By David Yager
The two most important words about inactive oil and gas wells and the industry’s legal obligation to clean up after itself are…Reclamation Certificate (RC).
The Merriam-Webster on-line dictionary definition of Holy Grail is, “something that you want very much but that is very hard to get or achieve.”
Holy Grail is a common industry reference to the elusive RC. It is formal acknowledgement from regulators that an asset has been properly decommissioned in a manner that meets provincial requirements.
The cleanup is completed. The file is closed. Off the books. Job well done. A good corporate citizen has been confirmed as such and rewarded by the Crown.
With the RC there is no further known financial obligation for that asset or its owner. This includes mineral license rentals, surface lease payments to the landowner, and municipal property taxes.
The other three important words are Asset Retirement Obligations (ARO) which are legal obligations associated with the retirement of tangible, long-lived assets, where a company must ultimately remove equipment or clean up hazardous materials from a leased site. Also called a decommissioning liability, ARO is a carried on the debt side of the balance sheet. No one has ever disputed who is responsible.
A perfect outcome for every shut down producing asset in Alberta is zero ARO because the industry has satisfactorily fulfilled its cleanup obligations and the province has issued tens of thousands of RCs.
This is what everybody supposedly aspires to, and a growing number of increasingly vocal stakeholders are demanding.
But we can’t get there from here.
Hardly a week goes by without another news story about another problem with Alberta’s ARO challenges.
Alberta has tens of thousands of suspended, non-producing wells, although this number is declining materially thanks to federal COVID job creation funds and Alberta’s $1 billion Site Reclamation Program. Because of nearly seven years of depressed commodity prices and rising costs, too many producers have gone broke and left their cleanup liabilities to the Orphan Well Association (OWA).
There have been steady complaints from landowners who are not being paid their access rental fees, also called surface lease payments. The oil company assets are still there, but not the cash.
There are repeated allegations that producers are intentionally dumping their liabilities on new owners, but that is now difficult to do.
Local governments regularly express concerns about unpaid municipal property taxes on industry assets and attempts by producers to reduce them. This is a significant political issue because so many rural municipalities have enjoyed big property tax income from oil and gas activity for decades.
These are the local problems. In the bigger picture, climate change activists claim that the world is in danger unless fossil fuels are replaced. The goal of the so-called “energy transition” is to turn oil, gas and coal into “stranded assets” – no commercial value because their products are either obsolete or illegal.
There is also talk about a “just transition” for displaced workers as Alberta’s enormous hydrocarbon reserves are turned into one giant stranded asset. Unemployed Albertans can be “justly” retrained to install solar panels on every rooftop.
None of the critics of public and private sector management of the ARO issue mention the ESG phenomenon or fossil fuel divestment. Activist institutional investors are happy to own oil stocks now that oil and gas prices are higher, but only if they increase dividends and cut back spending.
Think this through. The plan is to starve oil and gas producers for cash by any means possible. Exactly how companies are supposed to pay to clean everything up on their one-way path to insolvency should at least be acknowledged as a problem.
Alberta’s total ARO cost is hard to estimate. But the total assets to be decommissioned is not. At of the end of 2019 Alberta had over 450,000 wellbores drilled dating back to the turn of the last century (some reclaimed, most not); over 400,000 km. of pipelines; 30,000 oil batteries; 21,000 gas plants of various sizes; four refineries; five petrochemical hubs; and about 120 oil sands producing operations.
Successfully decommissioning these assets will require over half a million RCs.
The public ARO debate is more about “what” than “when” or “how”. Nobody has their head around what this all means or the method by which it will be executed. The chant by critics is “polluter pays”. Nothing else to talk about.
Alberta, which has courted and supported aggressive oil and gas development for over a century, is not seen as culpable or considered a “polluter” by allowing such massive expansion. But the public’s support is certainly measurable. The most popular premiers have been those presiding over steady economic growth driven by oil and gas development.
According to Alberta government figures, from 1971 to 2020 the province collected $242 billion in non-renewable income from land sales, coal, oil and natural gas production. Converted to 2020 dollars using the Statistics Canada Consumer Price Index, the total is $373 billion.
Plus jobs, capital expenditures, payroll taxes, corporate taxes, municipal taxes, surface lease payments, dividends, new businesses, exported goods and services and unlimited personal opportunities.
This has hardly been a one-sided transaction.
The suggestion that the oil industry has prospered at the expense of the province or Albertans is ridiculous.
What is never discussed is the rising cost of ARO in the past 30 years because of increasingly strict environmental protection and reclamation regulations. And the subsequent challenges this creates in securing a RC.
This is not new or unique to the oilpatch. Going back to the 1970s, the western world has tried to stop or reduce polluting the air, land and water. Alberta has been at the forefront in every area of oil and gas development stewardship. Few jurisdictions in the world have environmental, worker protection and community safety regulations as rigorous as Alberta.
The problem for ARO and RCs is that many of the assets requiring cleanup today were legally created in another era under far less restrictive regulations. At the same time that the industry and the province have been under severe financial pressure, there has been increased pressure to decommission more assets at greater cost despite having less cash to do it.
A few examples of new rules applied to old assets deserve explanation. In 1990 the ERCB (predecessor of the AER) introduced Directive 9 titled Casing Cementing Minimum Requirements. This required casing to be cemented on the outside below any groundwater near surface defined as “any aquifer which is a source of useable water.”
Good idea. Except that by 1990 at least 140,000 wells already existed that may or may not have met this new requirement.
To get an RC on these wells today, the owner has to demonstrate this cement exists. If not installed during drilling, this requires remedial cementing which is complicated and expensive.
Directive 20 in 2010 was titled Well Abandonment. It introduced new requirements for subsurface zonal intercommunication in an attempt to replicate the natural seals that existed before the well was drilled. It was intended “to cover all nonsaline groundwater … and to isolate or cover all porous zones.” A noble gesture, but also complex and expensive.
Directive 50 from 2012 was titled Drilling Waste Management. It effectively made the pits (often called sumps) excavated near the rig for drilling mud and flaring illegal.
Which is fine. Sumpless drilling is a great idea. Except prior thereto, over 390,000 wells had already been drilled. Today to get an RC, if there are old sumps buried on the location the owner must prove they are not contaminated. If they are, they must be excavated and replaced. The contaminated soil is trucked to a treatment facility for safe disposal and the hole filled with clean dirt.
At surface, the soil and contour of the ground must duplicate original conditions as much as possible. It includes proving that the reclaimed soil can grow grass, crops or trees to the same specifications as the undisturbed land around it. On the plains, achieving a RC can take three years or longer until you prove to regulators that the soil is safe and healthy by growing plants. In the forest, this can take seven years or longer until it is demonstrated that the trees are growing back properly.
Which is all responsible stewardship. But is can also be very expensive.
The AER has published cost guidelines outlining what developers should set aside for ARO for various assets. However, these are the basic costs and do not anticipate complex wellbore abandonments or site reclamations. Nor do they provide timelines on how long it will take from start to receipt of a RC.
Even after receipt of a RC, the regulations state that the licensee or permit holder is still responsible for remediating ARO deficiencies for 25 years and long-term contamination forever.
There are other obstacles that never make the news. Too many surface rights lessors actually never want their lessee – the oil company – to receive an RC. Because then they no longer have to pay surface rental fees. The reality is that for the amount of land involved, there is no crop that can be grown or no animal that can be grazed on that patch of land that will yield the same income as the rental fees for an access road and surface location.
The noble farmers and ranchers that regularly receive sympathetic news coverage as they tangle with big bad oil companies are not all being totally transparent. Too frequently they put their own interests first.
Rural municipalities are not enthusiastic about losing or reducing industry property taxes either. The main source of replacement tax revenue is from the voters that elect the politicians. They certainly want their cash, but they don’t necessarily want fewer industrial assets to tax.
Further, the total cost of a complex site remediation or wellbore abandonment is unknown, as is the outcome. In today’s cash-strapped oilpatch, earmarking an unknown amount of money for an ARO expenditure with an unknown end date is hard to justify. Regrettably, hard economic analysis leads to a decision to kick the can down the road and continue to pay surface leases and property taxes because at least that cost can be accurately calculated.
A company’s ARO is prepared by the accounting, engineering and operations and reviewed by independent auditors. It is a list of everything a company owns plus estimates of retirement costs and economic service life. It is discounted based on inflation and the number of years before the funds are required, then increased for the time value of money based on interest rates.
Reservoir maturity and production declines are part of the business. But the main cause of the growing number of Alberta’s suspended and orphan wells has been collapsed natural gas prices. Gas was the primary drilling target in Alberta for decades.
The Alberta government reports historical average natural gas reference prices in Canadian dollars per GJ. The price for this century is charted below.
Gas prices began to rise in the 1990s. The first big peak was in 2001 when it reached $11.21/GJ. It peaked again in 2005 at $11.38 and had one last high price spike in 2008 reaching $9.87/GJ. Although volatile, the average price in this period was over $6/GJ.
According to CAPP data, in the 20 gas-boom years from 1994 to 2014, 120,355 gas wells were drilled in Alberta, over 25% of all the wells ever drilled.
After 2008 the US shale gas drilling boom took over and permanently collapsed North American gas prices. Alberta had one brief hurrah when gas reached $5.20/GJ in February of 2014. But thereafter it has been in a death spiral until recently. It tagged bottom at $0.55/GJ in June of 2019, a 95% reduction from some of the peak prices when many of Alberta’s gas wells were drilled.
Gas producers got clobbered. Many didn’t have enough cash flow from existing production to replace reserves, service debt and maintain ARO programs. The capital providers that eagerly funded these companies for years quit returning calls. Many of the independent investment bankers would eventually disappear as well.
The result was suspended wells, delinquent surface lease payments and municipal property taxes, reduced employment, lower provincial royalties, slashed investment, reduced payroll and corporate taxes, bankruptcies and a flood of ownerless assets into the OWA.
As the cash flow and financial viability of smaller producers declined and more wells were suspended or assumed by the OWA, the response by the province was to demand they find more money for ARO. This resulted in the LLR (Licensee Liability Rating) and LMR (Liability Management Rating, financial solvency tests involving cash flow and ARO. If you were running out of cash flow because of tanking gas prices, the requirement was to produce more money for ARO.
Companies went broke. After the courts kept deciding that banks ranked ahead of ARO during bankruptcy proceedings, under the NDP government the solution was to challenge Canada’s Bank Act in the Supreme Court. The so-called “Redwater” decision in early 2019 put ARO ahead of senior secured lenders.
Shrinking credit markets got tighter. This was another major blow to the finances and solvency of Alberta’s struggling E&P sector, particularly for smaller operators without oil production and too much bank debt.
The biggest progress that has been made in almost a decade with natural gas came in 2019 following the election of the UCP under Premier Jason Kenney. His cabinet included an Associate Minister of Natural Gas with the specific assignment of dealing with stubborn low gas prices and takeaway issues. The province joined producers to press for a change in the gas tolling system for the NGTL gathering system in late 2019. Gas prices have improved materially ever since and were thankfully unaffected by the pandemic lockdown that clobbered oil in 2020.
The UCP also undertook changing the AER to make it more flexible and responsive. A new board and senior executives were put in place. Last year the province announced minimum ARO reduction commitments. The $1 billion SRP funding still being spent is significantly reducing the number of suspended wells. Separate funding to the OWA also has their well abandonment list declining.
Oil and gas prices have recovered, as have production volumes. The industry’s current financial health as measured by production, revenue and cash flow has exceeded everyone’s expectations.
However, despite the growing ARO issues of the past decade, no material changes have been made to the rising cost of complex asset decommissioning, the ability to secure a RC in a timely and cost-effective manner, or the conflicting aspirations of all the players in rural Alberta.
The elephant in the room remains how to deal with the province’s massive ARO challenge in a way that meets public expectations, is fair to the greatest number of stakeholders, and sustains continued reserve replacement and even growth in a new world where so many forces are committed to working against Alberta’s major industry.
There are many obstacles to Alberta’s ARO challenges. Credit is tighter because of the Redwater decision. The AER’s LMR calculations loom large in the ability to raise capital for many companies. Fossil fuel divestment initiatives and ESG investment criteria are discouraging the industry’s growth and impairing access to capital.
Big picture hurdles to overcome include pipeline opposition, carbon taxes, onerous regulatory approval legislation, and a highly politicized public disdain for the industry in the name of climate change.
Just last week the province of Quebec killed another promising LNG export project that would have moved western Canadian gas to international markets, ostensibly to protect the environment.
The response to meet the ARO challenges and stay in business has been requests by industry groups and various associations for government support.
The need to change the channel on the ARO issue first emerged in 2016 in a position paper from the Petroleum Services Association of Canada (which I wrote) titled, “Proposal to Accelerate Well Decommissioning, Wellsite Remediation and Environmental Protection, and Stimulate Oilfield Services Employment in Alberta.” It examined many of the ways in which new regulations had increased ARO costs over the past 30 years.
While never questioning the legal obligations of producers, it asked the province for production royalty reductions or tax credits to augment the significant cost increases to decommission legacy assets that were drilled or built to the letter of the law of the day. It modelled how the province could recover funding through payroll and fuel taxes from reclamation activity that would not otherwise exist.
To assist in securing funding, creative investment banker Ian Thomson formerly of Acumen Capital Partners invented the Resource Environmental Tax Credit (RETC), a new flow through share that would also include traditional tax write-offs for the Canadian Development Expense (CDE) and Canadian Exploration Expense (CEE).
While popular among producers and the provincial governments with oil and gas production, RETC was a federal tax matter. After four years of lobbying, the environmental aspect of RETC appeared to be wearing down the federal finance department. However, because of COVID in April of 2020 Ottawa instead announced $1.7 billion in well cleanup funding.
That Ottawa knew where to put oilpatch job money to preserve jobs in a way that was congruent with their overall climate change strategies is entirely due to many years of tireless lobbying by PSAC and the politically attractive “green” aspects of the RETC.
Other ideas have emerged. One is an initiative is called RStar (R*), the work of SAEN, a group of smaller E&P and service operators called the Sustaining Alberta’s Energy Network. It has lobbied the UCP and other stakeholders for a direct or transferable royalty credit against future production for funds spent on ARO. It is modelled after CStar – reduced royalty rates until payout which are essential to make new generation horizontal drilling and multistage fracturing plays economically viable in an era of low commodity prices and the more challenging geology of a maturing WCSB.
Other ideas include the Alberta Liabilities Disclosure Project (ALDP) which wants the government to take over producers with liabilities greater than their assets and use their production to fund their cleanup liabilities. ALDP states, “A new report…lays out how Alberta’s oil and gas companies are increasingly dining and dashing on the $40-70 billion cleanup bill for their spent wells—enabled by a complicit regulator and government.”
The Freehold Owners Association (FOA), which represents private mineral license holders, has also commented publicly. FOA rejects R* but likes some of the ideas from ALDP.
They all talk about jobs. And they all require the province do something different.
However, none of the foregoing address the many obstacles to attaining the only thing that really matters, which is the RC so the ARO on that asset can be reduced to zero.
At least on paper. The long-term reclamation obligations remains inescapable.
Dealing with this issue predictably and affordably will require the following.
- Recognition that the regulatory regime as it exists today was created over the past 120 years to build the oil and gas industry, not wind it down. Looking at the new pressures facing the business, this framework is not well suited to the realities of a mature industry with an uncertain future.
- All stakeholders should acknowledge the new and powerful forces at play in public policy and capital markets that are forcing major changes in the oil and gas business. Including putting it out of business. It is unrealistic to expect the industry to behave as it has in the past when the rest of the world views oil and gas so differently, and expectations have changed so materially.
- The province and other stakeholders must acknowledge all of the obstacles that have emerged to securing a RC and realize that unless this changes, financing and executing the remediation work resulting in the issuance of the required 500,000+ RCs in future decades will never occur. This includes reviewing regulatory processes and requirements and identifying where stakeholders are pitted against each other to the detriment of the province as a whole.
- The province should consider the issuance of Interim RCs as the asset decommissioning progresses. For example, if environmental reclamation expectations insist that it must take seven years or longer for the trees to grow back on a formerly forested site to achieve full compliance, recognition of the work already done while everyone waits for nature to take its course should be formalized.
- Once the RC is issued, the liability thereafter should be permanently transferred from the current owner to an independent entity. It would be a form of insurance funded by producers and would assume all future obligations in the unlikely event that any specific decommissioned asset becomes a future problem. When mineral licensees and asset owners see a path by which they can actually remove an ARO liability forever, interest in spending the money today to achieve a material reduction in financial liabilities tomorrow will increase. Knowing that there was a well-funded, long- term structure in place to protect the public interest decades into the future could reduce some of the obstacles to securing RCs today.
- Albertans must permit the government to move past the “polluter pay” mantra and deal with the problems as they exist today. When legacy Crown mineral licenses were sold, lessees did not envision a time when the reclamation process would be as expensive and challenging as it has become today. Or that there would a broad and growing public movement to put them out of business. Oil and gas producers and the province are partners in Alberta’s hydrocarbon prosperity, not opponents.
- Those demanding oilpatch ARO compliance should level the playing field by extending their concerns to renewable energy. Every day there are more wind and solar electricity generation assets at or near the end of their economic life. The global master plan is for many, many more. ARO for renewables should include recycling obsolete assets.
Fortunately, the world is not going out of the oil business anytime soon. Alberta is a major and useful contributor.
But the game has changed. Public policy and expectations must change with it.
David Yager is a Calgary oil service executive, writer, author and energy policy analyst. He is the President and CEO of Winterhawk Well Abandonment Ltd. He is the author of From Miracle to Menace – Alberta, A Carbon Story. More at www.miracletomenace.ca