Greg Hill couldn’t be more optimistic about Hess Corp.’s portfolio and personnel. “I’d put us against anybody,” the president and COO said in late January shortly after the company’s 2014 year-end earnings call.
Hill had also just spoken to members of the Louisiana Midcontinent Oil & Gas Association during the group’s annual meeting. How were folks doing in Louisiana? “They’re struggling—just like anybody—with where this is going,” Hill said.
“But this is an amazing industry. It is probably the most resilient in the world. It’s the only industry that can respond to these shocks and survive. It’s a phoenix. It survives and innovates its way to prosperity.”
Innovation certainly applies in North Dakota, where soaring oil output has created new prosperity. Looking at the North Dakota Department of Mineral Resources’ (DMR) map of well paths in the state, one- and two-sections swaths are striped with lateral wellbores. Many travel from a single pad and cascade.
From these, producers made 1.19 million barrels of oil a day (bbl/d) from more than 11,900 wells in November—the last month for which the state had released data by late January. The production was No. 3 to Texas’ 3.4 million a day in November and the federal-water Gulf of Mexico’s 1.38 million, according to EIA data.
It represented 13% of the U.S. total of 9.02 million a day—an amount approaching the U.S. peak of 10 million a day in 1970. In 1984, when North Dakota’s oil output first peaked, its 148,000 bbl/d was 1.6% of the U.S. total.
Among North Dakota’s nearly 12,000 wells, 8,640 were producing from the Bakken petroleum system, which also includes the Three Forks and Sanish formations. Representing 72% of the state’s producing wells, these were making 95% of its daily oil. The average per well: 130 barrels daily; the balance, 19.
On Jan. 14, however, the day of DMR director Lynn Helms’ monthly report, he noted the wellhead price for the state’s light, sweet crude was $29.25. It was the lowest since December 2008, he added, which was during the 2008-2009 financial-markets crisis.
With WTI at about $45 and Hess netting some $10 below that, why was Greg Hill so positive in January? Hess was ready for this, he said. “We have a strong balance sheet and a resilient and flexible portfolio.”
The company announced its Bakken spend in 2015 would be $1.8 billion, with about a third of that in this quarter while finishing up a 14-rig program and, then, paring to eight for the balance of 2015; fourth-quarter 2014 drilling consisted of 17 rigs.
Even with a 2015 average of 9.5 net rigs at work for Hess, however, it expects to drill 180 wells and complete 210, including 50 wells that were waiting on completion at year-end 2014. Its 2014 drilling and completion program brought 238 wells online. Average daily net production this year will be 14% to 27% more on an annualized basis than in 2014, Hill said.
How does that math work—nearly as many wells with roughly half the rigs? It is a result of efficiency gains, he said. “We expect to drill approximately 20% more wells per rig in 2015. So that’s 18-plus per rig in 2015 versus 15 in 2014.”
The rigs that will continue to work will drill in the sweetest spot—that is, Tier 1—of Hess’ 613,000-net-acre position in the play. The company intends to keep its assembly line working. “You have to maintain that capability. As we talk to investors, the question is ‘why not just cut the Bakken out?’ Well, you lose capability.”
Hess has been employing the “lean manufacturing” method in development of its Bakken position. “You have Bakken rigs on pads, so they ‘walk.’ But, if you have to move that rig and that fracturing operation to another pad, that takes about 1,000 truck loads,” Hill said. “You have to remove any inefficiency in the logistics of doing that—trucks showing up when they shouldn’t, equipment showing up late. You try to keep this line going with no waste.
“You can find a lot of waste in an inefficient flow of manpower, materials, equipment, supplies. We’ve been knocking out $100,000 and $200,000 a quarter consistently in our well costs just by attacking these things. There’s not one thing you can point to; it’s a lot of things that add up to big numbers.”
Hess’ first-quarter 2013 Bakken D&C cost per well averaged $8.6 million; in fourth-quarter 2014, $7.1 million. The company aims to preserve the operational gains. “Lean manufacturing depends on the supply chain cooperating with you. Let’s say people gut their unconventional business. The restart costs are going to be significant.” Re-enlisting talented personnel may be most difficult for the industry, he added. “There are a lot of new people in this business who have never been through these downturns. Attracting them back could be difficult. And it happened so fast: There are people who had jobs in this industry on Thanksgiving Day; by Christmas, they didn’t.”
To defer or not to defer?
North Dakota’s backlog of wells needing completion totaled 775 at the end of November, according to Helms’ mid-January report. Warren Russell and Michael Cohen, analysts for Barclays Capital Inc., noted at press time that only 39 wells were completed in November compared with 272 in August, 193 in September and 145 in October. The November completions were about as few as in January 2014, when temperatures and wind prevented work during 15 days, according to DMR reports.
Helms noted in January that there were 11 days in November of wind of greater than 35 mph, which is too strong for safe completions work, and seven days of temperatures below 10 degrees Fahrenheit, which is too cold to successfully move completion fluids.
The rig count had fallen by 25 since November, he added, to total 156, down from 191 in October.
“Oil price is by far the biggest driver behind the slowdown,” Helms reported. As for completions, “operators report postponing completion work to avoid high initial oil production at very low prices” and while working to place gas-capture infrastructure to meet North Dakota’s flaring-reduction rule.
Hess’ Hill said that deferring completions—in the Bakken or elsewhere—makes no sense. “I’ve heard people talk about that. That’s purely a cash-flow management kind of strategy. But you’ve already got half of the well’s cost sunk. For it to sit there idle with no revenue doesn’t make any sense from a return standpoint. You’re much better off just completing it and getting it onto production.”
While Hess won’t defer completions, paring back drilling does add up. “[On] an unconventional well like in the Bakken, 70% of the NPV is generated in the first three years. Outside the core of the core, it just makes sense to defer until the price comes back up—and we believe it will come back up.”
As for operators who are canceling rig contracts, Tudor, Pickering, Holt & Co. (TPH) analysts reported in late January that they were “still floored that [Helmerich & Payne Inc.]—the largest U.S. land driller and the land-drilling industry ‘gold standard’—is guiding its first-quarter, U.S., land-revenue days down 25% quarter-over-quarter.”
The analysts said they were revisiting their own “overall U.S.-land-rig-count decline—i.e., trajectory and magnitude—assumptions as well.”
But the cost of canceling rig contracts may pay off in a $45 WTI environment, they added. The fee for terminating the contracts is a small part of the well’s total cost. “For example, on a Bakken well costing some $10 million, even a rig with a high $20,000 dayrate only represents a little over 5% of the well cost,” they reported. “With low oil prices, why would an E&P obligate itself to spend the other [roughly] 90% of the well cost just because a rig is contracted? The … buyout is typically the remaining cash margin on a contract, so early terminations cost some $5 million per year of contract remaining for many rigs. [It’s] not too onerous.”