The cost of capital discipline: Big Oil's longevity challenge

Sustaining hydrocarbon production through the 2030s has become a strategic priority for the world’s largest oil and gas companies. A slowing energy transition and challenges in building out low-carbon businesses have prompted a recalibration back towards oil and gas to maintain cash flows (and dividends) through the next decade.

After five years of reduced upstream activity, however, many companies have been left with production – and cash-flow – outlooks that are more aligned with net-zero pathways, than the higher-for-longer demand scenario that appears to be playing out. Wood Mackenzie expects production from current commercial projects, for a peer group of 30 of the world’s largest exploration and production (E&P) companies, to fall by nearly 40% between 2025 and 2040, on average. The decline is most acute for companies without US tight oil exposure.

We forecast global oil and gas demand to grow by 6% to 2040, providing a solid macro backdrop that can sustain or even grow the upstream cash engine. However, pressure to return cash to shareholders and near-term price uncertainty are putting a ceiling on the investment needed to address the upstream longevity challenge.

The key question is: can oil and gas companies satisfy shareholder desire for payouts while ensuring cash-flow sustainability through the next decade?

Source: Wood Mackenzie Corporate Strategy and Analytics Service(CSAS)

These 30 companies collectively produce around 50 million barrels of oil equivalent per day (mmboe/d), meeting close to 30% of global oil and gas demand. Based on today’s portfolios of commercial assets, however, they will require an additional 22 mmboe/d by 2040 to maintain their share of the world’s supply. Filling that gap would require the group to add additional volumes equivalent to nearly two Permian basins or 14 Guyana-scale plays.

Figure 2: Production outlook - the group will need to find 22 mmboe/d to maintain its market share

Note: Doesn't include sub-commercial volumes
Source: Wood Mackenzie Corporate Strategy and Analytics Service(CSAS), Upstream Benchmarking Tool

Plugging the gap was easier in 2015

This group of 30 has form when it comes to adding new volumes to sustain production, but a lack of business development and exploration success in the early 2020s has left many of them with fewer growth options – and a bigger gap to fill – than a decade ago.

Back in 2015, we forecast that production from this group would fall 25%, or 11 mmboe/d, through 2030. That is a far less substantial decline than the nearly 40%, or 19 mmboe/d, fall in production from commercial assets we are now forecasting between 2025 and 2040.

Figure 3: Indexed production - the outlook today is worse than it was in 2015

Note: Doesn't include sub-commercial volumes
Source: Wood Mackenzie Corporate Strategy and Analytics Service (CSAS), Upstream Benchmarking Tool


The corporate cohort closed the gap last time around, delivering an additional 19 mmboe/d on top of our 2030 production forecast through a mixture of exploration, increased recovery, and mergers and acquisitions (M&A).

Most companies will produce more in 2030 than we forecast in 2015; only Petrobras and PetroVietnam will produce less. The big ‘winners’ have largely been US focused: ExxonMobil, Chevron, ConocoPhillips and Occidental have each added more than 1 mmboe/d, mainly through M&A-led US tight oil expansion. PetroChina and CNOOC have delivered similar results by doubling down on domestic plays in China.

These additions helped the peer group maintain its global market share but US tight oil – largely through M&A in the Permian Basin – and upgrades to the Chinese NOCs’ domestic volumes dominated. Barring the emergence of a new Permian-scale play, this is unlikely to be replicated. Even if it were, the peer group would still fall 3 mmboe/d short of what is needed to fill the looming gap to 2040.

Figure 4: Production outlook (2015 v 2025 view) - US Permian and China came to the rescue last time

Source: Wood Mackenzie Corporate Strategy and Analytics Service(CSAS), Upstream Benchmarking Tool

Why things are different this time around

Ten years on, not only is the next-decade gap bigger, but these companies have fewer obvious options for plugging it.

The great phase of US tight oil growth is ending. Production is nearing – or has even passed – its peak and is set to plateau in the coming years. Many of the most attractive corporate M&A opportunities to bolster E&Ps’ portfolios have already been snapped up. Chinese barrels are becoming increasingly costly to develop. What’s more, top resource-holding countries, such as Saudi Arabia, Russia and Iran, are closed for business, at least for now. The potential reopening of Venezuela has attracted headlines, but comes with a long list of challenges.

Of the 30 companies in our peer group, only Expand Energy, INPEX and Santos are set to produce more in 2040 than they are today based on our current view of their portfolios. Most companies will struggle to hold production at anywhere near today’s levels.

The situation is most acute for the Euro Majors and NOCs, who will need to find or access more than 1 mmboe/d – or 50% of their current production base – on average, to grow in line with demand. In absolute terms, CNPC has the biggest shortfall, with Pemex the most challenged in percentage terms. Equinor and Shell have the biggest gaps to fill among the Majors and IOCs.

Figure 5: Production outlook by peer group - the Euro Majors and NOCs have the biggest gaps to fill

Note: Numbers don't include sub-commercial volumes. NOC category doesn't include Middle East resource holders
Source: Wood Mackenzie Corporate Strategy and Analytics Service (CSAS)

Why companies cannot spend their way out

Compounding the challenge, the E&P sector is no longer constrained just by opportunity, but by capital. Fundamentally, oil and gas is a maturing business. To have a credible investment thesis, companies need to generate free cash flow at flat production under mid-cycle conditions to support sustainable shareholder distributions.

Since 2015, a smaller, more cautious investor base has redefined value. Scarred by weak equity returns – led by a shale sector that had threatened to overproduce its way to destruction – investors are now rewarding quarterly earnings and return of capital rather than long-term growth. 

Valuation upside now accrues to scale and credibility. Larger, more diversified producers have been re-rated as the market prioritises balance-sheet strength and through-cycle distributions. The rise of passive and momentum-based investing has exacerbated this large-cap premium by ensuring that larger companies continue to attract investors.

Investors increasingly expect these large companies to return 30% to 50% of operating cash flow by way of dividends and buybacks, with distribution resilience valued even above growth at attractive returns. Yet maintaining production remains essential to underpin cash generation, particularly in the absence of new, material growth engines, such as low-carbon businesses.

Because capital discipline is now a defining feature of how E&P companies are valued, companies cannot simply spend their way out of this dilemma. The core strategic challenge for the industry is, therefore, how to sustain output when reinvestment rates are roughly half of mid-2010s levels – a seemingly impossible equation that demands creative solutions.

Figure 6: Use of operating cash flow - reinvestment rates have almost halved since 2015

Path 2: creative capital structures

M&A 2.0: beyond traditional dealmaking

M&A remains essential to solving oil and gas companies’ longevity challenge, but traditional acquisitive growth has got tougher. While further industry consolidation is inevitable, many of the most attractive corporate acquisition opportunities have already been snapped up.

There are relatively few targets of scale with strong long-term growth outlooks. The reduction in IOC-led exploration activity has also reduced the flow of pre-final investment decision (FID) opportunities on the upstream asset market. Moreover, not every asset offers buyers as many synergies as tight oil and shale gas.

Oil and gas companies, therefore, will need to get more creative in their next phase of M&A-led growth. A greater capital pool for longevity might be unlocked if M&A were considered at a broader level, including:

• Strategic ventures: bringing new targeted investors into transition-focused vehicles prevents capital being drained by nascent growth businesses. In upstream, strategic ventures allow a company to pursue more opportunities more quickly by moving beyond the straitjacket of a group-level capital allocation framework in which non-core regions struggle to attract investment. Strategic ventures have unleashed a new phase of growth in the mature North Sea (Eni, BP, Repsol/TotalEnergies and Shell/Equinor), Africa (BP/Eni) and, most recently, in Southeast Asia (Eni/Petronas). More will follow.

Figure 7: BP strategic fit – Norway and Angola have thrived under their new strategic venture structure

Source: Wood Mackenzie Corporate Strategy and Analytics (CSAS), Upstream Benchmarking Tool

• Partnerships: strategic partner selection has long been critical to development risk sharing in pre-FID projects and the same logic applies to legacy portfolios. The key is finding partners with complementary strengths – cash-generative assets, infrastructure or regional expertise. Eni's Kutei Basin partnership with Petronas is a prime example: the NOC’s producing assets will fund the development of multi-tcf gas discoveries from Eni's selective M&A and exploration, turning a marginal legacy position into a regional growth engine.
• New financial structures: Saudi Aramco and ADNOC have recently agreed the sale and leaseback of midstream gas facilities to private equity investors. Similar structures have been deployed in US liquefied natural gas (LNG). Widespread leaseback arrangements could further benefit shareholders if they unlock hidden upside through cost-of-capital arbitrage.
• New financial structures: Saudi Aramco and ADNOC have recently agreed the sale and leaseback of midstream gas facilities to private equity investors. Similar structures have been deployed in US liquefied natural gas (LNG). Widespread leaseback arrangements could further benefit shareholders if they unlock hidden upside through cost-of-capital arbitrage.