1 minute read
By Linda Htien, Senior Research Manager, US Lower 48 Upstream Research, and Ann-Louise Hittle, Vice President, Oils Research
The past six months have profoundly changed the outlook for US tight oil, triggering a slowdown in the rate of growth with a lower peak now expected.
After several years of remarkable growth, the 2020 price collapse pitched US tight oil production into a year-on-year decline for both 2020 and 2021. After that jolt, starting in 2022, Lower 48 oil production returns to growth but at a far slower rate than before the pandemic. Volumes will be nearly 2 million b/d lower than previously expected over the next five years due to 2020’s events. In addition, peak production late this decade will be 600 kb/d lower than our previous projection.
Unlike the oil price downturn of 2014-2016, there is far less room for the sector to make sweeping improvements in well performance and operational efficiency. Companies that survive the unfolding shakeup will need to rebuild trust with investors. Even if they do, higher prices will not mean unbridled growth, making tight oil a less elastic source of supply. Heightened policy risks will put additional downward pressure on investment. Technological breakthroughs could be a boon for the industry, but outside of this the uncertainties weigh heavily to the downside.
For the oil market, the shift downward in our forecast for the US Lower 48 helps offset the steep losses in oil demand, especially in 2020 and 2021. However, from 2022, the cuts to our US supply outlook and slowing rate of growth mean a growing reliance on OPEC capacity to meet demand through this decade. The loss of US L48 supply heightens the risks of a tighter global market and higher prices this decade.
An unprecedented early run
US shale seemed unstoppable for a while, a 21st-century equivalent of the 1840s gold rush. Tens of billions of dollars were poured into tight oil assets by E&P companies of all shapes and sizes. Science as well as capital led to more and more productive wells as the best rock was delineated and developed. In the last decade, Lower 48 oil output tripled to 10 million b/d.
But it was never sustainable
Two years ago, we saw the emerging signs of a slowing sector and called for the peak rate of growth in 2018, a view we still hold today. Capital became harder to source as Permian players fervently outspent cash flow. Well-productivity gains stalled, and the reality of over-drilling reservoirs set in. Spending eventually disconnected from prices as operators prioritized cash flow over production growth at investors’ behest.
Then a setback in 2020
This year’s price crash drove a sharp pullback in tight oil, with a more rapid response and deeper cuts than the prior price crash four years ago. In a single quarter of 2020 – Q2 – Lower 48 oil production fell 2 million b/d (20%), driven largely by shut-ins and curtailments. Drilling and completions activity dropped by more than two-thirds, and these deep cuts will result in at least two consecutive years of decline. Investment capital is in short supply with US Independents financially stretched, and bankruptcies mounting.
Supply expectations are reset
Tepid growth was already in our forecast but it’s even lower now, and from a lower base. The average growth rate over the next decade will be less than one-fifth that of the previous three years, when prices were US$10/bbl lower. It will be like driving with the parking brake on.
If there’s a silver lining, it’s our outlook for stronger prices in the medium term. The inventory of undrilled wells is still there, and Lower 48 production could recover to its prior peak by the mid-2020s. However, US$70/bbl WTI is required. Higher prices will incentivize new well activity – but with limits.
Five forces reshaping the sector today
What’s slowing tight oil growth?
1. A new relationship with investors will reduce budgets
Tight oil will be a less elastic source of supply. In marked contrast to the last decade, we don’t expect operators to channel surplus cash flow from higher prices into growth investment.
Capital discipline is not a new theme in 2020, but more ideas are being floated now that show the industry’s commitment to it. Several operators indicated in Q2 earnings statements that capping reinvestment at around 70% to 80% of operating cash flow will be the go-forward model. In 2018 this figure was more like 120%. The shale sector typically adopts similar strategies, so expect to see more of this. Some operators plan to fix capex, even if prices rise. Companies like Concho, Pioneer, and Devon are moving (in various degrees) toward a variable dividend. Structures are being built where excess cash flow from rising oil prices will be funnelled directly to shareholders, not reinvested in projects. We think this theme will gather momentum. Just spending marginally less than operating cash flow won’t be enough to rebuild investor confidence going forward; more substantive measures like these are needed.
2. Less appetite for risk – the 80:20 rule
Operators can no longer afford to waste capital. Investors won’t allow it and prices don’t offer enough margin to absorb mistakes. Exploration of new Permian zones will remain stalled, so those proven commercial today will have to carry the weight of drilling in the near future. Inventory exhaustion in core areas and reservoirs is a real problem though. Without risk capital to delineate new reservoirs, there’s little chance of expanding the core. Future wells will be less productive. Production histories have shown that secondary benches – even in plays like the Bakken and Eagle Ford – are secondary for a reason. In some cases, the development of primary zones has also depleted adjacent reservoirs that once held production promise. Even ExxonMobil and Chevron, both early into their Permian growth journeys, are already ceding to preferred pad configurations. The Permian is following numerous other shale plays where 20% of acreage ultimately yields 80% of production.
3. Slow technology advancement
The oilfield service sector, which was instrumental in innovation during tight oil’s rapid growth phase, will struggle even more than E&Ps in this downturn. Budgets there have been cut deeper and the industry’s largest OFS firms are pivoting away from shale to lean on international conventional projects more. Schlumberger just took a major step in this strategic shift, announcing it would sell its entire US fracking business.
Even if there was a new wave of shale technologies to deploy, operators would struggle to fund implementation in the field. Conversion costs are never zero. Technology investment has continued in the data science space but, to date, those initiatives have delivered limited results in lowering development costs.
4. Heightened policy risk
A change in the White House would bring additional challenges to producers. But it won’t simply mean a return to Obama-era rules, which have been systematically reversed by the Trump administration. Democratic candidate Joe Biden’s recently announced US$2 trillion energy transition plan is ambitious to say the least. A Democratic majority in the Senate would open the door for a return to action – stricter limits on gas flaring, higher hurdles for new permits, and less willingness to open federal land to drilling.
The past two years have seen additional pipeline and permitting hurdles take shape across numerous shale basins. Legal challenges were cited as a reason for the Atlantic Coast Pipeline cancellation earlier this year, and the fate of the Dakota Access Pipeline is still unsettled as the courts decide whether it must be shut down for an environmental review. Even new intrastate pipelines in Texas are proving harder to build. Drilling rules are changing, too, particularly in the Rockies.
With change comes a new reality that tight oil projects will likely be susceptible to delays, take longer to execute, and cost more. ESG pressures will be far more consequential for tight oil’s future than it was for its past.
5. Consolidation
Even though global M&A stalled in H1 2020, the drivers for Permian consolidation still exist. There are simply too many producers operating at too high a cost.
The frozen asset market may be thawing with deals like Chevron’s acquisition of Noble Energy. And we would not be surprised to see two large Independents merge within the next six months. Severe downturns typically create an 18-month M&A window. We’re a third of the way in.
Deals will be done to shore up cash flow in the near term and ensure resilience in a low-price environment long term. Those that remain will benefit from lower fixed costs, operational efficiencies and economies of scale. High-quality, low-cost assets will fall into the hands of capital-efficient operators with strong balance sheets and lower cost of capital.
Why does it matter? Overall capital investment typically shrinks post-acquisition. Oxy is a prime example, having halved its combined tight oil budget after acquiring Anadarko. Consolidation will put downward pressure on development activity and production growth.
Impact on tight oil growth: more downside than upside
Some industry bears will tell you tight oil is dead. We are not in that camp. But all things considered, the uncertainties weigh to the downside and are less price-dependent than one might expect. It’s difficult to envisage a likely combination of these forces that results in a major comeback for the sector.
Peak production may not be behind us, but we firmly believe that peak growth is.
Wildcards that might change tight oil’s trajectory
Price: the tight oil cost curve has flattened the last few years, meaning that smaller movements in price have a larger impact on the financial performance of projects. Half-cycle breakevens between some of the best and worst tight oil assets (PV15) only differ by US$20/bbl.
Should prices move higher than our forecast of US$70/bbl WTI by 2025 and capex budgets stay flat, cash flow from operations will inevitably balloon. Variable dividend discussions might evolve to a committed higher base, allowing companies to find a healthy balance between growth and payouts.
Technology: this could also alter the outlook if digitalization initiatives eventually deliver breakthroughs in shale. Partnerships have always been needed for these initiatives to work. Slow to start, they are now being formed as G&A cuts have seen many digitalization teams disbanded.
Future portfolio positioning: this adds some uncertainty to the outlook, too. Five companies account for the lion’s share of tight oil growth, but leaders Chevron and ExxonMobil have global portfolios that include assets that keep delivering, like Guyana, the Eastern Mediterranean, and US Gulf of Mexico. Will their commitment to shale waver? Perhaps a bigger stretch – might they follow their European counterparts with bold initiatives for the energy transition? Will tight oil specialists like EOG and Pioneer be forced to look internationally again?