Public Document
IN THE MATTER OF AN ARBITRATION UNDER CHAPTER ELEVEN OF THE
NORTH AMERICAN FREE TRADE AGREEMENT
AND THE 1976 UNCITRAL ARBITRATION RULES
BETWEEN:
| WESTMORELAND MINING HOLDINGS LLC | Claimant |
AND
| GOVERNMENT OF CANADA | Respondent |
(ICSID Case No. UNCT/20/3)
GOVERNMENT OF CANADA
STATEMENT OF DEFENCE
June 26, 2020
Trade Law Bureau
Government of Canada
Lester B. Pearson Building
125 Sussex Drive
Ottawa, Ontario
K1A 0G2
CANADA
2. Alberta Considers Changes to Existing Emissions Regulations in 2013 ..........12
D. The Claimant’s 2019 Investment in Coal Mines in Canada ........................................25
III. THE TRIBUNAL DOES NOT HAVE JURISDICTION OVER THE CLAIMS ........26
V. CANADA HAS NOT VIOLATED ITS NAFTA OBLIGATIONS....................................30
VI. THE CLAIMANT’S DAMAGES CLAIM IS WITHOUT MERIT ...................................35
VII. CANADA’S PROPOSAL TO BIFURCATE THE PROCEEDINGS ..............................36
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1. Canada files this Statement of Defence in response to the Notice of Arbitration and Statement of Claim (“NOA”) filed by Westmoreland Mining Holdings LLC (the “Claimant” or “WMH”) against Canada on August 12, 2019.1 The Claimant brings this claim under NAFTA Chapter Eleven on behalf of itself and its subsidiary, Prairie Mines & Royalty ULC (“Prairie”), in connection with its investment in coal mines located in the Province of Alberta. The Claimant demands at least $470 million2 for alleged violations of NAFTA Articles 1102 (National Treatment) and 1105 (Minimum Standard of Treatment).
2. The Claimant’s NOA is nearly identical to a Notice of Arbitration and Statement of Claim filed by Westmoreland Coal Company (“WCC”) against Canada under NAFTA Chapter Eleven on November 19, 2018. WCC filed that NAFTA claim after submitting a petition for bankruptcy in the United States (“U.S.”) on October 9, 2018. On March 15, 2019, WCC announced that it had sold Prairie to the Claimant, a new company formed by WCC creditors. WCC is set to dissolve. WCC withdrew its NAFTA claim against Canada on July 23, 2019, and the Claimant filed the current claim less than a month later.
3. The Claimant explains in its NOA: “[t]he term ‘Westmoreland’ is used generically throughout this Notice of Arbitration and Statement of Claim to describe the facts and circumstances of the dispute.”3 However, the Claimant is not the same entity as WCC. The companies are distinct, and acquired investments in Canada at fundamentally different times. NAFTA Chapter Eleven does not allow an investor of a Party to file a claim on behalf of another investor. The Claimant must have had ownership or control of its investments at the time of the alleged breaches. It did not.
4. The Claimant nonetheless seeks millions of dollars in damages for the alleged economic disruption caused to WCC and its investments in coal mines by the Government of Alberta’s decision
1 Westmoreland Mining Holdings LLC, Notice of Arbitration, 12 August 2019 (“NOA”). ↩
2 Unless otherwise specified, all references to dollar amounts in this Statement of Defence are in Canadian dollars. ↩
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to phase out greenhouse gas (“GHG”) emissions and air pollutants (together, “emissions”) produced by coal-fired electricity generation by the year 2030. The decision was part of the Government of Alberta’s broader Climate Leadership Plan, which it announced on November 22, 2015 (the “2015 Climate Leadership Plan” or “Plan”). A response to climate change, the Plan was a comprehensive strategy to reduce emissions in the province. Since coal-fired electricity was the second-highest GHG-emitting sector in the province, Alberta’s decision to phase out emissions from coal-fired power plants by 2030 contributed significantly to its overall policy objective of reducing GHG emissions and air pollutants.
5. The Claimant alleges that “Albertan coalmine operators” were paid millions of dollars for the economic disruption allegedly caused to their operations by the coal-fired emissions aspects of the 2015 Climate Leadership Plan “to the exclusion of the only American coalmine operator”.4 This is incorrect. No company or individual received any payment from the Government of Alberta with respect to any interest in any coal mine under the 2015 Climate Leadership Plan or otherwise. Furthermore, coal mining was not a focal point of the 2015 Climate Leadership Plan because coal mining has a relatively low emissions profile. The Plan took no policy stance on the continued mining of coal in the province – it did not address any mineral rights, leases, land tenures, permits, ownership, royalty interests, or coal supply contracts.
6. The payments in question were voluntary payments that the Government of Alberta undertook, in 2016, to provide to the owners of the six coal-fired generating units in the province that were expected to operate – and produce emissions – beyond 2030 (“Transition Payments”). In exchange for these payments, the three owners (ATCO, Capital Power, TransAlta) committed to ceasing emissions from the six generating units by 2030, and to continue participating in the electricity market in Alberta. In undertaking to provide the Transition Payments, the Government of Alberta was concerned with reducing emissions from the high-emitting electricity sector. It was also concerned with ensuring that it could attract a sufficient level of continued investment in the electricity sector to maintain a reliable grid and reasonable price stability for consumers as the Province transitioned to a lower-carbon electricity system. This was particularly important in the context of Alberta’s
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unique competitive market for electricity generation in which the timing of, and need for, new generation assets are dictated by market forces, rather than by a centralized plan or a government utility. The Claimant’s claim that WCC, a coal mining company, was owed a Transition Payment similar to those paid to power companies is nothing short of an attempt at a windfall and must be rejected.
7. As Canada will explain in greater detail, the Claimant’s claims must be dismissed for several reasons. First, the claims fall outside of the Tribunal’s jurisdiction. In particular, the Tribunal lacks jurisdiction ratione temporis because the Claimant was not an “investor of a Party” at the time of the alleged breaches. The measures the Claimant challenges also do not “relat[e] to” the Claimant or its investments as required by NAFTA Article 1101(1) – NAFTA Chapter Eleven’s jurisdictional gateway to arbitration – because they pre-date the existence of the Claimant and its investments in Canada. Moreover, neither the Claimant nor its investments could have suffered damages arising out of the alleged breaches, as required under NAFTA Articles 1116(1) and 1117(1), because the alleged breaches transpired in 2015 and 2016, before the Claimant acquired its investments in 2019. These jurisdictional defects bar consideration of the Claimant’s claims in their entirety. In addition, any claims challenging the Government of Alberta’s decision to phase out emissions from coal-fired electricity in its 2015 Climate Leadership Plan must be rejected because they are time-barred under NAFTA Articles 1116(2) and 1117(2).
8. Second, the Claimant’s claim that the Government of Alberta’s decision to grant Transition Payments violated NAFTA Article 1102 must be dismissed because it is inadmissible by virtue of NAFTA Article 1108(7)(b). Under Article 1108(7)(b), “subsidies or grants provided by a Party” are excluded from the application of Article 1102, and the Transition Payments fall within this plain language. In particular, the Transition Payments are made under Alberta’s Energy Grants Regulation, which gives Alberta’s Minister of Energy the authority to “make grants to any person or organization in respect of any matter that is under the Minister’s administration.”5 The Transition Payments are
5 R-001, Energy Grants Regulation, A.R. 103/2003, s. 2. ↩
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also listed in the Government of Alberta’s publicly available grant payments disclosure table.6 As a result, the Tribunal may not consider the Claimant’s claim that the Government of Alberta failed to grant WCC a Transition Payment in contravention of NAFTA Article 1102.
9. Third, the Claimant’s NAFTA Article 1102 claim is without merit, in any event. Alberta did not discriminate against the Claimant on the basis of nationality in its allocation of Transition Payments, nor was its alleged treatment of the Claimant and the three electricity market participants that owned the six coal-fired generating units accorded “in like circumstances.” Both are necessary elements of an Article 1102 claim and both are absent in this case. The Claimant is one of several entities with investments in coal mines in Alberta, and not a single company or individual with coal mine interests received any sort of payment from the Government of Alberta for those interests under the 2015 Climate Leadership Plan or otherwise. Providing Transition Payments for interests in coal mines would not have advanced the Government of Alberta’s policy objective of reducing emissions in its electricity sector, while maintaining the reliability of the electricity system. The Claimant’s claim under NAFTA Article 1102 has no merit.
10. Fourth, both of the Claimant’s NAFTA Article 1105 claims must be rejected on their merits. The Claimant first alleges that the Government of Alberta violated Article 1105 because WCC was “arbitrarily and uniquely excluded”7 from receiving a Transition Payment. However, this allegation essentially repeats the Claimant’s allegation under NAFTA Article 1102. Nothing the Government of Alberta did comes close to being arbitrary and NAFTA tribunals have consistently held that Article 1105 is not a vehicle through which to recycle the same allegations made under Article 1102.
11. The Claimant next alleges that the Government of Alberta’s decision to phase out emissions from coal-fired electricity generation in its 2015 Climate Leadership Plan violated NAFTA Article 1105 because it disrupted the “predictable future”8 established for WCC and its investments by Canada’s Federal Government under emissions regulations enacted in 2012. However, government
6 R-002, Government of Alberta, Grant payments disclosure table, “CLP Coal Generation Transition”, “Energy General Armed” [Excerpts], available at: https://www.alberta.ca/grant-payments-disclosure-table.aspx. ↩
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regulations alone do not offer a predictable future, let alone in a federation like Canada where provinces have the constitutional prerogative to regulate emissions within their borders. Moreover, when WCC made its investment in Canada, increasingly stringent requirements for lower emissions from electricity generation were the trend globally and across Canada, including in Alberta. Public filings made by WCC at the time of its investment in Canada confirm its understanding of these regulatory trends.
12. The Claimant is thus incorrect to suggest that WCC reasonably believed its investments would have a predictable future under the federal regulations. Moreover, there are further factual flaws in the Claimant’s allegations as the federal regulations that had been enacted in 2012 were amended in 2018 such that, by the time the Claimant invested in Canada, the federal regulations required all coal-fired electricity generating units across Canada to meet stringent emissions performance standards earlier than under the 2012 version of the regulations – by December 31, 2029, at the latest. For all of these reasons, the Claimant’s Article 1105 claims must be dismissed.
13. Finally, the Claimant’s demand for “damages exceeding $470 million”9 is exaggerated, and ultimately, groundless. Two of the three coal mines the Claimant raises in its NOA – the Paintearth mine and the Sheerness mine – have reserves that will be exhausted in 2022 and 2024, respectively,10 well in advance of 2030 when emissions from coal-fired generating units in Alberta must be reduced to zero. The third mine – the Genesee mine – was owned jointly by WCC and Capital Power. On March 28, 2017, the two companies announced they had entered into a $70 million agreement with
10 NOA, Exhibit 3, Westmoreland Coal Company Presentation, “Westmoreland Announces Transformational Acquisition of Sherritt’s Coal Operations”, 24 December 2013, p. 10. ↩
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respect to the joint venture,11 pursuant to which WCC “fully recovered its capital investments at the mine”.12 The Claimant’s damages claim is thus inflated.13
14. Canada explains all of the defects that it has highlighted above in the sections that follow. In addition, in Section VII, Canada provides a summary of its proposal to bifurcate these proceedings, under which the Tribunal would first consider jurisdiction and admissibility rather than combining these preliminary objections with an unnecessary and expensive merits phase.
15. While historically a relatively cheap and reliable source of power in many jurisdictions, burning coal to generate electricity produces GHG emissions that contribute to climate change. When released into the atmosphere, GHG emissions act like the roof of a greenhouse, trapping the sun’s heat as it radiates back into the atmosphere, causing surface temperatures to increase. Using coal to generate electricity releases more GHGs into the atmosphere per unit of energy than does the combustion of almost every other hydrocarbon fuel. In fact, in 2013,14 burning coal to generate electricity accounted for about 72 per cent of total GHG emissions from the energy sector worldwide, with the energy sector contributing approximately 40 per cent of overall GHG emissions.15
11 R-003, Capital Power, Press Release, “Capital Power enters into cost savings agreement related to the Genesee Mine”, 28 March 2017, available at: https://www.capitalpower.com/media/media_releases/capital-power-enters-into-a-cost-savings-agreement-related-to-the-genesee-mine/. ↩
12 R-004, Westmoreland Coal Company, News Release, “Westmoreland Receives $52 Million Early Repayment of Genesee Mine Receivable”, 28 March 2017, available at: https://westmoreland.com/2017/03/westmoreland-receives-52-million-early-repayment-of-genesee-mine-receivable/. ↩
13 The Claimant expressly acknowledges that its damages claim is inflated because it has not discounted the amount to its present day value. See NOA, ¶ 86, fn. 35. ↩
14 Unless otherwise specified, all data in Canada’s Statement of Defence are from 2013, which is predominantly the year from which data would have been available to the Government of Alberta at the time that it announced its 2015 Climate Leadership Plan. ↩
15 R-005, The World Bank, “Understanding CO2 Emissions from the Global Energy Sector”, 2014, pp. 1-2, available at: http://documents.worldbank.org/curated/en/2014/02/19120885/understanding-co2-emissions-global-energy-sector. ↩
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16. Coal-fired power plants also release air pollutants, such as nitrogen oxides, sulphur oxides, and particulate matter, as well as heavy metals such as cadmium, lead, and mercury.16 The impacts of these emissions on air quality have been linked to a number of human health conditions, including chronic and acute respiratory diseases, heart disease, stroke, and diabetes.
17. As a result of the negative environmental and human health impacts of coal combustion to produce electricity, governments around the world have increasingly committed to reducing emissions from coal-fired electricity generation. For example, over the last decade, governments have halted support for new coal plants, more tightly regulated pollution from existing plants, and shut down old plants. Many countries, such as the United States and the United Kingdom, have enacted policies that effectively rule out new coal plants and require the retirement of existing coal fleets.17 Moreover, international institutions, such as the World Bank, European Investment Bank, and European Bank for Reconstruction and Development, have announced an end to the public financing of new coal plants.18
16 In Canada, coal-fired electricity generation is among the highest emitting sources of air pollutants. See R-006, Environment and Climate Change Canada, National Pollutant Release Inventory, “Sector Overview: Electricity” [Excerpt], p. 7. ↩
17 In 2014, the U.S. announced the Clean Power Plan, a policy to cut carbon pollution from the power sector by 30 per cent by 2030. See R-007, United States Environmental Protection Agency, “EPA Fact Sheet: Clean Power Plan”, available at: https://archive.epa.gov/epa/cleanpowerplan/fact-sheet-clean-power-plan.html. While U.S. policy concerning coal-fired electricity generation has since changed, its 2014 policy is indicative of the larger global trend. In 2015, the United Kingdom (“U.K.”) announced that it would be closing all of its coal-fired power stations by 2025. See R-008, The Guardian, “UK to close all power plants in switch to gas and nuclear”, 18 November 2015, available at: https://www.theguardian.com/environment/2015/nov/18/energy-policy-shift-climate-change-amber-rudd-backburner. ↩
18 R-009, The Washington Post, “The World Bank cuts off funding for coal. How big of an impact will it have?”, 17 July 2013, available at: https://www.washingtonpost.com/news/wonk/wp/2013/07/17/the-world-bank-cuts-off-funding-for-coal-how-much-impact-will-that-have/; R-010, BBC News, “European Investment Bank drops fossil fuel funding”, 14 November 2019, available at: https://www.bbc.com/news/business-50427873; R-011, Forbes, “Another Major Investor Joins World Bank in Dropping Support for Coal”, 14 December 2018, available at: https://www.forbes.com/sites/johnparnell/2018/12/14/another-major-investor-joins-world-bank-in-dropping-support-for-coal/#542c530b7d8a. ↩
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18. Canada represents less than two per cent of total global GHG emissions,19 but has high emissions per capita due to its geographic size,20 climatic conditions, and energy-intensive, resource-based economy. While most of the electricity in Canada is generated from non-GHG emitting sources, the supply mix varies considerably by province and territory depending on the availability of natural resources, transmission infrastructure, and market structure. In 2013, coal-based electricity, which represented 11 per cent of total electricity generation in Canada, was responsible for 72 per cent of total electricity sector GHG emissions.21
19. Politically, Canada is a federation composed of a central federal government, ten provincial governments, and three territorial governments. The Canadian Constitution and convention assign different powers to each order of government, such as the power to make laws over criminal matters or concerning natural resources. The protection of the environment, including the regulation of GHG emissions and air pollutants, is not specifically addressed under the Constitution. Both federal and provincial governments have taken action in this area.22
20. For example, in 2008, British Columbia banned conventional coal-fired power and required all electricity generation to have net zero emissions starting in 2016.23 In 2014, Ontario fully eliminated
19 R-012, Climate Watch, Historical GHG Emissions, “Global Historical Emissions Table: World, Canada” Data File, p. 2, available at: https://www.climatewatchdata.org/ghg-emissions?regions=WORLD%2CCAN, (showing Canada’s emissions comprised 857 MtCO2e of the world’s 48,962 MtCO2e in 2013). ↩
20 Canada is a country of physical extremes and contrasts, extending 5,300 kilometers east to west, the distance between Paris and New York, and 4,600 kilometers north to south. It is the second largest country in the world and encompasses six time zones. Canada also has the longest coastline of any country, spanning 243,042 kilometers along the Atlantic, Pacific, and Arctic Oceans. ↩
21 R-013, Environment Canada, “National Inventory Report: 1990-2013 Greenhouse Gas Sources and Sinks in Canada”, Part 3, Annex 11: “Electricity Generation in Canada: Summary and Intensity Tables”, [Excerpt], p. 72, available at: http://publications.gc.ca/collections/collection_2016/eccc/En81-4-2013-3-eng.pdf. ↩
22 Federal environmental laws are based on federal legislative powers over matters such as international borders, international relations, trade and commerce, navigation and shipping, seacoasts and fisheries, criminal law, and matters of national concern. At the federal level, many climate change regulations are developed under the authorities of the Canadian Environmental Protection Act, (1999), S.C. 1999, c. 33. Provincial environmental laws are based on provincial legislative powers over matters that include municipalities, local works and undertakings, property and civil rights, provincially owned (public) lands, and natural resources. Territorial governments exercise delegated powers under the authority of the Parliament of Canada. ↩
23 See R-014, Greenhouse Gas Reduction (Emissions Standards) Statutes Amendment, S.B.C. 2008, c. 20, 29 May 2008, [Excerpt], available at: https://heinonline.org/HOL/Page?collection=psc&handle=hein.psc/statbc9001&id=252&men_tab=srchresults. ↩
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coal as a source of electricity generation, following a decision to this effect in 2003. At the time, this action was the single largest GHG-reduction initiative in North America, eliminating approximately 28 megatonnes of annual GHG emissions – equivalent to 14 per cent of Ontario’s total 2005 GHG emissions, or over half of all vehicle emissions in the province.24 In 2014, Saskatchewan introduced the world’s first commercial-scale carbon capture and storage (“CCS”) electricity project, which is able to capture 90 per cent of the GHG emissions from the host coal-fired electricity generation facility.25
21. The Federal Government has also taken measures addressing GHG emissions caused by coal-fired electricity generation. For example, in 2012, the Federal Government adopted the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations (the “2012 Federal Emissions Regulations”),26 which imposed a stringent performance standard on new coal-fired electricity generation units and on those that reach the end of their “useful life”, generally defined as 50 years after the date of their commissioning.
22. In 2016, the Federal Government published a notice of intent to amend the 2012 Federal Emissions Regulations as part of a plan to accelerate the transition to cleaner electricity in Canada.27
24 R-015, Government of Ontario, “The End of Coal”, published 15 December 2017, available at: https://www.ontario.ca/page/end-coal; R-016, Pan-Canadian Framework on Clean Growth and Climate Change, Annex II: Provincial and territorial key actions and collaboration opportunities with the Government of Canada, [Excerpt], Ontario Key Actions, p. 18, available at: https://www.canada.ca/en/services/environment/weather/climatechange/pan-canadian-framework/annex-key-actions-collaboration.html#on. ↩
25 R-017, Government of Saskatchewan, News Release, “SaskPower Launches World’s First Commercial CCS Process”, 2 October 2014, available at: https://www.saskatchewan.ca/government/news-and-media/2014/october/02/boundary-dam-3-launch. Other examples include Québec, which announced a new Energy Policy in 2016 that included the elimination of burning coal to generate electricity. Similarly, in 2016, New Brunswick released a Climate Change Strategy, which included a decision to phase out coal-fired electricity. ↩
26 See R-018, Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, SOR/2012-167. The 2012 Federal Emissions Regulations related to Canada’s commitments under the Copenhagen Accord. In 2009, the 196 State Parties to the United Nations Framework Convention on Climate Change (the “UNFCCC”) agreed that “climate change is one of the greatest challenges of our time” and adopted the Copenhagen Accord, which recognized the need to hold global warming below 2 degrees Celsius above pre-industrial levels. R-019, United Nations Framework Convention on Climate Change, Report of the Conference of the Parties on its fifteenth session, held in Copenhagen from 7 to 19 December 2009, Decision 2/CP.15, Copenhagen Accord, published 30 March 2010, ¶ 1. Under the Copenhagen Accord, Canada committed to reducing its GHG emissions to 17 per cent below 2005 levels by the year 2020. ↩
27 R-020, Canada Gazette, “Canadian Environmental Protection Act, 1999, Notice of Intent to develop greenhouse gas regulations for electricity generation in Canada”, Part I: Vol. 150, No. 51 (2016), 17 December 2016. The proposed amendment related to Canada’s commitments under the Paris Agreement. In December 2015, the State Parties to the ↩
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The proposed amendment changed the definition of “useful life”, ensuring that all existing coal-fired generating units reach the end of their useful life by December 31, 2029, at the latest, accelerating the time at which the regulations’ stringent performance standard for GHG emissions must be met by all coal-fired generating units. The amended regulations came into force on November 30, 2018, and are expected to result in significant reductions in GHG emissions across Canada (the “2018 Federal Emissions Regulations”).
23. Electricity is central to economic activity in Alberta. Unlike in many other jurisdictions, Alberta’s industrial sector, including oil sands extraction and processing facilities and refineries with around-the-clock operations, accounts for over two-thirds of the province’s electricity consumption. Reliability of electricity supply and reasonable pricing for consumers are thus critical to sustaining economic activity in the province.
24. Due to Alberta’s abundant and easily-accessible coal reserves, coal-fired electricity has historically comprised a large share of the province’s generation portfolio. While this share has decreased since the 1990s, 64 per cent of electricity supplied into Alberta’s electricity market in 2013 was fueled by coal.28 As a result, electricity generation was the second largest emitting sector in Alberta, after oil and gas, accounting for close to one-sixth of the province’s total GHG emissions. While there are many factors that drive differences in emissions among provinces, Figure 1 provides an illustrative snapshot of GHG emissions from Alberta’s electricity sector within the Canadian
UNFCCC recognized that climate change represents an urgent and potentially irreversible threat to human societies and the planet. They adopted the Paris Agreement, which committed to holding global warming to “well below” 2 degrees Celsius above pre-industrial levels, and to make efforts to limit it to 1.5 degrees above pre-industrial levels. See R-021, United Nations Framework Convention on Climate Change, Paris Agreement, 12 December 2015. Canada joined the Paris Agreement in 2015 and committed to reduce Canada’s GHG emissions to 30 per cent below 2005 levels by 2030.
28 R-022, Alberta Electric System Operator, 2014 Annual Market Statistics Data File, “Contents” and “Market Participation” Sheets [Excerpt], p. 2. The full data file and accompanying reports are available at: https://www.aeso.ca/market/market-and-system-reporting/annual-market-statistic-reports/. Alberta accounted for 63 per cent of all coal power production in the country in 2013. See R-013, Environment Canada, “National Inventory Report: 1990-2013 Greenhouse Gas Sources and Sinks in Canada”, Part 3, Annex 11: “Electricity Generation in Canada: Summary and Intensity Tables” [Excerpt], pp. 81 (showing 38,500 GWh of coal-fired power produced in Alberta) and 72 (showing 60,900 GWh of coal-fired power produced in Canada), available at: http://publications.gc.ca/collections/collection_2016/eccc/En81-4-2013-3-eng.pdf. ↩
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context in 2013:
Figure 1: Provincial GHG Emissions and Electricity Generation by Energy Source (2013)29
A chart with the following characteristics:
25. Regulating emissions produced by generators in the electricity sector is a complex task that requires specific consideration of the regulations’ impact on the grid. The nature of a particular electricity market and the need to ensure reliability and stability of supply are thus front of mind when any government introduces regulations that will impact the electricity sector.
26. The structure of Alberta’s electricity market is unique in Canada. While the transmission and distribution components of the system are fully regulated, the wholesale power supply – or generation – component of Alberta’s electricity system has been an openly competitive market between
29 Data sourced from R-013, Environment Canada, “National Inventory Report: 1990-2013 Greenhouse Gas Sources and Sinks in Canada”, Part 3, Annex 11: “Electricity Generation in Canada: Summary and Intensity Tables” [Excerpt]. ↩
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predominantly private companies since 1996.30 Market forces, rather than a centralized plan, dictate the timing of, and need for, new generation in Alberta. Electricity generation plants typically cost hundreds of millions to billions of dollars and, in many cases, require close to a decade of planning, development, and construction.31
27. Private capital is, and has been, responsible for building the majority of Alberta’s existing generating assets. Privately-owned generators operating in Alberta are not guaranteed a particular return on their investments in generating assets. In particular, generators earn revenue only on the energy that they produce, and not for production capacity that they make available to the grid.32 There is also no price certainty for the energy that the generators produce – electricity is sold in an open market, with prices set in real time. Other than a price cap and a price floor, outcomes in the market are determined solely by the forces of competition. These factors present unique considerations for maintaining system reliability and stability of supply that inform Alberta’s regulation of emissions from the sector, in particular with respect to the ability to attract investment in generating assets.
28. Alberta was one of the first jurisdictions in North America to impose GHG emissions performance standards and a carbon pricing system on large industrial facilities through its 2007
30 See generally R-023, Government of Alberta, “Electricity Generation” Fact Sheet, December 2014, p. 2, available at: https://open.alberta.ca/dataset/9bea6054-fc58-418e-bfed-f5a2a3bec0fa/resource/6b13d2b6-1fb4-4a36-b7c8-a9fe03c781ab/download/fselectricitygeneration.pdf. Three municipalities also participate in the competitive wholesale generation market. ↩
31 For example, the most recent natural gas plant built in Alberta is estimated to have cost approximately $1.4 billion. The proponent first announced plans for the project in 2007, received permission to proceed in 2010, reached the construction stage at the end of 2011, and did not begin commercial operations until 2015. See R-024, Power Magazine, “Top Plants: Shepard Energy Centre”, 31 August 2015, available at: https://www.powermag.com/shepard-energy-centre-calgary-alberta-ownersoperator-enmax-and-capital-powerenmax/. A number of factors impact the operating and investment decisions of generating unit owners in the province, including price certainty, the cost of inputs (such as fuel source, e.g., coal or natural gas), and the cost of compliance with various regulations, including air quality and GHG emissions performance standards. See, e.g., NOA, Exhibit 3, Westmoreland Coal Company Presentation, “Westmoreland Announces Transformational Acquisition of Sherritt’s Coal Operations”, 24 December 2013, p. 2 (recognizing that “[f]uture legislation and changes in regulations, governmental policies and taxes, including those aimed at reducing emissions of elements such as mercury, sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases” are among the factors that “could cause actual results to differ materially from those in the forward-looking statements”). ↩
32 This is often referred to as an “energy-only” market. ↩
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Specified Gas Emitters Regulation (“SGER”). The SGER required large industrial emitters in Alberta, including coal-fired electricity generators, to reduce their GHG emissions intensity by 12 per cent below a facility-specific, historic emissions intensity baseline. Facilities like Alberta’s coal-fired electricity generation units could meet their reduction obligations in a number of ways, including by paying a set price of $15 per tonne of GHG emissions.
29. The SGER was originally scheduled to expire in September 2014. In 2013, the Government of Alberta engaged stakeholders on various proposals to increase the stringency of the performance standard and the carbon price. Among the proposals discussed was a more stringent requirement to reduce GHG emissions by 40 per cent below the applicable baseline, and a corollary increase in the carbon price to $40 per tonne.33 The Government of Alberta extended the existing SGER to June 2015 while it further consulted with stakeholders and reviewed its climate change policies more broadly.
30. On June 25, 2015, Alberta announced that it was establishing an expert advisory panel to undertake a comprehensive review of Alberta’s climate change policy, including the SGER.34 The Climate Change Advisory Panel (“Advisory Panel”) was mandated to review Alberta’s existing climate change policies, engage with the public as well as technical and industry stakeholders, and provide the Minister of Environment and Parks with advice on a comprehensive set of policy measures to reduce Alberta’s GHG emissions. In the period that followed, the Advisory Panel
33 See, e.g., R-025, The Canadian Press, “Redford says $40 per tonne carbon penalty no ‘magic number’ for her government”, 10 April 2013, available at: https://globalnews.ca/news/469654/redford-says-40-per-tonne-carbon-penalty-no-magic-number-for-her-government/, (reporting that “[r]ecent leaked reports suggest Alberta could move to a 40 per cent intensity reduction target with penalties of $40 per tonne.”); R-026, The Globe & Mail, “Alberta’s bold plan to cut emissions stuns Ottawa and oil industry”, 3 April 2013, available at: https://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/albertas-bold-plan-to-cut-emissions-stuns-ottawa-and-oil-industry/article10762621/. ↩
34 R-027, Government of Alberta, Press Release, “Province takes meaningful steps toward climate change strategy”, 25 June 2015, available at: https://www.alberta.ca/release.cfm?xID=38232B11A8C17-0B34-BB8E-6B03088D90D1C786. The Government of Alberta announced at the same time that it was updating the expiring SGER. As an interim solution, for a period of two years, the new GHG emissions intensity reduction requirements were increased to 15 per cent below the historic baseline in 2016, and 20 per cent in 2017. The carbon price increased to $20 per tonne in 2016, and $30 per tonne in 2017. ↩
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conducted broad consultations with the public and industry groups covering the breadth of the Albertan economy, including the Coal Association of Canada.35
31. On completion of its consultation and analysis, the Advisory Panel recommended that the Government of Alberta “broaden and improve its existing carbon pricing regime” (i.e. the SGER), and adopt a suite of complementary policies with respect to emissions in four key areas: (1) electricity; (2) oil and gas; (3) energy efficiency; and (4) technology and innovation.36 With respect to electricity, the Advisory Panel recommended an “integrated electricity policy package” that would assign a more stringent performance standard on emissions from the sector, phase out emissions from coal-fired power in Alberta altogether by 2030, and increase the overall share of renewables in Alberta’s electricity portfolio.37 The Advisory Panel noted that its proposed policies were designed to work within Alberta’s existing competitive electricity market structure.
32. The Government of Alberta subsequently announced the 2015 Climate Leadership Plan, which was largely based on the recommendations made by the Advisory Panel, on November 22, 2015.38 The Plan’s strategy was to reduce GHG emissions and transition towards a lower carbon economy. It included an expanded carbon pricing system, and a transition from coal-fired to renewable electricity sources.
33. Part of the Government of Alberta’s new carbon pricing regime was the Carbon Competitiveness Incentive Regulation (“CCIR”), which replaced the SGER as the primary mechanism to reduce emissions from large industrial emitters. Among other things, the CCIR increased the stringency of the GHG emissions performance standard applicable to all electricity generating units, which, for coal-fired electricity generators, represented a required reduction of
35 Westmoreland Coal Company was a member of the Coal Association of Canada. ↩
36 R-028, Climate Change Advisory Panel, Climate Leadership Report to Minister, 20 November 2015, p. 4. ↩
37 R-028, Climate Change Advisory Panel, Climate Leadership Report to Minister, 20 November 2015, pp. 6 and 30. ↩
38 R-029, Government of Alberta, Press Release, “Climate Leadership Plan will protect Albertans’ health, environment and economy”, 22 November 2015, available at: https://www.alberta.ca/release.cfm?xID=38885E74F7B63-A62D-D1D2-E7BCF6A98D616C09. ↩
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roughly 60 per cent from their existing levels of GHG emissions.39 The price of carbon under the CCIR was $30 per tonne.
34. The Government of Alberta further adopted the Advisory Panel’s recommended suite of complementary policies for the electricity sector, including a phase-out of all emissions – both those affecting air quality and GHGs – from coal-fired electricity generation and a corollary transition to lower-emitting forms of electricity generation by 2030.40 Three principles would guide this transition: maintaining a reliable electricity system for Alberta consumers; ensuring reasonable electricity price stability for consumers; and not unnecessarily stranding capital in Alberta’s competitive electricity market.41 These policies, and the policy goals they sought to achieve, were interrelated.
35. In 2015, there were 18 coal-fired generating units operating in Alberta. Four companies – ATCO, Capital Power, Maxim, and TransAlta – supplied the Alberta market with coal-fired electricity from these units, located at six plants in the province.42 Alberta was anticipating the retirement of at least 12 of these 18 units by 2030, representing approximately a quarter of the generating capacity in the province.43 Significant investment in new generation would be needed to reliably meet the province’s steadily growing demand for electricity and to maintain relative price
39 Under the CCIR, coal-fired generating units would need to match the emissions performance of the much lower emitting best-in-class natural gas combined cycle facility. ↩
40 The Government aimed to have renewable energy sources replace two-thirds of the coal-generated electricity existing in 2015, and comprise up to 30 per cent of Alberta’s electricity production by 2030. See R-029, Government of Alberta, Press Release, “Climate Leadership Plan will protect Albertans’ health, environment and economy”, 22 November 2015. ↩
41 R-029, Government of Alberta, Press Release, “Climate Leadership Plan will protect Albertans’ health, environment and economy”, 22 November 2015. ↩
42 Battle River (three units); Genesee (three units); Keephills (three units); Sheerness (two units); Sundance (six units); and H.R. Milner (one unit). ↩
43 R-030, Market Surveillance Administrator, “Market Share Offer Control 2015”, 30 June 2015, pp. 11-16, available at: https://resources.albertamsa.ca/uploads/pdf/Archive/000-2015/2015-06-30%20Market%20Share%20Offer%20Control%202015.pdf. Generation capacity refers to a generating unit’s capability to produce electricity, and stands in contrast to the amount of electricity the unit actually generates in a given time period. Aggregate generation capacity will not always match the amount of electricity generated given the range of supply and demand factors that influence electricity production. ↩
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stability for consumers beyond 2030. These factors were particularly critical in Alberta because of its unique industrial consumption profile.
36. In light of these retirements, the coal-fired emissions aspect of the 2015 Climate Leadership Plan focused on the six coal-fired generating units that were expected to operate beyond 2030, which accounted for an additional 16 per cent of generation capacity in the province:44
Table 1: Coal-Fired Generating Units in Alberta Expected to Operate Beyond 2030
| Generating Unit | Year Commissioned | Federal End of Useful Life | Generating Unit Owner (2015) |
|---|---|---|---|
| Sheerness 1 | 1986 | 2036 | ATCO (50%); TransAlta (50%) |
| Genesee 2 | 1989 | 2039 | Capital Power |
| Sheerness 2 | 1990 | 2040 | ATCO (50%); TransAlta (50%) |
| Genesee 1 | 1994 | 2044 | Capital Power |
| Genesee 3 | 2005 | 2055 | Capital Power (50%); TransAlta (50%) |
| Keephills 3 | 2011 | 2061 | Capital Power (50%); TransAlta (50%) |
37. Phasing out emissions from these generating units by 2030 would require transitioning the units to use other fuel sources or technologies – such as renewable energy, natural gas, or CCS technology – or replacing them altogether. It thus presented a complex policy challenge in the context of Alberta’s unique electricity market, which relies on private capital to undertake the significant investment risk of building new generating assets.
38. To help navigate this complexity in a transparent and objective manner, the Government of Alberta retained Terry Boston, an independent expert in electricity markets and systems, to advise it on the best options to achieve its policy goal of zero emissions from coal-fired generating units.45 Mr. Boston is the retired head of North America’s largest power grid, PJM Interconnection.
44 R-030, Market Surveillance Administrator, “Market Share Offer Control 2015”, 30 June 2015, pp. 11-16. ↩
45 R-031, Government of Alberta, Press Release, “Alberta takes next steps to phase-out coal pollution under Climate Leadership Plan”, 16 March 2016, available at: https://www.alberta.ca/release.cfm?xID=40400064C4850-E326-56B9- ↩
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39. Consistent with Alberta’s announcement of the 2015 Climate Leadership Plan, the guiding principles for Mr. Boston’s development and consideration of approaches to phasing out emissions from coal-fired power plants were to maintain: (1) electric system reliability; (2) reasonable stability and electricity prices for consumers and business; and (3) investors’ confidence in Alberta by not unnecessarily stranding capital and ensuring that workers, communities and affected companies were treated fairly in the facilitation process.46 Contrary to the Claimant’s allegation about Mr. Boston’s charge, which does not mention the first two elements,47 these guiding principles were interrelated, and pertained to the electricity sector. Maintaining electric system reliability was the “paramount” consideration.48
40. Accordingly, Mr. Boston was mandated to engage with the relevant electricity market participants (i.e. the three owners of the six coal-fired generating units expected to operate beyond 2030), with the government, and with the Alberta Electric System Operator (“AESO”), a not-for-profit independent system operator that manages and operates the provincial power grid and energy markets. Mr. Boston was instructed to consider the input he received through his consultations and to provide expert advice to the Government of Alberta on the preferred approach to phasing out coal-fired electricity emissions by 2030.
41. On September 30, 2016, Mr. Boston set out his recommendations to the Government of Alberta in an open letter to the Premier of Alberta.49 In his letter, Mr. Boston explained that the transition from coal-fired generation to renewable and natural gas-fired generation by 2030 would require $20 billion to $30 billion of investment in new generation assets.50 Mr. Boston further explained that a broad base of investors in the electricity sector believed that two elements were required for Alberta
4ED21CDD882F3960. Alberta also announced on the same day that a parallel process was underway to ensure ongoing support for coal communities and workers across the province, and to support economic development in the transition to a greener economy.
46 R-032, Letter from Terry Boston to Premier Rachel Notley, 30 September 2016, p. 1. ↩
48 R-032, Letter from Terry Boston to Premier Rachel Notley, 30 September 2016, p. 1. ↩
49 R-032, Letter from Terry Boston to Premier Rachel Notley, 30 September 2016. ↩
50 R-032, Letter from Terry Boston to Premier Rachel Notley, 30 September 2016, p. 2. ↩
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to attract the level of investment necessary to maintain reliable capacity and transition successfully toward renewable energy sources:
First, is the provision of voluntary payments for the six coal plants with remaining life beyond 2030. Second, is continued confidence that Alberta’s power market design produces competitive results which are fair and efficient, while encouraging the future investments needed to maintain reliability during the transition to cleaner sources of generation.51
42. In accordance with his mandate, and on the basis of his expertise and the input he collected during his consultation process, Mr. Boston recommended that the Government of Alberta provide voluntary payments to the three coal power plant owners – ATCO, Capital Power, and TransAlta – to facilitate Alberta’s transition to lower-emitting forms of electricity generation. Mr. Boston further recommended that the payments be based on specific and transparent criteria (see paragraph 47 below), and be provided over time, both to lessen the financial burden on the Province and to give the three incumbents a renewed opportunity to access capital markets. Since investments made by incumbents and by new players would be required to construct the new generation necessary to maintain a reliable grid, Mr. Boston believed that providing these “voluntary payments” would “create a positive investor outlook in Alberta for market-based generation and renewables.”52
43. On the basis of Mr. Boston’s recommendations, the Government of Alberta decided to provide voluntary Transition Payments to the owners of the six coal-fired generating units that were otherwise expected to operate beyond 2030. On November 24, 2016, the Province announced that it had concluded agreements with ATCO, Capital Power, and TransAlta to this effect.53 The agreements, named “Off-Coal Agreements”, provide the Transition Payments in annual instalments to each
51 R-032, Letter from Terry Boston to Premier Rachel Notley, 30 September 2016, p. 3 (based on input from 25 investment institutions and two of the largest independent power producers in North America). ↩
52 R-032, Letter from Terry Boston to Premier Rachel Notley, 30 September 2016, p. 2. ↩
53 R-033, Government of Alberta, Press Release, “Revised: Alberta announces coal transition action”, 24 November 2016. ↩
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company between 2017 and 2030 in exchange for the company’s commitment to cease coal-fired emissions at the relevant generating plants on or before December 31, 2030.
44. Consistent with the policy goals that Alberta sought to achieve with the Transition Payments, the Off-Coal Agreements also impose eligibility conditions that must be met before the annual Transition Payments will be made. In particular, the conditions for receipt of the Transition Payments include minimum annual investment spending requirements with respect to the company’s electricity business, and a commitment to continue generating electricity or to otherwise participate in the electricity market in Alberta.54 Companies have demonstrated their continued participation in the Alberta electricity market by, for example, investing in new renewable energy projects.55
45. The Transition Payments are made pursuant to Alberta’s Energy Grants Regulation, which gives Alberta’s Minister of Energy the authority to “make grants to any person or organization in respect of any matter that is under the Minister’s administration.”56 The Government of Alberta also lists the Transition Payments in its grant payments disclosure table, which is available online.57
46. The Claimant alleges that TransAlta “indicated it could make the transition without payments from the provincial government.”58 However, the Claimant’s allegation is based on a partial reading of the document to which it cites. A reading of the entire document demonstrates that TransAlta’s company officials were describing their own policy “proposal”,59 which they presented to the
54 See, e.g., NOA, Exhibit 19, Off-Coal Agreement between TransAlta Corp. et al., and Her Majesty the Queen In Right Of Alberta (represented by Ministry of Energy), 24 November 2016, s. 5; NOA, Exhibit 23, Off-Coal Agreement between Capital Power et al. and Her Majesty the Queen In Right of Alberta (represented by Ministry of Energy), 24 November 2016, s. 5. ↩
55 R-034, Government of Alberta, “Renewable Electricity Program”, pp. 2 and 3, available at: https://www.alberta.ca/renewable-electricity-program.aspx. ↩
56 R-001, Energy Grants Regulation, A.R. 103/2003, s. 2. ↩
57 R-002, Government of Alberta, Grant payments disclosure table, “CLP Coal Generation Transition”, “Energy General Armed” [Excerpts], available at: https://www.alberta.ca/grant-payments-disclosure-table.aspx. ↩
58 NOA, ¶ 60, citing NOA, Exhibit 13, Transcript, TransAlta Corp., Third Quarter 2015 Results Conference Call & Webcast 4, (30 October 2015). ↩
59 R-035, TransAlta Corporation, “Third Quarter 2015 Results Conference Call & Webcast Transcript”, 30 October 2015 [Complete Version of NOA, Exhibit 13], pp. 4 (“So this brings me to our second step in our plan: advocating for what we call the Dial Down Coal – Dial Up Renewables proposal.”) and 22 (“Our proposal is basically an executive summary on how we think this should work”). ↩
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Advisory Panel during its comprehensive review of climate policy in Alberta,60 and which specifically contemplated “[k]eeping some coal in the fuel mix.”61 Thus, “the transition” the Claimant alleges TransAlta could make “without payments from the provincial government”62 is not the one that Alberta ultimately adopted.
47. Alberta implemented the specific and transparent criteria proposed by Mr. Boston to determine the amount of the Transition Payments. In particular, the payments were based on the fully reviewable net book value (“NBV”) of each generating unit. NBV is typically the original book value of an asset, less accounting adjustments such as depreciation. Newer generating units will thus typically have a higher NBV than older units because they have depreciated less. Accordingly, a generating unit like Sheerness 1, which was commissioned in 1986, should have a lower NBV than Keephills 3, which was commissioned in 2011. Beginning with the NBV of the relevant generating units in 2016, based on the companies’ 2015 financial statements, Alberta calculated the percentage of that book value that could be attributed to the years of expected operating life after 2030 (“Proxy 2030 NBV”). It then made deductions to the Proxy 2030 NBV to account for the repurposing potential of components of the generating units or possible salvage, and then discounted the deducted Proxy 2030 NBV back to its net present value in 2016.63 Each company received a payment with respect to its share of the ownership interests in each relevant unit.
48. Contrary to the Claimant’s allegations,64 no interest in coal mines, coal mining equipment, coal mineral rights, or coal supply contracts was included in the Transition Payment amounts, even though
60 R-035, TransAlta Corporation, “Third Quarter 2015 Results Conference Call & Webcast Transcript”, 30 October 2015 [Complete Version of NOA, Exhibit 13], p. 21. ↩
61 R-035, TransAlta Corporation, “Third Quarter 2015 Results Conference Call & Webcast Transcript”, 30 October 2015 [Complete Version of NOA, Exhibit 13], p. 4. TransAlta further explained that, by 2030, their plan contemplated that “coal-fired electricity would have the same market share as renewables have today in the province”, which they stated was eight per cent. TransAlta’s officials later explained that their proposal was one of “hundreds of submissions” made to the Advisory Panel, and that there were “a number of different kinds of proposals” made in that context. See R-035, TransAlta Corporation, “Third Quarter 2015 Results Conference Call & Webcast Transcript”, 30 October 2015 [Complete Version of NOA, Exhibit 13], p. 21. ↩
63 See, e.g., NOA, Exhibit 19, Off-Coal Agreement between TransAlta Corp. et al., and Her Majesty the Queen in Right of Alberta (represented by Ministry of Energy), 24 November 2016, Schedule A, p. 11. ↩
64 See, e.g., NOA, ¶¶ 73, 76, and 79. ↩
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two of the power companies (Capital Power and TransAlta) also owned, directly or indirectly, coal-related interests.65 In providing Transition Payments, Alberta was concerned with reducing emissions from the high-emitting electricity sector. It was also concerned with ensuring that it could attract a sufficient level of continued investment in the electricity sector to maintain a reliable grid and reasonable price stability for consumers as the Province transitioned to a lower-carbon electricity system. The coal resource itself was not the focus of the policy, and those companies that received larger payments received them not because they also owned coal mine interests, but because of their ownership interests in newer and larger generation facilities.66
49. Moreover, the Government of Alberta made the Transition Payments voluntarily – they did not represent compensation for any obligation owed under the 2015 Climate Leadership Plan or otherwise. The Off-Coal Agreements explicitly recognized this fact.67 Accordingly, the recipients agreed to a broad “no action” provision under which they could not commence any legal action against the Province, AESO, or Terry Boston “with respect to the phase out of Coal-Fired Emissions from the Plants, including with respect to the mines, coal supply agreements, mining contracts, or mining equipment related to the coal used to fuel the Plants or alleging any other cause of action in relation to the phase out of Coal-Fired Emissions from the Plants.”68 Nothing in this broad “no action” provision supports the Claimant’s allegation that the Transition Payments included interests in coal mines.69
65 For example, TransAlta’s coal mining interests are held by its subsidiary, Sunhills Mining LP. Similarly, Capital Power holds interests in the Genesee mine through a Joint Venture with Prairies Mines & Royalty ULC. ↩
67 See e.g., NOA, Exhibit 19, Off-Coal Agreement between TransAlta Corp. et al., and Her Majesty the Queen in Right of Alberta (represented by Ministry of Energy), 24 November 2016, s. 4(a); NOA Exhibit 23, Off-Coal Agreement between Capital Power et al., and Her Majesty the Queen in Right of Alberta (represented by Ministry of Energy), 24 November 2016, s. 4(a) (both providing: “The Parties acknowledge that the Province is under no legal obligation to compensate or otherwise pay any amount to the Company as a result of the phase out of Coal Fired Emissions”). ↩
68 See NOA, Exhibit 19, Off-Coal Agreement between TransAlta Corp. et al., and Her Majesty the Queen in Right of Alberta (represented by Ministry of Energy), 24 November 2016, s. 7(a); NOA Exhibit 23, Off-Coal Agreement between Capital Power et al., and Her Majesty the Queen in Right of Alberta (represented by Ministry of Energy), 24 November 2016, s. 7(a). ↩
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50. The coal resource, like most natural resources in Canada, falls under provincial jurisdiction. Provincial governments typically own the majority of resources within their boundaries and have broad responsibility for managing resource development activities, including ownership, royalties, land-use planning, and allocations, as well as exploration, development, conservation, and use.
51. The Mines and Minerals Act70 provides the Government of Alberta with authority to administer, allocate, and enter into agreements with respect to minerals. It applies to all mines and minerals and related natural resources belonging to the Crown, including wells, mines, quarries, and minerals. The Government of Alberta’s Ministry of Energy oversees mineral tenure (including coal), coal policy, and the collection of royalties under the Coal Royalty Regulation.71 Coal mines are regulated by the Alberta Energy Regulator (“AER”), an independent corporation created by the Alberta Responsible Energy Development Act,72 mandated to provide the safe, efficient, orderly, and environmentally responsible development of upstream energy resources in the province. The AER administers several legal instruments, including the Alberta Coal Conservation Act and the Alberta Environmental Protection and Enhancement Act as it relates to coal, oil and gas, and oil sands facilities.73
52. In 2013, Alberta had nine active coal mines – three produced metallurgical or thermal-quality bituminous coal for export, four supplied subbituminous coal to electrical generating stations in the province, and two made small-scale sales. Alberta’s coal mines do not have a significant emissions profile, especially when compared to generating units that burn coal to generate electricity:
70 Mines and Minerals Act, R.S.A. 2000, Ch. M-17. ↩
71 Coal Royalty Regulation, A.B. Reg. 295/1992. ↩
72 Responsible Energy Development Act, S.A. 2000, Ch. R-17.3. ↩
73 Under the Coal Conservation Act, R.S.A. 2000, c. C-17, a mine will operate under a broad Permit to Develop a Coal Mine. Within that permit, smaller Coal Mine Licenses provide specific authorization for each of the open pit, tailings pond, waste dump, processing plant, supporting buildings, and other components. The AER also issues approvals under the Environmental Protection and Enhancement Act, R.S.A. 2000, c. E-12, which are typically conditioned on reclamation that must be achieved throughout the life cycle of a coal mine. ↩
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Figure 2: GHG Emissions from Coal Mines and Coal-Fired Power Plants (2013) 74
A bar chart with the following characteristics:
53. In light of their relatively low contribution to provincial GHG emissions, the reduction of GHG emissions from coal mining in Alberta was not a focal point of Alberta’s 2015 Climate Leadership Plan. To the contrary, the 2015 Climate Leadership Plan took no policy stance on the continued mining of coal – it did not address any mineral rights, leases, land tenures, permits, ownership, or royalty interests, or coal supply agreements.
54. The six coal-fired generating units expected to operate beyond 2030 that were the focus of Alberta’s 2015 Climate Leadership Plan are supplied by three coal mines: the Sheerness mine; the Genesee mine; and the Highvale mine. The table below identifies which mines supply which generating units, and sets out the ownership of each:75
74 Data sourced from R-036, Environment and Climate Change Canada, “National Inventory Report: 1990-2018 Greenhouse Gas Sources and Sinks in Canada”, Part 3, Annex 12: “Provincial/Territorial Greenhouse Gas Emission Tables by Canadian Economic Sector, 1990-2018”, Annex 13: “Electricity in Canada: Summary and Intensity Tables” [Excerpts], pp. 52 and 69. ↩
75 In addition to these companies there are others that hold interests in the coal mines, such as Altius Minerals Corporation, a Canadian company, which holds an interest in the coal royalty assets associated with the Sheerness and Genesee mines. The royalty assets include the right to receive payments for a certain percentage interest in each tonne of coal mined. This kind of private royalty arrangement is distinct from the government’s royalty regime. ↩
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Table 2: Generating Stations, Supplying Mines, Mine Ownership
| Generating Station | Unit | Supplying Mine | Mine Owner |
|---|---|---|---|
| Sheerness | Unit 1 | Sheerness | Prairie Mines & Royalty ULC |
| Unit 2 | |||
| Genesee | Unit 1 | Genesee | Prairie Mines & Royalty ULC (50%) Capital Power (50%)76 |
| Unit 2 | |||
| Unit 3 | |||
| Keephills | Unit 3 | Highvale | Sunhills Mining LP77 |
55. Contrary to the Claimant’s allegations that the Transition Payments were “Alberta’s scheme to compensate Albertan coalmine operators for the loss of their investments, to the exclusion of the only American coalmine operator,”78 no company in Alberta received any payment from the government with respect to any interest in any coal mine. Alberta’s Minister of Economic Development and Trade explained to WCC that capital associated with coal mines, coal mining equipment, or coal mineral rights was not relevant to the objective of the Transition Payments, and was not included in any payment made by the Government of Alberta:
[T]he payments under the Off-Coal Agreements were calculated based on the approximate capital invested in the coal-fired generation units that would not be recovered by the end of 2030, or recovered through repurposing equipment for another type of generation. It is important to note the calculations in the Off-Coal Agreements excluded capital in associated coal mines, coal mining equipment, and coal mineral rights.
76 Prairies Mines & Royalty ULC and Capital Power operated the Genesee mine as a joint venture. ↩
77 Sunhills Mining LP is a wholly owned subsidiary of TransAlta. ↩
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As you are aware, Alberta’s Climate Leadership Plan only addresses emissions from coal-fired power generation, and does not contain any policy stance on coal mining within the province.79
56. As explained by the Minister, coal mines in Alberta were not the object of Alberta’s emissions reduction policies.
57. The Claimant is a Delaware limited liability company. The Claimant is owned by creditors of WCC – a company that, on October 9, 2018, filed for bankruptcy protection in the United States.
58. On March 15, 2019, WCC announced that it had emerged from the bankruptcy process and that it had, among other things, sold its Canadian coal assets to the Claimant. WCC is set to dissolve.80
59. Among the assets that the Claimant acquired from WCC were Westmoreland Canada Holdings Inc., which owns Prairie, a company incorporated in Alberta and that operates four Alberta coal mines: the Genesee mine, the Sheerness mine, the Paintearth mine,81 and the Coal Valley mine.82 WCC acquired the coal assets in 2014 from Sherritt International (“Sherritt”). The coal reserves at the Paintearth mine and the Sheerness mine will be exhausted by 2022 and 2024, respectively, which WCC knew when it invested.83 Additionally, on March 28, 2017, WCC negotiated a $70 million agreement with Capital Power with respect to its joint venture at the Genesee mine.84 As stated by
79 R-037, Letter from The Hon. Deron Bilous, Ministry of Economic Development and Trade, Government of Alberta to John Schadan, Westmoreland Coal Company, 6 June 2017, p. 1. ↩
80 R-038, S&P Global Market Intelligence, “Westmoreland Coal to liquidate, but mines will continue bearing its name”, 8 March 2019, available at: https://www.spglobal.com/marketintelligence/en/news-insights/trending/tvgVHSbHeVi6Xrgykg2F4A2. ↩
81 The Paintearth mine services three generating units at the Battle River power station. These units are each expected to retire before the year 2030 and were thus not the focus of Alberta’s 2015 Climate Leadership Plan. ↩
82 The Coal Valley mine produces thermal coal sold mainly into the seaborne market. WCC also acquired three coal mines in Saskatchewan, and a 50 per cent interest in an activated carbon plant and a Char production facility in Saskatchewan. ↩
83 NOA, Exhibit 3, Westmoreland Coal Company Presentation, “Westmoreland Announces Transformational Acquisition of Sherritt’s Coal Operations”, 24 December 2013, p. 10. ↩
84 R-003, Capital Power, Press Release, “Capital Power enters into cost savings agreement related to the Genesee Mine”, 28 March 2017. ↩
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Kevin Paprzycki, WCC’s Chief Executive Officer at the time, “[w]ith this payment, we have fully recovered our capital investments at the mine.”85
60. When WCC invested in Canada, it did not acquire Sherritt’s royalty assets in the transaction.86 Those assets were purchased in 2014 by a group led by Altius Minerals Corporation (“Altius”), a Canadian-owned company incorporated in Alberta. Altius continues to own the royalty assets associated with the Genesee, Sheerness, and Paintearth mines.
61. While WCC’s earlier purchase of the Canadian assets from Sherritt met the threshold for a pre-closing “net benefit” review under Canada’s Investment Canada Act,87 the Claimant’s transaction was not subject to review.
62. The breaches of NAFTA Chapter Eleven alleged by the Claimant pre-date its investment in Canada. As a result, its claims are subject to insurmountable jurisdictional hurdles under Articles 1101(1), 1116(1), and 1117(1) of NAFTA Chapter Eleven. Furthermore, the claims concerning the Government of Alberta’s decision to phase out emissions from coal-fired generation units in the 2015 Climate Leadership Plan are time-barred. For these reasons, the claims must be dismissed in their entirety.
85 R-004, Westmoreland Coal Company, News Release, “Westmoreland Receives $52 Million Early Repayment of Genesee Mine Receivable”, 28 March 2017. ↩
86 Sherritt’s royalty assets were privately held mineral rights, where the owner set the royalty to be paid instead of the provincial government. ↩
87 The “net benefit” review under the Investment Canada Act, R.S.C., 1985, c. 28 (1st Supp.) considers a number of factors, including the effects of the investment on the level of economic activity in Canada, productivity, and competition, as well as the compatibility of the investment with national industrial, economic and cultural policies. In this context, investors often make voluntary undertakings, including, commonly, maintaining certain levels of capital investment. The threshold for “net benefit” review under the Investment Canada Act is revised on an annual basis, and had increased between 2014 when WCC underwent review and 2019 when the Claimant acquired the Canadian assets. WCC was also subject to federal Competition Act, R.S.C., 1985, c. C-34 review by the Competition Bureau in order for its acquisition to proceed. In this case, the Competition Bureau released a “no action letter” setting out that it had no intention of challenging the transaction. ↩
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63. The NAFTA Parties’ obligations under Chapter Eleven are not engaged with respect to a claimant until it becomes protected. The substantive protections afforded by NAFTA begin at the time when a claimant becomes an “investor of a Party”. For this reason, a tribunal’s jurisdiction under Articles 1116(1) and 1117(1) is limited to breaches alleged to have occurred after a claimant became a protected “investor of a Party”.
64. The Claimant was not protected by NAFTA at the time of the alleged breaches. The Claimant acquired its investment in Canada in March 201988 – years after the alleged breaches occurred. Accordingly, this Tribunal lacks jurisdiction over its claims.
65. Indeed, the Claimant does not even allege that Canada breached any obligations owed with respect to itself. When describing the facts and circumstances giving rise to the alleged breaches, the Claimant refers loosely to the treatment of “Westmoreland”.89 However, these references are to Westmoreland Coal Company, not Westmoreland Mining Holdings LLC. While the two companies hold similar names, they are separate legal entities with different ownership.90
66. It is not possible under NAFTA for an “investor of a Party” to claim damages on behalf of another investor of a Party. Under Article 1116(1), the Claimant can only file a claim on its own behalf for damage that it has suffered by reason of the alleged breach, not damage that another investor has allegedly suffered.91 The Claimant cannot establish prima facie that it has incurred loss
88 NOA, ¶ 5, fn. 1, and ¶ 18. The Claimant also alleges that WCC transferred “the instant NAFTA claim” to the Claimant in March 2019. This is inaccurate. WCC withdrew its claim on July 23, 2019. The Claimant subsequently filed its NOA on August 12, 2019. A claim is submitted to arbitration under NAFTA Article 1137 when “the notice of arbitration given under the UNCITRAL Arbitration Rules is received by the disputing Party.” The Claimant’s claim was therefore submitted to arbitration on August 12, 2019. ↩
89 See NOA, ¶ 5, fn. 1 (“The term ‘Westmoreland’ is used generically throughout this Notice of Arbitration and Statement of Claim to describe the facts and circumstances of the dispute. When deemed appropriate, specific references have been made to Westmoreland Mining Holdings or Westmoreland Coal Company.”). ↩
90 See R-038, S&P Global Market Intelligence, “Westmoreland Coal to liquidate, but mines will continue bearing its name”, 8 March 2019. ↩
91 NAFTA Article 1116(1) provides, in relevant part: “An investor of a Party may submit to arbitration under this Section a claim that another Party has breached an obligation under: (a) Section A [...] and that the investor has incurred loss or damage by reason of, or arising out of, that breach.” ↩
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or damage by reason of the alleged breach. Instead, the Claimant alleges that WCC incurred loss or damage by reason of the alleged breaches, which is not permissible.92 It is also not possible under NAFTA for an “investor of a Party” to claim damages on behalf of an enterprise it did not own or control at the time of the alleged breach. Under Article 1117(1), the Claimant can only file a claim on behalf of an enterprise that it owned or controlled at the requisite time.93 The Claimant cannot establish prima facie that any damages were incurred by an enterprise owned or controlled by the Claimant. Instead, the Claimant alleges that the enterprise incurred a loss prior to the Claimant’s choice to acquire it.
67. Nor can the Claimant establish that the challenged measures “relat[e] to” it or its investments, as required by NAFTA Article 1101(1).94 In fact, the challenged measures cannot “relate to” the Claimant or its investments because both occurred years before the Claimant chose to make its investment.
68. For these reasons, the Tribunal has no jurisdiction over any aspect of the Claimant’s claims.
69. Even if the Claimant could demonstrate that the Tribunal has jurisdiction over its claims pursuant to NAFTA Articles 1101(1), 1116(1), and 1117(1), its claims concerning Alberta’s decision to phase out emissions from coal-fired generating units in its 2015 Climate Leadership Plan are time-barred. Under Articles 1116(2) and 1117(2), the Claimant may not make a claim if more than three years have elapsed since it or its enterprise, respectively, first acquired, or should have first acquired,
92 As noted above, the Claimant refers to alleged losses incurred by the generic “Westmoreland”. See e.g., NOA ¶¶ 11, 34, 84-87, 95, and 109. This approach obscures that the claim refers to losses allegedly incurred by Westmoreland Coal Company, not the Claimant. ↩
93 NAFTA Article 1117(1) provides, in relevant part: “An investor of a Party, on behalf of an enterprise of another Party that is a juridical person that the investor owns or controls directly or indirectly, may submit to arbitration under this Section a claim that the other Party has breached an obligation under: (a) Section A [...] and that the enterprise has incurred loss or damage by reason of, or arising out of, that breach. ↩
94 NAFTA Article 1101(1) states: “This Chapter applies to measures adopted or maintained by a Party relating to: (a) investors of another Party; (b) investments of investors of another party in the territory of the Party; and (c) with respect to Articles 1106 and 1114, all investments in the territory of the Party.” ↩
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knowledge of the alleged breach and knowledge that the Claimant or its enterprise incurred loss or damage as a result of the breach.95
70. A claim is submitted to arbitration under the 1976 UNCITRAL Arbitration Rules (“1976 UNCITRAL Rules”) when the disputing Party receives the Notice of Arbitration.96 Canada received the Claimant’s Notice of Arbitration on August 12, 2019. Consequently, the critical date against which to assess the timeliness of the claim is August 12, 2016.
71. Alberta’s decision to phase out emissions from coal-fired generating units was made in a public announcement on November 22, 2015, nine months prior to August 12, 2016.97 The Claimant acknowledges in its NOA that the decision to phase out emissions from coal-fired generating units was adopted in 2015, and that this decision led to its alleged losses: “[t]he coal phase-out program, adopted in 2015 [...], has curtailed the time horizon for Westmoreland’s investments in the Mines, reducing their value and accelerating the time in which Westmoreland would have to complete its reclamation of the Mines at a cost that is no longer justified by the investments.”98 Accordingly, any claim concerning this measure is time-barred by virtue of Articles 1116(2) and 1117(2).
72. The Claimant alleges that Canada violated NAFTA Article 1102 because the Government of Alberta granted Transition Payments to owners of coal-fired electricity generating units, but did not provide the Claimant or its investment with a payment. However, Article 1108(7)(b) stipulates that
95 NAFTA Article 1116(2) provides: “An investor may not make a claim if more than three years have elapsed from the date on which the investor first acquired, or should have first acquired, knowledge of the alleged breach and knowledge that the investor has incurred loss or damage.” NAFTA Article 1117(2) provides: “An investor may not make a claim on behalf of an enterprise described in paragraph 1 if more than three years have elapsed from the date on which the enterprise first acquired, or should have first acquired, knowledge of the alleged breach and knowledge that the enterprise has incurred loss or damage.” ↩
96 NAFTA Article 1137(1)(c) provides: “A claim is submitted to arbitration under this Section when: [...] (c) the notice of arbitration given under the UNCITRAL Arbitration Rules is received by the disputing Party.” ↩
97 R-029, Government of Alberta, Press Release, “Climate Leadership Plan will protect Albertans’ health, environment and economy”, 22 November 2015. ↩
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Article 1102 does not apply to “subsidies or grants provided by a Party”. Consequently, Article 1102 does not apply to Alberta’s provision of Transition Payments.
73. The Transition Payments are plainly “subsidies or grants provided by a Party” within the meaning of Article 1108(7)(b). For example, they are made pursuant to the Government of Alberta’s Energy Grants Regulation, which gives the Alberta Minister of Energy the authority to “make grants to any person or organization in respect of any matter that is under the Minister’s administration.”99 The Transition Payments are also listed in the Government of Alberta’s grant payments disclosure table, which is available online.100 Moreover, as the Claimant also acknowledges,101 the payments were voluntary. This is evidenced by the Off-Coal Agreements, the mechanism through which the Transition Payments are granted, which explicitly states that “the Province is under no legal obligation to compensate or otherwise pay any amount to [the recipients]”.102
74. Accordingly, NAFTA Article 1102 does not apply to Alberta’s allocation of Transition Payments and the Tribunal is precluded from considering the Claimant’s claim under Article 1102.
75. Even if the Tribunal could consider the Claimant’s Article 1102 claim, it must fail in any event because Canada’s actions are fully consistent with the obligation of national treatment.
99 R-001, Energy Grants Regulation, AR 103/2003, s. 2. ↩
100 R-002, Government of Alberta, Grant payments disclosure table, “CLP Coal Generation Transition”, “Energy General Armed” [Excerpts], available at: https://www.alberta.ca/grant-payments-disclosure-table.aspx. ↩
102 See NOA, Exhibit 19, Off-Coal Agreement between TransAlta Corp. et al., and Her Majesty the Queen in Right of Alberta (represented by Ministry of Energy), 24 November 2016, s. 4(a); NOA Exhibit 23, Off-Coal Agreement between Capital Power et al., and Her Majesty the Queen in Right of Alberta (represented by Ministry of Energy), 24 November 2016, s. 4(a). ↩
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76. NAFTA Article 1102 prohibits discriminatory treatment on the basis of an investor’s nationality.103 In order to establish a breach of Article 1102, the Claimant has the burden of proving that: (1) the Government accorded “treatment” to the Claimant or its investment; (2) the Government accorded the alleged treatment “in like circumstances” to domestic comparator investors or investments; and (3) the treatment accorded to the Claimant or its investment was “less favourable” than the treatment accorded to appropriate domestic comparators. The Claimant cannot meet any element of the test.
77. First, the Government of Alberta has not accorded treatment to the Claimant or its investment. The Claimant acquired its investment in Canada in March 2019, years after the treatment it alleges violated Article 1102.
78. Second, neither the Claimant nor its investment were accorded treatment “in like circumstances” to the domestic comparators it cites. ATCO, Capital Power, and TransAlta are electricity market participants that are in manifestly unlike circumstances to the Claimant with respect to the Government of Alberta’s decision to grant Transition Payments. As explained above,104 the Transition Payments were granted to these companies to facilitate Alberta’s transition from coal-fired electricity generation to lower-emitting forms of electricity generation while maintaining the reliability of the electricity system. Providing Transition Payments to owners of interests in coal mine assets (like WCC, Altius, Sunhills Mining LP, and Capital Power) for those interests would not have advanced this rational policy objective.
79. In addition, power generating units and coal mines are themselves fundamentally unlike – they operate in different markets, have different supply relationships, have vastly different capital
103 NAFTA Article 1102 provides, in relevant part: ↩
(1) Each Party shall accord to investors of another Party treatment no less favourable than it accords, in like circumstances, to its own investors with respect to the establishment, acquisition, expansion, management, conduct, operation, and sale or other disposition of investments.
(2) Each Party shall accord to investments of investors of another Party treatment no less favourable than it accords, in like circumstances, to investments of its own investors with respect to the establishment, acquisition, expansion, management, conduct, operation, and sale or other disposition of investments.
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expenditure requirements, operate under different legislation,105 and report to different regulators.106 Power generating units that burn coal to generate electricity also have significantly higher emissions than coal mines.107
80. Third, neither the Claimant nor its investment were accorded less favourable treatment, in like circumstances, than Canadian investors and their investments. No individual or company – Canadian or American – received any payment relating to any coal mine interest or asset under the 2015 Climate Leadership Plan or otherwise.
81. In the absence of any treatment, much less nationality-based discriminatory treatment in like circumstances, the Claimant’s Article 1102 claim must fail.
82. Under NAFTA Article 1105(1), “[e]ach Party shall accord to investments of investors of another Party treatment in accordance with international law, including fair and equitable treatment and full protection and security.”
83. The NAFTA Free Trade Commission’s (“FTC’s”) binding interpretation confirms that Article 1105(1) is properly interpreted as referring to the minimum standard of treatment under customary international law.108 A breach of the minimum standard of treatment under customary international law requires conduct that is sufficiently egregious and shocking – a gross denial of justice, a complete
105 For example, while power generators operate under legislation such as the Alberta Utilities Commissions Act, S.A. 2007, c. A-37.2, and the Hydro and Electric Energy Act, R.S.A. 2000, c. H-16, coal mines operate under such legislation as the Coal Conservation Act, R.S.A. 2000, c. C-17, and the Mines and Minerals Act, R.S.A. 2000, c. M-17. ↩
106 For example, while power generators report to the Alberta Utilities Commission, coal mines report to the Alberta Energy Regulator. ↩
108 RLA-001, NAFTA Free Trade Commission, Notes of Interpretation of Certain Chapter 11 Provisions, 31 July 2001, available at: https://www.international.gc.ca/trade-agreements-accords-commerciaux/topics-domaines/disp-diff/NAFTA-Interpr.aspx?lang=eng. See also NAFTA Article 1131(2), which provides: “An interpretation by the Commission of a provision of this Agreement shall be binding on a Tribunal established under this Section.” ↩
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lack of due process, or manifestly arbitrary behaviour – so as to fall below accepted international standards.
84. As a threshold issue, the treatment that the Claimant alleges breached Article 1105 was not accorded to the Claimant’s investment. The Claimant invested in Canada in March 2019, years after the alleged breaches. What the Claimant challenges under Article 1105 is the treatment accorded to the investment of a different investor of a Party – WCC. For that reason alone, its claims under Article 1105 are untenable.
85. Even if the Claimant’s claims under Article 1105 on behalf of WCC are considered, its claims are entirely without merit for three reasons.
86. First, the Claimant impermissibly repeats its Article 1102 claim, arguing that Alberta’s decision to grant Transition Payments to Canadian-owned electricity market participants, but not to WCC, was arbitrary. NAFTA tribunals have repeatedly confirmed that Article 1105 is a not a vehicle for claimants to recycle allegations under Article 1102. As the FTC has pronounced, “[a] determination that there has been a breach of another provision of the NAFTA [...] does not establish that there has been a breach of Article 1105(1).”109
87. Second, the Claimant’s allegation that WCC was “arbitrarily and uniquely excluded” from receiving a Transition Payment is false as a matter of fact.110 No individual or company – Canadian or American – received a Transition Payment in relation to any coal mine interest or asset. Far from being arbitrary, the allocation of Transition Payments to power companies ensured that Albertans would have access to reliable and affordable electricity as its electricity sector transitioned to cleaner energy, and ensured that electricity market participants could access the capital required to participate fully in a transition to a lower-carbon electricity system within the province. Providing a Transition Payment to owners of interests in coal mines would not have advanced this rational policy objective.
109 RLA-001, NAFTA Free Trade Commission, Notes of Interpretation of Certain Chapter 11 Provisions, 31 July 2001. ↩
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88. Third, the Claimant’s argument that Government of Alberta’s decision to phase out emissions from coal-fired electricity generation in its 2015 Climate Leadership Plan violated WCC’s “expectation” of earning a “reasonable return on investment beyond 2030”111 under the Federal Government’s 2012 Federal Emissions Regulations is misguided. NAFTA tribunals have consistently confirmed that the customary international law minimum standard of treatment does not require a State to fulfill such an “expectation” of an investor. Article 1105 is not a guarantee of future investment returns, nor does it impose an obligation on the State to maintain an existing regulatory framework.
89. In any event, WCC could not have reasonably expected the 2012 Federal Emissions Regulations to provide “a predictable future”112 for its investment.113 Any informed investor would have known that provinces have the constitutional prerogative to regulate emissions within their borders and that Alberta was contemplating further emissions regulations, such as increases to the performance requirements and carbon prices under the SGER.114
90. Indeed, WCC’s alleged expectations are contradicted by contemporaneous statements it made to its investors. For example, in describing the Canadian coal mining assets it was about to purchase in its 2013 Annual Report, WCC anticipated that GHG and other climate change regulations in Canada, and in Alberta specifically, for coal-fired plants could change. WCC explained that these changes could have a “material adverse effect on our business, results of operations and financial performance.”115 The Annual Report further explained:
113 The Claimant’s allegation that WCC developed expectations based on undertakings that WCC made to acquire Sherritt’s assets in 2014 during a review of the proposed investment by Canada under the Investment Canada Act and Competition Act also does not make sense. See NOA, ¶¶ 106-107. The Claimant offered voluntary undertakings that Canada’s Minister of Industry could take into account, among other factors, when deciding whether to approve WCC’s investment as being a “net benefit” to Canada. Nothing Canada said or did in the context of approving WCC’s investment has any relevance to the Claimant’s claim against the challenged Alberta measures or establishes a breach of the customary international law minimum standard of treatment. ↩
114 See above ¶¶ 28 and 29. See also the discussion of SGER in R-039, Westmoreland Coal Company, 2013 Annual Report, 28 February 2014 [Excerpt], p. 29. ↩
115 R-039, Westmoreland Coal Company, 2013 Annual Report, 28 February 2014, [Excerpt], p. 29. ↩
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As it is unclear at this time what shape additional regulation in Canada will ultimately take, it is not yet possible to estimate the extent to which such regulations will impact the Sherritt Assets to be acquired by us. [...] For example, laws or regulations regarding GHGs could result in fuel switching from coal to other fuel sources by electricity generators, or require us, or our customers, to employ expensive technology to capture and sequester carbon dioxide. Political and environmental opposition to capital expenditure for coal-fired facilities could affect the regulatory approval required for the retrofitting of existing power plants.116
91. For these reasons, the Claimant’s Article 1105 claims have no merit in law or in fact.
92. The Claimant claims “damages exceeding $470 million”, comprised of US$441 million that it allegedly “otherwise expected to earn” from its mines and $42 million in allegedly “uncompensated expense” for reclamation costs.117 The Claimant’s damages claim is without merit.
93. The Claimant has not even attempted to meet the burden it bears to establish a causal link between each of the breaches of NAFTA Chapter Eleven that it alleges and the damages that it claims as a result. In particular, it has not explained how either the Government of Alberta’s decision to phase out emissions from coal-fired electricity generation or its decision to provide Transition Payments to electricity market participants to facilitate the Province’s transition to a lower carbon electricity system was the proximate cause of the damage or loss that it allegedly suffered. Indeed, the measures could not have caused the Claimant the damage that it claims because it made its investment in Canada years after the measures were adopted. Moreover, there are significant factual flaws in the Claimant’s allegations, including that it does not mention that the 2018 Federal Emissions Regulations were in force when it acquired its Canadian assets, which require all coal-fired generating
116 R-039, Westmoreland Coal Company, 2013 Annual Report, 28 February 2014, [Excerpt], p. 29. The 2014 Annual Report made similar statements. See R-040, Westmoreland Coal Company, 2014 Annual Report, 6 March 2015, [Excerpt], p. 31 (“Future federal legislation, including the implementation of potential international requirements enacted under Canadian law, as well as provincial emissions reduction requirements, may require the reduction of GHG or other industrial air emissions, or emission intensity, from our operations and facilities. Mandatory emissions reduction requirements may result in increased operating costs and capital expenditures. We are unable to predict the impact of emissions reduction legislation on our business and it is possible that such legislation may have a material effect on our business, financial condition, results of operations and cash flows”). ↩
117 NOA, ¶¶ 111, 86, and 87. Canada notes that the Claimant’s damages tabulation does not add up. ↩
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units to meet their stringent emissions standard by December 31, 2029, at the latest. As a result, the Claimant has not established the requisite causation.
94. But even if causation could be established, the Claimant must also demonstrate that it is entitled to the quantum of damages that it seeks. The Claimant has not explained how it arrived at “damages exceeding $470 million”,118 failing to identify even the basic information of the valuation methodology that it used to arrive at this figure. It is evident that the Claimant’s damages claim is overstated. In particular, both the Paintearth and Sheerness mines for which the Claimant claims damages have reserves that will be exhausted in 2022 and 2024, respectively,119 well in advance of 2030 when emissions from coal-fired generating units must be reduced to zero under the 2015 Climate Leadership Plan. The third mine with respect to which the Claimant claims damages, Genesee, WCC owned jointly with Capital Power. On March 28, 2017, WCC negotiated a $70 million agreement with respect to its joint ownership,120 pursuant to which WCC “fully recovered its capital investments at the mine”.121 Moreover, the Claimant has expressly acknowledged that its damages claim is inflated because it has not been discounted to present value.122 The Claimant’s damages claim is thus without merit.
95. Pursuant to Procedural Order No. 1,123 Canada proposes that the Tribunal bifurcate the proceedings into two phases. The first phase would address preliminary questions of jurisdiction and admissibility. Providing an efficient resolution of these questions would allow the disputing parties
119 NOA, Exhibit 3, Westmoreland Coal Company Presentation, “Westmoreland Announces Transformational Acquisition of Sherritt’s Coal Operations”, 24 December 2013, p. 10. ↩
120 R-003, Capital Power, Press Release, “Capital Power enters into cost savings agreement related to the Genesee Mine”, 28 March 2017. ↩
121 R-004, Westmoreland Coal Company, News Release, “Westmoreland Receives $52 Million Early Repayment of Genesee Mine Receivable”, 28 March 2017. ↩
122 See NOA, ¶ 86, fn. 35 (“The amounts in this section have not been discounted to present value.”). ↩
123 Procedural Order No. 1, 22 April 2020, ¶ 14.1. ↩
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to avoid the significant cost and time of presenting extensive factual arguments and evidence in support or defence of the merits of the claim.
96. Canada proposes that the following objections to jurisdiction be addressed in the preliminary phase of the arbitration:
97. Addressing these serious and substantial issues concerning the Claimant’s ability to bring this claim in a preliminary phase of the arbitration is consistent with Article 21(4) of the 1976 UNCITRAL Rules, which apply in this arbitration pursuant to paragraph 6.2 of Procedural Order No. 1. Article 21(4) stipulates that “[i]n general, the arbitral tribunal should rule on a plea concerning its jurisdiction as a preliminary question.” If accepted, Canada’s objections will efficiently dispose of the totality of the Claimant’s claims.
98. Furthermore, the factual issues underlying these objections are not intertwined with the merits of the Claimant’s allegations. The bulk of Canada’s jurisdictional objections concern the sale of WCC’s Canadian business to a new entity (i.e. the Claimant) with different owners (i.e. WCC creditors) in 2019, which occurred well after the alleged breaches in 2015 and 2016. These objections relate to a narrow range of factual issues that are unconnected to the merits. Moreover, the Claimant has already acknowledged the key facts underlying these objections – that it is a different “investor of a Party” than WCC and that it invested in Canada in March 2019.124
124 As a separate “investor of a Party”, the Claimant submitted a new Notice of Arbitration and provided a consent and waiver separate from WCC, as required by NAFTA Article 1121. See NOA, ¶¶ 25-26, and NOA, Exhibit 1 (containing ↩
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99. Likewise, Canada’s objection concerning the timeliness of the Claimant’s claim could be decided on the basis of the NOA, which acknowledges that Alberta’s 2015 Climate Leadership Plan was publicly announced in November 2015 and that this measure precipitated its alleged loss or damage.125
100. Canada also proposes that its objection to the admissibility of the Claimant’s NAFTA Article 1102 claim be resolved by the Tribunal as a preliminary question. Specifically, Canada proposes that the Tribunal issue a ruling on Canada’s objection that Article 1102 does not apply to Alberta’s allocation of Transition Payments because those payments are “subsidies or grants provided by a Party” under Article 1108(7)(b).
101. Article 15(1) of the 1976 UNCITRAL Rules provides that the Tribunal “may conduct the arbitration in such manner as it considers appropriate, provided that the parties are treated with equality and that at any stage of the proceedings each party is given a full opportunity of presenting his case.” In this case, a ruling on Canada’s NAFTA Article 1108(7)(b) objection in a preliminary phase of the arbitration would save the disputing parties the significant time and cost of presenting extensive factual arguments and evidence in support or defence of the national treatment claim on the merits.
102. The evidence required to address this serious and substantial objection as a preliminary matter will be minimal. The Claimant has already provided evidence of the nature of the payments in the form of Off-Coal Agreements, the mechanism through which the Transition Payments are granted.126 Moreover, Canada has already explained that the Transition Payments are made pursuant to Alberta’s Energy Grants Regulation and has provided evidence that the Transition Payments are disclosed to
consent and waiver of Westmoreland Mining Holdings LLC). The Claimant also explains that it acquired its Canadian investment in March 2019. See NOA, ¶ 5, fn. 1 (“Westmoreland Coal Company transferred most of its assets, including the assets at issue here, to Westmoreland Mining Holdings. This transfer was accomplished pursuant to a Plan of Reorganization approved by a U.S. federal bankruptcy court on March 15, 2019”).
126 NOA, Exhibit 19, Off-Coal Agreement between TransAlta Corp. et al., and Her Majesty the Queen In Right Of Alberta (represented by Ministry of Energy), 24 November 2016; NOA, Exhibit 23, Off-Coal Agreement between Capital Power et al. and Her Majesty the Queen In Right of Alberta (represented by Ministry of Energy), 24 November 2016. ↩
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the public as “grants” by Alberta in the ordinary course.127 It will thus be straightforward for the Tribunal to decide whether the Transition Payments fall within the broad meaning of the terms of Article 1108(7)(b).
103. Should the Claimant not consent to bifurcation, Canada will submit a Request for Bifurcation setting out the rationale supporting bifurcation in greater detail.
104. For the foregoing reasons, Canada respectfully requests that this Tribunal:
June 26, 2020
Respectfully submitted on behalf of Canada,
Signature
Adam Douglas
Krista Zeman
Megan Van den Hof
E. Alexandra Dosman
Mark Klaver
127 R-001, Energy Grants Regulation, A.R. 103/2003; R-002, Government of Alberta, Grant payments disclosure table, “CLP Coal Generation Transition”, “Energy General Armed” [Excerpts], available at: https://www.alberta.ca/grant-payments-disclosure-table.aspx. ↩