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North American E&P Capital Efficiencies Strengthening on Higher NatGas, Oil Prices

Capital efficiencies for many North American producers should strengthen on the back of higher natural gas and oil prices than in 2015, but cost "reflation" has begun to reappear, according to analysts.

Moody's Investors Service reviewed 35 U.S. and Canadian exploration and production (E&P) companies and found that the significant drop in profitability last year far outpaced declining oil and natural gas production costs. Proved reserves fell by 12%, reflecting reduced capital spending and negative price revisions, while finding and development (F&D) costs turned negative.

Assuming average West Texas Intermediate (WTI) prices of $40-55/bbl and Henry Hub natural gas prices $2.25-3.00/Mcfe, however, "the group's overall capital efficiency will be better than 2015," as higher commodity prices offset rising capital expenditures," said Moody's Senior Analyst R.J. Cruz. "Amid persistent low oil and natural gas prices, E&P companies have been searching for ways to become more efficient in finding and replacing reserves, reducing costs and avoiding leverage from creeping higher."

Of the 35 E&Ps reviewed by Moody's, reserves grew year/year in 2015 for only seven. Canadian oilsands producer Cenovus Energy Inc. led with a 7% expansion, while U.S. natural gas heavy Southwestern Energy Co. suffered the biggest annual reserve decline of 42% -- mostly because of negative price revisions. The 50 largest U.S. E&Ps last year eliminated 40 Tcf and 4.1 billion bbl because of reserve revisions, according to Ernst & Young LLP (see Shale DailyJune 14).

Average production costs declined overall last year on improved drilling efficiencies and lower service costs, while general/administrative (G&A) costs also fell because of higher production and reduced headcounts. If prices in 2016 were to average $55 oil/$3.00 gas, full-cycle costs should be $42/boe for oil-weighted producers and $3.37/Mcfe for gas-weighted producers, Moody's estimated.

However, don't be too quick to assume operating costs will continue to decline, said Sanford Bernstein's Bob Brackett. A review by Bernstein found that the second quarter marked "the beginning of cost reflation," with operating expenditures on the upswing.

"One common argument is that cost deflation is here to stay as operators continue to highlight cost reduction opportunities, communicating a sense of permanency for the cost reduction," Brackett said."This view leads some investors to worry about a race to the bottom for marginal cost," which appeared to be borne out in 1Q2016 conference calls.

For example, Devon Energy Corp. in its first quarter commentary said cost savings initiatives were "well on their way to preserve more than $1 billion of cash flows during the year" (see Shale DailyMay 4). Noble Energy Inc. CEO Dave Stover said the company "came in well below guidance on most of our key cost metrics," and a lease operating expense (LOE) reduction "is a powerful indication of our cost reduction efforts when you consider the company added almost 100,000 boe/d over that same period" (see Shale DailyMay 6).

"We have looked at the data for nearly 60 E&Ps over the last 25 quarters and analyzed the relation the costs have with the commodities prices," Brackett said. "Based on our analysis and recent increase in the commodities, we predict cost inflation in 2Q2016 numbers."

At the end of 1Q2016, E&P cash costs for the 60 producers had fallen by about one-third from levels in 3Q2014 when lower crude prices kicked in, Bernstein's review found. LOE over that period fell by about 33%, while production taxes declined 63%, exploration expenses by 31% and G&A by 16%. However, the 34% overall cost deflation wasn't enough to overcome the loss of revenue from price declines. Average E&P earnings in 1Q2016 were $7.90/boe -- a decline of 77% from 3Q2014.

Commodity prices so far in 2016 have risen significantly in 2Q2016 from 1Q2016, with West Texas Intermediate averaging $45.30/bbl from $33.40 and Henry Hub at $2.10/Mcf from $1.96/Mcf. Correlating cash cost components (LOE, taxes) with the blended price, cash costs likely rose 20% in 2Q2016, Brackett said.

Wells Fargo Securities LLC highlighted the structural improvements to operations, noting that the downturn has created a "Darwinian environment, of sorts, where only the fittest from a cost, efficiency, and cash flow perspective survive. Out of necessity, E&Ps have become much more efficient than they were 18, 12, and even six months ago," analysts David Tameron and Gordon Douthat said.

E&Ps now are able to generate returns at lower commodity prices, and $55/bbl oil today implies the "same returns" as $80-90 oil," Tameron said.

"This is important because it implies a degree of downside protection related to commodity price movements; there is greater upside exposure in a commodity bull market regardless of rebounding service costs given that much of the improvement is structural and less likely to reverse; and there is better stability of returns, at least in theory, associated with greater horizontal drilling expertise."

More efficient drilling and right-sized cost structures have bolstered margins to date this year, and that should continue even with pressures from rebounding commodity prices.

"This implies that, even if we see some reversal on certain expenditures (i.e. service costs, LOE), returns will have greater leverage to commodity price upside in the future," Tameron said. "In other words, there could be a period in which E&Ps earn outsized returns," which is the nature of a commodity/cyclical business.

The argument can be made that consensus forward margins are too conservative as commodity/cyclical business margins "often seem to go lower and higher than people expect," he said. "Given the technological and learning expected within the E&P industry, we could easily see a situation where we get a period of higher prices and better than expected margins over the next year or so."

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