The new state system of long-range oil production forecasting is based on the notion that it is better to aim low than miss high.
The latest state forecast says production in 2021 is likely to be 100,000 barrels a day below the estimate published last spring.
This doesn't mean oil company production plans for 2021 have been cut by 100,000 barrels a day.
It's just that the state is applying a "risk factor" to the gross production estimates it gathers from the companies.
So instead of expecting the pipeline to carry about 464,000 barrels that year, the new number is 366,000.
Any new project includes risk, so the revenue and natural resources departments said they've developed a formula to reduce the production estimates in light of the chance that the targets won't be met.
Previous forecasts have turned out to be too optimistic, mainly in terms of how much the smaller North Slope oil fields would produce and when.
The delay of projects ranging from Point Thomson to the development of the National Petroleum Reserve-Alaska has been an issue for many years.
Existing oil production has not been subjected to the risk factor reduction, but about half of the new oil the companies expect to be producing in 2021-from projects that are not yet in operation-is not counted in the new forecast.
Bill Barron, director of the Division of Oil and Gas, said projects may not be completed on time and they may not produce as much oil as the engineers predict.
The projects in question are listed by the state as being "under development" or "under evaluation."
He said projects under development have been identified by companies and approved by senior management, with funds approved for work by the companies.
Projects under evaluation are more uncertain.
"These are projects that are likely to occur in the future, but haven't really met the threshold of confidence that the industry says that they are going to commit primary funds for in a big way," said Barron.
"Every company is a little different. When the revenue consultant interviewed the companies, he would ask these types of questions: Is this project something that you would consider under development or under evaluation? And we kind of just let them tell us what they were going to tell us."
He said that some companies would regard a project as under development, when another firm would regard the same project as under evaluation.
"We just have to absorb some of that. What's important here is that the under evaluation really has more risk to it," he said.
In any case, a higher risk factor is attached to projects under evaluation than projects under development.
Missing from the forecast are exploratory projects such as shale oil, heavy oil, and major offshore projects in the Beaufort and Chukchi seas.
How and when projects move from the exploratory phase to the "under development' phase, for purposes of the state forecast, appears to be largely up to what the companies tell the state consultant from Colorado who collects the data, Frank Molli.
For instance, Repsol has drilled a couple of exploratory wells on the North Slope.
"If after this winter drilling season, if they feel like it is a project that probably will go forward, they would probably give us a forecast next year that will probably be classified under the under evaluation category."
In preparing the annual forecast, Barron said the consultant sits down with the oil companies and gathers the gross production data on what they expect to do.
"We don't ask them to put a risking component on. We've just actually over time just accepted the forecast they've given us on a gross basis," he said.
"What we then do in this new assessment is we look at what's the probability of that event occurring, in general what has the history been of those events occurring and associate then some risk in the out years," he said.
One of the projects under development today is the Point Thomson field, where the state says that a legal settlement with Exxon requires the company to produce 10,000 barrels a day by 2016.
But because the project is not in operation, the state has trimmed the expected production in its forecast.
Barron and Deputy Revenue Commissioner Bruce Tangeman said there is a risk that Exxon won't produce that amount, so the forecast has been adjusted by the same formula applied to other future projects that are still in the development stage.
The production forecast "was conducted independent of negotiations and terms of the settlement agreement," Tangeman wrote in response to a question I asked the department.
State officials said it would be subjective to change the risk factor for Point Thomson in light of the settlement and they wanted to be objective, applying the same formula.
So instead of 10,000 barrels a day in 2016 and climbing to 30,000 or 40,000 in the years that follow, the Point Thomson forecast is for 7,200 barrels a day in 2017, dropping to 4,800 by 2022. There is a big difference in these numbers.
The entire exercise of predicting oil production is subjective and the state should decide whether the legal agreement with Exxon can be counted on.
Dermot Cole can be reached at email@example.com or 459-7530.