ENMAX Power Corporation

Transcription

1 Decision D Interim Distribution Access Service Rates December 22, 2016

2 Alberta Utilities Commission Decision D Interim Distribution Access Service Rates Proceeding December 22, 2016 Published by The Alberta Utilities Commission Fifth Avenue Place, Fourth Floor, 425 First Street S.W. Calgary, Alberta T2P 3L8 Telephone: Fax: Website:

3 Contents 1 Introduction Details of the application Basis for the calculation of ENMAX s proposed 2017 interim DAS rates Test to support interim tariff applications Issues and Commission findings Order... 9 Appendix 1 Proceeding participants Appendix interim distribution access service rates Appendix 3 Inflation indexes used in the 2017 I factor calculation List of tables Table interim DAS revenue... 5 Table 2. Typical customer bill impacts total charges... 7 i

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5 Alberta Utilities Commission Calgary, Alberta Decision D Interim Distribution Access Service Rates Proceeding Introduction 1. On September 23, 2016, (ENMAX or EPC) submitted an application 1 to the Alberta Utilities Commission, requesting approval for its 2017 distribution access service (DAS) rates. ENMAX requested that the DAS rate be effective January 1, 2017, on an interim basis, as set out in Appendix A 2 and Appendix B 3 to the application. 2. On September 27, 2016, the Commission issued a notice of application that required interested parties to file a statement of intent to participate (SIP) by October 4, In the SIPs, parties were to indicate whether they supported or objected to the application, state reasons for their position, and identify any perceived need for further process, along with supporting rationale. The Commission received SIPs by the specified deadline from the Consumers Coalition of Alberta (CCA) and the Office of the Utilities Consumer Advocate (UCA). 3. After reviewing the application and the SIPs, the Commission determined that the application would be considered by way of a basic written process, as outlined in Commission Bulletin , 4 and on October 6, 2016, issued the following schedule for this proceeding: 5 Process step Due date Information requests (IRs) to ENMAX October 20, 2016 IR responses from ENMAX November 3, 2016 Submissions on the need for further process November 7, 2016 Argument (if required) November 10, 2016 Reply argument (if required) November 18, On November 7, 2016 and November 8, 2016, respectively, the Commission received letters from the CCA and the UCA regarding further process. Both parties advised that they did not oppose the application and would not be filing argument or reply argument. 5. On December 15, 2016, ENMAX filed a revised set of supporting schedules to the application. 6 ENMAX stated that it had discovered a minor error in the transmission system access service (SAS) variable charge in Schedule 8.2. The error affects the Small Commercial D200 typical bill comparison. ENMAX also advised that the rates in Appendix B EPC Distribution Tariff Rate Schedule are correct. ENMAX submitted that the nature of the error Exhibit X0003, application. Exhibit X0002, application, Appendix A, supporting schedules to the application, replaced by Exhibit X Exhibit X0001, application, Appendix B, Distribution Tariff Rate Schedule. Bulletin , Performance standards for processing rate-related applications, March 26, Exhibit X0010, AUC letter - Process and schedule. Exhibit X , application, Appendix A, supporting schedules to the application and cover letter. 1

6 does not in any way impact the interim distribution rates proposed in the application and should not cause a delay in the proceeding. 6. The Commission considers the record for this proceeding to have closed on December 15, 2016, when a revised set of supporting schedules to the application was filed. 7. In reaching the determinations set out within this decision, the Commission has considered all relevant materials comprising the record of this proceeding. Accordingly, references in this decision to specific parts of the record are intended to assist the reader in understanding the Commission s reasoning relating to a particular matter and should not be taken as an indication that the Commission did not consider all relevant portions of the record with respect to a particular matter. 2 Details of the application 8. ENMAX s current DAS rates were approved on an interim basis in Decision and have been in place, on an interim basis, since January 1, Basis for the calculation of ENMAX s proposed 2017 interim DAS rates 9. ENMAX determined its proposed 2017 revenues and 2017 interim DAS rates based on the Commission s approvals in Decision D , 8 Decision D , 9 as well as the applied-for amounts in ENMAX s capital tracker application, 10 and ENMAX s 2017 billing determinant forecast. 11 Specifically, ENMAX used the 2014 DAS rates approved in Decision D as the starting point and applied the performance-based regulation (PBR) parameters and going-in rate adjustment approved in Decision D to determine PBR DAS base rates for 2015, 2016 and ENMAX then applied its billing determinant forecast to the 2017 PBR DAS base rates to determine its projected 2017 DAS revenue amounts. Since ENMAX s DAS revenues were based on 2015 and 2016 interim DAS rates (as opposed to PBR DAS base rates), ENMAX then determined the revenue shortfall that resulted from using the interim rates in 2015 and ENMAX then applied an adjustment to the 2017 interim DAS revenue to collect 60 per cent of the revenue shortfall from 2015 and Finally, ENMAX adjusted the 2017 revenue amount to include 60 per cent of its applied for total capital tracker amounts for the years 2015, 2016 and The resulting projected 2017 revenue requirement was then used to determine the proposed 2017 interim rates, as further discussed below. 10. In Decision D , the Commission approved a negotiated settlement agreement (NSA) filed by ENMAX. The NSA included the PBR formula upon which ENMAX s Decision :, 2015 Interim Distribution and Transmission Tariff Application, Proceeding 3433, Application , November 12, Decision D :, Decision on Request for Review of Decision D Phase I Distribution Tariff and Transmission General Tariff Compliance Filing, Proceeding 20819, November 27, Decision D (Errata): Distribution, Performance-Based Regulation Negotiated Settlement Application and Interim X Factor, Proceeding 21149, October 3, Proceeding 21508, - Distribution capital tracker application. Exhibit X , application, Appendix A, supporting schedules to the application, Schedule 3. 2

7 DAS rates are to be based for Specifically, as set out in Term 3 of the NSA, the PBR formula is based on the formula approved by the Commission in Decision : Rt = BRt-1(1 + (I - X)) +/- Z +/- K +/- Y Where: Rt = upcoming year s rates for each class BRt-1 = current year s base rates for each class 13 I = inflation factor X = productivity factor Z = exogenous adjustments K = capital tracker amounts collected through K factor rate adjustments Y = flow-through items, collected through Y factor rate adjustments (not including Y factors collected through separate riders) 12. With respect to the I factor, ENMAX also based the formula on a weighted average formula using the Alberta average weekly earnings (AWE) index and the Alberta consumer price index (CPI) index, approved by the Commission in Decision , and as set out in Term 6 of the NSA: It = 55% x AWEt % x CPIt-1 Where: It = I factor for the following year AWEt-1 = Alberta Average Weekly Earnings Index (Statistics Canada Table , data vector v ) for the previous July through June period CPIt-1 = Alberta Consumer Price Index (Statistics Canada Table , data vector v ) for the previous July through June period 13. The signatories to the NSA also agreed, in Term 4, that ENMAX would adjust the 2014 DAS rates to effectively eliminate the unfavourable billing determinant variance experienced in 2014 for the year 2015 and forward, to reflect actual rather than forecast 2014 billing determinants, in order to remove any embedded 2014 DAS volume risk for the PBR term. This adjustment resulted in a $3.0 million adjustment to the PBR DAS base rates In Decision D , the Commission also approved an interim X factor of 0.8 for ENMAX to use in its DAS rates for 2015 through 2017, with the direction that the final X factor for the ENMAX PBR plan would be determined in Proceeding dealing with the parameters of the next generation PBR plans ENMAX calculated a 2017 I factor of negative 0.75, as opposed to the negative 0.76 per cent that has been calculated and applied for by the other distribution utilities in their 2017 annual PBR rate adjustment proceedings. 16 In response to a Commission IR, ENMAX confirmed Decision : Rate Regulation Initiative Distribution Performance-Based Regulation, Proceeding 566, Application , September 12, The ENMAX application had a typographical error in its formula which the Commission has corrected. Exhibit X0003, application, paragraphs 4-11; Exhibit X , application, Appendix A, supporting schedules to the application. Decision D (Errata), paragraph 53. Proceedings 21592, 21978, 21980, and

8 that it followed the methodology from paragraphs 248 and 249 of Decision to calculate the 2017 I factor. ENMAX stated: EPC has followed the methodology approved for the other regulated distribution facility owners ( DFOs ) under PBR but has applied the most recent data from Statistics Canada for the calculation of the I factor in its PBR Application instead of the unrevised July 2012 to June 2013 figures used by the other DFOs. EPC calculated its 2016 I-Factor of 2.06% based on data accessed from Statistics Canada on October 30, In Term 6 of the NSA, the signatories agreed to I factors for 2015 and 2016 of 2.92 per cent and 2.06 per cent, respectively. 17. Because ENMAX collected DAS revenues based on 2015 and 2016 interim DAS rates rather than PBR DAS base rates, ENMAX proposed to include in the 2017 interim DAS rates an adjustment to collect 60 per cent of the true-up between the two resulting revenue amounts. The total true-up amount is $1.41 million and ENMAX proposed an adjustment of 60 per cent or $0.84 million for this application In ENMAX s capital tracker application, it proposed K factors of $7.02 million, $16.44 million and $27.46 million for 2015, 2016 and 2017, respectively, for a total of $50.92 million. Similar to the 60 per cent adjustment used in the DAS revenue true-up described above, ENMAX proposed to include 60 per cent of the proposed K factors, or $30.55 million, in the 2017 interim DAS rates ENMAX did not seek approval for any Y factors in this application. In response to a Commission IR asking when and how ENMAX plans to address Y factors and its line loss reduction program, ENMAX responded that it intends to submit a filing after receiving a decision on its capital tracker application Based on the above, ENMAX s proposed 2017 interim DAS revenue is $ million, as summarized in Table 1 below Exhibit X0014, EPC-AUC-2016OCT20-002(a). Exhibit X0003, application, paragraph 13. Exhibit X0003, application, paragraph 16. Exhibit X0014, ENMAX-AUC-2016OCT

9 Table interim DAS revenue ($ million) 2017 PBR DAS base rate revenue forecast % of DAS revenue true-up % of K factors Total Source: Exhibit X0003, application, Table The CCA filed IRs on the application, and after reviewing the information on the record of the proceeding, both interveners submitted that they did not oppose the application and would not be filing argument or reply argument Test to support interim tariff applications 22. The Commission s predecessor, the Alberta Energy and Utilities Board, adopted a twopart test for evaluating interim rate applications. The test has since been used by the Commission. The two-part test is as follows: The first part of the test relates to quantum and need, and includes the following considerations: (i) Is the identified revenue deficiency probable and material? (ii) Can all or some portion of any contentious items be excluded from the amount collected? (iii) Is the increase required to preserve the financial integrity of the applicant or to avoid financial hardship to the applicant? (iv) Can the applicant continue safe utility operations without the interim adjustment? The second part of the test relates to the public interest and includes the following considerations: (i) Will the interim rates promote rate stability and ease rate shock? (ii) Will the interim adjustments help to maintain intergenerational equity? (iii) Can the interim rate increases be avoided through the use of carrying costs? (iv) Are the interim rate increases required to provide appropriate price signals to customers? (v) Is it appropriate to apply the interim rider on an across-the-board basis? 25 3 Issues and Commission findings 23. When evaluating the merits of an interim rate application, the Commission typically applies the above-stated two-part test. However, in its application, ENMAX has not proposed to Exhibit X0003, application, sections 2.1 and 2.2; Exhibit X , application, Appendix A, supporting schedules to the application, Schedule 6.0. Exhibit X , application, Appendix A, supporting schedules to the application, schedules 1.0, 3.0 and 5.0. Exhibit X , application, Appendix A, supporting schedules to the application, schedules 1.0 and 4.0. Exhibits X0018 and X0019. Exhibit X0003, application, paragraphs

10 rely on that test. Regardless, the Commission considers the two-part test to be useful in assessing ENMAX s proposed 2017 interim DAS rates. The two-part test weighs the benefits of rate stability, the minimization of rate shock and the potential for intergenerational inequity that might result on approval of final rates, against the costs that underpin the interim rate increase, whether they be contentious or non-contentious items, the impact the revenue deficiency has on the financial welfare of the utility, and the potential impact on safe utility operations. 24. The above-listed considerations in the two-part test may be given different weighting depending on the specific circumstances of each application. The Commission has evaluated ENMAX s application with these considerations in mind. 25. ENMAX s 2017 I factor of negative 0.75 per cent is different than the 2017 I factor of negative 0.76 per cent that has been applied for by the other regulated distribution facility owners. The Commission has determined that this is due to the periodic revision of inflation indexes by Statistics Canada, and the fact that ENMAX calculated its 2017 I factor based on data accessed from Statistics Canada on a different date than the other regulated distribution facility owners for the July 2014 to June 2015 period The Commission finds ENMAX s I factor calculations to be both reasonable and consistent with the formula and methodology set out in the NSA and Decision The Commission has also verified the Statistics Canada data used by ENMAX. Therefore, the Commission approves the 2017 I factor of negative 0.75 per cent calculated by ENMAX. 27. ENMAX is reminded that, in accordance with the Commission s direction at paragraph 249 of Decision , the Alberta AWE and Alberta CPI values from July 2015 to June 2016 that were filed in this proceeding should be used, unrevised, as the basis for the next year s inflation factor calculation. For convenience, these values are provided in Appendix 3 to this decision. 28. The Commission has reviewed the 2017 interim DAS rate calculations included in the application and the supporting schedules to the application and is satisfied that they are accurate. The Commission notes that ENMAX s 2017 interim DAS rate calculation methodology uses an across-the-board methodology that maintains the currently approved rate structure based on ENMAX s last approved Phase II cost-of-service study, and that has been previously approved by the Commission, most recently in Decision With respect to the billing determinant forecast, in its PBR application 27 and reaffirmed in its capital tracker application, 28 ENMAX has proposed that the billing determinant forecast be tested in its capital tracker proceeding. The Commission agrees that the capital tracker proceeding is the correct forum to assess ENMAX s proposed billing determinants and, accordingly, approves the proposed billing determinants, on a placeholder basis, for the purposes of this decision. 30. ENMAX is seeking a 2017 revenue of $ million in this interim rate application and has used this forecast revenue to underpin the applied-for interim base rates. The Commission has estimated, based on the information provided by ENMAX, a shortfall in revenue collection ENMAX accessed the data from Statistics Canada on October 30, 2015, whereas the other regulated distribution facility owners accessed the data from Statistics Canada, pertaining to the same period, in August Proceeding 21149, Exhibit X0005, paragraph 131. Proceeding 21508, Exhibit X0029, paragraph 88. 6

11 of approximately $21 million. This is based on the Commission s comparison of the 60 per cent collection applied for by ENMAX against a theoretical 100 per cent collection of the difference between its 2015 and 2016 interim DAS rates and its PBR DAS base rates, and its forecast capital tracker amounts. The Commission also notes that it has been two full years since ENMAX has had an adjustment to its rates. In light of the above, the Commission considers that to award any less than the requested 60 per cent interim recovery rate would have potential impact on the financial welfare and the safe operation of the utility. 31. To understand the impact of ENMAX s proposed interim rate increases on typical customer bills, the Commission has reviewed the bill comparison submitted by ENMAX in this proceeding and in Proceeding dealing with ENMAX s first quarter 2017 Alberta Electric System Operator demand transmission service (Q AESO DTS) rider request. 29 In that proceeding, ENMAX advised that it applied the carry-forward provision, approved at paragraph 40 in Decision , 30 to five rate classes, D100, D200, D300, D310 and D410, so that the total bill impact is limited to 10 per cent for each rate class. 31 The carry-forward provision is applied when the proposed quarterly rider causes a customer bill impact to exceed the ±10 per cent range for a given rate class on a total bill basis, generally considered by the Commission to constitute rate shock. The amounts in excess of 10 per cent are then carried forward to either the subsequent quarter or other future period that allows for these amounts to be collected or refunded without causing rate shock. The Commission has used the bill comparison information from Proceeding to prepare Table 2 below. Table 2. Typical customer bill impacts total charges 32 Rate class description Usage A B C D Current 2016 interim (December 1, 2016) Bill change (B-A) Bill change (B/A)-1 Proposed January 1, 2017 interim December 1, 2016 vs. January 1, 2017 December 1, 2016 vs. January 1, 2017 ($) (%) Residential rate D100 Typical Small Commercial rate D200 Typical Medium Commercial rate D300 Typical , Large Commercial - secondary rate D310 Typical 23, , , Large Commercial - primary rate D410 Typical 58, , , Street lighting rate D500 Typical Source: Exhibit X0008, application, Appendix 2, typical bill schedules, schedules 1.0 to The Commission has reviewed the typical bill impacts from December 2016 to January 2017, as provided by ENMAX in this application and in Proceeding 22265, in assessing the likelihood of rate shock resulting from the proposed 2017 PBR rates. As shown in Table 2, Exhibit X0008, application, Appendix 2, typical bill schedules, schedules 1.0 to 7.0. Decision : Commission-Initiated Review Electric Transmission Access Charge Deferral Accounts Quarterly Applications, Proceeding 3334, Application , December 2, Exhibit X0001, paragraph 18. Includes DAS, system access service, riders, retail and municipal charges. 7

12 customer rate classes will experience rate increases of 10.0 per cent or less. The Commission finds that, including the application of the carry-forward provision for the Q AESO DTS rider, the impacts to rate classes fall within a reasonable range and are not expected to cause rate shock. 33. Given the magnitude of ENMAX s potential revenue shortfall and in order to smooth out the rate impacts to customers bills, the Commission considers that some degree of interim rate adjustment should be made. The Commission is aware that any financial hardship to ENMAX could be mitigated by the award of carrying costs; however, it would not mitigate the risk of potential rate shock to customers. The Commission finds that approval of an interim increase to ENMAX s DAS rates will provide a gradual and stable transition to ENMAX s final 2017 distribution rates. 34. In determining the reasonableness of the requested increases, the Commission notes that it received no objection from interveners in this proceeding. Further, because the proposed rate increases are requested on an interim basis, rates will be trued up once the final 2017 DAS rates are approved. The Commission finds that ENMAX has included, in its proposed 2017 interim DAS rates, the approved ENMAX interim X factor and an I factor based on the Commission s approved methodology. Further, the Commission finds that the collection of 60 per cent of the DAS revenue true-up and of the proposed K factors is sufficient to account for any potentially contentious elements of those amounts in future proceedings. 35. The Commission also considers that applying the interim distribution rate increase to all rate classes on an across-the-board basis continues to be a reasonable method that is simple and cost effective to apply, and preserves the currently approved rate structure based on ENMAX s last approved Phase II cost-of-service study. 36. Accordingly, the Commission finds that the proposed 2017 interim DAS rates achieve a reasonable balance among the considerations in the two-part test, including rate stability, minimization of rate shock, and the potential impact of the revenue deficiency on the financial welfare of the utility and safe utility operations. Consequently, the Commission approves the 2017 interim DAS rates as filed in the application, to be effective January 1, In approving the interim rates for ENMAX, the Commission is not making any finding or determination with respect to any of the matters in ENMAX s capital tracker application, which is currently pending before the Commission. 38. The Commission has attached Appendix 2 to this decision showing the 2017 interim DAS rates to be applicable on and after January 1, 2017, until replaced by subsequent decisions or orders of the Commission. 8

13 4 Order 39. It is hereby ordered that: (1) The interim distribution tariff rates schedules attached as Appendix 2 to this decision are approved, on an interim basis, effective January 1, Dated on December 22, Alberta Utilities Commission (original signed by) Bill Lyttle Commission Member 9

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15 Appendix 1 Proceeding participants Name of organization (abbreviation) Company name of counsel or representative (ENMAX or EPC) Office of the Utilities Consumer Advocate (UCA) Consumers Coalition of Alberta (UCA) Alberta Utilities Commission Commission Panel B. Lyttle, Commission Member Commission Staff E. von Engelbrechten (Commission counsel) P. Howard J. Bezuidenhout E. Deryabina A. Jukov A. Spurrell 11

16 Appendix interim distribution access service rates (return to text) Appendix interim DAS rates (consists of 19 pages) 12

17 Appendix 3 Inflation indexes used in the 2017 I factor calculation (return to text) Alberta CPI Alberta AWE Average Year over year CANSIM CANSIM July to June % change 2017 v v AB CPI AB AWE AB CPI AB AWE I factor Date (2002=100) $ July August September October November (2002=100) December January February March April May June July August September October November December January February March April May $ % % % June Source: July 2014 to June 2015 data: EPC-AUC-2016OCT20-002(b), attachment, tab I Factor. July 2015 to June 2016 data: Statistics Canada website ( accessed on September 12,

18 Page 1 of 19 ENMAX POWER CORPORATION ( EPC ) DISTRIBUTION TARIFF RATE SCHEDULE RATES IN EFFECT AS OF JANUARY 1, 2017

19 Page 2 of 19 EPC DISTRIBUTION TARIFF RATE SCHEDULE Rate Code Rate Description Page D100 Distribution Tariff Residential 3 D200 Distribution Tariff Small Commercial 5 D300 Distribution Tariff Medium Commercial 7 D310 Distribution Tariff Large Commercial Secondary 10 D410 Distribution Tariff Large Commercial Primary 12 D500 Distribution Tariff Streetlights 15 D600 Distribution Tariff Distributed Generation 16 D700 Distribution Tariff Transmission Connected 19 Distribution Tariff Effective January 1, 2017 Page 2 of 19

20 Page 3 of 19 DISTRIBUTION TARIFF RESIDENTIAL RATE CODE D100 Rate Schedule for the provision of Electricity Services to residential Customers of a Retailer. ELIGIBILITY 1. Sites which use Electricity Services for domestic purposes in separate and permanently metered single family dwelling units with each unit either metered separately or incorporated into a common building with other units. 2. As a single phase or three phase wire service supplied at a standard voltage normally available. 3. Sites eligible under 1 and 2 that qualify as a Micro-Generator under the Micro- Generation Regulation. RATE COMPONENT TYPE UNIT PRICE DISTRIBUTION CHARGE FOR DISTRIBUTION ACCESS SERVICE Service and Facilities Charge per day $ System Usage Charge per kwh $ TRANSMISSION CHARGE FOR SYSTEM ACCESS SERVICE Variable Charge per kwh $ INVOICE PERIOD Monthly, from the date of the last invoice to the date of the current invoice. Distribution Tariff Effective January 1, 2017 Page 3 of 19

21 Page 4 of 19 TERMS AND CONDITIONS The Terms and Conditions of the EPC Distribution Tariff form part of this Rate Schedule and apply to all Electricity Services supplied under this Tariff. OTHER 1. No more than one additional unit of living quarters within a single family dwelling, such as a basement suite equipped with cooking facilities, may be provided Electricity Services through one Meter under Rate Code D100. If the dwelling contains more than one additional self-contained unit of living quarters, a Commercial Rate will apply unless a separate Meter is installed for each unit. All new construction in R2 or higher density areas shall have a separate Meter for each suite, or alternatively the Electricity Services may be invoiced at the appropriate commercial rate. 2. If a Residential Site has a garage with a separate meter, the garage will be assigned a commercial rate. 3. If a Site qualifies as a Micro-Generator, rate charges will only apply to energy inflow into the Site (i.e. no outflow charges). LOCAL ACCESS FEE (LAF) The LAF is a surcharge imposed by the City of Calgary and is not approved by the Alberta Utilities Commission. The LAF is collected by EPC on behalf of the City for all Sites located within the municipal boundaries of the City of Calgary. Distribution Tariff Effective January 1, 2017 Page 4 of 19

22 Page 5 of 19 DISTRIBUTION TARIFF SMALL COMMERCIAL RATE CODE D200 Rate Schedule for the provision of Electricity Services to small commercial Customers of a Retailer. ELIGIBILITY 1. Commercial Sites where the Energy consumption is less than 5,000 kwh per month (includes all unmetered services that are not Rate Code D500). 2. Sites eligible under 1 that qualify as a Micro-Generator under the Micro- Generation Regulation. RATE COMPONENT TYPE UNIT PRICE DISTRIBUTION CHARGE FOR DISTRIBUTION ACCESS SERVICE Service and Facilities Charge per day $ System Usage Charge per kwh $ TRANSMISSION CHARGE FOR SYSTEM ACCESS SERVICE Variable Charge per kwh $ INVOICE PERIOD Monthly, from the date of the last invoice to the date of the current invoice. TERMS AND CONDITIONS The Terms and Conditions of the EPC Distribution Tariff form part of this Rate Schedule and apply to all Electricity Services supplied under this Tariff. Distribution Tariff Effective January 1, 2017 Page 5 of 19

23 Page 6 of 19 OTHER 1. Temporary Construction/Service Construction and rental costs for necessary transformers and equipment required for any temporary Electricity Services (whether single or three phase, or whether served from an overhead or underground source), shall be payable by the Customer to EPC in advance and based on an EPC estimate. Construction costs include costs associated with: (a) (b) (c) (d) up and down labour; unsalvageable material; vehicles; and equipment. 2. Temporary Connection Service Where applied-for Connection Services are to be used for temporary purposes only, the Customer will pay EPC, in advance of the installation: (a) (b) EPC s total cost of installation and removal of the Facilities required for the temporary service; and the cost of unsalvageable material. 3. Unmetered Services For unmetered services where individual energy consumption is small and easily predicted, estimated consumption will be based on equipment nameplate rating and operational patterns. 4. If a Site that qualifies as a Micro-Generator, rate charges will only apply to energy inflow into the Site (i.e. no outflow charges). LOCAL ACCESS FEE (LAF) The LAF is a surcharge imposed by the City of Calgary and is not approved by the Alberta Utilities Commission. The LAF is collected by EPC on behalf of the City for all Sites located within the municipal boundaries of the City of Calgary. Distribution Tariff Effective January 1, 2017 Page 6 of 19

24 Page 7 of 19 DISTRIBUTION TARIFF MEDIUM COMMERCIAL RATE CODE D300 Rate Schedule for the provision of Electricity Services to medium commercial Customers of a Retailer. ELIGIBILITY 1. For Sites whose Energy consumption is equal to or greater than 5,000 kwh per month for at least six of the last 12 invoice periods, provided a peak demand greater than 150 kva was not registered twice in the previous 365 days. 2. Sites eligible under 1 above that qualify as a Micro-Generator under the Micro- Generation Regulation. RATE COMPONENT TYPE UNIT PRICE DISTRIBUTION CHARGE FOR DISTRIBUTION ACCESS SERVICE Service Charge per day $ Facilities Charge per day per kva of Billing Demand $ System Usage Charge per kwh $ TRANSMISSION CHARGE FOR SYSTEM ACCESS SERVICE Demand Charge per day per kva of Billing Demand $ Variable Charge per kwh $ Where kva of Billing Demand is defined as the greater of Metered, Ratchet or Contract Demand: Distribution Tariff Effective January 1, 2017 Page 7 of 19

25 Page 8 of 19 (a) Metered Demand is the actual metered demand in the Tariff bill period; (b) Ratchet Demand is 90% of the highest kva demand in the last 365 days ending with the last day of the Tariff bill period; and (c) Contract Demand is the kva contracted for by the Customer. INVOICE PERIOD Monthly, from the date of the last invoice to the date of the current invoice. TERMS AND CONDITIONS The Terms and Conditions of the EPC Distribution Tariff form part of this Rate Schedule and apply to all Electricity Services supplied under this Tariff. OTHER 1. Non-Standard Residential Bulk-Metering. 2. Bulk Metering is the metering of multiple-unit residential occupancies under one corporate identity, (e.g., town housing, apartments, mobile home parks). Where bulk-metering exists, the Customer shall not re-sell electricity, but may include electricity as part of the rental charge and not separate therefrom. 3. Includes Medium Commercial Sites served at primary voltage that existed prior to November 2004 rate class changes. 4. If a Site qualifies as a Micro-Generator, rate charges will only apply to energy inflow into the Site (i.e. no outflow charges). 5. D300 Primary Voltage Service Customers a. For locations or buildings that receive primary voltage service, there will be a transformation credit of $ per day applied to the Service Charge, and a transformation credit of $ per day per kva of Billing Demand applied to the Facilities Charge. b. The transformation credit is applicable only to D300 sites receiving primary voltage service prior to January 1, Distribution Tariff Effective January 1, 2017 Page 8 of 19

26 Page 9 of 19 LOCAL ACCESS FEE (LAF) The LAF is a surcharge imposed by the City of Calgary and is not approved by the Alberta Utilities Commission. The LAF is collected by EPC on behalf of the City for all Sites located within the municipal boundaries of the City of Calgary. Distribution Tariff Effective January 1, 2017 Page 9 of 19

27 Page 10 of 19 DISTRIBUTION TARIFF LARGE COMMERCIAL - SECONDARY RATE CODE D310 Rate Schedule for the provision of Electricity Services to large commercial (secondary) Customers of a Retailer. ELIGIBILITY 1. For Electricity Services that registered a monthly peak demand greater than 150 kva twice in the previous 365 days and served at secondary voltage. 2. Sites eligible under 1 that qualify as a Micro-Generator under the Micro- Generation Regulation. RATE COMPONENT TYPE UNIT PRICE DISTRIBUTION CHARGE FOR DISTRIBUTION ACCESS SERVICE Service Charge per day $ Facilities Charge per day per kva of Billing Demand $ System Usage Charge On Peak System Usage Charge Off Peak per kwh $ per kwh $ TRANSMISSION CHARGE FOR SYSTEM ACCESS SERVICE Demand Charge per day per kva of Billing Demand $ Variable Charge On Peak per kwh $ Variable Charge Off per kwh $ Distribution Tariff Effective January 1, 2017 Page 10 of 19

28 Page 11 of 19 Peak Where kva of Billing Demand is defined as the greater of Metered, Ratchet or Contract Demand: (a) (b) Metered Demand is the actual metered demand in the Tariff bill period, Ratchet Demand is 90% of the highest kva demand in the last 365 days ending with the last day of the Tariff bill period, (c) Contract Demand is the kva contracted for by the Customer. On Peak is all Energy consumption from 8 a.m. to 9 p.m. Monday to Friday inclusive, excluding statutory holidays (as according to the ISO Rules definition), Off Peak is all Energy consumption not consumed in On Peak hours. INVOICE PERIOD Monthly, from the date of the last invoice to the date of the current invoice. TERMS AND CONDITIONS The Terms and Conditions of the EPC Distribution Tariff form part of this Rate Schedule and apply to all service supplied under this Tariff. OTHER If a Site qualifies as a Micro-Generator, rate charges will only apply to energy inflow into the Site (i.e. no outflow charges). LOCAL ACCESS FEE (LAF) The LAF is a surcharge imposed by the City of Calgary and is not approved by the Alberta Utilities Commission. The LAF is collected by EPC on behalf of the City for all Sites located within the municipal boundaries of the City of Calgary. Distribution Tariff Effective January 1, 2017 Page 11 of 19

29 Page 12 of 19 DISTRIBUTION TARIFF LARGE COMMERCIAL - PRIMARY RATE CODE D410 Rate Schedule for the provision of Electricity Services to large commercial (primary) Customers of a Retailer. ELIGIBILITY 1. For Electricity Services that are served at primary voltage. 2. Sites eligible under 1 above that qualify as a Micro-Generator under the Micro- Generation Regulation. RATE COMPONENT TYPE UNIT PRICE DISTRIBUTION CHARGE FOR DISTRIBUTION ACCESS SERVICE Service Charge per day $ Facilities Charge System Usage Charge per day per kva of f $ Billing Demand per kwh $ On Peak System Usage Charge per kwh $ Off Peak TRANSMISSION CHARGE FOR SYSTEM ACCESS SERVICE Demand Charge per day per kva of Billing Demand $ Variable Charge per kwh $ On Peak Distribution Tariff Effective January 1, 2017 Page 12 of 19

30 Page 13 of 19 Variable Charge per kwh $ Off Peak Where kva of Billing Demand is defined as the greater of Metered, Ratchet or Contract Demand: (a) (b) Metered Demand is the actual metered demand in the Tariff bill period, Ratchet Demand is 90% of the highest kva demand in the last 365 days ending with the last day of the Tariff bill period, (c) Contract Demand is the kva contracted for by the Customer, On Peak is all Energy consumption from 8 a.m. to 9 p.m. Monday to Friday inclusive, excluding statutory holidays (as according to the ISO Rules definition), Off Peak is all Energy consumption not consumed in On Peak hours. INVOICE PERIOD Monthly, from the date of the last invoice to the date of the current invoice. TERMS AND CONDITIONS The Terms and Conditions of the EPC Distribution Tariff form part of this Rate Schedule and apply to all Electricity Services supplied under this Tariff. OTHER 1. The Customer is responsible for supplying all transformers whether owned by Customer or rented. 2. Primary Metering shall be metering at EPC s primary distribution voltage with any subsequent transformation being the sole responsibility of the Customer. 3. Multi-Sites a) For Customers that have a normally used service connection (preferred service) and a second service connection used strictly as a backup service Distribution Tariff Effective January 1, 2017 Page 13 of 19

31 Page 14 of 19 (alternate service), the demands of the two service connections will be totaled on an interval basis and charged based on Rate Code D410. b) For Customers that use more than one service connection on a regular basis, demands of all the service connections will be totaled on an interval basis and charged based on Rate Code D410 provided the service connections are: i) positioned on adjacent and contiguous locations; ii) not separated by private or public property or right-of-way; and iii) operated as one single unit. 4. If a Site qualifies as a Micro-Generator, rate charges will only apply to energy inflow into the Site (i.e. no outflow charges). LOCAL ACCESS FEE (LAF) The LAF is a surcharge imposed by the City of Calgary and is not approved by the Alberta Utilities Commission. The LAF is collected by EPC on behalf of the City for all Sites located within the municipal boundaries of the City of Calgary. Distribution Tariff Effective January 1, 2017 Page 14 of 19

32 Page 15 of 19 DISTRIBUTION TARIFF STREETLIGHTS RATE CODE D500 Rate Schedule for the provision of Electricity Services to Customers of a Retailer. ELIGIBILITY For all photo cell controlled lighting services including all streetlights, traffic sign lighting, roadway lighting and lane rental lighting. Services with photo cell controlled lighting will not be eligible for a Meter. RATE COMPONENT TYPE UNIT PRICE DISTRIBUTION CHARGE FOR DISTRIBUTION ACCESS SERVICE System Usage Charge per kwh $ TRANSMISSION CHARGE FOR SYSTEM ACCESS SERVICE Variable Charge per kwh $ INVOICE PERIOD Monthly, from the date of the last invoice to the date of the current invoice. TERMS AND CONDITIONS The Terms and Conditions of the EPC Distribution Tariff form part of this Rate Schedule and apply to all Electricity Services supplied under this Tariff. LOCAL ACCESS FEE (LAF) The LAF is a surcharge imposed by the City of Calgary and is not approved by the Alberta Utilities Commission. The LAF is collected by EPC on behalf of the City for all Sites located within the municipal boundaries of the City of Calgary. Distribution Tariff Effective January 1, 2017 Page 15 of 19

33 Page 16 of 19 DISTRIBUTION TARIFF LARGE DISTRIBUTED GENERATION RATE CODE D600 Rate Schedule for the provision of Electricity Services to Sites with on-site generation with a minimum export capacity of 1,000 kva. ELIGIBILITY RATE 1. For services with on-site generation connected in parallel with the EPC Electric Distribution System with a minimum export capacity of 1,000 kva. 2. For Electricity Services that are served at primary voltage. 3. For sites equipped with bi-directional interval recording metering. COMPONENT TYPE UNIT PRICE DISTRIBUTION CHARGE FOR DISTRIBUTION ACCESS SERVICE Service Charge per day $ Dedicated Facilities Charge per day customer specific System Usage Charge per kwh $ On Peak System Usage Charge per kwh $ Off Peak TRANSMISSION CHARGE FOR SYSTEM ACCESS SERVICE ISO Costs/Credits $ Flow through Distribution Tariff Effective January 1, 2017 Page 16 of 19

34 Page 17 of The customer specific Dedicated Facilities Charge daily amount will be determined as follows: Dedicated Facilities Charge = ((DFA + GA) x (CRF + OMA))/365 days. Where: a) DFA = current cost of dedicated feeder assets b) GA = general assets associated with DFA and equal to 10.8% of DFA c) CRF = Capital Recovery Percentage Factor based on EPC s weighted cost of capital and approved depreciation rate. d) OMA = Operation, maintenance and administration factor equal to 3.1% of DFA. The customer specific Dedicated Facilities Charge daily amount will be outlined in the Interconnection Agreement which will also include the term of the Agreement and an annual inflation adjustment. 2. The System Usage Charge will be determined using the net of the energy inflow and energy outflow at the Meter(s). System Usage Charge will be waived for sites that only have dedicated facilities and do not use the EPC primary feeder system. 3. On Peak is all Energy consumption from 8 a.m. to 9 p.m. Monday to Friday inclusive, excluding statutory holidays (as according to the ISO Rules definition), Off Peak is all Energy consumption not consumed in On Peak hours. 4. Flow-Through of ISO Costs/Credits will be determined by applying the ISO DTS rate and/or STS rate (and any applicable riders) to the difference between the POD billing determinants with and without the site(s) billing determinants. 5. An initial fee will be charged for the incremental cost of bi-directional meter(s). INVOICE PERIOD Monthly, from the date of the last invoice to the date of the current invoice. Distribution Tariff Effective January 1, 2017 Page 17 of 19

35 Page 18 of 19 TERMS AND CONDITIONS The Terms and Conditions of EPC form part of this Rate Schedule and apply to all Electricity Services supplied under this Tariff. OTHER 5. The Customer is responsible for supplying all transformers whether owned by customer or rented. 6. Primary Metering shall be metering at EPC s primary distribution voltage with any subsequent transformation being the sole responsibility of the Customer. 7. Multi-Site Locations c) For locations or buildings that have a normally used service connection (preferred service) and a second service connection used strictly as a backup service (alternate service), the demands of the two service connections will be totaled on an interval basis and charged on Rate Code D600. d) For locations that use more than one service connection on a regular basis, demands of all the service connections will be totaled on an interval basis and charged on Rate Code D600. LOCAL ACCESS FEE (LAF) The LAF is a surcharge imposed by the City of Calgary and is not approved by the Alberta Utilities Commission. The LAF is collected by EPC on behalf of the City for all Sites located within the municipal boundaries of the City of Calgary. Distribution Tariff Effective January 1, 2017 Page 18 of 19

36 Page 19 of 19 DISTRIBUTION TARIFF TRANSMISSION CONNECTED RATE CODE D700 Rate Schedule for the provision of Distribution Access Service to Customers of a Retailer that are connected directly to EPC Facilities at a transmission voltage. RATE COMPONENT TYPE UNIT PRICE DISTRIBUTION CHARGE FOR DISTRIBUTION ACCESS SERVICE Service Charge per day $ TRANSMISSION CHARGE FOR SYSTEM ACCESS SERVICE ISO Costs $ Flow through INVOICE PERIOD Monthly, from the date of the last invoice to the date of the current invoice. TERMS AND CONDITIONS The Terms and Conditions of the EPC Distribution Tariff form part of this Rate Schedule and apply to all Electricity Services supplied under this Tariff. LOCAL ACCESS FEE (LAF) The LAF is a surcharge imposed by the City of Calgary and is not approved by the Alberta Utilities Commission. The LAF is collected by EPC on behalf of the City for all Sites located within the municipal boundaries of the City of Calgary. Distribution Tariff Effective January 1, 2017 Page 19 of 19