Inching back in the black

ND oil production grows slightly in November after contracting in October

Mike Ellerd

Petroleum News Bakken

After oil production in North Dakota contracted by 0.2 percent in October, the state’s output rebounded in November, albeit slightly, posting a net increase of 3,691 barrels per day or 0.3 percent over October according to preliminary data released by the Department of Mineral Resources on Jan. 14. That increase put November production at 1,187,206 bpd, up just 3,691 bpd from October and setting a new production record but by a mere 978 bpd over the previous high in September.

The negative growth in October was attributed to both a weak crude oil market and efforts by operators to meet gas capture requirements. However, the October contraction in growth came on the heels of a record increase in production growth in September, which also occurred amid weakening crude oil prices. At that time Department of Mineral Resources Director Lynn Helms attributed the record growth in September to a consolidation of rigs back into the higher-producing, higher-return core of the Bakken formation.

Not only did production grow in November amid progressively weakening crude oil prices, but also amid a significant decline in well completions from 145 in October to only 39 in November. In a Jan. 14 monthly press conference, Helms said the ongoing focus back on the Bakken core regions was the driver behind November’s positive growth. “As the technology has improved some and as we’ve focused the drilling and completions in that core area, amazingly in November with only 39 new wells completed, we were able to sustain production,” Helms said. “So that tells you a lot about the core area - that it’s two or three times as productive as much of the outlier of the Bakken in general.”

November Williston Basin oil production data are not yet available for Montana and South Dakota, but in October, Williston Basin production in those two states averaged 76,718 and 4,602 bpd, respectively. Assuming similar production for November, the Williston Basin averaged approximately 1.26 million barrels per day of oil production in November.

In contrast to North Dakota’s slight increase in oil production in November, natural gas production in the state fell slightly, averaging 1.424 billion cubic feet per day in November, a 0.3 percent decline from October’s average of 1.430 bcf per day, a difference Helms called “statistically insignificant.”

The rig count as of the Jan. 14 press conference stood at 158, down from the 181 rigs operating in North Dakota at the end of December, the 188 rigs at the end of November and the 191 rigs at the end of October. Interestingly, in 2013 DMR had estimated that 90 completions per month would be necessary to maintain production, but in November production actually grew with just 39 completions, something Helms attributes to the “silver lining” of the Bakken core area.

Drilling permits were up slightly to 251 in December from the 235 issued in November but down from the 328 permits issued in October.

As of the end of November there were 11,942 producing wells in North Dakota, 72 percent of which were producing from the Bakken pool, which includes the Bakken, Three Forks and Sanish formations, with the remaining 28 percent producing from conventional “legacy” pools.

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Pipe and rail exports steady for 7th month

Of the remaining 6 percent of Williston Basin crude exports in November, 5 percent went to Tesoro’s refinery at Mandan and 1 percent was trucked across the border and into Canadian pipelines. Considering that 6 percent as part of the pipeline market share, 41 percent of crude oil produced in the Williston Basin in November — some 517,000 barrels per day — ultimately ended up in a pipeline.

That pipeline versus rail trend parallels a generally steady narrowing of the price differential between Brent North Sea and West Texas Intermediate over the same period, offering little advantage to ship Bakken crude to East and West Coast markets over pipeline transport to Midcontinent and Gulf Coast markets (see chart).

During a monthly press conference on Jan. 14, North Dakota Pipeline Authority Director Justin Kringstad explained that at any given time, the largest factor affecting how crude is exported from the basin is commitments that operators have through contracts with railroads and pipelines, regardless of where the price differential stands. However, in the absence of any commitments, operators will simply look at the economics at the time, given a rail shipping premium estimated at anywhere from $5 to as much as $15 per barrel. “The times when rail looks incredibly economic are when that spread widens to what we would guess to be anywhere above $5 — it’d be potentially more economically attractive to look at some of those coastal refining markets for that barrel,” Kringstad said.

After reaching an eight-month high of $13.70 in November 2013, the Brent/WTI spread narrowed nearly in half averaging $7.19 in May. The price spread then fluctuated in the $5 to $7 range through September but narrowed to a 15-month low average of $3.65 in October. In November, the spread widened slightly to an average $4.10 and remained essentially constant through December averaging $3.91.

However, since Jan. 1, the Brent/WTI spread has collapsed, narrowing from $4.06 on Dec. 31 to an average of $2.02 for the first 10 trading days of 2015. While crude oil prices continued a five-month decline, since Jan. 2 Brent has lost more value than WTI, falling by 14 percent compared to WTI’s drop of 8 percent. On Jan. 14, Brent settled at $48.69 on the New York Mercantile Exchange for February delivery and WTI settled at $48.48, resulting in a negligible Brent/WTI spread of 21 cents.

—Mike Ellerd