Workshop F PECO, an Exelon Company: Electric Rates, Recent Changes, Shopping Opportunities, Capacity Updates, Transmission Charges, Energy Efficiency & Conservation Plan Opportunities, Rebates and Other Regulatory Developments Impacting Rates 2:15 p.m. to 3:15 p.m.
Biographical Information Charis Mincavage McNees Wallace & Nurick LLC 100 Pine Street, P. O. Box 1166 Harrisburg, PA 17108-1166 Ph.: 717.237.5437 / Fax: 717.260.1725 cmincavage@mcneeslaw.com Charis is an attorney with McNees Wallace & Nurick LLC, where she practices in the Energy and Environmental Law Practice Group, focusing on issues involving natural gas, water, and electricity. Charis has represented and counseled large commercial and industrial customers in proceedings before both federal and state administrative agencies, as well as at the appellate level. She advises clients in the procurement of competitive energy services, as well as implementation of self-generation and utilization of alternative energy sources. She also assists clients in analyzing and negotiating wholesale and retail natural gas and electricity contacts, as well as other service requirements. In addition, Charis provides advice on issues related to legislation impacting energy regulation. Charis is a member of the Pennsylvania Bar Association and the Dauphin County Bar Association, and she is admitted to practice before the Supreme Court of Pennsylvania and the United States Supreme Court. She is the former Co-Chair of the American Cancer Society Central Pennsylvania Region Daffodil Days Campaign and is a current member of the Pennsylvania Family Support Alliance Board of Directors. Charis received her bachelor's degree, magna cum laude, from Dickinson College and her law degree, magna cum laude, from the Dickinson School of Law of the Pennsylvania State University. She resides in Hershey, Pennsylvania, with her husband and son. Dr. Lewis C. Cohen, Independent Energy Consultant 104 Woodside Rd. B104, Haverford, PA 19041 620-642-5180 lewiscohen@aol.com Dr. Lewis is an independent energy consultant and some of his clients include: Jefferson Health Systems, Pennsylvania Foundry Association, Association of Independent Colleges and Universities of Pennsylvania and Municipal Utility Alliance.
Workshop F PECO, an Exelon Company: Electric Rates, Recent Changes, Shopping Opportunities, Capacity Updates, Transmission Charges, Energy Efficiency & Conservation Plan Opportunities, Rebates And Other Regulatory Developments Impacting Rates 7th Annual Pennsylvania Energy Management Conference Charis Mincavage Attorney At Law McNees Wallace & Nurick LLC Dr. Lewis Cohen Energy Management And Procurement Consultant PA Energy Management Conference November 8, 2017
DISCLAIMER The information contained in this presentation material is intended to provide generally descriptive and summary information. Any conflict between the information contained in this material, or conveyed orally during the presentation, and the information provided in any of the Companies public filings, as part of Pa Public Utilities Commission Entries or Orders, or the Companies tariffs, or Pa Statutes and Rules, is unintentional and the docketed material controls. The information contained herein is subject to change during the regulatory process. PA Energy Management Conference November 8, 2017 2
OVERVIEW OF ISSUES TO BE DISCUSSED Transmission Formula Rate Filing Distribution Distribution Rate Filing Capacity Reservation Charge Energy Efficiency & Conservation Charge Distribution System Improvement Charge Generation Base Residual Auction Results Balancing Congestion Charges Other Regulatory issues Nuclear Subsidies, GRT, DOE Policy Statement 3
PECO'S FERC FORMULA RATE FILING May 1, 2017: PECO filed a request with FERC to implement formula based rates Updates transmission rates from "stated" to "forward looking" Forward-looking rates can be described as follows Transmission Owner ("TO") establishes a Projected Transmission Revenue Requirement ("PTRR") on a calendar basis TO then reconciles the budget with the Annual Transmission Revenue Requirement ("ATRR") Any difference will be recognized as an addition or subtraction from the following year's PTRR The formula components are used to determine the appropriate PTRR 4
PECO'S FERC FORMULA RATE FILING Purpose of Formula Rate Filing Will enable PECO to recover a $21.7 million gap between transmission costs and the revenues the Company currently receives under existing rates Fixed rate is $20,942/MW/year based upon PECO's $151.7 million transmission revenue requirement set in 1999 Projected revenue request for 2017 is $197 million 5
PECO'S FERC FORMULA RATE FILING Believes formula rate will track transmission revenue requirement as it changes from time to time PECO has indicated gap will get larger in future because transmission costs are increasing while transmission load is declining due to demand management and energy efficiency PECO hopes to facilitate certain transmission investments over the next five years years for a total of $433.5 million Transmission system investments include replacing aging transformers, purchasing spare transformers/ancillary equipment to enhance resiliency, and updating backbone connection to fiber optic technology Reliability Transmission Enhancement Projects include new transformer installations and circuit breakers, as well as higher capacity substation equipment 6
PECO'S FERC FORMULA RATE FILING PECO proposing a rate year to begin on June 1 and end on May 31 PTRR will be established on May 15 of each year with the transmission rate initially based upon projections PECO will provide actual requirement and accompanying true-up on May 15 of each year True-up of any over/under recovery will be billed and collected, with interest, through inclusion in subsequent PTRR PECO proposing to project and true-up based upon calendar year PECO's filing, however, does not clarify how calendar year coordinates with initial May filing Unclear whether initial PTRR covers calendar year 2017, 2018 or some combination of both 7
PECO'S FERC FORMULA RATE FILING Transmission revenue requirement will be based upon several components Return on investment Depreciation O&M Expenses Capital Structure Income Taxes Aforementioned components will constitute PECO's gross revenue requirement Revenue credits and credits for costs charged to other beneficiaries will then be added to achieve the net revenue requirement Net revenue requirement will be divided by the zonal peak load to produce PECO's Network Integrated Transmission Service ("NITS") charge 8
PECO'S FERC FORMULA RATE FILING PECO's formula would provide as follows: Base ROE of 10.5% 50-point adder for participating in PJM Total ROE of 11% Template for calculating PTRR and ATRR Protocols to address questions and challenges to filings 9
PECO'S FERC FORMULA RATE FILING Impact to customers: Recovery of transmission system investment through Network Integrated Transmission System ("NITS") charges Initially will decrease NITS by 6.5% to $19,590/MW-year NITS collected by Electric Generation Suppliers ("EGSs") Allow PECO to recover Regional Transmission Expansion Planning ("RTEP") costs from Transmission Owners Initially will increase Transmission Enhancement Charges ("TEC") by 30% to $11,340/MW-year TEC is collected by PECO through Non-Market Based Transmission ("NMBT") charge 10
PECO'S FERC FORMULA RATE FILING Procedural Implementation PECO requested that transmission rates be implemented on July 1, 2017 Philadelphia Area Industrial Energy Users Group (PAIEUG), Office of Consumer Advocate (OCA), and the Pennsylvania Public Utility Commission (PUC) filed Protests raising issues of concern, challenging certain provisions, and opposing various requirements PECO filed Answer responding FERC issued Letter Order Granted PAIEUG request for 5-month suspension o PECO cannot implement formula rates until Dec. 1, 2017 Rates subject to refund All issues set for hearing Parties must take part in settlement discussions 11
2015 ELECTRIC DISTRIBUTION BASE RATE CASE PECO's 2015 distribution rate case addressed various issues, including a request by PECO to implement a Capacity Reservation Rider ("CRR") Capacity Reservation Rider would: Replace the Auxiliary Service Rider ("ASR") Require customers to reserve capacity on PECO's system for future use Require customers with distributed generation ("DG") to reserve capacity for the nameplate ratings of the DG PAIEUG opposed the CRR Concerns about CRR by PAIEUG included: Proposal based on nameplate ratings Unsure of cost recovery from distributed generation Lack of information regarding cost-causation 12
2015 ELECTRIC DISTRIBUTION BASE RATE CASE Settlement reached in proceeding addressed issues including CRR: Clarified that CRR will be implemented solely on a pilot basis for customers installing DG equipment on or after Jan. 1, 2016 Required PECO to collect further data on alleged cost impacts justifying the pilot CRR and make such data available to all parties prior to expansion of pilot CRR in PECO's next base rate case Customers will not be assessed a CRR payment for "parasitic load" All customers on HT, PD and EP are authorized to enter into negotiations to establish an appropriate CRR rate Clarified the applicable terms and conditions of the pilot CRR CRR will be further reviewed in PECO's next distribution rate proceeding 13
ENERGY EFFICIENCY AND CONSERVATION CHARGE Feb. 2007: Governor Rendell outlined a proposed "Energy Independence Strategy" Oct. 15, 2008: Rendell signed House Bill 2200 (Act 129) into law Included compromise package addressing: Energy Efficiency ("EE") and Demand Side Response ("DSR") programs to be developed by Electric Distribution Companies ("EDCs") Smart meter technology Reorganization of the PUC's bureaus Default service procurement requirements 14
EE&C PHASES TIMELINE Phase I: Start date different for each EDC but generally 2009/2010 timeframe End date May 31, 2013 Phase II: Effective June, 1, 2013-May 31, 2016 Phase III: Effective June 1, 2016-May 31, 2021 Change from three to five years 15
EE&C PHASE I Jan. 20, 2009: PUC issued Phase I Final Implementation Order ("I.O.") Reductions in consumption and peak demand measured by savings approach Percentage goals same for all EDCs 1% and 3% EE goals; 4.5% DR goal Cost recovery Total annual cost may not exceed 2% of EDC's total 2006 revenue Class specific basis Based upon PLC for large commercial/industrial customers 16
EE&C PHASE II Phase II: Effective June, 1, 2013-May 31, 2016 Aug. 3, 2012: PUC issued Phase II Final I.O. EE portion of EE&C Plans extended No demand reduction targets Cost recovery for Phase II EE&C measures is confined to the customer classes that benefit from the measures Total annual cost may not exceed 2% of EDC's total 2006 revenue 17
EE&C PHASE II Adopted the Statewide Evaluator's budgets and reduction targets for Phase II Plans based on 2009/10 energy year forecasts: EDC 3-Yr. Spending Ceiling (total portfolio) 3-Yr. Program Potential Savings (MWh) 3-Yr. Program Acquisition Cost ($/MWh) 3-Yr. % of 2009/10 Forecast Duq. $58,637,855 276,722 $211.90 2.0% Met-Ed $74,600,676 337,753 $220.87 2.3% Penelec $68,924,232 318,813 $216.19 2.2% Penn Power $19,979,352 95,502 $209.20 2.0% PPL $184,504,128 821,072 $224.71 2.1% PECO $256,185,476 1,125,851 $227.55 2.9% West Penn $70,687,404 337,533 $209.42 1.6% Statewide $733,519,122 3,313,247 $221.39 2.3% 18
EE&C PHASE III Phase III: Began June 1, 2016 June 19, 2015: PUC issued Phase III Final I.O. Key issues of interest to Large Commercial and Industrial ("C&I") customers: Program length of 5 years (June 1, 2016-May 31, 2021) Demand Response ("DR") program will utilize the following design: o o o Curtailment events limited to June-Sept. Curtailment events will be called for the first 6 days that the peak hour of PJM's Day-Ahead ("DA") forecast is greater than 96% of the PJM summer peak demand forecast for each year of the program Curtailment events will last 4 hours 19
EE&C PHASE III o o o o Each curtailment event will be called to occur during the day's forecasted peak hours above 96% of PJM's summer peak demand forecast Once 6 curtailment events have been called in a program year, the DR program will be suspended for that program year Compliance will be determined based on the average MW performance across all event hours in a given program year DR programs may allow for dual-participation in Act 129 and PJM's Emergency Load Response Program ("ELRP") EDCs must demonstrate in their Plans that the cost to acquire MWs from customers who participate in PJM's ELRP is no more than half the cost to acquire MWs from customers in the same rate class that are not participating in ELRP 20
EE&C PHASE III EDC Adopted the following peak demand reduction requirements: 5-Year DR Budget Allocation (Million $) Program Acquisition Costs ($/MW/year) Average Annual Potential Savings (MW) % Reduction (Relative to 2007-2008 Peak Demand)* Duquesne $9.77 $57,976 42 1.7% Met-Ed $9.95 $51,210 49 1.8% PECO $42.70 $66,370 161 2.0% Penelec $0.00 $50,782 0 0.0% Penn $3.33 $49,349 17 1.7% Power PPL $15.38 $41,622 92 1.4% West Penn $11.78 $46,203 64 1.8% * % by which EDCs must reduce peak demand for Phase III 21
EE&C PHASE III Adopted the following consumption reduction targets: EDC Portfolio EE Budget Allocation (Million $) Program Acquisition Costs ($/1 st year MWh Saved) 2016-2020 EE Potential Savings % Reduction from 2010 Forecast (MWh) Duquesne $88.0 $199.5 440,916 3.1% Met-Ed $114.4 $190.9 599,352 4.0% PECO $384.3 $195.8 1,962,659 5.0% Penelec $114.9 $202.9 566,168 3.9% Penn Power $30.0 $190.4 157,371 3.3% PPL $292.1 $202.4 1,443,035 3.8% West Penn $106.0 $196.0 540,986 2.6% 22
EE&C PHASE III Carve-out for G/E/NP will be 3.5%, a significant reduction from the 10% G/E/NP carve-out utilized in Phases I and II EDCs will be allowed to bank only those savings attained in Phase II in excess of their targets for application towards Phase III targets; carryover savings may only be savings actually attained in Phase II EDCs are required to rebid all Conservation Service Provider ("CSP") contracts for Phase III 23
EE&C PHASE III Demand Reduction o o o o 0 MW peak demand reduction requirement for the first year of Phase III ending May 31, 2017, with the requirements outlined above applying for the remaining 4 years EDCs must obtain no less than 85% of the MW target in any one event Requires each EDC to achieve at least 85% of the DR target across all events in a given year to be compliant The overall demand reductions must also average to be equal to or greater than the target 50% discount on Act 129 DR incentives for dualenrolled accounts in Act 129 and PJM ELRP 50% of DR incentives if enrolled in both 100% of DR incentives if not enrolled in both 24
EE&C PHASE III Annual/Incremental Consumption Reduction o EDCs must achieve at least 15% of their consumption reduction targets in each program year Comprehensive EE Programs o At least 1 comprehensive EE program for non- Residential customers Plan Evaluation Process o EDCs must submit semiannual reports on Jan. 15 and July 15 of each year, and final annual reports by Nov. 15 that include reported savings for the program year Process to Make Recommendations for Additional Measures o Adopted Phase II expedited review process for minor changes, with one modification in no way precludes Large C&I customers from raising concerns regarding changes in rebates About 1/3 of way through Phase III with one DR summer 25
PETITION FOR ELECTRIC LTIIP AND DSIC Mar. 27, 2015: PECO filed Petition for approval of Long-Term Infrastructure Improvement Plan ("LTIIP") and Distribution System Improvement Charge ("DSIC") Oct. 22, 2015: PUC issued Order approving PECO's LTIIP/DSIC, but referring the following matters to the Office of Administrative Law Judge ("OALJ") for further review Whether PECO should be permitted to apply the DSIC to all rate schedules, including transmission voltage rates Whether revenues associated with the riders in PECO's tariff are properly included as distribution revenues 26
PETITION FOR ELECTRIC LTIIP AND DSIC Several rounds of settlement discussions were held May 8, 2017: Joint Petition for Complete Settlement DSIC formula only includes the qualifying revenues listed in Paragraph 27(b) of the Settlement Fixed Charge Variable Distribution Charge High Voltage Discount Applicable Riders Consumer Education Charge ("CEC") Energy Efficiency and Conservation ("EE&C") Charge Universal Service Fund Charge Tax Accounting Repair Credit ("TARC") 27
PETITION FOR ELECTRIC LTIIP AND DSIC DSIC calculation appropriately excludes the Nuclear Decommissioning Cost Adjustment ("NDCA"), the Non- Bypassable Transmission Charge ("NBT") and the State Tax Adjustment Clause ("STAC"), as such charges are not linked to distribution revenues Prior to PECO's next rate case, it will focus on including a more granular definition of distribution system costs for customers taking service at transmission voltage levels or at or within one span of a PECO-owned substation (i.e., transmission-transformed service) o Will enable parties to address appropriate application of the DSIC in PECO's next rate case o Research ensures that sufficient information is available to determine whether DSIC should be applied to all customers (or whether some customers should be excluded from the DSIC because they receive service from transmission assets) o Provides parties the opportunity to address these issues in PECO's next rate case 28
NUCLEAR DECOMMISSIONING COST ADJUSTMENT Current NDCA effective Jan. 1, 2013-Dec. 31, 2017 NDCA Credit: ($0.0002)/kWh Reflected in the current Variable Distribution Service Charges for Rates PD, HT and EP Proposed NDCA effective Jan. 1, 2018-Dec. 31, 2022 NDCA Credit: ($0.0006)/kWh Increase in credit of $0.0004/kWh; decrease in rates Reflected in the current Variable Distribution Service Charges for Rates PD, HT and EP Primary driver of the reduction is the 20-year life extensions granted by the NRC in 2014 for the Limerick units and the impact that has on trust fund earnings for those units Impact of expected TMI closure may be seen in 2023 filing 29
2020/2021 AUCTION RESULTS May 23,2017: PJM released the results of the Base Residual Auction ("BRA") for the 2020/2021 Delivery Year First auction where PJM procured 100% Capacity Performance ("CP") Resources LDA Resource Clearing Price ($/MW-day) RTO $76.53 EMAAC $187.87 PEPCO $86.04 BGE $86.04 COMED $188.12 PPL $86.04 Note: EMAAC consists of PSEG, JCP&L, PECO, Atlantic City Electric, Delmarva Power, and Rockland Electric Company 30
FTR/ARR AND BALANCING CONGESTION TIMELINE September 2016 FERC issued an order on a PJM filing to implement changes to Auction Revenue Rights ("ARR") and Financial Transmission Rights ("FTR") and balancing congestion settlements June 1, 2017: PJM begins to allocate balancing congestion to Real-Time ("RT") load and exports June 7, 2017: PJM makes presentation to Market Implementation Committee detailing results of their 2017 2018 ARR/FTR Annual Auction and makes projections of a $1-$24 million net benefit to ARR holders (i.e. electric generation supplier or load serving entity) Currently ongoing discussions regarding these PJM calculations (push back from suppliers) 31
FTR/ARR/BALANCINGCONGESTION OVERVIEW AND IMPACT Balancing Congestion costs were previously paid by FTR holders Balancing Congestion costs after June 1, 2017 have been assigned to Load Balancing Congestion costs are settled hourly and have appeared as a new line item on a PJM supplier monthly invoice Balancing Congestion charges will vary from month to month based on actual PJM costs 32
FTR/ARR/BALANCING CONGESTION IMPACT Many suppliers are passing these costs through to clients To date costs have been: June 2017: approx. $0.08/MWh July 2017: approx. $0.13/MWh Aug 2017: coming in around $0.08/MWh Line item for Balancing Congestion costs should not materially deviate from these charges For budgeting purposes, may want to estimate ~$0.20/MWh for this item. Over past 6 years, these numbers have ranged from approximately $0.14-$0.46/MWh Under any new contracts, may want to ensure supplier is including in fixed energy costs 33
PA GROSS RECEIPTS TAX FOR 2017 PA Gross Receipts Tax ("GRT") effective Jan. 1, 2017 No change from 2016 Public Utility Reality Tax Act ("PURTA") surtax will remain at zero mills GRT for 2017 = 5.9% Grossed-up GRT = 1/(1-5.9%), or 6.27% July 2017: Proposal passed in the Senate for an increase in electricity taxes from 5.9% to 6.5% Budget and any potential taxes uncertain as of early October 34
Illinois LEGISLATION ON NUCLEAR SUBSIDIES Exelon: Clinton (1,098 MW), Quad Cities 1 & 2 (1,880 MW) Total Nuclear Plant output: 2,978 MW Total Bailout Amount: $2.4 billion for nukes (Total initiative = $13.3 billion) Braidwood, Byron, Dresden, LaSalle plants were not in bailout New York Exelon: Nine Mile Point 1 & 2 (1,757 MW), FitzPatrick (850 MW), Ginna (610 MW) Total Nuclear Plant output: 3,217 MW Total Bailout Amount: $2.9 to $7.6 billion Indian Point plant was not in the bailout 35
LEGISLATION ON NUCLEAR SUBSIDIES Pennsylvania Exelon: Peach Bottom 2 & 3 (2,251 MW), TMI 1 (805 MW), Limerick 1 & 2 (2,296 MW) Talen Energy: Susquehanna 1 & 2 (2,520 MW) FirstEnergy: Beaver Valley 1 & 2 (1,835 MW) Total Nuclear Plant Output: 9,707 MW Bailout Amount: Unknown at this time Preliminary discussions may have occurred as part of budget/legislative initiatives Issue remained uncertain as of early October 36
LEGISLATION ON NUCLEAR SUBSIDIES May 30, 2017: Exelon announced that it will retire TMI on Sept. 30, 2019, absent policy reforms Exelon is taking the first steps to shutting down TMI, including: Informing stakeholders, including sending PJM a deactivation notice and making permanent shutdown notifications to the NRC by the end of June 2017 Taking one-time charges of $65-$110 million for 2017, and accelerating $1.0-$1.1 billion in depreciation and amortization through Sept. 30, 2019 Terminating capital investment projects required for longterm operation of TMI Canceling 2019 fuel purchases and outage planning Potential for change due to subsidies remains uncertain as of early October 37
DEPARTMENT OF ENERGY October 2017 Department of Energy ("DOE") issued Notice of Proposed Rulemaking ("NOPR") Proposes to guarantee cost recovery for "eligible grid reliability resources" that are located within organized markets like PJM Resources that are eligible for this "reliability and resilience rate" are certain types of resources that have 90 days of fuel on site Eg. coal and nuclear 38
DEPARTMENT OF ENERGY DOE requested that the NOPR be set for a fast track with comments due Oct. 23 and reply comments due Nov. 7 Joint Motion by renewables/petroleum/wind associations requesting denial of interim final rule, initiate a technical conference, allow for 90 day comment period, and reject expedited timeline 39
CONTACT INFORMATION Charis Mincavage Attorney at Law McNees Wallace & Nurick LLC 717-237-5437 cmincavage@mcneeslaw.com Dr. Lewis Cohen Energy Management and Procurement Consultant 610-642-5180 lewiscohen@aol.com 40