If actions speak louder than words, the industry is making obvious what it considers economic to drill by where it is deploying or idling rigs. In late April, the oil rig count had plunged 79% from its September 2014 peak, and the gas-directed count was off 75% from the peak.

A big consideration in planning today is well breakeven prices, which have been falling due to technical advancements that are likely long-lasting, and severe service company cost reductions, which likely are not. E&P companies frequently cite their breakevens by play, as do analysts. But that method has too many variables affecting it to be reliable. In turn, individual well or project breakeven economics ultimately affect return or profits for an entire company.

According to Platts Analytics’ analysis of IRRs, and accounting for regional spreads, WTI prices at $40/bbl will generate returns of 9% in the Bakken and 8% in the Eagle Ford—nothing to write home about.

Before OPEC’s meeting in November 2014—when the rig count was 1,200—the Baird energy research team said that the Eagle Ford oil window broke even at $65/bbl.

Fast forward to this April, when a Bain & Co. study said that at $50 oil, less than half of those producers earned a 10% IRR in the oil window, and with $30, none can.

“We are often surprised by how many unconventional players do not have a clear picture of their fully loaded cost per barrel produced,” Bain said. “With a clear understanding … companies will recognize the magnitude of required change and begin setting cost and well productivity targets.”

At $40 to $45/bbl, E&Ps will limit drilling and completions to the core of the core. If 100% of their acreage is held by production so they don’t have to drill at all, so much the better. Current commodity prices are not sustainable, and indeed, many observers now say the bottom has been reached. Some rig contractors are reporting that a few more rigs will start back up in the second half.

E&P executives increasingly cite $45 as the magic number that, if sustained for 90 days, will encourage them to start completing their drilled but uncompleted wells (DUCs). At $50 to $55/bbl, most say they will rig up and drill again, but recently Hess Corp. said it will wait for a sustained $60 price.

“The focus on lowering breakeven costs to support near-term cash flows could give way to a renewed focus on bolstering future return on capital employed [ROCE],” Deloitte said in a report this year. “As the industry improves performance on costs/efficiency, its future emphasis will not be on its ability to make profits at low prices, but about generating sufficient ROCE on a large base of devalued investments made in the past.”

Discussing the relationship between breakevens and returns is tricky. What is the breakeven price, the point at which dollars begin to generate a slim profit? And are all sunk costs such as land and G&A included, or just the drill and complete numbers?

Raymond James analyzed 18 onshore domestic plays this year and found half will give an IRR of 15% at $45 oil. At a lower price of $40, only six plays can achieve that IRR, it said. (For details, see the lead Newswell in the May 2016 issue.) But is 15% enough?

At the end of 2014, $70/bbl was the average breakeven price across all U.S. shale plays, but now many are profitable even at $30, said H.C. Freitag, vice president, integrated technology for Baker Hughes Inc., speaking at Hart Energy’s DUG Rockies Conference in March. However, in January 2015, IHS calculated a breakeven average of $65/bbl across all plays—assuming $100 oil held flat and $4/MMBtu gas.

The key question

Looking at this on a play-by-play basis, the Eagle Ford and Bakken rig counts have declined the most, while in the Scoop/Stack area of Oklahoma, the count is rising—where operators say a horizontal Meramec well costing $6.4 million could generate a 44% return at the March strip on Nymex. That’s an enviable result in anyone’s book.

Pioneer Natural Resources Co. said recently, “Despite the weak commodity price environment, the 2016 drilling program in the northern Spraberry/Wolfcamp area is expected to continue to deliver favorable internal rates of return, with returns of approximately 30% expected at current strip commodity prices. These returns … are benefiting from ongoing cost reduction efforts, drilling and completion efficiency gains and well productivity improvements.”

But here’s the question every investor must ask: What are the assumptions inherent in arriving at a breakeven cost per well or play?

“We first heard that nothing works under $60, then we heard $50. Now we’re hearing that nothing works under $30 to $35—but once we get to $45 or $50, most all of it works,” said Scott Kessey of Kessey Capital Partners LLC in Houston. “How much of this is reality, and how much is hoping and praying? Time will tell.”

Lower breakevens

The E&P industry soared like a shot from a cannon during the shale gale. Wall Street demanded growth, and the shales delivered beyond anyone’s wildest dreams. But costs soared too.

Today, the industry has pivoted to new metrics, and the goal of achieving a lower break­even price point is well on its way. Better frack techniques, pad drilling, higher EURs and lower drilling and completion costs enabled the industry to lower its breakeven hurdle in every play, and indeed, even in different sections of a play. The fine-tuning has been impressive.

“‘Breakeven’ is a very loose term with a lot of embedded assumptions, and each company or analyst may calculate it differently,” said Kessey.

Some people claim no well in North America breaks even if it costs $10 million or more. Others say yes, it does, but the real question is, for whom: the producer, the service company or the investor?

Indeed, the numbers vary wildly depending on a host of factors, such as location, lateral length, completion techniques and, of course, commodity prices. PDC Energy Inc. said it drove well costs in the D-J Basin down from $4.2 million to $2.5 million, and the wells produce on average 15% more, so the break­even has come down.

EOG Resources Inc. is on record comparing its 2014 well-level rate of return (ROR) at $65/bbl to returns it got on wells in 2012—when oil was $30/bbl higher. Morgan Stanley said average horizontal well costs fell 22% last year, and average single-well breakevens fell 15% to $39/bbl from $45/bbl at the start of the downcycle. It does anticipate a higher cost curve in the future.

“Breakevens keep coming down, but obviously, there is a wide range. In the Eagle Ford, we’re seeing as low as the $20s, and on the high end, the $40s, depending on which window you’re in [oil, gas, NGLs]. The reality is, some of the top performers in the sweet spots have breakevens in the low- to mid-$20s,” said John Norton, partner with Bain & Co. in Houston. “Less than two years ago, it was double that for almost everyone across the board.”

Return metrics

People boast of achieving lower breakevens, which affect returns, but shouldn’t the industry aim higher? If you spend $10 million and get back $10 million, congratulations, you broke even—but aren’t you in business to make a profit? (We’re not even taking into account the time value of money here.) Next will be whether the industry can be judged by the kind of returns it can generate.

But what are returns in a “normal” E&P world? Ask a dozen people, and you’ll get a dozen different answers. The problem is, too many assumptions are buried in a return. There is no one number across the industry, even though almost everyone says that once oil reaches a sustained $50/bbl, they will resume drilling.

Morgan Stanley looks at it this way: If a well breaks even at $30/bbl, you then must add another $25 to cover corporate breakeven (overhead), another $5 for service cost inflation, $12 for growth and delivery and $8 for more service cost inflation. Bottom line: a breakeven of $80/bbl.

“We believe a return to $80 WTI would be needed to reach consensus U.S. production growth in 2020,” it concluded.

Bloomberg recently claimed that the Bakken, Eagle Ford and Permian could combine for 700,000 boe/d of production growth if oil were $55 to $65/bbl.

The price point that triggers activity depends on the company, too. Anadarko Petroleum Corp. says the breakeven on its D-J Basin DUCs is just $25/bbl. In the Delaware Basin, the PV-10 breakeven is $30 for DUCs and $35 for undrilled locations, the company said.

However, in Anadarko’s first-quarter conference call, CEO Al Walker said even if oil recovers to $50, you won’t see the company ramp up its rig count—yet. It will save drilling on its best-return assets for a higher oil price later, he said.

Rules of thumb

“IRR or ROR can be very misleading,” said Jim McBride, managing director at Opportune and a longtime energy banker formerly at Capital One Southcoast. “If I lend you a dollar and you give it right back to me, I’ve just made an infinite rate of return—but I haven’t made any money.

“I’d suggest that the key measures for an equity investor to look at are return on invested capital [ROIC]—how many dollars will I make for every dollar I invest—and payout—how fast can I get my investment back.”

Payout is what McBride called “a backdoor” way to estimate ROR. “There’s an old rule of thumb that ROR approximately equals the inverse of the payout in years. If my cash on cash has a 10-year payout, I’m earning 10% ROR, but if the cash on cash is strong and has a three-year payout, my return is roughly 33%.”

Sadly, the Northeast gas price picture is a mess. Dominion South hub prices averaged below $1/MMBtu for March, with a low of just 83 cents on March 9, according to data from Platts/Bentek Analytics. At that price, no one is going to drill. And indeed, the rig count in the Marcellus and Utica is appallingly low.

Maintenance on the Rex pipeline, not to mention the warm winter, suppressed gas production in the Northeast this past February and March. Demand did not encourage higher production volumes. Even so, the Marcellus and Utica plays, and the Montney and Deep Basin plays in western Canada, enjoy the lowest full-cycle costs in North America, according to Calgary-based Solomon Associates, thanks to the economic uplift of their NGL yields, particularly condensate production.

Simon Mauger, director of gas supply and economics for Solomon (which acquired consultancy Ziff Energy Group), explains that the company uses a full-cycle cost evaluation from a development perspective.

“A few costs are not included (e.g., dead-end exploration, land acquisition and greenfield infrastructure development), but these costs vary from company to company, from play to play, and over time are difficult to assess.

“We calculate a return to the producer based on the capital employed to develop the gas resource, using a 15% before income tax rate of return.”

Kessey said both time value of money and the cash magnitude of the return are important to consider. “If I invest $10 million and in six months I get back $13 million and we’re done, that’s a high 60% IRR, but a low ROI—not likely acceptable to most investors since it didn’t move the meter that much.”

Private equity players look more at ROI and target a portfolio company return of two to two-and-a-half their investment back, but they hope for a three-bagger, he added.

“A savvy low-cost operator told me the big strides in reducing costs and improving EURs occur when you’re in the midst of a drilling program, not while you’re on the sidelines,” said Kessey.

“So we may see further improvement in breakeven figures due to continued technical advances once we get back into a drilling mode again. But we will most assuredly be facing a headwind of increasing service costs.”