North America's oil and gas operators, more than any group worldwide, are enduring the "most extreme" capital spending cuts, with expenditures likely to drop by 41% on average from 2015 and the onshore sector seeing the most pain, according to Evercore ISI.
The outlook by Evercore's energy research team is the culmination of six months of collecting data from a variety of sources, which initially included about 300 global operators (see Shale Daily, Jan. 7). Analysts James West, Samantha Hoh, Alex Nuta and Cameron Schnier continued crunching the numbers for exploration and production (E&P) companies because many budgets weren't finalized until February, when oil prices were at 10-year lows. Data gathering was completed on June 1.
"As expected, North American spending has suffered the steepest declines as low oil prices clamped down on investment in the shortest capital cycle region," West said. "Our survey now projects 2016 spending to fall by 41% in North America and 26% globally."
The "market share war" by the Organization of the Petroleum Exporting Countries (OPEC) and its drive to increase global demand largely have been successful in reducing investment in North American (NAM) onshore plays and consequently production, the Evercore team said. The NAM region still account for the largest proportion of global E&P spend with 18%, down from 23% in 2015.
"Though North America projects to endure the most severe spending decline for the second straight year at 41%, we had been bracing ourselves for much of the year for declines in the range of 45-50%."
Capex reductions by North American land (NAL) independents is going to be even sharper, however, off 53% year/year, Evercore is forecasting, highlighting the "devastation" that the downturn has wrought on land operations in particular.
"While smaller land levered E&P companies do not individually 'move the needle' like the offshore players, majors and NOCs, when aggregated they account for 23% and 19% of NAM spending in 2015 and 2016, respectively," West said.
The "undersized" NAM E&Ps may not be able to leverage economies of scale or access needed capital, so their spending driver is a "consideration of commodity prices, service costs, and the uncertainty of drilling 'one dry hole too many.' Many West Texas independents, for example, only operate a handful (20-50) of flowing wells, which together support just a few new drilling ventures each year."
At depressed crude prices and without a solid production profile to rely on, the plug and abandon projects may be especially detrimental to near- and long-term drilling projects. To preserve future cash flows, many small NAL independents temporarily are shutting in some of their more mature assets, aka the strippers, because the produced fluid split has a higher water cut and the extraction costs outweigh the crude oil revenue.
The pullback today could have a big impact on production down the line.
"We believe that a backlog of deferred maintenance from these shut-ins will lead to significant degradation to surface and downhole equipment, which together could hamper a future ramp-up in production as these smaller NAL operators scramble to bring wells back online with minimal cash."
NAL capex estimates for 2016 "predict more pain" in particular for oilfield services (OFS) operators in the Bakken, as well as the Marcellus and Utica shales. Investments in the Williston Basin's Bakken could shrink 68%, while investments in Appalachia may decline by 58%.
"The Bakken, Marcellus and Utica shales are among the less economical U.S. plays (at current oil and gas prices), so budget cuts in these regions are expectedly worse than in the Permian," West said.
Evidence points to the Permian Basin holding up remarkably well versus other areas of the U.S. onshore (see Shale Daily, June 3).
"Marcellus and Utica wells are structurally difficult to drill, with deep 13,000-foot pilots and 10,000-foot kick-offs navigating clay-rich mineralogies that require the use of expensive synthetic drilling muds, but activity in the region is also limited by a lack of takeaway capacity and depressed gas and condensate prices," West said. Meanwhile, Bakken wells overall have a lack of reservoir permeability and steep production decline rates, despite relatively low high horsepower fracturing requirements.
"We expect service spending to stay lower for longer in these regions, as incremental drilling activity will be added to more productive shales first," West said. However, a reportedly high number of drilled-but-uncompleted wells -- DUCs -- in the Bakken may support near-term pressure pumping capex" as some E&Ps and OFS operators acknowledged a 1Q2016 increase in Bakken pressure pumping utilization.
The recent commodity price rally may not have improved the outlook for near-term activity, but it may have at least prevented further budget cuts in NAM. In fact, some budgets already are being revised higher and here and there, some rigs are being added (see related story).
Conversely, international capex declines are projected to be even worse than Evercore had initially projected (8%), down 21% this year after falling 15% in 2015. The dynamic indicates that national oil companies (NOC) have become more decisive in their austerity measures "in addition to highlighting the relative attractiveness of North America shale plays relative to international acreage from the perspective of the majors."
In the U.S. Gulf of Mexico (GOM), production has exhibited more resilience than land with a record 1.8 million b/d projected for 2017, E&Ps surveyed told Evercore. A total of 14 projects in the deepwater GOM are scheduled to come online in 2016 and 2017, further boosting offshore output, including Royal Dutch Shell plc's Stones in 9,500 feet water depth and Anadarko Petroleum Corp.'s Heidelberg in 5,300 feet of water, which ramped up earlier this year.
"Shallow water spending has taken the sharpest dive since the downturn," West said. "We postulate that shallow water rigs will be the first to go back to work in the GOM when oil prices improve, since these projects are relatively inexpensive compared to deepwater, and logistically easier to materialize."
The recent oil price recovery is unlikely to have a big impact on activity in the second half of this year (2H2016) as operators are proceeding "cautiously and the majority two-thirds of our survey respondents have no plans to increase 2H2016 activity," West said. "However, of the one-third that does plan to increase 2H activity, 28% anticipate increasing by more than 10% while only 5% will increase by less than 10%."
This year's NAM capex plans mostly are in place, but spend could move higher if West Texas Intermediate (WTI) remains above $50/bbl and Henry Hub natural gas prices climb.
About 25% of E&Ps surveyed indicated a $50-55 price range is necessary to spur incremental spending, while $55-60 "appears to be the range to increase capex for the majority 41% of respondents."
For natural gas, 2016 spending plans could increase at a Henry Hub price as low at $2.50, "but the majority 44% of respondents are looking for a $2.75-3.00 price range. At more than a 20% move from current levels, this is a bit larger than the 17% move for WTI to the midpoint of the $55-60 range to incite the plurality of respondents to increase oil capex."
A "bigger move up in the gas price would elicit a larger move up in spending," said West. "If gas prices climb modestly to the $2.50-3.00 range, about two-thirds of respondents would increase capex by more than 10% (similar to oil capex). However, if gas prices climb above $3.00, a larger 78% of respondents would increase capex by 10% (versus a smaller 53% of respondents to the oil question).
"We believe this demonstrates that gas-directed activity may be even more elastic to gas prices than oil-directed activity is to WTI prices. But regardless of how we slice-and-dice the survey results, a small move in gas prices could result in meaningful capex spending later this year."
WTI has risen comfortably above a range where E&Ps might reduce spend again, but the Henry Hub gas price "is not too far from the $1.75-2.00 range for operators to decrease spending," West said. "As a result, we believe capex risk resides for natgas-directed activity in the oil patch."
Evercore's mid-year survey result is based on an average natural gas price forecast of $2.29, down 13% from the $2.63 basis in the initial 2016 outlook and only slightly below current prices.
"The consensus outlook appears to be for natural gas prices to trend higher, with the 12-month strip at about $2.80. The market has been patiently waiting for natural gas production declines that are only just materializing and should accelerate in non-Northeast plays." However, consumption is rising, with industrial demand expected to surge from expansion and greenfield projects coming online in through the first half of 2017.
Next year's capex outlook is more encouraging, with 73% of the global survey participants expecting to raise their spend and 28% keeping it flat at 2016 levels. None plan to lower capex next year.
"Operators are currently basing their 2017 spending plans on an average WTI price of $52 and Henry Hub price of $2.70," West said. "While $52 WTI is not too far from current levels, the range of responses varied from $40 to $65. The average cited flat 2017 spending at $48 WTI and $2.61 gas, while the average cited more than 25% spending at $52 WTI and $2.89 gas.
"Given the relatively narrow gap between the averages in WTI and gas for flat versus a more than 25% increase in spending, we believe commodity prices and cash flow will once again be the key determinants of spending in 2017."