Lines drawing in Alberta’s oil sands

Supporters call it the most significant regulation aimed at curbing greenhouse gases in Alberta’s, and perhaps Canada’s, history—the first carbon pricing regulation imposed on the oil and gas industry in North America. Others call the Specified Gas Emitters Regulation (SGER), set to expire in December, “low hanging fruit” for a government and industry still reluctant to take a bite out of emissions from Alberta’s oil sands.

The SGER was introduced by Alberta in 2007 to circumvent federal regulations widely expected at the time. It requires large facilities, including most oil sands operators, to cut greenhouse gas emissions 12% per barrel from pre-regulation levels. For every tonne of greenhouse gas that falls short, firms must pony up 15 Canadian dollars (US$13.44) to the Climate Change and Emissions Management Fund (CCEMF).

To meet the emissions reduction target, oil companies may also choose to improve facility operations, buy emission performance creditsfrom another facility that has surpassed its targets or purchase credits from an Alberta-based offset project. Because any combination of these can be used to meet the target, the fixed CA$15 paid to CCEMF acts as a price cap. A facility has nine years to reach the full 12% and is expected to maintain that reduction rate.

According to an impact assessment published in Calgary in 2013, under SGER Alberta companies cut GHG emissions by just over 40 MMmt of CO₂ equivalent from 2007 to the end of 2010. Of this, 70% was achieved through offset credit purchases and CCEMF payments. Management plans for accelerating GHG reduction through facility improvements and EPCs include use of natural gas, waste heat and vapor recovery, solvent addition and cogeneration, and minimizing steam to oil ratio in facility design.

What success looks like

In Canada the provinces own the resources while the federal government provides public oversight and environmental review. Interestingly, Alberta’s oilpatch companies “see regulations as one of the tenets of the strong system that we have that has attracted international investment,” said Greg Stringham, president of the Canadian Association of Petroleum Producers (CAPP). “They see can see that those rules are very open, and they understand them.”

The real challenge in Alberta, Stringham said, is the uncertainty that occurs when governments dither over what their policy and subsequent regulatory framework should look like. And certainty—or lack of it—will be the mindset of Alberta oil producers when the SGER comes up for renewal next year. Leaked proposals would see intensity reduction levels increase to 40% from 12% and the penalty for failing to meet that target rise from CA$15 to CA$40 per tonne. More modest expectations range from the status quo to a doubling of the existing numbers, which still would not lower general acceptance of the regulation by industry, Stringham asserted.

“The industry has paid into that fund now close to [CA]$400 million,” he said. “The framework is well established with quite a good level of certainty and acceptance.”

Since 1990, the overall emission intensity of the oil sands, he added, has been reduced by 28%. “That’s actual reductions; that’s not including today’s CCEMF payments or offsets,” he said. SGER builds on those reductions by also limiting the purchase of offset credits solely to companies operating in Alberta, “so there are no international trading or caps going on,” Stringham said. “So the only true alternatives are payment into the fund or actual GHG reductions through implementation of new technologies.”

Not that the SGER has won overwhelming support. This summer, former premier Dave Hancock heard rumblings from oilpatch companies that the levy was having a negative impact on investment and cost margins. Others, like Andrew Leach, an oilpatch analyst and associate professor at the Alberta School of Business, have said the hurdles oil producers have to jump to meet the current target are comparatively small.

“Its average costs are really low,” Leach said. “It requires a small percentage reduction over historic emissions intensity at your own facility.”

Leach estimates the average cost to be CA$1.60 or even less per tonne of carbon emissions over the life of an industrial project. Less than ¹/₁₀ mt of carbon emissions intensity per barrel produced at an oil-sands project works out to “cents or tens of cents per barrel,” nowhere near the types of investments major abatement initiatives like carbon capture and storage might achieve “from more stringent policies.”

Meanwhile, provincial auditor general Merwan Saher vented his displeasure, not with the regulation itself but with the way the government’s Department of Treasury Board and Finance has overseen its implementation as a core part of the province’s climate change strategy.

“We found no evidence that the department regularly monitored performance between 2008 and 2012 against the 2008 strategy targets … (and) the department’s processes to ensure the accuracy and completeness of the plan’s data were ineffective.”

A national strategy?

This is not the first time the oil patch has had questions about the impact new rule proposals might have on industry’s bottom line. In 2009, then-Premier Ed Stelmach introduced a tougher royalty regime intended to give the province a larger share of the oil sands largesse. It was a big change that came in the midst of falling investment that many felt would only fall further with the royalty reductions. When the sky did not fall and investment stabilized, industry realized it could adapt.

Similarly, proposals to change the SGER are unlikely to alter industry confidence. Shell, Cenovus and Suncor have each come out and said all of their current projects will still be viable between CA$45 and CA$65 a tonne. “None of these proposals on the table have imposed average costs even remotely near that range,” said Leach. Compliance costs also can be deducted from corporate income tax and royalty payments so the net impact on CA$80 bitumen barrel would be under CA$1.

But even higher emissions targets would be mitigated by the nine-year precompliance period. Leach expects the average cost to be closer to CA$14 to CA$15 per tonne, or CA$1.20 or less per barrel. “And then there is some question as to whether it would apply to upgrading,” he said. At the same time, he cautioned that oil-sands projects vary greatly in scope and profitability: SGER may impact Canadian Natural Resources Ltd. in the Grouse Oil Sands at 50,000 bbl/d more than Teck Resources Ltd.’s Frontier Oil Sands Mine at 277,000 bbl/d.

The good news, said Stringham, is the breathing room the SGER gives companies to continued advances in mitigating GHG at facilities. Use of solvents instead of steam and waste and heat recovery are just a few of the mitigation techniques that have picked up significantly in the seven years since the regulation was introduced. He expects those to accelerate after the new regulation is renewed in 2014.

In fact, Stringham is so bullish about the SGER framework he thinks it should be expanded into a national strategy, in part because environmentalists have persuaded the world, including the U.S., that Canada’s carbon reduction policy is limited to Alberta. They forget, Stringham said, “that 100% of the oil sands development that they’re so focused on is right here in Alberta.”