New World Trumps Old World in Integrated Oil
U.S. firms hold greater dividend safety, better assets, and more attractive valuations than their European counterparts.
As a "lower for longer" oil price scenario has become consensus, investors have begun to worry about the sustainability of integrated oil companies' dividends, pushing yields near 20-year highs. We think in most instances the concern is overblown, as increasing capital flexibility will allow firms to trim investment budgets to ensure dividend safety. The companies with the most at-risk dividends ( Total (TOT), Shell (RDS.A), and BP (BP)) have taken the additional step of offering scrip payouts to further preserve cash. While this will improve their cash coverage ratios, asset sales will still be necessary for these firms to fund future shortfalls, leaving any potential for dividend growth unlikely. Of the integrateds, Total's and Shell's dividends look to be the most at risk, but payouts would only be cut if oil prices do not recover to $70 a barrel longer term. As a result of this and other factors we will discuss, we prefer the higher-quality U.S. firms.
Whether dividends can be sustained is an understandable concern. Yields that in some cases sit at 20-year highs imply the market's growing doubt about sustainability and signal a warning or an opportunity, depending on the point of view. Compounding the issue are balance sheets that for the most part were in worse shape entering the current downcycle than the last one in 2008.
Dividend protection will largely come in the form of improved free cash flow, itself the result of capital spending reductions. Unlike many smaller exploration and production firms, whose focus on onshore drilling affords them greater flexibility and the ability to quickly adjust capital spending, large integrated firms typically invest in longer-cycle projects whose spending is largely set once construction begins. As a result, in the event of a decline in commodity prices, meaningful reductions in capital spending are generally unachievable until those projects are complete. With time comes flexibility, however, and we expect companies to take full advantage of it.
We expect a step down in integrateds' capital spending over the next two years, and in some cases, further reductions in 2018 (even assuming an oil price recovery). We estimate that on average, 2018 spending will be about 85% of 2015 levels. The reduced spending will in turn improve coverage ratios and lower break-even levels, but not all firms will see coverage ratios reach 1.0 times or break-even levels fall below futures prices. We forecast BP, Total, and Shell will neither see break-even levels fall below current futures prices nor generate sufficient free cash flow after capital spending to adequately cover cash dividend payments.
Break-even levels should fall primarily as a result of reductions in capital spending, implying debt relief beyond 2018. These break-even levels are much lower than the ones we calculated in late 2014 in the wake of the oil price collapse. Then, all but three companies needed oil prices to be at least $100/bbl in 2016 ($98/bbl on average) to reach break-even. A year later, that level has fallen dramatically ($78/bbl on average) as companies moved quickly to capture cost savings and cut capital spending.
We expect companies to remain aggressive on reducing capital spending through a combination of industry cost deflation and project deferment, indefinite in some cases or until cost savings improve returns in others. Ultimately, we think management commitment to dividends and capital spending flexibility, in a worst-case scenario setting investment levels equal to operating cash flow less dividends, keep dividends safe. Investing at maintenance levels risks future growth, though. Therefore, those firms with break-even prices well below future prices not only have room to withstand lower prices and maintain investment levels, but also hold the ability to increase spending to capture opportunities. On this front, ExxonMobil (XOM) and Chevron (CVX) stand out.
Given that break-even levels are likely to remain above oil prices through 2017 for most firms, we don't expect much improvement in financial health unless oil prices exceed our current forecast for depressed prices through 2017. Though we expect supply and demand to balance during the second half of 2016, inventory levels (and potentially rapid increases in U.S. production) are likely to keep a lid on prices for some time thereafter. In this case, a sustainable recovery in prices seems unlikely to occur before 2018. Even with our long-term oil price assumption of $70/bbl, Brent is well below recent highs. As a result, we expect debt levels will probably get worse before they get better. In a few cases, we see several firms breaching 25%, a level that management teams and rating agency guidelines suggest is significant.
With dividends largely secure, the question becomes what kind of dividend growth investors can expect going forward. We think most firms will find it challenging to increase dividends, given the outlook for a depressed commodity price environment. Before the downturn in oil prices late last year, dividend growth was already slowing for most firms as free cash flow coverage ratios deteriorated under greater capital spending. Payout ratios meanwhile remained largely constant (around 40%) outside volatile years such as 2009 and 2014, as high and rising oil prices buoyed earnings. The next five years, however, are unlikely to see similar dynamics.
While capital spending reductions will result in improved coverage ratios and cost-cutting and higher oil prices will reduce payout ratios, we think dividend growth is likely to be anemic, if not nonexistent, across the sector. We expect recent trends to continue, with the high-yield group (European integrateds) largely maintaining but not increasing payouts, while the dividend growth group (Exxon and Chevron) continues to do so, albeit at lower levels. It's worth noting that for BP, Shell, and Total, coverage ratios reflect only the cash portion of the dividend, not the scrip value, resulting in higher coverage ratios than would be realized if the dividend were entirely in cash.
Historically, Exxon's and Chevron's lower yields were supplemented with share repurchases, bringing total yields to levels on par with European firms. Although we expect continued dividend growth, we don't see the robust share repurchases of the past continuing. Chevron will find it difficult to reinstitute its repurchase plan, while we expect Exxon will continue at its currently diminished level of $500 million per quarter.
With firms slashing capital budgets to safeguard dividends, investors are probably questioning the potential for future growth. A review of the group's capital expenditure plans does show that the upstream segment is shouldering the bulk of the decline.
However, we view the reduction of upstream capital investment as a resetting to more historical levels after the investment frenzy of the past few years. If we adjust upstream capital spending on a per-barrel basis for each company, upstream investment is simply returning to more reasonable levels.
The investment phase of the past several years has secured the near-term growth outlook for most of the group, although growth after 2018 remains a question. The growth outlook to 2018 is as positive as it has been for some time, with average production growth (2015-18 compound annual growth rate) of 4% across the group.
The elevated level of spending was due in part to investment in long-life projects like liquefied natural gas and oil sands that are capital-intensive, given the need to invest in associated processing infrastructure in addition to the typical oil and gas extraction investment. As a result, exposure to this type of asset is increasing across the group.
While this dilutes returns, we think firms with greater exposure to long-life assets will find themselves in an advantageous position in the coming years. Long-life assets hold two important characteristics for firms managing through a low oil price environment. First, decline rates are negligible, if not nonexistent. LNG, oil sands, or large gas processing projects hold large resource bases that require additional infrastructure but produce at capacity levels for decades. Second, although initially capital-intensive, these projects require relatively little reinvestment to ensure stable production, turning them into free cash flow machines once on line. As a result, greater exposure results in lower companywide decline rates, less need to add new volumes to generate growth, and greater free cash flow available to reinvest elsewhere or cover shareholder returns. Lower commodity prices (and in some cases budget overruns) will lead to lower returns and less cash flow than thought at the time of these project sanctions. However, the benefits of these projects will prove valuable in a lower-for-longer scenario. Additionally, firms may find it challenging to increase their exposure as future projects will be economically challenged and less likely to go forward, given the higher costs of oil sands and oversupply of LNG.
Both Exxon and Chevron stand out as winners in the case of long-life exposure--Chevron for its relative increase and Exxon for its high absolute level. It's worth noting that Shell's 2018 figure excludes BG, which would otherwise be higher if included.
In the lower-for-longer scenario, a company's short-cycle investment opportunities also offer an advantage. While each firm has a large stable of long-cycle projects for potential development--of varying quality--the distribution of short-cycle opportunities (essentially unconventional shale gas and tight oil projects) is much less even.
The importance of these types of projects is threefold. First, efficiency gains and cost deflation have lowered the cost of many of these tight oil plays dramatically so break-even prices (10% internal rate of return) are below $60/bbl, making them some of the more attractive assets in the world. As a result, they offer an opportunity for production growth when oil prices are low. Second, and perhaps more important, the time between investment and first oil/cash flow is incredibly short. An unconventional well can begin producing 8-12 weeks after drilling begins compared with a typical offshore project that can take 3-5 years or longer in the case of LNG and oil sands mining projects. Third, unconventional investment can be dialed back and ramped up quickly. In a world where the United States is a swing producer, oil price volatility is likely to increase, meaning long-cycle projects hold greater investment risk as dividends can come under threat if capital budgets are geared toward long-cycle projects and maintain their historical inflexibility. Introducing unconventional investment adds flexibility to an otherwise inflexible capital budget.
Quantity is by no means quality, but we have a good idea which unconventional basins have the most attractive economics--Permian, Eagle Ford, Bakken, Oklahoma, and Marcellus (gas). Measuring the group's exposure to these basins gives us a good approximation of which firms have the greatest opportunity. The most acreage is held in the Permian, which is unsurprising given the basin's long history and production from non-unconventional sources. Those companies with large positions largely as a result of legacy ownership--Exxon, Chevron, ConocoPhillips (COP)--now find themselves in an enviable position as the Permian is proving to have the best returns and potential of all the unconventional plays. Legacy acreage typically holds advantaged royalty terms as well. We'd rate Chevron as the best positioned in the Permian, given that its acreage is concentrated in the Midland and Delaware basins where economics have proved superior so far.
In contrast, the Europe-based firms hold little legacy acreage, and recent efforts to increase exposure through acquisitions and joint ventures have largely been disappointing. As a result, these companies will continue to depend on long-cycle projects for growth and investment, putting them at a disadvantage.
While the uplift in free cash flow in the coming years is primarily a result of reduced capital spending, firms are also attacking their cost structure to generate savings (operating and capital) and selling assets to generate proceeds and high-grade their portfolios. A cursory review of the various initiatives shows European firms generally being the most aggressive, at least with respect to public pronouncements.
While their efforts are certainly welcome, they're arguably well overdue. Measuring the efficiency of the large integrated firms is tricky, and ultimately, we think return on capital is the best metric. However, we can look at a couple of measurements and how they've changed during the past five years to infer how each firm is managed and how efficient it is technically.
Coverage Ratios Have Deteriorated…
…While Payout Ratios Have Remained Relatively Stable
Source: Morningstar Equity Research
Chevron and Exxon have increased not only revenue per employee, but also--importantly--net income per employee. Production per employee for Exxon improved as well, which is particularly impressive given the large downstream operation that would otherwise weigh on this metric. While other firms such as BP and Shell were able to increase revenue per employee, they couldn't translate that into greater earnings per employee. Statoil (STO) also screens well here, but its downstream footprint is relatively small, boosting its production per employee. Total and Eni (E) remain the poorest performers on every metric, suggesting their large cost-improvement targets are sorely needed.
Which companies do you select--those with greater potential or those that may have less upside potential but a good record of execution? We'd tilt toward those with a record of improvement. Ultimately, a good portion of cost reduction will be realized through industry cost deflation, which the better-performing firms will realize as well. Additionally, given the longer cycles of large integrated firms, the risk remains that after near-term cost-cutting efforts are achieved, structural and cultural issues may persist that result in slippage. Finally, announced cost-cutting programs are unlikely to close the gap for the poorer performers.
Returns on Capital and Valuation
We expect the same trends that should improve dividend coverage--higher oil prices, increased production, and reduced spending--should lift returns on invested capital. However, we also expect returns will remain well below levels of years past as a result of lower oil prices and the amount of capital invested at the top of the cycle. These headwinds have left most of the group--with the exception of Exxon and Chevron--without economic moats, given their inability to earn excess returns at midcycle levels.
We expect Exxon to maintain its peer-leading ROICs and think it deserves a premium valuation as a result. Although Exxon is still undervalued, there less upside to our fair value estimate than for Chevron, which is our preferred integrated firm. Chevron has a solid balance sheet, improving coverage ratios, falling break-even levels, and potential for dividend growth. Additionally, it stands out for its upstream portfolio that includes a large cost-advantaged Permian acreage position.
BP also appears undervalued, and while investors are right to have some concern about its ability to pay the dividend at lower oil prices, it is actually in better financial shape than Shell or Total, given that the Macondo incident has forced it to be very conservative in terms of capital-expenditure commitments during the past few years. Furthermore, the very attractive settlement terms that BP agreed with the U.S. government spread the pain of payments over 20 years. As a result, the company is in better shape to weather the oil market downturn than investors are giving it credit for.
Allen Good does not own (actual or beneficial) shares in any of the securities mentioned above. Find out about Morningstar’s editorial policies.