North Dakota is beginning to see the effects of a depressed crude oil market, and in at least one rather unexpected way.
Oil production growth in the state set a record in September increasing by more than 52,000 barrels per day from the previous month according to data released by the Department of Mineral Resources, DMR, on Nov. 14. That would normally be viewed as positive news all the way around, but the reason for the growth is not because drilling and production are expanding, but instead, amid falling oil prices, operators are playing it safe and shifting focus back to the most productive Bakken core where wells simply have higher yields and better returns (see sidebar).
The effects of low prices don’t stop there. North Dakota is also seeing a number of drill rigs simply fall off the rosters. In a Nov. 14 monthly press conference, DMR Director Lynn Helms said the state’s current rig count is down “pretty dramatically,” standing at 186 on Nov. 14. That is five fewer than at the end of October and nine fewer than at the end of September. Helms said many operators are scaling back drilling plans and letting some of the less efficient drill rigs go as contracts expire.
“They had intended to increase rig count going into next year - almost all of them had budgeted for some fairly significant increases and were indicating that our rig count might go to 200 or maybe a little bit beyond that. They have dropped those plans at this point and plan to hold - at least the big double-digit drillers - plan hold at their rig count,” Helms said. “And they have alternate budgets that they could approve that actually reduce that,” Helms continued but added that operators are “not quick to do that” if they have very efficient rigs operating.
The revenue effect
Not only do low crude oil prices force operators to adjust, the Office of the Tax Commissioner as well as the Legislature must adjust also as lower prices mean lower revenues and lower revenues can mean tax adjustments.
Helms said the tax commissioner’s office watches the price of West Texas Intermediate, WTI, because that is the benchmark price that could trigger extraction tax incentives in the state should the price fall below a certain threshold for a long enough period of time. For calendar year 2014, that tax incentive trigger price is $52.06 per barrel, and if WTI falls and remains below that price for five consecutive months, oil extraction tax incentives kick in.
While the WTI price has fallen nearly 30 percent from its 2014 high of $107.62 on July 23, it settled at $75.82 on Nov. 14 for a spread of $23.76 above North Dakota’s extraction tax incentive threshold price. At approximately $75 per barrel, WTI would need to fall another 30 percent to hit the trigger price and then remain there for five consecutive months. “So those are converging although there is still a lot of room,” Helms said. However, since Nov. 12, WTI has lost some ground settling at $74.58 for December delivery on Nov. 19.
But Helms doesn’t foresee the WTI price falling below the trigger price. “My best guess is that it’s unlikely,” he said noting that a sharp, rapid drop in crude prices as seen in the current market generally results in a reasonably fast rebound. Noting that nothing is certain, and “I’ve surely learned to never say never,” Helms said that with a gap of nearly $25 between the current and the trigger price, “I think it’s a low probability that we’ll actually trigger.”
And with the 64th legislative session set to convene on Jan. 6, 2015, Helms believes crude oil prices will be in the forefront of lawmakers’ minds as they look ahead at the budget for the 2015-17 biennium along with proposed legislation that would shift tax percentages going to counties and provide an $800 million spending surge in impacted counties.
“They have the money in the funds right now to deal with the surge that they’re talking about, and I haven’t heard any talk about cutting the surge and making sure that ongoing construction projects out there get funded,” Helms said. “But a lot of peoples’ ideas about additional tax cuts, changes in property tax and income tax and all that - they’re getting a fresh look in terms of whether … any of that is realistic.”
Breakeven price and shifting rigs
In October, DMR provided crude oil breakeven prices and rig counts for 14 oil producing counties, and in the Nov. 14 press conference, Helms provided an update (see chart). DMR first calculates the average well production per county using type curves and a combination of monthly well operating costs, yearly drilling costs and initial production rates per county. Those average production values are then used to develop breakeven oil prices at a 10 percent rate of return.
The calculated breakeven costs for all 14 counties either increased from mid-October to mid-November or, in the best case scenario, remained flat (see table). The largest increase in breakeven price over that 30-day period was in Divide County where the breakeven increased from $85 to $104 per barrel. The lowest breakeven price was $29 in Dunn County, which remained flat over the period.
Of the 186 drill rigs operating as of Nov. 14, 169 were in the four “core” counties of Dunn, McKenzie, Mountrail and Williams, which are among the five counties with the lowest breakeven prices, ranging from $29 to $45 per barrel “So it’s in that $30 to $45 range, still very, very robust,” Helms said. The fifth county in the bottom five of breakeven costs was Stark County at $38 per barrel.
While the overall rig count decreased by only two at the end of that 30-day period, there was a noticeable shift of rigs. Over that period, McKenzie County gained six rigs while some higher breakeven counties like Divide, Burke and McLean lost rigs. “When you reach out to some of the areas where we’re seeing some real retraction … places like Burke County, Divide County, breakeven oil prices are $87 to $100 a barrel, and the rigs are being moved or the contracts are not being renewed,” Helms said.
However, Williams County, which has one of the lowest breakeven prices, actually lost four rigs. In the other two core counties, Dunn County lost one rig while Mountrail County maintained its count of 31.
Asked whether there is any angst over the rig count being down in the 180 range, Helms said there is. “The angst is over whether we’re going to be in the mid-190s or whether we drop down to 180 or, in a worst-case scenario, go to 165 and just drill the core area while we wait for oil prices to rebound.”
What operators are thinking
As Petroleum News Bakken has recently been reporting, a number of Williston Basin operators have been forthright about their concerns over oil prices, service costs and scaled-back plans in the coming year.
For example, in a third quarter earnings call on Nov. 11, Halcon Chief Executive Officer Floyd Wilson said his company is cutting five drill rigs in 2015 because of high service costs relative to current crude oil prices. “While we are substantially hedged for next year, we are in that uncomfortable space where crude prices have declined dramatically while service costs have remained at an all-time high,” Wilson said. “Of course the flip side to that is that efficiencies are at an all-time high as well, so it’s not … a black hole by any means, but they (service costs) are out of sync,” Wilson continued.
Occidental Petroleum CEO Steve Chazen also commented on service costs in his company’s third quarter call in late October. Chazen said Occidental will remain flexible in its capex in the current oil market, but he also said he believed service companies will lower their rates in response to the lower crude oil prices operators are getting for their product. “We also expect that, since the service companies were happy to raise prices when oil was going up, that they would have been just as happy to have their prices lower in the future.”
Other operators expressing concerns about activity in the current market include Oasis Petroleum. Chief Financial Officer Michael Lou said in a Nov. 5 conference call that while Oasis is in a strong position with a strong balance sheet and liquidity along with a resilient asset base, the company has “ultimate flexibility in future capital programs.” Lou said that if WTI prices hold above $80, Oasis would likely proceed in 2015 with a capital program similar to its $1.4 billion, 16 drill rig 2014 program. However, Lou said in a sub-$80 environment, Oasis would “contract activity to the core or deeper parts of the basin where our wells have the most price resiliency and where we have the most mature infrastructure.” But at $70 WTI or below, Lou said Oasis “would likely live with a cash flow and deliver flat to modest production growth.” In regard to service costs, Lou said they “will not stay where they had been if we sustain a lower oil price environment.”
In its third quarter conference call on Nov. 6, Continental Resources said it will cut its 22-rig Bakken drilling program down to 19 rigs in 2015. Continental also said it is planning to pull some rigs out of Montana and North Dakota’s Bakken fringe areas and into its core areas in the play.
Emerald Oil said in its third quarter conference call on Nov. 4 that one contract in its three-rig drilling program expires in March, and if the crude oil market remains depressed, it will go to an average 2.25-rig program.
