下面是小编为大家整理的2020年北美石油服务与设备行业展望：2020年又是“少花钱多办事”一年（完整）,供大家参考。
2020 North America Outlook 2020 Another Year of “Do More With Less”; Seasonal "Hope Trade" Comes Early This Year
We are highlighting an excerpt from our 2020 Outlook: You Can Only Reap What You Sow; Cash Harvesting Cycle to Sort the Wheat from the Chaff report published December 13 th . Prelim U.S. E&P budgets suggest low-to-mid double-digit capex decline in 2020. While we expect bulk of the U.S. E&Ps to announce 2020 budgets during 4Q19 earnings, our E&P Budget Tracker following 3Q earnings suggests a - 12% decline in y/y spending to be accompanied by a ~2% growth in production based on ~25% of names offering preliminary guidance. Anecdotal messaging from E&Ps emphasizing “value over volumes” has become increasingly homogenous, with several prepared to dial back spending and maintain flattish production profiles y/y in less favorable commodity price environment in order to generate better cash flow. Given that 2019 capital budgets have been consistently guided down through the year (down 150-200 bps v. when they were announced earlier this year) owing to an efficiency-induced favorable service cost environment and E&P capital austerity, we think a -10-15% base case reduction in 2020 spend is a reasonable bogey. While the rollover in shale productivity appears to be still out in the ether, expectations of a rollover in U.S. production could be enough for a hope trade in early 2020, in our view. Pressure pumping: more attrition needed before the market
can balance.
In our view, NAM frac epitomizes today’s “cycle of abundance”. Industry capacity was built up considerably over the course of the past cycle, fueled by voracious demand growth in shale and low barriers to entry. Today, with average frac operations far more efficient than in 2014 (stages/day +40%) and E&P growth initiatives waning, many pressure pumping providers are now saddled with equipment that likely will never see a wellsite again. As such, many pressure pumpers chose to retire fleets in 3Q19, such as PTEN and FTSI each announcing 300k hp reductions in nameplate capacity. All told we estimate over 2mm hp exited the market so far in 2019. However, with pricing falling and some contractors operating at EBITDA breakeven (or worse) levels, we believe still more hp needs to be cut up before a semblance of market balance can be restored. This will take time though, as pumpers work through spare parts of
idled equipment, and may not come until late in 2020 or even beyond. North America Equity Research 20 December 2019
Oil Services and Equipment Sean C Meakim, CFA AC
(1-212) 622-6684 sean.meakim@jpmorgan.com Bloomberg JPMA MEAKIM <GO> J.P. Morgan Securities LLC Danyel J Desa (91-22) 6157-3301 danyel.j.desa@jpmchase.com J.P. Morgan India Private Limited Andrew P Herring, CFA (1-212) 622-8585 andrew.p.herring@jpmorgan.com J.P. Morgan Securities LLC Corey Mergenthaler, CFA (1-212) 622-1167 corey.mergenthaler@jpmchase.com J.P. Morgan Securities LLC
Figure 1: Frac Demand (LHS, mm hp) and Utilization (RHS) 20
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0 2011 2012 2013 2014 2015 2016 2017 2018 2019e2020e2021e
120% 100% 80% 60% 40% 20% 0% Figure 2: EV/Replacement Value 1.6x
1.4x 1.2x 1.0x 0.8x 0.6x 0.4x 0.2x 0.0x HP Demand (mm hp) Marketable Utilization Nameplate Utilization
Source: Rystad, J.P. Morgan Estimates. CFW FTSI NEX LBRT
PTEN
PUMP RES TCW Source: Company reports, J.P. Morgan estimates. *CJ, FTSI, RES based on BBG consensus. See page 29 for analyst certification and important disclosures, including non-US analyst disclosures. J.P. Morgan does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision. www.jpmorganmarkets.com Group Avg.
Land drilling: lower counts to stay, pricing discipline key. 2019 saw the worst decrease in U.S. land drilling activity since 2016 (when the L-48 count
fell -47% y/y), with the 2019 YTD average of 949 down -8% from 2018’s average of 1,032. However, heading into 2020 we see scope for a reversal in the rig count delta early in year. Our view is driven by E&Ps resetting budgets on (relatively supportive) price decks most likely in the $50-55/bbl WTI range, and by our expectations for a repeat of 2019’s seasonal front-half spending weighting. The magnitude of the rebound we model is fairly restrained though, with expectations for only a +1% q/q gain in the average count from 4Q19 to 1Q20, and our base case is for a -13% y/y slowdown for the L-48 in 2020. Despite calls from the bears for a falloff in dayrates, pricing remained fairly resilient in 2019, averaging in the mid-$25k/d range for the coverage group. We expect contracts to persist roughly in this range or just below in 2020. Drillers understand that incremental price concessions are unlikely to lead to incremental rig additions as E&Ps simply don’t have the budgets for more rigs, so defending pricing and margin instead of chasing share continues to be the optimal decision. Figure 3: JPM U.S. Land Rig Count Forecast 2,000 1,800 1,600 1,400 1,200 1,000 800 600 400 200 -
Source: Baker Hughes and J.P. Morgan estimates. Figure 4: Rig Count Change by Operator Type (Indexed to 2Q16)
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Source: Enverus, J.P. Morgan estimates. Basins: Permian to continue dominating production growth, incremental E&P spending. We expect growth in the Permian to (relatively) outstrip other shale basins in 2020 as anecdotal commentary from E&Ps suggests plans to shift capital to the Midland/Delaware from other plays to focus on higher margin opportunities. In Appalachia, given E&Ps reticence to commit capital to the region and a sustained weak price environment for natural gas, we expect activity to continue to decline in 2020. Similarly, we think activity in the Eagle Ford is likely to trend downwards, with several E&Ps citing plans to shift capex to the Permian. In both the Bakken and DJ we think the drilling outlook is generally negative, while prospects for frac are somewhat brighter (but still lower y/y) due to a likely pickup in high-intensity completions in the former and improved full-cycle returns in the latter. Finally, in the Mid-Con we view 2019’s decline as likely to persist, and forecast a -20% y/y decline in the rig count. Canada: Alberta curtailment effects and insufficient pipeline capacity to keep activity restrained. Canadian activity has been challenged in 2019 (to say the least), on the back of insufficient pipeline capacity and government- mandated production limits. Though Alberta production limits have eased modestly over the year, WCS-WTI spreads currently stand at -$21/bbl, wider than the 2019 average of -$13/bbl. Our Integrated colleagues project that WCS differentials could widen further in 2020 as production curtailment effects ease, against the backdrop of a challenging pipeline approval environment and potential IMO 2020 quality aspects, resulting in a ‘lose-lose’ scenario for E&Ps (and services alike) next year, in our view. 2
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GOM: Service activity mixed, drillship market to tighten but slack remains. Most importantly for our coverage, drillship demand has and should continue to increase. Probable tenders are barbelled for the time being, with plenty of short- term work along with much more attractive opportunities in the pipeline, albeit fairly far out. The pursuit of utilization will still hold back the whole space, in our view. The jackup market remains little changed; we expect the mature market"s rig count to remain stable in 2020 at ~10. Semis will also stick to the status quo, with more movement between jobs in Mexico. However, GOM economics don’t warrant much optimism given macro environment. Leased acreage volume continues to climb while value per acre has remained flat over the last two years. The GOM pre-FID cost curve leaves little margin of safety
for operators such as TOT and BHP to greenlight incremental programs, which we view as required for the market to realize the long-awaited dayrate inflection. We think operator conservatism will bias projects to be pushed right as shorter cycle onshore economics remain comparatively attractive. Figure 5: Top 7 U.S. GOM Operators by Reserves and Production 35% 30% 25% 20% 15% 10% 5% 0% Figure 6: U.S. GOM Rig Count 40 35 30 25 20 15 10 5 0 RDS BP CVX EQNR MUR BHP TOT Production Reserves Source: Wood Mackenzie
Drillships Semis Jackups Source: IHS-Petrodata, J.P. Morgan estimates. Is the “circular logic” of U.S. onshore back? We hope to ride the 1H20 "hope trade". With U.S. shale production slowing, WTI prices towards the middle-to-low end of the range, and investors’ collective boot still firmly on the necks of public E&Ps, we expect E&P capex to fall (at least) -10-15% in 2020, following a -15% decline this year. As a result, we expect more idle rigs and
frac crews as well. While not exactly a bullish setup at face value, we argue the equity market already spent 2H19 pricing in this pain. Heading into 2020, we think the seasonally ephemeral “hope trade” looks already well underway, earlier than usual (OSX +30% off its 8/27 low v. +12% S&P). Still, we don’t recommend riding the highest beta one can find; instead, with lower activity we expect E&Ps to be ever more discerning, further enhancing the impact of our "haves and the have nots" thesis. With the market’s priorities shifted from top line growth to cash generation, we think select North American onshore stocks could get rewarded if they 1) offer good balance sheets and customer lists, 2) “squeeze the rag” on FCF, and 3) deploy a disciplined capital allocation approach that emphasizes cash harvesting. We would further stress those already trading at discounts to peers (e.g. NEX). To gain exposure to NAM in 1H20, we recommend top pick NEX, as well as OW-rated HAL, PUMP, LBRT, NINE, HP, WHD and MRC and N-rated TS.
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