North American exploration spending in 2019 is tracking higher for the third consecutive year, albeit at a slower pace, with natural gas-heavy budgets poised to reset higher, while oil operators weigh the implications of extended lower prices.
Surveys and conversations with exploration and production (E&P) and oilfield services (OFS) operators have given energy analysts some insight into how much has been budgeted for capital expenditures (capex) and where the activity is expected.
Last year a 20% increase in North America upstream capex lifted the global average to 9%, noted Evercore ISI’s analyst team, led by James West. This year’s spend marked a 580 basis point (bp) acceleration in global growth from 3.3% in 2017.
Evercore in recent weeks surveyed about 250 E&Ps to get a feel for what kind of capex is expected.
“Preliminary results from our 2019 survey suggest global capex is poised to increase for a third straight year, while coordinated growth expands into a second year,” West said. “However, growth is moderating once more in North America and could be a slight drag on global growth, despite an acceleration internationally.”
Now in its third year of recovery, global E&P capex is forecast to increase by 8% in 2019, reflecting growth in North America of 10% and international growth of 7%.
“The U.S. will continue to pace spending gains in 2019, with an estimated 10% lift to capex,” said West. “Our survey continues to point to 5% growth in Canada, but we believe flat-to-declining capex is more likely as operators continue to work through the budgeting season.”
U.S. E&P Capex Likely Up 8%
NGI’s Patrick Rau, director of Strategy & Research, pegs capex among U.S. independents to increase 8% year/year in 2019, based on consensus Wall Street estimates from more than 70 companies.
“That’s probably a pretty good number,” Rau said. “On the one hand, the recent rout in West Texas Intermediate prices will no doubt scare off some producers, but much of 2019 production was hedged throughout this year at higher prices. Free cash flow ultimately rules the spend, and those hedges have locked in a great deal of that.”
Analysts are wary that spending levels “will adequately safeguard against a looming supply disruption,” Evercore analysts said. In addition, “there is a fair amount of ‘un-quantifiable’ capex that will be brought to the table in North America by smaller private operators.”
Some things are already clear, as a few U.S.-focused operators, including supermajor Chevron Corp., have unveiled their 2019 capex plans. Chevron has earmarked $20 billion for organic capital and exploratory spending in 2019, a near-$2 billion boost year/year, with $7.6 billion specifically targeting the U.S. upstream. CEO Michael K. Wirth said the budget would include funding to expand the Permian Basin position as well as “additional shale and tight development in other basins.”
ConocoPhillips, the world’s largest independent, has a capex budget of $6.1 billion worldwide, with 51% ($3.1 billion) directed to the U.S. onshore. Capex overall is flat year/year, but the Houston super independent expects to spend less and still produce more.
Anadarko Petroleum Corp. in November also promised more production on a leaner budget, with overall capex of $4.3-4.7 billion; $3.1 billion alone is set aside for U.S. onshore targets.
Hess Corp. has a global capex budget of $2.9 billion, with most of it -- $1.87 billion -- directed to the United States.
The deep-pocketed operators appear ready to push through no matter the decline in oil prices, but for smaller operators, or those that work in only one basin, it may not be so easy. For example, Tulsa-based Midstates Petroleum Co. Inc., whose focus is the Mississippian Lime, earlier this month said it did not intend to operate any drilling rigs in the first half of 2019 and would continue to evaluate its future activity levels and capex on an ongoing basis.
“Given the current macroeconomic conditions and the fact that we have over 90% of our core acreage held by production, we have decided to take a pause on our drilling program as we enter 2019,” Midstates CEO David Sambrooks said.
E&Ps Expected Higher WTI Going Into ‘19
Many E&Ps entered the budget season on expectations that WTI oil prices would be trending close to $60/bbl.
“The recent 30% decline in oil prices that occurred while we were conducting our survey has only happened 13 times over the past 40 years, and oil prices were higher six months later in almost all occurrences,” Evercore’s team said. “Although oil prices are currently below our survey’s $60 WTI assumption, we expect oil prices to recover in the coming months supported by Saudi Arabia and Russia cohesiveness, bottlenecks to North American shale production growth and demand growth.”
For natural gas-heavies, budget assumptions “have bounced within a tight $2.80-3.10/MMBtu range for the past two and a half years,” with prices more stable and sharply contrasting oil volatility. The Energy Information Administration on Tuesday in its latest Short-Term Energy Outlook predicted 2019 gas prices would average $3.11/MMBtu, about 6 cents below average 2018 prices.
“Natural gas budgets appear poised for a positive reset, as more than half of all respondents indicated they would revise their 2019 budgets higher at natural gas prices below current levels,” West said. “The average price that would prompt higher spending in 2019 is $4.05/MMBtu, about 10% below the current spot rate.” A “solid 50%” of E&Ps surveyed “would increase their budgets if gas prices stay at current levels of around $4.45/MMBtu. Meanwhile, gas prices need to fall to $2.75/MMBtu for budgets to begin revising lower.”
Most of those surveyed said they would not cut their budgets unless gas prices fell to $2.00 or below.
Discipline, Free Cash Flow Still Priorities
The mantra to maintain capital discipline and improve free cash flow (FCF) continues. Still, development has to be done ahead to ensure there’s enough supply to meet demand down the road. For example, E&Ps are preparing to fill more liquefied natural gas (LNG) projects, as well as fill the oil export tanks. Beyond the unconventional drilling in the onshore, many of the big operators have plans on the board to dive once again into deepwater.
This year’s spending “surprised to the upside” for most of the regions from Evercore’s mid-year survey, but analysts now don’t have “quite the same confidence as we did a year ago, as the benefits for corporate tax cuts have largely passed and global economic growth appears to be slowing.”
Jefferies LLC’s analyst team hosted 69 companies at its recent annual energy conference in Houston and came away with the feeling that operators remain “somewhat optimistic” despite the plunge in oil prices. Balance sheets “are in much better shape versus 2014,” when oil prices plunged and sent plans out the window.
Most E&Ps have yet to issue their 2019 capex projections, but Jefferies analysts expect there to be “flexibility to pare back activity should pressure on the commodity persist.”
Activity already has slowed (per usual) in the final quarter, but with infrastructure constraints in the most active basin, the Permian, potentially governing growth early next year, “deceleration in the U.S. onshore could be an intermediate-term catalyst for the E&P group.
‘New Hope’ Has Arrived?
Sanford Bernstein analysts Bob Brackett and Srishti Sinha took a different approach for their forecast. They reviewed the financial and operational performance metrics for 60 North American E&Ps to assess the state of the business. They created an E&P timeline, divided into four “eras” -- the pre-unconventional “Old Way,” the unconventional “Land Grab,” “Shale Wars” and “New Hope.”
The first three eras did not reward investors, but New Hope was reflected in overall stellar 3Q2018 performance.
“In 3Q2018, E&Ps have generated the highest levels of FCF and production growth in a decade,” the Bernstein analysts said. “The last time we got closer to this level of FCF generation was in first quarter of 2008,” and the third quarter may have been the best ever for E&Ps.
“Of course, 3Q2018 saw nearly $70/bbl average WTI. Today we are at $50/bbl,” but hope is not lost, they said.
E&Ps can't control oil price or cash flow, but they can choose FCF as a goal, said the Bernstein analysts. If they select growth as a goal, with FCF as an outcome, they could be punished.
The E&P companies reviewed generated $3.70/boe of total FCF (including acquisitions) during 3Q2018.
“The last time we have seen a higher number than this was 3Q2009 (i.e., the 'dawn of shale oil'),” Brackett and Sinha said. The third quarter of 2018 also recorded the highest profitability since 4Q2014, which was the peak of the last cycle.
Investor attention likely will remain “hyper-focused on demonstrating capital discipline,” with any negative FCF programs, particularly for smaller E&Ps, to be out of favor, according to Tudor, Pickering, Holt & Co. Large-cap E&Ps with broader exposure should be able to take advantage of prospects in 2019 as they are more able to outspend than their smaller competitors, with stronger balance sheets and a line-of-sight to shareholder returns.
The Fitch Solutions Macro Research team expects to see more oil exploration in 2019 than this year. “Exploration largely dried up following the oil price collapse in 2014, as companies focused on conserving their cash, gearing their spending toward lower risk, lower cost and shorter cycle projects. However, there are signs that exploration activity is starting to recover.”
Deepwater and frontier exploration has shown signs of recovery, with the appetite returning to formerly expensive regions.
“Financial discipline continues to be a key concern for oil companies globally,” the Fitch team said. “Discipline will slacken as prices rise, but fears of peak demand and the longer-term health of the industry will likely keep margins more sharply in focus…”
Competition For Capital
The bigger issue may not be the capex level but how it is allocated, the Fitch team said.
“As the market has recovered, much of the additional cash has been funneled toward shareholders (through dividends and buybacks) rather than toward productive investments. This competition for capital is likely to persist in 2019, continuing to drag on exploration next year.”
Another way to look at capex allocation is exploration drilling, according to Rystad Energy’s team, which issued an analysis in November.
“Of the 100,000 wells drilled globally in 2013, 4% were exploration or appraisal wells,” Rystad noted. “In 2018, this share is expected to drop to only 2% of the 70,000 wells drilled,” for both offshore and onshore markets around the world.
A willingness to invest more in exploration in 2019 and beyond “is likely,” said Rystad analysts. However, it may depend on production results in 4Q2018.
“Given actual performance to date and changes in the production forecasts provided, selected shale operators need to increase production by 5.5% on average during 4Q2018 to achieve full year mid-point oil guidance estimates,” Rystad analysts said of North America’s E&Ps.
Many capex budgets were increased in 2Q2018 on average by 8%, while in the second half of the year, most maintained full-year spending guidance. These strategies, said analysts, “are expected to remain the focus of 2019 operations as well.”