CITATION: N-R Power and Energy Corporation v. Ontario Electricity Financial Corporation, 2015 ONSC 1641

COURT FILE NO.: Court File No. CV-12-9953-00CL

COURT FILE NO.: CV-12-9954-00CL

COURT FILE NO.: CV- CV-12-9955-00CL

COURT FILE NO.: CV- CV-12-9956-00CL

COURT FILE NO.: CV- CV-12-9957-00CL

COURT FILE NO.: CV- CV-12-9958-00CL

DATE: 20150312

ONTARIO

SUPERIOR COURT OF JUSTICE

BETWEEN:

N-R POWER AND ENERGY CORPORATION, ALGONQUIN POWER (LONG SAULT) AND N-R POWER PARTNERSHIP

KIRKLAND LAKE POWER CORPORATION

COCHRANE POWER CORPORATION

IROQUOIS FALLS POWER CORPORATION

CARDINAL POWER OF CANADA, L.P. AND MPT HYDRO L.P.

LAKE SUPERIOR POWER LIMITED PARTNERSHIP, BEAVER POWER CORPORATION, CARMICHAEL LIMITED PARTNERSHIP AND ALGONQUIN POWER (NAGAMAMI) LIMITED PARTNERSHIP

Applicants

– and –

ONTARIO ELECTRICITY FINANCIAL CORPORATION

Respondent

James D.G. Douglas and Heather K. Pessione, for the Applicants N-R Power and Energy Corporation, Algonquin Power (Long Sault) Partnership and N-R Power Partnership, Kirkland Lake Power Corporation, Cochrane Power Corporation and Iroquois Falls Power Corporation

Glenn Zacher, for the Applicants Cardinal Power of Canada, L.P. and MPT Hydro L.P.

Crawford G. Smith and Myriam M. Seers for the Applicants Lake Superior Power Limited Partnership, Beaver Power Corporation, Carmichael Limited Partnership and Algonquin Power (Nagamami) Limited Partnership

Timothy Pinos and Emily Larose, for the Respondent

HEARD: May 20, 21 and 22, 2014

Wilton-Siegel J.

[1] The Applicants have commenced six Applications with respect to the 12 power purchase agreements set out in Schedule “A” originally entered into between the Applicants and Ontario Hydro between 1989 and 1994 and amended by term sheets executed by the parties thereto between 2002 and 2008 (collectively, the “PPAs”).

[2] The Applicants seek a declaration that the Respondent, the Ontario Electricity Financial Corporation (“OEFC”), the successor to Ontario Hydro, has breached the PPAs in the calculation of the amounts payable to the Applicants beginning on or after January 1, 2011 by virtue of its application of a determination of Total Market Cost (“TMC”) that the Applicants assert does not comply with the PPAs.

[3] Alternatively, the Applicants seek declarations that the change in the determination of TMC applied by OEFC to determine such amounts payable constituted either a “change of law” or a “material change to the description of TMC”, or to the description of “DCRnew”, which triggered specific provisions in the PPAs between these Applicants and the OEFC.

[4] The Applicants also seek consequential relief requiring OEFC to calculate TMC from and after January 1, 2011 in the manner prior to the coming into force of the Reallocation Regulation (as defined below) and an order that OEFC pay to the Applicants an amount sufficient to compensate the Applicants for the losses they have incurred to date as a result of OEFC’s alleged breaches of the PPAs.

Ontario’s Electricity Market – Background

Ontario Hydro

[5] Prior to 1999, Ontario’s electricity sector was a vertically integrated monopoly structure. Ontario Hydro was the publicly owned electricity authority in Ontario. It owned and operated almost all of the electricity generation and high-voltage transmission in the province.

[6] Ontario Hydro sold and delivered the power it generated to municipal electric distribution utilities which distributed it to retail customers, and sold and delivered electricity directly to approximately one million remotely located rural retail customers. It also sold and delivered power to approximately 100 large industrial customers who were directly connected to Ontario Hydro’s transmission system (“Direct Industrial Customers”).

[7] As a vertically integrated monopoly, Ontario Hydro’s rates were “bundled” rates that represented Ontario Hydro’s fully-delivered all-in cost to generate and deliver electricity to its customers – i.e., generation/commodity cost (e.g., the price of natural gas, nuclear or hydro generation), transmission cost, ancillary service cost and all related costs.

[8] The Power Corporation Act required Ontario Hydro to supply power at cost to its wholesale municipal customers and its Direct Industrial Customers. Ontario Hydro’s electricity rates were therefore designed to collect from each customer class, including Direct Industrial Customers, its cost of supplying power to those customers.

[9] Ontario Hydro’s rates were fixed by Ontario Hydro, subject to prior review and a recommendation by the Ontario Energy Board (“OEB”). The rates charged to Direct Industrial Customers were published in a schedule prepared by Ontario Hydro and charged uniformly to Direct Industrial Customers according to their individual consumption in each hour of the relevant period.

Inception of the NUG Program

[10] In the late 1980s, Ontario Hydro began to explore opportunities to enlist the private sector in constructing new generation facilities. One of Ontario Hydro’s principal criteria for contracting with private non-utility generators (herein referred to as “NUGs”) was that they supply power at a cost no greater than Ontario Hydro’s avoided cost – that is, no greater than the cost Ontario Hydro would have had to pay to construct and operate new facilities to generate the power itself.

[11] Between 1987 and 1997, Ontario Hydro entered into approximately 100 power purchase agreements with NUGs, including the contracts which are the subject of these proceedings (the original “PPAs”). It is understood that the power supplied by NUGs today accounts for six to eight percent of Ontario’s electric generating capacity.

[12] The PPAs executed with the Applicants exhibit a number of common features. The original PPAs were long-term agreements, typically with 20- to 50-year terms, in order to provide the Applicants with predictable, long-term revenue streams sufficient to finance their projects on a non-recourse or project-finance basis.

[13] The original PPAs executed with the Applicants also included a price adjustment index to escalate annually the amounts payable, or portions of amounts payable, to the Applicants under their original PPAs. This index provided the NUGs with protection against general electricity industry-related cost increases. The price adjustment index that the parties selected was Ontario Hydro’s “direct customer charge” (“DCC”) or “direct customer rate” (“DCR”), which was derived from Ontario Hydro’s Direct Industrial Customer rate schedule. It is agreed that the terms DCC and DCR are interchangeable for present purposes. To be clear, the DCR and DCC did not constitute the rates payable under the original PPAs. Rather, the DCR and DCC were used as an index and the change in such index was used to calculate changes in the rates payable under the original PPAs.

[14] Direct Industrial Customers were retail customers served directly by Ontario Hydro whose average monthly maximum demand was 5 MW or greater. These Direct Industrial Customers were grouped together in one customer class.

[15] In order to convert a portion of the Direct Industrial Customer rate (i.e., the demand rate, which was expressed in dollars per kilowatt) into a volumetric rate expressed in dollars per kilowatt hour so that it could be incorporated into the DCR index, it was necessary for the parties to make an assumption about customer demand. The parties premised the DCR on a notional Direct Industrial Customer having three characteristics: (1) it was assumed to have a 100% load factor, meaning a constant and consistent energy demand for all 8760 hours of a year; (2) it was assumed to take “firm” power from Ontario Hydro, which was the most reliable form of power available; and (3) it had a specifically defined connection voltage. Such a customer is herein referred to as a “Proxy Customer”. The definitions of the DCR or the DCC in the PPAs, as applicable, are set out in Schedule "B".

[16] DCR represented the all-in price that the Proxy Customer would have paid for power based upon Ontario Hydro’s Direct Industrial Customer rate schedule and the Proxy Customer’s characteristics. The Applicants say that that the DCR was derived from, and therefore represented, Ontario Hydro’s direct and indirect cost of producing and delivering power to Ontario Hydro’s Direct Industrial Customers. They say that the parties selected the DCR as an appropriate index because it reflected Ontario Hydro’s broad range of costs for generating and delivering electricity. OEFC says that the DCR represented the price to the Proxy Customer for purchasing electricity as reflected in the word “charge” in the term Direct Customer Charge and the word “rate” in the term Direct Customer Rate.

Restructuring of the Electricity Market

[17] The Direct Industrial Customer rate schedule reflected incremental increases from 1988 to 1993. There was no increase in 1994. As a result of a number of factors, the Government of Ontario directed Ontario Hydro to freeze its municipal and Direct Industrial Customer rates for the period 1994 to 2000. This policy adversely affected NUGs, including the Applicants, whose PPA payments were indexed to Ontario Hydro’s published DCR.

[18] Subsequently, pursuant to the Energy Competition Act, 1998, the Government of Ontario established a framework for competition in the electricity sector. For this purpose, Ontario Hydro was re-structured into five entities, being: (1) Ontario Power Generation Inc. (“OPG”), which owns and operates the majority of the former Ontario Hydro’s generation facilities; (2) Hydro One Inc., which indirectly owns and operates the former Ontario Hydro’s high voltage transmission assets and distribution assets; (3) The Independent Market Operator (the "IMO"), subsequently renamed the Independent Electricity System Operator (the “IESO”), which administers the wholesale electricity market and oversees the reliability of the Ontario power system; (4) OEFC, which is the legal successor of Ontario Hydro, and which administers the assets, liabilities, rights and obligations of Ontario Hydro, including the NUG power purchase agreements that were not transferred to other companies; and (5) the Electrical Safety Authority, which oversees electrical safety. Wholesale electricity competition was formally introduced with the opening of the IESO-administered wholesale electricity market on May 1, 2002.

Establishment of the New Price Adjustment Index

[19] As a result of this re-structuring, it was necessary to integrate the original PPAs with NUGs, including the Applicants' PPAs, into the new market. This required replacing Ontario Hydro’s DCR index, which ceased to exist upon the re-structuring of Ontario Hydro and the commencement of the competitive wholesale market.

[20] In the re-structured electricity market, the all-in or “bundled” cost to Ontario Hydro of generating and delivering electricity to Direct Industrial Customers – e.g., generation, transmission and debt retirement costs – was “unbundled” and individually determined through a mix of market, regulatory and government mechanisms. There was, therefore, no omnibus rate for power established by OPG, as the successor for the generation activities of Ontario Hydro, to Direct Industrial Customers and, therefore, the calculation of the DCR based on what was charged to the Proxy Customer was no longer possible.

[21] To address this issue, the Government of Ontario established a NUG Advisory Committee, composed of NUG owners and other electricity sector representatives, to consider and advise on matters relating to the integration of NUG power purchase agreements into the new competitive electricity market. The NUG Advisory Committee produced a report on the management and disposition of Ontario Hydro's contracts with NUGs in 1999 (the “Advisory Committee Report”).

[22] The Advisory Committee Report was followed by the creation of a joint working group comprised of representatives of OEFC and the Independent Power Producers Society of Ontario (“IPPSO”), an industry group which represented the interests of NUGs and other privately-owned power generators. This working group issued a draft working paper on June 24, 2002 (the “Working Paper”).

Principal Issues Addressed in the Working Paper Regarding a New Price Adjustment Index

[23] The Working Paper expressed the mutual understanding of the parties that the index to replace the DCR should, as much as possible, replicate the nature and behaviour of the former DCR index:

Both OEFC and IPPSO have approached these discussions on the basis that the replacement for the DCR should replicate, to the extent possible, the nature and behaviour of the DCR as it currently exists. Furthermore, any such replacement should not afford any benefits or cause any detriments to either OEFC or each NUG contract holder that did not exist within the original DCR. …

The NUG Advisory Committee was of the view that the appropriateness of any replacement indices should be gauged against the attributes of the existing indices. Specifically, the NUG Advisory Committee concluded that any replacement indices should bear the following characteristics:

• Transparent and publicly available;

• Likely to be available for the duration of the term of the NUG contracts;

• Stable;

• As simple as possible to calculate as circumstances permit;

• Easily verified, both historically and on a prospective basis;

• Reflective of electricity prices;

• Ideally, have been in existence on or before the date of the original index [sic] took effect (or at least have some historical record);

• Predictable and reasonably forecastable; and

• Related to the energy industry.

OEFC and IPPSO agree that the nature and characteristics of the DCR need to be considered in determining an appropriate replacement index. Specifically, the behaviour of the replacement index in the new open market should be as close as possible to the behaviour that could have been expected of the DCR. Both OEFC and IPPSO recognize that any replacement index should not be subject to significant volatility.

[24] In considering a new replacement index, the Working Paper described the features and characteristics of the former DCR index which the parties sought to replicate in a new replacement index:

Nature of the DCR

The DCR represented the fully delivered cost of electricity for Ontario Hydro’s direct industrial customers for firm power at 100% load factor at either 230 kV, 115 kV or 44 kV and included the cost of the commodity, transmission and all other related charges.

Ontario Hydro, as a regulated monopoly electricity supplier, was for many years able to pass through changes in its costs to customers with relative ease. Ontario Hydro proposed the use of changes in the DCR as a suitable index for purposes of adjusting the contract price of NUG contracts on an annual basis. The DCR was expected, when the NUG contracts were negotiated, to protect the NUGs against general industry-related cost increases, although by its nature it would not fully reflect changes in any particular item.

The cost structure of the former Ontario Hydro and the NUGs was very different since each individual NUG faced costs specific to generation and for the most part, only one type of fuel cost. Ontario Hydro’s costs that formed the basis for the DCR reflected its diversified nature as a generation and transmission company. The broad range of costs that comprised the DCR is significant because it contributed to its stability and reduced its volatility.

[25] Based on the foregoing criteria, the Working Paper proposed that DCR be replaced with a new index to be derived from a basket of costs to supply electricity in the new competitive market approximately equivalent to the costs Ontario Hydro previously incurred to generate and distribute electricity. Accordingly, the Working Paper proposed that the newly unbundled costs of supplying power to Direct Industrial Customers be aggregated as a basket of total market costs (“TMC”) and that the replacement index be derived from this aggregated TMC basket:

While the detailed wording of the DCR definition varies slightly from contract to contract, it can be summarized as the fully delivered cost of uninterruptible power at 100% load factor to industrial customers directly connected at the relevant voltage. Both OEFC and IPPSO agree that this concept is the foundation for the revised definition of DCR, as described in detail below. […]

OEFC and IPPSO propose that the replacement for the DCR be defined as the fully delivered cost of uninterruptible power at 100% load factor to industrial customers which are wholesale market participants, thereby maintaining the existing definition, as described above. The current components of this definition are set out in the detailed definition below, and can be summarized as:

• Hourly Ontario Energy Price (“HOEP”)

• Wholesale Market Service Charges

• Transmission Service Charges

• Debt Retirement Charge

• Rural and Remote Electricity Rate Protection

• OPGI Market Power Mitigation Rebate (the “OPGI MMPA”)

• For DCR less than 50 kV, applicable distribution losses and service charges.

OEFC and IPPSO believe this proposal reasonably addresses many of the issues regarding the replacement of the existing definition of DCR and represents an acceptable approach to determining an appropriate replacement for the historic determination of DCR.

[26] In keeping with the original DCR, the 100% load factor customer assumption continued as it provided a convenient and consistent way to facilitate the conversion of the demand components of the TMC basket that were expressed in dollars per kilowatt into amounts expressed in dollars per kilowatt hour.

[27] The Working Paper contemplated an amendment to the calculation of TMC in the event of changes to the items comprising Total Market Cost in order to preserve the original economic effect of Total Market Cost, that is, to ensure that it continued to reflect the cost of uninterruptible power at 100% load factor to wholesale market participant industrial customers at the relevant voltage.

The Principal Amendments to the Term Sheets

[28] OEFC and each of the Applicants amended their original PPAs in a series of term sheets (the “Term Sheets”) executed between 2002 and 2008 establishing a common replacement for the DCR index.

[29] In each Term Sheet, the replacement index relies upon a component called “Total Market Cost”, which is contractually defined as follows:

Total Market Cost TMC (P) = cost per kWh of electricity delivered on 100% load factor firm basis to a Wholesale Market Participant load customer connected at the relevant voltage for the year P.

[30] The TMC combines in a single value all of the components applicable for determining the all-in price that the Wholesale Market Participant load customer having the characteristics of a Proxy Customer (as addressed below) would have paid for power, based on the customer’s characteristics.

[31] Two indices derived from TMC were established to reflect year over year changes in TMC in the NUG power purchase agreement rates in a similar manner as had previously been used: (1) TMC/3, or TMC index (herein, collectively referred to as the “TMC index”) which was a daily-weighted average of the TMC over the past three 12 month periods, and which is used for NUG power purchase agreement rates without minimum price increase provisions; and (2) DCRnew, which is calculated as the greater of (i) the TMC index, and (ii) the current/existing DCRnew rate. DCRnew is used for NUG power purchase agreement rates having minimum price increase provisions. These indices are collectively referred to herein as “DCRnew”. It is these indices that were used in the Term Sheets to determine the inflation index to be applied to rates payable under the PPAs.

[32] Seven of the Term Sheets also contain “change of law” clauses. These provide that in the event of such a change, OEFC would be required to calculate TMC in a manner that maintains the underlying philosophy and definition of DCR and preserves the original economic effect of TMC by continuing to reflect the cost of uninterruptible power at 100% load factor to Wholesale Market Participant load customers at the relevant voltage. These provisions are set out in greater detail below.

[33] The remaining five Term Sheets include “material change” provisions, rather than “change of law” provisions, which require mutual agreement between the parties for any material changes to the description of either DCRnew, or TMC, as applicable. Three of these Term Sheets refer to DCRnew while the two remaining Term Sheets refer to TMC. These provisions are also set out in greater detail below.

Important Features of TMC

[34] The following features of TMC are important for the issues on this application.

[35] First, the definition of TMC contemplates a price of electricity determined on a volumetric basis. This is explicit in the definition itself. It is reinforced by the description of TMC upon market opening included in each of the Term Sheets, which sets out the anticipated components of TMC at that time. As I understand these components, each is expressed, or is capable of being expressed, on a volumetric basis for a Proxy Customer.

[36] Second, implicit in the definition of TMC is an adjustment in the concept of the “Proxy Customer" for the purposes of the calculation of TMC. The "Proxy Customer” under the current regime is a Wholesale Market Participant load customer rather than a Direct Industrial Customer, as there is no longer a rate schedule published for Direct Industrial Customers. There is no definition of “Wholesale Market Participant load customer” under the Electricity Act, 1998 or the IMO Market Rules. However, the parties are agreed that, for present purposes, the definition of a "Wholesale Market Participant load customer" refers to a person who takes electricity supply directly from the IMO/IESO-controlled grid for its own consumption or sale as defined under the IMO Market Rules in force at the time the Term Sheets were entered into.

[37] The definition of TMC contemplates that the “Proxy Customer” will continue to have the three characteristics described above, namely: (1) a 100% load factor, meaning a constant and consistent energy demand for all 8760 hours of a year; (2) taking “firm” power from Ontario Hydro, which was the most reliable form of power available; and (3) a specifically defined connection voltage (subject to a revision in respect of this characteristic that is not relevant for present purposes). As mentioned, the 100% load factor assumption allows conversion of demand components of TMC that were expressed in $/kW into amounts expressed volumetrically in $/kWh. In these Reasons, the term “Proxy Customer”, insofar as it refers to the operation of the definition of TMC in the Term Sheets between the Applicants and OEFC, means a Wholesale Market Participant load customer having these three characteristics.

[38] There are two consequences of the definition of the Proxy Customer that are also important for present purposes. Each component of TMC must reflect the price of such component to the Proxy Customer given the characteristics of the Proxy Customer. Further, the price of a component of TMC to the Proxy Customer cannot, in my opinion, be determined having recourse to any additional characteristics of the Proxy Customer assumed for such purposes. Any such recourse would depart from the language of the definition of TMC without authorization in the language itself. More significantly, from a substantive point of view, insofar as it is necessary to make any such assumption in order to obtain a price or cost to the Proxy Customer of a component of TMC, there is no standard in the language of the definition that would permit a determination of the appropriateness of any such assumption. In this regard, reasonableness is not a sufficient standard. There may be a number of alternative reasonable assumptions – some more favorable to the Applicants, some more favorable to OEFC – in any given situation. Without such a standard, the choice of any particular assumption, and the resulting determination of the cost or price of the component, would be purely arbitrary.

[39] Third, as a related matter, the definition of TMC does not provide for any discretion in its application on the part of OEFC or otherwise. Accordingly, to fit within TMC, a proposed cost must be ascertainable solely by reference to the elements of TMC assuming that the electricity in respect of which the charge is proposed to be included is delivered on a 100% load factor firm basis to a Wholesale Market Participant load customer connected at the relevant voltage for the year i.e. to the Proxy Customer.

OEFC’s Calculation of the New Price Adjustment Index

2002 – 2004

[40] Commencing in 2003 (for the 2002 year), OEFC engaged Navigant Consulting Ltd. (“Navigant”) to calculate DCRnew pursuant to the Working Paper.

[41] Since 2003, OEFC has annually published Navigant’s calculation of TMC and DCRnew on a provisional, interim, second interim and final basis. OEFC uses Navigant’s calculations to adjust the price payable to NUGs under their respective power purchase agreements, including the Applicants’ PPAs. Navigant's calculations set out each of the cost components of TMC in the applicable period.

The Components of TMC Since 2002

[42] There are three broad categories of components applicable in the calculation of TMC:

Category 1: Those that have been included in the calculation of TMC since it was first established:

1. HOEP, as determined by IESO;

2. Transmission Network and Line Connection Charges, as determined by the Ontario Energy Board;

3. Debt Retirement Charge, as determined through legislation; and

4. Wholesale Market Service Charge, as determined by IESO.

Category II: Those established from time to time through regulation or legislation reflecting differences between the market prices received by certain generation assets and the regulated or contract price established for these assets:

1. Market Power Mitigation Agreement (“MPMA”) Rebate: a transitional framework introduced under the Energy Competition Act, 1998 that was intended to discourage OPG from exercising its market power. The MPMA mandated that OPG pay a rebate to consumers on 90% of its domestic sales when the wholesale price exceeded 3.8 cents/kWh.

2. Business Protection Plan Rebate (“BPPR”): Effective May 1, 2003, the MPMA Rebate was replaced by the BPPR pursuant to the Electricity Pricing, Conservation and Supply Act, 2002. The BPPR was the MPMA Rebate paid out to consumers who were not receiving the fixed price under ss. 79.4 and 79.5 of the Ontario Energy Board Act, 1998. The BPPR was intended to rebate half of the amount by which the weighted average commodity price of electricity exceeded 3.8 cents/kWh.

3. OPG Non-Prescribed Assets Rebate: OPG Non-Prescribed Assets are defined under the Electricity Restructuring Act, 2004 as specific generation assets operated and controlled by OPG in service as of January 1, 2006. The OPG Non-Prescribed Assets Rebate required OPG to make payments to consumers for revenues in excess of specified amounts earned on the OPG Non-Prescribed Assets for the period beginning April 1, 2005 and ending April 30, 2009.

4. Global Adjustment Mechanism, which is described in greater detail below.

Category III: Special Charges associated with one-time recovery of certain costs (or repayment of surpluses) determined by the government or the IESO:

1. Ministry of Energy and Infrastructure CAR Charge: Under O.Reg. 66/10 made on February 24, 2010, the IESO was permitted to recover the amount it is assessed with respect to the expenses and expenditures made by the (then) Ministry of Energy and Infrastructure for its energy conservation and renewable energy programs. The rebate was reflected as a volumetric charge in the 2009 TMC calculation.

2. IESO Operating Surplus Rebate: The IESO Operating Surplus Rebate was paid to market participants based on their proportionate quantity of energy withdrawn from the grid, excluding exports, in 2009. It was reflected in the calculation of the 2009 and 2010 TMC and associated indices.

[43] It is not disputed that OEFC was not responsible for setting any of the specific components of TMC or DCRnew, but was strictly responsible for performing the calculations to determine these rates as a result of such changes to the components of TMC. All of the items included in the TMC have been expressed as a volumetric charge.

[44] As the foregoing indicates, the components of TMC have changed several times since TMC was established after market opening in 2002. These changes were incorporated by Navigant into its calculation of DCRnew. The Applicants did not object to any of these changes. The Applicants say that these costs reflected real changes in the costs of generating and transmitting electricity and were consistent with the purpose of the DCRnew index and with the underlying philosophy and definition of DCRnew.

The Global Adjustment Mechanism

[45] The Global Adjustment Mechanism (the “GA”) is an electricity cost recovery/rebate mechanism, the principal purpose of which is to provide for the recovery from consumers of “out-of-market” electricity costs payable by government agencies – e.g., the Ontario Power Authority (“OPA”) – to certain contracted or regulated electricity generators or conservation providers.

Introduction of the Global Adjustment in 2005

[46] The GA was implemented in Ontario on January 1, 2005 pursuant to Ontario Regulation 429/04 under the Electricity Act, 1998. The GA reflects the difference between the HOEP and: (1) the regulated rates paid to OPG’s nuclear and hydroelectric baseload generating stations; (2) payments made to suppliers that have been awarded contracts through the OPA, such as new gas-fired facilities, renewable facilities and demand response programs; and (3) contracted rates administered by OEFC paid to existing generators. The GA is administered by the IESO. The total GA for the province is calculated on a monthly basis using information available to IESO related to OPA, OPG, and OEFC and is published monthly in the IESO’s Monthly Market Report, which is available on the IESO website. The GA is then converted to a rate for payment by consumers.

[47] The total monthly GA is largely the difference between the amounts that generators earn through the IESO wholesale spot market and the amounts they are entitled to under their contracts with the OPA. If the OPA-contracted generators earn less through the spot market than they are entitled to under their contracts, the OPA makes top-up payments to them; if the generators earn more, they make rebate payments to the OPA.

[48] From 2005 until December 2010, the IESO calculated the GA rate volumetrically by dividing the total GA by the total Ontario system demand for electricity during the month. The IESO then published this rate in dollars per MWh. All energy consumers, including wholesale or large-volume industrial customers (i.e. the former Direct Industrial Customers), were charged their portion of GA on a volumetric basis. That is, they were each charged an amount for GA in proportion to the amount of electricity they consumed during the relevant period.

Inclusion of the Global Adjustment in the New Price Adjustment Index

[49] Because the GA represented a new cost (or credit) for supplying electricity generation and is charged or credited to all electricity consumers on their monthly bill, OEFC incorporated the GA into its calculation of TMC and DCRnew. Navigant incorporated GA, calculated on a volumetric basis in $kWh in each such month based on a 100% load factor in each month and the GA rate, into its calculation of DCRnew.

[50] The GA grew substantially from the time it was introduced, from a $1.15 billion credit in 2005 to a $3.85 billion charge in 2010. This was principally due to two factors. First, during this period, the OPA procured large amounts of new generation (e.g., gas-fired, nuclear and renewable generation). The costs of this new generation, along with the costs of certain regulated rates, were added to GA. Second, there is an inverse relationship between the HOEP and GA. The lower the HOEP, the higher the above market costs paid to new generation and regulated generation. In other words, decreases in the HOEP will result, and have resulted, in increases in GA. In recent years, the GA has increased to the extent that in some months it has constituted two thirds to three-quarters of the total cost of electricity.

Amendments to the Global Adjustment Mechanism in 2011

[51] Effective January 1, 2011, the manner in which GA is allocated has been amended pursuant to Ontario Regulation 398/10 and the subsequent Ontario Regulation 121/12 under the Electricity Act, 1998 (collectively, the “Reallocation Regulation”).

[52] The Reallocation Regulation established two classes of customer for the purposes of the allocation of the GA Charge: (1) Class A customers, being those market participants and consumers with average monthly demand greater than 5 MW; and (2) Class B customers, being all other market participants and customers, together with any Class A customers who have elected to be deemed to be Class B customers.

[53] Under the Reallocation Regulation, Class A customers pay a percentage of the total GA in a year based on the proportion of electricity they consumed during the five peak demand hours in the previous year. The remainder of the total GA is allocated to Class B customers on a volumetric basis – i.e., based on consumption over all 8760 hours in the year. The five peak demand hours are the five hours in the year with the highest demand for electricity, which typically occur on the hottest days of the summer.

[54] Under the allocation formula in the Reallocation Regulation, if Class A customers reduce their electricity consumption during the five peak demand hours, they will pay a smaller portion of the total GA costs than they did prior to January 1, 2011, when their GA payments were based on their total electricity consumption. The Reallocation Regulation encourages Class A customers to reduce their GA payments by reducing their consumption during these five annual peak hours. The effect of the Reallocation Regulation was that low-volume consumers, the Class B customers, became responsible for a proportionately greater share of the GA, and high-volume consumers, the Class A customers, became responsible for a reduced share of the GA.

[55] The Reallocation Regulation did not reflect any change in actual costs of generating and distributing electricity nor did it reflect a change in the total GA charge in any given year, in the costs comprising the total GA, or in electricity costs generally. Rather, the Reallocation Regulation reallocated the existing GA charge for governmental policy reasons – principally, to reduce power prices for large industrial consumers and thereby spur industrial competitiveness as well as to encourage demand management and emission reductions by, for example, incentivizing larger consumers to shift consumption to off-peak.

Change to the Formula for Calculating TMC

[56] Following the coming into force of the Reallocation Regulation, Navigant amended the formula it uses to calculate the GA portion of TMC.

[57] Before this amendment, the IESO calculated the GA rate posted on its website as follows (the “Old Formula”):

Total $ GA charge for the period

Actual Total System Demand

Navigant then obtained a GA rate for the Proxy Customer (in $/kWh) by converting the GA rate posted on the IESO’s website into a volumetric rate using the 100% load factor assumption.

[58] Under the amended formula, Navigant has calculated the GA portion of TMC (in $/kwh) by dividing the total GA in dollars for each month by the product of the average system peak demand for the five peak demand hours in the 12 month base period and the number of hours in the month (the “New Formula”):

Total $ GA charge for the period

Average System Critical Peak Demand x Hours in the Period

[59] The New Formula reduces the GA amount included in TMC. As a result of the New Formula, the Applicants say that they have to date suffered, and will continue to suffer, significant material losses for the duration of the term of each of their PPAs in the form of reduced payments, given a lower TMC and therefore a lower rate escalation factor in their PPAs.

The Navigant Evidence Regarding the Calculation of the GA Allocation to the Proxy Customer

[60] The following describes Navigant’s explanation for the derivation of the New Formula. In its annual memo for 2011 regarding the calculation of TMC and DCRnew, Navigant advised that it had calculated TMC to reflect the allocation of GA to Wholesale Market Participant load customers at a 100% load factor under the Reallocation Regulation. In a memo to OEFC dated July 7, 2011, Navigant opined that “the inclusion of the amount of the [GA] for Class A consumers in the TMC according to [its calculation] satisfies the definition of TMC and ensures that the TMC continues to reflect the cost of uninterruptible power at a 100% load factor to Wholesale Market Participant load customers”.

[61] In paragraph 60 of his affidavit sworn July 15, 2013, Todd Williams, the managing director of Navigant responsible for Navigant's calculations of TMC (“Williams”), repeated this conclusion. The arithmetic approach by which Navigant derived the New Formula for the calculation of the GA component of TMC is set out in paragraph 59 of Williams' affidavit as follows:

59. The calculation of the GA component of TMC reflects the following:

(a) The total GA that would be payable by the Proxy Customer per period is calculated as follows:

Proxy Customer GA Cost ($/MW) = Total $ GA charge for the period/(Average System Peak Demand)

In this formula, the Average System Peak Demand is the average system peak demand during the five peak hours of the historical Base Period, as determined by the IESO.

(b) The unit GA that would be payable by the Proxy Customer per period on a per MWh basis is calculated as follows:

Proxy Customer GA Cost ($/MWh) = Proxy Customer GA Cost ($/MW/(Hours in period)

This reflects the fact that, per the term sheet definition of TMC, power would be delivered on 100% load factor firm basis to the Proxy Customer.

(c) Using the total GA calculation from the first formula as the Proxy Customer GA Cost ($/MW) in the second formula yields the following:

TMCGA = Total $ GA charge for the period/ (Average System Peak Demand * Hours in period)

[62] In the course of the hearing, counsel for OEFC sought an adjournment in order to introduce supplementary evidence regarding whether Navigant’s calculation of the GA component of TMC complied with the Reallocation Regulation, in response to an argument of the Applicants that it failed to do so. This request was denied on the ground that the issue before the Court is not whether Navigant’s calculation of the GA component of TMC complied with the Reallocation Regulation but rather whether it was consistent with the principles inherent in the definition of TMC. As the Reallocation Regulation did not address the PPAs, including the Term Sheets, in any manner, there is no issue of compliance with the Reallocation Regulation. Moreover, the issue of how Navigant calculated the GA component of the TMC is a factual matter that is not in dispute. As noted above, Williams is very clear in paragraph 59 of his affidavit regarding the manner in which he formulated his approach to such calculation i.e. how he developed the New Formula.

[63] However, subsequent to the hearing the Court advised the parties that, in its view, the assumptions implicit in the New Formula were significant for this proceeding and had not been fully addressed by the parties at the hearing as explained in Williams’ affidavit. Accordingly, the Court permitted supplementary submissions on this issue from the parties. In its correspondence to the Court, counsel for OEFC provided an explanation of Navigant's approach as well as an appendix which provides an algebraic derivation for the formula for TMCGA, both of which assist in understanding more clearly Navigant's approach to the derivation of the New Formula. This matter is addressed further below.

Applicable Law

[64] The parties agree that determination of the issues on this application requires the contractual interpretation of the PPAs. The applicable principles of contractual interpretation were set out by Blair J.A. in Ventas, Inc. v. Sunrise Senior Living Real Estate Investment Trust, 2007 ONCA 205, 85 O.R. (3d) 254, at para. 24:

… a commercial contract is to be interpreted,

(a) as a whole, in a manner that gives meaning to all of its terms and avoids an interpretation that would render one or more of its terms ineffective;

(b) by determining the intention of the parties in accordance with the language they have used in the written document and based upon the "cardinal presumption" that they have intended what they have said;

(c) with regard to objective evidence of the factual matrix underlying the negotiation of the contract, but without reference to the subjective intention of the parties; and (to the extent there is any ambiguity in the contract),

(d) in a fashion that accords with sound commercial principles and good business sense, and that avoid a commercial absurdity.

[65] In addition, in the recent decision of Sattva Capital Corp. v. Crestor Moly Corp., 2014 SCC 53 at paras. 56-57, Rothstein J., speaking for the Supreme Court, addressed the extent to which surrounding circumstances can inform contractual interpretation:

While the surrounding circumstances will be considered in interpreting the terms of a contract, they must never be allowed to overwhelm the words of that agreement (Hayes Forest Services, at para. 14; and Hall, at p. 30). The goal of examining such evidence is to deepen a decision-maker's understanding of the mutual and objective intentions of the parties as expressed in the words of the contract. The interpretation of a written contractual provision must always be grounded in the text and read in light of the entire contract (Hall, at pp. 15 and 30-32). While the surrounding circumstances are relied upon in the interpretive process, courts cannot use them to deviate from the text such that the court effectively creates a new agreement (Glaswegian Enterprises Inc. v. B.C. Tel Mobility Cellular Inc. (1997), 1997 CanLII 4085 (BC CA), 101 B.C.A.C. 62).

The nature of the evidence that can be relied upon under the rubric of “surrounding circumstances” will necessarily vary from case to case. It does, however, have its limits. It should consist only of objective evidence of the background facts at the time of the execution of the contract (King, at paras. 66 and 70), that is, knowledge that was or reasonably ought to have been within the knowledge of both parties at or before the date of contracting. Subject to these requirements and the parol evidence rule discussed below, this includes, in the words of Lord Hoffmann, “absolutely anything which would have affected the way in which the language of the document would have been understood by a reasonable man” (Investors Compensation Scheme, at p. 114). Whether something was or reasonably ought to have been within the common knowledge of the parties at the time of execution of the contract is a question of fact.

Issues On This Application

[66] There are three principal issues for determination on this application:

1. Has OEFC contravened the PPAs in its calculation of TMC?

2. Do the “change of law” clauses in the seven Term Sheets containing them prevent OEFC from implementing the regulatory amendments relating to GA?

3. Do the “material change” provisions in the five Term Sheets containing them require the consent of the Applicants who are parties to such Term Sheets to OEFC’s implementation of the regulatory amendments relating to GA?

I will address the disposition of each issue in turn.

Has OEFC Wrongfully Contravened the PPAs in its Calculation of TMC?

[67] The principal issue raised in this application is whether OEFC has contravened the PPAs in its determination and payment of rates since the amendments to the allocation of the Global Adjustment pursuant to the Reallocation Regulation.

[68] This requires a determination of whether, in calculating TMC since January 1, 2011, OEFC has accurately implemented the definition of TMC, which, to repeat, is as follows:

Total Market Cost TMC (P) = Cost per kWh of electricity delivered on 100% load factor firm basis to a Wholesale Market Participant load customer connected at the relevant voltage for the year P.

[69] Specifically, the Court must address whether the calculation of the GA cost of the Proxy Customer pursuant to the New Formula results in a component of TMC that is consistent with the definition of TMC. As mentioned, the definition of TMC requires that each component of TMC must reflect the cost of such component to the Proxy Customer given the characteristics of the Proxy Customer.

The Positions of the Parties

[70] By way of overview, OEFC argues that TMC constitutes the aggregate price paid by a Proxy Customer for electricity delivered to it in the relevant period. On the basis of this approach, the definition of TMC has been satisfied. The Applicants argue that TMC represents the aggregate of all costs of generating and supplying electricity to a Proxy Customer. They accept that GA qualifies as a cost component of TMC. However, the Applicants argue that the GA cost attributable to a Proxy Customer must be determined on a volumetric basis pro rata to consumption by all purchasers of electricity – that is, in the manner that it was determined prior to the enactment of the Reallocation Regulation. The following summarizes the principal arguments of the parties.

The Position of the Applicants

[71] The Applicants argue that the New Formula is flawed because it reflects the price of electricity as opposed to the cost of supplying electricity. They submit that DCR, and TMC, were selected as the bases for the index for rate escalation to protect the NUGs from industry-related cost increases. The Applicants argue that the allocation of GA under the Reallocation Regulation is inconsistent with this purpose. They submit that the use of the New Formula to calculate the GA component of TMC results in a calculation of TMC, and therefore of DCRnew, that does not have the result of protecting the Applicants from industry-related cost increases. They say that, instead, the New Formula mechanically incorporates into TMC a government change to electricity prices notwithstanding the fact that such price change has no relation to the actual costs of generating and transmitting electricity and notwithstanding the negative impact on the Applicants’ right to annually indexed PPA payments. The Applicants submit that OEFC’s implementation of the New Formula is a breach of the clear language of the PPAs and of the Working Paper and is contrary to the parties’ fundamental intention that TMC would continue to replicate the nature and behaviour of the DCR and would protect the NUGs against general industry-related cost increases.

The Position of OEFC

[72] OEFC submits that the New Formula accords with the definition of TMC and DCRnew because it reflects the new “price” that the Proxy Customer would pay. OEFC argues that TMC requires only that a cost or charge included as a component of TMC be expressed on a volumetric basis. On this approach to the definition of TMC, OEFC submits that it has fully complied with the PPAs in relying on Navigant’s calculation of a GA cost to the Proxy Customer on a per kWh basis pursuant to the New Formula.

[73] It should be noted, however, that OEFC does not argue that the calculation of a GA cost pursuant to the New Formula would satisfy the requirements of the definition of TMC even if TMC were understood to be a calculation of the costs of generating and supplying electricity to a Proxy Customer. In other words, OEFC’s position implicitly acknowledges that the amount of GA allocated to a Proxy Customer pursuant to the New Formula represents a diminution of any link that would otherwise exist between increases in the costs of generating and supplying electricity and the rates payable under the PPAs. More generally, the OEFC position implies that there need not be any connection between the cost of producing electricity and the price charged to the Proxy Customer.

Analysis and Conclusions

[74] Although the parties have proceeded on the basis that the framework for analysis of the issues on this application is whether TMC is a cost-index or a price-index, the substantive issue on this application is whether the definition of TMC requires that costs of generating and supplying electricity that are aggregated and then allocated to purchasers of electricity must be allocated on a basis pro rata to consumption of electricity or can be allocated on another basis – in this case, on a basis which is explicitly intended to subsidize a particular class of purchasers.

[75] I propose to address this issue in the following order. I will first set out certain preliminary observations that are relevant to the issue before the Court and will address a particular issue raised by the Applicants. I will then consider the alternative interpretations of TMC proposed by the parties. Finally, I will consider whether OEFC has complied with the PPAs based on the contractual interpretation of TMC reached in the preceding analysis.

Preliminary Observations

[76] The following five preliminary observations inform the conclusions reached below.

[77] First, as mentioned, the issue addressed in this section requires the contractual interpretation of the original PPAs as amended by the Term Sheets. While the context in which the original PPAs were negotiated and executed may assist in understanding the Term Sheets, the language in the original PPAs has been superseded by the language of the Term Sheets in respect of the issues on this Application.

[78] Second, in any event, I do not think the evidence before the Court establishes on a balance of probabilities that, at the time of execution of the original PPAs, the parties turned their minds to the question of whether the operative principle in the original PPAs was either exclusively the cost of electricity supplied to Direct Industrial Customers, as the Applicants argue, or exclusively the price of the electricity supplied to Direct Industrial Customers, as OEFC argues. Under the regime in existence at the time of execution of the PPAs, those amounts were the same and the concepts essentially two sides of the same coin. Accordingly, the parties did not need to turn their attention to this issue in drafting the PPAs and, in my view, there is no language in the PPAs that suggests that they did so. In particular, the use of the terms “rate and “rates” in the various definitions of DCR is not instructive in the interpretation of its successor, TMC. Instead, in selecting the DCR as the base index for the inflation index, the parties focused on the DCR’s ability to serve as a proxy for general industry-wide cost increases and its anticipated relative stability.

[79] Third, as mentioned, the Applicants’ position – that TMC represents the aggregate of all costs of generating and supplying electricity to a Proxy Customer – assumes that the concept of TMC requires that any costs or charges that are a component of TMC must be allocated to all customers, including but not limited to Proxy Customers, on the same volumetric basis based on actual usage or consumption by the customer relative to all other customers. OEFC’s position – that TMC constitutes the aggregate price paid by a Proxy Customer – implicitly rejects the Applicants’ position that there is any limitation on the manner of obtaining a volumetric basis for any cost or charge to be included in TMC.

[80] Fourth, as mentioned, the definition of TMC requires that the amount calculated in accordance with that definition shall be the same for all Proxy Customers.

[81] Fifth, and most importantly, the Working Paper is not a legally binding document, except to the extent of the incorporation by reference of specific passages constituting the descriptions of TMC and DCRnew addressed in the discussion below under “The Operation of the Material Change Provisions”. Nor was the Working Paper prepared for the purposes of litigation. Accordingly, the specific wording of particular phrases or terms in the Working Paper is not, in my opinion, a reliable interpretive guide for present purposes. In particular, for this reason, I do not accept the OEFC argument that the substantial similarity of the language in the Working Paper between the description of DCR and the description of the replacement index is indicative of the intention of the parties. In my opinion, this argument, and similar arguments of the Applicants, place undue reliance on specific wording, given that the Working Paper was not drafted with the intention that it would be a legally binding instrument between the Government of Ontario and any of the NUGs.

[82] However, the Working Paper does set out general principles that were acknowledged by both parties pertaining to the replacement indices, the DCRnew and TMC/3, and therefore of TMC. I think that the Court should treat the articulation of these principles in the Working Paper as “surrounding circumstances” that can be relied upon for the purposes of the contractual interpretation of the PPAs in accordance with the principles articulated in Sattva Capital. In particular, the following four general principles articulated in the Working Paper are relevant for the issues in this application and, to my understanding, are not disputed by the parties.

[83] First, when the NUG contracts were negotiated, the DCR was expected to protect the NUG's against general industry-related cost increases, although by its nature it would not fully reflect changes in any particular cost. The Advisory Committee Report expressed the purpose of the DCR in the following terms which are useful for present purposes:

As a price charged to an important class of [Ontario Hydro] customers, DCR was expected to reflect over time the impact of changes in Ontario Hydro's costs of doing business, and would thus be expected to protect NUG's against cost increases applicable to the industry.

[84] In addition, the parties intended that the replacement index for the DCR should replicate, to the extent possible, the nature and behaviour of the DCR as it currently existed. Further, in particular, any replacement index should not be subject to significant volatility. Lastly, the replacement index should not afford any benefit or cause any detriment to either OEFC or any Applicant that did not exist within the original DCR.

Preliminary Matter

[85] Before addressing the interpretation of TMC, I wish to address one argument raised by the Applicants that was addressed in the supplementary correspondence from the parties referred to above.

[86] At the hearing, the Applicants argued that the approach of Navigant to the calculation of the Proxy Customer's GA cost was inconsistent with the definition of TMC because it was not capable of expression as a cost per kWh without an assumption as to the Proxy Customer’s net volume of electricity withdrawn from the IESO grid during the peak demand period. The Applicants argued that, in using a denominator equal to the product of the average system demand during the peak period and the number of hours in the month for which GA is being calculated, Navigant was necessarily assuming a higher level of demand than the actual level of demand in the period. The Applicants argue that Navigant cannot calculate a GA cost for the Proxy Customer without having an actual value for the Proxy Customer’s peak system demand, which cannot exist for a hypothetical customer.

[87] The correspondence from OEFC sets out the basis on which Navigant arrived at its GA cost per kWh for the Proxy Customer. On the basis of the fuller explanation set out in that correspondence, I am satisfied that it is possible to derive such a rate based on the characteristics of the Proxy Customer.

[88] As I understand the calculations, the essential difference between the Old Formula and the New Formula can be described in the following manner. Under the Old Formula, the IESO calculated a GA charge per MWh for any period by dividing the total GA charge for the period by actual total system demand for the period. From this amount, Navigant calculated a GA charge for the Proxy Customer by application of the 100% load factor assumption. Under the New Formula, Navigant calculates a GA charge per MW by dividing the total GA charge for the period by the average system peak demand and then divides the result by the number of hours in the period to reflect the 100% load factor. The Navigant calculation proceeds on the basis that each Class A customer effectively pays the same amount of GA cost per MW of total peak demand. From this figure, the further calculation of GA per MWh follows mathematically by dividing the former amount by the number of hours in any given period based on the 100% load factor. I note that the figure resulting from the initial calculation is invariable for all Class A customers in any given period whereas the figure resulting from the final calculation is dependent upon application of the 100% load factor. Significantly for present purposes, in each case, the figures involved in the calculation of the GA per kWh charge for the Proxy Customer do not require any assumptions regarding the Proxy Customer apart from the 100% load factor.

[89] In their response to the explanation provided in OEFC's correspondence, the Applicants argue that the GA calculation prescribed by the Reallocation Regulation cannot be applied to the PPAs without misusing the 100% load factor assumption and improperly manipulating the calculation. The Applicants say that Navigant's use of the New Formula therefore reflects a number of errors.

[90] First, the Applicants say that the Reallocation Regulation mandates the calculation of a peak demand factor for the Proxy Customer according to the formula set out therein and that it is not possible to make such a calculation in the absence of actual consumption. In addition, they say that the formula in the Reallocation Regulation produces a different GA rate per MWh for each Class A customer based on each such customer's actual consumption of electricity during the peak demand period. On this basis, they argue there is no uniform GA rate per MWh to ascribe to the Proxy Customer and no GA rate applicable to the PPAs.

[91] Essentially, each of these alleged errors relates to the same issue – Navigant's use of the 100% load factor to convert its calculation of the GA cost per MW of average peak system demand of Class A customers into a GA charge expressed in ¢/kWh. The Applicants argue that the 100% load factor was agreed upon solely for the purpose of converting demand charges included in the DCR schedule into an energy rate i.e. a rate expressed in ¢/kWh for the purposes of the PPA.

[92] I do not agree with the Applicants’ position for two reasons.

[93] First, the fact that the amount of GA cost payable by each Class A customer varies according to its actual consumption in the peak demand period does not necessarily result in a different amount being payable by each customer whose consumption profile complies with the definition of a Proxy Customer. To the contrary, as I understand the arithmetical exercise described in paragraph 59 of Williams’ affidavit and expanded upon in the supplementary correspondence of OEFC, every Class A customer will pay the same GA cost per MWh of average system peak demand given independently determined amounts for total system peak demand and the total GA for a period to be allocated. Because each Class A customer, including the Proxy Customer, pays the same GA cost per MWh of average peak system demand, it is possible to calculate a volumetric charge in ¢/kWh to the Proxy Customer based on the 100% load factor without making any assumption regarding actual consumption during the peak demand period.

[94] Further, as the amount of GA per MWh of average system peak demand is effectively an implied demand charge, I do not see why the 100% load factor cannot be used to derive a GA rate expressed in ¢/kWh for the purposes of the calculation of TMC. Based on the materials before the Court, I do not see any substantive difference for this purpose between the demand charges that comprised a part of the DCR and the GA rate per MWh for any period calculated by Navigant in respect of Class A customers. Accordingly, as the GA rate per MWh and the 100% load factor for any period are invariable for all Class A customers, the resulting GA charge per kWh for the period will also be invariable.

[95] I would also observe that the Applicants’ argument that the denominator used in the New Formula overstates the actual demand in the period for which GA is being calculated is circular. The Applicants` argument ignores the essential fact that the Reallocation Regulation calculates the GA cost for the Proxy Customer by reference to peak system demand for an earlier period rather than by reference to actual demand in the period for which a GA cost is being calculated.

[96] On the basis of the foregoing, I do not accept the Applicants’ argument that OEFC has contravened the PPAs based on an alleged inability of the New Formula to express a cost of GA on a volumetric basis. However, the fact that such a calculation can be generated is also not determinative of the issue before the Court of whether, in substance, the amount calculated by the New Formula is consistent with the intentions of the parties regarding TMC. In my view, this issue is answered by the further considerations set out below.

The Alternative Interpretations of TMC

[97] The parties propose alternative interpretations of the definition of TMC, each relying on a different grammatical reading.

[98] OEFC argues that TMC is the price of electricity charged to a Wholesale Market Participant load customer. As the definition does not use the term “price”, OEFC relies on the words “cost per kWh of electricity … to a Wholesale Market Participant load customer…” The Applicants argue that TMC is the cost of the electricity that is delivered to a Wholesale Market Participant load customer. The Applicants rely upon the words “cost per kWh of electricity delivered”. The difference between these readings turns on the manner in which the remainder of the definition of TMC is integrated with the concept of the "cost per kWh of electricity".

[99] The Applicants’ reading treats the italicized clause as a unit that collectively describes the Proxy Customer and implies the words “which is” in the following manner:

Total Market Cost TMC (P) = cost per kWh of electricity [which is] delivered on 100% load factor firm basis to a Wholesale Market Participant load customer connected at the relevant voltage for the year P.

[100] OEFC's reading separates the italicized provisions that describe the Proxy Customer by the words “to a Wholesale Market Participant load customer”, as set out below. This separation is necessary for its interpretation of TMC as pertaining to the price charged to such a customer:

Total Market Cost TMC (P) = cost per kWh of electricity delivered on 100% load factor firm basis to a Wholesale Market Participant load customer connected at the relevant voltage for the year P.

[101] On balance, as a matter of the plain reading of the definition of TMC, I think that the Applicants' reading of the definition is correct for the following reasons.

[102] At its most basic, the position of OEFC is that the words “cost to” mean “price of”. If the parties had intended to refer to the price charged to a Proxy Customer, the definition would have been expressed in those terms, as “the price charged” to a Wholesale Market load customer. Even if the term “cost” had been retained, the definition would have been drafted in terms of the “cost per kWh of electricity to a Wholesale Market Participant load customer” rather than the “cost per kWh of electricity delivered to a Wholesale Market Participant load factor” which, by itself, leads in the direction of the cost not the price.

[103] The OEFC interpretation ignores the existence of the word “delivered” to the point of essentially reading it out of the definition. However, the grammar of the definition requires not only that “delivered” be included such that TMC becomes the cost of electricity delivered to a Wholesale Market Participant load customer but, more expansively, that “delivered” governs the whole clause, other than the concluding words “for the year P”.

[104] Further, the words “to a Wholesale Market Participant load customer” are situated in the definition in the middle of the clause describing the three characteristics of the Proxy Customer. From a drafting perspective, there is no reason why the conditions of the Proxy Customer should be split before and after the reference to a Wholesale Market Participant load customer as the OEFC interpretation requires.

[105] Beyond the plain meaning of the definition of TMC, I also consider that the Applicants' interpretation is supported by the “surrounding circumstances” in which the Term Sheets, including the definition of TMC, were negotiated and executed. In this regard, the following six considerations are relevant.

[106] First, as set out above, an important general principle articulated in the Working Paper is that the DCR was selected as an index reflecting over time the impact of changes in Ontario Hydro's cost of doing business. Such costs were incurred in one of two forms – direct costs that were allocated directly to the customer and other costs that were aggregated into a demand charge that was then allocated in accordance with the Proxy Customer assumptions. The important point is that, in each case, changes in these costs over time would be reflected in changes in the DCR or the TMC, as applicable. After the opening of the electricity market, the parties understood that costs would be treated in the same manner, which treatment would be reflected in TMC.

[107] The effect of the Reallocation Regulation is to disconnect an important class of costs from this relationship. The Reallocation Regulation has the result that total costs incurred in the generation of electricity will not be reflected uniformly in TMC. The result is a reduction in any increase in TMC that would otherwise have occurred. In an extreme case, as Williams agreed on his cross-examination, the principle would allow a category of costs to be reduced to nil for the Proxy Customer. I think this is inconsistent with the intentions of the parties regarding the purpose and therefore the operation of TMC. It introduces an element of arbitrariness into the calculation of TMC in respect of the costs that TMC is intended to track for purposes of the rate escalation index.

[108] Second, another important general principle in the selection of the definition of TMC was the mutual understanding that the parties did not intend to introduce new risks or benefits in respect of the index selected to replace DCR.

[109] In this case, the effect of the Reallocation Regulation is to introduce a new and extraneous risk into the calculation of TMC, namely the risk of an artificially low price for electricity resulting from a government mandated programme to subsidize a class of customers i.e. those Wholesale Market Participants load customers who are Class A customers under the Reallocation Regulation. Such a risk has the result of substantially eliminating whatever link exists between industry-wide cost increases pertaining to the generation and supply of electricity and the price of electricity.

[110] Third, as a related matter, it is also understood as a general principle that the replacement index for the DCR was to replicate, to the extent possible, the nature and behaviour of the DCR as it existed prior to 2002. There is no evidence, and no suggestion by OEFC, that the DCR was ever calculated on a basis that entailed cross-subsidization arrangements of either a class of customers in favour of Direct Industrial Customers or by Direct Industrial Customers in favour of another class of customers.

[111] These three general principles regarding the intended operation of the replacement index for DCR collectively indicate or imply an intention that any costs to be aggregated and allocated to purchasers of electricity should be allocated on a basis that is pro rata to the purchases or consumption of electricity by all purchasers. Accordingly, they imply that an allocation that departs from such principle with a view to subsidizing one class of purchasers at a cost or detriment to the remaining purchasers was not contemplated and is not consistent with the parties' intentions regarding the calculation of TMC.

[112] Fourth, the relationship between the HOEP and GA cost also exhibits an asymmetry that is inconsistent with the general principles under the Working Paper. As noted above, the higher the HOEP, the lower the GA cost in any period, and vice versa. However, HOEP is an energy charge that is paid by the Proxy Customer on a volumetric basis pro rata to consumption relative to all consumption in a given period. Accordingly, to the extent HOEP falls, and assuming all other factors remain constant, the portion of the costs that constitutes the GA charge and is allocated on a subsidized basis pursuant to the Reallocation Regulation rises. Conversely to the extent HOEP rises and assuming all other factors remain constant, the portion of costs that represent the GA charge will fall.

[113] Disregarding for the moment the small portion of GA costs that are not directly related to the generation of energy, both the HOEP and the GA charge deal with the cost of generating electricity. Under the regulated market system, Ontario Hydro in effect charged a blended rate that incorporated the varying costs of generation of electricity from different sources on a volumetric basis based on pro rata consumption. Insofar as TMC was intended by the parties to replicate the performance of the DCR in the regulated market context, it fails to do so insofar as all costs of the generation of electricity do not reflect a blended rate based on pro rata consumption of electricity as was the case with the DCR. Instead, incremental increases in energy costs as a result of an increase in the HOEP will be allocated on a pro rata consumption basis whereas incremental deceases as a result of a decrease in the HOEP will result in an increase in GA costs that are allocated disproportionately pursuant to the Reallocation Regulation. In this respect, the application of the New Formula has the result that the TMC fails to replicate the performance of DCR that would have occurred prior to the opening of the electricity market.

[114] Fifth, with respect to the relevance of other provisions of the Term Sheets, the Applicants argue that the interpretation of TMC as a cost index is also supported by the enumeration of the components of TMC at market opening. They argue that such an enumeration would have been unnecessary if TMC were a price index. I do not agree. The Proxy Customer is a notional customer for whom there is no published all-in price of electricity under the current market system comparable to the DCR. Given the deconstruction of the costs of generating and supplying electricity, as well as the other related costs included in the DCR, even if TMC were a price index such an enumeration would have been necessary in the restructured market for the sake of clarity in the calculation of the price of electricity to the Proxy Customer.

[115] However, as a related matter, the standard referenced in the Change of Law provisions in respect of any changes to the items comprising TMC would have been unnecessary if TMC were simply a price index. As mentioned, the Change of Law provisions require that any change to the items comprising TMC must be consistent with maintenance of the underlying philosophy and definition of TMC in order to preserve the original economic effect of TMC. Such standard necessarily subjects any proposed change to any of the items comprising TMC to this test. If the TMC were simply a price index, such a standard would be unnecessary, as any proposed change that could be expressed volumetrically would be included in TMC. Accordingly, I consider that this language of the Change of Law provisions is supportive of the Applicants’ interpretation of TMC.

[116] Sixth, there is a substantial, but not a complete, correspondence between the class of customers who are Class A Customers under the Reallocation Regulation and the customers who are Wholesale Market Participant load customers. The evidence before the Court is that, while most Class A Customers would also be Wholesale Market Participant load customers, there are some Wholesale Market Participant load customers who would otherwise constitute Class A customers but who have opted for categorization as Class B Customers because they are not in a position to reduce their electricity consumption during the peak system hours.

[117] This raises the significance of the lack of complete correspondence between Class A customers and the Proxy Customer for present purposes. OEFC argues that it should have no significance on the basis that, as expressed by Navigant in its memorandum dated July 7, 2011 referred to above, under the Reallocation Regulation, “virtually all of the consumption of wholesale market participants, excluding licensed distributors and generators, will qualify as consumption by Class A market participants.” I conclude, however, that, at least as currently drafted, the Reallocation Regulation provides some support for the Applicants’ position for the two reasons set out below although, as also discussed below, I do not put great weight on this consideration in reaching the conclusions in these Reasons.

[118] First, the definition of TMC treats all Wholesale Market Participant load customers as a single class. It does not contemplate the possibility that there could be differing prices to the Proxy Customer reflecting differential treatment under the price-setting legislation. OEFC urges the Court to ignore this consideration on the basis that, as mentioned, substantially all of the Class A Customers are Wholesale Market Participant load customers. Even assuming this to be the case, however, I do not think that this is correct from the perspective of contractual interpretation. The possibility of differing prices to a Proxy Customer depending upon its electricity consumption profile, even on an elective basis based on its economic self-interest, reflects an incompatibility between the Reallocation Regulation and the definition of TMC.

[119] Second, as a related matter, given the election under the Reallocation Regulation described above, the Proxy Customer is effectively defined as a Wholesale Market Participant load customer having the characteristics of a Proxy Customer who has also determined not to elect to become a Class B customer. This has the effect of adding an additional characteristic to the description of the Proxy Customer beyond the characteristics that are incorporated into the definition of TMC. In this sense, a Class A customer is not a Proxy Customer.

[120] I note, however, that both of the foregoing matters arise by virtue of the existence of the elective feature provided under the Reallocation Regulation. It is not suggested that there are Class B customers under the Regulation that would qualify as Proxy Customers. Therefore, these considerations would cease to be applicable if this elective feature were revoked by further regulation. For this reason, I do not consider that the lack of complete correspondence between the Proxy Customer and the Class A customer class is determinative of the issue in this application on its own.

[121] I would also add that, while it is possible that the characteristics of a Wholesale Market Participant load customer which would elect Class B customer status could be material to the present proceeding, the evidence does not provide a sufficient understanding of this matter to permit the Court to draw any conclusions on this issue. The Applicants state that the customers who have opted for Class B status are customers who are unable to change their consumption patterns during the peak system period. If this is accurate, it raises the question of whether the Proxy Customer, which has a 100% load factor, would fit into this category. On the other hand, Williams stated in his affidavit that the Proxy Customer would not make such an election as the 100% load factor characteristic of the Proxy Customer would not enable it to reduce its GA by electing Class B customer status.

[122] For completeness, OEFC also argues that the inclusion of certain items in the components of TMC that are not strictly related to current costs of generating and supplying electricity demonstrates that TMC is not a cost index but rather a price index. I accept that TMC includes certain costs that customarily have been paid for by electricity customers that are not strictly related to the costs of current generation and supply. Most of the costs in this category are, however, referable to the historic costs of such activities that must be amortized. In any event, I am not persuaded that the inclusion of certain other costs, such as for example the costs of safety inspections, convert the TMC into a price index.

[123] Under the existing electricity market system, the Government of Ontario is able to allocate to electricity customers as a whole whatever energy-related costs it considers should be borne by such customers. From the perspective of the Applicants, it would appear that the inclusion of additional costs to be borne by electricity customers pursuant to a government mandate is not adverse, as the effect is to increase TMC. As a conceptual matter, therefore, TMC is understood to comprise all energy-related costs that are intended to be recovered from electricity customers, including but not limited to all of the costs associated with the generation and supply of electricity, just as the DCR included all such costs prior to the market opening. On this basis, I conclude that the inclusion of certain costs in TMC that are not directly related to the costs of the generation and supply of electricity does not necessarily imply that TMC must be interpreted to be a price index, as the OEFC suggests. I therefore think the inclusion of such costs in TMC is also a neutral factor.

Conclusion Regarding the Interpretation of TMC

[124] Based on the foregoing, I conclude that it is implicit in the definition of TMC that costs that are not by their nature capable of being passed on directly to purchasers of electricity must be aggregated and allocated to purchasers pro rata based on purchases or consumption of electricity relative to purchases or consumption by all customers.

Application to the OEFC Calculation of GA Under the Reallocation Regulation

[125] Given the foregoing interpretation of the definition of TMC, I turn to the application of the definition in the present circumstances. I conclude that the OEFC calculation of TMC under the Reallocation Regulation is not compatible with TMC as defined in the Term Sheets for the following reason.

[126] The definition of TMC mandates an aggregation of the costs of generating and supplying electricity that is delivered to the Proxy Customer. The cost of GA is a permissible cost as it reflects, or constitutes, a cost of electricity generation. However, the cost of GA to Class A Customers, as calculated by Navigant, is determined on the basis of an allocation that is not pro rata according to electricity purchases as required by the definition of TMC. As such, TMC, as calculated by Navigant, reflects a reallocation of GA costs as between Class A Customers and Class B Customers, rather than an allocation of the underlying costs of generation in the manner that is required by the definition of TMC.

[127] I therefore conclude that the manner of calculating TMC applied by OEFC since the enactment of the Reallocation Regulation contravenes the definition of TMC and, accordingly, contravenes the PPAs.

Conclusion

[128] Given the foregoing conclusion, it is not necessary to address the alternative arguments of the Applicants that OEFC has breached the "change of law" provisions and/or the "material change" provisions of the Term Sheets. However, I have the following conclusions regarding the operation of these provisions in case it is necessary to address their application.

The Operation of the Change of Law Provisions

[129] As mentioned, seven of the Term Sheets contain a “change of law” provision substantially in the following form (herein, a “Change of Law provision”):

The parties recognize that changes in law, regulations and/or market rules (in any case, a “Change of Law”) will occur from time to time and may result in changes to the items comprising Total Market Cost. In such circumstances, the underlying philosophy and definition of DCR will be maintained in order to preserve the original economic effect of Total Market Cost. A Change of Law does not include changes in the amounts or rates of those items comprising Total Market Cost. The calculation of Total Market Cost will be amended as a result of any such Changes in Law to ensure that it continues to reflect the cost of uninterruptible power at 100% load factor to wholesale market participant industrial customers at the relevant voltage. In making any adjustments to the items comprising Total Market Cost as a result of a Change of Law, OEFC will not act arbitrarily and will undertake industry consultations. It is anticipated that the implications of any Change of Law will be dealt with by OEFC on a contract by contract basis. This Change of Law provision is not intended to affect any other provisions herein or in the PPA dealing with change of law matters. For further clarity, all other terms of the PPA, other than those dealing with Total Market Cost, shall not be subject to the Change of Law provisions.

Positions of the Parties

[130] The seven Applicants whose Term Sheets contain Change of Law provisions argue that the enactment of the Reallocation Regulation did not constitute a change in “regulations” that triggered this provision in their respective Term Sheets. On this basis, they argue that, for the reasons set out above, OEFC is required to continue to calculate TMC as it did prior to the Reallocation Regulation and that it breached the PPAs in implementing Navigant's calculation of the GA component of TMC using the New Formula.

[131] In the alternative, however, these Applicants argue that, if the Change of Law provisions in their respective Term Sheets were triggered by enactment of the Reallocation Regulation, OEFC failed to comply with the requirement that, in implementing its calculation of the GA component of TMC, the underlying philosophy and definition of DCR was to be maintained in order to preserve the original economic effect of TMC. As mentioned, these Applicants say that DCR was a cost-based index designed to protect the Applicants from industry-wide cost increases. They argue that the manner of calculation of the GA component included in TMC after the Reallocation Regulation does not reflect any relationship to the cost of generating and delivering electricity. They argue that, for this reason, the change in the calculation of TMC fails to maintain the underlying philosophy and definition of DCR and thereby the original economic effect of TMC.

[132] OEFC also argues that the Change of Law provisions were not triggered on the basis that there was no change to the items comprising TMC, only a change to the amount or rate of an item comprising TMC, which is expressly excluded. OEFC submits that, on this basis, nothing prevents the calculation of the GA component of TMC in the manner performed by Navigant.

[133] In the alternative, if the Change of Law provisions have been triggered, OEFC relies on the evidence of Williams described above as evidence that it has satisfied the requirements of the provisions including, in particular, maintenance of the underlying philosophy and definition of DCR.

Analysis and Conclusions

[134] I agree with both the Applicants and OEFC that the Reallocation Regulation did not trigger the Change of Law provisions in the relevant Term Sheets.

[135] The parties have included a GA component in TMC since 2005. The Reallocation Regulation did not amend the definition of GA or the quantification of the aggregate GA charge to be allocated among all customers in the electricity market. The effect of the Reallocation Regulation was limited to amending the allocation of GA among customers in the electricity market. This constituted a change to the “amounts or rates” of an item already comprising TMC, which was expressly excluded from the Change of Law provisions, rather than a “change to the items comprising TMC”.

[136] I do not agree, however, with the position of OEFC that, in the absence of an event that engages the Change of Law provisions, there was no restriction on its ability to incorporate a change to the allocation of GA into the determination of TMC after the Reallocation Regulation. OEFC remained obligated under the Term Sheets to comply with the definition of TMC in making any such change. As discussed above, I conclude that the calculation of the GA component of TMC in accordance with the New Formula is inconsistent with the intention of the parties with respect to the calculation of TMC.

[137] In addition, if it were necessary to address the operation of the Change of Law clauses on the basis that the enactment of the Reallocation Regulation triggered such provisions, I would conclude, for the reasons set out above, that in calculating the GA component of TMC by application of the New Formula, OEFC failed to maintain the underlying philosophy and definition of DCR and thereby failed to preserve the original economic effect of TMC.

The Operation of the Material Change Provisions

[138] As mentioned, five of the Term Sheets contain material change provisions to the following effect (herein a “Material Change provision”):

Any material changes to the description of [either DCRnew or TMC] as set out in the draft IPPSO-OEFC working paper described above will require final agreement by [the relevant Applicant] and OEFC, and the terms set out herein are conditional upon such mutual agreement.

The Positions of the Parties

[139] The Applicants whose Term Sheets contain Material Change provisions argue that the Material Change provisions, in either form, were triggered by the Reallocation Regulation. They submit that OEFC failed to obtain the agreement of the Applicants who were parties to such Term Sheets and, as such, the rates payable to such Applicants under the PPAs between these Applicants and OEFC, being based on an invalid calculation of TMC using the New Formula in respect of the GA component of TMC, are also necessarily invalid.

[140] For this purpose, the Applicants say that the reference in the Material Change provisions of the relevant Term Sheets to the “description” of DCRnew/TMC is intended to be broader than the statement of the definition of TMC alone in the Working Paper. They suggest that the description of DCRnew/TMC includes all of the text of the Working Paper commencing with the text under the heading "Development of Replacement Definition for DCR", excluding for clarity the appendices to the Working Paper. This view also incorporates the Change in Law provisions as described in the Working Paper.

[141] The Applicants say that, because each Term Sheet has a “no waiver” provision, OEFC cannot assert that a failure of the Applicants to respond prior to March 31, 2011 to OEFC's letter of March 2, 2011, which formally notified the Applicants of the change of calculation of TMC effective January 1, 2011 and requested any comments by March 31, 2012, is of no consequence. They say that OEFC's implementation of the New Formula to calculate the GA component of TMC constituted a unilateral change to the description of DCRnew/TMC. Accordingly, they say that, absent the agreement of the five Applicants involved, such Applicants are entitled to insist on the continued calculation of TMC in the manner conducted by Navigant prior to the coming into effect of the Reallocation Regulation.

[142] OEFC takes a narrower view of the descriptions of TMC and DCRnew in the Working Paper. It submits that the description of TMC is limited to the definition of TMC on page 7 thereof or, alternatively, to the text under the sub-heading “Definition” on pages 7 and 8 thereof. On this basis, it says the Reallocation Regulation did not change the definition of TMC, as GA had been included as a component of TMC since 2005.

[143] Similarly, OEFC says that the description of DCRnew has not changed. OEFC submits that the description of DCRnew is limited to the description of “Final DCRnew (P)” on page 8 of the Working Paper. OEFC submits that there has been no change in the description of DCRnew on the same reasoning as described above in respect of TMC.

Analysis and Conclusions

[144] I conclude that the parties intended the description of TMC in the Working Paper to refer to the text on pages 7 and 8 to the end of enumeration of the items to be included in TMC upon market opening for PPAs referencing DCR at 44kV or lower voltage.

[145] This is clear principally from the statement on page 6 that the "detailed description below sets out the scope of items included at market opening". This language necessarily limits the description of TMC to the relevant passages following such statement. There is also no language elsewhere in the Working Paper that supports the more inclusive approach of the Applicants. However, it is also clear from this statement that the description of TMC, as opposed to the definition of TMC, includes the description on page 7 of the items included in TMC at market opening. On this basis, I think the enumeration of the components of TMC on market opening is included in the "description" of TMC.

[146] I further conclude that the “description” of DCRnew includes the two expressions of the definition of Final DCRnew (P) on page 9 and the description of TMC on pages 7 and 8 as determined above. This result follows from the fact that the definition of DCRnew includes TMC as a component. As such, the "description" of DCRnew must necessarily extend to the description of TMC that precedes the definition of DCRnew.

[147] OEFC does not challenge the Applicants’ position that the effect of the change in the calculation of the GA component of TMC is material to the Applicants whose Term Sheets contain Material Change provisions. The issue for the Court is whether the Reallocation Regulation resulted in a material change to the description of TMC or DCRnew, as applicable, for the purposes of the Material Change provisions.

[148] I agree with OEFC that it did not for the same reasons that it did not trigger the Change of Law provisions in the other Term Sheets. GA had already been added to the components of TMC as described in the Working Paper. The “description” of TMC does not address any issues of allocation in respect of the components of TMC. In respect of DCRnew, there is clearly no material change in the definition of DCRnew. There is also no material change to the extent the description of DCRnew also incorporates TMC for the reasons set out herein.

[149] In these circumstances, it is therefore unnecessary to address whether OEFC's communications with the five Applicants whose Term Sheets contain Material Change provisions satisfied its obligations to obtain the “final agreement” of such parties. I therefore decline to address this issue.

[150] In this regard, however, OEFC argued that the description of TMC could not have been intended to include the description of the components of TMC as it would provide these five Applicants with a veto on any changes to TMC. While I do not propose to address this issue, I note that the determination above regarding the content of the “description” of TMC and DCRnew does not imply that any change to the components of TMC requires the agreement of the relevant Applicants. As I understand the description of TMC, it speaks only to the components of TMC at market opening, which has passed. In my view, the extent to which OEFC requires the agreement of the Applicants whose Term Sheets have a Material Change provision to a change to the components of TMC, or conversely the extent to which such Applicants have a veto over any such change, is not clearly expressed. It would, however, be reasonable to interpret such clause in line with the general principles of preservation of the underlying philosophy and definition of DCR as in the Change of Law provisions in the remaining Term Sheets, in addition to any obligation to act reasonably that might be implied in the exercise of rights under the Material Change provisions.

Conclusion

[151] Based on the foregoing, the Applicants are entitled to a declaration that the calculation of TMC used by OEFC to determine the amounts payable to the Applicants under their respective PPAs from and after January 1, 2011 does not comply with the PPAs. The Applicants are further entitled to an order requiring OEFC to calculate TMC from January 1, 2011 in the manner TMC was calculated prior to the coming into force of the Reallocation Regulation and to pay the Applicants an amount sufficient to compensate them for the difference between such amount and the amount previously calculated by OEFC, plus interest in accordance with the Courts of Justice Act.

Costs

[152] If the parties are unable to agree on costs, the Applicants shall have thirty days to submit costs submissions not exceeding five pages in length, including costs outlines in accordance with the Rules of Civil Procedure, and OEFC shall have a further thirty days to submit any costs submission and costs outline it may choose to deliver in response.

Wilton-Siegel J.

Released: March 12, 2015

SCHEDULE "A"

Court File #

Non-Utility Generator/Applicant

Facility

Date of PPA

CV-12-9953

N-R Power and Energy Corporation, Algonquin Power (Long Sault) Partnership and N-R Power Partnership

Long Sault

March 30, 1994

CV-12-9954

Kirkland Lake Power Corporation

Kirkland Lake

Oct. 10, 1989

CV-12-9955

Cochrane Power Corporation

Cochrane

Sept. 9, 1992

CV-12-9956

Iroquois Falls Power Corporation

Iroquois Falls

Feb. 11, 1994

CV-12-9957

MPT Hydro L.P.

Wawatay Dryden

April 1, 1992 Oct. 23, 1990

CV-12-9957

Cardinal Power of Canada

Cardinal

May 29, 1992

CV-12-9958

Serpent River Power Corporation (subsequently amended and assigned to Beaver Power Corporation )

Serpent River

June 26, 1989

CV-12-9958

Cameron Falls Power Corporation (subsequently amended and assigned to Beaver Power Corporation)

Cameron Falls

June 26, 1989

CV-12-9958

Carmichael Limited Partnership

Carmichael

April 1, 1992

CV-12-9958

Lake Superior Power Limited Partnership

Lake Superior

May 29, 1992

CV-12-9958

Algonquin Power (Nagamami) Limited Partnership

Nagamami

July 2, 1993

SCHEDULE "B"

The following table sets out the definitions of the DCR or the DCC in the PPAs, as applicable, of the Applicants:

Facility

Index

Definition of DCC or DCR

Cochrane

DCC

“the calculated rate charged by Hydro to its direct customers for supply of 115 kV firm power, assuming a 100% capacity factor, expressed in dollars per kilowatt-hour.”

Iroquois Falls

DCR

“the calculated rate that would be charged by Hydro to its direct customers for supply of 230 kV, assuming a 100% capacity factor.”

Kirkland Lake

DCC

“the calculated rate charged by Hydro to its direct customers for supply of 115kV firm power, assuming a 100% capacity factor, expressed in dollars per kilowatt-hour.”

Long Sault

DCC

“the calculated rate that would be charged by Hydro to its direct customers for the supply of 115 kV of firm power, assuming a 100% capacity factor, expressed in dollars per kilowatt hour.”

Lake Superior

DCR

“[rate] means in a subject year the calculated rate that would be charged by Hydro to its direct customers for supply of 115 kV firm power, assuming a 100% capacity factor, expressed in dollars per kilowatt-hour ($/kWh)”

Serpent River

DCR

“the four Time of Delivery Period rates expressed in cents per kilowatt hour applicable to direct customer purchases from Ontario Hydro for 115 kV firm Power at 100% load factor.”

Cameron Falls

DCR

“the four Time of Delivery Period rates expressed in cents per kilowatt hour applicable to direct customer purchases from Ontario Hydro for 115 kV firm Power at 100% load factor.”

Carmichael

DCR

“[rate] charged by Hydro to its direct customers for supply of 115 kV firm power, at 100% capacity factor.”

Nagamami

DCR

“[rate] means, for any Year a rate expressed in dollars per kilowatt hour applicable to direct customer purchases from Ontario Hydro for 115 kV firm Power at 100% load factor in effect during such Year…”

Cardinal

DCC

“…in a subject Year the calculated rate that would be charged by Hydro to its direct customers for supply of 115 kV firm power, assuming a 100% capacity factor, expressed in dollars per kilowatt-hour…”

Wawatay

DCR

“…for any Year, a rate expressed in dollars per kilowatt hour applicable to direct customer purchases from Ontario Hydro for 115 kV firm Power at 100% load factor in effect during such Year and calculated as set out in paragraph 19 of Schedule “A”.”

Dryden

DCR

“…means the four Time of Delivery Period rates expressed in cents per kilowatt hour applicable to direct customer purchases from Ontario Hydro for 115 kV firm Power at 100% load factor.”

CITATION: N-R Power and Energy Corporation v. Ontario Electricity Financial Corporation, 2015 ONSC 1641

COURT FILE NO.: Court File No. CV-12-9953-00CL

COURT FILE NO.: CV-12-9954-00CL

COURT FILE NO.: CV- CV-12-9955-00CL

COURT FILE NO.: CV- CV-12-9956-00CL

COURT FILE NO.: CV- CV-12-9957-00CL

COURT FILE NO.: CV- CV-12-9958-00CL

DATE: 20150312

ONTARIO

SUPERIOR COURT OF JUSTICE

BETWEEN:

N-R POWER AND ENERGY CORPORATION, ALGONQUIN POWER (LONG SAULT) AND N-R POWER PARTNERSHIP

KIRKLAND LAKE POWER CORPORATION

COCHRANE POWER CORPORATION

IROQUOIS FALLS POWER CORPORATION

CARDINAL POWER OF CANADA, L.P. AND MPT HYRDO L.P.

LAKE SUPERIOR POWER LIMITED PARTNERSHIP, BEAVER POWER CORPORATION, CARMICHAEL LIMITED PARTNERSHIP AND ALGONQUIN POWER (NAGAMAMI) LIMITED PARTNERSHIP

Applicants

– and –

ONTARIO ELECTRICITY FINANCIAL CORPORATION

Respondent

REASONS FOR JUDGMENT

Wilton-Siegel J.

Released: March 12, 2015