Winter is over for the long-distressed energy sector in North America, with upstream operators and service companies likely to have more spring in their steps as they offer up first quarter results.
Kinder Morgan Inc. was first out of the box on Wednesday, while the biggest oilfield service (OFS) operator, No. 1 operator Schlumberger Ltd., reported on Friday. General Electric, which is taking over Baker Hughes Inc., also reported on Friday, along with onshore expert Basic Energy Services Inc.
The onslaught by exploration and production (E&P) companies and the OFS operators begins next week, with many analysts anticipating much better results than a year ago.
On Coker Palmer Institutional's checklist of 1Q2017 trends and themes, analysts said they expect to see E&Ps model their outlooks for 2017 from a bit lower to within guidance, basically putting everyone inline. Operating costs in general are being controlled, which could give some air to cash flow.
"However, weaker-than-expected 1Q2017 commodity prices might largely offset costs," analysts said. Production also may be hindered by bigger wells, using longer laterals and more proppant, taking longer to bring online, along with downtime from offset wells. Production guidance likely will be weighted to the second half of the year, according to CPI, which mirrors other analyst forecasts.
'In Like A Lamb, Out Like A Lion'
Given the noise in the 4Q2016 earnings, "we believe changes to activity levels and budgets are unlikely" during the first quarter conference calls, said Jefferies LLC analysts Michael Hsu and Zach Parham. Because of "cost creep" in the more remote stretches of the Permian, Midland sub-basin operators, closer to services in the Midland/Odessa area of West Texas may perform better than those in the Delaware. Operators with Bakken Shale exposure also are expected to achieve because of continued strong performance on higher intensity wells.
E&Ps "may be underestimating service cost inflation," but "operators will likely continue to note that efficiencies will help to offset inflation and that much of 2017 budgets are contracted," said the Jefferies team.
Wells Fargo Securities LLC analysts led by David Tameron and Gordon Douthat said the first quarter would play out "in like a lamb, out like a lion," with a relatively quiet period for the exploration sector. Attention likely will be focused on, among other things, whether OPEC, the Organization of the Petroleum Exporting Countries, extends its pullback in global output beyond the end of May.
Wells Fargo also expects questions about OFS inflation and potential constraints because of the rapid ramp-up in onshore activity.
"Given crude volatility year-to-date, we expect service costs to remain at bay for now; however, we continue to see service costs moving higher than current Street expectations in the second-half, which is reflected in our wider group outspend forecast," said the Wells Fargo team.
For natural gas, "we continue to be constructive on the commodity given tightening supply/demand dynamics driving our above-consensus $3.40 estimate for the remainder of 2017 and believe gas equities have additional room to run."
U.S. production clearly is on a growth trajectory but this year, but output likely is going to be weighted toward the second half of the year, driven by larger completions and pad drilling trends.
"With the second-half set up for higher spending and activity levels, we expect service costs to move higher as well," Tameron said. "While budgets seem to be factoring in 10-15% cost inflation, we expect the actual number to be 20%-plus..."
And if, as expected, OPEC extends its pullback, U.S. activity should continue to steam ahead. That means there's a potential for "tightening logistics, particularly in the Permian," for rigs, crews and takeaway.
"Right now, we model crude pipeline capacity tightening in the second half of 2018, but expansion project delays or higher than expected volumes would certainly accelerate that timeline," Tameron said. In addition, he said there already are "early signs that the market expects constraints, evidenced by widening differentials on Waha futures."
At the recent Oil & Gas Investment Symposium in New York City, operators expressed concerns about the Waha gas basis from West Texas beginning to trade for 40 cents/MMBtu or more below the New York Mercantile Exchange, which may hurt realizations for the Permian's gassier Delaware sub-basin.
The weather pushed natural gas prices lower in early January, but they now have rebounded to above $3.15/MMBtu. Similarly, oil prices have been rangebound since late 2016, with West Texas Intermediate (WTI) trading between $48-53/bbl.
Gas Prices Looking Stronger
"We remain bullish on natural gas on a tighter supply/demand balance (excluding weather), with a $3.50/MMBtu long-term price forecast," said the Jefferies team.
Jefferies will be listening in for details about how gas basis differentials in Appalachia have tightened to date, given that three large pipeline projects are under construction. An estimated 7.1 Bcf/d entered service across the United States in 2016, marking one of the largest-ever year/year expansions of domestic gas pipeline capacity, according to the Federal Energy Regulatory Commission.
With new takeaway coming on especially in Appalachia, the potential exists for the regional E&Ps to reduce basis differential guidance for the full year.
Also bullish about gas prices are Wells Fargo analysts, who see an average $3.40/MMBtu, based on tightening supply/demand fundamentals that may drive a below-historical average storage forecast through the end of this year's injection season.
"We see potential running room for the natural gas-exposed names" in the U.S. onshore, particularly Marcellus operators, even through an early outperformance in response to an improving gas strip, Wells Fargo's team said.
While the 2017 gas deck is higher, Wells Fargo has revised lower its WTI forecast, with 2017 prices reset to $54.71/bbl from $57.26. For 2018, prices were reduced to an average $57/bbl from $60.
Commodity prices are unlikely to break into the upper $50s for oil or $3.50-plus for gas, which means "little change to 2017 E&P budgets" during the first quarter announcements, said Jefferies analysts.
"We do look for commentary on service cost inflation but believe that E&Ps will continue to indicate that much of the inflation can be offset by increased drilling efficiency."
Based on recent conversations with E&P management teams, oilfield services (OFS) cost inflation also may be underestimated. Many E&Ps had said during 4Q2016 conference calls they expected OFS prices would move 10-15% higher this year.
"However, our OFS team has noted further price inflation, with leading edge pressure pumping costs now up 30-40% from the bottom," said Jefferies' Hsu and Parham. "While E&Ps will be able to offset some of the service cost increases due to increased efficiencies (and some level of contracted services through much of 2017), we look for spot costs to continue to rise through 2017 and potentially pressure E&P budgets."
Costs Creep in Permian's Delaware
Cost creep in portions of the Permian Basin could lead to better results in the Midland sub-basin, which is closer to OFS operations in the Midland/Odessa area of West Texas, according to Jefferies analysts.
There's a "higher risk for cost increases in the western part of the Permian," i.e. the Delaware, because of its relatively more inaccessible geography in terms of labor and proppant, with Ward/Reeves counties more than a one-hour drive from Midland, TX, where many services -- and people -- are based.
To get people to move, Delaware operators may be offering higher compensation and benefits packages. In addition, proppant used in the Delaware often is sourced from brown sand mines in Central Texas, several hours away, or even further, from northern white sand mines in Wisconsin.
Meanwhile, in the Bakken, preliminary results by some operators indicate new wells are outperforming, and Jefferies analysts "see the enhanced completions leading to better than expected production volumes" and ultimately, higher estimated recoveries.
As E&Ps continue to block up acreage positions to drill longer laterals, particularly in the Permian and Appalachia, mergers/acquisitions may continue to be a sizzling topic of interest.
"While only a few Appalachia acreage packages have changed hands during 2017, we expect further consolidation within the basin throughout the year," said Jefferies analysts.
OFS Outlook Brighter
Following a two-year-plus rout, look for the OFS sector to begin making up for lost time.
"Pressure pumpers have come off a recent 2017 bottom, but the field outlook is the strongest since 2014," said the CPI analysts. "With capacity in far shorter supply than stocks would suggest, fracture pricing is at an apparent inflection as rates are 30% or higher than at the beginning of the year."
Giving a nod to recent data by the Energy Information Administration's Drilling Productivity Report, Evercore ISI analysts noted that drilled but uncompleted wells (DUC) in the Permian, Eagle Ford and Haynesville shales alone are up 13% since December. The DUC count in the Permian had risen 19% to nearly 300, while Haynesville DUCs were up 21% (32) and the count in the Eagle Ford was 4% higher (53).
"We attribute the increase in the Gulf region to the mad dash ongoing in the Permian and a flight of hydraulic horsepower (HHP) from other nearby basins to try to meet incremental demand in the Permian," Evercore analysts said. "The building inventory, which is approaching peak January 2016 levels, is a function of sold out completion equipment and increasing lead times, in our view, as opposed to operators deferring completions.
"The continued increases in drilling efficiencies and pad-adoption in conjunction with the rapid rig count ramp have only served as a further tailwind for HHP demand."
The inventory translates to future revenue growth for the OFS sector but it also suggests that contractors will have to accelerate reactivations, "thereby incurring higher than expected costs and pressuring near-term margins. This dynamic will likely also serve to accelerate pricing, but could introduce choppiness to 2017 estimates, especially given the natural lag between spuds and completions."