Industry-funded orphan well programs are barely a drop in the bucket, as these are typically funded to close less than 100 wells per year.  See Interstate Oil & Gas Compact Commission, Idle and Orphan Oil and Gas Wells (2019).  Moreover, many wells that are inactive aren’t even counted in orphan well programs—this gives the false impression that the problem is well in hand. In 2018, state orphan well programs plugged 2,377 of 56,600 documented orphan wells.  At this pace, it would take another 23 years just to plug the remaining documented orphan wells.  By comparison, at this pace, it would take state orphan well programs 1,600 years to plug the nation’s 3.8 million unplugged wells should they inherit this liability. For more information, see Billion Dollar Orphans.

Financial accounting standards require oil and gas companies to disclose the fair value of assets that are legally restricted for purposes of settling asset retirement obligations.  To our knowledge, no oil and gas companies report doing so.  As a general rule, they don’t set aside funds because they are not required to do so.

Oil and gas companies account for upstream decommissioning obligations, but it is hard to tell how accurately they account for them. They generally do not report liabilities for midstream and downstream decommissioning obligations. Oil and gas companies must recognize a liability for an asset retirement obligation (AROs) in the period in which it is incurred if a reasonable estimate of fair value can be made. All upstream oil and gas companies report liabilities for estimated well plugging costs. These estimates do not include costs for remediation, which companies believe cannot be reasonably estimated. Recognized liabilities are discounted at credit-adjusted interest rates. Companies with poor credit ratings that are more likely to default on well plugging obligations thus report relatively lower liability estimates than companies with strong credit ratings. The industry asserts that it is not possible to reasonably estimate the timing of midstream and downstream decommissioning obligations and that for this reason a reasonable estimate of fair value cannot be made.

S&P considers tax-adjusted asset retirement obligations (AROs) in its credit rating analysis. S&P does not consider the possibility that well plugging costs may come sooner or cost more than companies estimate. Moody’s and Fitch do not consider AROs at all.

It depends; the safest thing to do is require full bonding and avoid the bankruptcy process altogether. Regulators can recover plugging costs from the bankruptcy estate if funds remain after repayment of secured creditors, or if a court grants “administrative priority” to the closing costs. Regulators may also be able to demand additional financial assurance as a condition of approving sales and related license transfers in bankruptcy. The best and safest remedy for states is to require full bonding before companies enter bankruptcy, thereby allowing them to collect from the surety outside of the bankruptcy process.

States protect their taxpayers, citizens, and surface rights owners by requiring operators to provide financial assurance, usually in the form of surety bonds — just like a mortgage lender might require private mortgage insurance.

Blanket bonds provide a fixed amount of security for the plugging and remediation obligations of an unlimited number of wells operated by a single company. For example, a $25,000 blanket bond covers all of an operator’s wells on BLM lands in a single state, and a $150,000 blanket bond covers all of an operator’s BLM wells nationwide. Blanket bonds are a concern to taxpayers because they reduce the average bond amount per well, thereby increasing orphan well risk and because they allow a build-up of unplugged inactive wells. See The Moral Hazard of Blanket Bonds.

Plugging costs that are not covered by surety bonds are unsecured, or “self-bonded”. Regulators must rely entirely upon the continued financial solvency of oil and gas companies to fulfil self-bonded plugging obligations.

Small operators pose a more immediate orphan well risk. As the US and the world transition to a low carbon economy, even the largest oil and gas companies may pose an orphan well risk. Large operators of stripper wells pose a particular orphan well risk.

State and federal regulations generally require that well must be plugged when they are determined to be incapable of producing oil or gas and have no other future beneficial use.

Stripper wells are producing wells with average daily oil and gas production less than 15 barrels of oil or 90 mcf of natural gas. Stripper wells accounted for 10% of US oil production in 2015. We estimate it will cost $88 billion to plug 700,000 stripper wells in the US. The closure liabilities for these wells likely exceed their productive value.

According to the Canadian Association of Petroleum Producers, the average productive lifespan of an onshore oil or natural gas well is 20 to 30 years.

The cost to plug a well can vary from a few thousand dollars to over a million dollars. We estimate that the cost to plug a typical 10,000-foot vertical shale well is $300,000.

Plugging addresses potential downhole groundwater pollution and fugitive emissions of greenhouse gases and toxics to the air. Remediation addresses the contamination of land and surface water. All oil and gas wells must be plugged. Only some wells will require remediation.

The primary factor affecting plugging costs for all oil and gas wells is well depth. Other well-specific factors, such as well age, proximity to population centres, and borehole and casing damage, can also significantly influence plugging costs for a given well.

Accurate cost estimates are necessary for regulators to set appropriate bond amounts and for oil and gas companies to report accurate well plugging liabilities in their financial statements.

On average, plugging costs increase with depth. Modern shale wells are deep, averaging 10,000 feet in many basins. Newer wells tend to be much deeper than older wells. Also, according to the National Petroleum Council (NPC), horizontal shale wells, and particularly shale-gas wells, pose technical plugging challenges that may increase costs.

A typical shale well is much deeper than a typical orphan well. Industry reports that a typical orphan well costs $30,000 to plug. We estimate the cost to plug a typical shale well is $300,000.

The oil and gas data provider, Enverus, lists 2.6 million unplugged onshore wells in the US. The US EPA estimates that there are another 1.2 million undocumented unplugged onshore wells that aren’t in the Enverus database.

Absent special operational considerations, when bond amounts are lower than estimated plugging and remediation costs, it’s always in the operator’s financial interest to delay permanent abandonment of wells as long as possible, often by selling late-life and marginal assets to weaker companies.

Oil and gas companies argue that inactive wells may have future beneficial use that would be forfeited by permanent plugging. This potential future benefit is offset by the environmental risks posed by inactive wells and the risk that these wells will eventually be orphaned.

Data on well reactivation rates is currently limited. In 2018, California reported that the status of 107 idle wells (out of a total of 29,292) changed from idle to active. This amounts to an annual reactivation rate of 0.3%.

Very big. We estimate that plugging 2.6 million documented onshore wells in the US will cost $280 billion. This estimate excludes costs to plug an additional estimated 1.2 million undocumented onshore wells.

Orphan well risk increases as oil and gas production levels fall and the timespan of inactivity increases. The less financial penalty an operator suffers by orphaning a well, the more likely the well will be orphaned.

Covid-19 has temporarily shut-in tens of thousands of producing wells, and the energy transition may prevent the reactivation of these and hundreds of thousands more idle wells. The industry’s asset retirement obligations (AROs) – the accounting term for plugging liabilities – are accelerating, putting additional pressure on distressed corporate balance sheets.

The oil and gas industry’s ability to satisfy its obligations as they come due is uncertain. Regulators can address this uncertainty by requiring full bonding.

State and federal regulations require oil and gas operators to secure a surety bond to guarantee compliance with reclamation requirements. The surety bond is provided by a private insurer, which requires annual premiums and some collateral in return for the bond. When a well is plugged and meets the state’s closure conditions, the regulator will no longer require a bond and will release it back to the surety that issued it. If the operator fails to perform reclamation in a timely and proper fashion, the bond is forfeited, the surety pays the money to the regulator, and then obtains a claim for that amount against the operator. Sureties are only liable to regulators up to the face value of the amount of the bond. Inactive wells become orphaned when an operator fails to perform reclamation, the bond is insufficient to cover reclamation expenses, and there are no other responsible or liable parties to do so.

Operators with good credit pay on average an annual premium equal to 1% of the face amount of the bond, with no collateral. For example, the annual premium for a $100,000 blanket bond would be $1,000.

The US Government Accountability Office (GAO) found in 2019 that BLM bonds do not provide sufficient financial assurance to prevent orphaned wells. See GAO-18-250. Our research shows that states are equally under bonded.

Yes. Plugging and remediation costs are deductible from taxable income at the time the work is performed.

Yes. The law universally requires that oil and gas companies pay for well plugging in accordance with the “polluter pays” principle. Low bonding increases orphan well risk to states and the federal government, effectively shifting risk from industry to the public. This is a form of economic subsidy that benefits the fossil fuel industry to the detriment of alternative sources of energy.

State and federal onshore oil and gas regulators generally do not monitor the financial condition of operators to periodically assess orphan well risk. Surety bond providers may monitor the financial condition of operators and might make adjustments by, for example, requiring increased collateral amounts for less credit-worthy operators.

State and federal oil and gas regulators generally do not consider the financial condition of buyers in the sale or transfer of unplugged wells. Consequently and unlike private lenders, oil and gas regulators do not impose more stringent requirements on less credit-worthy operators. A notable exception is the State of Alaska, which commissioned an independent assessment of Hilcorp’s ability to assume BP’s decommissioning obligations in connection with Hilcorp’s proposed acquisition of BP’s oil and gas assets in the state.

The Energy Policy Act of 2005 directs the Department of Interior to establish a program to provide for the identification and recovery of reclamation costs from persons or other entities currently providing a bond or other financial assurance for an oil or gas well that is orphaned, abandoned, or idled. See GAO-18-250. Prior operators are generally not financially responsible for plugging costs under state laws. California is a notable exception. Under California law, the state can pursue previous operators as far back as January 1, 1996, to recover the cost to plug wells and decommissioning deserted production facilities. See California Public Resources Code - PRC § 3237.

Only the current (and sometimes former) operators of oil and gas wells are legally responsible for plugging them. Lenders could become financially responsible if they foreclose on oilfield assets held as security and become operators.

The cost and affordability of full bonding is not fully understood. However, bonds provided by private insurers should, in theory, reflect the risk that operators might default on their obligations. If operators cannot afford full bonding, the economic viability of domestic oil and gas production would be called into question.

Some operators have argued that higher bond coverage would result in lower production. The true impact of increased bonding costs on marginal profitability must be determined on a case-by-case basis. It may be the case that some domestic production would not be profitable if full bonding were required.

Low bonding would incentivize less plugging activity by operators and therefore a transfer of that liability to state and federal government. Whether national energy concerns justify such a transfer is a policy question for lawmakers. However, the intentional use of low bonding clearly constitutes a subsidy to industry.

Bonds ensure that the state is not on the hook if the operator defaults. The value of reclamation bonds to governments and taxpayers can be calculated in financial terms. It increases as the risk of operator default increases.

Relaxing bond requirements when oil prices are low is equivalent to a bank releasing collateral when a borrower experiences financial stress.

Oil and gas companies may seek to evade liability for plugging and remediating wells in several ways, including – (1) obtaining regulatory approval to temporarily abandon inactive wells; (2) using state idle well programs that allow wells to remain unplugged indefinitely subject to payment of fees and periodic inspections; (3) selling inactive and marginal wells (often to smaller companies); (4) filing bankruptcy; and (5) using federal government funds to plug wells (see Wyoming to help petroleum industry with coronavirus funding).

As a predictable result of the moral hazard created by regulators, inventories of largely self-bonded idle and orphan wells are exploding. For example, the count of idle wells in California has increased from just over 20,000 idle wells in 2015 to nearly 35,000 wells in 2020. This trend will only accelerate as the industry’s state of permanent decline continues.

Not necessarily. Idle well programs are ostensibly to protect public safety and the environment from the potential threats posed by idle wells. Regulations may require idle wells to be tested and, if necessary, repaired, or permanently sealed and closed, and may impose fees and higher bond amounts on operators to reflect the potential costs associated with those wells.  See, for example, California’s idle well program.  By allowing idle wells to remain unplugged for longer periods, perhaps indefinitely, idle well programs increase the probability that idle wells will eventually become orphans. Also, operators are known to game the system to maintain “active” status for unproductive wells by selling past production from leasehold tank inventory or by “swabbing” the well to extract and sell a small amount of fluid product each year.  This both defers plugging costs and avoids added fees and bonding requirements for inactive wells.  See Colorado Financial Assurance Technical Working Group Final Report (2018).

Well status categories differ across jurisdictions.  BLM defines abandoned wells as wells that have been properly plugged and have had final reclamation completed but have not been approved by the surface managing agency or wells that have been properly plugged but have not completed final reclamation. An idle well is a well that has been inactive for at least 7 years and has no anticipated beneficial use during the well’s lease term.  Shut-in wells are physically and mechanically capable of producing oil or gas in paying quantities or capable of service use. For example, an operator may put a well in shut-in status if it has not been connected to a sales line or it is not economical to connect to the line. Temporarily abandoned wells are another type of inactive well that is not physically or mechanically capable of producing oil or gas in paying quantities but that may have value for a future use.  See GAO-18-250.

One indicator of orphan well risk is bond coverage. Bond coverage, the ratio of active bonds to estimates plugging costs, is almost universally low, but some states have higher bond coverage than others. For example, Alaska recently increased its single well bonding amount to $400,000. North Dakota recently added limits on blanket bonds for wells idle more than 7 years and increased its single well bonding amount for inactive wells to $180,000.

We are currently working on a methodology to quantitatively assess and rank the effectiveness of state plugging programs in protecting taxpayers, citizens and surface owners from the financial and environmental costs of orphan wells.

The Moving Forward Act now working through the US Congress calls for BLM bonding reform and proposes setting aside funds to pay for orphaned wells. The program would give priority to States and Tribes that require companies to provide financial assurances prior to drilling a well equal to the estimated full cost of well closure and land remediation. In other words, the Act would prioritize grants based on bond coverage.

States are not legally obligated to plug orphan wells.  But as a practical matter, federal and state regulators consider oil and gas wells as potential liabilities because they may have to pay for reclamation if the well operator fails to do so.  See GAO-18-250.

According to the BLM, inactive wells have the potential to create physical and environmental hazards if operators fail to reclaim the well sites, which may involve plugging the well, removing structures, and reshaping and revegetating the land around the wells (i.e., returning well sites as close to their original natural conditions as reasonably practical). For example, inactive wells that are not plugged or not properly plugged can leak methane or toxics and contaminate surface water and groundwater.  See GAO-18-250.

Leaking methane, which contributes to climate change, is only one pollution pathway for unplugged wells.  Inactive wells that are not plugged or not properly plugged can also contaminate surface water and groundwater.  See GAO-18-250.  In addition, wells that are not leaking today may leak in the future due to exposure to the elements or changes in subsurface conditions.  Finally, aged, unplugged wells pose a problem when encroached upon by sensitive receptors (for example, through ex-urban land development).