Alberta’s New Energy Innovation Fund

Last week was a big week of announcements from the Alberta Government on its plans to reduce greenhouse gas emissions and diversify the Alberta economy. On December 5, 2017, the creation of a $1.4 billion Energy Innovation Fund to diversify the economy and reduce carbon pollution in the province was announced. The bulk of the funding for the Energy Innovation Fund results from the carbon levies that are being collected under the Climate Leadership Plan. 

The Energy Innovation Fund has five categories:

  • Oil Sand Innovation Fund – $440 million to help oil sand developers  increase production and reduce emissions, while adjusting to the new Carbon Competitive Incentive rules for large emitters. Funding in the Oil Sand Innovation Fund will start at $40 million a year in 2019-20, rising to $80 million in 2020-21 through 2024-25 until the $440 million fund has been depleted.

  • Innovation Across Sectors – $225 million for projects across sectors that support research, commercialization and investment in new technologies that reduce emissions in two program areas: Emissions Reductions Alberta ($80 million) and the new Climate Change Innovation and Technology Framework ($145 million). This new Climate Change Innovation and Technology Framework will help manage government investments in research, innovation and technology and will help commercialize products. 

  • Industrial Energy Efficiency – $240 million for projects that help companies reduce emissions and costs by upgrading equipment or facilities to lower energy use. Support will be available for large industrial, agricultural and manufacturing operations. 

  • Bioenergy – $63 million in grants for bioenergy projects, including biodiesel and ethanol – as well biomass-based electricity generation. Alberta’s existing Bioenergy Producer Program will be adjusted to provide grants to dedicated biofuel-producing facilities. 

  • Green Loan Guarantees – $400 million in loan guarantees to support investment in efficiency and renewable energy measures to reduce risk for financial institutions and make it easier for companies to invest.

If you would like to learn more about how the funds may impact your business, the Energy, Environmental and Regulatory Group at McLennan Ross would be pleased to assist you.

New “Rewards” for Low Carbon Emissions from Alberta’s Largest Greenhouse Gas Producers

By JoAnn P. Jamieson and Brittany Scott

The Alberta Government on December 6, 2017 formally unveiled its plans to reboot the carbon levy for Alberta’s largest emitters of greenhouse gases – those who emit more than 100,000 tonnes of carbon per year. This plan, known as the Carbon Competitiveness Incentives (“CCI”), will give companies credits if their facilities produce less than a benchmark amount of emissions, while those that exceed the threshold will have to buy offsets or pay $30 for every tonne of emissions over the limit. The CCI plan comes into effect on January 1, 2018 and replaces the Specified Gas Emitters Regulation. In order to ease the transition and to avoid “big hits” to industry, the government is going to phase in the full impact of the CCI plan over the next three years where industry will pay 50% of costs in 2018, 75% of costs in 2019, and the full amount of costs in 2020.

The aim of the CCI is for the Alberta government to protect its largest industries from competitive impacts that could simply shift production to other jurisdictions without a carbon levy. The idea now is that Alberta's heavy emitters will receive a reserve of "free" greenhouse gas emission credits, to be determined by a sector emissions benchmark. Benchmarks will be set relative to high-performing industrial projects that produce the same or similar products. Most industries will have a benchmark set at 80% of production-weighted average emissions. In the oil sands, emissions intensity will be measured by the amount of greenhouse gas produced in extracting one barrel of oil and the benchmark will be the top quartile of projects or 57.7 kilograms of carbon dioxide equivalent per barrel. Previously under the Specified Gas Emitters Regulation, heavy emitters were judged based on how improved they were from their historical performance – now, they will be judged against their competitors under an output-based allocation system that will be called the CCI.

The Alberta Government expects that, as a result of CCI, greenhouse gas emissions will be cut by 20 million tonnes by 2020 and 50 million tonnes by 2030. However, costs are also expected to be high, with the Alberta Government estimating the total value of levies per year coming in at upwards of $1.2 billion annually when in full force in 2020, though offsets and credits mean the NDP Government expects to take in closer to $800 million.

If you have any questions or concerns about how this will affect you, the Energy, Environmental and Regulatory Group at McLennan Ross would be happy to assist you.

The Costly Future of Site C

By JoAnn P. Jamieson and Brittany J.A. Scott

BC Hydro’s Site C Hydroelectric Project (“Site C”) has been a contentious endeavor from the start.1 In the latest chapter of the saga, the British Columbia Utilities Commission (the “BCUC”) released its final report (“Final Report”) on its inquiry (“Inquiry”) into the implications and costs of continuing, terminating, or suspending construction (with the option to resume by 2024).2 All three possible scenarios come with execution risk and a hefty price tag.


Site C is being built in the northeastern Peace River region and includes a new reservoir that will run 83 km along the Peace River and submerge approximately 5,000 hectares of land. Site C is forecasted to provide a peak capacity of approximately 1,145 MW and 5,286 annual GWh of electricity, which will power the equivalent of approximately 450,000 homes annually for approximately 100 years.

Under the Clean Energy Act3 Site C was exempt from having to obtain a Certificate of Public Convenience and Need from the BCUC; however an extensive environmental assessment was completed through a joint federal-provincial review panel hearing process in 2014. BC Hydro received approval to proceed from the provincial government in December 2014, and construction began in summer 2015.

Site C played a major role in the 2017 BC provincial election. After the NDP leader John Horgan became Premier, the newly-formed provincial government directed the BCUC to investigate Site C with the aim of answering four questions.4
  1. What are the implications, including costs to ratepayers, of (i) completing Site C by 2024, (ii) suspending Site C while maintaining the option to resume construction until 2024, and (iii) terminating construction and remediating the site?
  2. Is Site C on time and within the proposed $8.335 billion budget, excluding the $440 million project reserve established and held by the province?
  3. What are the mechanisms available to recover any costs associated with suspending or terminating Site C?
  4. Given the Clean Energy Act's objectives,5 could any other portfolio of generating projects and demand-side management initiatives provide similar benefits at similar or lower energy cost as Site C? 
The Inquiry followed a two stage process. The first phase consisted of fact gathering in which BC Hydro, Deloitte LLP, and members of the public were allowed to provide submissions to inform the Inquiry Panel’s preliminary report published on September 20, 2017 (“Preliminary Report”).6 This Preliminary Report noted that Site C was on schedule but found that the available information was insufficient to assess possible scenarios identified at that time. Given the limitations in the first phase, in the second phase, the Panel continued its inquiry with a series of community input sessions, First Nations input sessions, and technical sessions across the province. This second phase of the Inquiry resulted in the Final Report. 

Key Findings from the Final Report


The Panel begins the Final Report by assessing BC Hydro’s current load forecast and resource balance and surplus energy and capacity issues. The Panel found BC Hydro's “mid” load forecast to be “excessively optimistic” in light of recent economic developments in the province, and therefore used the “low” load forecast for its findings throughout the Final Report, noting that electricity demand could be less than even the low forecast. The Final Report then provides an extensive review of numerous risks that could impact the benefits of the proposed cases, including the emergence of disruptive technologies, construction cost overruns, the costs of developing alternative energy generation and variability in the province’s economy. 

Case 1: Complete Site C

The Panel reiterated that Site C is currently on schedule for an in-service date of November 2024, while also noting potential significant risks to the proposed timeline.  In particular, the Panel found it concerning that BC Hydro announced a one year delay at the start of the river diversion due to tension cracks in the Peace River valley near Fort St. John. Given the physical limitations of construction in this area, construction can only occur during a one-month window when river flow is at a low level. The Panel concluded that if the river diversion is not achieved by September 2019, Site C will not remain within its proposed budget of $8.335 billion.

The Final Report updates the Panel’s earlier findings on Site C’s budget including the additional costs associated with the delayed river diversion and numerous unresolved geotechnical and contractor issues, concluding that it may cost over $10 billion to complete. Further, the Panel notes that since Site C is still in its early stage of construction, there is much uncertainty given that the Peace River valley is an area prone to landslides. This inherent uncertainty may come with a price tag of being between 20-50% over budget.  


Case 2: Terminate Site C

The Panel found that terminating Site C would result in combined termination and remediation costs between $750 million to $2.3 billion, exclusive of the $2.1 billion in sunk costs to date. The Panel expressly recognized that whether taxpayers ought to pay for sunk costs instead of ratepayers in the future may be challenged, but did not take a position or affix a value of this in their analysis. Given a sensitivity calculation, the Panel estimated that terminating Site C would cost about $1.8 billion. 

The Panel agreed with BC Hydro that financing and alternative energy costs must be considered when looking at the total impact of termination to the ratepayer. In this analysis, the Panel considered whether another portfolio of commercially feasible alternative generation and demand-side management initiatives could provide similar benefits to Site C at a similar or lower unit energy cost. The Panel concluded that it is plausible to design an alternative portfolio at a lower unit energy cost than Site C, but at a slightly higher overall cost to the ratepayers ($3.234 billion for the Illustrative Alternative Portfolio compared to $3.188 billion for Site C). 

The Panel notes that to be competitive, an alternative portfolio must provide sufficient savings to account for the $1.8 billion in expected termination and remediation costs. Given the type of energy provided by Site C, many alternative types of energy such as wind are not dispatchable so they do not provide the same benefit to ratepayers. The Panel discusses this conundrum and concludes that because BC Hydro has substantial existing dispatchable energy, the “Illustrative Alternative Portfolio” (which has a relatively small amount of wind) would effectively provide the same value as that from Site C. 

Case 3: Suspend Site C with the Option to Resume in 2024

The Panel stated that the suspension scenario results in the highest total cost to ratepayers and most risky option. The Panel concluded that putting Site C into a state of suspension, would be just as costly as termination, if not more. In addition, suspension carries remobilization costs and the costs to complete the project beginning in 2024 including retendering contracts, renegotiating First Nations’ benefit agreements, and a restart of environmental permitting upon resumption of construction. The Panel estimated the costs to suspend, restart, and complete Site C, with some adjustments to the estimated $13.6 billion figure provided by BC Hydro, as being $14.812 billion.



The Final Report notes that all of the three options for Site C come with a hefty price tag:
  1. Completion comes with a risk of an in-service date of later than 2024 and a high probability of being over the $8.335 billion budget,
  2. Termination comes with the combined termination costs (estimated at $1.8 billion) plus the costs to secure generation from alternative sources comparable to completing Site C exclusive of the $2.1 billion in sunk costs to date, and
  3. Suspension carries an estimated cost of $14.8 billion.

Of the three options, the Final Report concludes that the scenario suspending the construction process until 2024 presents the greatest cost to ratepayers and is accompanied by further potentially-costly risks.

Given the BCUC’s cost estimates of each option, the Panel seems to suggests that a basket of renewable projects has a roughly comparable cost to completing the Site C. However, the Final Report advises that specific uncertainties associated with terminating or continuing will determine comparative viability. In particular, the potential for further cost overruns and the materialization of a higher or lower load forecast will be the primary determinative factors. Although the Final Report lacks a recommendation on which scenario is “best”, the Panel’s analysis and findings is intended to inform the BC Government’s decisions on the future of Site C. 


[1] It has been the subject of extensive debate during the provincial elections and much litigation including, but not limited to, Prophet River First Nation v Canada (Attorney General), 2017 FCA 15; Prophet River First Nation v British Columbia (Minister of Environment), 2015 BCSC 1682, aff’d 2017 BCCA 58; Prophet River First Nation v British Columbia (Minister of Forests, Lands and Natural Resource Operations), 2016 BCSC 2007; Peace Valley Landowner Assn. v British Columbia (Minister of Environment), 2015 BCSC 1129, aff’d 2016 BCCA 377; Peace Valley Landowner Assn. v  Canada (Attorney General), 2015 FC 1027; Peace Valley Landowner Assn. v  Canada (Attorney General), 2015 FC 1030; and British Columbia Hydro and Power Authority v Boon, 2016 BCSC 355.

[2] Released on November 1, 2017. Available at:

[3] Clean Energy Act, SBC 2010, c 22, s 7(1)(d).

[4] The Lieutenant Governor directed the BCUC to initiate the inquiry pursuant to Order-in-Council dated August 2, 2017 utilizing  its powers under section 5 of the Utilities Commission Act, RSBC 1996, c 473.

[5] Clean Energy Act, s 2. These objectives include, but are not limited to, achieving electricity self-sufficiency in BC, reducing electricity demand by 2020 by at least 66%, generating at least 93% of electricity in BC from clean or renewable sources, reducing BC’s greenhouse gas emissions, encourage economic development and creation/retention of jobs, and become a net exporter of clean electricity.