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Managing the Conventional Oilpatch’s Imminent Transition

The oil and gas industries externalize many costs, but perhaps the most brazen is the cost of cleanup. The regulatory regime managing oilfield reclamation in Alberta is premised on the capture of three years’ revenue from bankrupt oil and gas companies in order to fund the cleanup of a firm’s aging and expired oilfield infrastructure. In place for more than 15 years, the Licensee Liability Rating (LLR) program balances the ‘deemed assets’ of three year’s profit against a company’s ‘deemed liabilities’. Only when ‘liabilities’ finally exceed ‘assets’ are oil and gas companies required to begin funding their cleanup obligations. However, reflecting the depth of regulatory capture in Alberta, there has never been any mechanism to actually capture those assets to fund cleanup – companies simply go bankrupt and creditors liquidate everything of value. The liabilities are very real and their cleanup will eventually become the responsibility of government, but a company’s ‘deemed assets’ have only ever been used as the excuse to delay firms funding their considerable reclamation responsibilities. The assets have never been used to actually pay for the cleanup the way the regulatory program presupposes.

The establishment of an Alberta Reclamation Trust (ART) would finally create a vehicle to capture bankrupt companies’ assets to fund desperately needed oilfield cleanup in Alberta. Institutionally modeled on the Orphan Well Association (OWA), ART would be an independent non-profit organization with powers delegated from Alberta Energy and the Alberta Energy Regulator. ART would be transparent and accountable, with a board and conduct reflecting the public interest. Crucially, it would have the ability to accept not just the liabilities of defunct producers, but also their licenses, surface rights, and mineral rights. Building an inventory of liabilities will allow ART to carry out reclamation work efficiently, organizing it by region and allowing it economies of scale. Holding the licenses and surface/mineral rights will enable ART to operate not-yet-depleted wells to fund its ongoing reclamation work.

The sun set on Alberta’s crude oil and natural gas industries in 2009, when the industries last turned a profit. They have been operating by twilight ever since, absorbing more than $35 billion in losses only by selling equity and taking on increasing levels of debt. Their end is near. ART is the province’s best hope of managing the imminent decline of our iconic industries and avoiding their chaotic collapse, which would leave Alberta without a plan or the resources to manage the cleanup of hundreds of billions in unfunded oilfield environmental liabilities. The stakes are high. Concerted action cannot begin soon enough.

Reclamation was the least of oil and gas companies’ concerns when Alberta’s big oil and gas fields were developed throughout most of the 20th century. ‘There were no reclamation guidelines, and topsoil salvage wasn’t required until 1978’, a major Edmonton Journal investigation noted. ‘Drilling fluids, garbage and some toxic waste such as lead-based pipe joint compounds went into sumps which were later filled in with no record of where they were.’[1] Environmental regulations in the oil and gas business scarcely existed during the first many decades of development in Alberta. ‘Only two things seemed to matter during those glory days of the oil boom: getting it out of the ground and getting paid for it. No one worried too much about dumps of oil, drilling chemicals and sludges at the well site. Just bury it. Spills of oil and salt water were unpleasant, but considered a price of doing business.’[2] “In the past, companies figured the money they could get from salvaged equipment at a site was enough to cover the cost of cleanup”, according to a Petro-Canada accounting manager quoted by the Journal.[3]
But that began to change in the 1980s, as rising environmental awareness among Albertans[4] and a wave of bankruptcies elevated the issue of the oilpatch ducking responsibility for reclamation. In response, 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.”[5]

After a number of false starts and capitulations to industry over the next dozen years, Alberta energy regulators finally established the Licensee Liability Rating program in its current form in 2002. The LLR program is premised on an apparent balance between ‘deemed assets’ and ‘deemed liabilities’. Three years’ future profit (‘deemed assets’) is measured against the regulator’s partial tally[6] of reclamation liabilities (‘deemed liabilities’). Only when ‘liabilities’ exceed ‘assets’ are oil and gas companies required to begin contributing any money towards their reclamation obligations. The LLR program has always been a thinly-veiled charade to allow oil and gas companies to continue accumulating liabilities and avoid funding cleanup, [7] while allowing them to continue passing liabilities around like hot potatoes. [8] Alberta’s accumulation of oilfield environmental liabilities is sobering.

As of October 2015, Alberta had 276,397 wells to eventually safely plug, 341,897 wells to eventually remediate and reclaim, ~77,650 facilities to eventually remediate and reclaim, and 384,471 kms of pipeline to eventually 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 plugging and reclaiming wells. 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 well liabilities at more than $107 billion, not including very significant facility remediation/reclamation and pipeline abandonment/remediation 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).[9]

But LLR’s fatal flaw concerns companies’ supposed ‘assets’. The scare quotes are necessary because those ‘deemed assets’ do not exist. They have never been available to pay for the very real environmental liabilities industry has accumulated for decades. And there has never been any mechanism in place for regulators to capture three years’ profit to fund cleanup. That little oversight – unnoticed and unrectified for more than 15 years – is a glaring illustration of the extent industry has captured Alberta’s government, regulators, and media.[10]

The Canadian Association of Petroleum Producers was not kidding when they wrote: “The LLR Program protects industry, and industry protects the public.”[11] Alberta regulators have done a spectacular job protecting the oilpatch from having to fund the cleanup of the mess they’ve profited from, while a profit-driven industry with loose oversight is doing exactly as much as anyone should expect of them to protect Albertans – that is to say, as little as possible.

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.”[12] Except there has never been any mechanism to capture three years’ profit from bankrupt companies to fund reclamation – companies go broke, their creditors liquidate everything of value, and the cost of reclamation falls on other producers or (eventually) government[13] without one cent of those ‘deemed assets’ being collected for reclamation.

In order to make the polluter pay[14] and to avoid the chaos of unmitigated industry collapse, a vehicle needs to be built for the orderly winding down of Alberta’s crude oil and natural gas industries. As an independent non-profit organization with authorities delegated from Alberta Energy and the Alberta Energy Regulator, the Alberta Reclamation Trust would be tasked with transparently and accountably managing reclamation in the public interest – a vital and urgent task Alberta’s captured energy regulators have proven themselves incapable of. Empowered to assume responsibility for licenses and mineral/surface rights, ART will be capable of absorbing not just the liabilities of defunct oil and gas companies, but their still producing assets as well.

The revenue from future production has not only long-since been pledged for cleanup under the LLR system, it also remains the only viable way to finance the cleanup of a century’s loosely regulated energy development. Alberta’s crude oil and natural gas industries are already heavily indebted,[15] cashflow negative,[16] and on the brink of collapse into bankruptcy.[17] The RedWater Energy case presently before the Supreme Court of Canada – which would allow polluters across Canada to disown environmental liabilities in bankruptcy, ultimately saddling taxpayers with the cost of cleanup – makes the task of preparing for the imminent collapse of oil and gas companies in Alberta all the more pressing.

Alberta’s first priority needs to be containing the potential fallout from the coming RedWater Energy decision. There is a very real possibility the potentially disastrous Alberta court decisions could be overturned by the Supreme Court, but a favourable outcome is far from guaranteed. Whichever way the RedWater decision goes, the Alberta government needs to implement new legislation to contain the consequences. If the lower court decisions are upheld, tens of thousands of wells are at risk of being immediately disowned as creditors take advantage; if the lower court decisions are overturned, lenders and investors will for the first time be forced to take liabilities into serious consideration in their lending and investment decisions.[18]

Alberta needs legislation modeled on Ontario’s Forfeited Corporate Property Act, 2015 (FCPA).[19] Just as you need permission to form a corporation, in Ontario now, you need permission to dissolve one. Voluntary dissolution is no longer automatic; the province has the discretion to refuse to dissolve a corporation. Because bankruptcy insulates small firms from the cost of cleanup, it distorts their behavior, causing them to take on socially inefficient projects and to take excessive environmental risk.[20] For Alberta, an Ontario-style FCPA law would allow us to stem the flow of small producers going bust, entering bankruptcy protection, and shedding liabilities under the RedWater precedent. Creditors have already disclaimed ~1800 oil and gas sites in Alberta since the lower court decisions[21] and tens of thousands more would be under immediate risk of the same if we lose at the Supreme Court. FCPA-style legislation would effectively lock the doors and not let anyone escape until Alberta has the chance to sort out how to deal with insolvent industries responsible for hundreds of billions in unfunded environmental liabilities.

A benefit of ART is the ease with which it could be formed. The Orphan Well Association model was developed in close consultation with industry, it is well understood, and could be replicated with the urgency these issues demand. One of the quickest ways ART’s work could be funded is by enabling the transfer of the nearly $200 million reclamation deposits already held by the Alberta Energy Regulator. Transferring them to ART would free up company balance sheets of related liabilities immediately and avoid the burden of firms having to effectively spend the money twice to do the actual cleanup work before their deposits are returned and liabilities removed from their balance sheets. By utilizing third parties to do the cleanup work, ART would also be taking advantage of tens of thousands of unemployed energy service sector workers in Alberta and associated equipment left idle by the downturn in oil prices in recent years.

An Alberta Reclamation Trust would help manage the imminent decline of our crude oil and natural gas industries, minimizing disruption and unnecessary value destruction, while maximizing employment in the industry and the resources available for decades of needed cleanup work. ART’s abilities could be scaled up as capacity within the organization is built and public appreciation of the crisis of reclamation expands. Putting Albertans back to work cleaning up Alberta is the surest way to build support for ART’s mandate and protect it from the vagaries of politics. ART could also drive increased responsibility within still solvent and operating producers by carrying out a program of inspections of inactive and unplugged wells across Alberta that pose the greatest environmental risk and offering the opportunity for firms to transfer problem sites and funding to ART, which will soon exceed the efficiency and economies of scale available to any one firm doing reclamation work itself.

ART will also be an opportunity to reimagine industry relations with Alberta’s farmers, ranchers, landowners, and the public more generally. The friction of industry-friendly rules has always placed a burden on Alberta’s rural communities and ART would be an opportunity to right many of those wrongs. Sites managed by ART could ensure famers, ranchers, and landowners are treated fairly and their legitimate concerns get the priority they deserve. ART could also ensure all Albertans get the fair share of resource revenue they have been denied by repeated royalty cuts aimed at keeping a declining industry afloat. ART should pay market-competitive royalty rates to the province on all its production before the remainder of production revenue funds ongoing cleanup.
ART also has the potential to evolve into an insurance scheme.[22] Alberta’s Oil and Gas Conservation Regulation allows for a levy on licensees of wells and facilities for the Orphan Well Association, but is explicitly not an insurance scheme because there was never any intention for the OWA levy to reflect the sum of liabilities and risk. But Alberta’s crude oil and natural gas industries are not going to be around forever. An ART levy could be structured to internalize the many costs externalized by the oilpatch. And to the extent the true costs of energy development would make certain firms no longer viable, ART would absorb their liabilities as well as their assets to be managed in the public interest – further protecting the Alberta’s environment by further funding oilfield cleanup.

And ART isn’t just Alberta’s best hope to manage the imminent decline of our crude oil and natural gas industries – it is also a model that could be exported to other jurisdictions, not the least of which are British Columbia and Saskatchewan, which have adopted our deeply-flawed LLR systems for managing reclamation. ART is modeled on successful responses to banking crises, for which there are many parallels with the reclamation crisis faced by a variety of jurisdictions. Banking regulators have successfully used ‘bad banks’ to absorb liabilities and manage the winding down of insolvent players in an orderly fashion.

Reclamation isn’t quite so simple – oilfield liabilities are more ‘real’ than bad loans and have to actually be cleaned up rather than left to die a quiet death on a balance sheet somewhere – but ART would stabilize the decline of Alberta’s severely mature crude oil and natural gas industries and provide funding for the decades of cleanup inherent in that decline. ART could ensure full-employment within the oil and gas sector for generations.

ART could also be a powerful vehicle for reconciliation with Canadian First Nations. As noted by the Attorney General of Saskatchewan in his intervention in the RedWater Energy case at the Supreme Court, Canada owes fiduciary duties to Bands in administering reserve lands. The Supreme Court itself described that duty as requiring Canada to act “with loyalty, good faith, full disclosure appropriate to the subject matter and with ‘ordinary’ diligence in what it reasonably regarded as the best interests of the beneficiaries.” As indicated in its preamble, the First Nations Oil and Gas and Moneys Management Act provides Bands with the option of “managing and regulating oil and gas exploration and exploitation and of receiving moneys otherwise held for them by Canada.” It is a reflection Canada’s recognition of “the inherent right of self-government as an existing Aboriginal right under section 35 of the Constitution Act, 1982.” As the Attorney General noted, “The Act allows Bands to pass their own laws for regulating oil and gas development on reserve. It also allows Bands to incorporate provincial oil and gas laws for that purpose.”[23]

So far, First Nations have opted to adopt provincial regulatory regimes. But once they appreciate the profound deficiencies of British Columbia/Alberta/Saskatchewan’s LLR programs and the severe risk they face being saddled with reclamation costs, they may find cause to reconsider. Establishing their own regime along the ART model would afford First Nations control over the character of energy development on their lands, opening the economic and employment opportunities inherent in reclamation under their own control and direction. If current producers became unviable as a result of internalizing costs, such Aboriginal reclamation trusts would offer a way for those communities to absorb the viable assets on their lands to fund the ongoing reclamation of the depleted assets they inherit.

The Alberta Reclamation Trust is the province’s best hope of avoiding the chaotic collapse of its iconic industries into bankruptcy and the hundreds of billions in unfunded oilfield liabilities that will eventually fall to government. That fateful transition is far closer than most appreciate. Our captured regulators have left us in a precarious position, from which there is no easy or simple escape. But without a dramatic shift in course, the province is headed for economic and environmental disaster. If we can muster the political courage, there is still an opportunity to reclaim Alberta’s future.

SOURCES, LINKS, QUOTES, & NOTES
[1] Don Thomas, “Big oil, big cleanup: Putting an old oilfield out to pasture”, Edmonton Journal (18 July 1992), p. G3.
[2] Erin Ellis, “Big oil, big cleanup: Mopping up after the oil boom”, Edmonton Journal (18 July 1992), pp. G1ff.
[3] Erin Ellis, “Big oil, big cleanup: Chartered accountants help lay groundwork for cleanups”, Edmonton Journal (18 July 1992), p. G3.
[4] Don Martin, King Ralph: The political life and success of Ralph Klein (Toronto: Key Porter, 2002), pp. 95, 101: “Environmental concerns were rising to the top of the polls in the late 1980s… With the environment rated the top concern in public opinion polling, in 1989…”

Richard Domingue, “The greening of the economy: Repercussions on financial services”, Library of Parliament, Parliamentary Research Branch Background Paper BP-307E (September 1992), p. 2: “In the late 1980s, Canadians said that the environment was one of their main concerns. According to a CROP [Centre de Recherches sur l’Opinion Publique] survey published in June 1989, 85% of Canadians stated that they were prepared to pay more for environmentally friendly products. At the same time, people began to focus on the quality of life. In addition, according to the CROP survey, 88% of Canadians said they felt that public health was affected by pollution, 73% of respondents stated that pollution was a major cause of cancer, and 81% considered that pollution problems threatened the survival of the human race. …The media contributed a great deal to the dawn of new values by regularly reporting on environmental disasters”

Gordon Jaremko, Steward: 75 years of Alberta energy regulation (Alberta EnergyResources Conservation Board, 2013), p. 90:
Former ERCB chairman (1987-1994) Gerry DeSorcy recognized changes in public attitude towards resource development beginning in the late 1970s: ‘“There were societal changes, and notably a growing willingness of the public to speak out. My dad did his complaining over a glass of beer with friends. He would no more have thought about airing those concerns with the authorities than flying through the air.” When DeSorcy’s term as ERCB chairman ended a more environmentally conscious attitude prevailed. After retiring, he served as head of a public review of sour-gas standards, safety, and regulation. In that role, he had his finger on the pulse of the environmental movement. “I was surprised at the number of people—sound, responsible people that we talked with one-on-one, not just at town hall meetings—who said, ‘I’m not sure it’s worth it any more.’ As a society we changed from one that said, ‘Isn’t that awful but we’ve got to do it,’ into one that says, ‘There’s no room for error.’”’
[5] Energy Resources Conservation Board, “Recommendations to limit the public risk from corporate insolvencies involving inactive wells”, December 1989, p. 3.
[6] Linda Harrison, “Industry on hook for growing number of orphan wells”, Daily Oil Bulletin (3 December 2014): ‘“There is a general understanding in the upstream oil and gas environmental industry that the reclamation deposit values under the AER’s LLR system need to be updated,” said [OWA manager Pat] Payne, adding that it needs to be increased to better reflect current reclamation costs. …If they are underestimated then liabilities are underestimated, and less security is collected by the AER, so there is a greater risk of increased costs to the orphan fund and to industry if the values are not accurate, she told the DOB.’
What they do count, they underestimate, but 430,000+ kms of pipelines and corporate debt are also excluded from regulators’ tally of liabilities.
[7] Linda Harrison, “Alberta’s 100,000 inactive wells carry huge liability: Lawyer”, Daily Oil Bulletin (27 October 2010): ‘Since LLRP was introduced the ratio of abandoned to active wells has declined from 48% to 38%,[Ecojustice lawyer Barry Robinson] said. “It should be going the other way.” The ERCB itself has identified that the longer wells sit inactive, the greater the risk to the environment and public safety, said the lawyer, adding that’s primarily because knowledge of the wellbore, and in some cases the actual location, gets lost. …the deemed asset is actually a deemed cash flow rather than the actual asset for the company and it assumes all operators are equally profitable when in fact an individual licensee might be losing money on every barrel it pumps. Similarly, the calculation of deemed liabilities… ignores all of the licensees’ other financial liabilities, and they might be millions of dollars in debt, he said. Robinson provided an example of one such company his organization investigated. The unnamed company had $130,000 in the bank, $2 million in accounts payable and had active lawsuits against it for $2.5 million in unpaid accounts, for a total of $4.5 million in financial liability. That did not include any well liabilities. The company lost $1 million in operations in 2008 and lost $560,000 in operations in 2009, but stayed afloat by selling $1.3 million in equipment. Because the company had some production it was not required to have a security deposit, he said.’
[8] Alberta Energy and Utilities Board, “Directive 013: Suspension requirements for wells”, Bulletin 2004-29 (1 December 2004), p. 1: “During the last 15 years, property sales were very high and many of these inactive wells were transferred numerous times. With the sale of these wells, knowledge of wellbore conditions, and in some cases even knowledge of the well’s existence, was lost.”
[9] “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), pp. 8, 13, 34, tables 2-4. Historical spending on abandonment and reclamation divided by number of wells abandoned and reclaimed.

Alberta Energy Regulator, Liability Management Programs Results Report 40410 (3March 2018), p. 1.
[10] For a serious and careful examination of the power and influence of Alberta’s oilpatch, see Kevin Taft, Oil’s Deep State: How the petroleum industry undermines democracy and stops action on global warming—in Alberta, and in Ottawa (Toronto: James Lorimer, 2017).
[11] Canadian Association of Petroleum Producers, “Liability management submission to the Alberta Royalty Review Panel”, 20 November 2016, p. 3.
[12] Alberta Energy and Utilities Board, “Proposed Licensee Liability Rating (LLR) assessment: Expanded orphan program”, General Bulletin 2001-17 (7 August 2001), p. 5.
[13] Annual Report of the Auditor General of Alberta: 2004-2005 (October 2005), p. 176: “Without a requirement for timely abandonment (and reclamation for oilfield waste management facilities), and subsequent monitoring and enforcement, industry may defer their abandonment and reclamation activities and costs. If certain licensees do not meet their responsibilities for abandonment and reclamation activities in the future, other licensees or the government may have to cover the liabilities.”
[14] Colette Derworiz, “Producers must clean up abandoned oil wells: NDP”, Calgary Herald (13 February 2016), p. A7: ‘Environment Minister Shannon Phillips… [who] has been examining the issue for several months, said her department has major concerns about the abandoned wells. “My concern is the environmental liability,” she said Friday. “My concern is certainly the inconvenience to landowners and, at the end of the day, how much the provincial government could potentially be on the hook for.” …“We’re committed to the polluter-pay principle here,” she said… “Really, what we want to do is minimize the risk to the people of Alberta.” “…polluter-pay principle… That’s very important to us, because at the end of the day, the province is left with the environmental liability if we don’t have a good polluter-pay principle. We need to ensure that responsibility in oil and gas operations…”’
Lauren Krugel, “Minister lauds proposal for well cleanup”, Edmonton Journal (16 March 2016), p. B8: ‘…Alberta does have a polluter-pay principle that makes companies responsible for well decommissioning, [Energy Minister Marg] McCuaig-Boyd says…’
[15] Pat Roche, “Higher debt, higher declines distinguish current downturn from 2008-09”, Daily Oil Bulletin (20 March 2015): ‘How does the current oilpatch downturn differ from the last price slump in 2008-09? Peters & Co. Limited identified two main differences — higher debt levels and higher decline rates. In its Oil and Gas Overview: Winter 2015, the Calgary-based investment firm said debt levels are currently much higher than historically. In December 2008, Peters’ median forecast of 2009 debt for Canadian producers was only 1.6 times cash flow. Today that number is much higher for each of Peters’ peer groups of Canadian producers. Canadian large and integrated producers now have an estimated median debt-to-cash flow ratio of 3.6, up from an estimated 1.3 in 2009, according to Peters. Intermediate producers have an estimated debt-to-cash flow ratio of 3.4, up from an estimated two times in 2009. And for junior producers the ratio is estimated at 3.8, up from 1.6 in 2009. The other difference Peters noted is that plays with high first-year production declines were only just starting to be developed in 2008-09, particularly on the oil side. According to Peters, first-year production decline rates on some wells are 75 per cent or more, leading to much higher companywide decline rates. On average, the decline rates for Peters’ intermediate/junior peer group are now 30 per cent, up from 24 per cent in 2008. “This change is significant as it results in materially higher capital required to maintain current production levels than in the past,” Peters wrote. The investment firm also suggested the full-cycle breakeven commodity prices are “higher than most companies want to admit.” …A recent analysis by ATB Financial, using CanOils data, found that the total debt of a sample of Canadian producers (defined as having more than 50 per cent of their production in Canada) had increased by more than 80 per cent to $85 billion in the third quarter of 2014, up from $47 billion in the third quarter of 2008 on the eve of the last downturn. Total production from these companies increased by only 37 per cent over the same period. …In recent years producers were able to escape low gas prices by switching their focus to oil and natural gas liquid plays. But with all commodity prices low at the same time, there is no safe harbour.’
[16] Canadian Association of Petroleum Producers, Statistical Handbook (April 2017): Value of Alberta crude oil and natural gas production, 2010-2016 — exploration/development/operating costs & royalties/land sales = -$35 billion (2016$).
[17] Paul Wells and Richard Macedo, “Micro juniors facing tough challenge to survive”, Daily Oil Bulletin (10 June 2010): ‘…with little cash flow and poor prospects of raising capital, these “micro-juniors” can’t afford the expensive horizontal, multi-stage fracture wells now in vogue. …While the Alberta government’s recently revised royalty scheme is helpful on many levels, industry friendly changes are probably not enough to ensure the viability of companies that have built their business models and production profiles around natural gas. “Royalties in Alberta can’t get much lower than they are,” [Explorers and Producers Association of Canada President Gary Leach] said, adding that so-called micro-juniors – companies under about 1,000 BOE per day – are “going to find it very challenging going forward.” …juniors under about the 3,000 BOE per day threshold don’t find the same equity market support as some of their larger brethren do. …Bruce Edgelow, vice-president of energy with ATB Financial, said… “Clearly, the junior micro days, unless you are early days and you’ve got the ability to go and move quickly, are a little bit behind us, unfortunately.” Alan Bey, president and chief executive officer of Rock Energy Inc.…“You have to be looking for the two, three, five bcf gas wells,” he said. But to do that Bey said that given the level of maturity of the WCSB, it’s likely companies have to set their sights on tight resource plays, which means a per well cost in the $5 million to $6 million range. And for a smaller entity, if that type of expenditure results in a dry hole or less than stellar well, it could be lights out.’
John Tilak and Euan Rocha, “Canada’s banks feel pain of oil price rout, economic slowdown”, Reuters (25 February 2016): ‘After reporting quarter after quarter of market-topping results in recent years, the lenders were feeling the pull of gravity. …RBC set aside a significantly higher amount to cover for bad loans in the first quarter. RBC chief risk officer Mark Hughes… said debt covenant reviews this spring will likely result in reduced credit for some energy clients. …”We are doing one-on-one analysis on almost all of our exploration and production clients,” RBC chief financial officer Janice Fukakusa said in an interview. …Analysts have also been weighing various scenarios to assess the risks, but few see a doomsday scenario playing out. “Under a moderate stress scenario… it will be a profitability concern, not a capital concern,” Moody’s analyst Leon Frazer, which owns positions in RBC, TD, Scotia Bank and BMO. “The pain will grow, but in my opinion it is not going to lead to even a single year where the banks lose money. It’s just not going to get to those levels.”’
Paul Wells, “Spring loan reviews a bellwether of sorts in this current era of survival of the fittest”, Daily Oil Bulletin (8 March 2016): ‘…banks don’t want bad loans on their books and oil and gas companies, certainly, don’t want to go insolvent. Brothers in arms during these most difficult times? Perhaps. …[ATB Financial vice-president Bruce Edgelow:] “…we are all trying to… stay the course and provide support through this. …The next 90 to 120 days are going to be critical for the patch. Who can make it through the next borrowing base review where there’s likely to be further downward revisions [on reserves]… People fail to realize how hard we have to run to cover our losses. …When we write a loan off, the math that needs to be done to cover our loan losses is absolutely staggering. People don’t want us to take loan losses because it contracts your income, it looks poorly and it may cause you not to be as aggressive as you have historically been in different sectors. It’s a very slippery slope. So we’re trying to do the right thing.” Neil Narfason, a partner and senior vice-president with Ernst & Young Inc. and the firm’s transaction advisory services leader, energy, said… “…I think you have a lot of the banks willing to work with companies and remain flexible and look for solutions that don’t have to be a harsh result for the company,” he said. “So if there’s positive cash flow, even though the reserve review may indicate deficiencies, what we expect to see is the bank to allow a period of time to look for a resolution to the shortfall on the reserve value. Can you raise additional equity, can you raise junior debt, can you sell non-core assets, can you sell the whole company? So that’s what the banks are trying to work with the companies on in an effort to figure out if there’s a solution that can be found.” That said, Narfason expects there will be an uptick in insolvencies as 2016 continues to unfold. “It’s already way up, especially for oil and gas companies, in terms of the number of formal insolvency proceedings. But there’s also a lot behind the scenes with what we call business reviews where people such as ourselves get retained to advise the banks as to the company and its prospects, its cash flows and its options,” he said. “So there’s a lot of that going on that you wouldn’t see announced. But the formal insolvencies are definitely up. From this side of the world there is still going to be more failures to come as people just can’t weather this. So we expect to see more formal proceedings for both oilfield services and oil and gas companies.”’
Elsie Ross, “ERCB raises Licensee Liability Rating deposits”, Daily Oil Bulletin (13 March 2013): ‘In an updated Licensee Liability Rating (LLR) program effective May 1, 2013, the Energy Resources Conservation Board will require 248 licensees to post financial security of $297 million, up from the current 88 licensees that have posted deposits of $13 million. …If a company fails to pay the required security, the ERCB may take enforcement measures, which include ordering a facility’s suspension and abandonment. …The changes outlined in Directive 006 were made to address concerns raised by industry groups that the LLR program, which was last updated in 2006, significantly underestimated abandonment and reclamation liabilities, the board said in a bulletin. …Darrin Barter, an ERCB spokesman, said… In 2006, the industry was booming and generally operators’ assets outweighed their liabilities so there was a reduced need for the LLR, he said. Since then, costs have risen and producers are facing lower commodity prices. …The actual amount of financial security owing will depend on the licensee’s assets and liabilities when the LLR program changes are implemented and updated.’
Pat Roche, “LLR under fire as producers confront uneconomic wells”, Daily Oil Bulletin (27 November 2015): ‘The AER implemented the third and final phase of changes on Aug. 1 [2015] as the industry was reeling from the worst oil price downturn since the 1980s. …As oil prices crashed, more oil wells became uneconomic. But as a producer shuts in money-losing wellbores, its ratio of inactive wells to active wells rises, and the regulator demands hefty increases in liability deposits. So some juniors are producing at a loss because they don’t want to shut in uneconomic wells, said Bruce Edgelow, the ATB Financial vice-president who handles the Alberta government-owned financial institution’s troubled energy loans. “Because as soon as they shut their wells in, the regulator does this LLR review [and] says, ‘You owe me [for example] three-quarters of a million dollars,’” said Edgelow, who discussed the problem at a Canadian chartered accountants conference on Monday and at a CFA Society Calgary lunch on Thursday. …financially sound producers trying to conserve cash are, in effect, forced to produce uneconomic wells to avoid paying even more money under the LLR program. “It’s not about insolvency,” said Edgelow. “But they’re producing at a loss today because they can’t shut their wells in because of what will happen with the ratio.” The matter is being discussed by industry and the regulator. “EPAC and our colleagues at CAPP are in regular discussions with the AER about the LLR. There is no doubt the current business and financial environment is putting stress on the LLR program and Alberta operators,” said EPAC president Gary Leach. Discussions with the regulator are aimed at finding a way to allow producers who are not bankrupt to shut in uneconomic wells, said Edgelow.’
Darcy Henton, “Well, well, well, how many more leaks are there? Calmar situation may only tip of iceberg, environmental lawyer says”, Edmonton Journal (7 June 2010), p. A3: ‘NDP Leader Brian Mason says without deadlines, the program is doomed. “There are requirements that companies remediate these sites, but the major loophole is there are no timelines attached to it,” he says. “It’s like telling teenagers they must clean their room, but not giving them a deadline to do it.”’
Bob Weber, “Old Alberta wells that fail standards raise fears: Critics seek tougher rules”, Canadian Press (30 November 2014): ‘[Alberta lawyer Keith] Wilson said Alberta’s current rules only postpone the inevitable – perhaps until it is too late. “You have to clean up these wells while the cash is available in the oil companies to do so,” he said. “If they pay out all of their value in dividends and disposing of assets to shareholders without first cleaning up their liabilities, then who’s going to be left to deal with the liability?”’
Paul Wells, “Challenges continue to mount for EPAC member companies as commodity prices lag and policy changes add to uncertainty”, Daily Oil Bulletin (23 December 2015): ‘“The AER is acutely aware that there are many small operators who have little or no production and are unable or unwilling to fund even relatively small security deposits. Many of these sites are expected to end up with the Orphan Fund,” [Explorers and Producers Association of Canada President Gary] Leach said.’
Donald G. MacDiarmid, Sean J. Korney, Melanie Teetaert, Julie J.M. Taylor, Robert Martz, and Randon E. Slaney, “The oil and gas ROFR: Understanding current ROFR issues from the point of view of the transactional lawyer, the litigator, and in-house counsel”, Alberta Law Review, vol. 55, no. 2 (December 2017), p. 277: “Since the recent economic downturn in the Canadian oil and gas industry, there have been few
restructurings of oil and gas companies under the CCAA [Companies’ Creditors Arrangement Act]. Instead, liquidations of assets, either en bloc or in smaller packages, have been more common, implying that most of the financially strained companies were incapable of returning to a profitable operation.”

[18] James Mahony, “Oilpatch lenders working with clients to get through downturn”, Daily Oil Bulletin (15 October 2009) (liabilities not mentioned, only collateral): ‘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 (2February 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.”
[19] Dentons, “Corporate dissolution will not protect former directors and officers from environmental liabilities”, 5 December 2016: “On December 10, 2016, Ontario’s Forfeited Corporate Property Act, 2015 (the FCPA), comes into force, along with related amendments to the Ontario Business Corporations Act (the OBCA). Directors and officers may be aware of these changes in so far as they will set out a new corporate filing requirement to keep a register of property owned in Ontario. However, the FCPA and the amendments to the OBCA also set out a new regime governing forfeiture of corporate property, which will have significant impacts on corporate governance of environmental risks. In particular:

1. D&O liability: Directors and officers can be personally liable for the cost to remediate forfeited corporate property after the corporation has dissolved; and
2. Dissolution requires Crown consent: Corporate dissolution will no longer be automatic.

These changes build on years of proposals to increase corporate accountability for contaminated land, and are aligned with the recent trend to impose liability for environmental clean-up costs on directors and officers, regardless of fault.”

[20] Judson Boomhower, “Drilling like there’s no tomorrow: Bankruptcy, insurance, and environmental risk”, University of California Berkeley, Hass School of Business, Energy Institute at Haas Working Paper no. 254 (March 2016), p. 1: “Bankruptcy protection improves insolvent actors’ work incentives and mitigates coordination problems among creditors. However, bankruptcy protection also distorts behavior by insulating
actors from worst-case outcomes. …One important implication of bankruptcy protection is that firms in hazardous industries will take excessive environmental and public health risks. Since damages can be discharged in bankruptcy, firms with assets less than their worst-case liabilities face inadequate safety incentives. Economists call this the ‘judgment-proof problem’… The ability to avoid liability through bankruptcy creates a private cost advantage for small firms,
potentially shifting production away from larger producers with lower social costs of production. This paper measures the effect of bankruptcy protection on environmental outcomes and industry composition in the onshore oil and gas industry. …Bankruptcy protection lowers the expected private costs of environmental damage for small producers. As a result, small firms exercise too little care in each project; acquire some projects that would be efficiently operated by large firms; and develop additional high-cost projects where social cost exceeds social benefit.”
[21] Alberta Energy Regulator President and CEO Jim Ellis, “Why we are fighting”, Public statement (15 February 2018), p. 2.
[22] Mattias K. Polborn, “Mandatory insurance and the judgment-proof problem”, International Review of Law and Economics, vol. 18, no. 2 (June 1998), p. 145: “The insurance requirement forces the firm to internalize the victims’ expected losses via the premium, given its equilibrium level of care; hence, the investor has to bear all relevant social costs of an accident [or cleanup], costs of care as well as expected damages. When deciding whether to undertake the project, the investor will, therefore, take the socially correct decision.”
[23] Attorney General of Saskatchewan, “Intervener’s factum”, Supreme Court of Canada file no. 37627 (1 February 2018), pp. 13-14 (paras. 42, 45).

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2018-06-25T21:33:09+00:00