State revenue forecast: prices up

Production decline will turn around briefly, but state revenues currently bolstered by new PPT, worldwide high oil prices

Kristen Nelson

Petroleum News

Oil prices are higher, but production rates are lower in the state’s fall 2006 revenue forecast than in the spring 2006 revenue.

The Revenue team of former Gov. Frank Murkowski, led by outgoing Commissioner of Revenue Bill Corbus, ran through the numbers when the Alaska Department of Revenue released its fall 2006 forecast Dec. 1.

For the current fiscal year, FY 2007, “we are projecting $59.15 (per barrel of Alaska North Slope crude oil on the West Coast); this is up from $53.60 for last spring,” Corbus said.

The current price projections are consistently higher: FY 2008, $51.25 vs. $46.90; FY 2009, $49.50 vs. $25.50; and between $40 and $50 through 2016, compared to the spring forecast of $25.50 per barrel over that period.

“We’ve changed the long-term price outlook from $25.50 to $41.50,” Corbus said.

The department “continues to believe that there has not been a structural change in the world supply/demand relationship that has prevailed over the last several years,” he said, with OPEC continuing to play an influential role, slowing but strong global economic growth, high prices that are encouraging development of new oil supplies and continuing price volatility.

Michael Williams, the department’s chief economist, said the methodology the department used has changed, although the protocol — only changing long-run price forecast a maximum of every two years — has not changed.

For this forecast participants were asked to come up with scenarios: most likely case, high case and low case. Williams said that back to 2000 the forecast used the mid-range of the Organization of Petroleum Exporting Countries basket of prices, and prior to that they used a 15-year or five-year average. “So what they’ve done over time has changed.”

Market dynamic

The Revenue Sources Book said “key topics are presented (at the forecasting session) to assist the participants in making their forecasts. For the fall 2006 forecast, the topics reviewed were worldwide economic growth, oil demand, oil supply (for the countries belonging to the Organization of Petroleum Exporting Countries or OPEC and non-OPEC countries), geopolitics and prices (history, forecasts from other organizations and results from the pre-meeting solicitation).”

After all the results were compiled and reviewed, the department’s economics team chose the most likely forecast for the fiscal years 2007 to 2013, but beyond 2013, “projects were very high and the department believed they were unrealistic given 146 years of crude oil price history,” so for the official long-term forecast the low case scenario was selected.

A graphic in the Revenue Sources Book shows that the high price scenario climbed to the $75 range by 2013.

Both price and volume important

Petroleum engineer Dudley Platt addressed the changes in production. Differences between the spring and fall forecasts for FY 2007 and 2008 are because “we’re recovering from the pipeline fiascos and we’re getting back to normal sometime during this fiscal year ’08.” Platt said production is expected to be “relatively stable over the next three or four years.”

On the “big, mature fields like Kuparuk and Prudhoe,” production is “relatively predictable,” he said. “We are starting to see some backfill to account or offset or mitigate that decline from fields such as Fiord and Nanuq, the ConocoPhillips’ operation going on near Alpine.”

Alpine itself has been “an overachiever,” Platt said, but “seems to have peaked and we’ll be looking at a decline from about this point forward” from the main field. Northstar is near the end of peak production and will be on decline.

“The ability to make up for declines in all those fields is directly related to capital investment to go after oils, basically heavy oils, that are known to exist,” Platt said. If that money is spent and the heavy oil can be produced from West Sak, Orion, Polaris and Schrader Bluff, “it will go a long way to mitigate some of that decline. It won’t completely offset it, though, so over the next five years you’re going to see a decline, but that’s premised on spending that money.”

What role for heavy oil in Alaska?

In addition to providing a primer on what heavy oil is, Revenue notes that the real issue with heavy oil in Alaska “is not the API gravity, but the ability of the crude oil to flow, or its viscosity. While API gravity provides a measure of its density (and economic value), it fails to incorporate the more difficult issues surrounding flow.”

And flow, the department said, is the real issue in Alaska.

One of the reasons for flow issues with Alaska heavy oil is that it is within 6,000 feet of the surface on the North Slope — close to the permafrost — “where temperatures are cooler, thereby reducing the oil’s viscosity or ability to flow.”

There are three major deposits of heavy oil in the world, that is deposits of more than 1 trillion barrels: Canada (some 1.86 trillion barrels); and Russia and Venezuela (each with about 1.2 trillion barrels).

Alaska, the department said, is at the next level with the potential of some 100 billion barrels of heavy oil resources, of which more than 20 billion barrels are known reserves with the possibility of billions more which could be identified.

Five fields produce viscous oil in Alaska, the department said: Orion, Polaris, Schrader Bluff, Tabasco and West Sak. Tabasco and West Sak are produced at the Kuparuk River field; Schrader Bluff is produced at the Milne Point field; and Polaris and Orion are part of the Prudhoe Bay unit.

The Ugnu is a viscous formation shallower than West Sak/Schrader Bluff — and closer to the permafrost — and there is currently no Ugnu production, Revenue said. Ugnu formation temperature is below freezing, it has an API gravity of about 8 degrees and a very high oil viscosity. “The billions of barrels of reserves in this formation are not economical to produce now, but someday may be,” the department said.

Developing viscous oil requires different technologies than those for conventional oil. “Steam flooding” has traditionally been used to get viscous oils to flow, although in the last 10 years new techniques, such as steam assisted gravity drainage, have been developed and CO2 or natural gas injection have also been used.

“All of these techniques require facility and energy expenses that are well beyond the requirements for producing traditional oil reserves,” Revenue said.

Alaska viscous oil production also faces a solid waste disposal issue, as significant amounts of sand are produced with the heavy oil. Some North Slope facilities were not designed with sand disposal in mind and must be periodically closed to allow sand removal. “As newer facilities are developed, they will likely integrate solid waste disposal,” the department said.

—Kristen Nelson