Alberta’s New Abandoned-Well Program Makes Compliance Impossible for Some
The Alberta Energy Regulator has updated its LLR rules preventing wells from being abandoned. But the new law could inadvertently kill the companies that own them
The vertical oil well located near Red Earth Creek in northern Alberta, identified by the number 2-27, is by most accounts a good asset. The Crimson Oil & Gas-owned well typically produces about 20 barrels of oil equivalent per day, and has been valued at $650,000 by third-party engineers. But in March its production plummeted to zero when the sucker rods connecting its downhole pump to the pump jack snapped in two.
And because the well is surrounded by marshland, the company couldn’t justify sending in a service rig until winter (Crimson says it’s about a $20,000 fix, but accessing the site during summer months would have cost more than seven times that amount). Considering all the costly problems that can occur on an oil well, a $20,000 fix may seem like a good problem to have. Instead, the well poses a major threat to the company’s balance sheet. That’s because under the Alberta Energy Regulator’s Licensee Liability Rating (LLR) program, well 2-27 is fast becoming a liability.
The LLR program measures the value of a well largely based upon its monthly production over a year-long period, which has small producers like Crimson racing against the clock to keep up production – or run the risk of slipping into a negative asset-to-liability ratio with the regulator. “The recoverable oil in that well hasn’t gone down,” says Michael O’Byrne, the president of Crimson. “However, the way the AER looks at it, the value of that well is spiraling down on a month-by-month basis. There’s no opportunity for us to say to the AER: ‘This well is still worth, say, half a million dollars – it’s a good producer.’ ”
The company hopes to have the well repaired by November, weather permitting. Well 2-27 is only one of many assets owned by Crimson, which produces about 500 boe/d, but it’s emblematic of the risk non-producing assets can pose to juniors under the LLR program, particularly amid low commodity prices and in a tight capital market. If the company slips below the 1.0 ratio set by the AER, it will have to post a monthly security to the regulator – and if it has to post a monthly security, much of the capital Crimson needs to bring its ratio above 1.0 will be tied up in the LLR, and can’t be deployed elsewhere. “They tie up all your capital while you’re waiting for the market to recover,” says Jim O’Byrne, the chairman of Crimson. “So it’s very counterproductive in our minds.” For Alberta’s regulators, the LLR program is deemed a necessary measure in cleaning up the province’s growing itinerary of orphan wells. For juniors, however, it now represents one of their biggest operational risks.
The LLR program was introduced in 2000 by the Alberta Energy and Utilities Board in order to encourage companies to properly abandon and reclaim wells, facilities and pipelines after their operational life ends. Regulators at the time saw improper abandonment of wells as a serious environmental and financial liability, and the LLR program was meant to act as a deterrent for non-compliant operators. More than a decade later it was difficult to gauge the effectiveness of the program: By the end of 2012 there were 65,050 suspended wells in Alberta that had not yet been properly abandoned, according to the Energy Resources Conservation Board. As a result, in 2013 the deposit companies paid into the LLR fund was increased substantially. At the time the fund totaled $13 million, with 88 companies paying into it, but the changes ultimately increased that to $297 million from 248 companies, all within a two-month period. As of August 2015, the fund had a balance of $183 million.
Yet critics say the program still isn’t achieving what it set out to do. “The concept is right, [but] the practicality doesn’t work for what they’re trying to do,” says Rick Nixon, the CEO of Midlake Oil & Gas. “What it’s become is a solvency test instead of a process to abandon and reclaim wells.” It’s also a solvency test that overwhelmingly targets juniors. Of the 351 licensees that were below the industry threshold, almost all of them were small producers. The risk of being deemed insolvent according to LLR assessments has reduced junior producers’ ability to access capital in an already-constrained market. Bruce Edgelow, the vice-president of strategic initiatives at ATB Financial, says companies that fall below the 1.0 ratio feel added pressure in terms of repaying various debts. “We’re not per se declining loans [based on LLR ratios] but what we’re looking at is the net obligation of these companies,” he says. “The unfortunate part is the juniors tend to have more of these conversations now, because by virtue of their size they’re getting crunched more than anyone else.”
Some juniors are also frustrated at the difficulty they’ve had transferring well licenses after a company becomes insolvent. Crimson has yet to successfully transfer most of the 39 wells it purchased from Tallgrass Energy, a company that filed for receivership in 2013 (largely due, the company said at the time, to the increased LLR deposits demanded by the AER). Tallgrass completed its receivership in March of 2014, leaving behind 76 wells and 11 facilities in Alberta’s Bigoray area totaling an estimated $9 million in liabilities.
Those wells and other infrastructure, taken as a whole, included too steep a liability charge under the LLR to justify a purchase, so Crimson instead selected 39 of the Tallgrass wells that it considered salvageable. On August 19, 2014, it was granted the rights to the assets by a provincial court. Crimson expected to be charged about $390,000 by the AER to transfer the assets, based on its $10,000-per well transfer fee. But the regulator then included a non-refundable $2.8-million charge to the company – presumably to cover reclamation costs for the assets, though the AER never told Crimson how, precisely, that figure was determined.
In a letter sent to the Orphan Well Association (OWA) and AER on November 24, 2014, Crimson argued that the $2.8-million charge would unfairly drag the company into the “residual issues created by the Tallgrass insolvency,” adding that it had “no appetite to plunge headlong into becoming Tallgrass II.” At the time Alberta Oil went to press, it was still resolving the matter with the AER but had successfully transferred two wells and one facility from the regulator for a total refundable charge of $387,000.
For Crimson’s Jim O’Byrne, the apparent misunderstanding between his company and the AER speaks to a short-sightedness in the program that favors abandoning wells through the OWA rather than transferring them to competent operators – a practice that, he argues, would more effectively work toward reclaiming Alberta’s orphan wells. “If you were transferring that license to a better licensee, why would the AER not accept that transfer?”
The AER wouldn’t comment directly on the matter but says it operates under the mandate to protect industry, and ultimately government, from assuming abandonment and reclamation costs. “In the instance of transfers we have some specific guidelines, again largely based upon protecting the public,” says Brenda Cherry, vice-president of closure and liability at the AER. In 2014 the regulator began offering the LLR Program Management Plan, which offered more lenient payment timelines to small producers that meet specific criteria. But juniors like Crimson still see the program mostly as a non-negotiable assessment of what counts as an asset and what counts as a liability – one that is forcing them to keep up production at all costs. “We’re not the only ones who are on shaky ground,” says Michael O’Byrne. “We don’t know where we’re going to be with the AER six months from now.”
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