Tim Bradner

Medicaid rolls expected to grow when ACA kicks in

Medicaid costs in Alaska have leveled off, for now. They’ll creep up again next year, however, when the new federal Affordable Care Act kicks in. Medicaid is a huge item in the state budget, and its rapid growth in recent years has been a big driver in the increasing size of the state operating budget. The program provides health care for low-income and disabled Alaskans, and many senior citizens. A little more than half the costs are paid by the federal government and the rest by the state, and the program is administered by the state Department of Health and Social Services. In state fiscal year 2012, the budget year that ended last June 30, the Medicaid budget was $1.37 billion, up only 0.69 percent from the previous fiscal year 2011 budget of $1.36 billion. In the current budget year, fiscal year 2013, which ends this June 30, the projected spending is now estimated at $1.46 billion, according to data provided by Margaret Brodie, the state’s Medicaid director in the Department of Health and Social Services. The state Legislature had budgeted $1.66 billion for the year, so there are savings that are partly resulting from cost-containment measures and partly from lower use of health care services by those covered by Medicaid. Lawmakers in Juneau are being asked to budget $1.66 billion for Fiscal 2014, which begins July 1. This is the same amount approved for the current year and presumably some of the cost-containment measures the department has undertaken will continue to reduce costs. There’s a new factor that will offset part of that. It’s the “woodwork” effect, Brodie said in an interview. These are Alaskans who are now eligible for Medicaid but who have not signed up for various reasons. In 2014 the new federal health care law will require people to have health insurance, and that will be a wake-up call for those now eligible to sign up, Brodie explained. This has nothing to do with a decision Gov. Sean Parnell is considering on whether or not to expand Medicare to the higher income limits allowed in the federal law. The Alaskans in “the woodwork” are eligible now, but have just not signed up, Brodie said. “We anticipate that when it becomes mandatory to have insurance these individuals will apply so they will not have to pay for coverage. We anticipate approximately 1,500 people (signing up) for one half of the fiscal year,” or the January to June half of the 2014 fiscal year. That is estimated now to cost $3.29 million for the half-year, which is being requested now for the department’s budget. Similar additions to the Medicaid rolls, about 1,500 people per year, are expected in the next two years as more people become aware of the new federal requirement for coverage, Brodie said. That will add to costs. However, the department has also been able to reduce costs. One step, taken in mid-2012, was a policy to encourage the use of generic instead of name-brand medications. “The annual cost-avoidance from this initiative is between $5 million and $6 million a year,” Brodie said. More generic medications will become available as brand-name medication patents expire, she said. Another initiative by the department being launched in April is a requirement for pre-approvals for certain types of costly radiology procedures. “This will be required for hospitals, or for physicians doing ordinary x-rays,” Brodie said. The concern is that there may be an over-use of expensive radiology procedures like MRIs (magnetic resonance imaging) and PET scans (positron emission tomograohy), particularly when the equipment is owned by physician practices. The department has also had a case-management program in effect where nurses work with Medicaid patients with chronic conditions. State Health and Social Service Commissioner Bill Streur has said that this results not only in better care, but usually in cost-savings as well. “The right care at the right time,” usually results in efficient care and lower costs, he has said previously. Utilization, or the amount of medical services people use as well as the number of people enrolled, is typically a major factor in the growth of overall cost of Medicaid but the relation between the two is not always direct. For example, between fiscal years 2011 and 2012, utilization grew by 3.3 percent but the cost of medical services grew by only 0.5 percent, according to data provided by Brodie in a briefing to legislator in Juneau. “In 2012 we had the highest percent of the (Alaska) population enrolled in Medicaid, at 21 percent, with 92 percent of those enrolled using medical services or receiving benefits. However, expenditures did not increase exponentially,” Brodie said. In previous years the relationship was the reverse. Between fiscal years 2009 and 2010, costs grew by 14.2 percent while utilization only grew by 5.6 percent, the data indicated. Not surprisingly, medical care expenditures consume more than half the Medicaid budget, or 54.3 percent; senior and disability services is next at 32.1 percent, and behavioral health, such as psychiatric care, takes up 12.1 percent of the budget. The remaining 1.4 percent is split between Adult Preventative Dental and Children’s Medicaid, Brodie said in her presentation to legislators. Among the successes on containing costs in 2012, pending per recipient for general health care services declined from $5,428 to $5,315, or 2.1 percent; behavioral health spending per beneficiary went from $12,041 to $11,613 in 2012, or 3.6 percent down. However, spending for senior and disability services increased 2.7 percent, from $43,652 to $44,844 per beneficiary in 2012. Spending on senior citizens is difficult to control. “As our population ages we can anticipate increased costs,” Brodie said. Much of this is for personal-care attendant services where senior citizens and the disabled can receive care in their homes. While expensive, it is less costly and better for patients than the alternative, nursing homes. A national initiative in Medicaid is to reduce costs incurred from fraud, an estimated $22.5 billion estimated nation-wide. Brodie said the Department of Health and Social Services has a new manager in the Medicaid Fraud Unit. “He is very active, so we should be seeing some activity,” in spotting fraud. “We also have a surveillance utilitization team that combs through claims looking for patterns. We also receive reports (of fraud) from individuals,” Brodie said.

Sheffield's success: Overcoming hardship, personal loss

Bill Sheffield’s conservative streak on spending, and his business acumen, were honed in a tough depression-era upbringing. Sheffield was born in 1928 in Spokane, Wash. The family was comfortably middle-class with his father’s insurance business, but then times got tough. When the depression set in, “No one bought insurance,” Sheffield recalls. To survive the family grew vegetables from its rented five-acre farm and sold them at a roadside stand. Sheffield was very young but he remembers Franklin D. Roosevelt’s election as president and later Roosevelt’s famous radio talks, which inspired hope amid the nation’s economic despair. “I sat on the floor listening, and I’ll never forget his words,” Sheffield said. “‘My friends,’ he would start, and you would feel he was talking directly to you.” Roosevelt’s New Deal programs created jobs and Sheffield’s father eventually got one, giving the family a better income. Seeing Roosevelt’s policies work at close hand was an inspiration, and it molded Sheffield’s philosophy at a young age. It made him a lifelong Democrat, a Roosevelt-type, pro-job Democrat. “There were wise people around Roosevelt and they could get things done. It was all about creating jobs that people could make a good, honest living with, and raise their families,” Sheffield remembers. “That was what government was for, to help people.” This belief has remained with him since. World War II ended the depression and after an Air Force stint and electronics school training, Sheffield joined Sears Roebuck. Sears was expanding in post-war Alaska. The story is well-known that Sheffield came to Alaska to start TV sales and service for Sears. He arrived in Seward in 1953 on the Alaska Steamship Co.’s SS Aleutian. The train to Anchorage took eight hours, he remembers. With Sears, Sheffield’s responsibilities grew. When the company expanded its retail line into appliances and home building materials, Sheffield moved into sales. For four years he was Sears’ top salesman in the nation. It was in these years that Sheffield also overcame a problem that had plagued him since childhood, a difficult stutter. “As I child I would go into a store and couldn’t speak. I had to point to pictures,” he recalls. It wasn’t until his early 50s that Sheffield overcame his stutter. Sheffield was ambitious. He became active in the Jaycees, or Junior Chamber of Commerce, and got to know other young up-and-comers like George Sullivan and Tom Fink, two future mayors. He became a friend with Brad Phillips, who was then a Republican state senator. The two became roommates, in fact, and then business partners. This was the start of Sheffield’s hotel chain. Sheffield and Phillips first leased the 13-room Anchorage Inn at 9th and D Streets, and then leased the 31-room Red Ram, near 5th Avenue and Gambell Street. This was small business, close and personal. Sheffield remembers running the night desk himself at the Red Ram and even changing and cleaning rooms in the middle of the night when airline crews came in late. Sheffield eventually bought his partners out. Phillips went on to found an excursion business in Prince William Sound. Sheffield was set to open another hotel, Anchorage Travelodge on 3rd Avenue, in 1964 just as the Good Friday earthquake struck. The earthquake damage was repaired, the Travelodge opened, and the chain expanded. Sheffield bought the famous Baranof Hotel in Juneau in the late 1960s and opened a string of hotels in smaller communities around the state, as well as the 13-story Sheffield House at 5th and G streets, a downtown Anchorage landmark (now the Westmark). There were 19 hotels in the chain when Sheffield sold them to Holland America Line. Most continue in operating today as Westmark hotels. Meanwhile, Sheffield had met and married his wife Lee. By the late 1970s he was happy in his life, successful in business and ready for new challenges. He had long been a big fundraiser for Democrats and now wanted to run for office himself. He set his sights high, too: the 1978 governor’s race. Tragedy intervened, however. Lee was diagnosed with cancer. “I dropped everything, politics, running the business, to become her full-time caregiver,” Sheffield remembers. Lee struggled with her cancer for one year with Sheffield constantly at her side, finally succumbing in 1978. She died at home, in Sheffield’s arms. It took a while to recover from Lee’s loss, but the aim for the governor’s mansion was eventually reset for 1982. The stars were aligned for that. A bond proposition to pay for moving the state capital from Juneau was on the ballot, as was a referendum on rural subsistence. Sheffield opposed moving the capital, which gave him the Southeast vote, and supported subsistence, which helped get rural votes. He was lucky, too, that in the Republican primary Tom Fink, a conservative Anchorage Republican, defeated charismatic Lt. Gov. Terry Miller of Fairbanks, a Republican moderate. In the contest against Sheffield, Fink was pro-capitol move and anti-subsistence, positions that played mainly to his Anchorage constituency. Sheffield won handily with his support from other parts of the state.

Study finds billion-dollar benefit to Medicaid expansion

Expansion of Alaska’s Medicaid program under the new federal Affordable Care Act would create $1 billion to $1.5 billion in new wages in the state between 2014 and 2019 from added jobs in health care and employment generated by new business activity, according to a study by Northern Economics Inc., an Anchorage-based consulting firm. Expansion of Medicaid under the federal law is discretionary to states and Gov. Sean Parnell is now considering whether to allow the expansion in Alaska. The Northern Economics study, which assessed the costs and benefits of Medicaid expansion, was done for the Alaska Native Tribal Health Consortium, or ANTHC, and was released Jan. 18. ANTHC operates health care facilities for Alaska Native people, most in small rural communities. The state Department of Health and Social Services is doing its own study of Medicaid expansion. The study is reported to be complete, but it has not yet been released. Under the federal law the federal government would pay for 100 percent of the costs of expanded Medicaid for three years starting in 2014, and then 90 percent after. “If the expansion is authorized, about 97 percent of the program costs will be federally paid over the first six years and 94 percent over the first decade,” the Northern Economics report said. The expansion would cover adults who are currently not covered by Medicaid and who have annual incomes up to 138 percent of the Federal Poverty Level, or $20,000 in annual income for an individual and $26,000 annually for a couple. If the expansion in Alaska is allowed, an estimated 34,760 low-income Alaskans currently not covered by Medicaid will be covered, Northern Economics said in its report. This estimate was developed by the Urban Institute, a national organization, but it actually represents about two-thirds of the full population that could be covered, said Pat Burden, a principal at Northern Economics. If all Alaskans that could be eligible were covered, the number could increase to about 65,400 in a “full case” scenario, Burden said. The employment and wage effects of the expansion consider only the more conservative “mid-case” scenario, Burden said. There a lot of reasons why not all people eligible for Medicaid may not take advantage of it, including that many low-income people may live in remote rural communities with limited access to information, or that there may be language barriers, Burden said. Valerie Davidson, government affairs director for ANTHC, said her organization estimates that about one-fourth of all Alaskans currently covered by Medicaid are Alaska Native. Although he has not yet made a decision, Parnell has expressed concern about the expansion because of the additional state costs, estimated by Northern Economics at $34.9 million for the Alaskans newly covered by the expansion under a mid-case expansion scenario. However, the actual state costs will be much lower because many health care services now paid by the state outside of Medicaid, such as care for prisoners, public health immunization programs and the state Catastrophic and Chronic Assistance Program, will be paid by Medicaid if the program is expanded. “This would reduce the net effect of the expansion on the state budget by about half,” Northern Economics said. Tribal health organizations that operate hospitals and clinics serving mostly rural communities, but also in Anchorage and Fairbanks, have a big stake in the Medicaid expansion issue, said Davidson. Federal Indian Health Service funds cover only about half the average cost of health services provided to federal employees, as measured on a national scale, Davidson said. Because of that, Congress allowed Alaska Natives to be covered by Medicaid, to supplement the IHS funding, but also provided that 100 percent of the Medicaid share be paid by the federal government. However, that only happens if the care is given in a Tribal facility. If an Alaska Native goes to a non-Tribal care provider the state picks up 50 percent of the cost, Davidson said. One of the state’s goals is to encourage more Alaska Natives to get care in the Tribal-operated facilities so the federal government picks up all the cost, State Health and Social Services Commissioner Bill Streur has said previously. Davidson said one effect of the expansion would be to improve the Tribal health facilities’ ability to expand care, including to more specialized services. That will encourage more Alaska Natives to use Tribal facilities, such as in urban centers. That will help the state because those costs will all be paid for by the federal government, she said.

Fresh faces, energy in Juneau as session opens

A new Legislature convenes in Juneau Jan. 15 bringing fresh faces and energy to tackle old problems, nagging issues like oil taxes and, with oil production declining, restraining the growth of spending. Republicans are firmly in control of both the House and Senate, with 13 Republicans and 7 Democrats in the 20-member Senate, and 25 Republicans and 15 Democrats in the 40-member House. Rep. Mike Chenault, R-Nikiski, was chosen to once again be Speaker of the House, while Sen. Charlie Huggins, R-Mat-Su, will lead the Senate as president. Revenues seem sufficient to cover expenses for the upcoming 2014 fiscal year, which begins July 1. The latest estimate is that the state will receive $11.36 billion in total revenues in the 2013 fiscal year. Gov. Sean Parnell has proposed a spending plan of $10.86 billion, which includes a proposed capital budget of $1.8 billion. If the Legislature adds $500 million in capital appropriations, which is quite possible, the expenditures will match expected income. A possible $2.35 billion capital budget is healthy, but will be down from the $2.88 billion capital budget approved for the current 2013 fiscal year. Lawmakers will meanwhile be watching oil production levels and oil prices and will make final budget decisions based on an updated revenue forecast that will be made in the spring. Oil production is declining at rates of about 6 percent per year, a matter of concern to legislators. Energy problems in the state will be at the forefront in 2013. House Speaker Chenault and Rep. Mike Hawker, R-Anchorage, have reintroduced their bill to expedite an in-state gas pipeline from the North Slope; Parnell has included $95 million in his proposed budget for continued work on licensing a $4.6 billion hydro dam on the upper Susitna River; and Fairbanks legislators will be at work to get a natural gas trucking project under way from the North Slope to relieve high space heating and power costs. The 2013 version of the Chenault-Hawker bill to facilitate the in-state gas pipeline is HB 4, among the prefiled bills. The measure is similar to last year’s HB 9 which established new confidentiality powers and made changes on regulatory issues, and also would allow the state Alaska Gasline Development Corp. to have access to $200 million set aside in a fund to finance engineering and development. Parnell is expected to unveil a new proposal to adjust the state’s oil and gas production tax, which the governor says is too high and inhibits investment in new oil development. A similar proposal by Parnell in 2011, continuing through the 2012 session, resulted in deadlock. The House passed the governor’s bill, HB 110, but the Senate refused to approve it both years and was unable to get a majority of its coalition leadership to approve an alternate proposal it developed. Republicans have a clear majority in 2013, up to 13 from the previous 10, and Democrats’ numbers have dropped from 10 to 7, so there may be a better political environment for the oil tax issue this year. “May” is the operative word. Passage won’t be a slum dunk for this controversial, complex issue. The three Fairbanks senators, all Republicans, were pressured in their campaigns to demand that tax reductions for industry be linked to increased investment and improved production, a good idea in theory but complicated to actually write in the tax code. Legislators also hope to see progress on the large natural gas pipeline and LNG export project being planned by the three major North Slope producers and TransCanada, a pipeline company. The governor is hoping to see the companies commit to pre-Front End Engineering and Design, which would involve the first substantial financial commitment to the project. Lawmakers will also be watching to see if that happens. The producers have made it clear that progress on adjusting the oil tax is needed for the gas pipeline because a healthy oil producing industry is needed over the long term to pay for the infrastructure that will also support gas production. On other issues, it is clear that with both the incoming Senate President Huggins and Speaker Chenault representing Southcentral Alaska, issues affecting that region will have a priority this year that was absent in 2012. In a talk to the Resources Development Council Jan. 3 Huggins mentioned legislation to expedite the long-planned Knik Arm crossing project, a road down Cook Inlet’s west side to boost resource development in that area, and upgrades to electrical distribution grids, a priority for Southcentral electric utilities. On the Knik crossing, Rep. Mark Neuman has introduced HB 23, relating to bonds and reserve funds needed for the Knik Arm Bridge and Toll Authority that was formed to build the crossing. Huggins and Chenault, who was also at the RDC meeting, both mentioned support for the Watana hydro project and the in-state gas line. It’s noteworthy also that the two Finance co-chairs in charge of the capital budget are both from Southcentral, Rep. Bill Stoltze, R-Chugiak, on the House Finance Committee and Sen. Kevin Meyer, R-Anchorage, on the Senate Finance Committee. The House and Senate co-chairs for the operating budget are Rep. Alan Austerman, R-Kodiak, and Sen. Pete Kelly, R-Fairbanks. Given the positions they are in, Huggins and Stoltze are also expected to give a priority to sports fisheries and particularly efforts to enhance and protect the diminished king salmon fisheries in Cook Inlet. The first batches of pre-filed bills by House and Senate members are available, 46 bills in the House and 10 bills in the Senate. The measures aren’t formally introduced until the Legislature gavels in on Jan. 15, however. Many of the proposals have been in the Legislature before and many are relatively routine changes to statutes. Many are of interest to businesses, among them HB 6 in the House and SB 8 in the Senate relating to audits of pharmacy records; a House proposal making changes in the Uniform Commercial Code, in HB 9; bills relating to commercial motor vehicles, in HB 15 and commercial vehicle registration in HB 19; a bill allowing issuance of one business license for multiple lines of business in HB 32; a Senate bill requiring reporting and analysis of tax credits in SB 5; a bill dealing with computation of tax on the state corporate income tax in SB 7; and a bill requiring more information on oil and gas expenditures related to petroleum investment tax credits, in SB 10.

Health insurance rates to go up in 2014 as ACA kicks in

For health care, 2013 starts the big countdown. Some provisions of the federal Affordable Care Act, like certain new taxes, took effect Jan. 1, but the big changes will be in 2014. That’s when major parts of the federal act take effect, and a lot of the effects won’t be pleasant. Premera Blue Cross Blue Shield of Alaska, the major provider of health insurance in Alaska, has done an internal assessment of how the new act is likely to affect premiums in the individual Alaska insurance market, at least for individuals and families that may seek coverage in a new insurance exchange required to be operating by January 2014. The effects will be strikingly different on people in different age groups and income classes but the bottom line is that most individual policy premiums are likely to go up, some by substantial margins. If individuals or families are in moderate- to low-income groups and qualify for new federal subsidies, that will help greatly. The individual policy market is a subset of the overall health insurance market, but the factors at play that influence costs may also influence other segments of the health insurance market, including group policies. Here’s the bottom line: On average, premium costs may increase between 30 percent and 88 percent before federal subsidies are applied for those who qualify based on preliminary estimates, according to Eric Earling, a company spokesman for Premera. The federal law sets the family income limit for subsidies at four times the federal poverty limit for Alaska, which works out to $115,000 for a family of four. Depending on a family’s income there are a wide variety of impacts. Jeff Davis, who heads Premera’s Alaska unit, said a younger Alaskan couple aged 30 to 34 with two small children and who are moderate-income and earning $115,000 a year or less will qualify for the planned new federal subsidies. They could see up to a 42 percent decrease in out-of-pocket health care expenses, according to Premera’s estimates. However, if the couple exceeds the $115,000 income limit by even a small margin, the subsidy goes away and they could see an increase as high as 158 percent in out-of-pocket costs. The underlying costs of insurance, which will be reflected in higher premiums for many, are to be driven up by the requirements of the federal law, which will set certain minimum benefits and have other requirements such as no denials of coverage because of preexisting conditions. While these requirements are popular with the public they still will add to costs. They also tighten the range of risks and limit the flexibility that an insurer like Premera can use in designing a policy. “Today we can match risk to the premium rate. We know there is less risk of health problems with a healthy 24-year-old compared to someone who is 64,” Davis said. Because there is less risk, the premiums can be lower. For the older person, who can usually expect more frequent health issues, premiums will be higher. Davis said the range of risks currently can be as much as one to five, with a young healthy person at one (lowest risk) and paying the lowest amount, and an older person at four or five (more risk) and paying more. The new federal health care act has the effect of squeezing this range “toward the middle,” Davis said, because the minimum coverage and other requirements increase risks across-the-board. Currently a younger person may be able to choose a “bare-bones” health plan that has lower premiums. But with the required minimum coverage and other new rules there will be less flexibility for bare-bones plans. The effect of all this is that younger, healthier people will pay more for their insurance, some by considerable margins. Many older people may pay less. Who pays what will depend on individual circumstances and the effects are now hard to predict. Overall, most Alaskans, particularly those buying individual policies, are likely to pay more. Another requirement in the federal law is that everyone must be covered by health insurance one way or another. This may seem desirable from a policy standpoint, because reducing the number of uninsured will help hospitals now stuck with uncollectable bills from those without insurance. However, the requirement in the federal law that everyone be insured is very weak, particularly for young, healthy people, Davis said. “There is a $95 federal tax penalty. For a young person who earns more than the income limit to qualify for the subsidy and who could face a $1,000 a month health insurance premium, going without coverage and paying the tax penalty will be very tempting,” he said. As for group policies, another big uncertainty is how many employers of workers in low-wage industries may opt to drop coverage and move their workers into the subsidized exchanges. “It might mean less money paid out,” for employers in spite of any federal penalties, Davis said. This is something Premera is watching closely because the company does a lot of business with small employers buying small-group policies. The effects are unpredictable. For example, an insured group for a small employer paying lower wages could drop, from 20 to 5, for example, with most of the employees moving into the subsidized exchanges and only a handful of managers or older employees left under the company policy. “That would affect the cost” for maintaining the company’s coverage, Davis said. What Premera doesn’t know is how many of the individuals or families will seek coverage in the exchange, and what their income profile will be. One telling indicator is that when Premera did an analysis of single people and families covered by its individual policies in Washington state it found that up to 75 percent of those currently covered may not be eligible for the subsidies.

Foodie alert! New store offers international selections

For foodies in Anchorage there’s a new treat. It’s Oil & Vinegar, a small store in Anchorage’s downtown Fifth Avenue mall that specializes in olive oils, vinegars, sauces and other food treats mainly from the Mediterranean. Vickie and Brent Rose of Anchorage opened their store Nov. 1. Business has been brisk since word got around among those interested in food culture, to the point that the couple has had to order in extra supplies. Brent Rose works for an international airline and flies to Europe. Vickie Rose is a retired medical records technician, and volunteered at their church kitchen for events and catering for friends and family. Both are self-admitted “foodies” who enjoy trying new things and sharing their experiences. With their new store now open, “I get to be around my hobby all day long, and to talk about it,” Vickie Rose said. Oil & Vinegar is a franchise of Assisi, a Netherlands-based firm that started business 13 years ago to specialize in small, upscale gourmet food retail outlets, first in Europe and now the U.S. The store offers a wide variety of olive oils and vinegars, sauces and spreads, most with intriguing names such as Chardonnay Jalapeno Grapeseed and Provencal Herb extra virgin olive oil. Brent Rose’s favorite is the Ederflower Apple Lime vinegar. The store also has a selection of truffle products as well as a Barolo wine vinegar with truffles, many spices as well as bread dips which are tasty when used as a dry seasoning, and mustards, sauces and other specialty foods. There is a Wasabi Ginger dressing which has the Wasabi taste without the burn. A tasting table in the middle of the store allows customers to sample the products. There’s a nearby pasta table, too. Flavored extra virgin olive oils and vinegars are sold in bulk in a rack of glass amphora containers that cover a wall, with another rack of stainless steel containers known as “fusti” in Italy, where the products from seven countries are dispensed. There are about 40 varieties of oils and vinegars from different nations in the store, mostly European. They will also soon carry an extra virgin olive oil from California. The olive oil from California will be from olives that where crushed in October this year. These oils and vinegars are available for purchase with a bottle which is purchased at the store, Vickie Rose said, but once that bottle is empty it can be refilled with a new purchase.  All of this is in 920 square feet in the mall, which is about the size of all Oil & Vinegar stores, even in Europe. The small size is intended to give the store a more intimate European feel. There are now more than 100 Oil & Vinegar stores in 14 countries, mostly in Europe. However, there are now 11 stores in the U.S. including the new Anchorage store, said Matt Stermer, manager of Assisi’s franchising in the U.S. Stermer himself owns one of the first stores opened in the U.S., in Bellevue, Wash., and now owns franchise for the U.S. Stermer said a Palm Beach, Fla., store opened two weeks after Anchorage and a Scottsdale, Ariz., store is due to open before the end of the year. A Valencia, Calif., store will open in 2013, Stermer said. Stermer sees Anchorage as a good fit for the company. “We look for communities of about 250,000 population, demographics that show a generally affluent population, a good tourism industry and an established ‘food’ culture, with people who appreciate good food and new tastes,” Stemer said. Anchorage fits all that, he said. The Roses first encountered Oil & Vinegar stores in England while visiting one of their daughters, who was studying there. Both are long-time Anchorage residents who both learned about the food business, and franchising, years ago while working for Bill Pargeter, an Anchorage businessman who developed the first McDonald’s franchise outlets in the city. The years passed with the Roses pursuing their careers but the two never lost their interest in owning their own business, and one with a food theme, they said. In 2009, thinking about a retirement business, the two got serious, Vickie said. The idea had been planted. “We really liked Oil & Vinegar when we saw the first store,” which was in Bath, England. “We met and talked with Matt (Stermer), we signed the franchise agreement in 2011 and opened this year,” she said. The store is expected to do well in Anchorage because Alaskans do travel and have experienced wide varieties of cuisine, and other new niche retail stores in the city are doing well, such as Summit Tea and Spice, which recently grew out of its small South Anchorage store and has opened a larger store in Midtown. Summit Tea and Spice offers gourmet food items too, but Vickie Rose said she sees Oil & Vinegar as complementing rather than competing head-on with Summit Tea and Spice, or other specialty food stores in Anchorage. She has also been surprised how many military people come in looking for things to add to meals to remind them of cuisine they liked while stationed at bases in Europe. Another surprise is how many visiting rural Alaskans, curious about new tastes, come in during conventions and meetings held in Anchorage by Alaska Native organizations. The downtown mall location is expected to be good during the summer tourist season, too. Stermer said tourists are a good source of business in many other places where there are stores. Brent and Vickie Rose admitted concerns about the store’s first post-holiday period, when the Christmas rush is over and things slow down. However, the two are developing a marketing plan to continue building interest in Oil & Vinegar, with special events with chefs, for example.

Utilities make first draw from gas storage

Just in time for recent cold weather, Southcentral Alaska utilities are now making their first withdrawals from a new natural gas storage facility near Kenai. “We’ll be depending on gas storage for 20 percent of our estimated peak needs this winter,” Chugach Electric Association spokesman Phil Steyer told the Anchorage Chamber of Commerce Nov. 26. The storage project, completed this year, “is just in time” for the winter, Steyer said. Other utilities are withdrawing gas from storage also. Enstar Natural Gas Co. said colder weather has resulted in more gas demand from its customers. The new Cook Inlet Natural Gas Storage Alaska, or CINGSA, facility is critically important this winter because the ConocoPhillips natural gas liquefaction plant near Kenai is no longer able to divert gas to the utilities as it has been in past winters. “We are now selling all the gas we produce to the utilities. We are not making LNG at the plant, which is in a “warm shutdown,” ConocoPhillips spokeswoman Amy Burnett said. Chugach Electric, Anchorage’s city-owned Municipal Light and Power and Matanuska Electric Association made presentations to the chamber on new electrical generation and power distribution projects they have under way, but uppermost of the minds of utility managers are looming long-term shortages of gas, the need to meet peak-demand periods this winter, and rate increases needed to pay for new projects and for rising prices of gas. Steyer recommended to chamber members that they plan for electric rate increases of 5 percent to 10 percent in 2013, although final numbers won’t be known for some time. Enstar Natural Gas Co. rates will rise, too. Although Enstar was not at the chamber Nov. 26, its spokesman John Sims said the utility has advised the Regulatory Commission of Alaska that its cost for natural gas will increase by 14 percent in the first quarter of 2013, an amount that will have to be passed on to consumers. Enstar’s gas costs are expected to average $7.24 per thousand cubic feet, or mcf, in the first quarter of the year, up from $6.16 per mcf in the last quarter of 2012 and $6.71 per mcf in the first quarter of 2012. The major challenge for Enstar is simply getting enough gas for its needs in 2013, however. Sims said the utility still faces a gap of about 4.2 billion cubic feet of its expected 2013 requirement of about 33 billion cubic feet, although negotiations are continuing with producers in the region. “The fact that we are going into the new year with a gap this large puts us into an uncomfortable position,” Sims said. If Enstar is unable to secure its supplies the utility will have to ask the electric utilities to share gas they have under an agreement between the Southcentral utilities. This would be expensive, but the electric utilities have capabilities to shift to alternatives for some of their needs, such as using diesel to some extent, halting sales of power outside the region or even importing power from Golden Valley Electric Assoc. in Fairbanks. “The electric utilities will bear the brunt of any fuel shortage because you can shut us off,” from gas, Joe Griffith, Matanuska Electric Association’s general manager, told the Anchorage chamber. Enstar has no alternatives, however, and its system must be protected, he said. Steyer reviewed the gas supply situation for chamber members. Although Enstar’s gap is immediate, Chugach faces its own gas supply gap in 2014 and 2015, and ML&P faces future gaps as well. Steyer cited findings from a consulting firm hired by the utilities that has forecast an annual supply gap, between total gas demand and estimated total supply, of 6.2 billion cubic feet in 2015, 11.4 billion cubic feet in 2016 and 16.6 billion cubic feet in 2017. The utilities are working together now to meet those gaps with either imported liquefied natural gas or compressed gas. Suppliers of LNG and compressed gas have now responded to Requests for Proposals from the utilities, and an economic consulting firm will be hired soon to compare the proposals and make recommemndations. “Some are saying ‘no, no’ to gas imports, but we will have to have some kind of new gas in the pipeline by the winter of 2014 and 2015,” ML&P’s general manager Jim Posey said. It’s too early to know the additional cost of importing gas but at the chamber meeting Posey said it might cost 30 percent to 40 percent more than what is now being paid to gas producers in the region. LNG prices in Pacific markets are now trending downward. “There’s a lot of gas on the water,” he said. ML&P improvements ongoing Posey reviewed ML&P’s plans with chamber members. The city utility, which is celebrating its 80th anniversary this year, serves a 20-square-mile core area of Anchorage’s downtown and midtown, including the bulk of the city’s large commercial and institutional including the midtown office, university and health care buildings. To modernize and keep up with growth, ML&P has a $459 million five-year capital improvements program under way, Posey said. The bulk of this, $274 million, is for new power generation facilities including ML&P’s 30 percent share of the new Southcentral Power Project now being built in south Anchorage. The new generation plants are more efficient than what they are replacing, and are expected to use 28 percent to 34 percent less natural gas to generate the same amount of power. “This is the busiest construction year we’ve seen in the last 40 to 50 years. The work is being driven by improvements we’re making at our power plants but also to repair damage from the wind storm that hit us this fall,” Posey said. One large project underway is construction of expanded generation facilities at ML&P’s power plant near Muldoon on the Glenn Highway. About 200,000 cubic yards of dirt were excavated this year at a site for a new power plant building adjacent to the existing plant. Three new gas turbines are on order, which will arrive in 2014 and be installed in 2015, Posey said. ML&P is also continuing work to replace above-ground power lines with underground lines. About $2.5 million is budgeted this year for this work, Posey said. A new, $22 million substation is also being installed so ML&P’s share of power from the new South Anchorage power plant can be moved efficiently to midtown Anchorage, the largest growth area for the utility. “The construction of new office towers has shifting our whole load to midtown,” Posey said, and the power transmission infrastructure must meet this demand. Another major customer will be Verizon Wireless, he said. ML&P gets most of its natural gas from the Beluga gas field, where it is the one-third owner. The field is declining at rates of about 17 percent per year but continued investments in compressors and new producing wells have offset some of that. In 2011, the owners of the field, which include ConocoPhillips, which operates the field, Chevron (now Hilcorp Energy) and ML&P, invested $60 million and achieved an 18 percent to 20 percent production increase, Posey said, but the long-term underlying decline has continued. New production wells drilled in the Beluga field don’t produce as much as gas, either. In the field’s early years there were wells that produced as much as 40 million cubic feet of gas per day, Posey said. Now the average daily rate per well is 15 million cubic feet, he said. New Chugach plant to fire up in 2013 Chugach Electric Association’s largest construction project is the new $369 million, 183-megawatt Southcentral Power Project, of which it is 70 percent owner with ML&P owning the remainder. The plant is nearing completion and will be generating electricity to grid in the first quarter of 2013, Chugach’s Steyer said. Chugach has a number of other projects also under way including replacements of transmission lines along the Seward Highway that serve Hope and Seward, and development of a stream diversion at Chugach’s Cooper Lake hydro facility, at Stetson Creek. Stream diversions have the effect of putting more water through a hydro plant, increasing the amount of power produced, Steyer said. Things are busy in the Matanuska Electric Association service area which includes the Matanuska-Susitna Borough along with parts of north Anchorage. MEA’s biggest project is construction of its new Eklutna Generating Station at Ekutna, its manager, Joe Griffith, said. Design work is essentially done on the plant as well as site preparations and a connection to a natural gas pipeline. Ten large engines that will produce the power are on order. They are large machines, 19 feet tall and 60 feet long, each weighing 300 tons.  The engines use natural gas as fuel but Griffith is investigating where a propane-air mixture can also be used. They can also be switched to diesel quickly, but if that were to happen the fuel cost to MEA would triple. MEA has other projects underway also including planning for a 37-mile new distribution line to move power more efficiently from the new generation plant at Eklutna to MEA’s main center of demand in the Wasilla area.

Hilcorp boosts oil in 2012, gas continues drop

Hilcorp Energy has been able to rebuild Cook Inlet oil production since taking over ownership of producing properties in early 2012, but natural gas production continues to fall in fields the company has interests in, according to information made available by the company. “It is not coincidental that fields where we are seeing increases are those we operate and fields we are seeing declines are fields where we are not the operator, or are in partnership,” Hilcorp spokeswoman Lori Nelson said. Hilcorp feels some of the other companies operating in the Inlet could be more aggressive in controlling costs, she said. Oil production in four Cook Inlet fields where Hilcorp is owner and operator has increased from about 6,500 barrels per day last January, when Chevron transferred ownership, to nearly 8,000 barrels per day in November, the data indicates. Hilcorp president Greg Lalicker presented some of the information at the Resource Development Council’s annual conference Nov. 14. The bulk of the increase is a resulted of an aggressive program of well workovers and repairs initiated by Hilcorp. The company has spent about $230.7 million in 2012. There was a 122 percent increase of oil output from the small Swanson River field, Alaska’s first commercial oilfield that was discovered in 1957 and has been producing since 1959. McArthur River, Cook Inlet’s largest oil field, has seen a 8 percent increase since Hilcorp took over. Granite Point, the second largest in the Inlet, is up 27 percent. The Trading Bay field is up 36 percent. The picture is different with natural gas, however. Hilcorp’s overall net gas production is slightly down for the January-through-November period to about 6,000 thousand cubic feet, or mcf, per day but the three largest fields the company has interests in are showing declines. The Beluga River field, in which Hilcorp has a one-third interest and is operated by ConocoPhillips, gas production is down 11 percent since January. The Marathon-operated Nilnilchik field, in which Hilcorp has a 40 percent interest, is down 6 percent in gas production. Trading Bay, where Marathon also is operator, has seen gas production drop by 33 percent. The only significant gas field that has shown an increase has been Deep Creek, which has more than doubled its production. Hilcorp and Marathon have signed an agreement for Marathon to sell its Inlet gas production assets to Hilcorp for $375 million and the transaction is expected to close after January, following approval by a state court judge on a Consent Decree signed by Hilcorp with the state. Hilcorp plans to invest $50 million in the properties being acquired from Marathon on 2013, Nelson said, along with $150 million to $200 million in the other Inlet properties. The state had antitrust concerns with the acquisition because in purchasing Marathon’s properties Hilcorp will own 70 percent of Cook Inlet gas production. In the Consent Decree Hilcorp agreed not to increase its prices for gas sold to utilities for five years except for a 4 percent annual escalator that essentially adjusts for inflation. The company is also barred from selling gas to a LNG export market until local utility needs are met.

Point Thomson construction expected to begin in January

ExxonMobil Corp. hasn’t officially given the green light on construction at the Point Thomson gas field 60 miles east of Prudhoe Bay — the company is still securing final permits, it says — but all indications are that the project is a go. Construction of gravel pads, roads and other facilities is expected to begin in January, under the current schedule. Installation of 2,200 vertical support members, or VSM, and a 12-inch, 22-mile pipeline will begin later in the winter. A camp, offices and warehouse have been established at Deadhorse, at Prudhoe Bay. The first activity will be construction of an ice road from Prudhoe to Point Thomson, which should begin in December. The companies aren’t saying what the project cost will ultimately be other than it is a “multi-billion-dollar” undertaking. Sources familiar with the planning say costs will far exceed the $1.3 billion originally estimated, however. Randy Broiles, ExxonMobil’s vice president for the Americas, praised efforts by the state and others to overcome obstacles facing Point Thomson in the past. “This much-needed progress is heartening and demonstrates what can be achieved by working together, but as producers, legislators, regulators and citizens, we need to maintain the momentum,” Broiles said at the Resource Development Council’s annual conference Nov. 14. “This project is now ready to become what I hope is the first step in commercializing Alaska’s significant natural gas resources,” Broiles told the RDC. Point Thomson construction will also be the largest North Slope project in several years and will employ several hundred people this winter, a welcome development for Alaska’s support contractors and suppliers who have been worried about a slowdown of work on the North Slope. ExxonMobil is the operator and owner of the largest percentage in Point Thomson, but BP is also a significant owner and ConocoPhillips also has a smaller stake. There are an estimated 8 trillion cubic feet of natural gas reserves discovered at Point Thomson as well as about 200 million barrels of liquid condensate, a natural gas liquid. There are additional pools of conventional oil near the field but the viability of producing those is not yet certain. ExxonMobil will build a gas cycling and condensate production project as a first phase of development. Gas will be produced from the high-pressure reservoir, the liquid condensates will be stripped off, or separated, and the gas will be injected back underground. The field is pressured at more than 10,000 pounds per square-inch, about twice as high as Prudhoe Bay’s initial pressure. This means injecting the produced gas back underground is no easy feat — the compressors needed to inject the gas will be among the most advanced in the world, ExxonMobil said. The liquids, meanwhile, will be shipped by pipeline to the Prudhoe Bay field where they will be blended with crude oil in the Trans-Alaska Pipeline System. The project requires 22 miles of new pipeline to be built from Point Thomson to the small Badami field, where a connection will be made with an existing pipeline from Badami to Prudhoe Bay. Two wells were drilled for the project in 2010 and are currently suspended. Three other wells are planned to support the initial production, and drilling will resume in 2015 under the current schedule. The project will produce 10,000 barrels per day of condensates, a small amount given the scale of investment. However, the project is seen basically as a test of whether gas cycling will work in the Point Thomson reservoir, where there are still some technical questions. If it works as expected the liquids production can be scaled up. If there are problems, the facilities being built can be converted to support conventional gas production for a pipeline or to ship gas to Prudhoe Bay for use in oil recovery. The 22-mile pipeline will have a capacity of 70,000 barrels per day to accommodate increased condensate production or, at some time, conventional crude oil production. The startup is expected the winter of 2015-16, according to a presentation ExxonMobil made to the Alaska Oil and Gas Conservation Commission on Oct. 30. When it begins production, Point Thomson will represent the first commercial use of North Slope gas, Broiles told the RDC Nov. 14. The project also sets the stage, in terms of infrastructure, for a large natural gas pipeline that may be built, because Point Thomson gas, which will be recycled in the current project, is critical for a pipeline. Broiles noted key recent milestones for the project. Last March the state and the Point Thomson owners settled long-standing litigation over disputes on previous work commitments. Those disagreements had blocked progress in development. In late summer the U.S. Army Corps of Engineers issued a long-awaited final environmental impact statement and in October issued a record of decision approving the EIS, a major regulatory milestone. In his talk to the RDC Broiles praised the team approach the companies, the state, and the regulatory agencies have taken to secure the key permits for Point Thomson. “Gov. (Sean) Parnell and the state of Alaska played a key role in this process,” he said.

Flint Hills files application, then backs off LNG trucking plan

Flint Hills Resources has filed plans to build a $184 million natural gas liquefaction plant at Prudhoe Bay with Alaska agencies, but has put the project on hold until sufficient customer demand is firmed up, a company spokesman said Nov. 19. “We’re backing off until we see what others come up with,” Flint Hills spokesman Jeff Cook said. Mike Brose, a company vice president, said in a press release that Flint Hills will await proposals from others before proceeding. The company is a subsidiary of Koch Industries, If the plant is built, LNG would be trucked from the North Slope about 400 miles to Fairbanks, in Alaska’s Interior, to provide fuel for industrial customers, including itself, and other potential buyers. Flint Hills operates a refinery at North Pole, east of Fairbanks, and now uses crude oil to provide power and to heat crude oil taken from the Trans-Alaska Pipeline System for refining. Golden Valley Electric Association, the Interior Alaska electric cooperative, had been working with Flint Hills on the plan to truck LNG, but Brose said Nov. 19 that a joint-venture approach will not proceed, although Golden Valley could be a customer for the plant. Golden Valley is hoping to use natural gas from LNG to generate power, replacing fuel oil that is now used in generation plants. In its application to the state, Flint Hills said it would build its plant on a gravel pad ranging from 9 acres to 12 acres. A 1 million-gallon LNG storage tank would also be located at the site. Meanwhile, there is another company interested in a North Slope LNG trucking operation. Spectrum LNG LLC, owner and operator of Desert Gas LP, in Arizona, has also filed applications with the state to build a Prudhoe Bay LNG plant, according to Ray Latchem, Spectrum’s president. Spectrum’s plant in Arizona now supplies 50,000 gallons of LNG daily for vehicle fleet use in the Los Angeles and Phoenix markets. The company also led development of a small LNG plant near Anchorage that now supplies LNG for shipment by truck to Fairbanks Natural Gas, a small gas utility operating in Fairbanks. Ironically, Flint Hills and Spectrum have both filed for surface leases at the same locations near the Prudhoe Bay field. “We filed our applications first and they came along and top-filed on us within 30 days, which means the state will have to decide which one of us gets the lease,” for the plant, Latchem said. Elizabeth Bluemink, spokesman for the state Department of Natural Resources, confirmed that Commissioner of Natural Resources Dan Sullivan will decide which company will get the lease. Flint Hills spokesman Cook said the company is in discussions with a North Slope producer to supply gas to the plant. Golden Valley had separately negotiated a contract with BP to supply gas for its needs, but that assumed it would be part of the Flint Hills project, but Cook would not confirm that Flint Hills is part of the BP contact with Golden Valley. Latchem said that if Spectrum’s plan goes forward it would make LNG for local use on the North Slope, for vehicles or heavy equipment, but would also truck LNG to Fairbanks. Latchem previously helped develop Fairbanks Natural Gas, a small private utility that now serves 1,100 commercial and residential customers in a core downtown area of the city with gas shipped as LNG from Anchorage by truck. In its Nov. 19 press release, Flint Hills said, “With the completion of phase 2 engineering, the next step that must be taken is to determine whether there is sufficient interest in LNG, outside of the industrial demand that FHR (Flint Hills Resources) is targeting, to build a plant. Flint Hills believes that the Alaska Industrial Development and Export Authority, or AIDEA, and the Alaska Energy Authority are the right entities to explore that question, and has invited those entities to provide the company with a proposal.  Mike Brose said, “we don’t think that we would build the plant for our needs and the needs of other industrial users alone, so we will wait for AIDEA or AEA to do further investigation and present a proposal if they think that is appropriate. Flint Hills is willing to provide AIDEA and AEA our completed phase 2 engineering studies if that would be helpful in their analysis.” Brose said that Flint Hills anticipates that Golden Valley’s needs for power generation will be considered in the analysis by AIDEA and AEA.   If the project were to proceed, Flint Hills said it could have its plant operating in the second quarter of 2016, assuming that it can begin construction in 2014. About 500 construction workers would be needed to build the facility. Operations would require about 10 permanent staff, according to the application.

LNG project is linked to oil tax change, producers say

All three major North Slope producing companies say progress on a large natural gas pipeline and liquefied natural gas project is linked to reform of the state’s oil production tax, an issue that will be before the state Legislature again in its 2013 session. The three companies made presentations at the Resource Development Council’s annual Alaska resources conference Nov. 14, and all three voiced the same message: “It is essential to build a competitive fiscal regime for both oil and gas. Stability is essential,” said Randy Broiles, ExxonMobil Production Co.’s vice president/Americas.  John Minge, president of BP’s Alaska production company, said gas and oil production tax issues are linked because the two are produced out of the same wells and supported by the same infrastructure. Gas production won’t work economically unless there also oil production that supports the oil field infrastructure, but the present state tax, known as ACES, does not encourage long-term development of known oil resources in the existing fields that are needed to sustain the field infrastructure. “We are serious about gas to LNG, but fiscal reform for oil and gas is essential to enable this massive investment to happen,” Minge said. “If the state has a short-term 10- to 15-year future mindset, ACES is the right approach. But if you want to take a long-term view and have a sustainable oil business and have a real shot at gas, change is needed. Within that view the legacy (producing) fields are essential.” Nick Olds, ConocoPhillips’ vice president for North Slope operations and development, agreed: “North Slope gas production will depend on a healthy oil business,” to preserve the producing infrastructure for the big legacy field of the North Slope. “Over the next four decades we see the potential for developing 4 billion barrels, but to produce those barrels we will need to invest substantially in renewal of the infrastructure, and to maintain it so we will have a platform for gas,” Olds told the RDC. Gov. Sean Parnell had earlier planned to introduce a bill revamping the state gas production tax but subsequently decided to hold off to give the Legislature time to consider anew the oil production tax adjustment next spring. A change in the gas tax, mainly establishing a mechanism for tax stability, is essentially unworkable unless the oil tax issue is addressed first, the North Slope companies have said previously. Under Alaska’s net profits-type production tax, oil and gas production are taxed together because they are produced from the same wells.  In his presentation to the RDC BP’s Minge criticized the ACES tax as short-sighted policy. “ACES is clearly a short-term going out-of-business policy and it will deliver very predictable results. It is delivering very predictable short-term results and we have a 5-year track record to prove it,” Minge said. “The State of Alaska is doing very well taking mass amounts of the upside (of revenues) at today’s oil price. The long-term (industry) investment is down, especially capital going into production enhancement activities.” Olds, of ConocoPhillips, said his company has increased its capital investment in Lower 48 producing properties from $1.6 billion in 2009 to $4.8 billion in 2012, mainly because of stronger oil prices. In Alaska, however, ConocoPhillips’ annual investment remained essentially flat, at about $900 million per year, over the same period. That is mainly because the state tax captured most of the gain of higher prices, leaving the company with little incentive to increase investments. To illustrate this, Olds said that in 2007 oil prices were at about $70 per barrel, the state earned about $27 in net revenues per barrel and ConocoPhillips earned about $22 per barrel. In 2011, oil prices had increased to $106 per barrel and the state’s earnings per barrel increased to $51 per barrel, a gain of $23 per barrel. However, ConocoPhillips’ earnings per barrel increased only to $25 per barrel in 2011, a gain of only $3, he said. Minge, at BP, painted a bleak picture unless something is done: “Decline continues at 6 to 8 percent per year and we can reasonably forecast that in 10 years the production in TAPS will be somewhere around 300,000 barrels per day.” That is now considered the lowest economic operating limit for TAPS. For critics of tax reform who question what Alaska “gets” for the tax adjustment, Minge said, “you get a future,” with an industry that could extend for decades. There are also complaints that the proposals so far have contained no guarantee that the companies will actually invest and produce new oil, but Minge said there are many examples around the world where governments have reduced taxes to encourage new production, and the initiative has worked. “I’m aware of no other place where people demand guarantees,” he told the RDC. Alaska should step forward and make the change now, he said. “You hold the keys, and you also hold the hammer,” Minge said, meaning the state can take the action to enable new investment but also holds the “hammer” to re-impose taxes if the industry does not perform. Minge said BP is having to take steps now to adjust the company’s plans and strategy to fit within the ACES policy. “We probably should have done that two or three years ago, but we can no longer wait,” he said. “Today our plans have really been mismatched against the state’s policy. It was built on the hope that a change (to ACES) will come. We’ve been focused on the more challenged resources and we need to take steps to invest in light (conventional) oil. We’re going to stop our heavy oil investment into the heavy pilot project within a few months,” Minge said.  Minge encouraged Alaskans to work together to break the divide: “Alaskans are very aligned about what they want: a sustainable oil business, a major gas project to go forward, and everyone wants affordable energy for in-state needs and everyone wants jobs,” Minge said. “However, the current policy does not deliver that outcome. Policy decisions are essential to the future. We need to find a way to come together.” Broiles, of ExxonMobil, said there has been real progress on developing a large natural gas project and also in developing the Point Thomson gas and condensate field, which will involve the first commercial gas production on the Slope. Broiles praised the state for stepping forward last March to settle long-standing litigation over Point Thomson, and said the settlement was essential to a large gas project going forward. “The state was not quick or easy in their decision to settle this, but if we can build on this, to keep the momentum, the prize is huge,” he said. The U.S. Army Corps of Engineers issued its final Record of Decision on the Point Thomson environmental impact statement in October and the company is now working to secure other needed permits, an ExxonMobil spokeswoman said. Construction on the multi-billion-dollar project is expected to begin this winter. The project will produce gas, strip off liquid condensates, and inject the gas back underground. The liquid condensates will then be shipped to Prudhoe Bay by pipeline and mixed with crude oil in the Trans-Alaska Pipeline System.

Apache, Buccaneer advance Cook Inlet exploration work

Apache Corp. has spudded its first Cook Inlet exploration well, the company’s top Alaska manager told the Resource Development Council’s annual conference Nov. 14. Drilling operations began at 7:44 a.m. that day, John Hendrix, Apache’s Alaska manager, told the RDC audience in Anchorage. The well, Kaldachabuna No. 2, is on Cook Inlet’s west side a few miles from the Tyonek Native village, Hendrix said. Apache is primarily focused on oil prospects but it is likely the company may discover natural gas as well. In another development, Buccaneer Energy Ltd., an Australia-based independent, said Nov. 20 that it is preparing to conduct production tests at its Kenai Loop No. 4 gas well drilled at the company’s Kenai Loop field on the Kenai Peninsula. The company is awaiting final permits from the State of Alaska to conduct the tests, which are expected to be done after Nov. 27, according to a press release issued by Buccaneer. The well has been drilled to its intended location and has been cemented in place. During drilling, multiple sandstone formations with gas shows were encountered, but tests are needed before it is known whether the well can be produced commercially, Buccaneer said. The bottom location is about 2,000 feet from the Kenai Loop No. 1 well that was drilled successfully in 2011 and is now producing about 6 million cubic feet per day. If Kenai Loop No. 4 is successful it will make additional supplies of natural gas available to Southcentral utilities, who are concerned about declining production in the region’s large, older fields. Buccaneer is also engaged in Cook Inlet offshore production and with two partners — Ezion Holdings of Singapore and the Alaska Industrial Development and Export Authority — brought a jack-up rig to Cook Inlet this fall. The rig, the Endeavour, is currently undergoing repairs and upgrades at Homer. It will be moved soon to the company’s Cosmopolitan prospect near Anchor Point where a well will be drilled to test a known shallow gas deposit, company vice president Mark Landt told the RDC conference Nov. 15. Meanwhile, Apache Corp. now has access to about 1 million acres of subsurface lands in the Cook Inlet basin through leases with the State of Alaska or exploration agreements with Alaska Native corporations including Tyonek, Hendrix told the RDC. Since 2011 the company has been engaged in a multi-year 3-D seismic program of its acreage, the most thorough ever attempted in Cook Inlet. To date Apache has completed the seismic on about 200,000 acres, Hendrix told the RDC conference Nov. 14. “This data will give us an ability to look deeper in Cook Inlet than anyone has been able to do previously,” he said. The company’s primary targets are oil prospects bypassed in earlier Cook Inlet exploration, but Hendrix said badly needed gas will also be discovered. In its heyday in the 1970s and early 1980s, Cook Inlet produced 227,000 barrels per day, but production has now declined to between 10,000 and 12,000 barrels per day, Hendrix said. Apache believes there are substantial opportunities in the area because the normal cycle of exploration was cut short by prolific North Slope oil discoveries in the late 1960s and 1970s, which diverted companies away from the Inlet, Hendrix told the RDC.

Southeast Alaska mines nearing release of key economic assessments

Mining projects are on a roll in southern Southeast Alaska. Heatherdale Resources Ltd. plans to have a pre-feasibility study, an important stage in mine development, done for its proposed Niblack multi-metals mine in mid-2013. The company hopes to be able to apply for permits to build the mine in mid-2015, according to Heatherdale CEO Patrick Smith. Niblack is on Prince of Wales Island about 27 miles from Ketchikan, and is blessed with good tidewater access, Smith told the Alaska Miners Association at the group’s annual convention in Anchorage Nov. 8. If developed, Niblack could produce 1,500 to 2,000 tons of ore per day under the current plan. The ore contains copper, gold, zinc and silver, with much of the value in the copper and gold, Smith said. It would be an underground mine similar to the existing Greens Creek Mine on Admiralty Island near Juneau, Smith said. An important development is that Heatherdale hopes to finalize a plan to process ore from Niblack in a processing plant in Ketchikan, Smith said. Ore would be shipped by barge to a proposed plant at an industrial site on Gravina Island, the location of a former sawmill that has access to inexpensive hydro power provided by way of submarine cable from the nearby Ketchikan community. Building the mill at Gravina Island, if the plan proceeds, would require about 200 construction workers and would take about 18 months, Smith said. Another Southeast proposed underground mining project at an advanced stage is a rare earths project at Bokan Mountain, also on Prince of Wales Island bout 35 miles from Ketchikan, and also with good access by water. Ucore Rare Metals Inc., the developer, plans to have its preliminary economic assessment completed and published very soon, Ucore’s chief operating officer, Ken Collison, told the AMA, also on Nov. 8. A press release with the major conclusions of the PEA would be published first, and followed 45 days later with the release of the full report. The schedule now calls for a feasibility study for the mine, the final step before approval by the owners, to be completed by the end of 2013. “Once permits are issued, and how long that will take is the big question, construction would take about one-and-a-half years,” Collison told the miners association. Ucore would mine just more than 1,000 tons of ore per day but would use a new crushing sorting technique to identify ore with the highest content of rare earths, Collison said. Only about 375 tons of ore per day would be processed. The remaining waste rock would be temporarily stored on the surface but would eventually be placed back underground as “back-fill” in the mine. If the mine proceeds to production it would employ about 170 in its operations, with hourly workers on a two-week on, two-week off schedule and members of the management team on a one-week on, one-week off schedule. Ucore also plans to open an office in Ketchikan soon. The power requirement at a Bokan Mountain mine would be about 3 to 4 megawatts in operation but at the beginning, when the ore process mill is being started, the requirement is expected to reach 6 megawatts. Collison said Ucore is discussing the possibility of importing liquefied natural gas, or LNG, from a supplier in the Pacific Northwest to fuel power generation. “It would be about half the cost of using diesel,” he said. The plan now is to make two concentrates at the mine containing rare earth elements, but Ucore is also experimenting with a new technology that could allow the concentrates to be separated into three rare earth metals at the mine. The elements would be dysprosium, neodymium and erbium. Laboratory tests performed by IntelliMet LLC, a Montana firm, have demonstrated that the elements can be successfully separated from a composite of solutions that replicate the ores to be mined at Bokan Mountain, Ucore announced Oct. 3 in a press release. If processing of the rare earth metals could be done at the site it would lessen the dependence of the U.S. on China as a source of rare earth processing. Rare earths are commonly used in technology systems. Westmountain Gold produces first gold bar at Terra Project WestMountain Gold has completed analysis of gold and silver concentrates produced in a test run of a pilot processing mill at the company’s Terra project, a mine near the Alaska Range. The company also produced its first gold bar as part of the tests. “The assay results of gold concentrates from the Terra project mill are 71 percent gold and 29 percent silver. The gold recovery from the first metallurgical testing of the concentrates is greater than 98.5 percent recovered from the concentrate,” the company said in a Nov. 16 press release. Small quantities of copper, tungsten, antimony and zinc are also present in the ore, the tests have indicated. A 401-gram gold bar was produced from which 9 ounces of gold and 4 ounces of silver can be recovered through additional refining, the tests indicated. WestMountain president Greg Schifrin said, “The Terra Project mill has produced high concentration gold from the gravity mill. We are enthusiastic about the equipment and pilot mill upgrades underway and the anticipated production during the upcoming 2013 season.” Northern Dynasty to own share in “Big Chunk,” near Pebble Northern Dynasty Minerals has securing a major ownership share in the “Big Chunk” group of state mining claims located near the large Pebble copper/gold prospect near Iliamna southwest of Anchorage. The agreement between Northern Dynasty, which owns 50 percent of Pebble, and Liberty Star Uranium & Metals Corp., provides for Northern Dynasty to obtain ownership of 199 state mining claims in the “south block” part of the Big Chunk project to satisfy a $4 million loan made to Liberty Star. Tucson, Ariz.-based Liberty Star will retain 229 mining claims in the prospect area. Liberty Star also owns 184 mining claims in the “north block” part of the prospect area. Liberty Star did limited test drilling on the Big Chunk project in 2012 and has identified seven other targets through geochemical analysis, according to the company’s chief geologist, Jim Briscoe.

BP will shelve North Slope heavy oil production test project

BP will close an experimental heavy oil production project on the North Slope and slow investment in other technically-challenged oil resources to refocus on shorter-term opportunities with small accumulations of conventional light crude oil, BP’s Alaska president, John Minge, told the Resource Development Council’s annual conference Nov. 14. The move is related to the state of Alaska’s unwillingness so far to make changes in the state’s oil production tax to encourage more longer-term investment by producers in major producing fields on the slope, said “We have realized there is a certain mismatch in our strategy and it is time to take corrective steps. We have been too heavily focused on developing challenged resources,” Minge said. BP will switch gears to increase investment on near-term conventional oil and field projects to “de-bottleneck” production facilities to make them more efficient, he said. BP has drilled three heavy oil wells in a pilot production project in the Ugnu oil deposit, a massive undeveloped resource with about 23 billion barrels of oil in place but which cannot be produced with conventional wells. The wells are experimental, but some have produced several hundred barrels a day, BP has said previously. BP spokeswoman Dawn Patience said the test production won’t be shut down immediately but will not be maintained, so that the wells will be closed as operating problems develop. The pilot wells use a technology known as “Cold Heavy Oil Production with Sand,” or CHOPS, that was adapted from similar procedures used in Alberta. CHOPS involves use of an auger device to bring up the thick oil as well as sand produced with the oil. Minge said BP will also reduce its investment in other “challenged” oil prospects including drilling production wells into the Sag River formation, a thin layer of reservoir generally overlying the main Prudhoe Bay formation. BP and other producers are encouraging the state to change its production tax to encourage more long-term investment, Minge said. Gov. Sean Parnell has proposed an adjustment to the tax and it was passed by the state House in 2011, but not the Senate.

Railbelt legislators take control of House, Senate leadership

Conservative Republicans from Alaska’s “railbelt” region — Southcentral and Interior Alaska — will have an iron grip on top leadership positions in the state House and Senate when the Legislature convenes its 2013 session in January. Republicans currently hold 13 seats in the 20-member Senate and 25 seats in the 40-member House. Democrats hold 7 seats in the 20-member Senate and 15 in the House. Winners in the state elections met in the days after Nov. 7 to sort out key posts and chairmanships of most committees, particularly the influential Finance committees. The big losers in the new organization are rural and Southeast, where several veteran Alaska Native legislators, previously influential, are out of the loop either by having been defeated in the elections or pushed into the political backbench by the Interior-Southcentral axis of the new leadership. Sen. Charlie Huggins, a veteran Republican senator from the Matanuska-Susitna Borough, will be Senate President. Rep. Mike Chenault, Republican House member from Nikiski, near Kenai, will be Speaker of the House once again. Chenault has held the position for two consecutive Legislatures, or four years. The positions become official when the Legislature meets in Juneau on Jan. 15, its members are sworn in, and a Committee on Committees is appointed in both bodies to propose the leaders and committee assignments, which are then voted on by House and Senate members. Republican Sen. Kevin Meyer of Anchorage will co-chair the Senate Finance Committee with newly elected Republican Pete Kelly of Fairbanks, who was previously in the state Senate, as the other co-chair. On the House Finance Committee, Rep. Bill Stoltze, Republican of Chugiak, will again be co-chair, with another seasoned veteran, Rep. Alan Austerman, Republican of Kodiak, becoming the other co-chair. Several members of the previous Republican-Democrat coalition in the Senate have joined the new Republican majority to give it more stability. They include former Senate President Gary Stevens of Kodiak, who has been given chairmanship of the Senate Education Committee, and Sen. Bert Stedman of Sitka, a former Finance co-chair, who will chair the Senate Health and Social Services Committee. Two Democrats, also part of the former coalition, have also joined the majority. These include Sen. Dennis Egan of Juneau, who will chair the Senate Transportation Committee, and Sen. Donny Olson, of Nome. Olson will be able to retain a seat on the Senate Finance Committee. Democrats in the minority in the Senate include five veteran lawmakers: Sens. Johnny Ellis, Hollis French and Bill Wielechowski of Anchorage; Berta Gardner of Anchorage, currently a member of the House who was elected to the Senate, and Bethel Sen. Lyman Hoffman, previously co-chair of the Finance committee. French and Wielechowski were reelected in heated contests in their districts. French’s lead over challenger Bob Bell, the Republican, was narrow, however. As of Nov. 24 he held a 56-vote lead over Bell, with some absentee and challenged ballots still to be counted. The election results that were really crucial to the Republican domination of the Senate came in Fairbanks, however, where Sen. John Coghill and now-incoming senator Pete Kelly defeated two Democrat incumbent senators, Sens. Joe Paskvan and Joe Thomas. Coghill and Thomas, both incumbents, were matched against each other because of the 2012 redistricting of the Legislature, which occurs every 10 years. The district includes parts of Fairbanks, and the eastern Interior as well as Valdez, and its conservative constituency appeared to favor Coghill, although Thomas is a moderate, pro-development Democrat. The Paskvan-Kelly race, in a newly-drawn core Fairbanks Senate district, was heated. Paskvan raised more money for his campaign, much of it from organized labor, while Kelly had substantial help from Republican party funds, including from out of state. While Coghill was favored in his race, the Paskvan-Kelly race seemed like a toss-up, although Kelly won decisively in the end. Had it gone the other way, though, the Republicans would have had less of a decisive majority in the senate to the point that another coalition with Democrats would have been possible, or even likely. Other legislators in the leadership lineup include veteran Anchorage Republican Sen. Lesil McGuire, who will be chair of the Rules Committee in the Senate, an influential position. In the House, Rep. Craig Johnson, another Anchorage Republican, holds this position. The Rules Committee meets only rarely but its chair is responsible for deciding the selection and timing of bills to move to the House and Senate floor, which is important. The Senate Majority Leader, who will promote the majority’s legislative agenda on the floor of the Senate, will be Fairbanks Sen. John Coghill. In the House, Rep. Lance Pruitt of Anchorage, a Republican legislator who completed his first term in 2012, will be Majority Leader. Pruitt is still a newcomer to the Legislature who survived a bruising campaign for reelection against a strong Democratic opponent, but his selection as Majority Leader signals confidence in him held by his Republican colleagues in the House. Sen. Cathy Giessel, an Anchorage Republican just reelected to her second Senate term, will chair the Resources Committee in the Senate. She will play an important role in the Legislature’s work on oil tax reform that is expected to continue this spring. One important race result still teetering is in Southeast Alaska where incumbent Republican Rep. Bill Thomas of Haines held a two-vote lead over Democrat Jonathan Kreiss-Tomkins of Sitka on Nov. 14. Final votes will be counted in the next few days. Initial election results had Kreiss-Tomkins narrowly leading Thomas, a veteran legislator. Thomas was co-chair of the House Finance Committee in the last Legislature.

State, federal lease sales net $15M in North Slope bids

The U.S. Bureau of Land Management received 14 bids on 160,080 acres of federal oil and gas leases in the National Petroleum Reserve–Alaska in a lease sale held Nov. 7. Cash bonus bids totaled $898,900 from two companies. BLM is responsible for management of the federal reserve, which covers 23 million acres of the western North Slope. BLM now holds an annual areawide every fall and plans the sale for the same day as the state’s North Slope areawide sale, Murphy said. Twelve of the bids on leases submitted Nov. 7 were by Alaska independent NordAq Energy for tracts in the central part of the petroleum reserve. The other two bids, in the northeast part of NPR-A, were from Houston-based independent Woodstone Resources, a company new to Alaska. Meanwhile, state officials have expressed satisfaction with the state area-wide lease sale that netted $14.2 million, also held Nov. 7. The Division of Oil and Gas opened bids at the Dena’ina Civic and Convention Center in Anchorage and received 132 bids on 122 tracts from 13 different bidding groups, encompassing approximately 310,500 acres. In the State of Alaska lease sale, NordAq acquired 60,000 acres of offshore state leases in Smith Bay, just north of the NPR-A. Woodstone also bid for leases in the state sale. NordAq president Bob Warthen said his company is working on an integrated exploration program for the offshore Smith Bay acreage and the company’s onshore federal leases in the reserve with a target for drilling in 2014. The Smith Bay state leases are in shallow water. NordAq would build an artificial ice island to support the drilling, Warthen said. NordAq has also acquired onshore NPR–A leases held previously by FEX LLC, a subsidiary of Talisman Energy. FEX has drilled exploration wells on the leases and discovered oil and gas but has not been able to do production tests on the wells. The company decided to sell its leases and leave Alaska for reasons that have to do more with changed corporate priorities than the viability of the Alaska prospects, FEX has said. Warthen hopes to organize an exploration program that would explore Smith Bay, the onshore former FEX leases and the newly-acquired inland leases in an organized fashion. Although the FEX leases are in a part of the northern NPR-A where new leasing is now excluded, Warthen said that BLM officials have assured him that NordAq will be able to develop the FEX leases if commercial production can be established. A pending NPR-A land management plan would also allow a pipeline from the offshore Smith Bay state leases to come ashore and possibly connect with the other NordAq leases and with a large west-east pipeline being considered by Shell, if that company’s exploration in the Chukchi Sea is successful. Bidders in the state lease sale included North Slope major producers BP, Chevron, ConocoPhillips and ExxonMobil bidding together for two tracts west of the Kuparuk River field. There were also smaller companies and at least two new players. The bids by the major companies were in an area where there could be an untapped extension of the Kuparuk field, industry sources familiar with the area said. The percentages of the companies in making the bids are roughly comparable to the percentages the companies hold in Kuparuk. There is renewed interest in the western part of the central slope area since Brooks Range Petroleum discovered its small Mustang deposit and made plans to develop it. Repsol is also exploring in the area. The Beaufort Sea sale netted the state close to $1.8 million, with Alaskan independent NordAq Energy being the most aggressive bidder for the Smith Bay acreage. The North Slope Foothills area, which hasn’t seen any bidding in the past three years, received eight bids, all from Anadarko Petroleum Corp., which has explored in the area. The Foothills region has seen sporadic exploration for oil and gas and several large gas prospects have been identified in recent decades. “We are encouraged to see bidding in the Foothills region as well as the potentially gas-prone area in the southern part of the North Slope sale area, which may have an associated oil play,” said Bill Barron, Division of Oil and Gas director.

Hilcorp degree will cap gas prices, limit LNG sales

Cook Inlet gas producer Hilcorp Energy LLC has agreed to terms of a consent decree that will cap the price of gas sold to utilities and industrial customers for five years and not allow gas to be sold into LNG export markets until local utility needs are met, a state attorney said Nov. 8. The consent decree, if agreed to by an Alaska Superior Court, will clear the way for Hilcorp to complete its acquisition of Marathon’s Alaska assets, most likely in early January. Assistant State Attorney Ed Sniffen said the decree applies only to Hilcorp and not to Marathon. Even though the decree is not yet in effect, Hilcorp agreed Nov. 7 to abide by its terms between now and the time it is approved, Sniffen said. The U.S. Federal Trade Commission meanwhile agreed to drop its own investigation of the Marathon-Hilcorp sale and has deferred to the state of Alaska and the pending consent decree, the FTC said in an announcement Nov. 7. The parallel federal and state investigations have been under way for most of 2012. Sniffen said the state of Alaska is concerned because Marathon and Hilcorp today produce about 70 percent of the Cook Inlet gas sold to regional utilities, and having that much production controlled by one company could put utilities at a disadvantage in negotiations. Terms of the proposed decree will be made public when notices are published, probably early next week. The court will take comments from the public and interested parties for 60 days. Following that, a state Superior Court hearing will be held and a decision made on the consent decree he said. Final resolution of the matter will likely come in January, clearing the way for the Marathon asset sale, Hilcorp spokeswoman Lori Nelson said. Marathon disclosed last month to investors that the Cook Inlet assets were sold to Hilcorp for $375 million. Sniffen said the deal freezes gas prices sold by Hilcorp to utility and industrial customers at prices existing when the decree is official, likey in January, but those prices are expected to be similar to the average price of Cook Inlet gas today, about $6.52 per million cubic feet, Sniffen said. The deal has an escalator allowing a 4 percent annual increase, he said, and this would likely result in an allowable price of about $7.72 per mcf at the end of five-year period in 2017, he said. “This was a very difficult balancing act for us because we want to protect the local consumers and at the same time give Hilcorp enough of a price incentive to explore for gas,” Sniffen said. The provision prohibiting Hilcorp from selling gas for export as LNG until local utility needs are met also applies to sales to companies “who intend to resell the gas for LNG export,” Sniffen said. This issue may be moot if ConocoPhillips, which owns an LNG plant near Kenai, south of Anchorage, fails to renew the LNG export license for the plant that is due to expire next March. Sniffen said the state has not been informed by ConocoPhillips of any plans to apply for a renewal, but if an application is made it would likely come in January. There is increasing sensitivity to the Cook Inlet gas supply situation because existing fields are declining in production and local utility demand is expected to exceed annual production by the 2014-15 winter, requiring gas to be imported as LNG or compressed natural gas, utility officials told the state regulatory commission in a recent briefing. Several companies are exploring for oil and gas in Cook Inlet but no major discoveries have been made yet. Even if they are it is unlikely they can be put into production in time to meet the projected 2014-15 shortfall.

Schlumberger's history dates back to first oil well in Alaska

Schlumberger, the oilfield service company, is so embedded in the history of the petroleum industry that its proper pronunciation should be on the entry quiz for new oil workers. If it’s pronounced properly (hint: founders Conrad and Marcel Schlumberger were French) the new employee passes the test. If it’s said improperly (hint: like a hamburger) the boss points the way to the door. Schlumberger has been in Alaska since 1956. When Richfield Oil drilled its Swanson River discovery well in 1957 — the well that laid the foundation for Alaska statehood — Schlumberger was there doing the well logging. Fast-forward half-a-century plus five years. A lot has happened in the state, and Schlumberger is still here, logging wells and lot more. If the oil and gas fields are ever depleted, all the prospects explored and the industry is packing up, Schlumberger will still be here, helping abandon old wells. That will never happen, of course, because old oil fields continually reinvent themselves — Schlumberger helps with that, too — and creative and entrepreneurial geologists and engineers always find new ways to squeeze more oil and gas out of rocks. Schlumberger is involved in that, too. What the company does is use technology to help the oil explorers or producers find out where the petroleum is, figure out how much of it there is, and get it out of the ground. Schlumberger started in France in the 1920s but is now an international firm, with 115,000 employees worldwide. Schlumberger works most places in the world where there’s oil and gas being produced or looked for. The total now is 85 countries. In Alaska, the company has at least one of its 17 service and product lines engaged with every major oil producer and every explorer as well, says Schlumberger’s Alaska Manager Lees Rodionov. Services the company provides, which are vital to the industry, include the “logging” or the mapping of subsurface reservoir intervals using special tools, to providing drilling fluids to control the well during the drilling process and cementing the well casing (the steel tubulars of the well) that make the well stable and safe. There’s a wide range of other services including work done before a well is drilled (the analysis of geologic information), the measurements of fluid movement during production, to help the operator produce the well most efficiently, work related to remediation of old wells, and much more. Much of the work is at the leading edge of oil industry technology. For example, Schlumberger helped develop techniques to conduct tests and measurements in the hole while drilling is still under way, a technique called “logging-while-drilling” or LWD. This was a great leap forward for the petroleum industry because it meant logging could be done without having to stop drilling and pull all the drill pipe up out of the hole, a process that takes time and costs money. LWD not only avoids that but allows for immediate changes in the drilling plan with the equipment still in the hole, which guides the drillers with more precision to the desired spot deep underground. Other products and services that Schlumberger provides during the drilling process include bits, various drilling tools and mudlogging. Another technology the company helped pioneer and now operates in Alaska is coiled-tubing services, mobile equipment with huge metal coils that are lowered down wells to do repair work, or even used in drilling. For many types of jobs, using coiled-tubing units is much more economical than using a drill rig. Anything that lowers the costs of drilling and completing wells makes it possible to reach and produce smaller oil pockets that were previously uneconomic. Another technology aimed at accessing bypassed hydrocarbons is Schlumberger’s LIVE Digital Slickline service in which traditional slickline has been coated with a proprietary material and allows for digital two-way communication without being affected by well completions, conditions or fluids. A “slickline” operation involves a thin cable passing through pressure control equipment, allowing work to be done safely on live oil and gas wells. (Editor’s note: Schlumberger maintains a widely-used oilfield glossary on its website, at http://www.glossary.oilfield.slb.com/default.cfm). The company is now at the forefront in developing automated drilling technologies, which allows work to be done with fewer people on the rig. This not only lowers costs, but with less people working around machinery, it improves safety too. Schlumberger now has nine locations in the state including two in Anchorage, four on the North Slope and three on the Kenai Peninsula. There are about 850 Schlumberger employees in Alaska, 75 percent of them are Alaska residents and a lot of them were recruited in the state, Rodionov said. “Our corporate strategy is to recruit where we work. We want to be part of the community,” she said. Schlumberger recruiters pay close attention to the University of Alaska Fairbanks and University of Alaska Anchorage. “We’re a technology company so we focus our recruitment on the engineering and science disciplines, such as petroleum engineering and other geosciences. We’re interested in any graduate with a technical degree, however,” including fields like computer science and math, Rodionov said. Business is growing for Schlumberger in Alaska, and that means the company is hiring, and hiring Alaskans. Two hundred employees have been added to the Alaska workforce in the last two years, Rodionov said. What’s driving the growth is the expanding activity by explorers, many of them small to mid-size independents. Schlumberger invested $30 million in its Alaska operations in 2012, including a new building on the Slope to consolidate drilling support functions, which will completed in 2013. The company plans a $50 million investment next year, focusing on bringing new technology to the state and new facilities in Kenai to support the growth there. “We saw rig activity up 15 percent to 20 percent this year over last, and expect to see similar growth in 2013,” Rodionov said. That’s good news for Schlumberger, because where there are rigs drilling there is demand for the company’s services.

Fairweather bets on growth of Slope work

Fairweather LLC has plans to expand its North Slope support facilities at the Deadhose Airport, adding personnel living quarters and industrial warehouse space to an aviation and medical service center the company opened in August. Despite uncertainties over future North Slope work, Fairweather decided to take the plunge and invest, a gamble that offshore exploration by Shell and onshore drilling by explorers will result in discoveries and new activity, said Lori Davey, Fairweather’s director of marketing. “We have a lot of faith in the industry. If Shell is successful offshore, or ConocoPhillips and Statoil, it could be huge,” Davey said. Deadhorse is well positioned to support work in the Beaufort Sea and east of Prudhoe Bay, where ExxonMobil is developing the Point Thomson field, or to the west where Repsol and Brooks Range Petroleum are exploring and developing new fields. Fairweather isn’t overly concerned about a competitive support base someday being built at Barrow or Wainwright to support the Chukchi Sea. “Deadhorse is 200 miles further east, but what we have going for us is year-around public road access,” via the Dalton Highway, she said. Fairweather is also doing work for Shell and its support contractors on the western North Slope. What the company has built at Deadhorse so far is the Deadhorse Aviation Center, which includes a 20,000-square foot hanger, 11,000 square feet of office space, cargo-handling and transfer, and 24 bedrooms with single baths and facilities for dining and other support, Davey said. The facility is owned by Fairweather LLC, Offshore Support Services, LLC, a subsidiary of Louisiana-based Edison Chouest, and Kaktovik Inupiat Corp., the village corporation for Kaktovik, an Inupiat community on Barter Island east of Prudhoe Bay. “We’re doing very well with the aviation center,” Davey said. “Our hanger is rented out, as are the bedrooms and the office space. We could use more business for the cargo and terminal,” but that will come, she said. A trauma medical clinic in the facility designed to support remote medical emergencies, a service Fairweather specializes in, is also being used. Fairweather doesn’t operate emergency medical evacuation flights but supports aviation companies which do, she said. Medical personnel in the facility are linked to Providence Hospital in Anchorage. Because it is located on the state-owned Deadhorse Airport, property tenants at the Deadhorse Aviation Center must be aviation-related, and while the outlook is for growth in aviation services on the Slope, the critical need is for more general support for contractors and service companies, Davey said. With that need in mind, Fairweather has leased state acreage adjacent to the Deadhorse Aviation Center, but off the state’s airport premises, so that facilities can be built to serve tenants not related to aviation. The first tract leased by Fairweather on the airport property was seven acres, and this support the Deadhorse Aviation Center. The second parcel leased was 10.4 acres just off the airport property, and this is now slated for development for new hotel and warehouse facilities. A third 13-acre parcel leased that has not yet been developed will be a site for a future large aviation hanger big enough to support a C-130 aircraft. Davey said the large hanger project will be built when the demand justifies it. The most critical need now, however, is for bed space, and Fairweather intends to build facilities a step above the basic facilities offered for rent in older camps at Deadhorse, with not just single rooms but attached single bathrooms. Phase one of the expansion will involve facilities with 120 to 140 beds, depending on need, and 4,000 square feet of new office space. Fairweather is meeting with firms who could provide design/build services for these, and Davey hopes that these can be built in 2013 and open in the later part of the year. Phase two could involve additional bedrooms or it could be warehouse space, for which there is also a big need. If built as warehouses, units could be about 2,300 square feet with large doors suitable for drive-thru service. Davey said Fairweather is serving customers, mostly contractors and service firms, who may not be doing work for the major field operators, BP and ConocoPhillips, and who therefore are not able to use facilities built and owned by those companies within the oil fields. The company is also aiming at longer-stay tenants. “We are not in the hotel business. There are other facilities at Deadhorse, such as the Prudhoe Bay Hotel and Aurora Hotel, who offer short-term stay services,” Davey said. For longer-stay customers it’s also important to have higher quality rooms. Professional workers and technicians on longer-term assignments for employers on the North Slope, and who will work out of Deadhorse, will put up with lower quality accommodations for a short period but not for long stays, Davey said. Medevac support is an important part of the function of the aviation center. The clinic there allows for patients to be transported into a heated ambulance bay, treated in a trauma room and loaded into a medevac aircraft without leaving the building. The clinic also has 24-hour telemedicine consultation with Providence Hospital, which allows for X-rays, EKGs and lab specimens to be digitized and sent to Providence via the internet before decisions are needed to medevac or do local treatment. The medical clinics maintained by BP and ConocoPhillips at Prudhoe Bay and Kuparuk are similar, but Fairweather’s clinic is available for injured workers or others not affiliated with the operations of those companies. With more companies working on the slope, including explorers like Repsol, Brooks Range Petroleum and others, having these kinds of services available to the public is increasingly important, Davey said.

Enstar faces second winter shortage as supplies tighten

Colleen Starring, president of Enstar Natural Gas Co., is on the spot this winter. Her utility supplies natural gas to virtually all commercial buildings and most homes across Southcentral Alaska. Starring’s problem is ensuring there’s enough gas to supply her customers. Enstar is short 4.2 billion cubic feet of about 33 billion cubic feet it needs to keep the heat on. This is the second year Enstar has faced a deficit in gas supplies at the start of winter, but last year the gap was only about a billion cubic feet and most of that was made up through a short-term auction system the utility set up for producers to sell small quantities of surplus gas they may have. The 4.2 billion cubic foot gap this year, however, is too big to make up through the auction system. Things may yet work out. A Consent Decree just negotiated by the state with Hilcorp Energy on its pending acquisition of Marathon Oil Co.’s Cook Inlet assets could clear the way toward sales of more gas from the Marathon fields to the region’s utilities. Alternatively, if ConocoPhillips decides not to ship more cargos of liquefied natural gas from its Kenai LNG plant in 2013, and decides not to renew an export license for the plant that expires next March, the company could make more gas available. Hilcorp and ConocoPhillips are already major gas suppliers to the region’s utilities. However, at the root of the problem is declining production from gas fields Southcentral Alaska. For example, the Beluga gas field, long a main supplier of gas to the utilities, is declining at rates of 17 percent to 19 percent per year, said Jim Posey, general manager of Anchorage’s city-owned Municipal Light and Power. ML&P owns one third of the Beluga field. By 2014 or 2015, production from fields in the region will fall below annual demand, requiring that gas be imported either as LNG or compressed natural gas. Explorers are busy in the area but it’s considered unlikely that enough new gas can be found and put into production quick enough, said Tom Walsh, managing partner of Petrotechnical Resources of Alaska, or PRA, a consulting firm hired by the utilities to study the gas situation. On the positive side, there’s a new gas storage facility operating on the Kenai Peninsula that now has gas in storage for peak cold weather demand this winter. The first withdrawals of gas from the Cook Inlet Natural Gas Storage Alaska project have already been made, Enstar spokesman John Sims said. Beluga budget dispute But another twist for now, however, is a disagreement among the Beluga field owners about funding a $50 million budget for servicing and other work on producing wells in the field. ConocoPhillips, Hilcorp and ML&P each own one-third of the Beluga field with ConocoPhillips as the field operator. Posey, of ML&P, said Hilcorp has declined to fund its full one-third share of the budget. Hilcorp spokeswoman Lori Nelson confirmed this. “We certainly recognize the need for enhanced production. Hilcorp did reject the $50 million proposed budget,” Nelson said. “We have a long and successful record with this kind of work and believe it can be done for a smaller price tag.” Posey doesn’t buy that. “When they decide to pull in their horns (on spending) it means less gas supply,” he said. He said he’ll take up the matter with his boss, Anchorage Mayor Dan Sullivan, and the issue may also be appealed to Houston, where Hilcorp and ConocoPhillips are headquartered, Posey said. Walsh, of PRA, is fairly pessimistic, however. In terms of the supply gaps, Walsh told the Regulatory Commission of Alaska in an Oct. 24 briefing that, “we don’t believe there is a lot of uncontracted gas (reserves) out there. There’s just not enough drilling. There’s not enough new gas coming into the system,” Cook Inlet producers’ own information on the extent of their reserves is the best data there is, and while some of this must be shared with the state Division of Oil and Gas, state officials are required to keep it confidential. Information, supply gaps remain The lack of having this information available to the utilities, and the public, is a sore point with Chugach Electric CEO Brad Evans, who has pushed unsuccessfully for the state to do a regional Cook Inlet resource plan putting all information into one place. Walsh said the companies will drill to meet contract commitments, and the fact that there are large gaps in contracted supplies for 2013 and the years following probably means the companies don’t believe there is a lot of untapped gas, or that gas that is there can be profitably produced at least at present prices. PRA has estimated that the number of new production wells being drilled would have to double for new reserve additions to make up for the annual depletion of the fields, and the increased drilling isn’t happening. Also, some of the new wells being drilled are not successful. Of three production wells drilled in the Beluga field in 2012 one is not producing as expected. There is a great deal of exploration planned for Cook Inlet, and although most of it is aimed at oil, some gas will inevitably be found too. “It’s great to see this, and it’s all due to the state exploration incentives,” Walsh said. “There has been virtually no exploration in Cook Inlet in 40 to 50 years.” But few, if any, of the explorers will be able to develop their discoveries in time to meet the utilities’ shortfall. “Their timeline will not resolve this issue,” he said. As for the needed work in the existing fields, Walsh said, “we are not seeing the kind of activity we need, and based on recent history we don’t expect it to occur.” Bob Pickett, one of the commissioners of the state regulatory commission, thinks the situation is precarious. “We’re in a conundrum. We’ve moving out of an era with the ‘legacy’ (older) fields where there was a lot of gas and prices were low. Today Cook Inlet has the nation’s highest gas prices. Now, with discussions of gas imports, we could see those prices double,” Pickett said. The possibilities of mechanical and geologic failures must also be considered, Walsh said. Mechanical failures could include the malfunctioning of gas field compressors, as has happened, which would impair the flow of gas to utilities — not good if it happens during cold weather — or there could be geologic failure, such as disappointments in drilling or encroachment of water into the gas producing wells. Enstar’s Starring said her gas utility can’t switch fuels, unlike the electric utilities who can do it to some extent. Enstar’s customers also can’t conserve on heating enough to make a significant difference. “There are only so many sweaters you can put on,” she said. “Our only option is to go to curtailment (of supply). We have a curtailment plan and we are awaiting an opportunity to present this,” to the regulatory commission. Starring said a new system Enstar initiated to allow producers to bid small quantities of gas they may have to meet Enstar’s short-term peak requirements worked well last winter. Enstar spokesman John Sims said the amounts of gas bid under this system for 2012 were about 700 million cubic feet. While this mechanism works well to meet short-term needs during periods of peak demand it will not supply large volumes of gas. “The gas simply isn’t available,” Sims said. Alternative power Chugach Electric Association is in better shape than Enstar in that it has other alternatives than natural gas, such as hydro for a long-term base, wind power as a supplement and, in an emergency, bringing power down from Fairbanks over the Intertie. Chugach now uses about 25 billion cubic feet per year of gas, and after Homer Electric Association and Matanuska Electric Association stop buying wholesale power from Chugach, the utility’s annual need for gas will drop to about 9.5 billion cubic feet per year, Lee Thibert, Chugach’s senior vice president for planning, told the regulatory commission. More efficient gas turbines and “combined cycle” (using waste heat) facilities at the new Southcentral Power Plant now under construction in south Anchorage will result in an expected savings of 3 billion cubic feet of gas yearly. Wind power will help, too. The new Fire Island wind project will allow Chugach to reduce its annual gas need to just under one-half a billion cubic feet. Additional hydro power in the regional grid is also important. Hydro power from Bradley Lake near Homer is now the least expensive source of power along the Railbelt and additions to its capacity are planned. Consumer conservation is already playing a role: Consumers are using new, more efficient appliances and lighting systems and the savings in electrical use have translated to an estimated 700,000 thousand cubic feet, or mcf, of gas saved over the last 10 years, a trend which is expected to continue. Despite these developments, Chugach faces its own gas supply shortfall of about 3 billion cubic feet in 2015 and 6 billion cubic feet in 2016, Thibert told the RCA. Matanuska Electric Association will be generating its own electricity in 2015 at a new power plant being built at Eklutna, north of Anchorage, MEA’s general manager, Joe Griffith, told the regulatory commission. The project is under construction now and is ahead of schedule and under budget so far, Griffth said. The plant is to be in operation in January 2015. MEA has yet to contract for a long-term supply of gas, however, although talks are under way with producers, Griffith said. The plant will need about 5 to 6 billion cubic feet of gas per year when when operating, he said. Anchorage’s city-owned Municipal Light and Power has agreed to make gas available initially to test the Wartsila engines in the plant, but this supply is only temporary, Griffith said. However, the Wartsila engines do have dual-fuel capabilities, so MEA could also generate power with diesel if need be, Griffith said. The engines can make the transition seamlessly, he said. A four-day supply of diesel will be kept on site, and additional fuel can be efficiently brought in by rail if needed. MEA is also investigating the possibility that a propane-air mixture can also be used as fuel, giving the co-op another option for a backup, Griffith said. Some improvements in the region’s pipeline network are also needed to move more natural gas efficiently to the northern end of the system, Griffith told the RCA. The conversion of two cross-Cook Inlet pipelines, the Cook Inlet Gas Gathering System, or CIGGS, to a two-way flow instead of one-way will ease this, but it may not be the total answer, Griffith said. Griffith said any discovery of new gas will take time to bring into production. Griffith said his concern is for the next two to three years. “Getting through the next two to three years will require us to do something heroic,” he told the commission. Anchorage’s Municipal Light and Power now relies mainly on its one-third share of gas production from the Beluga field for its supply of gas, although ML&P also shares in hydro power as do other regional electric utilities. However, gas production from Beluga is declining and by 2015 ML&P will need to purchase gas from other sources, its general manager, Jim Posey, told the regulatory commission. ML&P will need about 3.6 billion cubic feet in 2015 and about 5 billion cubic feet in 2016, Posey said. After 2016 its requirement for new gas may decrease because of the efficiency of the new power plant being built with Chugach Electric, and other improvements in the ML&P system. Posey said there can be some benefits from energy conservation but there are limits to this for many ML&P customers, who are mainly owners of large commercial buildings in the downtown core of Anchorage. Still, Posey said ML&P has seen 40 percent reductions of electricity use by homeowners through conservation, and he singled out one large Anchorage building, the Performing Arts Center, which achieved a 20 percent reduction several years ago after a series of efficiency measures.


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