Executive Summary
Navigating oil and gas in a time of hyper-uncertainty
Down the decades, the risks of the oil and gas industry have always been tempered by an unwavering assumption that demand would rise indefinitely. Now, however, as the energy transition gathers momentum and the upstream industry is forced to navigate uncharted waters, that belief has all but evaporated.
The upstream industry now finds itself having to supply oil and gas to a world in which future demand – and price – are highly uncertain. The range of possible outcomes is dizzying. A gradual energy transition, for instance, could require the industry to invest in new production capacity for another decade or two. Wood Mackenzie’s accelerated energy transition (AET-2) scenario, in contrast, in which global warming is limited to 2 °C, sees oil demand and prices slide while gas fares comparatively well.
This makes strategic planning infinitely more complicated. This Horizon examines the key issues management and investors need to consider as the upstream sector positions itself for the challenges ahead.
HORIZONS
Swimming upstream:
a survivor's guide
May 2021
Fraser McKay Vice President, Head of Upstream Analysis
Angus Rodger Research Director, Asia Pacific
Greig Aitken Director, M&A Research
Contents
Navigating oil and gas in a time of hyper-uncertainty
Extreme planning, the upstream edition
Capital allocation: an upstream investment playbook
Against the tide: finding a buoyant business model
Conclusion: cash cows can swim
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Fraser McKay
Vice President,
Head of Upstream Analysis
As head of our Upstream Research team, Fraser is responsible for maximising the quality and impact of our analysis of key global upstream themes.
Fraser joined Wood Mackenzie in 2003, initially as an upstream analyst leading our offering in Canada and Alaska. Since then he has managed research teams focused on delivering in-depth, strategic corporate and upstream analysis and played a key role in building out our Americas upstream and corporate research capacity. Fraser has also played a key role in the development of a suite of products, including our M&A Service, Corporate Benchmarking Tool and Mid-Cap
Corporate Coverage.
In his senior roles, Fraser has managed and contributed to major strategic consulting projects, interacted with client executive teams and government entities at the most senior level, and presented upstream and corporate material to global audiences.
Prior to joining Wood Mackenzie, Fraser worked for Schlumberger in various field and managerial positions in the oilfield services sector.
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Angus Rodger
Research Director, Asia Pacific
Angus leads our benchmark analysis of global pre-FID delays and deep-water developments, including cost deflation and project evolution studies.
Since joining Wood Mackenzie nine years ago, Angus has worked on a variety of upstream projects across Asia and Australasia. He has also been instrumental in devising our pre-FID project tracker which identifies major projects in development across the globe.
An expert in deep-water analysis, he has advised both national and independent oil companies on new business development including stranded gas monetisation, exploration strategy, regional basin screening and country-entry strategies.
Angus previously worked in London covering the North Sea and West African upstream sectors. With a background in finance, research and journalism, he is accustomed to drawing on a wide range of information sources and quickly getting to the crux of an issue. He is a regular speaker at leading regional conferences and frequently provides insight on industry trends to leading news channels.
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Greig Aitken
Director, M&A Research
With over 12 years of relevant experience, Greig brings a holistic view of corporate activity to the upstream M&A
research team.
Greig heads up the M&A Service, which harnesses the power of Wood Mackenzie's global asset research to provide an unparalleled independent view on upstream mergers and acquisitions. Greig's responsibilities include overseeing and supporting individual deal evaluations, and analysing industry trends on themes such as valuations, corporate strategies and value creation. Greig's views are regularly sought by the media and he is a frequent presenter at forums and conferences.
Greig joined Wood Mackenzie in 2012 as analyst in the M&A Service. Prior to this, Greig was a sell-side equities analyst in Brewin Dolphin’s award-winning institutional broking business (now N+1 Singer). He was Extel-rated in both the Technology and Oil & Gas sectors, and was the #1 ranked stock picker in the energy sector (FT / Starmine Analyst Awards, UK & Ireland). Greig spent the early part of his career as a software developer in the pensions and life assurance industry.
With a background in technology, Greig has taken a keen interest in the rising prominence of digitalization in the oil and gas industry, and has contributed to recent Wood Mackenzie research on the topic.
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Extreme planning, the upstream edition
As we saw in the April edition of Horizons, our AET-2 scenario frames the extreme uncertainties faced by the oil and gas industry as it plans for the future. AET-2 is a scenario, not a forecast, but it shows how stepped-up efforts to tackle climate change could mean a radically different future for oil and gas demand and prices, to one of continued growth.
Figure 1: A wide range of demand uncertainties
Source: Wood Mackenzie Energy Transition Service
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The current is strong and the stakes are high
The oil and gas industry has enjoyed a century of near continuous demand growth. Oil and gas demand, rebounding as the world recovers from the Covid-19 pandemic, is set go beyond the record 160 million barrels of oil equivalent per day (boed) reached in 2019. The world will still need oil and gas supply for decades to come, even as the energy transition erodes fossil fuels’ share
of energy.
After six years of weaker prices, upstream is fitter and leaner than ever. It will generate as much cash flow this year at US$60/bbl as it did at US$100/bbl prior to the 2014 price crash - and there’s huge value yet to be extracted. The global upstream sector is worth US$4.8 trillion based on our Lens upstream valuation models, using a long-term corporate planning price of US$50/bbl.
To say operators’ valuations are sensitive would be an understatement. The range of valuations is a staggering US$3.3 trillion to US$8.7 trillion, assuming AET-2 or another decade of continued demand growth as boundaries. Total sector economic rent varies from US$9 trillion to US$23 trillion if host governments’ direct share through taxes and royalties is included.
Oil and gas companies have no control over the vagaries of demand and price. But the decisions they make as the transition unfolds will be critical to maximising the value of the upstream business, however things play out.
Figure 2: Global post-tax asset valuation sensitivity
Source: Global Lens upstream, commercial asset post-tax NPV10
Figure 3: Global post-tax cash-flow sensitivity
Source: Global Lens upstream, commercial asset models
Capital allocation:
an upstream investment playbook
Upstream investment has never been for the fainthearted. Projects can take decades from cradle to grave and go through multiple commodity cycles. The energy transition brings a new level of uncertainty. How can the industry deliver the requisite supply and stay profitable, investible, resilient and sustainable?
Delivery and discipline are paramount in all aspects of the upstream value chain as the macro environment for oil and gas gets tougher. Performance against budgets and timelines has improved dramatically since the last downturn, but the industry needs to remain relentless in its push to improve efficiency, drive down costs and deliver projects flawlessly. Mistakes could be disastrous. Oil and gas companies need to send a strong signal to stakeholders that they can be reliable stewards of capital.
There are five key things that will influence upstream capital allocation.
1. Short-termism will reign
Projects with shorter payback periods will be prioritised and portfolios with multiple and varied investment options will be of higher worth. Capturing the upside used to be a core part of the upstream investment philosophy. The future will be about minimising unproductive capital and changing tack quickly to mitigate risks.
The industry’s affinity for complex, long-life developments with thin margins has to end, as does its propensity for exuberant spending when prices rise, as they are even less likely to remain up in future. Too often in the past, peak spending has coincided with peak service costs, and peak production with price nadirs.
The phasing and the rightsizing of projects can help, reducing capital intensity and capturing average costs and prices throughout cycles. This approach would have generated returns 3–4% higher during the last two price cycles.
Incremental onshore global conventional and North American unconventional resources are at the sharp end of short-cycle investments. Under our AET-2 scenario, very little long-term greenfield spending is required to meet demand. It is no surprise that the sliver of investment that survives is concentrated in sustaining existing production and the best available opportunities in the Lower 48. Only exceptional, low-cost projects in more challenging resource themes will work in
all scenarios.
2. Gas is good
Lower full-cycle emissions and the potential to combine with CCS/CCUS underpins the resilience of gas demand. Upstream capital should flow in that direction.
It’s not happening yet – absolute spending on oil considerably exceeds that on gas. The returns on developing a barrel of oil today are higher, with oil-production and cash-flow profiles delivering more value upfront. Gas prices are lower than oil prices on an energy-equivalent basis – though in time, this relationship will reverse.
Sanctioning large-scale gas and liquified natural gas (LNG) projects is already a big economic and psychological hurdle for many boards. Big gas projects can throw off huge cash flows at high margins once developed, but there is no hiding from their long payback periods and chunky capital commitments. Returns have been low and project execution hard-fought.
The stronger outlook for gas demand as a transition fuel supports a pivot to gas, but the industry must find a way to generate acceptable returns from big gas projects. There are far more stalled and stranded gas than oil fields globally, simply because they are harder to commercialise. Of the 900 billion boe of non-commercial resources in our Lens dataset, two-thirds are gas.
A more creative mindset is required and some of the answers come from the oil playbook. The industry is increasingly targeting smaller-scale, shorter-cycle onshore gas projects to improve optionality. But recent Eastern Mediterranean deepwater gas developments have shown that gas returns can be substantially improved through quicker and phased development, if the rocks are good enough.
3. Decarbonising upstream is crucial
Projects with lower carbon footprints are increasingly attractive, as are investments that decarbonise existing assets. They prolong asset lives, maintain investability and could capture price premia. The industry needs to shake off the perception that decarbonisation is a cost centre. Carbon pricing will expedite this, but most low-hanging fruit – improved facility efficiency, reduced leakage and flaring – can be value-accretive.
For large companies with long-life portfolios, the next step is to think beyond Scope 1 and 2, even if they are sceptical on the pace of transition. One option would be to add more gas to the portfolio, regardless of lower baseline returns. Another would be to scale up carbon capture, both utilisation and storage (CCUS/CCS) – a great opportunity for the industry to leverage its technical expertise and infrastructure and become part of the solution, rather than part of the problem.
CCUS/CCS capacity must rise from the paltry 40 million tonnes per annum today to 4–8 billion tonnes per annum by 2050 if the world is to achieve its net-zero carbon ambitions. This is a huge growth opportunity, and oil and gas companies are in prime position to capitalise. But CCUS/CCS requires coordinated progress on carbon pricing and other value streams, legislation and investment incentives. Mature infrastructure-rich basins with depleted reservoirs and saline aquifers, such as the North Sea, US Gulf of Mexico or Western Australia, are well placed to
become testbeds.
4. Exploration isn’t dead
It’s still a capital allocation option. Exploration budgets may be smaller and practised by fewer companies, but high-quality, low-cost discoveries can outcompete higher-cost, more carbon-intensive discovered resources. This means more focused exploration than in the past and, by extension, probably fewer exploration wells. If international oil companies continue to step away, national oil companies will become the lifeblood of the sector.
5. Competition with renewables is intensifying
The largest players will increasingly measure exploration and production investment against solar, wind and other low-carbon investments. Expected returns from oil and gas projects will eclipse those of more predictable renewables for some time, but the relative value proposition will narrow over time.
Figure 4: New project returns by resource theme at corporate planning prices
Source: Wood Mackenzie Lens upstream
All averages are weighted by capital spending.
Economics are based on assumed corporate planning prices of US$50/bbl Brent long term.
Figure 5: Oil versus gas investment split
Source: Wood Mackenzie Lens upstream
Figure 6: Returns sensitivity to demand outcomes
Source: Wood Mackenzie Lens upstream, global future projects excluding US Lower 48
Figure 7: Competition for capital
Source: Wood Mackenzie Lens upstream at US$50/bbl Brent long-term
*A blend of large IOC/Majors’ internal hurdle rates.
Against the tide:
finding a buoyant business model
Upstream oil and gas business models will change as the transition gathers pace. Companies will need to follow the blueprints for best-in-class capital allocation and prioritise the stability and dependability of dividends over growth. ESG considerations will increasingly determine
capital availability.
1. Serial consolidation is inevitable as peak demand nears
The pros? Reduced overheads and less competition plus increased efficiency and buying power equals higher margins. The cons? Less innovation, an inability to attract and retain talent and the decision-making inertia that comes with bigger companies. Consolidation is already well underway in the highly fragmented US Lower 48 and is more advanced in the Canadian oil sands and other mature markets. The trend will widen and accelerate and could include a new wave of
mega-mergers.
Figure 8: The need for consolidation
Source: Wood Mackenzie Lens
2. Specialists will fill any gaps
Some specialist companies could become very large. The niches they will exploit will be based on existing technical and organisational competencies. Examples include mature asset rejuvenation; low-cost vertically integrated specialists in harvesting and retiring assets; leveraging close ties with host governments or regional integration with demand centres. For some, the competitive advantage could be ownership by entities that are freer of ESG constraints than mainstream investors. Conversely, for others, it could be a specialism in maximising valuation multiples through improved ESG performance.
3. Spinouts and joint ventures will be created, as uncertainty drives corporate restructuring
At the Majors’ level, Big Energy could split into ‘GoodCo’ and ‘BadCo’ along the boundary of new and old energies. Investors could choose between the two to suit their growth or dividend strategies. GoodCo – new energies – would need to be of sufficient scale for this to be meaningful. Some are already considering separate entities for new energies businesses to test the concept, attract lower-cost capital and win higher valuations.
On its own, however, this does not address the issue of how to effectively manage the upstream business. There are, of course, more dramatic options. Fit-for-purpose investment vehicles could be created using joint ventures or innovative deal-making to align interests across regions or resource themes.
A solution for large international oil companies trying to exit non-core areas to improve investment discipline could be to aggregate portfolios in areas such as West Africa or Asia. The new entity would create efficiencies and improve margins. Cash flow would be distributed, but remain at arm’s length of the core upstream operations of Big Energy.
Could new, very large-scale integrated gas companies solve the investment conundrum by creating the right mix of short-cycle piped gas, offsetting the risk of developing LNG megaprojects?
4. The rise of resource-holding national oil companies
The biggest national oil producers (NOCs) will gain market share in all demand scenarios. Middle Eastern NOCs have the lowest-cost, lowest-carbon barrels and cheap finance, making them more resilient to change than their international brethren. But any cash-rich NOCs will view uncertainty as an opportunity to acquire assets in a buyers’ market.
While they will retain the appetite to develop big projects, they will have to future-proof them too. As the rapid emergence of ‘green LNG’ proves, disruptive change can come fast. Qatar is already the lowest-cost supplier of LNG, but its decision to invest in CCS/CCUS means it can offer low-carbon molecules as well, effectively locking in its competitive advantage. Other national oil companies are looking to repurpose old fields and infrastructure for CCS/CCUS, hydrogen and renewables, and many have the capital to scale it up.
Heatmap of global upstream emissions (Scope 1 and 2)
Source: Wood Mackenzie Lens
Cost of capital and ESG
Inevitably, the cost of capital and the cost of doing business in oil and gas will increase. We’ve seen it in coal, where the shift to smaller niche financiers increased thermal coal’s funding costs. The availability of capital is not the issue; instead, coal projects fail due to their economics, payback periods or lack of regulatory approval. Despite having a less challenging future than coal in almost all energy transition scenarios, the same will be true for oil and gas. Viable projects will get funded.
Stakeholders from banks to insurers are considering whether oil and gas still fit with corporate mandates. Direct ESG risks, such as carbon pricing, demand destruction, social licences and other factors, are used to screen investments. An ever-increasing proportion of blue-chip investor capital will disappear.
The onus is on oil and gas companies to improve their ESG credentials. The bond of trust with stakeholders, which grants them a licence to operate, must improve. For the biggest players, diversification into new energies will play an increasing role, but this is a not an option for many industry participants. They will need to reduce Scope 1 and 2 emissions to reduce their exposure to increasingly expensive debt.
Talent and technology
Navigating the energy transition puts people and technology in the spotlight as never before. Technology promises efficiency from leveraging data with artificial intelligence and super-computing. The brain-drain of technical expertise into growth sectors, including the low-carbon value chain, is already a concern.
Upstream has always had a highly skilled and dedicated workforce. The industry needs to continue to compete for best-in-class talent. This includes engineers and geoscientists but, increasingly, a more diverse pool of data science, technological innovation and other skills are required. To attract them, the industry needs to position itself as a high-tech, sustainable business with its own leading-edge technologies, such as CCS/CCUS, in which new recruits and existing employees can build a satisfying career.
Conclusion:
cash cows can swim
Oil and gas is a risky business. Over the years, those risks have been tempered by a single tenet – that oil and gas demand would continue to rise indefinitely. As the energy transition gathers momentum, however, that belief has all but evaporated.
The upstream industry now finds itself having to supply oil and gas to a world in which future demand – and price – are highly uncertain. The range of possible outcomes is dizzying. A gradual energy transition, for instance, could require the industry to invest in new production capacity for another decade or two. Wood Mackenzie’s AET-2 scenario, in contrast, sees oil demand and prices slide while gas fares comparatively well.
Strategic planning gets infinitely more complicated when the possibilities of a two-degree world are incorporated. We believe management - and investors - need to bear in mind four key things as the upstream sector positions itself for the
challenges ahead.
Capital allocation becomes short-termist. Short-cycle, high-return, low-carbon projects are in; capital-intensive, long-payback oil projects are out. This could lead to under-investment in supply, exacerbating market volatility. Operators need portfolio optionality and agility, so they can adjust to changing market conditions.
Investment will shift to gas, ending oil’s long supremacy, as gas plays a leading energy transition role. The industry will have to figure out the conundrum of weaker economics if the giant gas projects the world needs are to happen.
The industry must tackle environmental, social and corporate governance (ESG) issues head on. The decarbonisation of upstream will prolong the life of the industry and make it more investible; the bond of trust with stakeholders must improve for upstream to retain the social licence to operate.
Business models must adapt to maximise value as the sector matures.Consolidation will bolster margins. Specialists will carve out niches. Applying the right technology and retaining the right people will determine their success.
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As the upstream sector tries to navigate these uncharted waters, financial strength will be its life jacket. Even under our AET-2 scenario, upstream is a cash cow; a few more years of firm prices would strengthen balance sheets, making a choppy voyage more comfortable. Whatever happens, upstream will remain big business and provide enormous support to the global economy for quite some time to come.
After six years of weaker prices,
upstream is fitter and leaner
than ever
Oil and gas companies need to send a strong signal to stakeholders that they can be
reliable stewards of capital
The industry needs to shake off the perception that decarbonisation is a cost centre
Only exceptional, low-cost projects in more challenging resource themes will work in all scenarios
This insight uses data from our innovative Lens platform which provides comprehensive data and analytics for immediate business insight.
Find out more
Inevitably, the cost of capital and the cost of doing business in oil and gas will increase
The onus is on oil and gas companies to improve their ESG credentials
Continued demand growth for another decade
AET-2 scenario
Post-peak demand stays above 90 million barrels per day out to 2050, encouraging investment in costlier sources of supply and supporting prices just above US$80/bbl (2020, real) by 2030.
Gas demand remains strong, with growing coal displacement in Asia underpinning prices of US$8 to US $9/mmbtu through 2040 and beyond.
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Oil demand would peak before 2025 and fall towards 35 million barrels per day by 2050, 70% below peak levels. By 2030, Brent would average US$40/bbl (real, 2020) and continue its decline in the
years beyond.
Gas demand grows into the 2030s. The declines thereafter would be very gradual, falling to 20% below our base-case scenario by 2050. North American gas prices are US$3 to US$4/mcf and LNG prices remain robust at US$7 to US$8/mmbtu, before starting to fall post 2040. Gas becomes more expensive than oil on an energy-equivalent basis.
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Range of uncertainty
Continued growth for gas
AET-2
2000
2004
2008
2012
2016
2020
2024
2028
2032
2036
2040
2044
2048
100
200
300
400
500
Billions of cubic feet per day
Range of uncertainty
Continued growth for oil
AET-2
2000
2004
2008
2012
2016
2020
2024
2028
2032
2036
2040
2044
2048
20
40
60
80
100
120
Million barrels per day
AET-2
Corporate planning prices
Continued demand growth
0
1
2
3
4
5
6
7
8
9
10
Middle East
North America
Russia & Caspian
Asia
Latin America
Africa
Europe
Oceania
Upstream asset valuation (US$ trillion)
US$5.5 trillion range of outcomes
2010
2012
2014
2016
2018
2020
2022
2024
2026
2028
2030
2032
2034
2036
2038
2039
0
0.2
0.4
0.6
0.8
1.0
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1.4
Annual upstream asset cash flow (US$ trillion)
Continued demand growth
Corporate planning prices
AET-2
5
6
7
8
9
10
11
12
13
14
15
Average payback period (years)
0%
10%
20%
30%
40%
50%
Average IRR by theme
Permian US tight oil
Northeast US shale gas
Deepwater gas
Conventional gas
LNG
Deepwater oil
Conventional oil
Oil
Gas
Bubble size equates to average project size by capex
US$4bn capex
2010
2012
2014
2016
2018
2020
2022
2024
2026
2028
2030
0%
10%
20%
30%
40%
50%
60%
70%
Proportion of global investment
Oil
Gas
Continued demand growth
Corporate planning prices
AET2
0%
5%
10%
15%
20%
25%
30%
35%
IRR
Oil
Gas
Future renewables target (basic)
Future renewables target (leveraged)
2010-2019 investment
Future gas investment
Future oil investment
0
5
10
15
20
25
IRR (%)
Industry targets*
Wood Mackenzie Lens data
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Figure 1: A wide range of demand uncertainties
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Company count by oil-equivalent production band
0
20
40
60
80
100
120
140
160
Greater than
1 Mboe/d
Greater than
500 kboe/d
Greater than
250 kboe/d
Greater than
125 kboe/d
Greater than
60 kboe/d
Greater than
30 kboe/d
Greater than
15 kboe/d
2,300 companies (1,700 in US Lower 48)
Not state owned
State owned
... 2,300
Company count by oil-equivalent production band
0
20
40
60
80
100
120
140
160
Greater than
1 Mboe/d
Greater than
500 kboe/d
Greater than
250 kboe/d
Greater than
125 kboe/d
Greater than
60 kboe/d
Greater than
30 kboe/d
Greater than
15 kboe/d
2,300 companies (1,700 in US Lower 48)
Not state owned
State owned
Future renewables target (basic)
Future renewables target (leveraged)
2010-2019 investment
Future gas investment
Future oil investment
0
5
10
15
20
25
IRR (%)
Industry targets*
Wood Mackenzie Lens data
Continued demand growth
Corporate planning prices
AET2
0%
5%
10%
15%
20%
25%
30%
35%
IRR
Oil
Gas
2010
2012
2014
2016
2018
2020
2022
2024
2026
2028
2030
0%
10%
20%
30%
40%
50%
60%
70%
Proportion of global investment
Oil
Gas
5
6
7
8
9
10
11
12
13
14
15
Average payback period (years)
0%
10%
20%
30%
40%
50%
Average IRR by theme
Permian US tight oil
Northeast US shale gas
Deepwater gas
Conventional gas
LNG
Deepwater oil
Conventional oil
Oil
Gas
Bubble size equates to average project size by capex
US$4bn capex
2010
2012
2014
2016
2018
2020
2022
2024
2026
2028
2030
2032
2034
2036
2038
2039
0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
Annual upstream asset cash flow (US$ trillion)
Continued demand growth
Corporate planning prices
AET-2
Chart 3
AET-2
Corporate planning prices
Continued demand growth
0
1
2
3
4
5
6
7
8
9
10
Middle East
North America
Russia & Caspian
Asia
Latin America
Africa
Europe
Oceania
Upstream asset valuation (US$ trillion)
US$5.5 trillion range of outcomes
Range of uncertainty
Continued growth for gas
AET-2
2000
2004
2008
2012
2016
2020
2024
2028
2032
2036
2040
2044
2048
100
200
300
400
500
Billions of cubic feet per day
Range of uncertainty
Continued growth for oil
AET-2
2000
2004
2008
2012
2016
2020
2024
2028
2032
2036
2040
2044
2048
20
40
60
80
100
120
Million barrels per day
... 2,300