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Elements of production forecast risked Fall forecast: oil revenues down from spring; Revenue, Division of Oil & Gas, rework methodology for longer-term crude oil forecast Kristen Nelson Petroleum News
The Alaska Department of Revenue rolled out its fall 2012 forecast Dec. 5, projecting lower unrestricted general fund revenues compared to the spring forecast. The department cited a lower oil price ($108.67 per barrel for fiscal year 2013 compared to $110.44 in the spring forecast) and lower production levels, 553,000 barrels per day compared to 563,000 bpd forecast in the spring.
The department also described changes in how it does its long-term production forecasts, which as Revenue Commissioner Bryan Butcher said, have been consistently too high compared to actual data.
The drop from the spring forecast in unrestricted general fund revenues for FY13, the current fiscal year, is 11 percent, from $8.44 billion forecast in the spring to $7.51 billion in the current forecast, a drop of $928.4 million.
Butcher said that in addition to the lower oil price and reduced production, companies spent more than expected in the spring forecast, revenue from the state corporate income tax came in weaker than expected and non-oil revenue was less than expected because of lower interest rates.
Total expected FY13 revenues, restricted, unrestricted and federal, are $14.610 billion in the fall forecast, down from $15.324 billion in the spring forecast; the total for FY12, the previous fiscal year, was $13.564 billion.
Company spending Company spending is an issue because of production tax credits. The credits, Butcher said, are “a combination of tax credits that go out to new entrants that don’t have a tax liability with the state as well as currently producing companies that subtract the tax credits off their tax liability.”
The figures for FY10 were $250 million refunded to companies with no tax liability and $412 million claimed by companies and used against tax liability, a total of $662 million. In FY11, $450 million went to companies with no offsetting tax liability and $386 million to companies with tax liabilities, a total of $836 million; the estimate for FY12 is $353 million to companies with no tax liability and $360 million to companies with a tax liability, an estimated total of $713 million.
Butcher said Revenue is estimating $800 million in FY13 and as much as $1 billion in FY14.
He said a lot of time was spent on the credit issue over the last legislative session and more time would be spent on it because of the increase from half a billion to as much as a billion.
The amount is substantial, he said, and when governors and legislators put those credits in law “they had a certain idea of what they were going to get for them.”
Over the last year the department has been digging back into historic numbers and requesting and getting more information from companies to get “a more detailed breakdown than they’ve ever given us before on what they’re spending on” so the state can “flesh out exactly what we are getting for those credits.”
Butcher said what concerns him is that if the price of oil drops the state could be looking at “potentially a multibillion-dollar deficit” and would still have up to a billion dollars going out to the companies, and that wouldn’t be a part of the state’s budget that could be reduced.
Five-year look back Bruce Tangeman, Revenue’s deputy commissioner for tax, said the department did a five-year look back last year and divided what the credits went for into categories. For calendar year 2012 the department will do the same breakdown into five or six categories.
The department is working with the companies to get more detailed categories starting in calendar year 2013, but that, he said, requires the companies to adjust their systems.
The ultimate issue is how much additional production the state gets for those tax credits.
Butcher said that for credits for companies without tax liabilities — those doing exploration — “it’s impossible to even try to quantify” the results. “We’re not going to know for years if the tax credits the state has made available ends up in increased production.”
And it “would be extremely difficult” even with companies already doing business to “define what extra amount of production” is a result of the tax credits.
A new tax bill Butcher said Revenue was working with the Department of Law on what would go into a tax change proposal, but said the credit issue is definitely “a piece of the entire pie that we’re looking at when you look at what the state gives and what the state receives. And what we’re getting for it is all part of one big equation,” he said.
This year, unlike prior to the 2011 session, Butcher said, “we’ve had the time, we’ve had the consultants, increased work with DNR, to be able to dig through these and really try to come up with as well-rounded an approach as we possibly can.”
He said the plan is to submit a tax bill to the Legislature in January and while Butcher said he didn’t know specifically what would be in it, tax credits are “one of the pieces we’re evaluating.”
Production forecasting On the issue of production forecasting, Revenue has been working to “come up with a more reasonable, more prudent way of doing a long-term revenue forecast that gets us closer to what we see,” Butcher said.
It’s something the department has been discussing for many years, he said.
Long-term, the department “has never forecasted over 2.5 percent a year decline,” Butcher said, while “we see historically 6 percent (decline) a year, so DOR hasn’t just been missing it long term, they’ve been missing it substantially.”
In its 2012 forecast, the department broke out currently producing, under development and under evaluation volumes “to try to inform folks that there’s less certainty in each of the buckets, in each of the tranches, but we didn’t do a lot with the actual numbers — we kept the process the same.”
This year, Butcher said, “working with DNR closer than we have before, we’re actually implementing a different way of moving forward and what we think is a lot more accurate way.”
Good technical information Tangeman said that in looking at how the production forecast had been done, the department realized the technical information was good, but budget issues were not included in the analysis. And while forecasts out one and two years were relatively accurate, longer-term forecasts, out six to 10 years, averaged an error rate of 40 to 60 percent.
Department of Natural Resources’ Division of Oil and Gas Director Bill Barron described the way production is broken out: current production, where fields and wells are online; fields or projects which are under development — have been funded and are in various stages of development; and under evaluation — fields where reserves have been identified as technically recoverable, but where evaluation is ongoing development funding has not been approved.
Confidence is high for current production, Barron said, but less so for timing and production in under development projects, and even less in projects which are under evaluation.
Tangeman said there are many examples of fields that were supposed to come on in a given year at a certain volume and came on later and at half the projected volumes. He said the department could see the examples in the history, “but we weren’t accounting for them going forward, and that’s really the crux of what we were trying to address,” adding risk factors to projects.
Satisfied with current production Barron said that when the division looked at data for currently producing fields they were satisfied — the well-by-well review done by Revenue’s consultant, aggregated by field — was technically good.
But for projects under development or under evaluation, the second and third tranches, there is increasingly less confidence, he said, and the division worked with Revenue’s economists to establish confidence levels.
The economists developed standard deviations for two sets of production data, one reflecting a period of higher production and the other representing a period of lower production, resulting in two different slopes which could then be used to test future forecasts.
The confidence levels were done by Revenue economists, with guidance from the division on timeframes.
More problematic Barron said fields and wells that are currently producing are not risked at all.
For oil under development and under evaluation, industry practice was assessed and two factors were considered — technical and budgetary — with more confidence placed on near-term projects and less on those farther out in time.
Technical issues include construction, rig problems and whether wells come on as expected or whether there were reservoir management issues. Then there are budgetary issues: Not product price, Barron said, but the timing and priorities of budgeting items within a company.
The system was then applied to past production projections, where the error rate had been 40 to 60 percent, and for projections six to 10 years out, the error rate dropped to between 25 and 30 percent compared to the actual.
Barron said numbers forecast under this new system won’t be right, they are only forecasts, but will be closer to what happens because they incorporate risks going forward.
As Tangeman summarized it, the previous production forecast system used “a 100 percent probability, best-case scenario” for new oil. “And that’s not reasonable or prudent for lawmakers and the executive branch in order to make these decisions long term.”
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