Tim Bradner

State officials target mid-2015 for workers' comp changes

A new method of paying medical fees for injured workers under the state workers’ compensation program won’t be in place until mid-2015, and it will take more time for insurance companies to judge any effects on lowering costs so that adjustments can be made in premiums paid by employers. That’s the word from state officials in charge of implementing House Bill 316, a bill passed by the Legislature in April changing the way medical care is paid for under workers’ compensation. First, though, Gov. Sean Parnell must sign the bill, said Mike Monagle, director of the state Workers’ Compensation Division. Assuming Parnell approves the measure, the next step will be to reactivate the Medical Rate Advisory Committee, an advisory group to the state Workers’ Compensation Board that has been inactive in recent years, Monagle said. Under HB 316, the committee will devise the new procedure for paying medical costs and then update it yearly, he said. Recommendations will be made to Dianne Blumer, state commissioner of Labor and Workforce Development, and would be adopted by the state Workers’ Compensation Board. The current procedure is for medical providers to be paid at the 90th percentile of fees considered “usual, customary and reasonable” for certain procedures. Those will be changed to a system based on Medicaid and Medicare rates for the procedures that are adjusted with a “conversion factor” for local conditions. Rep. Kurt Olson, R-Soldotna, prime sponsor of HB 316, said the 90th percentile system tended to drive up overall medical costs by setting rates near those charged by the most expensive health care providers. The Alaska Medicaid and Medicare rates already have a geographic differential, Monagle said, but the medical review committee will derive the conversion factors to make additional adjustments. “There are some providers who are worried that the new system will be used to drive down rates to near those of Medicare, at which point many would be unable to serve injured workers. The sponsor (Olson) told them that isn’t the intent,” Monagle said. “On the flip side of this, we all know of cases where certain specialty procedures in Alaska are priced several times the levels of other states with no apparent relation to actual cost,” he said. In studies of Alaska’s health care market, the Alaska Health Care Commission has blamed large differences in price to lack of competition for certain specialized services in the state. Thirty states now use similar procedures of using Medicaid and Medicare rates adjusted by conversion factors, Monagle said. The expectation is that the system will reduce high medical costs of the current system which given Alaska the highest workers’ compensation insurance premiums in the nation despite a workplace safety record that seems to be getting better every year, Monagle said. State law requires employers to carry insurance to pay for medical costs and in some cases lost time for employees injured on the job. In 2013 there were 19,000 workplace injuries, some minor and some major, in Alaska, Monagle said. There are questions in the medical community as to how the new system will actually work. The Medical Services Review Committee will have to grapple with developing Alaska-specific conversion factors after the committee is reactivated, Monagle said. The goal is to have a proposed new system by the end of the year, after which regulations will have to be developed, published and public hearings held. All that will take time, which means it’s likely the new system won’t be fully up and running until the middle of next year. Monagle said the first task is to review who is now on the committee, which hasn’t met since 2009. Blumer, the state labor commissioner, may want to make changes in the committee’s membership. People serving on the committee will also be asked if they want to continue in its new, more active role, Monagle said. The from 2005 to 2009 the review committee worked with a legislative task force on workers’ compensation on ideas of changing the medical fee structure but ultimately no change was made. The current 90th percentile system has been in place for years, Monagle said. Workers’ compensation medical costs in Alaska are increasing at about 10 percent per year compared with an annual inflation of 4 percent in the medical cost component of the Anchorage Cost of Living, Monagle said. Anna Latham, a legislative aide to Olson, said, “Medical costs constitute 76 percent of workers’ compensation claims in Alaska, which has a serious impact on premium rates paid by all Alaska employers.” “The result is that Alaska has the highest workers’ compensation premiums in the nation. Medical costs under the program are continuing to rise despite a 14 percent decline in claims by injured workers,” due partly to employers’ workplace safety improvements, Latham told the House Labor and Commerce Committee in hearings on HB 316 held last spring.

Oil and gas industry needs 7,500 trained workers

Alaska needs 7,500 trained, highly skilled oil and gas workers to meet industry demand by 2018, according to a new report produced by the Alaska Department of Labor and Workforce Development. Mega-projects like the Alaska LNG project are not included in those totals and will increase the demand. The pipeline and LNG project itself would not be in construction until after 2019, but if it appears to be proceeding in 2016 and 2017 it would have the effect of accelerating other projects, whose sponsors would not want their projects to get caught in shortages of skilled labor and logistics backlogs due to the big gas project.  “The 7,500 estimate is conservative based on what we see happening in the market right now,” without the gas project, said Wanetta Ayers, business partnerships director in the Labor Department. The estimate is a combination of 5,500 workers needed to replace those currently in the industry who are expected to retire in the next few years, and 2,000 additional workers to accommodate expected growth in the industry. Many experienced industry workers are approaching retirement and it will take time to recruit and train replacements. As new projects that are planned come into better focus the workforce development plan will be recalibrated. Employment in oil and gas, by contractors and producing companies, has been increasing for years due partly to increased maintenance on the aging North Slope fields but more recently due to a rapid increase in new development activity on the Slope and in Cook Inlet. Industry employment reached 13,400 in March, a record for monthly employment, according to Labor Department statistics. In 2011, workers in the industry earned $1.9 billion, or 13.2 percent of all Alaska payroll earnings, according to the workforce report. “Alaska oil and gas occupations offer some of the highest wages in the state. Average annual earnings in the industry were over $120,000 in 2011, nearly two and a half times than average for the state,” the report said. The new workforce plan is an update of the Alaska Oil and Gas Strategic Training Plan first published in 2008. The updated version has a sharper focus on education and training needs. It identified institutions offering training and the various incentives and resources available for students, and outlines a plan to step up coordination with schools on career awareness. Most jobs in the industry require education beyond high school, whether vocational or in a traditional university. In 2011 there were 7,600 young Alaskans who graduated from high school or received a GED, but studies of the workforce show that, on average, almost a quarter of those do not proceed with further education. The workforce plan focuses on the next five years, when several new development projects are expected, and is the work of a task force of oil and gas industry officials aided by education and training advisors.  “The Alaska Oil and Gas Workforce Development Plan recognizes the needs of the industry today and in the coming years,” said Labor and Workforce Development Commissioner Dianne Blumer. “The plan also anticipates the new workforce demand created by increased investment and a portfolio of new projects.  “To prepare Alaskans to claim the thousands of jobs that will be available, we must have a comprehensive strategy that aligns our workforce development system with workforce demand.” Less than a decade ago, nearly 40 percent of young Alaskans left for education and jobs Outside. That trend is now changing. More Alaskans are remaining in the state for higher education and are also motivated by increased employment opportunities. “We are now focusing on a workforce development system that is a combination of education, training and timing,” Blumer said. “We must be prepared to produce work ready Alaskans just as increased demand is emerging. Students in our middle and high schools will comprise much of the work force for these future projects.” A goal of the 2008 workforce plan was to encourage industry and schools to work together to increase awareness among young people of career opportunities in natural resource industries. A second objective was development of integrated career and technical education system to align and coordinate the work of training institutions with employers. Third, there was to be increased opportunities for registered apprenticeships in skilled occupations. One successful outcome of these and other initiatives was the development of a pipeline training program based in Fairbanks which to date has provided training to 1,646 workers. “Based on a review of wage records three years after exiting these training programs, 80 percent of these individuals were represented on Alaska payrolls. Wages for these individuals increased by slightly more than 30 percent or more than $13 million since receiving training,” according to the new workforce plan.

Decisions upcoming for C-P projects in NPR-A

The U.S. Bureau of Land Management expects to complete a final supplemental environmental impact statement on ConocoPhillips’ Greater Moose’s Tooth 1 development in the National Petroleum Reserve-Alaska by September, and a Record of Decision for the project about a month later. The ROD will clear the path for other federal agencies to issue permits, such as the U.S. Army Corps of Engineers’ Section 404 permit on wetlands, BLM spokeswoman Erin Curtis said. Public comments on the draft supplemental environmental impact statement, or SEIS, closed April 22. ConocoPhillips is developing the project with its minority partner, Anadarko Petroleum Co. GMT-1 and CD-5, another project now in construction, would be the first commercial oil projects developed in the 23 million-acre National Petroleum Reserve-Alaska. Although NPR-A is federal land, the State of Alaska will receive state production tax revenue and a share of federal royalties from any production. Assuming the permits for GMT-1 are in hand, and no serious regulatory problems have surfaced to date, ConocoPhillips spokesman Natalie Lowman said the company board of directors could give the final go-ahead for GMT-1 late this year. At the same meeting, Lowman said the board will also decide on two other proposed ConocoPhillips projects: a new drill site and an expansion of the West Sak viscous oil project, both in the Kuparuk River field. However, the outcome of a referendum in the Alaska August primary election that could repeal the 2013 reform of the state oil production tax will also be weighed by the company’s board. For now, assuming the board’s approval is given, ConocoPhillips’ schedule for GMT-1 calls for ordering long lead-time items like steel late this year and to begin construction in early 2016 of an 8-mile gravel road and 12-acre gravel production pad along with bridge piers for two stream crossings, according to the company’s plan submitted to BLM. In the first quarter of 2017, installation of vertical support members for pipelines and construction of the pipelines, power systems and production facilities would be done. Drilling of production wells would begin in the second quarter of 2017 with first production late that year, according to the schedule. The plan also calls for a bundle of four pipelines to serve GMT-1. This includes a 20-inch pipeline to carry fluids from the site, a mixture of crude oil, gas and water, to the CD-5 pad from where it will be shipped on to oil and gas processing facilities in the Alpine field. The processed, sales-quality crude oil would be shipped from the Alpine field to the Trans-Alaska Pipeline System through the existing Alpine field pipeline. GMT-1’s pipeline bundle also includes a 14-inch pipeline to transport water —either seawater or produced reservoir water — for pressure maintenance along with two six-inch pipelines, one to carry lean gas from the Alpine field for pressure maintenance and a second to carry a miscible injectant, a mixture of natural gas liquids, for enhanced oil recovery. GMT-1 is expected to produce about 30,000 barrels per day at peak. The initial development program at GMT-1 calls for 33 wells. About 400 construction workers will be employed at peak. ConocoPhillips is also drilling exploration wells to test for the possibility of further development in the area. This winter the company drilled two wells, the “Rendezvous 3” test to assess the potential for a future GMT-2 several miles west of GMT-1, and “Flat Top,” a well near GMT-1 drilled to evaluate acreage that site for future expansion. Meanwhile, construction is proceeding on CD-5, a $1 billion project near the Alpine field that, once complete, will also support the development of GMT-1 farther west. About $400 million will be spent in 2014 on CD-5 construction with about 600 workers employed this year mostly in the winter-spring construction season. Three small bridges for the project are now complete with the final bridge to be finished by early 2015. Drilling of production wells will also start in early 2015.

Labor market tightens as tourist season ramps up

If you’re out for dinner in a restaurant this summer, you may find the wait-time for your meal is a little longer. Seasonal employers say they are experiencing difficulties in hiring certain types of workers — kitchen staff for example — as the tourist season begins. Bruce Bustamante, vice president for Princess Tours, says his company is having no problem with the “front-end” needs such as customer service, baggage handlers and front-desk staff, mainly because Princess conducts an aggressive pre-season recruiting in the state. However, there are difficulties recruiting for the back-end kitchen staff, Bustamante said. Operators of larger seasonal hotels in outlying areas are feeling the pinch more but it’s being felt in urban restaurants as well. Even Anchorage’s iconic Moose’s Tooth Pizzeria, where business seems to be roaring summer and winter, has had challenges this spring but solved the problem by raising wages in the kitchen, said Dan Fiacco, the company’s general manager. There is still a problem retaining skilled kitchen staff, however, because workers in that field tend to be highly mobile. Moose’s Tooth is having no problem finding front-end customer-service staff, however, he said. Neal Fried, a labor economist with the Alaska Department of Labor and Workforce Development, said was he was surprised to hear about Moose’s Tooth because the company has a reputation of paying well and offering good health benefits. Bill Popp, president of the Anchorage Economic Development Corp., agrees the labor market is tight in Anchorage and hiring problems are being found for many restaurants and retailers in Anchorage. This is being aggravated by the opening of several new restaurants and retail outlets like Hard Rock Café and Texas Roadhouse, and retailers like Cabela’s and the new, expanded Natural Pantry. The rebound in the tourist industry will keep things tight. “Retail has exploded,” Popp said. “We’re up 400 jobs so far this year, and ‘leisure and hospitality’ (restaurants and bars) are up 350,” compared with the same period of 2013. Retail, restaurants and hotels mostly draw from the same pool of relatively young workers. Popp also said wage inflation, at least in Anchorage, tends to aggravate things. The state’s oil and gas industry is booming and the ripple effects of that spreads all through the economy, the effect being that workers in fields with more modest pay scales are drawn to higher-paying jobs. Other factors in the Anchorage economy are also at work, such as the shortage of affordable housing. “Anchorage is the 20th most expensive housing market in the nation. It takes an income of $40,000 a year to afford a one-bedroom apartment,” he said. That takes most retail and food and beverage workers out of the rental market, unless there are two incomes in a family, because the average wage for a retail worker was $29,400 a year in 2013. For a leisure and hospitality worker, it was $21,250 a year in 2013, according to state labor data. “Finding good workers in these fields is very challenging, unless you’re willing to pay more,” Popp said. Fried acknowledged the problem but downplayed its broad significance, and said spot labor shortages have happened before. “It is a tight labor market and our unemployment is very low, but this is not a new thing,” he said. What is a surprise, however, is that Alaska is not seeing the level of in-migration that the state has experienced before, which plays into the labor market. Last year, in fact, there was net out-migration. There are always people moving to and leaving Alaska but in 2013 about 2,800 more people left the state than came to Alaska, Fried said. In 2011 there was net in-migration of 1,215 and in 2012 there were 1,118 more people coming to the state than leaving. “The U.S. job market is still not that great, and we’re surprised that there are not more people coming here from the Lower 48,” Fried said. In previous periods of U.S. recession, in the 1970s and again in the 1980s, there was substantial in-migration of people looking for work, but not this year, he said. “One factor is that our wage is not a premium anymore,” at least compared with many states, Fried said, particularly the west coast states Alaska tends to draw from.  For large seasonal employers like Princess Tours, finding, hiring and in many cases training about 3,000 seasonal workers very spring is difficult. Princess is doing fine this year in staffing for its needs in the major cities, where there are many repeat workers from year to year, but finding people for lodges in outlying areas like Denali Park is always a big challenge, even though the company provides housing. Bustamante said Princess aggressively recruits in Alaska at job fairs and works with the King Career Center in training young people for workers in the visitor industry. These efforts generally result in about a third of Princess Tours’ seasonal workers being Alaskan. The percentage of job applications from Alaska is about 29 percent, Bustamante said, but the company typically hires about half the Alaskans who apply, he said. Julie Saupe, president of Visit Anchorage, said, “Every year it’s tough. We hear anecdotes of problems, but everyone seems to be getting the people they need,” at least in Anchorage. What is on peoples’ minds in the visitor industry, however, is the prospect of major industrial projects drawing away workers. Although it is several years away, Saupe said many local hotel and restaurant owners are looking at the possible construction of a major gas project with dread, fearing the loss of employees like happened during the TAPS oil pipeline boom of the 1970s. Even though construction of a major gas project might not begin until after 2019 if it appears to be proceeding many developers of smaller projects will push their schedules forward to get in front of the big project, which will dominate the economy.

ISER backs Revenue on tax impact

Scott Goldsmith, the University of Alaska’s venerated senior economist, has stepped into the political snake pit of the oil tax repeal debate. Goldsmith is well-known for his study of Alaska fiscal trends, which have been underway for almost two decades, but his new study comparing Senate Bill 21, the oil production tax regime enacted by the Legislature in 2013, with the tax that preceded it known as ACES, has stirred a tempest in the political community. A key finding in Goldsmith’s study is that at current oil prices and production costs, the two taxes bring in about the same amount of revenue. Opponents of the tax change have labeled it a “giveaway” to the industry. A hotly contested referendum question will appear on the state primary election ballot in August. A campaign to defeat the referendum, “Vote No on 1” has been fired up, while a campaign to defend it, “Vote Yes! Repeal the Giveaway” has also formed. The debate will be charged and contentious, with supporters of the repeal arguing the tax change gives away too much, while supporters of SB 21 say the change was necessary because badly-needed industry investment was leaving Alaska because of ACES, and that the decline in oil production from the North Slope was accelerating. Since the Legislature approved the tax change in April 2013 — it became effective this Jan. 1 — industry activity on the Slope has picked up, and more barrels of oil are being produced compared with what had been forecast. Goldsmith attempted to sort out the differing claims and his work, in general, validated conclusions the state Department of Revenue had reached earlier this year, and briefed to legislators in February. So far no one has challenged Goldsmith’s calculations although one critic, who asked not to be identified, complained that “the analysis is written like a press release for the industry,” rather than an academic paper. Others complained about the venue for the release of the study, a meeting of Resource Development Council members, who generally opposed ACES and support SB 21, and the fact that Northrim Bank, which has supported SB 21, contributed to the university to support Goldsmith’s work, although the bank’s support goes to a range of research initiatives on the Alaska economy. A more focused criticism from state Sen. Hollis French, D-Anchorage, who is Senate Minority Leader and a critic of the tax change, is that the analysis is incomplete and doesn’t present the overall picture because it doesn’t adequately present revenues lost during a period of high prices. For next year, however, the state Revenue Department has found the new tax will bring in more revenue in fiscal year 2015 than ACES would have, under the oil prices and costs that are now estimated. The latest estimate is that SB 21 will bring in $1.74 billion in FY 2015 compared with $1.625 billion had ACES still been in effect. However, prices and costs are unpredictable and in some years ACES may have brought more revenue, while in some years the new tax under SB 21 will yield more, Goldsmith said in his analysis. Department of Revenue analysts have also said that that would happen. Goldsmith’s study is on the university’s Institute of Social and Economic Research website, as Web Note No. 17, “Alaska’s Oil and Gas Production Tax: Comparing the Old and the New.” While the new tax law might impose higher taxes on companies in some years the industry still supports the change, Goldsmith told the RDC, because the new tax can be modeled more easily and is, therefore, more predictable for the companies as they plan future investments. “Also, under ACES there was no tax reduction for ‘new’ oil,” developed by the companies, Goldsmith told the RDC. That incentive, which isn’t given unless there are actual new barrels produced, is a key difference between ACES and SB 21, he said. Broadly, Goldsmith’s conclusions are that the tax change had little to do with large budget deficits the state will experience this year and next year. Those revenue reductions are due mainly to declines in oil prices and production, and higher production costs, Goldsmith said. Also, if oil prices stay in the same range as today, which is expected, and production costs continue to rise, which is also expected, the new tax can be expected to generate more revenue. However, if oil prices rise and production costs stay the same or drop, the ACES tax would generate more income. In a separate part of his study, Goldsmith looked at the job-creating effects of new Alaska investment by the industry, which the tax change is expected to generate. Using a variety of economic analysis tools, Goldsmith found that $4 billion in new industry investment will result in 5,000 new public and private sector jobs per year in the state over 20 years, with more than $300 million per year in additional wages and salaries paid. In his criticism, French said Goldsmith should have noted that if oil prices do rise again, as happened following 2007 when the ACES tax was enacted, the new SB 21 would result in a large loss of revenue compared with the former tax, French said. “That’s the giveaway, what we lose during a high price spike,” French said. “Between 2007 and 2013 we earned $8.5 billion as a result of ACES. Had SB 21 been in effect we wouldn’t have that money in our reserve accounts today.” Another criticism, French said, is that production costs are estimates given to the state by industry and that the Department of Revenue has done no audits of the costs. “The department is woefully behind on audits,” French said, so the estimates given by the companies should be taken with a grain of salt, for now at least. In looking at cost increases in his analysis, however, Goldsmith goes to other sources to attempt to validate the trend of rising production costs. In his talk to the Resource Development Council May 1, Goldsmith cited world industry capital cost indexes which show the oil and gas capital cost index at 230 in third quarter 2012 (in 2000, the base year, the index was 100) compared with a more gradual rise in general inflation (about 130 in late 2012 over 100 in 2000). Oil field labor costs have also risen, Goldsmith said. He calculates that the per-barrel labor cost was $10 in 2011 compared with less than $2 in 1981. Oil producers are also getting more water, four times as much, and less oil, with fluids being pumped up, Goldsmith told the RDC. Finally, all these costs, such as handling more water, are spread over fewer barrels of oil being produced. In 1980 the average North Slope well produced 3,500 barrels per day, Goldsmith said. Today the average is about 250 barrels per day. All that drives up the production cost per barrel, which directly affects the net value of the oil against which the state production tax is levied.

$5.4M sale has first AK Peninsula bids since '07

Bidding was modest at the state’s annual Cook Inlet and Alaska Peninsula “areawide” lease sales May 7, with bids coming from independent companies and most of those in Cook Inlet from companies already established there. A surprise, however, is that there were three bids on tracts near Port Moller on the Alaska Peninsula in southwest Alaska. The state Division of Oil and Gas routinely offers leases on state-owned lands on the peninsula when it makes the Cook Inlet acreage available. Until this year, however, there have been no bids for Alaska Peninsula leases since 2007. Shell acquired several leases in 2007 but subsequently dropped them. This year two small independents, Auxullium Alaska Inc. and Novus Terra Ltd. offered bids on three parcels. All three leases were near shore and southwest of Port Moller. In the Cook Inlet sale, 152 state-owned oil and gas tracts were offered and 35 sold for about $5.4 million in high bids, state Oil and Gas Division Director Bill Barron said. All bids were from independent companies. No major companies submitted bids. Bids for 10,280 acres of leases sold on the Alaska Peninsula totaled $51,400, Barron said. Cook Inlet leases sold totaled 108,543 acres. “Eight bidders participated in the Cook Inlet sale and the high bids of the sale, of $153 per acre came from Woodstone Resources for two tracts,” Barron said. The state had set a minimum bid of $25 per acre. Hilcorp Energy acquired 13 tracts in the sale with bids ranging from $30 to $40 per acre, while Apache Alaska Corp. won seven tracts with bids that ranged mostly from $26 to $50 per acre but with an $86-per-acre bid on one tract. Hilcorp is the major oil and gas producer in the Inlet, having acquired Chevron Corp. and Marathon Oil Co. properties in 2012 and 2013. Apache is engaged in a multi-year exploration program. Other companies participating included Cook Inlet Energy, a small producer on Cook Inlet’s west side, which acquired four tracts near its existing producing areas; NordAq Energy, which acquired four offshore tracts in North Cook Inlet, and Woodstone Resources, acquiring two offshore tracts also in North Cook Inlet. On most tracts there were single bids but a handful attracted two bidders and one brought three. Apache beat out Hilcorp in bids for two leases, with Hilcorp’s bids of $51.33 and $53.22 per acre topped by Apache’s offer of $86.33 per acre on one lease and $86.53 per acre on the second. All of the leases were for 10-year terms with royalty rates set at 12.5 percent. The annual rents range from $1 per acre to $3 per acre in the peninsula sale to $10 per acre to $250 per acre on the Cook Inlet tracts, Barron said. Cook Inlet has seen a redevelopment of industry activity and new production in recent years, and the state’s annual areawide sale, in which all unleased state land in the region is offered, is usually seen as a barometer of activity. The results in this sale, while modest in terms of revenue to the state, demonstrate continued interest by the larger independents, such as Hilcorp and Apache, and the appearance of new firms interested in the Inlet, such as Woodstone Resources.

NANA Construction becomes big employer in Big Lake

NANA Development Corp. has become a major employer in the Matanuska-Susitna Borough at the company’s module fabrication facility near Big Lake. About 100 to 150 people are working there at any given time depending on the flow of work, according to Sagen Juliussen, Alaska manager for Grand Isle Shipyard, a NANA subsidiary that operates the facility. Grand Isle Shipyard is based in Louisiana and does support work for offshore oil and gas platforms. It recently merged with NANA Construction, which provides services to companies in Alaska’s petroleum and mining industries. NANA bought the 27-acre Big Lake tract in 2008 with one building that supported light manufacturing. More facilities were added as the plant was developed to build light modules, mostly remote housing units, and heavy steel units in oil and gas and mining modules. Facilities were also installed for the manufacturing of control panels. A module unit for BP’s Gathering Center 2 was recently completed and moved to the North Slope. NANA decided to build its plant in the Mat-Su Borough so as to avoid the extra trucking distance from an Anchorage location as well as issues of moving over-sized module units out of the municipality. Locating at Big Lake also allowed NANA to use Port MacKenzie, the Mat-Su Borough’s port on Knik Arm, for loading sea-lift modules and bring materials in. The facility is currently capable of supporting the fabrication of over 30 modular units concurrently and, with the adjacent laydown areas, of storing over 50 units. “The majority of our projects have been for North Slope clients but we have also done work for Cook Inlet oil and gas producers and for the Red Dog Mine,” said Juliussen. NANA has been involved in oil, gas and mining support work since the mid-1970s. Its acquisition of Grand Isle Shipyard in Louisiana represented a major expansion into the U.S. Gulf of Mexico. Through the merger of NANA Construction with Grand Isle, the experience of the Louisiana company has been brought to Alaska.

Lease sale nets $5.4M, Alaska Peninsula draws first bids since 2007

Bidding was modest at the state’s annual Cook Inlet and Alaska Peninsula “areawide” lease sales May 7, with bids coming from independent companies and most of those in Cook Inlet from companies already established there. A surprise, however, is that there were three bids on tracts near Port Moller on the Alaska Peninsula in southwest Alaska. The state Division of Oil and Gas routinely offers leases on state-owned lands on the peninsula when it makes the Cook Inlet acreage available. Until this year, however, there have been no bids for Alaska Peninsula leases since 2007. Shell acquired several leases in 2007 but subsequently dropped them. This year two small independents, Auxullium Alaska Inc. and Novus Terra Ltd. offered bids on three parcels. All three leases were near shore and southwest of Port Moller. In the Cook Inlet sale, 152 state-owned oil and gas tracts were offered and 35 were sold for about $5.4 million in high bids, state Oil and Gas Division Director Bill Barron said. All bids were from independent companies. No major companies submitted bids. Bids for 10,280 acres of leases sold on the Alaska Peninsula totaled $51,400, Barron said. Cook Inlet leases sold totaled 108,543 acres. “Eight bidders participated in the Cook Inlet sale and the high bids of the sale, of $153 per acre came from Woodstone Resources for two tracts,” Barron said. The state had set a minimum bid of $25 per acre. Hilcorp Energy acquired 13 tracts in the sale with bids ranging from $30 to $40 per acre, while Apache Alaska Corp. won seven tracts with bids that ranged mostly from $26 to $50 per acre but with an $86-per-acre bid on one tract. Hilcorp is the major oil and gas producer in the Inlet, having acquired Chevron Corp. and Marathon Oil Co. properties in 2012 and 2013. Apache is engaged in a multi-year exploration program. Other companies participating included Cook Inlet Energy, a small producer on Cook Inlet’s west side, which acquired four tracts near its existing producing areas; NordAq Energy, which acquired four offshore tracts in North Cook Inlet, and Woodstone Resources, acquiring two offshore tracts also in North Cook Inlet. On most tracts there were single bids but a handful attracted two bidders and one brought three. Apache beat out Hilcorp in bids for two leases, with Hilcorp’s bids of $51.33 and $53.22 per acre topped by Apache’s offer of $86.33 per acre on one lease and $86.53 per acre on the second. All of the leases were for 10-year terms with royalty rates set at 12.5 percent. The annual rents range from $1 per acre to $3 per acre in the peninsula sale to $10 per acre to $250 per acre on the Cook Inlet tracts, Barron said. Cook Inlet has seen a redevelopment of industry activity and new production in recent years, and the state’s annual areawide sale, in which all unleased state land in the region is offered, is usually seen as a barometer of activity. The results in this sale, while modest in terms of revenue to the state, demonstrate continued interest by the larger independents, such as Hilcorp and Apache, and the appearance of new firms interested in the Inlet, such as Woodstone Resources.

First LNG ship since 2012 arrives at ConocoPhillips plant near Kenai

The first liquefied natural gas tanker arrived Friday morning at the ConocoPhillips LNG plant at Nikiski, near Kenai, following the company’s reactivation of the plant this spring. The plant has been in a suspended status since late 2012. The Excel is owned and operated by the Belgium-based Exmar shipping group. ConocoPhillips spokeswoman Amy Burnett could not say how long it will take to load the vessel or the destination of the cargo, although presumably it is in Asia. ConocoPhillips plans six LNG shipments this year at approximately one-month intervals, Burnett said. The company has authorization from the U.S. Department of Energy to export LNG from the Kenai plant for two years. The plant was built in 1969 by Phillips Petroleum and Marathon Oil. Phillips later merged with Conoco and subsequently purchased Marathon’s 30 percent share. LNG shipments to Japan were made from 1969 to 2010 under long-term contracts with Tokyo Gas and Tokyo Electric, when the contracts expired. Shipments since then have been on a per-vessel basis. Plant operations and LNG exports were suspended in late 2012 as natural gas reserves in Cook Inlet were depleted. The measure was taken to reserve gas for regional utilities, which are also supplied by ConocoPhipps. Utilities’ needs are now met through recent new gas discoveries by Hilcorp and other companies, which has allowed for a resumption of exports.

Competitive Instincts

Marc Langland remembers it as the most depressing day of his life. It was in 2007, in Juneau, and Langland and fellow Alaska businessman Jim Jansen were working the capitol hallways urging legislators not to pass a draconian new oil tax being pushed by then-Gov. Sarah Palin. A third of Alaska’s economy depends on oil, and state government depends on the industry for 90 percent of its revenues. Don’t wreck a good thing, Langland and Jansen told lawmakers. “They told us they weren’t in favor of the tax either but that they couldn’t go against Palin because she was so popular,” with the public, Langland recalled. “Either they were lying to us or they just lacked guts.” One legislator who did have guts was Rep. Ralph Samuels, an Anchorage Republican, who was the only legislator who voted no on Palin’s proposals. Langland and Jansen were infuriated, but they also realized that the legislators weren’t getting many phone calls from constituents, and that few Alaskans, few Alaska businesses and few community leaders really understand the connection between the state’s prosperity and one of its major industries, particularly oil, the one that pays the bills for state government. “Most of the public just does not understand that our state government can destroy our economy in the blink of an eye (through tax policy). The petroleum industry needs to invest tremendous capital to get the maximum production out of the ground, and their success in doing this is critical to our economy,” Langland said. When Langland and Jansen came back to Anchorage they began talking to people in the business community, and this led to the formation of the “Make Alaska Competitive Coalition,” a grass-roots organization to educate Alaskans about the importance of petroleum industry. It was the start of a journey. Jansen’s company, Lynden Transport, does a lot of work for oil and gas customers, so he has a stake in the issue. Langland has a stake too, but more indirect. Northrim Bank, where Langland was then CEO, serves a broad range of small and medium-sized business customers as well as individuals. The stake for Northrim’s customers is in the health of Alaska’s economy. Palin’s tax law, which was named Alaska’s Clear and Equitable Share, or ACES, imperiled that, but the connection wasn’t well understood. “I was particularly concerned that the business community was not connected on this, to the extent it should be. Business was certainly not as well organized as, say, the environmental community,” Langland said. “This is important to all of us, whether we’re in the private or public sector. An economy that is dominated by government and one industry is very fragile. It doesn’t create wealth like an economy dominated by the private sector. We’re not like the Lower 48 where there can be three or four large industries.” Informing Alaskans about their economy and urging citizens to take personal responsibility for keeping it healthy, has become a passion for Langland, now retired as Northrim’s CEO but still active as its chairman and president. Langland still lives in the state part of the year. “Marc has a strong feeling that citizens need to understand their economy and he constantly works to get this across. People need to have a commitment to preserving the economy because it supports their communities,” said Jeanine St. John, with Lynden Transport, a longtime friend. Laurie Fagnani, with MSI Communications, has worked with Langland and said, “Marc’s philosophy is that with education comes awareness and healthy discussion,” about the economy. “He is a big believer in sustainability, and this comes about because he is a businessman who understands that Alaska has to be able to get its products to market profitably. He gets this.” Forming a coalition The Make Alaska Competitive Coalition launched in 2011 with the backing of a diverse group of supporters including labor and Alaska Native corporation leaders, former University of Alaska President Mark Hamilton and two former governors, Tony Knowles and Bill Sheffield, both Democrats. Things had started happening when Palin resigned in 2009, midway through her first term, and Lt. Gov. Sean Parnell became governor. Parnell was elected in 2010, and began a three-year effort to reform the ACES tax and reverse a drain of industry investment from Alaska. Langland, Jansen and others supported that through Make Alaska Competitive and the governor’s effort finally resulted in passage of Senate Bill 21 in 2013, replacing ACES with Parnell’s own tax law, the “More Alaska Petroleum Act.” The ink was hardly dry on Parnell’s signature on the law when new industry investment began to flow back into the state. ConocoPhillips almost immediately announced it would put a new drill rig to work in the Kuparuk River field, and this was soon followed by announcements of new projects by BP for the Prudhoe Bay field. But then critics of the tax change, having failed to stop it in the Legislature, mounted a voter referendum to repeal it, and gathered sufficient signatures to put the question on the August 2014 primary election ballot. “We had to get back in the saddle again,” Langland said. Make Alaska Competitive was cranked up again and new, sister organization was formed to help fight the referendum: “Keep Alaska Competitive.” Make Alaska Competitive was never a big-money campaign and neither is Keep Alaska Competitive, which is mostly business-to-business networking aimed as helping medium and small businesses educate employees about the upcoming vote. “We solicited contributions of any size. $500 was a lot, and $5,000 was a big deal. We had to make every dollar count,” recalls Laurie Fagnani, of MSI Communications, who worked with the MAC campaign. There wasn’t enough money for television but there was for some radio advertisements. Most of the activity was in-person contact through presentations at chambers of commerce luncheons. Themes were developed like, “Fix ACES…unleash opportunities,” and “New oil, new jobs,” Fagnani said. The first goal was to educate people that something had to be done. Langland said it was tough to raise money because the organization wouldn’t solicit or accept donations from the petroleum industry. Make Alaska Competitive raised several hundred thousand dollars through two cycles of fundraising, but this was peanuts in terms of what’s spent on most political campaigns. Langland credits the supporters of Make Alaska Competitive. “We’ve had to go back to them twice,” once in the initial stage to make people aware of the problem with ACES, and the second when the Legislature was actively considering SB 21, he said. “They’ve been very patient. Now, with the repeal, we’re having to go back a third time.” Origin in opportunity The startup of Northrim Bank amid the wreckage of failed Alaska financial institutions in the depths of Alaska’s 1987 recession is now part of Alaska business history lore. It’s a story of entrepreneurship and pluck by the bank’s founders Langland and Arnold Espe, and should be required reading in business schools. Espe died a few years ago and Langland, having built Northrim from a startup into a successful and expanding financial institution now with more than $1.2 billion in assets and $12.3 million in income in 2013. Northrim’s story began in the early 1970s when Langland and Espe, who were friends and working for separate banks (Langland was at National Bank of Alaska) saw an opportunity to buy First National Bank of Fairbanks. This was then sold to KeyBank, which was just coming into Alaska. Espe and Langland stayed on to work for KeyBank but a large institution didn’t feel right, so the two kept an eye out for opportunities. It didn’t take long for those to appear, although they didn’t look like opportunities to others, which was important. In 1986, crude oil prices crashed. State government finances went into a tailspin. Then-Gov. Bill Sheffield had to cut spending sharply to keep the state government solvent. Unlike now there were no reserve funds, and the Permanent Fund, even if it was available to be tapped, wasn’t as fat as now. Sheffield had to slash the state capital budget virtually overnight, and by almost a billion dollars. That was big money in those days. The state’s economy, at that time still small but overheated with the spending of new state petroleum revenues, went into a sharp slump. Thirteen banks and other financial institutions failed, mainly due to being overextended on real estate. At the time Alaska was filled with construction workers building things, and banks were in a go-go phase lending to builders and others. When the state money dried up the workers left, newly-built homes and condos went unsold, and banks were stuck holding a lot of paper. There are opportunities in disaster. The state’s older, stronger banks, like National Bank of Alaska and First National Bank Alaska, quickly began buying up the better assets of the failed banks and doing quite well at it. Langland and Espe, wanting to work for themselves, sensed an opportunity to serve customers who, for one reason or another, wanted another option than NBA or First National. So they started a bank, with the state’s economy still in recession and business confidence at a low ebb. The two assembled a group of eight to 10 initial investors and $2 million in seed money and tried first to buy one of the failed banks. The U.S. Federal Insurance Deposit Corp. spurned the offer and wound up selling the assets to another bank, although for far less than Langland and Epse offered, Langland recalled. Timing is everything This was a critical juncture at Northrim, and in stepped Anchorage financial advisor Allan Johnston and his firm Wedbush Morgan Securities to help raise equity capital. There was some fortunate timing amid the tragic event of the Exxon Valdez hitting the rocks in Prince William Sound with the company spending big money on oil spill cleanup, stimulating the economy. This was the start of economic recovery. But there was bad timing, too — the run-up to the first Gulf War began in 1990, and raising money nationally was difficult. “There were just a handful of IPOs (Initial Public Offerings) in the fall of 1990, and we were one of them,” Langland recalled. Despite that, the offering raised about $8 million. There were challenges on the regulatory side, too. “The FDIC was still struggling with failed Alaska banks, so we were not well received, with a new bank,” Langland said. An innovative solution was to become chartered as a Federal Reserve Bank, a type of institution well known in the U.S. east but less so in the west. Espe’s contacts in the Federal Reserve helped facilitate this but it ultimately didn’t sit well with the western Federal Reserve Banks who were not used to the concept. Northrim was first chartered by the Federal Reserve and subsequently switched to become a state-chartered bank, which it has been ever since. Those were lean but also creative times. There was a period when the bank operated out of a trailer until the acquisition of Northrim’s current building on C Steet could be completed. Langland gives credit to a loyal group of 23 core staff, mostly veterans from failed banks, who brought their experience, and contact, to the infant Northrim. “We were able to distinguish ourselves from our competition with our people,” Langland said. The efforts of those people plus some creative advertising and marketing — that Langland credits to advertising consultant Art Hackney — made the difference. Two big breakthroughs came when two Alaska Native village corporations, Klukwan Inc. and Natives of Kodiak Inc., became equity investors and also deposited funds in the bank. To this day Northrim reserves two seats on its board for Alaska Native leaders, Langland said. Irene Rowan, former chair of Klukwan, and Tony Drabeck, of Natives of Kodiak, have been board members for years. A union pension fund from the west coast was also an early investor. Today Northrim’s record of steady growth has attracted continued interest and Langland said large institutional investors have typically held 58 to 61 percent of the bank’s shares over the years, which is typical of most small and medium-sized community banks in the U.S. Northrim is successful today by any standard. The bank has $1.2 billion in assets, with branches in Southcentral Alaska and Fairbanks, and since April 2014 in Southeast Alaska when Northrim closed on the purchase of Alaska Pacific Bank of Juneau, which operates branches in Southeast. Langland has also passed the helm of the bank to CEO Joe Beedle. Under Beedle the bank has launched creative new ventures like Enroll Alaska, an initiative of Northrim Benefits Group, to help Alaskans enroll in health insurance under the new federal Affordable Care Act. Alaska is a long way from Zearing, Iowa, population 500, where Langland grew up. Northrim is a long way, too, from Tri-County State Bank in Zearing, where Langland started his banking career. It was after graduating from the University of Iowa and a stint at a Denver bank that Langland became interested in Alaska. He joined National Bank of Alaska in 1965 and spent 12 years working for NBA in several Alaska communities, before joining Espe and embarking on an adventure in forming Northrim. Langland’s upbringing in a small Iowa town, where everyone knows and watches out for each other, shaped not just him but also the values he has infused in Northrim. Not his first rodeo Langland’s interest in connecting Alaskans to the health of their economy isn’t new. It actually started long before ACES and the current debate over SB 21. It was in the late 1990s when Langland became concerned about state government’s overdependence on petroleum and the need to diversify sources of state revenue and restrain spending. This was something Alaskans didn’t understand, and it was dangerous because sudden dips in oil prices can wreck havoc on state finances, which was aptly demonstrated in 1986 and again in 1998. The oil price crash of 1998, when prices plummeted to as low as $8 per barrel, created a financial crisis for state government. Prices eventually rebounded and the situation eased, but for Langland and many business leaders there were too many memories of the 1986 price crash and the sharp Alaska recession it caused. The 1998 crash created the impetus for the Alaska Fiscal Policy Council, formed as a nonprofit to conduct forums and issue policy papers. Ultimately the council stimulated the sponsorship of research on the state’s economy by the University of Alaska Anchorage’s Institute of Social and Economic Research, or ISER, said Cheryl Frasca, a former state budget director who was active with the Fiscal Policy Council. Northrim Bank became a major sponsor of the ISER’s work and has contributed $1 million over the years to support it, according to Dr. Scott Goldsmith, senior economist at ISER and the lead on the research program. There are six elements to the research program, and they include the state of Alaska’s economy and monitoring its health, and the importance of petroleum. Goldsmith gives Langland credit for being far-sighted: “He has a long-term view for the future of the state, and is one of the few people who seem able to see beyond the next legislative session.” Northrim isn’t the only business that supports ISER’s fiscal policy work, or even the only bank. First National Bank Alaska also supports the work and helps distributes Goldsmith’s reports. Two key findings from ISER’s research are that oil and gas supports, directly and indirectly, about one-third of the state’s economy, and that had oil never been discovered here, at least in the quantities found on the North Slope, Alaska’s economy would be about half the size it is now. “We would be about like Maine,” Goldsmith said — a great place to live but not a particularly great place to make a living. ISER’s more recent work has delved into the impending state budget gap and steps the Legislature can take to forestall a financial crisis in a few years. That is not a pretty picture. According to ISER’s latest work on that, if present trends continue the state will run out of money and still face a huge budget deficit in 2024. The budget deficits of fiscal years 2014 and 2015 state operating and capital budgets and the diversion of $3 billion from state cash reserves into public employee pension funds will accelerate that. Given the budget trend, Cheryl Frasca now thinks the Fiscal Policy Council’s work must be restarted. In recent years it has been picked up by Commonwealth North, an Anchorage-based business policy group that has a fiscal policy committee. Frasca thinks that work should be resumed and accelerated. “When I was budget director in 2006 our state operating budget was $2.2 billion. It is now over $5 billion. What the heck happened?” she asks. What happened was ACES and Sarah Palin. Palin’s ACES oil tax brought a surge of money into the treasury during an unprecedented oil price spike, but it wasn’t sustainable when oil prices fell and industry investment went south to oil fields in North Dakota and Texas. Meanwhile, with money in the treasury there was a huge run-up of spending, all in the years Palin was governor. That’s not a recipe for sustainability, and it is what worries Marc Langland. All of which goes back to his Iowa upbringing and Midwestern values. “People in Midwestern small towns live with basic values: Be straightforward, honest, and be involved,” Langland said. As anyone who knows him can attest, Langland lives those values and while he may be semi-retired from the bank he founded, he is hardly retiring from his passion for securing Alaska’s fiscal future.

AIDEA approves $50 million investment at Mustang field

Alaska’s state development corporation will invest $50 million in a $225 million oil processing facility for the planned Mustang oil field on the North Slope. The Alaska Industrial Development and Export Authority board approved the action April 24. Alaska-based independent Brooks Range Petroleum is developing Mustang, which has an estimated 24 million barrels of recoverable oil and is to begin production in late 2015, according to Brooks Range Chief Operating Officer Bart Armfield. Peak production, expected to be reached by 2017, is estimated at 12,000 barrels per day, or b/d. Production would increase to 15,000 b/d, the planned capacity of the process plant, in a second phase of drilling. Total development costs including the processing plant and development drilling of Mustang are estimated at $583 million, Armfield said. Eleven production and 20 injection wells, for gas and water, are planned in the development. Mustang is located between the Kuparuk River field and the Alpine fields, both producing. The deposit is in an advantageous location near the Alpine pipeline, a common carrier pipeline. AIDEA already has $20 million invested in Mustang through the development of an access road and the gravel pad for the process plant, which were both built last year. The field is expected to produce $300 million to $640 million in new state revenues and about $45 million in tax revenue to the North Slope Borough, the regional municipality, AIDEA’s deputy director for development, Jim Hemsath, told the authority’s board. About 200 to 250 construction workers would be employed in building the plant and related infrastructure, 100 in drilling, 50 in engineering and design work and 20 to 25 in ongoing operations at the plant, according to information presented to the authority’s board. The investment by AIDEA is structured to be temporary, with the state corporation being bought out by other partners within seven years, Hemsath said. During those years the authority will earn 10 percent on its investment, according to terms of the deal. The deal is being structured so that the process facility, Mustang Operations Center 1, will be jointly owned by AIDEA and CES Oil Services Pte. Ltd., or CES, in a new company, MOC1, LLC. CES is a subsidiary of Charisma Energy Services, an affiliate company of Ezion Holdings, a Singapore-based investment firm active in energy. Ezion is also AIDEA’s partner in the Endeavour jack-up rig in Cook Inlet. The new jointly-owned company will contract with Brooks Range to build and operate the plant. Brooks Range is also responsible for developing the field itself. In a related development, Brooks Range is reported to be close to an agreement with a major new investor in the company’s projects, including Mustang. Details of the deal remain confidential but an announcement could be made in a few weeks. Brooks Range is owned by Alaska Venture Capital Group, a consortium of small independents mostly based in Kansas. The company has been exploring on the North Slope for several years mostly targeting medium-sized prospects bypassed by major oil and gas companies.

Pioneer closes sale to Caelus, Nuna development on tap

More new oil projects are planned for the North Slope spurred by the state’s reform of its oil production tax, according to a new pair of entrants to Alaska. A new development is that Caelus Energy, new owner of the former Pioneer Natural Resources producing assets in Alaska, plans to begin construction next winter on the Nuna project, an undeveloped oil deposit near the producing Oooguruk field now owned by Caelus, company officials said. Caelus and its investment partner, Apollo Global Management, completed the acquisition of Pioneer’s 70 percent share of Oooguruk and other assets in Alaska April 15, Caelus CEO James Musselman said. Caelus and Apollo paid $300 million in cash for Pioneer’s assets. Eni Oil and Gas retains its 30 percent share of Oooguruk but is not involved in Nuna, which is 100 percent owned by Caelus. Musselman said Caelus and Apollo have been looking at the North Slope for some time, attracted by the geologic prospectivity of the region. What finally motivated the partners to jump into Alaska was the state’s move in 2013 to reform its oil and gas production tax, however, he said. “We will begin placing gravel for Nuna’s production pad this winter and we are planning to have first production by the third quarter of 2016,” Musselman said in an interview with the Journal. Preliminary estimates are that Nuna can produce 15,000 to 20,000 barrels per day, or b/d, he said. Oooguruk is now producing about 15,000 b/d in gross production, although that is shared with Eni. A 31-well drilling program is planned for Nuna, with an estimated overall capital cost of $1.5 to $2 billion, he said. There are also tentative plans for a second production pad at Nuna. Meanwhile, Alaska’s Department of Natural Resources has transferred special reduced royalty arrangements for Oooguruk that were negotiated with Pioneer to Caelus, and Musselman confirmed that discussions are underway with state officials on similar royalty arrangements for Nuna. That, plus other special tax incentives the state offers, will make Nuna economic to develop, he said. Musselman paid special compliments to the DNR and its staff for helping facilitate the entry of Caelus and Apollo, and to Gov. Sean Parnell for his encouragement. Caelus officials couldn’t comment on the oil quality at Nuna but previous wells drilled by other companies in the same area have yielded oil with quality ranging from 19 to 24 API gravity, according to data on file with the Alaska Oil and Gas Conservation Commission. In a related development, Caelus officials also said that Pioneer had very good results this spring with large hydraulic fracturing of four new production wells at Oooguruk. Pat Foley, who headed Pioneer’s operation in Alaska and who will continue under Caelus, said one of the wells peaked at 7,000 b/d in production tests after the fracturing but that production on all four is being “choked back” to 2,500 b/d to 3,000 b/d for reservoir management reasons. That is about double what Oooguruk production wells have been averaging, he said. Based on those results, Musselman said Caelus will look at applying fracturing to some of the existing Oooguruk wells where production has decreased. Alaska Commissioner of Natural Resources Joe Balash said the entry of a private equity investor like Apollo into the North Slope oil and gas projects is significant. Equity firms are reported to have invested already in projects on the Slope, but have not made the information public. “That this was done in a very public way is a significant signal of confidence,” Balash said. Apollo had assets under management of approximately $161 billion as of December 31, 2013, in private equity, credit and real estate funds invested across a core group of industries, including energy, according to the April 15 announcement by Caelus and Apollo. Nuna is one of several new small- to medium-sized projects now under development on the Slope. April 24, the state development corporation, the Alaska Industrial Development and Export Authority, approved a $50 million state participation with Brooks Range Petroleum, another Alaska independent, in development of the Mustang field, which will begin producing in late 2015 and will peak at 15,000 b/d. ConocoPhillips, one of the large companies operating on the slope, also has the new CD-5 project under construction near the Alpine field, which will produce 16,000 b/d at peak, and a new drill-site in the Kuparuk River field, Drill Site 2-S, which will produce about 8,000 b/d. BP also has new projects underway in the large Prudhoe Bay field including assessment of a $3 billion new development in the west end of the field.

REI, state tackle study of second LNG plant for Cook Inlet

There are now plans for yet another liquefied natural gas plant in Cook Inlet, in addition to ConocoPhillips’ plant that is now restarting and the plan for a large LNG plant built as part of the North Slope pipeline project. A Japanese consortium and the state’s development corporation, the Alaska Industrial Development and Export Authority, or AIDEA, are jointly studying another possible LNG plant that could be built in the Matanuska-Susitna Borough near Port MacKenzie, a spokeswoman for the Japanese group said. REI Alaska Inc. and AIDEA have entered an agreement to jointly-fund a $240,000 pre-feasibility study for a project that could export 1 million to 1.5 million tons of LNG yearly to Asia markets, said Mary Ann Pease, an REI vice president who heads the company’s Alaska operations. If built, the plant would require an estimated $1 billion in investment and would require about 1,000 workers for construction. Two other Cook Inlet plants are already on their way to exporting LNG. The existing ConocoPhillips plant getting ready to make its first exports shipments in May after resuming operations (the plant has been mothballed), and there’s a second proposed large LNG plant that would be the terminus for a 42-inch gas pipeline from the North Slope if that is built. That would have a capacity of about 15 to 18 million tons per year. Pease said REI’s project wouldn’t compete with ConocoPhillips’ existing Cook Inlet LNG plant because there is demand for Alaska LNG in Japan far beyond what ConocoPhillips can supply. “REI would also use newer liquefaction technology so that our plant would be more efficient, making more LNG for a specific volume of gas, than would be the case at the ConocoPhillips plant,” which was built in 1968 and went into operation in 1969, Pease said. The project is also intended to serve Alaska regional markets, for example coastal communities that could be supplied with LNG by barge. Some of the Japanese participants in REI are utilities and municipal governments who would purchase LNG from the plant, Pease said. Toshitami Kaihara, former governor of Hyogo Prefecture in Japan, led the formation of REI in 2011 to seek alternative energy sources after the Fukushima nuclear plant, which supplied electricity to Hyogo, was damaged by the earthquake. REI’s plan is also tied to the state’s Alaska Gasline Development Corp. “backstop” plan for an $8 billion, 36-inch pipeline from the North Slope to Southcentral Alaska that could be built if a proposed large Alaska LNG bring proposed by North Slope producers falters. AGDC is also involved in the large project, which has a preliminary cost estimate of $45 billion to $65 billion. The state’s backstop pipeline plan is to supply gas to Alaska communities only, Pease said, and does not include an LNG plant or export capability. REI’s project would supply that, she said, which would allow the state’s in-state line to ship larger volumes and achieve greater efficiencies. It is believed that in-state gas needs for power generation and space heating along the Interior Alaska-Southcentral route of the gas pipeline would amount to about 250 million cubic feet of gas per day, which would leave ample spare capacity in the pipeline for other customers, for in-state industry or for gas exports. However, REI believes its project could work even if there is no pipeline from the North Slope, Pease said. “We’ve spoken to every Cook Inlet producer and there does appear to be gas available that is beyond what is needed to meet local utility requirements,” she said. A determination that local domestic needs are met would be key to getting a federal export permit for gas exports. AIDEA agrees with this assessment. An April 24 resolution approved by AIDEA’s board authorizing the authority’s participation said, “Local gas producers in the Cook Inlet area have confirmed the availability of excess gas after full commitments to the utilities in Southcentral are met.” Ted Leonard, executive director of the state development corporation, told AIDEA’s board that the pre-feasibility study to be underway soon is expected to take about 90 days, after which AIDEA will help help sponsor further work if results are favorable. The authority would consider an equity investment in the plant, Leonard said. REI’s plant would be located at Port MacKenzie on upper Knik Arm in Cook Inlet, near where the same region that the state-built pipeline would terminate with a connection to existing regional utility gas pipelines. Pease said a possible site has been identified for the plant. ConocoPhillips’ LNG plant is at Nikiski, on the Kenai Peninsula, on the other side of Cook Inlet from the proposed REI location. Nikiski is also where the LNG plant that is part of the proposed gas pipeline project from the slope would be built. That plant, which could be operating in 2024 at the earliest, is planned to ship 15 million tons to 18 million tons of LNG yearly.

With state role in LNG approved, special session likely

With the Legislature’s approval, at least in concept, for state participation in a large North Slope gas pipeline and natural gas liquefaction project, state officials are now working to execute the agreements for work on pre-Front End Engineering and Design for the giant project. Also, preliminary agreements will be signed with TransCanada Corp. for the pipeline company to become the state’s partner in a 25 percent share of the pipeline and North Slope gas conditioning plant, Alaska Natural Resources Commissioner Joe Balash said. Following that, the state’s current contract with TransCanada under the Alaska Gas Inducement Act, or AGIA, will terminate, he said. The pre-FEED involves more detailed engineering and design work that will be beyond the conceptual-level studies of the project so far and will lead to a better estimate of costs, which are currently expected to range between $45 billion and $65 billion, Balash said. The pre-FEED cost is pegged at about $450 million and the state’s 25 percent share of that would be $112.5 million, but a hefty share of that, for the pipeline and gas treatment plant, will actually be paid by TransCanada, Balash said. The state would own a full 25 percent share of the large natural gas liquefaction, or LNG, plant planned in Nikiski at the southern terminus of the pipeline. If the state decides not to proceed with a partnership with TransCanada, the pipeline company will have to be repaid. Balash said the pre-FEED work will be done in 2015 but that the refined cost estimates would not be available until later in the year. If the results are favorable and decisions are made to continue, the parties will begin the full Front End Engineering and Design phase involving much more detailed work that would set the stage for a Final Investment Decision, the go or no-go, in 2019. Meanwhile, work will also begin immediately on negotiating the formal Participation Agreements for the state’s involvement in the project. These are the actual partnership documents not only between the state and North Slope producers BP, ConocoPhillips and ExxonMobil, but among the companies themselves. Balash said that agreement, which will be very detailed, must go back to the Legislature for approval but that this wouldn’t happen during a regular 2015 legislative session but in a special session that would be called later in the year, he said. “There will likely be some legislation dealing with property tax issues, which affect municipalities, during the regular session,” but the big decisions will be left for a special session, Balash said. What will be separately negotiated is the state’s gas shipping contract with TransCanada. The state will be taking its royalty and production tax in-kind, or in the form of gas, and this will amount to 25 percent of the North Slope gas production.  Because TransCanada will own, and finance, the 25 percent of the gas treatment plant and pipeline, the state must enter into a long-term contract with the pipeline company to ship the state’s 25 percent share of the gas. This will be a binding “take or pay” contract that will allow TranCanada to finance the construction, and once signed, the state is legally obligated. This will be a long-term, multi-billion-dollar commitment. The gas shipping contract with TransCanada and the Participation Agreement with the producers are to come before legislators in the same 2015 special session. Balash said one of the sticky parts of the Participation Agreement will be some kind of agreement on fixing the fiscal terms for the project, a must-have for the North Slope producers. “We don’t yet know what form this might take, or how we would define fiscal ‘certainty,’ but it’s important because all the parties have to be able to count on the future cash flows. The form of this hasn’t been worked out yet,” Balash said. The discussions mainly involve the state production and property tax. Corporate income taxes are not part of the deal, he said. A fix on fiscal terms like taxes, meaning an assurance to the producers that taxes wouldn’t increase over a period of years, is sensitive politically and is also legally complicated. Some legislators are also concerned that the administration will be pushed to include a freeze on oil taxes along with gas taxes. This happened when former Gov. Frank Murkowski was negotiating a similar state gas pipeline participation deal in 2006. Murkowski reluctantly agreed to it in return for other concessions by the producers, but it evoked strong criticism in the Legislature and helped doom the initiative that year. On taxes, the state constitution prohibits one Legislature from “binding” another, which means there is no legal way legislators can make an assurance that a future Legislature might not change taxes. This limitation is recognized by all parties and the consensus is that any assurance of fixed tax terms, even in the form of a contract, would amount to a kind of moral pledge, but one which can’t be legally enforced. The state has made moral pledges in many kinds of agreements, including a moral pledge for backing of public revenue bonds, and the Legislature has never allowed any of these pledges to be reneged on. Also, the Legislature has already provided for assurance on taxes and royalty terms in the AGIA contract with TransCanada although any new agreements would be in a different form. The state taking its gas production tax in-kind lends some assurance to the partners on taxes because the state, though TransCanada, will be investing in pipeline capacity to ship this gas. The royalty share, in contrast, is fixed by contract in the lease at amounts ranging from 12.5 percent to 16.6 percent depending on the lease and those amounts won’t change, although there are issues in how the royalty is administered. Having the state take its royalty in-kind and make its own shipping arrangements is important to the producing companies because it eliminates the possibility of disagreements over royalty values when the royalty is paid in cash. These kind of disagreements became a real problem after the Trans-Alaska Pipeline System was completed in 1977, and the resulting litigation, known as the Amerada Hess case, was to cost all parties hundreds of millions of dollars before a settlement was finally reached. The producing companies want to avoid these kinds of disputes with the gas pipeline, and having the state take its royalty in kind and sell the royalty gas itself solves these problems, the producers have said.

Alaska stake in LNG project approved

Before finishing all of its work in Juneau, the Alaska Legislature approved state participation in a large North Slope gas pipeline and liquefied natural gas project, one of the major pieces of business for the 28th session. Lawmakers approved a plan late April 20 for the state to negotiate a partnership with North Slope producers BP, ConocoPhillips, ExxonMobil and TransCanada Corp., a pipeline company, in the proposed pipeline and liquefied natural gas, or LNG, export project. Gov. Sean Parnell must still sign the bill, but that is expected. The Legislature’s approval to Senate Bill 138 came as lawmakers worked to finish other business in their 2014 session in Juneau. April 20 was the 90th day of the session, and, by regulation, expected to be the last. However, lawmakers did not finish their work that day, and pushed past the regular deadline. The plan is essentially for the state to take its royalty and tax revenue share of natural gas production “in kind,” or in gas instead of cash, and to invest in 25 percent of the project, or sufficient capacity for the state to ship its own share of gas production, state Department of Natural Resources Commissioner Joe Balash has said in briefings. SB 138 also provides for the state to separately negotiate a deal with TransCanada to invest in and own the state’s 25 percent share of the proposed 800-mile, 42-inch pipeline and a large gas treatment plant on the North Slope, Balash said. The state would retain ownership, however, of its 25 percent of the LNG plant, which is planned at Nikiski, near Kenai, through a state corporation, the Alaska Gasline Development Corp., or AGDC. “This is truly a historic moment for Alaskans,” Parnell said in a statement. “By passing Senate Bill 138, the Legislature has put Alaska on a path to controlling her own destiny by becoming an owner in the Alaska LNG Project. Alaskans have waited a long time for a gasline, and for the first time in our history, we have alignment, authorization from the Legislature, and a clear path forward. The Alaska LNG Project has begun.” Preliminary estimates for the cost of a project range from $45 billion to $65 billion, but those estimates are to be refined in further engineering studies. In operation, it would produce between 16 million and 18 million tons of LNG yearly, mostly for export markets. While state participation in large oil and gas projects in common in many parts of the world this would be the first time a U.S. state has entered such a partnership. The legislation passed April 20 will allow the producers to begin the Preliminary Front-End Engineering and Design stage of the project to further refine cost estimates, Parnell said. Work will begin this summer on that, and the state is to share part of the costs. The producers will also begin a more formal LNG marketing effort that will include the state’s 25 percent share of LNG, he said. Negotiations will also begin on a formal participation agreement between the state and producers and, separately, between the state and TransCanada. Those are expected to be concluded in 2015 and must also be approved by the Legislature. If the projects appears feasible after completion of refined cost estimates in the pre-FEED , the consortium will proceed to a multi-billion-dollar Front-End Engineering and Design, or FEED, stage that will accomplish final engineering and set the stage for a Final Investment Decision to proceed with the project. That is expected in 2019. If all proceeds as planned, the project would begin operating in 2024. Legislators have been working on SB 138 since January, when their 2014 session was convened. There were points when disagreements developed, mainly over TransCanada’s role. Some lawmakers felt the state didn’t need to partner with TransCanada and that it could finance its full 25 percent share itself, without the participation of the pipeline company. A former Alaska governor, Frank Murkowski, also lobbied legislators to kick TransCanada out, arguing that the terms of the proposed deal with the pipeline company were too much to TransCanada’s advantage. In the end TransCanada stayed in the deal at the urging of Balash and Alaska Commissioner of Revenue Angela Rodell, who argued the advantages for the state in partnering with an experienced pipeline company in dealing with the three major slope producers outweighed the financial consequences. In his statement, Parnell said the passage of SB 138 also expands the role and mission of AGDC, the state gas corporation, empowering it to carry the state’s equity interest in the project’s infrastructure, particularly the liquefaction and marine facilities. AGDC will also continue to aggressively pursue the advancement of the Alaska Stand Alone Pipeline, or ASAP, project parallel to the Alaska LNG Project, Parnell said. ASAP is a plan for a state-led 36-inch pipeline that could proceed if the big pipeline and LNG project fails. The state corporation has been working on the ASAP project as a backstop to the large project, and that work will continue. “SB 138 is a huge validation of the Legislature’s decision to create an Alaskan-owned pipeline development company,” AGDC President Dan Fauske said. “AGDC will now lead the state’s participation in this exciting LNG export project, while continuing to advance ASAP, the smaller in-state alternative. The work we’ve done to date is of significant value to the Alaska LNG Project, and going forward, AGDC will leverage the work of both efforts until we’ve gathered the facts necessary to make the most informed decision. Ultimately, the goal is to sanction a project that is in Alaska’s long-term best interests. AGDC’s management and board recognize the tremendous responsibility we’ve just been given, and are ready to get to work.” Parnell commended legislators for their work on SB 138. “I want to really commend legislators for their hard work and thorough review of this legislation, especially Sen. Anna Fairclough and Rep. Eric Feige for carrying our bill in their respective bodies,” Parnell said. “Alaska’s future is bright, especially as it relates to getting Alaska’s gas to Alaskans. I look forward to working with legislators along the way to continue to advance the Alaska LNG Project and get gas to Alaskans.”

Legislature OKs subsidies, tax credits for in-state refineries

Alaska’s Legislature approved a tax credit and subsidy for in-state refiners April 21 as lawmakers rushed to finish up their 2014 session in Juneau. House Bill 287 is aimed mainly at helping PetroStar Inc., which operates two small refineries near Fairbanks and Valdez and which has asked for state help. However, the bill also sparked controversy and a roiling 2 a.m. debate in the Senate April 21 because it also benefits Tesoro Corp., which operates a refinery near Kenai. Tesoro has not asked for state financial help but needs another part of the bill that extends a state contract to purchase royalty crude oil. “It strikes me as the heart of irrationality to give money to a for-profit corporation that doesn’t need it,” said Senate Minority Leader Hollis French, D-Anchorage, during the early morning debate when the bill passed the Senate. French offered an amendment that would require a company provide data to the state before receiving the subsidy but it was voted down in the Republican-controlled Senate. Sen. Bill Wielechowski, D-Anchorage, said the money should be a loan, not a grant, but his amendment proposing that was voted down, too. Two Republican senators wound up voting against the bill. Sen. Anna Fairclough, R-Eagle River, said, “Alaskans don’t want to have to import fuel (if there are no in-state refiners) but business is business and a free market is supposed to be free. I’m looking for reasons to press the green button on this (to vote yes) but I’m not there yet.” Sen. Mike Dunleavy, R-Wasilla, also voted no on the bill. Sen. Peter Micciche, R-Soldotna, who represents the district where Tesoro’s refinery is located, voted yes, and said he wants to see Tesoro encouraged to make new investments even if the refinery is not distressed. Under the bill refiners can receive a state corporate income tax credit for up to 40 percent of the cost of new capital investments, and if they have insufficient corporate tax liability they can turn the credits in to the state and receive cash payments. The legislation puts a cap on the tax credits at $10 million per year per refinery so that PetroStar, with two plants, would be eligible for up to $20 million a year if the company invests in both of its plants. PetroStar is a subsidiary of Arctic Slope Regional Corp., an Alaska Native regional corporation based in Barrow. That Tesoro has not asked for a state handout but would get it anyway under HB 287 has outraged Wielechowski, who has pushed bills on gasoline and diesel price-gouging by refiners. “Tesoro has been gouging the people of Alaska for years,” Wielechowski said during the Senate debate. “For years Alaska gasoline prices averaged seven cents a gallon above Seattle but in 2008 prices in Alaska shot up to $1.50 a gallon over Seattle and have never gone back to the historical average. The evidence shows refiner margins are through the roof.” That isn’t the case with PetroStar, which is making zero profits this year, company president Doug Chapados told the Senate Finance Committee on April 20. Because PetroStar takes crude oil from the TransAlaska Pipeline System and returns unused portions of the crude to TAPS, with lighter ends used to make product, the company must pay stiff penalties under the Quality Bank, a financial mechanism that compensates other TAPS shippers and the state for the effects of the returned oil in degrading the crude oil quality. Those payments, which have escalated in the last two years, along with high crude oil costs, have endangered PetroStar, Chapados told the committee. The same problems are faced by Flint Hills Resources, owner of another refinery near Fairbanks, but its owner, Koch Industries, has decided to close the refinery due to problems related to loss of commercial jet fuel sales to fuel importers as well as the Quality Bank penalties cited by PetroStar. State help for PetroStar is supported strongly by legislators from Fairbanks who argue the plant is important to the community because it is a major supplier of jet fuel through a dedicated pipeline to Eielson Air Force Base, which is east of Fairbanks. The U.S. Air Force has been making efforts to scale back Eielson to cut costs and local community leaders don’t want to see the loss of a local jet fuel supply to give them added reasons. “If we lose Eielson, we lose a third of our local economy,” said Rep. Doug Isaacson, R-North Pole. For a few days it looked as if the bill might be expanded to also help Agrium Corp., which is considering a restart of its large fertilizer and ammonia plant also at Nikiski. An amendment offered in the House Rules Committee by House Speaker Mike Chenault, a Republican whose district includes Nikiski, where Agrium’s plant is located, would have allowed any facility engaged in oil and gas processing to be eligible for the tax credits. The following day, however, Rep. Mike Hawker, R-Anchorage, proposed another amendment that would exclude LNG projects, compressed natural gas and gas-to-liquids plants from the tax credits. That stirred concern in rural Alaska communities that hope to develop small-scale LNG and compressed gas projects as alternatives to fuel oil. Hawker said later his intention was not to foreclose any project but not to have the tax credits applied to a proposed large liquefied natural gas plant at Nikiski. There was a concern about the tax credits applying to BP’s shutdown gas-to-liquids research plant, also at Nikiski. Eventually Gov. Sean Parnell decided against any expansion of the bill. The Agrium amendment by Chenault as well as Hawker’s amendment were taken out in the Senate Finance Committee at the request of Department of Natural Resources Commissioner Joe Balash. Meanwhile, Tesoro is a bit embarrassed over having been caught up in the tax credit issue, which PetroStar needs. What Tesoro wants in HB 287 is a section of the bill that gives needed legislative approval to an extension of the company’s contract to buy state royalty crude oil. The company supports the incentive tax credits, Tesoro spokesman Matt Gill said, but its main focus has been on the royalty contract extension. The bill was originally introduced to approve the royalty oil contract. The in-state refiners’ tax credit was added to the bill recently in a state House committee. Bob Tkacz, a correspondent for the Journal, contributed to this story.

Lawmakers not quite done in Juneau, but gas project is approved

The Alaska Legislature may not be quite finished with its work in Juneau but one major piece of business, approval for state participation in a large North Slope gas pipeline and liquefied natural gas project, is finished. The Legislature approved a plan late Sunday for the state to negotiate a partnership with North Slope producers BP, ConocoPhillips, ExxonMobil and TransCanada Corp., a pipeline company, in the proposed pipeline and liquefied natural gas, or LNG, export project. Gov. Sean Parnell must still sign the bill, but that is expected. The Legislature’s approval to Senate Bill 138 came as lawmakers worked to finish their other business in their 2014 session in Juneau. The plan is essentially for the state to take its royalty and tax revenue share of natural gas production “in kind,” or in gas instead of cash, and to invest in 25 percent of the project, or sufficient capacity for the state to ship its own share of gas production, state Department of Natural Resources Commissioner Joe Balash has said in briefings. SB 138 also provides for the state to separately negotiate a deal with TransCanada to invest in and own the state’s 25 percent share of the proposed 800-mile, 42-inch pipeline and a large gas treatment plant on the North Slope, Balash said. The state would retain ownership, however, of its 25 percent of the LNG plant, which is planned at Nikiski, near Kenai, through a state corporation, the Alaska Gasline Development Corp. “This is truly a historic moment for Alaskans,” Parnell said in a statement. “By passing Senate Bill 138, the Legislature has put Alaska on a path to controlling her own destiny by becoming an owner in the Alaska LNG Project. Alaskans have waited a long time for a gasline, and for the first time in our history, we have alignment, authorization from the Legislature, and a clear path forward. The Alaska LNG Project has begun.” Preliminary estimates for the cost of a project range from $45 billion to $65 billion, but those estimates are to be refined in further engineering studies. In operation, it would produce between 16 million and 18 million tons of LNG yearly, mostly for export markets. While state participation in large oil and gas projects in common in many parts of the world this would be the first time a U.S. state has entered such a partnership. The legislation passed Sunday will allow the producers to begin the Preliminary Front-End Engineering and Design stage of the project to further refine cost estimates, Parnell said. Work will begin this summer on that, and the state is to share part of the costs. The producers will also begin a more formal LNG marketing effort that will include the state’s 25 percent share of LNG, he said. Negotiations will also begin on a formal participation agreement between the state and producers and, separately, between the state and TransCanada. Those are expected to be concluded in 2015 and must also be approved by the Legislature. If the projects appears feasible after completion of refined cost estimates in the pre-FEED , the consortium will proceed to a multi-billion-dollar Front-End Engineering and Design, or FEED, stage that will accomplish final engineering and set the stage for a Final Investment Decision to proceed with the project. That is expected in 2019. If all proceeds as planned, the project would begin operating in 2024. Legislators have been working on SB 138 since January, when their 2014 session was convened. There were points when disagreements developed, mainly over TransCanada’s role. Some lawmakers felt the state didn’t need to partner with TransCanada and that it could finance its full 25 percent share itself, without the participation of the pipeline company. A former Alaska governor, Frank Murkowski, also lobbied legislators to kick TransCanada out, arguing that the terms of the proposed deal with the pipeline company were too much to TransCanada’s advantage. In the end TransCanada stayed in the deal at the urging of Balash and Alaska Commissioner of Revenue Angela Rodell, who argued the advantages for the state in partnering with an experienced pipeline company in dealing with the three major slope producers outweighed the financial consequences. In his statement, Parnell said the passage of SB 138 also expands the role and mission of AGDC, the state gas corporation, empowering it to carry the state’s equity interest in the project’s infrastructure, particularly the liquefaction and marine facilities. AGDC will also continue to aggressively pursue the advancement of the Alaska Stand Alone Pipeline, or ASAP, project parallel to the Alaska LNG Project, Parnell said. ASAP is a plan for a state-led 36-inch pipeline that could proceed if the big pipeline and LNG project fails. The state corporation has been working on the ASAP project as a backstop to the large project, and that work will continue. “SB 138 is a huge validation of the Legislature’s decision to create an Alaskan-owned pipeline development company,” AGDC President Dan Fauske said. “AGDC will now lead the state’s participation in this exciting LNG export project, while continuing to advance ASAP, the smaller in-state alternative. The work we've done to date is of significant value to the Alaska LNG Project, and going forward, AGDC will leverage the work of both efforts until we've gathered the facts necessary to make the most informed decision. Ultimately, the goal is to sanction a project that is in Alaska’s long-term best interests. AGDC’s management and board recognize the tremendous responsibility we’ve just been given, and are ready to get to work.” Parnell commended legislators for their work on SB 138. “I want to really commend legislators for their hard work and thorough review of this legislation, especially Sen. Anna Fairclough and Rep. Eric Feige for carrying our bill in their respective bodies,” Parnell said. “Alaska’s future is bright, especially as it relates to getting Alaska’s gas to Alaskans. I look forward to working with legislators along the way to continue to advance the Alaska LNG Project and get gas to Alaskans.”

House approves workers' comp changes

JUNEAU — A bill revamping how medical costs under the Alaska workers’ compensation program are calculated passed the state House Wednesday. Time is tight for House Bill 306 to make it through the state Senate before the Legislature’s required April 20 adjournment, however. The legislation changes the method for paying medical fees of injured workers under the state program to one that is used in several other states. State Rep. Kurt Olson, R-Soldotna, sponsor of the bill, believes the new method will slow the fast-rising workers’ compensation medical costs that are driving up the costs of workers’ comp insurance premiums employers must pay. “This is an effort to reduce exorbitant costs in both the public and private sectors,” Olson said when he introduced the bill in mid-February. Workers’ compensation medical costs in Alaska are increasing at about 10 percent per year compared with an annual inflation of 4 percent in the medical cost component of the Anchorage Cost of Living, says Mike Monagle, director of the state Workers’ Compensation Division. “Medical costs constitute 76 percent of workers’ compensation claims in Alaska, which has a serious impact on premium rates paid by all Alaska employers,” said Anna Latham, an aide to Olson. “The result is that Alaska has the highest workers’ compensation premiums in the nation. Medical costs under the program are continuing to rise despite a 14 percent decline in claims by injured workers,” due partly to employers’ workplace safety improvements, she said. The problem has been in the way payments in Alaska are currently made, which are set at the 90th percentile for the costs of specific procedures in a given area.   Monagle said that if there are just a few practitioners for a given medical procedure the 90th percentile rule has the effect of setting the rate at close to what the most expensive practitioner charges. When those rates are published, the providers charging less expensive rates see that and are encouraged to raise their rates, which creates an upward spiral of prices, he said. HB 316 shifts to a different system where prices would be based on federal Medicaid and Medicare rates for procedures and then adjusted through a “conversion factor” that would be set by the Alaska Medical Services Review Committee, an advisory body to the Alaska Workers’ Compensation Board. The Commissioner of Labor and Workforce Development ultimately approves the conversion factor under HB 316. Medicaid and Medicare rates are already given a regional geographic adjustment for Alaska and Medicaid rates are also adjusted for higher-cost areas within the state. The conversion factor would make additional adjustments, but just how that will work is unclear. Critics in the Legislature said HB 316 does not define the conversion factor or describe it. Rep. Andy Josephson, D-Anchorage, said he is concerned about that, and that the rates might fall to the point that some medical providers will turn away injured workers. There are now concerns in the other direction, however, that the bill’s influence in moderating rates may have been weakened. An amendment made to the bill recently in the House Finance Committee, at Olson’s request, tends to strengthen the hand of the medical rate review committee. Medical providers, who have little incentive to see lower rates, hold four of the nine seats on the committee. The Alaska Medical Association suggested the change. “It has been tough to keep all the stakeholders happy with this,” Olson said. In the previous version of the bill the rate review committee’s role was advisory only, with the actual decision on the conversion factor made by the workers’ compensation board.  

ConocoPhillips to reopen LNG plant, resume exports

ConocoPhillips is restarting its liquefied natural gas plant on the Kenai Peninsula and will resume shipments of LNG in May, the company announced April 14. Five shipments are planned this year, ConocoPhillips spokeswoman Amy Burnett said. The announcement came as the U.S. Department of Energy issued its approval of exports, also on April 14. DOE authorized the shipment of 40 billion cubic feet of gas over two years. An important part of this development is that ConocoPhillips will process natural gas and market LNG for third parties, such as independent explorers now finding and developing gas in Cook Inlet. “The 2014 export program includes a combination of ConocoPhillips and third-party gas,” Burnett confirmed in a statement. This will provide a new market outlet for new gas producers in the region, she said. In the past, ConocoPhillips has only processed its own gas, or gas owned by Marathon Oil Co. when that company was a minority owner of the LNG plant. Providing a market to Cook Inlet producers was part of the State of Alaska request to ConocoPhillips last fall asking for the company to apply for a renewal of its export permit, which it allowed to expire in 2012 based on limited gas supplies available to local utilities. Now that local utilities have signed deals into 2018 with Inlet producer Hilcorp, which has purchased and revitalized former Chevron and Marathon fields, other companies exploring the Inlet will need a market if economic discoveries are made. Meanwhile, the plant restart will be a real shot in the arm for the renewal of Cook Inlet’s oil and gas industry. “This is great news for the cradle of Alaska’s oil and gas industry on the Kenai Peninsula,” said Alaska U.S. Sen. Mark Begich, who worked with the DOE on the approval. “With plenty of gas available to meet local needs through at least 2018, we’re seeing the kind of job growth responsible oil and gas development can provide.” The federal agency had agreed earlier that ConocoPhillips can export to nations that are in Free Trade Agreements with the U.S., such as South Korea. Exports to those nations are approved by DOE with a streamlined process. The April 14 approval by DOE, however, extended that to countries who are not in free trade agreements, such as Japan. ConocoPhillips has mainly exported LNG to Japan in the past although there have been shipments to Korea. Begich had pushed the DOE to process the ConocoPhillips application to ship to non-Free Trade Agreement countries outside the queue DOE has set up for non-FTA LNG export projects. “DOE has approved only six applications from Lower 48 projects in that queue since 2012, and at least 24 applications remain in the queue,” Begich said in a statement. Except for Alaska’s project, LNG export proposals seeking DOE approval are all Lower 48 plants. Those have sparked sharp controversy over the possibility that exports could result in higher domestic prices for natural gas, and opposition to exports from U.S. industries, such as chemical manufacturers, that benefit from low-cost gas used as feedstock. Begich pressed the case for Alaska being treated differently “I asked Acting Assistant Secretary for Fossil Energy, Chris Smith, to visit the plant last summer, and familiarize himself with our industry, our workforce and the unique situation of our country’s only LNG export plant with a safe track record spanning four decades,” Begich said. “That visit is paying dividends today.” Burnett said the reopening will not result in any significant increase in employment at the LNG plant because most of its employees were retained when the plant went into mothball status. Exports were stopped in 2012 because of shortages of natural gas in Cook Inlet fields. The gas supply situation has now improved due to new drilling to the point that a surplus would be available for export during summer. In winter, however, gas production will be reserved for local utilities.

Slope gets busy from CD-5 to Point Thomson

JUNEAU — North Slope oil fields are busy places these days. ConocoPhillips told a state legislative committee in Juneau that it expects to see 50,000 barrels per day of new North Slope production in 2018 based on projects now under construction and planned. Field operators also have extensive maintenance and facility “renewal” projects underway for the oilfields, a panel of company managers told the Senate Resources Committee April 8. Those include construction of a replacement for a field pipeline carrying seawater for field pressure maintenance in the Kuparuk field, and major “turnaround” maintenance projects planned this summer for three major production facilities in the Prudhoe Bay field. Construction o one new project, CD-5 near the producing Alpine field, is also now under construction, and will be producing 16,000 barrels per day beginning in late 2015, Scott Jepsen, the company’s vice president for external affairs, told the Senate Resources Committee in Juneau. Two of ConocoPhillips’s new projects planned — a new drillsite in the Kuparuk field and a new production pad in the northeast National Petroleum Reserve–Alaska — must still get the approval of the company’s board but the company has moved ahead with gravel placement for the Kuparuk field drillsite this winter. That project alone employed 70, Jepsen said. A third project is a planned expansion of a viscous, or heavy, oil project in the Kuparuk River field, Jepsen said. Investment in the ConocoPhillips-managed projects will total $2 billion by the company and its partners. Jepsen was part of a panel of industry and state officials who briefed the legislators on the outlook for new production from the North Slope. Meanwhile, ExxonMobil will also have its Point Thomson field completed and producing 10,000 barrels per day, or b/d, of liquid condensates by 2016, Sofia Wong, the company’s infrastructure manager for its Point Thomson project, told the legislative committee. Point Thomson is a large gas and condensate field east of Prudhoe Bay. The condensate project is a preliminary step toward production of the gas, Wong said. The Point Thomson costs are pegged at $4 billion and to date ExxonMobil and its partners in the field, BP and ConocoPhillips, have spent $2 billion, she said. Including Point Thomson, that would bring total new production to 60,000 b/d on the Slope by 2018. On the planned summer maintenance at Prudhoe Bay, BP will shut down three of the field production facilities at intervals in July and August to perform scheduled maintenance and upgrades, Frank Paskvan, BP’s Alaska technology manager, told the Senate Resources Committee. Work will be performed in the field’s Central Gas Facility, Flow Station 3 on the eastern side of Prudhoe Bay and Gathering Center 2 on the western side, Paskvan said. The Central Gas Facility is one of two major gas-handling plants at Prudhoe Bay. It processes about 7 billion cubic feet per day that is currently being produced with crude oil, removes gas liquids from the raw gas and sends it on to a second plant, the Central Compressor Plant, where the gas is injected back into the reservoir for pressure maintenance. The work involves refurbishing and upgrading compressors, heat exchangers and valves and will include other process and safety improvements. Two years have gone into planning the work, and costs are estimated at $76 million. Also, a new process module will be added to Gathering Center 2 to increase the facility’s gas-handling capabilities. This would prepare the facility to be part of a longer-term $3 billion project BP is planning for the western part of the Prudhoe field, but that project is still under study. Paskvan told the legislators BP hopes to start production at its new west Prudhoe Bay project in 2018, which will have a peak production of 40,000 barrels per day. The project will also include an expansion of two other drillsites. The GC-2 module has just been completed at a fabrication plant in Southcentral Alaska operated by NANA Development Corp. and will be trucked to the North Slope this spring. Alaska Deputy Revenue Commissioner Bruce Tangeman, said the new projects will essentially stem the decline of the producing North Slope fields for a period. The North Slope is now producing about 530,000 barrels per day. Tangeman said the state revenue department has calculated that increased activity on the slope will add 13,600 barrels per day of production this year over an estimate made by the state in early December. The 2014 increase will be enough to stem the decline of the field from 8 percent between 2012 and 2013 to a projected decline of 1.8 percent between 2013 and 2014, Tangeman told the legislators. The long-term decline on the slope has been 6 percent, he said. The state’s latest production estimate is for a 2 percent decline next year and 1 percent in 2016 but the ramp-up of industry activity, which he credited to a change in state tax laws, “is making it happen a lot faster than we had thought,” Tangeman said. The 2014 summer maintenance shutdowns at Prudhoe Bay will cause temporary interruptions in North Slope production, however Prudhoe Bay is currently producing about 325,000 barrels per day, according to Alaska Department of Revenue production statistics, but output typically drops during summer because field plants are less efficient in warmer weather.  

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