BP officials say current oil tax could impair LNG project


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Phil Cochrane

BP Exploration Alaska officials say the company’s shift toward exploiting near-term new conventional oil prospects in the producing North Slope oil fields and backing away from complex, long-term projects like heavy oil is a result of the state’s current tax policy that discourages long-term investments.

In a presentation to the Alaska Oil Support Industry Alliance’s annual “Meet Alaska” conference Jan. 11 and in separate interviews, the company also explained a link between needed new investment in the Slope’s oil producing fields and the planning for a natural gas pipeline currently underway.

The bottom line is that changes in the state’s oil and gas production tax are needed to encourage new investment in the oil fields, and that’s also needed to support hoped-for commercial gas production, the company told Alliance members.

“With the current fiscal climate, we are forced to change our course. That is to develop easier and proven light oil, and ensure we are efficient in all aspects of our business,” said BP Vice President for External Affairs Phil Cochrane during a presentation.

Things could always change, of course. BP said oil production is declining at rates of 6 percent to 8 percent per year in the North Slope fields it operates, and while there are substantial untapped oil resources in the Prudhoe and Kuparuk River fields that could help stem the decline, many of them are economically marginal and technically challenged, and producing companies including BP argue the state’s high production tax discourages their development.

Meanwhile, BP will actually increase the number of working rigs on the Slope to seven in 2013, up from six rigs, “but it’s important to understand how they will be used given he current climate,” Cochrane said.

“These rigs will be deployed in legacy fields and held accelerate production from existing reserves. They won’t search for or produce new sources of oil,” he said.

It’s also worth noting that in 2006 BP had 11 rigs at work in the fields it operates.

“This reflects a (new) strategy of draining the easiest and proven oil faster in an effort to offset decline and add cash flow in the near term. But this is a short-term solution to a short-term (state) fiscal policy,” Cochrane said.

The state’s high tax encourages short-term oil development strategies by taking most of the profit from investments at higher oil prices. Gov. Sean Parnell has introduced a proposed modification of the tax, a course BP supports.

Damian Bilbao, BP’s Alaska head of finance Alaska LNG, said in an interview that the company’s new strategy will focus on nearer-term projects that add production and do not involve large, long-term capital investment.

“There will be a lot of things done on existing pads where there is existing infrastructure. We likely won’t be building new production pads, which can cost $1 billion to $2 billion,” with the needed construction of infrastructure, involving gravel, new utilities and roads and new wells, he said. “Cash flow is important to us, so a big project that consumes a lot of capital has a hard time competing,” in the current environment.

The new plan will add production short-term without tying up a lot of capital for a period, which happens when new production pads are built.

What the tax policy particularly discourages is development work on new resources like heavy oil, which have marginal returns and tie up capital for long periods.

The experience over time is that once new projects like heavy oil begin producing the performance can be improved over time, but the ACES tax discourages that, Bilbao said. What this means is that BP’s work on heavy oil, viscous oil development and technically-challenged conventional oil projects will go on the back burner.

Cochrane said that overall industry investment in new oil development on the North Slope has fallen off sharply since the ACES tax was adopted in 2007.

“Last year only $1 out of $4 in BP’s capital expenditures went toward enhancing production in BP-operated fields. The remainder was spent on maintenance, operations and repairs,” he said. “Additionally, only one out of every five of our North Slope staff is involved in finding new oil or building projects.”

BP is one of the two major operating companies on the North Slope. ConocoPhillips, the other major operator, made similar comments about the effects of the state tax on Alaska capital investment.

About 70 percent of ConocoPhillips’ Alaska capital investment in its North Slope fields has gone toward maintenance, the company’s Alaska president, Trond-Erik Johansen, has said in presentations.

The concern for getting new investment into the oil fields affects planning for a large natural gas pipeline and liquefied natural gas export project, too.

BP, ConocoPhillips and ExxonMobil senior managers all said at the Resource Development Council annual conference this past November that continued oil production is needed to support gas production, and a reduction in the oil tax is needed to secure new investment.

Bilbao, at BP, said in the interview that oil must continue to support the producing infrastructure.

“When we look at LNG we are assuming a zero cost of supporting the production infrastructure. All the costs of supporting (field) pipelines and wells must be paid by oil, not LNG,” he said.

Maintaining existing infrastructure is vital because much of the known gas on the North Slope will be produced existing wells and facilities, Bilbao said. While this is a big plus for the Alaska gas project, in that little upstream investment is needed, the companies also don’t want to load several billion dollars per year of maintenance costs on top of an already-burdened gas and LNG project.

“Gas production could begin sometime after 2023 based on contracts over 20 to 30 years,” Bilbao said. “By 2050 and 2060 we will have 90-year-old production infrastructure at Prudhoe Bay. The only way this will work is if we know, at the time of sanction (2016) that LNG won’t have to carry the cost of (supporting) the oil facilities,” that there will be enough new oil production from the field to support operations and maintenance.

BP, ConocoPhillips, ExxonMobil and TransCanada, a pipeline company, are now engaged in the “concept selection” stage of the big gas project, which among other issues involves which south Alaska port, either Valdez or the Kenai Peninsula would be best for the pipeline terminus and LNG plant.

Once a concept is selected, which could be done by the end of February, the next decision is whether to commit to pre-Front End Engineering and Design for the project. This could happen by mid-year but it could be earlier, according to company officials interviewed.

Pre-FEED will involve “several hundreds of millions” of dollars in expenditures for engineering and would represent the first substantial spending on the LNG export plan. The State of Alaska is pushing the companies for faster action.

“We’d like an earlier commitment to pre-FEED, by February,” Alaska Natural Resources Commissioner Dan Sullivan has said in interviews.

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

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