Why It Matters If Fracking Companies Are Overestimating Their ‘Proved’ Oil and Gas Reserves

By Sharon Kelly, an attorney and freelance writer based in Philadelphia. She has reported for The New York Times, The Guardian, The Nation, National Wildlife, Earth Island Journal, and a variety of other publications. Prior to beginning freelance writing, she worked as a law clerk for the ACLU of Delaware. Originally published at DeSmogBlog .

Back in 2011, The New York Times first raised concerns about the reliability of America’s proved shale gas reserves. Proved reserves are the estimates of supplies of oil and gas that drillers tell investors they will be able to tap. The Times suggested that a recent Securities and Exchange Commission (SEC) rule change allowed drillers to potentially overbook their “proved” reserves of natural gas from shale formations, which horizontal drilling and hydraulic fracturing (“fracking”) were rapidly opening up.

“Welcome back to Alice in Wonderland,” energy analyst John E. Olson told The Times, commenting on the reliability of these reserves after the rule change. Olson, a former Merril Lynch analyst, is best known for seeing the coming Enron scandal 10 years before the infamous energy company imploded in 2000.

Today, those same rules have allowed shale drillers to boost their reserves of oil, as well as natural gas. As a result, these “proved” reserves, which investors and pipeline companies are banking on, could potentially be much less proven than they appear.

And the unprecented degree to which this is happening in the shale industry casts a shadow of doubt on the purportedly bright future of America’s booming oil and gas industry.

Rising ‘Proved Undeveloped’ Reserves

Under the updated SEC rules, which went into effect in 2009, drillers can count oil and gas from wells that won’t be drilled or fracked for up to five years as part of their proved reserves. Those as-yet-untapped wells can be put on a company’s books as a subset of their “proved” reserves, listed under the label “proved undeveloped” reserves.

And drillers can count all of the oil and gas they expect to pump out over the well’s entire lifetime — before they’ve found out how fast that well flows or seen a single drop of oil from it.

Those “proved undeveloped reserves” now make up an average of just over half of the proved oil reserves at 40 drilling companies active in shale gas basins nationwide, according to SEC filings reviewed by DeSmog. For drilling companies that are less heavily involved in shale drilling, the average mix is roughly 30 percent — similar to the industry’s average before the SEC rule change.

At Bakken shale driller Abraxas Petroleum, approximately 70 percent of oil reserves fall into the proved undeveloped category, SEC filings for 2017 show. That figure is the same for Permian basin driller Halcón Resources. For Marcellus/Utica operator Southwestern Energy, it’s a stunning 78 percent.

Forty-seven percent of the proved oil reserves in Texas’ and New Mexico’s Permian Basin — recently touted as potentially the largest oil basin in the world — now fall into the proved undeveloped category, a review of SEC filings from thirteen of the largest Permian operators reveals.

Proved reserves are the foundation of the oil industry’s assets, the gold-standard for oil supply figures.

When they book a barrel of proved reserves, companies vouch that they are at least 90 percent confident that they can produce that barrel at today’s oil prices.

And shale proved reserves are hugely important — not just for the oil markets, but for U.S.energy policy.

Shale reserves are a major part of the reason politicians like President Donald Trump now speak not just about American energy security but “energy dominance.” Lenders accept proved reserves as collateral underpinning hundreds of billions of dollars in debt. And investors use proved reserves as one of the key metrics for measuring a driller’s prospects against its peers.

Changing Rules for ‘Proved Reserves’

The old SEC rules were designed with conventional oil reserves in mind, the iconic gushers of the first oil rushes. Very roughly speaking, you could reliably estimate how much oil could be pumped from a new find once you struck oil and then did some testing to measure your find.

The hard part was finding those pools of oil to begin with. Once you did, figuring out how much was underground (and then what percentage of that could be pumped from the ground) became relatively straightforward for petroleum engineers.

But shale oil and gas are different — everyone in the industry knows where the shale rock layers containing oil and gas are. The question has become how much trapped fossil fuel can you afford to free up by using the expensive process of hydraulic fracturing to shatter that shale.

The SEC’s 2008 decision to change this rule, one of the last acts of the outgoing George W. Bush administration, scrapped the “flow test.” This long-standing requirement had obligated a company to first flow oil or gas from a well or ones nearby in the same formation before counting that well’s oil as “proved.”

But after 2009, companies were allowed to use new methods to establish oil supplies as proved, replacing the old flow test with a range of technologies, including secret proprietary methods. As long as a company considered those technologies reliably able to predict whether oil and gas could be pumped, the SEC would be satisfied.

The rule change also allowed shale drillers more freedom to assume that an as-yet-undrilled well will produce about the same amount of oil and gas as their other wells nearby.

This shift in SEC policy landed right at the dawn of the shale rush, allowing shale drillers to count oil and gas from all of the wells they planned to start flowing within the next five years as proved reserves.

It’s a setup that implicitly assumes drillers will act rationally — only making plans to drill wells from which oil can be sold profitably. But it coincided with an unprecedented journey into deep debt for the historically cash-rich oil and gas industry, which in a single decade burned through over $280 billion more than it has earned from shale oil and gas, according to the Wall Street Journal.

Regulators also considered — but ultimately rejected — a proposal that would have required third-party audits of booked reserves.

The SEC’s enforcement agents have instead focused heavily on enforcing the five-year rule, challenging companies whose numbers don’t add up.

“I believe that everyone is satisfied that the 5-year rule on PUDs will resolve any insecurity about these reserves. (I am not),” Arthur Berman, a petroleum geologist who since the very early days of shale drilling has warned about the reliability of shale reserves estimates, told DeSmog via email.

“I don’t trust the proved producing reserve numbers because I cannot replicate them on a per-well or company basis by my own technical estimates based on production history. The PUD component is, therefore, highly suspect.”

House of Cards

For years, the problem of reserves overbooking has been known in the oil industry as “the problem no one wants to talk about.”

Oil companies have plenty of reasons to present the rosiest possible picture of their future prospects, while Wall Street investment analysts often focus on short-term prospects or compare companies against their peers rather than scouting for industry-wide issues. And once a loan is made, lenders have little incentive to question whether collateral is as valuable as it was expected to be.

The SEC rule revision also aimed to provide investors with better ways to assess the uncertainty associated with oil and gas wells.

It enabled drillers to talk about a range of likely outcomes by allowing them to describe reserves as “probable” (at least 50 percent likelihood) and “possible” (at least 10 percent likelihood) to their investors, in addition to “proved” (90 percent likelihood) reserves.

By letting drillers convey a range of numbers and the levels of risk associated with them, investors would be better informed, the SEC reasoned.

The “possible” reserves category never really caught on in the industry. Instead, after the rule change the category that grew significantly, at least among shale drillers, was proved reserves — and particularly proved undeveloped reserves.

And because the rules closely link drillers’ five-year plans to the price of oil, the shale industry has already gone through one massive wave of reserves write-downs.

To be sure, if oil prices rise, drillers will have plenty of cash on hand to pay off their debts and keep production flowing. Figuring out exactly where that break-even line lies has long been the subject of heated debate.

But while many have viewed the shale industry’s tenacity during the price slump as evidence that shale can offer decades more of cheap oil, the picture that emerges on closer inspection suggests that shale drillers have struggled far more than generally understood.

In other words, American oil might be far more expensive than the relatively cheap gasoline prices of the past few years would suggest.

Oil Prices Go Down While Percentage of ‘Proved Undeveloped’ Reserves Goes Up

When oil prices collapsed from over $90 per barrel (of West Texas Intermediate crude) in 2014 to less than $50 in 2015, drillers had to write down billions of barrels of proved reserves in what Bloomberg called “a puff of accounting smoke.”

At that point, lenders faced an expensive dilemma — if they foreclosed on loans to drillers, they would have to shoulder the burden of actually drilling that oil or selling the acreage to someone who could, all in a market where oil prices had plunged.

The Oil and Gas Financial Journal took a close look at what happened next in a September 2017 article — and what they found deserves an in-depth review.

In 2015, after oil prices slumped, drillers started claiming that their as-yet-undrilled wells (those in the proved undeveloped reserves category) would have higher initial production rates and last longer, resulting in higher total production — even though nothing changed about the physical assets — which let them add proved reserves to their books, the Journal reported.

“Some of these changes may be justified, but, in many cases, reserves values were already inflated as borrowers levered up with the ultra-low interest rates to boost returns and fund the large unconventional [shale] programs prior to 2014,” reservoir engineer and finance consultant Laura Freeman wrote.

What’s worse? Instead of cracking down on companies for nudging their numbers upwards, banks turned a blind eye.

“For many companies, if not all, the changes [to proved undeveloped reserves on the books] weren’t enough to cover billions of dollars in gaps, but borrowing bases still didn’t contract,” Freeman wrote.

Banks routinely review the “borrowing base” for their loans, making sure that a loan is covered by enough collateral.

“However, despite a 75 percent contraction in oil prices from 2014 to 2016,” Freedman found, “many of these loans were not reduced in 2015, 2016, or 2017.”

She gave the example of Chesapeake Energy, one of the nation’s largest oil and gas drillers, which was heavily involved in the shale rush.

“In plain terms, in 2016 Chesapeake no longer had sufficient collateral to back its loans … but the losses associated with foreclosing were so high that the lenders cut the interest rate coverage in half” and took other steps to bail Chesapeake out. “Unfortunately, they are only one example of many in the industry and many others have a much higher draw on borrowing bases that are now not sufficiently collateralized.”

The oil and gas sector currently owes over $833 billion to lenders, a May 31 analysis by Reuters found, and nearly half of that — roughly $400 billion — is due to be paid off or refinanced by the end of 2019.

That means banks and drillers will be re-negotiating hundreds of billions of dollars in loans relatively soon.

Overbooking and Overbuilding

For pipeline companies, one of the hardest challenges is finding the balance between what their ever-optimistic customers expect to be able to pump from an oil or gas field and how much pipe they can actually afford to lay.

Shale plays are notorious for having concentrated sweet spots, where the best wells can be drilled, surrounded by larger areas that give less bang for drillers’ buck.

That’s why it caught a lot of attention when Mark Papa, ex-CEO of EOG Resources (originally Enron Oil and Gas) and founder of Centennial Resource Development, told a crowd in November 2017 that in two of the country’s biggest shale plays, North Dakota’s Bakken and Texas’ Eagle Ford, the sweet spots are already 70 percent drilled out.

And, he warned, the nation’s most prolific shale field, the Permian basin in Texas, might not be far behind.

“The Permian has the same rock quality and phase issues as the Bakken and Eagle Ford — it’s just less developed to date,” a November 16 presentation by Papa notes.

One of the biggest vulnerabilities of the revised SEC rule is that companies can predict that their as-yet-undrilled wells will be in the sweet spots, without having a full and clear understanding of exactly how big those sweet spots are (or having initial production readings to find out for sure) — and the difference between a well in a sweet spot and a well outside one can be significant.

‘We Don’t Know What We’re Doing’

For Permian pipeline builders already worried about their industry’s habit of building more pipe than needed and then struggling to pay the bills when there’s not as much oil or gas to ship as expected, questions about the reliability of proved reserves numbers add an extra layer of uncertainty to an already difficult calculus.

“If we don’t overbuild this time, it will be the first time in the history of the industry. There’s absolutely, we will overbuild, there’s no doubt about it,” Wouter van Kempen, Chairman, President, and CEO of DCP Midstream, said at an April 16 executive roundtable at the GPA Midstream 2018 Convention.

“The question is when, and by how much, and I think what you heard earlier from all of us here, none of us want to own that last gas project, none of us want to own that last pipe because those are not the ones you want to own.”

“We don’t know a lot of the time,” Bill Ordemann, Executive Vice President of Enterprise Products, added, as the executives discussed the possibility of overbuilding pipelines, according to materials from that conference provided to DeSmog.

“We don’t know what we’re doing.”

Instead, the pipeline industry has sought to pass some of the risk back to drillers through contracts that require payment even if pipes go unused, explained Terry Spencer, President and CEO of ONEOK, a natural gas infrastructure company.

That strategy puts the hot potato right back into the hands of shale drillers — and it turns out the drilling industry may be far less prepared to handle that risk than their proved reserves figures suggest.