The Power Group at McCarthy Tétrault LLP is pleased to present Canadian Power – Key Developments in 2016 – Trends to Watch for in 2017. It is our second annual Canadian power industry retrospective. The idea behind this publication is to provide an overview, at both the regional and national levels, of the most significant developments in the Canadian power sector in 2016, including in the areas of project finance, environmental, regulatory and aboriginal law, and to highlight key trends to watch for in 2017.
Table of Contents
REGIONAL PERSPECTIVES ...... 1
British Columbia ...... 1 Alberta ...... 8 Ontario ...... 18 Québec ...... 21
TOPICAL ANALYSES ...... 24
Mergers and Acquisitions ...... 24 Aboriginal Law ...... 28 Environmental Law ...... 33 The Art of Carbon Pricing in an Emissions Constrained World ...... 40
ABOUT McCARTHY TÉTRAULT’S NATIONAL POWER GROUP ...... 43
Special thanks to our publication authors: Dominique Amyot-Bilodeau, Stephanie Axmann, Daniel Bénay, Louis-Nicolas Boulanger, Daniel Goudge, Bryn Gray, Kimberly Howard, Ainslie Hurd, James Klein, Mathieu LeBlanc, Selina Lee-Andersen, Beverly Ma, Zachary Masoud, Sven Milelli, Gordon Nettleton, Sebastian Nishimoto, Seán C. O’Neill, Robin Sirett, Matthieu Rheault, Joanna Rosengarten, Monika Sawicka, George Vegh and Christopher Zawadzki.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
1
McCarthy Tétrault LLP mccarthy.ca
REGIONAL PERSPECTIVES British Columbia
Sven Milelli Sebastian Nishimoto Robin Sirett Ainslie Hurd
Introduction
With no new significant power procurement opportunities on the horizon, B.C.’s power sector remained focused on a number of industry developments including: the progress of BC Hydro’s 1,100 megawatt (“MW”) Site C Clean Energy Project located in the Peace region (“Site C Project”) as initial construction and procurement efforts continue; updates to BC Hydro’s load forecast showing lower load growth than anticipated in previous forecasts; continued anticipation regarding the development of LNG projects in the Province and the opportunities associated with related loads; adjustments to BC Hydro’s Standing Offer Program and the introduction of a Micro-Standing Offer Program targeting sub-1 MW projects; and the commencement in earnest of electricity purchase agreement (“EPA”) renewal negotiations as an increasing number of early-generation EPAs begin to expire.
SITE C PROJECT: LITIGATION AND CONSTRUCTION UPDATES The B.C. Government and BC Hydro have successfully defended against several legal challenges to the Site C Project brought by various claimants, including the Peace Valley Landowner Association (the “PVLA”) and Treaty 8 First Nations in both B.C. and Alberta. In October 2016, the B.C. Supreme Court dismissed a further challenge by the West Moberly and Prophet River First Nations. See page 28, the Aboriginal Law summary for a more detailed overview of this proceeding. 2016 also saw the PVLA and the West Moberly and Prophet River First Nations launch appeals in the B.C. Court of Appeal and the Federal Court of Appeal, respectively; the B.C. court unanimously rejected the PVLA’s appeal, while the Federal court’s decision is pending.
Construction of the Site C Project, which commenced in mid-2015, has progressed steadily through 2016, which saw the completion of a 1,200-room workers’ accommodations, the clearing of over 900 hectares for site preparation, the construction of a temporary bridge linking the north and south banks of the dam site. In addition, BC Hydro awarded a turbine supply and installation contract to Voith Hydro Inc. and sought proposals for other major components of the Site C Project, including the generating station/spillways and the supply of hydro-mechanical equipment.
BC Hydro also entered into impact benefits agreements with various First Nations anticipated to be affected by the Site C Project, including the Dene Tha’ First Nation, the McLeod Lake Indian Band and
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
2
McCarthy Tétrault LLP mccarthy.ca
the Saulteau First Nations. These impact benefits agreements provide the local First Nations with financial payments, economic opportunities and, in certain cases, grants of Crown land.
BC HYDRO’S REVENUE REQUIREMENTS APPLICATION In July 2016, BC Hydro filed a three-year Revenue Requirements Application with the BC Utilities Commission (“BCUC”) (the “RRA”). In the RRA, BC Hydro updated its 20-year load and capacity forecasts from those previously provided in its 2013 Integrated Resource Plan (the “2013 IRP”) to reflect lower-than-expected load growth forecasts in the mining, oil and gas, pulp and paper and LNG sectors, the closure of the Howe Sound Thermo-Mechanical Pulp Facility, and low commodity prices. BC Hydro extended the projected dates on which new energy and capacity resources would be required to fiscal 2022 and fiscal 2020, respectively, from fiscal 2017 (for both energy and capacity) as set forth in the 2013 IRP. In the 2013 IRP, BC Hydro had projected the need to add 400 MW of capacity from gas turbines to meet a projected capacity shortfall on the North Coast in 2020. However, in the RRA, BC Hydro had assumed that no additions would be made to capacity in the North Coast before the end of fiscal 2024.
The 2013 IRP provided targets for energy and capacity savings from demand-side management (“DSM”) of 7,800 gigawatt hours (“GWh”)/year and 1,400 MW, respectively, from fiscal 2013 to fiscal 2021. However, in the RRA, BC Hydro revised the energy and capacity savings from DSM to 5,100 GWh/year and 900 MW, respectively, from fiscal 2016 onward. Although these DSM-related savings are lower than the targets in the 2013 IRP, BC Hydro still expects to comply with the objective in the Clean Energy Act (British Columbia) for BC Hydro to meet at least 66% of the anticipated increase in demand through conservation and efficiency by 2020. In addition, while the 2013 IRP recommended that BC Hydro expend $445 million on DSM measures from fiscal 2014 to fiscal 2016, the RRA provided that BC Hydro’s spending on DSM would be reduced to approximately $375 million through fiscal 2017 to fiscal 2019.
LNG: STATUS AND ANTICIPATED POWER NEEDS In its 2013 IRP, BC Hydro forecasted demand from the LNG industry in the amount of 3,000 GWh/year of power (with a range of 800 to 6,600 GWh/year) and 360 MW of capacity (with a range of 100 to 800 MW/year) by 2022. However, in its RRA, BC Hydro acknowledged the uncertainty in future LNG-driven load growth given delays in final investment decisions (“FID”) on the two largest proposed LNG projects, the LNG Canada and PNW LNG Projects in 2016.
The LNG Canada Project located in Kitimat, B.C., which is majority owned by Shell, is slated to draw approximately 2,000 GWh/year of electricity from BC Hydro’s grid to power ancillary (i.e. non- liquefaction) activities. However, in July 2016, LNG Canada announced that the joint venture participants, including Shell, PetroChina, Mitsubishi Corporation and Kogas, had decided to delay FID. LNG Canada had previously announced that it would make an FID at the end of 2016.
In June 2015, Pacific NorthWest LNG (“PNW LNG”), which is majority-owned by Petronas, announced a conditional FID in respect of its LNG project located near Prince Rupert, subject to the approval by the B.C. Legislature of the project development agreement between the B.C. Government and the proponent, which approval was granted at a special sitting of the B.C. Legislature held in July 2015, and the issuance by the Federal Government of a positive environmental assessment decision, which
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
3
McCarthy Tétrault LLP mccarthy.ca
was granted on September 27, 2016. However, as with the LNG Canada Project, the timing of a full FID for the PNW LNG Project remains uncertain following Petronas’ announcement that it will be conducting a total cost review of the proposed project prior to tabling it to the project’s shareholders for FID.
On November 4, 2016, the parent company of Woodfibre LNG, Pacific Oil & Gas Limited, announced a positive FID for the Woodfibre LNG Project, located near Squamish. Although smaller than the LNG Canada and PNW LNG Projects, the Woodfibre LNG Project is notable for its reliance on electricity from BC Hydro’s grid, rather than natural gas, to power natural gas liquefaction activities. Woodfibre LNG representatives said that the decision to take FID was, in part, based on the B.C. Government’s announcement in November 2016 of the new “eDrive” electricity rate for LNG producers who connect to BC Hydro’s grid. The eDrive rate will be the same as the standard industrial electricity rate and will be subject to the same rate increases set out in BC Hydro’s 10 Year Rates Plan.
The B.C. Government’s Climate Leadership Plan released in August 2016 promotes electrification of upstream natural gas activities (as opposed to self-generation through burning natural gas) as a means of reducing greenhouse gas emissions. The Climate Leadership Plan estimates that full electrification of natural gas projects in the Montney Basin in Northeast B.C. could reduce greenhouse gas emissions by up to 4 million tonnes/year. However, the Climate Leadership Plan acknowledges that creating the infrastructure for electrification will require large capital investments, and indicates that the B.C. Government is in talks with the Federal Government to invest some of the necessary capital.
STANDING OFFER PROGRAM (“SOP”) AND MICRO-STANDING OFFER PROGRAM (“MICRO-SOP”) The SOP and Micro-SOP, which are aimed at new, small scale, renewable energy projects, are currently BC Hydro’s only active procurement opportunity for independent power producers (“IPPs”). The SOP is open to projects with a capacity of 100 kW to 15MW, while the Micro-SOP is limited to projects with a capacity between 100 kW and 1 MW.
Revised SOP Rules In April 2016, BC Hydro released a new version (Version 3.2) of its SOP Rules to address feedback it received during First Nation and stakeholder consultation meetings and focus group discussions conducted over the last few years. Some of the most notable changes are summarized below:
• Additional Generators - new generators added to sites with existing generation are no longer eligible under the SOP.
• First Nations Consultation - BC Hydro now considers the issuance of land tenures, permits and licenses as sufficient evidence that a Crown agency has completed its First Nations consultation.
• Cluster Rules - revised rules regarding project clusters and common generation facilities clarify that such arrangements are permitted but must not exceed 15 MW in the aggregate.
• Staged Review Process - SOP application and review processes are now organized into eligibility and system impact stages, while rigid timelines for EPA offer and acceptance have
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
4
McCarthy Tétrault LLP mccarthy.ca
been replaced with the more general requirement that such steps occur "within a commercially reasonable period of time".
• Changes to Standard Form EPA - the Standard Form EPA has been streamlined, and the number of appendices has been reduced from 12 to three.
New Micro-SOP In March 2016, BC Hydro introduced the Micro-SOP, which is limited to very small-scale clean energy projects in B.C. with capacities between 100 kW and 1 MW. The Micro-SOP is only available to projects which are beneficially owned by First Nations or communities, including municipalities, not-for-profit groups, public organizations and participants in the agriculture sector. However, First Nations and community groups are still eligible for the Micro-SOP if they partner with private sector IPPs to develop the project.
The Micro-SOP differs from the SOP in certain key respects, including the following:
• Time of Delivery Price Adjustments – there are no time of delivery price adjustments.
• Interconnection – all projects must be directly interconnected to BC Hydro’s distribution system.
• Standard Form Agreements – the standard form interconnection agreement and EPA are simplified relative to the SOP forms.
• Screening Studies – there is a mandatory screening study which estimates the interconnection requirements for the project (subject to a $5,000 fee).
• EPA Term – the EPA term ranges from 5 to 40 years from COD of the project (as opposed to 20 to 40 years from COD for SOP projects).
As of August 2016, there was one application submitted under the Micro-SOP for the 1.0 MW Siwash Creek Hydro Project near Boston Bar.
Available Energy Volume BC Hydro maintains a 150 GWh/year target volume for both the SOP and Micro-SOP, on a first-come, first-served basis. In August 2016, BC Hydro published figures for available energy volume under the SOP and Micro-SOP for each Target COD year showing zero availability in 2016 and six, eight and 82 GWh/year of available volume for SOP and Micro-SOP projects with Target CODs in 2017, 2018 and 2019, respectively (see table below).
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
5
McCarthy Tétrault LLP mccarthy.ca
Available Energy Volume (SOP/Micro-SOP) 100 80 Available Energy 60 Volume 40 (GWh) 20 0 2016 2017 2018 2019 Year
On August 18, 2016, BC Hydro announced that it has received sufficient SOP applications to fill the remaining available SOP energy volume up to the end of the 2019 calendar year. BC Hydro will continue to receive and review applications but will not assign any volume for year 2020 and beyond for the SOP until the price and target volume post-2020 Target CODs are determined by BC Hydro with input from Clean Energy BC, an industry organization which represents IPPs.
Overview of Awarded SOP EPAs In August 2016, BC Hydro released an updated list of current SOP EPAs and SOP applications showing 25 EPAs and 11 applications. Four of the EPAs were awarded in 2016, including EPAs in respect of the Clemina Creek Hydro Project, the Hunter Creek Run-of-River Hydroelectric Power Project, the Serpentine Creek Hydro Project and the Winchie Creek Hydro Project. A breakdown of the current EPAs by energy source is set out below:
Biogas (12%) Biomass (8%) Hydro (60%) Solar (4%) Wind (16%)
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
6
McCarthy Tétrault LLP mccarthy.ca
EPA Renewals As of November 2016, BC Hydro had 114 EPAs with IPPs whose projects have reached COD (representing approximately 19,762 GWh of annual supply and 4,836 MW of capacity) along with 21 EPAs with IPPs with development-stage projects (representing approximately 2,385 GWh of annual supply and 567 MW of capacity).
In BC Hydro’s RRA, BC Hydro indicated that since 2013, it has entered into agreements with IPPs to terminate 14 EPAs and defer the delivery of energy under an additional 11 EPAs, representing a reduction in nameplate capacity of 435 MW, a permanent reduction in contracted energy of 1,890 GWh/year, a temporary deferral in contracted energy of 2,050 GWh between fiscal 2015 and fiscal 2018 and a $2.1 billion reduction in BC Hydro’s electricity purchase commitments.
BC Hydro further indicated in its RRA that it will be pursuing EPA renewals on a cost-of-service basis, which will favour those IPPs which provide the lowest cost, greatest certainty of continued operations and best system support. In renegotiating EPAs, BC Hydro will consider, among other things, the opportunity cost of the IPP, the electricity spot price, and the cost of service for the IPPs. Based on the assumption that IPPs will have fully recovered their capital expenditures during the initial term of their EPAs, BC Hydro expects to negotiate lower energy prices when renewing EPAs. BC Hydro estimates that it will be able to acquire power under renewed EPAs at or below $85/MWh, although the actual energy price under each renewed EPA will be the subject of bilateral negotiations between BC Hydro and the applicable IPP.
BC Hydro has stated that it plans to acquire through renewed EPAs 50% of the energy and capacity contributions of existing bioenergy EPAs and 75% of the contributions of the existing run-of-river hydroelectric EPAs that are due to expire by 2024.
WHAT TO EXPECT IN 2017
LNG Final Investment Decisions As in 2016, LNG projects continue to face uncertainty in 2017 given the difficulties faced by the global energy industry as a whole. B.C. Minister of Natural Gas Development, Rich Coleman, has predicted that FID could be made in respect of the PNW LNG by April 2017. However, only time will tell whether 2017 will see the announcement of any further FIDs.
BC Hydro’s 2015 Rate Design Application In September 2015, BC Hydro filed its 2015 Rate Design Application with the BCUC (the “RDA”), which represented the first comprehensive review of BC Hydro’s rates since 2007. Over the course of 2016, the BCUC received arguments from a variety of interested parties, including various advocacy groups for low income individuals who argued in favour of measures, such as reduced rates and delayed disconnections, to assist low income individuals meet their electricity needs. Given that the parties submitted their final arguments to the BCUC in October 2016, we expect that the BCUC will release its decision in the first half of 2017.
EPA Renewals Fourteen of BC Hydro’s EPAs with IPPs will expire by the end of 2019 and, according to BC Hydro’s RRA, BC Hydro will continue to assume renewal of 50% of the energy and capacity contributions from
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
7
McCarthy Tétrault LLP mccarthy.ca
biomass EPAs and 75% from the run-of-river hydroelectric EPAs. As stated by Paul Kariya, executive director for Clean Energy BC, “that must mean that 25% fall off the table.” EPA renewal prospects will no doubt be affected by the $3.5 billion revenue shortfall announced by BC Hydro in July 2016. BC Hydro cited reducing the amounts paid to IPPs under renewed EPAs as a measure to reduce its costs.
Future Drivers of Renewable Energy in B.C. Given the substantial power requirements of LNG plants, the growth of B.C.’s LNG industry represents a significant source of future load growth along B.C.’s coast. In addition, the B.C. Government’s plan to electrify upstream natural gas activities (e.g. extraction and compression) in Northeast B.C. could significantly increase the load in that region. However, industry watchers predict that construction of the proposed electrification infrastructure in Northeast B.C., such as B.C. Hydro’s proposed Peace Region Electricity Supply project and ATCO’s North Montney Power Supply project, will depend on LNG projects reaching positive FID.
Another potential driver of demand for B.C.-generated power is the prospect of increased hydroelectricity exports to Alberta in response to the Alberta Government’s “30 by ‘30” target of having 30% of the electricity in the Province be sourced from renewable sources (e.g. wind, hydro and solar) by 2030. B.C. Premier Christy Clark, a promoter of increased electricity exports to Alberta, has requested $1 billion in funding from the Federal Government to upgrade the transmission infrastructure connecting the B.C. and Alberta power grids. However, given the large costs and political considerations involved, it remains to be seen whether the prospect of increased electricity exports to Alberta will materialize into a concrete driver of demand for B.C. electricity.
An additional potential driver of long-term growth in renewables is the Federal Government. On November 4, 2016, Federal Environment and Climate Change Minister, the Hon. Catherine McKenna, announced that by 2025, the Federal Government will power its facilities solely with renewable energy. As a result of this development, the Federal Government could represent a substantial new customer for BC Hydro.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
8
McCarthy Tétrault LLP mccarthy.ca
Alberta
Kimberly Howard Beverly Ma
Introduction
Throughout 2016, a number of developments directly affected Alberta’s power sector. Many of these significant developments arose in connection with the implementation of the Climate Leadership Plan (“Climate Plan”) by the Government of Alberta (“Province”), which was originally announced in November of 2015. Among other things, the Climate Plan promised an economy-wide carbon price, a legislated cap on oil sands emissions and set goals for the phase-out of coal-fired generation by 2030.
For the power sector, the driving objective is to cease emissions from coal-fired generation by 2030. Two-thirds of the existing coal electricity is intended to be replaced with renewable energy and one- third with natural gas. To date, the Province has taken a number of steps toward achieving these goals. Significantly, and by way of example, Alberta recently announced a major restructuring of its electricity market, from a fully deregulated regime to a hybrid system incorporating capacity payment mechanisms.
Market Snapshot
CURRENT STATUS Alberta is one of the few jurisdictions in the world with an “energy-only” market. For the time being, transmission and distribution in Alberta is regulated, while the generation and retail sale of electricity is open to competition. The market is a real-time, energy-only equilibrium market, or power pool. The Alberta Electric System Operator (“AESO”) is responsible for facilitating a fair, efficient and openly competitive market and for the safety and reliability of the electricity grid.
The following are some key statistics of Alberta’s electricity market:
− Approximately 39% of Alberta’s installed electricity generation capacity is from coal, almost 44% is from natural gas, 9% is from wind, and the remaining capacity is from water, biomass and waste heat forms of generation.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
9
McCarthy Tétrault LLP mccarthy.ca
Source: AESO, Electricity in Alberta, as of August 2016.
− As of May 2016, the AESO estimated the changes depicted below to Alberta’s future generation capacity based on the anticipated policy changes. Although, the estimates are based on the assumption of 4,200 megawatts (“MW”) of installed renewable capacity, which the Province subsequently announced a target of 5,000 MW from wind, solar and hydro projects by 2030.
Source: AESO 2016 Long-term Outlook, as of May 2016.
SHIFT TO CAPACITY MARKET Early in 2016, the Province directed the AESO to spearhead initiatives for development and implementation of the Renewable Electricity Program (“REP”). The AESO undertook stakeholder consultation and developed draft recommendations in the form of a report that was delivered to the Province on May 31, 2016. In this report, it recommended that Alberta transition from an energy-only market to a capacity market to facilitate the Province’s objectives to achieve a lower-carbon, sustainable electricity system.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
10
McCarthy Tétrault LLP mccarthy.ca
Under the proposed market transition, Alberta will incorporate mechanisms to compensate power producers for their generation capacity. Alberta’s electricity market will therefore be comprised of three markets: (1) a market for energy; (2) the ancillary services market; and (3) a market for capacity, in which generators will agree to be available to supply electricity when required. Each market produces separate revenue streams:
− energy payments, which are paid to the generator for electricity that is purchased;
− payments for services required to ensure the safety and reliability of interconnected electric system; and
− capacity payments, which are paid to the generator for making generation capacity available on demand.
The AESO’s current proposed timeline to implement the capacity market is as follows:
− Alberta’s capacity market will be developed in consultation with stakeholders, and will be implemented by 2021.
− AESO has estimated that the design of the market will take 2 years to complete, with an additional year to finalize legal contracts and to set up a procurement process.
− The first capacity contracts are expected to be entered into at least 3 years after the design process starts.
− The earliest date that capacity procured through the initial auction could be in-service is 2024.
Key Developments in 2016
The Alberta economy is a key driver affecting the electricity market. The downturn in the price of oil coupled with the Province’s various steps to implement the Climate Plan and retire coal-fired generation impacts future renewables development, system planning by the AESO, power prices for consumers and even the future fate of Alberta’s energy-only market.
The developments in 2016 highlighted in this update include: (1) the phase-out of coal emissions by 2030; (2) updates respecting Alberta’s statutory Power Purchase Arrangements (“PPAs”) for coal-fired generation; (3) amendments to the Balancing Pool structure and other consumer protection initiatives; (4) the launch of the AESO’s REP; and (5) noteworthy regulatory decisions affecting the power market, including the recent hearing on the Fort McMurray West 500 kV Transmission Project.
PHASE-OUT OF COAL EMISSIONS BY 2030 Alberta’s emissions from coal are to cease by 2030 either through the retirement of units or by owner action to fully sequester carbon dioxide. The Climate Plan’s goal is to replace these units with two- thirds renewable energy and one-third natural gas generation. The Province legislated its “30 by ‘30” target in the Renewable Electricity Act, which was tabled in November 2016.
In March of 2016, Terry Boston was named to act as the Province’s independent coal phase-out facilitator. Generally, he was tasked with presenting options to the Province that will strive
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
11
McCarthy Tétrault LLP mccarthy.ca
to maintain the reliability of Alberta’s electricity grid and the stability of prices for consumers, and avoid unnecessarily stranding capital while meeting the Province’s objective to phase out coal generation by 2030.
In November 2016, the Province reached agreements with the facility owners of coal-fired units with operating lives beyond 2030, being TransAlta Corporation (“TransAlta”), Capital Power Corporation (“Capital Power”), and ATCO Ltd. (“ATCO”), to provide transition payments as part of the coal phase- out process. Mr. Boston spearheaded the discussions with the three facility owners, and recommended transition payments to these generators as a means to offset the losses they will incur as a result of the coal phase-out program, and to incent reinvestment into Alberta’s electricity market.
The initiatives by the Province are in line with the Federal Government’s objective to transition from coal power to clean energy by 2030. Indeed, the Government of Canada recently announced its decision to accelerate investment in clean electricity by using the Canada Infrastructure Bank to finance projects such as commercially viable clean energy systems.
Under the proposed scheme, TransAlta, Capital Power, and ATCO are expected to receive annual payments over the course of 2016 to 2030 totaling $1.1 billion. The Province announced that these payments will not be funded by consumer electricity rates, but rather by the Alberta’s carbon levy on industrial emissions. The payments will represent the approximate disruption to the capital investments of these facility owners.
POWER PURCHASE ARRANGEMENTS LITIGATION The PPAs were the chosen mechanism to transition the Alberta electricity market from a cost-of- service model to the current deregulated energy-only model. The PPAs are statutory arrangements imposed by regulations under Alberta’s Electric Utilities Act to allow their holders to buy output from the facility owners and bid it into the power pool. The PPAs have recently declined in profitability for their holders as a result of increased costs attributed to Alberta’s regulation of greenhouse gas (“GHG”) emissions and lower revenues resulting from falling power pool prices. For example, changes to the Specified Gas Emitters Regulation in 2015 significantly increased the cost of emissions for those emitting 100,000 tonnes or more of GHG. Starting in 2018, coal-fired generators will pay a levy constituting $30.00 per tonne of carbon dioxide on emissions above what Alberta’s cleanest natural- gas fired plant would create for the same amount of electricity.
Before the Climate Leadership Act officially became law, all PPA holders gave notice of their intention to terminate their PPAs under their respective contractual “Change in Law” provisions. Such provisions, dubbed the “Enron Clause” by the Province, allow the PPA holder to terminate the PPA without penalty if a “Change in Law” renders the PPA “unprofitable or more unprofitable.” In December 2015, ENMAX was the first to announce that it was “terminating” its interest in a PPA with the owner of the Battle River 5 coal plant subject to the PPA. The Balancing Pool accepted the termination of the Battle River PPA in accordance with the terms of the PPAs, and to date, this is the only termination that has been formally accepted. The Balancing Pool’s acceptance of the other PPA terminations is pending.
Controversy arose as the Province disputed the effectiveness of the Change in Law Clause. The Province filed an application seeking a declaration from the courts as to the validity of the Change in Law Clause. Specifically, it contends that, in 2000, during the process of finalizing the PPAs but
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
12
McCarthy Tétrault LLP mccarthy.ca
before their “auction”, a request was made on behalf of Enron to add the phrasing “or more unprofitable” to the Change in Law provision. This added language broadly increased the discretion of the PPA holders to terminate their respective PPAs. The form of PPAs previously approved by public hearings were granted such amended phrasing by the Energy Utilities Board of Alberta without public notice or hearing. Further, the Province is arguing that the last-minute amendment to the PPA was void from the outset because it was done without proper consultation or review, and thus there was no authority to amend the PPAs in the first place. The Province’s strategy appears to be that if the words “or more unprofitable” are found by the court to not be valid, the PPA holders will not have met the condition necessary to allow the Balancing Pool to accept the termination of the PPAs and will, therefore, need to keep performing their contractual obligations. Generally, the position of the PPA holders is that the Province’s legal claim is without merit and the Province should not be permitted to retroactively amend an arrangement for which PPA generators and holders have relied upon and made significant capital investments under for nearly two decades.
In addition to the Province’s application for a judicial declaration, the resolution of disputes respecting the PPAs has progressed along a number of other different courses, including by way of:
− Negotiations between the Province and buyers respecting terms of termination of PPAs.
− An application by ENMAX to the Court of Queen’s Bench to determine the effective date of termination of its interest in the PPA respecting the Battle River 5 coal plant, following the Balancing Pool’s acceptance of its termination.
− Arbitrations commenced by TransCanada Energy and ATSC Power Partnership respecting their entitlement to terminate PPAs associated with the Sundance A, Sundance B and the Sheerness coal plants.
To date, the Province has reached final settlement agreements with Capital Power, AltaGas Ltd. and TransCanada Energy Ltd. respecting litigation over the PPAs. Accordingly, these companies will be removed from the court proceedings initiated by the Province. The outcome of the PPA disputes remains uncertain, and it will be interesting to see whether the courts and arbitrators will hear these matters before settlements are reached, and if so, whether they will reach consistent decisions.
CONSUMER PROTECTION The Province recently announced several initiatives targeted at ensuring low and stable electricity prices for consumers, including: (1) legislative amendments to permit the Balancing Pool to borrow funds from the Province; (2) a short-term price-cap on electricity prices; and (3) a door-to-door ban on selling household energy products, as further discussed below.
Amendments to the Balancing Pool The Balancing Pool was established by the Province through regulations under the Electric Utilities Act in 1999 to help manage the transition in Alberta’s electricity industry to an openly competitive market. As part of its mandate, the Balancing Pool was required to manage unsold PPAs.
Depending on the outcome of the PPA disputes, the Balancing Pool may be forced to take over the terminated PPAs. Pursuant to section 96 of the Electric Utilities Act, a PPA that has been terminated and such termination has been accepted by the Balancing Pool is deemed to have been sold to the
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
13
McCarthy Tétrault LLP mccarthy.ca
Balancing Pool. The Balancing Pool then has the statutory option of continuing to hold the PPA, reselling it, or terminating it by paying the generator an amount equal to the net book value of the generating unit. If the Balancing Pool maintains the PPA, it becomes responsible for offering the capacity into the market and making payments under the PPA to the generator. By taking over the PPAs, the Balancing Pool would have to pay power producers the same amount that PPA buyers would have, and the result is that the Balancing Pool would risk having insufficient funds.
Currently, the Province reports that the average electricity consumer receives a Balancing Pool credit of $1.95 on their monthly bill. However, if the Balancing Pool became responsible for the terminated PPAs, it is expected that the Balancing Pool would have to remove that credit and apply a charge of $8.40 per month (approximately $100.00 per year) effective January 1, 2017, with similar charges applied until the end of 2020. The introduction of Bill 34, or the Electric Utilities Amendment Act, 2016, (“Bill 34”) in November 2016 offers a potential remedy to this problem.
Bill 34 allows the Balancing Pool to borrow money from the Province to manage its funding obligations, smoothing price volatility over a longer period of time to provide more stability in electricity costs for consumers. Additionally, Bill 34 provides the Balancing Pool until 2030 to meet its net zero obligations. As a result of these amendments, it is estimated that the Balancing Pool’s charge would instead be 67 cents per month for the average consumer (which is $7.73 less per month than if the Province had not intervened).
Effectively, Bill 34 ensures that the Balancing Pool can meet its financial obligations without consumers shouldering an immediate and disproportionate increase to electricity bills. Presently, the Province has not announced the total amount of the loans that will be made to the Balancing Pool, and thus the final cost of this initiative to tax payers remains to be determined.
Price-cap on Electricity Prices The Province announced its commitment to protecting consumers from volatile electricity prices by implementing a price-cap of 6.8 cents per kilowatt hour from June 2017 to June 2021. Consumers on the Regulated Rate Option will pay the lower of the market rate, or the ceiling rate. It bears mentioning that, as the cap on electricity prices and the implementation of power capacity payments will likely not overlap, the implications of the capacity power market on long-term consumer prices remain uncertain.
While the funding of the off-coal payments and the financial incentives under the AESO’s REP, are intended to be covered by Alberta’s carbon levy on industrial emissions, Alberta Energy indicated during a briefing call held on December 9, 2016 that the source of the funds for the consumer price- cap had not yet been finalized. Who ultimately pays for the potential costs of the consumer price-cap could become a highly political issue.
Door-to-Door Ban As of January 1, 2017, selling household energy products unsolicited door-to-door is prohibited though the implementation of legislative changes to Alberta’s Fair Trading Act and its regulations targeted at direct sales and energy marketing.
The prohibition will apply to unsolicited sales of household energy products only, and specifically: furnaces, natural gas and electricity energy contracts, water heaters, windows, air conditioners and energy audits. The Province has made it clear that the ban is targeted at door-to-door sales, and
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
14
McCarthy Tétrault LLP mccarthy.ca
energy companies can still sell directly to customers through other means, including telephone, online sales, kiosks and advertising.
Retailers must ensure that all door-to-door sales have ceased as of January 1, 2017. Further, all practices for sales and marketing conducted through the remaining permitted means (i.e. telephone, internet, kiosks and advertising) should be also reviewed to ensure any practices that could potentially be classified as door-to-door comply with the new legislative requirements.
AESO’S RENEWABLE ELECTRICITY PROGRAM The Province tabled the Renewable Electricity Act, which received Royal Assent on December 14, 2016, legislating its “30 by ‘30” target and providing powers to the AESO to administer a competitive bid process for its REP. Under the REP, successful bidders enter into a Renewable Electricity Support Agreement (“RESA”) with the AESO, which will provide a 20-year indexed renewable energy credit, structured akin to a CFD, to cover any difference between the participant’s bid price for the project and the pool price of energy in the market.
Competitive Procurement Process The REP process will consist of three stages:
1) Request for Expressions of Interest: 4-6 weeks Interested parties determine whether to participate in the competition. There is no obligation on interested parties to participate at this stage.
2) Request for Qualifications (“RFQ”): 4-6 months Bidders meeting certain eligibility requirements submit their qualifications and pay a qualification fee to participate in the bid.
3) Request for Proposal (“RFP”): 2-3 months Qualified RFQ bidders submit their final binding offer for support (i.e. bid price).
Following the closing of the competition, the REP process must be approved by the Minister. After this, the successful bid participants will enter into a RESA with the AESO.
Project Eligibility The purpose of the RFQ stage is to identify participants and projects that are eligible to participate in the RFP. The RFQ stage allows the AESO to evaluate the financial, technical, and other eligibility requirements of participants, and ensures that the project being bid is completed by the specified in-service date. Participants qualified by way of the RFQ stage will be eligible to participate in the RFP.
First Competition Late in 2016, the AESO released a draft Term Sheet proposed for the RESA and solicited stakeholder feedback. The first competitive bid process (the “First Competition”) is expected to commence in Q1 of 2017. The First Competition will see participants bidding to provide up to 400 MW of renewable electricity. Future competitions for renewable generation are expected between now and 2030 as Alberta transitions away from coal-fired generation.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
15
McCarthy Tétrault LLP mccarthy.ca
The First Competition will:
− be open to all renewable technologies, with lowest cost qualified projects receiving support;
− support an indexed renewable energy credit payment mechanism;
− require supported projects to be operational by the end of 2019;
− offer 20-year contract terms consistent with international norms; and,
− require projects to connect to existing transmission or distribution infrastructure to avoid indirect costs to electricity consumers.
The RFQ stage for the First Competition will begin in Q2 of 2017, and the RFP in Q4. The winning bidder will be the lowest cost qualified project.
Future Competitions In its report titled Renewable Electricity Program Recommendations, the AESO provided a framework of the bidding process for future auctions, including criteria for project eligibility. The AESO stated that, at the RFQ stage of the procurement process, bidders must pay a non-refundable qualification fee and demonstrate their qualifications in the following three categories: (1) project eligibility; (2) financial strength and capability; and (3) technical capability, as further described below. 1) Project Eligibility: Bidders are required to meet the prescribed eligibility criteria, and may be required to demonstrate whether: − the project to be developed uses technology that meets the prescribed definition of renewable;
− the project is a new or expanded development;
− the project is situated in Alberta;
− the project is utility-scale (equal to or greater than 5 MW);
− the project is likely to achieve a specified in-service date based on activities completed to date and a demonstrated understanding of activities yet to be completed; and/or,
− the project requires new transmission system or distribution system investment.
2) Financial Capability: Bidders must demonstrate that they have adequate financial strength to develop the project, including the establishment of sufficient net worth and confirmation that there is no reasonably foreseeable event that could have a material adverse impact on financial standing.
3) Technical Capability: Bidders must demonstrate that they have the technical skills to develop the proposed project, including recent involvement in similar projects or experience in each stage of project development.
It should be noted that these are only minimum requirements, and additional eligibility criteria may be introduced, as seen in the specific requirements set out under the First Competition. Further, Alberta’s
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
16
McCarthy Tétrault LLP mccarthy.ca
Minister of Environment left it open for future competitions to allow indigenous participation or projects to be built in specific regions to outweigh cost considerations.
Energy Efficiency Program Along with the Climate Leadership Act, the Province introduced the Energy Efficiency Alberta Act to establish a new government agency. The newly-created Energy Efficiency Alberta mandate is to:
− raise awareness among energy consumers of energy use and the associated economic and environmental consequences;
− promote, design and deliver programs and carry out other activities related to energy efficiency, energy conservation and the development of micro-generation and small scale energy systems in Alberta; and,
− promote the development of an energy efficiency services industry.
While further details on plans for the agency are currently sparse, the Province is in the process of taking the necessary steps to launch programming in the spring of 2017, including by consulting Albertans and stakeholders to design programs to manage energy consumption.
FORT MCMURRAY WEST 500 KV TRANSMISSION PROJECT In December 2014, the AESO awarded, through its first ever competitive process, the construction and operation of the Fort McMurray West 500 kV Transmission Project (“West Project”) to the Alberta PowerLine Limited Partnership. The second part of the AESO’s Fort McMurray transmission system reinforcement is a second major transmission line called the Fort McMurray East 500 kV Transmission Project. Similar to the West Project, the transmission facility operator will be selected through the AESO’s competitive process. Due to economic conditions, the AESO deferred the launch date of the second project.
The hearing for the West Project commenced on October 12, 2016 in Edmonton, and ended on November 10, 2016. It is expected that the AUC will release its decision on the project and approval of a route by early February 2017.
Into 2017 and Beyond
Significant changes to Alberta’s generation mix are ahead, and with such changes come uncertainty. The economic downturn, continuing lack of detail respecting certain aspects of the Climate Plan’s implementation and the outcome of the PPA litigation contribute, among others, to the current state of uncertainty in the Province. Such regulatory uncertainty creates challenges for the forecasting of load, generation and economic growth in Alberta, and policy announcements have affected such predictions even as of the AESO’s most recent forecast in May 2016.
The targeted displacement of coal-fired generation will be a monumental challenge, and the success of the REP could be affected due to natural gas prices on increased provincial reliance on natural gas, which by its nature could result in increased price volatility for the Alberta power market generally. This increased price volatility is not only driven by the variations in fuel source costs, but also by the
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
17
McCarthy Tétrault LLP mccarthy.ca
inherent nature of natural gas generation and its ability as a product to permit flexible power generation strategies.1 For example, smaller generation facilities allow operators to cycle down plants when prices are low and bring them on only during peak prices, further exaggerating the price volatility.2 The more difficult it becomes to accurately forecast price curves, the greater the challenges to incumbents or potential new entrants to predict operational risks.
Implications from the overhaul of Alberta’s power market will need to be considered in light of other regulatory changes recently announced by the Province. It will be critical to watch how the capacity market will interact with the principles of the energy-only market and how the principles legislated within the Fair, Efficient and Open Competition Regulation will be applied to the various relationships between generators participating in the Alberta market, including the successful bidders from the REP and the auction for capacity contracts, and how such incentives will be addressed with incumbent generators who already invested, built and operate natural gas and renewable generation facilities in Alberta. Depending on the rates of the capacity market and the terms of the capacity contracts, greater price volatility could affect participation levels in capacity markets.
The recent announcements by the Province have provided consumers some reassurance of stability amidst the uncertainty. The price-cap on electricity prices in the retail market provides comfort that consumers will be protected, at least in the short-term, from unstable electricity prices. Further, the decision of the Province to provide transition payments to coal generators with facilities that were slated to operate beyond 2030 offsets losses that they will incur as a result of stranded assets, acting as a catalyst to encourage reinvestment into renewables that are needed to meet the energy gap. Together, these measures offer comfort that short-term volatility will be addressed for consumers and producers alike, as tangible measures are being introduced to attain future energy security. However, the ongoing source of funding for such measures will be a critical issue for the Province and its taxpayers.
1 Craig Parsons, “Market Outlook Report: What effect will the shift from coal to natural gas fired electricity generation in Alberta have on the price of the Alberta Electric System Operator’s system marginal price of electricity?” (Genalta, 2015) at 42. 2 Ibid.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
18
McCarthy Tétrault LLP mccarthy.ca
Ontario
Seán C. O’Neill James Klein George Vegh Zachary Masoud
Introduction
For Ontario’s power sector, 2016 was marked by uncertainty, setbacks and anticipation on a variety of fronts, including with respect to the Large Renewable Procurement II (“LRP II”), political strategies to reduce energy costs, the early days of energy storage in Ontario and the continued development of the cap-and-trade program. Despite the sound of receding footsteps as Ontario’s renewable energy developers ran west to the siren call of the Alberta and Saskatchewan renewable capacity procurements, 2016 was nonetheless a busy year with many developments in Ontario’s power industry. We predict the spotlight, although dimming, will continue to shine on this Province in 2017.
LARGE RENEWABLE PROCUREMENT – STILL KEEPING ONTARIO INTERESTING LRP II was announced on April 5, 2016 with procurement targets of 600 MW of wind, 250 MW of solar, 50 MW of waterpower, 30 MW of bioenergy and 50 MW for technical upgrades and optimization of existing facilities. Submissions for the LRP II Request for Qualifications (“LRP II RFQ”) were due on September 8, 2016. The Ontario Independent Electricity System Operator (the “IESO”) received fifty- nine LRP II RFQ submissions and successful applicants were to be notified in November 2016. The second phase of the process, the LRP II Request for Proposals (“LRP II RFP”), was expected to begin in early 2017, with contracts offered by May 2018. However, on September 27, 2016, the Minister of Energy issued a policy direction to suspend the LRP II process. In response to this direction, the IESO cancelled the first phase of the LRP II RFQ and announced that it would not commence the LRP II RFP.
Suspending LRP II was noted as being a part of the Ontario Government’s plan to reduce electricity costs for consumers. Indicating that renewable energy prices were expected to continue to decline further, the Ministry of Energy advised that suspending LRP II would allow the Government to procure renewable energy at an even lower cost in the future. It further noted that suspending the LRP II process “would save up to $3.8 billion in electricity system costs relative to Ontario’s 2013 Long-Term Energy Plan (“LTEP”) forecast” and up to $2.45 per month on the average residential electricity bill of a typical consumer.
The Ministry of Energy based its decision to suspend the LRP II process on the Ontario Planning Outlook (“OPO”) published by the IESO. The OPO indicated that Ontario has abundant electricity resources to support the development of projects planned in the LTEP. The findings in the OPO considered a range of demand forecasts for electricity in Ontario from 2016 to 2035.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
19
McCarthy Tétrault LLP mccarthy.ca
MINISTRY OF ENERGY – STRATEGIES TO REDUCE ENERGY COSTS In addition to the suspension of LRP II, in 2016, Ontario took several actions with the aim of reducing electricity costs while still ensuring that the Province continues to have a clean, reliable source of electricity. Of note is the following:
1. Ontario entered into a seven year agreement with Québec to trade electricity, capacity and energy storage, which the Government claims will reduce Ontario’s electricity system costs by about $70 million when compared to previous forecasts.
2. Ontario passed legislation to reduce electricity bills in Ontario by 8 per cent, an amount equal to the Provincial portion of the Harmonized Sales Tax, effective January 1, 2017.
3. Ontario announced that it would reduce Feed-In Tariff (“FIT”) prices through annual price reviews, which the Government indicates could save ratepayers at least $1.9 billion.
4. Ontario refined the refurbishment schedule of the Province’s existing nuclear fleet by agreeing to have Bruce Power L.P. commence its refurbishments in 2020, instead of 2016, which the Government indicates would help to achieve $1.7 billion in savings. The decision by Ontario Power Generation to continue to operate the Pickering nuclear generation facility up to 2024, pending regulatory approvals, is also being described by the Government as saving ratepayers as much as $600 million.
ENERGY STORAGE – EARLY DAYS In 2016, energy storage continued to gain momentum in Ontario. Low cost energy storage is on the cusp of materially expanding in Ontario as the price of storage technology lessens and growing markets further drive down costs.
The IESO published a report on energy storage in March 2016 (the “IESO Report”)3 in response to a letter issued to the IESO by the Minister of Energy on April 22, 2015, requesting that “the IESO should review the outcomes of the 50 MW energy storage procurement and incorporate resulting learnings, along with any other relevant analyses or new knowledge, into a March 1, 2016 report.” The IESO Report noted three types of opportunities for energy storage in Ontario: (1) energy storage technologies that are capable of withdrawing electrical energy from the grid, storing such energy for a period of time and then re-injecting this energy back into the grid; (2) energy storage technologies that withdraw electricity from the grid and store the energy for a period of time until used by a host facility; and (3) energy storage technologies that only withdraw electricity from the grid like other loads but convert it into a storable form of energy or fuel that is subsequently used in an industrial, commercial or residential process or to displace a secondary form of energy. The IESO Report concluded that energy storage facilities can provide a wide range of services needed to reliably operate the power system in Ontario, including regulation, voltage control, operating reserve, and flexibility, and can help improve the utilization of existing transmission and distribution assets by deferring some costs associated with their upgrades or refurbishments, as well as improve the quality of electricity supply in certain areas of the system by controlling local voltages.
3 IESO Report: Energy Storage, March 2016: http://www.ieso.ca/Documents/Energy-Storage/IESO-Energy- Storage-Report_March-2016.pdf.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
20
McCarthy Tétrault LLP mccarthy.ca
We continue to be of the view that renewable energy integration, system reliability matters, and quickly improving technology and economics will make this a key growth area in Ontario in terms of technology development and market application. Commercial transactions, including financings, will accelerate in due course.
CAP AND TRADE – NOW UPON US On April 13, 2015, Ontario Premier Kathleen Wynne formally announced plans to create a cap-and- trade program for greenhouse gas emissions in Ontario, to be linked with the systems already in place in Québec and California. Ontario’s cap-and-trade program came into effect on January 1, 2017 and the Government projects that it will generate about $1.9 billion per year in proceeds, in large part, through Government-held auctions for emission allowances. The date for Ontario’s first auction has not yet been announced. The Government plans to reinvest the proceeds raised through cap-and-trade into projects that reduce greenhouse gas emissions. These include projects aimed at reducing household energy consumption, building more public transit and assisting factories and businesses in reducing their environmental footprint. The cap-and-trade program will function in an Ontario-only market for at least the first year, however the Government of Ontario has stated that its intention to link with California and Québec in 2018.
PREDICTIONS FOR 2017 Looking forward, we anticipate that 2017 will continue to see sustained mergers and acquisitions in Ontario with respect to generation projects. (For a more detailed discussion, please see “Mergers & Acquisitions on page 24.)
Additionally, as the 2018 Provincial election looms, those developers having obtained contracts in the Large Renewable Procurement I process will be looking to accelerate construction and financing to ensure that milestones are met in order to mitigate the likelihood of the termination for convenience clauses in such contracts being triggered. Developers with a long term view will be closely watching Darlington and future supply forecasts to judge whether the OPO’s predictions will hold or create opportunities through unanticipated supply deficits.
Finally, the IESO’s emphasis on market renewal should lead to a greater focus on using the IESO- administered market to purchase services such as demand response, regulation and even electricity capacity. The Government seems committed to using market renewal to reduce costs, so one can expect an activist IESO to continue to put pressure on generator costs and seek means, through market design changes or contracts, to further bend the cost curve.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
21
McCarthy Tétrault LLP mccarthy.ca
Québec
Daniel Bénay Matthieu Rheault Louis-Nicolas Boulanger Mathieu LeBlanc
Introduction
2016 was a transition year for the Québec energy sector. This does not, however, mean that it will be remembered as being any less important. Key initiatives were launched and mark the beginning of a new era in Québec’s energy policy.
The Government announced its intent to significantly amend its regulatory framework applicable to the exploration, development and production of hydrocarbons. This initiative should provide a modern structure for an industry which has been marked by uncertainty and political controversy over the past several years.
Additionally, the Québec Minister of Sustainable Development, Environment and the Fight against Climate Change introduced legislation to modernize the environmental authorization regime established under the Environment Quality Act. If adopted in their current form, the proposed legislative changes could have important repercussions on the environmental assessment procedure and on the authorization regime applicable to energy projects.
More important, 2016 was the year that the Québec Government unveiled its energy plans for the next 15 years. In its new energy policy for 2016-2030, Québec states its ambitious goal of becoming, by 2030, a North American leader in renewable energy and energy efficiency.
Many industry observers were quick to point out that this new energy strategy fell short of establishing a clear plan for the procurement of additional renewable energy in Québec. This should not, however, have come as a surprise considering the several reports highlighting energy surpluses in Québec as well as the growing opposition to wind energy projects, deemed to be an “expensive and uneconomical” source of electricity. This current situation in Québec is not so different from much of the rest of Canada where cancellation or indefinite delays of new renewable energy procurement RFPs have made the news.
This situation has forced Québec and other Canadian IPPs and stakeholders to rethink their overall investment strategy, including their business plans, in order to mitigate the reduced investment opportunities in their jurisdictions. One important trend, which has been increasing in popularity in 2016, is the growing interest to develop international renewable energy projects. Consequently, many IPPs are now actively pursuing green field and brown field opportunities in the U.S., Europe, South America and elsewhere in the world. As examples in 2016, Innergex acquired several wind power
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
22
McCarthy Tétrault LLP mccarthy.ca
projects in France and Hydro-Québec announced its strategic plan to aggressively pursue international transactions. It will be interesting to follow the development of this trend over the coming months.
Outlined below are highlights of the announced energy policy and of the new regulatory framework for hydrocarbons. Also, see the modernization of the Québec environmental authorization regime in the Environmental Law section of this publication.
QUÉBEC’S NEW 2030 ENERGY POLICY In April 2016, the Québec Government unveiled its energy policy for 2016-2030, entitled “Energy Policy 2030, The Energy of Québecers – a Source of Growth”. The policy is the result of two major public consultations that took place in 2013 and 2015. It follows the previous policy in effect from 2006 until 2015 and aims to set out a vision of energy development which would make Québec, by 2030, a North American leader in renewable energy and energy efficiency.
Unlike the previous policy, the 2030 Energy Policy fails short of announcing any concrete measures for the procurement of additional renewable energy. The new policy does, however, confirm the Government’s intentions with respect to various forms of renewable energy.
The Government confirms its renewed interest in wind energy, although it advises that the continued development of wind energy is desirable only to the extent that the impact on consumers is limited and that additional supply of energy is required in order to meet any fluctuations in Québec’s annual electricity needs. The exportation of electricity produced from existing wind farms will be considered.
Small hydroelectric projects will serve as sources of economic development for local and aboriginal communities. The Government will ensure that these projects meet the highest environmental and social acceptability standards, in addition to generating economic benefits for local and aboriginal communities.
The Government will continue to support the generation of bioenergy, including biomass cogeneration plants operated by enterprises in the pulp and paper industry.
Natural gas is recognized as a profitable source of transition energy for Québec and will play an important role in supporting the economic development of Québec, notably in Northern Québec, for the decades to come. To that end, the Government plans to expand the current natural gas network, develop a supply network for liquefied natural gas and increase production of renewable natural gas.
The 2030 energy policy also contemplates an overhaul of the current framework applicable to the development and production of hydrocarbons in Québec. See Québec’s New Hydrocarbons Regulatory Framework below for additional information on the proposed changes.
An Act to implement the 2030 Energy Policy and to amend various legislative provisions (Bill 106) was introduced at the National Assembly on June 7, 2016. Its review has been the subject of difficult debates especially as some stakeholders have suggested that the proposed changes to hydrocarbons and other energy matters should be subject to a distinct statutory regulatory framework. Bill 106 was finally passed on December 10, 2016.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
23
McCarthy Tétrault LLP mccarthy.ca
QUÉBEC’S NEW HYDROCARBONS REGULATORY FRAMEWORK Bill 106, discussed in Québec’s New 2030 Energy Policy above, also enacted the new Petroleum Resources Act (the “Act”) that will replace and reform, once in force on the date or dates to be set by the Government, the existing provisions under the hydrocarbon mining regulatory regime in Québec. The Act will significantly modify the regulatory framework applicable to the exploration, development and production of hydrocarbons in Québec. The Act is intended to regulate the development of petroleum resources, while ensuring the safety of persons and property, environmental protection, and optimal recovery of the resource. It also aims at ensuring that hydrocarbon mining work is performed in compliance with the greenhouse gas emission reduction targets set by the Québec Government.
The Act introduces an auction process for the award of hydrocarbon exploration rights, which constitutes a major shift from the current regulatory framework. For example, explorations licence holders will be required to inform the Minister of Energy and Natural Resources of any significant discovery and of any commercial discovery of hydrocarbons. The holder will also be required to submit a petroleum production project to the Régie de l’énergie (Québec energy regulator) and apply to the Minister for a production licence, within four years after any discovery, without which the Minister may revoke the exploration licence, without compensation.
Before undertaking the production or storage of petroleum, an exploration licence holder will be required to (i) submit for review its project to, and obtain a favourable decision from, the Régie de l’énergie; (ii) obtain an authorization under the Environment Quality Act after completion of the environmental impact assessment and review procedure; and (iii) obtain a production or storage licence from the Minister. Any significant change to a petroleum production project will be subject to prior review and approval of the Régie de l’énergie. The Act will confer a crucial new regulatory role to the Régie de l’énergie concerning petroleum production and storage projects in Québec.
The Act also provides additional permitting requirements applicable to various hydrocarbon-related activities, including geophysical or geochemical surveys, stratigraphic surveys, as well as drilling, completion, re-entry and major maintenance work in a well.
In addition, the Act will require that license holders recover petroleum in an “optimal” manner using generally recognized best practices for ensuring the safety of persons and property, environmental protection and optimal recovery of the resource.
Finally, the Act provides that license and junction pipeline authorization holders will be subject to a strict no-fault liability regime requiring operators to indemnify any person for damages caused through or in the course of their work or activities, up to a liability cap to be determined by regulation.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
24
McCarthy Tétrault LLP mccarthy.ca
TOPICAL ANALYSES Mergers and Acquisitions
Louis-Nicolas Sven Seán C. Christopher Boulanger Milelli O’Neill Zawadzki
Introduction
2016 witnessed two key developments in Canadian power sector M&A activity. First, we saw an increased focus on the acquisition of operating assets, reflecting a maturing domestic asset mix and reduced investment in development projects in the absence of significant procurement opportunities. Second, these same industry trends resulted in a growing number of Canadian developers pursuing opportunities abroad.
Nationally, power generation assets developed under Provincial procurement programs are fast approaching or have reached their operational stages. As such, a new wave of acquirors with an appetite for stable cash flows is overtaking the previous generation of greenfield acquirers and developers. Similarly, the potential for higher returns has encouraged Canadian companies to pursue investment opportunities abroad. Overall, the lack of opportunities for material greenfield investment in Canada (aside from Alberta and Saskatchewan) appears to be a significant motivating factor for both trends.
INCREASED FOCUS ON OPERATING ASSETS The shift in focus away from greenfield project investments towards the acquisition of developed operating assets appears to be motivated primarily by financial rather than strategic considerations, as yield-hungry investors have sought to acquire reliable operating assets that provide steady cash flows. This activity was bolstered by foreign acquirers who were, at least in part, attracted by favourable currency exchange rates against the Canadian dollar.
The shift in focus to operating assets also reflects the ongoing trend of declining opportunities for investments in a decent pipeline of greenfield projects. Apart from the tantalizing prospects of a decade of build-out on the prairies, opportunities in other Provinces are not appealing to many except for incumbent developers rounding out their existing portfolios. In Ontario, the Provincial Government’s decision to cancel the first phase of the second round of the Large Renewable Procurement program has diminished the prospects of any near-term developments in the renewable generation space and strangled the last grasp of optimism there. In Québec, Hydro-Québec’s decade-long generation asset building program has come to an end.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
25
McCarthy Tétrault LLP mccarthy.ca
The utility has publicly stated that it will likely wait up to five years before moving forward with any new hydroelectric projects within the Province. Similarly, Hydro-Québec has provided no indication that any renewable generation RFPs are coming, at least in the near future. In British Columbia, prospects are similarly weak for any significant competitive procurement opportunity in the coming decade amid reduced industrial load, continuing uncertainty regarding B.C.’s nascent LNG industry, and the continued development of BC Hydro’s 1,100 MW Site C hydroelectric project.
Meanwhile, in Ontario, the last of the projects under the feed-in-tariff (“FIT”) 1.0 and 2.0 programs have achieved or are on the cusp of achieving commercial operation. Under the terms of the FIT contracts, certain transfer and change of control restrictions have fallen away opening up these assets for acquisition opportunities without the additional cost and complexity of pre-COD compliant acquisition structures or the need for benediction from the Ontario Independent Electricity System Operator. At the same time, many of the original strategic acquirers see that, like the Toronto real estate market, it is always a seller’s market if you have a decent product and low interest rates. For potential acquirers, the development risks attached to these projects during the planning and construction phases have now been dramatically reduced or eliminated. Similarly, the increased availability of performance metrics and operational data have allowed potential acquirers to conduct more accurate asset assessments and valuations.
Canadian Renewable Energy M&A - Deal Value by Sector 2011-2016 (C$ billion)
Wind Energy $7.34
Solar Energy $3.38
Hydroelectric Power $2.54
Alternative Energy $0.03 Resources
Source: CapitalIQ
CANADIANS PURSUING M&A OPPORTUNITIES INTERNATIONALLY In 2016, we observed Canadian utilities, renewables developers and independent power producers seeking opportunities to extend and diversify internationally both in terms of growth and revenue sources. We witnessed a variety of international activity in the form of conventional mergers and acquisitions, joint ventures and the establishment of international offices. As noted above, this trend is reflective of the reduced scope for domestic investment opportunities in a maturing market with a flaccid project development pipeline. Worth monitoring is whether the impressive Canadian expansion into off-shore wind, including Northland Power starting to sell energy from its 600 MW North Sea Project, is a blip or a trend.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
26
McCarthy Tétrault LLP mccarthy.ca
Canadians are investing in more mature markets, including Europe and the U.S., and appear willing to pay relatively higher purchase prices for target companies and assets in more stable political and operating environments. At the same time, Canadians are pursuing higher returns in greenfield developments in less mature markets including Africa and Latin America. These regions have experienced rapid growth in power demand and policy initiatives targeting broader electrification. Mexico, which has recently opened its electricity sector to international investment, is projected to install 40 GW of new capacity in the next 10 years based on changes to load growth, updated market design and positive long-term auction expectations.
In general, Canadian companies have viewed opportunities abroad as presenting better prospects for higher returns. For example, Hydro-Québec recently formed Hydro-Québec International (“HQI”), a global acquisition arm that will invest abroad in power infrastructure assets in politically stable countries with growing economies. The creation of HQI forms a major part of Hydro-Québec’s strategy to double revenues and boost profits by 65% in the next 15 years.
It is worth noting that European-based companies were some of the first movers in the Canadian renewables market. These companies first developed their knowledge, expertise and capital base domestically, following which they began to look abroad for new opportunities as the European market for renewables matured. Conceivably, we may be witnessing a mirror sequence of events as homegrown Canadian companies now begin to look for more opportunities abroad.
Canadian Companies Pursuing International Opportunities
Canadian acquisitions abroad included:
• Enbridge Inc. acquired a 50% stake in • Innergex Renewable Energy Inc. (as a Eolien Maritime France SAS (EMS) (co- co-investor with Desjardins Group Pension owned by EDF Energies Nouvelles S.A.). Plan) acquired a total of nine wind power EMS is currently developing three offshore projects in France, consisting of seven wind farm projects in France with an projects from German company, wpd aggregate capacity of a total of 1,428 MW europe GmbH, with an installed capacity capacity. of 87 MW and two projects from French group, BayWa r.e., with an installed capacity of 24 MW.
• Algonquin Power & Utilities Corp. • Boralex Inc. acquired a portfolio of wind acquired the Missouri-based utility, power projects in France and in Scotland The Empire District Electric Company, with an aggregate capacity of nearly for $3.4B. 200 MW for C$103M.
PREDICTIONS FOR 2017 In 2017, we expect that domestic operating assets put up for sale will be subject to robust auctions as other developers and institutional investors continue to search for long-term yield-generating assets. We also expect that foreign acquisitions, particularly of development projects and pipelines, will intensify as Canadian-based companies develop experience and expertise operating in foreign jurisdictions and seek growth outside the highly-competitive domestic market.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
27
McCarthy Tétrault LLP mccarthy.ca
Domestically, the implementation and planning around new carbon pricing policies and its impact on the relative cost curves of conventional coal and gas-based generation as compared with renewable generation will be accompanied by a similar shift of investment away from conventional generation sources to alternative sources. In the short term, this transition will be most pronounced in Alberta, supported by the de-carbonization strategies being implemented by large utilities under that Province’s Climate Leadership Plan (discussed in greater detail in the Alberta Regional Overview section).
Finally, we predict a continuation of mid-cap consolidation in the local distribution company market in Ontario. This consolidation will continue to be motivated by smaller municipalities’ capital requirements and higher growth and profit potential for consolidators through synergies, economies of scale and other accretive factors.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
28
McCarthy Tétrault LLP mccarthy.ca
Aboriginal Law
Bryn Gray Selina Lee-Andersen Stephanie Axmann Daniel Goudge
Key Developments in 2016
In 2016, there were a number of key Aboriginal law developments with potential impacts on the energy sector. Highlights include the following:
BRITISH COLUMBIA
A Site C Project Litigation: As Site C Project litigation proceedings continue to work their way through the courts, construction continues on BC Hydro’s Site C Project, a third dam and hydroelectric generating station on the Peace River in northeast B.C.:
− B.C. Supreme Court dismisses legal challenge by West Moberly and Prophet River First Nations to overturn Site C permits: On October 31, 2016, the B.C. Supreme Court (the “BCSC”) dismissed the First Nations’ petition to seek judicial review of 29 permits issued by the Province for Site C. The Court held that the statutory decision makers correctly decided that the Province had met its obligation to consult in this case. In his decision, Justice Sewell urged the parties to renew their efforts to reach agreement on a custom consultation process for the project. Until a consultation agreement is concluded, the parties must act in accordance with their existing agreements and jurisprudence.
BCSC allows application by Rio Tinto Alcan to add the Federal and Provincial Crown as defendants to First Nations’ private nuisance action against Rio Tinto Alcan: In April 2015, the B.C. Court of Appeal (the “BCCA”) allowed the appeal (in part) of the Saik’uz First Nation and the Stellat’en First Nation of the Supreme Court of B.C.’s decision in Thomas v. Rio Tinto Alcan Inc., 2013 BCSC 2303, a private tort action by the First Nations against Rio Tinto Alcan for nuisance and breach of riparian rights due to the operation of the Kenney Dam on the Nechako River. On August 12, 2016, the BCSC granted the application of Rio Tinto Alcan to add the Federal and Provincial Crown as defendants in the First Nations’ action on the basis that the Province owns water that is subject of litigation (subject to whatever Aboriginal title or rights the plaintiffs may have), only the Crown has the knowledge and expertise necessary to meaningfully respond to the plaintiffs' claims respecting Aboriginal title, and private litigants may not be able to adequately represent the interests of the non-Aboriginal community where asserted Aboriginal title and rights are involved.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
29
McCarthy Tétrault LLP mccarthy.ca
SASKATCHEWAN
Challenge to Saskatchewan hydropower project dismissed in part in Peter Ballantyne Cree Nation v. Canada (Attorney General), 2016 SKCA 124: On September 28, 2016, the Saskatchewan Court of Appeal dismissed (in part) the appeal of a summary dismissal of a First Nation’s claim arising from the operation of hydro-electric facilities on the Reindeer River. The claim sought damages and declaratory relief for the continuous flooding of a portion of reserve land that the Peter Ballantyne Cree Nation (the “PBCN”) alleges was caused by the construction and operation of the Whitesand Dam, which began operating in 1943. The Court of Appeal agreed with the Chambers judge’s determination that the bulk of the PBCN’s claims are out of time, but concluded that their claim against Saskatchewan and SaskPower for continuing trespass on their reserve land should proceed to trial. The Court of Appeal also dismissed the PBCN’s claim for a breach of the duty to consult for every decision to change the amount of water passing through the Whitesand Dam, which the PBCN said constituted a novel adverse impact. The Court of Appeal disagreed, finding that the duty to consult was owed prior to the Dam’s original construction in 1943 (the breach of which is statute barred) and that there was presently no novel impact that triggered the duty to consult, noting that the same area of the reserve has been flooded since the creation of the Dam, and that the changes in the amount of water passing through the Dam are determined solely by the terms of its operating license.
ONTARIO
Challenge to Bow Lake wind project dismissed in Michipicoten First Nation v. Ontario (Minister of Natural Resources), 2016 ONSC 6899: On November 2, 2016, the Ontario Divisional Court dismissed an Ontario First Nation’s challenge to several Crown approvals for the Bow Lake Wind Farm Project (the “Project”), a 36 turbine facility on the eastern shore of Lake Superior. The application by the Michipicoten First Nation (the “MFN”) was dismissed for undue delay (it was brought 15 months after the REA approval) and the Court also dismissed the MFN’s allegation that it had not been adequately consulted prior to the approvals being issued. The Court concluded that the MFN had been properly consulted based on the substantial record of correspondence from the proponent and the numerous opportunities afforded to them to provide input. The Court also held that, despite these opportunities, the MFN did not provide meaningful feedback about the potential adverse effects of the Project on their Aboriginal or treaty rights and that it had to do more than simply express a blanket concern about the Project.
FEDERAL
Federal Jurisdiction over Métis and non-status Indians confirmed in Daniels v. Canada (Indian Affairs and Northern Development), 2016 SCC 12: On April 14, 2016, the Supreme Court of Canada restored a Federal Court decision declaring that Métis and non-status Indians are within the jurisdiction of the Federal Government under s. 91(24) of the Constitution Act, 1867. The Court determined that both its past decisions and the historical evidence established that s. 91(24) of the Constitution Act, 1867 was intended to cover all Aboriginal peoples, not just “Indians” as defined by the Indian Act. However, the Court stressed that its decision merely resolves the longstanding dispute between the Federal and Provincial Governments over which one of them is able to enact legislation concerning Métis and non-status Indians. Further, the Court emphasized that its decision does not require the Federal Government to pass any laws concerning Métis and non-status Indians, nor does it bar the Provinces from enacting laws of general application that impact Métis and non-status Indians.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
30
McCarthy Tétrault LLP mccarthy.ca
This decision has been the subject of some erroneous commentary and interpretation vis-à-vis the duty to consult. This decision did not deal with s. 35 Aboriginal rights and did not in any way impact the existing law on the duty to consult which arises when a Crown decision may adversely impact asserted or established Aboriginal rights. The decision also did not impact current law that this duty exists to protect the collective rights of Aboriginal peoples and is owed to the group that holds the Aboriginal rights at issue or is authorized by that rights-holding group to represent it for this specific purpose.
Federal Court of Appeal finds that Canada failed to fulfill duty to consult in approving Northern Gateway: On June 23, 2016, the Federal Court of Appeal (“FCA”) held that the Federal Government failed to fulfill the Crown’s duty to consult in the phase prior to issuance of an Order in Council for the Northern Gateway pipeline project, and remitted the matter to the Governor in Council for redetermination. Before making its decision, the Governor in Council must fulfill its duty to consult affected Aboriginal communities. The FCA approved of Canada’s framework for consultation, and cited many ways in which Canada acted reasonably, but noted errors such as insufficient timelines and lack of meaningful dialogue. The FCA did not take any issue with the consultation undertaken by the project proponent, rather the Court focused on the conduct of the Crown. The FCA acknowledged that the challenges associated with the approval process for Northern Gateway were immense and that the Crown should not be held to a standard of perfection in discharging its duty to consult. Nevertheless, it found that an important phase of the Aboriginal consultation process “fell well short of the mark”.
Federal Government to Implement UN Declaration on the Rights of Indigenous Peoples: In May 2016, the Federal Government announced at the United Nations that it was now a full supporter of the UN Declaration on the Rights of Indigenous Peoples (the “Declaration”), without qualification. Canada initially voted against the Declaration in 2007 (along with the US, Australia, and New Zealand) but then issued a statement of qualified support in 2010. Canada’s delay in adopting the Declaration was largely due to concerns with the provisions that stipulate that states must obtain the free, prior and informed consent (“FPIC”) of Aboriginal groups in a number of situations. There is a concern that these provisions could be interpreted as providing an Aboriginal veto right against Government actions or decision-making affecting an Aboriginal groups’ traditional territories, including resource development projects. It remains unclear as to how the Declaration will actually be implemented by the Federal Government. However, Canada has indicated that it will not be adopting the Declaration word-for- word into Canadian law and it will be consulting to determine how the Declaration can be interpreted and implemented within our existing constitutional framework. The Federal Government’s commitment to implement the Declaration “in accordance with the Canadian Constitution” suggests that it will not interpret FPIC as a veto as this would be inconsistent to our constitutional framework. While it remains to be seen how the Federal Government will implement FPIC, it is likely that consent will be seen as the objective of consultation. This would not materially change existing Canadian law on the duty to consult but in practice could lead to increasing scrutiny by the Federal Government about accommodation and the efforts taken by proponents to achieve consent. It should be noted that Canada’s decision to implement the Declaration only applies to federal decision-making and the Declaration will need to be implemented by the Provinces in order to affect Provincial decision-making.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
31
McCarthy Tétrault LLP mccarthy.ca
The Year Ahead
3 Cases to Watch at the Supreme Court of Canada: In 2017, the Supreme Court of Canada (“SCC”) is expected to release decisions in three duty to consult cases that could have implications for Aboriginal consultation relating to power projects. The appeals were heard on November 30 and December 1, 2016:
− The first two cases will require the SCC to consider the role of regulatory tribunals vis-à-vis the duty to consult and the extent to which the Crown can rely on consultation undertaken through regulatory processes to fulfill the duty to consult. These two cases relate to approvals by the NEB for the reversal of an existing oil pipeline in Ontario (Chippewas of the Thames First Nation v. Enbridge Pipelines Inc) and a seismic testing program in Nunavut (Hamlet of Clyde River v. TGS-NOPEC Geophysical Company ASA). In both cases, all Aboriginal consultation was conducted by the respective proponents and through the NEB process and the federal Crown did not engage in separate consultations. To date, the courts have upheld the Crown’s ability to rely on regulatory processes to fulfill the duty to consult. However, the degree of permissible reliance depends on the facts of the case and the SCC may develop further principles to assist the Crown and lower courts in making such decisions. The SCC’s determination of these cases will also likely clarify the role of regulatory tribunals vis-à-vis the Crown’s duty to consult and the circumstances in which they are required to engage in consultation and determine the adequacy of consultation.
− The third case will require the SCC to consider the intersection between s. 2(a) of the Charter and the duty to consult relating to s. 35 rights as well as the extent of accommodation that may be required where there are potential impacts on an Aboriginal group’s spiritual beliefs. This case relates to the B.C. Government’s approval of a Master Development Agreement for a proposed ski resort in the Jumbo Valley (Ktunaxa Nation v. British Columbia). The Ktunaxa Nation Council has alleged a breach of the duty to consult and a breach of their freedom of religion to exercise a spiritual practice under s. 2(a) of the Charter, both of which have been dismissed by the B.C. Supreme Court and the B.C. Court of Appeal. The Ktunaxa claim that the proposed resort would be located in a sacred area of spiritual significance as the home of the Grizzly Bear Spirit and that the proposed development would desecrate the site and cause the Grizzly Bear Spirit to leave. This will be the first time that the SCC is called upon to consider an Aboriginal spiritual rights case. This case could have significant impacts on future development projects in Canada given that there are large tracts of land throughout the country that are subject to asserted Aboriginal spiritual rights.
− Panel recommendations expected following review of federal environmental and regulatory processes: In 2016, the Federal Government commenced a review of federal environmental assessment processes, the National Energy Board, as well as the Fisheries Act and the Navigation Protection Act. The reviews of Canada’s environmental assessment processes and the National Energy Board are being undertaken by independent panels and have fairly broad terms of reference with respect to environmental and Aboriginal issues. Final panel reports are expected in early 2017. It is anticipated that there will be further public consultation on the reports as well as any legislative changes that result. The reviews of the Fisheries Act and the Navigation Protection Act are being undertaken by Parliamentary
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
32
McCarthy Tétrault LLP mccarthy.ca
Committees and are more limited in scope. They are looking at changes the previous Harper Government made to the fish habitat provisions in the Fisheries Act and the significant reduction of waterways subject to federal navigation oversight. These changes were significantly criticized by Aboriginal groups at the time as they were perceived to reduce the protection of fish habitat, which is subject to debate, as well as reducing federal oversight of navigable waters. It is anticipated that the Standing Committees will release reports on these reviews in early 2017.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
33
McCarthy Tétrault LLP mccarthy.ca
Environmental Law
Dominique Kimberly Selina Joanna Monika Amyot-Bilodeau Howard Lee-Andersen Rosengarten Sawicka
Introduction
In 2016, there were a number of key environmental law developments across Canada with potential impacts on the energy sector. Highlights include the following:
BRITISH COLUMBIA
Greenhouse Gas Industrial Reporting and Control Act is now in force: British Columbia’s Greenhouse Gas Industrial Reporting and Control Act (“GGIRCA”), which was passed by the British Columbia Legislature in November 2014, came into force on January 1, 2016. The GGIRCA enables performance standards to be established for industrial facilities or sectors. It currently sets a GHG emissions benchmark for LNG facilities, along with an emissions benchmark for coal-based electricity generation operations. The GGIRCA establishes a GHG emissions intensity benchmark of 0.16 carbon
dioxide equivalent (“CO2e”) tonnes per tonne of LNG produced, which will cover all facility GHG emissions (including combustion, electricity generation, venting and fugitives) from the point when gas enters a facility to where it is loaded on to a ship or rail car to go to market. Three new regulations also came into effect on January 1, 2016: (1) Greenhouse Gas Emission Reporting Regulation, which adds compliance reporting requirements; (2) Greenhouse Gas Emission Control Regulation, which establishes the British Columbia Carbon Registry to track compliance unit transactions and sets criteria for developing emission offsets issued by the Government; and (3) Greenhouse Gas Emission Administrative Penalties and Appeals Regulation, which establishes the process for the levying of administrative penalties for non-compliance with the GGIRCA or regulations.
Water Sustainability Act is now in force: The Water Sustainability Act (“WSA”), which was passed by the Legislature in April 2014, came into effect on February 29, 2016. The WSA replaces many parts of the old Water Act and creates a new regulatory regime for water management within British Columbia. One of the biggest changes that the WSA makes is to the regulation of groundwater. Under the WSA, all groundwater users (except domestic wells) will require a water licence to divert water from an aquifer (unless the diversion is otherwise authorized under the regulations).
The Province is taking a phased approach to the enactment of the WSA. While the majority of the WSA came into effect at the end of February, section 18, which provides for quick licensing procedures, has yet to be brought into force. This next phase will include regulations relating to measuring and reporting, livestock watering, water objectives, planning and governance. Along with the WSA, the following regulatory scheme also came into effect on February 29, 2016:
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
34
McCarthy Tétrault LLP mccarthy.ca
− Water Regulation under the Water Act was repealed and the Water Sustainability Regulation was enacted under the WSA;
− Ground Water Protection Regulation under the Water Act was repealed and a new Groundwater Protection Regulation was enacted under the WSA;
− British Columbia Dam Safety Regulation under the Water Act was repealed and a new Dam Safety Regulation was enacted under the WSA;
− Water District Regulation was enacted under the WSA;
− Water Sustainability Fees, Rentals and Charges Tariff Regulation was enacted under the WSA;
− Sensitive Streams Designation and Licencing Regulation under the Fish Protection Act was repealed; and
− Violation Ticket Administration and Fines Regulation under the Offence Act was amended to add offences and fines under the WSA.
New Spill Response Regime: On February 29, 2016, the Provincial Government introduced a bill to amend sections of the British Columbia Environmental Management Act to introduce new requirements for spill preparedness, response and recovery and to institute a certified preparedness and response organization. The bill received royal assent on May 19, 2016, but has yet to come into force. Notably, the amendments will establish new requirements for spill preparedness, response and recovery and create new offences and penalties.
Updated Climate Change Action Plan released: The BC Government released its long awaited Climate Leadership Plan (the “Plan”) on August 19, 2016. The Plan, which updates the Province’s 2008 Climate Action Plan, contains 21 new actions to reduce emissions across the following sectors: (i) natural gas; (ii) transportation; (iii) forestry and agriculture; (iv) communities and built environment; and (v) public sector. The Plan follows the release of the Climate Leadership Team’s (“CLT”) report in November 2015, which made 32 recommendations including, among others, the establishment of a mid-term 2030 GHG emissions reduction target and a reduction in the Provincial sales tax from 7% to 6%, which would be offset by an increase in the carbon tax by $10 per year commencing in July 2018. While the Plan reflects some recommendations made by the CLT and feedback received through public consultation and stakeholder engagement sessions, the Plan bypasses BC’s 2020 target of achieving a reduction in GHG emissions of 33% below 2007 levels and instead charts a path for BC to reach its 2050 target of 80% below 2007 levels.
ALBERTA
Implementation of Climate Leadership Plan: Near the end of 2015, Alberta released its Climate Leadership Plan (“Climate Plan”) which, among other things, promised an economy-wide carbon price, a legislated cap on oil sands emissions and set goals for the phase-out of coal-fired generation by 2030. For the power sector, the objective is to replace two-thirds of the existing coal electricity with renewable energy and one-third with natural gas. The 2030 goal is for renewable sources to account for 30% of Alberta’s total operating generation capacity.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
35
McCarthy Tétrault LLP mccarthy.ca
Economy-wide carbon price: Changes to the Specified Gas Emitters Regulation (“SGER”) in 2015 increased the cost of emissions for large industrial emitters, which emit 100,000 tonnes or more of greenhouse gases. Such facilities are subject to the following costs of compliance under SGER:
Site-specific emissions intensity Payments for each tonne over reduction targets: a facility’s reduction targets: 12% in 2015 $15 in 2015 15% in 2016 $20 in 2016 20% in 2017 $30 in 2017
Alberta has also introduced a Carbon Competitiveness Regulation basing emissions intensity credits on a comparison with the most efficient natural gas generator.
Province-wide carbon levy: In May 2016, the Government of Alberta tabled the Climate Leadership Implementation Act enabling it to impose a Province-wide carbon levy. The carbon levy will be included in the price of all fuels that emit GHG when combusted. These include transportation and heating fuels such as diesel, gasoline, natural gas and propane. It will not apply directly to consumer purchases of electricity. As of January 1, 2017, a $20/tonne carbon levy will be applied to fuels. This levy will increase to $30/tonne in 2018. Revenues from the carbon levy will be used for initiatives to reduce GHG emissions and to fund carbon rebates, as well as for investments in clean technology, green infrastructure and to help finance the AESO’s REP. The carbon tax will also be used for an “adjustment fund” to help individuals and families, small business and First Nations adjust as the new policy is implemented.
Legislated cap on oil sands emissions: On November 1, 2016, Bill 25: Oil Sands Emissions Limit Act (“Bill 25”), was introduced and is intended to cap emissions from oil sands production at 100Mt. The oil sands sector accounts for approximately one-quarter of Alberta’s annual emissions and these facilities are currently charged a levy based on each facility’s historical emissions under the SGER. The legislation also contemplates certain exceptions in respect of cogeneration emissions, upgrading emissions, and potential discretionary exemptions by regulation (likely to accommodate new technological developments). Bill 25 came into force on December 14, 2016.
Methane emissions reduction plan: Alberta intends to cut methane emissions by 45% from 2014 levels by 2025. The Province’s largest source of methane emissions is from the oil and gas industry (venting, fugitive emissions from natural gas driven pneumatics and leaks and from flaring). The former Climate Change and Emissions Management Corporation, now Emissions Reduction Alberta, has earmarked a total of $40 million to help advance technologies to reduce methane emissions in Alberta, providing successful applicants with up to a maximum of $5 million.
Oil and Gas Abandonment, Reclamation and Remediation Costs: A notable development in this area is the recent Alberta Court of Queen’s Bench decision in Re Redwater Energy Corporation, 2016 ABQB 278 (“Redwater”), which has caused significant upset in the Alberta oil and gas sector and could impact the Alberta Energy Regulator’s (“AER”) enforcement practices going forward. In Redwater, the court held that sections of Alberta’s Oil and Gas Conservation Act and Pipeline Act were inoperative to the extent that they conflicted with section 14.06 of the federal Bankruptcy and
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
36
McCarthy Tétrault LLP mccarthy.ca
Insolvency Act, which allows a receiver or trustee to disclaim certain assets of an energy company in bankruptcy proceedings. This decision prompted the AER to announce interim measures. As a condition of transfer of existing licences, approvals, and permits, the AER will require all transferees to demonstrate they will have a LLR of 2.0 or higher immediately following the transfer to increase (albeit temporarily) its required Liability Management Rating (assets over deemed liabilities) to 2.0 for the purpose of transferring licences. Although the Redwater decision is being appealed by the AER and Alberta’s Orphan Well Association, and a number of industry participants have sought and obtained permission to intervene in the appeal, the decision could weaken Provincial oil and gas regulators’ ability to recover the costs of remediation and reclamation from insolvent energy companies. As at the date of this publication, the Court of Appeal’s decision in Redwater has not yet been released.
ONTARIO Evolution of climate change regime: Ontario’s climate change policy evolved significantly in 2016 with the release of legislation that brought into force an Ontario cap-and-trade program on January 1, 2017. In the spring of 2016, the Ontario Government finalized the Climate Change Mitigation and Low- Carbon Economy Act, 2016, as well as The Cap and Trade Regulation (O. Reg. 144/16) under the Act. Together, the Act and regulation set out the details of Ontario’s cap-and-trade program, which is the key policy initiative aimed at meeting Ontario’s climate change goals. The Government of Ontario also released a Climate Change Action Plan in June 2016 which outlines the initiatives that will be funded by the proceeds from cap and trade. These initiatives include retrofitting buildings, technology to help industry reduce emissions, accelerating public transport and rail expansion, increasing bicycle transportation, fuel switching to low-carbon fuel, low carbon fuel standards, research and development and electric vehicle incentives.
Introduction of Waste Free Ontario Act: In the summer of 2016, Ontario passed the Waste-Free Ontario Act, framework legislation aimed at diverting more waste from landfills and fighting climate change. The Act will require producers to take full responsibility for recycling their products and packaging and will create a new body, the Resource Productivity and Recovery Authority, to replace Waste Diversion Ontario. The Government has stated that the new authority will have enhanced compliance and enforcement powers to oversee the new waste diversion programs in Ontario. Ontario has also stated its intension to have a zero waste policy in the future, and this new legislation will be part of that strategy. The details of the new Waste-Free Ontario Act will be set out in regulations, which are likely to be released in 2017.
QUÉBEC
Modernization of Environment Quality Act: On June 7, 2016, the Québec Government introduced Bill 102, which is aimed at modernizing the environmental authorization scheme established by the Québec Environment Quality Act. If adopted in its current form, this bill could have important repercussions on the environmental assessment procedure and on the authorization process of energy projects carried out in the Province. Among other things, the bill includes various measures to streamline the environmental authorization process, including the environmental impact assessment and review process (the EIA process) for major energy projects. Bill 102 would also allow the Government to subject any project to the EIA process if it: (i) may raise major environmental issues and public concern warrants it, (ii) involves a new technology or new type of activity in Québec whose apprehended impacts on the environment are major; or (iii) involves major climate change issues. Furthermore, it would facilitate public access to various environmental and permitting documents.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
37
McCarthy Tétrault LLP mccarthy.ca
Bill 102 was subject to consultations in parliamentary committee in November and December 2016 and its adoption is currently anticipated to occur before summer 2017.
FEDERAL
Federal Government launches review of environmental and regulatory processes: On June 20, 2016, the Federal Government launched a comprehensive review of four key environmental and regulatory processes, namely:
− federal environmental assessment processes under the Canadian Environmental Assessment Act, 2012 (“CEAA 2012”);
− National Energy Board (“NEB”);
− Fisheries Act; and
− Navigation Protection Act.
The reviews of CEAA 2012 and NEB commenced immediately, while those concerning the Fisheries Act and the Navigation Protection Act began in October 2016. The Federal Government’s stated goal for reviewing CEAA 2012 is to develop new, fair processes that are robust, incorporate scientific evidence, protect our environment, respect the rights of Indigenous peoples, and support economic growth. The review will include environmental assessment processes conducted by the Canadian Environmental Assessment Agency, the Canadian Nuclear Safety Commission, and the NEB. The NEB review is aimed at modernizing the NEB and ensuring that its composition reflects regional views and has sufficient expertise in such fields as environmental science, community development, and Indigenous traditional knowledge. The stated objective of the Fisheries Act and the Navigation Protection Act reviews is to “restore any lost protections and to incorporate modern safeguards”.
Ratification of Paris Agreement and introduction of pan-Canadian carbon pricing plan: The Federal Government ratified the Paris Climate Change Agreement (which came into force on November 4, 2016) and introduced a pan-Canadian carbon price in early October 2016. Under the pan-Canadian carbon pricing strategy, the Federal Government has set a minimum price on carbon
starting at $10/tonne of CO2e in 2018, which will increase by $10 per year until it reaches $50/tonne of
CO2e by 2022. This means that each Province and territory will be required to implement carbon pricing in its jurisdiction within two years, whether in the form of a carbon tax or a cap-and-trade system. If the carbon price in a jurisdiction does not meet the federal minimum price, the Federal Government will step in and impose a carbon price that makes up the difference and return the revenue to the Province or territory. In addition, Provincial and territorial goals for reducing emissions must be at least as stringent as federal targets. Canada has pledged to reduce its GHG emissions by 30% from 2005 levels (approximately 523 Mt) by 2030.
Announcement of Canada’s Mid-Century Long-Term Low-Greenhouse Gas Development Strategy: At the United Nations climate change conference (COP 22) that was held from November 7 – 18, 2016 in Marrakech, Morocco, the Federal Government released Canada's Mid-Century Long- Term Low-Greenhouse Gas Development Strategy (the “Long-Term GHG Strategy”), making Canada one of the first countries to do so. Under the Long-Term GHG Strategy, Canada considers an emissions abatement pathway consistent with net emissions falling by 80% in 2050 from 2005 levels.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
38
McCarthy Tétrault LLP mccarthy.ca
This is consistent with the Paris Agreement’s goal to hold the increase in the global average temperature to well below 2°C above pre-industrial levels, while pursuing efforts to limit the temperature increase to 1.5°C above pre-industrial levels. Canada’s Long-Term GHG Strategy makes it clear that it is not a blueprint for action. Rather, the strategy is meant to inform the conversation about how Canada can achieve a low-carbon economy.
The Year Ahead
BRITISH COLUMBIA Second Phase of Water Sustainability Act: The Province has yet to establish and implement the second phase of the WSA, which includes water objectives, water sustainability plans, measuring and reporting requirements, livestock watering, designating areas, dedicated agricultural water, and alternative governance approaches. For the purposes of sustaining water quantity, water quality and aquatic ecosystems, water objectives may be set by regulation in relation to watersheds, streams or aquifers. These objectives will likely form the basis for decision makers in the determination of water allocation and water licence conditions.
Final Investment Decisions anticipated for some LNG projects: Following the announcement in November 2016 that the Woodfibre LNG project will proceed, further final investment decisions are anticipated in 2017 in connection with other LNG projects. However it is unlikely that any other LNG proponents will announce final investment decisions before the Provincial election in May 2017. According to the Province, as of November 2016, there are 20 proposed LNG projects at various stages of development. A number of more advanced projects have already received environmental assessment approvals, while others are currently undergoing environmental and other regulatory reviews. To date, four LNG project proponents have received their Provincial environmental assessment approvals: Kitimat LNG (in June 2006), Pacific Northwest LNG (in November 2014), LNG Canada (in June 2015) and Woodfibre LNG (October 2015). Kitimat LNG, LNG Canada, Woodfibre LNG and Pacific Northwest LNG have also received federal environmental assessment approvals.
ALBERTA
Implementation of Climate Leadership Plan anticipated in 2017: As noted above, the Alberta Government is in the process of implementing the various components of its Climate Leadership Plan and a number of policies, including the carbon levy, will come into force in 2017. Large industrial emitters will continue to be subject to the SGER framework until the end of 2017, when the Province will transition to product and sector-based performance standards. Further details will be available after industry consultations. Alberta has also recently started a process of engagement with First Nations and Métis organizations on the joint development of Indigenous Climate Leadership initiatives.
ONTARIO Kick-off of cap-and-trade program in 2017: The Ontario cap-and-trade program came into effect on January 1, 2017 and the first compliance period will be four years long (ending on December 31, 2021), with three year compliance periods thereafter. It will initially be an Ontario-only system,
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
39
McCarthy Tétrault LLP mccarthy.ca
however, the Ontario Government has stated its intention to link with the California and Québec cap- and-trade systems, perhaps as early as 2018. Some details of the cap-and-trade program (for example, those relating to offset credits and early reduction credits) are yet to be finalized. Amending regulations are expected following the requisite public consultation periods.
QUÉBEC
Adoption of Bill 102: As noted above, the Québec Government introduced Bill 102 at the Québec National Assembly in June 2016. Bill 102 is currently subject to consultations by the parliamentary committee and its adoption is anticipated to occur before summer 2017.
FEDERAL
Panel recommendation reports expected following review of environmental and regulatory processes: As discussed above, the Federal Government has commenced its review of environmental and regulatory processes, which is focused on reviewing federal environmental assessment processes, modernizing the NEB, and restoring lost protections and introducing modern safeguards to the Fisheries Act and the Navigation Protection Act. The environmental assessment review is well underway and public consultations will be completed by mid-December 2016 with a final report to be submitted by the review panel to the federal Minister of the Environment and Climate Change in early 2017. The panel for the NEB modernization review was constituted in November 2016 and it is expected to complete its public consultation and submit its report to the federal Minister of Natural Resources by March 31, 2017. Recommendations on the Fisheries Act and Navigation Protection Act are also expected in early 2017. It is anticipated that there will be further public consultation on the reports as well as any legislative changes that result. The outcome of these four reviews could have significant implications for large power projects as they could expand the type of projects that require federal environmental assessments and are likely to result in additional requirements for proponents that must obtain federal environmental assessment approval. In addition, these reviews could also increase the number of waterways subject to the Navigation Protection Act and associated federal permitting requirements as well as expand federal permitting requirements for projects that may affect fish habitat.
Further details of federal climate change plan expected: The Federal Government will continue to develop a national climate change strategy. As discussed above, the Federal Government has
announced a pan-Canadian carbon pricing plan with a minimum price of $10/tonne of CO2e starting in
2018, which will increase by $10 per year until it reaches $50/tonne of CO2e by 2022. Each Province and territory will be required to implement carbon pricing in its jurisdiction within two years, whether in the form of a carbon tax or a cap-and-trade system. Currently, Canada’s four biggest Provinces representing more than 80% of Canada’s population (Ontario, Québec, Alberta and British Columbia) either have carbon pricing in place or will introduce it in 2017. This approach will be reviewed in 2022 to confirm the path forward, including continued increases in stringency. The Federal Government is also expected to develop regulations on other emission reduction initiatives such as energy efficiency and investments in clean energy and green infrastructure.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
40
McCarthy Tétrault LLP mccarthy.ca
The Art of Carbon Pricing in an Emissions Constrained World
Selina Lee-Andersen
Introduction
The Paris Climate Change Agreement came into force on November 4, 2016 and as global efforts get underway to implement the agreement, the Canadian Federal Government continues to craft its strategy to shift Canada to a low-emissions economy. At the recent United Nations climate change conference (COP 22) in Marrakech, Morocco that was held from November 7 – 18, 2016, the Minister of Environment and Climate Change announced Canada's Mid-Century Long-Term Low-Greenhouse Gas Development Strategy at COP 22, making Canada one of the first countries to do so.
Fall 2016 was an eventful one for Canadian climate change policy as the Federal Government introduced a pan-Canadian carbon price and ratified the Paris Agreement in early October. Under the pan-Canadian carbon pricing strategy, the Federal Government has set a minimum price on carbon
starting at $10 per tonne of carbon dioxide equivalent (CO2e) in 2018, which will increase by $10 per
year until it reaches $50 per tonne of CO2e by 2022. This means that each Province and territory will be required to implement carbon pricing in its jurisdiction within two years, whether in the form of a carbon tax or a cap-and-trade system. If the carbon price in a jurisdiction does not meet the federal minimum price, the Federal Government will step in and impose a carbon price that makes up the difference and return the revenue to the Province or territory. In addition, Provincial and territorial goals for reducing emissions must be at least as stringent as federal targets. Canada has pledged to reduce its greenhouse gas (GHG) emissions by 30% from 2005 levels (approximately 523 Mt) by 2030. Currently, Canada’s four biggest Provinces representing more than 80% of Canada’s population (Ontario, Québec, Alberta and British Columbia) either have carbon pricing in place or will introduce it in 2017. This approach will be reviewed in 2022 to confirm the path forward, including continued increases in stringency.
The introduction of a pan-Canadian carbon price follows a global trend where carbon pricing is being increasingly seen as the key mechanism by which meaningful GHG emission reductions can be achieved.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
41
McCarthy Tétrault LLP mccarthy.ca
OVERVIEW OF CARBON PRICING MECHANISMS A price on carbon looks to capture what are referred to as the external costs of carbon emissions, i.e. costs that the public pays for indirectly, such as damage to property as a result of flooding. By placing a monetary value on carbon, the rationale is that governments, businesses and individuals will have an incentive to change their behaviour to less carbon intensive alternatives. Market instruments are perceived as providing more cost efficient and flexible compliance mechanisms to drive emission reductions, so governments are now looking to the market for solutions. There are two main types of carbon pricing mechanisms available to policymakers:
• An Emissions Trading System (ETS) is a market-based approach designed to provide economic incentives for reducing emissions. While emissions trading systems tend to be complex, the economic concept behind it is straightforward – since climate change is a shared global burden and the environmental impacts of reducing emissions is the same wherever the reductions take place, it makes economic sense to reduce emissions where the cost is lowest. Under an ETS, an annual limit or cap is set on the amount of GHG emissions that can be emitted by certain industries. Regulated entities are then required to hold a number of emissions allowances equivalent to their emissions. Regulated entities that reduce their GHG emissions below their target will require fewer allowances and can sell any surplus allowances to generate revenue. Regulated entities that are unable to reduce their emissions can purchase allowances to comply with their target. By creating demand and supply for emissions allowances, an ETS establishes a market price for GHG emissions. In order to achieve absolute reductions in GHG emissions, the limit or cap is gradually lowered over time.
• A carbon tax puts a price on each tonne of GHG emissions generated from the combustion of fossil fuels. The idea is that over time, the carbon price will elicit a market response from all sectors of the economy, thus resulting in reduced emissions. The design and implementation of carbon taxes varies widely and will depend on the jurisdiction’s energy mix, composition of its economy, existing tax burdens, existence of complementary environmental policies, and political considerations. In terms of scope, some jurisdictions have focused on a narrow category of energy users and large emitters, while others such as British Columbia (BC) have adopted a broader scope where the carbon tax covers GHG emissions from the combustion of all fossil fuels.
The key differences between the mechanisms are that with an ETS, the quantity of emission reductions is known, but the price is uncertain. With a carbon tax, the price is known, however the quantity of emissions reductions is uncertain. Both carbon pricing mechanisms can generate revenue that can be used to lower other taxes or invest in “green” initiatives. Both mechanisms also have related monitoring, reporting, verification and compliance obligations, and both need special provisions to minimize the effects on certain energy intensive, trade exposed industries.
CARBON PRICING AROUND THE WORLD In its State and Trends of Carbon Pricing 2016 Report, the World Bank and Ecofys estimate that approximately 40 countries and more than 20 cities, states and provinces currently use carbon pricing mechanisms or are planning to implement them. Carbon pricing initiatives cover about half of the emissions in these jurisdictions, which translates into approximately 13% of global GHG emissions.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
42
McCarthy Tétrault LLP mccarthy.ca
Recent developments have signaled a general move towards cap-and-trade as the preferred market tool for addressing climate change. In North America, both Québec and California launched cap-and- trade systems in January 2013 and linked their programs one year later, creating North America’s largest carbon market. Ontario’s cap-and-trade program came online in 2017, and is expected to link to Québec and California in 2018. BC and Alberta have chosen the carbon tax as their policy tool for reducing GHG emissions – BC has implemented a broad based, revenue neutral carbon tax of CAD
$30 per tonne of CO2e, while Alberta’s $20 per tonne carbon levy came into effect on January 1, 2017 (and will increase to $30 per tonne in 2018).
At the international level, the European Union ETS was established in 2005 and has the distinction of being the world’s first and largest emissions trading system. Together with Québec and California’s system, and the launch of a cap-and-trade system in South Korea in 2015, the World Bank estimates that the total value of global emissions trading systems and carbon taxes in 2016 is approximately US $50 billion. If a national ETS is implemented in China (China’s regional cap-and-trade markets are currently in their pilot phase), unofficial estimates suggest that the total value of ETS and carbon taxes could potentially double to about US$100 billion.
INDUSTRY LEADS THE WAY In recent years, companies have been working hard to reduce their carbon footprints by setting emission reduction targets and taking action to address climate change impacts in both their own operations and their supply chain. Given the range of climate policies across jurisdictions, companies are often faced with having to consider multiple carbon compliance costs in their business decisions. As a result, there have been increasing calls from the private sector on governments to establish clear pricing and regulatory certainty to support climate-related investments and climate risk assessment efforts. In the meantime, companies have been assessing risk and developing business plans based on a real or internal carbon price that is incorporated into their planning and investment decisions. On April 22, 2016, the United Nations Global Compact (UNGC) called for a minimum internal carbon price
level of US$100 per tonne of CO2e by 2020, which UNGC believes is the minimum price needed to shift market signals in line with the 1.5 – 2°C pathway set out in the Paris Agreement.
As countries, businesses and individuals look for innovative approaches to reduce their carbon footprint, pricing carbon will become an increasingly prominent policy and business planning tool for governments and industry alike.
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
43
McCarthy Tétrault LLP mccarthy.ca
ABOUT McCARTHY TÉTRAULT’S NATIONAL POWER GROUP
Our Power Group has more than 30 lawyers, including many of the most experienced energy lawyers in Canada. Our principal areas of practice include project development, and project finance, mergers and acquisitions, utility restructuring, privatizations and procurement. We also have extensive expertise in advising and representing clients in the area of energy regulation.
Drawing on our wide breadth of expertise and experience in the power and energy sectors, we provide practical and timely advice to our clients, and prefer to take a hands-on approach to resolving issues. We understand the complexities associated with developing, structuring, financing, approving and operating a variety of different types of power projects.
Our retainers on North American electricity matters include acting for several of Canada’s major public and private electric generators, transmission and distribution utilities, major equity investors and developers of power projects, lenders to power projects and fuel and equipment suppliers to the power industry. We have acted on behalf of developers, lenders or investors in relation to: − more than 80% of the hydro and wind projects developed in B.C. in response to BC Hydro’s most recent competitive power call; − more than 75% of Ontario wind power projects with over 20 MW nameplate capacity under the Province’s Feed-In Tariff program; and − more than 80% of the wind projects developed in Québec since Hydro-Québec’s first major 1,000 MW RFP in 2003.
We have assisted clients with all aspects of power project development and financing, including energy regulation, grid inter-connection, real estate assembly and site-use planning, power purchase arrangements, construction and long-term financing, permitting and environmental, insurance, construction contracts, turbine supply contracts, tax structuring, joint venture and warranty arrangements.
We are consistently recognized as Canada’s leading firm for Power expertise:
− Band 1, the highest honour, in Energy: Power (Chambers Global) − Tier 1 in Energy: Power (Legal 500)
− Top tier ranking for Energy: Electricity expertise (Ontario) (Canadian Legal Lexpert Directory)
− Awarded Energy & Natural Resources Client Choice Award for Canada (International Law Office)
− Recognized as Canadian Mining and Energy Law Firm of the Year (Acquisition International magazine)
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
44
McCarthy Tétrault LLP mccarthy.ca
For more information please contact:
BRITISH COLUMBIA ALBERTA
Sven O. Milelli Robin Sirett Kimberly J. Howard Gordon Nettleton 604-643-7125 604-643-7911 403-260-3575 403-260-3622 [email protected] [email protected] [email protected] [email protected]
ONTARIO QUÉBEC
David A.N Lever Seán C. O’Neill Louis-Nicolas Boulanger Marc Dorion, Q.C., Ad. E. 416-601-7655 416-601-7699 514-397-5679 514-397-5676 [email protected] [email protected] [email protected] 418-521-3007 [email protected]
Canadian Power Key Developments in 2016 – Trends to Watch for in 2017
VANCOUVER Suite 2400, 745 Thurlow Street Vancouver BC V6E 0C5 Tel: 604-643-7100 Fax: 604-643-7900 CALGARY Suite 4000, 421 7th Avenue SW Calgary AB T2P 4K9 Tel: 403-260-3500 Fax: 403-260-3501 TORONTO Suite 5300, TD Bank Tower Box 48, 66 Wellington Street West Toronto ON M5K 1E6 Tel: 416-362-1812 Fax: 416-868-0673 MONTRÉAL Suite 2500 1000 De La Gauchetière Street West Montréal QC H3B 0A2 Tel: 514-397-4100 Fax: 514-875-6246 QUÉBEC CITY 500, Grande Allée Est, 9e étage Québec QC G1R 2J7 Tel: 418-521-3000 Fax: 418-521-3099 LONDON, UK 125 Old Broad Street, 26th Floor London EC2N 1AR UNITED KINGDOM Tel: +44 (0)20 7786 5700 Fax: +44 (0)20 7786 5702