The recommendations of the taskforce will start to feed through to company disclosures, with several companies already committing to implementing them going forward. This analysis demonstrates how feasible it is to apply this kind of simple scenario analysis to produce decision useful information on the oil and gas sector, and reflects the kind of disclosure starting to be seen from leading companies.

In response to these developments, this new analysis has been developed to provide indicators of company exposure to the low-carbon transition. The approach of building up understanding of asset level data and integrating the relative economics of production options provides analysis which reflects how energy markets work, going beyond blanket approaches to allocating the carbon budget across an entire sector.

The numbers – focus on future production options

Since demonstrating the vast overhang of coal, oil and gas in the ground compared to a carbon budget to limit global warming to two degrees, Carbon Tracker has developed forward-looking indicators to understand the implications for individual companies. One of the most frequent reactions from investors is to ask who the winners and losers are under such a scenario. Whilst simple reserve and resources numbers across all fossil fuels answered the macro question of whether there was exposure to unburnable carbon, a more sophisticated approach looking at production profiles is required to differentiate at a company level.

Carbon supply cost curves

In order to try and allocate the carbon budget at a company level, Carbon Tracker developed the carbon supply cost curve approach. First this requires splitting up the fossil fuels as each has its own regional markets, primary uses, and differing greenhouse gas intensities. Not to mention that the financial position of coal, oil and gas producers is clearly not the same. For each main market for each fuel, all the potential supply options are lined up in cost order and a demand intersect consistent with the scenario being analysed is applied. The economic logic applied is that the most competitive supply sources will be produced to meet demand, based on the relative costs of the projects. The full methodology is explained in an accompanying paper.

Oil is treated as a single global market as there is sufficient trading to justify that; gas is split up into global liquefied natural gas (LNG), Europe and North America, on top of other domestic markets. A single industry database (Rystad Energy UCube) is used to provide the relative costs of production. Any company may debate the precise levels of a specific project, but costs are not generally available otherwise and would not necessarily be on a consistent objective basis. Supply costs change over time and the analysis would have to be updated to understand how the positioning of a company’s portfolio of projects is changing going forward.

The costs of any particular project may change due to a range of factors, including efforts to reduce cost by the operator through improved design, or the level of activity in the sector inflating or deflating contractor and equipment costs. Particular regions or technologies may also progress relative to others. For example, the standardisation of drilling technology has contributed towards reduced costs, especially in US shale, largely in response to the lower oil price seen in recent years. For economies heavily reliant on hydrocarbon industries, (e.g. Venezuela, Russia), the change in oil price has also impacted currency valuations, which has affected the position on the cost curve when converted to US$. The exposure of companies to excess capex in a 2D scenario will also change as they sell and acquire interests in projects, undertake M&A activity at the corporate level, and explore for new discoveries.

Scenario analysis – degrees of warming

2D reference scenario

The International Energy Agency’s (IEA) 450 scenario has been used as the 2D demand scenario, as detailed in the World Energy Outlook 2016 (WEO). The 450 scenario is consistent with a 50% chance of delivering a 2°C global warming outcome, which is then worked back to estimate a demand scenario with this result. From a climate perspective, this is not great odds of achieving this outcome, therefore the scenario should be viewed at the generous end in terms of the levels of fossil fuel demand it accommodates. Demand is taken from the latest IEA scenarios on a fuel-by-fuel basis, and by region. The 450 scenario is then compared to a business as usual scenario, which reflects identified base case potential supply in the database used. At a macro level, this is slightly higher than the IEA New Policies Scenario (NPS).

As indicated by the TCFD, applying a consistent comparable 2D scenario enables investors to understand the relative exposure of companies within a portfolio. This does not prevent companies or other stakeholders from providing analysis of other scenarios they believe are more likely or more desirable.

Paris-related scenarios

The UNFCCC Conference of the Parties (COP) in Paris at the end of 2015 brought a focus on a range of outcomes either side of the 2D scenario, including the Nationally Determined Contributions (NDCs). These plans, which focus on commitments by individual countries for 2020-30, are currently not sufficient to achieve the 2D scenario, but could be ratcheted up in review phases.

The NPS is the IEA’s modelling outcome of where the world is currently headed, and takes into account the NDCs. The IEA NPS results in a carbon budget which is equivalent to a 50% likelihood of limiting anthropogenic warming to around 2.7°C. It is worth remembering that the IEA scenarios are updated each year and the latest NPS would not present much of a test compared to current industry plans where they already largely reflect the current policy environment. Trying to identify the gap between industry plans and NPS is of limited value.

Many investors are also aware of the wording from the UNFCCC Paris COP regarding limiting anthropogenic warming to “well below 2°C”, and pursuing efforts to “limit the temperature increase to 1.5°C”. These kinds of scenarios would present a very strict carbon budget requiring instant and drastic action to curtail emissions and keep fossil fuels in the ground. The IEA and IRENA highlighted some of the challenges to achieving an outcome below two degrees of warming in a recent analysis. There are limited details on the implications of a 1.5°C scenario for fossil fuel demand, therefore it is not currently possible to analyse in the same way as the IEA 450 scenario. The latest IEA Energy Technology Perspectives 2017 has produced a scenario which delivers a 50% probability of 1.75 degrees of warming which could be used as the basis for future analysis.

Scenarios are often misrepresented. Ultimately they are one version of the future, not a prediction or forecast. Use of a particular scenario does not mean that an organisation thinks it is the most likely or that it agrees with all of the underlying assumptions. Practically speaking, to conduct this analysis, there are very few publicly available scenarios that provide the detail on fossil fuel demand necessary to model the supply requirements. The IEA scenario provides a feasible reference point which is accepted by the industry. The most advanced companies already produce a range of scenarios to inform their thinking, and the reference scenario is not intended to limit or discourage companies going beyond it.

The carbon budget

In order to allocate the carbon budget from a given scenario to the company level, it is necessary to apply a timeframe. Oil and gas carbon budgets are derived from the 2016 IEA 450 scenario for the period 2017-2035. This is then correlated with the equivalent amount of oil and gas production over this period and the amount of capex that would be required through 2025 to deliver this supply. Considering production and it’s timing, rather than just reserves data, is essential to calculating the potential impact on revenues if investors wish to integrate this thinking into Net Present Value (NPV) sensitivity tests, as demonstrated later in this report.

The oil and gas carbon budget to 2035 for CO₂ emissions based on the IEA 450 scenario is 320 GtCO₂ split 59% for oil and 41% for gas. This amount of production is then compared to the business as usual scenario from the industry database to understand how much potential production and capital expenditure is excess to requirements in this scenario. It should be noted that not all of the surplus projects will have been granted a final investment decision or are certain to go ahead at this stage. In fact, this is the benefit of this scenario analysis – there is still time to review these decisions and for shareholders to engage on the capital expenditure plans of the company. For those companies that have already decided to align with a lower demand outlook, they can confirm that they have taken those options off the table. At present there is relatively little information about the status of different projects available for investors.

The overhang of potential emissions from business-as usual oil and gas use which exceeds the IEA 450 carbon budget to 2035 is as follows:

Note: totals may not add up due to rounding. Source: Rystad Energy, CTI analysis

Carbon supply cost curves

To supply these levels of oil and gas, the most economic projects are selected – i.e. those on the left-hand side of the cost curve ordered by breakeven price. This leaves the highest cost options as those that would not need to proceed under a 2D scenario, assuming economic logic plays out. The breakeven price is the oil or gas price required to give a NPV of zero for each asset using a given discount rate or internal rate of return (IRR). In this case, we have used an IRR of 15%, illustrative of the minimum target return we see as being satisfactory for sanction given risks such as cost overruns, etc.

Global oil production is plotted on a single supply curve. Natural gas supply is split into regional markets – Europe, North America and global LNG. This means that the approach attempts to more closely replicate the regional allocation of the carbon budget, which will give a different result to combining all gas globally on the same cost curve. Domestic gas markets are assumed unchanged in a 2D scenario and account for 75 GtCO₂.

Oil carbon supply cost curve

2D capex pathway

Having calculated the oil and gas production associated with a 2D scenario, we can then identify the level of capital expenditure required, and the delta to business-as-usual, (BAU). The drop in the oil price since 2014 has curtailed capex spending from the boom times when oil prices sat above US$100/bbl. The 2D pathway would see spending need to be kept down around the current level, rather than rebounding to previous levels.

It is worth noting that capex is always required just to maintain current levels of production due to the naturally declining production rates of oil and gas wells – the exception being some oil sands projects which have a more consistent production level due to the different production techniques used. As cheaper options are used up new projects being brought on will typically be higher cost, meaning that the investment per barrel of new production keeps increasing in the long term. Underneath, longer term trends are also the cyclical movements relating to cost deflation/inflation which are caused by the prevailing level of investment activity and degree of price pressure. The recent lower oil price levels have driven a round of cost-cutting and reduced demand and prices for oil and gas service industries.

Source: Rystad Energy, CTI analysis

Gas

In total, 31% of business-as-usual gas capex is not needed in the 2D scenario – similar to the overall oil level. Domestic gas markets are assumed to continue to supply to meet demand. For the regional markets, 60% LNG, 60% North America, and 37% European capex is surplus to requirements to 2025 in a 2D scenario. This challenges the growth plans of operators in these markets.

Note: totals may not add up due to rounding. Source: Rystad Energy, CTI analysis

Exposure across different types of company

The table below indicates that around 60% of the potential capex and production that is not consistent with a 2D scenario is associated with companies in the private sector. The quarter of production that has state ownership also includes INOCs (International National Oil Companies – NOCs that have greater geographic reach) – many of which have partial listings, eg Statoil, Petrobras. Therefore there is still some capital markets exposure to these projects, even if the potential for influence is diminished. This shows that whilst NOCs have a big role in oil and gas production, they are less at risk under a lower demand scenario.

Note – unknown and unspecific not allocated to either NOC+INOCs or private sector. Source: Rystad Energy, CTI analysis

Company and project exposure

Exposure to capex outside the 2D budget varies widely throughout the curve. Companies that have a lower percentage of unneeded capex can be seen as more aligned with a 2D budget; companies with a greater percentage of unneeded capex warrant further attention from investors. Further disclosure could be requested to explain how the company is attempting to be more “future proof” by expressly cancelling or selling high-cost projects, or reconsidering its business model entirely.

For a sample universe of companies, the percentage of total potential capex that is outside the 2D budget is shown below. Percentage of upstream capex has been arranged into bands, with companies with more than a third of capex outside of 2D having higher than average exposure.

Source: Rystad Energy, CTI analysis

It is clear that some companies would have to forego the majority of their options in a 2D future, significantly impacting growth plans. Other companies are already highly resilient to this scenario, including Saudi Aramco for example. Oil sands operators generally do not perform well, which reflects the ongoing challenges to expanding production with both carbon limits and export infrastructure constraints. Shale operators are spread along the cost curve, with some positions performing better than others.

Optionality & flexibility

Discussions with oil companies indicate that there is a desire to retain a certain amount of optionality to allow flexibility depending on which future emerges, responding to possible changes in oil price. In other words, to retain some higher-cost projects as future development possibilities without committing if not warranted in the price environment at the time. This is understandable, but will only deliver a 2D aligned scenario if all companies choose not to exercise this optionality. Different types of project also offer greater flexibility. For example, US shale producers have relatively short cycle options which offer greater ability to reduce investment and lower production quickly. Conversely, major projects with high initial capital investment and long payback periods such as greenfield oil sands projects or LNG plants are more difficult to wind down and expose developers to longer periods of risk.

However, such optionality is not entirely cost free – for example, companies may have to pay fees to acquire acreage even if it is not developed, or licence terms may commit them to an exploration programme. Furthermore, companies that are encouraged by higher oil prices to press ahead with such projects run the risk of being caught out by prices deteriorating after they have committed material capital, like some of those sanctioned prior to 2014’s downturn.

Company carbon budgets equivalent to the UK

It is also worth noting how significant the production of the oil majors and NOCs are in terms of the remaining carbon budget. As context, the UK-estimated carbon budget for the period 2018-32 is 6.26 GtCO₂ according to the UK Climate Change Committee. This means that a single major company is producing enough oil and gas to use up the UK’s entire carbon budget for the period. This demonstrates the importance of investors tackling climate change by ensuring major oil companies are aligning with climate objectives.

High cost projects – examples of projects outside the 2D budget

The largest projects that are outside the 2D budget can be put forward as examples of high cost options that should not be pursued in a demand-constrained world. In this exercise, high risk projects are listed in order of capex, giving an indication of the possible financial risk of developing them. The list is limited to projects which are “new”, meaning either at the discovery stage or not yet discovered (i.e. excluding projects which are already in production or under development). Undeveloped projects have lower sunk costs, and are thus easier to cancel than projects which have already received significant capital, and would therefore require the company to write that expenditure off.

Companies may have already decided to defer or cancel some of these projects, and revisit a final investment decision in the future. This is where companies can provide transparency about which projects they see are part of their future strategy, or how they think they are aligned or not with a 2D scenario. This list highlights projects that the cost curve data indicates are not consistent with a 2D scenario – the companies are best placed to indicate where in their project pipeline a project sits. Whilst a certain degree of optionality around the marginal production point is sensible, the highest cost projects are clearly those that are most at risk in a 2D world (and indeed are highest risk and lowest return in any demand scenario).

For example, the five oil projects with the highest capex not needed outside the 2D budget are shown in the table below.

Source: Rystad Energy, CTI analysis

At the global level, some of the largest projects outside the 2D budget will be in the hands of state-owned companies, making them less transparent and moving the risks to taxpayers rather than private investors.

NPV sensitivity

A common method of valuing oil and gas projects is net present value (NPV), the sum of future free cash flows using a given discount rate (here 10%). The NPVs of a company’s 2D-compliant portfolio and its BAU portfolio can be compared to give an insight into the cost structures of the two and their relative values. As the key driver of NPV is the oil price, the values of the two portfolios can be sensitised to different oil prices, and hence relative leverage to the oil price (and hence relative volatility) can be determined. This concept was explored in Carbon Tracker’s Sense & Sensitivity report.

As most producing projects are within the 2D budget, the 2D premium (the greater value of the 2D portfolio than the BAU portfolio) particularly comes out in relation to new projects, which are the focus on this indicator. The chart shows how the 2D premium across the global oil and gas industry would be around US$1.4trn if prices average around US$60/bbl going forward at a 10% discount rate. The 2D future can therefore be positive in value terms for the oil and gas industry overall as long as it aligns with it and does not bet on high demand and prices.