Tim Bradner

Shell restarts work in Chukchi; Apache takes delivery of rig

Shell has resumed work at the Burger-A exploration well in Chukchi Sea off Alaska’s northwest coast. The drillship Noble Discoverer was brought back to the well location the weekend of Sept. 22 and 23 after waiting almost a week for a massive, slow-moving ice floe to move over the site, Shell spokesman Curtis Smith said. Work had started on a bottom excavation for a blowout preventer Sept 16 but after less than a day the ship had to be moved away because of the ice floe moving toward it. Meanwhile, another drill vessel, the Kulluk, “is still on standby” Sept. 25 in the eastern Alaska Beaufort Sea. Shell had agreed to hold off on drilling in the Beaufort until local Inupiat Eskimo whalers had completed their fall whale hunt. Shell said earlier that the Kulluk may be moved near the well location. The company has permission from the U.S. Interior Department to do preparation work on the top of the wells including setting the blowout preventer and drilling and installing casing to about 1,400 feet. However, the company does not yet have permission to drill deeper to hydrocarbon-bearing zones at about 7,500 feet to 8,000 total depth. The company gave up hopes for drilling completed wells to the oil-bearing zones after equipment on an oil spill response barge needed to be at the site was damaged in a test in Puget Sound, in the Pacific Northwest. The damage could not be repaired in time to get the barge to the Arctic. Under Interior Department rules Shell cannot drill all the way down to the target depth of the wells until the response barge is on the scene. That will now be next year. However, the completion of “top hole” work on the exploration wells will give the company a jump-start in completing the wells in 2013, Shell officials have said. Apache takes delivery of drill rig for Cook Inlet exploration Apache Corp. has taken delivery of drilling rig brought to Alaska by truck from North Dakota and plans to begin drilling the company’s first Cook Inlet exploration well in the fourth quarter of 2012. The well, an onshore test, will be on the west side of the Inlet near Tyonek, a small Alaska Native village, Apache’s general manager, John Hendrix, told an oil and gas conference in Anchorage. “We are targeting oil, but we believe we will find natural gas as well,” Hendrix said at the Alaska Oil and Gas Congress meeting held Sept. 17 through Sept. 20. The rig brought north is the Patterson-UTI rig, which was previously working in the Bakken oil shale development, Hendrix said. Apache has largely concluded a multi-year 300-square-mile 3D survey across the Cook Inlet Basin that began in 2011. The marine segment across the Inlet is now being completed along with remaining parts of the survey on the Kenai Peninsula, on the Inlet’s east side. Analyses of the seismic data under way now will result in additional well targets identified by the end of the year, Hendrix said. Cook Inlet has seen a renaissance of exploration in recent years with Hilcorp Energy purchasing producing asset from Chevron Corp. last year and new offshore exploration planned by independents Buccaneer Energy; Furie Operating Alaska; Cook Inlet Energy and NordAq Energy.

Repsol's drilling a bright spot of winter Slope exploration

Repsol E&P USA plans three new Alaska North Slope exploration wells this winter, the company said in an interview Sept. 21. North Slope exploration drilling in expected to be down this winter compared with last year, but Repsol’s continued drilling is a bright spot for the industry. One well planned is Repsol’s “Q-6” test,” is a renewed effort to test a prospect on the Colville River delta being drilled last year in the company’s “Q-2” well when drillers encountered a shallow gas deposit, resulting in a gas release and a well control incident, said Bill Hardham, Repsol’s Alaska manager. There were no injuries or major damage to the rig by the gas kick, and the gas was diverted from the rig, but work on the well was suspended. The location is on the Colville River delta northeast of the producing Alpine field. A second test planned this winter is “Q-1”, located a few miles east of Q-6 and also on the Colville delta. A third test, “Q-3” is further inland near the Colville River but south of the Alpine field. Repsol had planned to drill five wells last year but scaled down the plan to four wells and then drilled only two after the gas release incident at Q-2. The wells completed last were “Q-4,” a shallow water offshore location northwest of the Colville Delta, and “K-1”, an onshore well at an inland location southwest of the Kuparuk River field. “We found some interesting opportunities in the two wells we did complete. We are still evaluating the results,” Hardham said. “We’re not ready to go to development with anything yet, and we may need to do more seismic and possibly more delineation drilling.” The goal this winter is mainly to complete an evaluation of Repsol’s North Slope acreage that was started last year, Hardham said. Last year was a real learning experience for Repsol. The company was pleased with the support it got from contractors and their workers — at one point Repsol’s drilling employed more than 500 people — and drilling costs were generally in line with what was expected. North Slope exploration wells in remote areas that need ice roads cost about $40 million each, Hardham said. One surprise was the intense cold weather, which caused some operational delays. It was an unusually cold winter. “We had been expecting and planning for periodic whiteouts, but the duration and intensity of the cold surprised us,” he said. During one visit to the slope Hardham encountered minus 59 degrees Fahrenheit. Minus 35 degrees Fahrenheit is considered the normal operational limit for equipment. The cold delayed some rig moves for Repsol, and caused problems for some equipment. Repsol has a large North Slope land position with about 500,000 acres under lease and multiple prospects. “We have a multi-year exploration plan. We see a lot of opportunities,” Hardham said. The company is in a partnership with Armstrong Oil and Gas Co. and GMT Exploration Co., both Denver-based independents, with Repsol holding a 70 percent interest in the acreage. A cautionary note, however, is Repsol’s concern over the state’s high oil production tax, Hardham said. Repsol had made its deal with Armstrong and GMT in anticipation that the tax would adjusted, he said. Repsol wanted to get out in front of a surge in North Slope exploration and development that it believed would occur if the tax were lowered. “It looked like the production tax was headed for reform. This was a key part of our decision to invest,” Hardham said. “The opportunities we are chasing are fairly moderate, and they will need help on the economics. We may be able to develop some of them without the tax being changed, but not to the degree we would like to.” Hardham said the state tax law does have good exploration tax credits for explorers on the front end of the project. “We’re taking advantage of those, but ultimately we’ve got to produce anything we find,” he said. Repsol hopes the tax can be adjusted, and the company is still bullish. Hardham himself is now in the state full time. Until six weeks ago he basically commuted from Repsol’s Houston offices. In January, the company will also move out of temporary offices in downtown Anchorage to larger space in Anchorage’s mid-town, in the JL Towers. Two other companies new to Alaska, Hilcorp and Statoil, are also in that building.

BP signs deal to supply natural gas to Fairbanks utility

North Slope producer BP Exploration Alaska Inc. signed an agreement to supply as much as 23 billion cubic feet per year to Golden Valley Electric Association of Fairbanks for 20 years, Cory Borgeson, the utility’s president and CEO, said Sept. 19. Golden Valley is the electric utility serving Interior Alaska. The utility is working on a deal to build a natural gas liquefaction plant on the North Slope and truck LNG to Fairbanks for use in power generation. Golden Valley would also sell gas surplus to its needs to other potential buyers including Flint Hills Resources, operator of a crude oil refinery near Fairbanks, and Fairbanks Natural Gas, operator of a small gas utility in the Interior city. Fairbanks Natural Gas now trucks LNG from a small LNG plant in the Matanuska-Susitna Borough north of Anchorage, which liquefies gas purchased from Cook Inlet producers. Golden Valley is seeking state financial help in developing the LNG plant on the North Slope. Borgeson said the price terms of the contract with BP are confidential, however. The utility now generates most of its power using fuel oil and naptha, which are made from crude oil at the Flint Hills refinery and are very expensive. Having acess to less costly gas for power generation would help Golden Valley lower electrical generation costs. Similarly, Flint Hills uses oil to heat crude oil and provide power at its refinery. Gas would lower its operating costs, the company has said in previous statements. “In addition to satisfying our own electrical generation needs, we at GVEA recognized the opportunity and our responsibiity to address the energy crisis facing Interior Alaska’s residents and businesses, in particular the high cost of space heating,” Borgeson said in a statement.

Parnell and Sullivan promote Alaska LNG in Asia

Gov. Sean Parnell and state Natural Resources Commissioner Dan Sullivan have been in Japan and Korea in the last two weeks, drumming up interest in a large Alaska liquefied natural gas project. North Slope producers and TransCanada Corp., a gas pipeline company, are due to submit a progress report to Parnell Sept. 30 on their work on a gas pipeline and LNG project. In a related development, a spokesman for TransCanada says the company, which has teamed up with the North Slope producers on LNG, is “encouraged” by the results from its recent solicitation of interest. Under terms of a state contract, TransCanada recently solicited market interest in a gas project although expressions of interest were nonbinding. TransCanada cannot reveal the identity of firms that expressed interest, however. Parnell was in Japan conducting an economic trade mission with energy officials in Japan and Korea with a focus on promoting Alaska’s gas in Pacific Rim markets. “We look forward to capitalizing on the enormous potential that exists for Alaska’s North Slope natural gas in our state and in Pacific Rim nations,” Parnell said in a statement issued in Asia. “This is a great opportunity to strengthen existing relationships and build new ones that will grow economic opportunity with Japan and South Korea.” Parnell met with the CEO of Korea Gas Corp., or KOGAS, to discuss Alaska’s longtime role as a reliable exporter of LNG to Asia from Kenai, and the state’s plan boost those exports with a major Alaska gas pipeline to tidewater. Separately, the Korea Chamber of Commerce and Industry arranged for meetings between Parnell and executives from several Korean companies including Samsung C&T, STX Energy, Daesung Industrial Co., Ltd., Korea Midland Power Co., GS Global Co., LG International Corp., Hyundai Heavy Industries, and Korea Kumho Petrochemical Co., Ltd. Parnell said there was significant progress being made on an all-Alaska gas pipeline to tidewater and the investment potential for these companies in Alaska. In his visit to Korea prior to Parnell’s arrival, Sullivan met with senior government officials as well as executives with KOGAS and Korean National Gas Corp, or KNOC. Sullivan had also been invited to speak Sept. 19 at the LNG Producer-Consumer Conference, one of the world’s major LNG conferences, and separately at a special briefing Sullivan gave organized by the U.S. Embassy in Tokyo. Six hundred people had been registered to attend the Producer-Consumer Conferenc but Sullivan said the actual count was closer to 1,000. The Asia LNG managers for BP and ExxonMobil, two major North Slope producers, were at the LNG conference along with government officials and companies promoting competing LNG projects, which gave Sullivan a chance to listen to competitors’ pitches. About 70 invited industry and government officials attended the separate embassy briefing by Sullivan, which lasted for three hours. Sullivan said his private, individual meetings with officials and industry executives were basically to lay the groundwork for Parnell, who followed him. “He was there to meet with the ministers and CEOs,” Sullivan said, after the commissioner’s sessions with lower-level officials and managers. Sullivan said he hit strongly on Alaska’s 40-plus years of reliability in serving Asian customers with LNG shipments from Kenai, and said he wasn’t shy about contrasting that with the spotty record of competitors like Russia, which has used gas supply as a political lever. “I was pretty blunt. They have a crummy reputation for reliability. If they don’t like you, they cut you off,” Sullivan said. Similarly, there was a buzz at the LNG conference about projects at Kitimat, B.C., but Sullivan had the chance to point out that the development of shale gas on which the projects depended has yet to happen on a major scale and that First Nations issues affecting the pipelines needed for the plants have yet to be resolved. Alaska’s advantage is that the gas resource is known and secure. “There is zero resource risk. The infrastructure for production is in place. There is political stability. There’s no other place that offers those things except northern Alaska,” Sullivan said. In terms of TransCanada’s solicitation of interest, company spokesman Shawn Howard said there was interest from potential shippers and “major players from a broad range of industry sectors and geographic locations,” including North America and Asia. He declined to name them, citing confidentiality. He wouldn’t say if preference was shown for a project that serve North America markets or for one that would allow for liquefied natural gas exports overseas. The non-binding solicitation ended Sept. 14. The expressions of interest are just that: not firm commitments to any one project. Howard says TransCanada continues to work with the North Slope’s major players to evaluate options for bringing Alaska gas to market. In 2010 TransCanada and ExxonMobil, its partner, conducted an open season for an earlier plan to build an all-land pipeline to Alberta, for delivering Alaska gas ultimately to Lower 48 markets. The development of inexpensive shale gas had disrupted that plan, however, and attention has now turned to a pipeline to southern Alaska and an LNG terminal at a south Alaska port.

Parnell withdraws state cooperation in NPR-A land planning

Alaska Gov. Sean Parnell has withdrawn the state as a “cooperating agency” with the U.S. Bureau of Land Management on National Petroleum Reserve-Alaska issues. The governor also asked Interior Secretary Ken Salazar to redo the department’s long-range land management plan for the NPR-A. Parnell is unhappy that Interior has classified about half of the 23-million-acre petroleum reserve off-limits to drilling without giving prior notice to the state or any other cooperating agency. Sharon Leighow, the governor’s press secretary, said withdrawing the state as a cooperating agency is largely a symbolic move. “It’s more of a statement. It won’t stop the process of adopting the management plan. It’s our way of saying that despite our best efforts we’re being ignored. We still plan to file protests when the final plan is adopted,” Leighow said. BLM officials agreed. “Being a cooperating agency allows the state to be at the table, but consensus isn’t required among cooperating agencies and as lead agency we wind up making the final decision,” said Serena Sweet, BLM’s planning supervisor for NPR-A. In a Sept. 12 statement, Parnell said, “”Your recent surprise announcement of a preferred alternative effectively withdrawing millions of acres in NPR-A (an area designated by Congress for oil and gas development to meet the energy needs of the nation), and the complete failure of the Department of the Interior to take into account the State’s comments as a cooperating agency, shows a complete lack of respect for the views of the State.” Parnell said the state had provided comments supporting full development of oil and gas resources in the NPR-A with reasonable mitigation measures. The State’s recommendations were not included in the selected alternative. Parnell called Interior’s action a “stealth” approach because it prevented the state or other cooperating agencies from, “suggesting and discussing other alternatives as a preferred alternative or ways to mitigate impacts in areas set aside from development,” Parnell said in a letter to Salazar sent Sept. 12. President Barack Obama and Secretary Salazar have made expanding responsible oil and gas production here at home a clear priority. Oil production is higher right now than any time in 8 years and natural gas production at its highest level ever. However, the growth has been on private lands while federal permits are down. BLM officials defended Salazar’s action in a Sept. 14 statement. “The preferred alternative for the NPR-A was developed by the Secretary after analyzing more than 400,000 comments from the public,” agency spokeswoman Ruth McCord said. “The selected alternative would make 72 percent of the projected oil resources in the NPR-A available while also making sure that Alaska’s globally significant wildlife populations and the subsistence rights of Alaska Natives are protected. This is textbook smart development and this kind of balancing is required by law. “Further, nearly 12 million acres of land are made available through the plan. The preferred alternative also makes certain that pipelines carrying oil and gas from operations in the Chukchi and Beaufort Seas will be allowable through a broad swath of public land, including two areas identified for special management.” The preferred alternative is one of several considered in Interior in development of a long-range comprehensive land management plan for the reserve. Several alternatives were spelled out in the draft management plan and also a draft environmental impact statement that is also being done. Interior had not picked a preferred alternative in the drafts but recently announced a new plan, the “B-2 alternative” that combined elements in the plans that were published. BLM officials in Alaska said a key feature of the preferred alternative is that it would permit access and facilities to conservation lands as long as the uses were not inconsistent with the purpose of the conservation designation. State and industry leaders are concerned about large sections of coastline in northern and northwest parts of the reserve placed in proposed conservation areas as well as the Colville River along the eastern boundary of NPR-A.

Shell gives up completing wells

Shell has given up drilling to hydrocarbon depths on its Chukchi Sea and Beaufort Sea exploration wells this year following damage to an undersea spill containment dome during tests in Puget Sound. The damage cannot be repaired in time for the spill response barge, the Arctic Challenger, to reach the Arctic, Shell spokesman Curtis Smith said. Under rules agreed to by Shell in its spill response plan, the barge, with an undersea blowout containment system, must be in the Arctic and near the exploration wells when Shell drills down to depths where oil and gas might be encountered. The company has permission, however, to do preparatory work on the upper portion of the wells, the “top hole,” with its drillship Noble Discoverer, and this might be done on several wells to give Shell a jump-start on 2013 drilling. The U.S. Interior Department has given Shell a drilling permit for its first Chukchi Sea well, Burger-A, to do the top-hole work, and applications are pending to do similar top-hole work on other wells including the first well in the eastern Alaska Beaufort Sea. A second Shell drill vessel, the Kulluk, is in the Beaufort Sea awaiting the end of the annual fall subsistence whale hunt by local Inupiat Eskimos. Shell had agreed to hold the Kulluk away from the drill location until the whale hunt was finished. Meanwhile, the company began moving its drillship Noble Discoverer back to the Burger-A well location in the Alaskan Beaufort Sea Sept. 19 after the passage of a massive ice floe over the prospect, Smith said. The ship must be re-anchored at the site, Smith said. “It will probably be 36 to 48 hours before we can resume work on the well,” he said. Shell has received approval to do “top hole” work on the well and started preparations at the site Sept. 9, but had to pull off the well less than 24 hours later when the ice moved toward the location. The floe was large, about 30 miles long by 11 miles wide, and moved slowly. It took several days to move over the Burger well location, Smith said. Shell has permission to excavate a well cellar and install a blowout preventer and set casing to the 1,400-foot level. However, under Interior Department rules the company cannot drill deeper to possible hydrocarbon-bearing zones until it has a specialized spill response barge on the scene. Despite the setback with the spill barge, preparation work on the exploration wells will help Shell’s effort in 2013. About two-thirds of the time needed to complete the wells is in the “top end” work, the blowout preventer installation and installation of surface casing and casing to the 1,400 depth, Shell vice president Pete Slaiby has said in a previous briefing. One that work is done, it would typically take 7 to 10 more days to drill down about 6,000 feet to reach the potential hydrocarbon zones. Shell has invested more than $4.5 billion in its Arctic effort since 2005, when the company returned to Alaska and bid in an Alaska Beaufort Sea Outer Continental Shelf lease sale. In 2007, Shell mounted a major effort to explore in the Beaufort Sea but was stopped by lawsuits filed by environmental groups and the North Slope Borough, which was concerned about drilling in the area used by bowhead whales in their fall migration. In 2008, Shell acquired its Chukchi Sea leases in another OCS lease sale and began planning for exploration drilling there. In 2010, the company’s plans were set back again when the Gulf of Mexico blowout caused the Interior Department to suspend OCS exploration drilling until drilling rules were revamped. Revisions were completed in 2011, and Shell’s plans were approved by federal regulators for the 2012 program. However, a late summer breakup of ice in the Arctic caused further delays. The mechanical mishap with the spill containment dome is the latest setback.

EPA fuel regs will raise cruise costs 70 percent by 2015

Another major headache is confronting cruise companies operating to Alaska. New U.S. Environmental Protection Agency offshore emissions rules for ocean vessels in U.S. coastal areas effective that went into effect Aug. 1 have raised fuel costs by about 40 percent for cruise ships operating to Alaska. A further tightening of emission limits effective in 2015 will raise that to almost 70 percent over previous costs. To absorb that cost, the per passenger price of a typical seven-day cruise would have to go up $126. Cruise operators say they can bear the 40 percent fuel cost hike but not the 70 percent increase, and that major changes in cruise schedules and ports of call are likely in 2015 if some agreement can’t be worked out with EPA to mitigate the effects. The State of Alaska sued to stop the new fuel rules in July. Cruise companies like Holland America Lines typically work out their ship deployment schedules as far as 18 months in advance. If changes are made they could show up in the 2014 summer season and surely in 2015. The 2015 rule change, “would harm us significantly,” said Stein Kruse, president and CEO of Holland America Line. “We don’t see a way to pass that (higher) cost on to our customers, and we would have to take steps to mitigate the increase which will affect our deployments,” of cruise ships, Kruse said. Tom Dow, Holland America Line’s government affairs manager, said the current 1 percent sulfur rule in effect since August has increased fuel costs by about 40 percent, adding $220,000 to the fuel cost for a typical 7-day cruise voyage to Alaska. The estimate for the more stringent 0.1 percent sulfur rule effective in 2015 is for the fuel cost to increase to $380,000 over previous costs for a seven-day trip, or about 69 percent over previous costs, Dow said. Kruse said Holland America Line charges a variety of prices for their Alaska voyages, including discounted fares, but a typical cost for a 7-day cruise is about $1,000. The current fuel cost increase, at the 1 percent sulfur rule, could add $73 to that in 2013 and 2014, but the 0.1 percent sulfur rule would add $126 the per-passenger cost in 2015. Dow said the estimates assume current crude oil prices. The cost of the emissions rules are greater than were those of a state of Alaska cruise passenger tax imposed in 2006, but then reduced in 2010. The original state passenger “head tax” was $50 per passenger which, when additional port passenger taxes were added, worked out to a tax of about $65 per passenger. That caused several cruise lines to redeploy vessels away from Alaska. The state later reduced the tax to where it is now about $35 per passenger including the port taxes. This level is bearable, Kruse said, particularly because the revenues go to support local capital improvements that aid cruise ships and passengers. Kruse said his company is continuing to work with the EPA on some compromise that would mitigate the cost impacts on the cruise lines and still meet EPA’s goals of cleaner air in coastal areas. “We support the intent of the rules. Requirements to burn cleaner fuels where it matters is fine with us, for example going to zero emissions in ports,” Kruse said. “But a hundred miles out to sea, why burn high quality fuels when there’s very little benefit?” Cruise lines have some options. The ships typically have fuel-switching capabilities and can switch to clean-burning fuels when near populated areas, and could link to local power sources when in ports, allowing engines to be shut off. EPA officials were not available to comment on the status of negotiations with the cruise companies. A key objection by ocean shippers is that EPA’s Emissions Control Area extends 200 miles out to sea off both the U.S. east and west coasts. Kruse said he sees the merit of a 200-mile zone off a heavily populated area like Los Angeles but not off the coasts of Canada and southeast Alaska, which are lightly populated, and particularly when there are east winds blowing emissions to the west, further out to sea. Vessels operating to and from Alaska, which include cruise ships and cargo ships on regular voyages to the state, are affected heavily because their entire voyage from the Pacific Northwest to Alaska is within the 200-mile regulated zone. Canada has adopted similar 200-mile emissions control areas off its west and east coasts, although Canada’s rule is not effective until later this year. Fuel costs weigh heavily on cruise lines operating to Alaska because of the length of voyages from Seattle and Vancouver, B.C., where most ships depart, up the Inside Passage of southeast Alaska and across the Gulf of Alaska to Southcentral Alaska ports. Atlantic cruises to eastern Canada are also entirely within the emissions control zones of both countries and are similarly affected, Dow said. However, cruises to Mexico and the Caribbean are less affected because the ships are within the U.S. emissions control area for only a short distance, and can then switch fuels. Also, cargo vessels serving U.S. coastal ports from foreign ports are less affected because they can switch to the low-sulfur fuels only when they pass the 200-mile limit off the U.S. coast. EPA is negotiating with shipping companies on exemptions to the rule. A recent agreement with Totem Ocean Trailer Express, or TOTE, a cargo carrier operating ships to and from Alaska, will have the company convert to liquefied natural gas to meet emissions goals. That works for TOTE because its vessels operate exclusively to Alaska but this would not work well for cruise lines, industry sources said, because the companies operate their ships in Alaska only during the summer and move vessels to the Caribbean, the Mediterranean and other warmer destinations in winter. Kruse said Alaska is an important market for cruise companies. Holland America Line has seven ships operating in Alaska waters this summer, and its sister company, Princess Cruises, also has seven ships in the state. Both are owned by Carnival Cruise Lines. Holland America Line and Princess have 14 vessels in Alaska between them. "This represents 14 percent of Carnival’s ships,” Kruse said.  

Port of Anchorage plan to be ready by spring

A U.S. Army Corps of Engineers assessment of the Port of Anchorage expansion project is due in late October and port officials aim to have a revamped plan ready by next spring, port manager Rich Wilson says. In November, voters will be asked to approve $50 million for the Port of Anchorage as part of a statewide, $453.5 million general obligation bond proposition to fund transportation projects. “By next spring our team is anticipating presenting a plan for building port facilities that meet updated business requirements,” Wilson said. Wilson took over as manager at the Port of Anchorage on May 14, following the retirement of long-time port director and former Gov. Bill Sheffield. He was previously business development manager at Ted Stevens Anchorage International Airport and was city administrator at St. George, in the Pribilof Islands. What’s first on Wilson’s agenda for the port, beyond ensuring smooth operations, is to develop a long-range business plan on which to base the expansion. He hopes to have a contractor on board by October to develop the business plan, the first part of a port master plan. The effort is now on restoring confidence in the port expansion, he said. The facility handles about 4 million tons of freight annually, including about 80 percent of food and other supplies for Southcentral and Interior Alaska. “We were dealt a blow by the challenges that hit the expansion plan for which the port got tagged,” somewhat unfairly because a federal agency, the U.S. Maritime Administration, or MARAD, was actually in charge of the project, Wilson said. MARAD had not previously managed major construction. Cost overruns partly caused by new environmental requirements as well as damage to open cell sheet piles during the previous construction have plagued the project. The pricetag on the full expansion was headed toward $1 billion. Last year, Anchorage Mayor Dan Sullivan asked for a more affordable, scaled-back project and also changed the management structure so that the Municipality of Anchorage will run the project. Previously the city, which owns the port, had a minor role in construction decisions. “We’re working now to rebuild confidence by engaging people and validating the business requirements,” Wilson said. Wilson said the new construction plan will focus on repairing the previous damage to the sheet piles and finishing phase one of the expansion, which are the two barge docks at the port’s north end. Maintenance work will meanwhile continue on the existing, aged steel piles that support the current dock. Some of those are more than 50 years old. There’s no doubt, however, that the existing dock will eventually have to be replaced and that some form of the original expansion, which will replace the old dock, is needed. Corrosion is taking its toll on the old steel pilings. These are being strengthened with steel “sleeves” installed around the corroded piling, but the cost of the maintenance is running around $1 million a year or more. Even if the dock is maintained it is becoming difficult for the facility to handle the weight of some industrial cargoes being unloaded, Wilson said. For example, heavy new turbines needed for Matanuska Electric Association’s power plant now under construction at Eklutna will stretch the weight-bearing capability of the dock to the limit when they are unloaded, he said. Also, the dock won’t support the weight of new cranes that Horizon Lines, a major customer, would like to install to be able to unload larger ships that will be coming on line. The port’s existing cranes can reach out 35 feet to lift containers off decks of vessels moored the dock, Wilson said, but the new cranes would be able to reach out 100 feet. The dock can’t handle the weight, however. More important is that a new, stronger dock is needed in case there is another major earthquake. The existing dock may not survive that, which could shut down a port that handles 80 percent of the food and other supplies for Southcentral and Interior Alaska. Meanwhile, the work that has already been done on the expansion has brought the port new business. So far 63 acres of new, usable port land has been added at the site of the new barge docks. There are customers for the new space, mainly builders of Cook Inlet Region Inc.’s new wind project on Fire Island and Golden Valley Electric Assoc.’s wind project at Eva Creek, near Healy. “These are short-term leases, but we were able to make $30,000 to $40,000 per month in lease and dockage revenues,” Wilson said. Most of the port’s business has been stable, but one other new prospect is a plan by Delta Western to build a new bulk fuel storage facility as a “hub” for its fuel service to western Alaska villages, Wilson said. Tesoro Corp. and Flint Hills Resources, which operate refineries, as well as Crowley, a major fuel distributor, currently operate fuel storage facilities at the port. Petroleum loading and unloading, and storage is a major business for the port. A new initiative, Wilson said, is to lease 100 acres adjacent to port property that is owned by Joint Base Elmendorf Richardson. The land will serve as additional space for “laydown” for materials or equipment storage. Wilson said he hopes to finalize the agreement for the lease within 18 months. Meanwhile, a lot of the infrastructure built so far on the port expansion is a good investment, Wilson said. A road has been built up the hill behind the port to JBER that initially served to support movement of gravel, but it now provides direct access to the base for movement of military vehicles during a deployment. The utilities, a road link and an extension of a double row of rail track along the back of the port are also useful. The rail link, which still needs a final increment of extension, will be useful for direct loading of rail cars from barges at the new barge docks, eliminating a truck shuttle. It also serves a purpose now by allowing military vehicles during a deployment to be moved directly by rail to the large storage area on the port’s north end, eliminating having to unload the vehicles from the train in the main railroad yard and move them along the port’s main access road. “Our overall goals are to hold the line on rates for service, offsetting our cost increases; to sustain reliability of service; be able to serve the military needs as one of the nation’s 19 strategic ports for defense needs, and to take advantage of new technologies as they develop,” Wilson said. The port has held the line on rates for several years. “We live within our means,” Wilson said, but the port has also had to defer maintenance. “We are hoping the expansion will eventually give us the stability that we need,” he said.

State issues new report detailing hydrocarbon and geothermal resources in rural areas

A new report detailing fossil fuel and geothermal potential in unexplored areas of Alaska was released Sept. 7 by the Alaska Division of Geological and Geophysical Surveys. The 144-page study, four years in development, is intended primarily to aid small rural communities in looking for more affordable, local sources of energy, state natural resources commissioner Dan Sullivan said. “We know that the high cost of energy is the primary concern and challenge for many communities. Our goal is to assist them in making energy development decisions,” Sullivan said. It is designed to be a companion to a similar inventory of renewable resource potential including wind, biomass and small hydro, developed by the Alaska Energy Authority four years ago. Sara Fisher-Goad, executive director of the Alaska Energy Authority, said the new report supplements and extends her agency’s Renewable Energy Atlas. “It will be useful in our regional energy planning efforts,” underway by the AEA, she said. Bob Swenson, the state geologist and director of the Division of Geological and Geophysical Surveys, said he was surprised, once the information was compiled, at the extent and quality of the fossil fuel resources outside the better-known North Slope and Cook Inlet basins. In a Sept. 7 briefing, Swenson said that he was struck by the extent and quality of coal formations in different parts of the state which also indicate the potential for biogenic natural gas and coal-bed methane, which could be sources of energy for local communities. A new report detailing fossil fuel and geothermal potential in unexplored areas of Alaska was released Friday by the Alaska Division of Geological and Geophysical Surveys. Alaska has many unexplored sedimentary basins particularly in Interior and western Alaska. Swenson said he was struck, however, by the extent and quality of coal formations which also indicate the potential for biogenic natural gas and coal-bed methane, which could be sources of energy for local communities. “We were also surprised at the extent of quality geothermal resources, some with extreme high temperatures, mainly on the Alaska Peninsula and Aleutian Islands,” Swenson said. Alaska has had the most aggressive renewable resource funding program of any U.S. state for several years now, with about $200 million invested to date in grants to mostly small rural projects, but Fisher-Goad said the program can also be used for certain small-scale fossil fuel projects such as natural gas.

Looking at shale oil issues in Alaska

Great Bear Petroleum and its partner, Halliburton, are now drilling into North Slope shale rocks, extracting core samples and conducting tests to see if oil can be extracted from the shale. The first test well, Alcor No. 1, about 17 miles south of Deadhorse, at Prudhoe Bay, has now been completed, said Great Bear’s president, Ed Duncan. A second test, Merak No. 1, is being drilled about one and a half miles south of the Alcor well and is expected to be at the point for its first core to be extracted in mid-September. Great Bear is a small Alaska-based company formed to explore potential resources in the large shale formations underlying North Slope lands south of large producing fields. The company holds about half a million acres of state oil and gas leases across a wide area of lands south of the major producing fields on the North Slope. Halliburton, a major U.S. oil services company with considerable experience in hydraulic fracturing has teamed up with Great Bear on its North Slope project. Fracturing is the process with which oil is extracted from shale, which is too tight for oil and gas to flow like in conventional, porous reservoir rocks. Great Bear believes oil from the North Slope shales can be produced with the same drilling and fracturing procedures now used in the large shale oil areas now producing in North Dakota and Texas. The shales were the source rocks of oil and gas that seeped out over eons to migrate upward, and northward, through porous rocks to accumulate in large reservoir traps that now form the large Prudhoe Bay, Kuparuk River and other producing fields on the Slope. Chemical “fingerprinting” tests have shown that the oil in many of the large fields originated eons ago in the deeper shale formations that lie to the south. Duncan believes, as do state geologists, that a great deal of oil is left in the shale source rocks. Great Bear’s test wells are being drilled at locations adjacent to the Dalton Highway, a gravel road that provides year-around access to the North Slope. Road access allows the drilling to be done in the summer, in contrast to typical exploration wells on the Slope which are off the road system and can be done only in winter. It’s too early for any results of the testing, Duncan said. A range of diagnostic tests are now under way on core samples extracted from Alcor No. 1, he said. “We’re focused at this point on learning about the rock mechanics,” and how efficiently the shale will fracture to allow oil to flow, Duncan said. The next step will be a diagnostic fracturing test involving injection of a small amount of water into the rock. “This will help is define a larger fracturing test to be done later this year,” Duncan said. Great Bear plans to continue drilling until late December. Regulatory, legal issues Meanwhile, beyond key technical and economic questions – whether the shale can be efficiently fractured and whether oil can be produced – lie a number of complex regulatory and legal issues for the companies and state land managers. The state has a multi-agency task force working on the questions but any recommendations for changes to state laws and regulations will likely wait until Great Bear and Halliburton answer the key technical questions. However, Louisiana Cutler, an attorney with K&L Gates, a law firm, has outlined some of the key challenges in a Sept. 10 talk given to the Alaska chapter of the International Association of Energy Economists. K&L Gates has done extensive work in legal and regulatory issues in states where shale gas is being produced and is now working with Great Bear in Alaska, but Cutler said her remarks on Sept. 10 offered her own perspective, and not Great Bear’s. The primary regulatory problem is that Alaska’s land laws and regulations were designed for conventional oil and gas fields where there are defined reservoir traps, or pools, she said. A primary tool for regulation of the industry to protect various leaseowners’ rights and to prevent physical loss of oil and gas through poor depletion practices is by forming units, or groups of leases, to provide a mechanism for administration. Shale oil wells are different than ordinary oil wells, though, in that the well taps oil locked in tight rocks in the immediate vicinity of the well, so that there is virtually no “communication” of oil from an area on a nearby lease, which can happen with normal oil wells tapping into a conventional oil-saturated sandstone reservoir. Units, or groups of leases, can still be established for shale oil leases, but they may have to be different than units now formed for conventional oil. Changes in regulations, and possible statute changes, will be needed. The unit is important because it is the primary mechanism under Alaska law where oil and gas leases can be extended beyond their primary terms, which is usually 7 years to 10 years. “The standard lease term may not be long enough to accommodate rational development of all shale resources,” in an area, Cutler said. If oil and gas production begins from a lease, it is automatically extended. But if there is a prolonged period of exploration and testing — as is often the case with conventional oil and will almost certainly be the case for shale oil — the lease may expire before production begins. Typically, units are formed for an extension of lease terms. This requires the state’s approval and is usually accompanied by a negotiated work program for the leases. There is no real requirement for units to be formed because the primary motivation – prevention of physical loss of oil and gas through migration or seepage through rocks, doesn’t occur with shale oil because of the tightness of the rock. However, if units aren’t formed, the state and the companies will have to develop some other mechanism for extension of lease terms if the shale oil resource is to be developed. Potential shale development in Alaska is different in this respect than with the big shale oil plays in North Dakota and Texas. In those states the lands are privately owned, usually by farmers and ranchers, who have more flexibility in working out lease terms and extensions than in Alaska, where the state is landowner.

Statoil delays Arctic offshore drilling

Statoil has delayed its first exploration drilling in the Chukchi Sea until at least 2015 because of continued regulatory uncertainties facing Shell’s efforts to drill, a Statoil official in Houston said Sept. 7. This is a delay of one year from the previous plan. Statoil had been planning to drill its first well in 2014. “In light of the significant uncertainty regarding Alaska offshore exploration, we have decided to take the prudent step of observing the outcome of Shell’s efforts before finalizing our own exploration decision timeframe,” Statoil spokesman Jim Schwartz said in a statement. “We believe it is important to observe the timing and outcomes of obtaining all necessary permits, securing regulatory approvals and demonstrating that exploration operations can be reliably and cost-effectively conducted in this dynamic and challenging environment.” Shell’s efforts to drill its first exploration wells in the Chukchi and Beaufort seas have been stymied by a number of factors including lengthy permitting procedures and, more recently, weather, ice and delays in certification of a spill response barge. Schwartz said Statoil has made no firm decisions on drilling even in 2015, but would continue scientific research that is underway in a joint program with Shell and ConocoPhillips as well as other preparations and work with local communities. ConocoPhillips has been planning to drill its first Chukchi Sea exploration well in 2014 and has made no change to the plan, company spokeswoman Natalie Lowman said. Shell now has two drill vessels in the Arctic. The drillship Noble Discoverer began work on one well at the Burger prospect in the Chukchi Sea but had to cease operations due to a large approaching ice flow. The second vessel, the Kulluk, is in the Beaufort Sea waiting for Inupiat whalers to complete their fall subsistence whale hunt. The U.S. Interior Department gave Shell permission for drilling only to the 1,400-foot level in the Chukchi Sea until a specialized spill barge is on the scene. The barge has not yet completed final inspections and certifications. Meanwhile, there has been no response yet from the U.S. Interior Department to Shell’s request for a two-week extension to a Sept. 24 for a halt to drilling activities in hydrocarbon zones. Under the rule Shell can continue testing any well drilled to a hydrocarbon zone before Sept. 24, however. It can also do work on other wells including “top-hole” drilling to 1,400 feet and setting of casing on wells that can be completed next year.

Alaska battles reputation as a tough place to do business

Alaska is now attracting more interest from the world’s petroleum and minerals industries, Alaska Natural Resources Commissioner Dan Sullivan says. However, the state still has a lingering reputation as a tough place to do business that is casting a long shadow, he said. Sullivan spoke to business and community leaders in Anchorage Sept. 6 at the Resource Development Council’s first fall bi-weekly meeting of fall 2012. “Alaska’s reputation still isn’t the greatest,” Sullivan said. “I believe this is ‘old thinking’ but the conventional wisdom is still that this is a difficult place to do business, to invest, to get permits, and that the government is hostile.” Sullivan and other state officials are chipping away at the bad reputation but it’s slow going. What doesn’t help is that lot of Alaskans “are living a little in the past,” he said. “As long as the pipeline was over 1 million barrels a day we didn’t have to hustle. But we’re in a different era now,” Sullivan said, with the oil in the Trans Alaska Pipeline System less than 600,000 barrels per day. “We have the resource base but we now need to hustle,” he said. “Capital is going all over the world.” Taxes come up a lot in the commissioner’s discussions with potential investors. “We can only tell them we’re working on it,” Sullivan said. Gov. Sean Parnell has proposed adjustments to the state’s oil production tax, which is among the highest in the world, but the proposals bogged down in the Legislature in 2011 and 2012 sessions. Sullivan is on the road a lot, speaking at energy and minerals conferences and knocking on doors at corporate offices. He was in Houston at the North America Prospect Expo, better known as NAPE, from Aug. 20 to Aug. 24. On Sept. 19 he will be in Tokyo at the LNG Producer-Consumer Conference, a major event sponsored by Japan’s Ministry of Economy, Trade and Industry, or METI, and will also stop in South Korea for other gas-related meetings. There was one positive development at the NAPE Houston conference. A major private equity investor, Tudor, Pickering & Holt, sponsored a luncheon focused on Alaska, giving Sullivan a stage to pitch the state to 60 potential investors. In Tokyo, Sullivan will be able to test the waters before an expected Sept. 30 report by North Slope producers on a major Alaska LNG project, and also gauge reaction by Japanese companies to Russian President Vladimir Putin’s promise to develop a major LNG project at Vladivostok to supply Japan (Russia already ships LNG to Japan from Sakhalin). Sullivan says his message is received with interest and that 50 percent of the “cold calls” he makes on corporate executives result in requests for more detailed information. Inevitably, the negatives come up, though. Costs are high, taxes are high, lawsuits are many, and the regulatory environment is tough. There’s not a lot the state can do about high costs in remote operating environments, and while progress is being made in streamlining state permit procedures, Alaska has to reinforce its message that environmental standards are high. That is actually a positive, Sullivan said. A lot of negative press comes with Shell’s long effort to get its Arctic offshore exploration approved by the federal government, which now appears to be happening. But there is also the government’s apparent inability to complete its decision on the Point Thomson environmental impact statement for the multi-billion-dollar gas and condensate project. If that goes past mid-October, ExxonMobil will be unable to mobilize in time to start construction this winter. As many as 1,000 jobs could be created for Point Thomson construction this winter. Sullivan said he and other state officials are making phone calls daily to get the Point Thomson EIS decision out in September, the original goal of the U.S. Army Corps of Engineers. “Those guys are getting sick of my phone calls,” he said. All that said, Alaska has some big selling points. The sheer size of the resource base is one, but there are others. For example, Alaska’s North Slope is the only place where a company can pursue a shale oil resource as well as a conventional oil resource. “You won’t find 100-million-barrel conventional oil finds in the Bakken (N.D.) shale oil region, but you will here,” Sullivan told the RDC. There are also actions by some major companies on the North Slope that haven’t been widely noticed, the commissioner said. One is ConocoPhillips’ acquisition of a large acreage position south of Point Thomson in a 2010 state lease sale, and Shell’s acquisition of state leases in near-shore submerged lands within the state’s three-mile offshore territorial limit, Sullivan said. Results of the state’s December, 2011 area-wide lease sale were encouraging, too. The state received more than 300 bids from more than 15 bidders including companies new to Alaska like Repsol and Royale Energy, Sullivan said. “It was one of the most successful sales in recent Alaska history,” he said. Cook Inlet state lease sales have seen a steady increase in companies bidding and new firms entering the basin, with the 2011 lease sale particularly strong. The next North Slope area-wide lease sale is set for Nov. 7 and, like last year, will be held in coordination with the U.S. Bureau of Land Management in offering National Petroleum Reserve-Alaska leases. On the permitting and regulatory reform front, the state and the North Slope Borough recently signed a Memorandum of Understanding to coordinate permitting actions, Sullivan said. This will help remove any stumbling blocks between a developer having to get permits from state agencies as well as the borough, which is the regional municipal government for the North Slope.

Vitus bringing competition to Alaska

The scrappy entrepreneurs who organized last winter’s emergency shipment of fuel through frozen seas to Nome are at it again. Mark Smith and Justin Charon, who own and manage Vitus Marine along with Shaen Tartar, another partner, are busy delivering fuel this summer to remote western Alaska rural communities using new, technologically-advanced tug and barge units. They are now also developing an independent 5 million-gallon bulk fuel storage plant at Port MacKenzie, the Matanuska-Susitna Borough’s port on Knik Arm across from Anchorage. Site preparation is under way now and the company hopes to have construction of the facility begin next year. The bulk storage plant, being done under an affiliate company, Central Alaska Energy, is intended to serve a niche market with specialized services, such as inventory management and fuel storage for customers, Smith and Charon said. The large fuel operators could also be customers for Central Alaska Energy themselves, the two said. Still, Central Alaska will be new blood in the Southcentral Alaska fuel business, and that’s just what’s needed, state officials who study the state’s energy situation have said. Last January, Vitus Marine became briefly famous, thanks to intense international media coverage of the unprecedented shipment of fuel through sea ice assisted by the U.S. Coast Guard icebreaker Healy. Bonanza Fuels in Nome had been caught short of fuel when a scheduled late season barge delivery was blocked by a Bering Sea storm. Rather than fly the fuel in, which would have been prohibitively expensive, Bonanza turned to a new company, Vitus, for fresh ideas. Smith and Charon are long-time veterans in the rural fuel and barge business, but their company, Vitus, was a new entity. Vitus had just started operation in the region last summer with two new tug and barge sets built under a long-term agreement with Alaska Village Electric Cooperative, or AVEC. The solution for Nome is now well-known. Vitus arranged for a Russian tanker, the Renda, to deliver the badly needed fuel, and for the Healy to cut a path through the icepack in the Bering Sea and Norton Sound. It all went off without a hitch. Nome got its fuel, and the Coast Guard got a chance to strut its stuff in the international media and, by the way, to remind Washington, D.C., that the nation has only one operating icebreaker, the Healy, which is really designed to support research and not break heavy ice for commercial shipping. Two other U.S. icebreakers, which are heavier than the Healy, are laid up and only one is likely to be brought back into service. Vitus’ business is delivering fuel, though. The company got its start with the AVEC fuels contract and an agreement for the cooperative, which operates 53 small rural utilities, to finance the two tug-and-barge sets and buy fuel from Vitus on a multi-year contract. “AVEC had been seeing year-over-year increases in fuel costs and its board asked for a long-range rate stabilization plan. We put together a proposal that would bring us in as new competition in the market,” Charon said. Under the plan, AVEC financed and built the tugs and barges and leased them to Vitus as operator. AVEC remains as the owner, although Vitus may eventually purchase the equipment, Smith said. The arrangement has precedents. Before Alaska became a state, the federally-owned Alaska Railroad, which historically operated steamboat service on the Yukon River and tributaries, built modern diesel-powered river towboats and leased them to Yutana Barge Lines. Crowley purchased Yutana, and now operates the Yukon barge service. The tugs and barges were built in 2010 and delivered and went into service in western Alaska late 2011. One barge has a capacity of 8,000 barrels and the second a capacity of 10,000 barrels. This year is the first full operating year for Vitus using the new equipment, Smith said, and so far things are going well for deliveries despite the usual glitches with weather and water depths in some rivers. Vitus has other customers in western Alaska besides its anchor customer, Smith said. Meera Kohler, AVEC’s president, said, “It’s a little early to say exactly what the impact of receiving our fuel from Vitus has had on our delivered cost. I think our arrangement is saving us about 12 to 15 cents a gallon but I’ll be able to do a much more rigorous analysis when the year is closed out.” What is unusual about the new tugs and barges is that they link together to effectively operate as a single unit, like a ship, Charon said. This has important advantages over the conventional tug and barge setup where the tug pulls and maneuvers the barge with towlines, which are metal cables or heavy rope. This makes the combined units easier to maneuver when making beach deliveries in rough seas, where there are no docks, Smith said. The operation is also safer because it avoids the periodic breaking of towlines, which happens with the conventional setup. Breaks in lines and lash-backs of cables are a common source of injuries. The tugs and barges, when linked, also have a speed advantage of about 20 percent over a conventional tug towing a barge, Smith said. The downside is that the units are typically more expensive than conventional equipment, he said. Southcentral fuel storage Meanwhile, the Central Alaska Energy venture involves the construction of six bulk storage tanks with a combined storage capacity of 5 million gallons. The company has a 5.5-acre lease at the site, so there is room for expansion. “The advantage of the location compared with, for example, the Port of Anchorage is that the water depths at the dock are deeper, at 40 feet to 60 feet, compared with 40 feet and less at the Anchorage port,” Charon said. There is also less of a siltation problem. An expansion at Port MacKenzie would also not face the same kind of public opposition as has happened in Anchorage, where Government Hill residents overlooking the port worry about large quantities of fuel being stored at the base of the hill. There is also some road and trucking distance advantage at Port MacKenzie for some customers, such as those in Interior Alaska who would be served via the Parks Highway. The borough road to Port MacKenzie is gradually being improved. It is paved for half its length and the remaining gravel road is in excellent condition, Smith said. Still, it’s not the Parks Highway, he acknowledged. If the planned Alaska Railroad link is built to Port MacKenzie it would improve access, he said. The rail bed is now under construction, but the Mat-Su Borough must still raise funds for the rails to be laid. A principal advantage of the Central Alaska facility is its modest size, which means it can be efficiently served with small or large shipments. Vitus has looked at building bulk storage elsewhere such as in Seward, but the tanks would have to be large and the facility would be best served by large shipments. The ability to efficiently work with smaller shipments will give Central Alaska more flexibility to meet particular customers’ needs. “We’ll be small, and will provide an alternative for people who want a different level of service,” Charon said. “For example, a customer could lease space in one of our tanks, providing a way to store fuel. For some customers, such as construction contractors, having the ability to ensure a supply of fuel at a known cost is important.”

Anchorage 49th State Angel Fund will award $4.1M in 2012

Anchorage’s new city-run 49th State Angel Fund is off to a good start in stimulating local entrepreneurs with small business startups or expansions. There were 25 direct applications from businesses and three from private or institutional investment funds in the first round of applications that closed Aug. 5, according to Joe Morrison, the Municipality of Anchorage’s manager for the program. Anchorage has received $13.2 million in federal funds under the State Small Business Credit Initiative to start the program, and is the first U.S. city to receive such an allocation. About 60 percent, or 15, of the business applicants survived the initial screening and are now before the Angel Fund’s advisory committee, he said. “Our criteria is that these applicants be able to provide significant economic benefits to Anchorage, for example by maintaining a headquarters in the city. The economic benefits could extend statewide, of course, and even outside Alaska,” said Lucinda Mahoney, Anchorage’s city Chief Financial Officer, in a recent briefing to Anchorage’s Chamber of Commerce. The city’s Angel Fund is being managed through Mahoney’s finance office. Morrison said about $20 million in investments were requested, which is about five times the amount of money, about $4 million, that will be available this year. “These are strong applications that were put together by people with experience, and who will help deploy this capital effectively,” Morrison said. The identities of the applicants are confidential for now, but that will change by year-end. “Our intent is that by the end of the year we will be able to tell the public who we funded and for how much,” although some details will not be disclosed, Morrison said. Morrison said $4.13 million is expected to be awarded this year, with the balance, $8.5 million, to be awarded in 2013. The federal program is one-time funding. A preliminary review of the applications was done by Anchorage Economic Development Corp. and municipal finance staff. An advisory group to the 49th State Angel Fund of local businessmen and finance specialists will make recommendations in mid-September. Finalists to receive funding will be selected by Oct. 1, after which a three-month period of due diligence will be conducted. Mayor Dan Sullivan and Mahoney, the city CFO, will announce the final applicants chosen for investments at the end of the year. “Angel” funds are traditionally investment funds run by private individuals, such as venture capital investors, who provide critical early start-up or expansion capital for entrepreneurs. These are typically in businesses with high growth potential, where there is considerable profit possibility. Typically, angel funds also provide for the early investor to be bought out, hopefully at a considerable profit. “Many companies, particularly small businesses and start-up companies, have found it increasingly difficult to obtain loans due to the tightening of credit markets,” Morrison said. Congress passed the State Small Business Credit Initiative to help make more money available for small businesses. Federal rules require the 49th State Angel Fund to limit applications to firms with 750 or fewer employees, a category which most potential small business applicants in Anchorage fit. The applicant must also be able to match the city’s investment with his or her own money on a one-to-one ratio, so that if the angel fund invests $1 million the applicant must bring in $1 million in either equity or debt financing. It must also be new money, not funds already in the enterprise. Another federal requirement is that the applicant must show an ability to bring in additional funds for further growth on a 10-to-1 ratio, in either further debt or equity funding. “The applicants have to show us how they can leverage this investment with additional funds to grow quickly, and to provide us with an exit strategy so we can be bought out,” Mahoney said at the Chamber briefing. Morrison said the decision on what to do with funds returning to the municipality after the city’s equity is bought out will be made by future municipal leaders. However, it is expected that the city’s ownership of a share of the investment funds will continue for a number of years. The angel fund strategy is also that most of the funds, about two-thirds, will go to local investment funds to help them grow. “Our goal is that we want to help build these local private investment funds that are emerging in the community so they become more visible. There is risk capital available for entrepreneurs here but it is not highly visible,” Morrison said. Meanwhile, many of the nine direct business applicants turned down in the first screening fell short not because of quality but because of difficulties in meeting the requirements like the one-to-one match, Morrison said. Where quality deficiencies did exist, the applicants were referred to other resources in the community, like the University of Alaska Anchorage Small Business Development Center or another UAA group, the Center for Economic Development, Morrison said. Applicants that weren’t funded in 2012 are also free to re-apply for the 2013 rounds of funding, he said.

Fire Island, Eva Creek set to begin producing wind power

The new Fire Island 17.6 megawatt wind power project developed by Cook Inlet Region Inc. will be generating power in a week or two. Commissioning of the 11 wind turbines on the island is expected to be completed by Sept. 8 or 9 and a 72-hour test of the facility is expected the week of Sept. 10. “After that, the contractors turn the keys over to us,” CIRI spokesman Jim Jager said. Meanwhile, a second wind power project will be supplying electricity to the Southcentral–Interior Alaska “railbelt” power grid in late October. It is Golden Valley Electric Assoc.’s Eva Creek project, which has 12 turbines with a capacity of 25 megawatts. Eva Creek is near Healy, between Anchorage and Fairbanks on the Parks Highway. Fairbanks-based Golden Valley, the electric cooperative serving Interior Alaska, held a ribbon-cutting ceremony at Eva Creek with state and local officials in late August. Golden Valley will use Eva Creek power in its own system, while CIRI will sell power from Fire Island to Chugach Electric Assoc.  Fire Island is in Cook Inlet just offshore from Ted Stevens Anchorage International Airport. CIRI owns most of the land on Fire Island and developed the wind project with a first-phase cost of $65 million. The project was intended to be larger but was scaled back to 11 turbines in a first phase to allow for the variable wind power to be efficiently integrated into Chugach’s system. The State of Alaska contributed $20 million to the project to pay for submarine cables connecting the island to the mainland, and for the connections to Chugach’s power grid. The total cost, including both the CIRI and state investment, is $85 million. Golden Valley is developing Eva Creek for about $95 million, which includes $10 million contributed by the state to help pay for site access and other infrastructure. Golden Valley had to build a 10-mile road to the site from Mile Post 260 on the Parks Highway 14 miles north of Healy. Eva Creek is coming on line at a good time for Golden Valley. The co-op is having to raise its rates 6 percent because of an 11 percent increase in fuel costs, mostly for oil and naphtha used at Golden Valley’s 120 Megawatt generating plant at North Pole, east of Fairbanks. Wind power won’t result in lower rates but will help dampen possible future increases in oil costs, Golden Valley has said in the past. The Fairbanks utility has a goal of generating 20 percent of its power needs from renewable energy by 2014. Eva Creek is expected to generate about 76,700 megawatt/hours of electricity annually, while Fire Island is expected to produce about 50,000 megawatt/hours per year. Jager, of CIRI, said wind storms like Anchorage experienced the night of Sept. 4 are not really good for wind projects. When wind speeds exceed 55 miles per hour, wind project operators must close the system down or the turbines can become destabilized and risk damage, he said. “Our optimum wind speed for power generation is about 42 miles per hour. We can start making power at wind speeds of 7 to 9 miles per hour,” he said. Wind speeds are expected to be strongest at the Fire Island site during December, which generally coincides with Chugach Electric’s winter peak demand for power

Shell drillship ready to work at Chukchi Sea

Shell’s drillship Noble Discoverer is in the Chukchi Sea and was preparing to begin site preparation for drilling at the company’s Burger prospect on Sept. 6 or 7, company officials said. Bad weather caused some delays. The drillship was held about 10 miles south of Burger earlier in the week as Shell waited for rough seas to settle, company spokesman Curtis Smith said. Meanwhile, a second Shell drill vessel, the Kulluk, is in the Beaufort Sea and will be on standby west of its exploration site to give Inupiat Eskimo whalers time to finish their bowhead whale subsistence hunt. In another positive development for Shell, the U.S. Environmental Protection Agency issued modified air quality permits for the drill ships. “Once at the drill site, the Discoverer will connect to the eight pre-staged anchors, a process that will take roughly 16 hours,” Smith said. “When the anchors are connected and deemed secure, the Discoverer will begin doing the well preparations.” Anchors for the drillship were set earlier on the sea bottom at the Burger site, its initial prospect in the Chukchi Sea. Interior Secretary Ken Salazar announced Aug. 30 that the department had issued a drilling permit to Shell that would allow the company to begin preparation of the drill site. The Secretary spoke in a press briefing in Washington, D.C. That work that Interior approved will include construction of a “mud-line cellar,” an excavation in the sea-floor, for installation of a blow-out preventer, as well as the drilling of a 8.5-inch “pilot hole” to test for shallow gas accumulations that may have been missed by seismic surveys. Once those tests are done, drilling will be allowed to the 1,400-foot level with installation of casing. Salazar said Shell will not be able to drill further to potential hydrocarbon zones until the Arctic Challenger, a specialized spill response barge, completes inspections in a Bellingham, Wash., shipyard and is on the scene. Salazar also said no decision would be made on Shell’s request for an extension of a Sept. 24 deadline for drilling into hydrocarbon zones until the Arctic Challenger spill barge has passed inspections. Because Shell will not be allowed to drill below 1,400 feet until the barge is on scene no decision is needed for now on the deadline extension, he said. Shell’s Alaska vice president, Pete Slaiby, said that even if the company can only drill the so-called “top holes” this year, it will consider the season successful. “We got a late start because of ice, but we will have demonstrated a lot of things, mainly that we can work safely,” he said. About two-thirds of the time needed to drill the well will be spent on the mud cellar and the initial drilling and setting of casing. Once the spill barge is on the scene, Slaiby said the drillship will have to drill another 6,000 feet, approximately, to reach hydrocarbon zones. Installation of the blow-out preventer and drilling to 1,400 feet is expected to take about two weeks. Once the barge is on scene it will take about 7 to 10 days to drill down to the hydrocarbon zone, he said. Under rules set by the government Shell must stop drilling into hydrocarbon zones on Sept. 24, but well-testing and abandonment work on the well can be done after that, Slaiby said. The permit issued Aug. 30 is for the Chukchi Sea well only, and no similar permit has been issued yet for the Beaufort Sea well. However, the Kulluk will not begin drilling until after the end of the fall Inupiat subsistence whale hunt in the Beaufort, which has just started, Slaiby said. The Kulluk is not under as tight a drilling deadline as the Noble Discoverer. The Interior Department will allow drilling in the Beaufort Sea until late October. Shell’s exploration sites in both the Chukchi and Beaufort Sea are in areas where hydrocarbons were discovered in previous drilling, so the drilling planned this year is aimed at assessing those earlier results and establishing more reserves. Shell itself drilled an exploration well as the Burger site as well as two other exploration locations in the Chukchi Sea in the early 1990s and found a large gas accumulation and signs of oil at Burger. The discovery was not economic at the time, however. In the Beaufort Sea, Unocal drilled its “Hammerhead” exploration well in the 1980s and made an oil discovery near where Shell now plans to explore. A few years later ARCO Alaska made an oil discovery at another site nearby, its “Kuvlum” discovery. Neither of the oil discoveries were economic at the time, however.

Effort to obtain North Slope propane may have hit a dead end

An effort to bring propane from the North Slope for use in home heating and possibly as a vehicle fuel may have hit a dead end. The Alaska Oil and Gas Conservation Commission ruled Aug. 17 that the practice by Prudhoe Bay producers to inject propane that is part of natural gas produced with crude oil back into the underground reservoir does not constitute “waste.” State law prohibits oil field practices that result in the loss, meaning lack of full recovery and use, of oil and gas fluids. The AOGCC, a quasi-judicial regulatory commission, has the responsibility of enforcing that. Harold Heinze, a former state natural resources commissioner and former president of ARCO Alaska, had petitioned the commission last December that the refusal by BP, the Prudhoe Bay operator, to sell propane from the gas that is produced and then reinjected, constituted waste. Once injected back underground much of the propane may never be recovered from the reservoir, Heinze had argued. Heinze was formerly executive director of the Alaska Natural Gas Development Authority, which had worked to facilitate a project to move propane off the slope for use as a fuel by consumers and businesses. Rural communities had expressed interest in propane as an alternative to conventional fuel oil, which is very expensive. At a June 19 hearing on the matter BP argued all the propane produced with the gas at Prudhoe was needed for additional oil recovery. In its Aug. 17 decision the AOGCC agreed with the company. Natural gas is produced along with crude oil in many oil wells and the gas is normally sold to local customers, but where there are significant commercial customers, as on the North Slope, the field operators must find other uses for the gas. Most of it is now rejected back into the reservoir, where it helps maintain reservoir pressure and oil production. Flaring of produced gas is not allowed by the AOGCC. Some of the gas produced at Prudhoe Bay is used for local power generation and space heating. Also, many of the natural gas liquids in the gas, including propane, are extracted from the produced gas, with some of the heavier liquids mixed with oil and shipped through the Trans Alaska Pipeline System. The lighter gas liquids, including propane, are used in Enhanced Oil Recovery to extract more oil from the producing fields. Heinze, who has knowledge of the North Slope oilfield operations from his days at ARCO, felt some of the propane could taken off and moved by truck to Fairbanks, or even shipped by barge down the Yukon River to small villages. The field producers had initially appeared open to this while ANGDA developed the propane idea but then apparently changed course, Heinze said. The petition Heinze filed with the AOGCC was to get the producers to state their reasons and to put testimony on the record, he said. BP argued at the June 19 hearing that propane injected into the reservoir as part of an EOR project or even as a small part of the main “residue” gas stream left after most liquids had been extracted, was effective in recovering additional crude oil. The AOGCC affirmed BP’s conclusions in its findings: “The selling of 1 barrel of propane that could have been used (in enhanced oil recovery) will result in the loss of about 0.7 barrels of oil.” The loss is worse, however, because a barrel of crude oil has a greater energy content than propane. On a “barrel of oil equivalent” comparison, adjusted for the differences in energy value, the sale of one BOE (barrel of oil equivalent) of propane results in the effective loss of 1.08 barrels (in BOE) of oil, the commission found. On the basis of that, the commission found the propane injection to be beneficial in recovering more oil, and that waste was not occurring. Heinze said he was satisfied with the decision. “The commission was focused on its primary job, which is recovery. BP did a good job of proving its case that every molecule of propane is needed, using the existing facilities, to recover oil,” he said. There are still lingering questions, however. One is that if the propane is effective in enhancing oil recovery, the producers should show why they are not investing in expanding the gas process facilities to extract more propane and use it in EOR, Heinze said. “However, this is for someone else to pursue. From a practical standpoint, the issue is over for me. I accomplished what I set out to do, which is to give the issue a fair hearing and put sworn testimony on the record,” he said.

LNG is an option for Hawaii, but major obstacles loom

Hawaii is looking at the possibility of purchasing liquefied natural gas from Alaska, but it is unlikely to happen anytime soon even though LNG could be purchased today, in theory, from the ConocoPhillips plant in Kenai. That’s what Hawaiian officials told a gathering of business leaders convened in Anchorage by Alaska U.S. Sen. Mark Begich on Aug. 23. There’s also a problem long-familiar to Alaskans, the U.S. Jones Act, which requires shipments between U.S. ports to be done in American-built and manned vessels. Currently there are no U.S.-built LNG carriers. Robert Isler, Hawaii Electric Co.’s manager for generation development, told Begich and others at the meeting that his utility is studying imports of liquefied natural gas for power generation but concerns over infrastructure, mainly a site for an LNG terminal and re-gasification facilities, must be worked out before a source of LNG can be decided. Hawaii residents pay some of the highest electricity costs in the nation because power is mostly generated with fuel oil, Isler said. Dale Hahn, energy advisor to Hawaii’s lieutenant governor, also attended the meeting and said a major complication is the effect that fuel switching could have on the two refineries in Hawaii, he said. About half the fuel produced at the refineries owned by Tesoro and Chevron is used for power generation, she said. The concern is that if LNG takes that market away it could adversely affect the refineries and local supplies of transportation fuels they also produce. Infrastructure is the immediate concern, however. “We have not yet identified where we would place LNG import infrastructure,” Isler said. “We have limited land and harbor space, and being volcanic it gets really deep immediately offshore,” which limits the ability to build offshore,” he said. A more immediate problem for Hawaii Electric are new U.S. Environmental Protection Agency emissions rules that will limit particulates and sulfur emissions for generation plants now using oil, he said. ‘’We have a situation where we have either do an estimated $900 million upgrade of our plants to meet the rules or switch fuels, and we have decided to switch fuels,” Isler said. LNG is a solution but the EPA won’t wait six to seven years for facilities to be in place, so as an interim step Hawaii Electric will switching to a lower-sulfur fuel. “We currently use a No. 6 fuel oil which is low-sulfur, with a sulfur content of 0.5 percent, but to meet the EPA rules we will go to a lower sulfur fuel at 0.05 percent by 2015,” he said. Even this will cause problems for the refineries because they cannot make fuel with this specification. An added complication is that Tesoro is looking for sell its refinery, Isler said. Chevron would be able to bring in the fuel from elsewhere, however, he said. As for LNG, the infrastructure issues have to be settled before it will be known what size vessel can be accommodated, whether a large LNG carrier, a smaller ship or even a barge, he said. Once that is known, a source for LNG can be found. Alaska is closer to Hawaii than LNG suppliers in Sakhalin, Australia or Indonesia, and there is an LNG plant in Cook Inlet operated by ConocoPhillips, but the Jones Act, a federal law requiring use of U.S.-built and operated ships in domestic intra-coastal shipping, creates an additional problem, Isler said. An exemption from the Jones Act for Hawaii would probably require action by Congress, Isler said. “Those issues are down the road for us,” he said.

Doyon to spend $37M on exploration

Doyon Ltd., the Interior Alaska Native regional corporation, says it will spend $37 million this year on several oil and gas projects in Interior Alaska and will drill second a test well in the prospective Nenana Basin, west of Fairbanks, this winter. Doyon will also be the first explorer to take advantage of a new Alaska exploration incentive that will have the state pay for 80 percent of the well and extend preferential state tax treatment, Doyon CEO Aaron Schutt said in a Aug. 27 briefing in Fairbanks. The new well will be Doyon’s second in the Nenana Basin. The first well, Nunivak No. 1 drilled in 2009, found evidence of hydrocarbons but was not a commercial discovery, said Jim Mery, Doyon’s vice president for natural resources. Doyon is based in Fairbanks. Permit applications for the ndew well have been made, Mery said. Its location is about 11 miles west of Nenana and about 8 miles west of the Nunivak No. 1 well drilled in 2009, Mery said. Doyon is also interested in the northern part of the basin following seismic work done there last winter, and more seismic testing is planned for this winter. Applications for permits for two potential wells are being prepared for that area but they will not be drilled this winter, Mery said. Doyon had four partners in the 2009 well including independents Rampart Energy Co. of Colorado and Minnesota-based Cedar Creek Oil and Gas Co., and two Alaskan firms, Usibelli Energy and Arctic Slope Regional Corp., another Alaska Native corporation. Those companies have an option to join in on the second well but for now Doyon is proceeding on its own, Mery said. In the Aug. 27 briefing, Schutt said Doyon’s board has approved $37 million for Interior oil and gas exploration projects this year that include the well and additional seismic in the Nenana Basin as well as seismic exploration in the Yukon Flats basin north of Fairbanks. “These projects show a lot of promise. If successful, they could provide substantial benefits not just to our shareholders, but also to all Alaskans in terms of jobs and helping alleviate the energy crisis in Interior Alaska,” Schutt said. The initial target is for natural gas that would serve Fairbanks, about 60 miles east of the exploration site, but there is oil potential as well. Flint Hills Resources operates an oil refinery near Fairbanks and the Trans Alaska Pipeline System, which is operating below its capacity, runs near the city. The Nenana Basin program is on state-owned lands but in the Yukon Flats Doyon will explore its own lands and lands belonging to nearby village corporations, Mery said. An area near Stevens Village, on the Yukon River, is of particular interest, Mery said. It is also very near the TAPS pipeline, he said. Doyon and its partners now hold a state exploration license in the Nenana Basin, which gives the corporation rights to explore across approximately 500,000 acres of state lands and to convert some of the license area acreage to leases. This year Doyon will convert 400,000 acres, most of the land now held under the exploration license, to conventional state leases with seven-year terms. Besides the Nenana Basin in the Interior the state has issued four other exploration licenses in the Copper River and Susitna River regions, but Doyon is the first to convert areas in the licenses to state oil and gas leases. Schutt credited the new state incentives with allowing Doyon to proceed with the well. A change in state tax law approved by the Legislature in 2012 extended to Alaska frontier basins special incentives enacted for Cook Inlet three years ago that has now attracted new companies to the Inlet, and that have resulted in new discoveries of natural gas. The incentives provide for the state to pay directly for 80 percent of well costs and 75 percent of seismic, Schutt said, and also to extend to frontier basins a low state production tax that applies to Cook Inlet rather than a higher tax that applies to the North Slope. That would previously would have applied in frontier basins. “The recent state legislation expanding exploration incentives and a change in the oil production tax regime in frontier basins including Interior Alaska, were essential for us to move forward with these substantial projects,” Schutt said. Senate Bill 23, approved by state lawmakers in the 2012 session, included sections creating the new frontier basin incentives. Schutt gave credit to State Rep. Steve Thompson, R-Fairbanks, and state Sen. Tom Wagoner, R-Kenai, who took the lead in extending the new incentives to the frontier areas. Thompson, who attended the Doyon briefing in Fairbanks, said, “Doyon is the Interior’s biggest player in oil and gas today and when they talk, we listen. The potential for jobs, lower energy costs and a more positive future outlook is amazing.” Besides the Nenana Basin the incentives cover the Yukon Flats, the Selawik Basin near Kotzebue where NANA Regional Corp. of Kotzebue hopes to promote exploration, the Copper River basin near Glennallen, and Emmonak, Egegik and Port Moller in southwest Alaska. Doyon owns about 11 million acres of Interior Alaska lands and its one of the nation’s largest private landowners. It has about 18,500 shareholders, mostly Interior Alaska Athabascan Indians. Doyon also owns several operating companies including Doyon Drilling, one of state’s major drilling contractors, and pipeline and utility service and operating companies. Besides conducting oil and gas exploration on its lands and state lands, the corporation also has a substantial minerals exploration program underway on lands.

Legislators ask Parnell for local guarantees on LNG export renewal

Seven Alaska legislators asked Gov. Sean Parnell to seek explicit guarantees in a renewal of a federal license for liquefied natural gas exports from Alaska that local natural gas needs will be met by producers before gas is exported. The request was made in a letter sent to Parnell on Aug. 24. An LNG export license issued by the U.S. Department of Energy that is currently held by ConocoPhillips for its Kenai LNG plant will expire in March 2013. “We anticipate the governor will soon receive requests to offer state support for applications to renew the export license,” said state Rep. Les Gara, a Democrat from Anchorage, in an interview Aug. 24. What prompted the request was a contract dispute over commitments made by Marathon Oil to supply gas to a new gas storage facility being developed to meet local utilities’ winter peaking needs. Cook Inlet Natural Gas Storage Alaska, or CINGSA, the company developing the facility, said it was not receiving gas pledged by Marathon in a contract agreed on in 2011, and told the Regulatory Commission of Alaska in an Aug. 13 letter that it believed Marathon sold the gas to be exported as LNG to command higher prices. Late in the day on Aug. 24, CINGSA and Marathon announced they had resolved the dispute and enough gas would be supplied to pressurize the storage facility to allow withdrawals by utility companies at the previously agreed upon rates. The seven lawmakers, which include three state senators and four members of the state House, asked Parnell in the letter to include language on local needs that was included in a two-year extension of the export license granted in 2008 but not included when the license was given another extension in 2010, Gara said. “The 2008 commitment conditioned state consent (for the export license) on a binding commitment by ConocoPhillips and Marathon to meet local supply needs during the period of the export license,” Gara said. Marathon has since sold its interest in the LNG plant to ConocoPhillips. In 2010, Gara and other legislators asked Parnell to again condition the state’s consent on the license extension on having the local-needs language included in the license, but Parnell did not do that. Gara said that had the language been included the potential disruption of gas supply to the storage facility would not have happened. CINGSA spokesman John Sims said the storage facility needs 7 billion cubic feet of “pad gas” to pressurize the reservoir so that utility customers storing gas will be able to withdraw gas in winter at the rates they need. Besides Gara, the letter to Parnell was signed by state representatives Pete Peterson, Berta Gardner, and Chris Tuck, and state senators Hollis French, Bill Wielechowski and Bettye Davis. All seven lawmakers are from Anchorage, and all are Democrats.


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