Report: Big Oil Hasn’t Saved for Retirement … and It Could Cost States Billions

For the Drilled podcast, Amy Westervelt interviews the authors of a new report on the looming multi-state disaster of abandoned oil and gas wells.

by | Jun 18, 2020

GULF OF MEXICO - JULY 03: The Discoverer Enterprise drilling rig is seen as it continues the effort to recover oil from the Deepwater Horizon spill site on July 3, 2010 in the Gulf of Mexico off the Louisina coast. Millions of gallons of oil have spilled into the Gulf since the April 20 explosion on the drilling platform. (Photo by Joe Raedle/Getty Images)


The oil and gas industry is getting out of a lot of obligations these days. They have pushed for and gotten regulatory pauses, rollbacks, tax breaks, all kinds of good stuff. Although, of course, the American Petroleum Institute is still insisting that the industry is “not getting a bailout.”

One of the big ways that the industry is getting off the hook for its responsibilities is in the case of its wells and more specifically, what happens to them when they’re not producing oil or gas anymore. That is becoming an even bigger problem amidst the COVID-19 pandemic, because a lot of wells have been temporarily idled and some percentage of those will end up being abandoned altogether.

Shale gas companies are already starting to go bust in various parts of the country, and more are announcing their downfall every day. It remains to be seen whether demand will actually return to normal levels after the pandemic.

Plus, there will be an energy transition at some point. And a lot of folks are starting to wonder what will happen to these oil and gas sites once that transition gets underway. In order to get permits to drill oil or gas wells, fossil fuel companies are required to get permits. And with those permits, they have to commit to plugging and remediating well sites when they’re done with them. It’s an expensive proposition and one that the industry tends to put off as long as possible, in part because no states actually require these companies to put up the money for plugging and remediating wells before they start drilling.

A new report, out today from Carbon Tracker, finds that on top of all that, the oil and gas industry has been dramatically underestimating the cost of doing this remediation for years. The report finds, in fact, that plugging shale wells can cost up to 10 times what companies have been estimating. That’s a huge financial liability that’s not on the books of shale gas companies, which are already struggling financially for various other reasons.

Here we talk to the report’s coauthors, Greg Rogers and Rob Schuwerk, executive director of Carbon Tracker North America, about their findings.

Amy Westervelt: I was hoping you could maybe start with sort of the genesis of the report. What made you realize that this was something that we needed data on?

Rob Schuwerk: This is a combination of Greg’s longstanding interests, interest in AROs and Carbon Tracker’s focus on really the implications of the energy transition for fossil fuel companies and their investors. We started looking at how, you know, asset retirement obligations on the balance sheet were reported, how frequent they revised those estimates … we had a working thesis that Greg has largely built over the years of observation on this as to why that was the case, which was that as assets were retired, people had to revise those estimates to reflect the actual costs. And those were a lot more significant. And we took sort of that work sort of thinking about, well, in terms of an energy transition, what’s going to happen here? Are these assets all going to live their full estimated use for lives? If we can’t extract and burn all of these fossil fuels consistent with our climate targets, how are we actually really going to expect that these assets to, you know, live another 30, 40, 50 years, in some cases, you know, through to the end of the century? If you’re thinking about oil sands assets, for example. So our initial focus was actually on individual companies and what they’ve got on the balance sheets and what kind of impact there would be if we saw something called ARO acceleration. And you see a little bit on that in this paper because it’s still an important concept. But as we looked at it, we said, well, OK, there’s a great story here in the US. Let’s focus on the U.S., let’s focus on onshore and let’s look and see. You know, in addition to just looking at the corporate reported figures, which don’t really give you any of the backstory, they give you the discounted present value at some discount rate that the company has used. You don’t have the undiscounted numbers. You know, what it really costs.

But when we looked around for what things really cost, we saw a lot of claims from industry and in many cases from the regulators as well, I think in parroting some industry numbers, that were looking at, you know, tens of thousands of dollars or less to close a lot of these wells, including the one estimate from Baker Hughes that we have in there that’s focused on, you know, thirty three thousand dollars to close wells in places like the Eagle Ford with average, you know, wellbore depths, total vertical depths of like nearly 10000 feet. And looking at actual data, there was a lot of evidence to suggest that those costs were going to be far greater.

Greg Rogers: That was a big aha for me, Amy. As we were searching for actual cost data—preferably not estimates, but, you know, actual costs, what did it cost to plug and abandon these onshore wells? And it started to look like there was a self-referential loop going on between industry and state orphaned well programs that are largely funded by industry where the industry would point to the orphan well cost estimate, which was the only available cost data we could find in the United States and say, hey, we like those costs. That would seem to be ranging $5,000 to $40,000 a well. And so we’re going to reference those costs in terms of the economic analysis of shale and fracking in the U.S. onshore oil industry.

So, we had this orphan well data. But one thing that started to stand out from that is that most of those wells are old and they’re shallow. So there’s millions of undocumented wells, even pre regulatory wells in the United States. And a lot of those have found their way into orphan well programs. Some of these wells are just a few hundred feet deep and don’t even penetrate a groundwater source, so we knew that when we saw that, that the average depth, the vertical depth of the shale wells was much, much deeper, ranging from 6500 to 12000 feet of vertical depth.

And we’re wondering, well, what’s the correlation between depth and cost? And there were a few studies out there that looked at the US orphan well data suggesting there was a correlation between death and costs, but that it was linear. So just, you know, ten dollars a foot, let’s say, so it doesn’t matter whether it’s a thousand foot well or a twenty thousand foot well, it’s gonna cost ten dollars a foot.

And you had some state bonding regimes that actually incorporated a dollar per foot in determining bond values to financial assurance for the plug and abandonment costs. So that was interesting and something that obviously made depth relevant. But the most important finding came out of research of industry data outside the United States, in Australia, that indicated that the correlation between depth and cost was exponential rather than linear. And when we looked more closely at the orphan well data that was available in the US, it also seemed to support an exponential correlation rather than a linear correlation.

AW: Could you speak a little bit to how or why is it that there’s no transparency about these costs?

RS: No one has made them provide that cost information. They have no interest in providing that information, just to make that clear. So someone needs to be interested in having them do it.

And I think that really it is, you know, at the regulatory level, you’re suffering from some level of capture, which you’ll typically see when you have a regulator for a specific regulated industry.

But that was also combined with the belief that I think a lot of people have had about oil and gas and the idea that this industry may not have the money on its balance sheet today to close all of its wells immediately, but they will close over time and it will keep making money and keep drilling wells. And there’ll be cash flows in the future because we all need energy. If we’re going to have economic growth, it’s correlated with it. And so there is going to be cash in the future to close these. So why worry about it? Why worry about what the actual costs are?

The problem, of course, is all those assumptions have been completely upended by the energy transition. And then the pandemic has been sort of a shot across the bow on that to realize how quickly things can turn and potentially shut in wells. And it gives a glimpse also of the financial condition that the companies are then in. And the arguments that of course they’re going to make, which is that we can’t afford to do that now. So, I think that has kind of shaking things up. And so the question is really, should regulators still not pay attention to what these actual costs are and or will they continue to do that? That’s becoming increasingly bigger and bigger issue are most of the oil and gas industry’s history.

AW: So it’s been sort of a self-bond, self-reporting situation. And states are starting to realize, “Oh, this is potentially going to leave us holding a bill that we can’t necessarily afford to pay either.” Can you just talk about what this problem looks like for states and what some of them are trying to do about it?

GR: One of the things that’s happening is that the coronavirus pandemic has accelerated the shut shutdown of wells, which has drawn a lot of attention to this topic, and kinda shining a light on the reality that the orphan well funds are not sufficient to plug and abandoned a large number of wells that are becoming idle and non-economic at the same time. But the states first were realizing the problem they were in before the pandemic hit. And they were starting to do things like increasing bond amounts, increasing idle well fees, and tightening up on the regulatory flexibility about allowing temporary abandonment of wells. So temporary abandonment is a state when a well is shut in, but not permanently. So production has stopped, but the well is left in a state of limbo where at least in theory, it can be started back up again. So those are the types of things I think that we will see states doing.

And there’s a few other actions, but essentially they’re tightening up on the credit. And I think the easiest way to think about this is that the legal obligation to plug and abandon an oil well at the end of its economically useful life is a liability to the state. And normally when you think of a debt like this, that has financial consequences, the creditor would charge interest on that or require collateral. So, self-bonding means free credit on these liabilities. And that’s largely been the case for four decades. But what the states are doing, they can either require immediate permanent retirement of wells that have been sitting idle for a long time or they can increase the carrying costs of that outstanding debt.

AW: I feel like every day I’m seeing another news story about a shell company declaring bankruptcy or warning that it will be going bankrupt. So what is the real situation that a lot of these states are in right now? How much of this debt does it look like some states are going to be absorbing no matter what?

GR: You know, initially the parameters that are important in trying to understand a state-wide orphan well risk would include the number of wells. An average cost per well on coverage. How much security is actually in place then? Then you get into some more complex issues like the useful life of the well. I mean, do all the wells need to be plugged and abandoned now or just are some going to continue to produce for many years into the future? And then the credit risk of the operator. So to the extent that they’re self-bonding, can is the operator good for it? Will the operator remain good for it? I’ll give you just a couple of pieces of information, you know, that help fill in that framework. So just look at the number of operating and idle wells that are out there. The numbers are pretty staggering. So these are not orphan wells, pre regulatory wells, undocumented wells. These are wells that are currently out there tagged to a specific operator. And they’re either producing now or they’re in a state of temporary abandonment or shut in. Texas has over 400,000 wells. California over 100,000 wells. Pennsylvania, over 100,000 wells. Kansas, over 90,000. Ohio, over 90,000. New Mexico, over 50,000. In North Dakota, over 25,000. So one is, we’re talking about a large population of wells.

And our research is indicating that the cost to plug these wells is going to be significantly more than the orphan well cost experience. And that for the shale wells may be as much as $300,000 a well. That’s based on known evidence that we have, cost data that’s coming out of Australia.

So maybe more, maybe less than that. That’s still a pretty big number.

AW: Well it’s still about 10 times what they’ve been estimating.

GR: Yeah. So we’re talking numbers that are in the billions. For some states they’re going to be in the tens of billions.

And the exercise is going to require getting a full inventory of the wells in each state and knowing the depth of those wells because when you’re talking about an exponential correlation, depth becomes really important. But I think we can get at that and we will be able to put a rough cost estimate for statewide orphan well risk. And I think the numbers are going to be shocking to a lot of folks at a certain point.

AW: The states don’t have money to do this either. And some of this work will just be left undone. Is that something that you’re looking at and what the impact of that on, you know, communities near these wells?

RS: There are a number of different ways of thinking about the environmental impact from some from these wells. So you can think even in places where people are not nearby, you have the potential, you know, when you have improperly plugged wells or you have wells that you’re abandoned and have not been plugged, you have the potential for leakage. You have the potential for toxic emissions. You have the potential for greenhouse gas emissions and the potential to infiltrate groundwater and contaminate groundwater. But the reality is, actually, you do have situations in Colorado—there are many places in Colorado where you have wells that are literally within neighborhoods. The same is true in California, where you go to from Los Angeles to Long Beach and there are wells.

Those are often incredibly costly to close. I mean, we were talking with somebody from CalGEMS the other day about this who is responsible for that in Los Angeles. And they got to close some wells that were like 700 feet deep, something like that. So actually quite shallow. And it was over a million dollars to close it because they had to re-drill the wellbore. So the cost can be quite significant.

When we think of the $300,000 that we’re talking about here, that’s sort of an average. There’s all kinds of contingencies that could make it much more costly as well. But you have to do that because you have people that are getting sick, you know, headaches and nosebleeds. Obviously, there’s plenty of carcinogens in petroleum.

GR: The question is really who’s going to pay? So once we once we get a handle on the what’s it going to cost questions, who is actually going to pay this bill? I think you can start first and say, is it going to be industry? The orphan well funds are not even close to being up to the task of retiring all the existing producing and temporarily idled wells. And then you get into landowners and citizens. So the landowners have a lot at stake here because many of them have abandoned equipment on their land and surface contamination. It’s not what they bargained for. And so they’re just kind of left with a mess on their property. And then you’ve got citizens that can be impacted by toxics or water contamination. And then you get to the environment. There are a lot of negative consequences to abandoned and unplugged wells.

AW: I guess this is naïve, but I’m still sort of shocked at how willing states have bend to just be left holding the bag on this.

GR: We talk a little bit about that in the paper to try to make sense of how did we get here? So Rob describes the moral hazard that exists, which is quite evident when you look at it. So it begs the question, why did states do this? Why did they operate this way? And I think it’s actually pretty obvious that this was inevitable. These regulatory agencies were initially set up to protect the oil and gas resource basically to protect it so we could get as much of that hydrocarbon resource out of the ground as possible. And putting additional costs on the industry was viewed negatively because that was going to reduce the amount of oil and gas that could be extracted.

And then you add to that the dynamics of the various oil-producing states and the ability of industry to play one state against the other, creating a race to the bottom. And you still hear this kind of discussion from states that, well, if we increase the costs on industry, they’re going to withdraw from our state and go someplace else, so it’s in our financial best interest to keep their costs low.

And, you know, that makes perfect sense until you look at the liability side of the balance sheet. So as long as you’re pushing those costs off, discounting them over decades and essentially sort of out of sight, out of mind on the closure side of this issue, then the idea of reducing the bonding costs makes good economic sense.

What we’re trying to do in the paper is draw attention to that, to the liability side of the balance sheet, so that folks don’t just see the asset side and realize that there is a huge bill to pay here. And we simply haven’t planned for it because the incentives were all going in the other direction for the past hundred years.

AW: Has there been any indication of willingness from states to potentially take these things to court? I covered the climate liability cases for a long time and this sounds so similar to a lot of kind of the basis of those suits and especially the fact that, you know, we’re getting more specific costs in place here. Are you seeing any potential for liability suits that would cover the cost of damages here?

RS: You’ll know if the state is interested in doing that when they actually file a complaint. Probably not before then…

AW: Well yeah, that’s true!

RS: But the fact is, you know, are the conditions there for them? I think the answer to that is yes.

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Amy Westervelt is the editor-in-chief of Drilled News, creator and host of the Drilled podcast, and founder of the Critical Frequency podcast network, named AdWeek's Podcast Network of the Year in 2019. An award-winning print and audio journalist, Amy has contributed to The Guardian, The Wall Street Journal, and The Washington Post, as well as KQED, The California Report, Capital Public Radio, and many other outlets. She is the 2015 winner of the Rachel Carson award for "women greening journalism," and a 2016 winner of an Edward R. Murrow award for her series on the impacts of the Tesla Gigafactory in Nevada. In 2019, the Drilled podcast won the Online News Association's "Excellence in Audio Storytelling" award.