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Vol. 12, No. 43 Week of October 28, 2007
Providing coverage of Alaska and northern Canada's oil and gas industry

Small independent on board with ACES

Thompson: ACES train has left station, AVCG wants five things to remain in Palin’s bill, four to be changed, favors 22.5% rate

Kay Cashman

Petroleum News

By mid-2008 Alaska Venture Capital Group and its partners will have invested more than $100 million in their oil and gas properties in Alaska, including drilling two exploration wells last winter, one of which was a dry hole. Small, Kansas-based AVCG entered the state in 1999, participated in the past seven North Slope areawide lease sales and acquired acreage from other companies. AVCG and its partners, which are part of the Brooks Range Petroleum Corporation Group, currently hold more than 300,000 acres of exploration leases in five exploration prospect areas on the North Slope.

Neither AVCG, nor the three partners it brought in last year, have produced any oil in Alaska that would help them recoup their investment, which is expected to include as many as four new exploration wells this coming winter.

On Oct. 22 Ken Thompson, AVCG managing director, told members of the Alaska Legislature that it would be small independents like AVCG and its partners who would produce the relatively small pockets of oil remaining on the Central North Slope outside of existing, mature, units.

In the “10 to 100-plus million barrel range,” Thompson said the fields “may be too small for the giant producers” but could be “company makers” for a small independent.

“We believe there are hundreds of millions if not billions of barrels of oil left on the Central North Slope in smaller fields of this size for small independents like ours that want to take this type of exploration risk,” he said.

Tax change bad for investment

But those independents won’t invest in Alaska if the state raises its taxes again this year, the former president of ARCO Alaska told legislators.

When Thompson was recruiting AVCG’s three partners in 2005 and 2006, many of the investors he approached “were concerned about the threat of tax increases in Alaska. PPT proved tax increases were not a threat but a reality. Adding yet another tax increase via the ACES bill this year shows instability in Alaska’s tax policy which results in uncertainty and risk when making investment decisions,” he said.

Thompson testified by phone before committees that had invited comments from the oil and gas industry as part of a special session called by Gov. Sarah Palin to remove what she calls the taint of bribery on the Petroleum Profits Tax that was passed in 2006 with the support of legislators who have since been indicted on bribery charges in an FBI probe that promises to extend to other legislators. Palin’s administration, with the help of expert advisers, spent the last few months putting together a revised production tax proposal called Alaska’s Clear and Equitable Share bill, or ACES, which, among other things, includes a 25 percent increase. Palin says the new plan is needed because PPT is projected to bring in less than expected.

“In FY 2008, based on forecasted price and production levels, the PPT is expected to generate about $250 million over that which would have been generated under the ELF system. However, this is more than $800 million less than what was predicted in the PPT fiscal note,” the Alaska Department of Revenue said in its status report released midsummer 2007.

Would like to see PPT run its course

PPT is a tax on profits, a net tax, and replaced the state’s previous production tax, commonly known as ELF, which was a tax on the gross. ACES is a hybrid tax, part net and part gross.

Thompson, like almost everyone else from industry who testified at the beginning of the 30-day special session, prefers that PPT “be allowed to run its course” for a few years.

“My ultimate wish,” he said, “would be … to leave PPT alone and re-review it under the law as planned in 2011 or perhaps even in 2010. But the ACES train has left the station and cannot be stopped.”

Thompson said he agreed with Dr. Pedro van Meurs, “that in the light of declining oil production in the State of Alaska and prospectivity trending to smaller field sizes, the state should not once again increase its taxes after having done so last year.”

‘Bad apples’ pushed for 20% tax

“I heard that consultant Daniel Johnston differed strongly from Dr. van Meurs and urged the oil industry to understand the ‘cloud of corruption’ over the existing Petroleum Profits Tax … that this alone provides a good reason to change PPT. I challenge Daniel Johnston that the bushel should not be thrown out because of a few bad apples,” Thompson said, pointing out that legislators accused of taking bribes supported a 20 percent base tax rate, not the 22.5 percent rate that was adopted for PPT.

Thompson also reminded legislators that the “progressivity tax was added at high oil prices to drive the real tax rate to even higher levels than 22.5 percent, with a range exceeding 30 percent now possible at certain prices.”

He also noted that oil companies were also being hit with other taxes and fees, including royalties on production, corporate taxes, ad valorem property taxes, and environmental and permitting fees.

Aces train moving fast

But, Thompson said he would support ACES in hopes of making it a better piece of legislation.

“I am politically astute enough to know that the ACES train is moving fast down the track, so I can stand out of the way or jump on board and try to make the ACES bill better before we reach derailment in the long-term relationships between this industry I love and this state I love,” he said. (After serving as ARCO Alaska’s president from 1994 to 1998, Thompson left the state for three years to take the position of executive vice president for ARCO Alaska’s parent, Los Angeles-based ARCO, heading up global oil and gas exploration for the company before it was snapped up by BP, and ARCO Alaska’s assets were sold to Phillips Petroleum, at which time Thompson moved back to Alaska.)

Keep five things in ACES

In reviewing the ACES bill, Thompson said there were five things his company liked, and four things it would change.

Keep the exploration and development investment tax credits, he said.

The exploration tax credits, which range from 20 to 40 percent in both PPT and ACES, are important for a small explorer startup company like AVCG.

Cash refunds to companies like AVCG and its “working interest partners via the credits mean that we can apply that cash to our capital budget the next year to run adequate seismic and do additional drilling that increases the chance of more oil production and reserves for us and for the state,” Thompson said.

Likewise, the credits for losses for a small company while its establishing production — and the development investment credit — “can take substantial risk out of development” of the smaller fields AVCG’s joint venture is focusing on.

Thompson also wants to keep the “standard tax deduction/exemption for smaller companies.”

“The Small Producer Tax Credit that exempts up to the first $12 million in production taxes for smaller companies” allows them to “return a larger share” of annual cash flow for exploration and investment while they build a company to a “critical mass of reserves and production necessary to expand staffing and have a routine level of major capital spending each year,” he said.

And, he said, keep the new ACES tax credit allowance for qualified delineation wells.

Thompson likes a proposal in ACES that would make it possible to get a tax credit allowance for drilling up to two delineation wells following a discovery. This, he said, would be “very helpful” to both small and large explorers, because one well is often “not enough to determine if field size is large enough to warrant development.”

“A real case in point,” Thompson said, is AVCG. If the company should make a discovery this winter at its Tofkat exploration well on the western side of the North Slope, “we will have to drill one or two delineation wells to confirm if field size is sufficient to develop the resource. … Often, due to the nature of these complex stratigraphic traps where sands unpredictably come and go, the delineation wells can be almost as risky as the initial exploration well. Having a credit where the state, in a real sense, is sharing in the risk will — I think — expedite delineation of new fields and advance development for revenues.”

The fifth thing Thompson wants to keep in the ACES bill is the Oil and Gas Tax Credit Fund, which could be used to purchase certain tax credits from explorers and producers.

“This ACES provision would establish a procedure and standard for appropriation into this fund and management of this fund,” he said. “Having a clear and transparent way for small explorers to receive their credits at full value is extremely important for AVCG to then be able to plow those credits back into seismic and exploration on the North Slope.”

Things to change

Change the recovery of tax credits from two years as proposed in ACES back to the recovery of credits in one year currently provided for in PPT, Thompson advised.

Under PPT a company could file for the various credits, and if approved, would receive full capital credits up to a maximum of $25 million per company. In the new ACES law, while the cap has been removed which Thompson said “is very positive,” the credits are “refunded over two years instead of over one year, e.g., 50 percent of qualified credits can be applied for in the first year once a well is completed or abandoned and 50 percent in the following year.”

For a small company like AVCG, this component in ACES will “definitely affect our capital spending in a given winter as we plow all the credit refunds back into seismic or exploration drilling.”

Thompson offered as an example, AVCG and its working interest owners plan to spend $41 million in seismic and exploration drilling this coming winter and about the same in 2009.

“We calculate that we could receive $16 million cash in qualified credits in midyear 2008,” he said. “So essentially, our working interest owners are planning to provide cash out of pocket of $25 million for the 2009 drilling season. This is a fixed number based on cash availability in these small companies to spend toward the Alaska portfolio. If the state refunds only one-half of this credit in the first year, or only $8 million instead of $16 million, AVCG and our partners will still provide $25 million out of our pockets as now planned and budgeted … meaning our overall spending in 2009 will be $33 million, not $41 million, i.e. $25 million from our available funds and only $8 million from the state,” resulting in one less well in 2009. “And one less chance for another discovery that eventually could provide revenues to us all.”

An “innovative compromise,” he said, would be for the Legislature to consider a small company refund provision that “allows for companies that meet the no-production or low-production measures in the Small Company Tax Credit provision of the PPT law — that remains in ACES — to receive tax credit refunds that are fully refunded in the first year for qualified costs.”

Average government Gulf take is just 45%

Number two on Thompson’s list of things to change was the base tax rate, from 25 percent in ACES back to 22.5 percent in PPT, “re-reviewing … again in 2011 after some time has passed as allowed for in current law.”

What is fair, and how exactly is “fair” determined?

Thompson’s answer: “I saw a copy of a presentation entitled Guiding Principles For A New Production Tax System by the Department of Revenue urging the changes in ACES, arguing that the average government take in various international countries averaged 67 percent for all types of fiscal regimes … 74 percent for production sharing agreements, but only 55 percent for tax and royalty regimes. … Somehow, the Department of Revenue representatives concluded an average of 68 percent as provided for in ACES would be close to the average of 67 percent for all types of regimes internationally.

“First,” he said, “the average recommended to Alaska is the average of all regimes, i.e. the averaging of government take from tax and royalty regimes with the government take from production sharing agreement, PSA, regimes.”

In the countries Thompson worked in that had production sharing regimes, “the risk profile for capital development was often much different that in regimes that use a tax and royalty regime such as Alaska. In PSA countries, it was not unusual for a producer on capital projects to have a very low initial tax burden until the capital investment was fully recovered plus a negotiated rate-of-return was achieved. Then and only then was the government take increased substantially … thus giving the average take for such countries as 74 percent.”

But the risk profile in those countries “was often much better than Alaska,” because there was “upfront recovery of capital and a preferred investor rate-of-return,” he said, noting that ACES high tax rate and the added progressivity tax will start immediately along with royalties, corporate taxes, property tax and other charges “instead of allowing for recovery of capital and a contractual rate-of-return,” as is the norm in PSA regimes.

Main competition from U.S.

He also noted that most individual and company investors, including AVCG’s, “do not consider international regimes as competition for our investment dollars with Alaska. Rather, the main competition for their cash is other parts of the United States.”

“I found it astounding … that the average of 67 percent for all international regimes did not consider weight-averaging in the major American producing states,” Thompson said. “As examples, the current government take in the Gulf of Mexico offshore — one of the main competing areas for Alaska investment dollars — averages 45 percent. This is under consideration by the U.S. government for increase, but it is highly doubtful with the boom going on in deepwater exploration and development that the U.S. government would increase the government take from 45 percent to 68 percent,” which is what it would be under ACES as it is written.

In other producing states that compete for AVCG investment the state and federal combined government takes in 2006 averaged 45-57 percent and were as follows, Thompson said.

U.S. Gulf of Mexico 45 percent

Colorado 51 percent

Wyoming 52 percent

Kansas 53 percent

Texas 53 percent

New Mexico 53 percent

Oklahoma 53 percent

California 53 percent

Louisiana 57 percent

“To my knowledge, these states do not have the added progressivity surcharge tax which further separates Alaska in government take from these competing states,” he said. “I would argue that Alaska should have a government take of 55 percent if we were to maintain long-term competitiveness with these other states for investment dollars. Having said that, some of these states do not have the prospectivity of Alaska, so Alaska could command some premium in take but certainly not as high as being proposed in ACES.”

If Alaska set a government take at 60 percent to the government and 40 percent to the investor, the ACES legislation should be amended to allow for a base tax rate of 22.5 percent not 25 percent, Thompson said, and should also be amended to allow for a trigger price of $40 per barrel and not $30 per barrel; plus, the incremental progressivity tax rate increase should be 0.2 percent per dollar.

State should share in reward, and risk

His argument for changing the trigger price to $40 per barrel net vs, $30 per barrel, number three on his list, is that if the government take is to be 60 percent and not 68 percent as proposed by ACES, the trigger price “should stay the same as in the PPT law, i.e. $40 per barrel net.”

“If Alaska is to share in high prices with the progressivity surcharge tax, then Alaska should share in the pain of low prices,” Thompson argued. “To amend the trigger price lower when and if prices collapse will be a false economy measure for the State of Alaska. When prices fall and a company’s cash flow is sharply reduced, capital spending will fall.”

Number four on his list is to consider some type of transitional investment expenditure tax credit.

“This provision allowed for in PPT was repealed in ACES,” Thompson said. “While this provision does not greatly benefit our company, AVCG, because we did not have large seismic or exploration drilling costs between March 31, 2001, and April 1, 2006, it is important to other major investors in Alaska.”

He offered ConocoPhillips, the state’s largest explorer and developer, as an example because “with the ARCO heritage assets” ConocoPhillips “was hardest hit in tax exposure with the change from the old severance tax law to the PPT and now to ACES.”

“I simply think allowing a good steward who is the largest explorer in Alaska some transition allowance to ease the pain of greatly increased taxes is the right thing to do and can only build better, more trusting relationships,” he said.

The BRPC Group consists of AVCG, its operating subsidiary Anchorage-based Brooks Range Petroleum Corp., and its three co-ventures — Calgary-based TG World Energy Corp. and Bow Valley Alaska Corp., and Ramshorn Exploration, which is a subsidiary of Ramshorn Investments Inc., a Houston-based private equity firm that is a wholly owned subsidiary of Nabors Drilling USA.

Thompson said AVCG is “a privately held member LLC comprised of private equity investors made up of 15 independent oil and gas companies and individuals from Kansas and me as an owner/member partner from Alaska.” He told legislators “AVCG/Brooks Range Petroleum likes to think of our company as ‘Alaska’s independent oil and gas company.’”

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BRPC to drill 3-4 wells on three prospects, North Shore development possible

In testimony to the Alaska Legislature on Oct. 22, Alaska Venture Capital Group Managing Director Ken Thompson said AVCG and its joint venture partners in Brooks Range Petroleum Corporation Group are hoping to drill as many as four wells this winter on three different North Slope prospects. The BRPC Group, Thompson said, will first go back in to complete and test its North Shore exploration well, which was drilled in the winter of 2006-07, and was one of the first two exploration wells operated by the partners on Alaska’s North Slope.

Both 2006-07 wells were drilled in the Gwydyr Bay area northwest of Prudhoe Bay. The Sak River No. 1 was a dry hole, but earlier this year the BRPC Group said the other well, North Shore No. 1, looked like an oil strike. “We plan to complete and test this well this winter,” Thompson said.

The partners also ran a 130-square mile 3-D seismic survey over both their acreage and surrounding acreage, in their Gwydyr Bay prospect area last winter, investing more than $44 million on land, seismic and drilling, he said.

“This winter our joint venture group will be among the most active of explorers as we plan to shoot over 200 square miles of new seismic data on the extreme western and eastern sides of the Central North Slope and to drill up to four exploration wells.”

The BRPC Group, which has Nabors 27 Rig under contract, is planning to drill one or two wells near North Shore No. 1, Thompson said, in hopes it “can discover a sufficient volume of oil to warrant a commercial development at Gwydyr Bay.”

The partners are also planning to drill a prospect south of the Alpine field, which is part of ConocoPhillips’ Colville River unit.

“We will drill our Tofkat No. 1 well … and also drill a fourth exploration well on a prospect to be named,” spending more than $40 million on seismic and drilling in the winter of 2007-08, Thompson said.

If the “North Shore oil completion test is as suspected and one of the wells strikes oil close by, we may proceed with North Shore development with more substantial capital investment in the winter exploration season of 2008-09.”

On the same day Thompson was testifying, TG World Energy Corp. sent out a press release with more detailed information about the BRPC Group’s plans. (The BRPC Group consists of AVCG LLC, its operating subsidiary Brooks Range Petroleum Corp. and its co-ventures TG World Energy, Ramshorn Investments Inc. and Bow Valley Alaska Corp.)

TG World said the North Shore No. 1 well, in which it has a 35 percent working interest, reached a final total vertical depth of 10,319 feet (13,309 feet measured depth) in the Ivishak formation and was cased as a potential oil producer. The well’s bottomhole is approximately 1,100 feet west of the 1974 Mobil Gwydyr Bay South No. 1 well, which TG World said was reported to have flowed at an average of 2,263 barrels per day on production test from the Ivishak formation.

In the Titania prospect area, the Tofkat No. 1 exploration well’s reservoir target will be the Kuparuk sandstones, TG World said, describing the prospect as “seismic-defined” and noting that the Nanuq field in the Colville unit 5 kilometers northwest from Tofkat, produces from the Kuparuk.

If Tofkat No. 1 is a discovery, the partners “may choose to drill a sidetrack well this winter season to help delineate the reservoir extent. Under the terms of the joint venture arrangements, TG World will, by paying 35.7 percent of the well costs, earn a 25 percent working interest in the complete Titania prospect area,” TG World said.

Three-dimensional seismic data acquired by the partners in the winter of 2006-07 over the Gwydyr Bay prospect area “has identified two small satellite prospects to North Shore No. 1 that can be reached from the North Shore No. 1 drilling pad,” TG World said. “The first satellite prospect is expected to be drilled after Tofkat No. 1 well operations are completed,” the company said, noting that it has a “35 percent working interest in the satellite prospects.”

The first North Shore satellite, if successful, “could be a catalyst for North Shore field development,” TG World said.

The partners expect to select another well to drill during the 2007-08 season “from prospects in the Gwydyr Bay area covered by proprietary 3-D seismic data,” TG World said. “Final prospect selection is awaiting delivery and interpretation of the pre-stack depth-migrated seismic volume,” the company said, noting it has a 35 percent working interest “in the relevant leases.”

TG World also said, “a CGG-Veritas seismic crew has been secured for a one-month slot. The joint venture plans to acquire up to 200 square miles of 3D data over portions of its lease holdings in the Slugger and Titania/Big Island prospect areas. Prospects developed from these surveys would be candidates for drilling” in the 2008-09 and 2009-10 winter seasons. TG World is paying 25 percent of the costs of the seismic program.

—Kay Cashman