Saturday, April 28, 2012

Governor's 1 Million Barrel Challenge for Alaska' s Oil is "Ambitious, but Achievable"

Production bump probably result of 2011 TAPS shutdown; prices drive profitability

Eric Lidji
For Petroleum News

ConocoPhillips earned $616 million in Alaska in the first quarter of the year, as a rare combination of rising oil prices and production bumped profits 12 percent year over year.

The unusual uptick in Alaska oil production volumes, though, is caused in part by a four-day shutdown of the trans-Alaska oil pipeline in January 2011 and not necessarily increasing activity this year. And the slight bump comes as ConocoPhillips is rapidly increasing its liquids output from the Lower 48, particularly from unconventional plays.

The largest operator in Alaska produced 226,000 barrels of oil and natural gas liquids per day in the state in the first three months of the year, up 5 percent from 214,000 bpd in the first quarter of 2011 and down slightly from 227,000 bpd in the fourth quarter of 2011.

By comparison, ConocoPhillips produced 201,000 bpd of liquids from its Lower 48 portfolio, up 34 percent year over year and 8 percent quarter over quarter, where the company operates in the Eagle Ford, Bakken and Permian resource plays.

For natural gas, ConocoPhillips produced 59 million cubic feet per day in Alaska in the first quarter, down 12 percent year over year. The company produced 1.5 billion cubic feet per day in the Lower 48, down slightly year over year and quarter over quarter.

ConocoPhillips said second quarter production would be down between 50,000 and 60,000 barrels of oil equivalent per day, companywide, because of maintenance work in Alaska, as well as in Australia, the United Kingdom and two projects in Canada.

When asked by Citigroup Inc. analyst Faisel Khan why the quarterly earnings for Alaska were higher than usual, Chief Financial Officer Jeff Sheets mentioned “a bit of a pricing lag on some of the crude” that can impact quarterly comparisons “in a rising market.” On two occasions, Sheets pointed to the fiscal system in Alaska, specifically pointing out that Alaska has “a pretty progressive tax regime at the current price environments.”

ConocoPhillips and other companies want the state to change its tax code.

Alaska price premium

While Lower 48 production is gaining on Alaska, Alaska remains the more profitable play for now, largely because of a major pricing disparity between the two regions.

Although ConocoPhillips produced only slightly lower liquids volumes and far higher natural gas volumes in the Lower 48 than in Alaska during the quarter, the company earned only $254 million from the Lower 48, compared to $616 million in Alaska.

That’s because ConocoPhillips realized an average sales price of $112.20 per barrel for Alaska crude oil but only earned $76.40 per barrel for Lower 48 crude during the quarter.

Additionally, ConocoPhillips reported an average price of $4.68 per thousand cubic feet for Alaska natural gas compared to $2.65 per mcf for its Lower 48 volumes. While Alaska natural gas is traded on long-term contracts in a relatively tight market, Lower 48 prices are highly liquid and being kept down by a surplus of supply from shale plays.

In a sign of the times, ConocoPhillips did not post any sales from its liquefied natural gas export facility in Kenai, perhaps for the first time in the nearly 45-year history of the pioneering plant. ConocoPhillips announced plans in early 2011 to mothball the plant because it couldn’t secure contracts overseas, but a series of unexpected events allowed the company to continue making shipments to Japan and China throughout the year.

During the quarter, ConocoPhillips also reported $9 million in exploration expenses and $135 million in depletion, depreciation and amortization expenses in Alaska.

Companywide $2.9B in earnings

Companywide, ConocoPhillips earned $2.9 billion during the quarter, down from $3 billion in the first quarter of last year. The company produced 1.64 million barrels of oil equivalent per day worldwide during the quarter, its last as an integrated company.

Going forward, ConocoPhillips will become one of the largest independent exploration and production companies in the world and Phillips 66 will become a downstream company managing refining and marketing, midstream and chemicals operations.

ConocoPhillips said the Arctic, particularly Greenland, the Chukchi Sea in Alaska and the Barents Sea in Norway would continue to remain a focus for the upstream player.

Friday, April 27, 2012

Shale oil & gas paradigm shift drives US, world energy outlook

—Alan Bailey

Like the proverbial hurricane triggered by the flapping of a butterfly’s wings, the emergence of horizontal drilling and hydraulic fracturing techniques for the development of shale oil and gas is blowing a gale-force wind of change through the U.S. energy scene.

A recent report to Energy Secretary Steven Chu by the National Petroleum Council said that North America could increase oil production by 10 million to 12 million barrels per day by 2035, a prediction that may be an underestimate, Lou Pugliaresi, president of the Energy Policy Research Foundation, told the Alaska World Affairs Council on April 20.

With massive increases in production in North Dakota, Montana and Texas, for example, the official government data cannot keep abreast of what is happening, he said.

Surging production

Pugliaresi said that the Energy Policy Research Foundation has been monitoring four U.S. shale plays and predicts that, with increased production of 2 million barrels per day from these plays, by the end of 2013 no more light sweet crude oil will be imported into the Gulf of Mexico. It is reasonable to assume that North America as a whole can increase oil production by 500,000 barrels per day each year, he said.

Also taking into account new oil production from Brazil, within 10 to 15 years there will be no further need to import Middle Eastern oil into the Western Hemisphere, Pugliaresi said.

Yet as recently as 2008 the Energy Information Administration testified to Congress that, regardless of how much land was leased for oil and gas exploration or how actively people pursue new resources, the United States would need to import substantial new supplies of natural gas, he said.

And, anticipating a surge in gas imports, companies invested $30 billion in liquefied natural gas receiving facilities. But as U.S. domestic shale gas production flourishes, those import facilities are now operating at about eight percent capacity, Pugliaresi said.

Abundant sources

With oil and gas source rocks already being essential ingredients for conventional oil and gas production in the United States, source rocks with the potential for shale oil and gas development are abundant in the country. And the simple models used for government resource forecasts cannot nimbly adjust to paradigm shifting breakthroughs such as the emerging technologies for exploiting source rock shales, Pugliaresi said.

The rapidly evolving technology is causing the cost of finding new resources to drop and the estimates of resource recovery volumes to climb.

“There are source rocks everywhere. It’s a manufacturing process. Nobody drills a dry hole anymore,” Pugliaresi said. “The technology is moving very fast.”


Moreover, the production of relatively low-cost ethane, for example, from shale plays will place the United States in a strong position in the global petrochemical industry, Pugliaresi said, adding that the United States is now becoming competitive with the Middle East in this arena and has the lowest petrochemical feedstock costs in the world.

“The United States is the most competitive country for value-added processing in the petrochemical business,” Pugliaresi said.

Shell is considering the construction of a very large U.S. ethylene cracker, with the states of Pennsylvania, West Virginia and Ohio vying to provide a venue for the project, he said.

And, although the United States is a net importer of petroleum, including imported crude oil, the country is a net exporter of refined petroleum products such as diesel and gasoline, with refineries on the Gulf Coast especially well placed to act as export platforms, Pugliaresi said.

Cultural shift

The shale oil and gas revolution is also causing a change in the culture of U.S. oil and gas production, with production migrating away from the Gulf of Mexico region. Shale gas production started in Texas and rapidly moved to Oklahoma, West Virginia, Virginia and Pennsylvania, eventually leading to shale oil production in North Dakota, Pugliaresi said.

He attributed the rapid migration of shale development technologies and ideas across these states to the relative ease and speed of land leasing and industrial development in regions with little federal land.

However, infrastructure development for the transportation of oil has become something of an issue, especially with the need to ship oil to coastal refineries. Pugliaresi commented that he views the Keystone XL pipeline debacle as particularly unfortunate, since that pipeline could assist with the transportation of U.S. oil as well as carrying oil from Canada.

Because of pipeline bottlenecks, 100-car trains are shipping some North Dakota oil at considerable expense to Louisiana, while choke points for oil shipment are depressing oil prices quite dramatically in some North Dakota locations, Pugliaresi said.

“We really have to fix this problem,” he said.

Government regulation

Pugliaresi said that government regulation and permitting also need to keep up with the rapidly evolving oil and gas situation.

“This is happening so fast and so quick that the way we traditionally regulate and permit new projects in the U.S. is not going to work,” he said.

For example, it will likely be necessary to export some U.S. oil into Canada or Mexico, to enable the appropriate combination of crude types to be delivered to Gulf of Mexico refineries. But at present companies are very unlikely to be able to obtain export permits, Pugliaresi said.

Asked about the prospects for a pipeline to export Alaska natural gas to the Lower 48 states, Pugliaresi said that it will likely be a long time before Lower 48 gas prices attain levels sufficient to support the transportation of gas from Alaska. However, the economics of exporting U.S. gas to the Pacific Rim are intriguing at present, he said.

When it comes to Alaska oil development, it is necessary to find a way to deal with oil price uncertainty and to align the interests of those with capital to invest with the interests of the state and the federal governments, Pugliaresi said.

Environmental questions

Criticized by a couple of people in the World Affairs Council audience for not including the cost of environmental factors such as global warming and ocean acidification in his analysis of expanding oil and gas production, Pugliaresi responded that it is necessary to carefully consider the trade-offs between the economic value of oil and gas development and the cost of any resulting environmental impacts.

The value of oil and gas production for a state such as Pennsylvania is very significant, and to make comparisons with alternatives such biofuel production it is necessary to assess the value and cost of these alternatives, he said, adding that any form of energy production has some environmental impact.

Pugliaresi had earlier commented on the relative economics of fossil fuels and renewable energies. A fairly recent world view that oil would become short in supply and high in price is being reversed, thus raising questions over the relatively high cost of technologies such as wind power, solar energy and electric cars: While the value-added processing of petroleum products can create new jobs and fuel economic growth, the development of goods whose value is less than their cost of production is problematic, he said.

Harboring Seward's Waters: Alyeska Oil Spill Response Training

Thursday, April 26, 2012

House researches, Senate waits for answers

Bob Tkacz
The Alaska Journal of Commerce

“We’re in the valley of a decision,” Rep. Alan Dick said April 24 at the end of the third daylong House Resources Committee hearing on Gov. Sean Parnell’s oil tax reduction bill.

As the first week of the 30-day special session ended, a decision was not expected soon. Co-chair Paul Seaton, R-Homer, had no target date or timeframe for debate on markup to House Bill 3001. The House Special Energy Committee is unofficially at the table during the research mode, but its members won’t be moving or voting on amendments. Other lawmakers can send written questions to the chair during hearings.

The measure goes next to the House Finance Committee.

The Senate Resources Committee was generally on a parallel course, planning in particular to question Parnell administration consulting firm, Gaffney, Cline and Associates on the economic basis for the twin Senate Bill 3001.

Otherwise it, and the full Senate are waiting for the House to take action after the Senate’s failed effort to pass an oil production incentive bill during the regular session.

“I do think it’s appropriate that we see what the House thinks at the end of their process and to see if there is a potential for compatibility in that regard,” said Sen. Joe Paskvan, D-Fairbanks, co-chair of the Senate Resources Committee.

He added that House hearings “are getting the answers with similar information we got in the Senate over a year ago.”

A two-hour Senate Resources Committee meeting held April 24 was the only one of any kind in the Senate in four days.

The April 20 committee session included a scolding for Revenue Commissioner Brian Butcher from the administration’s most ardent champion.

“We were called into session with kind of a half-baked bill, and I mean that in sincerity,” Sen. Lesil McGuire, R-Anchorage, said to Butcher. “You’re in a position where you’re trying to sell a bill where, I think, you just don’t understand the ins and the outs of it.”

After that and a two-hour hearing earlier in the month, Deputy Commissioner Bruce Tangeman and William Barron, director of the Division of Oil and Gas, Paskvan took a three-day break to await more specifics supporting a bill that is generally a different approach to the tax cuts in HB 110 for the Prudhoe Bay and Kuparuk legacy fields. The Senate majority summarily rejected that bill during the regular session.

The revised HB 110 provisions are viewed by most Democrats and several Republicans in both bodies as unnecessary or too generous. They exclude 40 percent of legacy field gross revenues from consideration in the calculation of the progressivity tax. They also cut the cap on the maximum progressivity tax rate to 60 percent from 75 percent of production value and extend to the North Slope the 40 percent well lease expenditure credit now available in Cook Inlet.

PFC Energy, the Legislature’s contract consultants, projected a $1.45 billion decline in revenue from what the state would have received under current tax law if the bill had been in effect last year.

The incentives that have bipartisan support give new North Slope fields a 30 percent gross revenue exclusion from base and progressivity tax amounts, but not from the progressivity calculation formula, for 10 years.

Sen. Bert Stedman, R-Sitka, co-chair of the Senate Finance Committee, called SB 3001’s legacy field provisions “almost identical” to HB 110. Paskvan agreed.

“It appears that they are advancing a policy but are not prepared on the detail or the substance of that policy, and so that is part of the further questioning that we’ll have to engage in,” Paskvan said.

PFC Energy spokesmen have given the House committees a mini-seminar on multinational oil and gas company investment decision-making, and global strategy and portfolio overviews of Alaska’s three major producers.

PFC Senior Director Ton Reinsch suggested Alaska should reach agreement with the majors on the rate of decline in the legacy fields and offer incentives for incremental production.

“It’s a tried and true method, but you have to incent that additional production. At the end of the day it is critical for the government to be perceived as getting a fair deal, but equally or more important that those flows continue,” Reinsch said.

He noted that the approach has been applied on a project or field-specific basis elsewhere and could be complicated if attempted basin-wide.

Reinsch also noted that the lag time from legislative action to field response to money in the treasury the state’s near term oil revenue future is already written.

PFC “can speak so firmly,” he emphasized, because “if it is going to turn the dial for any of these companies in the next five to seven years, they’ve already discovered it and we modeled it.”

Whether the committee will take Reinsch’s advice remains to be seen.

“It seems obvious more than half the committee understands this is not a good thing,” Rep. Berta Gardner, D-Anchorage, said of HB 3001. With sufficient data that she emphasized she has not yet seen, Gardner, a Resources Committee member, said a bill with new field credits could pass the House.

Gardner suggested the major producers couldn’t justify tax cuts because they have rarely applied for royalty relief under a long-standing option that would require them to disclose to the state detailed economic data.

Rep. Lance Pruitt, R-Anchorage, co-chair of the Energy Committee said, “It seems to be there’s alignment on (incentives for) outside of the legacy fields or the new producers, or everything that’s new. There seems to be a fairly good understanding that we probably need to make something to attract them there. I think the legacy fields, that’s the huge hiccup.”

The Senate is also holding on to HB 9, Speaker Mike Chenault’s bill to build a southbound natural gas bullet line from the North Slope to the Mat-Su Valley. The Senate Community and Regional Affairs Committee released its version of the bill shortly before a one-hour hearing April 19. Chairman Donny Olson, D-Nome, cancelled the next day’s session and had no meetings scheduled through April 25 at least.

As passed by the House, HB 9 creates the Alaska Gasline Development Corp. as an independent subsidiary of the Alaska Housing Finance Corp. with the authority to plan, design, build and operate a natural gas pipeline. Olson’s rewrite requires legislative approval before any construction, which Rep. Mike Hawker, the bill’s co-sponsor, panned.

Hawker said lawmakers’ interests are too local to give them control of project of state importance.

“We are essentially obligated, when a project comes forward, if it’s not the one that absolutely benefits me to the greatest degree possible, I’m obligated to challenge it,” he said at the hearing.

Read more:

Saturday, April 21, 2012

Legislators back at work; Special session called on oil taxes, in-state line; bill based on Senate’s new field tax

Kristen Nelson
Petroleum News

It looked like Senate Finance had an oil tax compromise senators could live with when, after weeks of work on the measure, it moved Senate Bill 192 out of committee April 11.

But SB 192 never reached the Senate floor.

The bill, a fundamental change of Alaska’s oil and gas production tax system with different tax rates for existing production from legacy fields, incremental production from legacy fields and new oil, couldn’t garner enough support from members of the Senate Bipartisan Working Group.

On April 14 another plan surfaced, a tax change affecting only production from new fields. Senate Finance added that measure to House Bill 276, credits for exploration and seismic work in frontier basins (see story in this issue).

The Senate passed HB 276 by a vote of 17 to 3, but it got no traction in the House, with portions of HB 276 moved to other legislation and HB 276 withdrawn by its sponsor.

The tax change proposed by Gov. Sean Parnell last year, an across-the-board production tax cut, passed the House last year but stalled out in the Senate, with senators saying they needed more information before making tax changes.

So the session ended with no major changes in the state’s oil tax system.

Within the hour of legislators gaveling out the governor had called a special session to begin April 18, with the oil tax issue, House Bill 9 (the in-state gas pipeline bill) and HB 359, sex trafficking, on the agenda.

‘A new dynamic’

At an April 16 press conference the governor said he was interested in the approach the Senate took in HB 276, and said with the “Senate’s action there’s a new dynamic now at work that I think might lead to a compromise that could produce new production, both now and in the future.”

Parnell said the Senate proposal wasn’t the whole answer because any new oil discovered as a result of the credits wouldn’t be going into the pipeline for a number of years, and he was concerned “that vast resources in our legacy fields will remain untapped.”

The governor also said the Senate’s approach, focusing only on new fields, “will cost the state billions of dollars across 10 years while we have declining production and no new revenues from new production.”

He cited the example of a company proposing to spend $9 billion in the state over the next 10 years on new fields. Under the state’s existing tax structure that company would get credits of between 45 and 65 percent, “so the state will pay half of the cost of that exploration across the next 10 years,” meaning the state would have to come up with $4 billion to $6 billion in that timeframe, while production from existing fields is declining.

The governor said he wants to see a proposal which would incentivize new production from existing fields, along with new field production, and believes that with “a significant tax change in existing fields” the state could see as much as 100,000 new barrels a day “within a year and a half or two years.”

“I want to see whether we can take what the Senate has already agreed is meaningful in the new field context and make it material enough to do the same in existing fields,” Parnell said.

If the Legislature reaches an impasse, Parnell said he would understand.

“But I think it’s worth a try to create a competitive environment where more production can be produced,” he said.

HB 9

On House Bill 9, a bill moving along work on a small-diameter in-state gas pipeline, Parnell said that if the key provisions in HB 9 don’t pass, “Alaska’s gas line efforts, in my view, will be set back for one to two years.”

The governor said he was asking the House and Senate to waive the uniform rules and take up HB 9 where it was when the session ended; both bodies did that April 18.

Parnell said he disagrees with House Speaker Mike Chenault on whether the Alaska Gasline Development Corp. needs to come back to the Legislature before a pipeline gets built, and said he’s “not trying to empower AGDC at this moment to go and contract and have an open season and sanction a pipeline; I think we have to have some gates they have to go through where they are held accountable by the Legislature and by the executive.”

On the other hand, the governor said he doesn’t agree with legislators who believe AGDC’s “efforts should be killed off.”

“I’m not in that camp,” he said, explaining that the state needs alternatives — the large line from the North Slope to markets and the smaller in-state line — because without an option, the process would slow down, as it did under the Stranded Gas Act negotiations “when one party’s negotiations were swept off to the side and ... the process slowed down and the state had no other alternative.”

The new bill

The governor submitted a new oil tax bill to the House and the Senate April 18, describing it as “a piece of legislation that blends the positions of the House and Senate into a comprehensive approach that will bring economic opportunity to Alaskans for generations to come.”

New North Slope oil and gas production is incentivized with a 30 percent exclusion, based on gross value at the point of production or GVPP, from the production tax value used to calculate the base rate and progressivity for the first 10 years of sustained production. This applies to fields not in production or in a unit on Jan. 1, 2008 — which would exclude Point Thomson but include Oooguruk and Nikaitchuq.

For currently producing North Slope fields, there is an exclusion, but only from the value used to calculate progressivity: 40 percent of the GVPP would be excluded from the monthly production tax value used to calculate progressivity; progressivity would be capped at 60 percent.

The bill also extends tax incentives for well lease expenditures available elsewhere in the state to North Slope activities and allow producers to apply tax credits in one year.

The new-oil provision

So what would the 30 percent exclusion in calculating base rate and progressivity for the first 10 years of sustained production look like?

Senate Finance had PFC Energy model the lifecycle effects for a new small development — a 70 million barrel field with peak production of 10,000 barrels per day at $100 oil.

Finance co-Chair Bert Stedman, R-Sitka, said at the April 14 hearing when the proposal was first aired publicly that the “concept of the 30 percent gross revenue allowance was derived out of our previous work on trying to enhance new oil production” with a gross progressivity calculation, and is an approach to incentivizing oil outside of existing developments within the current ACES structure.

Gerald Kepes, a partner in PFC Energy and head of the consultancy’s upstream and gas practice, showed models run at the 30 percent gross revenue allowance for new developments at three different development costs: $17 per barrel; $25 per barrel; and $34 a barrel.

Kepes said with a $17 per barrel capital cost under the current tax, Alaska’s Clear and Equitable Share or ACES, a lifecycle analysis showed a net present value or NPV of $112 million and an internal rate of return or IRR of 16 percent, with total government take ranging from 67 percent at $60 oil to 75 percent at $100 oil and 79 percent at $150 oil.

With the gross revenue allowance of 30 percent applied to ACES, NPV rose to $201 million and IRR to 20 percent; government take ranged from 56 percent at $60 oil to 64 percent at $100 oil and 66 percent at $150 oil.

“So it’s a substantial difference for these lower-cost new developments,” Kepes said.

Capex of $25 a barrel

At development costs of $25 a barrel for the same new development, which Kepes said “is more in line with the costs that we see with these new developments ... away from existing infrastructure,” NPR under ACES would be $24 million and IRR 11 percent, with government take ranging from 68 percent at $60 oil to 75 percent at $100 oil and 79 percent at $150 oil.

At the $25 a barrel capital cost with the 30 percent gross revenue allowance, NPV is $121 million and IRR 14 percent, with government take ranging from 51 percent at $60 oil to 62 percent at $100 oil and 67 percent at $150.

At a capital cost of $34 a barrel, which Kepes characterized as “among the higher or highest cost rates that we’re looking at,” under ACES NPV is a negative $90 million and IRR 7 percent, with government take ranging from 80 percent at $60 oil, to 77 percent at $100 oil and 79 percent at $150 oil.

With the 30 percent gross revenue allowance, NPV on this type of project is a positive $3 million and IRR 10 percent, with government take ranging from 49 percent at $60 oil to 62 percent at $100 oil and 66 percent at $150 oil.

Legislators received a letter from 70 & 148 LLC, a partner with Repsol in new developments which have been cited at capital costs of $9 billion over 10 years, expressing “strong support” for passage of the new oil provisions Senate Finance added to HB 276, calling the new field tax changes “exactly what is needed in order to have the oil industry focus on Alaska over other oil producing regions,” but also noting that the company hopes modifications can be made in the tax code “that will make operations within the legacy fields more competitive as well.”

Gas injections begin at new storage facility

Tim Bradner
Alaska Journal of Commerce

Natural gas is now being injected into a new gas storage facility on the Kenai Peninsula, Enstar Natural Gas says.

Five injection wells are now in operation at the Cook Inlet Natural Gas Storage Alaska facility on the Kenai Peninsula south of Anchorage, according to Enstar spokesman John Sims. Gas injection began April 1.

“We’re ramping up the injection to test the performance of the storage reservoir. So far we’re quite pleased,” Sims said.

Gas being injected now will provide pressurization for the reservoir, a depleted pool within the Cannery Loop gas field.

“Later we’ll start injecting gas for withdrawal later this year,” he said.

CINGSA is the first independent gas storage facility in Alaska, and the largest with 11 billion cubic feet of storage capacity. Cook Inlet gas producers own five other storage facilities, all smaller. The largest is at Marathon Oil’s Kenai gas field, which has a capacity of 6 billion cubic feet.

Injection will continue through the summer, with the first withdrawals planned for November and December, when there is peak demand for gas in Southcentral Alaska, said Sims.

Sims is also with Enstar Natural Gas Co., whose owner, SEMCO Energy, is one of the owners of CINGSA. The other owner is MidAmerican Energy Holdings.

New gas storage capacity is needed in Southcentral Alaska because daily gas production in producing fields in the region now falls below the daily peak demand in winter, and utilities like Enstar worry that gas storage capacity of the producers is insufficient to supply the utilities.

The new CINGSA facility will be able to withdraw gas at rates of 150 million cubic feet per day in the winter. Customers who will store gas include Enstar and two regional electric utilities, Chugach Electric Cooperative and Anchorage’s city-owned Municipal Light and Power.

The new facility has also cost less to construct than estimated, Sims said.

“We recently filed documents with the Regulatory Commission of Alaska indicating costs of $160 million, which is below the $180 million originally estimated. We’re quite pleased about that because it will mean lower costs for our customers for gas taken from storage,” Sims said.

This article appears in the AJOC April 22 2012 issue of Alaska Journal of Commerce

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Legislature awards money for UA engineering buildings

by Jonathan Grass
Alaska Journal of Commerce

The University of Alaska has been on a mission to increase its engineering students for several years now. That mission got a big push in the final hours of the legislative session, when the House passed the Senate’s capital budget that include more than $100 million for new engineering buildings at two campuses.

To be complete, the governor must still sign off on the budget, but both campuses see this as a big step forward in the Engineering Expansion Initiative the university’s Board of Regents adopted in 2007.

The Legislature awarded UA $58.6 million for construction on a new engineering building at the University of Alaska Anchorage. The University of Alaska Fairbanks got $46.3 million for its construction. Both of these amounts are roughly half of what each needs to complete the projects. University officials say the plan will most likely involve requesting the rest at next year’s session.

Although the engineering buildings were not in the capital request from the Board of Regents, the projects were pushed through in the Senate Finance and received strong support from engineering firms and students. Much of this stems from the current facilities’ inadequacies.

The projects include a mix of new construction and renovation of existing space.

UAA’s building will be located across from the new Health Sciences Building. Mike Driscoll, UAA provost and executive vice chancellor, said the numbers have gone up dramatically over the last five to six years, and more space is needed. He said the current space is less than half of what’s needed to accommodate the college’s growing engineering program. The new building also will improve modernization of the space and enhance the labs to allow better hands-on studies.

“The new facility give us somewhere like 60,000 usable square feet,” he said.

The building itself will be a living experiment to showcase things like instrumentation, measuring, heating and cooling systems, and seismic activity potential to the engineering students.

Driscoll said the hope is that construction can begin in next spring’s season after additional planning. It would still be a couple of years until the building is usable.

The new UAF building will supplement the existing engineering facility, Duckering Building, adding 54,000 square feet, said Doug Goering, dean of the College of Engineering and Mines at UAF. He said Duckering currently has 80,000 square feet. There is the possibility for more space in the new one because one floor will be for future expansion.

Goering said the additional space is close to what was determined to be needed, as programs and research expenditures have essentially doubled since 2005.

He said the new building will have an open floor plan and some internal glass to increase visibility of how engineers work, which is something Duckering lacks the ability to do.

The department also wants plans to build more study space, connectivity, and space for student teams to work and do special projects. Some of these projects include work on rocket and satellite design, civil engineering in bridge building competitions and work with the Society of Automotive Engineers.

Goering said they are partway through the design now and construction could start in about a year.

UAA’s plans include a code-required parking structure. UAF’s plan does not include such parking, which Goering said contributes to its lower cost.

The construction is part of the University of Alaska’s initiative to increase undergraduates in engineering to fill an occupational gap. The university reports that most engineering jobs in the state are filled by non-residents.

The Alaska Department of Labor projects an average of 50 new engineering jobs annually through 2018 and another 70 openings from annual turnover and retirement.

The university has been focused on expanding its engineering program for some time, particularly its undergraduate engineers. The Board of Regents has called the Engineering Expansion Initiative its No. 1 new construction priority for academic programs.

Engineering enrollment has increased by 53 percent between 2007 and 2010 in engineering undergraduates, the university reports. There were 72 baccalaureate degrees awarded in this field when the initiative came through in 2007, compared to 148 in 2010.

Driscoll said UAA has more than 1,000 students enrolled in undergraduate and graduate classes.

Goering said the university is on track to double its 2006 engineer students by 2014.

The Legislature previously awarded $4 million to each campus for planning and design. Private gifts of more than $26 million for the engineering program initiative have come in from nearly 770 individuals and corporations since fiscal year 2007. UAF also able to garner $400,000 in general funds.

“We’re very grateful for the engineering companies for all support they’ve given and recognizing the quality of graduates and wanting to see more of them,” Driscoll said.

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Wednesday, April 18, 2012

Parnell submits opening proposal on oil taxes for special session

Alaska Journal of Commerce

With the special session of the state Legislature under way at 1 p,m. Wednesday, Gov. Sean Parnell transmitted legislation to change Alaska's oil tax regime to foster new production and encourage further development of current sources to stem the decline in North Slope production.

Parnell issued the call for a special session just as the regular session of the Legislature ended at midnight, April 15. Lawmakers have been waiting, however, to see just what Parnelll would propose for oil tax changes.

The Legislature convened in a special session to address oil taxes, an Alaska gasline, and human trafficking legislation.

In a statement, Parnell said, “Alaskans are well aware that oil production is declining from our legacy fields. The cost of maintaining a declining field goes up year after year, and higher cost barrels of oil get left in the ground if they are not economic to produce. That is the risk: Without meaningful tax change for legacy fields as well as new fields, a larger percentage of Alaskans’ resources will remain locked in the ground.”

“We can avoid this risk and ensure a more prosperous future for Alaskans if we are willing to continue working to increase oil production in all of Alaska’s fields.”

For new North Slope fields, Parnell’s bill incentivizes new oil and gas production by providing a 30 percent exclusion, based on gross value at the point of production, from the production tax value used to calculate the base rate and the progressivity tax for the first 10 years of sustained production from new fields.

For currently producing North Slope fields, the bill establishes an exclusion of 40 percent of gross value at the point of production from the monthly production tax value used to calculate the progressivity tax.

The bill caps progressivity by establishing a 60 percent maximum rate. Finally, the bill would extend tax incentives for well lease expenditures available elsewhere in the state through AS 43.55.023(l) to North Slope activities and would allow producers to apply tax credits in one year.

These changes are designed both to encourage development of new, currently undeveloped leases or properties, and from known fields in the state, Parnell said in the statement.

Read more:

Tuesday, April 17, 2012

Marathon to exit Alaska; Selling its Cook Inlet assets to Hilcorp to focus on oil resources elsewhere

Alan Bailey
Petroleum News

Another major change in the landscape of the Alaska oil and gas industry emerged on April 9 when Marathon Oil Corp. announced that it had agreed on the sale of all of its Alaska assets to Hilcorp Alaska, the Alaska division of Houston-based Hilcorp Energy Co. Marathon is a major natural gas producer in Alaska’s Cook Inlet basin and has been operating in the state since the 1950s.

“We’ve been operating here for almost 58 years and over that time we have certainly valued all the relationships that we have throughout the state,” Wade Hutchings, Marathon’s Alaska asset team manager, told Petroleum News on the day that the sale was announced.

The Marathon sale comes on the heels of Hilcorp’s purchase of all of Chevron’s Cook Inlet oil and gas assets in 2011.

Corporate strategy

The sale reflects a Marathon corporate strategy to focus on oil rather than natural gas production, Hutchings said.

“The principal driver in our desire to sell these assets at this point is really driven by that forward strategy, which today for the company is very much focused on liquids-rich resource plays,” he said, adding that Marathon has no substantive issue with the current regulatory or fiscal situation for the Cook Inlet oil and gas industry.

“With an effective date of Jan. 1, 2012, the sale includes 17 million barrels of oil equivalent of net proved reserves across 10 fields in the Cook Inlet, as well as natural gas storage, and interests in natural gas pipeline transmission systems,” Marathon said in an April 9 press release. “In 2011 net production averaged approximately 93 million cubic feet of natural gas per day and 112 barrels of oil per day. Additionally, Marathon Oil had approximately 12.5 billion cubic feet of natural gas in storage at the end of 2011.”

The company operates gas fields in the Beaver Creek, Cannery Loop, Kasilof, Kenai, Ninilchik, North Trading Bay and Sterling units.

The Marathon pipeline assets include the Cook Inlet Gas Gathering System that runs under the Cook Inlet, the Kenai Nikiski pipeline on the Kenai Peninsula and the Beluga pipeline on the west side of the inlet. The company also owns a gas storage facility in the Kenai gas field.

The sale does not include Marathon’s Glacier No. 1 drilling rig, which the company is marketing separately. And in 2011 Marathon sold its 30 percent share of the liquefied natural gas plant at Nikiski on the Kenai Peninsula to ConocoPhillips.

Yet to close

Hutchings said that the sale to Hilcorp will likely close in the fall, given the time needed to address issues such as the need for a regulatory review of the transfer of ownership of some assets. Hilcorp will likely retain most of Marathon’s approximately 62 Alaska personnel, he said.

The financial terms of the sale have not been disclosed.

However, the acquisition of Marathon’s assets would appear to be a logical move in expanding Hilcorp’s already substantial operations in the Cook Inlet basin.

“We are excited about taking over these (Marathon) assets in the Cook Inlet,” Lori Nelson, external affairs manager for Hilcorp Alaska, told Petroleum News April 9.

Hilcorp likes to come into an area to take on aging assets that have potential for further development, Nelson said.

“Legacy assets, just like what Marathon has on the table, are certainly key for Alaska and the key for a company like Hilcorp,” she said.

John Barnes, Hilcorp Alaska’s executive vice president, used to be Marathon’s production operations manager for the Cook Inlet, leaving that position in 2007.

The sale of Marathon’s Alaska asset will make Hilcorp and ConocoPhillips the dominant gas producers in the Cook Inlet basin. ConocoPhillips operates the Beluga River and North Cook Inlet gas fields. Aurora Gas, Armstrong Cook Inlet and Buccaneer Energy also produce Cook Inlet gas.

Cook Inlet milestone

The exit of Marathon from Alaska represents something of a milestone in the state’s oil and gas history. The company’s predecessor, Ohio Oil Co., bought interests in a number of leases on the Kenai Peninsula in 1954, with its early assets including a working interest in the Swanson River oil field, discovered in 1957. The company participated in the discovery of the huge Kenai gas field in 1959 and began supplying natural gas to the Anchorage utility market in 1961.

In partnership with Unocal (now part of Chevron), Marathon discovered the Trading Bay and McArthur River oil fields offshore in Cook Inlet in 1965. In 1986 Marathon set the Steelhead platform, the largest Cook Inlet offshore platform, for the McArthur River field. And on the Kenai Peninsula the company partnered with Phillips Petroleum (now ConocoPhillips) to build the Nikiski LNG plant, which went into operation in 1969, exporting LNG to Japan.

Marathon sold most of its Cook Inlet oil production in 1996 and after that focused on natural gas exploration and development. In 2000 the company commissioned and started using its own truck-mounted drilling rig, the Glacier No. 1, for its gas-well drilling. By 2006 Marathon had brought on line new gas fields at Ninilchik, Kasilof and West Fork while also maintaining gas production in operational fields through new development drilling. The company had implemented a new well completion technology, the Excape technology, to exploit the multiple reservoir sands that typify Cook Inlet gas fields.

In March 2010 Marathon drilled its last Cook Inlet basin gas exploration well in its Sunrise prospect, in Cook Inlet Region Inc. land inside the Kenai National Wildlife Refuge in the northern Kenai Peninsula. The company has not released the results of that drilling, other than saying that it “encountered a zone of interest.”

In 2006 Marathon commissioned its Kenai gas storage facility in support of its contractual obligations for the supply of utility gas during the winter.

A Third Phase; Brooks Range Petroleum aiming for the era of the small independent

Eric Lidji
For Petroleum News

With its announcement of a 40 million barrel discovery at its Mustang prospect, Brooks Range Petroleum Corp. is entering development mode after 13 years of exploration.

It could also be entering the third phase of the history of North Slope development.

After decades where only a few majors could afford to operate on the North Slope, the past decade saw the arrival of larger independents and new overseas entrants. With a commercial operation at Mustang, Brooks Range Petroleum could help usher in an era where many smaller independent producers could set up shop on the North Slope, too.

It would follow in the footsteps of Savant Alaska, the company now in charge of the Badami unit on the eastern North Slope, and Armstrong Oil & Gas, the pioneering independent that brought numerous big players to Alaska and is now working alongside fellow independent GMT Exploration Co and Spanish major Repsol E&P USA to explore a large swath of acreage extending across much of the central North Slope.

For the third phase to work, though, Brooks Range Petroleum believes the state needs to give smaller companies incentives to work together, to essentially mimic the abilities of those major companies, like many smaller fish swimming together to appear larger.

Long-held dream

If the third phase takes hold, it would fulfill a long-held dream among oil patch entrepreneurs, including John Jay “Bo” Darrah Jr. and Barton Armfield. They founded the Alaska Venture Capital Group in 1999 after watching majors pass over smaller North Slope fields that would be “company makers” in almost any other part of the country.

The company spent the next five years buildings up a portfolio of potential leads across the North Slope and creating a joint venture of independents to fund an exploration campaign. In 2006, it created Brooks Range Petroleum to operate activities on behalf of the joint venture. Today, Alaska Venture Capital Group owns leases, manages strategy and negotiates deals, while Brooks Range Petroleum provides technical and administrative services and handles operational expenses on behalf of the joint venture.

Currently, the joint venture includes Alaska Venture Capital Group and Nabors affiliate Ramshorn Investments, but previous incarnations also included the Calgary independents TG World Energy Inc. and Bow Valley Energy Ltd. (The British independent Dana Petroleum eventually bought Bow Valley and ultimately chose to sell its Alaska assets back to the joint venture to focus on the North Sea and Africa.)

Seven holes in five winters

Once getting its acreage, partners and financing together, the joint venture led by Brooks Range Petroleum quickly became one of the most active explorers on the North Slope.

In 2007, the group focused on the Gwydyr Bay region north of the Prudhoe Bay unit, an area long known to contain numerous smaller fields by North Slope standards. It acquired 130 square miles of 3-D seismic in the area and drilled the North Shore No. 1 and Sak River No. 1 wells. While Sak River No. 1 proved to be a dry hole, North Shore No. 1 found 70 feet of oil-charged Ivishak sandstone and flowed at 2,092 barrels per day of oil.

In 2008, the group focused on its leases near Nuiqsut. It shot 220 square miles of 3-D seismic around is Tofkat and Big Island prospects and drilled the Tofkat No. 1 well and two sidetracks, ultimately announcing a discovery in the Kuparuk sands in the region.

The following year, Brooks Range Petroleum formed the Beechey Point unit over its leases in Gwydyr Bay, including the Pete’s Wicked discovery it acquired in 2008.

In 2010, the group returned to Gwydyr Bay, drilling the Sak River No. 1A sidetrack and the North Shore no. 3 delineation well, but did not release results from either well.

That year, the group also acquired the North Tarn leases that became Mustang.

In 2011, the group drilled the North Tarn No. 1 well to test the Brookian and Kuparuk formations in the area southwest of the Kuparuk River unit. This year, the group returned to drill the Mustang No. 1 delineation well that confirmed the prospect. The Alaska Department of Natural Resources approved the Southern Miluveach unit at the prospect.

Meanwhile, the group also began studying development of its East Bank prospect within the Beechey Point unit and began inventorying other prospects at Southern Miluveach.

In the coming year, Brooks Range Petroleum could theoretically conduct as much exploration and development work as is has in its entire history until now. The company is slated to drill exploration wells in all five of its existing units in addition to a proposed well in a sixth unit yet to be approved by the state. While that’s going on, the company also plans to begin preliminary engineering for its development at Mustang.

Eyeing source rock potential

As a smaller player, Alaska Venture Capital is open to innovative development ideas.

Under the advice of Tudor, Pickering and Holt Co., the company is pursuing two potential development strategies. The first involves finding an investor that would fund initial costs until Mustang comes online, and later going public to raise capital. The second involves finding a producer willing to take a majority stake in the project.

Among the eight companies that have shown an interest in partnering with Alaska Venture Capital Group, one unnamed player is particularly interested in the potential for unconventional source rock plays. Alaska Venture Capital Group believes the western 100,000 acres of the joint venture’s more than 230,000-acre leasehold in Alaska are in the thermally mature area for the Shublik formation, and possibly the Kingak and Hue/GRZ, AVCG Managing Director Ken Thompson recently told Petroleum News.

The joint venture began discussing the source rock potential of its acreage at its companies meeting as early as the summer of 2010, according to Thompson. “We feel our JV’s almost 100,000 acres to the west around Tofkat, Big Island and even our Southern Miluveach unit area has source rock potential being in the right maturation and depth window. And we are also studying source rock and low-permeability sands potential in our Beechey Point unit,” Thompson told Petroleum News in March 2011.

The Shublik is more than 200 feet thick is areas of the western acreage, compared to 75 to 100 feet thick in other areas of the North Slope, according to Brooks Range Petroleum Vice President of Exploration Larry Vendl. The shallower depth of the Shublik in western area, around 13,000 feet, also makes it more likely to be in the oil window, Vendl said.

Sinclair’s Colville No. 1 well, just north the Mustang area, tested an interval around 7,900 feet deep in the Shublik source rock and recovered 510 feet of oil over two hours, Vendl noted. “While that oil volume was not exciting when oil prices were $10-20 per barrel, that volume is worthy of further assessment at today’s $100 per barrel,” he said.

Brooks Range Petroleum is currently conducting the standard assessments of the source rocks in its acreage to gauge performance, such as strength, brittleness, total organic carbon content, kerogen types, thicknesses, thermal maturity, and lithology variability.

Although bringing Mustang online by the first quarter of 2012 is the near-term priority for the company, Brooks Range Petroleum “is planning source rock horizontal well tests in 2014, but may elect to place a source rock horizontal well tail on a Kuparuk development well in 2013 as a lower-cost way to assess the source rock characteristics and flow capacity underlying the Southern Miluveach Unit,” Armfield told Petroleum News. The company is also considering added a horizontal tail on exploration wells in the Tofkat or Putu unit just to the west of Southern Miluveach to assess Shublik potential of its acreage closer to the National Petroleum Reserve-Alaska, Armfield added.

Noting the “excellent work” of Alaska shale frontrunners Great Bear Petroleum, Royale Energy and Halliburton, as well as ongoing efforts in the Lower 48, Alaska Venture Capital Group and Ramshorn “plan to be ‘fast followers’ versus being the source rock leader at this point in time,” Thompson said, “with the Mustang and other near-term developments taking priority to generate positive cash flow from oil production in early 2014, positioning for broader scale source rock assessment and development as well as continuing conventional geologic trap exploration and development.”

‘Field of Dreams’

As Brooks Range Petroleum approaches development, it is espousing the Field of Dreams philosophy for boosting North Slope activity: “If you build it, they will come.”

Specifically, that refers to infrastructure projects that improve smaller fields.

When the company applied to form the Southern Miluveach unit, it said Mustang could underpin development in the region by improving the economics of several marginal accumulations. “The other potential hydrocarbon accumulations are currently believed to be marginally economic and would not be developed without existing infrastructure and a processing facility within (the unit),” the company wrote. “Likewise, future development of the other potential hydrocarbon accumulation within (the unit) using the Mustang processing infrastructure will extend the economic life of Mustang production.”

When Alaska Venture Capital Group began, its principals anticipated improved access on account of terms in the Charter for the Development of the North Slope that encouraged the majors to open their facilities to independent producers. Because the charter did not dictate terms, though, negotiations under those terms have often been drawn out.

While Pioneer Natural Resources Inc. chose to enter into a facility sharing agreement with ConocoPhillips at the Kuparuk River unit when it brought the Oooguruk unit into production in mid-2008, its partner Eni Petroleum elected to build independent production facilities when it brought the nearby Nikaitchuq unit online in early 2011.

Brooks Range Petroleum plans to build a standalone modular production facility at Mustang, but the company believes it can improve the economics of smaller fields by building wisely and it believes the state can help the process along through tax breaks.

In a presentation to Commonwealth North in January 2011, Thompson said Alaska Venture Capital Group and other companies had identified numerous leads on the North Slope for potential fields in the range of 25 million barrels of less. He called these smaller accumulations a “new frontier,” on par with heavy oil and unconventional oil fields.

To promote development, he suggested a tax holiday on regional processing facilities until a sponsor recovers its costs. The developer, in turn, would agree to a published tariff with a 12 to 15 percent investor’s rate of return on facility capital and operating costs.

The facility would be open to all producers as long as capacity existed, and could accommodate additional producers in the future through expansions or back out clauses.

The optional credit would allow developers to take the tax break in return for set terms.

Cooperation is especially important for source-rock development, Thompson said. “If the source rock potential on the North Slope is to be truly unlocked to its maximum, multi-billion barrel potential, all in industry will need to work together and in unison with the state of Alaska. In particular, one of the biggest challenges facing potential development of thousands of source rock producing wells is the transportation logistics,” he said.

Because source rock development requires more drilling than conventional exploration, Thompson favors multi-well pads spaced about three miles apart and connected by relatively short gravel roads, similar to a scheme outlined by state engineers.

That’s where the Field of Dreams philosophy comes into play, he said.

Because of the logistics of moving rigs, equipment and supplies to that grid of remote pads, Thompson said that planning and possibly building environmentally friendly roads in advance of development “could be the single most important step to move the momentum of source rock development from this and next year’s ‘proof of concept’ to the following years’ full-scale, rapid development in the source rock fairway.”

The Thompson Plan

Additionally, Thompson proposed six other ideas for improving North Slope access.

Those include big issues such as reducing, eliminating or bracketing the progressivity rate on production taxes to give operators more of the upside during high oil prices, and fiscal certainty for future natural gas production to allow producers to reclaim costs.

It also includes two issues unique to independents. The first is extending the Smaller Producer Tax Credit to 2021. The credit pays up to $12 million per year to companies that produce less than 50,000 barrels of oil equivalent per day (and an increasingly smaller credit for companies that produce up to 100,000 barrels of oil equivalent per day), but is set to expire in 2016. The second is allowing exploration companies to be fully reimbursed for tax credits collected before production begins, rather than at 50 percent.

Thompson also supported Gov. Sean Parnell’s proposal for a 30 percent credit for well work to encourage infield development at legacy fields, and proposed a three-year tax holiday for viscous oil production brought online by 2016 and a five-year tax holiday for unconventional shale and low permeability developments brought online by 2021.

The BRPC management team

Today, Alaska Venture Capital Group is led by Managing Director and former ARCO executive Ken Thompson and Executive Managing Member Edger Dunne.

Brooks Range Petroleum is lead by Darrah, its president and chief executive officer, and by Armfield, its chief operating officer. The management team also includes:

• Vice President of Exploration Larry Vendl, who worked on the delineation and development of Prudhoe Bay in the 1980s and helped BP develop the Milne Point unit;

• Chief Geophysicist Larry Smith, who came to Alaska in 1997 as part of the team Union Oil Co. of California assembled to reinvigorate its exploration in the Cook Inlet basin;

• Senior Geoscience Advisor Doug Hastings, who played a role in the discovery of the Alpine and Tarn fields for ARCO Alaska during his 25 years on the North Slope;

• Engineering and Development Manager Mark Wiggin, a 30-year veteran of the Slope;

• Controller Tom Habermann, who managed development projects in Ukraine before working for the Arctic Builders Source and Mikunda Cottrell Accounting & Consulting;

• Drilling Manager Dan Shearer, another 30-year veteran of the Alaska oil and gas industry who helped bring the Alpine field online during his time with M-I Swaco.

• Special Projects Manager Laurette Rose, who splits time between the North Slope during the winter months and Anchorage for the remainder of the year for the company.

Video: Alaska Natural Resource Month

Steve Pratt was interviewed with the Political Insider team to discusses Alaska Natural Resource Month (March) , and Alaska Energy Kids Day at the Museum.

Special session called after legislature fails to pass oil tax changes

Tim Bradner
Alaska Journal of Commerce

It was a wild ride on the last day of the 2012 legislative session, and now Gov. Sean Parnell has called lawmakers back to take care of unfinished business – changes to the state’s oil and gas production tax.

On its closing day the Senate attempted to insert language reducing taxes on new oil developed on the North Slope into other bills, but the House balked and senators ultimately backed off.

The Legislature did pass a bill extending a generous set of investment tax credits and a reduced rate of tax for new oil and gas found in unexplored Interior and western Alaska basins, but the kind of comprehensive change Parnell wanted was not accomplished.

The bill for Interior basins, dubbed the “middle earth” incentive by legislators, was attached to a bill extending the state’s film tax credit program and another bill granting special tax treatment for new small business startups that emphasize new technologies.

All of these are now in Senate Bill 23, which passed in the closing hours of the session on Sunday.

Another bill that passed important to health care providers was House Bill 78, extending incentives to help recruit health care professionals in certain critical fields including primary care physicians to the state.

The bill provides for assistance in repayment of medical school loans and for grants to experienced professionals who agree to work in underserved communities, such as rural villages.

The state capital and operating budgets passed on the final day of the session, which is customary. There were few last-minute surprises in either bill.

The House added a set of its priority projects to additions the Senate had made earlier to SB 160, both on top of the governor’s capital requests which were in the bill he originally introduced. Parnell said he had left “room” in the bill for legislators to add projects but said he wanted the overall cost of the bill to be similar to that for the current year, about $2.9 billion including federal funds.

If the total cost of the bill as passed by the Legislature exceeds that Parnell may veto items to bring the price tag down.

The capital budget contains a wide range of new construction around the state, but two significant projects are two major new engineering buildings, one for University of Alaska Anchorage and the other for University of Alaska Fairbanks.

Also in the capital budget is $25 million for Alaska Aerospace Corp. as the state’s contribution toward a project expanding the Kodiak Launch Facility owned and operated by the state space corporation.

Contingent on the state funds, Lockheed Martin Corp. is raising about $100 million in financing for the project. The company wants to use Kodiak for launches of satellites with its Athena III rocket. At present the launch facility is too small to handle the Athena rocket.

Construction is due to begin this summer on the expanded launch project.

In the operating budget, House Bill 284, the only significant difference between the House and Senate versions was money for tourism promotion. In the end the budget conference committee opted for the higher amount as proposed by the House, $16 million for tourism marketing.

Parnell also supports that amount for tourism promotion.

Another important bill that passed was House Bill 250, extending the state’s renewable energy grant program for 10 years, until 2024. The current five-year program winds down next fiscal year, FY 2013.

Lawmakers also appropriated $25 million for new renewable energy projects in the Fiscal 2013 budget. So far the state has spent about $179 million to fund 310 projects, mostly small wind, biomass, small-scale hydro, heat recovery and geothermal projects.

Most of the projects serve small rural communities.

Read more:

Tuesday, April 10, 2012

‘Bigger than us;’ With proved 40M barrel discovery at Mustang, Brooks Range looks for capital

Kay Cashman
Petroleum News

Brooks Range Petroleum Corp. has proved up a 40 million barrel discovery on Alaska’s North Slope; that’s 40 million barrels of recoverable oil, which can be expected to produce for 15 years, yielding 13,500 barrels of oil per day at its peak.

The Mustang prospect, formerly known as North Tarn, in the new Southern Miluveach unit on the southwestern boundary of the Kuparuk River unit, held more recoverable oil than Brooks Range expected — in the Kuparuk sands, which had been the company’s secondary target.

“The Kuparuk is good quality sands with excellent pressure and oil flow capability,” Alaska Venture Capital Group LLC’s lead managing member, Ken Thompson, told Petroleum News April 3.

Mustang, its recoverable reserves established with four penetrations, plus three other smaller developments and numerous exploration upside anomalies on 230,000 acres of leases, is “bigger than us … bigger than both of us,” Thompson said, referring to the two companies that control the acreage in the unit — operator Brooks Range Petroleum’s parent AVCG and Nabors Industries’ Ramshorn Investments.

“We’ve had much more success than our owners can afford … more than we imagined. … Simply put Mustang along with our other development opportunities and exploration upside across the North Slope is much bigger than we are, so we are looking for a large partner, or partners, to share capital needs,” he said.

AVCG and its partners have spent “about 200 million dollars on exploration in the last 10 years, $40-60 million of that in the last couple of years, and we will now increase spending substantially to develop Mustang, confirm our other development areas and continue to explore,” he said.

It’s going to take “a few hundred million dollars to develop Mustang,” he said; a project that operator Brooks Range would like to see in production in early 2014 from seven horizontal producer wells and eight horizontal injectors, utilizing a standalone modular facility and a pipeline connecting to the Alpine pipeline which crosses near the wells.

“This year we went back in and deepened a well we started last year and got a confirming flow test. Then the second well, Mustang 1, came in with thicker sand and we didn’t need to drill another well, as planned. We decided to save our capital for development,” Thompson said.

Mustang just part of the story

The other fields AVCG and Ramshorn have in their joint, Brooks Range-operated, North Slope portfolio include “another 100 million barrels in reserves and resources in three other development areas that we have pieced together in the last several years,” Thompson said, as well as “numerous strat traps that are in the 10-50 million barrel range which add up to a valuable ‘string of pearls’.”

The anchor field will be Mustang, which could be larger than 40 million barrels of recoverable oil, as Thompson said there may be a Kuparuk formation extension to the northwest that would add additional reserves and field life, in an area the company calls Appaloosa, where Brooks Range will drill extension exploratory wells in the future.

Plus, there is the Brookian: “When we drilled North Tarn No. 1, we did encounter Brookian sands with oil shows but they were lower permeability than anticipated. Later in field development, we plan to test their commerciality with a long horizontal well and frac jobs ... or recomplete depleted Kuparuk producers into the Brookian sands with horizontals,” he said.

Three other development areas, 100 million barrels

The other three development areas that Thompson said hold about 100 million barrels in recoverable reserves and resources “need some delineation drilling before construction of production facilities. …”

“Four years ago Brooks Range had good results from an Ivishak oil flow test at Beechey Point,” the unit north of the Prudhoe Bay field, in the Gwydyr Bay region. And we know of other accumulations in what we call the East Bank development area of our Beechey Point unit.

“We also found Kuparuk sands right next to ConocoPhillips’ Nanuq field in our Tofkat well, and we mapped seismic anomalies in the Brookian and Jurassic sands,” Thompson said.

“Then we acquired leases just east and adjacent to the Badami unit, between it and Point Thomson, called our Telemark development. An oil well drilled in 1970 by one of the majors tested 750 barrels of oil a day in the Flaxman sandstones,” he said.

The nine-lease Telemark prospect, which Brooks Range is in the process of unitizing, wasn’t commercial at $18 oil, Thompson said, but today, with horizontal wells and higher oil prices, it’s a different story.

Up to 1 billion barrels, may be 30-40% producible

As for the smaller traps, as former president of ARCO Alaska, which pioneered 3-D seismic west of the Kuparuk River field, Thompson saw a lot of the 10-50 million barrel traps on seismic a decade or more ago, what he calls a “string of pearls.” And more recently with Brooks Range.
“Our joint venture, just in the last two years, has finally been able to analyze all the proprietary 3-D we have run. When we map our stratigraphic anomalies we see up to 1 billion barrels of oil recoverable … so with geologic chance factors, maybe 30-40 percent of that is producible. …

“Bottom line, we have a great portfolio of map-able exploration projects for the next three years, and beyond,” Thompson said.

Using Tudor, Pickering, Holt & Co.

Which is why Thompson, the man in charge of raising money for operator Brooks Range, brought in a Houston-based integrated energy investment and advisory firm to help assist in evaluating strategic options for AVCG and Nabors joint portfolio of Alaska North Slope leases.

“We have hired Tudor, Pickering, Holt & Co., the firm that pieced together the Armstrong/Repsol deal, to work on behalf of AVCG and Nabors,” Thompson said, with AVCG taking the lead and Nabors-owned Ramshorn also joining the process. Ramshorn and AVCG recently bought out TG World Energy, the third partner in the Brooks Range-operated leases.

“We’re looking for a partner that can come in and take a large portion of our working interest in return for funding. We want to move ahead this fall with the Mustang development. And next winter move on delineation of the other three development areas and continue a good level of exploration particularly on our western anomalies,” Thompson said.

They are open to an acquisition of the full or partial ownership of the assets or an equity investment into the holding company, AVCG, he said.

But Brooks Range’s preference is for a cash-based bonus component up front with a commitment to fund the forward program.

Alaska-grown oil company might go public

Tudor, Pickering is pursuing two funding strategies.
“We recently shared all of our data with five world-class private equity firms — in the energy industry they are the top five you’d want to have involved,” Thompson said.

“In strategy 1 they would invest all the capital for development and exploration until we get to first quarter 2014 when Mustang starts production. Once that happens we’ll have enough operating cash flow from oil production to fund everything else,” he said.

Then, “two or three years after that we’d go public, do an initial public offering, a stock market launch,” he said.

An IPO can be used to raise expansion capital and become a publicly traded enterprise.

“This interests us — and is viewed as innovative and distinct to some of the equity firms we’re talking to — because it would create an Alaska-grown, publicly traded, independent producer. It would be a first for the state,” Thompson said.

“But cash from private equity firms can be expensive, dependent on the share of the company they demand for the capital, so pursuing a second strategy makes business sense,” he said.

Strategy 2 is to find a producer, or two, in Alaska or elsewhere in the world, who is willing to put up the funds in return for a majority share of the working interests.

“We would like to continue to operate but some company might want to operate; we’re open to that discussion. And at the right indicative offer, we would enter into an exclusive arrangement with just one company to own part of or all the assets” Thompson said.

Of the three producers that have requested more detailed data or visited the data room Tudor, Pickering set up two months ago in Houston, and the five oil companies that recently requested to see Brooks Range’s drilling results from this winter’s drilling, most seem to want Brooks Range to operate.

“We’ve shared everything” with prospective partners, Thompson said, “from seismic, to lease and financial information, to logs from drilling. We’ve even run sophisticated reservoir simulations for Mustang and Tofkat development.”

Because of confidentiality agreements with the eight prospective producer partners, Thompson could not name them but, he said, they include “producing companies from all over the world; most have never been to the North Slope, but they are interested in Alaska, and some are there already.”

Besides being able to handle the funding of the Mustang development, “we’re looking for a partner whose culture fits our culture and is great to work with. Again, however, for the right price, we would divest all assets and turn over operations if required,” he said.

What about ACES?

What about Alaska’s production tax, Alaska’s Clear and Equitable Share, the production tax enacted in 2007, better known by its acronym, ACES? Are prospective producers paying attention to the debate in Juneau?
“Yes,” Thompson said, “they are watching. Some are even tapping into the Legislature’s website, watching committee hearings on the tax bills.”

“In the last two months, in dealing with planning groups and senior executives in these companies, they have all asked, ‘what is Alaska going to do on the tax regime?’ I have been honest with them; I tell them that I don’t think it will get worse, that there will probably be a modest improvement,” he said.

“Some of these companies are going to wait on the adjournment of the legislative session. It will effect what they are going to do.”

“This deal, finding a funding partner, or partners, can be a big step in helping level out North Slope production, so that more companies get interested in Alaska,” Thompson said.

Shale player’s main interest tight oil

One company that is looking at operator Brooks Range and all the leases it operates for the joint venture between AVCG and Nabors has told Thompson that “they find our conventional plays interesting but their main interest is our acreage that also has potential for unconventional source rock plays, the Shublik and other shales.”
“We own a little over 230,000 acres on the North Slope; 100,000 acres of that is out west, between Kuparuk and Alpine, right in the fairway with the right maturity for oil in the source rock shales. One company is evaluating that acreage for unconventional oil. They say our conventional plays lower their risk in the shales,” he said.

So what does Thompson, a petroleum engineer turned top executive for ARCO, turned independent player, think of his last few years, and future, with AVCG and Brooks Range?

“I have had so much fun; this last winter, especially. It’s like the old days for me. … The last time I was this excited was in 1994-95, when I first came to Alaska, and the well-site geologist faxed to my home the discovery confirmation well logs for the Alpine field,” he said.

Monday, April 9, 2012

House speaker: With six days left in session Senate sits on key bills

Tim Bradner
Alaska Journal of Commerce

JUNEAU — With six days left in the 2012 legislative session, the state Senate is still sitting on most of the heavyweight issues, House Speaker Mike Chenault said Monday.

“The Senate still has possession of the capital budget, oil taxes and House Bill 9,” Chenault said in a briefing by House leaders in the capitol. “We have the film tax credit and education bills on our side,” which are priority bills for senators.

House Bill 9 is the speaker’s own bill that beefs up the state-owned Alaska Gasline Development Corp. to build an in-state gas pipeline.

Meanwhile, over the weekend the Senate Finance Committee passed out its version of a state capital budget totaling $2.63 billion, including federal funds.

On increased education funding, one of the hot-button issues in the final week of the regular session, Chenault said he believes the House will come to agreement on a “package” of bills for schools by the end of the week.

“I won’t say SB 171 (the senate’s school funding bill) is dead, but there are a number of people on our side who are concerned with a three-year increase in the Base Student Allocation,” that is in the Senate-passed bill.

There are school funding issues of concern to the House, however, including energy costs and rising school bus costs.

“We’re trying to put together the whole picture,” Chenault said.

Most of the discussion seems to be in the back rooms, however, because the House Finance Committee has held no hearings on several education bills passed by the Senate.

One issue in the House getting intense attention is an extension of the state’s film tax credit program which would wind down next year unless extended by the Legislature. A subcommittee of the House Finance Committee led by Rep. Mia Costello, R-Anchorage, has been holding hearings and is due to report out a bill with proposed changes to the program Monday.

There has been intense lobbying on both sides of the bill by groups who see it as fostering a new film production industry for Alaska and others, including small Alaska filmmakers, who argue the program helps out-of-state producers more than them.

On the capital budget, Chenault said final agreements on the bill have yet to be made with the Senate but that the House is likely to add about $300 million in projects to the bill passed out of the Senate Finance Committee over the weekend.

Chenault said he is very frustrated with the senate over its inability, so far, to send its proposed oil tax bill to the House. Senate Bill 192 is still in the Senate Finance Committee.

“We can’t wait much longer. We don’t know what the problem is in the senate, whether there is trouble getting enough support to pass a bill or if the senate really wants to send us a bill,” Chenault said.

“It’s imperative that we put a tax system in place this year that will allow us to attract new investment. Otherwise we’ll just continue to watch the production decline,” he said.

On a possible extension to the session or a special session if there is an impasse on oil taxes or other issues, Chenault said he would rather have a special session than to just extend the session beyond the scheduled April 15 adjournment.

Extending the session would leave all bills in play, a distraction for legislators. A special session allows attention to focus on key issues.

If the governor calls a special session he will determine which issues are addressed, Chenault said.

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