Look, I get it, ok?
People like to read about oil. Which in turn means there’s a lot of demand for tortured analysis of oil prices – what drives them, where crude is headed, what the economics are behind this or that discrete shale play, etc. etc.
Where there’s demand, they’ll be supply and so month after month we get a veritable deluge of sellside research that purports to explain where things are headed. It’s a valiant effort, but it all smells of goal seeking – or at least on my end it does.
Simply put, I’m not 100% sure this is a market that needs to be overanalyzed. You’ve got a swing producer and you’ve got a marginal producer. And if you understand the definition of those terms, then you really don’t need much more information to understand how this market works.
Now I’d be laughed out of the room if I were to tell a bunch of analysts that anyone who can manage a C+ in a graduate level econ course understands all they need to understand about crude. But laugh as they might, I would challenge those analysts to explain to me how the past three years of price action deviates materially from an explanation that could be derived from basic econ principles.
I mean OPEC does something to push prices in one direction or another (let’s leave aside their motives), US production responds in a highly predictable fashion (e.g. going the fuck out of business when prices plummet and coming back online when prices rise), and then OPEC takes a look at GCC budgets and market share every once and a while and decides what they want to do next. That’s just all there is to this.
Well, that’s not entirely accurate. The X-factor has been DM central banks who have kept capital markets open to otherwise insolvent producers which means that rather than going completely out of business, some operators in the US were able to simply hibernate until prices rose anew. So you know, OPEC cut production, prices rose, the marginal producers came back, their resurgence capped price gains while the possibility that OPEC would extend the cuts put a floor under things, oil was rangebound, and here we are.
Again, you can throw out all the numbers, charts, and seasoned analysts you want to throw out, but that’s just all there is to this story at some basic level. If you want to cover all your bases, you can throw Russia into the equation but again, you don’t need to be an energy analyst to incorporate that into your narrative.
That said, there’s a demand for tortured analysis and where there’s demand there will be supply and so Goldman is out with a pretty epic note on Tuesday called “The Shale Productivity Paradox, v2.” The fact that this is “v2” speaks to my contention that this analysis is becoming increasingly tortured.
For those interested (and I can almost guarantee this will be one of the most read posts today), here are the key takeaways and some additional selected excerpts.
The combination of new project startups, shale productivity gains and rising OPEC production capacity slightly reduces the call on US shale oil from our prior estimates in 2018-19, and the aggressive ramp up of US shale activity warrants producers to limit incremental rig adds. While we are bullish on near-term prices as inventories normalize (to $55/bbl WTI), either 2018-19 futures need to be in the $45-$50 range now or there would be downside to our forecast for higher 2018-19 prices once we get into those years. The companies most negatively impacted are those that need to depend on hedging or would have wide outspending of cash flow at a $50/bbl WTI price. This further supports owning equities of shale scale winners, in our view, for contiguous acreage that allows for longer laterals, shared facilities, and technology advantages. Historically equities have outperformed the S&P 500 when front-month prices rise and futures curve shifts to backwardation, though shale has made longer-dated prices more important today than in past periods.
If both shale and OPEC produce at capacity, oversupply would result; price signal is needed to stop shale activity acceleration. We see US oil growth of about 0.8 million bpd per year in 2018-20 (vs. 1.0 mn on average in 2013-15 and headline demand growth expectations of 1.2-1.5 million bpd in 2018-20), though this now assumes OPEC is more restrained vs. its growing capacity. Without OPEC restraint (beyond 2017), there is risk of a lower call on US oil growth and downside to our oil price forecasts. We are on track to exceed 0.8 million bpd of US oil growth in 2018, warranting price signals to stop the acceleration of US shale activity.
This price signal – backwardation in the forward curve with 2018 futures prices sub-$50 – is another reason to own shale quality. To achieve rational growth from OPEC/shale and not maximum growth by one side vs the other, the oil futures curve needs to move to backwardation to limit aggressive US producer hedging. This favors producers with healthy balance sheets and attractive cost structures that are not dependent on hedging. It also favors producers with scale as they can likely respond most quickly to front-month price signals with less cost volatility. This further emboldens our E&P equity preferences for shale scale winners with contiguous acres – EOG, PXD, CLR, COG, RRC among others. We downgraded WLL to Sell from Neutral, HES/XEC to Neutral from Buy and upgraded NFX to Buy from Neutral.
Maintain $50/bbl long-term price. Forward curve likely needs to reflect at/below $50 pending greater confidence in inventory normalization. We do not see need for a simultaneous price signal sustained $55/bbl oil signal in both futures curve and front-month prices in 2017-19, particularly as longer-dated futures around these levels would prompt too visceral a supply stimulus across shale or too much hedging to keep OPEC from restraining production vs. capacity. Our long-term oil price remains $50/bbl WTI, though for higher spot prices in 2018-19 futures prices for these years need to first reflect at/sub-$50 per bbl to slow shale activity from its current pace. We lowered target prices to now largely reflect $50/bbl WTI oil with productivity gains in our fundamental values vs. largely reflecting $55/bbl previously.
Flat to falling rig count, tightness in pressure pumping/frac sand markets justify owning completions/sand over rigs. The US land rig count has more than doubled since May 2016, and while it may increase some further, it should be nearing a plateau for three reasons: First, owing to well productivity (partly on greater pressure pumping and sand intensity), we believe rig count in the 850-900 level is enough to grow US oil production by ~800K bpd annually. Second, E&P budgets cannot justify continued growth in US land rig count given limited FCF generation. Third, short-term bottlenecks are developing based on timing of planned pressure pumping capacity additions that could push higher inventory of drilled but uncompleted wells (DUCs). As a result, we expect demand for completion services to continue to grow despite flattening in the rig count, and project differentiation to develop between land drilling stocks and completion stocks (pressure pumpers, frac sand, completion equipment) going forward. We recently downgraded HP to Sell from Neutral, we are Buy-rated on HAL/PUMP/SLCA/EMES.
Midstream tightness possible in 2019, but new projects under development. Among high-growth basins, we expect Permian crude takeaway infrastructure is sufficient to meet near term production levels through 2018, but see risk of some supply tightness in 2019. A number of recently proposed greenfield projects accounting for 1.2mn bpd of crude takeaway capacity have announced a current or planned open season and 2019 in-service dates. For natural gas and NGL takeaway, new projects have been announced to move molecules from Midland towards Corpus Christi, which should contribute to easing some bottlenecks on inter-and intrastate pipelines moving out of the basin and towards demand centers in the Gulf Coast.
Quality bias on Americas Conviction List as growth opportunities are concentrated among fewer companies. We maintain a quality bias on our Conviction List, as we believe scale is critical to thriving in a $50/bbl world and as the growth opportunity (in both E&P and Oil Services) gets concentrated among fewer participants.
Backwardation may hasten consolidation, but the timing is unclear. Already we have seen $50 bn of shale M&A in the past two years, but only 3 of 36 transactions >$0.2 bn have been publicly traded corporate deals.
Lookback suggests shale still has room to grow, prices to remain rangebound. Production growth and substantial resource from shale is no longer a surprise to the market. The debate now is about magnitude both in terms of production at various prices and longevity of inventory. A lookback at the past 50 years of oil’s history shows that resource areas tend to expand over 7-15 years. We are in year six of the shale expansion, and we believe shale growth is on track to continue growing meaningfully for another 7- 10 years. In periods in which supply growth is robust, we have seen oil prices fall or remain low until technology matures. This was the case both in 1965-72 after which US growth slowed and prices rose (partly on the OPEC embargo) and in 1984-98 after which the Gulf of Mexico/North Sea matured and prices rose sharply. We believe we are in a lower for longer environment until there is greater evidence shale deliverability is surprising to the downside or OPEC runs out of spare capacity.
We see favorable growth into the middle of next decade. We believe the Big 3 shale plays (Permian Basin, Eagle Ford Shale and Bakken) combined with Cana Woodford plays (SCOOP/STACK) and the DJ Basin can together drive on average 0.8 mn bpd of annual production growth through 2020 and 0.7 mn bpd of annual production growth in 2021-25. We see production plateauing towards the end of the next decade at present. Importantly, as described below, we still see room for additional productivity gains; our estimates incorporate expectations for 3%-10% productivity gains per year through 2020.
While rest of the world is finding ways to move breakevens down towards $50/bbl WTI, we still see shale as the dominant source of growth and as a critical source of short cycle production. Our global cost curve from our recent Top Projects report shows continued decline in shale breakevens, though at a smaller pace vs. in past years. Outside of shale, we increasingly see industry – majors, national oil companies (NOCs) and governments – working to accommodate new projects that break even at $50/bbl WTI or less with a goal of becoming more competitive with shale. This largely is occurring through a combination of improved tax/royalty terms by host governments, more limited scale by producers (smaller projects that come online more quickly) and cost reduction/efficiency gains. We still see production from new projects falling off towards the end of the decade as a result of the reduction in investment after oil prices collapsed post-2014. As such, we expect shale will continue to be a critical source of marginal supply because shale along with OPEC spare capacity are the principal sources of short-cycle supply.
US deliverability rising – 1+ million bpd annually at $55 oil. A combination of productivity gains, access to capital, rising resource and falling breakevens (ex-cyclical inflation) contributes to slightly greater deliverability of US production than previously assumed. We believe we could see annual US oil growth of 1 million bpd (rising over time due to productivity gains) if we see a price signal and actual prices of $55/bbl WTI oil. Beyond productivity gains, we believe two other factors are critical in how aggressively US production grows:
1. Level of reinvestment of cash flow – our sensitivity assumes capex is close to cash flow in 2018-20, though we assume 105%- 113% if oil were to average $50 and companies broadly stick with existing plans;
2. Potential oil services or midstream constraints, we see rising likelihood of completion constraints
Barring production disruptions or much larger than expected demand, it is difficult for us to see a situation in which the “call” on US oil is in excess of 1 million bpd. As such, we believe that the oil price signal to producers (combination of futures curve and frontmonth prices) is unlikely to be a flat $55/bbl.
Continue to assume $55/bbl WTI in 2H17. At its May 25 meeting, OPEC agreed to extend production cuts initiated in 2017 for nine months through 1Q 2018. This strongly indicated OPEC’s interest in bringing inventories back to normal levels. We believe inventories will normalize by year-end which should lead to higher front-month oil prices. We continue to assume $55/bbl WTI oil in 2H 2017.
But shale is not the only avenue for potential production growth in 2017-18. Outside shale, we see about 1.4 million bpd of growth from Top Projects (on a risked basis) in 2017 and another 0.9 million bpd in 2018. We now assume greater deliverability (haircutting targeted production by 2.5% per year vs. 3.5% previously due to an improvement in recent deliverability trends). Separately, we see OPEC deliverability rising by about 0.6 million bpd per year in 2017-20, driven largely by new fields coming online in Iraq, some additional capacity in Iran/UAE/Kuwait and a new field and longer-term greater drilling activity in Saudi Arabia. In 2018, we believe if OPEC produces at capacity and shale produces at a growth rate consistent with $55/bbl WTI, we would see OECD inventories move back to excessive levels vs. the 5-year average. We assume that non-OPEC production outside of Top Projects declines at an elevated rate vs. the past 5-10 years, but at a lower rate than in 2016. Mexico, China, Colombia are key areas to watch as key drivers of 2016 declines. Even if declines stay elevated, there is not room in our view for the market to handle “full capacity” from shale, OPEC and Top Projects at $55/bbl WTI without inventories moving well above the 5-year average on days of demand basis.