Key findings of the report
“Thermal Coal in Asia – Stopping the Juggernaut” edited by Mark Fulton (ETA), pulls together key sources to show that both China (by 2020) and India (in the 2030s) will exceed their IEA ETP annual carbon budgets. Furthermore, without a massive scale-up in renewable energy and the development of Carbon Capture and Storage (CCS) in key geographic areas (particularly China), the total carbon budget up to 2050 will also be exceeded in the 2030s. These conclusions are based on existing and “under construction” thermal coal power plants, yet even if no additional power plants are constructed, the budget would still not be met. Consequently, the research report calls for action: (1) to reform electricity markets so that low cost renewables are dispatched first; (2) to extend robust moratoriums on new coal power plants; (3) to cap longer-term coal consumption and emissions in the power sector in the context of carbon markets.
Summary Report PDF Download:
Full Report PDF Download:
Oil majors could be worth up to $140 billion more by aligning production with climate targets.
Key findings of the report
Continuing Carbon Tracker’s focus on upstream capex for new oil and gas projects, we have developed a Carbon Sensitivity Analysis. This brings together low carbon demand scenarios with oil price and discount rate sensitivity to understand how reducing exposure to high cost, high carbon projects can optimise value. Given the unpredictability of oil prices, we believe that a sensitivity approach which incorporates a wide range of oil prices (including those that might be thought unlikely at the time) is valuable. This analysis aims to show that it can make financial sense for the oil and gas majors to adopt a strategy of aligning their project portfolios to be consistent with a 2˚C outcome, rather than pursue volume at all costs.
Mark Fulton, Senior Research Advisor to Carbon Tracker, presents the key high level findings of the report launched on 25th November in London:
- $2.2 trillion of capex through 2025 associated with unneeded fossil fuel supply, which through 2035 equates to 156 GtCO2 of emissions
- No new thermal coal mines needed through 2035
- 1/3rd of potential oil supply from new projects is unneeded
- 1/4th of potential gas supply from new projects is unneeded
- 90% of unneeded fossil fuel capex tied to oil and gas
- Risks to private-sector oil and gas, with listed and partly-listed companies owning 2/3rds of capex and carbon associated with unneeded oil and gas production
- “High-cost carbon traps” that include Canadian oil sands, Arctic oil and gas (US, Russia, Canada), deep/ultra-deep water oil and gas (e.g. Mexico and Brazil) and LNG projects (e.g. Qatar, Australia, and Indonesia)
- High state ownership of unneeded thermal coal supply, in India and China. Listed exposure to US and seaborne
In the past few years, carbon asset risk (CAR) has gone from a fringe topic discussed primarily by NGOs to a serious consideration of some of the largest companies in the world. Recent market action, investor pledges, new models and results, and significant shareholder resolutions are all contributing to pushing CAR into the public attention. This report discusses some of the most important recent developments and provides the first attempt at quantifying the uptake of CAR assessment and management.
Key findings of the report
Production subsidies summing up to:
- Nearly US$8 per tonne in the US Powder River Basin ($2.9b/year); and
- Nearly US$4 per tonne ($1.3b/year) in Australia.
The removal of these subsidies would result in:
- An 8%-29 % reduction in demand for US PRB coal, with associated cumulative reductions of 0.7 to 2.5 GtCO2 to 2035, equivalent to 9 to 32 coal plants.
- A 3%-7% reduction in demand for Australian Seaborne coal, though with unknown carbon reductions due to substitution of coal from other (often also-subsidized) producers.
Removing subsidies to coal extraction should be a central plank of any country’s fiscal and environmental plan. Particularly as subsidies to renewable energy come under increasing pressure, subsidies to the mature coal sector should not be ignored. A broader geographic range for coal subsidy elimination will boost the carbon benefits, as the ability for coal supplies to move in from other subsidized markets will be constrained.
Key takeaways and recommendations
- In this report we examine the implications of a low gas demand scenario (“LDS”) below the expectations of the majors, but above the IEA’s 450 Scenario (global 2012- 2035 gas demand CAGR of 1.4% in the LDS compared to 0.8% in the 450 Scenario).
- 97% of LNG demand to 2025 is already covered by existing projects, meaning that projects accounting for a potential $283bn capex are not needed.
- Europe and North America will continue to need significant new gas production.
- Unconventional gas remains limited in Europe, accounting for 5% of production over the period, with challenges from cost and environmental concerns.
- $10/mmBtu is the key breakeven gas price test in Europe and LNG.
- Gas can play a part in the energy transition, but to use the carbon budget efficiently it is important that GHG emissions are minimised.
In our view, fossil fuel companies and their shareholders are exposed to the following key risks associated with climate change.
Commodity Price risk:
- What is the risk to the value of existing company reserves in a ‘low carbon’ scenario for demand where commodity prices are likely to be lower but certainly more volatile?
- What is the relative exposure to future high cost, high carbon developments that may prove unnecessary and hence sub-commercial in a ‘lower carbon’ scenario?
Capital allocation risk:
Is there sufficient flexibility within existing capital budgets to avoid pressure on shareholder dividends and employee levels in a ‘lower carbon’, low price scenario?
- Are management and shareholder interests aligned correctly for a ‘low carbon’ scenario, which would likely require a low/no growth investment strategy?
- Coal prices down 40% since 2011 due to surging supply and slowing (or negative) demand growth.
- Over last three years Bloomberg Global Coal Index of 32 publicly- listed coal miners has lost half of its value, with leading indicators suggesting continued market pessimism.
- Since 2011 US coal sector has seen major bankruptcies and extensive management shake-ups.
- Having grown steadily since 2000, from 2012-2013 combined capex of major publicly-listed thermal coal producers actually declined slightly – although remained 3X cash return to shareholders via dividends and share buybacks.
- Major diversified miners Rio Tinto, BHP Billiton, and Vale have been disposing of thermal coal assets.
- We forecast global thermal coal demand to peak in 2016 and then declines (2035 demand 4% < 2013 level).
- Risks to profitability for 36% of potential thermal coal production through 2035 – including half of production from new mines.
- Strong headwinds to greatly expanded US coal exports to Asia – Excluding China, through 2025 we find $112 billion of mining capex associated with potential high- cost production.
- Non-China high-cost capex concentrated in US as well as export mines of Australia, Mozambique, Botswana, Indonesia, and South Africa.
- Exposure to high-cost capex for diversified miners, major US and Chinese coal producers, and Asian industrial conglomerates.
- Amid low returns, several large diversified miners have been selling thermal coal assetsCoal Demand-IEEFA Research Paper.
CTI’s analysis shows that in a low demand scenario the seaborne coal market will account for an average of 850 million tonnes per year over the next 20 years. Such a scenario will require production only up to a breakeven price of $75/tonne. This means mines with costs higher than this will not provide investors with a decent level of return. “We see a low demand scenario leading to a $75/tonne peak break-even price for profitable new development in seaborne markets–companies and investors need to understand their exposure to projects higher up the cost curve.”
￼The CTI analysis shows that some of the world’s biggest greenfield coal projects in Australia’s Galilee Basin are already out of the money under a low-demand scenario. In the US, the potential expansion of mines in the Powder River Basin also has challenging economics. These areas also require major investment in infrastructure to deliver production to the Pacific market, and new ports on the US West coast and adjacent to the Australian Great Barrier Reef have all faced opposition.
Given that over the next decade private-sector oil companies will invest $1.1 trillion in new upstream capex, controlling carbon asset risk ought to be a priority for stewards of capital. With falling returns and rising capital intensity (capex/barrel of production capacity), investors should scrutinize company investment plans more thoroughly than they have in the past.
To complement our recent report on carbon asset risk in the oil industry (Carbon Supply Cost Curves – Evaluating Financial Risk to Oil Capital Expenditures), this note compares projections of future oil demand under “business-as-usual” and carbon-constrained scenarios from a variety of sources.
This report recommends, to manage carbon asset risk in their portfolios, investors should engage with oil companies to advocate for incorporating such risks into their long-term demand projections and business planning.
To complement our recent report on carbon asset risk in the oil industry (Carbon Supply Cost Curves – Evaluating Financial Risk to Oil Capital Expenditures), this note examines recent trends in the upstream oil industry related to project costs, financial returns, and technical/geopolitical risks.
As the transition to a low-carbon world is likely to bring increasing structural pressure on future oil demand and prices, cost-control and capital discipline will be essential strategies for oil companies to protect shareholders from carbon asset risk. The analysis in this note is intended to further the dialogue between investors and industry on that topic.
Building on November 2013 Carbon Tracker Initiative report on Canadian oil sands, this paper specifically responds to the USDOS FSEIS findings that development of the Keystone XL (KXL) pipeline is “unlikely to significantly impact the rate of extraction in the oil sands.”
We find that FSEIS modeling does not fully explore how the lower transportation costs (relative to rail) enabled by KXL improve producer economics and hence affect future oil sands production.
On a stand-alone basis, we find all the available capacity of KXL is economic over rail costs, and this is equivalent to incremental bitumen production in 2018 of 500-525 kbpd (i.e. 25% of Canada’s total 2013 bitumen production) and more over time.
Through 2050, cumulative lifecycle greenhouse gas (GHG) emissions attributable to “KXL-enabled production” are equivalent to the annual GHG emissions from one billion passenger vehicles or the annual carbon-dioxide (CO2) emissions from 1400 coal-fired power plants. Put differently, they are nearly equal to total US CO2 emissions in 2013.
Analysts CTI: James Leaton, Reid Capalino, Luke Sussams
External Research Advisors: Mark Fulton, Mark Lewis
Ceres Clean Trillion Report
In order to limit global warming to 2 degrees Celsius and avoid
the worst effects of climate change, “…investments in low-carbon energy technologies will need to at least double, reaching $500 billion annually by 2020, and then double again to $1 trillion by 2030.”
International Energy Agency (IEA) “Energy Technology Perspectives 2012”
Authors: Mark Fulton, Reid Capalino