14th December 2015
Two topics have had more than their usual shares of attention this year: Redeterminations and Impairments. 2016 seems set to be even more challenging for both.
Redeterminations and Impairments are two different things, governed by separate standards and requirements.
Redeterminations are commercially driven and follow discretionary criteria established by lenders.
Impairments are standard driven and follow international accounting rules and country specific regulatory reporting requirements.
While impacted by the same driver, current hydrocarbon prices are not the only factor that affects Redeterminations and Impairments. This article looks at the degree to which judgment can influence Redetermination and Impairment decisions and the impact these decisions may have on future industry activity.
First, a word on Reserves. The most widely used global standard for reserves and resource determination is defined in the Petroleum Resources Management System (PRMS) http://www.spe.org/industry/reserves.php. This system has been developed by and has the endorsement of international technical oranizations, including SPE International, AAPG, the World Petroleum Council, SPEE and SEG.
Regulatory authorities in some countries have established reserve reporting definitions and criteria that are similar but not identical to the PRMS standards. A notable example is the Securities and Exchange Commission (SEC), which defines a specific methodology for determining the oil price to be used in reserve determinations, whereas PRMS allows some discretion on this point. Key differences in the PRMS standards (most often used in relation to borrowing base determinations) and SEC standards (used by companies listed in the US for reporting reserves and Impairments) are summarized in the following table.
The PRMS framework provides for the classification of reserves and resources based on an assessment of the commercial risks and the technical uncertainties associated with a hydrocarbon project. While technical factors (uncertainty in future production volumes) determine whether reserves are categorized as proved, probable or possible, several (mostly) objective criteria govern whether volumes may be classified as reserves in the first place. “Commerciality” is a necessary condition in order for any volume to be classified as reserves, but economic viability alone is not sufficient to meet the commerciality standard. Commerciality requires several criteria to be met, including a reasonable certainty that there is a plan for the necessary expenditures to be made to allow undeveloped volumes to be brought on stream in a reasonable time frame (typically within 5 years).
With a reported US$200 billion plus of delayed, deferred or abandoned projects around the world, some of which may economically still be viable, that is a lot of what, last year, might have been reserves that this year might no longer be so.
Redeterminations of company borrowing bases are typically evaluated twice a year; in the Spring and in the Fall. Redeterminations are, in essence, judgment calls made by lenders regarding the estimated economic value of an assessment of future hydrocarbon production. A project-specific assessment of recoverable volumes is used to generate a production and cash flow schedule based on the contractual rights and obligations associated with the project. A portion of that cash flow schedule is then considered when the lender establishes the customer’s borrowing base.
Lenders must use judgment to forecast the prices, costs and the investment hurdle rates they will apply in their redetermination evaluation; and judgments on these factor may vary been lenders. Similarly, lenders can use judgment to determine the degree of economic value they will assign to reserves sub-classes. Proved Developed Reserves obviously qualify for the highest degree of economic certainty. Proved Undeveloped Reserves are typically discounted and, in North America, Probable and Possible reserves are typically excluded from borrowing base determinations. However, there are no global standards on discount rates or reserve sub-class exclusions and in some regions (Asia-Pacific for example) a discounted value of Probable reserves may also be included. In deciding on the borrowing base, lenders may also use judgment to determine how long a period of operations they will include in their forward cashflow projections. In a volatile price environment, periods considered will be shorter unless hedging is used to provide longer-term stability in product pricing.
When commercial or technical conditions change materially, redeterminations are required. These redeterminations impact the asset holder’s borrowing base, affecting liquidity and the company’s near-term operating ability. When redeterminations are negative, companies may be forced to respond by cutting budgets and near-term work programs.
Impairments of the value of a company’s reserves are typically reviewed quarterly, although they may be required any time a material negative change occurs. Declining (long-term) petroleum prices, significant downward reserve revisions or changes in fiscal, operational or political factors can trigger Impairment. There are differences between the International Financial Reporting Standards (over 100 countries have adopted IFRS) and US GAAP rules related to Impairments, so a company’s basis for accounting is an important factor. It is beyond the scope of this article to describe all of the differences between IFRS and US GAAP, but Impairment test triggers, the level (grouping of assets) and the measurement of and/or reversal of Impairment charges are all areas where differences exist .
Impairments impact the asset holder’s stated capital, thereby indirectly affecting stock price and the company’s ability to raise capital for long-term programs. Impairments may therefore result in a company’s decision to reallocate available capital to core assets, leading to disposal of non-core assets.
For companies listed in the United States, Securities and Exchange Commission (SEC) guidelines (https://www.sec.gov/rules/final/2009/33-8995fr.pdf) also provide guidelines for when Impairments must be reported. The SEC rules provide for little discretion by the evaluator in forecasting the pricing and technologies that can be applied and the categorization of reserves that may be considered.
Spring 2015: We “Wait” Four months into the price decline and no-one was really sure how low the oil price would go or how long it would stay low. Lenders used their discretion to avoid significant redeterminations. Companies, following SEC guidelines requiring the use of 12-month historical average price (counter-intuitively, at December 31, 2014 it was actually very close to US$ 100 per barrel), avoided declaring impairments. The Bid/Ask spread began to widen and M&A deal flow slowed.
Fall 2015: We “See” Prices had fallen below half of the prior year level and, following the false dawn in the middle of the year, many now forecast that prices will remain low for 2-5 years. Although reluctant to force restructuring, lenders could no longer avoid redeterminations and it is reported that the borrowing bases of up to 75% of all E&P companies were negatively affected . Similarly, with the 12-month historical price now at a much lower level at around US$60 per barrel, third quarter 2015 impairments increased 79% compared to second quarter 2015 . Many E&P stock prices fell precipitously. The Bid/Ask spread remained wide, but distressed asset sales began to occur.
Spring 2016: And Then What? We know activity levels will be low. Most 2016 budgets have already been set below 2015’s depressed levels. The SEC WTI mandated oil price will be around US$50 per barrel; potentially quite a ray of sunshine at a time when the price has just fallen through US$40 per barrel, and may yet test further lows in the coming weeks. However, while the higher price may help color the economics, a company must still maintain its activity plans in the face of lower realized prices and corporate cash flow constraints if it wishes to book the volumes as reserves.
In the face of all this, will the freeze that has limited M&A activity begin to thaw as companies seek to realize cash flow other than from production? GCA believes it will.
GCA’s unconventional play database and modeling reveals significant economic differences between Operators and fairways within plays. For example, the model indicates that at a $40 per barrel oil price, only two out of the ten major operators in the Eagle Ford are making a profit on their average new drill wells. The majority of the Eagle Ford producers need a WTI price over $50 per barrel to breakeven at current drilling program costs, and for every above-average well there is a below-average well that requires a higher price still to recover its costs.
Q1 2016 Redeterminations and Impairments are likely to further weaken the borrowing bases of companies and their ability to raise capital for future drilling; and this time, lenders will be more inclined to also press for restructuring and asset sales to improve balance sheets. GCA expects the Bid/Ask spread to narrow as companies face the reality of a prolonged period of low prices; and private equity, which previously supported drilling programs, will increasingly be deployed for predatory acquisitions.
- GCA Oil & Gas Monitor
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- Asia-Pacific & China
- Middle East
- Russia & Caspian
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