Friday, December 30, 2011

Advice on development; NPC team recommends actions to make best use of Arctic energy resources

Alan Bailey
Petroleum News

The National Petroleum Council, or NPC, has published a working document containing recommendations to Energy Secretary Steven Chu on federal policies for the development of oil and gas resources in the Arctic regions of North America. With a broad membership from the oil and gas industry, academia, Native American groups, financial organizations and public institutes, and with private funding, the federally chartered NPC provides information and recommendations for the energy secretary on matters relating to oil and gas.

An NPC Arctic subgroup with representatives from several companies involved in the oil and gas industry, including ExxonMobil, Shell, Anadarko Petroleum Corp., Chevron and Schlumberger, prepared the document, the scope of which includes some areas south of the Arctic Circle, where climatic conditions are comparable to those in the Arctic.


Exploration needed

The working document says that exploration needs to proceed now, to begin to validate the huge quantities of oil and gas resources that the U.S. Geological Survey has estimated to exist in Arctic North America. Exploration is especially urgent in Arctic Alaska, to keep oil flowing through the trans-Alaska oil pipeline in viable quantities — low and lowering oil flow rates in the pipeline threaten mechanical problems with pipeline operation as well as economic problems, as the fixed pipeline operational costs become spread over fewer and fewer barrels of oil.
“TAPS (the trans-Alaska pipeline) is a national asset that has successfully delivered billions of barrels of oil to America,” the working document says. “With the current lack of exploration and development in Alaska, this critical asset could be decommissioned sooner than forecast, as the existing North Slope oil fields continue their production decline.”

Regulatory clarity

Access to prospective areas within the U.S. Arctic needs to be encouraged by the removal of regulatory uncertainty and by limiting the endless legal challenges that currently add to that uncertainty, the document says.
“Numerous Arctic producing fields exist around the world, both onshore and offshore, which are operating safely,” the document says. “Technology and practices to prevent and mitigate environmental risks already exist and will continue to be enhanced.”

The document cites the use of low impact Rolligon vehicles and the drilling of extended reach wells as examples of technologies that minimize Arctic environmental impacts. As new Arctic challenges emerge, new innovations will be made — technology will not be a limiting factor in Arctic exploration and development, the document says.

At the same time, a coordinated approach to permitting, as in Norway or Greenland, would lead to more predictable project schedules and eliminate redundant overlaps between the functions of different regulatory agencies.

Insufficient time

Infrequent lease sales, lengthy permitting procedures, a high incidence of litigation and short drilling windows all combine to discourage exploration and field appraisal operations, the document says. And existing 10-year lease terms do not allow sufficient time to ensure sustained exploration and production in Arctic basins, especially in the offshore.
“The realistic drilling window for offshore operations in the Arctic U.S. is typically 70 to 105 days,” the document says. That compares with a typical window of perhaps up to 150 days onshore in the Arctic, and a window of almost 365 days in the Gulf of Mexico. Yet all of these regions have the same 10-year lease terms. Under the current regulatory regime it typically takes four or five years from the first permit application to complete the necessary steps to be able to drill an initial exploration well in an Arctic offshore lease, the document says.

The document recommends the adoption in the United States of a system akin to the use of Canadian discovery licenses — Canada issues a license of this type to an operator that has made a substantial hydrocarbon discovery, to enable the operator to hold a discovered field until can be viably developed, the document says. The U.S. system of lease unitization and development planning can force an operator to abandon leases that are currently uneconomic, even although the constantly changing economic climate may subsequently lead to viability.

Jones Act

The Jones Act, the federal statute that requires all goods carried between U.S. ports to be transported in U.S. flagged ships, causes the United States to lag other nations both in Arctic development and in the deployment of ice breakers, ice-resistant tankers and other Arctic class support vessels, the document says. No equivalent statute exists in Canada, for example.
“While technology exists to find and extract the Arctic energy, a viable solution should be sought to improve the inherent cost premiums associated with complying with the Jones Act,” the document says. “A more reasonable policy would enable the future development of economically sub-marginal and marginal fields.”

The document also questions the current lack of federal oil and gas outer continental shelf revenue sharing with local communities. Given that communities on the North Slope of Alaska are concerned about risks to their livelihoods from offshore oil developments, there needs to be sharing of federal revenues with those communities, the document says.

Tanker use

The document also recommends consideration of the use of ice-resistant oil tankers as a means of transporting oil from the Arctic, rather than building new pipelines across onshore areas with multiple jurisdictions.
“Presently, oil tankering through the Barents Sea is common and this tankering capability is expected to be greatly accelerated in the near future,” the document says. “In the Russian Arctic, ice-breaking oil tankers are being loaded for (oil) export to North American and European markets via an ice-resistant floating storage facility located about as far north of the Arctic Circle as Prudhoe Bay.”

Thursday, December 29, 2011

Judge dismisses government’s move to revoke BP’s probation

Tim Bradner
Alaska Journal of Commerce

U.S. District Court Judge Ralph Beistline dismissed a claim by the U.S. Justice Department that BP had violated terms of a probation order when a field pipeline ruptured and spilled oil in 2009.

BP was on probation over a series of spills in 2006 from Prudhoe Bay field pipelines that were caused by corrosion. The company paid a $20 million penalty over violations resulting from the spills.

The probation had been scheduled to end Nov. 30, 2010. The Justice Department filed its petition for a revocation of the probation Nov. 16, 2010.

In a decision released Dec. 27, Beistline found that BP did not violate terms of the probation and also released the company from probation, which had been scheduled.

Beistline held proceedings in Anchorage from Nov. 29 to Dec. 7 to hear evidence.

The 2009 spill occurred when an 18-inch field pipeline that was not in service but still containing a mixture of produced water and oil froze and ruptured, spilling an oil-water mixture on the tundra. BP cleaned up the oil spill, estimated at 362 barrels, and subsequently repaired the pipe.

In its petition the Justice Department contended that BP should have known about the freezing and blockage earlier than it did, citing a similar problem with a pipeline in 2001, and that better positioning and monitoring of sensors on the L-3 pipeline would have alerted BP to the freeze-up problem.

BP responded that the sensors were installed in 1993 for a different reason — to monitor for problems with handling natural gas in the pipeline.

The government had also claimed BP failed to adequately respond when the no-flow condition of the pipeline was discovered on Nov, 14 and the rupture and spill occurred on Nov. 29.

In his decision, Beistline wrote, “the government has failed to establish by a preponderance of the evidence that BP committed criminal negligence. While the court would prefer a failsafe system where accidents never happen, it recognized that human beings and engineering practices are not perfect and that, on occasion, unexpected or unanticipated accidents can and will happen.”

Beistline concluded BP was in compliance with industry standards in its operation of the L-3 line and that the pipeline alarm systems were operating in line with accepted standards.

The judge also noted that BP conducted a thorough investigation of the 2009 pipe rupture and had shared it with the government.

BP spokesman Steve Rinehart said, “We are pleased with the decision and appreciate the court’s attention. We know that the privilege of working in Alaska comes with a responsibility to maintain high standards. We will continue our commitment to running safe and compliant operations.”

Tim Bradner can be reached at tim.bradner@alaskajournal.com.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-January-1-2012/Judge-dismisses-governments-move-to-revoke-BPs-probation/#ixzz1hxpGCVVt

Tuesday, December 27, 2011

North Slope exploration well count drops; NSB OKs Repsol

Kay Cashman
Petroleum News

The North Slope Borough Planning Commission’s recent approval of Repsol’s ice pad permits for the coming winter exploration season carries a stipulation that allows no more than three drilling rigs to operate at the same time, even though four drilling pads were approved, effectively dropping the number of total penetrations by Repsol from 12 to nine.

In response to concerns from local residents, prior to the planning commission’s Dec. 15 meeting in Nuiqsut, Repsol had pulled its permit request for the Qugruk-3 pad, reducing its drilling pads from five to four and probable wells from 15 to 12 (see map prepared by Mapmakers in September, prior to that decision, at http://bit.ly/tC1Wev).

The commission approved a fifth pad, but it was for staging ice road construction and drilling operations (not shown on map).

Savant gets rig for half season

Drilling operations have to be complete at Kachemach-1 pad before drilling starts at the single offshore pad in the mix, Qugruk-4, which is the reason for the number of vertical wells, laterals and geologic sidetracks in Repsol’s program dropping to nine, Petroleum News sources say.
When Nabors 9ES rig is done drilling at Kachemach-1 pad, it will be moved to Savant Alaska’s eastern North Slope Red Wolf exploration pad, essentially splitting the short winter season in half.

Kachemach-1 is southwest of Kuparuk, near Meltwater. Except for Qugruk-4 pad north of the Colville unit in the nearshore waters of the Beaufort Sea, all of Repsol’s Qugruk pads are between the Colville River and Kuparuk River units. Following the Dec. 15 commission decision, the fifth rig that Repsol reserved for this winter’s drilling was being considered by Linc Energy for its five to six well program at Umiat, but Linc has reportedly decided to postpone its drilling until next winter, in part because there isn’t enough time to finalize all the details of its program.

The other oil and gas companies that initially wanted to start drilling in January but do not have rigs under contract as of Dec. 22, are Great Bear Petroleum and UltraStar Exploration. (Great Bear is the only one of the 2012 North Slope explorers planning a year-round program and that’s because its proposed four to six drilling pads are in an existing industrial corridor along the Dalton Highway, so the company is not restricted to having to use seasonal ice roads and pads.)

UltraStar has already postponed its well until next winter, but Great Bear’s intentions have been to get a rig for January drilling, so perhaps it will do a deal with Repsol?

Neither company is saying anything at this time, since negotiations, if they exist, would have just begun.

Brooks Range, Pioneer on track

With Nabors 7ES rig under contract, Brooks Range Petroleum Corp.’s plans are still on track to deepen and test its previously drilled North Tarn No. 1 well and to drill two to three appraisal wells, the Mustang No. 1 , 2 and 3, all in the newly formed Southern Miluveach unit on the western boundary of the Kuparuk River unit. (The September Repsol map mentioned above does not show final boundaries for Brooks Range units established by the State of Alaska. See Nov. 6 PN article with current Mapmakers unit map at http://bit.ly/spBC0q.)

With Nabors 27E under contract, Pioneer Natural Resources is still planning to drill two Nuna wells this winter, targeting the Torok formation. Both bottomholes are in the newly expanded Oooguruk unit.

The Alaska Oil and Gas Conservation Commission defines the wells as exploratory because they will be drilled to discover or delineate a new pool.

Following is the current well count estimate for 2012 exploration and evaluation wells, with 22 penetrations on the low side and 27 on the high side:

• Brooks Range Petroleum: 1 rig, 2-3 wells

• Great Bear Petroleum: 1 rig, 4-6 vertical wells + 4-6 laterals/sidetracks

• Pioneer 1 rig, 2 wells

• Repsol: 3.5 rigs, 9 wells, including sidetracks and laterals

• Savant 0.5 rig, 1 well




Monday, December 26, 2011

Conoco sees construction of CD-5 project in 2014, production in 2015

Tim Bradner
Alaska Journal of Commerce

ConocoPhillips Alaska Inc. will  seek corporate approval in the second half of 2012 to proceed with development of the long-delayed $600 million CD-5 project following the U.S. Army Corps of Engineers’ approval of a Colville River bridge permit Dec. 19.

The bridge crossing of the river will allow the company to develop the CD-5 oil accumulation in the National Petroleum Reserve-Alaska.

There were a stipulations attached to the permit.

“We will be evaluating the permit and the stipulations over the next couple of months, and we will then have to incorporate the stipulations into our CD-5 work plan,” ConocoPhillips spokeswoman Natalie Lowman said.

The company will seek corporate approval in the last half of the year, and will then spend about a year in engineering and planning, Lowman said. The schedule would have construction under way in 2014 and the first production from CD-5 – the first commercial oil production from the NPR-A since it was created in 1923 –  toward the end of 2015, she said.

CD-5 is expected to produce between 10,000 and 18,000 barrels per day. ConocoPhillips owns 78 percent of the Alpine field, including the CD-5 project, with a 22 percent minority holding by Anadarko Petroleum Co.

Although CD-5 is within NPR-A the subsurface mineral rights are owned by Arctic Slope Regional Corp., the Alaska Native regional corporation owned by Inuit people on the Arctic Slope, which would receive production royalties. Under federal law, however, those are shared 50-50 with the state of Alaska.

An important element in the Corps’ CD-5 decision is that the bridge and road infrastructure would ease the extension of road infrastructure to two other ConocoPhillips oil and gas discoveries farther west in NPR-A that are now part of the Mooth’s Tooth Unit in the reserve.

Phillips said the development of the two NPR-A discoveries farther west would depend on the state of Alaska’s modification of its oil production tax. Although the federal government owns the petroleum reserve, the state’s petroleum tax applies to production from the area.

In a statement issued Dec. 20, Alaska state U.S. Bureau of Land Management Director Bud Cribley hailed the Corps’ decision on the bridge permit, which was originally contested by Interior Department wildlife agencies and the U.S. Environmental Protection Agency, as an example of government and industry working together to find solutions to complex environmental permitting problems.

CD-5 was discovered in 2001 and an Environmental Impact Statement for its development, including the bridge, was approved in 2004. The project went on hold for several years while there were negotiations with local Inuit villagers over the location of the bridge. An agreement was eventually reached to change the bridge location so it would not affect subsistence fishing by the villagers.

The project was then delayed further by the Corps’ decision against the bridge permit, although it had been approved earlier in the EIS.

The concern expressed to the Corps by the U.S. Fish and Wildlife Service and the EPA was that the bridge would require extensive gravel placement that could impair wetlands and sensitive regional waterfowl habitat.

Also, the environmental agencies worried that an east-west road configuration that would result in further NPR-A development west of CD-5 would cut laterally across the northward flow of water in the wetland area, further impairing habitat.

At the urging of the two agencies, the Corps blocked the bridge permit and suggested ConocoPhillips build an underground river crossing for a pipeline and to provide support for CD-5 development by ice road in winter and by air in summer, similar to the way ConocoPhillips has developed other drillsites in the region that are cut off from road access by river channels.

ConocoPhillips and state of Alaska agencies protested the Corps’ decision, arguing that an underground pipeline crossing would create more potential hazard because of the three-phase flow through the pipeline of raw crude, gas and water could create corrosion. Above-ground pipeline on a bridge would be easier to inspect and maintain, it was argued.

After a lengthy review, the Corps agreed with that argument, along with the EPA and U.S. Fish and Wildlife Service.

Among conditions attached to the permit is a requirement that other companies be able to use the bridge for NPR-A development.

“Over the long term, the bridge at CD-5 will minimize environmental impacts in the area because it allows other companies that develop leases in the NPR-A to use the same crossing, rather than seek approval for additional channel crossings in the area,” BLM Director Cribley said in his statement.

Tim Bradner can be reached at tim.bradner@alaskajournal.com.

This article appears in the AJOC December 25 2011 issue of Alaska Journal of Commerce

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-25-2011/Conoco-sees-construction-of-CD-5-project-in-2014-production-in-2015/#ixzz1hg9ks2He

Friday, December 23, 2011

Alaska’s economy expected to muddle along in 2012

Tim Bradner
Alaska Journal of Commerce

Alaska’s economy is doing OK, muddling along, but here are key things to watch for in 2012:

• Oil prices. State Department of Revenue petroleum economists expect prices to remain strong through 2012 and 2013 at about the current $100 per barrel-plus, but continued weakness in the U.S. and world economy could bring softer prices.

That’s good for consumers – especially at the gas pump – but bad news for the state treasury. Declining oil production is expected to cause a $700 million decline in state revenues next year even if oil prices remain at current levels, and any softening of prices will cause the slide in revenues to accelerate.

Oil pays for about 90 percent of the state budget, and directly and indirectly accounts for a third of the state’s economic activity, according to University of Alaska studies.

Oil industry activity is expected to remain stable, although new projects in the existing producing fields will be down. This should be offset to some degree by expanded exploration drilling this winter, however. The industry will watch closely possible actions in the state Legislature in early 2012 in making adjustments in the state oil production tax. If changes are made it would stimulate activity in the large producing fields.

• State of Alaska. State spending is a major driver in the state’s economy and despite some uncertainty over oil revenues, the state operating and capital budgets are expected to be at ranges similar to the current year. Gov. Sean Parnell’s proposed capital budget released Dec. 15 reflects a $600 million reduction from the current year capital budget, but Parnell said he has “left room” in the capital budget for the Legislature to make additions, which it will surely do.

The capital budget usually totals several billion dollars and is spent mainly on construction. It is important to the state’s construction industry.

• Federal cuts. The federal government accounts for about a third of Alaska’s economy, and federal installations and programs are expected to be hit with budget reductions as Congress tries to rein in spending and reduce massive deficits.

• Mining activity. Minerals development is expected to remain strong, although metals prices – particularly for metals like gold, silver and zinc now produced in Alaska – may be volatile amid continued weakness in the economy. Alaska’s major producing mines are producing at expected levels and several new mines are in advanced stages of development.

Mining developments to watch include the large gold project at Donlin Creek being developed by Donlin Gold, a joint venture of Barrick Gold and NovaGold Resources; the International Tower Hills gold project near Livengood, north of Fairbanks; the large Pebble copper/gold project near Illiamna, southwest of Anchorage; and the Niblack multi-metals project near Ketchikan, in Southeast Alaska.

The Donlin Gold partners are expected to file for long-planned environmental permits in April 2012. A key factor will be a source of energy for the project. The current plan is for a natural gas pipeline to be built from Southcentral Alaska. Donlin Gold project is on land owned by Calista Corp. and The Kuskokwim Corp.

International Tower Hills is now finalizing a pre-feasibility study for its Livengood gold project, an important milestone. If the project moves to development it would be a large surface mine similar.,, and possibly larger, than the Fort Knox gold mine northeast of Fairbanks, which is now producing. Power supply is important to International Tower Hills also, and the current plan is for a long-distance electrical transmission line to be built to the mine from Fairbanks along the Elliot Highway.

Golden Valley Electric Association, the Interior electric cooperative, would supply power to the Livengood mine as it does to Fort Knox.

Pebble project partners Anglo American and Northern Dynasty Minerals are engaged in planning and continued environmental studies. At Niblack, project developers are in advanced stages of exploration to expand the base of confirmed resources. If that mine moves to development, it would be similar to the producing Greens Creek Mine near Juneau.

• Fisheries. This sector continues to be an important, traditional industry for Alaska. The annual salmon harvest always has surprises, but the estimates now are for the big Bristol Bay harvest to be similar to 2011; upper Cook Inlet to be better, and Southeast harvests, mainly of pink salmon, to be lower that this year.

The big groundfish offshore fisheries are generally stable. The Bering Sea pollock harvest is expected to be about the same as this year, and Bering Sea cod catches will be up. In the Gulf of Alaska pollock catches will be up. The winter snow crab fishery will see a nice bump in allowable catches to the highest allowable harvests in years.

Halibut catches will be down statewide as regulators restrict harvests to help the biomass rebuild, although the Southeast allowable catch will be up a little from this year. The restrictions will affect commercial harvesters as well as sports fish charter operators for whom halibut fishing is a big draw for clients.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-25-2011/Alaskas-economy-expected-to-muddle-along-in-2012/#ixzz1hO0VuP22

Tuesday, December 20, 2011

Year in Review: Oil kept Alaska going


Tim Bradner
Alaska Journal of Commerce

It’s been a good 2011 for Alaska, all things considering. We could be like most other U.S. states, bogged down in recession. Thanks mainly to oil, we’re not.

Looking at the good things first, the number of people working in Alaska continues to gradually increase. State government is wallowing in oil revenues, with North Slope crude oil prices surpassing $100 per barrel.

The state is spending that money, too. Multi-billion-dollar state capital budgets in recent years are helping the state’s construction industry. Despite the pinch of a high state petroleum tax, spending by the industry – and employment – continues to be strong, although the bulk of that is on maintenance, not projects that will produce more oil.

Beyond this and possibly into next year, however, there could be trouble brewing for petroleum. The combination of a steady 6 percent annual decline in production and 10 percent or more increase in the state budget means that big cutbacks in state spending are on the horizon unless there are very large new discoveries of oil very soon on state-owned lands.

Still on the oil front, a positive note is a surge in new exploration drilling on the North Slope this winter, which is reassuring after several years of low activity. But a cautionary note is that most of the exploration is being done by one company, Repsol, and the state is also paying for a half or more of exploration expenses through an incentive program. Also, the exploring companies — including Repsol — believe any discoveries they make will be modest in size.

If Shell and other companies get the go-ahead to explore federally owned Arctic offshore waters the discoveries could be large enough to stop the decline of oil moving through the trans-Alaska oil pipeline, but they will not contribute to state revenues.

In Cook Inlet, explorers are finding new natural gas deposits, which geologists have predicted, somewhat allaying fears of a gas shortage in Southcentral Alaska. Two of the three new discoveries made in 2011 need to be fully tested, but even if modestly successful they will make a big contribution toward security of gas supplies.

Alaska’s other industries appear steady or growing.

Mining

Mining is a real bright spot, with metals prices at high levels. Mineral exploration has increased sharply and several major new mines are in advanced stages of development planning, among them the big Donlin Creek gold project near the Kuskokwim River and International Tower Hills’ gold project near Livengood, north of Fairbanks. These projects haven’t been given approval by their owners or government regulators, but things are looking good for them.

Work also continues on the big Pebble gold/copper project near Illiamna. It will still be several years before a development decision is made, but if Pebble, which is a very large deposit, becomes a mine it will be a major economic boost to the state and Southwest Alaska, an economically depressed region. People in some local communities have concerns over environmental effects of the mine, and state and federal regulatory agencies are certain to give the project applications a through review when they are made.

New mine development will have positive economic benefits to the regions in which the mines are located, and operating mines make substantial and solid contributions to local government revenues if the mines are located within municipalities. However, mines cannot afford to pay the kind of taxes to the state government that oil producers pay.

Tourism

Tourism was better in 2011, back on the growth track after a sharp dip in 2009 caused by the national recession. Visitor numbers were up for cruise visitors, which is the engine that drives much of the Alaska tourism industry, and for independent travelers who typically fly to Alaska and make their own tour and hotel arrangements.

The visitor industry is highly seasonal and while it makes a nice contribution to local employment and municipal revenues, the industry is always subject to the uncertainties of the national and worldwide economy. There is also formidable competition from other tourist destinations including other states, which are easier to reach, and although Alaska has always had an allure pocketbook realities often have the final say. Costs for tour operators, particularly fuel, are also high in Alaska.

Fisheries and seafood

Fisheries, one of Alaska’s traditional industries, are growing. There was a good salmon harvest in 2011 and salmon prices are up significantly, which translates into more income for salmon harvesters and more shared fisheries tax revenue for coastal communities. The offshore ground fish industry appears stable. This industry, mostly involving the harvest of pollock and cod, works in federal waters off Alaska’s shores are relies on shore-based infrastructure and support services in coastal communities.

Fish harvests are subject to the uncertainties of nature, but Alaska fisheries regulators and their federal counterparts in the big offshore fisheries have good reputations for strict management to maintain the biological health of the fisheries. The numbers of fish caught will vary from year to year, sometimes in big swings, but there will always be fish.

The increasing demand for Alaska’s seafood is impressive. Domestic and international buyers seem to have really caught onto consumers’ interest in wild-caught fish, which are free of chemicals and contaminants found in many farmed fish, and this has helped push demand, and prices, upward. The surge in sales of fresh salmon from Alaska during the harvest season is a result of this trend.

Also, the economic growth in big emerging markets, particularly China, has led to a desire for more protein in diets, which has also pushed up demand for lower-value Alaska fish like pink salmon. Pink salmon prices are at high levels this year, and much of the harvest is being exported to China.

Federal spending

A major worry on the horizon for Alaska, however, is the real possibility of big cuts in federal spending. Money from the federal government, for military bases and a plethora of programs, constitutes about a third of the state’s economy (oil accounts for another third and everything else fills in the final third), according to University of Alaska studies.

As the national government deals with its deficits, cuts in spending are almost sure to be part of the agenda and Alaska will feel this more than elsewhere because the federal government presence in Alaska is bigger, on a proportional basis, than in most other states.

Tim Bradner can be reached at tim.bradner@alaskajournal.com.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-18-2011/Year-in-Review-Oil-kept-Alaska-going/#ixzz1h42E4dIx

Friday, December 16, 2011

State predicts oil production to drop to 574,000 barrels per day in fiscal 2012

By Tim Bradner
Alaska Journal of Commerce

The state revenue department estimates that oil production will decline to an average of 574,000 barrels per day for the state’s current fiscal year, 2012, from an average 603,000 barrels per day in fiscal 2011, the financial year which concluded June 30, according to the state’s annual production forecast released Thursday.

The expected rate of decline is 4.7 percent between fiscals 2011 and 2012.

The forecast is for a further decline to an average of 555,000 barrels a day for fiscal year 2013, which begins July 2012, the department said. This assumes a production decline rate of 3.3 percent.

However, state Revenue Commissioner Byran Butcher warned that the production decline could be more severe, because the department assumes that some projects now being evaluated or planned will actually move to production.

“Without these layers (of new production) the production decline could be as high as 9.1 percent,” instead of 4.7 percent, Butcher said in his letter to Gov. Sean Parnell, which accompanied the revenue forecast.

Between fiscals 2010 and 2011, production declined at 6.3 percent, Butcher said.

“The forecast includes a much greater decline from the currently producing sectors offset by potential new development from projects now under development or under evaluation. Most of the opportunities to add production are from continued satellite (field) development at Alpine, at the Nanuq and Alpine West satellites, continued developments of the Oooguruk and Nikaitchuq fields and expanded viscous or heavy oil development,” such as in the Orion satellite of the Prudhoe Bay field, Butcher said in the letter.

The Oooguruk field is operated by Pioneer Natural Resources while Nikaitchuq is operated by Eni Oil and Gas. The Alpine field is operated by ConocoPhillips.

If production rates do drop to the 550,000 barrels per day average in fiscal 2013, they are in the range where Alyeska Pipeline Service Co. has predicted operating problems with the Trans-Alaska Pipeline System. Alyeska said there are likely to be more unexpected winter shutdowns, such as occurred over a one-week period last January, as throughput continued to drop.

The pipeline company is taking steps to deal with the lower throughput issues, including the addition of heaters at critical points along the 800-mile pipeline, Alyeska President Tom Barrett has said previously.

In terms of revenues, high oil prices will push total Alaska revenues to $8.9 billion for 2012, a $1.1 billion increase over revenues in fiscal 2011, but the forecast for 2013 is for a moderation of income to $8.2 billion due mainly to expectations of lower production.

The revenue department expects ANS crude oil sales prices to average $109.33 per barrel in fiscal 2012 and remain basically stable through 2013 at $109.47 per barrel, according to the forecast.

Oil production taxes and royalties provide 90 percent of total state revenues, the revenue department said.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-18-2011/State-predicts-oil-production-to-drop-to-574000-barrels-per-day-in-fiscal-2012/#ixzz1gksXYHY4

ANS production down; Revenue says production will drop below 600,000 bpd this fiscal year

Kristen Nelson
Petroleum News

The Alaska Department of Revenue’s fall forecast, released Dec. 15 as Petroleum News was going to press with this issue, shows a sharp decrease in forecast production compared to the spring forecast, with Alaska North Slope crude oil volumes dropping below 600,000 barrels per day beginning in the current fiscal year, 2012. In the spring forecast, Revenue was projecting production of more than 600,000 bpd through fiscal year 2017.

Production is projected to average 574,000 bpd for FY 2012, dropping below the 500,000 bpd mark in FY 2020.

In his cover letter to the governor, Revenue Commissioner Bryan Butcher said North Slope production declined 6.3 percent in fiscal year 2011 and a decline of another 4.7 percent is expected in FY 2012, “assuming that the oil production included in the ‘under development’ and ‘under evaluation’ layers of our production forecast come to fruition.”

Without those layers, the FY 2012 decline could be as high as 9.1 percent, he said. For FY 2012, Revenue shows 26,000 bpd under development and 1,000 bpd under evaluation.

In a press release on the forecast Butcher said, “Alaska’s revenue outlook is strong and relatively stable this year due mostly to continued high oil prices,” but warned of the impacts of steadily declining oil production.

New oil is a crucial part of the department’s ANS forecast, accounting for 4.6 percent in FY 2012 and rising steeply to 47.2 percent of ANS production in FY 2021.

Butcher contrasted production forecasts by Revenue in fall 2007, shortly after the passages of ACES, or Alaska’s Clear and Equitable Share, when Revenue was projecting “that ANS production in 2012 would be 675,000 barrels per day. Four years later our production forecast has changed, with 100,000 fewer barrels per day anticipated in FY 2012,” he said.

Spring vs. fall

There is also a difference between what Revenue projected last spring and its fall forecast.

The final year of the spring forecast, FY 2020, shows production of 530,000 bpd; the fall forecast shows projected production dropping to 486,000 — the first projection below 500,000 bpd — in FY 2020.

One change between spring and fall is when production is expected from BP Exploration (Alaska)’s Liberty prospect east of Endicott and from ConocoPhillips Alaska’s west side CD-5 project in the National Petroleum Reserve Alaska.

In the spring, Liberty production was shown as beginning in FY 2013. The fall forecast wraps Liberty into an offshore category which includes Northstar, Liberty, Nikaitchuq and Oooguruk, and while Liberty isn’t noted separately, the first uptick in production from the offshore category comes in FY 2016, peaking in 2017. The spring forecast showed a similar pattern, with Liberty production beginning in one year and peaking in the next and the uptick volumes are similar to standalone Liberty forecast from the spring forecast, which showed a peak of 39,000 bpd.

NPR-A production, shown in the spring forecast as beginning in FY 2015, is shown in the fall forecast as beginning in 2017 and peaking in FY 2019.

Kuparuk production the same

For producing fields, only the Kuparuk forecast remains the same, 87,000 bpd in FY 2012, dropping down through 83,000 and 81,000 bpd in FY 2014, with some differences in the out years, but nothing substantial.

Prudhoe Bay stood by itself in the spring forecast; in the fall forecast it includes production from Milne Point, so while Prudhoe numbers would appear to be up, they are actually down compared to the combined Prudhoe-Milne spring forecasts.

Prudhoe is forecast to produce 276,000 bpd in FY 2012, down from 297,000 in the spring forecast. The FY 2013 fall forecast shows 269,000 bpd, down from 284,000 in the spring forecast; the downward trend (both overall and compared to the spring forecast) continues through 2020, the last comparison year.

Prudhoe Bay satellites are also forecast to produce less in the fall forecast, from 37,000 bpd in 2012 to 16,000 bpd in 2020 in the spring forecast down to 36,000 bpd for 2012 in the fall forecast and dropping off to 18,000 bpd in 2020 in the fall forecast compared to 27,000 bpd in the spring forecast.

ANS price up

While Revenue’s production forecast is down from last spring, the price forecast is up.

In the spring, Revenue projected Alaska North Slope on the West Coast at $94.70 a barrel for fiscal year 2012; the fall forecast estimates $109.33.

Revenue’s ANS West Coast price forecast is $109.47 a barrel for FY 2013 (compared to $95.79 in the spring); this fall’s forecast continues above the level forecast in the spring through FY 2016, when the trend reverses and the fall forecast drops below the spring forecast through FY 2021, the end of the forecast period shown in the fall forecast.

The fall West Texas Intermediate price forecast is below the spring forecast with the exception of FY 2014.
ANS production down

Revenue says production will drop below 600,000 bpd this fiscal year

Kristen Nelson

Petroleum News

The Alaska Department of Revenue’s fall forecast, released Dec. 15 as Petroleum News was going to press with this issue, shows a sharp decrease in forecast production compared to the spring forecast, with Alaska North Slope crude oil volumes dropping below 600,000 barrels per day beginning in the current fiscal year, 2012. In the spring forecast, Revenue was projecting production of more than 600,000 bpd through fiscal year 2017.

Production is projected to average 574,000 bpd for FY 2012, dropping below the 500,000 bpd mark in FY 2020.

In his cover letter to the governor, Revenue Commissioner Bryan Butcher said North Slope production declined 6.3 percent in fiscal year 2011 and a decline of another 4.7 percent is expected in FY 2012, “assuming that the oil production included in the ‘under development’ and ‘under evaluation’ layers of our production forecast come to fruition.”

Without those layers, the FY 2012 decline could be as high as 9.1 percent, he said. For FY 2012, Revenue shows 26,000 bpd under development and 1,000 bpd under evaluation.

In a press release on the forecast Butcher said, “Alaska’s revenue outlook is strong and relatively stable this year due mostly to continued high oil prices,” but warned of the impacts of steadily declining oil production.

New oil is a crucial part of the department’s ANS forecast, accounting for 4.6 percent in FY 2012 and rising steeply to 47.2 percent of ANS production in FY 2021.

Butcher contrasted production forecasts by Revenue in fall 2007, shortly after the passages of ACES, or Alaska’s Clear and Equitable Share, when Revenue was projecting “that ANS production in 2012 would be 675,000 barrels per day. Four years later our production forecast has changed, with 100,000 fewer barrels per day anticipated in FY 2012,” he said.

Spring vs. fall

There is also a difference between what Revenue projected last spring and its fall forecast.

The final year of the spring forecast, FY 2020, shows production of 530,000 bpd; the fall forecast shows projected production dropping to 486,000 — the first projection below 500,000 bpd — in FY 2020.

One change between spring and fall is when production is expected from BP Exploration (Alaska)’s Liberty prospect east of Endicott and from ConocoPhillips Alaska’s west side CD-5 project in the National Petroleum Reserve Alaska.

In the spring, Liberty production was shown as beginning in FY 2013. The fall forecast wraps Liberty into an offshore category which includes Northstar, Liberty, Nikaitchuq and Oooguruk, and while Liberty isn’t noted separately, the first uptick in production from the offshore category comes in FY 2016, peaking in 2017. The spring forecast showed a similar pattern, with Liberty production beginning in one year and peaking in the next and the uptick volumes are similar to standalone Liberty forecast from the spring forecast, which showed a peak of 39,000 bpd.

NPR-A production, shown in the spring forecast as beginning in FY 2015, is shown in the fall forecast as beginning in 2017 and peaking in FY 2019.

Kuparuk production the same

For producing fields, only the Kuparuk forecast remains the same, 87,000 bpd in FY 2012, dropping down through 83,000 and 81,000 bpd in FY 2014, with some differences in the out years, but nothing substantial.

Prudhoe Bay stood by itself in the spring forecast; in the fall forecast it includes production from Milne Point, so while Prudhoe numbers would appear to be up, they are actually down compared to the combined Prudhoe-Milne spring forecasts.

Prudhoe is forecast to produce 276,000 bpd in FY 2012, down from 297,000 in the spring forecast. The FY 2013 fall forecast shows 269,000 bpd, down from 284,000 in the spring forecast; the downward trend (both overall and compared to the spring forecast) continues through 2020, the last comparison year.

Prudhoe Bay satellites are also forecast to produce less in the fall forecast, from 37,000 bpd in 2012 to 16,000 bpd in 2020 in the spring forecast down to 36,000 bpd for 2012 in the fall forecast and dropping off to 18,000 bpd in 2020 in the fall forecast compared to 27,000 bpd in the spring forecast.

ANS price up

While Revenue’s production forecast is down from last spring, the price forecast is up.

In the spring, Revenue projected Alaska North Slope on the West Coast at $94.70 a barrel for fiscal year 2012; the fall forecast estimates $109.33.

Revenue’s ANS West Coast price forecast is $109.47 a barrel for FY 2013 (compared to $95.79 in the spring); this fall’s forecast continues above the level forecast in the spring through FY 2016, when the trend reverses and the fall forecast drops below the spring forecast through FY 2021, the end of the forecast period shown in the fall forecast.

The fall West Texas Intermediate price forecast is below the spring forecast with the exception of FY 2014.

Saturday, December 10, 2011

Agencies agree on bridge; Corps of Engineers decision this year

—Kristen Nelson

A roadblock to development of ConocoPhillips’ CD-5 drill site in the National Petroleum Reserve-Alaska has been removed.

The U.S. Fish & Wildlife Service and the Environmental Protection Agency, which had opposed the company’s plan to put the crude oil pipeline from CD-5 to the company’s Alpine production facilities on a bridge to be built across the Nigliq Channel of the Colville River, have reached “an agreement in principle” with the company on the proposal.

In a Dec. 5 announcement the U.S. Department of the Interior said the agreement fulfills a request from the U.S. Army Corps of Engineers that the agencies evaluate environmental impacts associated with the revised project.

Interior said the agreement in principle confirms that construction of a pipeline and bridge over the Nigliq Channel is acceptable to Fish and Wildlife and EPA “so long as the permit application includes conditions that reflect agreements reached” among ConocoPhillips, Fish and Wildlife and EPA.

“The conditions include engineering changes and substantial mitigation proposed by the company based on consultations with the resource agencies,” Interior said.

ConocoPhillips has also agreed to allow other companies that develop leases in NPR-A to use the same crossing, “rather than seek approval for additional channel crossings in the area. This approach will reduce the environmental impacts” associated with future developments west of the Colville River, Interior said.

Interior said the corps is expected to carry out remaining steps associated with the permit review in the coming weeks.

Pat Richardson, spokeswoman for the corps’ Alaska District, told Petroleum News in an email that the corps’ goal “is to have a decision this month.” She said the corps received additional information from ConocoPhillips as late as Thanksgiving week and that information must be analyzed.

“ConocoPhillips sees this as a positive step in the process of granting the Section 404 permit for the CD5 project,” ConocoPhillips Alaska spokeswoman Natalie Lowman said in a Dec. 5 email. “We have not yet seen the permit nor its conditions, but we are encouraged by today’s announcement.”

Bridge vs. HDD

The current permitting process came to a standstill in February 2010 when the corps denied ConocoPhillips Alaska permits to develop the CD-5 project, citing overriding national interests, specifically concerns about “further impacts to the aquatic resources” in the Colville River Delta, which lies just east of NPR-A.

The preferred alternative in the 2004 environmental impact statement for Alpine satellite development included a bridge and a road.

After facing local opposition over the location of the Nigliq Channel bridge in an earlier proposal, ConocoPhillips had reached resolution on local concerns about the project with changes in bridge location and an agreement to fund a road to connect the nearby community of Nuiqsut to the project’s road system, and had local support for the project.

The corps said it had determined that the pipeline should be buried under the Nigliq Channel using horizontal directional drilling, but noted that would require new permit applications.

EPA and Fish & Wildlife both opposed granting the permits.

EPA told the corps it had determined that the Colville River Delta is an aquatic resource of national importance, triggering action under a 1992 memorandum of understanding between EPA and the Department of the Army. Fish & Wildlife also told the corps it had found the delta to be an aquatic resource of national importance, and also cited a memorandum of understanding with the corps.

The CD-5 drilling pad, on the other side of the Nigliq Channel from the Alpine facilities, is not in the Colville River Delta, but 2.5 miles of the road back to Alpine and the bridges (the Nigliq Channel crossing and two smaller bridges) would be.

State opposed HDD

The State of Alaska opposed horizontal directional drilling under the Nigliq Channel, and has backed ConocoPhillips’ bridge and road proposal.

“We believe the state’s input and advocacy helped in achieving this positive outcome, and we will continue to monitor this project through the permitting process,” Alaska Gov. Sean Parnell said in a statement following Interior’s announcement.

The governor noted that the state has demonstrated in reports that the corps’ preferred alternative, buried pipelines under the Nigliq Channel, was not the least environmentally damaging alternative.

“This agreement is long overdue, but no less welcomed,” said Sen. Lisa Murkowski, R-Alaska, in a Dec. 5 statement. She said she expects the corps to now move quickly to approve the proposed bridge “and allow access to the oil and natural gas reserves within the National Petroleum Reserve.”

The senator said that she has “had numerous disagreements with the administration on Alaska issues, but I appreciate the involvement of the White House and the Interior Department in removing this particular roadblock to improving our nation’s energy security.

Murkowski noted, as she has in the past, that EPA, “without public notice or process, designated the Colville River as an Aquatic Resource of National Importance (ARNI).”

Congressman Don Young, R-Alaska, said he welcomed the announcement, but “the fact of the matter is that this should have happened sooner.” He noted the importance of the CD-5 project not only for Alaska jobs, “but also because it will put this nation on a path towards becoming energy independent.”

“This is a great way to ring in the holiday season at a time when Alaska’s oil and gas industry needs to hear some good news on the development front,” said Sen. Mark Begich, D-Alaska,

“It’s been a long and sometimes frustrating process to get to this decision,” Begich said. “I commend ConocoPhillips and the Interior Department for sticking with it.”

$25 million day; State, Bureau of Land Management, hold North Slope, Beaufort, NPR-A sales

Kristen Nelson
Petroleum News

The State of Alaska and the U.S. Department of the Interior’s Bureau of Land Management both held Alaska oil and gas lease sales Dec. 7 in Anchorage, with apparent high bids of $24,606,947 from a combination of new entrants and established players.

BLM’s National Petroleum Reserve-Alaska sale, the smallest of the sales, had 20 bids on 17 tracts by three bidders, for a total of apparent high bids of $3,637,477 on some 119,987 acres.

The Alaska Department of Natural Resources’ Division of Oil and Gas held three areawide oil and gas lease sales — Beaufort Sea, North Slope and North Slope Foothills. The state received no bids for the Foothills sale. It received 89 bids on 78 tracts from 11 bidders or bidding groups in the Beaufort Sea sale, a total of $6,874,656.80 in apparent high bids, with 281,095 acres sold. In the North Slope areawide sale, the state received 220 bids on 179 tracts from 13 bidders or bidding groups, for $14,094,812.47 in apparent high bids on 335,289 acres.

Presidential direction

The BLM sale was held in response to a May 14 direction from President Obama to Interior to conduct annual oil and gas lease sales in NPR-A.

In a release on sale results Interior noted that the sale followed the announcement that two federal agencies have reached agreement with ConocoPhillips on the proposed Alpine satellite development plan in NPR-A (see page 1 story in this issue). Interior said the bridge over the Nigliq Channel of the Colville River and the road between the proposed CD-5 drill site and the Alpine facilities would be the first pipeline and all-weather road into NPR-A, and said the existence of that infrastructure is expected to spur further exploration and development in the reserve.

“As industry begins to build infrastructure and explore and develop oil and gas in this area of the North Slope of Alaska, we expect to harness the energy and economic benefits of the NPR-A for our nation,” Interior Secretary Ken Salazar said in a statement.

Interior said the State of Alaska would receive 50 percent of the NPR-A bid receipts, some $1.8 million, as well as 50 percent of the annual rental revenue generated from the sale. An economic evaluation of the NPR-A bids is the next step; BLM expects to issue leases by mid-April.

BLM Alaska Deputy Director Ted Murphy said after reading bids that next year’s NPR-A sale would also be in the fourth quarter.

This was the sixth largest North Slope lease sale the state has held and the second largest since the areawide leasing program was begun in 1998. In recent years, only the 2006 sale ($15.7 million) was larger.

Gov. Sean Parnell said the combined North Slope and Beaufort sales, more than $21 million, was one of the most successful in recent Alaska history, and called it “an important, positive step that attracted additional investment to the North Slope.”

“Reversing the declining flow of oil through TAPS and getting to 1 million barrels per day is critical to our economy and the nation’s energy security,” the governor said in a statement following the sale.

“It was quite a respectable showing,” Commissioner of Natural Resources Dan Sullivan told Petroleum News after the sales.

He said the bids showed “there is more interest in the shale than just Great Bear,” and said he was pleased to see “very big world-class companies who know Alaska well were taking some pretty sizeable positions — Repsol, Shell, ConocoPhillips, Pioneer, Armstrong.”

“We participated in scores of meeting with oil and gas companies, investors, policy makers (leading up to the sale). … Certainly learned a lot. I would say there were some companies that I thought would show up who didn’t. It’s always hard to know why. … Perhaps high costs, but I am just speculating … tax reform, some companies might be waiting it out.”

There were no bids in the North Slope Foothills sale, and Sullivan said that was probably due to the lack of a gas pipeline.

“We’ve been relentlessly working the governor’s five-point plan, and we’ll keep on working it,” Sullivan said. “This is just the first inning of a long term strategy. … Here is the issue: We recognize the status quo is not working. A critical part of our five-point plan is tax reform. We’re going to work hard on that during the upcoming legislative session. Very hard.”

70 & 148, ConocoPhillips

Armstrong subsidiary 70 & 148 LLC bid the most across all the sales: high bids of $2,149,580.80 in the state North Slope sale (11 tracts, 37,120 acres) and $2,701,636 in the NPR-A sale (11 tracts, 62,044 acres), for a total of more than $4.8 million.

In the NPR-A sale, 70 & 148 took tracts between the ConocoPhillips Alaska-operated Greater Mooses Tooth unit and the border of state lands, matching up with the 11 tracts the company took in the North Slope sale, giving the company a substantial block across the state-NPR-A boundary.

ConocoPhillips Alaska, bidding in all three sales, took 35 tracts in the North Slope sale, 99,840 acres for $2,717,424 in apparent high bids, with the bulk of the tracts in a large block south of Point Thomson and Badami on the east side.

In NPR-A, the company took three tracts, 23,650 acres, with apparent high bids of $524,325, bringing the company’s total to more than $3.2 million for the day. The NPR-A tracts are: a tract south of company-held acreage adjacent to its Greater Mooses Tooth unit; one tract adjacent to three state tracts it holds across the NPR-A border south of Nuiqsut; and a tract which was a “hole” in a large block of acreage the company holds southwest of Mooses Tooth.

ConocoPhillips bid unsuccessfully in partnership with Exxon on one tract in the Beaufort Sea sale.

Repsol, Great Bear
Repsol E&P bid in both the North Slope and Beaufort sales

In the Beaufort sale, Repsol was apparent high bidder on five tracts adjacent to a large block of Repsol leases north of the Colville River unit, some 19,200 acres, for which it bid $376,256.

In the North Slope sale Repsol took 26 tracts, 45,920 acres, for $2,642,193.60, bringing its total to just over $3 million.

The North Slope tracts Repsol took are in two blocks, one in the central North Slope, adjacent to existing Repsol leases south of Kuparuk, and the second block adjacent to existing Repsol leases south of Kuparuk and Prudhoe Bay.

Great Bear Petroleum, which bid only in the North Slope sale, had $2,910,633.60 in apparent high bids on 32 tracts, filling in a “hole” in tracts the company took south of Kuparuk in last year’s North Slope sale.

Royale Energy

Royale Energy, a new bidder in the state, took 60 tracts in the North Slope sale with apparent high bids of $2,717,424 on 99,840 acres.

Royale took tracts in three areas: east of Great Bear Petroleum’s existing acreage; south of Great Bear acreage; and a large block of leases near the border with NPR-A.

Royale was bidding against Great Bear on some acreage and against 70 & 148 in other areas.

Shell Offshore, bidding in the Beaufort Sea sale, took 18 leases in Harrison bay, 86,400 acres, for $2,615,200.

A bidding group of Daniel K. Donkel 25 percent and Samuel H. Cade 75 percent, took 35 leases in the Beaufort Sea sale from north of the Arctic National Wildlife Refuge (near existing Donkel-Cade leases) on the east to Simpson Lagoon north of Milne Point on the central North Slope, 94,080 acres, for $1,525,760 in apparent high bids. Cade also took a single lease, adjacent to BP’s Northstar unit, 1,920 acres, $21,120.

Donkel and Cade also took three tracts in the North Slope sale, 7,680 acres, for $171,520, bringing their total for the sale to more than $1.7 million.

NordAq Energy, Cook Inlet leaseholder and explorer, took 11 tracts in Smith Bay off NPR-A in the Beaufort Sea sale, 58,880 acres for $1,356,902.40.

Woodstone Resources

Woodstone Resources of Houston, a new bidder, took nine tracts in the North Slope sale, 12,960 acres for $488,160. The tracts are all well south of existing production and include sites of three old exploration wells: Itkillik Unit 1, Nora Fed 1 and Susie Unit 1.

Woodstone was also a bidder in the NPR-A sale, and was apparent high bidder on three tracts, 34,293 acres, for $411,516, bringing its total for the day to almost $900,000 for the two sales. The tracts are in the southern area of NPR-A, adjacent to acreage held by Petro-Canada and Anadarko.

AVCG took one tract in the Beaufort Sea sale, paying $206.75 an acre, a total of $529,280 for 2,560 acres. AVCG fended off two competing bids, including one from a 50-50 bidding partnership of ConocoPhillips and Exxon, to take the tract adjacent to its Beechey Point unit. Its bid for tract 286 was the highest bid in the Beaufort Sea sale.

Savant Alaska also fended off competing bids for two tracts, these in the North Slope sale, paying $212,096 for 5,120 acres, one tract adjacent to three existing Savant tracts on the edge of ANWR and the second tract to the north on the ANWR border.

Pioneer Natural Resources Alaska had the highest per-acre bid in both the North Slope and Beaufort Sea sales, $876 per acre for small tracts at its Oooguruk unit. The company paid $118,260 for 135 acres, two tracts, in the Beaufort Sea sale, and $43,800 for 50 acres, one tract, in the North Slope sale.

A bidding group of J. Andrew Bachner 90 percent and Keith C. Forsgren 10 percent, took five tracts on east side in the Beaufort Sea sale, north of ANWR, bidding against Donkel and Cade. Bachner-Forsgren had apparent high bids on 17,920 acres for $331,878.40.

A bidding group of Alaska LLC/Gavora one lease in the North Slope sale, 1,440 acres, for $36,158.40.

State sees North Slope lease sales as modest success

Tim Bradner
Alaska Journal of Commerce

Alaska officials called the state’s Dec. 7 onshore and offshore North Slope lease sale a modest success, but expressed disappointment that several companies they courted in months prior to the sale failed to bid.

The state of Alaska received $20.97 million in high bids for onshore and offshore leases sold Dec. 7 the annual area-wide sales on unleased acreage. A federal sale in the National Petroleum Reserve-Alaska drew only a handful of bids, netting $3.06 million from three companies bidding.

Bidding was mostly by companies currently on the North Slope who expanded their acreage positions, although two companies new to Alaska, both small independents, joined the bidding.

"Today’s lease sale was an important, positive step that attracted additional investment to the North Slope,” Gov. Sean Parnell said in a statement. “Reversing the declining flow of oil through TAPS (Trans-Alaska Pipeline System) and getting to 1 million barrels per day is critical to our economy and the nation's energy security.”

"One of our immediate goals for this lease sale was to increase the number and type of investors and companies investing in Alaska,” said Natural Resources Commissioner Dan Sullivan. “We are pleased that the sale was successful in this respect, but there is certainly an opportunity to do more in the future to attract additional investment.”

Sullivan said he had made personal calls on companies in home offices urging them to bid, and followed up with visits by teams of state geologists.

“We need to go back to them and find of what was wrong,” Sullivan said.

Sullivan said he was encouraged, however, that Repsol bid to expand its existing Slope holdings, with high bids on 25 state onshore leases and five state offshore leases, including 45,920 acres. Repsol now has a 70 percent interest in about 500,000 acres of onshore North Slope lands, which it is exploring this winter.

The onshore state sale, conducted first, brought in $14.094 million in high bids for 179 tracts, while the offshore sale, in state-owned submerged lands of the Beaufort Sea, brought in $6.874 million in high bids for 78 tracts sold, state Oil and Gas Director Bill Barron said following the lease sale.

Meanwhile, the federal government received $3.06 million in high bids in a National Petroleum Reserve-Alaska lease sale held hours after the state sale. There were 20 high bids submitted on 17 tracts by three bidders in the sale, according to Ted Murphy, Bureau of Land Management’s deputy director in Alaska.

BLM had initially announced the results at $3.6 million in high bids but then released a corrected amount. Bids were submitted on 141,739 acres out of about 3 million acres of NPR-A lands offered in the lease sale.

Although the bidding was modest, “we are seeing an increased interest in the North Slope also evidenced by results of the state lease sale. This is in sharp contrast to our last lease sale,” in which there were no bids, said Bud Cribley, the Alaska BLM director.

One surprise in the sale was the return of ConocoPhillips, a producer on the Slope, to bidding for state exploration acreage. ConocoPhillips acquired 35 onshore tracts, mostly in the Point Thomson area east of Prudhoe Bay, as well as one tract east of the Alpine oil field, near NPR-A west of Prudhoe.

ConocoPhillips has been absent from onshore exploration for some years, and has focused on its planned exploration of federal offshore leases in the Chukchi Sea.

Industry observers at the sale said that ConocoPhillips’ lease acquisitions in the Point Thomson area are likely related to a pending settlement of litigation between Point Thomson Unit leaseholders, which include ConocoPhillips, and the state of Alaska. A settlement agreement was reached in September between the state and ExxonMobil, the Point Thompson Unit operator, but has not been agreed to yet by other partners in the unit, which include BP, Chevron and ConocoPhillips.

Also in the sale, three small independent companies bid have apparently won their first North Slope leases. Woodstone Resources of Houston was high bidder on nine state onshore leases and two federal NPR-A leases. Royale Energy Inc. of San Diego was high bidder on 60 onshore leases.

Alaska-based NordAq Energy, a small independent active in the Cook Inlet Basin in southern Alaska, was high bidder in 11 state offshore leases north of the NPR-A.

Armstrong Oil and Gas, a Denver-based independent that has worked on the Slope for many years, was high bidder on 11 state onshore leases and 10 federal NPR-A leases.

Great Bear Petroleum, an Alaska independent, was high bidder on 32 onshore leases in an area where the company plans a shale oil exploration project this winter. One surprise of the sale is that Great Bear faced little competition in bidding for leases that were open within its proposed shale oil play except for unsuccessful bids by Royale Exploration on some of the tracts.

This may indicate that other companies do not share Great Bear’s hopes for developing production from shale source rocks in the area, industry sources at the sale said.

Shell acquired 18 state offshore leases near Harrison Bay, south of federal Outer Continental Shelf leases held by the company. Harrison Bay is one of Shell’s target areas for exploration in the Beaufort Sea.

High bids in the state sales, which included North Slope onshore and Beaufort Sea offshore sales held, came from Pioneer Natural Resources Alaska for $876 per acre for two offshore tracts and one onshore tract. Both parcels were small and adjacent to areas where Pioneer is now working.

Individual bidders acquired offshore state leases in Beaufort Sea tracts offshore the Arctic National Wildlife Refuge and offshore state lands in the Point Thomson and Prudhoe Bay field areas.

The bidding did indicate some success for the strategy of the state and the BLM in holding their sales on the same day, an effort to facilitate bids by companies on adjacent acreage along the Colville River boundary between the NPR-A and state lands.

Armstrong and Woodstone Resources both submitted high bids on state and NPR-A tracts along the Colville River, indicating interest in geologic plays extending across the border.

This article appears in the AJOC December 11 2011 issue of Alaska Journal of Commerce

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-11-2011/State-sees-North-Slope-lease-sales-as-modest-success/#ixzz1g8MVngYg

Thursday, December 8, 2011

AOGCC proposes new regulations on blowout control plans

Tim Bradner
Alaska Journal of Commerce

The state of Alaska is considering strengthened regulatory controls on offshore drilling with a new requirement for operators to have a blowout control plan.

A recommendation to change the state’s drilling rules comes at the end of a lengthy review of the state’s drilling safety rules by the Alaska’s Oil and Gas Conservation Commission, said Cathy Foerster, one of the three AOGCC commissioners.

AOGCC is a quasi-judiciary independent state regulatory agency that oversees drilling and other oilfield safety and production practices in Alaska, including state-owned submerged lands to the three-mile territorial limit.

The Alaska Department of Environmental Conservation now requires drillers to have approved contingency plans in place to control oil spills, including large spills from a blowout. The proposed AOGCC rule would be specific to blowout control, however, and would be reviewed by the commission’s staff, where there is expertise on drilling.

The proposal came about because of concerns on the Macondo well, where a blowout preventer on the Deepwater Horizon rig failed to function. The resulting explosion and fire killed several people, destroyed the rig, and caused one of the worst oil peacetime spills in the history of the industry.

“The state of Alaska’s drilling rules, implemented through the AOGCC, were very strong even before Macondo – stronger that the federal government’s, in fact – and a detailed post-Macondo review of regulations by the AOGCC and outside experts revealed no major flaws except in one area, a specific requirement for a plan to control a blowout,” Foerster said.

Foerster said she believes Alaska is the only U.S. state to conduct a detailed review of drilling regulations following the Gulf of Mexico disaster.

The commission also is adding to its staff of inspectors and drilling engineers because of the greater scrutiny that the state is now giving drilling operations, she said.

The state commission decided to do its review because some of the problems in well safety that were identified in deep ocean wells like Macondo could also occur in ultra extended-reach wells drilled in Alaska, such as at BP’s planned Liberty project, where wells would be drilled out as much as eight miles laterally from the surface location of the drill rig.

Extended-reach wells are routinely drilled in Alaska, although not to the distances planned at Liberty. Extended-reach wells were drilled by ExxonMobil at Point Thomson and by BP and at the Milne Point and Niakuk fields near Prudhoe Bay.

Well blowouts have happened in Alaska, although they are rare. So far the blowouts in the state have been on gas rigs, not oil, and there has never been a case of oil released in an Alaska blowout reaching the land surface or open water, Foerster said.

Since 1962 there have been four offshore blowouts in Cook Inlet, all involving releases of gas, the last in 1987. On the North Slope, there have been seven blowouts that have occurred in approximately 5,000 wells drilled since the Prudhoe Bay oil field was discovered in 1967. None of them involved a release of crude oil, and none caused injuries, Foerster said.

State rules require the testing of blowout preventers every seven days on exploration wells being drilled and “workover,” or maintenance well, and every 14 days on new production wells being drilled. Test results must be filed with the commission.

AOGCC inspectors are also on-scene to witness many tests. The commission’s records indicate that state inspectors attend tests of well control systems on every active drill rig in the state once every two months. The AOGCC’s data shows a “pass rate” of 98 percent for blowout control equipment.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-11-2011/AOGCC-proposes-new-regulations-on-blowout-control-plans/#ixzz1fz4clb82

Working up from typist to executive director, Crockett retires


Tim Bradner
Alaska Journal of Commerce

Alaska Oil and Gas Association Executive Director Marilyn Crockett is set to retire. Kara Moriarty, formerly deputy director for the association, will move into the executive position. Crockett began at the organization as a typist, and over the years worked her way up the ladder to executive director.

Alaska Oil and Gas Association Executive Director Marilyn Crockett is set to retire. Kara Moriarty, formerly deputy director for the association, will move into the executive position. Crockett began at the organization as a typist, and over the years worked her way up the ladder to executive director.

Marilyn Crockett, a slip of a girl fresh out of high school, met Bill Hopkins, then executive director of the Alaska Oil and Gas Association, for a job interview. Marilyn could type very well, was very proficient at shorthand (a now lost art) and the job was for a receptionist/typist.

It was 41 years ago, and at 17 years old, she felt intimidated by Hopkins and was relieved when the interview was done. She thought she blew it.

To her surprise, Hopkins called and offered her the job.

It was a fortunate decision. It launched Crockett on a long career that would eventually see her rise to take the executive director’s job, from which she is retiring at the end of December. It was a good break for AOGA too, because having someone like Crockett on staff for four decades, rising through the ranks and learning the industry’s issues, has made her a valuable source of institutional memory on a wide variety of complex government policy issues.

In an industry where managers of operating companies typically rotate from Alaska to other places, and vice versa, having that continuity of experience has been invaluable.

It was a different era when Crockett came aboard at AOGA. Cook Inlet was Alaska’s crown jewel in terms of oil production and additional platforms were being installed.

Hopkins, a former assistant to Gov. Bill Egan, was the petroleum industry’s most public persona as its chief lobbyist in Juneau in his work as director of the industry’s trade association.

There was a small staff of three, including Crockett. Long distance phone calls were a major expense. So was the copy machine bill and postage.

Things changed as the industry grew. The North Slope started up in 1977, the major operating companies, on both the North Slope and Cook Inlet, developed their own public relations and lobbying staffs.

While AOGA maintained its advocacy efforts, it also evolved into a more traditional trade association where oil and gas companies, and even refiners, could meet and talk together and work out common approaches to issues.

Trade associations like AOGA perform a valuable function as a forum for companies to meet and talk with each other, but one thing an association must be very careful about is anti-trust considerations. There can be no discussions about prices, marketing or anything that might be construed as inhibiting competition. AOGA’s rules are very strict about this, Crockett says.

As the industry grew AOGA grew, and as the industry contracted as crude oil prices periodically crashed, AOGA contracted. At one time the association had eight people on staff and a variety of public relations programs including a series of teacher orientation workshops that included field trips, some to the North Slope.

Budget cuts, as the industry hit lean times, ended some of those programs but the school programs have evolved. Alaska Resource Education, formerly AMEREF, a project of the Resource Development Council, was established and is now an independent nonprofit.

Another industry group, the Alaska Process Industry Careers Consortium, which works on workforce development, now has a well developed teacher “ex-tern” program were high school teachers spend some of their summers in actual working jobs with producing companies and contractors.

As things tightened and communication technology advanced, AOGA slimmed down its staff and has been stable at four people for several years. The association still has an active public relations outreach program, publishing a newsletter and managing a public speaking program.

“We feel it’s very important to remind people of the industry’s economic contributions. A lot of Alaskans don’t remember what things were like here before there were oil revenues to the state,” Crockett said.

AOGA’s board, made up of the industry’s senior managers in Alaska, provides overall guidance – this year’s AOGA president is Dale Pittman, ExxonMobil Corp.’s Alaska production manager – but the association’s nuts-and-bolts work is done through its standing committees.

The standing committees are Environmental, Health and Safety, Lands, Exploration and Operations, State Legislative, and Tax. Other committees are formed for special purposes, such as an offshore committee now active because of the new interest in exploring in the Arctic offshore.

Specialists in these areas are named to the committees. The legislative committee is very active as it oversees the association’s advocacy and legislative efforts.

Because a lot of activity in the Legislature and the administration involves taxation, the association’s tax committee, made up of tax specialists, is also active, reviewing tax legislation and developing comments, usually technical in nature, which become part of the association’s presentations to legislative committees.

The lands committee has been concerned mainly with lease sales and has been less active in recent years with the state’s switch to its regular “area-wide” lease sales, but the committee still exists and meets on an as-needed basis, Crockett says.

The environment committee is also active, Crockett says, because it deals with highly complex state and federal air and water quality issues. In recent years there are also issues like federal Endangered Species Act designations and habitat declarations that affect the industry, and the association has become active in this area.

It is on complex regulatory issues that trade associations like AOGA can be most effective, and also provide valuable assistance to the government agencies because the association brings the combined experience and knowledge of all companies working in Alaska to bear on a problem.

Governmental agencies and legislators often want to be able to communicate with the industry as a whole, and a trade association like AOGA is a preferred was for agency officials to talk with an industry and listen to thee affected companies in one setting.

In years past AOGA was heavily involved in the development of the coastal management, through the original state legislation and regulations that implemented that, and then in the revamp of the program by former Gov. Frank Murkowski. The program ended last year when the Legislature declined to extend it. Crockett points out that the association supported an extension of the program but not any changes to it, which were proposed by some legislators.

A few other examples illustrate where AOGA, as a trade association, has been effective. One was in working with the state Department of Environmental Conservation in, most recently, the state’s assumption of federal authority to issue industrial wastewater permits.

Previously this permitting was all done by the U.S. Environmental Protection Agency but federal law allows the federal agency to delegate the permit authority to states, although this must be done under guidelines set by EPA. The state DEC is now assuming this authority in stages. There were several issues, most important how the changes for operating the program would be funded, where AOGA worked closely with DEC.

Previously, AOGA played a substantial role in resolving issues related to the state’s assumption of air quality permitting authority from the EPA. In this case the federal Clean Air Act requires states to fund all of the costs of administering the programs.

This got complicated because companies in many industries must obtain air quality permits and the concern was that a cost-reimbursement formula that was based only on a simple criteria, such as tons of air pollution per year, would have operators of major facilities like oil and gas producers, refiners and utilities picking up most of the tab.

In fairness, most of the real cost of the program would come for the DEC in administering permits for a wide variety of businesses which emit much lower volumes of pollutants.

A solution worked out by an ad hoc committee formed by businesses, industries and municipalities and utility operators and with AOGA’s major involvement, led to a unique financing procedure partly based on tons of pollution and partly on the hours spent by agency personnel on a permit.

Crockett and her husband, Jack, will now become “snowbirds,” spending part of the year in warmer climates.

On Crockett’s departure, Kara Moriarty, formerly deputy director for the association, takes over as executive director. Kate Williams is the association’s staff for regulatory issues, and Tamara Sheffield, herself a long-tenure staffer of 30 years, provides support services to the organization.

This article appears in the AJOC December 11 2011 issue of Alaska Journal of Commerce

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-11-2011/Working-up-from-typist-to-executive-director-Crockett-retires/#ixzz1fz0EV4Oh

Busy winter exploration season planned for North Slope

Tim Bradner
Alaska Journal of Commerce

It will be a busy exploration season on the North Slope.

New drilling by Repsol is driving the pace of exploration with four to five drill rigs under contract but Brooks Range Petroleum, Linc Energy and Great Bear Exploration also plan drilling, employing one drill rig each. In addition Anadarko Petroleum is going back to test a natural gas find in the foothills region of the southern North Slope.

Linc Energy’s Umiat project is not technically exploration since the oil accumulation there has long been known, but the company is planning to drill five wells and to do flow tests of three to four to assess the productivity of the shallow Umiat reservoir.

The company is developing a 90-mile snow road from the Dalton Highway to Umiat to move a drill rig and other major equipment. Anadarko will also use the road for part of the distance to move equipment it will need to test its well, although a drill rig will not be required.

There is an estimated 1 billion barrels of oil resource estimated to lie in the shallow sandstone reservoir at Umiat, much of it actually in the permafrost, according to Corri Feige, Linc Energy’s Alaska manager. Only a part of this will be produced, however. The oil is very good quality, however, measured at 37 degrees API, Feige said.

Linc Energy is studying a small crude oil pipeline that would be built parallel to a gravel access road the state of Alaska is planning to build to the area.

Brooks Range Petroleum, which is exploring on behalf of several independent companies, will return to its North Tarn 1-A well drilled last year to deepen and test the well, said Bart Armfield, Brooks Range’s chief operating officer. When that work is completed the rig will move to the company’s nearby Mustang prospect to drill. An exploration project to search for gravel will also be done.

An ice road will be built from a production pad in the southwest part of the Kuparuk River field, with the Nabors 7ES rig and two camps capable of housing 100 people moved to the exploration site.

If a commercially viable project is developed Brooks Range will move to the design of a production facility and procurement and construction in 2013 with a possible start of production in 2014. Capital costs for the Mustang project are estimated at $597 million. If an extension of the prospect to the north, called Appaloosa, is also developed, a further $454 million in capital investments will be required.

The planning now assumes a 10,000 barrels-per-day production facility with 15 wells, including seven producers and eight injection wells.

Great Bear plans to drill six test wells at locations adjacent to the Dalton Highway south of Prudhoe Bay to test its concept that oil can be produced from shale source rocks, according to Great Bear President Ed Duncan. The shale formations are known to be the sources for oil that accumulated over time in several of the large producing fields to the north of Great Bear’s leases. The company hopes that substantial amounts of oil remain in the shales.

What is planned, if the theory holds, is a production project similar to that being done to extract shale oil in North Dakota and Texas. The production plan involves horizontal wells and multiple fracturing, a procedure similar to that used in the shale oil projects of the Lower 48.

Repsol, a medium-sized integrated company based in Madrid, Spain, acquired a 70 percent interest in 500,000 acres of North Slope onshore leases last March in a deal with Denver-based independent Armstrong Oil and Gas. The company planned an aggressive program to test prospects because of impending lease expiration deadlines, its project manager, Bill Hardham, said.

Drilling will be at prospect locations north and west of the Kuparuk River field and south of Kuparuk near the Meltwater production pad. Four to five rigs will be employed, and the activity will be so intense that the company has chartered an Alaska Airlines Boeing 737 for twice-weekly flights to the Slope.

This article appears in the AJOC December 11 2011 issue of Alaska Journal of Commerce

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/AJOC-December-11-2011/Busy-winter-exploration-season-planned-for-North-Slope/#ixzz1fywknBdU

Saturday, December 3, 2011

Cook Inlet energy projects under way

Kristen Nelson
Petroleum News

The Resource Development Council included a fairly complete Cook Inlet update on the program of its annual conference.

From oil and gas, through wind and underground coal gasification, to natural gas storage, companies involved in the current upsurge in Cook Inlet activities were on the podium Nov. 17.

Apache

Apache Corp., Cook Inlet’s newest big player, with more than 800,000 acres, was represented by its newly named Alaska general manager, John Hendrix, who told the RDC audience he remembers Cook Inlet in its heyday, before the discovery of Prudhoe Bay. But by the time he graduated from college and went to work for Schlumberger, the work was on the North Slope.
“All the focus, all the money, were going into Prudhoe Bay,” Hendrix said.

Apache is focused on the historic oil play in Cook Inlet and is looking for oil “with new 3-D seismic technology,” he said.

“We feel there’s potential out there. We’re more focused on oil — gas will come along with the oil … but we’re oil focused.”

Apache has begun a three-year 12,000-square mile 3-D seismic shoot in Cook Inlet using a new nodal technology.

Hendrix said there are 220 people on the west side of Cook Inlet deploying nodes with the first actual shoot done Nov. 11. He said crews will work until mid-December and then start back up Jan. 15. Twelve small drill rigs will be used to drill the holes onshore; offshore air guns will be used.

In all of its operations, Apache shoots a lot of seismic, Hendrix said.

“We’re a very seismic, geo-science oriented company … and you have to know the data before you drill. You gather the data, you put your strategy forward and then we drill.”

He also said that Apache’s “chairman, in a number of meetings I’ve been with him, he doesn’t want us to stop drilling until we hit bedrock. We don’t want anybody to come behind us and turn over a stone and find there’s oil reserves; we want to make sure when we drill, that we leave no … stone untouched.”

Buccaneer

Jim Watt, president and COO of Buccaneer Alaska, said Buccaneer sees majors moving out and independents moving into Cook Inlet, “normal for a lot of maturing basins.”

But, he said, Cook Inlet is an underexplored basin where recent U.S. Geological Survey reports show “tremendous upside” and where there is existing infrastructure, a strong local market and attractive natural gas prices.

Buccaneer has some 66,000 acres onshore and at one prospect, Kenai Loop, just north of the city of Kenai, it “leased, permitted and drilled our first well within nine months.” That natural gas well will be on production in December, he said. Buccaneer has a contract with Enstar for delivery beginning in April, “but we hope we will sell in the spot market” before then, Watt said.

At West Nicolai on the west side of Cook Inlet Buccaneer expects to acquire seismic in 2012 and drill in 2013.

And at West Eagle on the southern Kenai Peninsula Buccaneer is reprocessing seismic and would like to drill in 2012.

The company also has offshore prospects and has completed purchase of the Endeavour jack-up drilling rig for use in Cook Inlet. Buccaneer is also looking at the potential for liquefied natural gas for use in Alaska. Watt said “we feel we can move LNG from the Cook Inlet to Fairbanks and be very competitive.”

Furie/Escopeta

Drilling engineer Bob Laule, filling in for Furie Operating Alaska (formerly Escopeta Oil) President Ed Oliver, gave a brief update.
“Furie came; we drilled; and we found gas,” he said.

He said the company got a late start and wasn’t able to complete its well, but drilled to 8,800 feet and did “some testing which gave us some very good indications of gas in the Sterling and in the Beluga formations.”

Laule said they will re-enter the well next spring, approximately mid-April and drill to total depth, “set a couple of extra additional stands of pipe and go into a testing program.”

Then Furie will drill a second well. Laule said he didn’t know if they’d get to testing the second well next year.

Cook Inlet Energy

JR Wilcox, president of Cook Inlet Energy, said his company “is one of the few small independent oil producers in the state.” Cook Inlet Energy re-established production after Pacific Energy declared bankruptcy in 2009.
Production was shut down in September and Cook Inlet Energy was approved as successor operator in December, hired a staff and “within about two weeks we had some production going.”

Over the next four months the West McArthur River unit was restarted and production was up to 400 percent of what it was when it was shut-in.

Wilcox said the company has continued to optimize wells at its onshore properties.

It took longer to get the Osprey platform back into operation, but first oil came off the platform in June, he said. With a $100 million credit facility work began on a big rig for the Osprey platform so the company could begin drilling sidetracks from the platform and increase production. About a third of that rig is now in Nikiski, Wilcox said, and work will begin on the platform in the next few months.

Cook Inlet Energy is also building a small rig on the west side that will be truck mounted and “should be just an ideal rig for drilling gas on the west side.”

The company is “getting set up to execute our second phase of development on the Osprey platform” with the new rig, is continuing to optimize production from existing wells and continuing to exploit oil and gas reserves near its facilities, Wilcox said.

Enstar, CINGSA

John Sims, director of corporate communications for Cook Inlet Natural Gas Storage Alaska and Enstar Natural Gas, told the RDC audience that while Enstar is “very cautiously optimistic about all the activities going on here in Cook Inlet,” it has concerns until it has a contract for gas delivery before the Regulatory Commission of Alaska.
Semco Energy, Enstar’s parent company, and MidAmerican LLC, partners in Cook Inlet Natural Gas Storage Alaska, or CINGSA, were joined in October by First Alaska and Cook Inlet Region Inc., Sims said.

The five injection-withdrawal wells are being drilled for the storage project, with the project on schedule and slightly under budget. The first well cost about $7 million and the second two came in at about $5 million each, prior to perforating.

The middle three wells, technically the easiest, were drilled first, Sims said. It has taken about 30 days per well, with about half of that time required to move the rig. The wells should be completed by February.

With four customers for storage capacity — Enstar, Chugach Electric Association, ML&P and Homer Electric coming in later — CINGSA is at 11 percent capacity for the 11 billion cubic feet of gas storage.

There is expansion capacity at the facility and Sims said expansion will be “dependent on performance and also the market demand.”

Having storage, which will be available for withdrawal in the winter of 2012-13, helps with swing demand in the winter, he said, helps producers with production in the summer when gas is injected and acts as an insurance policy should there be equipment failure.

Asked whether with successful gas exploration and storage the utilities will still need LNG, Sims said, “storage isn’t the savior for Cook Inlet by any means; it’s a part of the puzzle.”

“Another piece involves the additional exploration and development that we’re seeing.”

But, he said, Enstar and the utilities are still evaluating the LNG option, “not just for gasifying going forward put also for an insurance policy.”

And, he said, “until we actually have those contracts that erase that need, it’s something that we’re still going to have to move forward with.”

Cook Inlet Region Inc.

Ethan Schutt, senior vice president, land and energy development, for Cook Inlet Region Inc., said the Fire Island wind project has regulatory approval for contracts from the Regulatory Commission of Alaska.
Financing for the project needs to be closed, “so that we can move into project construction in April,” he said, adding that the project has all its permits.

CIRI is also working on an underground coal gasification or UCG project.

The Cook Inlet basin has a “world-class coal resource that’s really never been exploited at a commercial level,” Schutt said.

CIRI has been working on UCG for almost three years, he said, and to date has “drilled 13 stratigraphic core holes to test both the geology and the resource,” and collected a suite of oil and gas type data during that program, “so we have a pretty robust data set from that site, a place just north of the Beluga River on the north side of Cook Inlet on CIRI surface and subsurface land.”

The data has been incorporated into a geological model.

CIRI is currently shooting some eight and a half line miles of “shallow high-resolution 2-D … to tie together all the data points that we collected with the drilling program and enhance our data set as we move towards a … characterization program to begin sometime in 2012.”

The project represents some 300-plus million tons of coal, Schutt said, “the equivalent of more than 4 (trillion cubic feet) of natural gas on an energy basis, so just in our little site we have quite a world-class resource in that coal.”