In the run up to COP 26 many oil and gas companies have announced ‘net-zero by 2050’ targets. However, very few companies reveal whether the prices they use to evaluate oil and gas reserves or test the value of their fixed assets for impairment[1], align with such targets or consider climate-related risks at all.

What prices might industry use to align reporting with climate targets? The industry data and analytics firm Wood Mackenzie recently published the Accelerated Energy Transition-2 or “AET-2” scenario, which identifies a pathway to limiting emissions below two degrees.[2] In AET-2, dwindling oil demand pushes future prices towards the marginal price of oil production, with gas prices remaining relatively more resilient.

Figure 1:  AET-2 scenario oil prices

WoodMac concludes that,”[t]he tantalising hope of a few more years of windfall cash flows may lead some [International Oil Companies] and [National Oil Companies] to defer action, but delay will not be a sustainable corporate strategy under the AET-2 scenario.“

Clearly, the AET-2 price deck would challenge the economics of any oil and gas company’s reserves.  If companies are considering such scenarios, they aren’t disclosing it to shareholders.  We’ve reviewed many oil and gas company annual reports and of those that disclose their value-in-use impairment assumptions (typically European and Canadian companies), none use future commodity price decks approximating the collapse in oil prices modelled by analysts such as Wood Mackenzie.

Even the lowest prices disclosed (for impairment testing) are much rosier than Mackenzie finds in its Accelerated Energy Transition-2 or “AET-2” scenario. Since companies are using more optimistic scenarios it follows that asset valuations are likely also higher than they should be as a result.  But investors want to know: what are these assets worth if the world lives up to its Paris pledges?

Chevron’s March 2021 climate report[3] offers one answer worth examining:  why not look at the value of reserves using disclosures that are required by the Securities & Exchange Commission (SEC): the so-called “standardized measure of oil and gas” (or “SMOG”)?[4]

The SMOG provides a comparable measure of the value of an oil and gas company’s proved reserves (which are a primary driver of company valuation).  The SMOG requires companies to use a common set of assumptions[5] to value the future cash flows from their proven reserves, including an average price from the last year.  The SEC recognizes that past year prices may not be consistent with reasonable estimates of future prices (and that may become a bigger problem as prices drop on the race to net-zero), but it requires the SMOG to facilitate comparability across companies by making them all use consistent, observed prices.  The calculations also require companies to include estimated costs for end-of-life asset retirement obligations (AROs).[6]  This gives investors some insight into the (net) cash flows that those proven reserves might yield under specified conditions and allows some level of comparability that would be impossible under varying company assumptions.

While some SMOG assumptions are fixed year over year (i.e., the discount rate is always 10%), prior-year commodity prices fluctuate by nature.  This means that the SMOG can provide a natural experiment to examine the value of reserves against low or high prices.

Now enter the pandemic: in 2020, companies’ SMOGs reflected pretty low oil prices– about $35/bbl for many U.S.-based oil and gas producers (compared to about $52/bbl in 2019).[7]  Those prices begin to get into the AET-2 scenario territory (Figure 1, above).

Assuming SMOG prices continued into the future, proven reserves would still generate positive cash flow, as can be seen in the second column of Figure 2 below.  But net future cash flows are only half the story.  Are they enough to recoup the remaining carrying costs (e.g., reported values for the company’s investments in property, plant and equipment)?  Are they enough to provide the return on investment (or ROCE) that investors are expecting?

Figure 2 shows that, depending on assumptions used, discounted future cash flows may be insufficient to recoup the company’s investment values. These shortfalls could be substantially bigger than the $87 billion in impairments that major oil and gas companies took in the first nine months of the pandemic.[8]  Exxon’s shortfall is 77% of the carrying value of its assets. Indeed, for a few of these companies, if these shortfalls were taken as impairments, those companies would be nearly balance-sheet insolvent (their liabilities would be the same as or greater than their assets).  This can have many adverse implications.  In some jurisdictions, a company with negative shareholder equity cannot pay dividends and even though exceptions to this exist, loan covenants my prevent companies from making such distributions.

Figure 2:  Comparing SMOG values to Upstream PPE[9]

Estimated asset recoverable amounts, which are represented by these net cash flows (excluding ARO costs) are in column 3, with the shortfall in column 4:

There are some caveats to using the SMOG for these assessments. To be clear, under both U.S. and international accounting rules, impairment[11] testing must be based on reasonable assumptions about future prices.  SMOG prices are, by definition, historic prices, and may not be the same as estimated future prices. Accounting requirements allow management to use future commodity price assumptions that they can credibly support as reasonable to their auditors[12]; thus, in a context in which prices are reasonably expected to rise in the future, future price assumptions may increase expected returns on every estimated barrel to be sold. Management can also make assumptions about the successful development and production of probable (50% or higher chance of recovery) and possible (10% chance of recovery or higher) reserves, increasing the volumes that are the basis for future cash flows.  And, management can use entity-specific discount rates, including those lower than the 10% in SMOG, giving more value to out-year volumes.

If these assumptions could have an impact on which side of the solvency line a company sits, shouldn’t investors be made aware of what they are, at the least?  And if last year’s Covid-induced average oil price is indicative of a potential net-zero carbon energy transition, shouldn’t investors have a means of understanding the difference between management’s view of the accounts and one that follows the Paris targets?

 

Written by Rob Schuwerk & Barbara Davidson.

 

[1]  Property, plant and equipment associated with oil and gas production is typically valued in corporate accounts via a discounted cash flow analysis.  This requires assumptions around future development and operational costs as well as commodity prices.

[2] https://www.naturalgasworld.com/action-to-achieve-paris-climate-goals-will-upend-oil-and-gas-markets-87375

[3] Chevron Corporation, Climate Change Resilience Report, p. 31 (Mar. 2021).

[4] See Rule 4-10 of SEC Regulation S-X. Full name: “Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves”. Also known as “present value-10” or “PV-10”.

[5] It does this by specifying a discount rate (10%) to be used in discounting cashflows, specifying a formula for determining oil prices (12-month rolling average first-day-of-month spot price), and specifying how future costs and taxes should be estimated.  For more information on the test, see this:  https://www.sprioilgas.com/blog/sec-oil-and-gas-reserve-reporting-an-in-depth-explanation.  See also FASB ASC 932: Extractive Activities—Oil and Gas No. 2010-03.

[6] Note that while AROs are cash outflows in SMOG, they would be excluded when testing assets with retirement obligations for impairment.  See ASC 360-10-35-18.

[7] See, e.g., Continental Corp. 2020 10-K (Feb. 16, 2021).

[8] See: https://www.theguardian.com/business/2020/aug/14/seven-top-oil-firms-downgrade-assets-by-87bn-in-nine-months

^[9] Information obtained from related company’s 2020 20-F filings.

^[10]  We have added the discounted ARO liability from company reports back into the SMOG discounted cash flows as a proxy for what would occur under U.S. GAAP for assets with retirement obligations that have been capitalized into the asset.  See ASC 360-10-35-18: “Estimated future cash flows related to the liability for an asset retirement obligation that has been recognized in the financial statements shall be excluded from ….[t]he discounted cash flows used to measure the asset’s fair value.”

[11] Impairment testing evaluates whether the net book value of an asset is still worth the booked amount, or whether circumstances have changed which have made it worth less, i.e., impaired.  Under U.S. GAAP, there’s a complicated two-part test:  once there is a reason to test for impairments, the company first compares the net value of the property, plant and equipment (“net PP&E”) against the undiscounted value of future net cashflows.  If those cashflows are insufficient to cover the value of the asset, it must be written down.  The write down is measured as the difference between the net PP&E and the discounted value of future net cashflows. Under IFRS requirements companies can use the same discounted value of future net cashflows to determine if there is an impairment and to calculate the impairment loss.

^[12] In Europe and Canada, these are mostly disclosed.  In the U.S., they aren’t.