming before moving with the own facilities, Painter said. He worked to help train people there. There is more support for the infant industry these days, too. Haa Aani, a Sealaska Corp. subsidiary in Juneau that works on regional development projects, is actively working with small oyster farms in several Southeast communities, providing business expertise and other assistance. The state Legislature also approved a special mariculture loan program last spring that is just now being put into effect.

Despite exploration surge, Southcentral faces shortage

The natural gas supply situation for Southcentral Alaska, including for Anchorage, isn’t getting any better. Aging gas producing fields continue to decline and not enough new production wells are being drilled to offset that, according to the latest assessment by Petrotechnical Resources of Alaska, a consulting firm. Unless an exploration company announces a big gas discovery, the region will be short of gas by 2014, and 2015 at the latest, according to Pete Stokes, managing director of PRA. The firm has been doing annual reports for the regional utilities since 2010 and the message has been essentially the same, the only difference being that the drilling of a few more production wells in the producing fields has pushed out the date the shortfall hits by one year, from 2013 to 2014. In its latest report, PRA looked at drilling in the first half of 2012 and found the trend basically continuing, with not enough wells drilled. One bright spot is that two gas wells drilled in west Cook Inlet earlier this year had good initial production rates. Stokes warned that Cook Inlet gas wells can also see sharp decline rates after an initial surge of production. PRA presented its latest assessment to the Alaska Support Industry Alliance Oct. 11. The information was given earlier to an Anchorage municipal energy task force. One bright spot is that a gas storage facility built on the Kenai Peninsula is in operation and will supply gas to meet peak cold weather demands this winter, Stokes told Alliance members. That helps ease one problem, meeting peak demand for gas in cold weather, but it doesn’t address the expected long-term, overall shortage. Gas storage puts surplus gas produced in summer in storage for use in winter but it doesn’t bring any new gas to the region. There is also an uptick in exploration drilling, however. “It’s great to see all the activity,” and the hope is that there will be sizeable discoveries, Stokes said. “Hope is not a good strategy.” Current producers are also still investing, another good sign. Beluga gas field owners, where ConocoPhillips is operator, drilled two new gas wells. Hilcorp Energy, which took over Chevron’s Alaska assets, is investing in rehabilitating aging Cook Inlet production platforms. But all this may not be enough. PRA estimates that 13 to 14 new wells need to be drilled each year to offset the gas fields’ declines, but companies are actually drilling only five to six wells per year, Strokes said. Because of this, what PRA is projecting is an annual shortfall of supply, meaning that by 2015 there won’t be enough gas produced from gas wells in Southcentral Alaska to meet the total demand, Stokes said. When that happens, gas will have to be brought in from somewhere else, most likely by importing gas as liquefied natural gas, or LNG, or compressed natural gas in large container vessels. “The only way to ensure a supply of gas will be to import it,” Stokes said. That won’t be cheap. Natural gas is now selling for $12 to $15 per thousand cubic feet on spot markets, about twice the price now being paid for locally-produced gas by utilities in the region, he said. There will also be expenses related to engineering and construction of gas import facilities. Compressed natural gas is another option, where gas could be purchased at a much lower cost in western Canada or the Pacific Northwest, compressed and shipped north in special containers. But that will also involve expense. Meanwhile, building a pipeline to bring gas from the North Slope can’t be done in time. Alaska Natural Gas Development Corp., a state corporation, is working on a plan for a 24-inch pipeline that could be built south from the Slope to Interior Alaska and Southcentral, but that couldn’t be built until 2020, Stokes said. A large gas pipeline project being discussed by North Slope producers and TransCanada Corp. couldn’t be built until 2023 or 2024. What could change this picture quickly is if one or more of the companies drilling exploration wells in Cook Inlet announce a major gas discovery. Several companies are drilling, Stokes said, but so far there are no announcements of major discoveries. Furie Operating Alaska, a small independent company, is currently exploring offshore with a jack-up rig and announced a gas discovery last year, but the company has not released information on the well. NordAq Energy, another independent, is exploring its Shadura prospect on Cook Inlet Region, Inc. lands, Buccaneer Energy is drilling a second well in its new Kenai Loop gas field near Kenai, and Armstrong Oil and Gas plans new wells at its North Fork field north east of Homer. Until new discoveries are announced, the utilities can only count on the known gas in the producing fields, which is the data PRA is working with. Cook Inlet gas fields are now producing about 100 billion cubic feet of gas per year, half of what they produced 10 years ago. Regional utilities, Enstar Natural gas Co. and the electric utilities, are using about 69 billion cubic feet of that, with the rest used as fuel by offshore oil producers, the Tesoro refinery near Kenai, Stokes said in the PRA presentation. An amount is also still being exported as LNG by from ConocoPhillips’s LNG export plant near Kenai, which is still operating. Enstar Natural Gas depends on gas for 100 percent of its needs, and expects to need 33.6 billion cubic feet in 2012, according to PRA’s analysis; Chugach Electric Assoc. uses gas for 90 percent of its power generation and expects to use 25 billion cubic feet in 2012. Municipal Light & Power, Anchorage’s city-owned electric utility, uses gas for 88 percent of its power generation and will use 10.6 billion cubic feet in 2012. A troubling sign, Stokes said, is that of the 65 billion cubic feet estimated to be needed by the utilities in 2015, the utilities have been able to contract for only 30 billion cubic so far, Stokes said. Stokes doubted that the producers have a big store of gas banked. “If there were any gas available, it would be under contract by now,” Stokes said.

Japan firms open Alaska office to pursue LNG

A consortium of Japanese companies has opened an office in Alaska with hopes of working with the State of Alaska, North Slope producers and TransCanada Corp. on a large Alaska natural gas liquefaction project, and fast-tracking the project to build it by 2017 or 2018. The consortium, Resources Energy Inc., proposes to develop and own the LNG plant itself at a south Alaska tidewater port but said it could also invest in the pipeline needed to bring North Slope gas south to the plant, said the company’s Alaska Manager Mary Ann Pease. North Slope producers BP, ConocoPhillips and ExxonMobil, as well as independent pipeline company TransCanada, are working on a potential $45 billion to $65 billion Alaska LNG export project, but have not yet committed to investments in preliminary engineering or made decisions on commercial aspects, such as who would own components of the project. Members of the Japanese consortium include Japan Petroleum Exploration Co. Ltd.; Idemitsu Kosan Co.; JX Nippon Oil and Energy Corp.; Mitsubishi Gas Chemical Co. and Nippon Telephone & Telegraph. Nippon Steel Corp. and two Japanese trading companies, Itochu Corp. and Sojitz Corp. as well as the Japan Bank for International Cooperation, are involved in discussions with the consortium members, Pease said. Pease said the group sent a letter to TransCanada indicating an interest in shipping 2.7 billion cubic feet a day through a potential large-diameter pipeline from the North Slope to south Alaska during the pipeline company’s recent non-binding Solicitation of Interest to shippers. TransCanada said it has received “strong interest” in its solicitation but did not identify potential shippers. Resources Energy is now the second group of Asian companies who are acknowledging submitting letters of interest to TransCanada. On Sept. 16, a group of mostly Korean companies submitted a letter of interest through the Alaska Gasline Port Authority, an Alaska municipal group hoping to facilitate a pipeline and LNG project. Pease said the Japanese group wants to build and own the liquefaction plant and associated LNG tankers and has in mind a plant capable of shipping up to 20 million tons of LNG per year, a project of about the same scale as that being considered by the Slope producer group. “We need a deep water and ice-free port for the LNG plant so our preference is now Valdez, on Prince William Sound, but studies are still under way and several locations in Southcentral Alaska are being considered,” Pease said. The group wants to move ahead now with a detailed feasibility study and sees a faster timeline for the project than that contemplated by the producer group and TransCanada. “We believe we can have this project in operation in 2017 or 2018,” Pease said. In an Oct. 1 letter to Gov. Sean Parnell the producer group laid out a work plan for their project that involves a 10-year plan, so that the first LNG would not be shipped until 2023 or 2024. The producers’ work on a large gas project is linked to commitments made in a settlement of litigation with the state over lease disputes at Point Thomson, east of Prudhoe Bay. Parnell he was satisfied with the Oct. 1 progress report from the producers but state Natural Resources Commissioner Dan Sullivan said separately that the administration is pushing the group to make firm commitments by mid-spring, 2013. Pease said the Japanese group is ready to commit now to a detailed feasibility study but wants to do it under the auspices of a Memorandum of Understanding with the state. “Japanese companies are used to doing business on a government-to-government basis, where there is some official involvement of the state,” Pease said. The state negotiated a Memorandum of Understanding with the Alaska Gasline Port Authority in 2004 to assist the port authority in pursuing an LNG project, and Pease said her group would like something similar. The state is being cautious in its response so far. The Japanese group met with Sullivan on the matter in July and was referred to a state-owned corporation, Alaska Gasline Development Corp., or ADGC, which is now working on an in-state gas pipeline system. Pease said AGDC told the group, however, it cannot work with Resources Energy at this time, because the state corporation said it is in the final stages of securing a federal environmental impact statement, or EIS, for its 24-inch in-state pipeline. Bringing in new parties could complicate and delay a final EIS for that project, the Japanese group was told, according to Pease. ADGC also said it is limited to transporting 500 million cubic feet per day under terms of a state agreement with TransCanada. That amount is insufficient to meet the export needs of Resources Energy’s owners, Pease said. Meanwhile, other Asian firms who filed expressions of interest with TransCanada in September through the Alaska Gasline Port Authority include Korea East West Power, KOGAS of Korea, GS Energy of Korea, PTT International Ltd., of Thailand, and PT PNG LNG Indonesia, according to Bill Walker, general manager of the port authority.

Consent reached to restart Healy Clean Coal Plant

Golden Valley Electric Association of Fairbanks and the Alaska Industrial Development and Export Authority, Alaska’s state development corporation, have worked out a consent decree with federal attorneys that could allow for a restart of a mothballed 50-megawatt new-technology coal power plant at Healy in Interior Alaska. The plant has been idle for almost 12 years, although critical operating systems have been maintained. The agreement is highly unusual because the Healy Clean Coal Project, or HCCP, is not operating and no violation of the Clean Air Act has occurred, sources familiar with the deal said. However, the federal Clean Air Act does allow the government to file for an injunction to block a violation that is pending. In this case the U.S. Justice Department filed for an injunction in federal court to block the restart of the Healy plant but filed the Consent Decree at the same time. The deal requires Golden Valley to invest $40 million in additional emissions controls in the HCCP and another approximately $5 million in emissions improvements at an adjacent, smaller and older 25 megawatt coal plant. Golden Valley and the state authority, or AIDEA, made the deal with the U.S. Department of Justice and the Environmental Protection Agency after extended negotiations with environmental groups to forestall litigation failed. Golden Valley spokeswoman Corinne Bradish said the consent decree will be published in the Federal Register soon and will be subject to a 30-day public review period before going to a U.S. District Court for approval. If the court approves, a decision that could come by the end of the year, Golden Valley hopes to have the plant operating in 18 to 24 months, Bradish said. Having access to inexpensive coal-fired power is important to the Interior Alaska utility because most of its power is now generated with costly fuel oil. Coal is much less expensive than oil, and power can be generated with coal for 5 to 6 cents per kilowatt hour compared to a range of 20 to 50 cents per kilowatt hour in the utility’s oil-fueled plants depending on which unit is operating, said Kate Lamal, a consultant to Golden Valley. The $305 million plant was built by AIDEA in 1996 and 1997 and was to be operated by Golden Valley, which was also to purchase power from the plant. The U.S. Department of Energy contributed $120 million to the project costs to demonstrate new coal combustion and emissions control technologies, with AIDEA and the State of Alaska funding the remainder of costs. The facility operated for one year under a contract with DOE to test the technologies with different types of coal but was shut down after operating problems, unrelated to the new environmental systems, developed during a 90-day commercial operations test. A decade of litigation followed between Golden Valley, the plant operator and regional electric utility, and AIDEA, which owned the plant and had built it. In settling the dispute AIDEA agreed to sell the plant to Golden Valley, but when the State of Alaska issued a renewed air quality permit for an operating plant, environmental groups objected, arguing Golden Valley should initiate a more complex type of air permit as if the plant were new construction. EPA agreed but urged the utilities to negotiate with the environmental coalition led by the Sierra Club. Extended negotiations spanning two years included a proposal for the added environmental controls, which Golden Valley has agreed to as part of the Consent Decree, but also that the utility agree to phase out its coal plants in 20 years. Golden Valley balked at this, and the negotiations ended. The utility then proposed the Consent Decree to EPA as a way of forestalling a lawsuit from the environmental groups, and EPA agreed to the approach. Cory Borgeson, Golden Valley’s acting president, said, “We chose to pursue the Consent Decree option with EPA because, otherwise, there was no defined end to the air permitting process,” with almost certain appeals of the Clean Air Act’s Prevention of Significant Deterioration permit procedure. “Very important, the Consent Decree avoids what we believe would have been lengthy and costly litigation,” Borgeson said. Environmental groups had targeted the plant restart as part of a national effort to force the closure of coal-operating electric power plants. In addition to new combustion and emissions systems in the original plant design, aimed at reducing sulfur dioxide (SO2) and nitrous oxide (NOX), Golden Valley agreed to install a Selective Catalytic Reduction, or SCR, system in the plant’s exhaust system to further reduce SOX and NOX, Lamal said. The utility will spend an additional $5 million at a smaller, older 25 MW coal plant, Healy 1, that is adjacent to the 50 MW HCCP. Another $250,000 will be contributed to a wood stove change-out program operated by local municipalities, and that would reduce particulates from wood smoke, a major contributor to human health problems that occur locally during certain winter air conditions. “A couple of things need to happen before we have the keys to the plant. One is the judge’s final approval following the 30-day public review. Second is the approval of the Regulatory Commission of Alaska,” Borgeson said. Lamal said EPA made significant concessions in recognition of special conditions. One is that Golden Valley will be allowed to restart the plant and operate it for 18 months without the SCR being installed. “This will allow us to get the plant operating in a stable condition,” Lamal said. Secondly, plant shutdowns for the modifications will be done during the summer, a period of low power demand in Alaska.

Permit glitches lead Apache to suspend seismic work

Apache Corp. has temporarily halted its extensive Cook Inlet 3-D seismic program because of unexpected delays in securing permits from the National Marine Fisheries Service for a final section of marine seismic in the Inlet, a company spokeswoman said Oct. 2. “These are just glitches in the federal permitting, and it is not a serious setback. We have now completed 3-D seismic on about 300 square miles and we are very pleased with the results, but we have a lot of acreage yet to do and to evaluate,” company spokeswoman Lisa Parker said. Apache hopes to get the permit issues worked out and to resume the marine seismic in early 2013, she said. The company’s overall multi-year seismic program will cover 1,200 square miles, Parker said. Alaska state officials have said Apache is conducting the most extensive seismic program ever done in the Cook Inlet Basin, a mature producing region that has been producing oil and gas since the early 1960s. Apache has almost 1 million acres under lease in the region, combining state and private lands. Parker also said Apache’s preparations to drill its first exploration well are continuing with a goal of beginning drilling before the year-end. The well will be drilled on the west side of the Inlet about four miles north of the Native village of Tyonek. The company is now moving a rig to the location. “We’ve had a few setbacks due to weather in getting barges and materials to the site. Most of the rig components are there, but we’re still mobilizing,” Parker said. Apache brought the rig to Alaska from North Dakota. “It’s nice to see more drilling equipment being added in Cook Inlet,” where explorers are concerned about a scarcity of rigs and service contractors, Parker said. “I’m also happy to see equipment being brought to Alaska from North Dakota instead of the other way around,” she said. The Alaskan industry is also concerned about a drain of oil contractor equipment and skilled personnel from the state to the booming Bakken shale oil play. Parker said Apache also plans to extend its onshore Kenai Peninsula seismic program, on Cook Inlet’s east side, into the Kenai National Wildlife Refuge in 2013. The company will explore subsurface lands in the refuge owned by Cook Inlet Region Inc., an Alaska Native corporation. Apache signed an agreement to explore Cook Inlet’s lands two months ago. Parker said the company is now preparing an environmental assessment to cover its seismic work in the refuge. No significant issues are expected with the assessment, Parker said, as the company is working closely with the U.S. Fish and Wildlife Service, which manages the refuge. The assessment will also rely mainly on data from a conservation plan prepared for the refuge by the agency itself. Plans are to do the seismic in the refuge in fall, 2013, but if the plan is approved by the end of the year the work might be done next spring, Parker said. One positive note in Apache’s relations with federal agencies and the National Marine Fisheries Service in particular, Parker said, is a wealth of Cook Inlet marine mammal data, including on endangered beluga whales, the company is providing the agency from marine mammal observers stationed on offshore seismic vessels and aerial marine mammal surveys.

State to press for early commitment to LNG

A consortium of North Slope producers and TransCanada Corp. submitted a report Oct. 1 to Gov. Sean Parnell outlining progress on an Alaska gas pipeline and large liquefied natural gas export project, and his spokesperson Sharon Leighow said the governor’s expectations have been met. This past spring, Parnell asked North Slope producers and TransCanada Corp., a pipeline company, to provide information on how an LNG project would be organized, an approximate cost estimate and a work plan by Sept. 30. The state has also tied a settlement of a dispute over Point Thomson state oil and gas leases east of Prudhoe Bay to progress on the LNG project, although the Point Thomson producers were also given other options in the settlement. The letter sent to the governor was from North Slope producers BP, ConocoPhillips and ExxonMobil, as well as TransCanada. It described a potential pipeline and LNG project that would cost $45 billion to $65 billion in 2011 dollars. Once the project was formally launched, the letter said, it would be four to five years before final engineering, procurement and construction could start, and another five to six years to build the project. Gas and LNG production would begin in 2022 or 2023 assuming commitments to begin preliminary feasibility and engineering are made in 2013. The timetable submitted by the companies in the Oct. 1 letter did not tie the schedule to specific dates but in an interview state Natural Resources Commissioner Dan Sullivan said the administration will push for a commitment to the preliminary engineering phase in early 2013. The companies also warned, however, that the issue of certainty of state fiscal terms must be addressed for the project. Similar concerns have been expressed earlier for other gas project plans. At this point the LNG and pipeline plan is in a “concept selection” stage, the companies said. This early effort involves about 200 company employees and contractors and expenditures of “tens of millions” of dollars, according to the Oct. 1 letter. Advancing to preliminary engineering and feasibility work will require a commitment of several billions of dollars and 400 to 500 people working, the companies said. If the project were built, construction would employ 9,000 to 15,000 workers on gas conditioning facilities on the North Slope, an 800-mile pipeline that would be 42 inches to 48 inches in diameter, and the LNG project at a southern Alaska port. Significantly, the letter did not indicate whether the pipeline terminus and LNG plant would be in Valdez or Cook Inlet, two potential locations that have been discussed. Company officials, speaking on background, said the route and location of the LNG plant would be made in a later phase of the project feasibility study. The $45 billion to $65 billion cost estimate is a significant increase over an approximate $40 billion estimated by the producing companies and TransCanada for an all-land pipeline from the North Slope to Alberta previously pursued. That project is now deemed uneconomic because of a flood of inexpensive shale gas in North American markets. Sullivan said there is no doubt the Alaska LNG project would be among the most costly, and largest, in the world, but there are other LNG projects being developed in the same cost range, such as the large Gorgon project in Australia. There are also smaller LNG projects in North America that offer competition for Alaska and would be less costly the build, Sullivan said. These include separate projects being proposed by Shell and Apache Corp. at Kitimat, B.C., which would liquefy gas produced from shale gas wells in Alberta. However, an Alaska project has significant advantages, Sullivan said. The chief advantage is that the gas supply is known and that infrastructure now built on the North Slope can be used in gas production. “We have zero resource risk,” Sullivan said, as well as huge potential added conventional gas resources in the central North Slope and the National Petroleum Reserve-Alaska, which geologists believe to be gas-prone. In contrast, the shale gas wells that the Kitimat projects will even initially depend on have not yet been developed and the gas resource is still only a potential, Sullivan said. Also, Kitimat LNG will require a pipeline, although shorter in distance than in Alaska. However, rights-of-way agreements across lands owned by First Nation groups have not been completed and that must be done by the Canadian federal government. In contrast, the needed Alaska gas pipeline faces no significant permitting or right-of-way problems. “The Kitmat projects are also smaller, and do not enjoy the advantages of scale that we offer,” Sullivan said. As for competitor projects overseas, Sullivan said Alaska’s two chief drawing cards are its location in a stable political, safe environment, in contrast with large projects in places like Indonesia, Russia or the Persian Gulf. Sullivan said there is a long way to go on the LNG project but there has been significant progress this year. In his State of the State speech to the Legislature last January, Parnell laid out goals for the producing companies to settle the long-standing Point Thomson lawsuits in the spring and an agreement among the three producers and TransCanada to “align” behind an LNG project and work together. Those goals were met, Sullivan said. The remaining goal, a definition of a project, a work plan and an approximate estimate, was to be achieved by the end of the third quarter of 2012, or Sept. 30. That goal was also met. “To appreciate the progress you have to look at where we were just a year ago,” Sullivan said. “We were still in litigation over Point Thomson, which meant that one fourth of the gas reserves needed for this project were in court. The producers were not aligned on gas, and they weren’t even talking to each other,” about a gas project. The state administration worked out its settlement on Point Thomson in March, and Parnell also persuaded the CEOs of the three major companies to meet with him in Anchorage, a meeting in which the agreement to work together was finalized. Point Thomson has about 8 trillion cubic feet of gas reserves confirmed through drilling, which means they are a known resources. There is an additional approximate 26 trillion cubic feet of gas in the Prudhoe Bay field, which is also an oil-producing field. The Point Thomson and Prudhoe Bay gas make up most of the 35 trillion cubic feet of known gas on the slope that would underpin a major gas project. Ultimately more gas will be needed but once a gas project is agreed on new exploration will begin which will find more gas.

Commission to focus on ways to manage benefit costs

You’re in business and you see that your employee health benefits costs are rising 15 percent a year. So, would you prefer something more affordable? How about a 2.8 percent annual increase? This can be done. Wisconsin-based Serigraph Inc., a company with 1,000 employees and $40 million in annual sales, has done it. John Torinus, Jr., the company’s chairman, will be in Anchorage Oct. 11 to tell the Alaska Health Care Task Force, a state advisory panel, how Serigraph did it. Torinus will also address members of Commonwealth North at a special luncheon that same day. Both meetings at the Hilton Hotel in Anchorage and are open to the public, according Deb Erickson, director of the health care commission and Jim Egan, Commonwealth North’s executive director. Commonwealth North, an Anchorage-based business and public policy group, has had task force members working on health care for a long time. The health care commission’s meeting will actually span two days, but Thursday, Oct. 11 will be the main event. The commission typically focuses each of its bimonthly meetings on a theme, and the theme for the October meeting is on what employers can do to better manage health care costs and help employees stay healthy. “We’ll want to look at what role there could be for government, particularly the state, to give support for employers,” Erickson said. Serigraph is one company that is pioneering a more aggressive approach to management of employee health care benefit costs. Its approach, much of it centered on employee wellness initiatives and employees “taking ownership” of their health, is attracting a lot of attention. Serigraph’s strategy also includes working for transparency in medical cost information, putting emphasis on primary care to keep people out of expensive hospitals, helping employees navigate the maze of medical pricing information, and use of “medical tourism,” or travel to other locations where quality is high but costs may be lower. “Many employers are beginning to embrace control of health care costs as part of a business strategy, Erickson said. Serigraph is an outstanding example, but some Alaska employers are following this path. One of them is Providence Health Systems, which is a major health care provider but also a major employer, Erickson said. Providence started developing an employee health management program four years ago and now has an on-premises primary care clinic for its employees. The clinic makes it easy for employees to get primary care. While Providence is a major health care provider, it does not actually offer primary care at its main hospital in Anchorage. Access to primary care is critical. “That’s one thing that the (health care) commission learned in its first year,” Erickson said. “In other countries where overall health is better and costs are lower, all emphasize primary care, and the health outcomes are better.” Providence Health Systems also has a human resources manager assigned to the employee health issue. Tammy Green is director of Providence’s “Well-Being and Absence Management” unit. She will also address the health care commission at its October meeting. Many larger Alaska employers like Alyeska Pipeline Service Co. and the City and Borough of Juneau have employee health programs, embracing wellness initiatives, though not to the degree Providence is going to for its employees. Premera Blue Cross Alaska, which provides health insurance coverage for a wide range of employers, has also focused on similar programs for medium-sized and even small firms. A good part of the Oct. 11 health commission agenda is devoted to Alaska employers dealing with health care – the entire afternoon is devoted to discussions after Torinus’ presentation at noon – but other items will be discussed in the morning. Among those will be a presentation on a possible “all-claims” database for Alaska that would provide accurate and accessible information on costs and cost trends. Erickson said one of the commission’s objectives is to improve the transparency of health care cost data for consumers and also health care planners and providers. Several states have these and several are working on them, she said. The commission has hired a consulting group, Freedman Healthcare, to assess the feasibility and usefulness of such as system in Alaska, and preliminary findings will be presented to the commission at the October meeting. The concept is for all payers – private insurance companies, self-insured employers, Medicaid and medicare and, hopefully, defense department agencies – to provide information on the cost of procedures to a common data base. “One objective is to increase transparency for the public. New Hampshire has a program, for example, that provides information to the public through a website so that consumers can see what they can expect to pay for a procedure with different providers in the area,” Erickson said. The information, in a common database, is also needed to do the financial analysis for medical “payment reform,” where payments are tied to improvements in outcomes, in a patient’s health, compared with the current “fee for service” system where health providers are paid essentially by the procedures they do, and the number of them. Another report at the commission’s October meeting will be made by Milliman Inc., in a continuation of a study the firm is doing on Alaska health care pricing and reimbursement. Last year Milliman reported on comparison of hospital and physicians charges with providers’ charges in the Lower 48. The latest focus for Milliman is on the pricing of pharmaceuticals. An update of the study will be made by the firm. The second day of the commission meeting, Oct. 12, is devoted to updates from state officials on issues the group has previously worked on including evidence-based medicine; health information infrastructure; transparency and payment reform; the patient-centered Medical Home initiative, and updates on federal health care reform including the possible expansion of Medicaid in Alaska and the health benefits exchange system.

$453.5M in transportation bonds on ballot

Voters will be asked in November to approve $453.5 million in new state general obligation bonds for port and highway projects around the state. General obligation bonds commit the state itself to repayment from any source of revenue, in contrast to revenue bonds issued by the state, or any other Alaska government, which are tied to revenues from the project being funded for repayment. Because it is a general commitment of public revenues, the state constitution requires that general obligation bonds be approved by voters in a state election. The ballot question appearing in November will ask permission to borrow $195.4 million to fund 18 port and port-related transportation projects around the state, and also $254.5 million to finance highway and road projects in different regions. As is often the case, the Legislature made substantial changes in its 2012 session to the bond proposal that was submitted by Gov. Sean Parnell in January. Parnell had proposed a $350 million bond package for six port projects only. Lawmakers added port projects – no surprise in an election year – but also reduced funding Parnell had proposed mainly in two high-profile projects in Southcentral Alaska, to allow money to be spread around the state. There was deep concern in the Legislature, and also by the governor, that running the pricetag for the bond package too high, and with too many projects added, would push the cost past the threshold voters would accept in November. Partly because of that worry, legislators added the highways section of the proposal, out of the belief that including road improvements would make the package more attractive to voters. The state has other sources of funds for highways, mainly the federal highways transportation program that pays 90 percent of costs. However, having the state fund some highway projects directly, whether from bond proceeds or by a state capital appropriation, has advantages. A big advantage is that it allows projects to be done faster, since federally-funded projects are done on a schedule. In some cases state funding also avoids the red tape that often accompanies federally-funded road projects, The federal funds aren’t lost, of course, because they can be shifted to other projects. However, in the Legislature’s brokering of the bonds proposal there were some big losers, as well as some winners. The governor had proposed $200 million of his $350 million total go to help the Port of Anchorage finish its expansion (the Anchorage Municipality, on behalf of the port, had asked for $300 million). The Legislature pared this to $50 million. Parnell also asked for $110 million in the bond package to largely complete the Alaska Railroad extension to the Matanuska-Susitna Borough’s Port MacKenzie. Lawmakers cut this to $30 million. Parnell asked for $10 million for the City of Emmonak so that western Alaska coastal community could build a barge dock to increase the efficiency of unloading fuel and general freight for the Lower Yukon region. Lawmakers cut this to $3 million. Parnell’s proposal for $10 million to the City of Seward for port improvements related to a planned relocation of Community Development Quota fishing vessels to Alaska from Seattle survived and is in the ballot proposal, along with $10 million Parnell proposed for a continued expansion of a port facility in Bristol Bay. Parnell’s $10 million proposal for dock improvements in Ketchikan was changed. It was taken out of the bond package and funded instead by a state capital appropriation. With the money taken from the Port of Anchorage and Mat-Su rail extension, as well as the reduced funding for Emmonak, legislators approved bond money for a variety of other, smaller port projects. Kotzebue and Nome, which have influential legislators – Sen. Donny Olson and Rep. Reggie Joule – received $10 million each; $10 million for Kotzebue’s Cape Blossom Road and port will allow planning and engineering to start on this long-planned deep-water port for the community. Nome has a city dock, but the $10 million in the bond issue will fund planning and permitting for an extension. Both Kotzebue and Nome are plagued by shallow water offshore requiring some of Nome’s freight and all of Kotzebue’s to be offloaded offshore to shallow-draft “lightering” barges, which raises costs. Other parts of the bond proposal contain $15 million for boat harbor upgrades in the Haines Borough, which is represented by Rep. Bill Thomas, who co-chaired the House Finance Committee. Sitka, represented by Sen. Bert Stedman, who co-chaired the Senate Finance Committee, would get $7.5 million for a dock at the city’s Sawmill Creek Industrial Park. Sand Point, on the Alaska Peninsula, would get $2.5 million for local road reconstruction; St. George in the Pribilof Islands would get $3 million for harbor reconstruction; Togiak, a western Alaska coastal community, would get $3.3 million for a waterfront transportation facility; Bethel would get $4 million for harbor dredging; Newtok, another western Alaska village threatened by coastal erosion, would get $4.1 million for an emergency evacuation road. Many of these smaller western Alaska projects were ushered through under the guidance, indirectly and directly, of Sen. Lyman Hoffman, co-chair of the Senate Finance Committee. Kodiak would receive $15 million for a pier replacement. Kodiak is represented by Senate President Gary Stevens. The diversion of funds from the Anchorage port project and Mat-Su rail extension arose partly because legislators last spring were unclear of whether the Anchorage port had a clear plan for finishing construction and repairing defects from earlier work. The port is now working with the U.S. Army Corps of Engineers, who has retained CH2M Hill, on a plan for finishing the project. Similarly, there were questions by some legislators about the commercial justification for the Mat-Su rail extension, and whether there would really be the use of the extension, and the port, that the borough believes will be the case. The surprise in the Legislature’s bond deliberations is over how Emmonak lost out in the funding. The $10 million for that community’s dock was enough to get the project completely built. Unlike most of the other small projects in the bond package, Emmonak was “shovel ready” with all the engineering work done, according to Christine Klein, Calista Corp.’s Chief Operating Officer. Calista was working with Emmonak on the project. It’s uncertain how much Emmonak will now be able to do with only $3 million. However, some of the other projects, such as Kotzebue’s Cape Blossom road and port, also had separate funding in the Fiscal 2013 state capital budget, although it will take more money to get that project actually built. Some of the other projects in the bond proposal also had separate appropriations in the capital budget, legislative sources said. As general policy, there is always a healthy debate over whether it is better to borrow money for capital improvements and pay interest or whether, if the state has the cash, it is better to just pay for the projects and avoid the interest payment. It’s a judgment call in the end. With interest rates very low, borrowing at this time seemed attractive to the governor and lawmakers.

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