Epic Oil Crash Sets Up Brutal Downturn for Energy Sector

Editor’s note: Read the latest on how the coronavirus is rattling the markets and what investors can do to navigate it.

On April 20, U.S. oil prices dipped into negative territory and Brent crude swooned shortly after. The coronavirus has wreaked havoc on worldwide consumption of gasoline and other crude products, and the supply response thus far has been lethargic and ineffective. As a result, storage utilization is dangerously high, and investors who paid heavily to escape short-term crude futures may yet breathe a sigh of relief. Even before the latest oil collapse, the outlook was bleak: The 9 million barrel/day decrease in global demand that we now forecast due to COVID-19 eclipses prior downturns, and brinksmanship by Russia and Saudi Arabia has delayed a crucial response on the supply side. But extrapolating Armageddon oil prices to infinity is a mistake. We think the GDP impact of COVID-19 will be modest in the long run. Once a vaccine is developed, we see little reason for demand for most oil-related items (even for air travel) not to fully return to normal. If the intensity of consumption is not severely affected, we will eventually see strong catch-up demand, which cannot be satisfied without a contribution from U.S. shale--and that business model simply does not work at strip prices. The marginal cost for shale producers is $55/barrel (West Texas Intermediate), and without a recovery to that level, shale investment will fall far short of what's necessary.

Storage Fears Send Crude Tumbling WTI crude spiraled into negative territory on April 20 as oil traders played a high-stakes game of musical chairs. Widespread social distancing due to the coronavirus has dragged down oil consumption, and storage utilization at the Cushing hub, where delivery of the WTI contract occurs, is rapidly climbing. Storage utilization has been sharply rising for the United States overall in recent weeks, due chiefly to the dearth of oil demand because of COVID-19. However, utilization in Cushing has surged the most, going from 50% in early March to 72% by April 10. If this rate of increase continues, Cushing's tanks will be full by mid-May. Practical limits could be reached much earlier than that, given that utilization never rose above 90% in the prior oil downturn in 2016.

That makes front-month futures contracts much riskier than usual--nobody wants to take physical delivery if there’s nowhere to store it. In the April 20 scramble, some investors paid as much as $40 per barrel to offload futures for May delivery because if Cushing does get full, it could cost even more to find an alternative home for physical barrels at the time of delivery. The price of the front-month WTI contract (for delivery in May), which expired April 21, fell from $20/bbl to negative $38/bbl over the course of the trading day. Near-term Brent prices subsequently declined as well, suggesting global storage utilization is mirroring the U.S. But because Brent futures are cash-settled, the declines were less severe.

The significance of the declines was probably overblown by intense media coverage, given that longer-dated futures were affected much less severely. The WTI June contract has fallen from $26/bbl on April 17 to $17/bbl (35%), indicating moderate concerns about near-term storage, but it has stayed out of negative territory so far. The December 2020 contract has fallen only about 14%, and the 2021 average strip price is down about 9%. These are all significant declines, but far from catastrophic. In our view, any physical constraints will evaporate once OPEC cuts kick in and COVID-19 isolation ends. So, it doesn’t make sense to discount long-term prices for storage risk.

2020 Set for Historic Demand Decline, but With a Quick Bounce Back We now expect a 10 mmb/d impact from COVID-19 on global oil demand in 2020. Subtracting this impact from our pre-COVID forecast (about 1.2 mmb/d growth) yields our new forecast for an almost 9 mmb/d (9%) oil demand decline in 2020.

This is a stunning hit to demand by historical standards, easily surpassing the 1.6% decline in the prior recession (2007-09). No one-year decline in oil demand in the post-WWII era comes close, although we did see a 10% cumulative demand decline from 1979 to 1983 in response to the oil price shock of the late 1970s. While this forecast might seem sensationally bearish, we think it’s very much realistic (and roughly in line with leading-edge consensus--the International Energy Agency’s newly released April oil market report projects a 9.3 mmb/d demand decline in 2020).

Our oil demand forecasts draw on Morningstar's macroeconomic work, which incorporates the impact of COVID-19. We forecast a 1.4% fall in global real GDP in 2020, incorporating a 460-basis-point impact from COVID-19 (compared with our pre-COVID-19 expectation of 3.2%). Typically, oil demand growth has about a 1-to-1 relationship with GDP growth. However, given the disproportionate hit to transportation from COVID-19, we're expecting a much greater hit to oil demand than overall GDP in 2020.

However, we still don’t think it’s time for investors to panic on oil demand. Crucially, we believe that oil demand will see dramatic catch-up growth in 2021 and afterward. That’s because we forecast a modest long-run impact on the global economy from COVID-19, which implies a V-shaped recovery in GDP. We don’t think that the ensuing COVID-19 recession fits the mold of a 2008-style recession that has longer-lasting economic impact, as the world’s productive capacity will be largely untouched by the virus, and economic confidence should rebound quickly once the virus subsides.

We expect jet fuel and gasoline (8% and 26% of global oil demand, respectively) to drive over 70% of the hit to 2020 oil demand. These products are driven mostly by passenger transportation, which will be curtailed for social distancing. Likewise, we expect the second quarter to drive about half of the 2020 impact, as that is when social distancing will probably crest.

Our forecasts are informed by our month-by-month projections for COVID-19 outbreak severity in the U.S. and implementation of mitigation measures including business closures and voluntary social distancing. In our base case, we expect the need for social distancing to fall dramatically in the second half of 2020, as we project a much lower fatality rate thanks to the development of effective drug treatments. While we developed this model for the U.S., it is a good guide for what to expect for the rest of the world on average.

In percentage terms, we think jet fuel will take the biggest hit in 2020 (37% impact). In recent weeks, airlines have discussed cutting near-term capacity by 40%-70%. Drawing on early data from various sources, Rystad Energy projects a 60% hit to second-quarter demand, in line with our view. While we expect much of life to return to normal in the second half of 2020, we still think people will reduce travel and avoid most large events. Given the close contact with masses of people from dispersed areas that air travel entails, we think it will lag the sharper recovery for gasoline demand.

We don’t think demand for diesel or other oil products (primarily petrochemicals, industrial fuel, and marine fuel) will be hit any harder than GDP, as demand for these oil products is primarily driven by demand for goods. Unlike typical global recessions, which have hit investment expenditure and durable goods consumption much harder than services consumption, this recession will be focused more on services, given the need for social distancing.

Although we think gasoline will take a smaller hit (16%) than jet fuel, its large share of global oil demand (26%) means that it is the single-biggest driver of our forecast impact to 2020 oil demand.

We calculate the expected impact on U.S. gasoline demand by breaking out U.S. passenger vehicle miles by trip purpose. We project an 18% impact to traveling for work and school, which accounts for 34% of miles driven. We estimate that roughly 30% of U.S. workers are office workers who are highly eligible to work from home. We assume that these workers reduce their commuting by 80% in the second quarter and one third for the second half of 2020 on average. For the remaining 70% of U.S. workers, we expect substantial reductions in commuting only to the extent that businesses are closed, which we think will occur mainly in the second quarter. We assume a 30% impact from these workers in the second quarter and 5% of workers in the second half.

Likewise, for shopping we expect a rough second quarter followed by a second-half 2020 rebound. Our forecast for a 12% hit to shopping miles slightly surpasses our projected 11% hit to retail sales thanks to e-commerce substitution.

Meanwhile, we think recreation and other trips, which includes restaurants, will be hit hardest; although we expect restaurant closures to largely abate after the second quarter, we think longer-distance travel for vacations will remain somewhat subdued even in the second half of 2020.

Altogether, this analysis indicates a 17% impact to U.S. gasoline demand, which we use as our estimate for the OECD countries broadly. For non-OECD countries, we expect a marginally smaller impact (15%), as we think travel in middle- and lower-income countries is less discretionary, and we expect a smaller GDP impact for these countries as well.

How Quickly Will Things Return to Normal? We expect a relatively V-shaped recovery for oil demand, in line with our views for economic growth. We expect some lingering impact in 2021 as a vaccine probably won't be available until midway through the year, but nevertheless the bulk of the lost demand should be recovered by 2021. That's in line with the rapid demand recovery we project for the second half of 2020. Morningstar forecasts a nearly complete recovery in GDP from the COVID-19 impact, with just a 0.9% impact to the long-term trend of real GDP. Therefore, oil demand should likewise recover nearly to its pre-COVID 19 trend, assuming that the oil intensity of GDP isn't affected by the crisis.

Could there be any lasting damage to the oil intensity of GDP? Once a vaccine is developed, we see little reason for demand for most oil-related items (even for air travel) not to fully return to normal. One possible factor is that the crisis could create a permanent boost to working from home. According to a recent Gartner survey, 74% of surveyed CFOs thought that at least 5% of workers previously working in company offices will become full-time work-from-home employees after the COVID-19 crisis ends. CFOs cited the cost benefits of working remotely, and about 20% mentioned plans to cut back on real estate expenses. That said, the cost-cutting impetus could subside once the economic downturn passes. Also, 5% of large-company office workers account for probably less than 1% of the U.S. workforce; this select group could well have transitioned to working from home in the next several years anyway.

We think it’s also possible that the abrupt shift to working from home in 2020 may be less than fully functional for some companies, which could sour employers’ long-run assessment of it. Indeed, one of the leading academic proponents of working from home is pessimistic about the COVID-19 work-from-home experiment, citing especially the negative effect on productivity of having children at home (due to closed schools). In addition, many workers have plunged into a less-than-ideal setup in terms of home office space, desk ergonomics, and audiovisual equipment.

One somewhat analogous historical episode is the temporary surge of female labor mobilization during WWII and its impact on long-term female labor force participation. U.S. female labor force participation increased from about 28% in 1940 to 34% in 1945 in order to fill the gap left by military mobilization of U.S. males. However, female participation fell back to 30% by 1947 and ended the decade at 33%, an increase of 500 basis points, which was roughly in line with the long-term trend beginning in 1930. In this example, an exceptional change in labor market patterns during a crisis had at most a modest impact on long-run trends in the labor market.

Our Long-Term Oil-Price Forecast Is Unchanged Our equity valuations incorporate strip pricing for the first two years of our forecasts, and currently the strip is indicating a very weak next two years for oil prices, with prices averaging about $28/bbl WTI, or 50% below the 2019 average of $57/bbl.

We agree with the market’s pessimism on near-term oil prices, as oil will be in severe oversupply due to the 9 mmb/d drop in demand that we now anticipate. We assume about 5.25 mmb/d in combined production cuts from OPEC and Russia for 2020, which will drive global oil supply lower by about 5 mmb/d for the year--insufficient to fully offset the lost demand. This imbalance implies a 4.1 mmb/d inventory build in 2020, or 1.5 billion barrels for the full year. This easily surpasses the 0.8 billion barrels implied inventory build during the 2014-16 oil bust.

After OPEC, the fastest responder among major oil suppliers is generally U.S. shale, but even U.S. shale can’t react to lower oil prices overnight. We forecast a 43% year-over-year drop in the U.S. light tight oil rig count in 2020, and we think drilled but uncompleted deferrals will amount to about 10% of shale oil wells drilled. This will slow U.S. oil supply growth to zero in full-year 2020 (with U.S. supply down almost 1 mmb/d comparing the fourth quarter of 2020 with the fourth quarter of 2019). However, this doesn’t fully offset the demand drop.

Oil markets should considerably tighten after 2021, thanks to the robust demand recovery coupled with slowing supply from U.S. shale and other areas. Upstream companies are aggressively cutting capital spending this year, which will eventually damp their output. Unless producers are willing to start investing in growth again, we think the current glut could transition fairly quickly into a shortage. But the required increase in activity won’t happen without higher oil prices. The U.S. shale industry is still the marginal producer in our global framework, and that business model doesn’t work if prices dip sustainably below our $55/bbl midcycle forecast.

After 2020, we expect the U.S. to contribute more in rebalancing global oil supply with demand, which should placate both OPEC and Russia. In 2021, we expect OPEC and Russia’s oil production to rebound to a combined 44.5 mmb/d, or 2.5 mmb/d below 2019 levels. Meanwhile, we expect U.S. supply to fall to 16.1 mmb/d in 2021 from 17.2 mmb/d in 2019. This is a rapid shift for the U.S., given its prior growth trend (1.5 mmb/d average growth over 2017-19). For comparison, U.S. production actually grew by 0.75 mmb/d over 2014-16 despite the oil price downturn.

The much faster shift in U.S. production this time around is driven by a much faster reaction by U.S. shale producers, which have already cut the U.S. horizontal rig count by 32% since March 13. By contrast, during the 2014-16 downturn, the rig count wasn’t reduced this much until March 2015, even though oil prices had already fallen 50% by the end of 2014.

Unlike the 1980s, We Don't Expect OPEC Support to Collapse Given the massive hit to oil demand in conjunction with concerns about OPEC supply restraint, some have understandably drawn comparisons to the 1980s, a disastrous decade for oil markets. Real oil prices fell 46% from 1980 to 1985 despite steep OPEC cuts, due to vicious declines in oil demand. Then in 1986, the bottom fell out, as support for ever-deeper OPEC cuts eroded. OPEC production increased 13% in 1986, and oil prices collapsed another 48%. Altogether, it took oil markets two decades to recover from the hit to the demand and loss in OPEC coordination--oil prices didn't recover to 1985 prices in real terms ($56/bbl WTI in constant 2018 dollars) until 2005.

However, we don’t think this historical episode is a good guide for today. First, the hit to oil demand in the early 1980s was a permanent shock to demand. To a great degree, this was a delayed reaction by oil consumers to the ramp-up in oil prices in the late 1970s. Higher prices led to permanent shifts in behavior and improvements in fuel efficiency, which took several years to play out. By 1980, oil demand was almost 30% below the pre-1980 trend. By contrast, the massive decrease in oil demand in 2020 is (in our view) a mostly temporary response to COVID-19, which should reverse after the outbreak subsides.

Given the magnitude and permanency of the demand collapse, OPEC faced a nearly impossible task in the early 1980s in propping up oil prices. Within OPEC itself, cooperation was showing signs of fraying even before 1986, with the United Arab Emirates, Algeria, and Venezuela only cutting an average 20% in 1985 versus 1978 levels (versus over 50% for Saudi, Kuwait, and Iran).

Return of U.S. Production Growth Will Require Robust Activity Recovery We project that the U.S. supply will need to return to growth after 2021 in order to balance global supply and demand. World oil supply grew an average 1.2 mmb/d in 2017 through 2019, while the U.S. grew an astounding 1.5 mmb/d over that period. Not only did the U.S. account for all incremental global supply needs, but it made up for substantial production declines from other producers, notably Iran and Venezuela.

However, we forecast substantial activity declines in 2020 in response to lower oil prices, commensurate with the deep capital expenditure cuts by exploration and production companies that have been announced so far. This activity decline will put the brakes on U.S. shale production growth. If the U.S. shale growth engine is to restart (which we expect will need to happen by late 2021), that will require much higher activity and spending, which in turn will necessitate higher oil prices.

We project that the U.S. light tight oil rig count will recover to about 620 by 2023, which we see as its sustainable, long-run equilibrium level. This is about in line with average 2019 levels, when oil prices averaged $57/bbl (close to our $55/bbl long-run oil price forecast). This will allow for the U.S. to account for about 1 mmb/d in average annual supply growth over 2022-25, about in line with the growth in global oil supply.

Looked at from another angle, we still think the long-run break-even cost of U.S. shale is $55/bbl. Historically, U.S. shale production has contracted when oil prices have been below this level and grown rampantly when prices have been above it.

We see little reason to change this long-term expectation. In the short run, temporarily low activity will probably push service pricing below our long-term expectations. However, the activity rebound we anticipate through 2023 will reverse these short-term savings. Moreover, pricing was already quite weak in 2019 for many U.S. shale oil service markets. Service companies in many U.S. shale markets, including pressure pumping and land drilling, were earning returns on capital far below cost of capital. It’s unlikely that pricing could remain sustainably lower than we saw in that year.

What about the potential for efficiency gains to lower break-even costs? We had already anticipated this occurring in the next several years in the U.S. shale space, including about a 15% reduction in drilling days per horizontal well. U.S. shale operators were already prioritizing high-efficiency development before this year’s downturn; we don’t think operators will be able to (sustainably) eke out even more efficiency gains in response to the lower prices. The low-hanging fruit is gone.

U.S. E&P: Don't Underestimate Ability to Endure Weak Prices Upstream stocks have already been kicked from pillar to post in the last couple of years, and commodity prices were only partly to blame. The S&P Exploration and Production Select Index lost 60% of its value between October 2018 and February 2020, even though WTI crude lost only 30%. A variety of issues have reduced investor appetite for E&Ps, including the fear that gasoline will soon become obsolete (a longer-term story, in our view) and the risk that a left-leaning U.S. presidential candidate would torpedo the shale industry with a fracking ban (a less urgent threat now that those candidates have dropped out, and something the industry can probably compromise on if it continues working to minimize emissions through reduced flaring and more efficient fuel consumption). But the biggest issue holding many investors back has been the perceived failure of these companies to live within cash flows year after year and the constant reliance on external funding.

There’s no doubt that capital efficiency was historically poor among shale companies, but we have long been sympathetic to the argument that learning by doing takes time. Drilling hundreds of wells generates constant feedback, enabling companies to optimize their processes through trial and error, and there’s strong evidence that most companies have dramatically lowered their production costs as a result. But the recent performance of the stocks shows that investor patience has clearly worn thin, and by dragging down crude prices, the coronavirus has further delayed the pivot to profitability.

Nevertheless, by sustaining those efficiency gains and scaling back growth ambitions, most E&P companies we cover should be able to tolerate the Armageddon crude prices we now expect this year. For many companies, we expect leverage ratios will rise dramatically, but that’s based on slumping earnings rather than spiraling debt. By acting quickly to slash dividends and dial back capital spending this year to the bare minimum, and after factoring in hedge protection (covering 30%-40% of expected volumes in many cases), all but four companies in our coverage group will outspend cash flows by less than 20% this year.

Living within cash flows probably isn’t good enough in this environment, though, which will probably choke off access to external capital for most U.S. E&Ps. So those with long-term debt maturing in the next couple of years will struggle to refinance. To play it safe, investors should assume that any maturing senior notes are a call on liquidity and will need to be covered with cash or bank credit. And be careful with the latter: E&P credit facilities are often asset-backed, and the capacity is redetermined semiannually based on the value of crude oil reserves (which in turn depends on crude prices). Restrictive covenants can also limit access to committed capital. Either way, bank credit can dry up just as it is most needed, making us wary of companies that will need to rely heavily on their revolvers.

The good news is that very few companies in our E&P coverage will need to load up on bank debt, even after paying off expiring senior notes. EOG Resources EOG, Occidental Petroleum OXY, and Pioneer Natural Resources PXD all face large maturities before the end of 2021, but they also have large cash war chests to fall back on. Range Resources RRC has substantial near-term debt to contend with, but it also has a cash reserve and is expecting to sell mineral rights to shore up its balance sheet further (although it could take a haircut if forced to sell before the market recovers).

The company most likely to run into liquidity issues is Antero Resources AR. Though Antero is a natural gas producer, it also outputs natural gas liquids, giving it exposure to crude prices (on the plus side, natural gas and Antero shares have both rallied on recent oil weakness, as less competing associated gas is now expected from oil plays). Antero is caught between a rock and a hard place, as it has overcontracted its midstream takeaway capacity and is paying an extra $0.15 per thousand cubic feet in marketing costs as a result. That makes it difficult to cut capital spending, as this would postpone the swing to profitability that we expect when it grows into its committed volumes. In the meantime, it is burning cash and has about $1 billion debt coming due in 2021. Like Range, another natural gas producer with meaningful NGL exposure, it will probably use asset sales to bridge the funding gap but could end up selling the family silver at bargain prices in this commodity environment.

In addition, Antero and Range could come close to tripping the restrictive covenants associated with their revolving credit facilities. Both are required to maintain EBITDAX/interest expense ratios of at least 2.5 times, and refreshing our models to incorporate our updated views on near-term commodity prices brings these companies close to the covenant thresholds. There’s some wiggle room--for instance, Range’s credit agreement specifies EBITDAX to cash interest only, and there may be scope to capitalize a portion of its interest to improve this ratio. But in general, we’d steer clear of companies getting close to covenant limits whether they break them or not.

On the oil side, Laredo Petroleum LPI is most at risk. The company does have a very strong hedge position, with essentially all of its expected production locked in at $45/bbl or better this year. But only a third of next year’s volumes are similarly protected, driving up net debt/EBITDA and potentially busting the 4.5 times ceiling in Laredo’s credit agreement. The good news is that it has already refinanced its long-term debt commitments this year, leaving it with no maturities before 2025.

Top Picks in U.S. E&P The marginal cost for the wider group is around $55/bbl (WTI). If prices stay well below that threshold indefinitely, shale activity will remain at a skeleton level and U.S. production will rapidly decline, turning the current glut into a shortage within a couple of years. So, we remain confident that a recovery is inevitable. But the market seems to be extrapolating weak prices to infinity, making most energy stocks look cheap.

For safety, we like EOG and Pioneer. The caveat is that to benefit from higher prices a few years down the line, these companies have to remain a going concern in the meantime. So, we recommend prioritizing the balance sheet above all else in this environment. EOG and Pioneer both entered this crisis period with very low financial leverage, coupled with the ability to generate sustainable excess returns on invested capital. Though both have substantial debt maturities in the next couple of years, they also have large cash reserves and shouldn’t need to rely on bank borrowing.

The best-in-class operators are Diamondback Energy FANG and Continental Resources CLR. Diamondback started 2020 with modest financial leverage and has only $400 million in debt coming due before the end of 2021 (leaving it in a good spot, with more than half of its available bank credit unused). Continental does not typically hedge and is therefore more exposed to the downturn than most peers. At strip prices, it will exit 2021 with net debt/EBITDAX at an uncomfortable 4 times. But it has no debt maturing in the next two years, and we still expect very little outspending, keeping debt/capital below 50% (well below its covenant ceiling of 65%). So, neither company is under immediate pressure financially, even at Armageddon crude prices, and both have stellar records for keeping production costs at the bare minimum relative to peers.

It may be surprising that we’ve highlighted only a handful of companies with potential liquidity issues, given current oil prices. But our coverage is strongly tilted to the higher end of the quality spectrum. Among public E&Ps, the companies we follow tend to be larger, with more economies of scale, better access to credit, more technical know-how, and in some cases better acreage. As such, these companies have stronger balance sheets and rank higher on profitability metrics. While we wouldn’t rule out widespread restructuring and bankruptcies across the sector during this very difficult period, we think most of our coverage will emerge unscathed.

Oilfield-Services Stocks Look Cheap as Investors Have Written Off Capex Recovery Since mid-February, oilfield-services stocks have crashed, with the OSX down around 60%. This caps off a terrible two years for oilfield services, with the OSX down 80% since mid-2018 as a whole. The sell-off has left the industry incredibly cheap, as our average covered name trades at a 60% discount to our fair value estimate. Also, we think our covered names have the balance sheet strength to withstand atrocious oil markets in the next two years.

Before the coronavirus-related sell-off, oilfield-services stocks already looked undervalued to us, as we think the market was underrating long-run oil and gas capital expenditure growth. We’ve believed a good deal of the spending cuts on the international side since 2014 are unsustainable, as (unlike in the U.S. shale space) the cuts haven’t been accompanied by proportionate savings in unit development costs. Additionally, costs for many international producers have been trending up for decades. These arguments remain in place in the long run, even with weaker oil demand in the near term due to COVID-19. To be sure, we expect a rough next two years for oilfield services. We project a 24% cumulative capital expenditure decline through 2021 as producers respond to lower oil prices by throttling back their spending. North America will see the greatest cuts (down 44% in 2020) as fast-moving, price-sensitive U.S. shale producers have already cut rigs over 30% in the past month. However, we think these near-term spending cuts will have to be reversed, as we’re not expecting substantial long-term effects on oil supply/demand from COVID-19. Moreover, we forecast that capital spending by 2024 will be up 15% from 2019 levels, marking a more than full recovery from this year’s COVID-19 disruption.

For oilfield-services companies to benefit from our forecast capital expenditure recovery, they’ll have to survive the next two years. This won’t be easy, given that we expect spending to fall 18% below the prior 2016 trough, when many companies struggled. However, we think the companies we cover should be able to evade financial distress. Our coverage is drawn largely from the higher-quality end of the spectrum; we wouldn’t be surprised if several oilfield-services bankruptcies occur outside of our coverage. In any case, our coverage is well placed thanks to minimal debt maturities in the next two years, which will be easily covered by cash balances and revolver availability. We still project that several companies will generate substantial free cash flow, even in this extreme commodity environment, which will add to available cash. Weatherford International WFTLF is the only company for which we expect substantial negative free cash flow in the next two years, but this should be easily covered by its cash balances.

Given that near-term debt maturities are covered, the other main area of potential concern is debt covenants. Only Core Laboratories CLB has covenants on current borrowings (although a few others have covenants on undrawn revolvers). We’re slightly worried about Core Lab’s 2.5 times maximum leverage ratio on its revolver (on which it has about $150 million in outstanding borrowings). Given Core Lab’s very strong record of profitability (and we think it will remain free cash flow positive), we think there’s a good chance lenders would give it a break if the covenant is breached. If not, however, Core Lab would probably have to make a large dilutive equity issuance to fix the covenant breach.

Integrated Oils' Yields Still High, but Dividends Largely Safe When we looked at the safety of integrated oils' dividends in mid-March, the average yield for the group was 12%. Today, the average yield has fallen to 9%, yet capital spending cuts have materially improved break-even oil prices for the group, although they remain below current oil prices. Despite the drop in yields, they remain well above historical levels and in some cases are above 10%. Furthermore, the group continues to trade at a price/fair value of 0.55 compared with 0.45 in mid-March, demonstrating that ample value still exists.

As expected, most integrated oils announced reductions to capital spending plans for 2020. However, the magnitude of reductions, 20%-30% from original guidance, was greater than we expected. Typically, integrated oils have limited capacity in the near term to adjust spending plans, given the longer construction times and size of their projects. However, the sharp reductions in spending demonstrate the group has learned its lesson from the last downcycle (2014-16) and incorporated more flexibility into their plans, largely through greater investment in short-cycle projects like onshore unconventional and brownfield offshore development. As a result of these capital spending reductions, 2020 break-even levels have fallen.

Despite the improvement, break-even levels remain above expected 2020 average oil prices. That is why balance sheet capacity remains critical to ensuring dividend safety, as Equinor’s EQNR recent decision to reduce its dividend demonstrates. Equinor’s net debt/capital ratio of 28.5% places it the higher end of the range. Other companies, like BP BP and Shell RDS.A/RDS.B, have similarly high debt loads as Equinor, with year-end 2019 net debt/capital ratios of 31% and 27%, respectively. However, both have much larger downstream operations that, though they are also experiencing difficult market conditions, help cushion the blow of lower upstream revenue. Their management teams are also more likely to defend the current dividend with the introduction of a scrip option, given its importance to each company’s shareholder base. In contrast, Equinor is a more upstream-oriented company that does not have the same perception as a dividend play.

That said, we see a higher probability for Repsol REP, which has a history of reducing the dividend, to do so again, given its high debt load (year-end 2019 net debt/capital of 32%). Eni E also has a history of reducing its dividend, but its leverage levels are much more reasonable at 20% net debt/capital. For Chevron CVX, ExxonMobil XOM, and Total TOT, which have net debt/capital ratios below 21%, we see the dividend as safe as well.

Of the group, Chevron has the safest dividend thanks to its low leverage levels and strong free cash flow generation. Total stands out for its dividend safety among Europeans. Chevron’s superior dividend safety appears largely priced into the stock, which trades at the narrowest discount to our fair value estimate among the group.

For those investors looking for value, we recommend Shell, as its yield is not indicative of its dividend safety, in our opinion. It also trades at one of the widest discounts to our fair value estimate. For investors with longer holding periods, we’d suggest Exxon. Even before the recent fall in oil prices, it had been underperforming, as the market was skeptical of its increased investment in growth that stood in contrast to peers. However, while its countercyclical strategy will reduce free cash flow in the near term, it could ultimately prove prescient if current reductions in investment result in supply shortages and higher prices five years from now.

U.S. Midstream: Focus on Quality in Challenging Environment Broadly, we think the industry can muddle through this environment, ultimately by focusing on protecting the balance sheet and generating excess cash flow (operating cash flow minus distributions/dividends minus capital spending). The focus on liquidity is important because we now expect Permian oil supply to decline, following a wave of rig releases by exploration and production companies. For instance, we expect Diamondback, one of the basin's top producers, to deliver essentially flat production this year and a decline of 15% in 2021. While fee-based contracts are now the norm in midstream, instead of commodity-based, they are exposed to volume declines. We also expect a focus on the balance sheet, since most of our coverage has leverage above 4 times, exposing the space to both higher debt costs and liquidity challenges for the weakest players.

High-quality companies such as Enterprise Products Partners EPD, Magellan Midstream Partners MMP, Plains All American Pipeline PAA, Cheniere Energy LNG, and Cheniere Energy Partners CQP remain well positioned. Similarly, gas-focused names such as Energy Transfer ET and Kinder Morgan KMI should do well. Williams WMB will need to proactively address its maturity issues, given its lack of excess cash flow, but the resilience of its operations should provide a buffer. Companies with substantial oil storage operations, such as Plains, Enterprise Products Partners, and Magellan, should benefit amid extremely high demand for oil storage. On the negative side, we think some entities, including MPLX MPLX, DCP Midstream DCP, Energy Transfer, and Oneok OKE, are under substantial pressure by investors to reduce payouts to more aggressively address high leverage or other business priorities. We think the payouts are financially supportable, given our expectations around business results and the entities’ balance sheets, but this environment is offering management sharply higher returns elsewhere, particularly around repurchasing highly discounted debt.

Canadian Energy: Market Pricing Enbridge Like Oil Will Remain Weak Forever Canada's energy sector has been hit as hard as any by the historic crash in oil prices. Earlier this year, the industry was on the verge of rapid expansion as oil sands producers have found a way to generate significant free cash flow with oil prices near $50/bbl. But with the average oil sands supply cost (excluding transportation) near $20/bbl, producers are now rapidly burning cash. As such, we expect a meaningful reduction in the country's crude supply over the next two years, with supply falling from 5.6 mmb/d in 2019 to 4.4 mmb/d by 2021.

Our top pick among Canadian energy stocks is Enbridge ENB/ENB which operates oil and natural gas pipelines. The downturn in oil prices and the expectation of lower Canadian crude supply has renewed fears over Enbridge's ability to generate sustainable, long-term cash flows and maintain stable dividends because of the potential loss of throughput on the company's Mainline system. In our view, the market underappreciates Canada's long-term supply growth opportunities and Enbridge's cash flow generation potential.

We think that investors are mistakenly worried about underutilization of the Mainline pipeline system due to production cuts and the construction of competing pipeline expansions. Even if the Keystone XL and TransMountain Expansion are placed into service (our base case), we expect only minor underutilization of the Mainline until Canadian crude supply ramps up to our forecast levels once crude prices normalize to our $55/bbl WTI midcycle forecast. Accordingly, we expect all the major pipeline expansions to be operating near full capacity within the next decade, fueled by our above-consensus outlook for Canadian crude production.

Even with the Mainline operating at reduced levels, we expect enough cash flow to cover the company’s coveted dividend. Contrary to popular belief, the Mainline isn’t the only driver of profitability and cash flow generation. Almost 75% of Enbridge’s 2019 adjusted EBITDA was generated from its other assets that are underpinned by secured contracts. Because of this, the dividend looks safe over the next decade.