Integrated Oils: A Free Cash Flow Story

Integrated oil companies are set to reverse years of little or no free cash flow despite significantly lower oil and gas prices as high levels of investment give way to growth and capital restraint. We expect increased free cash flow from both upstream and downstream segments. In upstream segments, improved cost structures and the addition of higher-margin production will increase cash margins, offsetting much of the impact of lower oil prices. Meanwhile, service cost deflation, standardization, and simplification combine to reduce the capital intensity of key project areas such as deep-water, shelf, and onshore, creating the opportunity to do more with less. In downstream segments, continued strong market conditions combined with earnings growth lead to strong free cash flow generation. This results in financially stronger and healthier companies that can increase dividends and repurchase shares. Importantly, this improvement can occur at our midcycle oil price of $60 a barrel--well below current levels--and in many cases, the market is underpricing the improvement. We think

Upstream: Cost Improvements Lead to Greater Free Cash Flow The combination of improved cost structures and lower capital-intensive production growth has culminated in improved free cash flow generation for the upstream operations of integrated oils compared with recent years. Driving the improvement in free cash flow generation is a reset in upstream development capital and operating costs to sustainably lower levels that will allow integrated oils to deliver greater free cash flow at much lower oil prices.

While integrated companies reaped the benefits of higher earnings as oil prices remained high from 2010 to the second half of 2014, free cash flow generation deteriorated. After a decade of steadily increasing oil prices, outside a quick dip in 2008-09, companies revised their internal price decks upward in anticipation of continued $100-plus oil prices, setting off a wave of investment in capital-intensive projects like oil sands and liquefied natural gas. In addition to the increased capital requirements, these projects also took much longer to construct and bring on stream, meaning there was little concurrent production growth. However, we expect the next five years to be better, thanks to reduced capital intensity, improved cost structures, and stronger production growth.

Since 2014, integrated oils have made dramatic progress in reducing their operating cost structures, with per-barrel production costs down 30% on average across nearly all regions. Granted, they had plenty of room for improvement. Integrated oils have experienced outsize growth in operating costs, with most seeing per-unit costs increasing much faster than industry indexes (IHS Upstream Operating Cost Index) during 2010-14. Based in part on cost-cutting programs, integrateds have successfully reversed the bulk of those increases, driving operating costs per barrel back below 2010 levels in many cases.

We expect much of these operating cost improvements to hold over time. Changes in operating costs typically track oil prices and activity levels, and although we expect the latter to increase, we expect oil prices to decrease from current levels toward our midcycle assumption of $60/bbl.

Also, integrated companies arguably became fat between 2000 and 2014 as oil prices steadily rose, leaving ample opportunity for trimming. We’ve seen this in part as head counts have been slashed despite maintaining volumes, thus improving production per employee metrics and therefore productivity and efficiency. Also, technological improvements are making their way through the oil industry, including remotely controlled oil platforms, autonomous robots used for subsea inspection, streamlined procurement, and other digitization efforts that should improve productivity and efficiency and reduce costs over time.

New Volumes at Lower Capital Costs and Higher Margins The critical element in our forecasts for increased free cash flow during the next five years is our expectation for a sustained, material reduction in capital spending without sacrificing growth. This results from a reduction in investment in the capital-intensive, long-lead-time projects (such as oil sands mining and LNG) that have characterized the growth portfolios during the past five years, along with a move toward more traditional projects like offshore, which have seen a dramatic reduction in capital and operating costs.

Based on our analysis of growth projects, nearly 70% of new volumes will come from offshore projects. Only about 10% of new volumes will come from LNG, and this is largely composed of volumes from the ramp-up of projects completing construction, while the percentage from oil sands is even lower. These new developments are also concentrated in already developed areas such as the Gulf of Mexico, Brazil, and the North Sea, suggesting lower-cost and quicker development as existing infrastructure is leveraged.

Meanwhile, a substantial decline in capital costs of those projects has occurred through downsizing, standardization, simplification, redesign, high-grading effects, unit prices, and currency gains. Critically, deep water, a central element of integrated portfolios, has seen greenfield development costs fall 42%, from $11 per barrel of oil equivalent in 2012-14 to $7/boe in 2015-17, according to Rystad. Meanwhile, shelf and onshore development costs are down 31% and 26%, respectively. Given that the bulk of these estimated costs--70%-80% based on company estimates--is from factors other than services cost deflation, they are likely to be sustainable.

Increasing costs in these areas have improved as well. In addition to their efficiency improvements, operators have put pressure on suppliers of supply vessels, subsea inspection, maintenance and repair, and maintenance and modification services. For newly sanctioned deep-water projects, lifting costs have demonstrated the greatest improvement, falling 30%, while shelf and onshore costs fell 20%. Given the slack in offshore service supply, we’d expect some reinflation, but not back to 2014 levels.

Deep-water projects hold greater opportunity for cost improvement, thanks to their higher margins and the ability to downsize projects without a material reduction in reserves developed. Credit largely goes to companies’ cost-cutting programs for nearly half of the cost reductions, as they resulted in an emphasis on standardized solutions that could be reused, as opposed to requirements for flexibility, which lead to more predictable budgeting and reduced cost contingencies. Deflation in oil-driven currencies since 2014 relative to the U.S. dollar (the Brazilian real has deflated 35%, the Norwegian krone 31%, the British pound 22%, the Canadian dollar 17%, and the Australian dollar 15%) has also played a role where services are supplied locally. The result is that these previously high-cost development areas now fall toward the lower end of the cost curve for new volumes.

These improvements also hold consequences for the future. The sharp reduction in offshore costs is particularly important for integrated oils, as a large portion of their discoveries has come from these areas in the past 10 years. Combined with our projection for continued low costs in the unconventional space, the bulk of future developments should be able to capitalize on recent cost and capital reduction efforts.

The benefits of lower capital and operating costs are twofold. First, the lower operating costs on existing and new projects will help offset what are expected to be lower oil prices, resulting in less impact on margins relative to the decline in oil prices. Second, integrated oils can increase production at much lower absolute and (importantly for returns) per-unit levels of capital spending.

The culmination of growth and cost reductions is a much stronger cash margin profile than integrated companies held in the past. Our forecast calls for oil prices in 2022 of $60/bbl (midcycle) compared with $108 in 2013, yet we forecast realized cash margins to only be $8/bbl lower on average. This results in much stronger relative cash generation.

With regard to the second point, we forecast absolute levels of upstream capital spending to be 40% lower on average. However, on a per-barrel basis, levels should be 50% lower on average, demonstrating the production growth we expect integrated companies to deliver during the next five years.

While 2010-14 was largely characterized by flat or declining volumes, we expect the next five years to demonstrate growth as past investments finally bear fruit and new, lower capital investments are added. We expect production to grow at an average compound annual growth rate of 4%, led by

The culmination of these factors--reduced capital intensity, stronger cash margins, and production growth--is a material improvement in upstream free cash flow generation during the next five years compared with 2010-14, even as we expect oil prices to average $68/bbl compared with $103/bbl. Total,

Downstream: Improved Operations, Earnings Growth, and Strong Market Outlook Integrated oils' downstream segments are often overlooked, but in the past few years they've proved their value. While cash flow from upstream operations cratered, downstream cash flow, which is less leveraged to changing oil prices, remained stable or grew, providing support to the much-valued dividend. We expect the segment's strong free cash flow generation of the past several years to continue thanks to improved portfolios, earnings growth, and the strong possibility of favorable market conditions.

Downstream performance has improved in the past five years thanks to strong market conditions, particularly in the United States, and structurally improved organizations. With refining portfolios that were overly exposed to stagnating demand in Organisation for Economic Co-operation and Development countries, integrated oils have actively divested, shuttered, or repurposed underperforming refining assets, reducing capacity by 15% on average since 2010. Meanwhile, efforts have been made to reduce costs, in part by reducing head count, which has decreased by 25% on average since 2010. These cost reductions and portfolio improvements should result in improved performance relative to historical levels even if market conditions deteriorate.

Additionally, nearly all integrateds are investing in increasing downstream earnings. Strategies vary, but we expect downstream earnings to grow by 25% on average from 2017 to 2022. We’d note the high growth rate for

Broadly speaking, European companies are pursuing more retail and marketing growth, in contrast to Exxon and Chevron, which have moved away from owning their own retail sites to a branded model. While marketing and retail investment offers an avenue for growth and penetration in fast-growing markets in Latin America and Africa, there is typically little in the way of competitive advantage associated with these assets, as switching costs and brand power are low and there are few meaningful barriers to entry. That said, capital intensity can be relatively low and earnings tend to be much more stable than in refining, resulting in high returns on capital. Additionally, ownership of these assets as part of an integrated model that includes refining can result in cost advantages and provide opportunities to capture additional value along the supply chain. Furthermore, for the Europeans--Shell, BP, and Total--additional marketing assets allow them to further leverage their global trading operations.

Exxon and Chevron are more targeting refining and chemical investment that improves yields and increases feedstock flexibility, and processing of advantaged feedstocks typically results in a cost advantage. The investments are more capital-intensive but also more difficult to replicate. While BP appears to lack any chemical investments, this is not the case, as growth in chemical earnings will go toward offsetting loss of earnings through divestment, leaving them unchanged over the measurement period.

We expect market conditions to remain rather strong, or above midcycle conditions, for the next several years, which could result in continued strong downstream earnings and cash generation. While product inventories are supportive of margins and crude spreads are wide thanks to growing production, it is perhaps IMO 2020--the new limit on sulfur content--that could drive several more years of strong margins. Although uncertainty abounds regarding methods and levels of compliance, it is commonly thought that the ease of substitution and availability of marine gasoil, compared with installation of scrubbers or use of LNG, will create a swing in global demand amounting to nearly 3 million barrels per day from residual fuel oil to distillate. The impact on market prices is likely to be higher diesel prices (the International Energy Agency estimates a 20%-30% spike) and lower residual fuel prices. Differentials of heavy crude will also probably widen as refiners cut heavy runs to reduce residual fuel production in response.

This is good news for Europe-oriented refiners such as Total,

Despite higher gasoline yields, North America-oriented refiners (over 40% of total capacity) such as Chevron, Exxon, and Shell should see some benefit as well. Their greater complexity, as well as the availability of heavy crude (Canada, Mexico, Venezuela), positions them to benefit from the potential of wider heavy differentials. BP appears to be the exception to the rule: With greater European exposure (46% of total capacity) yet relatively high middle distillate yields, low residual fuel output, and higher complexity, the company is well positioned. The culmination of the improved portfolio, earnings growth, and strong market conditions should extend the strong free cash flow we’ve seen over the past several years.

Cost Improvements Prompt Us to Revisit Moat Ratings Given the progress that's been made on improving costs, we've taken another look at the economic moat argument for integrated oils. We find that Shell and BP have joined Exxon and Chevron as earning narrow moats, in our view.

Our moat argument for these companies rests on a higher degree of confidence in the ability of their integrated model to deliver excess returns at our midcycle oil price of $60/bbl. That includes an improving upstream cost position and a strong downstream position capable of supporting returns through the commodity price cycle. While we don’t forecast returns reaching the levels they did when oil prices were $100/bbl, we think the integrated model is able to deliver excess returns, albeit a lower level, that are sustainable through the cycle. In other words, duration of returns is key, not magnitude. Additionally, for Shell and BP we’ve detected a change in capital-allocation discipline and cost focus. This should help close the gap in returns with Exxon and Chevron, which have historically performed better in this regard.

Total, Repsol, Eni,

Upstream Segments as a Moat: Returns to Improve Over Time Although the lower spending and improved margins will lead to greater free cash flow generation even at lower oil prices during the next five years, the improvement in returns will take longer in the upstream segments. The addition of higher-return barrels into the portfolio during 2018-22 will be insufficient to overcome the amount of capital expended over the past 10 years, ultimately preventing a recovery in returns on capital employed from reaching levels seen when oil prices were $100/bbl.

While returns fell in 2015-17 as oil prices declined, returns on capital in the upstream segment (as measured by ROCE) were deteriorating well before then, owing to the aforementioned higher spending and high-cost reserve replacement. Despite much higher oil prices in 2010-14 on average compared with 2003-09, returns were much lower.

Although we expect margin improvement during the next five years, it will be insufficient to return earnings to prior levels, given our outlook for lower commodity prices. Also, while we expect cash margins to be strong relative to historical levels, return calculations use aftertax earnings, whose recovery will be challenged by higher depreciation levels. Furthermore, while capital spending will fall, we don’t project capital employed to fall in the next five years, leaving relatively lower earnings to cover a similarly high level of capital. As such, returns will struggle to breach 10%.

The increase in spending and resulting higher levels of capital employed will leave a legacy that will prove to be a high hurdle for each integrated to clear to achieve a 10% return on average capital employed, rather modest compared with the high levels of the past 15 years, when returns often exceeded 20%. In 2022, margins will be $4/bbl on average, too low to earn a return of 10% for the given level of capital employed. We estimate oil prices would need to be closer to $74/bbl for the group to achieve 10% returns.

The relatively low returns in 2022 compared with historical figures and the need for higher prices would suggest a lack of a moat at our midcycle price assumption of $60/bbl. However, we’d argue that the 2022 returns figures are not fully representative of full-cycle returns and fail to account for an improvement in returns that will probably continue. First, much of the rise in capital spending during 2010-14 was the result of investment in “long-plateau” projects such as LNG and oil sands, which are likely to generate lower full-cycle returns (around 10%) than historical projects (around 25%). However, it also means that capital requirements were front-loaded while the earnings stream is much longer-duration, which negatively affects returns in two ways. First, it resulted in much higher levels of unproductive capital during construction, which weighed on returns in past years. Second, once production begins, it takes decades to fully realize the full value of the reserve base; meanwhile, the capital required is fully counted in the capital base, which weighs on returns. However, as we move further out in time, earnings will remain constant as the projects continue to produce at plateau levels, but the capital base against which returns are calculated will fall as it is depreciated and reinvestment needs are limited.

Second, the higher levels of capital associated with these barrels mean that newer high-margin and high-return barrels will have less initial influence in the calculation of total portfolio returns, as their relative contribution is much smaller. (All else equal, a barrel with a 10% return that costs $25 will affect returns more than a barrel that costs $10 but has a 25% return.) However, this should also improve over time as older barrels are depreciated and the portfolio is refreshed with newer projects that have higher margins and lower capital requirements. As these new barrels are added at lower capital costs, it should eventually lower the per-boe capital base, which then will require lower margins to earn a 10% return. Given this return profile, we’d argue most integrateds (with the exception of Repsol) have probably earned an upstream moat.

Furthermore, when we look at break-even oil prices of upstream portfolios, we can see that while the price for developments is wide-ranging, on the whole, portfolios are break-even at less than $50/bbl. Given our midcycle price of $60/bbl, this would suggest all companies’ upstream portfolios should deliver excess returns going forward when measured over a long enough period.

Downstream Assets as a Moat: Buttressing Companywide Returns In addition to the improvement in upstream returns, we find that in many cases, downstream segments are moat-enhancing, given the quality of assets and countercyclicality of earnings that underpin companywide returns. Global integrated oils might hold a host of nonupstream activities in their downstream segments. However, we typically distill those activities into three key areas: (1) refining, (2) retail, marketing, and distribution, and (3) chemicals manufacturing.

Moats in refining and chemical production rely on cost advantage, primarily feedstock cost advantage. Although retail, marketing, and distribution usually does not possess a sustainable competitive advantage, in our view, as barriers to entry are low and switching costs elusive, we have typically found it can add to a cost advantage as part of an integrated network. Having your own marketing network can ensure distribution channels for refining production, thus supporting utilization levels. Those companies can also leverage their trading organizations to create additional opportunities to capitalize on the value chain.

For refining, a feedstock cost advantage comes from processing oil that trades at a discount to established benchmarks either because it is lower quality or because it is stranded and requires additional transportation cost. A refinery can only capture a quality differential through investment in upgrading capacity that allows it to process lower-quality crude into a similar amount of refined product as a light crude barrel. We can measure a refiner’s ability to do this using a refinery’s Nelson complexity index. In general, the higher the NCI, the greater that refinery’s ability to make higher-value products from a given feedstock. However, the earnings uplift from a processing a high-quality discount crude is offset in part by the concurrent increase in capital employed, thus limiting the upside in returns.

Transportation discounts are more favorable, as they don’t require incremental intensive capital investment. The most notable example are light crude discounts found in midcontinent North America. Excess supply relative to demand and the need to transport volumes to the coast for export result in price discounts to international benchmarks (for example, the West Texas Intermediate/Brent spread). North American refineries have the added bonus of lower operating costs thanks to low-cost natural gas that reduces energy cost, a large component of cash operating cost.

As such, all else equal we find complex portfolios with higher amounts of North American assets to be more competitively advantaged, with North American assets in U.S. midcontinent and Gulf Coast (PADD 2, 3, 4) and in Canada having greater access to discount crude. Moreover, these advantages compound. A more favorable margin environment, thanks in part to the availability of crude discounts and the lower operating costs, entices refiners to run at higher utilization levels, which in turn results in lower per-unit costs, improving profitability.

Chevron (54% of total capacity), Exxon (44%), Shell (40%), and BP (40%) stand out for exposure to North America. Despite its high exposure to North America, over half of Chevron’s capacity is located in California, which does not enjoy quite the same benefits that midcontinent and Gulf Coast refiners do. Although the California market can produce higher product margins, higher operating costs and environmental regulations can weigh on returns.

Outside of the potential near-term benefits, we find European refining to be the most at threat long term, given the lack of cost advantage, potentially weakening regional demand, and susceptibility to imports from low-cost suppliers. While many integrateds have significant amounts of their capacity located in Europe, we can see a difference in their asset quality that suggests a superior competitive position. While European refining was challenged much of the past decade, we can see that more complex, larger facilities were able to run at higher levels of utilization. Their ability to run at higher rates despite lower margins implies a lower cost position. BP, Shell, and Exxon stand out.

Meanwhile, Total, Eni, and Repsol lag, even though all three have made improvements and high-graded their portfolios in recent years, leaving them better positioned than they once were. European refining is typically less complex, as fluid catalytic cracking is less common in the region (and Asia as well) because demand for diesel is higher, which can be met with hydrocracking. In contrast, fluid catalytic cracking is found more frequently in the U.S., given its greater production of gasoline.

As with refining, we can infer feedstock advantage for petrochemical production by looking at geography. As most integrateds are primarily commodity petrochemical producers, cost advantage by way of low-cost feedstock is really the only competitive advantage available. Based on industry cost curves developed by IHS, ethane-based production in the Middle East and North America sits at the low end of the cost curve, ahead of LPG feedstock in North America, Europe, and the Middle East and the use of naphtha globally. Thus, using relative amount of chemical production in North America and the Middle East as an indicator of cost advantage, Chevron (through its joint venture with Phillips 66) stands out, with nearly all its capacity in these two regions, followed by Exxon, Total, and Shell.

Ultimately, the ability to consistently deliver excess returns on capital determines the existence of a moat. Looking at returns on capital employed in five-year periods helps to account for volatility inherent in refining. Only Exxon and Chevron consistently deliver returns above 10%, which is reflective of high-quality, well-run asset bases. Shell hovers close to 10%, demonstrating the value of its integrated chemical operations, but its exposure to Europe, as with BP, has weighed on returns. Total is an interesting exception, given its strong returns and exposure to Europe. However, given its historically large refining asset base and high distillate yields, it did well when refining margins were strong, as they were in the mid-2000s and the past few years. Its trend toward capital-light, high-margin retail in recent years, along with a rationalized refining portfolio, has helped as well. In total, we think the downstream segments of Exxon, Chevron, Shell, and Total earn moats.

Outside of consistent delivery of strong returns, these portfolios stand out for high exposure to North America, competitive European refining positions, and strong chemical portfolios. Total rates as an exception with respect to refining but compensates with a strong marketing and services segment. Repsol and Eni have been unable to consistently deliver returns over time, while Equinor’s positions largely just consist of two small European refineries. Petrobras’ downstream segment has historically delivered losses when oil prices rose rapidly due to government-controlled product pricing. Though market-based reforms have taken place, we find it too early to assign a moat to the segment.

Free Cash Flow Growth Underpins Shareholder Returns The expected increase in free cash flow should lead to greater cash returns to shareholders through dividend increases and share repurchases. During the past 10 years, most of the group has delivered some dividend growth, but it's been uneven. Only Exxon and Chevron have delivered uninterrupted growth, although it has slowed considerably in recent years. Shell's and Total's dividends are higher than they were 10 years ago, but growth has largely been absent in the past few years. The rest of the group's record is less distinguished, with Equinor, Repsol, and Eni reducing their dividends as oil prices fell in 2008 and 2014. BP suspended its dividend with the Macondo incident in 2010, then reinstated it at half its previous level; although it has grown since, it remains below prior levels.

We expect this to change in the coming years and have already seen signs, or in some cases guidance, during the last round of dividend announcements. Exxon (6.7% growth), Chevron (3.7%), Total (3.2%), BP (2.5%), and Equinor (4.5%) have all increased their quarterly dividend recently. Total continues to offer a scrip option for investors but is fully offsetting dilution with repurchases and has committed to a 10% increase in its dividend from 2017 levels by 2020, implying further increases. Repsol increased its full-year 2018 payout by 14.5% and has guided to growth through 2020 that implies an 8% CAGR from 2017. Eni has guided to a 3.8% increase in its dividend in 2018.

Otherwise, long-term guidance, outside a desire to increase dividends, remains sparse or vague. Every financial framework shares common elements including investing in the business, maintaining the balance sheet, increasing the dividend, and repurchasing shares, although not necessarily with the same order of priority. However, by looking at current leverage levels and future free cash flow (in 2022 at our midcycle oil price of $60/bbl) relative to current dividend commitments (assuming full cash dividends in 2018), we can infer a capacity for future growth. Combined with historical precedent--which companies have a record of continual dividend growth--the likelihood of future growth emerges.

Looking across the group, we see strong potential for dividend growth during the next five years. Given that most companies prioritize their balance sheets and/or financial flexibility, we measure 2017 year-end debt/capital ratios. Here, we find most balance sheets in reasonable shape, with all companies below 30% and averaging 22%. We also look at each company’s 2018 dividend payment (total cash expended) versus our anticipated 2022 free cash flow to incorporate a midcycle oil price (that is, looking through the cycle to set a sustainable payout) and potential earnings growth, which indicates room for growth of the dividend from current levels. This is probably the more important metric, given that debt ratios are broadly in line with most long-term targets of 20%-30%. The average 2022 coverage ratio is 2.0, with several companies above that level, most notably Chevron, Shell, and Equinor.

Alternatively, we can look at how implied growth and coverage rates would affect one another. First, we analyze which companies might not be able to increase the dividend at a 5% CAGR through 2022 by looking at implied 2022 free cash flow coverage ratios. Comparing the two values provides a rather clear ordering of which companies can increase the dividend.

With this, we can see that Chevron, Equinor, Shell, and Total can quite easily deliver relatively strong dividend growth at about 4% annually, as they are able to maintain free cash flow coverage of approximately 1.8 times or greater in 2022. One note on Exxon: Its 2022 free cash flow represents a relatively low figure compared with its long-term capability, as during this period it will actually be increasing investment to drive long-term earnings growth. As such, we still think the company can increase its dividend, as its cash generation is strong and management has made sustainable dividend growth a priority.

Outside of dividend growth, investor expectations are high around the potential for share repurchases. In addition to capital expenditure cuts, oil prices (and futures curves) are now sitting well above our midcycle assumption of $60/bbl, the level that most companies have used as a planning assumption. As a result, the likelihood of share repurchases has increased. Some companies, such as Shell ($25 billion 2018-20) and Total ($5 billion 2018-20), have provided specific guidance, while others have just included repurchases as a function of distributing excess cash.

Valuations Look Attractive Integrated oils are well positioned for the next five years, in our view, given the progress made on improving upstream performance and what is likely to be a favorable downstream market environment. We've increased our fair value estimates in many cases to reflect this, leaving the group trading at an average discount of 15%. However, we see differences in valuation among companies that don't necessarily reflect differentiation in earnings and free cash flow growth and potential for shareholder returns growth.

Discounted cash flow remains our primary tool to distinguish these differences; we incorporate the earnings growth of each company over the next five years and use a $60/bbl oil price for our long-term estimate. Based on those results, Shell, Total, and Chevron stand out as the most attractively valued and hold the strongest competitive advantages and greatest capacity for shareholder returns. Petrobras clearly screens as the cheapest based on our fair value estimate, yet it holds much greater risk than the rest of the group, given its higher debt load and potential for government intervention that could result in losses or value-destructive capital-allocation decisions. Exxon is the remaining 4-star name, but its long-date earnings growth leaves it without near-term catalysts.

In many cases, the market is not recognizing the projected improvement in returns during the next five years. The market has rightly recognized the deterioration in returns and cash flow over the past decade. As returns on equity average deteriorated with increased upstream investment, price/book ratios have compressed.

We don’t see ROEs returning to the 20%-30% range from the period when rising oil prices outpaced capital cost inflation and generated strong earnings off integrated oils’ low-cost legacy portfolios. We do think returns will improve from the depressed levels posted the past few years, which should result in higher valuations. However, implied price/book ratios do not reflect the improvement in ROEs we expect to occur. In fact, we find many companies are trading at a P/B lower than historical relationships with ROE imply.

The P/B valuations largely align with our price/fair value valuations, with Shell and Total trading at a discount to their implied P/B ratio (based on our estimate of midcycle ROEs), while Equinor trades at a premium. Exxon also trades at a large discount to the valuation implied by its historical ROE and P/B relationship. It has historically achieved a premium multiple, given the premium returns it generated. However, that premium has diminished as its returns have fallen with the group. We expect this premium, which averaged nearly 9% from 2005 to 2017, to compress to 1% for 2018-22, suggesting Exxon’s multiple should compress as well.

We also see free cash flow yields as attractive and not indicative of long-term trading averages. While free cash flow has proved elusive the past 10 years, integrated oils regularly generated strong cash flow between 2000 and 2007. As we see a return to this period, we can measure current free cash flow yields and those implied by 2022 free cash flow to compare with yields during 2000-07

Relative to where they traded in the past when generating stable free cash flow, BP, Chevron, Shell, and Total currently trade at much higher yields on 2018 and 2022 estimated free cash flow, implying that they are undervalued. Exxon looks less attractive on this metric because will see a relatively smaller increase in free cash flow during the next five years, given its increase in capital spending.