DNR refines Slope production forecast
In second year of in-house forecasts, Division of Oil & Gas notes changes made based on results from last year; production grows
Alaska has now seen two consecutive years of crude oil production increases and appears to be on track to see a third year of increases, Ed King, special assistant to the Alaska Department of Natural Resources commissioner, told House Finance Oct. 25. Production averaged 501,000 bpd in fiscal year 2015, he said, rose to 514,900 bpd in FY 16 and to 524,000 bpd in FY 17.
July-October FY 17 averaged 484, 581 bpd, and July-October in the current fiscal year, FY 18, averaged 488,792 bpd.
King illustrated the short-term forecast for FY 18 (July through June) compared to the FY 17 actuals and the July through October actuals for FY 18. He noted that the forecast varied from the actuals in July and August, but that September and October actuals were tracking the forecast.
King said major increases in FY 16 over FY 15 came from the Colville River unit, some 7,000-8,000 bpd, mostly reflecting CD-5 production. Prudhoe Bay had a similar year-over-year increase and that, he said, is mostly from operational efficiencies, what he called really good management by the operator. There was an increase at Nikaitchuq which came from new wells. FY 16 to FY 17 increases came from similar sources, with CD-5 continuing to be drilled out and continued efficiencies at Prudhoe.
Industry performance is impressive compared to previous trends, King said. Before the last two years, there was a production decline of about 5 percent a year, he said. FY 17 actual production compared to the trend shows Prudhoe By up some 27,000 bpd; Colville River up some 17,000 bpd, mostly from CD-5; the Kuparuk River unit up some 5,000 bpd, mostly from Drill Site 2S. There were also smaller increases at Endicott, Milne Point and Northstar, where Hilcorp has recently taken over operatorship - and increasing production from older fields is a focus for Hilcorp, he said.
Asked how much of the Prudhoe Bay increase was operational compared to rework and new wells, King said BP is running only one or two rigs, compared to five in previous years, so this isn’t new wells, it’s something else, describing it as very effective base rate management and deferral management, doing more with that they have and more efficiencies. All the easy oil is gone now at Prudhoe, he said, it is mature and producing at a fraction of its peak rate, which makes it easier to manage the decline rate - you don’t need as much improvement to mitigate a lower decline, King said.
Forecast changeKing compared the fall 2016 forecast with the preliminary fall 2017 forecast and talked to the changes. Last year, he said, we didn’t have the last 12 months of data. Analysts looked at what they did have - capital expenditures were down 44 percent and the price was down.
He said the assumption was that with capital expenditures reduced (down 44 percent in 2016 compared to 2015) and fewer rigs operating, that the result would be an acceleration in the production decline.
What actually happened, he said, was that operators outperformed expectations - doing more with less.
Not only did production outperform the state’s forecast in FY 17, it outperformed the combined operator forecast, with the operators outperforming what they thought they could do.
By March, King said, it became evident there might be something wrong with the forecast and a revised forecast was issued with a shallower decrease.
King said last year was the first year DNR took over the forecast. Part of the forecast model incorporated some economic testing because the department wanted to make sure projects were profitable before they were plugged into the model. One thing they realized, he said, is that once projects are sanctioned they tend to go ahead. Now, he said, we’re starting to see operators are able to find ways to improve - so the model is evolving.
Methodology changesPaul Decker, a geologist and resource evaluation manager at DNR’s Division of Oil and Gas, noted that this was just the division’s second run through doing the production forecast.
The process was pretty sound last year, Decker said, but some things have been identified for change.
Among them, last year future projects with first oil five years beyond the forecast were treated as a “pot of gold” - they were outside the official forecast and excluded from the Revenue Sources Book.
This year, there is a 10-year future projects outlook and projects beyond five years are part of the official forecast, noted as “under evaluation.”
Last year there was no seasonality adjustment, he said, but in fact there is a 60,000-70,000 bpd swing in winter due to weather efficiencies vs. summer with maintenance shutdowns. The division hadn’t anticipated the focus on month-to-month, so this year seasonality was built in.
There was also a near-term emphasis this year, whereas last year the focus was on improving long-term predictions. This year there is a near-term emphasis, he said, with attention to a realistic long-range outlook.
And last year some of the under evaluation projects, those not yet fully sanctioned, were not risked for chance of occurrence but counted at full face value. This year, under evaluation projects were risked for chance of occurrence within the 10-year forecast window, there was an estimate of the soonest the project might happen and also an estimate of a realistic delay based on personal experience and analysis of statistics on discovery to development of North Slope fields.
Decker said he was comfortable the division significantly improved the forecast in the way long-term projects are handled. He said time would tell if the details in how long-range projects are handled are correct.
Decker said there is a small uncertainty range for currently producing fields. The methodology for projects under development uses applied quantitative probabilistic ranges using type wells and some financial risk is acknowledged. These are projects detailed in plans of development or in confidential meetings with the Department of Revenue, Decker said.
And projects under evaluation have been announced but are premature for sanctioning, with applied quantitative probabilistic ranges using type wells and a financial risk using project breakeven price, as wells as uncertainties including the chance of occurrence and project timing risk.
Decker presented two forecast graphs: one only for currently producing fields - it doesn’t include under development - and a slide showing years two to 10 of the forecast with new pools and expansion of some existing fields layered on top of producing fields. He said the forecast for producing fields shows an almost seamless merger between actual production and the fall 2017 forecast.