May 16, 2018, United Arab Emirates:  Since mid-2014, the harsh cyclical downturn in oil prices has tested, and proved, the resilience of international oil majors' integrated business models. S&P Global Ratings recognizes the majors' downstream refining and petrochemical assets provided them with a cushion as cash flows from the upstream businesses, especially straight exploration and production businesses, plunged.

 Those downstream businesses have since taken a backseat as higher oil prices, lower costs, and capital expenditure (capex) help upstream performance recover. Nonetheless, one of the concerns arising from the industry downturn has been whether the largest oil companies have been underinvesting, as a result of the huge capex cuts since 2014.

In our view, this is not the case for the majors.

Despite cutting investments by nearly 50% and postponing final investment decisions on major developments, activity levels did not drop as muchas dollar capex.

Indeed, production--both actual and projected--is growing for the majors in aggregate.

Key Takeaways

• Despite cutting capital expenditure since 2014, concerns that the big oil companies would suffer from underinvesting have proved unfounded, in our view.
•  At some companies, proved reports took a hit as the fall in prices affected the economicsof some projects. Nevertheless, projected and actual production at the major oil companies has risen.
•  Credit metrics for the companies are recovering to rating commensurate levels, but aggregate debt remains well above 2013 levels.

In the charts below, we present performance data for the oil and gas supermajors for 2013-2017. 

Our ratings analysis included a review of the mix and evolution of the supermajors' production and the reserves that support this production.

We also examine the resilience, longevity, competitiveness, and risks of these assets.

Some of the supermajors' significant upstream and downstream group assets are held in affiliates.

An oil company's production and reserve metrics typically include its share in affiliates, while its cash flow statements and credit metrics show only the dividends received from affiliates or investments made into them.

Our rating analysis of an oil major considers its upstream businesses and how the financial creditmetrics for the whole group measure up against our rating thresholds as well as other factors.

From 2014 to 2016, as oil and gas companies struggled with weak oil prices, we took severalnegative rating actions. Our actions were in response to our expectation that those companies would see persistently weaker performance as well high debt and leverage, and negative cash flows after shareholder distributions.

The recovery in credit metrics is well underway, but S&P Global Ratings-adjusted debt in 2017 remained up 135% on 2013, on a combined basis.

Production Through The Downturn

Oil production profiles showed only modest changes in 2013-2017.

The liquid and gas production mix remained relatively stable across the five supermajors, although Shell, which had acquired BG Group in 2015, saw a step up in its production profile in 2016.

Aggregate production is likely to continue growing, although the profiles differ by company.

We generally consider liquids production more profitable than gas. Across all majors, about 55% of the production profile consisted of liquids, on average. Chevron is still the most liquids-focused player, at about 65% of its production profile.

By contrast, only about 45% of Shell's production is
liquids.

Under the Securities and Exchange Commission's rules, net proved reserves incorporate only those reserves that can be produced economically, as specified. Accordingly, Exxon Mobil took a particular hit in 2016, as lower prices affected the economics of its project in Canada.

The company subsequently removed 3.5 billion barrels of bitumen from its proved reserves.

Shell's proved reserves also declined in 2015, but its acquisition of BG helped it increase its proved reserves to above 13 billion barrels of oil equivalent (boe) in 2016.

Nearly 50% of BP's proved reserves come from affiliates, highlighting its reliance on affiliates.

Rosneft continues to increase its contribution, while BP's reserves have recently been depleted.

Several projects have been excluded from net proved reserves under the SEC rules.

A key measure for oil companies is their reserve life index (RLI), which indicates the number of years it would take to use up their reserves, assuming a constant production rate and no portfolio changes.

There is a continuing need to replenish depleting reserves, even if this is typically a lumpy, rather than a smooth process.

Since 2013, the average RLI on a one-year production basis has reduced by one year to 13 years--we still consider this sufficient on a proved reserve basis.

Shell is an outlier--in 2017, its RLI declined below 10 years. We consider 10 years as an indicative threshold for highly rated entities.

We'll therefore continue to review how rapidly this metric can recover.

Although the average reserve life index has reduced, we still consider the current 13 years sufficient, on a proved reserve basis.

Cost Cutting Softened The Blow

As oil prices plummeted, all the major companies saw combined oil and gas revenue per boe fall by more than half. Material and continuing cost cutting initiatives helped to soften the impact of this plunge in revenue.

Gas sales acted as a hedge, but their mitigating effect was reduced because some gas and LNG contracts were linked to oil prices.

That said, we also saw the difference between the highest and lowest revenue per boe among the majors narrow; in 2017 it was just $5, compared with $20 in 2013.

Total remains the most operating-cost-efficient major. In part, this indicates that it operates in emerging markets, similar to Eni SpA. But other oil majors have also cut costs markedly--Royal Dutch Shell slashed its unit costs by more than 50%.

Even at affiliates, costs have significantly reduced. Some of the reduction stems from cuts, operating efficiencies, and logistics improvements.

But costs also fell because foreign currency movements have favored subsidiaries that do not operate in U.S. dollars. 

Stronger prices, combined with cost-cutting measures, caused operating cash flow trends to turn positive in 2017 at both consolidated subsidiaries and equity accounted affiliates.

Nevertheless, on average, oil majors' affiliates' cash flow per boe in 2017 was on a par with 2015 levels.

At $54 per barrel (/bbl), average oil prices in 2017 were roughly the same as in 2015 ($52/bbl).

Although costs per barrel had dipped in 2016, affiliates saw them rise again in 2017.

Chevron's results from equity-accounted companies saw a boost in 2017, primarily because of a more-favorable tax position at its Kazakhstan-based Tengizchevroil (TCO) affiliate compared with 2016.

It also benefitted from increasing production at its TCO and LNG projects.

Historically, TCO has also enjoyed relatively low-cost positions, which have supported strong cash flow generation.

BP saw a similar boost to unit cash flows when its production tax position became more favorable in 2014, compared with 2013.

Group financial metrics are recovering toward rating thresholds

To support free operating cash flow generation, the majors have cut aggregate capex by almost half since 2013.

We project a modest reversal of that trend in the next few years, but the significant efficiency improvements in the industry suggests that capex is unlikely to approach the high levels of 2013. Activity levels have not fallen nearly as far as dollar-denominated investment levels, which have declined in aggregate by nearly 50% since 2013.

Leverage rose, but by less than expected

Leverage increased significantly through the downturn, exacerbated by a fall in dividends from equity-accounted joint ventures and affiliates. An upsurge in the level of fixed-asset disposals compared with 2013 provided companies with additional cash to help them meet their financial obligations and prevent an aggressive rise in leverage to fund capex and dividends. Funds from operations (FFO) to debt was roughly 35% on average at the end of 2017, compared with almost 85% in 2013.

That said, the variance is quite high. Exxon Mobil's FFO to debt stood at 45% at the end of 2017, much stronger than BP's 24% (which included the impact of additional Gulf of Mexico payments). 

Chevron saw the biggest drop in FFO to debt, in part because it had a strong starting point, but also because it used debt funding for capex and dividend payouts.

We reflect these differences, as well as our future expectations for these companies, in our assessment of their financial risk profiles.