Energy security: the return of long-term contracts?

Spot markets have delivered more and more ‘commodities on demand’ over the past half-century. But is this model fit for the energy transition? Many markets are now desperately short, causing explosive price rises. And sufficient volumes may still not be available at any price. So this 13-page note considers a renaissance for long-term contracts and who might benefit?


Liquid spot markets have long been seen as the apotheosis of commodities. Over time, small and immature markets are supposed to graduate towards ever-greater liquidity. Ultimately, the entire market is to be bought and sold at the prevailing prices on some highly liquid exchange, where any seller in the market can reach any buyer in the market, and vice versa. It is a kind of “commodities on demand” model. The history and evolution of this model is laid out on pages 2-3. But 2022 is showing its limitations.

Challenge #1 for liquid spot markets is that prices can explode in a shortage. We review energy costs, price elasticity factors, and their consequences on pages 4-6.

Challenge #2 for liquid spot markets is that even after prices explode, sufficient supplies may still not be available at any price. We zoom in on LNG as an example on pages 7-8. A country that has 90% of its supplies locked in on contracts is clearly going to fare very differently in 2022-23 than one that had planned to source 90% of its supplies from the spot market.

Challenge #3 is securing future supplies amidst uncertainty. No one wants to finance a 20-year project where prices could collapse, volumes could collapse or the commodity in question could even be banned outright. As an OPEC oil minister recently stated “it isn’t going to work like that”.

Could all of this point to a renaissance for long-term contracts? On pages 11-13, we outline what this might look like, who might benefit, and some possible pushbacks.

Decarbonizing global energy: the route to net zero?

This 18-page report revises our roadmap for the world to reach ‘net zero’ by 2050. The average cost is still $40/ton of CO2, with an upper bound of $120/ton, but this masks material mix-shifts. New opportunities are largest in efficiency gains, under-supplied commodities, power-electronics, conventional CCUS and nature-based CO2 removals.


This note looks back across 750 of our research publications from 2019-21 and updates our most practical, lowest cost roadmap for the world to reach ‘net zero’. Our framework for decarbonizing 80GTpa of potential emissions in 2050 is outlined on pages 2-3.

Our updated roadmap is presented on pages 4-6. Most striking is the mix-shift. New technologies have been added at the bottom of the cost curve. Other crucial components have re-inflated. And we have also been able to tighten the ‘risking factors’ on earlier-stage technologies, thus an amazing 87% of our roadmap is not technically ready.

The resulting energy mix and costs for the global economy are spelled out on pages 7-8, including changes to our long-term forecasts for oil, gas, renewables and nuclear.

What has changed from our 2020 roadmap? A full attribution is given on pages 9-10. Disappointingly, global emissions will be 2GTpa higher than we had hoped mid-decade, as gas shortages perpetuate the use of coal.

A more detailed review of our roadmap is presented on pages 11-18. We focus on summarizing the key changes in our outlook in 2021, in a simple 1-2 page format: looking across renewables, nuclear, gas shortages, inflationary feedback loops, more efficiency gains, carbon capture and storage and nature-based carbon removals.

Is the world investing enough in energy?

Global energy investment in 2020-21 has been running 10% below the level needed on our roadmap to net zero. Under-investment is steepest for solar, wind and gas. Under-appreciated is that each $1 dis-invested from fossil fuels must be replaced with $25 in renewables, to add the same new energy supplies. Future energy capex requirements are staggering. These are the conclusion in our 14-page note.


This 14-page note compares annual energy investment in different upstream energy sources with the amounts that would be required on our roadmap to net zero. The methodology is explained on page 2.

Current investment levels in each energy source are described on pages 3-5, reviewing the trajectory for each major category: oil, gas, coal, wind and solar. A stark contrast is found in capex per MWH of new added energy supplies.

We have constructed 120 different models, in order to stress-test the capex costs per MWH of new added energy supplies, across different resource types. Conclusions and comparisons from our modelling are presented on pages 6-8.

How much would the world need to be investing, on our roadmap to net zero, or indeed on the IEA’s roadmap to net zero? We develop our numbers, category by category, on pages 9-12, to identify where the gaps are greatest.

Conclusions and controversies are laid out on pages 13-14. Disinvestment from oil and gas will tend to exacerbate future energy shortages. To avoid this, it would be ideal to replace each dis-invested $1 of oil and gas investment with around $25 of new renewables investment.

CO2-EOR: well disposed?

CO2-EOR is the most attractive option for large-scale CO2 disposal. Unlike CCS, which costs over $70/ton, additional oil revenues can cover the costs of sequestration. And the resultant oil is 50% lower carbon than usual, on a par with many biofuels; or in the best cases, carbon-neutral. The technology is fully mature and the ultimate potential exceeds 2GTpa. This 23-page report outlines the opportunity.


The rationale for CO2-EOR is to cover the costs of CO2 disposal by producing incremental oil. Whereas CCS is pure cost. These costs are broken down and discussed on pages 2-5.

An overview of the CO2-EOR industry to-date is presented on pages 6-7, drawing on data-points from technical papers.

Our economic model for CO2-EOR is outlined on pages 8-10, including a full breakdown of capex, opex, and sensitivities to oil prices and CO2 prices. Economics are generally attractive, but will vary case-by-case.

What carbon intensity for CO2-EOR oil? We answer this question on pages 11-12, including a debate on the carbon-accounting and a contrast with 20 other fuels.

The ultimate market size for CO2-EOR exceeds 2GTpa, of which half is in the United States. These numbers are outlined on pages 13-15.

Technical risks are low, as c170 past CO2-EOR projects have already taken place around the industry, but it is still important to track CO2 migration through mature reservoirs and guard against CO2 leakages, as discussed on pages 16-17.

How to source CO2? We find large scale and concentrated exhaust streams are important for economics, as quantified on pages 18-21.

Which companies are exposed to CO2-EOR? We profile two industry leaders on page 22.

What implications for reaching net zero? We have doubled our assessment of CO2-EOR’s potential in this report, helping to reduce the costs in our models of global decarbonization.

Low-carbon refining: insane in the membrane?

Almost 1% of global CO2 comes from distillation to separate crude oil fractions at refineries. An alternative is to separate these fractions using precisely engineered polymer membranes, eliminating 50-80% of the costs and 97% of the CO2. We reviewed 1,000 patents, including a major breakthrough in 2020, which takes the technology to TRL5. Refinery membranes also comprise the bottom of the hydrogen cost curve. This 14-page note presents the opportunity and leading companies.


The CO2 intensity of refining and the need for economic decarbonization of the sector are quantified on pages 2-4. The discussion focuses upon the CO2 intensity of distillation, including the thermodynamics and costs.

The opportunity to use membranes in lieu of conventional distillation is presented on pages 5-6. We draw on economic models to present respective costs and CO2 intensities of membrane processes.

Hence we screened 1,000 patents to identify leading companies exploring refinery membranes. The findings are presented on pages 7-8. There are three key reasons why the technology has been slow to gain traction.

The most active patent filer in refinery membranes is profiled on page 9, a publicly listed conglomerate with headquarters in the US.

ExxonMobil has made a breakthrough in 2020, deriving permeate streams from a synthetic polymer membrane that resemble the output from a distillation column. We have reviewed the technical disclosures on pages 10-13, highlighting the commercial opportunity and remaining challenges.

Membranes can also unlock the lowest cost hydrogen in the world, recovering hydrogen that is currently wasted or purged in the effluent streams from refinery units. An industry leading example of this technology is explored on page 14.

Turning the tide: is another offshore cycle brewing?

Oil markets look primed for a new up-cycle by 2022, which could culminate in Brent surpassing $80/bbl. This is sufficient to unlock 20% IRRs on the next generation of offshore projects, and thus excite another cycle of offshore exploration and development. Beneficiaries include technology leaders among offshore producers, subsea services, plus more operationally levered offshore oil services. The idea is laid out in our 17-page note.


Our oil market outlook is detailed on pages 2-5, seeing 2Mbpd of under-supply by 2022 and a potential inventory draw of 2.5bn bbls.

>$80/bbl oil prices are needed to instigate a new offshore cycle, as modelled and explained on pages 6-9.

Can’t the next oil cycle be quenched purely by ramping up short-cycle shale, instead of another offshore cycle? We answer this pushback on pages 10-11.

Is another offshore cycle compatible with the energy transition and global decarbonization? We answer this pushback on pages 12-13, with detailed data on CO2 emissions per barrel offshore versus elsewhere.

Who benefits? We present the technology leaders among producers, service companies and emerging technologies on pages 14-17, drawing on our prior patent screens and technical research.

On the road: long-run oil demand after COVID-19?

Another devastating impact of COVID-19 may still lie ahead: a 1-2Mbpd upwards jolt in global oil demand. This could trigger disastrous under-supply in the oil markets, stifle the economic recovery and distract from energy transition. This 17-page note upgrades our 2022-30 oil demand forecasts by 1-2Mbpd above our pre-COVID forecasts. The increase is from road fuels, reflecting lower mass transit, lower load factors and resultant traffic congestion.


Upgrades to our granular 2020-2050 oil demand models, including headline numbers, are outlined on pages 2-3.

Travel demand that will never come back is described on pages 4-5, including remote work, a shift to online retail and lower business travel. Our forecasts for higher oil demand are not based on a Panglossian recovery of travel habits to pre-COVID levels.

The shift from mass transit to passenger cars is detailed on pages 6-9, covering ground-transportation (buses and train), mid-range air travel, and reverse urbanization enabled by remote working.

Load factors are lightly reduced, requiring more cars to service each passenger-mile of travel, as outlined on page 10.

Higher road traffic dents fuel economy, which we have quantified using real-world data from the City of New York, also drawing on data from prior oil downturns, on pages 11-14.

Implications for oil markets, companies and the energy transition are discussed on pages 15-17.

What oil price is best for energy transition?

It is possible to decarbonize all of global energy by 2050. But $30/bbl oil prices would stall this energy transition, killing the relative economics of electric vehicles, renewables, industrial efficiency, flaring reductions, CO2 sequestration and new energy R&D. This 15-page note looks line by line through our models of oil industry decarbonization. We find stable, $60/bbl oil is ‘best’ for the transition.


Our roadmap for the energy transition is outlined on pages 2-4, obviating 45Mbpd of long-term oil demand by 2050, looking across each component of the oil market.

Vehicle fuel economy stalls when oil prices are below $30/bbl, amplifying purchases of inefficient trucks and making EV purchases deeply uneconomical (pages 5-6).

Industrial efficiency stalls when oil prices are below $30/bbl, as oil outcompetes renewables and more efficient heating technologies (page 7).

Cleaning up oil and gas is harder at low oil prices, cutting funding for flaring reduction, methane mitigation, digitization initiatives and power from shore (pages 8-9).

New energy technologies are developed more slowly when fossil fuel prices are depressed, based on R&D budgets, patent filings and venturing data (pages 10-11).

CO2 sequestration is one of the largest challenges in our energy transition models. CO2-EOR is promising, but the economics do not work below $40/bbl oil prices (pages 12-14).

Our conclusion is that policymakers should exclude high-carbon barrels from the oil market to avoid persistent, depressed oil prices (as outlined on page 15).

Digitization after the crisis: who benefits and how much?

Digitization offers superior economics and CO2 credentials. But now it will structurally accelerate due to higher resiliency: Just 8% of digitized industrial processes will be materially disrupted due to COVID-19, compared to 80% of non-digitized processes. In this 22-page research report, we have constructed a database of digitization case studies around the energy industry: to quantify the benefits, screen the most digital operators and identify longer-term winners from the supply chain.


Pages 2 outlines our database of case studies into digitization around the energy industry.

Page 3 quantifies the percentage of the case studies that reduce costs, increase production, improve safety and lower CO2.

Pages 4-6 show how digitization will improve resiliency by 10x during the COVID-crisis, stoking further ascent of energy industry digitization.

Page 7 generalizes to other industries, arguing digitization will accelerate the theme of remote working, esepcially in physical manufacturing sectors.

Pages 8-9 screen for digital leaders among the 25 largest energy companies in the world, based on our assessment of their patents, technical papers and public disclosures.

Pages 10-11 identify leading companies from the supply chain, which may benefit from the acceleration of industrial digitization; again based on patents and technical papers.

Pages 12-22 present the full details of the digitization case studies that featured in our database, highlighting the best examples, key numbers and leading companies; plus links to delve deeper, via our other research, data and models.

Remote possibilities: working from home?

The COVID-19 crisis will structurally accelerate remote working. The opportunity is explored in our 21-page report. It can save 30% of commuter journeys by 2030, avoiding 1bn tons of CO2 per year, for a net economic benefit of $5-16k per employee. This makes remote work a materially more impactful opportunity than electric vehicles in the energy transition.


Remote work currently saves c3% of all US commuter miles, which comprise 33% of developed world gasoline demand (pages 2-4).

Remote work could save 30% of all commuter miles by 2030, structurally accelerating as the COVID-19 crisis changes habits (page 5).

Remote work, thus screens as more impactful than electric vehicles, as an economic opportunity in the energy transition (page 6).

Ecconomic benefits are $5-16k pp pa. Our numbers are conservative. They under-reflect productivity and wellbeing improvements in the technical literature (pages 7-8).

We stress test our numbers, looking profession-by-profession across the entire US labor force, and considering new technologies (pages 9-13).

Direct energy impacts save 1bn tons of annual CO2. Impacts on oil, gas and electricity demand are quantified, including evidence from the COVID crisis (pages 14-17).

Hidden consequences are more nuanced: reshaping mobility, urbanization and online retail habits (pages 18-21).

Copyright: Thunder Said Energy, 2022.