Oil and gas investors underestimated this systemic risk: the cost of plugging


Ive came to this article to delve into a boring but important oil/gas production obligation, which is increasingly becoming an implicit liability: the cost of plugging.

Author: Dwayne Purvis, PE is a reservoir engineering and management consultant based in Texas, assisting operators and investors in making prudent acquisitions and adding value, especially in difficult-to-understand reservoirs.Originally published on Oil price

When I started my career as a third-party reservoir engineer 26 years ago, the cost of plugging seemed dispensable to this newbie. Residual values ??may include abandonment costs, so they can be ignored. Any included cost becomes irrelevant through discounting, and it is very fair to assume that other people will buy assets long before they spend the money (regardless of asset retirement obligations). All of these are slowly changing, and, in my opinion, these assumptions can no longer be relied on. Decades of constant change and accumulated clogging costs have made them important, and the standard present value measure of liabilities obscures the more relevant cash flow impact.

Soon after the oil price plummeted in 1986, onshore regulators across the United States systematically relaxed requirements for timely blockades. The regulatory methods for plugging and the final legal obligation for plugging still exist, but most operators are allowed to let oil wells sit idle indefinitely. With few exceptions, idle wells have been accumulated in onshore assets for 35 years. My research shows that about half of the unplugged onshore oil wells are now idle and ready to be plugged. In half of the production, the average age is about 36 years old, and most of them are low-interest or marginal producers.

In the context of investment portfolios, the cost of plugging a single well becomes irrelevant. However, deferred costs have accumulated to the point that at the end of the oil field’s life, it is not only necessary to block the last producer, but also to block decades of temporary abandoned oil wells and lease-level shared pipelines and facilities. Changes in the value of old pipelines and equipment usually result in operators now having to plug the well with their own pockets. The cost of plugging a single well is very small, but all the uncertainties about the cost are higher than what I have experienced recently.

The operator plans to use cash flow to fund this rapidly growing liability, even if the cash flow is gradually reduced and the ARO is compounded. The reserve analysis used for these plans sometimes does include costs, but not always. The SEC’s assessment includes the cost of congestion, and asset purchasers and their sources of funding are increasingly aware of the threat of retirement costs. At this point, any buyer of the asset should be prepared to bury it.

When they do, both engineering evaluation and accounting audits use present value to measure the impact of plugging liabilities. However, the operator actually plans to cover the ever-increasing cost from cash flow. Near the end of field life, the present value of net income has declined exponentially, and then has accelerated in recent years, while the present value of liabilities has continued to increase. Towards the end of the life cycle, the coverage of the present value of the asset to the present value of the liability reversed, but the coverage of the cash flow of the liability reversed several years earlier than the present value.

To complicate matters, oil wells with low interest rates/old age are more risky than oil wells in early and middle age. They vary more with decreasing uncertainty, commodity prices, total operating costs, the allocation between fixed and variable costs, and intermittent maintenance costs. Since the age and maturity of oil well groups are often related to the assets to be acquired or even the entire investment portfolio, the cash flow from other oil wells and assets may or may not be sufficient to close the wells in accordance with statutory, contract and contract requirements. moral standard.

Decision makers in the oil industry use economic criteria such as expenditure, present value, and return on investment to measure expected cash flows—first a large investment, and then a decline in returns. The retirement scenario of modern American oil and gas fields presents the opposite, albeit on a small scale—declining inflows, and then a relatively large cost of capital—and overturning traditional economic metrics. I suggest that evaluation should provide decision makers with a new and more relevant cash-based economic measure, which I call “retention.” Its function is similar to expenditure, but in reverse-during this period, all available cash flow cannot be distributed and must be retained to fund the upcoming capital ARO.

In addition to the high concentration of idle wells and the low rate of active wells across the country, our anecdotal experience shows that some assets have direct problems. Our company’s recent large and small evaluations have found that sometimes even when predicting the remaining economic life of several decades, the project can only provide a few years of distributable cash flow, and then all the net income must be recovered as accumulated liabilities Funding. Taking into account the inherent risks of cash flow, the rebate period must be longer. In some cases, the rebate period has not yet started just because the current commodity prices are high. In other words, many assets and even some asset portfolios will need to quickly start using all net income to plug liabilities.

The old military axiom applies: “A plan failure is a plan failure.” Operators may not only rely on current production, but can avoid ARO through sales or additional development to delay and fund ARO. They may also count on price increases or ongoing workovers. These strategies involve meaningful risks and are not entirely consistent with the traditional confidence of production reserves and the certainty of liabilities. High-risk production assets may be a good business model, but another axiom applies: “Hope is not a strategy.”

The first step of the plan is to use this new retention standard to measure relatively certain liabilities, rather than ambiguously defined cash flow and time. My experience in recent years has convinced me that treating ARO clearly has now become the professional responsibility of executives, investors, lenders, and accountants who use my analysis to make strategic decisions. An alternative to a viable retirement strategy is to file for bankruptcy. The bankruptcy responsibility left to the state or landowners is not in line with public welfare, and bankruptcy is not a strategy for continued operations or any reasonably prudent operators.



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