Yves here. This post delves into a nerdy but important oil/gas production obligation that is increasingly acting as a hidden liability: plugging costs.
By Dwayne Purvis, P.E. is a reservoir engineering and management consultant based in Texas who assists operators and investors to make circumspect acquisitions and to increase value, especially in hard-to-understand reservoirs. Originally published at OilPrice
When I started my career as a third-party reservoir engineer twenty-six years ago, plugging costs seemed optional to this neophyte. Salvage value probably covered abandonment costs, so they could be ignored. Any included costs were made irrelevant by discounting, and it was more than fair to assume that someone else would buy the asset (without consideration for asset retirement obligations) long before the time came to spend the money. All of these have slowly changed, and, in my observation, none of those assumptions can be relied on any longer. Decades of changing and accumulating plugging costs make them significant, and standard present value measures of the liabilities obscure the more relevant cash flow implications.
Shortly after the oil price crash of 1986, onshore regulators across the U.S. systematically loosened the requirements for timely plugging. The regulatory method of plugging and the ultimate statutory obligation to plug both remained, but operators were allowed mostly to let wells sit idle indefinitely. Except for minor exceptions, idle wells have been accumulating in onshore assets now for 35 years. My research shows that about half of all unplugged onshore wells now sit idle and ready to be plugged. Of the half that are producing, the average age is about 36 years, and the large majority of those are low-rate or marginal producers.
In the context of a portfolio, plugging costs for a single well vanish into insignificance. However, deferred costs have accumulated so that the end of field life requires plugging not just the last producer but decades of temporarily abandoned wells as well as lease-level shared lines and facilities. Changes to the value of used pipe and equipment routinely cause operators now to come out of pocket for plugging wells. The single-well costs to plug individual wells have been minor, but all of the uncertainty in costs lie on the high side of what I recently experienced.
Operators plan to fund this burgeoning liability using cash flow, even as cash flow tapers and as AROs compound. The reserve analyses used for these plans do sometimes include costs, but not always. Evaluations for the Securities Exchange Commission include plugging costs, and asset buyers and their funding sources increasingly recognize the threat of retirement costs. At this point, any buyer of an asset should be prepared to bury it.
When they have done so, both engineering evaluations and accounting audits have used present values to measure the impact of plugging liabilities. However, operators actually plan to pay for the growing costs out of cash flow. Approaching the end of field life, present value of net income decreases exponentially then accelerate downward in the last few years while the present value of the liability grows without fail. Near the end of life, the coverage of asset present value to liability present value inverts, but the cash flow coverage of the liabilities inverts years earlier than present value does.
To compound matters, low-rate/late-life wells present more risk than early- and mid-life ones. They vary much more with decline uncertainty, commodity prices, total operating costs, split between fixed and variable costs, and intermittent repair costs. Since the age and maturity of groups of wells tends to be correlated within an asset to be acquired or even within an entire portfolio, cash flows from other wells and assets may or may not be sufficient to plug wells as required by statutory, contractual, and ethical standards.
Decision-makers in the oil industry use economic yardsticks such as payout, present value and return on investment to measure expected cash flows — first, large investments and then declining returns. The end-of-life scenario for modern U.S. oil and gas fields presents the opposite situation though at a smaller scale — declining inflows then relatively large capital costs— and upends traditional economic yardsticks. I propose that evaluations should inform decision-makers with a new and more relevant cash-based economic yardstick that I call “holdback.” It functions like payout but in reverse – period during which all available cash flow cannot be distributed and must be held back to fund impending capital AROs.
Aside from high concentration of idled wells and the low rates of active wells nationally, our anecdotal experience suggests immediate issues with some assets. Both small and large evaluations made recently by my firm have found that, sometimes even when projecting decades of remaining economic life, projects can offer only a few years of distributable cash flow before all net income must be held back to fund the accumulated liabilities. Accounting for the inherent risk in the cash flows, the holdback period must be longer, and in some cases the holdback period has not yet begun only because of the current high commodity prices. That is to say, many assets and even some portfolios of assets will need shortly to begin dedicating all net income to plugging liabilities.
The old military axiom applies: “A failure to plan is a plan to fail.” Instead of relying solely on current production, operators may gamble on a sale to avoid ARO or on additional development to delay and to fund AROs. They may also count on increased prices or on-going well repair work. These gambits involve meaningful risks not entirely consistent with the traditional confidence of producing reserves nor with the certainty of the liabilities. High-risk producing assets can be a good business model, but another axiom applies: “Hope is not a strategy.”
The first step to planning is to use this new holdback yardstick to gauge the relatively certain liability against less well-defined cash flow and timing. My experience over recent years leads me to the conviction that treating AROs explicitly has now become a professional duty to the executives, investors, lenders, and accountants who use my analyses for strategic decisions. The alternative to a viable retirement strategy is filing bankruptcy. A bankrupt liability left for the state or for landowners does not serve the public welfare, and bankruptcy is no strategy for a going concern or for any reasonably prudent operator.