Using Holdback to Avoid the Cash Flow Trap at Closing


*This blog is written by Dwayne Purvis for Carbon Tracker*

The dynamics of unfunded plugging liabilities have changed so much over the years that investors and auditors no longer use a proper financial lens to examine the threat. The conventional economic criterion of present value makes asset retirement obligations appear artificially remote, and the resulting standardized myopia risk creates a cash flow trap for operators and investors, which can, at in turn, entrap regulators and taxpayers. To avoid the unrecognized risk, oil companies, their partners and regulators should turn to a new financial measure, presented here as “restraint”.

Regulatory backsliding has racked up decades of unfunded abandonment liabilities

The catastrophic drop in the price of oil in 1986 seemed temporary, but under current regulations, temporary shutdowns threatened to trigger the permanent abandonment of a large number of wells. To preserve the reactivation option longer, state regulators typically changed their rules to allow wells to be monitored — instead of plugged — after two years of inactivity. It has therefore become common in financial calculations and planning to exclude asset retirement obligations (AROs) such as plugging of wells. The costs were low, distant and therefore immaterial. The leniency of regulators towards the industry has failed to predict the obvious, albeit possible, future.

Nearly 40 years later, accumulated liabilities have become more than just material. Previous Carbon Tracker Reports This is Closure hour and Billion Dollar Orphans outline the billions of dollars of exposure facing oil companies and ultimately taxpayers. In Texas, for example, the oil industry’s unfunded clog liability is estimated to be about as large as the state’s annual budget, which itself is essentially funded by a severance tax on oil and gas production instead of a state income tax. A cyclical or secular pattern of prices could simultaneously lower government revenues, increase its inherited liabilities, and then incentivize taxpayers to clean up old oil company profit centers.

Conventional financial criteria focus on the present, trap the future

Today, valuators and investors are increasingly (and rightfully but not universally) considering some form of ORA in their decisions. They usually plan to pay the costs after the end of productive life, as implied by applicable regulations, and they value this plan using conventional financial tools, namely present value and rate of return. By design, these financial criteria arrive at comparable values ​​as of today’s date by discounting end-of-life liabilities more than net revenues received earlier.

While conventional criteria are useful for gaining perspective in the present time, reducing future events to a current perspective obscures events at the other end of the timeline. If the cash flows simply fell into oblivion, it might suffice to reduce future events in this way. Instead, owners of oil and gas producing assets must come back out of pocket at the end of the asset to fund ever-growing AROs. Using the current value creates a cash flow trap. Shrinking margins must pay for rising liabilities, and funding AROs can take years or even decades of cash flow.

The current value standard obscures the reality of upside-down “assets”

To illustrate the end-of-life dynamics of an oil field, the table below characterizes the capacity of a generic well to pay the plugging costs. The first columns on the left side assume that the single sink only has to pay its own costs. On the right in the table, the columns show the effects of increasing proportions of unused wells in the same lease, so that the last producer bears the responsibility of financing the plugging of unused sister wells as well.

The sketched column uses conventional criteria: the present value of net income is divided by the present value of ARBs. This analysis suggests that liabilities outweigh assets for the first time in the last two years of productive life. Even six and seven years before the end of life, the liabilities seem to represent only about 20% of the asset value.

The next column, however, reveals the same scenario by removing present value myopia and comparing net revenue and ARO on a not updated base. The property is, in fact, financially flipped on a cash basis approximately six years before its scheduled end, although the current value still suggests the asset is secure.

Appraisers, investors and auditors are right to look at present value to understand one aspect of the situation, but it’s a simple matter of arithmetic to measure the same situation in a different way and arrive at a non-essential conclusion: Declining production and thinning margins mean net present value may remain positive for years even after liabilities exceed total future earnings.

As in this example, an operator plans by making forecasts of production, price and cost knowing that the reality of all three could turn out to be much higher or lower than he has assumed. If they analyze their projections using present value, as is universally the case, they may think they have many years before they have to worry about planning for their retirement. However, it is possible that, although the current value seems profitable, all the expected profits should rather be saved in order to have the money available to pay its debts in the longer term.

Cash flow inversion compounded by historical and continued accumulation

The next columns to the right of the table show how the financial situation deteriorates as the costs of abandonment accumulate. The fourth column of the table illustrates the situation of a field at the end of its life in which half of the open wells have already ceased production. On a large scale, although data reporting is incomplete and inconsistent, it appears that about half of the U.S. onshore disconnected wells are already shut down, and most producers are referred to as “marginal” or “stripping” wells at the end of the day. of life. For the record, I observe in practice many leases and fields where two-thirds or more of the wells opened no longer produce in paying quantities. These types of “assets” can face shutter liabilities equal to the profits of the last 10 or 20 years of production. Of course, if the earnings projections don’t hold over that time frame, investors and the public could still be challenged.

US onshore assets are already mostly near the center of the scenario chart. Going forward – assuming traders continue their current course – passing time moves their assets down the chart while warehousing more expired wells pushes assets to the right, biting both sides simultaneously only to end up being significantly underfunded.

The trap and how to see it

This is the cash flow closure trap: the owner of a mature oil or gas field may find themselves facing years of operation with little or no economic returns, little or no access to capital , and instead a significant exit risk -pocket liabilities. Worse for the planning, the closing of the trap is not gradual and smooth as the table above suggests. The inherent price, production and cost volatility can trigger the trap sooner or later than expected. They might find that many years of life remaining still cannot fund their clogging obligations.

Whatever the path to dodging this trap, strategic training begins by looking at the situation differently to see the threat: looking back from the end of life rather than forward from the present. I propose a new measure called “holdback” similar to the payment measure but in reverse: the number of years of undiscounted net income that should be “held back” to fund future undiscounted capital.

In the mechanistic table above, the period of “hold” highlighted in red ranges from years to decades, and the figure below graphically sketches the concepts. The time remaining before the holdback begins may be referred to as the “distributable life”, as the net income could flow through to investors.

However, these criteria alone cannot resolve the inherent and differential uncertainties between net revenues and the relatively fixed liabilities they should cover. “Holdback coverage” can be the ratio of undiscounted net income to undiscounted liabilities. These are the numbers reported in most of the columns above. A holdback coverage of 1.25, for example, suggests that there is more than enough money available, but it also shows that a 25% increase in the liability estimate or a 20% decrease net income would reduce the owner’s expected distributable income to zero. Yet a further step would be to look at net income discounted for risk divided by undiscounted liabilities.

Then what ?

The possibility of stranded liabilities threatens just about everyone in the value chain: operators, lenders, investors, auditors, regulators, and even the paying public. The measure of restraint offers the foresight to avoid deadly financial risk in individual acquisitions, entire portfolios, and even large pools.

For managers and auditors who use the results of reserves and economic projections like the ones I prepare, the measure of restraint raises a larger question: what does it mean for a business when projected cash flows over many years barely cover the legal obligations? Or worse, what does it mean when the projected cash flows already falls short of future commitments?

For regulators and elected officials, the shutdown trap raises a meatier question: Should regulations change, or should taxpayer voters continue to shoulder the billion-dollar gamble that corporations will voluntarily reap profits from their pockets to put cement in the ground?


To learn more about the history, need, and application of holdback, please see the original white paper.


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