2016 Electric Resource Plan Modeling Assumptions Update

Transcription

1 Page 1 of 16 Public Service Company of Colorado 2016 Electric Resource Plan Modeling Assumptions Update (CPUC ) August 2017 xcelenergy.com 2016 Xcel Energy Inc. Xcel Energy is a registered trademark of Xcel Energy Inc

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3 Page 3 of ERP PHASE II MODELING ASSUMPTIONS UPDATE Introduction As part of its 2016 Colorado Electric Resource Plan ( 2016 ERP ) filing in Proceeding No. 16A-0396E, Public Service Company of Colorado ( PSCo, Public Service or the Company ) provided a list of modeling assumptions in Section 2.7 of Volume 2 of the 2016 ERP. This list included both discrete values for certain assumptions or, in some cases, the methodologies to be used to develop the values. In its 2016 ERP Phase I Decision (Decision Nos. C and C , collectively referred to as the Phase I Decision ), the Commission either: (1) approved the assumptions and methodologies as originally set forth in Section 2.7 of Volume 2 of the 2016 ERP, or (2) modified certain assumptions and methodologies as explicitly ordered. Paragraph 10 of the Commission s Order in Decision No. C requires as follows: Prior to issuing the all-source RFPs, Public Service shall file a complete list of the Strategist modeling inputs and assumptions consistent with the discussion above [in Decision No. C ]. Accordingly, consistent with the 2016 ERP and the Commission s Phase I Decision, the updated base case and sensitivity values and/or methodologies to be used in Phase II are presented below. 1. Discount Rate 1 Base 6.78% Sensitivity % Sensitivity % 2. Gas Price Forecasts Sensitivity (low), Base, Sensitivity (high): See Table below. 1 Consistent with Decision No. C , the Company will utilize as a base modeling assumption a 6.78% discount rate for purposes of calculating net present values (NPVs) associated with each modeled resource portfolio. In calculating the revenue requirements of ownership bids, the Company will use its most current projection of financing costs. 3

4 Page 4 of 16 Table Fuel and Market Price Inputs CIG Rocky Mountain 4-Corners Gas Price Forecast Electric Market Price Forecast Coal Price Forecast ($/mmbtu) ($/MWh) ($/mmbtu) Low Base High On-Peak Off-Peak Base

5 Page 5 of Gas Transportation Costs Updated costs applied in Phase II Solicitation will be based on gas generator location. 4. Firm Fuel Charges Updated costs applied in Phase II Solicitation will be based on gas generator location. 5. Market Prices See above Gas Price Forecast section. 6. Gas Price Volatility Mitigation ( GPVM ) Adder Base Sensitivity $0.00 /MMBtu $0.468 /MMBtu 7. Coal Price Forecasts See above Gas Price Forecast section. 8. Reserve Margin Reserve Margin 16.3% 9. Surplus Capacity Credit Base RAP: 100 Base Post RAP: 100 $2.79/kW-mo for 4 months of each year. $/kw-mo the cost of a generic combustion turbine for all twelve months of a year. N/A 10. Seasonal Capacity Purchases 11. CO 2 Price Forecasts Base Sensitivity 1 Sensitivity 2 Sensitivity 3 $0.00 / ton-co2 High Case 3-Source Blend Low Case CPP Blend Social Cost of Carbon 5

6 Page 6 of 16 $/Short Ton $/Metric Ton Year High Case 3-Source Blend Low Case CPP Blend Social Cost of Carbon 2010 $ $ $ $ $ $ $ $ $ $ $ $ $20.00 $1.86 $ $20.49 $2.79 $ $20.99 $4.21 $ $21.50 $4.63 $ $22.02 $6.65 $ $22.56 $8.69 $ $23.11 $10.79 $ $23.68 $12.97 $ $24.25 $15.06 $ $24.85 $15.43 $ $25.45 $15.81 $ $26.07 $16.19 $ $26.71 $16.59 $ $27.36 $16.99 $ $28.03 $17.41 $ $28.71 $17.83 $ $29.41 $18.27 $ $30.13 $18.71 $ $30.87 $19.17 $ $31.62 $19.64 $ $32.39 $20.12 $ $33.18 $20.61 $ $33.99 $21.11 $ $34.82 $21.63 $ $35.67 $22.15 $ $36.54 $22.69 $ $37.43 $23.25 $ $38.34 $23.81 $ $39.28 $24.40 $ $40.24 $24.99 $ $41.22 $25.60 $ $42.23 $26.23 $ $43.26 $26.86 $76 6

7 Page 7 of Inflation / Construction Escalation Rates Escalation Rate 2.0% 13. Demand Side Management Forecasts Table 2.7-3: Demand Reduction Goals Dispatchable DR Goal (MW) Transmission Delivery Costs Updated costs applied in Phase II Solicitation will be based on proposed generator location. 15. Transmission Interconnection Costs Updated costs applied in Phase II Solicitation will be based on proposed generator location. 16. ELCC Capacity Credit for Wind Resources Existing Wind 16.0% Incremental Wind See Table below Table 2.7-4: Average ELCC to Apply to Incremental Wind (MW_AC) Northern Limon Lamar % 9.8% 18.8% % 9.2% 16.9% % 8.4% 14.0% 17. ELCC Capacity Credit for Solar Resources Existing Utility-Scale Solar 55.0% Existing Distribution-Interconnected Solar 37.0% Incremental Solar See Table below Table 2.7-5: Average ELCC to Apply to Incremental Solar Northern Front Range San Luis Valley Western Slope (MW_AC) Fixed Tracking Fixed Tracking Fixed Tracking % % 41.5% 13.5% 52.5% 41.5% 53.0% % 40.2% 42.2% 50.4% 41.0% 52.0% % 37.8% 39.1% 47.1% 39.0% 49.5% % 33.2% % 29.1% 7

8 Page 8 of Resource Acquisition Period May 2016 to May 2024 (8-year RAP) 19. Planning Period June 1, 2016 June 1, SO 2 Effluent Costs and Allocations Base $0.00/ton-SO NO x Effluent Costs and Allocations Base $0.00/ton-NOx 22. Mercury Effluent Costs and Allocations Base $0.00/ton-Hg 23. Spinning Reserve Requirement Rocky Mountain Reserve Group ("RMRG") Requirement: 210 MW This requirement is a function of how the RMRG designates the Most Severe Single Contingency ( MSSC ) and therefore can change with changes to the group s generation and transmission systems. To the degree that a single bid or portfolio of bids may increase the MSSC going forward, the Company will include a cost estimate of the resulting cost increase in the Company s spinning reserve requirement within its bid evaluation. The Company will make available to bidders the incremental spinning reserve cost (on a $/MWh basis) to be applied in the bid evaluation no later than September 28, 2017 (the date of the Pre-Bid Conference). 24. Emergency Energy Costs Energy Cost $500/MWh 25. Dump Energy / Wind Curtailment Costs Costs = Energy * (PTC/(1-tax rate) 26. Wind Integration Costs See Table below. 8

9 Page 9 of 16 Table Wind Integration Costs Incremental Wind Integration Costs ($/MWh) for Additional Wind in RAP 1 0MW* 200MW 400MW 600MW 800MW 1000MW 1200MW $0.00 $3.24 $3.30 $3.33 $3.36 $3.39 $ $0.00 $3.40 $3.47 $3.50 $3.54 $3.57 $ $0.00 $3.59 $3.67 $3.71 $3.75 $3.79 $ $0.00 $3.82 $3.92 $3.96 $4.01 $4.06 $ $0.00 $4.04 $4.14 $4.20 $4.25 $4.30 $ $0.00 $4.20 $4.31 $4.37 $4.43 $4.48 $ $0.00 $4.29 $4.41 $4.47 $4.53 $4.60 $ $0.00 $4.40 $4.53 $4.60 $4.66 $4.73 $ $0.00 $4.26 $4.40 $4.47 $4.53 $4.60 $ $0.00 $4.39 $4.54 $4.61 $4.69 $4.76 $ $0.00 $4.51 $4.66 $4.74 $4.82 $4.90 $ $0.00 $4.61 $4.77 $4.85 $4.94 $5.02 $ $0.00 $4.57 $4.75 $4.83 $4.92 $5.01 $ $0.00 $4.17 $4.70 $4.80 $4.89 $4.98 $ $0.00 $4.22 $4.78 $4.87 $4.97 $5.06 $ $0.00 $3.78 $4.60 $4.79 $4.92 $5.03 $ $0.00 $3.87 $4.74 $4.94 $5.07 $5.19 $ $0.00 $3.92 $3.92 $4.20 $4.52 $4.73 $ $0.00 $3.99 $3.99 $3.99 $3.99 $4.15 $ $0.00 $4.04 $4.04 $4.04 $4.04 $4.20 $ $0.00 $4.10 $4.10 $4.10 $4.10 $4.10 $ $0.00 $4.15 $4.15 $4.15 $4.15 $4.15 $ $0.00 $4.20 $4.20 $4.20 $4.20 $4.20 $ $0.00 $4.25 $4.25 $4.25 $4.25 $4.25 $ $0.00 $4.31 $4.31 $4.31 $4.31 $4.31 $ (1) Represents the incremental cost applied to all additional MWH of generation. Blank cells indicate no applicable generation in given year due to lack of additional resources. Assumes a 2020 COD with a 25- year life and CF of 41.5% * Includes Rush Creek 9

10 Page 10 of Wind Induced Coal Plant Cycling Costs Per Commission Decision No. C , the Company will use the results from its most recent wind and solar-induced coal plant cycling study. This study was filed in Proceeding No. 16A- 0396E as Attachment KLS Solar Integration Costs Table Average Solar Integration Costs (All Scenarios) $/MWh (All Scenarios) 2016 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $

11 Page 11 of $ $0.62 (1) Represents the average cost applied to all applicable annual MWh of generation. Solar Integration costs do not vary by scenario. 29. Owned Unit Modeled Operating Characteristics and Costs a. Maximum Capacity b. Minimum Capacity Rating c. Seasonal Deration d. Heat Rate Profiles e. Variable O&M f. Fixed O&M g. Maintenance Schedule h. Forced Outage Rate i. Emission rates for SO 2, NO x, CO 2, Mercury and PM j. Contribution to spinning reserve k. Fuel prices l. Fuel delivery charges 30. Thermal PPA Operating Characteristics and Costs a. Contract term b. Maximum Capacity c. Minimum Capacity Rating d. Seasonal Deration e. Heat Rate Profiles f. Energy Schedule g. Capacity Payments h. Energy Payments i. Maintenance Schedule j. Forced Outage Rate k. Emission rates for SO 2, NO x, CO 2, Mercury and PM l. Contribution to spinning reserve m. Fuel prices n. Fuel delivery charges 31. Renewable Energy PPA Operating Characteristics and Costs a. Contract term b. Name Plate Capacity c. Accredited Capacity d. Annual Energy e. Hourly Patterns f. Capacity Payments g. Energy Payments h. Integration Costs i. Emission rates for SO 2, NO x, CO 2, Mercury and PM if applicable 11

12 Page 12 of Load Forecast Table Actual and Forecasted Summer Native Load Peak Demand Annual Growth Compound Growth to/from 2016 MW Base Base Base , % -0.3% , % 0.0% , % -0.4% , % 0.0% , % 1.1% , % 0.9% , % -0.7% , % -0.3% , % 0.2% , % 3.5% , % 4.8% , % 0.0% , % -2.0% , % -0.4% , % 0.0% , % 0.3% , % 0.4% , % 0.4% , % 0.8% , % 0.8% 12

13 Page 13 of 16 Table Actual and Forecasted Annual Native Load Energy Sales GWh Annual Growth Compound Growth to/from 2016 Base Base Base , % -0.8% , % -0.9% , % -1.5% , % -1.4% , % -1.0% , % -1.1% , % -1.0% , % -0.3% , % -0.7% , % -0.8% , % -1.0% , % 0.0% , % 1.9% , % 1.4% , % 1.4% , % 1.1% , % 1.3% , % 1.0% , % 1.3% , % 1.3% 13

14 Page 14 of 16 Resource Need In Decision No. C at paragraphs 45 and 46, the Commission directed the Company to develop two resource need scenarios: one scenario corresponding to a need of 0 MW in 2023, and the second scenario based on the Company s updated demand forecast. Table summarizes these resource need scenarios over the RAP. Table Public Service Resource Need Forecast ZERO-NEED SCENARIO Resource Need (MW) UPDATED/UNADJUSTED SCENARIO Resource Need (MW) (454) - Negative values indicate resource shortfall (need). Table below is a Loads and Resources Table representation of the Updated/Unadjusted need scenario in Table above. 14

15 Page 15 of 16 Table PSCo Loads and Resources Company-Owned Coal Subtotal 2,473 1,981 1,981 1,981 1,981 1,981 1,981 Purchased Coal Subtotal Total Coal-Fired Generation 2,623 2,131 2,131 2,131 2,131 2,131 1,981 Company-Owned Gas- Steam Subtotal Company-Owned CC Subtotal 1,836 1,836 1,836 1,836 1,836 1,836 1,836 Purchased CC Subtotal Total Gas-Fired CC ,215 2,215 2,086 2,086 2,086 2,086 1,954 Company-Owned CT Subtotal Purchased CT Subtotal Total Gas-Fired CT 1,070 1,070 1,070 1,070 1, ,793 1,793 1,793 1,793 1,793 1,537 1,537 Total Gas-Fired Generation 4,008 4,360 4,231 4,231 4,231 3,975 3,843 Company-Owned Storage Subtotal Purchased Biomass Subtotal Company-Owned Hydro Subtotal Purchased Hydro Subtotal Total Hydro Company-Owned Solar Subtotal Purchased Solar Subtotal Customer Choice Solar Total Total Solar

16 Page 16 of 16 Table PSCo Loads and Resources Company-Owned Wind Subtotal Purchased Wind Subtotal Total Wind Total Renewable Generation ,108 1,145 1,181 1,210 Net Dependable Capacity 7,541 7,388 7,308 7,471 7,508 7,288 7,035 PSCo Load 6,532 6,616 6,671 6,733 6,792 6,846 7,029 Interruptible Load (555) (575) (598) (623) (623) (623) (623) Firm Obligation Load 5,977 6,041 6,073 6,110 6,169 6,223 6,406 Reserve Margin Requirement (MW) ,006 1,014 1,044 IREA & HCEA Backup Reserves Total Reserve Margin Requirement 1,014 1,025 1,030 1,036 1,046 1,054 1,084 Reserve Margin Actual 1,568 1,348 1,236 1,362 1,340 1, Resource Position: Long/(Short) (454) 16