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.
I’m not sure if anyone can answer this, but in my experience on this side of the pond it is always a requirement for any kind of drilling or mining activity for a bond (or cash) to be posted as part of the regulatory process for clean up and plugging costs. It doesn’t always work (on many occasions the bond proves to be for far too little), but it does provide an incentive to larger operators, as the bond price will rise significantly if they are in the habit of walking away from liabilities.
Oil and gas drilling does however have particular problems when it comes to plugging, as it is notoriously difficult to assess if the plugging was done correctly retrospectively. For deep wells, its not enough to just pour in come concrete and cap – you need to cap off each geological layer to ensure that migrating gas doesn’t work its way via natural fractures and end up in groundwater or to the surface. Its almost impossible to do this unless you have an operator with very meticulous logs, and that requires a lot of trust.
Another issue which is often forgotten is that a production or exploration well can be adequately plugged, but gas or oil can migrate on other forgotten wells, including those done for initial geological sampling, or even just water wells (The latter can be very deep, and are almost never adequately plugged if they are duds). The nuclear repository at Sellafield ran into huge problems when someone realised that nobody had logged whether the original boreholes used to assess the geology had been correctly sealed – they had the potential to make a supposedly impermeable geological layer impermeable (not that this changed UK policy).
PK- I can’t address the bond issue, but the Uranium mining situation on Pine Ridge Reservation is instructive. Back in the late 40s through the 60s, Uranium exploration was conducted extensively on PR, with thousands of drill holes made. Although little, if any, mining was actually done, many exploratory drill holes exposed Uranium deposits to ground water resulting in widespread radioactive contamination. The result of this drilling is that vast swathes of PR has undrinkable well water & the residents must purchase bottled water for drinking. (PR has the lowest per capita income in the US)
The oil companies know all about these sinking bonds ( money aside to fund capping) they know it and they have willfully ignored it for decades and decades – I would not be surprised if the total cost to properly cap all wells (millions of them) on land and in the golf would be far greater than a Trillion dollars or possibly far more since I did not know about the requirement to cap off each layer.
Or, because it’s Texas, oil companies will be allowed to BK and walk away. It’s not just a regulatory/cash flow issue, it’s a problem of actually enforcing those regulations on profitable companies.
If someone sees examples [rather than just happy talk] of revenue held in escrow etc. due to this, that’d be great..
The Marcellus ain’t much different (aside from directionally drilled, fracked ethane being heavier & scarier in isolated Valley communities, with only volunteer emergency personnel & Boss Hogg style governance? Kinda hard to check cement-jobs or casing 20K down, miles out, through various strata
In the great farce of capitalism, the stunt-double is always the government. Oil reserves just happen to be better than any other slick, expensive (and often useless) insurance policy against disaster. Oil is our most useful resource, hands down. We love to hate oil – it’s human nature for the addict to hate the fix. But the question is, How can we conserve oil long into the future? Because we will need it. And the answer is… the government.
When it comes to bankrupt well operators taxpayers are most often on the hook for paying to plug wells as well as associated cleanup. These costs add up to tens of billions of dollars.
The bonds may only cover the cost of plugging the production wells and not the environmental liability. I have some experience in oil response in the midwest. There were issues with dry wells that weren’t developed for production that may have contributed to shallow aquifer / surface water contamination. Even with geophysical investigations and considerable effort with excavation, we couldn’t necessarily find the cause of oil that migrated at/near the surface. I hope that the state agency would require / maintain drill records and ensure compliance for newer wells, but we all know how that goes. If there is a threat of oil discharge to an inland waterway, the EPA would have authority for clean-up. If there is a threat to a coastal waterway, it’s US Coast Guard jurisdiction. Regardless, the Oil Spill Liability Trust Fund is managed by the USCG which is funded through a tax on oil. USCG may seek cost recovery for response operations. If a landowner was compensated for the oil production when the wells were in operation, there’s a chance they may be liable. If it’s not a threat to navigable water, the state would likely manage the cleanup. State resources / enforcement authority would vary but landowners in the frac boom, may have a host of health, environmental, legal, financial issues during the frac bust.
Guess what happened to the well ExxonMobil DID plug, instead of killing the Gulf. Anybody, ANYBODY?
https://www.southernfriedscience.com/chronicle-of-a-death-forestalled-the-gulf-of-mexico-oil-spill-that-didnt-happen/ (the Q125 casing was 2 1/4″ thick & we’d thrown out ~42 of them for laps, halfway through the wall.)
In Alberta Canada we have the Orphan Well Association (OWA) which levies all producers to fund the retirement of abandoned wells. The levy is calculated by the regulator based on the producers estimated share of expected costs going forward based on modelling from historical data. The industry has generally been rather critical of this because it takes the costs up front and makes activity more expensive. A case a few years back in the Supreme Court of Canada between the regulator and a small outfit found that the Orphan Well Association is paid first before bond holders if an operator goes bust. This also made smaller producers unhappy by bringing abandonment cost forward. That said, I think OWA is good for the citizens of Alberta.