Value and Cost of Distributed Generation ACC Staff Workshop #1 – May 7, 2014 Docket No. E-00000J DG Valuation ─ Lessons from the APS Distributed Energy and Net Metering Technical Conference Bob Davis Principal and Executive Consultant nFront Consulting LLC

Conference Overview APS Distributed Energy and Net Metering Technical Conference

22 ACC decision ordered that “APS shall conduct a multi- session technical conference to evaluate the costs and benefits of Distributed Renewable Energy and Net Metering” Six workshops and forums held February 21, 2013 through May 28, 2013 Over 180 registered stakeholders and presenters included representatives from local and national solar industries, environmental groups, consumer groups, regulatory interests, and electric utilities Presentations provided by content experts enlisted by the stakeholders, APS and the conference Facilitator Cost-benefit matrix developed summarizing stakeholder perspectives on costs and benefits of DE Facilitator’s Report issued July 8, 2013

33 APS Distributed Energy and Net Metering Technical Conference Major topics covered:  DE and net metering activities and regulatory trends throughout the U.S.  Concepts of electric utility retail ratemaking  Review of APS rates and potential cost shifting caused by solar DE  Electric utility avoided cost concepts and APS planning for solar DE  Solar DE evaluation models and approaches  Stakeholder studies of costs and benefits of net metering and DE costs and benefits for APS  SAIC update of the 2009 R. W. Beck Study of DE value

44 DE Cost and Benefit Categories Stakeholder Agreement Stakeholders, including APS, reached agreement on categories of costs and benefits that should be considered when evaluating DE Avoided utility costs (benefits):  Fuel and purchased power  Variable operations and maintenance  Environmental compliance  Avoided generation capacity investment  Fixed operation and maintenance costs for avoided generation capacity  Electric system losses  Avoided transmission and distribution investments Incurred utility costs:  Utility integration costs  Program administration costs

55 DE Cost and Benefit Categories Stakeholder Disagreement Fuel hedging Market price mitigation Cost of ancillary services Value of ancillary services provided by DE RES avoided costs Non-compliance environmental impacts Decommissioning costs Ratepayer cross- subsidization Utility systems costs Grid security Marginal value of reduced water consumption Health effects Economic development and jobs Civic engagement / conservation awareness Energy subsidies Technology synergies Ratepayer / consumer interest Stakeholders could not agree that the following should be included when computing utility benefits of DE

66 DE Costs and Benefits – Methodologies Stakeholders generally did not reach agreement on methodologies for computing costs and benefits (even when agreeing on categories) Computation of avoided generation capital and fixed O&M costs  Generic or avoided planned facilities  Incremental capacity reduction or size of avoided facilities  Timing (current year or date of avoided facilities) Computation of transmission and distribution avoided facilities/costs  Average embedded costs/rates or avoided planned facilities  Size and timing (similar to generation avoided costs)  System-wide assessment or analysis of specific circuits

77 DE Costs and Benefits – Methodologies (cont.) Stakeholders generally did not reach agreement on methodologies for computing costs and benefits (even when agreeing on categories) Avoided energy costs (simulated dispatch or market price) Electric system losses (average or marginal losses) Integration costs / ancillary services:  Incremental operating costs to respond to intermittent solar DE production  Value of voltage control from solar DE Treatment of avoided costs in current APS rates:  APS rates set through embedded not marginal cost treatment  Life-cycle benefits produced by DE installations are not permitted in rate setting

Technical Considerations DG Valuation

99 Comparison of Value of Solar DE Presented at APS DE/NEM Technical Conference Value of Solar for APS System – Expected / Base Case (¢/kWh) Cost-Benefit Category SAIC Update Nominal $ Crossborder Study 2014 $ Avoided Fuel, Var. O&M, Purchase Power Avoided Emission Costs Avoided Gen. Capacity, Fixed O&M, NG Trans Avoided Transmission Costs Avoided Distribution Costs Renewable Benefits n/a 4.5 Integration Cost n/a Total Value of Solar DE

10 Comparison of Value of Solar DE (cont.) Differences in Assumptions and Methodology Avoided Cost Crossborder StudySAIC Update All CategoriesProjected 20 year levelized costSingle year avoided cost Generation Energy Costs Market energy cost (blend of CT and CC energy costs) APS generation simulation Emission Costs Does not include CO2 costsIncludes avoided CO2 costs Generation Capacity Costs ELCC at 50%, 15% capacity reserves, avoided ancillary services ELCC at 30% (2020) and 21% (2025), includes capacity reserves Transmission Facility Cost Assumes marginal cost of transmission all years, 50% ELCC Small deferred expansion project in 2025 Distribution Facility Cost Assumes marginal cost of distribution all years, 50% ELCC No deferred expansion projects Renewable Benefits Includes incremental value of RPS, portfolio diversity, grid security, etc. No incremental RPS benefits

11 Technical Modeling Issues Effective Load Carrying Capability (ELCC) is expected to decline with additional DE/DG installations  ELCC is specific to the DE/DG technology being added  Capacity reserves should be added only if ELCC approach does not already encompass impact on reserves Avoided energy cost can be less than the average operating cost of CT and CC resources  Other lower-cost resources can contribute to a utility’s marginal costs (e.g., coal generation, purchased power)  Marginal operating costs of generating units are less than average operating costs  Significant DE/DG implementations can introduce inefficiencies in utility operations

12 Technical Modeling Issues (cont.) Avoided transmission and distribution costs require detailed study  Specific expansion/upgrade projects should be considered (do projects exist that can be deferred or avoided)  T&D facility costs should be segregated costs that can be avoided (e.g., wires) and those that cannot (e.g., metering)  ELCC or Peak Load Reduction (PLR) for T&D should be evaluated by feeder or line  System reliability and security must be considered (the impact of DE/DG intermittency at a feeder level should be evaluated)  Voltage control and other distributed grid benefits of DE/DG should be investigated

13 Coincidence of Solar DE Shape with Utility Loads

14 Dependable Capacity Diminishes with Increasing Solar DE Penetration

15 Dependable Capacity Diminishes with Increasing Solar DE Penetration

16 Dependable Capacity Diminishes with Increasing Solar DE Penetration

17 Dependable Capacity Diminishes with Increasing Solar DE Penetration

18 Dependable Capacity Diminishes with Increasing Solar DE Penetration

19 Dependable Capacity Diminishes with Increasing Solar DE Penetration

20 Dependable Capacity Diminishes with Increasing Solar DE Penetration

21 Dependable Capacity Diminishes with Increasing Solar DE Penetration

22 ELCC Decreases with Increasing Solar DE Penetration Expected Penetratio n in 2025

23 Rate Design Considerations One size does not fit all  Costs and benefits of DE/DG will vary by technology and application  Rate design, whether NEM or “value of” tariffs, need to accommodate different DE/DG technologies DE/DG impacts some areas of utility operations and costs more than others  Rates (or offsets) should be matched to the value received from DE/DG  Fixed and variable costs avoided through DE/DG are more readily assigned through energy and demand rates  Unbundled rates permit more direct assignment of DE/DG benefits Incremental impacts of DE/DG may need to be considered  Future DE/DG installations may reduce utility fixed costs less than installations made today (due to lower ELCC)  Rate design will need to consider whether to treat DE/DG customers on an average or incremental basis