DERIVATION OF PROPOSED CHANGES TO SRP s TRANSMISSION AND ANCILLARY SERVICES PRICES EFFECTIVE APRIL 1, 2015

Transcription

1 DERIVATION OF PROPOSED CHANGES TO SRP s TRANSMISSION AND ANCILLARY SERVICES PRICES EFFECTIVE APRIL 1, 2015 SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT DECEMBER 12, 2014

2 TABLE OF CONTENTS DERIVATION OF PROPOSED CHANGES TO SRP s TRANSMISSION AND ANCILLARY SERVICES PRICES... 3 I. Prices for Ancillary Services... 3 II. Prices for Wholesale Transmission Services... 6 III. Real Power Losses... 7 PROPOSED PRICE SCHEDULES... 8 Scheduling, System Control and Dispatch Service... 9 Reactive Supply and Voltage Control from Generation Sources Service Regulation and Frequency Response Service Energy Imbalance Service Network Integration Service Operating Reserve Spinning Reserve Service Operating Reserve Supplemental Reserve Service Long-Term Firm and Short-Term Firm Point-to-Point Transmission Service Non-Firm Point-to-Point Transmission Service Annual Transmission Revenue Requirement for Network Integration Transmission Service. 17 Real Power Loss Service COST SUPPORT EXHIBITS AND TABLES Exhibit A Ancillary Service Scheduling, System Control and Dispatch Service Exhibit B Ancillary Service Reactive Supply and Volatage Control From Generation Sources Service Exhibit C Ancillary Service Regulation and Frequency Response Service Exhibit D Ancillary Service Spinning Reserve Exhibit E Ancillary Service Supplemental Reserve

3 Exhibit F Firm Point-to-Point Transmission Service Exhibit G Non-Firm Point-to-Point Transmission Service Table 1 Monthly Peaks for Fiscal Year Table 2 Annual Average Hourly Load Fiscal Year Table 3 Revenue Requirements Table 3 Revenue Requirements (Continued)

4 DERIVATION OF PROPOSED CHANGES TO SRP s TRANSMISSION AND ANCILLARY SERVICES PRICES Effective: April 1, 2015 In conjunction with the Proposed Adjustments to SRP s Standard Electric Price Plans Effective with the April 2015 Billing Cycle, this document provides financial details in support of the proposed adjustments to prices for retail ancillary services, and SRP s prices for wholesale transmission and ancillary services. Specifically, management proposes that the prices associated with Schedules 1 through 8, Schedule 10, and Attachment H of SRP s Open Access Transmission Tariff be adjusted to reflect current costs and loads. Schedules 1 through 8, Schedule 10, and Attachment H include the prices for Ancillary Services, Firm Point-to-Point Transmission Service, Non-Firm Point-to-Point Transmission Service, and the Annual Transmission Revenue Requirement for Network Integration Transmission Service. The prices for ancillary services are based on a historical test year, SRP s Fiscal Year 2013 (financial reporting year ending April 30, 2013). The prices for transmission are based on a projected test year, SRP s budget year 2016 (budgeting year ending April 30, 2016). SRP s prices for transmission and ancillary services were calculated using data from SRP s Fiscal Year 2013 accounting data, the Unbundled Revenue Analysis in Support of Proposed Adjustments to SRP s Standard Electric Price Plans Effective With the April 2015 Billing Cycle (Unbundled Revenue Analysis), Power Operations data, audited financial and accounting records, and budgets. Management s proposed changes are summarized below, followed by the proposed prices and supporting cost tables. I. Prices for Ancillary Services Schedule 1 - Scheduling, System Control and Dispatch Service Scheduling, System Control and Dispatch Service is required to schedule the movement of power through, out of, within, or into a Control Area. The rate for Scheduling, System Control and Dispatch Service is determined from FERC Account 561, Load Dispatch for Transmission and SRP s Transmission System Peak for retail and long-term wholesale commitments. The proposed rate is $1.14/kW-year, an increase from the current rate of $1.09/kW-year. Exhibit A in the Cost Support Exhibits and Tables section of this report contains the calculation of the rate for Scheduling, System Control and Dispatch Service. 3

5 Schedule 2 Reactive Supply and Voltage Control from Generation Sources Service The shared production plant costs associated with Reactive Supply and Voltage Control from Generation Sources Service were determined from the cost of Turbogenerator Systems and Accessory Electric Equipment and the ratio of the VAR rating squared to the sum of the VAR rating squared and the MW rating squared of the generation units supplying this service. This share is applied to fixed production cost to determine the annual cost of supplying this service. The proposed rate is $1.16/kW-year, a decrease from the current rate of $1.27/kW-year. Exhibit B in the Cost Support Exhibits and Tables section of this report contains the calculation of the rate for Reactive Supply and Voltage Control from Generation Sources Service. Schedule 3 - Regulation and Frequency Response Service Regulation and Frequency Response Service is accomplished by committing on-line generation whose output is raised or lowered (predominantly through the use of automatic generating control equipment) as necessary to follow the moment-by-moment changes in load. The annual cost for Regulation and Frequency Response Service is based on the fixed costs of the generating resources providing this service. A regulation reserve of +/- 50 MW was applied to the average hourly load of SRP s network system customers to determine the required regulation reserve of 3.12%. The regulation reserve for a Transmission Customer is determined by multiplying the Transmission Customer s hourly load by the required regulation reserve of 3.12%. The proposed rate is $7.82/MW-hour, an increase from the current rate of $1.57/MWhour. The rate is applied to the customer s required regulation reserve. The increase in the rate is primarily attributable to changes in the resource mix that contribute toward this service. Exhibit C in the Cost Support Exhibits and Tables section of this report contains the calculation of the rate for Regulation and Frequency Response Service. Schedule 4 - Energy Imbalance Service - Network Integration Service Energy Imbalance Service is provided when a difference occurs between the scheduled and the actual delivery of energy to a load located within a control area, or deliveries of power and energy out of the control area from generation resources located within the control area, over a single hour. SRP must offer this service when the transmission service is used to serve load within its control area. The transmission customer must either purchase this service from SRP or make alternative comparable arrangements, which may include use of non-generation resources capable of providing this service, to satisfy its Energy Imbalance Service obligation. The Board of Directors of SRP has approved the revised methodology for Energy Imbalance Service that is consistent with the practices of other transmission providers in the region, and meets the requirements of the FERC pro forma Open Access Transmission Tariff. 4

6 Schedule 5 - Operating Reserve Spinning Reserve Service Operating Reserve - Spinning Reserve Service is needed to serve load immediately in the event of a system contingency. Spinning Reserve Service may be provided by generating units that are on-line and loaded at less than maximum output. The annual cost for Spinning Reserve Service is based only on the fixed costs of the resources providing this service since this service requires generating units to spin unloaded. A study performed by SRP Transmission and Generation Operations determines the resources used to provide spinning reserves. A spinning reserve requirement of 1.5% in every hour, consistent with regional reliability requirements, is required. The spinning reserve for a Transmission Customer is determined by multiplying the Transmission Customer s hourly load by the required spinning reserve of 1.5%. The proposed rate is $16.29/MW-hour, an increase from the current rate of $4.84/MWhour. The rate is applied to the customer s required spinning reserve. The increase in this rate is primarily attributable to the NERC mandatory Reliability Standard BAL-002-WECC-2, effective October 1, 2014, that reduced the spinning reserve percentage from 3.5% to 1.5%. Exhibit D in the Cost Support Exhibits and Tables section of this report contains the calculation of the rate for Operating Reserve Spinning Reserve Service. Schedule 6 - Operating Reserve Supplemental Reserve Service Operating Reserve - Supplemental Reserve Service is needed to serve load in the event of a system contingency; it is not available immediately to serve load but rather within a short period of time. SRP s supplemental reserves are provided by generating units and firm wholesale purchases. Only the fixed (demand related) costs associated with these resources are included in the annual cost of Operating Reserve - Supplemental Reserve Service. SRP s Southwest Reserve Sharing accounting data are used to determine the resources used to provide supplemental reserves. A supplemental reserve requirement of 1.5% in every hour, consistent with regional reliability requirements, is required. The supplemental reserve for a Transmission Customer is determined by multiplying the Transmission Customer s hourly load by the required supplemental reserve of 1.5%. The proposed rate is $20.51/MW-hour, an increase from the current rate of $7.76MWhour. The rate is applied to the customer s required supplemental reserve. The increase in this rate is primarily attributable to the NERC mandatory Reliability Standard BAL-002-WECC-2, effective October 1, 2014, that reduced the spinning reserve percentage from 3.5% to 1.5%. Exhibit E in the Cost Support Exhibits and Tables section of this report contains the calculation of the rate for Operating Reserve Supplemental Reserve Service. 5

7 II. Prices for Wholesale Transmission Services The proposed prices for Firm and Non-Firm Point-to-Point wholesale transmission services have increased, for prices effective April 1, The annual transmission revenue requirement has increased to a greater extent than the loads and transmission reservations used to calculate the prices. The prices in Schedules 7 and 8 are applicable to wholesale entities. Prices for transmission service (including Must-Run service) applicable to retail customers are included in SRP s Proposed Adjustments to Standard Price Plans Effective with the April 2015 Billing Cycle. The inclusion of Must-Run costs is consistent with the Resolution of The Board of Directors of The Salt River Project Agricultural Improvement and Power District, Setting Forth a Final Decision Adopting Terms and Conditions for Competitive Electric Services, dated August 14, Must-Run costs only apply to SRP s retail customers. Schedule 7 - Long-Term Firm and Short-Term Firm Point-to-Point Transmission Service SRP s rate for Firm Point-to-Point Transmission service is a postage stamp rate applicable to all parts of SRP s transmission system 69kV and above. The proposed Annual Firm Point-to-Point Transmission Rate is $19.48/kW-year, an increase from the current rate of $14.23/kW-Year. The rate is based on SRP s Annual Transmission related costs (exclusive of must-run costs) and SRP s Transmission System Peak. Exhibit F of the Cost Support Exhibits and Tables contains the calculation of the Firm Point-to-Point Transmission Rate. The proposed prices for firm Point-to-Point transmission services are the maximum rates that may be charged for such service. Discounts may be applied. Consistent with SRP's Standard Electric Price Plans effective June 1, 2004, a Transmission Cost Adjustment Factor (TCAF) may be applied to both wholesale and retail customers to collect any new costs resulting from the establishment of regional transmission entities and/or new rules established for the wholesale market. Much discussion continues relating to these topics nationally, and it is possible that new entities or rules may emanate from regulatory or legislative action. If SRP does not incur any such new costs, SRP will not charge the TCAF. As of the effective date of these proposed new prices, the TCAF is set to zero. Schedule 8 - Non-Firm Point-to-Point Transmission Service The prices for Non-Firm Point-to-Point Transmission Service are capped at the prices for Firm Point-to-Point Transmission Service. In addition to the rate caps calculated for Firm Pointto-Point Transmission Service, hourly rate caps have been calculated for On- and Off-peak Non- Firm Point-to-Point Transmission Service. Exhibit G of the Cost Support Exhibits and Tables contains the calculation of the Non-Firm Point-to-Point Transmission Prices. Customers under this service schedule also are subject to the TCAF. 6

8 Attachment H - Annual Transmission Revenue Requirement for Network Integration Transmission Service Attachment H in SRP s Open Access Transmission Tariff describes the annual transmission revenue requirement for the wholesale Network Integration Transmission Service. SRP uses the ratio of the Network Customers Network Load to SRP s total transmission load to allocate SRP s annual transmission revenue requirement to network customers. Attachment H also describes the annual revenue requirement for must-run generation. This service is needed to manage transmission congestion and maintain the reliability of transmission service provided to SRP s retail customers, including both bundled sales customers and Direct Access Program customers taking Network Integration Transmission Service. The annual transmission revenue requirements for Network Integration Transmission Service and for must-run generation are found on page 17 of this document. The increase in the annual transmission revenue requirement was largely driven by the new investment in transmission facilities such as Palo Verde-Southeast Valley-Browning 500- kilovolt (kv) transmission project. The cost of retail Network Integration Transmission Service has been allocated to retail customer classes based on four coincident peaks (4CP) (using peak loads for the months of June through September) of the retail Network Integration Transmission customers, consistent with billing to wholesale customers. Please refer to SRP s Proposed Adjustments to Standard Price Plans Effective with the April 2015 Billing Cycle and SRP s Unbundled Revenue Analysis for transmission charges (inclusive of must-run costs) that are applicable to SRP s retail customers. Customers under this service schedule also are subject to the TCAF. III. Real Power Losses Schedule 10 Real Power Loss Service Real Power Losses, identified in Schedule 10, are associated with all transmission service. SRP is not obligated to provide Real Power Losses. The Transmission Customer is responsible for replacing losses associated with all transmission service as calculated by SRP. The proposed Real Power Loss factor is 3.24 percent (3.24%) unless otherwise specified in a Service Agreement. This is an increase from the current rate of 2.1 percent (2.1%). 7

9 PROPOSED PRICE SCHEDULES 8

10 SCHEDULE 1 Scheduling, System Control and Dispatch Service Scheduling, System Control and Dispatch Service will be provided in accordance with SRP s Open Access Transmission Tariff Schedule 1 at a rate not to exceed: Annually: Monthly: Weekly: Daily: Monday through Saturday Sunday Hourly: On-Peak* Off-Peak** $1.14/kW-year $0.09/kW-month $0.02/kW-week $0.004/kW-day $0.003/kW-day $0.23/MW-hour $0.13/MW-hour *On-Peak Hours for the months of April through September are Monday through Friday beginning hour ending 0700 through hour ending 2200, Mountain Standard Time (MST). On-Peak Hours for the months of October through March are Monday through Friday beginning hour ending 0800 through hour ending 2300, MST. **Off-Peak Hours: all hours other than On-Peak Hours 9

11 SCHEDULE 2 Reactive Supply and Voltage Control from Generation Sources Service Reactive Supply and Voltage Control from Generation Sources Service will be provided in accordance with SRP s Open Access Transmission Tariff Schedule 2 at a rate not to exceed: Annually: Monthly: Weekly: Daily: Monday through Saturday Sunday Hourly: On-Peak* Off-Peak** $1.16/kW-year $0.10/kW-month $0.02/kW-week $0.004/kW-day $0.003/kW-day $0.23/MW-hour $0.13/MW-hour *On-Peak Hours for the months of April through September are Monday through Friday beginning hour ending 0700 through hour ending 2200, Mountain Standard Time (MST). On-Peak Hours for the months of October through March are Monday through Friday beginning hour ending 0800 through hour ending 2300, MST. **Off-Peak Hours: all hours other than On-Peak Hours 10

12 SCHEDULE 3 Regulation and Frequency Response Service Regulation and Frequency Response Service will be provided in accordance with SRP s Open Access Transmission Tariff Schedule 3 at a rate not to exceed: $7.82/MW-hour of Regulation and Frequency Response reserved A Transmission Customer purchasing Regulation and Frequency Response Service will be required to purchase an amount of reserved capacity equal to 3.12% of the Transmission Customer s network load responsibility in each hour for Network Integration Transmission Service. The billing determinants for this service shall be reduced by any portion of the 3.12% purchase obligation that a Transmission Customer obtains from third parties or supplies itself. 11

13 SCHEDULE 4 Energy Imbalance Service Network Integration Service Energy Imbalance Service Network Integration Service will be provided in accordance with SRP s Open Access Transmission Tariff Schedule 4. SRP shall establish charges for energy imbalance based on the deviation bands as follows: (i) deviations within +/- 1.5 percent (with a minimum of 2 MW) of the scheduled transaction to be applied hourly to any energy imbalance that occurs as a result of the Transmission Customer's scheduled transaction(s) will be netted on a monthly basis and settled financially, at the end of the month, at 100 percent of the Hourly Proxy Price; (ii) deviations greater than +/- 1.5 percent up to 7.5 percent (or greater than 2 MW up to 10 MW) of the scheduled transaction to be applied hourly to any energy imbalance that occurs as a result of the Transmission Customer s scheduled transaction(s) will be settled financially, at the end of each month, at 110 percent of the Hourly Proxy Price for under scheduling or 90 percent of the Hourly Proxy Price for over scheduling; and (iii) deviations greater than +/- 7.5 percent (or 10 MW) of the scheduled transaction to be applied hourly to any energy imbalance that occurs as a result of the Transmission Customer s scheduled transaction(s) will be settled financially, at the end of each month, at 125 percent of the Hourly Proxy Price for under scheduling or 75 percent of the Hourly Proxy Price for over scheduling. For purposes of this Schedule, the Hourly Proxy Price is calculated using the published day ahead Intercontinental Exchange ( ICE ) Price Index for the hub pricing and volumes at Palo Verde for firm on-peak and off-peak prices. The hourly prices used for calculating Energy Imbalance Services for the billing month will be posted on SRP s Open Access Same time Information System (OASIS) 10 days after the last day of the billing month. If the Energy Imbalance Service is provided during a time where no volumes were reported at the Palo Verde hub, the most recent firm on-peak and off-peak prices will be carried forward. If the ICE Index permanently ceases to report day ahead pricing for the Palo Verde hub, if the methodology used to determine the index at the Palo Verde hub is materially modified, or if the ICE Index is otherwise no longer commercially acceptable, SRP shall select a permanent replacement index, reported by a reputable third party, that reflects the actual same-day firm transactions at an appropriate hub. There are no further deviations from the pro-forma language for SRP s Open Access Transmission Tariff for Energy Imbalance Service Network Integration Service. 12

14 SCHEDULE 5 Operating Reserve Spinning Reserve Service Operating Reserve Spinning Reserve Service will be provided in accordance with SRP s Open Access Transmission Tariff Schedule 5 at a rate not to exceed: $16.29/MW-hour of Spinning Reserve Capacity A Transmission Customer purchasing Spinning Reserve Service will be required to purchase an amount of reserved capacity equal to 1.5% of the Transmission Customer s network load responsibility in each hour for Network Integration Transmission Service. The billing determinant for this service shall be reduced by any portion of the 1.5% purchase obligation that a Transmission Customer obtains from third parties or supplies itself. 13

15 SCHEDULE 6 Operating Reserve Supplemental Reserve Service Operating Reserve Supplemental Reserve Service will be provided in accordance with SRP s Open Access Transmission Tariff Schedule 6 at a rate not to exceed: $20.51/MW-hour of Supplemental Reserve Capacity A Transmission Customer purchasing Supplemental Reserve Service will be required to purchase an amount of reserved capacity equal to 1.5% of Transmission Customer s network load responsibility in each hour for Network Integration Transmission Service. The billing determinant for this service shall be reduced by any portion of the 1.5% purchase obligation that a Transmission Customer obtains from third parties or supplies itself. 14

16 SCHEDULE 7 Long-Term Firm and Short-Term Firm Point-to-Point Transmission Service Long-Term Firm and Short-Term Firm Point-to-Point Transmission Service will be provided in accordance with SRP s Open Access Transmission Tariff Schedule 7. The Transmission Customer shall compensate SRP each month for Reserved Capacity at prices not to exceed: Yearly Delivery: Monthly: Weekly: Daily: Monday through Saturday Sunday Hourly: On-Peak* Off-Peak** One-twelfth of the demand charge of $19.48/kW-year, billed monthly $1.62/kW-month $0.37/kW-week $0.06/kW-day $0.05/kW-day $3.90/MW-hour $2.22/MW-hour Transmission Cost Adjustment Factor: SRP may increase the Transmission Cost Adjustment Factor to recover transmission related costs or charges incurred by SRP resulting from standardized wholesale market designs, regional transmission organizations, or related activities. * On-Peak Hours for the months of April through September extend from hour ending (HE) 0700 through HE 2200, Mountain Standard Time (MST). On-Peak Hours for the months of October through March extend from HE 0800 through HE 2300, MST. ** Off-Peak Hours: all hours other than On-Peak Hours 15

17 SCHEDULE 8 Non-Firm Point-to-Point Transmission Service Non-Firm Point-to-Point Transmission Service will be provided in accordance with SRP s Open Access Transmission Tariff Schedule 8. The Transmission Customer shall compensate SRP for Reserved Capacity at prices not to exceed: Monthly: Weekly: Daily: Monday through Saturday Sunday Hourly: On-Peak* Off-Peak** $1.62/kW-month $0.37/kW-week $0.06/kW-day $0.05/kW-day $3.90/MW-hour $2.22/MW-hour Transmission Cost Adjustment Factor: SRP may increase the Transmission Cost Adjustment Factor to recover transmission related costs or charges incurred by SRP resulting from standardized wholesale market designs, regional transmission organizations, or related activities. * On-Peak Hours for the months of April through September extend from hour ending (HE) 0700 through HE 2200, Mountain Standard Time (MST). On-Peak Hours for the months of October through March extend from HE 0800 through HE 2300, MST. ** Off-Peak Hours: all hours other than On-Peak Hours 16

18 ATTACHMENT H Annual Transmission Revenue Requirement for Network Integration Transmission Service The annual transmission revenue requirement for purposes of the Network Integration transmission service shall be $250,887,872. An additional $143,010,410 for must-run generation needed to manage transmission congestion and maintain the reliability of the transmission service provided to retail customers is allocated to all of SRP s retail customers, including both bundled sales customers and Direct Access Program customers taking Network Integration transmission service. SRP may increase the Transmission Cost Adjustment Factor to recover transmission related costs or charges incurred by SRP resulting from standardized wholesale market designs, regional transmission organizations, or related activities. 17

19 SCHEDULE 10 Real Power Loss Service Capacity and energy losses occur when a Transmission Provider delivers electricity over its transmission facilities for a Transmission Customer. Beginning October 2, 2000 SRP began offering a Real Power Loss Service to any customer taking Point-to-Point Transmission Services under Part II of the SRP Open Access Transmission Tariff. The Transmission Customer must either purchase this service from SRP or make alternative comparable arrangements to satisfy its Real Power Loss obligation. The amount of, and charges for, Real Power Loss Services are to be based on the prices posted on SRP s OASIS as may be changed from time to time. A Transmission Customer electing this service shall purchase an amount of energy equal to 3.24 percent (3.24%) of the total kilowatt-hours of energy provided by the Delivering Party(ies) at the Point(s) of Receipt unless otherwise specified in a Service Agreement. This service may be elected at the time the reservation is made or any time up to the time the energy is scheduled. A Transmission Customer electing to purchase Real Power Loss Services must do so for all energy scheduled for a particular reservation on a given day. The Transmission Customer will compensate SRP based on the prevailing market price of energy. Such market price is equal to published day ahead Intercontinental Exchange ( ICE ) Price Index for the hub pricing and volumes at Palo Verde for firm on-peak and off-peak prices. If Real Power Loss Service is provided during a time where no volumes were reported at the Palo Verde hub, the most recent firm on-peak and off-peak prices will be carried forward. If the ICE Price Index permanently ceases to report day ahead pricing for the Palo Verde hub, if the methodology used to determine the index at the Palo Verde hub is materially modified, or if the ICE Price Index is otherwise no longer commercially acceptable, SRP shall select a permanent replacement index, reported by a reputable third party, that reflects the actual same-day firm transactions at an appropriate hub. 18

20 COST SUPPORT EXHIBITS AND TABLES 19

21 Exhibit A Ancillary Service Scheduling, System Control and Dispatch Service SOURCE/COMMENT 1. Scheduling, System Control and Dispatch Costs $ 14,673,832 SRP Accounting data Acct Transmission System Peak 12,879,250 kw Table 1 3. Annual Charge $ 1.14 /kw-year Ln. 1/ Ln Monthly Charge $ 0.09 /kw-month Ln. 3/ Weekly Charge $ 0.02 /kw-week Ln. 3/ Daily Charge Monday through Saturday $ /kw-day Ln. 3/ (52 * 6) Sunday $ /kw-day Ln. 3/ (52 * 7) 7. Hourly Charge On-peak $ 0.23 /MWh Ln. 3/ (52 * 6 * 16)) * 1000 Off-peak $ 0.13 /MWh (Ln. 3/ 8760) *

22 Exhibit B Ancillary Service Reactive Supply and Voltage Control From Generation Sources Service 1. Reactive Supply and Voltage Control Costs $14,971,579 Table 3 2. Transmission System Peak 12,879,250 kw Table 1 SOURCE/COMMENT 3. Annual Charge $ 1.16 /kw-year Ln. 1/ Ln Monthly Charge $ 0.10 /kw-month Ln. 3/ Weekly Charge $ 0.02 /kw-week Ln. 3/ Daily Charge Monday through Saturday $ /kw-day Ln. 3/ (52 * 6) Sunday $ /kw-day Ln. 3/ (52 * 7) 7. Hourly Charge On-peak $ 0.23 /MWh Ln. 3/ (52 * 6 * 16)) * 1000 Off-peak $ 0.13 /MWh (Ln. 3/ 8760) *

23 Exhibit C Ancillary Service Regulation and Frequency Response Service 1. Regulation and Frequency Response Costs $ 6,849,288 Table 3 2. SRP Annual Average Hourly Load 3,200,691 kw Table 2 3. Regulation Reserve Requirement (+/- 50,000kW) 3.12% SOURCE/COMMENT 4. Hourly Charge $ 7.82 /MWh Ln. 1 * 1000 /(Ln. 2 * Ln. 3 * 8760) 22

24 Exhibit D Ancillary Service Spinning Reserve 1. Spinning Reserve Costs $ 6,849,288 Table 3 2. SRP Annual Average Hourly Load 3,200,691 kw Table 2 3. Spinning Reserve Requirement 1.50% SOURCE/COMMENT 4. Hourly Charge $ /MWh Ln. 1 * 1000 /(Ln. 2 * Ln. 3 * 8760) 23

25 Exhibit E Ancillary Service Supplemental Reserve 1. Supplemental Reserve Costs $ 8,626,380 Table 3 2. SRP Annual Average Hourly Load 3,200,691 kw Table 2 3. Supplemental Reserve Requirement 1.50% SOURCE/COMMENT 4. Hourly Charge $ /MWh Ln. 1 * 1000 /(Ln. 2 * Ln. 3 * 8760) 24

26 Exhibit F Firm Point-to-Point Transmission Service SOURCE/COMMENT 1. Annual Transmission Related Costs $ 250,887,872 SRP's Unbundled Revenue Analysis Appendix Schedule A-1 2. Transmission System Peak 12,879,250 kw Table 1 3. Annual Charge $ /kw-year Ln. 1/ Ln Monthly Charge $ 1.62 /kw-month Ln. 3/ Weekly Charge $ 0.37 /kw-week Ln. 3/ Daily Charge Monday through Saturday $ 0.06 /kw-day Ln. 3/ (52 * 6) Sunday $ 0.05 /kw-day Ln. 3/ (52 * 7) 7. Hourly Charge On-peak $ 3.90 /MWh Ln. 3/ (52 * 6 * 16)) * 1000 Off-peak $ 2.22 /MWh (Ln. 3/ 8760) *

27 Exhibit G Non-Firm Point-to-Point Transmission Service SOURCE/COMMENT 1. Annual Transmission Related Costs $ 250,887,872 SRP's Unbundled Revenue Analysis Appendix Schedule A-1 2. Transmission System Peak 12,879,250 kw Table 1 3. Annual Charge $ /kw-year Ln. 1/ Ln Monthly Charge $ 1.62 /kw-month Ln. 3/ Weekly Charge $ 0.37 /kw-week Ln. 3/ Daily Charge Monday through Saturday $ 0.06 /kw-day Ln. 3/ (52 * 6) Sunday $ 0.05 /kw-day Ln. 3/ (52 * 7) 7. Hourly Charge On-peak $ 3.90 /MWh Ln. 3/ (52 * 6 * 16)) * 1000 Off-peak $ 2.22 /MWh (Ln. 3/ 8760) *

28 Table 1 Monthly Peaks for Fiscal Year 2013 (Year Ending April 30, 2013) Monthly Coincident Peak Demands (kw) Retail Wholesale Total Jun ,548 6,606 13,154 Jul ,567 6,625 13,192 Aug ,440 6,503 12,943 Sep ,089 6,139 12,228 4CP 6,411 6,468 12,879 Sources: * Monthly Peak Demand Forecast * Supply and Trading Data Notes: * Wholesale includes long-term firm off-system sales and wheeling. 27

29 Table 2 Annual Average Hourly Load Fiscal Year 2013 (Year Ending April 30, 2013) Table 2 Source/Comment 1. Sale to Ultimate Customers (MWh) 27,158,133 System Sales for FY13, Management Operating and Financial Report, April Transmission Losses (@ 3.24%) (MWh) 879,924 Ln. 1 * 3.24% 3. Average Hourly Load (kw) 3,200,691 ((Ln. 1 + Ln. 2) / 8760) *

30 Table 3 Revenue Requirements SRP Revenue requirements for the following: Reactive Supply and Voltage Control from Generation Sources Service Regulation and Frequency Response Service Spinning Reserve Supplemental Reserve Fiscal Year 2013 (Year Ending April 30, 2013) Table 3 Generating Units providing Ancillary Services Cost of Plant Agua Fria - Steam Agua Fria - GT Coronado Craig 29% Crosscut Four Corners 10% Hayden 50% Kyrene - Steam Kyrene - GT Mohave 20% Navajo 21.7% Palo Verde 17.49% Santan Desert Basin Kyrene Combined Cycle Springerville 1 Investment in Plant - Gross $ 60,694,377 $ 24,844,557 $ 1,443,384,978 $ 284,371,552 $ - $ 81,795,231 $ 140,837,783 $ 8,099,404 $ 104,525,056 $ 177,373 $ 336,099,735 $ 1,282,778,471 $ 665,360,520 $ 293,354,537 $ 60,720,502 ############ 2 Investment in Plant - Net of Accumulated Depreciation $ 5,260,117 $ 1,187,629 $ 557,290,478 $ 37,640,963 $ - $ 13,752,160 $ 22,708,772 $ 549,959 $ 61,434,276 $ 103,263 $ 14,069,531 $ 268,919,116 $ 458,564,871 $ 196,649,231 $ 42,417,913 $ 954,741,136 3 Allocation of Common & General and Intangible Plant - Gross $ 4,651,988 $ 1,526,963 $ 71,798,770 $ 11,979,857 $ - $ 3,940,895 $ 6,200,397 $ 531,525 $ 6,859,473 $ 8,380 $ 16,711,766 $ 51,978,599 $ 53,544,900 $ 20,278,522 $ 33,549,425 $ 35,034,444 4 Allocation of Common & General and Intangible Plant - Net $ 1,270,957 $ 356,633 $ 23,111,506 $ 4,717,123 $ - $ 1,209,292 $ 2,010,657 $ 249,445 $ 3,219,156 $ 2,532 $ 5,767,015 $ 19,203,935 $ 32,754,907 $ 10,327,613 $ 24,833,359 $ 15,181,281 5 Total Net Plant (2 + 4) $ 6,531,074 $ 1,544,262 $ 580,401,984 $ 42,358,085 $ - $ 14,961,453 $ 24,719,429 $ 799,404 $ 64,653,432 $ 105,796 $ 19,836,546 $ 288,123,051 $ 491,319,778 $ 206,976,844 $ 67,251,272 $ 969,922,417 6 Committed Capital Factor Total Committed Capital (5 * 6) $ 6,531,074 $ 1,544,262 $ 580,401,984 $ 42,358,085 $ - $ 14,961,453 $ 24,719,429 $ 799,404 $ 64,653,432 $ 105,796 $ 19,836,546 $ 288,123,051 $ 491,319,778 $ 206,976,844 $ 67,251,272 $ 969,922,417 8 Rate of Return 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 9 Annual capital Cost (7 * 8) $ 280,836 $ 66,403 $ 24,957,285 $ 1,821,398 $ - $ 643,342 $ 1,062,935 $ 34,374 $ 2,780,098 $ 4,549 $ 852,971 $ 12,389,291 $ 21,126,750 $ 8,900,004 $ 2,891,805 $ 41,706, O&M Demand Related $ 5,251,224 $ 334,871 $ 25,713,359 $ 10,928,927 $ - $ 6,177,792 $ 5,442,340 $ 3,376,054 $ 18,903,924 $ 449,136 $ 21,253,881 $ 87,288,175 $ 38,888,358 $ 11,314,284 $ 10,981,633 $ 35,797, O&M Fuel $ 12,179,060 $ 6,794,073 $ 122,014,506 $ 33,024,439 $ - $ 20,958,866 $ 18,647,292 $ 5,269,147 $ 23,773,875 $ 161,300 $ 58,461,880 $ 60,460,028 $ 84,130,201 $ 31,074,755 $ 23,773,875 $ 67,846, O&M Energy Related $ 2,770,272 $ - $ 24,944,788 $ 13,751,154 $ - $ 4,666,062 $ 1,843,332 $ 317,703 $ - $ 1,861 $ 11,512,747 $ 35,685,699 $ - $ - $ - $ 13,715, Property Taxes $ 918,178 $ 20,154 $ 9,177,953 $ 915,904 $ 10,135 $ 261,760 $ 406,908 $ 13,067 $ 1,459,651 $ - $ 4,104,227 $ 10,827,677 $ 6,586,325 $ 3,072,529 $ 1,007,831 $ 7,005, Depreciation Expense $ 614,081 $ 96,635 $ 22,478,709 $ 14,767,800 $ - $ 2,313,260 $ 1,944,836 $ 194,389 $ 2,455,998 $ 0 $ 1,591,692 $ 8,249,296 $ 18,530,090 $ 6,667,625 $ 1,691,611 $ 30,045, A&G $ 1,609,483 $ 363,389 $ 8,592,207 $ 3,533,632 $ 53,052 $ 2,340,346 $ 1,402,095 $ 7,535 $ 841,687 $ 31,224 $ 11,036,508 $ 18,468,439 $ 4,753,114 $ 3,686,298 $ 581,151 $ 7,094, Total Annual Cost ( ) $ 23,623,134 $ 7,675,525 $ 237,878,808 $ 78,743,253 $ 63,187 $ 37,361,429 $ 30,749,738 $ 9,212,269 $ 50,215,231 $ 648,070 $ 108,813,906 $ 233,368,605 $ 174,014,838 $ 64,715,495 $ 40,927,905 $ 203,211, Total Demand Related Cost ( ) $ 8,673,803 $ 881,453 $ 90,919,513 $ 31,967,661 $ 63,187 $ 11,736,501 $ 10,259,115 $ 3,625,419 $ 26,441,356 $ 484,909 $ 38,839,280 $ 137,222,878 $ 89,884,637 $ 33,640,740 $ 17,154,030 $ 121,649, Reactive Supply and Voltage Control 3.30% 0.93% 2.27% 0.00% 0.00% 0.00% 0.00% 2.61% 0.00% 0.00% 0.00% 0.00% 1.81% 4.07% 7.56% 2.22% 19 Regulation 0.32% 0.03% 1.04% 0.00% 0.00% 0.08% 0.00% 0.00% 0.04% 0.00% 0.44% 0.00% 1.50% 1.27% 3.50% 2.09% 20 Operating Reserves - Spinning 0.32% 0.03% 1.04% 0.00% 0.00% 0.08% 0.00% 0.00% 0.04% 0.00% 0.44% 0.00% 1.50% 1.27% 3.50% 2.09% 21 Operating Reserves - Supplemental 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.15% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 22 Reactive Supply and Voltage Control Revenue Requirement (17 * 18) $ 285,822 $ 8,162 $ 2,060,043 $ - $ - $ - $ - $ 94,790 $ - $ - $ - $ - $ 1,625,552 $ 1,367,885 $ 1,296,481 $ 2,696, Regulation Revenue Requirement (17 * 19) $ 27,858 $ 267 $ 947,592 $ - $ - $ 9,128 $ - $ - $ 9,290 $ - $ 172,144 $ - $ 1,348,457 $ 426,235 $ 600,679 $ 2,546, Operating Reserves - Spinning Revenue Requirement (17 * 20) $ 27,858 $ 267 $ 947,592 $ - $ - $ 9,128 $ - $ - $ 9,290 $ - $ 172,144 $ - $ 1,348,457 $ 426,235 $ 600,679 $ 2,546, Operating Reserves - Supplemental Revenue Requirement (17 * 21) $ - $ - $ - $ - $ - $ - $ - $ 5,369 $ - $ - $ - $ - $ - $ - $ - $ - Sources: SRP Accounting Data SRP Pow er operations Identified Generating Units providing Ancillary Services SRP's SRSG Reserve Accounting Data 29

31 Table 3 Revenue Requirements (Continued) SRP Revenue requirements for the following: Reactive Supply and Voltage Control from Generation Sources Service Regulation and Frequency Response Service Spinning Reserve Supplemental Reserve Fiscal Year 2013 (Year Ending April 30, 2013) Table 3 Generating Units providing Ancillary Services Cost of Plant Crosscut Horse Mesa - Conventional Horse Mesa - Pumped Storage Mormon Flat - Conventional Mormon Flat - Pumped Storage Roosevelt South Consolidated Stew art Mountain Total Steam and Hydro Retail Interruptible 1 Investment in Plant - Gross $ 624,699 $ 39,577,000 $ - $ 24,116,303 $ - $ 25,510,300 $ 2,857,134 $ 18,481,843 $ 4,898,211,355 $ - 2 Investment in Plant - Net of Accumulated Depreciation $ 256,691 $ 21,827,852 $ - $ 12,274,018 $ - $ 12,885,729 $ - $ 9,859,800 $ 1,737,652,368 $ - $ - 3 Allocation of Common & General and Intangible Plant - Gross $ 20,619 $ 3,056,044 $ - $ 1,997,478 $ - $ 2,609,342 $ 94,304 $ 1,962,461 $ 293,301,707 $ - $ - 4 Allocation of Common & General and Intangible Plant - Net $ 8,918 $ 607,647 $ - $ 389,668 $ - $ 614,160 $ 40,790 $ 470,135 $ 131,165,448 $ - $ - 5 Total Net Plant (2 + 4) $ 265,609 $ 22,435,499 $ - $ 12,663,686 $ - $ 13,499,889 $ 40,790 $ 10,329,934 $ 1,868,817,816 $ - $ - 6 Committed Capital Factor Total Committed Capital (5 * 6) $ 265,609 $ 22,435,499 $ - $ 12,663,686 $ - $ 13,499,889 $ 40,790 $ 10,329,934 $ 1,868,817,816 $ - $ - Purchased Pow er Contracts Total 8 Rate of Return 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 4.30% 9 Annual capital Cost (7 * 8) $ 11,421 $ 964,726 $ - $ 544,539 $ - $ 580,495 $ 1,754 $ 444,187 $ 80,359,166 $ - $ - 10 O&M Demand Related $ 137,040 $ 10,418,206 $ - $ 1,694,057 $ - $ 1,801,622 $ 141,036 $ 1,444,471 $ 261,940,389 $ - $ - 11 O&M Fuel $ 34,927 $ 2,884,738 $ - $ 2,050,326 $ - $ 1,927,853 $ 17,616 $ 823,074 $ 508,461,831 $ - $ - 12 O&M Energy Related $ - $ - $ - $ - $ - $ - $ - $ - $ 95,493,617 $ - $ - 13 Property Taxes $ 10,135 $ 391,117 $ - $ 250,165 $ - $ 205,031 $ 143,486 $ 196,212 $ 39,978,444 $ - $ - 14 Depreciation Expense $ - $ 626,877 $ - $ 550,427 $ - $ 536,064 $ 584,046 $ 419,982 $ 84,313,418 $ - $ - 15 A&G $ 53,052 $ 1,011,452 $ - $ 841,021 $ - $ 306,023 $ 29,489 $ 266,704 $ 59,807,902 $ - $ - 16 Total Annual Cost ( ) $ 246,575 $ 16,297,116 $ - $ 5,930,535 $ - $ 5,357,089 $ 917,427 $ 3,594,630 $ 1,130,354,767 $ - $ - 17 Total Demand Related Cost ( ) $ 211,648 $ 13,412,379 $ - $ 3,880,209 $ - $ 3,429,236 $ 899,811 $ 2,771,556 $ 526,399,319 $ - $ - 18 Reactive Supply and Voltage Control 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 19 Regulation 0.00% 0.28% 0.00% 0.90% 0.00% 20.10% 0.00% 0.00% 0.00% 0.00% 0.00% 20 Operating Reserves - Spinning 0.00% 0.28% 0.00% 0.90% 0.00% 20.10% 0.00% 0.00% 0.00% 0.00% 0.00% 21 Operating Reserves - Supplemental 0.00% 37.86% 0.00% 32.78% 0.00% 33.33% 0.00% 0.00% 0.00% 0.00% 0.00% 22 Reactive Supply and Voltage Control Revenue Requirement (17 * 18) $ - $ - $ - $ - $ - $ - $ - $ - $ 6,738,735 $ - $ - $ 9,435, Regulation Revenue Requirement (17 * 19) $ - $ 37,341 $ - $ 34,911 $ - $ 689,243 $ - $ 83 $ 4,303,227 $ - $ - $ 6,849, Operating Reserves - Spinning Revenue Requirement (17 * 20) $ - $ 37,341 $ - $ 34,911 $ - $ 689,243 $ - $ 83 $ 4,303,227 $ - $ - $ 6,849, Operating Reserves - Supplemental Revenue Requirement (17 * 21) $ - $ 5,077,450 $ - $ 1,271,991 $ - $ 1,143,079 $ - $ 28 $ 7,497,915 $ 1,128,465 $ - $ 8,626,380 Sources: SRP Accounting Data SRP Pow er operations Identified Generating Units providing Ancillary Services SRP's SRSG Reserve Accounting Data 30