decision 2009-270 atco electric ltd. · 2018. 2. 23. · as set out in appendix a, schedule 5-b-1,...

Decision 2009-270

ATCO Electric Ltd. 2010 Interim Distribution Tariff and Transmission Facility Owner’s Tariff December 21, 2009

ALBERTA UTILITIES COMMISSION Decision 2009-270: ATCO Electric Ltd. 2010 Interim Distribution Tariff and Transmission Facility Owner’s Tariff Application No. 1605601 Proceeding ID. 370 December 21, 2009 Published by Alberta Utilities Commission Fifth Avenue Place, 4th Floor, 425 - 1 Street SW Calgary, Alberta T2P 3L8 Telephone: (403) 592-8845 Fax: (403) 592-4406 Web site: www.auc.ab.ca

http://www.auc.ab.ca/

AUC Decision 2009-270 (December 21, 2009) • i

Contents

1 INTRODUCTION................................................................................................................. 1

2 BACKGROUND ................................................................................................................... 2

3 DISCUSSION OF ISSUES................................................................................................... 2 3.1 Purpose of Interim Tariff ............................................................................................... 2 3.2 2010 Interim Distribution Tariff .................................................................................... 3 3.3 Rider B - Balancing Pool Adjustment............................................................................ 5 3.4 2010 Interim Transmission Facility Owner Tariff ......................................................... 5 3.5 Other Matters ................................................................................................................. 5

4 ORDER .................................................................................................................................. 8

APPENDIX 1 – PROCEEDING PARTICIPANTS................................................................... 9

APPENDIX 2 – 2010 INTERIM DISTRIBUTION TARIFF ................................................. 10

APPENDIX 3 – RATE IMPACT SCHEDULES ..................................................................... 11

APPENDIX 4 – RIDER B – BALANCING POOL RIDER DETERMINATION................ 12

APPENDIX 5 – 2010 INTERIM TRANSMISSION TARIFF ................................................ 13 List of Tables Table 1. Estimated Rate Impact of the 2010 Interim Distribution (DT) Rates vs. Current

Approved Rates Including Retail Energy................................................................. 3

Table 2. Estimated Rate Impact of the 2010 Interim Distribution (DT) Rates vs. Current Approved Rates Excluding Retail Energy................................................................ 4

Table 3. Estimated Impact of 2010 TFO vs. Current Approved Rate.................................. 5

AUC Decision 2009-270 (December 21, 2009) • 1

ALBERTA UTILITIES COMMISSION Calgary Alberta ATCO ELECTRIC LTD. Decision 2009-270 2010 INTERIM DISTRIBUTION TARIFF AND Application No. 1605601 TRANSMISSION FACILITY OWNER’S TARIFF Proceeding ID. 370

1 INTRODUCTION

1. On November 3, 2009 ATCO Electric Ltd. (AE) filed an application (Application) with the Alberta Utilities Commission (AUC or Commission) requesting approval of 2010 interim Distribution and Transmission Facility Owner’s (TFO) Tariffs. AE requested approval of the Application by December 18, 2009 to be able to test and implement the interim tariffs for January 1, 2010.

2. AE requested interim approval for its Distribution Tariff effective January 1, 2010 in accordance with the 2010 Negotiated Settlement Agreement1 (NSA). AE submitted that these rates most closely reflected the circumstances that are forecast to exist for 2010 and that use of these rates would require the least adjustment once the final 2010 Distribution Tariff was approved.

3. AE sought approval to use an interim TFO Tariff until approval was received for AE’s 2009-2010 General Tariff Application (GTA) Phase I Compliance Filing.

4. AE requested approval to amend its 2009 Rider B (Balancing Pool Adjustment Rider) to align with the change to the Alberta Electric System Operator’s (AESO) Rider F (Balancing Pool Consumer Allocation Rider). On November 23, 2009 AE updated its Application to reflect the decreased refund amount for Rider B of $4.00/MWh which had been submitted by the AESO in an application to the AUC on November 19, 2009.

5. Notice of the Application was issued on November 4, 2009. Parties interested in intervening in the Proceeding were required to file a statement of intention to participate (SIP) by November 18, 2009. SIPs were received from the Consumer’s Coalition of Alberta (CCA) and the Alberta Electric System Operator (AESO). AESO neither supported nor opposed AE’s application.

6. In its SIP, the CCA confirmed that the proposed 2010 interim Distribution Tariff reflected the 2010 Phase II NSA reached between AE and the parties that was filed with the Commission. The CCA supported AE’s proposal to amend its 2009 Rider B Balancing Pool Adjustment Rider. However, the CCA questioned a statement in the Application regarding “other matters outstanding that will impact the final charges to customers.”2 In response to this statement, the CCA submitted:

1 Signatories to the NSA included ATCO Electric Ltd. (AE), the Consumers Coalition of Alberta (CCA), the

Office of the Utilities Consumer Advocate (UCA) and the Industrial Power Consumers of Alberta (IPCAA). 2 ATCO Electric 2010 Interim Tariff Application, November 3, 2009, page 2, lines 2-24.

2010 Interim Distribution Tariff and Transmission Facility Owner’s Tariff ATCO Electric Ltd.

2 • AUC Decision 2009-270 (December 21, 2009)

in order to provide the Commission and parties a sense of the forthcoming rate changes and in order to avoid a multiplicity of rate changes and avoid potential rate spikes, AE should be directed to file a summary of such “matters outstanding” impact (sic) rate changes in 2010, including the estimated timing of rate changes as well as the quantum if it can be reasonably estimated at this time.3

7. The Commission issued a process letter on November 25, 2009 establishing the following schedule to deal with the Application:

Process Step Deadline

Time Deadline

Date If No IRs Are

Received Information Requests (if any) 2:00 PM November 27, 2009 Information Responses 2:00 PM December 1, 2009 Simultaneous Argument 2:00 PM December 3, 2009 December 1, 2009 Simultaneous Reply 2:00 PM December 7, 2009 December 4, 2009

8. The Commission considers the record for Proceeding 370 closed as of December 7, 2009. The Commission panel assigned to deal with this Application consisted of Carolyn Dahl Rees, Vice-Chair, Bill Lyttle, Commissioner, and Anne Michaud, Commissioner.

2 BACKGROUND

9. On December 5, 2008 AE filed a 2010 Distribution Tariff Phase II application (Application No. 1597983, Proceeding ID 143) with the Commission. On May 29, 2009 AE filed a request for approval to initiate a negotiated settlement process with the registered intervener groups in respect of all matters relating to the application. The Commission granted the request on June 9, 2009 and on August 19, 2009 AE filed with the Commission for approval a fully executed NSA. The Commission approved the NSA on December 3, 2009 in Decision 2009-231.4

10. On October 31, 2008 AE filed an application for a 2009 interim TFO Tariff. In Decision 2008-134,5 the Commission approved a 2009 TFO Tariff of $194.0 million on an interim basis effective January 1, 2009.

3 DISCUSSION OF ISSUES

3.1 Purpose of Interim Tariff 11. At the time of its application, AE anticipated the release of two Commission Decisions on applications that would influence the final 2010 tariffs. The applications were AE’s 2009-2010 GTA Compliance Filing (Application No. 1605361, Proceeding ID 279) and the 2010 Phase II NSA. As noted above, Decision 2009-231 regarding AE’s 2010 DT Phase II was released on December 3, 2009.

3 Exhibit 13, CCA SIP dated November 18, 2009, paragraph 7. 4 Decision 2009-231: AE 2010 Distribution Tariff – Phase II (Application 1597983, Proceeding ID 143.)

(Released: December 3, 2009). 5 Decision 2008-134: ATCO Electric Ltd., 2009 Interim Distribution Tariff and Transmission Facility Owner’s

Tariff (Application No. 1593221, Proceeding ID. 121) (Released: December 19, 2008).

http://www.auc.ab.ca/applications/decisions/Decisions/2009/2009-231.pdfhttp://www.auc.ab.ca/applications/decisions/Decisions/2008/2008-134.pdf



12. AE proposed to have rates in place by January 1, 2010 that would reflect those in the 2010 NSA. As a decision on AE’s 2009-2010 GTA Compliance Filing was not expected in time for AE to implement the rates approved in the NSA, an interim Distribution Tariff was required.

3.2 2010 Interim Distribution Tariff 13. In its November 3, 2009 application, AE provided a number of summary schedules that can be found in the Appendices to this Decision:

• Appendix 2 – 2010 Interim Distribution Tariffs • Appendix 3 – Rate Impact Schedules • Appendix 4 – Rider B – Balancing Pool Rider Determination • Appendix 5 – 2010 Interim Transmission Tariff

14. Interim Distribution Rates, which include retail energy, will see an overall decrease on January 1, 2010 from current approved 2009 rates. The interim rate adjustments will impact rate classes differently as shown in the following table.

Table 1. Estimated Rate Impact of the 2010 Interim Distribution (DT) Rates vs. Current Approved Rates Including Retail Energy6

Rate Class

DT Base Rate including

Energy Charge May 1 2009

$/month

DT Base Rate including

Energy Charge Jan 1 2010

$/month

Impact May 1 2009

to Jan 1 2010

$

Impact

May 1 2009 to Jan 1 2010

% D-11 Residential 108.47 102.92 (5.55) -5.1 D-21 Commercial 828.65 705.25 (123.40) -14.9 D-25 Irrigation 2,476.05 2,512.26 36.21 1.5 D-26 REA Irrigation 2,030.08 1,770.96 (259.12) -12.8 D-31 Industrial 1,819.18 1,532.82 (286.36) -15.7 D-41 Oilfield 992.19 845.11 (147.08) -14.8 D-51 REA Farm 150.36 119.31 (31.05) -20.7 D-56 Farm 172.11 135.60 (36.51) -21.2 D-61 Street Lighting 13.11 14.35 1.24 9.5 D-63 Private Lighting 16.60 14.70 (1.90) -11.4 T-31 Industrial 91,315.53 76,954.81 (14,360.72) -15.7

6 Application, Appendix B – Bill Comparison Schedules.



15. Table 2 below sets out the total changes in transmission and distribution rates and riders, excluding energy costs, for typical usage by customers in AE’s rate classes:

Table 2. Estimated Rate Impact of the 2010 Interim Distribution (DT) Rates vs. Current Approved Rates Excluding Retail Energy7

Rate Class

DT Base Rate excluding

Energy Charge May 1 2009

$/month

DT Base Rate excluding

Energy Charge Jan 1 2010

$/month

Impact May 1 2009

to Jan 1 2010

$

Impact

May 1 2009 to Jan 1 2010

% D-11 Residential 53.54 60.48 6.94 13.0 D-21 Commercial 245.32 279.09 33.77 13.8 D-25 Irrigation 1,508.29 1,793.75 285.46 18.9 D-26 REA Irrigation 1,062.31 1,052.45 (9.86) -0.9 D-31 Industrial 533.25 588.21 54.96 10.3 D-41 Oilfield 319.74 352.94 33.20 10.4 D-51 REA Farm 43.93 39.35 (4.58) -10.4 D-56 Farm 65.68 55.64 (10.04) -15.3 D-61 Street Lighting 6.45 7.88 1.43 22.2 D-63 Private Lighting 9.94 8.23 (1.71) -17.2 T-31 Industrial 13,472.20 20,062.48 6,590.28 48.9

16. As set out in Appendix A, Schedule 5-B-1, AE’s NSA rates are designed based on a 2010 target distribution revenue requirement of $423.8 million plus estimated franchise fees and taxes of $14.3 million, for a total of $438.1 million.

17. In AE’s 2009-2010 GTA Compliance Filing submitted on August 14, 2009, AE estimated the 2010 proposed distribution revenue requirement at $422.6 million plus estimated franchise fees and taxes of $14.3 million, for a total of $436.9 million.8

18. The difference between the revenue forecasted to be collected with the NSA rates and the proposed 2010 target revenue requirement as set out in the 2010 GTA Compliance Filing is estimated to be approximately $1.2 million. AE did not request any changes to the design and structure of the 2010 tariff between interim and final rates including the cost of service. For these reasons, AE submitted the existing NSA rates should be made effective on an interim basis.

19. AE proposed to leave the NSA rates in place until its 2010 tariffs were finalized and recommended that the difference between the forecast revenues collected on the approved interim and final tariffs be dealt with through a future rider application. AE submitted that this would allow it to begin collecting its 2010 forecasted revenue requirement as of January 1, 2010 and this would help to minimize rate swings from interim to final rates for 2010.

20. Once the Commission issues its decision on AE’s 2009-2010 GTA Compliance Filing, AE proposed to design the final 2010 tariff based on the approved updated 2010 revenue requirement within 30 days, as agreed upon in the NSA and approved by the Commission.

7 Application, Appendix B – Bill Comparison Schedules. 8 Exhibit 2, AE 2010 Interim Tariff Application, November 3, 2009, page 3 lines 11-13.



3.3 Rider B - Balancing Pool Adjustment 21. To properly flow through this rider to customers in AE’s service area, AE set its Rider B on the same rate set out in AESO’s tariff schedule for Rider F. AESO’s Rider F is a mechanism whereby AESO passes on refunds or recoveries from the Balancing Pool. The rate in 2009 was a $6.50/MWh credit.

22. In Decision 2009-2399 the Commission approved AESO’s request to provide a $4.00/MWh credit for consumption from January 1, 2010 through December 31, 2010 inclusive.

23. In its update to the Application, AE proposed to amend the Balancing Pool Rider for 2010 which forms part of the proposed 2010 interim Distribution Tariff. The CCA supported AE’s proposal to amend its 2009 Rider B Balancing Pool Adjustment Rider.10

3.4 2010 Interim Transmission Facility Owner Tariff 24. AE currently has its 2009-2010 GTA Compliance Filing before the Commission and therefore has requested an interim TFO tariff to be effective January 1, 2010 until it receives final approval for its 2010 TFO tariff.

25. The 2010 TFO Tariff as filed in the 2009-2010 GTA Compliance Filing was $246.3 million. The applied-for monthly interim charge would be $20.525 million. AE stated that all amounts would be trued up once final TFO Tariffs were determined. The impact of the new tariff is as follows in Table 3.11

Table 3. Estimated Impact of 2010 TFO vs. Current Approved Rate 2009

($ Million) 2010

($ Million) Annual Forecast TFO Revenue 194.0 246.3 Monthly Forecast TFO Revenue 16.17 20.525 3.5 Other Matters 26. As noted above, the CCA included a recommendation in its SIP regarding further materials that it considered AE should file.

27. In Reply Argument, AE addressed the CCA’s concerns by stating that there are a number of important matters that are still before the Commission that may affect final rates.12 For example, AE advised that the pool price forecast will have changed by the time the final 2010 tariff application is developed. Also, there are other key deferrals that will be incorporated into the next Rider G application. As such, AE indicated that it will address these matters in detail in its 2010 final tariff application expected in the first quarter of 2010 and in the 2010 Rider G application and therefore there was no need to file additional materials.

9 Decision 2009-239: Alberta Electric System Operator 2010 Rider F (Application No. 1605636,

Proceeding ID. 399) (Released: December 1, 2009). 10 CCA letter, November 18 2009, page 2, paragraph 9. 11 2010 data from Appendix E, 2010 Interim Tariff Application; 2009 Data from Decision 2008-134, 2009 Interim

Distribution Tariff and Transmission Facility Owner’s Tariff, Appendix 5, Released December 19, 2008. 12 Exhibit 21, AE Reply Argument, page 2.

http://www.auc.ab.ca/applications/decisions/Decisions/2009/2009-239.pdf



28. The CCA, in its Reply Argument, advised that it had nothing further to add in reply on this issue.

3 COMMISSION FINDINGS

28. AE has requested the following approvals:

• To make the tariff as set out in the 2010 NSA effective January 1, 2010 on an interim basis.

• To amend its 2009 Rider B – Balancing Pool Adjustment Rider to align with AESO’s Rider F – Balancing Pool Consumer Allocation Rider.

• To utilize an interim TFO Tariff until it receives approval on its 2009 – 2010 GTA Compliance Filing.

29. AE’s purpose in requesting interim Distribution and TFO Tariffs was to use January 1, 2010 rates that reflected the anticipated 2010 revenue requirement more closely than the rates currently in place. Any difference between the forecast revenues collected on the approved interim and final tariffs would be dealt with through a future rider or adjustment application.

30. AE’s application was not opposed by the parties. Regarding CCA’s request for more information raised in its SIP, the Commission considers that speculation on the outcome of outstanding matters as requested would not be helpful or efficient.

29. When evaluating the merits of an interim rate application, the Commission must weigh the potential benefits of rate stability and minimization of rate shock 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. In Decision 2005-099,13 the Board noted the following factors it considered when evaluating the need for interim rate increases:

These factors can be grouped into two categories, those that relate to the quantum of, and need for, the rate increase and those that related to more general public interest considerations. Quantum and need factors are those which relate to the specifics of the requested rate increase and include:

• The identified revenue deficiency should be probable and material • All or some portion of any contentious items may be excluded from the amount

collected • Is the increase required to preserve the financial integrity of the applicant or to

avoid financial hardship to the applicant? • Can the applicant continue safe utility operations without the interim adjustment?

13 Decision 2005-099: ATCO Gas 2005-2007 General Rate Application, Interim Rate Application

(Application 1404168) (Released: August 29, 2005).




If all or a portion of the suggested rate increase appears appropriate after a consideration of the quantum and need factors, the Board must assess certain general public interest factors to see if a rate increase is justified, these include:

• Interim rates should promote rate stability and ease rate shock • Interim adjustments should help to maintain intergenerational equity • Can interim rate increases be avoided through the use of carrying costs? • Interim rate increases may be required to provide appropriate price signals to

customers • It may be appropriate to apply the interim rider on an across-the-board basis

The Board recognizes that the above listed considerations may be given different weighting depending on the specific circumstances surrounding each application. The Board has considered the above factors in its deliberations.14

30. With respect to the quantum and need factors, the Commission:

a. accepts AE’s submission that the projected difference of $1.2 million will not result in a material impact on rates;

b. accepts AE’s submission that a significant portion of the projected revenue shortfall is probable, given that the Compliance filing has been submitted for approval; and

c. notes that there has been no suggestion made that AE will be unable to perform its regulated services or that safety of operations will be impacted should the interim increase be denied.

31. With respect to the general public interest factors, the Commission observes that no intervener has objected to the Application. The Commission also notes the Alberta Energy and Utilities Board made the following statement in Decision 2002-115:15

An interim rate increase aimed at recovering a portion of any shortfall that is ultimately demonstrated and approved provides for a leveling out of the impact of any final rate increase, thereby promoting rate stability and easing any rate shock to customers at a later date. The Board also considers it appropriate that customers’ rates for a given period reflect the costs associated with that period in order to maintain intergenerational equity.16

creases

r a ssible the costs associated with the period in order to

maintain intergenerational equity.

factors identified above to approve the requested interim 2010 Distribution and TFO Tariffs.

32. Promoting rate stability and easing future rate shock by leveling out final rate inwith interim rates is a key consideration for the Commission in this Application. The Commission also considers the use of interim rates helpful in ensuring customers’ rates fogiven period reflect to the extent po

33. The Commission considers it reasonable after consideration of the quantum and need factor and the general public interest

14 Ibid, pages 7 and 8. 15 Decision 2002-115: ATCO Gas - 2003/2004 General Rate Application (Application 1284374)

(Released: December 24, 2002). 16 Ibid, page 10.




32. In Decision 2009-239 the Commission approved the AESO’s 2010 Rider F, and the AE Rider B – Balancing Pool Adjustment Rider is based on AESO’s Rider F. AE’s application for approval of Rider B was not opposed by any of the parties and therefore the Commission approves AE’s Rider B as filed.

4 ORDER

33. IT IS HEREBY ORDERED THAT:

(1) ATCO Electric Ltd.’s 2010 Interim Distribution Tariff is approved on an interim basis effective January 1, 2010.

(2) ATCO Electric Ltd.’s existing Rider B – Balancing Pool Adjustment Rider shall

be reduced to a refund of $4.00/MWh to coincide with the AESO Rider F decrease, effective January 1, 2010.

(3) ATCO Electric Ltd.’s Interim Transmission Facility Owner Tariff is approved on

an interim basis effective January 1, 2010. Dated in Calgary, Alberta on December 21, 2009. ALBERTA UTILITIES COMMISSION (original signed by) Carolyn Dahl Rees Vice-Chair (original signed by) Bill Lyttle Commissioner (original signed by) Anne Michaud Commissioner



APPENDIX 1 – PROCEEDING PARTICIPANTS

Name of Organization (Abbreviation) Counsel or Representative

ATCO Electric Ltd.

J. Grattan The Consumer’s Coalition of Alberta

J. Wachowich Alberta Electric System Operator

J. Martin Alberta Utilities Commission Commission Panel C. Dahl Rees, Vice-Chair B. Lyttle, Commissioner A. Michaud, Commissioner Commission Staff

C. Wall (Commission Counsel) C. Taylor D. Cherniwchan



APPENDIX 2 – 2010 INTERIM DISTRIBUTION TARIFF

(return to text)

Appendix 2 -2010 Interim Distribution Ta

(consists of 51 pages)



APPENDIX 3 – RATE IMPACT SCHEDULES

(return to text)

Appendix 3 - Rate Impact Schedules

(consists of 16 pages)



APPENDIX 4 – RIDER B – BALANCING POOL RIDER DETERMINATION

(return to text)

Appendix 4 - Rider B

(consists of 1 page)



APPENDIX 5 – 2010 INTERIM TRANSMISSION TARIFF

(return to text)

Appendix 5 - 2010 Interim Transmission T

(consists of 1 page)

2010 Interim Distribution Tariff and Transmission Facility Owner's Tariff ATCO Electric Ltd.

Sheet 1 of 1 Effective: 2010 01 01

Supersedes: _________

AUC Decision 2009-270 (December 21, 2009)

APPENDIX 2

ATCO ELECTRIC LTD.

2010 INTERIM DISTRIBUTION TARIFF

JANUARY 1, 2010

ATCO Electric Ltd. Appendix 2 – 2010 Interim Distribution Tariff 2010 Interim Distribution Tariff and Transmission Facility Owner's Tariff Page 2 of 51




PRICE SCHEDULE INDEX RESIDENTIAL SERVICE Standard Residential Service Price Schedule D11

SMALL GENERAL SERVICE Standard Small General Service Price Schedule D21 Small General Service - Energy Only Price Schedule D22 Small General Service - Isolated Industrial Areas - Distribution Connected Price Schedule D24 Irrigation Pumping Service Price Schedule D25 REA Irrigation Pumping Service Price Schedule D26

LARGE GENERAL SERVICE/INDUSTRIAL Large General Service/Industrial - Distribution Connected Price Schedule D31 Large General Service/Industrial - Transmission Connected Price Schedule T31 Generator Interconnection and Standby Power - Distribution Connected Price Schedule D32 Transmission Opportunity Rate - Distribution Connected Price Schedule D33 Transmission Opportunity Rate - Transmission Connected Price Schedule T33 Large General Service/Industrial - Isolated Industrial Areas - Distribution Connected

Price Schedule D34

OILFIELD Small Oilfield and Pumping Power Price Schedule D41 Small Oilfield and Pumping Power - Isolated Industrial Areas - Distribution Connected

Price Schedule D44

FARM SERVICE REA Farm Service Price Schedule D51 REA Farm Service - Excluding Wires Service Provider Functions Price Schedule D52 Farm Service Price Schedule D56

LIGHTING SERVICE Street Lighting Service Price Schedule D61 Private Lighting Service Price Schedule D63

PRICE OPTIONS Idle Service Option F Service for Non-Standard Transformation and Metering Configurations Option H REA Distribution Price Credit Option P

PRICING ADJUSTMENTS (RIDERS) Municipal Assessment Rider A-1 Balancing Pool Adjustment Rider B Special Facilities Charge Rider E Temporary Adjustment Rider G Interim Adjustment Rider J Interim RRT Adjustment Rider Q

ATCO Electric Ltd. Appendix 2 – 2010 Interim Distribution Tariff 2010 Interim Distribution Tariff and Transmission Facility Owner's Tariff Page 3 of 51 Price Schedule D11

Standard Residential Service




Availability For System Access Service and Distribution Access Service for all Points of Service throughout the territory served by the Company. Price Schedule D11 is available for use by a single and separate household through a single-phase service at secondary voltage through a single meter. Price Schedule D11 is not applicable for commercial or industrial use.

Price The charge for service in any one billing period is the sum of the Customer Charge and Energy Charge, determined for each individual Point of Service.

Customer Charge Energy Charge

Transmission - 1.61 ¢ / kW.h

Distribution 63.89 ¢ / day 5.40 ¢ / kW.h

Service 26.01 ¢ / day -

TOTAL PRICE 89.90 ¢ / day 7.01 ¢ / kW.h

Application 1. Price Option - the following price option may apply:

Idle Service (Option F)

2. Price Adjustments - the following price adjustments (riders) may apply: Municipal Assessment (Rider A-1) Balancing Pool Adjustment (Rider B) Temporary Adjustment (Rider G) Interim Adjustment (Rider J) Interim RRT Adjustment (Rider Q)


Standard Small General Service


Supersedes: __________


Availability For System Access Service and Distribution Access Service for all Points of Service throughout the territory served by the Company, with single or three-phase electric service at secondary voltage. Not applicable for any service in excess of 500 kW.

Price Charges for service in any one billing period shall be the sum of the Customer Charge, Demand Charge, and Energy Charge, determined for each individual Point of Service.

Customer Charge

Demand Charge

Energy Charge

For the first 200 kW.h per kW of billing

demand

For energy in excess of 200 kW.h per kW of billing demand

Transmission - 7.91 ¢/kW/day 0.48 ¢ / kW.h 0.48 ¢ / kW.h

Distribution - 18.21 ¢/kW/day 3.09 ¢ / kW.h -

Service 32.87 ¢ / day - - -

TOTAL PRICE 32.87 ¢ / day 26.12 ¢/kW/day 3.57 ¢ / kW.h 0.48 ¢ / kW.h

The billing demand for the Transmission, Distribution and Service charges shall be the higher of:

(a) the highest metered demand during the billing period; (b) 85% of the difference between the highest metered demand in the twelve month period including

and ending with the billing period and 150 kW, if this is greater than zero; (c) the estimated demand; (d) if applicable, the Transmission Contract Demand (TCD) applied to Transmission charges, and/or

the Distribution Contract Demand (DCD) applied to Distribution and Service charges; (e) 5 kilowatts.

Application 1. Power Factor Correction - where a Customer's power factor is found to be less than 90%, the

Company may require the Customer to install corrective equipment. 2. Price Options - the following price options may apply:

Idle Service (Option F) Service for Non-Standard Transformation and Metering Configurations (Option H) REA Distribution Price Credit (Option P)



Standard Small General Service – Energy Only




Availability For System Access Service and Distribution Access Service for all Points of Service throughout the territory served by the Company, with single or three-phase electric service at secondary voltage. Not applicable for any service in excess of 50 kW.

Price Charges for service in any one billing period shall be the Energy Charge, determined for each individual Point of Service.

Energy Charge

For the first 50 kW.h per kW of billing demand


Transmission 0.59 ¢ / kW.h 0.59 ¢ / kW.h

Distribution 20.54 ¢ / kW.h 6.80 ¢ / kW.h

Service - -

TOTAL PRICE 21.13 ¢ / kW.h 7.39 ¢ / kW.h

The billing demand applied to determine the billing energy per block of energy charge for the Transmission, Distribution and Service charges shall be the higher of: (a) the highest metered demand during the billing period;

(b) the estimated demand;

(c) if applicable, the Transmission Contract Demand (TCD) applied to Transmission charges, and/or the Distribution Contract Demand (DCD) applied to Distribution and Service charges;

(d) 5 kilowatts.

The minimum annual charge is 12 times the sum of:

(a) the Service Charge from Price Schedule D21; and (b) the Total Demand Charge from Price Schedule D21 multiplied by the higher of the DCD or 5 kW.

Application 1. Power Factor Correction - where the power factor at a Point of Service is found to be less than

90%, the Company may require the installation of corrective equipment. 2. Price Options - the following price option may apply:

Idle Service (Option F) Service for Non-Standard Transformation and Metering Configurations (Option H)

3. Price Adjustments - the following additional charges (riders) may apply: Municipal Assessment (Rider A-1) Balancing Pool Adjustment (Rider B) Temporary Adjustment (Rider G) Interim Adjustment (Rider J) Interim RRT Adjustment (Rider Q)


Standard Small General ServiceIsolated Industrial Areas




Availability For Distribution Access Service, single or three-phase, for all Points of Service throughout the territory served by the Company distribution connected from an isolated industrial areas. Not applicable for any service in excess of 500 kW.

Price Charges for service in any one billing period shall be the sum of the Customer Charge, Demand Charge, and Energy Charge, determined for each individual Point of Service.

Customer Charge

Demand Charge

Energy Charge

For the first 200 kW.h per kW of billing demand


Distribution - 18.21 ¢/kW/day 3.09 ¢ / kW.h -

Service 32.87 ¢ / day - - -

TOTAL PRICE 32.87 ¢ / day 18.21 ¢/kW/day 3.09 ¢ / kW.h -

The billing demand for the Distribution and Service charges shall be the higher of:

(a) the highest metered demand during the billing period;

(b) 85% of the difference between the highest metered demand in the twelve month period including and ending with the billing period and 150 kW, if this is greater than zero;

(c) the estimated demand;

(d) the Distribution Contract Demand (DCD);

(e) 5 kilowatts.

Application 1. Power Factor Correction - where a Customer's power factor is found to be less than 90%, the

Company may require the Customer to install corrective equipment.

2. Price Options - the following price options may apply: Idle Service (Option F) Service for Non-Standard Transformation and Metering Configurations (Option H) REA Distribution Price Credit (Option P)

3. Price Adjustments - the following price adjustments (riders) may apply: Municipal Assessment (Rider A-1) Temporary Adjustment (Rider G) Interim Adjustment (Rider J)


Irrigation Pumping Service




Availability For System Access Service and Distribution Access Service for all Points of Service throughout the territory served by the Company, between April 1 and October 31 for seasonal irrigation pumping loads. Not applicable for any service in excess of 150 kW.

Price Charges for service in any one billing period during one Season shall be the sum of the Customer Charge, Demand Charge, and Energy Charge, determined for each individual Point of Service.

Customer Charge Demand Charge Energy Charge

Transmission - 8.14 ¢/kW/day 0.49 ¢ / kW.h

Distribution - 12.65 ¢/kW/day -

Service 25.92 ¢ / day - -

TOTAL PRICE 25.92 ¢ / day 20.79 ¢/kW/day 0.49 ¢ / kW.h





(d) 5 kilowatts.

For non-demand metered services, demand shall be estimated based on equipment nameplate ratings as kW Billing Demand = kW Nameplate Rating, or kW Billing Demand = HP Nameplate x 0.746.

Application 1. Idle Service - in the event the service remains idle for two consecutive seasons, the Company

may remove its facilities, unless the Customer pays the minimum charge for the upcoming season prior to December 31, of the preceding year.

2. Power Factor Correction - where a Customer’s power factor is found to be less than 90%, the Company may require the Customer to install corrective equipment.

3. Price Adjustments - the following price adjustments (riders) may apply: Balancing Pool Adjustment (Rider B) Temporary Adjustment (Rider G) Interim Adjustment (Rider J) Interim RRT Adjustment (Rider Q)


REA Irrigation Pumping Service




Availability For System Access Service and Distribution Access Service for all Points of Service throughout the territory served by the Company, between April 1 and October 31 for seasonal irrigation pumping loads of Rural Electrification Association Customers and individual co-operative and colony farms with their own distribution systems. Not applicable for any service in excess of 150 kW.

Price Charges for service in any one billing period during one Season shall be the sum of the Customer Charge, Demand Charge, and Energy Charge, determined for each individual Point of Service.

Customers in the REA O & M Pool



Distribution - 3.99 ¢/kW/day -



Customers outside of the REA O & M Pool



Distribution - - -







(d) 5 kilowatts. For non-demand metered services, demand shall be estimated based on equipment nameplate ratings as kW Billing Demand = kW Nameplate Rating, or kW Billing Demand = HP Nameplate x 0.746.


REA Irrigation Pumping Service




REA Specific Charges:

Other charges are applied on behalf of the REAs as defined in contracts and are subject to change from time to time.

These charges include operation and maintenance charges and deposit reserve charges, and are in addition to the charges contained in this price schedule.

The minimum charge for the season shall be 7 times the Service Charge and 7 times the Demand Charge.

Application 1. Idle Service - in the event the service remains idle for two consecutive seasons, the Company

may remove its facilities, unless the Customer pays the minimum charge for the upcoming season prior to December 31, of the preceding year.

2. Power Factor Correction - where a Customer’s power factor is found to be less than 90%, the Company may require the Customer to install corrective equipment.

3. Price Adjustments - the following price adjustments (riders) may apply: Balancing Pool Adjustment (Rider B) Temporary Adjustment (Rider G) Interim Adjustment (Rider J) Interim RRT Adjustment (Rider Q)


Large General Service / IndustrialDistribution Connected




Availability • For System Access Service and Distribution Access Service, single or three-phase distribution

connected, for all Points of Service throughout the territory served by the Company. This rate is not applicable for any new Small Oilfield and Pumping Power service with yearly average operating demands of less than 75 kW, effective January 1, 2008.

• For distribution connected loads greater than 500 kW, the Point of Service must be equipped with interval data metering.

Price Charges for service in any one billing period shall be the sum of the Customer Charge, Demand Charge, Energy Charge and Charge for Deficient Power Factor, determined for each individual Point of Service:


For the first 500 kW of billing demand

For all billing demand over 500 kW

Transmission - 11.68 ¢/kW/day 13.52 ¢/kW/day 0.48 ¢ / kW.h

Distribution 14.88 ¢/day 20.18 ¢/kW/day 16.32 ¢/kW/day -

Service $2.1852 /day - 0.67 ¢/kW/day -

TOTAL PRICE $2.3340 /day 31.86 ¢/kW/day 30.51 ¢/kW/day 0.48 ¢ / kW.h


(a) The highest metered demand during the billing period (including any demand delivered and billed under Price Schedules D32 and D33);

(b) 85% of the highest metered demand (including any demand delivered and billed under Price Schedules D32 and D33) in the 12-month period including and ending with the billing period;

(c) the estimated demand; (d) the Distribution Contract Demand (DCD); (e) 50 kilowatts.

The billing demand for the Transmission charges shall be the higher of: (a) The highest metered demand during the billing period (excluding any demand delivered and billed

under Price Schedules D32 and D33); (b) 85% of the highest metered demand (excluding any demand delivered and billed under Price

Schedules D32 and D33) in the 12-month period including and ending with the billing period; (c) the estimated demand; (d) the Transmission Contract Demand (TCD);


Large General Service / IndustrialDistribution Connected




(e) if any of the above are equal to or greater than 1000 kW, 80% of the highest metered demand (excluding any demand delivered and billed under Price Schedules D32 and D33) in the 24-month period.

(f) 50 kilowatts.

If energy is also taken under Transmission Opportunity Rate (Price Schedule D33), during the billing period, the billing demand will be the Price Schedule D31 Base Demand as specified under the corresponding agreement.


Charge for Deficient Power Factor - For customer power factor which is less than 90%, an additional charge for deficient power factor of 20.04¢/kV.A/day will be applied to the difference between the highest metered kV.A demand and 111% of the highest metered kW demand in the same billing period.

Application 1. Price Options - the following price options may apply:


2. Price Adjustments - the following price adjustments (riders) may apply: Municipal Assessment (Rider A-1) Balancing Pool Adjustment (Rider B) Special Facilities Charge (Rider E) Temporary Adjustment (Rider G) Interim Adjustment (Rider J) Interim RRT Adjustment (Rider Q)

ATCO Electric Ltd. Appendix 2 – 2010 Interim Distribution Tariff 2010 Interim Distribution Tariff and Transmission Facility Owner's Tariff Page 12 of 51 Price Schedule T31

Large General Service / IndustrialTransmission Connected




Availability • For System Access Service, for all Points of Service throughout the territory served by the Company

that are directly connected to a transmission substation, and do not make any use of distribution facilities owned by ATCO Electric.

• The Point of Service must be equipped with interval data metering.

Price Charges for service in any one billing period shall be the sum of the Demand Charge, Energy Charge and charge for Deficient Power Factor, determined for each individual Point of Service.

Demand Charge Energy Charge



Transmission Current AESO DTS Rate Schedule less under frequency load shedding credit

Current AESO DTS Rate Schedule less under frequency load shedding credit

Charges per current AESO DTS Rate

Schedule

Distribution 1.10 ¢/kW/day - -

Service 7.69 ¢/kW/day - -

TOTAL PRICE 8.79 ¢/kW/day + Current AESO DTS Rate Schedule less under frequency load shedding credit

Current AESO DTS Rate Schedule less under frequency

load shedding credit


(a) The highest metered demand during the billing period (including any contract opportunity demand delivered and billed under Price Schedule T33);

(b) 85% of the highest metered demand (including any contract opportunity demand delivered and billed under Price Schedule T33) in the 12-month period including and ending with the billing period;

(c) the estimated demand; (d) 50 kilowatts.

The billing demand for the Transmission charge shall be the higher of:

(a) The billing demand charged to ATCO Electric by AESO at a Point of Delivery, that is attributable to the customer at that Point of Delivery;

(b) the highest metered demand during the billing period; (c) the ratchet level as set out by the AESO at a Point of Delivery, where (a) through (c) exclude any

contracted Opportunity Demand delivered and billed under Price Schedule T33; (d) the estimated demand; (e) the Transmission Contract Demand (TCD) for Customers served from diversified PODs, or 90%of

the TCD for Customers served from dedicated PODs; (f) 50 kilowatts

ATCO Electric Ltd. Appendix 2 – 2010 Interim Distribution Tariff 2010 Interim Distribution Tariff and Transmission Facility Owner's Tariff Page 13 of 51 Price Schedule T31

Large General Service / IndustrialTransmission Connected




The ‘highest metered demand’ is defined for the purposes of this price schedule, according to the current approved AESO DTS Rate Schedule.

If energy is also taken under Transmission Opportunity Rate (Price Schedule T33), during the billing period, the billing demand will be the Price Schedule T31 Base Demand as specified under the corresponding agreement.

Charge for Deficient Power Factor – Power Factor Charges according to the current approved AESO DTS Rate Schedule will apply.

Application 1. Price Options - the following price option may apply:

Service for Non-Standard Transformation and Metering Configurations (Option H)

2. Price Adjustments - the following price adjustments (riders) may apply: Municipal Assessment (Rider A-1) Balancing Pool Adjustment (Rider B) Special Facilities Charge (Rider E) Temporary Adjustment (Rider G) Interim Adjustment (Rider J)


Price Schedule D32Generator Interconnection and Standby Power




Availability • For Points of Service served by the Company with on-site generating equipment connected to the

distribution system, which may be used to supply load at the same site.

• To provide standby power to the on-site load in the event of a forced outage or derate of on-site generating equipment, to provide power for generator startup, and to provide supplemental power if the on-site demand requirements exceed the generator capacity.

• To provide credits to Generators for reduced DTS charges from AESO.

• To charge Generators if the Point of Delivery attracts STS charges from AESO.

• For interconnection of the generator to the distribution system.

• The Point of Service must be equipped with 4-quadrant interval data metering, for both supply and demand, the cost of which will be in addition to the charges under this rate.

Price Charges for service in any one billing period shall be the sum of the Customer Charges, Demand Charges, Energy Charges, Other Charges, Charge for Deficient Power Factor (determined for each individual Point of Service), and Fixed Charges defined below.




Transmission - 11.68 ¢/kW/day 13.52 ¢/kW/day 0.48 ¢ / kW.h



TOTAL PRICE $2.3340 /day 31.86 ¢/kW/day 30.51 ¢/kW/day 0.48 ¢ / kW.h


(a) The highest metered demand during the billing period (including any demand delivered and billed under Price Schedule D33);

(b) 85% of the highest metered demand (including any demand delivered and billed under Price Schedule D33) in the 12-month period including and ending with the billing period;


(d) the Distribution Contract Demand (DCD).






The billing demand for the Transmission charges shall be the higher of:

(a) The highest metered demand during the billing period (excluding any demand delivered and billed under Price Schedule D33);

(b) 85% of the highest metered demand (excluding any demand delivered and billed under Price Schedule D33) in the 12-month period including and ending with the billing period;


(d) the Transmission Contract Demand (TCD);

(e) if any of the above are equal to or greater than 1000 kW, 80% of the highest metered demand (excluding any demand delivered and billed under Price Schedules D33) in the 24-month period including and ending with the current billing period;

If energy is also taken under Transmission Opportunity Rate (Price Schedule D33), during the billing period, the billing demand will be the Price Schedule D32 Base Demand as specified under the corresponding agreement.


Charge for Deficient Power Factor - For customer power factor which is less than 90%, an additional charge for deficient power factor of 20.04¢/kV.A/day will be applied to the difference between the highest metered kV.A demand and 111% of the highest billing kW demand in the same billing period, where billing demand is as defined in this price schedule.

If the Company incurs an increase to the Point-of-Delivery (POD) billing demand with AESO as a result of a standby event of the customer (i.e. the new demand at the POD is coincident with an outage of the generator), then an additional charge may apply, equal to the Transmission Demand Charge for Price Schedule T31, multiplied by the incremental POD demand incurred. This charge will apply for the current billing period, and for the next 11 billing periods.

Capital Recovery Charges:

The cost of the Incremental Interconnection Facilities will be determined as set out in Section 9.6 of the Terms and Conditions for Distribution Service Connections. The total amount will be collected from the customer in accordance with Section 9.8 of the Terms and Conditions for Distribution Service Connections. A contract will be arranged between the customer and the Company, specifying the contract term and the monthly amount, which will be calculated using the Company’s Rate of Return, Income Tax and Depreciation in effect at the commencement of the contract term.

The Generating customer will be required to pay all replacement costs for incremental facilities as per Section 9.6 of the Terms and Conditions for Distribution Service Connections.

Incremental Operations and Maintenance Charges:

The minimum monthly incremental Operations and Maintenance charge will be:

(0.014% X Incremental Interconnection Cost) per day

The Generating customer will be required to pay for switching or isolation as per Section 9.6 of the Terms and Conditions.






Incremental Administration and General Charges:

The minimum monthly incremental Administration and General charge will be:

(0.005% X Incremental Interconnection Cost) per day

Generator Credits for reduction in Billing Determinants at the Point of Delivery:

Credit = DTS * (A – B) Where:

A = Monthly Gross Billing Determinants at the POD to which the generator is connected (which will be determined by adding the interval output data metered at the generator to the net interval data metered at the POD).

B = Monthly Net Billing determinants at the POD to which the generator is connected.

DTS = The charges as per AESO’s effective DTS tariff.

The Company will calculate the generator credits on a calendar quarterly basis after all power production information has been provided to the Company in accordance with Section 9.5.4 of the Terms and Conditions for Distribution Service Connections.

Generator Charges for a Point of Delivery:

Charge = STS * A Where:

A = Monthly Net Supply Billing determinants at the POS to which the generator is connected.

STS = The charges as per AESO’s effective STS tariff.


Idle Service (Option F) Service for Non-Standard Transformation and Metering Configurations (Option H)



Price Schedule D33Transmission Opportunity Rate

Distribution Connected




Availability • Available only to Points of Service which are eligible as determined by AESO for Demand Opportunity

Service, throughout the territory served by the Company for loads greater than 1,000 kW.

• Available only when AESO determines that there is sufficient transmission capacity. Service on this rate is interruptible for transmission system security reasons at AESO’s request.

• The Point of Service must be equipped with revenue approved time of use metering. The cost of the time of use metering is in addition to the charges in this rate.

• Telemetering is required for all points of service on this rate with demands greater than 2,500 kW, and any associated costs will be in addition to the charges in this rate.

Price Charges for service in any one billing period shall be the sum of the following charges determined for each individual Point of Service. The AESO DOS charges will be applied according to the terms of the DOS option selected by the Customer:

Customer Charges

Demand Charges

Demand Charges

Energy Charges Energy Charges

For all kW of Opportunity

Contract Demand

For the peak kW above the

Opportunity Contract Demand

For all kW.h metered above the Base Demand, not

exceeding the Opportunity Contract Demand

For all kW.h metered above the


Transmission Transaction Charge per AESO

DOS Rate Schedule

- Per Price Schedule D32

Per AESO DOS Rate Schedule

Per Price Schedule D32

Distribution 14.88 ¢/day 20.18 ¢/kW/day 16.32 ¢/kW/day - -

Service $2.1852 /day - 0.67 ¢/kW/day - -

TOTAL PRICE $2.3340 /day + AESO DOS Rate

20.18 ¢/kW/day 16.99 ¢/kW/day + D32


Per Price Schedule D32

The attached form must be completed and submitted to the Company, and serves as an Opportunity Contract which specifies the period and the Opportunity Demand requested by the Customer, as well as the DOS option selected.

The charges according to the AESO DOS Rate Schedule will be the approved charges in effect during the billing period, and will be revised in accordance with AESO’s charges as required.







Application 1. Base Demand - A Customer qualifying for this rate must establish a Base Demand with the

Company on Price Schedule D31 prior to receiving service under this rate (which will be submitted as part of the attached form).

(a) For existing Customers, the Price Schedule D31 Base Demand will normally be the maximum billing demand in the 12 most recent billing periods.

(b) New Customers qualifying for this rate may select the Large General Service/Industrial D31 Base Demand based on forecast loads and economics, provided the Company agrees that the conditions of applicability are satisfied.

(c) Once established, the Price Schedule D31 Base Demand remains fixed for the purposes of billing all future service on this rate.

2. Applicable Charges – This rate schedule applies in conjunction with rate D31, in that the first block demand charges apply only to the first 500 kW of the combined demand (i.e. D31 and D33, and D32 should there be an excursion above contracted opportunity demand), and the remainder of the combined demand is subject to the second and third block demand charges. The Service Customer Charge does not apply again as it has already been applied to the base load on Price Schedule D31.

3. Options - A Customer requesting service under this rate must select the provisions of one of AESO’s DOS Rate Schedules. The Customer is subject to AESO’s minimum Opportunity Service charges, attributable to that customer.

4. Notice Period - A Customer requesting service under this rate is required to provide notification as prescribed in the AESO tariff in relation to DOS service.

5. Load Curtailment - When a load curtailment directive is given, the load at the point of service must not exceed the Price Schedule D31 Base Demand until the Company gives notification that the interruption period is over, at which time consumption of energy may be resumed.

6. Non-Compliance Charges – In the event of a load curtailment directive, if the load served under this rate is not curtailed for the entire interruption period, any charges incurred by the Company will be charged to the Point of Service on this rate.

7. Price Options – the following price options may apply: Service for Non-Standard Transformation and Metering Configurations (Option H)

8. Price Adjustments - the following price adjustments may apply: Municipal Assessment (Rider A-1) Balancing Pool Adjustment (Rider B) Temporary Adjustment (Rider G) Interim Adjustment (Rider J)







This form will be completed and signed by ATCO Electric after a telephone request from a Customer for Transmission Opportunity Service. The form will be faxed to the Customer upon which the Customer will confirm the information with a signature and fax the completed form back to ATCO Electric Control Centre – (780) 632-5959.

Customer Name: Date of Request:

Time of Request:

1. OPPORTUNITY CONTRACT PERIOD:

Start Date: Start Time:

End Date: End Time:

Number of Hours in Contract Period: Hours

2. TRANSMISSION OPPORTUNITY SERVICE OPTION:

AESO “DEMAND OPPORTUNITY SERVICE”: DOS 7 Minutes:

DOS 1 Hour:

DOS Term:

3. OPPORTUNITY CONTRACT DEMAND: kW

4. BASE DEMAND:

Large General Service/Industrial Price Schedule D31 Base Demand:

kW

Sum of Demands on all Opportunity Service Contracts: kW

Total Base Demand: kW

Confirmation: 1) for ATCO Electric 2) for


Price Schedule T33Transmission Opportunity Rate

Transmission Connected




Availability • For System Access Service, single or three-phase, for all Points of Service throughout the territory

served by the Company that are directly connected to a transmission substation, and do not make any use of distribution facilities owned by ATCO Electric.

• Available only to Points of Service which are eligible as determined by AESO for Demand Opportunity Service, throughout the territory served by the Company from the Alberta Interconnected System for loads greater than 1,000 kW.

• Available only when AESO determines that there is sufficient transmission capacity. Service on this rate is interruptible for transmission system security reasons at AESO’s request.

• The point of service must be equipped with revenue approved time of use metering. The cost of the time of use metering is in addition to the charges in this rate.

• Telemetering is required for all points of service on this rate with demands greater than 2,500 kW, and any associated costs will be in addition to the charges in this rate.

Price Charges for service in any one billing period shall be the sum of the following charges determined for each individual Point of Service. The current approved AESO DOS charges will be those according to the terms of the DOS option selected by the Customer:

Transaction Charge

Demand Charges

Demand Charges

Energy Charges Energy Charges

For all kW of Opportunity

Contract Demand

For the peak kW above the


For all kW.h metered above the Base

Demand, not exceeding the Opportunity Contract

Demand

For all kW.h metered above the Opportunity

Contract Demand

Transmission Per AESO DOS Rate Schedule

- Per Price Schedule T31


Per Price Schedule T31

Distribution - Per Price Schedule T31


- -

Service - Per Price Schedule T31


- -

TOTAL PRICE Per AESO DOS Rate Schedule





The attached form must be completed and submitted to the Company, and serves as an Opportunity Contract which specifies the period and the Opportunity Demand requested by the Customer, as well as the DOS option selected.

The charges according to the AESO DOS Rate Schedule will be the approved charges in effect during the billing period, and will be revised in accordance with AESO’s charges as required.







Application 1. Base Demand - A Customer qualifying for this rate must establish a Base Demand with the

Company on Price Schedule T31 prior to receiving service under this rate.

(a) For existing Customers, the Price Schedule T31 Base Demand will normally be the maximum billing demand in the 12 most recent billing periods.

(b) New Customers qualifying for this rate may select the Large General Service/Industrial T31 Base Demand based on forecast loads and economics, provided the Company agrees that the conditions of applicability are satisfied.

(c) Once established, the Price Schedule T31 Base Demand remains fixed for the purposes of billing all future service on this rate.

2. Applicable Charges - This rate schedule applies in conjunction with rate T31, in that the first block demand charges apply only to the first 500 kW of the combined demand (i.e. T31 and T33, and T31 again should there be an excursion above contracted opportunity demand), and the remainder of the combined demand is subject to the second block demand charges.

3. Options - A Customer requesting service under this rate must select the provisions of one of AESO’s DOS Rate Schedules. The Customer is subject to AESO’s minimum Opportunity Service charges, attributable to that customer.

4. Notice Period - A Customer requesting service under this rate is required to provide notification as prescribed in the AESO tariff in relation to DOS service.

5. Load Curtailment - When a load curtailment directive is given, the load at the point of service must not exceed the Price Schedule T31 Base Demand until the Company gives notification that the interruption period is over, at which time consumption of energy may be resumed.

6. Non-Compliance Charges – In the event of a load curtailment directive, if the load served under this rate is not curtailed for the entire interruption period, any charges incurred by the Company will be charged to the Point of Service on this rate.

7. Price Options – the following price option may apply: Service for Non-Standard Transformation and Metering Configurations Option H(d).

8. Price Adjustments - the following price adjustments may apply: Municipal Assessment (Rider A-1) Balancing Pool Adjustment (Rider B) Temporary Adjustment (Rider G) Interim Adjustment (Rider J)







This form will be completed and signed by ATCO Electric after a telephone request from a Customer for Transmission Opportunity Service. The form will be faxed to the Customer upon which the Customer will confirm the information with a signature and fax the completed form back to ATCO Electric Control Centre – (780) 632-5959.

Customer Name: Date of Request:

Time of Request:

1. OPPORTUNITY CONTRACT PERIOD

Start Date: Start Time:

End Date: End Time:

Number of Hours in Contract Period: Hours

2. TRANSMISSION OPPORTUNITY SERVICE OPTION:

AESO “DEMAND OPPORTUNITY SERVICE”: DOS 7 Minutes:

DOS 1 Hour:

DOS Term:

3. OPPORTUNITY CONTRACT DEMAND: kW

4. BASE DEMAND:

Large General Service/Industrial Price Schedule T31 Base Demand:

kW

Sum of Demands on all Opportunity Service Contracts: kW

Total Base Demand: kW

Confirmation: 1) for ATCO Electric 2) for


Price Schedule D34Large General Service/Industrial

Isolated Industrial Areas




Availability For Distribution Access Service, single or three-phase, for all Points of Service throughout the territory served by the Company from an isolated industrial area. This rate is not applicable for any new Small Oilfield and Pumping Power service with yearly average operating demands of less than 75 kW, effective January 1, 2008.

Price Charges for service in any one billing period shall be the sum of the Customer Charge, Demand Charge, and Charge for Deficient Power Factor, determined for each individual Point of Service.






TOTAL PRICE $2.3340 /day 20.18 ¢/kW/day 16.99 ¢/kW/day -

The billing demand for the Distribution and Service charges shall be the higher of: (a) The highest metered demand during the billing period; (b) 85% of the highest metered demand during the 12-month period including and ending with the

billing period; (c) the estimated demand; (d) the Distribution Contract Demand (DCD); (e) 50 kilowatts.


Charge for Deficient Power Factor - For customer power factor which is less than 90%, an additional charge for deficient power factor of 20.04¢/kV.A/day will be applied to the difference between the highest metered kV.A demand and 111% of the highest metered kW demand in the same billing period.



2. Price Adjustments - the following price adjustments (riders) may apply: Municipal Assessment (Rider A-1) Special Facilities Charge (Rider E) Temporary Adjustment (Rider G) Interim Adjustment (Rider J)


Price Schedule D41Small Oilfield and Pumping Power




Availability For System Access Service and Distribution Access Service, single or three-phase, for all Points of Service throughout the territory served by the Company. This rate is available only to new Points of Service for production energy requirements in the petroleum and natural gas industries including related operations, such as rectifiers, cathodic protection and radio transmitters with yearly average operating demand less than 75 kilowatts, effective January 1, 2008.

Price Charges for service in any one billing period shall be the sum of the Customer Charges, Demand Charges, Energy Charges and charge for Deficient Power Factor, determined for each individual Point of Service.



Distribution 49.88 ¢ / day 45.38 ¢/kW/day -


TOTAL PRICE $1.3607 / day 55.29 ¢/kW/day 0.49 ¢ / kW.h


(a) the highest metered demand during the billing period; (b) 85% of the highest metered demand during the 12-month period including and ending with the

billing period; (c) the estimated demand; (d) if applicable, the Transmission Contract Demand (TCD) applied to Transmission charges, and/or

the Distribution Contract Demand (DCD) applied to Distribution and Service charges; (e) 4 kilowatts.


The 85% ratchet applies only to demand metered loads. The cost of converting an energy meter to a demand meter will be in addition to the charges on this rate.

Estimated Demands - Where it is impractical to meter a point of service, the Company may bill on the basis of estimated maximum demands. In such case, the monthly bill shall be the demand charge above applied to the estimated demand, plus a flat rate of $1.47 per kW in lieu of the charge for energy.

The Metered demand will be the greater of the registered demand in kW, or 90% of the registered demand in kV.A where a kW reading is not available.

Charge for Deficient Power Factor - where a Customer’s power factor is found to be less than 90%, the Company may require such Customers to install corrective equipment. For Customer power factor which is less than 90%, an additional charge for deficient power factor of 44.53¢/kV.A/day will be applied to the difference between the highest metered kV.A demand and 111% of the highest metered kW demand in the same billing period.






Application 1. Demand Metered - where services are demand metered, the meter will normally be read and

reset at least once every two months. 2. Price Options - the following price option may apply:

Idle Service (Option F)

3. Price Adjustments - the following price adjustments (riders) may apply: Municipal Assessment (Rider A-1) Balancing Pool Adjustment (Rider B) Special Facilities Charge (Rider E) Temporary Adjustment (Rider G) Interim Adjustment (Rider J) Interim RRT Adjustment (Rider Q)







Availability For Distribution Access Service, single or three-phase, for all Points of Service throughout the territory served by the Company from an isolated industrial area. This rate is available only to new Points of Service for production energy requirements in the petroleum and natural gas industries including related operations, such as rectifiers, cathodic protection and radio transmitters with yearly average operating demand less than 75 kilowatts, effective January 1, 2008.

Price Charges for service in any one billing period shall be the sum of the Customer Charges, Demand Charges, and charge for Deficient Power Factor, determined for each individual Point of Service:

Customer Charge Demand Charge

Distribution 49.88 ¢ / day 45.38 ¢/kW/day

Service 86.19 ¢ / day -

TOTAL PRICE $1.3607 / day 45.38 ¢/kW/day


(a) The highest metered demand during the billing period;

(b) 85% of the highest metered demand during the 12-month period including and ending with the billing period;


(d) the Distribution Contract Demand (DCD);

(e) 4 kilowatts.


The 85% ratchet applies only to demand metered loads. The cost of converting an energy meter to a demand meter will be in addition to the charges on this rate.

Estimated Demands - Where it is impractical to meter a point of service, the Company may bill on the basis of estimated maximum demands. In such case, the monthly bill shall be the demand charge above applied to the estimated demand.

The Metered demand will be the greater of the registered demand in kW, or 90% of the registered demand in kV.A where a kW reading is not available.

Charge for Deficient Power Factor - where a Customer’s power factor is found to be less than 90%, the Company may require such Customers to install corrective equipment. For Customer power factor which is less than 90%, an additional charge for deficient power factor of 44.53¢/kV.A/day will be applied to the difference between the highest metered kV.A demand and 111% of the highest metered kW demand in the same billing period.







Application 1. Demand Metered - where services are demand metered, the meter will normally be read and

reset at least once every two months.

2. Price Options - the following price options may apply: Idle Service (Option F)

3. Price Adjustments - the following price adjustments (riders) may apply: Municipal Assessment (Rider A-1) Special Facilities Charge (Rider E) Temporary Adjustment (Rider G) Interim Adjustment (Rider J)


Price Schedule D51REA Farm Service




Availability For System Access Service and Distribution Access Service, for all Points of Service throughout the territory served by the Company, for farming operations which are connected to a Rural Electrification Association’s distribution system.

Price • Charges for service in any one billing period are the sum of the Customer, Demand and Energy

charges as indicated below, determined for each individual Point of Service.

• Please refer to individual REA Tariffs to determine applicable REA charges.

REA Farms in O & M Pool


Transmission - 5.22 ¢/kV.A/day 0.48 ¢ / kW.h

Distribution - 8.61 ¢/kV.A/day -

Service 29.16 ¢ / service / day - -

REA Specific Charges See REA Tariff - -

Total Price C1 ¢ / service/ day 13.83 ¢/kV.A/day 0.48 ¢ / kW.h

REA Farms Outside of O & M Pool



Distribution See REA Tariff See REA Tariff -

Service See REA Tariff - -

REA Specific Charges See REA Tariff - -

Total Price C1 ¢ / service /day D1 ¢/kV.A/day 0.48 ¢ / kW.h

kV.A capacity for billing purposes will be determined as follows:

(a) For breakered services of 25 kV.A or less, the kV.A capacity will be set by the breaker size as shown below:

Breaker Amperes 25/41 35/50 50/75 75/110 100/150 200

Transformer Capacity in kV.A 3 5 7.5 10 15 25






(b) For non-breakered REA farm services of 25 kV.A or greater, the kV.A capacity for billing purposes is the greater of:

i. the highest metered kV.A demand during the billing period;

ii. the estimated demand;

iii. 25 kV.A.

REA Specific Charges

Other charges are applied on behalf of the REAs as defined in contracts and are subject to change from time to time.

These charges include operation and maintenance charges and deposit reserve charges, and are in addition to the charges contained in this price schedule.

Application 1. Demand Metering - when the Company determines, by estimation or measurement, that a

25 kV.A breakered service may be overloaded, the company may require replacement of the breaker with a demand meter and modification of the service facilities in accordance with the Terms and Conditions.

2. Price Option - the following price option may apply: Idle Service (Option F)

3. Price Adjustments - the following price adjustments (riders) may apply: Balancing Pool Adjustment (Rider B) Temporary Adjustment (Rider G) Interim Adjustment (Rider J)



Excluding Wire Services Provider Functions




Availability • Applicable to any Rural Electrification Association, for whom the Company is not acting as the wire

services provider, as set out in the EUA. • For all Points of Service throughout the territory served by the Company, for farming operations which

are connected to the Rural Electrification Association’s distribution system.

Price Charges for service in any one billing period are the sum of the Customer, Demand and Energy charges as indicated below, determined for each individual Point of Service.



Distribution - - -

Service 25.18 ¢/service/day - -

TOTAL PRICE 25.18 ¢/service/day 5.22 ¢/kV.A/day 0.48 ¢ / kW.h

kV.A capacity for billing purposes will be determined as follows:

(a) For breakered services of 25 kV.A or less, the kV.A capacity will be set by the breaker size as shown below:

Breaker Amperes 25/41 35/50 50/75 75/110 100/150 200

Transformer Capacity in kV.A 3 5 7.5 10 15 25

(b) For non-breakered REA farm services of 25 kV.A or greater, the kV.A capacity for billing

decision 2009-270 atco electric ltd. · 2018. 2. 23. · as set out in appendix a, schedule 5-b-1,...

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