Alaska’s $6 billion question

To meet production forecast substantial new investment required

Larry Persily

Petroleum News Government Affairs Editor

The Alaska Department of Revenue estimates North Slope producers will need to ante up $6 billion in capital spending in fiscal years 2006-2008 if the region is to reverse its declining production by 2010 and meet the state’s production forecast. (Fiscal years measured by the state start in July and end in June, whereas slope producers’ budgets are figured from January to December.)

At an average $2 billion per year, that much spending would be almost double the producers’ capital budgets for 2002-2004 when no new major projects were under construction on the North Slope.

A significant chunk of the $6 billion would be needed to develop the Point Thomson field east of Prudhoe Bay and the National Petroleum Reserve-Alaska west of Prudhoe Bay, and to boost heavy oil production at West Sak, Revenue reported. The department’s spring forecast shows those three fields supplying almost 20 percent of the slope’s entire production by 2010, Dan Dickinson, Tax Division director at Revenue, said in a recent presentation to the Alaska House Ways and Means Committee. His testimony came during consideration of legislation to amend the state’s production tax, raising the rate when oil prices are high.

The spring forecast shows North Slope production falling from a fiscal 2004 average of 985,000 barrels a day to 928,000 barrels in fiscal 2009, then rebounding to 978,000 barrels in fiscal 2010 with more than 170,000 barrels expected from Point Thomson, NPR-A and West Sak.

That’s why the department sees the need for a timely jump in capital spending. “It’s got to happen over the next four years or so,” said Chuck Logsdon, chief petroleum economist for the Department of Revenue.

State counts on Point Thomson, NPR-A in fiscal 2009

The state’s capital spending estimates are based on several assumptions, Dickinson said:

• $2.35 per barrel in ongoing capital spending to maintain producing fields.

• $2.50 per barrel for new onshore field development.

• $4 per barrel for offshore field development.

• And a three-year development schedule for new production.

The department’s $6 billion spending estimate “is driven by those rules of thumb,” Dickinson said, not by budget plans provided by the companies.

Point Thomson at 70,000 barrels in 2010

Any development decision on Point Thomson, a high-pressure gas condensate field on the Beaufort Sea, just off the western edge of the Arctic National Wildlife Refuge, is likely tied to plans for a pipeline to carry North Slope natural gas to market. The Revenue Department capital spending assumption does not include the costs of the proposed gas line.

“Based upon a combination of cost and resource estimates, a project to recover condensate (at Point Thomson) prior to gas sales is not viable under the current fiscal system,” ExxonMobil Houston spokesman Bob Davis said April 28.

The field owners — with BP and ChevronTexaco holding significant shares along with Exxon — have spent more than $800 million over the years, including drilling 19 exploration and appraisal wells, Davis said.

Meanwhile, ExxonMobil continues looking at how it could develop the field, Davis said.

ConocoPhillips says NPR-A flow could start in 2008

ConocoPhillips has interests in 1.1 million acres in NPR-A.

The Revenue Department forecast shows the first oil from NPR-A in fiscal 2009, starting at 3,000 barrels a day, then building to almost 100,000 barrels a day by 2015.

ConocoPhillips is also the operator at West Sak, a shallow, viscous oil reservoir above the Kuparuk field. West Sak started production in 1997 at 250 barrels per day. This year’s flow is running about 9,000 bpd, with the department projecting that heavy capital spending and new technology will boost that total to 29,000 bpd in fiscal 2005 and then 80,000 bpd by 2010.

Horizontal, multi-lateral wells and regulatory approval of new wells from a drill pad on the west side of the field will help increase production, the state reported. The new drill site by itself could produce more than 30,000 bpd, ConocoPhillips reported in January.

The federal environmental impact statement for the company’s proposed NPR-A development is expected later this year.

How probable is a $6B capital investment?

Kay Cashman

Petroleum News publisher and managing editor

In fiscal year 2010, 170,000 barrels per day of the 978,000 barrels projected are expected to come from new North Slope developments at Point Thomson, NPR-A and West Sak.

Van Dyke pointed out that the last three green-field developments were all prior to 2002 — Badami, Northstar and Alpine.

“So yes, the investment in fiscal years 2002 to 2005 is down in relative terms to some of the even earlier years. (There has been) lots of drilling but not a lot in the way of new facilities in the last few years,” Van Dyke said.

And the last few years represent North Slope “facility sharing at its best,” which he said is probably not allowed for in Revenue’s spending estimates. “Needed new investment may be lower relative to past spend due to facility sharing,” Van Dyke said.

“NPR-A and the heavy oil (West Sak, Schrader Bluff and Orion) look solid so I think that extra money will be spent. Point Thomson is the wild card. Who knows what Exxon/BP/Chevron will do? If they don’t go forward at Point Thomson then the production forecast will be off by that amount. On the other hand maybe Pioneer and Kerr McGee will get some new oil on line by then to fill that void,” he said, referring to successful exploratory drilling in the last two winter drilling seasons by two new North Slope players.

“There is no absolute answer looking five or 10 years out, and yes there is some uncertainty in the forecast. That’s why it’s called a forecast. There is some chance that the actual production numbers will be lower, but likewise there is some chance that they will be higher,” Van Dyke said.