Monday, October 31, 2011

Natural gas prices will be down in in 2012

Tim Bradner
Alaska Journal of Commerce 

Here’s good news for Southcentral Alaska consumers: Enstar Natural Gas Co. will file a gas cost adjustment with the Regulatory Commission of Alaska later this week for the first quarter of 2012 that will be 37 cents per thousand cubic feet, or mcf, lower than the gas cost filed a year ago for first quarter 2011.

Enstar President Colleen Starring made the announcement at the Anchorage Chamber of Commerce “Make it Monday” luncheon meeting on Monday.

Because there will be no change to Enstar’s administrative or other expenses, it means heating costs for Enstar’s customers will be lower for the first part of the year than last year.

Despite declining gas reserves in Southcentral Alaska, Enstar’s gas prices have been trending downward slowly, and Starring credited that to new gas producers appearing on the scene, mainly small independents, who are exploring for and finding new gas supplies.

State exploration incentives approved by the Legislature have caused an upsurge in drilling in Southcentral Alaska, Starring said.

The lower price is also an effect of a pricing formula for one of Enstar’s major suppliers, Unocal Corp., that is linked to the Henry Hub gas trading index in Louisiana, where natural gas prices are at very low levels.

Enstar’s average gas cost was $6.75 per mcf in 2011, down from $6.99 per mcf in 2010.

Friday, October 28, 2011

BLM sets date, time for December National Petroleum Reserve lease sale

Tim Bradner
Alaska Journal of Commerce

The U.S. Bureau of Land Management will hold its planned December National Petroleum Reserve-Alaska lease sale on Dec. 7, at 1 p.m. in Anchorage, BLM officials announced Friday. The sale will offer 283 tracts, or about 3.06 million acres, in the northeast and northwest planning areas of the petroleum reserve.

BLM’s sale will come several hours after a state of Alaska area-wide lease sale of about 15 million acres, which will be held at 9 a.m., also in Anchorage.

The unusual timing of having both lease sales on the same day will allow bidders maximum advantage in bidding for prospects that straddle the boundary between federal and state lands, state Natural Resources Commissioner Dan Sullivan said.

This means a bidder could potentially pick up acreage on state and federal land and gain more flexibility in accessing oil and gas pools, Sullivan said.

A 2005 U.S. Geological Survey assessment identified 19 oil plays in the central North Slope region that lie astride the boundary between the NPR-A and Alaska-owned lands, and 17 of these are included in the federal sale, Sullivan said.

The near-simultaneous offering, “should greatly improve a company’s ability to explore and develop both state and federal acreage. We have been coordinating with the federal government on our lease sale dates in the hope that working together will enhance opportunities,” the commissioner said.

BLM officials said they have worked to balance environmental protection responsibilities with orderly resource development. “I believe it is possible to develop oil and gas resources while protecting important surface and subsistence resources,” said Bud Cribley, BLM’s Alaska director. “The sale in December reflects BLM’s mission to balance the protection of natural resources and rural subsistence with the nation’s need for oil and gas development in the NPR-A,” Cribley said.

Republished with the permission of the Alaska Journal of Commerce. This article appears in the AJOC October 30 2011 issue of Alaska Journal of Commerce. Read more:

Petroleum industry packs big punch in state’s economy

Tim Bradner
Alaska Journal of Commerce

Alaska’s oil and gas industry packs a powerful economic punch in the state. A new study by McDowell Group, a Juneau-based consulting firm, has estimated that the petroleum industry directly creates 4,000 jobs, that industry support and service companies create 7,700 jobs, and that the “indirect” employment effect of those 11,700 industry and contractor jobs creates another 26,000 jobs.

The grand total is 44,800 jobs and $2.65 billion in annual payroll in the state, according to Jim Calvin, McDowell Group’s lead researcher on the project.

The data is from industry activity in 2010.

Calvin said that every one job created by a primary company, such as an oil producing company, creates nine additional jobs in the support sector.

The work was sponsored by the Alaska Oil and Gas Association, the petroleum industry trade group. McDowell Group presented the findings last Thursday, Oct. 27, at AOGA’s annual luncheon in Anchorage.

In terms of regional employment impact, the industry created 25,400 jobs and $1.56 billion in wages in Anchorage; 4,700 jobs and $320 million in wages in the Kenai Peninsula Borough; 3,000 jobs and $168 million in wages in the Fairbanks North Star Borough; 3,600 jobs and $268 million in wages in the Matanuska-Susitna Borough; and 700 jobs and $57 million in wages in Valdez.

Republished with the permission of the Alaska Journal of Commerce. Tim Bradner can be reached at Read more:

Repsol applies for 98,852-acre Qugruk unit; 4 wells this winter

—Kristen Nelson

Repsol E&P USA Inc. has applied to the Alaska Department of Natural Resources for formation of the 98,852-acre Qugruk on the North Slope.

Repsol, 70 & 148 LLC and GMT Exploration Co. LLC jointly proposed formation of the unit. The three together hold 91.5 percent of the working interest within the proposed unit area.

Other leaseholders in the proposed unit are: Pioneer Natural Resources Alaska Inc., Anadarko Petroleum Co., ConocoPhillips Alaska Inc., Paul L. Craig and Peter G. Zamarello. The unit agreement has been executed by Repsol, 70 & 148 and GMT. Repsol said it has offered the other leaseholders the right to join the unit and is awaiting their response.

The proposed unit, in somewhat of a “T” shape, is between the Colville River unit to the south and west, the Oooguruk unit to the south and east and the proposed Placer and South Miluveach units to the south. The northern limit of the proposed unit is the boundary between state waters and the federal outer continental shelf.

One-year plan

The initial plan of exploration is for one year and includes four wells. Repsol proposed a bond payable to DNR to ensure that work begins, with DNR to release the bond to Repsol when the first exploration well spuds. Repsol said the unit working interest owners agree to having the unit terminate if the first well is not drilled during the 2011-12 drilling season.
Prospective intervals to be tested by the exploration program include — but are not limited to — the Cervelo, Judy Creek, Nechelik, Nuiqsut and Alpine sandstones within the Jurassic Kingak shale, and the Cretaceous Kuparuk C sandstone (Kup “C”), Torok formation and Nanushuk Group.

The four planned wells are the Qugruk 1 in section 28 of township 13 north, range 6 east, Umiat Meridian, with a proposed true vertical depth of 7,100; the Qugruk 2, in section 25 of township 13 north, range 6 east, UM, with a proposed TVD of 7,000 feet; Qugruk 3, in section 31, township 12 north, range 6 east, UM, with a proposed TVD of 7,150 feet; and Qugruk 4, in section 15 of township 13 north, range 4 east, UM, with a proposed TVD of 8,300 feet.

Repsol said the sequence in which the wells are drilled may be changed and the location and drilling depth of subsequent wells may be adjusted following drilling of prior wells.

In its permitting paperwork Repsol has indicated that it may drill one vertical well and as many as two sidetracks at each location. It is also permitting the Kachemach exploration well farther south — outside of the proposed unit area — and just east of the Meltwater participating area of the Kuparuk River unit.

Kingak, Kup “C”, Nanushuk group

There have been many exploration wells drilled in the area surrounding the proposed unit, including six wells within the proposed unit, beginning in 1966 and extending through to 2008, Repsol said in its unit application.
Primary objectives for the proposed unit are “sands within the upper portion of the Jurassic Kingak Shale, the Cretaceous Kup ‘C’ sand and several sands within the Cretaceous Nanushuk Group.” Two sands in the J-2 interval of the Kingak shale are informally termed the Cervelo and Judy Creek sands, the Nechelik sand, the Nuiqsut sand and the Alpine “A” and “C” sands. Within the Nanushuk group the sands are the Nanushuk 3, Nanushuk 2 or Qannik sand, Nanushuk 6 and Nanushuk 7.

There is both 2-D and 3-D seismic over the area of the proposed unit, Repsol said.

While proprietary 3-D seismic exists over most of the proposed unit, Repsol said the primary 3-D seismic it has licensed over the proposed unit are the 2000 Fiord 3-D, the 1997 Kalubik 3-D and the 2007 Big Island 3-D. The company said that variably spaced 2-D lines (half a mile to 2-mile spacing) acquired from the 1970s to the 1990s were used in areas with no 3-D coverage.

Existing seismic “allows detailed mapping of fault patterns, truncation of individual Jurassic sands by the Lower Cretaceous Uncomformity (LCU), and amplitude anomalies associated with sands,” the company said.


Because of production in adjacent areas, Repsol provided DNR with an extensive analysis of what it considers to be analogous production.

The Nuiqsut sand is productive in the Oooguruk unit to the east of the proposed Qugruk unit, Repsol said, while the Nechelik, Alpine “A” and Alpine “C” sands are producing in the Colville River unit to the west of the proposed unit.

“All the zones are being developed by horizontal laterals with alternating producing and injection wells.”

The Kup “C” sand is a major North Slope reservoir and is produced most notably from the Kuparuk River field southeast of the proposed unit, Repsol said.

“Structure at the Kup ‘C’ level consists of an extremely large, roughly circular, four-way closure known as the Colville High,” Repsol said, and the lands proposed for the Qugruk unit are “on the northwest flank of the structure but are still nearly entirely within the area of closure.”

The Nanushuk group is divided into nine zones within the area proposed for the unit, including the Nanushuk 2, equivalent to the Qannik sand that is being developed within the Colville River unit, where Qannik sand production is south of the proposed Qugruk unit. There are six producing Qannik wells and three injection wells, with oil ranging from 27 to 32 degrees API gravity.

“To date the Qannik sand is the only sand that has been tested within the Nanushuk Group, however reservoir properties for the other Nanushuk sands are anticipated to be similar.”

Madrid-based Repsol took a position in state acreage when it picked up a 70 percent working interest in 494,211 acres assembled by Armstrong Oil and Gas of Denver (bidding as 70 & 148 LLC) and northern Alaska acreage held by GMT Exploration LLC.

Under the deal, announced in early March, the remaining 30 percent is split 75:25 between Armstrong and GMT.

Repsol’s previous interests in Alaska were in federal outer continental shelf acreage in the Beaufort and Chukchi seas.

Through to 2015? New Cook Inlet gas producers help stretch supplies for another few years

Alan Bailey
Petroleum New

With temperatures in Southcentral Alaska dropping as winter approaches, local gas and power utilities are gearing up for another nail biting few months, trying to ensure that severe cold or an equipment malfunction will not trigger power outages as utility gas supplies from the Cook Inlet basin tighten. And on Oct. 21 four utilities — Enstar Natural Gas Co., Chugach Electric Association, Municipal Light & Power and Matanuska Electric Association — provided the Anchorage Mayor’s Energy Task Force with overview of the current gas supply status.

In summary, the utilities said that the storage of summer produced gas for use in the winter has become a critical factor in the battle to ensure the availability of sufficient gas to meet peak winter demand; new Cook Inlet gas producers are starting to have an impact in the gas supply situation; and utilities will probably have enough gas to meet total annual demand until 2015, from which point the import of liquefied natural gas may be necessary to bolster local gas supplies.

More gas needed

James Posey, ML&P general manager, told the task force that recent Cook Inlet gas discoveries have not been sufficient to avert the LNG import option. Without new discoveries leading to 50 million to 80 million cubic feet per day of production “we’re nowhere out of this box,” he said.

And Colleen Starring, president of Enstar, told the task force that, with the utilities still determining the cost parameters for LNG imports, it is too early to comment on the specifics of import options. Posey said that the utilities anticipated having more information to impart some time in 2012.

Starring said that Enstar continues to negotiate long-term gas supply contracts with local gas producers. However, starting in January 2011 the company has had to tender for daily volumes of “bid gas” from qualified producers, to supplement gas obtained under the terms of contracts for guaranteed gas supplies. The future gas supply situation depends on discoveries by companies currently exploring in Cook Inlet — there has been significant investment in this exploration in the past couple of years, Starring said.

New contracts with new producers are already appearing in Enstar’s contract list for future supplies, she said.

Growing gap

Enstar sees a significant and growing gap between its current contracted gas supplies and gas demand from 2013 onwards. However, the company hopes that new Cook Inlet gas coming on line will delay any need to import LNG until 2015, Starring said. Enstar is also keeping an eye on gas pipeline options for obtaining gas from the North Slope, she said.

Meantime, Cook Inlet Natural Gas Storage Alaska, Enstar’s sister company, is forging ahead with its new gas storage facility on the south side of Kenai, on the Kenai Peninsula. CINGSA plans to start accepting gas for storage in the spring of 2012, to support the delivery of utility gas in the winter of 2012-13. At the CINGSA site the buildings have been constructed, one well has been completed, a second well is ahead of schedule and the drilling of a third well will start soon, Starring said.

At the beginning of 2011 Enstar moved to a quarterly gas cost adjustment for its customers, thus enabling the company to pass on the higher cost of winter gas, Starring said. The Enstar gas cost adjustment ranged from $7.12 per thousand cubic feet in the first quarter of 2011 to $5.74 in the third quarter.

“We’re trying to send the right price signals to customers,” Starring said.

Bid gas

Enstar now has seven companies signed up to potentially supply bid gas during the coming winter, with the company expecting bid gas to account for about 3 percent of its overall supplies. Buccaneer Energy, one of the companies that have a contract for bid gas, also has a contract to supply gas to Enstar for storage in the CINGSA facility, starting in the spring, Starring said.

It is not possible to say how much bid gas might be available to Enstar on any particular day, but on one especially cold day during the last winter the company was able to obtain all of the bid gas that it needed, Starring said.

Phil Steyer, CEA’s director of government relations and corporate communications, said that CEA uses natural gas as a fuel to meet 90 percent of its power generation needs. The company has gas supply contracts to meet its needs through 2013, possibly through 2014, with increasing unmet needs thereafter, he said. Meantime, the tightening gas supply situation has led to increasing complexity in the delivery of gas to power plants, although modifications to the pipeline infrastructure will improve the flexibility with which gas can be transported. And starting in 2012 the company will be storing some of its winter gas supplies in CINGSA’s new facility. Along with other Southcentral utilities, CEA is considering the option of importing LNG to fill gaps in future gas supplies.

CEA is working with ML&P to build a jointly owned, state-of-the-art, combined cycle gas-fired power plant in Anchorage. That plant is scheduled to go into operation by Dec. 1, 2012, and its use will greatly increase the efficiency of the two utilities’ power generation, thus reducing their gas demand from the beginning of 2013, Steyer said. And CEA’s overall retail power load has remained fairly flat, with customers power usage actually dropping in recent years, thanks primarily to improved efficiency in people’s use of energy.

Multifaceted approach

Although CEA expects to remain a gas fueled utility for some time to come, the utility is taking a multifaceted approach to meeting its long-term energy needs, Steyer said. Increments to the power capacities of the Bradley Lake and Cooper Lake hydropower systems on the Kenai Peninsula are planned, although increased power output from Bradley Lake is contingent on some transmission line upgrades on the Kenai Peninsula. Increasing the capacities of the transmission lines running north and south out of Anchorage would also allow greater flexibility in power generation. Looking further into the future, there is also the proposed major hydropower system at Watana on the Susitna River.

Posey said that, in addition to investing with CEA in the new Anchorage power plant, ML&P has been improving its own power plant, replacing turbines and some pipe work. The utility is investing in upgrades, including a new well and compressors, in the Beluga gas field, the field that it part owns with ConocoPhillips and Chevron and that forms its primary source of gas.

Turning point

ML&P expects its gas needs to drop as its power generation efficiency improves, but gas output from the Beluga field is also declining. “Our turning point is 2018, when we will turn the corner of having to buy more and more gas each year,” Posey said.

Joe Griffith, general manager of MEA, told the task force that MEA is moving ahead with a new 135-megawatt power station that the utility has been planning to build at Eklutna, at the base of the Chugach Mountains. The utility has the necessary air permit for the plant but is still seeking fuel supplies for the power generation. The plan is to use natural gas as fuel, but the generators will be also be able to operate with other fuels — MEA plans to keep diesel fuel on site as a backup but is investigating the potential use of propane.

MEA is making improvements to the utility’s transmission and distribution networks, including the rebuild of some very old substations, Griffith said.

Republished with the permission of the Petroleum News.

Parnell shifts on gas pipeline, wants new look at LNG

Tim Bradner
Alaska Journal of Commerce

The gas pipeline plan may be shifting from Canada to an LNG project in southern Alaska. Gov. Sean Parnell called on North Slope producers and TransCanada Corp. to reexmine the LNG option in light of low gas prices in the Lower 48 states and the buildup of gas supply from shale gas producers.

In a speech to the Alaska Oil and Gas Association’s annual meeting Oct 27, Parnell said there is little progress to date on TransCanada’s current plan for a pipeline to Alberta, from where gas could be shipped on to the Lower 48. However, markets for LNG in Asia are strong, and the governor wants a new look at that. Various companies including North Slope producers and TransCanada have looked at LNG and exports to Asia over the years.

The state is in a contractual relationship with TransCanada under the state’s Alaska Gasline Inducment Act, or AGIA, to support the pipeline company’s current effort on a 48-inch pipeline from the North Slope to Canada. TransCanada and ExxonMobil are in a separate relationship to do engineering and feasibility work on the pipeline to Canada, which is expected to cost in the range of $40 billion.

Parnell did not commit on any additional state financial support for a pipeline to an LNG project other than $500 million already committed to TransCanada under the AGIA contract, but he did say that he would be open to a tax agreement on gas production this year, in time for the Legislature to consider in 2011, if TransCanada and the North Slope producing companies could agree to pursue an LNG project.

In a statement, TransCanada said, “TransCanada, as the licensee under AGIA, has regular conversations with different levels of the state administration on matters pertaining to the Alaska Pipeline Project. Those discussions are held in confidence under the terms of the license. TransCanada is continuing its efforts to advance the Alaska Pipeline Project to successfully transport North Slope gas to market,” the statement said.

In his comments, Parnell said, “It’s my impression that TransCanada and the producers are looking for something different, because there’s no forward movement on the pipeline to Canada. It appears the market has shifted,” adversely in North America, because of shale gas.

“I have communicated to TransCanada, ExxonMobil, BP and ConocoPhillips the frustration that Alaskans have with the lack of progress, and I want to send a signal that if the producers and TransCanada want to take a hard look at LNG, we are flexible and will support that,” the governor said.

As part of an open season held by TransCanada in mid-2010 under the AGIA contract the pipeline company offered prospective shipped the option of a 36-inch pipeline alternative to an LNG project at Valdez, in south Alaska. TransCanada said it did get offers from shippers in the open season but would not say whether the offers were to send gas to Canada or Valdez.

Since 2010, however, TransCanada vice president Tony Palmer has said that the company’s efforts are focused on the pipeline to Alberta, and not to an LNG project in Valdez.

Parnell did not specify any preference for a pipeline to Valdez or to the Kenai Peninsula south of Anchorage, where there is an existing small LNG plant owned by ConocoPhillips. Separately, the state is backing engineering work on a 24-inch gas pipeline from the North Slope to southern Alaska if the 48-inch pipeline to Canada is not built.

There is speculation in Alaska that the governor may push for the two projects to be merged, with a 36-inch pipeline built to the Kenai Peninsula. ConocoPhillips is currently planning to mothball its plant at Nikikski, near Kenai, partly because of a lack of gas supplies from Cook Inlet producing fields.

If gas were brought from the North Slope the plant would have to be expanded and upgraded.

Republished with the permission of the Alaska Journal of Commerce . Tim Bradner can be reached at This article appears in the AJOC October 30 2011 issue of Alaska Journal of Commerc Read more:

Thursday, October 27, 2011

Shell one more notch closer to getting permits

Tim Bradner
Alaska Journal of Commerce

Shell may be one more notch closer to getting final permission to explore offshore off Alaska’s northern coasts, but environmental organizations and a North Slope tribal group have filed new appeals.

The U.S. Environmental Protection Agency issued a final air quality permit Oct. 21 for Shell’s planned Beaufort Sea exploration program, one of two areas where Shell hopes to explore in 2012 and 2013.

The permit covers activities by the Shell-owned drilling vessel Kulluk and several support vessels. The permit for the Beaufort Sea is a minor source permit, which limits the Kulluk and its support ships to 250 tons of emissions per year. One of Shell’s prime areas of interest is in the Camden Bay areas of the Beaufort Sea east of Prudhoe Bay.

On Sept. 19 EPA issued two final air quality permits for Shell’s Chukchi Sea drilling using the drillship Noble Discover, which is under contract to Shell. The permits for the Discoverer allows that vessel to be used in both the Chukchi Sea and Beaufort Sea. The Kulluk’s permit allows it to be used only in the Beaufort Sea.

However, 10 environmental groups and a tribal organization from Point Hope filed appeals Oct. 24 of both final air quality permits. Earthjustice, an environmental law firm, filed the appeals to the EPA’s internal Environmental Appeals Board, or EAB. It was on behalf of the Native Village of Point Hope, Resisting Environmental Destruction of Indigenous Lands, Alaska Wilderness League, Center for Biological Diversity, Natural Resources Defense Council, Northern Alaska Environmental Center, Ocean Conservancy, Oceana, Pacific Environment, Sierra Club, and The Wilderness Society.

Shell officials were not available for comment but a company spokesman said earlier that appeals of the Kulluk and Discoverer permits to the EAB were expected.

The EAB has previously reviewed draft air quality permits for Shell’s programs. Last year environmental groups appealed an earlier version of the permit to the EAB, which returned a decision last January recommending certain changes. EPA’s Region 10 revamped and reissued the permits, which have now again been appealed to the EAB.

There is no deadline for the appeals board in making its decision. Shell has said previously that it needs to make a final decision in October on whether to mobilize its vessels for the planned 2012 exploration.

EPA had also issued a draft permit to ConocoPhillips for its Chukchi Sea exploration using a jack-up rig, but on Sept. 26 ConocoPhillips withdrew the application with the intention of resubmitting it in December, EPA said in a press release.

“Shell has been in pursuit of a usable air permit for nearly five years. We appreciate that EPA Region 10 has thoroughly evaluated our program and issued a final permit for the Kulluk that is technically and scientifically sound,” Shell spokesman Curtis Smith said. “Shell has gone to great lengths to meet the goal of having no measurable impact on coastal villages, including a retro-fit of the Discover’s catalytic exhaust system and ongoing, multi-million dollar modifications to the Kulluk.”

The EPA air quality permit process was very complex and expensive for both Shell and the agency. One reason is that the Alaska Arctic permits are the first air quality permits worked on by EPA, in this case EPA’s Region 10 office in Seattle, so the agency was doing something for the time, as well as in a new area, the Arctic.

In the U.S. Gulf of Mexico the U.S. Minerals Management Service, now the BOEM, issues and administers air permits but Congress gave authority to EPA for OCS areas outside the western gulf, such as the Alaskan Arctic, the eastern Gulf of Mexico and for any leasing in off the Atlantic and Pacific coasts.

Shell plans to drill up to three wells in the Chukchi Sea using the Discover and up to two wells using the Kulluk in 2012, Smith said. Shell bid for federal Outer Continental Shelf leases in the Beaufort Sea in a 2005 lease sale and in the Chukchi Sea in a 2008 lease sale. Exploration has been held up by a variety of lawsuits and delays in permitting, and despite the appeals the company believes it is now making progress toward a goal of drilling in 2012, Smith said.

On another front, Shell received approval on its Beaufort Sea exploration plan from the U.S. Bureau of Energy Management but the permit has been appealed by a coalition of environmental groups to the U.S. 9th Circuit Court of Appeals. A draft exploration plan for the Chukchi Sea is before the BOEM now, and the agency has only recently been able to begin work on it.

Previously the leases issued in 2008 had been held up by a federal court injunction in a lawsuit brought by environmentalists over claims of defects in the original Environmental Impact Statement for the lease sale. The BOEM has revised the EIS and the injunction has been lifted, but there could be further appeals.

Exploration in the Beaufort and Chukchi Seas is important because both regions are highly prospective for oil and gas. In the Beaufort Sea Shell will drill in an area, near Camden Bay east of Prudhoe Bay, where a previous oil discovery has been made, although it was not economic.

In the Chukchi Sea the company will drill a prospect on which Shell previously had leases, explored in the early 1990s and made a large gas discovery, although also not economic at the time.

Gov. Sean Parnell and other state officials believe the Arctic offshore regions where Shell, ConocoPhillips and other companies want to explore has good prospects for increasing the amount of oil moving through the Trans Alaska Pipeline System, which is now operating at less than a third of its capacity.

The Camden Bay area particularly has potential for additions to TAPS liquids “throughput” because Shell’s prospects are 15 miles to 20 miles offshore and any oil production brought ashore through a subsea pipeline could be moved to TAPS through pipelines that now extend east of Prudhoe Bay.

This article appears in the AJOC October 30 2011 issue of Alaska Journal of Commerce

Republished with the permission of the Alaska Journal of Commerce.

South to the Future: North Dakota’s Oil Boom Series

KTUU's Steve MacDonald just returned from North Dakota and is working on a three-part series about their Oil Boom and the impact on Alaska. It might be a series you'll be interested in watching. The series will air Monday-Wednesday on the Channel 2 NewsHour at 6pm.

North Dakota is fast becoming one of the largest producers of crude oil in North America. For years, a huge oil field in western North Dakota sat idle until the state lowered taxes, giving oil companies the incentive to invest. Now business is booming. As production at Alaska’s Prudhoe Bay slows, oil workers are beginning to follow the jobs to the North Dakota prairie. Channel 2’s Steve MacDonald recently visited the flourishing region to answer the questions Alaskans need to know: Are Alaska’s oil jobs going south? Is North Dakota’s gain our loss? What does is all mean for Alaska’s future?

Starting Monday October 31st at 6pm on the Channel 2 NewsHour, Steve will introduce us to Alaskan’s seeking opportunity amid the North Dakota oil boom. Throughout the week Steve will explore the jobs migration, oil taxes and small town North Dakota’s growing pains. Don’t miss this unparalleled look at one of Alaska’s most pressing issues.

Sunday, October 23, 2011

NANA, NovaGold sign joint-venture deal to explore for minerals

Tim Bradner
Alaska Journal of Commerce

A long-anticipated agreement on minerals exploration in Northwest Alaska has been signed.

NovaGold Resources Inc. of Vancouver, British Columbia, and NANA Regional Corp., the Kotzebue-based Alaska Native regional corporation, have agreed jointly explore and develop base metals discoveries on lands held by NANA at Bornite, on the upper Kobuk River east of Kotzebue, and by NovaGold in the Ambler Mining District, which is further east but nearby.

NANA’s board gave approval to the joint-venture agreement earlier this year but the deal was not finalized until late Wednesday, Lance Miller, NANA’s vice president for natural resources, told the Resource Development Council Thursday.

NovaGold’s holdings are on state lands while NANA’s lands are its own, selected under the 1971 Native claims settlement act, and patented mining claims that were purchased.

The NovaGold land holdings include the Arctic deposit, a high value copper discovery made originally by Kennecott Minerals and sold to NovaGold. On its lands, NANA owns the Bornite copper deposit, also a discovery made by Kennecott and subsequently sold to NANA.

The two known deposits are about 20 miles apart. Both NovaGold and NANA had active exploration programs in 2011.

Separately, the state of Alaska is doing preliminary feasibility work on an approximate 200-mile road to the Ambler Mining District from the Dalton Highway, an existing road from Interior Alaska to the North Slope. The road is intended to facilitate mineral exploration and mine development in the region.

In addition to work on the Arctic and Bornite discoveries, other mining companies are exploring two other base metals discoveries in the region, the Sun deposit owned by Andover Ventures Inc. and Smucker, a deposit owned by Teck Alaska. Sun is in the eastern part of the Ambler Mining District, while Smucker is in the west.

NANA is also engaged with Teck Alaska at the Red Dog Mine, a large lead/zinc mine in the DeLong Mountains in the western Brooks Range. Red Dog now produces about 1 million tons a year of lead-zinc concentrates. NANA is the land and royalty owner.

“The agreement consolidates NovaGold’s and NANA’s land holdings into an approximate 180,000-hectacre (446,000-acre) land package and provides a framework for the exploration and development of this high-grade and prospective poly-metallic belt,” NovaGold said in a press release Tuesday.

The Arctic deposit holds indicated mineral resources of 17 million tonnes grading 4.1 percent copper and 6 percent zinc plus gold, silver and lead. Expressed in terms of copper-equivalent, a way of representing the value of the combined metals, the deposit is 8.3 percent copper-equivalent. “The Arctic deposit is regarded to be one of the highest grade undeveloped volcanogenix massive sulfide deposits in the world,” NovaGold said in its press release.

The Bornite deposit is estimated at about 50 million tons of ore with copper grades of 1.2 percent to 4 percent.

This article appears in the AJOC October 23 2011 issue of Alaska Journal of Commerce

Republished with the permission of the Alaska Journal of Commerce.

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CIRI continuing work on underground coal gasification; seismic survey planned

By Tim Bradner
Alaska Journal of Commerce

Cook Inlet Region Inc. is continuing its work on a potential commercial-scale underground coal gasification project, the first in North America, and will begin a high-resolution shallow seismic survey at a proposed site for the project in November.

Ethan Schutt, vice president for lands for CIRI, told the Alaska State Senate's natural resources committee Thursday that CIRI is working on lands it owns about 60 miles west of Anchorage and that geologic modeling, completed on a basis on 13 test core holes, has confirmed presence of thick coal seams below the 600-foot depth. This is the depth at which CIRI would target an underground gasification project.

CIRI has now commissioned a high-resolution shallow seismic program, the data from which will allow modeling to be completed, Schutt said. Three seismic survey lines, each eight miles long, will be done, he said.

Underground coal gasification involves combustion in a deep coal seam with production of a synthesis gas, a mixture of hydrogen and carbon monoxide, up a production well from the coal seam. The combustion is regulated by air injected through a separate well.

Synthesis gas would be used either in power generation or, through a process of upgrading, in the manufacture of a synthetic natural gas or other products, Schutt said. Synthetic natural gas would be almost identical to the gas used by Enstar Natural Gas Co. in its system and could be a substitute for that gas.

The coal resource is very large, Schutt said.

“CIRI has identified about 300 million tons of coal in the project area, which is the equivalent of 4.8 trillion cubic feet of gas,” he said.

The gasification technology can be scaled up in increments, so it can start small and be expanded. Based on conceptual work so far the company believes it can supply a synthetic natural gas to the local market for less than prevailing prices, Schutt told the legislators.

Utilities in Southcentral Alaska are now purchasing natural gas from producing companies for prices of about $6 to $8 per thousand cubic feet.

Republished with the permission of the Alaska Journal of Commerce

This article appears in the AJOC October 23 2011 issue of Alaska Journal of Commerce
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Tom Barrett, President of Alyeska Pipeline Service Company addresses the Alaska Federation of Natives

Part 1

Part 2

Thursday, October 20, 2011

Ormat has a setback on geothermal project

Tim Bradner
Alaska Journal of Commerce

Ormat Technologies has suffered a setback at its proposed Mount Spurr geothermal project 75 miles west of Anchorage. The company has disappointing results from drilling of a 4,000-foot test well and is now reevaluating the project, according to Paul Thomsen, Ormat’s director of business development.

“Drilling results are discouraging. The rock type found (conglomerate) is inferior for geothermal development than the rock type (volcanic) that we anticipated based on all available data, and the temperature gradient measured was lower than expected,” Thomsen said in an e-mail.

“Volcanic rock has a higher heat capacity, meaning it can hold heat better, thereby increasing reservoir temperature,” he added. “While this undoubtedly represents a setback to our planned exploration and development, we will continue to analyze the data, together with the data collected in 2010 and with other available data, and will file a report by the end of the year,” with state agencies.

Ormat has been working with the Alaska Energy Authority on the project. AEA has provided grants to help fund the exploration work, although Ormat has invested several million dollars of its own money in the project.

Ormat concluded its 2011 summer drilling and demobilized its drill rig in August. The company encountered some difficult drilling conditions as well as weather delays and was forced to stop slightly short of its target depth of 4,100 feet. The depth actually drilled was to 3,988 feet, Thomsen said.

Ormat was hoping to develop the state’s first commercial-scale geothermal project at Mount Spurr. The first phase would have provided 50 megawatts of power to the Southcentral Alaska power grid, but the plan was to eventually scale it up to 100 megawatts.

Thomsen told a state legislative committee last January that the shallow core holes drilled in 2010 showed evidence of water mixing with hot geothermal fluids, and evidence of multiple geologic faults that could accommodate geothermal resources. Ormat had also obtained geochemistry indicating higher temperature resources at depth. The deeper core test planned for 2011 was to confirm that resource, Thomsen told the state House and Senate Resources committees on Jan. 24.

The final report on the 2011 drilling will, “summarize our conclusions and our recommendations moving forward,” Thomsen said. The Alaska Energy Authority has provided a $2.1 million grant to the Mount Spurr project, which was matched with $2.1 million by Ormat. Ormat’s own investment is substantially higher, though.

Additional state grants were approved for the 2012 program, which was to involve the drilling of test production wells.

Unlike wind power, which is intermittent, a geothermal project is steady. Because of this there are fewer problems with the integration of geothermal power into a power grid compared with wind.

This is the second setback this year with an Alaska geothermal project. Nannek Electric Association has had to terminate a planned geothermal project in its service area when drilling and financial problems developed with a test drilling program.

Tim Bradner can be reached at
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Savant takes over as operator of a North Slope field

Tim Bradner
Alaska Journal of Commerce

Savant Alaska LLC has taken over as operator of the small Badami field east of Prudhoe Bay.

The previous operator, BP Exploration Alaska Inc., announced the change Oct. 16 in a communication with its employees.

Savant, based in Denver, Colo., has been redeveloping and drilling new wells at Badami, which is 25 miles east of Prudhoe, under a “farmout” arrangement with BP negotiated in 2008. BP developed Badami in 1998 and then shut the field in 2003 due to poor well performance and reservoir complications.

BP worked with the wells and restarted operations temporarily, and then suspended production again. The reservoir geology at Badami turned out to be more complex than anticipated.

Savant and Arctic Slope Regional Corp., its partner, began production again in late 2010 under the farmout with BP. Savant and ASRC drilled horizontal sidetrack wells from vertical wells drilled earlier by BP and also drilled a separate exploration well, which was successful.

Badami is currently producing about 1,500 barrels per day, Savant Vice President Greg Vigil said recently in an interview.

“Savant will now assume operation of the Badami plant and associated surface facilities that have been operated by BP and which were restarted in November 2010,” BP said in a notice sent to its Alaska employees. BP will continue to operate the field and provide support through a transition period, the company said.

“This is a good outcome for BP, Savant and the state of Alaska. BP will now be able to focus on its core North Slope assets,” BP said in the announcement.

The 25-mile Badami pipeline connecting the field to the Trans-Alaska Pipeline System is being operated at rates below its capacity, but the pipeline is considered key infrastructure that will be important for future development in the eastern North Slope and offshore federal Beaufort Sea leases where Shell plans to explore in 2012.

ExxonMobil and its partners, which include BP, are developing a gas cycling and condensate production project at Point Thomson, about 60 miles east of Prudhoe Bay and 35 miles east of Badami. That project will produce about 10,000 barrels per day of liquid condensate and transport it through a new pipeline that will connect with the existing Badami pipeline.

Meanwhile, Shell hopes to drill offshore exploration wells in 2012 in Camden Bay, which is north of Point Thomson. If a commercial discovery is made, the oil will be brought ashore and shipped to the trans-Alaska oil pipeline through the existing pipelines built east from Prudhoe Bay.

Tim Bradner can be reached at
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Sunday, October 16, 2011

ANCSA paved way for Alaska Natives, state to prosper together

Andrew Jensen
Alaska Journal of Commerce

A young Alaska Native looks down to read his protest sign Sept. 10, 1969, as a group of disgruntled people demonstrated outside Sydney Auditorium here as the oil-rich North Slope lands were being leased by the state.
AP Photo/Barry Sweet

Editor’s note: This story was originally published in the Journal in October 2010.

U.S. Fish and Wildlife Services enforcement officer Harry Pinkham got more than he bargained for when he arrested a couple Iñupiat hunters for shooting ducks around Barrow in May 1961.

Hunting migratory waterfowl from March to September was barred under a 1915 treaty between the United States and Canada, but had never been enforced in the Arctic until shortly after Alaska became a state in 1959.

After two arrests locally for illegal hunting, Charlie Edwardsen and his cousin, on instructions from his grandfather, proceeded to shoot as many ducks as they could, and later that evening 138 Iñupiat men summarily presented the ducks to Pinkham at his hotel and demanded to be arrested, according to the book, “Take My Land, Take My Life,” by Donald Craig Mitchell.

The charges against Edwardsen’s uncle, John Nusunginya, and Tom Pikok, another Inupiat, were dropped and Fish and Wildlife Services backed off its enforcement efforts.

The Barrow “duck-in,” as it came to be known, would not be the last time Edwardsen was heard from, or the last time Alaska Native solidarity would carry the day against the power of the government.

The duck-in, in addition to an audacious federal proposal to use a nuclear blast to form a harbor in Point Hope (later shelved) and an equally controversial project to build a large dam on the Yukon River at Rampart (flooding a huge area in the Yukon Flats), helped unify Alaska Native people in a quest for land rights.

The duck-in, the proposed nuclear blast motivated the Inupiat people of the Arctic to assert their rights, as did Rampart Dam in Interior Alaska.

In the Arctic, Edwardsen helped form the Arctic Slope Native Association which filed the first large aboriginal land claim, covering all of northern Alaska. This was to start a series of similar large land claims across Alaska, which soon blanketed the state.

Ten years later, President Richard Nixon signed the Alaska Native Claims Settlement Act, or ANCSA, a landmark piece of American legislation that for the first time wove the right to self-determination into the resolution of aboriginal land rights.

The act, now almost 40 years old, settled Native land claims with 44 million acres and $962 million paid over 11 years from the U.S. Treasury and income from oil revenue. Rather than model the act on the reservation system of the Lower 48, with Native Americans still living under the control of Bureau of Indian Affairs, 13 regional corporations and about 200 village corporations were formed to manage the funds and land to provide economic opportunity and integration for Alaska Natives.

“It’s quite remarkable what was accomplished, especially when you see where these guys came from,” said University of Alaska Anchorage professor Willie Templeton, who is also director of Native Student Services. “They did not allow Alaska Natives to be a marginalized population. When you look at the future development of the state, the Alaska Natives are at the table. We play a major role in the development of the state and the success of the state is going to be dependent on the success of the Native corporations.”

Shares of stock in the corporations were issued to 80,000 Alaska Natives, and more than 100,000 Natives are shareholders today. In 2008, some $171 million in dividends were paid, representing 66 percent of net income to the regional corporations.

Income for the 12 regional corporations in 2008 was $6.9 billion, double the revenue of just four years earlier, boosted by billions in federal contracting dollars awarded through the Small Business Administration’s 8(a) program.

Since 1970, according to socio-economic research performed by the University of Alaska, inflation-adjusted income has grown by 50 percent to $42,703 and the proportion of Alaska Natives living below the poverty line has declined from 47 percent to 22 percent.

Native healthcare has also improved dramatically through the Alaska Native Tribal Health Consortium, the Southcentral Foundation and the development of telemedicine to provide care in remote villages.

“I don’t think we realize how fortunate we are until you go down and see how they do it in the (Lower 48),” Templeton said. “We may not agree with some of the decisions our leaders make, but we definitely have more control over our lives than other Native people in a general sense. That’s not to say we don’t have challenges. But the point is I’m confident we have the talent growing up in the Native community that we can meet those challenges.”

In a way, ANCSA has been more important to Alaska than the Statehood Act itself.

From statehood in 1959 to the signing of ANCSA in 1971, Alaska had been stuck in a kind of development purgatory. It was largely unable to select the 103 million acres promised from the federal government when Alaska joined the Union because the entire state was subject to Native land claims, and Interior Secretary Stewart Udall had imposed a freeze on all land transfers to force a settlement of the claims.

Shortly following statehood, Alaska did successfully select land for oil and gas development in Cook Inlet and the North Slope, and began collecting millions in royalty income. Not long after, the nascent Alaska Native activist movement began challenging every state land claim.

At the U.S. Department of the Interior, responsible for settling Alaska’s land selections, an unofficial “drawer veto” policy took effect. If an outstanding Native claim existed on the lands selected by Alaska, the state request went in a drawer and no action was taken — much to the consternation of the state’s leadership and its Congressional delegation.

The widely held belief that Alaska Natives neither deserved nor had use for the tens of millions of acres they claimed, and their dogged insistence to the contrary, created years of impasse.

While progress toward a fair settlement of land claims moved haltingly throughout the mid-1960s, the time was not wasted among the Native community, as organizing thrived from Southeast to the Arctic. Their political clout and savvy grew, and bolstered by the Tundra Times newspaper and editor Howard Rock, so did unity and Native awareness.

The organizing efforts of Emi Notti, the president of the Cook Inlet Native Association, culminated in 1966 in Anchorage, where 300 Native leaders from across Alaska arrived to begin crafting their own proposals for settlement of land claims.

After learning that politicians and bureaucrats in Washington, D.C., were attempting to craft a settlement without Native input, Notti has sent letters to 14 Native organizations inviting them to a meeting in Anchorage. Rock picked up the letter and featured it in the Tundra Times, and the impressive show of support in Anchorage led to the formation of the Alaska Federation of Natives, with Notti as its first president.

Notti recalled those early meetings in an interview with the University of Alaska Anchorage celebrating the 30th anniversary of ANCSA: “It was hard to get people to start trusting each other. We would hold meetings from 8 o’clock in the morning until 10, 11 o’clock at night. They were wide open; everybody had a say. We would vote on issues, it was hard to get everybody to work toward consensus.

“With these open meetings, people started trusting each other; they all had a say and they were all treated with respect. Even if we had great differences of opinion, we arrived at a position, issue by issue — the amount of land, the amount of money … After a lot of arguments and discussion, we arrived at our positions and marched on to Congress.”

There was not much enthusiasm for the AFN proposal in Congress, the White House or in Juneau, but Alaska Natives did have the support of some key state legislative figures such as state House Speaker Mike Gravel, whose whirlwind campaign through 124 Native villages in 24 days nearly propelled him to an unlikely upset of four-term Congressman Ralph Rivers in the 1966 Democratic primary.

Charlie Edwardsen, who was helping energize the land claims movement in the Arctic, was a legislative page for Gravel in Juneau that year when he met Willie Hensley of Kotzebue, another emerging Native leader who wrote the seminal paper on Alaska Native land claims for a constitutional law course at the University of Alaska Fairbanks. Hensley was a founder of Northwest Arctic Native Association, which became NANA Regional Corp. after ANCSA passed, and eventually served as its president.

Hensley, who’d been in school at George Washington University, met Notti and other Native leaders during that fateful year of 1966 that witnessed the formation of AFN.

Yet for all their organizing prowess and emerging political stature, it was the discovery of oil in Prudhoe Bay by Atlantic Richfield Co. and Humble Oil Co. in 1968 that injected the need to settle Alaska Native claims with a new sense of urgency.

With a plan envisioned to build a pipeline from the North Slope to Valdez needing thousands of acres and miles of right-of-way crossing Native lands, Gravel, by then elected to the U.S. Senate, held firm in standing for a claim settlement first before the project could move forward.

“(Gravel) was insisting that, ‘you’re not building this thing until the land claim is solved,’” Templeton said.

Ted Stevens was also in the U.S. Senate by that time, having been appointed to fill the vacancy left by the death of Sen. E.L. (Bob) Bartlett. Gravel and Stevens worked together with Native leaders for passage of the claims act.

ANCSA was signed in 1971. Construction of the Trans-Alaska Pipeline System began in 1974 and was completed in 1977. The effect on Alaska was nothing short of transformational.

In 1976, the gross state product was $8 billion and Alaskans earned $5 billion in personal income taxed at 14.5 percent, the highest rate in the nation. Nearly 40 years later, oil revenue provides nearly 90 percent of state revenue, Alaskans no longer pay state income tax, gross state product has swelled to $39 billion and state residents earned $25 billion in personal income.

“Alaska Natives gave this state the ability to prosper in that settlement,” Templeton said.

The greatest gift, of course, from leaders like Notti, Hensley and Rock was to Alaska Natives.

“They really have passed on something to us, the next generation,” said Templeton, who was 15 when ANCSA passed. “They got us to the table and kept us from being marginalized. It’s our job to maintain what they have given us. We are players. We have a future in this state. That’s something it did that sometimes we don’t recognize. It maintained the sense that we have a future.”

Andrew Jensen can be reached at
Republished with the permission of the Alaska Journal of Commerce

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Enough gas — just; Enstar will continue to need ‘just in time’ bid gas during coming winter

Alan Bailey
Petroleum News

Southcentral Alaska gas utility Enstar Natural Gas Co. continues to face a tight gas supply situation but anticipates having sufficient gas to see it through the coming winter, Mark Slaughter, Enstar’s manager of gas supply, told the Regulatory Commission of Alaska on Oct 12.

Enstar obtains the bulk of its gas through what are termed “firm” contracts, in which gas producers guarantee to supply contracted volumes of gas. Under this type of arrangement, the producers are responsible for ensuring that gas flowing from their gas fields and available from their gas storage facilities is sufficient to meet contractual obligations.

Bid gas

During the winter of 2011-12 Enstar anticipates obtaining 97 percent of the gas that it needs through these firm contracts, with the utility obtaining the remaining 3 percent of its supply through a new gas bidding system introduced in January 2011. Under this system, on a day-to-day basis the utility requests bids from qualified gas producers to supply additional gas, with the utility normally accepting the lowest price bid. The bid system operates, in effect, as a small scale spot market for Cook Inlet gas, allowing producers to compete for gas sales and set market-based gas prices.

A producer participating in the bid system requires an RCA approved contract with Enstar for that participation. Last winter three producers participated and the system worked quite well, with bid gas accounting for 4.3 percent of Enstar’s gas demand in the first quarter of the year and accounting for 10 percent of the demand on a typical cold winter day, Slaughter said.

Although the gas supply contracts assumed a bid gas price of $12 per thousand cubic feet, competitive bidding resulted in an average price around $9, he said.

Declining production

Gas production from gas fields in the Cook Inlet basin continues to decline, but a new source of supply from Anchor Point Energy’s North Fork gas field on the Kenai Peninsula, coupled with the availability of gas put into storage by gas producers during the summer, will offset that decline. However, there is uncertainty about the situation regarding the closure of the Nikiski LNG plant on the Kenai Peninsula — closure of that plant could make available more gas for utility use, Slaughter said.

Chevron subsidiary Unocal is bringing a new gas storage facility on line in the Ivan River field. Cook Inlet Natural Gas Storage Alaska is building a new gas storage facility near Kenai, but that facility will not be available to support winter supplies until the winter of 2012-13.

Enstar also has agreements with power utilities Chugach Electric Association and Municipal Light & Power to curtail sales of gas-generated power to Fairbanks utility Golden Valley Electric Association during days of high winter demand. And in October there will be a test of the Energy Watch system, in which Southcentral gas consumers are encouraged to reduce demand as much as possible during severe winter cold.

Demand and supply

In the coming winter, the new supply contract with Anchor Point Energy will add up to about 7 million cubic feet per day of gas to Enstar’s firm supplies. However, that increase will be somewhat offset by a natural increase in gas demand from Enstar’s customers and an increase in demand resulting from the return to Enstar on Oct. 1 of some commercial gas supply contracts with the military. The upshot of all of this is that Enstar expects its overall usage of bid gas on a typical winter day to drop from 10 percent to about 7.9 percent of its overall demand in the first quarter of 2012.

However, because Enstar’s annual gas demand is increasing, the utility anticipates purchasing an overall slightly higher total volume of bid gas in 1012 relative to 2011.

At the same time, the number of producers participating in the bidding system has increased to seven, thus presumably reducing the risk of a shortfall in gas supplies.

Available gas

New participants in the system all potentially have gas supplies available for bid at some point in the winter, Slaughter said. Buccaneer Energy, for example, is in the process of hooking up its new Kenai Loop gas field, with production from there expected to start in December. Cook Inlet Energy plans to drill several new gas wells in the basin during the fall and has interests in fields operated by Aurora Gas. Anchor Point Energy already has an Enstar contract that includes provision for the supply of bid gas, and Aurora Gas operates several gas fields.

As part of its winter planning Enstar has to model a possible but very unlikely worst-case winter day, in which severe cold would drive absolute peak utility gas demand. Under this type of scenario, Enstar anticipates the possibility of needing somewhat more bid gas in 2012 than the utility had planned on for a similar scenario in 2011.

Republished with the permission of the Petroleum News

Escopeta reaches stopping point for KLU, planning future work

By Eric Lidji

Escopeta Oil Co. has completed the first stage of drilling at its Kitchen Lights Unit No. 1 well and now must wait for word from the state before it can continue to total depth.

Escopeta recently reached a depth of 4,933 feet at the offshore well in the Cook Inlet, the depth where the state asked the company to temporarily stop work. “We’re at Checkpoint Charlie right now,” Escopeta Strategic Officer Steve Sutherlin said on Oct. 12.

Sutherlin is a former Petroleum News reporter and a minority owner of the company.

Although Escopeta intends to drill KLU No. 1 to 16,000 feet, the Alaska Department of Natural Resources told the company to pause at 4,800 feet while it “evaluates and determines the reasonableness and prudence of moving forward with additional drilling,” according to a Sept. 2 letter from Division of Oil and Gas Director Bill Barron.

After logging the well at its current depth, Escopeta plans to open the existing 12 and 1/4-inch wellbore to 17 and 1/2 inches and then run the 13 and 3/8 inch cement casing.

Drilling could continue this year

Escopeta could conceivable continue drilling this year, but only if the company and the state both feel comfortable with moving forward this fall, Sutherlin said. The company recently performed a successful test on its blowout preventer equipment, he added.

It remains to be seen how the state-requested delay will impact state-imposed deadlines for Escopeta to reach a total depth by this fall or lose the unit, but Sutherlin said the company is operating on the assumption that the sides will come to an agreement and noted that Escopeta officials plan to meet with state officials soon about a range of issues.

“We just want to make sure that we’re all on the same page,” he said.

Shallow gas would be marketed

Although KLU No. 1 is targeting oil, it will likely encounter shallow natural gas deposits first and Escopeta plans to make a push to bring those to market soon, Sutherlin said.

“The company’s key strategy for 2011 is to learn as much as possible about the natural gas bearing structures in the Corsair prospect, with an eye on expediting gas production,” he said. “We think that Cook Inlet exploration, in concert with efforts such as Enstar’s new gas storage facility, can avert a crippling gas supply shortage in the region.”

Escopeta began drilling KLU No.1 in the Corsair prospect using the Spartan 151 jack-up rig on Sept. 2, but a “malfunction on a downhole tool” soon after spudding caused several weeks of delays, Escopeta President Ed Oliver told Petroleum News in early October.

In addition to the Corsair prospect, the 83,394-acre offshore Kitchen Lights unit also includes the East Kitchen, Kitchen and Northern Lights oil and gas prospects.

The Spartan 151 is the first jack-up rig in Cook Inlet since 1994.

Republished with the permission of the Petroleum News

Thursday, October 13, 2011

ConocoPhillips maintenance spending up; new development down

Tim Bradner
Alaska Journal of Commerce

ConocoPhillips says it is spending a greater percentage of its budget to maintain aging North Slope oil fields this year and less on development of new oil.

Almost 70 percent of the company’s spending is going for maintenance, ConocoPhillips Alaska’s President Trond-Erik Johansen told the Anchorage Chamber of Commerce Oct. 10. That’s up from about 60 percent last year.

Ten years ago the percentages were almost reversed, with most of ConocoPhillips’ spending devoted to finding oil, he said.

Aging of the production and pipeline infrastructure on the Slope requires more upkeep but the diminished share of the budget devoted to finding new oil is of concern, and it’s mainly a result of the state’s current tax system that can take over 80 percent of any gain on a new oilfield investment, Johansen said.

Given the decline in oil moving through the Trans-Alaska Pipeline System, that’s a situation that should change. Oil moving through TAPS was down almost 7.5 percent compared to the year before, according to data from the state Department of Revenue.

Gov. Sean Parnell has proposed legislation that would change the state tax law, with House Bill 110. The governor’s bill has passed the state House and is pending in the state Senate.

“Our key problem is that oil production is dropping. We’re still spending a lot of money but it’s mostly on maintaining the steel. This doesn’t get us new oil,” Johansen said.

The urgency of this isn’t yet apparent to most Alaskans. Pipeline problems caused by the low amount of oil moving through TAPS are a worry too. During a shutdown of TAPS last January, “we were a day away from freezing up the pipeline,” when Alyeska Pipeline Service Co. workers got repairs made and the TAPS restarted, Johansen said.

Oil from any discoveries in the Chukchi Sea, which is where ConocoPhillips is now putting its new exploration dollars, will be 10 years or more in the future. There are good prospects for new oil within and near the existing producing fields, such as from viscous, or thick, oil deposits, or new satellite oil accumulations near the producing fields, but the state tax discourages this, Johansen said.

There will be an increase in new exploration on the Slope this winter, which is welcome news, but this won’t get new oil into the pipeline within five years, he said. By 2017 the TAPS flow may be so low that the pipeline will experience operating problems.

With a crude oil price of $115 per barrel ConocoPhillips’ return on new investment, what financial planners call the “marginal investment,” is only 10 percent to 15 percent.

Using this example, the state takes 75 percent to 80 percent of the profit on a new oil field investment, while the federal share is 5 percent to 10 percent, Johansen told the Anchorage Chamber.

At lower oil prices of $60 per barrel to $70 per barrel, the shares between the governments and industry is about 50-50, he said.

Norway, where Johansen is from, also has a high tax rate on oil, but not as high as Alaska under higher oil prices. At an oil price of $115 per barrel, Norway’s tax on profits from new oil investment is about 78 percent compared to about 90 percent in Alaska, he said.

Although Norway’s tax is high its fiscal system has been stable and unchanged, and the stability is something that companies can count on. In Alaska the tax system has been revamped several times in just a few years, Johansen said.

The main problem in the Alaska tax is a progressivity formula that escalates the tax rate as oil prices increase, he said. This formula has been in the tax law since Alaska switched to a net profits-type tax in 2006, but it was changed by the Legislature in 2007 so that the tax increased much faster as prices moved up.

This has created a situation where, “at high oil prices there is less profit to companies who are taking the risk,” on new investment. “This is counterproductive at a time when the companies need to be developing new, higher-cost and risky projects,” Johansen said.

This is one reason why the number of drilling rigs working to find new oil in existing fields, where the bulk of new oil is expected to be found in the near future, is remaining steady at about seven to eight working rigs, Johansen said. In North Dakota, in contrast, the number of rigs working has tripled with the higher oil prices.

Tim Bradner can be reached at

This article appears in the October 2011 issue of Alaska Journal of Commerce

Wednesday, October 12, 2011

VIDEO: Why America is Foreign Oil Dependent

Rebecca Logan with the Alliance, and Michelle Egan with Alyeska Pipeline Service Company discuss the Trans Alaska Pipeline, oil production decline, regulatory barriers, and other challenges facing Alaska.

ConocoPhillips buys Marathon’s share of LNG plant in Kenai

Tim Bradner
Alaska Journal of Commerce

ConocoPhillips has purchased Marathon Oil Co.’s 30 percent interest in the Kenai natural gas liquefaction plant the two companies have owned since 1969, a ConocoPhillips spokeswoman confirmed Oct. 11.

The purchase was completed Sept. 26 but was not announced, according to Natalie Lowman, the spokeswoman. The transaction occurs as ConocoPhillips, the operator, prepares to mothball the plant, which is expected to occur near the end of October, Lowman said.

Earlier this year the two companies announced that the plant would cease LNG production but that its facilities would be preserved to help meet regional gas needs in the future, or for a resumption of LNG exports if more gas supply becomes available.

Initially, ConocoPhillips and Marathon said they would cease LNG production in mid-year but then extended the expected shutdown to allow for additional cargoes to be shipped to Asian buyers.

“We have made four shipments since earlier this year and we are studying the possibility of making a fifth shipment,” Lowman said. “We are still working out our plans for preserving the plant facilities.”

One goal in the preservation is to keep the LNG storage tanks in a cold state.

There are three storage tanks at the facility with a capacity of storing 2.2 billion cubic feet of gas as LNG.

The plant is in Nikiski on the Kenai Peninsula, about 10 miles north of the city of Kenai and 60 miles south of Anchorage. ConocoPhillips and Marathon both supply gas to the plant with ConocoPhillips’ gas coming from the Tyonek platform at the North Cook Inlet gas field and Marathon’s gas coming from several onshore fields the company operates. ConocoPhillips is the operator of the LNG plant.

Until recently the plant supplied only Tokyo Gas and Tokyo Electric under long-term contracts, but on the termination of the long-term contracts ConocoPhillips has shipped one cargo to a buyer in China and three additional cargoes to Japan, Lowman said.

Republished with the permission of the Alaska Journal of Commerce. Read more:

Sunday, October 9, 2011

Industry criticizes BLM for paltry offer in NPR-A sale

By Tim Bradner,
Alaska Journal of Commerce

State officials say they have been told by the U.S. Bureau of Land Management that a federal lease sale planned for the National Petroleum Reserve-Alaska in December will be held on the same day, Dec. 7, that the state will hold an area-wide sale on state lands including acreage adjacent to the NPR-A.

Industry officials are meanwhile expressing disappointment that BLM will offer only 3 million acres of the 23 million-acre petroleum reserve, compared with the state’s offer of almost 15 million acres in its lease sale, and criticized the Department of the Interior for withholding parts of the northeast NPR-A that offer the best prospects for major oil discoveries.

“They have clearly let the U.S. Fish and Wildlife get the upper hand by setting aside the Teshekpuk Lake area near the coast,” said Dick Gerrard, Alaska manager for FEX LLC, in an interview. “BLM is clearly taking the easy way out to avoid conflicts,” he said.

Gerrard said he is disturbed at the precedents being set for large-scale withdrawals from lease sales of tracts near the coast.

“Once this happens the policy gets set in stone. There are many places, as we’ve seen on state lands to the east at the Milne Point and Niakuk fields, where drilling very near the coast allows for extended-reach wells to tap reservoirs a few miles offshore,” he said.

Areas south of the coast that are being offered for leasing are more prone to natural gas discoveries, Gerrard said. FEX, the U.S. Subsidiary of Talisman Energy, a major Canadian independent, has been active in NPR-A exploration but is now withdrawing.

Ken Boyd, a former state oil and gas director now working as a consultant, said much of the acreage being offered by BLM in December has been leased before by companies and relinquished due to low potential. “They (Interior) just refuse to offer the areas with the best potential,” Boyd said.

However, state geologists mapping the North Slope shale formations, which could be a source of production of oil from shale through fracturing, do show shales in the areas that BLM will offer.

Gerrard, of FEX, said, “If someone were making a resource play (for shale) they may pick up some of these leases as an option, but because the area is within NPR-A, west of the Colville River and without access to infrastructure, a shale oil development would be prohibitively expensive.”

Joe Balish, state deputy commissioner of Natural Resources, said the state would like to see BLM offer up more acreage, but is pleased that at least something is out there. “Would we like to see more? Yes. But at least this is a start,” Balish said.

Balish said the state will hold its lease sale in Anchorage on the morning of Dec. 7, and that BLM officials have told him they will hold theirs in the afternoon, also in Anchorage. A BLM spokeswoman in Anchorage said the NPR-A sale date has not officially been set because it requires publication of the sale notice in the Federal Register.

“We can say that the lease sale will be held in early December,” spokeswoman Ruth McCord said.

However, BLM has released information on the tracts to be offered. In documents released with the tract maps BLM said it is offering approximately 23 percent of the 13.4 million acres in two planning areas of the reserve that are approved for leasing.

In its lease sale, the state will offer almost 15 million acres of unleased lands in the central North Slope, the foothills region of the southern North Slope and state-owned submerged lands in the Alaskan Beaufort Sea.

“We are very focused on prospects along the Colville River that may straddle the border between state lands and the NPR-A, and we’re happy to see the BLM coordinating their sale with ours,” in the timing of the lease offerings, Balish said.

Balish said the state would include state-owned Beaufort Sea submerged lands north of the coast in its lease sale, including some offshore acreage north of the NPR-A. The state owns subsurface rights from the shoreline out to Alaska’s three-mile territorial limit.

That means the state could be leasing tracts just offshore the onshore acreage BLM has withheld from leasing. Environmental groups have pushed Interior to withhold onshore tracts near the coast because this is prime habitat for migratory waterfowl. However, the area also has some of the highest potential for major oil discoveries, industry and government geologists have argued.

Republished with the permission of the Alaska Journal of Commerce. Tim Bradner can be reached at Read more:

Saturday, October 8, 2011

Over a million!

Alyeska, PHMSA settle; Trans-Alaska pipeline operator makes work commitments in wake of PS 1 oil leak

Wesley Loy
For Petroleum News

The operator of the trans-Alaska pipeline has reached a settlement with federal regulators, who raised major safety concerns following a January oil leak at Pump Station 1.

Alyeska Pipeline Service Co. signed the settlement, or “consent agreement,” with the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration.

The deal resolves the “notice of proposed safety order” PHMSA issued to Alyeska on Feb. 1, allowing the parties to “avoid further administrative proceedings or litigation,” the consent agreement says.

The consent agreement notes, however, that Alyeska continues to dispute some of the findings in the agency notice.

The seven-page document makes no mention of a fine for Alyeska, but does say the company is subject to daily civil penalties of up to $100,000 per violation if it fails to comply with the agreement, which includes extensive Alyeska work commitments.

The settlement took effect quietly on Aug. 17.

Multiple risk conditions cited

Alyeska is the Anchorage-based consortium that runs the 800-mile oil pipeline on behalf of owners BP, ConocoPhillips, ExxonMobil, Chevron and Koch Industries.
Alyeska’s president, Thomas Barrett, formerly was PHMSA administrator.

PHMSA issued its Feb. 1 notice following an oil leak at Pump Station 1 on Alaska’s North Slope. The leak, discovered Jan. 8 in the basement of a booster pump building, forced two shutdowns of the pipeline, the longest one lasting about 84 hours.

The spill, which resulted in no oil escaping the building, was attributed to internal corrosion in some station piping. The mainline, 48-inch pipe was not involved.

PHMSA said it conducted an investigation of the Pump Station 1 leak and, more broadly, of the “safe operation” of the pipeline system.

“As a result of the investigation, it appears that multiple conditions exist on your pipeline facility that pose a pipeline integrity risk to public safety, property or the environment,” the notice to Alyeska said.

The notice focused on the pipeline’s declining throughput — from a peak of more than 2 million barrels per day in 1988 to an average of about 609,000 barrels in September — and the implications low flow has for pipeline safety, particularly during a winter shutdown.

The agency raised concerns about crude oil cooling down and water freezing inside the pipeline, about potential corrosion in inaccessible piping, and about Alyeska’s “cold restart” procedures and equipment.

PHMSA proposed a laundry list of “corrective measures,” many of which are incorporated in the consent agreement.

Alyeska’s work commitments

Alyeska spokeswoman Katie Pesznecker provided Petroleum News this statement on the consent agreement:
“We are pleased we reached an agreement with PHMSA. We are committed to working with our regulatory agencies to continue to safely operate and maintain the Trans Alaska Pipeline System. Many of the projects in the Consent Agreement are projects that have been underway for some time, including efforts to mitigate the compounding technical challenges related to declining throughput and crude oil temperatures, ongoing modifications to our cold restart plan, and work to identify and isolate or replace certain piping on TAPS. These issues are complicated, and we are engaged in ongoing discussions with our regulators so we can determine the best path to continue to safely maintain and operate TAPS. We believe the simplest solution to mitigate issues related to steadily declining throughput is to get more oil in the pipeline.”

Under the agreement, signed by Mike Joynor, Alyeska’s senior vice president of operations, the company makes numerous work commitments. Among these:

• Alyeska will replace or remove oil piping that can’t be inspected with in-line tools, known as pigs, or some other PHMSA-approved method.

This was a concern in the Pump Station 1 incident, which involved “low-flow, dead-leg” piping installed in the 1970s and encased in concrete.

Alyeska has submitted an evaluation to PHMSA of which piping is to be replaced.

• Alyeska will install an additional pig launcher and receiver on the pipeline between pump stations 5 and 10.

PHMSA had questioned Alyeska’s ability to remove inspection or cleaning pigs that might be inside the line at the time of a shutdown. A pig could “cause a plug in the pipeline” in a cold restart scenario, the agency said.

• Alyeska will study the need for increased tank capacity at pump stations as a way to “mitigate the consequences of a cold weather shutdown,” the consent agreement says.

PHMSA had raised concern about the lack of oil storage capacity particularly upstream of Pump Station 1.

Under the consent agreement, Alyeska must develop a plan for oil storage projects, if any, by Dec. 31. Possibilities include bringing existing tanks back into service, the agreement says.

• Alyeska agreed to submit a revised cold restart plan to PHMSA and pre-position certain equipment during winter. The consent agreement says an agency inspector would make a field visit to see that the necessary workers and equipment are ready.

PHMSA said Alyeska, during the January shutdown, had trouble implementing its cold restart procedures — an assertion Alyeska’s Barrett disputed.

Restarting the pipeline after an outage is always a high-stress event, even in the best of conditions.

Maintaining oil temperature

The consent agreement pays considerable attention to the problem of oil temperature.
“Alyeska has proposed several projects which are aimed at maintaining crude oil temperatures on the pipeline at a level that will allow safe cold-weather operations,” the agreement says. “Based on current operational conditions, including crude oil characteristics, Alyeska will develop a plan and timeline for implementation and completion of proposed projects designed to create sufficient time to allow for safe restart or implementation of the Revised Cold Restart Plan, and safe ongoing cold weather operations. The projects will be designed to maintain the crude oil temperatures at or above the minimum allowable temperature ... in the event of a prolonged shutdown during cold weather conditions.”

Alyeska was to submit its initial plan and timeline to PHMSA by Oct. 1, the agreement says, adding that approved projects “may not be cancelled solely for financial reasons.”

In an Aug. 1 letter to PHMSA, Alyeska provided its evaluation of the minimum oil temperature needed for safe operation of the pipeline.

As part of a recent low flow study, Alyeska said it conducted modeling, simulation and “actual flow loop testing” to determine the effects of temperature on pipeline system crude.

The study determined that if the oil temperature goes below about 31 degrees Fahrenheit, water entrained in the oil can start to freeze.

“Therefore, Alyeska has accepted the temperature of 31°F as the minimum temperature under flowing conditions for safe operation of the pipeline,” the letter said.

However, the letter added: “Taking into consideration throughput and ambient condition variables, the low flow study recommends the minimum crude oil temperature be maintained at or above 36°F. Alyeska has initiated projects with the primary purpose of maintaining the crude oil temperature at or above 36°F.”

PHMSA, in its Feb. 1 notice, said the minimum pipeline oil temperature recorded at a pump station during the January shutdown, as reported by Alyeska, was 25.7 degrees.

Republished with the permission of the Petroleum News.

Friday, October 7, 2011

ANS September production up 13.3%; North Slope crude oil volumes average 608,680 bpd, compared to 537,275 in Augus

Kristen Nelson
Petroleum News

With the exception of Endicott and Northstar, production at all Alaska North Slope oil fields was up in September over August. And August production was up over July as scheduled maintenance projects wound up.

ANS production averaged 608,680 barrels per day in September, up 13.3 percent from an August average of 537,275 bpd (compared to the July average of 462,407 bpd).

The largest volume increase was at the BP Exploration (Alaska)-operated Prudhoe Bay field, where production averaged 306,696 bpd in September, up 58,775 bpd (23.7 percent) over an August average of 247,921 bpd. Prudhoe Bay production includes satellites at Aurora, Borealis, Midnight Sun, Orion and Polaris.

The largest percentage increase month over month was at the BP-operated Lisburne field, which at 33,250 bpd was up 28.9 percent, or 7,458 bpd, from an August average of 25,792 bpd.

Except where noted, volumes are from the Alaska Department of Revenue’s Tax Division, which tracks oil production by major production centers and provides daily production and monthly averages.

Kuparuk, Alpine up

Production at the ConocoPhillips Alaska-operated Kuparuk River field averaged 137,968 bpd in September, up 3.6 percent from an August average of 133,145 bpd. Kuparuk production includes satellite production from Tabasco, Tarn, Meltwater and West Sak, and production from the Pioneer Natural Resources-operated Oooguruk and the Eni-operated Nikaitchuq fields.

Revenue’s Tax Division does not split out volumes for Nikaitchuq and Oooguruk in its published figures, but those volumes are available from the Alaska Oil and Gas Conservation Commission on a month-delay basis.

August figures from AOGCC for Nikaitchuq show a total of 196,442 barrels, an average of 6,337 bpd. AOGCC August figures for Oooguruk show a total of 186,161 barrels, or 6,005 bpd.

The ConocoPhillips-operated Alpine field averaged 83,509 bpd in September, up 2 percent from an August average of 81,849. Alpine includes satellite production from Fiord, Nanuq and Qannik.

Milne, Endicott, Northstar down

BP’s Milne Point field averaged 22,312 bpd in September, down 0.45 percent from an August average of 22,413 bpd.

The BP-operated Endicott field averaged 12,359 bpd in September, down 1.6 percent from an August average of 12,558 bpd. Endicott includes production from the Badami field on the eastern North Slope.

AOGCC August production figures for Badami show a total of 35,430 barrels, some 1,143 bpd.

Production at the BP-operated Northstar field averaged 12,586 bpd in September, down 7.4 percent from an August average of 13,597.

The temperature at Pump Station 1 on the North Slope averaged 38.8 degrees F in September, down from an August average of 45.94 F.

Cook Inlet production up

Cook Inlet production averaged 13,126 bpd in September, up 9.5 percent from an August average of 11,991 bpd. The September Cook Inlet volume is the highest Cook Inlet production has been since it averaged 13,438 bpd in October of 2008. Cook Inlet production has been in decline for more than four decades and the most recent eruptions at Redoubt Volcano, in March 2009, caused closure of the Drift River Terminal and a further drop in production. Inlet producers solved logistics issues for shipping west side production, and volumes stabilized. Cook Inlet Energy, which acquired assets of Pacific Energy Resources in Cook Inlet in late 2009, restarted production from the Osprey platform this summer. Production from the platform was shut down by the previous owner in mid-2009.

AOGCC August figures show Cook Inlet production coming from Beaver Creek (4,373 barrels for the month); Granite Point (53,710 barrels); McArthur River (119,100 barrels); Middle Ground Shoal (76,245 barrels); Redoubt Shoal (18,477 barrels); Swanson River (16,636 barrels); Trading Bay (14,459 barrels); and West McArthur River (28,730 barrels), a total of 331,730 barrels for August.

ANS crude oil production peaked in 1988 at 2.1 million bpd; Cook Inlet crude oil production peaked in 1970 at more than 227,000 bpd.

Republished with the permission of the Petroleum News

Thursday, October 6, 2011

Shell moves closer to OK for offshore drilling

Tim Bradner
Alaska Journal of Commerce

Step by step, Shell is moving closer to gaining final permission to drill exploration wells in offshore Arctic waters next summer. But, environmental groups aren’t giving up on court challenges.

Earth Justice has filed with the U.S. 9th Circuit Court of Appeals a new appeal of Shell’s exploration plan for the Beaufort Sea.

In recent developments, the U.S. Department of the Interior filed a record of decision approving a revised supplemental environmental impact statement for the Chukchi Sea OCS Lease Sale 193 with a federal district court in Alaska.

The court had ordered the agency to submit its decision on Oct. 3, which was done. As expected, Interior upheld the sale based on the new SEIS. The court will decide whether the document meets objections raised in July 2010.

All actions on the Chukchi Sea have been on hold until the litigation over the original Sale 193 EIS filed by environmental groups is resolved by the court. Once a decision is made, the Bureau of Ocean Energy Management, a part of the Interior Department, can begin work on a draft plan of exploration for the Chukchi filed by Shell.

“We believe the Chukchi plan we submitted in May is technically and scientifically sound, and we look forward to exploring this critical part of our Alaska portfolio in 2012,” Shell spokesman Curtis Smith said.

Meanwhile, BOEM has given approval for Shell’s Beaufort Sea exploration plan, but that has now been appealed to the 9th Circuit appeals court. Earth Justice filed a simple notice of appeal that will be followed up by a brief.

In May 2010 the 9th Circuit court upheld a previous exploration plan for the Beaufort that is similar to the current plan, with the exception that Shell has added additional improvements, particularly subsea oil capture and containment systems that will be in place in the event of an undersea blowout, Smith said.

The U.S. Environmental Protection Agency has also issued air permits for Shell’s drilling vessels planned to be used in the Beaufort and Chukchi seas, and those could still be appealed by drilling opponents to the EPA’s internal Environmental Appeals Board.

Smith said Shell in increasingly optimistic.

“We like the milestones we are achieving, and those are tracking our own internal goals,” he said.

Shell won’t order a mobilization for 2012 until a final “go, no-go” decision, expected later this month, but the company has already spent “tens of millions” in advance preparation work, Smith said.

The engineering and construction of the new undersea oil capping and containment system will involve an expenditure of several hundred million dollars, he said.

Shell’s Beaufort Sea primary targets are in an area near Camden Bay, east of Prudhoe Bay. The company plans to drill in an area where oil has previously been discovered, although not developed. Beaufort Sea oil is considered to be the best prospects for near-term additions of throughput for the Trans-Alaska Pipeline System because Shell can take advantage of existing pipelines built east from Prudhoe Bay to Badami.

By the time Shell possibly finds and develops oil in the area, a new pipeline will be built farther east from Badami to the Point Thomson area, where ExxonMobil, BP and Chevron are working to develop a gas cycling and condensate production project.

In the long run, the Chukchi Sea has prospects for much larger discoveries but extensive infrastructure will be needed, including a pipeline built from TAPS across the National Petroleum Reserve-Alaska and an undersea pipeline built 60 miles or farther into the Chukchi Sea.

However, Shell is also drilling where oil and gas have previously been discovered. ConocoPhillips, Statoil and Repsol also have leases in the Chukchi Sea and are planning exploration.

Republished with the permission of the Alaska Journal of Commerce. Tim Bradner can be reached at

Sunday, October 2, 2011

Work on 2 gas pipelines continues; state picking up most of the tab

Tim Bradner
Alaska Journal of Commerce

Work continues on the two pipeline projects planned to bring natural gas from the North Slope, one project an alternative in case the other falters. The state of Alaska is contributing financially to both projects to the tune of about $900 million.

The 48-inch pipeline from the Slope to Alberta under development by TransCanada Corp. and ExxonMobil Corp. is on schedule for an October 2012 application for a license to the Federal Energy Regulatory Commission, ExxonMobil and TransCanada managers supervising technical an environmental work on the project said.

Technical work done for the FERC applications is now 60 percent to 70 percent complete, officials said.

Myron Fedak, of ExxonMobil, the Alaska Pipeline Project’s Environmental, Regulatory and Land manager, and TransCanada Corp.’s Mel Johnson, pipeline director for the Alaska Pipeline Project, spoke Sept. 21 at the Alaska Oil and Gas Congress, an energy conference held in Anchorage.

The 48-inch pipeline would be about 1,750 miles long, about half of it in Alaska, and would cost $32 billion to $41 billion to construct. It could be in operation in 2020 or 2022.

The state of Alaska is contributing $500 million of a total of $700 million estimated for the cost for engineering and environmental work associated with the FERC licensing, under an agreement signed with TransCanada and ExxonMobil.

Johnson, of TransCanada, said the state’s contribution has been critical in keeping the project moving forward given the current North American gas market, which is awash in gas supplied from shale.

Johnson and Fedak couldn’t comment on the commercial outlook for the project but they acknowledged the challenges.

“Without AGIA (the state Alaska Gasline Inducement Act) and the direct involvement of the state, I don’t think we would have this level of activity under way in light of the commercial uncertainties,” Johnson told the conference.

Meanwhile, an alternative 24-inch pipeline planned from the Slope to Southcentral Alaska, pursued by a state of Alaska corporation as an alternative in case the 48-inch pipeline is delayed, has suffered one setback, although it may not imperil the project’s overall schedule.

A draft environmental impact statement, or DEIS, expected to be released this fall has been delayed and is now expected to be out after the end of the year, Dan Fauske, president of the state’s Alaska Gasline Development Corp., said during a separate presentation.

Despite the three-month delay for the DEIS, the project team is still aiming at having an open season, a period in which gas shipping contracts will be solicited, in late 2013. The state is funding ADGC’s development work on the 24-inch pipeline, which is expected to total $400 million by the time the open season is held.

The 24-inch pipeline, as now envisioned, would be 737 miles long with a 35-mile, 12-inch lateral pipeline built to Fairbanks from the route of the larger pipeline west of the Interior city. It would cost about $7.5 billion to build and could be completed by 2018.

Fauske said that if the larger 48-inch pipeline is built only the southern half of the smaller pipeline would be needed, from Southcentral Alaska to a connection with the larger pipeline in the Interior.

Johnson, of TransCanada, said there are about 135 people working on the engineering and permitting effort for the 48-inch pipeline, about half of them on loan from TransCanada and about half from ExxonMobil. The engineering efforts are being managed from two offices, with a group in Calgary leading the pipeline engineering and a second group based in Denver focused on the gas treatment plant, itself a multi-billion-dollar mega-project that would be built on the North Slope, and is needed to process the raw gas when it is produced.

A lot of the technical work this year is being focused on materials, including the testing of pipe that might be used. There is also a considerable amount of work on soils including permafrost, and which involves experts from the University of Alaska Fairbanks, among others.

On the environmental side, Fedak, of ExxonMobil, said the 2010 and 2011 work programs focused on defining wetlands, vegetation and fish and wildlife. Air quality monitoring and meteorological work, as well as noise surveys, are underway in 2011 and will continue into 2012, he said.

The environmental work has involved 150,000 man-hours of effort so far with as many as 150 people in the field at one time on various surveys.


Republished with the permission of the Alaska Journal of Commerce. Tim Bradner can be reached at