In this Update

  • The pre-existing Specified Gas Emitters Regulation (SGER) imposes a $30 per tonne carbon price on all industrial emissions over a pre-determined cap, and the newly announced Carbon Competiveness Incentive Regulation (CCI) with layer sector benchmarks on output-based allocations to different emitting industries and tighten allowable emissions on those industries over time
  • The federal government is ensuring carbon pricing is here to stay through various legislative initiatives
  • In order to optimize outcomes within the new legislative structures, effective carbon management strategies begin with carbon auditing or tracking and cost minimization strategies
  • Other carbon investment strategies include leveraging technology for additional revenue, direct investment in renewable power projects and negotiating flexible bilateral contracts for electricity and/or renewable energy credits

The proliferation of carbon pricing policies and emissions regulation in Alberta warrants proactive carbon planning and decisive action by upstream oil and gas producers, power generators, and other large industrial carbon emitters in Alberta. This article summarizes the impetus for carbon auditing and highlights some available strategies for Albertan industrial carbon emitters.

Confluence of laws are demanding attention to carbon management

The pre-existing Specified Gas Emitters Regulation (SGER) imposes a $30 per tonne carbon price on all industrial emissions over a pre-determined cap, and the cost of excess emissions is anticipated to grow to $50 per tonne by 2022. An equivalent retail carbon tax is imposed on the wider economy under the Climate Leadership Act (Alberta).

Recently, the Government of Alberta announced the Carbon Competitiveness Incentive Regulation (CCI), which will come into effect January 1, 2018.

The CCI will impose output-based allocations of carbon costs within an industry. Most large emitters will be held to a benchmark of 80% of production-weighted average emissions intensity for their industry sector, including the upgrading natural gas processing and multi-product chemical manufacturing industries. Exceptions will apply for the electricity, oil sands in-situ and mining, and other sectors. The CCI will also tighten the free emissions allocations each year, beginning in 2020, among other changes to the provincial regulatory structure.

The federal government is ensuring that carbon pricing is here to stay by its introduction of the Pan-Canadian Framework on Clean Growth and Climate Change, which announces a federal backstop for any province which fails to maintain a minimum carbon price on a broad base of fuel emissions.

Within provincial boundaries, in addition to carbon pricing, the Government of Alberta is procuring unprecedented renewable power generation through long-term contracts for renewable credits or emission offsets, developing a capacity market to replace the energy-only deregulated wholesale electricity model, and doubling down on carbon legislation by introducing parallel methane emissions reduction regulations and restricting oil sands production-related emissions.

On December 13, 2017, the Government of Alberta awarded long-term contracts for nearly 600 MW of wind generation under Round 1 of its Renewable Electricity Program.

All taken together, the confluence of climate management laws portend that industrial scale carbon emitters in the province would be wise to develop effective carbon management strategies.

Carbon auditing

The first step to an effective carbon management strategy is carbon auditing or tracking. The amalgam of carbon legislation in Alberta has for the first time created an incentive structure to meaningfully reward Alberta companies for critically evaluating their operating structures and making reasonable investments towards carbon efficiency.

We suggest that all companies with operations in Alberta should conduct carbon audits on both a corporate basis and a project-by-project basis. Those who do so will be able to identify the areas in their plant design, equipment or operating practices where they can most efficiently manage their carbon compliance and associated costs. Long-term carbon costing on internal financial models is an important component of the audit process to ensure that organizations are making economic investment decisions that take into account the anticipated long-term trajectory of carbon pricing.

The incentive for large industrial emitters to conduct thorough internal carbon audits is further stimulated by the upcoming transition to an output-based allocation approach under the SGER, which will shift the bulk share of carbon levies in specific trade-exposed industries to the least efficient operators in that industry, on a comparative basis. In other words, the most carbon-efficient facilities in the specific industries will be rewarded with emission performance credits to be sold at profit or used for future operations, while their competitors will be burdened with a disproportionate share of carbon levies of the entire industry.

A further driver towards internal carbon auditing for public companies is ever-increasing shareholder pressure to formulate and communicate corporate carbon plans as part of environmental and corporate disclosure. This is particularly valid for public companies with a public reputation for corporate social responsibility, or heavy external pressure to implement the same.

Cost minimization strategies

A candid audit of the impact of climate costs on a large emitter’s bottom line may call for one or more cost minimization strategies. For instance, some hospitals, school boards, municipalities and other emitters with significant operating costs have begun to implement plans to transition to LED lighting, on-site solar power generation, greener transportation fuels and other measures to reduce their carbon-related operating costs.

Others who have incorporated long-term carbon pricing forecasts in their models have opted not to make certain capital investments for pure economic reasons, or on the basis that the publicized carbon impact of the proposed investment would not be justified from a corporate social responsibility standpoint.

Moreover, an Alberta emitter conducting carbon audits and placing internal pricing on carbon consumption may determine that it should exit its least carbon-efficient or highest carbon-emitting stream of business or retire older, less efficient facilities already in operation. For instance, TransAlta Corporation and ATCO Power have each announced that they will accelerate their retirement of their least economically viable coal-fired generation facilities in favour of conversion of those facilities to natural gas in advance of the province’s coal phase-out deadline. An accelerated conversion from coal to natural gas-fired production results in a significant reduction in carbon emissions, and therefore this strategy minimizes the carbon compliance costs of these entities.

Similarly, future large-scale investment in power infrastructure in Alberta is likely to be based on highly efficient natural gas-fired generation or cogeneration projects, on the basis that such facilities can meet Alberta’s load requirements while having limited or no exposure to carbon levies based on the currently anticipated output-based allocation regulatory structure.

Carbon investment strategies

In addition to inducing cost minimization strategies, a thorough carbon audit can help a large emitter evaluate whether and to what degree capital or operational investments are worth making relative to their alternative costs of SGER compliance. Following such an audit, a company may, among other things, decide to (i) leverage technologies to increase its revenue stream or decrease its emissions profile, (ii) make a direct investment in the carbon offset market, or (iii) enter into contracts for emission offsets which hedge its carbon exposure.

(i) Leveraging technology for additional revenue

The implementation of provincial carbon policies presents an opportunity for upstream producers and power generators to capitalize on technologies which generate additional revenue streams.

Oil and gas companies, or associated service companies, which develop in-house commercially deployable technologies for the reduction of greenhouse gas emissions can license their technological innovations or contract out those services to competitors as a new revenue stream.

Technology can also be leveraged to secure government funding. For instance, since its first funding round in 2010, Emissions Reduction Alberta (ERA) has invested a significant portion of the proceeds of the fund credits purchased by large emitters under the SGER compliance scheme into private organizations with renewable energy, energy efficiency, carbon capture and storage, and cleaner production and processing projects, for an estimated aggregate reduction in emissions exceeding seven megatonnes by 2020. With the announcement of the CCI, the province has also highlighted approximately $1.4 billion in provincial funding for the industrial implementation of emission reduction projects, through the ERA and other government vehicles.

As the fund credit price continues to increase and as emissions reductions requirements under SGER continue to be made more rigorous, the amount of funding available for ERA research and development grants and ERA commercial investment funding will continue to grow. Importantly, ERA funding comprises a non-dilutive investment and can offer partial financing options for renewable power projects or other projects that are not otherwise commercially competitive.

(ii) Direct investment in emission offset-generating projects

Some Alberta large emitters have chosen to make a direct investment in emission offset-generating projects in the province as a means of accessing the economic upside of carbon legislation, particularly renewable power projects.

For oil and gas production or pipeline companies to invest directly in renewable energy or other emission-offset generating projects, the rationale for equity investment or outright ownership of renewable projects is multi-fold. Increasingly stringent emission reduction requirements and increasing carbon levy costs under the SGER or successor legislation will make emission offsets both more costly and more necessary and appealing. In-house development of offset-generating projects circumvents the need to identify a seller and to incur transaction costs in negotiating purchase and sale agreements.

Furthermore, vertical integration of the generation and the use of emission offsets gives a large emitter greater certainty over the ownership, protocol-compliant generation and verification of the emission offsets which are needed for its SGER compliance.

Also, investing directly and publicly in popular renewable emission offset-generating projects helps the oil and gas industry gain social license, or at least better public relations that would result from privately purchasing fund credits or entering into private, bilateral short-term contracts for emission offsets.

Furthermore, the oil and gas industry and renewables have a natural symbiosis, in that oil and gas producers often have investment capital, technological expertise, experience deploying large and capital-intensive energy projects, and pre-existing relationships in the communities where both types of projects tend to be located.

However, it is notable that the newly announced CCI Regulation will cap how much of a large emitter’s compliance with its emissions reductions can be achieved through the use of emission offsets and will shorten the shelf life of emission offsets. These two new regulations will drive parties to trade their emission offsets.

(iii) Contractual participation in the emission offset market

Some large emitters may not have the capital, core competency or interest in direct investment in renewable power or other emission offset-generating projects, but can still benefit from participation in the emission offset market as a carbon management strategy.

Large emitters which do not want to pay the $30 per tonne-and-rising fund credit price for excess carbon emissions can currently access the emission offset registry online maintained on behalf of the province, and negotiate for a purchase and sale contract for serialized emission offset credits generated in accordance with the registry’s requirements. There are several options for such contractual participation in the emission offset market, including long-term bilateral contracts.

Bilateral contracting can be quite flexible, and allows the large emitter to purchase a specified quantity of carbon credits for a specified period of time, in accordance with its needs and the profile of the emission offset-generating project. A large emitter can also negotiate the right to publicize affiliation with a specific renewable power project without having to make the full capital outlay or develop the in-house expertise required to own or operate a renewable power project. This form of contracting offers the large emitter a certainty of supply of emission offsets which the provincial offset registry or an online trading platform do not. Furthermore, agreement on a fixed price could function as a hedge against future changes to carbon pricing policy.

If the emission offset-generating project in question is a renewable power project, a noteworthy feature of the bilateral contract option is that the emission offsets can be bundled with some or all of the power produced by the project in a long-term virtual power purchase arrangement. This approach would allow a large emitter to negotiate long-term supply from one provider to minimize transaction and administrative costs and could function as a hedge on both power and emission offset prices. However, a long-term bilateral contract with a power project which is not yet constructed, which is subject to regulatory curtailment risk over time, and whose emission offsets may not be valid for use under the prevailing regulatory structure in the distant future entails a degree of risk not palatable to all large emitters. The attractive feature of long-term virtual power purchase agreements is that they can be tailored to meet the unique needs of both the renewable project proponent and the large emitter.

For those large emitters which choose to participate in emission offset contracts or invest directly in such projects, it is significant that Alberta’s emission offset protocols conform to a robust internationally recognized standard. Emission offsets in Alberta generated under this widely recognized standard often qualify as renewable energy credits, which can be used for compliance with the climate rules in other jurisdictions in Canada and the United States. Consequently, large emitters with multijurisdictional operations can apply emission offsets purchased in Alberta to meet their regulated and voluntary emissions reductions in other markets where they conduct business, and sell them outside the province where possible. Those entities which generate or buy and sell emission offsets in Alberta can leverage their emission offset generation and trading mechanisms across Canada’s different jurisdictions (which will presumably follow a similar standard pursuant to the new federal framework), and arbitrage Canadian carbon prices with those applicable internationally, to optimize their carbon management strategies and generate value for “excess” emission offsets which are not required to comply with provincial emission reduction requirements.