Introduction

In advance of the COP21 climate change meetings in Paris last December, and in concert with the carbon policies announced by the new federal Liberal government, on November 22, 2015 Alberta Premier Rachel Notley advanced several climate related policies for Alberta. Her government’s Climate Leadership Plan¹ set out four ambitious targets:

• A broad-based levy on all carbon dioxide (“CO₂”) emissions;
• A 100 megatonne cap on total oil sands CO2 emissions;
• Accelerated shut-down of coal-fired electricity generation; and
• Target quotas for renewable electrical energy generation.

These policies appear to have been well received on the world stage and should go some way towards improving Alberta’s social licence to operate. However, when combined with the economic impacts in Alberta of current low commodity prices for oil and natural gas and a parallel increase in delivered electricity prices, the latter two electrical energy related policy changes have many potential implications for Alberta’s competitive electricity generation market and its regulated transmission and distribution systems.

With the release of the provincial budget in April 2016, how these broad electrical energy policies are to be implemented, particularly under current economic conditions, would appear to be the next process step for government. Key process related questions regarding the effects of these new policies on the Alberta electrical system that both regulators and government will need to address include:

• How will coal plant shutdowns be accelerated without creating unacceptable levels of stranded assets, compromising reliability, or overly burdening electricity consumers?
• How will the mandated increase in renewable energy generation capacity be incentivized without compromising Alberta’s competitive electricity generation market? and
• How will we prevent costly duplication of transmission and distribution infrastructure as we increase the proportion of renewable electricity in the system?

In addition, in an economy where revenue from energy exports has been slashed, Albertans are also asking government to ensure that to the extent possible they are protected from other rising costs. Some of the questions raised by the proposed climate change policy include:

• How do we continue to retain and attract new investors in generative electricity capacity, increasing supply and therefore presumably reducing costs?
• How do we ensure that transmission and distribution costs better match other economic indicators in Alberta? and
• How will consumers be affected when power wholesalers shed their Power Purchase Arrangements (PPAs) and return these obligations to the Balancing Pool?

To explore at least some of these questions, we have chosen to break them into three broad areas of analysis. These are:

1. Electricity Generation: The potential impacts of accelerated coal plant closure and renewable energy integration for Alberta’s market-based generation system.
2. Electricity Transmission and Distribution: The costs, reliability and logistical consequences of bringing more distributed and intermittent renewable energy sources into the electricity grid.
3. Power Purchase Arrangements: The consequences of early terminations of PPAs for coal-generators in particular and the marketplace in general.

Underlying all three of these themes we also believe that there is a final policy question with profound regulatory consequences that also needs to be addressed by government before it moves forward with any significant changes to the current system. We wonder, given the direction and potential magnitude of the energy policy changes that will result from the implementation of the Climate Action Plan:

Is this the right time for government to assess the implications of a transition back to a fully regulated electricity system in Alberta?

Electricity Generation

Unlike other jurisdictions in Canada, electricity in Alberta is generated within a competitive market. The transition of Alberta’s electricity generation to a market-based system began in 1996 and was purportedly pursued to encourage efficiencies in the sector via a healthy infusion of competition. However, the expected larger new entrants into the commercial generation market have largely failed to appear with the few that did enter the market having fairly rapidly exited again.

New generation in Alberta has for decades been built with private capital but since 2001, the owners of electricity generation plants have been fully at financial risk for new investments in generation. Under deregulation, the Alberta Utilities Commission (AUC) now only approves:

generation at the facility level, i.e. a generator must comply with regulations such as safety, environmental, design standards and public consultation. The AUC does not regulate where generation is located in the broad sense, what type of generation is built, how much generation is built, who builds generation, nor ultimately the rate of return earned by owners.²

The Alberta Electricity System Operator (AESO) which plans for and operates most of Alberta’s electric system, including a competitive wholesale electricity market, also has no ability to dictate if, when or where new generation will be built or what returns the plants will engender for their owners. Investment decisions are driven solely by the revenues generators hope to realize from energy sales – hence the term “energy only market.”

Between 2002 and 2008, following a sharp price spike and subsequent decline as deregulation was being introduced, the price paid by Albertans for the generation portion of their power bills has risen relatively steadily. In some years, despite the earlier argument that competition should reduce power price, generation costs have also risen more rapidly than in other jurisdictions. However given that the real cost of generation was not hidden elsewhere, as also happens in some jurisdictions, the actual increases were likely reasonable and also likely reflective of the relatively strong economy.

More recently electricity prices have dropped sharply in this case in alignment with declines in the economy, first in 2009 and later in 2014. This suggests that unlike what can happen in regulated markets, the price for power generation in Alberta is at least now reflective of broader market signals, including supply relative to demand. Currently Albertans are enjoying very low generation costs presumably due to an increase in supply relative to demand and given the current economic climate, Albertans are very unlikely to welcome any changes to the system that increase these costs. This of course raises questions about the potential implications of the Climate Leadership Plan on the principles unpinning Alberta’s deregulated electricity generation market.

There are two commitments in the government’s plan that particularly trouble proponents of deregulated electricity generation. The first is an artificial acceleration of the shutdown of coal-fired electricity plants. Government has stated that by a 2030 target date “coal-fired plants will be phased out and replaced by renewable energy and natural gas-fired electricity, or by using technology to produce zero pollution.”³

The second commitment is the prescription of renewable energy targets for electricity in Alberta with government’s stated goal that: “By 2030, renewable sources like wind and solar will account for up to 30 per cent of electricity generation.”⁴ By dictating the make-up of future generation both of these policies imply a significant re-entry by government into the generation marketplace.

Albertans are now asking serious questions about how these undertakings will be implemented. With respect to the fixed retirement date for all coal-fired power plants, one major issue is the economic impact of stranded investment. Currently 18 coal-fired generating stations operate in the province. Twelve of these plants are already expected to retire without provincial intervention by 2030. These retirements will occur at the nominal end of their economic life as a result of federal regulations and hence the province should be at little or no financial risk.

However, if the provincial cut-off date for coal-fired power in Alberta remains at 2030 this leaves six plants to be retired early, before federal requirements come into effect and in some cases well before the end of their economic life. For example, the newest plant in the fleet, Keephills#3, was commissioned in 2011 and under current market forecasts and regulations would be both economic and federally compliant as late as 2051. Its potential forced early retirement to meet new provincial climate change requirements represents a major risk of stranded assets to the owners and a major risk of future costs to Alberta consumers who may ultimately become responsible for these costs. Conservative estimates of remaining net book value of these plants is in the billions of dollars should the government or the courts determine that compensation is owed.

Alberta consumers are also concerned about how price and reliability will be maintained as the various coal-fired power plants are shut down. Albertans currently depend on coal-fired power for about 65 per cent of all of the province’s base load electrical generation and in a deregulated market there is of course no publicly driven mechanism to ensure that they will be replaced. Whether due to provincial or federal requirements, a less than orderly shutdown creates the potential for reduced supply, higher prices and even more importantly, a publicly unacceptable reduction in reliability.

The 2015 Climate Leadership Report⁵ to the Minister of Environment and Parks may, quite wisely, offer at least a partial solution to this dilemma. The report does not call for shutting in of coal-fired power plants per se. Rather the Panel recommended:

that government pursue a predictable phase out of coal-fired power, should it determine that this will not occur solely as a result of the combined effects of carbon pricing, renewables policy and air quality regulations and federal end-of-life performance standards for coal plants.⁶

Since there continue to be significant advances in CO₂ capture technologies, with 14 years to implement those technologies, it would seem very reasonable for government, rather than insisting that shutting down is the only option, to also provide a second alternative. That alternative would be to afford coal-fired plant owners the option of meeting new stringent emission standards by 2030 through technology improvements.

Adopting this option would raise costs but would avoid stranded investments and maintain generation levels. Unfortunately the government has potentially limited this option by indicating that coal-fired power plants would need to have “zero pollution”⁷ to remain in operation post 2030. However, since this is a patently unfair target that no source of power, renewable or otherwise can meet, it should be possible to apply common sense and work towards optimizing the value of these remaining power plants.

Mr. Terry Boston, a recently retired power executive in the U.S., has been named by Premier Notley as the Coal Phase-Out Facilitator to advise on how the economic and power reliability implications of these early plant retirements can best be addressed. His work is very important as a government driven shutdown program that treats shareholders poorly could easily be the death knell for future private investment in the Alberta generation market.

Similar questions are being raised with respect to government’s approach to delivering its mandated increase in the province’s renewable energy portfolio with the associated answers having a wide range of potential impacts. For example, it is as yet unclear whether government expects the AESO to demonstrate that 30 per cent of produced electricity is actually generated from renewables. Or is their task to ensure that renewable sources account for 30 per cent of generation capacity? These two interpretations of the government’s target yield quite different answers with significant implications for both price and reliability.

The rate at which increased renewables are introduced is another issue. If government settles on an aggressive schedule for renewable energy transition, some look to other jurisdictions, the U.K. for example, and question Alberta’s ability to successfully integrate such significant incremental levels of wind and solar energy into the grid. The levels of dispatchable generation required to backstop the renewable production will also be significant and will likely have to be gas-fired to provide sufficient flexibility. This will require a sizable capital investment and in the absence of additional new government policy, will have to be made by private investors without any guarantee of a return. Others question the continued interest of landowners in Alberta, especially in the windy southern regions, to release vast swaths of land to wind turbines.

And like the case for mandated shut down of coal-fired generation, other significant broader policy questions remain. For example, how will the AESO accomplish either of these goals while maintaining a deregulated generation system where economics are the key signal for new private investment? Any time government chooses to incent one form of generation significantly, there is clearly a risk of dis-incenting investment into other forms of generation. For example, Layzell et al ⁸ of the University of Calgary have recently proposed that by significantly increasing cogeneration at existing and future SAGD operations, Alberta could achieve even larger CO₂ emission reductions more quickly and with much less impact to power reliability.

There is no doubt that the Alberta government wants to advance a solutions-based approach to the policy driven shut-down of coal-fired electricity generation and integration of increased levels of renewable energy into our electricity generation market. The challenge though will likely be much greater than simply finding the right pace for the transition if government also wishes to maintain both a competitive and reliable generation market.

Electricity Transmission and Distribution

Recently, Albertans have become increasingly focused on the relative costs of transmission and distribution. Unlike generation costs, transmission and distribution costs are regulated and unlike generation, have not been sensitive to the decline in the economy.

Renewable energy tends to be both more intermittent and distributed than non-renewable energy and a significant increase in renewable supply will require different transmission and distribution infrastructure than the more traditional larger power plants. For example, if a significant portion of the new renewables come from micro generation, they will rely on the distribution system to flow into the grid. These new power sources will need to be integrated into existing systems that were primarily built to support non-renewable base load power sources and/or send power into homes, not out.

The AESO has already successfully integrated wind power into Alberta’s transmission grid, especially from southern Alberta. However, the Climate Leadership Plan proposes a significant further increase in renewables. A major challenge going forward will be ramping up the pace of this integration of renewable energy into the existing infrastructure, without creating a dual system and/or major new costs to consumers.

Since transmission and distribution costs have already been rising rapidly in Alberta relative to generation costs, one question that does appear to be already up for consideration is whether even the current costs of transmission and distribution are justified. Alberta is presently divided into several regions where individual companies have the exclusive right to transmit and distribute electricity without competition. As is the case in other regulated power systems, these companies have “an obligation to serve” and so are subject to government policy directives. However, unlike generation in Alberta, these transmission and distribution companies are largely protected from the economic risks of these new policies. Provided their investments are deemed to have been “prudent” by their regulator, in this case the AUC, both capital and operating costs will normally be covered in rate base.

As a quid pro quo for the obligation to serve, regulated utilities are awarded an opportunity to earn a return on investor equity (ROE) at a rate set by the AUC. The approved ROE to 2015 was 8.3 per cent, based on 2013 economic conditions. Since the prescribed utility ROE is forward looking – i.e. it is designed to try to reflect future economic conditions based on real data from a test year, the next review of utility ROE is set for 2017, using 2015 data.

While the 2015 data will presumably reflect a fair portion of the effects of the recent economic slowdown, for many companies in today’s economy an 8.3 per cent ROE would of course be considered exceptional. Therefore in setting a new ROE for the utilities, although the AUC is expected to rely only on data for the test year, there will likely be significant pressure on the AUC from consumers to take into account data post 2015 as well in determining what future ROE during a provincial wide recession is “just and reasonable.” The AUC will undoubtedly be asked to consider the question: “Since other companies operating in Alberta are doing more, for less, shouldn’t our regulated utilities be expected to at least do the same?”

Even under less stressful conditions, there is always pressure from consumers in rate cases to ask the regulator to look beyond the test year, particularly if this will lead to lower costs. However, in our view, while this is tempting, setting the “right” ROE is never easy since too low a return on investment can often raise other costs, including growing costs which are also passed on to consumers.

Nor does Alberta need even more uncertainty in the electricity marketplace, which a politically driven rate case would surely create. Utilities have an obligation to transmit and deliver electricity to Albertans; in that way, they are captive. So, fairness, all round, and a long view, are essential.

However, there may be other mechanisms available to either government or the AESO which could potentially have an even more significant positive impact on future transmission rates. If increased costs of adding significant amounts of renewables cannot be avoided, then there is particular incentive for government, as it implements the Climate Leadership Plan, to actively look at these options.

Of particular note is the potential to reconsider the need for as yet unbuilt transmission lines.

In 2009, in the midst of several years of “hockey-stick” economic growth projections, rancorous debate about the appropriate apportioning of roles between government and regulators with respect to new transmission decisions culminated in Bill 50.⁹ This legislation moved responsibility for establishing whether there was a need for new transmission from the AUC to the government, and eventually led to approval of an ambitious build of new transmission in Alberta, including two major North-South lines between Calgary and Edmonton and two from Edmonton to Fort McMurray.

The two southern transmission lines have already been completed and are now partially reflected in utility bills. However, the application for the first line to Fort McMurray, which is budgeted at $1.433 billion, comes before the AUC in June. Although the AUC is currently no longer allowed to determine whether this line is needed, others parties can. It would seem to be extremely prudent for this government to ask its officials, particularly in the face of a sharp decline in oil sands activity, to very carefully re-examine the need for this massive expansion in transmission as it is currently designed. Albertans may clearly prefer to spend on other priorities.

A second option the government has for reducing transmission costs is to take a close look at the “zero congestion” directive of the AESO and the impacts this policy is having on costs. In the February 2012 Government of Alberta Powering Our Economy: Critical Transmission Review Committee Report, an uncongested network and the role of the AESO in delivering that network are described as:

A robust and unconstrained transmission system…that provides equal access so all consumers and generators can connect to the grid….. The AESO is required to plan a transmission system that is sufficiently robust so that 100 percent of the time [emphasis added] transmission of all anticipated in–merit electrical energy can occur when all transmission facilities are in service…..¹⁰

The “zero congestion” policy was conceived on the premise that by removing transmission constraints, the success of the then fledgling competitive power generation market would be much more likely. It was also expected to lower the cost of generation by ensuring the cheapest power was also dispatched.

Zero congestion would appear to be a wonderful ideal – if you are a generator – but is it sound policy for consumers? This question becomes even more relevant as transmission costs take up an ever greater portion of the total consumer utility bill. Since as a result of government policy consumers foot the entire bill for new transmission, a very simple yet potentially very beneficial step by government may be to ask the AUC to re-examine the need for and efficacy of this policy. For example, it may now be significantly more cost effective to build less infrastructure and backfill any constrained flow with improved contracting and short term use of higher priced electricity, including imports from B.C.

A third opportunity to better control the transmission and distribution costs being passed directly on to consumers would be to better ensure that the associated capital costs are kept as low as possible. Currently, the “prudency” of these costs are assessed after the fact by the AUC and the AUC is understandably reluctant to apply the luxury of 20-20 hindsight to already incurred costs. A simple additional step in this process would be to require that utilities have independent cost managers in place to oversee costs on transmission and distribution projects as they are being built rather than after the fact. The idea of an independent cost oversight manager, not dissimilar to what in industry is referred to as an “owner’s engineer,” has been tested in other jurisdictions, with positive outcomes.

It may be time for sober second thought on Alberta’s electricity transmission and distribution policies. More than ever, Albertans need to be smart in how we bring on new kinds of power, including more wind and other intermittent renewable energy, and how we connect that power to consumers. Part of that wisdom includes managing all of the costs.

Cancellation of Power Purchase Arrangements

Transitioning from a regulated to a deregulated energy market in the late 1990s created a number of legacies. To accomplish its goals, government was forced to artificially create a power market (the Power Pool operated by the AESO) as well as reduce the market power of the incumbent operators (generators). Since government also hoped to accomplish this reduction in market power without forcing the operators to sell their assets, the PPA was introduced as a tool to accomplish this goal. The PPA was intended to carry on the previous regulatory compact between government and operators by providing the owners of these already approved and previously regulated generating assets the opportunity to recover their fixed and variable costs for a pre-established “life of the project.”

The PPAs were sold at auction to buyers who believed that the revenues they could receive from electricity sales through the Power Pool over the life of the arrangement would be sufficiently greater than the purchase price for the PPA. However, not all of the PPAs offered for sale received an acceptable bid and the buyer obligations for the unsold PPAs were assumed by the Balancing Pool. The Balancing Pool was created by statute as the legislative entity responsible to fill the void if no purchaser bid to acquire a PPA at the time of deregulation. The Balancing Pool is also required, if certain conditions are met, to assume a PPA that had previously been acquired by power buyers.

It is this latter option which is currently creating consternation in the Alberta power market. The PPAs include a clause giving the power buyer the right to terminate the PPA under certain pre-agreed conditions, including a change in environmental laws that make the PPA “unprofitable or more unprofitable”.   Recently in Alberta there has been a spate of PPA terminations between four power buyers, ENMAX, TransCanada, AltaGas and Capital Power and two coal-fired electricity generators, TransAlta and ATCO. These cancellations were ostensibly the result of recent changes in Alberta’s climate change policies, in this case the Specified Gas Emitters Regulation (“SGER”).¹¹ These changes, the power buyers have argued, have effectively made the PPAs “more unprofitable”.

These terminations by the power buyers have in turn triggered the requirement that the Balancing Pool, and through the Balancing Pool, the public, reassume responsibility for these PPAs. This assumption of contracts by the Balancing Pool and the linkage back to government climate change policies as the trigger for the terminations, has raised significant media attention and a number of interesting questions. Although Albertans are likely unfamiliar with most if not all of the terms and concepts, if they are listening to the media coverage, they are likely now wondering about the implications of these terminations for consumers and about the role of the Balancing Pool, until now a relatively obscure entity.

While there are a number of contentious issues associated with the early termination of the PPAs, there appears to be general agreement on the following three points:

1. In the context of current power pool prices, coal-fired generation PPAs are not generally considered economic.                   There appears to be little doubt that few generators, irrespective of fuel source, are finding current prices to be acceptable. This is likely particularly true for large base load coal-fired power plants unable to take advantage of short term price variability. Of note, however, these same PPAs have been economic in the past and should electricity prices increase to past levels, these PPAs may very well be economic again in the future, even with the increased costs triggered by the new rules under SGER and/or its future replacement, the carbon levy.
2. The new SGER provisions (or any similar form of carbon levy) will increase costs for the holders of the PPAs.         Since available energy efficiencies have likely already been tapped to satisfy earlier SGER requirements, meeting these incremental requirements almost undoubtedly will require coal-fired power generators to reduce their emissions by deploying new technology (and therefore capital) or alternatively to pay an increased per tonne price. Furthermore, these costs seem to be transferable, through the PPAs, from the generators to the buyers. If so, profitability of the PPAs for the buyers will be further reduced by the new SGER requirements.
3. If the PPAs are legally terminated, the Balancing Pool is legislatively obligated to assume the responsibilities of the buyer to the operator.       There appears to be little debate about this last point. Rather the question hinges more on what options the Balancing Pool might have in addressing these PPAs. The three options appear to be:
   1. Continue to offer the electricity into the Power Pool. If this option is chosen, electricity consumers would pay the difference between the contract price and the price actually received for the electricity in the pool.
   2. Attempt to sell the PPA. To accomplish this, the Balancing Pool would have to find another willing buyer. In the current marketplace, this option seems highly unlikely to be successful in the near term but may become feasible over time.
   3. Terminate the PPA. The Balancing Pool can choose to end the relationship with the generator and pay the net book value of what is left to run under the individual contract. This has been done before and can be expensive. In 2005, the Clover Bar PPA was terminated by the Balancing Pool and the owner of the facility was paid $83-million, the remaining net book value.

Clearly none of these options are likely to benefit Alberta consumers. And, if not addressed, the long term impacts of these terminations remain uncertain. For example, currently, the Balancing Pool issues a credit to consumers on their electricity bills, in the range of $3/month. If all of the electricity under the recently terminated PPAs was sent to the Power Pool, this credit could flip to a charge on consumer bills in the range of $5 to $10/month. While the Balancing Pool may be able to offset some of these costs, to the extent the PPA terminations trigger increases in power costs, the political space available to government to advance its Climate Leadership Plan is likely to be reduced.

Based on the initial response from government to the early termination of the PPAs, it would appear likely that this was an unintended consequence of the requirement for additional carbon reduction under SGER. A key question now being asked is whether the recent changes to SGER do in fact allow the buyers to legally terminate their PPAs. While the Alberta Government appears to be suggesting that this is a question still open for discussion, our initial reading of the language in the PPAs suggests this argument may be a difficult one for government to successfully advance. Of course, given the significance of this issue, it’s likely that courts will ultimately be weighing in on the question.

That said, since it was government that introduced the SGER changes, in our view, government may also be able to mitigate or reverse the impacts by removing the trigger for the PPA terminations. Presumably government could exempt coal-fired power plants from the new SGER requirements entirely. The rationale for this exemption would be that, unlike other industries, coal-fired power plants are already being treated separately and in fact more aggressively as they are subject to complete shutdown within a fixed timeline. To require already approved coal-fired power plants to now meet both sets of regulatory requirements may be quite unfair, especially as original investments were made in a regulated environment and there are few near-term opportunities to manage these incremental economic costs.

Conclusions

Moving forward to implement its ambitious Climate Leadership Plan is a priority for Alberta’s Government, and as a means of improving how Alberta is perceived in the world market, is certainly justified. However, the electricity systems in Alberta are unique, and the implications of climate change policies for generation, transmission and distribution are inter-twined and sometimes difficult to predict. As the government makes changes to carbon levies and policies, it will be essential to scrutinize the impacts and be adaptive, to assure that the intended outcomes (e.g. emissions reductions) are actually achieved and unintended consequences (e.g. loss of investor confidence or system reliability) are understood and managed.

As the “legacy” power plants gradually reach the end of their economic life, the electricity being produced in Alberta is increasingly being generated by companies that chose to invest in an open and competitive market. An even further accelerated shut-down of coal-fired plants, coupled with a legislated and aggressive ramping up of renewable energy sources (presumably through the use of incentives), will need to be carefully orchestrated if we are to preserve this desire to invest. Too much uncertainty, including a lack of full understanding of the consequences of inter-connected policies and overly rigid rules when more flexibility could meet the same goals, will unnecessarily put levels of future investment at risk.

The proposed changes in power mix under the Climate Leadership Plan – triggered by the shutting down of large base-load plants and the introduction of new tranches of more distributed and intermittent renewable energy sources into Alberta’s electricity grid – will also impact electricity costs, reliability and logistics. Taxpayers are assuming a new carbon levy, effective 2017, and will understandably be wary of funding even further costs to green the grid. This is all the more true in the midst of an economic recession. These concerns may significantly limit the government’s ability to implement its policies over the longer term.

We encourage government to comprehensively review the full life cycle costs of their recommended changes to the electrical energy matrix. As well, we strongly encourage government to evaluate the impacts of existing policies (e.g. AESO’s zero congestion directive) and infrastructure plans (e.g. the transmission build from Edmonton to Fort McMurray) to identify other sources of savings to help offset some of the economic impacts of the Climate Leadership Plan.

Finally, the early terminations of PPAs with coal-fired generators are very likely an excellent example of an unintended consequence of the government’s focus on reducing emissions. Challenging the legality of these terminations in court is one option, but we would urge government to consider easier solutions, including simply reinstating the previous SGER requirements for coal-fired generation. This recalibration would be fair and an easily justifiable small step “backward” particularly if it allows the overall Climate Leadership Plan to move forward.

Underlying all of these themes, we also believe that there is a final policy/regulatory question that needs to be addressed by government before it moves forward with any significant changes to the current electricity system. Given the direction and potential significance of the energy policy changes being proposed, is this the right time to proactively assess the implications of a transition back to a fully regulated electricity system in Alberta?

It is quite possible that the proposed changes are already sufficiently substantive to trigger the end of future investment in Alberta’s power market, absent some form of price guarantee. If this happens, without a plan in hand, these impacts may prove to be by far the most costly and unintended consequences of the Climate Leadership Plan.

*Donna Kennedy-Glans, Q.C., lawyer and businesswoman, former energy executive and Associate Minister of Electricity and Renewable Energy (Alberta).

**Dr. Brian Bietz, environmental scientist and regulatory consultant, former Board Member, Alberta Energy and Utilities Board and Chair, Natural Resources Conservation Board.

1. Government of Alberta, Climate Leadership Plan, (Edmonton: 22 November 2015) [Climate Leadership Plan], online: Government of Alberta <http://www.alberta.ca/climate-leadership-plan.cfm>.
2. Alberta Utilities Commission, “Alberta’s Energy Market” online: AUC <http://www.auc.ab.ca/market-oversight/albertas-energy-market/Pages/default.aspx>.
3. Climate Leadership Plan, supra note 1 at “Ending Coal Pollution” section.
4. Ibid.
5. Government of Alberta, Climate Leadership Report to Minister, (Edmonton: 20 November 2015) at p 48 under “Implementation of Regulated Coal Phase Out”.
6. Ibid.
7. Supra note 3.
8. David B Layzell et al, “A Strategy to Reduce the Carbon Footprint of SAGD Production”, (Industry Trends and New Technology delivered at the Annual Conference of the Canadian Heavy Oil Association, Calgary, 5 April 2016) [unpublished].
9. Bill 50, Electric Statutes Amendment Act, 2nd Sess, 27th Leg, Alberta, 2009.
10. Government of Alberta, Powering Our Economy: Critical Transmission Review Committee Report, (Edmonton: February 2012), online: Government of Alberta <http://www.energy.alberta.ca/Electricity/pdfs/CTRCPoweringOurEconomy.pdf>.
11. Specified Gas Emitters Regulation, Alta Reg 139/2007.