Lower 48 service-cost inflation forecast

June 5, 2017
Onshore development and drilling activity ramped up in the US Lower 48 states (L48) during the first quarter, prompting the beginnings of service-cost inflation that could reach 15%, including margin recapture in 2017.

Jackson Sandeen
Wood Mackenzie Ltd.
Houston

Onshore development and drilling activity ramped up in the US Lower 48 states (L48) during the first quarter, prompting the beginnings of service-cost inflation that could reach 15%, including margin recapture in 2017.

A Wood Mackenzie report on recovery costs said a combination of stable oil prices and increased operators' budgets spurred drilling activity, which in turn boosted service demand. The international natural resources consultancy added that the speed at which activity picked up supports its cost-inflation outlook.

WoodMac expects service companies will regain some pricing power this year, but does not forecast a return to 2014 levels.

Three factors point to 2017 becoming an inflection point for onshore services:

• Growing confidence regarding oil prices following production-cut targets implemented by the Organization of Petroleum Exporting Countries and other major producers.

• Outsized increases in L48 operator capital budgets.

• Steep discounts by service companies contributing to negative operating margins for several quarters.

Break-even oil prices

The days of rock-bottom break-even oil prices may be over, but operators adopting a more aggressive development mode will find it harder to realize additional productivity increases and drilling efficiency.

On average, US-focused independents have increased capital budgets 60% year-on-year. Increased activity means tightening of equipment, time, and labor supplies, which will put pressure on upstream costs.

The ongoing recovery is unlikely to mirror the 2011 upcycle. At that time, the global economy was still weak and US unemployment was high. In the intervening years, non-energy industries have recovered, soaking up much of the available labor pool. This will make hiring difficult for operators.

E&P companies anticipate cost inflation this year of 10-20%. Service companies forecast 15-40% inflation, depending on product line. WoodMac's base forecast is 15% for the year. Supply-chain segment, regional differences, and contract duration will influence ongoing price negotiations.

Service-cost inflation will be distributed unevenly. The most severe cost increases are likely to face operators in the Delaware, Midland, Williston, and Denver-Julesburg basins.

Despite rising costs, core areas with wellhead breakevens of $30-40/bbl will continue to yield profits. But marginal assets with breakevens above $40/bbl could become unattractive if drilling efficiency and productivity gains halt as onshore activity levels accelerate.

Well economics

WoodMac expects 10% cost inflation for horizontal rigs (Fig. 1). The Bone Spring, Niobrara, and Wolfcamp experienced 50% growth in horizontal completions 2016-17.

Pressure pumping, rig day-rates, and proppant costs together account for most gross well expenses and comprise the biggest share of operators' drilling and completion budgets.

Pressure-pumping providers discounted prices for 2 years, with prices now down about 40% from their peaks. WoodMac forecasts a 37% increase in tight oil completions this year, adding pressure on the short-term market.

Some operators have waited 2-3 months for pressure-pumping equipment. Those operators lucky enough to win slots on a pumper's schedule have paid a premium for equipment, sometimes as much as 20-40%.

WoodMac analysts will be watching fracturing job costs over the next 12-18 months. Increases in this sector could be indicative of inflation trends for service companies.

Pressure-pumping equipment will require capital investment before returning to the oil patch. Fracturing equipment has been cannibalized while pressure pumpers fell behind on equipment maintenance and repairs during the downturn.

A downside risk for pressure-pumping cost inflation will be the speed at which fracturing equipment is reactivated. Public companies will reinvest as demand allows. Meanwhile, some privately owned companies (Keane Group of Houston, FTS International of Fort Worth, Tex., and ProPetro Holding Corp. of Midland, Tex.) have filed for initial public offerings or gone public to secure financing.

New pressure-pumping providers, such as BJ Services and C&J (post-bankruptcy), can undercut established players on price. L48 operators quickly will absorb new pressure pumping capacity unless oil prices fall sharply.

Climbing rig counts

Total rig counts rose more than 80% from May 2016 to February 2017 (Fig. 2), but the key question is whether onshore drilling demand has reduced uncontracted rig supply enough to move contract pricing.

Rig utilization dived in 2016, with some drilling contractors reporting 30% utilization. Recently, utilization rates moved higher due to attrition in mechanical and silicon-controlled-rectifier rigs. The high-specification rig market is experiencing much higher utilization rates, with contractors reporting close to full capacity.

High-spec rigs (such as self-mobilized, pad-capable, three-mud pump, 7,500-psi mud systems) already are seeing 15-20% inflation and could approach $20,000/day by yearend. Day rates will edge closer to $30,000/day as drilling contractors move from upgrading rigs to constructing newbuilds.

A caveat on rig inflation predictions is that long-term contracts awarded during 2014 will expire into a lower-priced spot market, down 40% from peak pricing. Day rates could fall from pre-downturn levels of the mid-$20,000 range to the mid-to-high teens during contract renegotiations.

Some new contracts include a ceiling price on day-rate inflation throughout 2018. It is unclear whether new long-term rig contracts will be signed during 2017 as many operators were burned on 3-year deals finalized in 2014.

Drilling times also have fallen since 2014. Operators no longer need as many rigs as they did thanks to increased efficiencies brought about by practices such as drilling longer laterals.

WoodMac expects proppant costs to rise by 15% this year, noting that there is a potential for oversupply of sand in 2018, which could hurt proppant pricing.

Proppant use per lateral foot has grown steadily (Fig. 3). Sand usage is expected to increase during 2017 as the number of horizontal completions and proppant volumes used per well rise. Leading exploration and production companies already are pushing proppant levels beyond 3,000 lb-ft in the Permian basin.

Another risk is that operators will start to encounter diminishing returns as proppant loads increase. The types of sands operators prefer could also shift.

Inflation varies

Numerous factors drive basin-specific inflation, including increased company spending, comments by operators about service-price hikes, and rig additions.

Fig. 4 shows the increase in wellhead breakevens from cost inflation in 2017.

Rising costs will increase production break-even levels for operators. The costs of producing even the best horizontal wells will increase by an average of $5/bbl in 2017 based on basin cost-inflation assumptions.

There are outliers, however, to the general trend of additional spending equating more inflation. The Delaware basin's 2016 base spend already was at record levels. Operators in the ArkLaTex hold very play-specific equipment for development of the Haynesville shale. The South Central Oklahoma Oil Province and Sooner Trend Anadarko basin Canadian and Kingfisher counties (SCOOP-STACK) plays in the Anadarko basin have been stalwart assets for 2 years. But some of the fastest-growing operators are refocusing investments to the Delaware.

Permian basin plays and subplays have undergone increased drilling activity for some time. In Midland, Tex., pressure-pumping equipment is difficult to obtain without being on a waiting list or paying a premium.

Permian operators swiftly absorbed available top-tier drilling rigs, forcing some operators to turn to lower-tier rigs.

A step change in non-Permian basin cost inflation would be needed past 2017 to incentivize labor and equipment to move from West Texas. Service companies, however, might be unwilling to commit to more remote basins until operators agree to long-term contracts.

The author
Jackson Sandeen ([email protected]) is a Wood Mackenzie Ltd. senior research analyst working on the Lower 48 upstream research team. He evaluates and analyzes Permian basin assets of upstream oil and gas operators, assists with consulting projects, and publishes reports on key regional trends. Previously, Jackson worked on the WoodMac deepwater Gulf of Mexico team. He earned degrees in economics and broadcast journalism from Boston University (2011). He is a Chartered Financial Analyst.