Canadians Should Be on Red Alert over Alberta Redwater Energy Case

By Regan Boychuk

It’s time for Albertans to wake up! Alberta’s Energy Regulator estimates our oilpatch has accumulated $260 billion in unfunded cleanup liabilities.

It’s time for Albertans to wake up! Alberta’s energy regulator estimates our oilpatch has accumulated $260 billion in unfunded cleanup liabilities. [1]

If the Supreme Court of Canada affirms the Alberta courts’ sweeping interpretation of federal bankruptcy law in the Redwater Energy case, every polluter in Canada will be welcome to walk away in bankruptcy from the mess they have created too.

It’s not entirely accurate to say Alberta’s oilpatch hasnever been held accountable for cleaning up the mess it profited from. During a century of development, the province’s oil and gas corporations were held responsible for a year and a half. That was a generation ago.

In June 1991, the Alberta Court of Appeal ruled unanimously in the Northern Badger case that “abandonment of oil and gas wells is part of the general law of Alberta enacted to protect the environment and for the health and safety of all citizens.” Those regulations bound all who became licensees of oil and gas wells,even in bankruptcy, the court ruled. [2]

The Northern Badger case hinged on the question of whether regulatory orders to do cleanup work should be treated as unsecured debts that could be compromised in bankruptcy. Alberta’s Court of Queen’s Bench had decided environmental cleanup took a back seat to lenders. “This was incorrect,” legal scholar Dianne Saxe wrote at the time in theWindsor Review of Legal and Social Issues.

The logical conclusion of that decision by Justice Jack MacPherson of the Court of Queen’s Bench would have been that a trustee in bankruptcy could ignore all provincial statutes if they could save money that could repay the debts of lenders. Ms. Saxe wrote this could include “dumping hazardous waste in a school yard if that were cheaper than using licensed disposal sites as required by provincial legislation.” Fortunately, she noted, Justice MacPherson’s decision was reversed on appeal. [3]

After Northern Badger, the banking industry accepted the credit risk of enabling polluters and oil executives suddenly worried they were potentially on the hook for the cost of cleanup. [4] The impact was dramatic.It became inconceivable for lenders not to do an environmental audit before issuing new loans. Banks policed clients with diligence—regular pollution checks and in-depth investigations at any hint of trouble, theCalgary Herald reported in January 1992. [5]

That all ended when Ralph Klein became premier in December 1992, closing the oilpatch’s brief 18-month window of accountability. The province’s power to make the polluter pay was traded away by his government for what became the Orphan Well Association (OWA).

The largely industry-funded OWA has so far cleaned up about 700 sites. Another quarter-million wells have been drilled since Mr. Klein was sworn in as premier. There is virtually no funding set aside for the cleanup of those additional wells.

So the public will ultimately be on the hook for the environmental consequences of the oilpatch’s profit. [6] This is what makes the Redwater Energy case currently before the Supreme Court of Canada so important to Canadians, wherever they live in Canada.

In lower court, Alberta Chief Justice Neil Wittmann took the view—which would certainly seem peculiar to lay people—that banks that lent millions without regard to cleanup liabilities were innocent third parties in bankruptcy and that polluting oil and gas companies were part of the public, so it would be no great injustice if taxpayers were left to fund cleanup while banks liquidated everything of value for themselves. [7]

Regardless of the potential consequences, Alberta’s appeal court confirmed the now-retired chief justice’s ruling in a split decision, arguing, “The result … is not that the Alberta Energy Regulator cannot regulate end-of-life obligations, it just means the Regulator must not wait until an event of insolvency before doing so.” [8]

But Alberta energy regulators have always based their management of end-of-life obligations on having control of revenue after insolvency to fund the cleanup,à la Northern Badger. [9]

It may not yet be obvious to Albertans and other Canadians, but changing the rules this near to the end of the oil-and-gas game creates a crisis. And not just for Alberta.

There is nothing specific to Alberta or oil and gas about the implications of the courts’ current interpretation of bankruptcy law. Every factory, mine and pulp mill across the country will have a perverse incentive to run the company into the ground to escape the environmental consequences of their profit.

The industry-aligned C.D. Howe Institute did the debate on these critical issues a disservice with its September 2017 report, which in the view of many experts seriously downplayed the scale of the liabilities threatening taxpayers.

The report, entitled All’s Well that Ends Well, credited the OWA as the source for the authors’ reclamation estimates. The report cited, however, actually put the cost 15 times higher than the figure the C.D. Howe Institute used for its partial tally of well liabilities. [10]

The high-end estimate of the risk to taxpayers isn’t $8.6 billion, as suggested by the C.D. Howe report, but well north of $100 billion. [11]

Add in the cleanup related to oilsands sites, pipelines, processing facilities and other contaminated areas, and you get the Energy Regulator’s $260 billion estimate—which many experts also think is low.

Because lenders and investors have been carrying on as if no one ever has to clean up, [12] the Supreme Court’sRedwater decision will have a huge impact either way it goes.

There is no easy solution, but Canadians and Albertans need a serious and informed debate about our options.

Regan Boychuk is an independent researcher in Calgary and part of ReclaimAlberta.ca , which advocates solutions to the crisis of aging and expired Alberta oil and gas wells. He is the former public policy research manager of the Edmonton-based Parkland Institute.

This post also appears on David Climenhaga’s blog, AlbertaPolitics.ca .

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SOURCES, LINKS, QUOTES, & NOTES

[1] In February 2018, Alberta Energy Regulator Vice President of Closure and Liability Management Robert Wadsworth told a crowd at Calgary’s Petroleum Club that oilfield environmental liabilities for Alberta’s oil and gas wells, facilities, pipelines, bitumen mines, SAGD projects, and related contamination totaled roughly $260 billion.

[2] Chief Justice Herb Laycraft, Court of Appeal of Alberta, PanAmericana de Bienes y Servicios v. Northern Badger Oil & Gas Limited [Northern Badger], Reasons for Judgment 181 (12 June 1991), pp. 7, 11 (paras. 21, 33).

[3] Dianne Saxe, “Throwing the net wider: Can parent companies and lenders be held liable for contaminated land?”, Windsor Review of Legal and Social Issues, vol. 3 (May 1991), pp. 42-43.

[4]Canadian Bankers Association, “Sustainable Capital: The effect of environmental liability in Canada on borrowers, lenders, and investors”, November 1991, pp. 9, 13: “In the event the polluter cannot pay [i.e. ‘orphans’], then the liability should be treated as a social cost. …[But] relief from direct liability risk would not relieve a lender from the credit risk caused by environmental liability. The lender must still contend with the possibility that a borrower may be a polluter and that cleanup obligations imposed on the borrower could cause the value of its security to be eroded or eliminated. The borrower’s cash flow may be insufficient to pay for cleanup and still service the debt. For this reason, lenders will undertake due diligence procedures whenever they have a concern that a borrower’s business may pose an environmental risk.”

Harvey Enchin, “Nervous directors bail out”, Globe and Mail (31 July 1992), pp. B1ff: ‘quitting the board could become a growing trend among directors who are becoming increasingly concerned they will be held personally liable for financial commitments their companies are unable to meet. If this bandwagon picks up steam, it could seriously thin the ranks of candidates for directors.’

[5] Jeff Adams, “Well cleanup will cost $4.5 billion”, Calgary Herald (18 January 1992), p. C9: ‘[“chief operating officer of Petroleum Financial Consultants Inc., a Calgary firm that estimates well reclamation costs for owners, buyers, lenders and insurance companies”, Donald] Bain said the Northern Badger case has highlighted the importance for banks and insurance companies of conducting environmental assessments before they lend money or underwrite drilling projects. The same goes for major investors and would-be partners. These assessments will show how much cleanup will be needed. The costs must be included in a well’s overall production costs when judging its economic viability. The higher the costs, the narrower the profit margins – and the sooner depleting production will result in shutdown. “Companies can’t go on producing, with no thought of the day of reckoning,” argued Bain, a former Canadian Imperial Bank of Commerce executive who helped put together the 1987 deal in which Hong Kong billionaire Li Ka-shing bought 43 per cent of Husky Oil Ltd. of Calgary. …“For any company that’s been burying its head in the sand, the new rules are going to hurt,” [Petroleum Financial Consultants President Charles] Dove said.’

Gordon Jaremko, “New rules cracking down on industrial polluters”, Calgary Herald (5 September 1992), p. B4:
‘“All the banks have implemented policies to assess environmental risks,” reports CPA [Canadian Bankers Association] commercial affairs director Brian Farlinger. “It would be inconceivable now that a lender wouldn’t want an environmental audit done.” …The private environmental policing  stems from a string of painful lessons learned in court cases over pollution damages, Farlinger explains. …The [CPA’s new] guidelines set out a program that goes beyond holding environmental audits when new loans are made. The policy calls for lasting “diligence,” with loan agreements requiring regular pollution checks, guarantees by borrowers that they will keep their operations clean and commitments to repair environmental damage promptly. Every business borrower faces a check called a “phase one” environmental audit, including inspections and reviews of operations’ history. Any hints of trouble trigger “phase two” audits. These call out all the environmental troops to investigate soil, air and water conditions, then require repairs as conditions for granting loans. Businesses are taking the advice to heart.’

Alan Boras, “Industry confronts task of burying its past”, Calgary Herald (17 November 1992), p. A11: ‘Cleaning up the wastelands of Canada’s oil and gas industry – 200,000 abandoned and spent wells, gas plants and refinery sites – will cost an estimated $5 billion. Albertans’ share is about $1,600 each, a bill no one knows who will eventually pay. Known in the oilpatch as decommissioning and reclamation of small oil and gas sites, it’s an environmental problem that’s attracting booming attention. Organizers had expected 80 to 100 people at a one-day seminar Monday sponsored by the Canadian Association of Petroleum Producers. But more than 320 showed up, paying $187.25 each to uncover opportunities on how to reduce costs of shutting down wells that no longer produce oil and gas. “The interest is phenomenal,” said Darrell Chollak, chairman of the association’s decommissioning task force. It recently released a  comprehensive report on how to meet provincial environmental guidelines and clean up polluted land and tear down unused facilities. …older sites,
built and operated before anyone worried about environmental damage, could prove to be great problems. There are potential risks for every corner of the industry, including legal liability of company directors and financial risk for banks which lend millions to petroleum companies. …the petroleum industry… doesn’t appear to have the cash on hand. …“There’s a lot more work that has to go on. I think the doors are now open for government, industry and the public to get together to start resolving some of the issues, such as who’s going to pay,” Chollak said.’

[6] Michael A. Marion, Michael G. Massicotte, and Jessica L. Duhn, “Canada’s aging oil and gas infrastructure: Who will pay? The public and private cost recovery frameworks”, Alberta Law Review, vol. 52, no. 2 (December 2014), pp. 352, 346, 343: “Historically, the Canadian oil and gas industry has followed the caveat emptor principle by which vendors attempt to pass risks associated with oil and gas assets, including Environmental Costs, down the chain of title through conveyances, assignments, novations, industry agreements, and contractual indemnities. …this strategy will likely be effective in many cases… Tracking ownership can be complicated by lost records, poor record-keeping, changing operators and operator practices,
insolvency of working interest participants or co-owners, and even the long-standing perpetuation of mistakes in the administration of the assets. These issues are heightened for aging infrastructure. For example, the historical tracking of the ownership of field gathering systems [pipelines] has been inconsistent at best and, in some cases, is non-existent. As such industry infrastructure ages and requires expenditure of Environmental Costs in the future, there will likely be significant litigation over who owns the infrastructure, which contracts govern, and who is responsible to pay for Environmental Costs. …In the end, the provinces and regions may be responsible for the costs of aging infrastructure where a company is insolvent.”

“Affidavit of [OWA Director] David Wolf filed September 23, 2015”, pp. 2, 4-5, paras. 4, 6-7, 15-16 in Supreme Court file no. 37627, Appellant’s Record, vol. 4, tab 31, pp. 117, 119-20 [emphasis added]: “the primary purpose of the OWA is to conduct abandonment or site reclamation activities on specific properties designated by the AER as “orphans”… There is no other safeguard beyond the OWA for addressing abandonment and reclamation liabilities of sites left behind bankrupt licensees. Without the OWA, responsibility for such abandonment and reclamation activities would fall to the Alberta government, and, ultimately, the Alberta taxpayer. …the OWA has limited resources with which to work with in order to conduct the requisite abandonment, remediation or reclamation activities on orphaned sites. …The OWA’s budget for the current fiscal year is $30,800,000… The recent increase in the number of new orphaned wells from 80 in the precious fiscal 2013/14 year to 591 in the 2014/2015 fiscal year is troubling. Substantial additional resources will be required if this trend continues. An increase in the number of insolvent corporations in the present economic climate could substantially increase the exposure of the OWA.”

[7] Chief Justice Neil Wittmann, Court of Queen’s Bench of Alberta, Redwater Energy Corporation (Re), Reasons for Judgment 278 (17 May 2016), p. 22 (para. 81): “Answering the AER’s submission that the ATB knew the risks associated with advancing funds to Redwater including regarding the abandonment liabilities, the ATB submits that this is irrelevant. It adds that what is relevant is that the ATB secured the loan with a first priority charge against all the
assets, subject to statutory exceptions. The ATB also took specific secured registration against each of the leases on the individual property. The ATB adds that the only thing it had in its possession regarding abandonment liabilities was a reserve report. …The creditors deprived of the usual order of priority in bankruptcy will be subject to a ‘third-party-pay’ principle in place of the ‘polluter pay’ principle. …the licensee, who is also part of the public…”

[8] Justices Frans Slatter and Frederica Schutz, Court of Appeal of Alberta, Orphan Well Association v Grant Thornton Limited, Reasons for Judgment 124 (24 April 2017), pp.32-33, 7 (paras. 97-99, 105, 25): “the appellants argue, there is no unfairness in subordinating the Alberta Treasury Branches’ position to Redwater’s environmental obligations. Alberta Treasury Branches knew of these risks, assessed them in its creditworthiness analysis, and should not now be able to complain that they have come to fruition. Fairness is perhaps in the eye of the beholder, but this argument cannot succeed. …Whether this is fair or not is not the issue… A final related point is the argument that the decision of the chambers judge would motivate corporate reorganizations and insolvencies merely for the purpose of avoiding environmental liabilities. …these fears are exaggerated. …The result of the trial reasons is not that the Alberta Energy Regulator cannot regulate end-of-life obligations, it just means that the Regulator must not wait until an event of insolvency before doing so.” [9] Regulators considered two approaches in 1989. In the first, regulations could be made so stringent that future problems would be extremely unlikely. “But this would impose excessive costs on the entire industry,” regulators curiously rationalized, “whereas only a portion of the industry is likely to generate problems.” They leaned towards a second approach, where less stringent regulations could be accommodated if regulators “had greater control over what happens to wells when the licensee goes into receivership or bankruptcy.”

Energy Resources Conservation Board, “Recommendations to limit the public risk from corporate insolvencies involving inactive wells”, December 1989, p. 3.
As regulators alluded to in 1989, they were willing to trade strict rules to prevent the accumulation of unfunded liabilities in exchange for greater control over companies once they fall into bankruptcy. That same Faustian bargain is at the root of the LLR program to this day. ‘Liabilities’ are underestimated and then balanced by supposed ‘assets’. As long as ‘assets’ exceed ‘liabilities’, reclamation remains entirely unfunded. What the regulator counts as ‘assets’ are three years’ future profit, “this being considered the time required to fund abandonment and reclamation costs.”

Alberta Energy and Utilities Board, “Proposed Licensee Liability Rating (LLR) assessment: Expanded orphan program”, General Bulletin 2001-17 (7 August 2001), p.5.

[10] Benjamin Dachis, Blake Shaffer and Vincent Thivierge, “All’s Well that Ends Well: Addressing end-of-life liabilities for oil and gas wells”, CD Howe Institute Commentary no. 492 (September 2017), pp. 15-16. Whether CD Howe initially misread the report, they are now aware of the error and choose to continue misrepresenting it. Lead author Ben Dachis, email exchange with author (18-19 February 2018). CD Howe’s mistake is to conflate annual OWA spending on reclamation with the total cost of reclaiming all wells in their inventory. Properly understood, the OWA report CD Howe cites puts their historical average cost of reclaiming an oil or gas well at $304,448 – not the $20,000/well figure CD Howe uses in their report. See Alberta Oil and Gas Orphan Well Abandonment and Reclamation Association, Orphan Well Association 2015/16 Annual Report (June 2016), tables 2, 4, pp. 8, 29. Historical spending on reclamation divided by number of wells reclaimed.

[11] As of October 2015, Alberta had 276,397 wells to eventually safely plug. All those, plus another 65,500, for a total of 341,897, then need to eventually be remediated and reclaimed. Then there are ~77,650 facilities to eventually remediate/reclaim and 384,471 kms of pipeline to remediate and safely abandon. Alberta’s Orphan Well Association has extensive experience plugging and reclaiming wells/facilities/pipelines and their annual reports represent the single best publicly available source for the actual cost of reclamation. According to the OWA’s historical experience, it costs an average of ~$84,000 to safely plug a well in Alberta and an additional ~$245,000 to remediate and reclaim. Using these OWA estimates, this puts Alberta’s well liabilities at more than $107 billion, not including very significant facility remediation/reclamation and pipeline remediation/abandonment liabilities. The regulator’s LLR program currently holds slightly more than $196 million in reclamation deposits, or 0.18% of well liabilities (not including pipelines and facilities).
“Affidavit of Bob Curran filed November 12, 2015”, pp. 2-3 (paras. 5-6, 9) in Supreme Court of Canada file no. 37627, Appellant’s Record, vol. 4, tab 34, pp. 191-92:
192,082 active wells (43%)
77,219 inactive wells (17%)
65,500 abandoned wells (15%)
104,145 reclaimed [or reclamation exempt] wells (23%)
7,096 newly drilled wells (2%)
~60,000 active facilities (71%)
~15,000 inactive facilities (25%)
~2,650 “reported as abandoned” facilities (4%)
335,199.7 kms of active pipeline (77.7%)
49,271.2 kms of inactive pipeline (11.4%)
46,958.8 kms of abandoned pipeline (10.9%)

Alberta Oil and Gas Orphan Well Abandonment and Reclamation Association, Orphan Well Association 2016/17 Annual Report (June 2017), tables 2-4, pp. 8, 13, 34. Historical spending on abandonment and reclamation divided by number of wells abandoned and reclaimed. Alberta Energy Regulator, Liability Management Programs Results Report 40410 (3 March 2018), p. 1.

[12] James Mahony, “Oilpatch lenders working with clients to get through downturn”, Daily Oil Bulletin (15 October 2009) (liabilities not mentioned, only collateral and resource prices): ‘Banks base their loans to producers on reserves in the ground, adjusted for additions and revisions. While some producers are assessed annually, most juniors are evaluated twice yearly. …many producers have cut capital spending this year and aren’t replacing production with new reserves. That coupled with a lower gas price forecast could materially reduce borrowing capacity. …In reviewing reserves, evaluators assume a certain gas price. That figure can have a huge effect on the value of the reserves and on how much credit the junior can qualify for. One lender said this is where the industry was cut some slack, since the gas price applied on this year’s evaluations was higher than it could have been.’

“Brief of the Alberta Energy Regulator for declaration for trustee to comply”, Court of Queen’s Bench of Alberta in Bankruptcy, court file no. BK01-094570 (20 November 2015), p. 2 (paras. 6-8): “It is ATB’s standard practice in accordance with its Industry Knowledge Guide to specifically consider the debtor’s statutory abandonment and reclamation obligations when assessing its risk exposure and to expect its customers to comply with same. This exposure is managed by ATB through ensuring the debtor budgets for and sets money aside for abandonment. […] In consideration of Redwater’s abandonment and reclamation obligations, ATB required Redwater to complete an environmental questionnaire that included questions regarding Redwater’s policies to ensure timely abandonment, reclamation and decommissioning of uneconomic sites. ATB also required submission of a third party report outlining abandonment costs in relation to calculations under the AER licensee liability rating (LLR) program, and engineering reports that included information regarding Redwater’s abandonment and reclamation liabilities. The December 31, 2014 engineering report indicated that certain Redwater properties would need to be abandoned in 2015 and others in 2020[…] As of January 29, 2015, and prior to appointment of the Receiver by ATB, ATB records indicate it anticipated full recovery on its debt notwithstanding low commodity prices.”

Chief Justice Neil Wittmann, Court of Queen’s Bench of Alberta, Redwater Energy Corporation (Re), Reasons for Judgment 278 (17 May 2016), p. 22 (para. 81): “Answering the AER’s submission that the ATB knew the risks associated with advancing funds to Redwater including regarding the abandonment liabilities, the ATB submits that this is irrelevant. It adds that what is relevant is that the ATB secured the loan with a first priority charge against all the assets, subject to statutory exceptions. The ATB also took specific secured registration against each of the leases on the individual property. The ATB adds that the only thing it had in its possession regarding abandonment liabilities was a reserve report.”

Sayer Energy Advisors President Alan W. Tambosso, “The impact of changes to the AER’s LMR system on M&A activity”, Daily Oil Bulletin (29 April 2015): ‘Several years ago, most purchasers of assets appeared to pay little attention to the cost of dealing with future liabilities. Regardless of the number of non-producing wells, assets generally changed hands for prices based solely on the value of the producing wells. A few years ago we started to notice increased purchaser awareness of future liabilities. Many prospective purchasers were interested in purchasing only assets with few liabilities. A few savvy purchasers made offers to purchase that excluded liability wells from the property. As the LMR changes came into effect [after May 2013], the purchaser awareness has evolved to the point where acquiring shut-in or abandoned wells is a rare occurrence.’

Jeremy McCrea, “Intermediate oil and gas producers: Subtleties with industry ARO reporting ahead of Redwater hearing”, Raymond James Industry Comment (2 February 2018), pp. 1-2: “ARO values reported in a majority of company Financial Statements are calculated by a standard estimate provided by the AER [Alberta Energy Regulator]/equivalent depending on the region/depth, etc. …As standard practice, Abandonment Retirement Obligations (AROs) are rarely included in debt, FFO [funds from operations] or valuation calculations. So long as an operator’s LLR rating was in compliance, these long-dated liabilities have remained immaterial to investors.”