Workshop F. PJM 101 Insights into the Regional Electricity Markets Operated by PJM and How Electricity Prices are Impacted. 1:45 p.m. to 3:00 p.m.

Transcription

1 Workshop F PJM 101 Insights into the Regional Electricity Markets Operated by PJM and How Electricity Prices are Impacted 1:45 p.m. to 3:00 p.m.

2 Biographical Information Louis M. D Alessandris, Senior Market Policy Specialist FirstEnergy Corp. 76 S. Main St. General Office 17th Floor, Akron, OH ldalessandris@firstenergycorp.com Lou D Alessandris is a Senior Market Policy Specialist for FirstEnergy Corp. His current responsibilities include regulatory research and market monitoring at PJM and FERC. Prior to joining the company in 2006, Lou held marketing positions in the marketing group at Malco Products, Inc., and worked on demand side management programs for Ohio Edison, a FirstEnergy subsidiary, and Cincinnati Gas & Electric. During his years in the energy industry, Lou has worked in various capacities on the regulated and deregulated side of the business, building an adept understanding of complex utility issues, functioning market structures and energy-related proceedings. Lou participates in the FirstEnergy Speakers Bureau, presenting topics such as Energy Efficiency and Energy Markets to various civic organizations. He earned a bachelor of arts degree from Washington and Jefferson College and a master s of Business Administration from the University of Cincinnati. Kevin Murray, Executive Director Industrial Energy Users - Ohio 21 East State Street 17th Floor, Columbus, Ohio murraykm@mwncmh.com Kevin Murray is the Executive Director of the Industrial Energy Users-Ohio and a Technical Specialist in the Columbus, Ohio office of McNees Wallace & Nurick LLC. He has worked with customers addressing matters that affect the pricing, availability and reliability of natural gas, electricity and other utility services. His experience includes evaluating regulatory proceedings at the Federal Energy Regulatory Commission and various state agencies; providing analysis of proposed tariff or rate offerings; assisting in the development of regulatory and commercial strategies; and providing clients assistance in utility contract negotiations, utility and site selections for new facilities, and performing competitor analysis and analysis of customer usage patterns. He has assisted customers on committing energy efficiency projects towards electric distribution company portfolio obligations to comply with recent legislative requirements. He has been extensively involved in activities related to the creation and start up of regional transmission organizations and energy markets in the Midwest. He is a sector representative for end use customers on the Midcontinent ISO Advisory Committee and previously served as committee chairman. Prior to joining McNees Wallace & Nurick LLC, Mr. Murray spent twelve years with a large industrial corporation where his duties including managing a 20,000 DTH per day natural gas portfolio for the company s Midwest facilities and participating in natural gas, pipeline and electric utility contract negotiation. He also was a company representative at the Electricity Consumers Resource Council (ELCON) and Process Gas Consumers (PGC), where he participated in the development of regulatory advocacy positions and worked with outside counsel representing the company in regulatory proceedings. Mr. Murray also spent several years in supervisory positions in manufacturing operations. Mr. Murray received a Bachelor of Science degree in Metallurgical Engineering from the University of Cincinnati.

3 Insight s into Regional Electricity Markets Operated by PJM and How Electricity Prices are Impacted Lou D Alessandris Senior Market Policy Specialist Ohio Energy Management Conference September 20, 2016

4 Buses, Hubs and Zones PJM s energy markets are organized around buses, hubs and zones Buses are individual pricing points Each power plant has its own bus Load clusters have their own bus Generators get paid at generation bus; loads pay based on load buses Hubs are centralized commercial trading points Main hubs for Ohio use are AEP-Dayton and Western Group of buses Price is less volatile than at a single bus Zones are transmission-defined areas Hourly-priced contracts with retail suppliers are typically priced at the respective zonal Locational Margin Price (LMP), made up of buses in that zone ATSI, AEP, Dayton, Duke Each power plant and load center has its own bus; there are nearly 11,000 buses on PJM system Ohio Energy Management Conference September 20,

5 Two Markets PJM has both a Day-Ahead energy market and a Real-Time energy market Provides market participants with option to participate in a forward market for electric energy Both markets set prices in the same fashion Load serving entities (LSEs) forecast and bid demand in the Day-Ahead energy market Day-ahead market is a financial market Prices are set hourly for the next operating day PJM goes back and conducts a reliability assessment commitment if they determine more generation is likely needed Real-Time market is a physical market based on actual system conditions Prices are set every five minutes based on actual conditions If your contract with your supplier is: Fixed: likely scheduling power in the day-ahead market Hourly: likely using the real-time market Ohio Energy Management Conference September 20,

6 Security-Constrained Economic Dispatch PJM utilizes security-constrained economic dispatch to meet the needs of customers at the lowest cost Subject to transmission and operational constraints Subject to generator constraints (minimum run time, maximum run time, minimum down time, maximum daily starts, maximum weekly starts, etc.) Stack generator offers from lowest to highest Begin dispatching generators starting from lowest cost solution and moving up the stack until customer load needs are met If dispatched, generators receive the same energy payment regardless of their offer price Economic theory dictates this provides the least-cost solution over time Ultimate payment depends on transmission congestion and losses Ohio Energy Management Conference September 20,

7 Locational Marginal Price (LMP) LMP is the cost to serve the next megawatt of load at a specific location using the lowest production cost of all available generation, while observing all transmission limits LMP System Energy Price Transmission Congestion Cost Cost of Transmission Losses Ohio Energy Management Conference September 20,

8 System Energy Price Calculated by PJM and represents the optimal system dispatch Ignores congestion Same price for every bus in PJM LMP System Energy Price Transmission Congestion Cost Cost of Transmission Losses Ohio Energy Management Conference September 20,

9 System Energy Price Simple Example Lower Price Higher Price Generator A 400 MW $30/MWH Generator C 300 MW $37/MWH Not Dispatched Not Dispatched Dispatched 90 MW Dispatched 400 MW Generator B 200 MW $35/MWH Generator D 500 MW $45/MWH Load Center 490 MW PJM Dispatches 400 MW from Generator A, 90 MW from Generator B. Load pays $35/MWH Generators A and B are paid $35/MWH Ohio Energy Management Conference September 20,

10 System Energy Price Simple Example Lower Price Higher Price Generator D 500 MW $45/MWH Generator C 300 MW $37/MWH Generator B 200 MW $35/MWH Generator A 400 MW $30/MWH Not Dispatched Dispatched 10 MW Dispatched 200 MW Dispatched 400 MW Load Center 490 MW 610 MW PJM Dispatches 400 MW from Generator A, 200 MW from Generator B, 10 MW from Generator C Load pays $37/MWH Generators A, B and C are paid $37/MWH Ohio Energy Management Conference September 20,

11 Transmission Congestion Cost Congestion is a situation in which heavy use of the electric grid prevents the lowest-priced electricity from flowing to a specific area Would be zero if no constraints Used to price congestion on the system Load pays congestion price; generators (or holders of financial transmission rights) are paid congestion price LMP System Energy Price Transmission Congestion Cost Cost of Transmission Losses Ohio Energy Management Conference September 20,

12 Transmission Congestion Simple Example Lower Price Higher Price Generator D 500 MW $45/MWH Generator C 300 MW $37/MWH Generator B 200 MW $35/MWH Generator A 400 MW $30/MWH Dispatched 0 MW 110 MW Dispatched 10 MW 300 MW Dispatched 200 MW Dispatched 400 MW 0 MW Load Center 610 MW PJM Dispatches 200 MW from Generator B, 300 MW from Generator C, 110 MW from Generator D Load pays $45/MWH ($37 energy, $8 congestion) Generator D is paid $45/MWH, Generators B and C are paid $37/MWH* * Holders of FTRs receive the difference in revenue Ohio Energy Management Conference September 20,

13 Transmission Losses Losses occur when electricity is transmitted over distances The longer the distance, the greater the losses The lower the voltage, the greater the losses Transmission losses are priced according to marginal loss factors Varies by location Load pays the loss price; generation is paid the loss price LMP System Energy Price Transmission Congestion Cost Cost of Transmission Losses Ohio Energy Management Conference September 20,

14 Transmission Losses Simple Example Lower Price Higher Price Generator D 500 MW $45/MWH Generator C 300 MW $37/MWH Generator B 200 MW $35/MWH Generator A 400 MW $30/MWH Not Dispatched Dispatched 10 MW 30 MW Dispatched 200 MW Dispatched 400 MW Load Center 610 retail (630 MW with losses) PJM Dispatches 400 MW from Generator A, 200 MW from Generator B, 30 MW from Generator C Generators A, B and C are paid $37/MWH, but load pays $38.21 ($37 energy, $1.21 losses) Ohio Energy Management Conference September 20,

15 LMP February 18, 2015, 7:55am Ohio Energy Management Conference September 20,

16 Simple Examples Are NOT Reality The preceding examples were simplified for ease of understanding The PJM system is far more complex than the three generator/one load center (four bus) examples shown PJM has nearly 11,000 buses used in LMP calculations LMP is calculated every hour in the day-ahead market, every five minutes in the real-time market PJM runs ~4,000 what if scenarios every five minutes to proactively correct the system in the event of a transmission outage Losses are calculated based a generator s distance from a system load center point that changes every five minutes Losses are rolled back into energy price offers prior to the system energy price calculation Ohio Energy Management Conference September 20,

17 Ohio Energy Management Conference September 20,

18 Forward-Looking Statements This presentation includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management's intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms anticipate, potential, expect, "forecast," "target," "will," "intend," believe, "project," estimate," "plan" and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements, which may include the following: the speed and nature of increased competition in the electric utility industry, in general, and the retail sales market in particular; the ability to experience growth in the Regulated Distribution and Regulated Transmission segments and to successfully implement our revised sales strategy for the Competitive Energy Services segment; the accomplishment of our regulatory and operational goals in connection with our transmission investment plan, including but not limited to, our pending transmission rate case, the proposed transmission asset transfer, and the effectiveness of our repositioning strategy to reflect a more regulated business profile; changes in assumptions regarding economic conditions within our territories, assessment of the reliability of our transmission system, or the availability of capital or other resources supporting identified transmission investment opportunities; the impact of the regulatory process on the pending matters at the federal level and in the various states in which we do business including, but not limited to, matters related to rates and the Electric Security Plan IV in Ohio; the impact of the federal regulatory process on the Federal Energy Regulatory Commission (FERC)-regulated entities and transactions, in particular FERC regulation of wholesale energy and capacity markets, including PJM Interconnection, L.L.C. (PJM) markets and FERC-jurisdictional wholesale transactions; FERC regulation of cost-of-service rates, including FERC Opinion No. 531's revised Return on Equity methodology for FERC-jurisdictional wholesale generation and transmission utility service; and FERC s compliance and enforcement activity, including compliance and enforcement activity related to North American Electric Reliability Corporation s mandatory reliability standards; the uncertainties of various cost recovery and cost allocation issues resulting from American Transmission Systems, Incorporated's realignment into PJM; economic or weather conditions affecting future sales and margins such as a polar vortex or other significant weather events, and all associated regulatory events or actions; changing energy, capacity and commodity market prices including, but not limited to, coal, natural gas and oil, and their availability and impact on margins and asset valuations; the continued ability of our regulated utilities to recover their costs; costs being higher than anticipated and the success of our policies to control costs and to mitigate low energy, capacity and market prices; other legislative and regulatory changes, and revised environmental requirements, including, but not limited to, the effects of the United States Environmental Protection Agency's Clean Power Plan, coal combustion residuals regulations, Cross-State Air Pollution Rule and Mercury and Air Toxics Standards programs, including our estimated costs of compliance, Clean Water Act waste water effluent limitations for power plants, and Clean Water Act 316(b) water intake regulation; the uncertainty of the timing and amounts of the capital expenditures that may arise in connection with any litigation, including New Source Review litigation, or potential regulatory initiatives or rulemakings (including that such initiatives or rulemakings could result in our decision to deactivate or idle certain generating units); the uncertainties associated with the deactivation of certain older regulated and competitive fossil units, including the impact on vendor commitments, and as they relate to the reliability of the transmission grid, the timing thereof; the impact of other future changes to the operational status or availability of our generating units and any capacity performance charges associated with unit unavailability; adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to the revocation or non-renewal of necessary licenses, approvals or operating permits by the Nuclear Regulatory Commission or as a result of the incident at Japan's Fukushima Daiichi Nuclear Plant); issues arising from the indications of cracking in the shield building at Davis-Besse; the risks and uncertainties associated with litigation, arbitration, mediation and like proceedings, including, but not limited to, any such proceedings related to vendor commitments; the impact of labor disruptions by our unionized workforce; replacement power costs being higher than anticipated or not fully hedged; the ability to comply with applicable state and federal reliability standards and energy efficiency and peak demand reduction mandates; changes in customers' demand for power, including, but not limited to, changes resulting from the implementation of state and federal energy efficiency and peak demand reduction mandates; the ability to accomplish or realize anticipated benefits from strategic and financial goals, including, but not limited to, the ability to continue to reduce costs and to successfully execute our financial plans designed to improve our credit metrics and strengthen our balance sheet through, among other actions, our previously-implemented dividend reduction, our cash flow improvement plan and our other proposed capital raising initiatives; our ability to improve electric commodity margins and the impact of, among other factors, the increased cost of fuel and fuel transportation on such margins; changing market conditions that could affect the measurement of certain liabilities and the value of assets held in our Nuclear Decommissioning Trusts, pension trusts and other trust funds, and cause us and/or our subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated; the impact of changes to material accounting policies; the ability to access the public securities and other capital and credit markets in accordance with our financial plans, the cost of such capital and overall condition of the capital and credit markets affecting us and our subsidiaries; actions that may be taken by credit rating agencies that could negatively affect us and/or our subsidiaries' access to financing, increase the costs thereof, and increase requirements to post additional collateral to support outstanding commodity positions, letters of credit and other financial guarantees; changes in national and regional economic conditions affecting us, our subsidiaries and/or our major industrial and commercial customers, and other counterparties with which we do business, including fuel suppliers; the impact of any changes in tax laws or regulations or adverse tax audit results or rulings; issues concerning the stability of domestic and foreign financial institutions and counterparties with which we do business; the risks associated with cyber-attacks on our electronic data centers that could compromise the information stored on our networks, including proprietary information and customer data; and the risks and other factors discussed from time to time in our United States Securities and Exchange Commission filings, and other similar factors. The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on FirstEnergy's business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. FirstEnergy expressly disclaims any current intention to update, except as required by law, any forward-looking statements contained herein as a result of new information, future events or otherwise. Ohio Energy Management Conference September 20,

19 PJM s Energy, Capacity and Ancillary Service Markets and How These Markets Impact Electricity Prices 11th Annual Northern Ohio Energy Management Conference September 20, 2016 Kevin Murray Executive Director, Industrial Energy Users Ohio Direct Dial: murraykm@mwncmh.com

20 Focus of This Presentation The Capacity Component of Your Bill Explanation of Reliability Pricing Model ( RPM ) Factors that influence RPM outcomes What is and What May Be 18

21 What is PJM has implemented significant changes that impact the capacity product and prospective clearing prices: Capacity Performance o Phased in Transition Load Forecasting Methodology 19

22 RPM Capacity prices are set by the RPM RPM is designed to obtain sufficient resources to meet the needs of consumers in PJM Goal is to cost effectively obtain resource commitments to ensure adequate resources every day of the year Obtains resource commitments to meet system loads three years in the future via the Base Residual Auction ( BRA ) Resources can be any type of power plant (nuclear, coal, gas, wind, solar, hydro, etc.), demand response, or energy efficiency All utility members could choose to participate in RPM or opt out and become a Fixed Resource Requirement ( FRR ) entity No Ohio electric distribution companies are currently FRR entities Capacity is typically the second largest component of a retail customer s overall power price 20

23 RPM Process PJM determines the amount of capacity resources required to serve forecast peak load PJM adds an installed reserve margin to load forecast 16.7% reserve margin for June 1, 2016 to May 31, 2017 Reliability criterion based on loss of load expectation not exceeding one event in 10 years PJM identifies any constrained sub regions and establishes separate locational deliverability areas ( LDAs ) An area can be constrained due to transmission limitations These LDAs are cleared separately in RPM auction American Transmission Systems, Inc. ( ATSI ) is a separate LDA Price separation occurred for 2015/2016 and 2016/2017 delivery years; no separation in 2017/2018 AEP Ohio, Duke and Dayton Power & Light are Rest of Market 21

24 RPM Auction BRA is held three years prior to the start of delivery year PJM Delivery Year runs June 1 to May 31 BRA held in May 2016 was for the 2019/2020 Delivery Year Three Incremental Auctions ( IAs ) held between BRA and Delivery Year PJM updates forecasts and balances the amount of capacity required PJM may be short or long on capacity based on updated load forecasts Allows generators and demand response participants the ability to manage their portfolios Three IAs are held at set times each year First: 20 months prior to delivery Second: 10 months prior to delivery Third: 3 months prior to delivery 22

25 Rest of Market BRA Clearing Prices Auction Date Delivery Period (June 1 to May 31) BRA Value ($/MW Day) May /2008 $40.80 July /2009 $ October /2010 $ February /2011 $ May /2013 $ May /2013 $16.46 May /2014 $27.73 May /2015 $ May /2016 $ May /2017 $59.37 * May /2018 $ * August /2019 See explanation that follows * Final results affected by Capacity Performance transition auctions 23

26 Capacity Performance Fundamental RPM rule changes went into effect Summer 2015 Outgrowth of 2014 Polar Vortex experience Two capacity products: Capacity Performance ( CP ) and Base Capacity ( BC ) CP resources must be capable of sustained, predictable operation year round, including the coldest winter day Subject to non performance charge during emergency conditions throughout the Delivery Year BC resources are those capacity resources not capable of such sustained, predictable operations year round but capable of providing energy and reserves during hot weather operations Subject to non performance charge during emergency conditions during June through September BC product eliminated effective 2020/2021 Delivery Year Limited Demand Response ( DR ) and extended summer DR eliminated effective 2018/2019 Delivery Year Effectively rolled into BC product Annual DR can provide CP 24

27 Capacity Performance Enhanced penalties for non performance by CP resources Resources expected performance compared to actual performance during Performance Assessment Hours ( PAHs ) PAHs are triggered by PJM's declaration of emergency actions Shortfall subject to non performance charge CP: Net Cost of New Entry ( CONE ) divided by the assumed 30 PAHs per year BC: Resource clearing price divided by the assumed 30 PAHs per year Bonus performance may be eligible for performance credit Increase in the generator offer cap to Net CONE x balancing ratio Roughly 85% of Net CONE or $250/MW day Elimination of the 2.5% holdback, effective 2018/2019 Delivery Year 25

28 Capacity Performance Transition Auctions Gradual phase in to 100% CP resources by 2020/2021 Up to 60% CP in 2016/2017 Up to 70% CP in 2017/ % CP in 2018/2019 and 2019/2020 Transition auctions for voluntary commitments of CP resources in 2016/2017 and 2017/2018, with gradually escalating CP requirements, offer caps and penalties No locational specific requirements; therefore, each auction cleared at a single clearing price 26

29 Rest of Market Auction Clearing Prices with CP Auction Date Delivery Period (June 1 to May 31) Clearing Price ($/MW Day) August /2017 $98.29 September /2018 $ August /2019 $ ATSI Zone Cleared at $ per MW-Day for the 2016/2017 delivery period 27

30 Calculating Your Capacity Obligation Capacity Peak Load Share (PLS) Based on average of your coincidental peak matched against highest five summer (June, July, August) hours against all of PJM Forecast Pool Requirement Added capacity planned to meet the unforced reserve margin Zonal Scaling Factor Accounts for forecasted load growth versus prior year and any changes to capacity portfolio. These are electric distribution company (EDC) specific. Capacity Obligation Amount of capacity supplier must procure to serve your facility Date/Hour Your Peak (MW) 17: : : : : PLS.569 X Forecast Pool Requirement X Zonal Scaling Factor Your Capacity Obligation =.660 MW 660 KW PLS may also be subject to a weather normalization adjustment 28

31 Calculating Your Capacity Cost RPM The final RPM rate consists of a weighted average of the BRA and the three IAs Capacity Cost RPM price times your Capacity Obligation in MW Day. Suppliers purchase adequate RPM Capacity and convert to kwh costs for inclusion in fixed price or capacity can be passed through via a monthly demand charge Your Capacity Obligation.660 MW X 2013/2014 RPM Rate $232.55/MW-Day X Days 365 = Capacity Cost $56,021.30/yr, $4,668.44/mo or $0.014/KWh 29

32 Takeaways Understand your peak consumption to determine if you can take action to lower your peak and, thus, lower your PLS and, thus, lower your capacity costs Many competitive retail electric suppliers ( CRES ) are willing to contract for generation supply with capacity costs exclusively on a pass through basis Monthly charges change automatically when quantity and price change New capacity obligations take effect each January New capacity prices take effect each June 30

33 What May Be Capacity Market 2.5% hold back that was previously in place has been eliminated 2016/2019 BRA PJM has adopted changes to load forecasting methodologies to correct for persistent over forecasting Approximately 5,000 to 6,000 MW reduction in forecast 31

34 Offer Caps Since the start of PJM s energy market, offer caps at $1,000 per Mwh have been in place in PJM s energy market In the winter of 2014/2015 a temporary waiver of the offer cap was in place FERC has accepted tariff changes to increase the offer caps Offers now capped at $2,000 per MWH 32

35 NOPR Settlement Intervals and Shortage Pricing Docket No. RM Final rule issued June 16, 2016 requires settlement intervals to match dispatch intervals PJM currently dispatches on five (5) minute intervals but settles based on hourly averages Final rule does not require load to be settled on five minute intervals. FERC believes this reform will improve incentives for resources to respond quickly to dispatch instructions, leading to fewer out of market actions 33

36 NOPR Settlement Intervals and Shortage Pricing Docket No. RM Require Regional Transmission Operators/Independent System Operators ( RTOs/ISOs ) to trigger shortage pricing for any dispatch interval during which a shortage of energy or operating reserves occurs Some RTOs/ISOs currently restrict triggering of shortage pricing to certain causes only or require a certain duration E.g., PJM restricts transient shortage events from triggering shortage pricing FERC focuses on the trigger for shortage pricing, not the shortage price itself E.g., PJM s shortage pricing penalty factor is $850/Mwh 34

37 Order 745 FERC Order 745 requires RTOS to allow DR resources to participate in all market products Some ability of state commissions and smaller utilities to restrict participation D.C. Circuit Court of Appeals vacated Order 745 Court decision stayed pending appeal U.S. Supreme Court reviewing case On January 25, 2016, the Supreme Court issued a decision upholding Order 745 and overturning the lower court ruling See appendix for description of PJM demand response options 35

38 CPV Maryland, LLC v. PPL EnergyPlus, LLC Issue: (1) Whether, where, as a result of a state directed procurement, the contract price to build and operate a power plant is the developer s bid price, and may result in payments beyond what the developer earns selling the plant s capacity in the auction supervised by the Federal Energy Regulatory Commission (FERC) the program is field preempted as a state s attempt to set interstate wholesale rates; and (2) whether a state directed contract to support construction of a power plant is conflict preempted because its long term pricing structure provides incentives different from the incentives provided by prices generated in the FERC supervised yearly capacity auction. Source SCOTUS blog 36

39 CPV Maryland, LLC v. PPL EnergyPlus, LLC Held: Maryland s program is preempted because it disregards the interstate wholesale rate FERC requires. A state law is preempted where Congress has legislated comprehensively to occupy an entire field of regulation, Northwest Central Pipeline Corp. v. State Corporation Comm n of Kan., 489 U. S. 493, 509, as well as where, under the circumstances of [a] particular case, [the challenged state law] stands as an obstacle to the accomplishment and execution of the full purposes and objectives of Congress, Crosby v. National Foreign Trade Council, 530 U. S. 363, 373. Exercising its exclusive authority over interstate wholesale sales, see 16 U. S. C. 824(b)(1), FERC has approved PJM s capacity auction as the sole ratesetting mechanism for capacity sales to PJM, and has deemed the clearing price per se just and reasonable. However, Maryland through the contract for differences guarantees CPV a rate distinct from the clearing price for its interstate capacity sales to PJM. By adjusting an interstate wholesale rate, Maryland s program contravenes the FPA s division of authority between state and federal regulators. 37

40 Ohio Supreme Court On April 21, 2016 the Ohio Supreme Court issued a decision that found the Public Utilities Commission of Ohio unlawfully authorized the collection of transition revenues or their equivalent when it approved an electric security plan for AEP Ohio in 2012 that included the collection of a non bypassable retail stability rider. The case ( ) has been remanded to the Public Utilities Commission of Ohio for further proceedings. The Public Utilities Commission of Ohio has taken no further action. 38

41 Ohio Supreme Court On June 20, 2016 citing its decision in the case the Supreme Court issued a decision finding that the Public Utilities Commission of Ohio unlawfully authorized the Dayton Power & Light Company to collect a non bypassable Service Stability Rider as part its current electric security plan. The case has been remanded to the Public Service Commission of Ohio for further proceedings. The Public Service Commission of Ohio has not acted on the remand. 39

42 New York The New York Public Service Commission issued an order on August 1, 2016 that requires 50% of the state s electricity to be acquired from renewable energy resources by The order also requires load serving entities to purchase zero emission credits ( ZEC ) associated with the output of the Ginna, FitzPatrick and nine Mile Point nuclear facilities. ZEC set and an initial rate of $17.48 per MWH. ZEC expected initial cost of $483 million per year. 40

43 What is behind all of this? Natural gas prices have increased 50% over the last few months but are still below $3.00 per DTM. At $3.00 natural gas, combined cycle natural gas units will displace many coal fired units. Renewable output in increasing (federal subsidies). Even when nuclear and coal fired units are dispatched margins are reduced. 41

44 The Bottom Line Continue to see substantial regulatory churn at both the federal and state level (Ohio electric security plans) Many changes could place upward pressure on capacity prices Economic and environmental drivers continue to generate headwinds for coal fired power plants Customers need to get engaged and stay engaged 42

45 Appendix 43

46 Demand Response Options (as they currently exist) DR Resources (participation in capacity auctions) On par with generation resources Limited DR, Extended Summer DR, Annual DR exist through 2017/2018 Eligibility to participate as CP or BC beginning 2018/2019 Eligibility to participate as CP beginning 2020/2021 May require three year advance commitment BRAs & IAs each year prior to Delivery Year Must plan ahead to capitalize on capacity value Measurement and verification requirements Participant is obligated to reduce load when requested by PJM 44

47 DR Program Term & Registration Requirements Annual re registration is required to participate in subsequent Delivery Years Registration occurs prior to May for the upcoming year that begins June 1 DR auction registration occurs approximately 30 days in advance of each auction At time of registration, customer selects the amount of electrical usage that it will curtail Minimum amount is 100 kw unless aggregating multiple sites Maximum curtailment amount cannot exceed the customer facility's peak load contribution ( PLC ) value that is in effect at the time of the registration On site generation can be used to meet curtailment obligation 45

48 DR Program Term & Registration Requirements Requires PJM membership or use of a Curtailment Service Provider ( CSP ) that is a PJM member Customer must have hourly interval metering 46

49 Emergency DR Participation Limited DR One year commitment: June 1 May 31 ( Delivery Year ) PJM has the right to request up to 10 separate curtailments, each lasting no more than six hours Participant is provided up to two hours advance notification Curtailment can only occur during non holiday weekdays between 12:00 PM 8:00 PM June September Compliance is verified for any June September curtailment events Dispatches outside the hours and months above are voluntary events One hour test curtailment required if no curtailment events occur Available through 2017/2018 Delivery Year 47

50 Emergency DR Participation Extended Summer DR One year commitment: June 1 May 31 ( Delivery Year ) PJM has the right to request unlimited curtailments, each lasting no more than 10 hours Participant is provided up to two hours advance notification Curtailment can only occur any day during June October and the following May between 10:00 AM 10:00 PM Compliance is verified for any curtailment events during compliance months Dispatches outside the hours and months above are voluntary events One hour test curtailment required if no curtailment events occur Available through 2017/2018 Delivery Year 48

51 Emergency DR Participation Annual DR One year commitment: June 1 May 31 ( Delivery Year ) PJM has the right to request unlimited curtailments, each lasting no more than 10 hours Participant is provided up to two hours advance notification Curtailment can only occur any day (unless on an approved maintenance outage during October April) June October and the following May between 10:00 AM 10:00 PM November April 6:00 AM 9:00 PM Compliance is verified for any curtailment events during compliance months Dispatches outside the hours and months above are voluntary events One hour test curtailment required if no curtailment events occur Available through 2017/2018 Delivery Year 49

52 Emergency DR Participation BC One year commitment: June 1 May 31 ( Delivery Year ) Available only for 2018/2019 and 2019/2020 Delivery Years PJM has the right to request unlimited curtailments between the hours of 10:00 AM and 10:00 PM, each curtailment lasting no more than 10 hours Participant is provided up to two hours advance notification Curtailment can only occur any day between June and September Dispatches outside the hours and months above are voluntary events Curtailments outside of this window eligible for Bonus Payments One hour test curtailment required if no curtailment events occur 50

53 Emergency DR Participation CP One year commitment: June 1 May 31 ( Delivery Year ) Available beginning 2018/2019 Delivery Years PJM has the right to request unlimited curtailments any day during the Delivery Year (unless on an approved maintenance outage during October April) No limit on the number of curtailment hours Curtailments must be between 10:00 AM and 10:00 PM during months of June October and the following May, and between 6:00 AM and 9:00 PM during the months of November thru April Participant is provided up to two hours advance notification One hour test curtailment required if no curtailment events occur 51

54 Other PJM DR Programs Economic DR Under PJM's Economic DR Program (ELRP), two programs: (compensation is based on real time or day ahead locational marginal pricing) Real Time ( RT ) Dispatchable Participant submits offer price/quantity, minimum downtime, and notification period No non compliance charges PJM provides notification to curtail load one or two hours in advance Day Ahead ( DA ) Participant submits offer price/quantity and notification period by noon the day prior to the intended curtailment Price certainty, financially guaranteed market Know by 4:00 PM day before curtailment if offer cleared Must perform or there are non performance charges 52

55 Other Considerations End users with Interruptible utility rate contracts may not be allowed to participate in DR Most (if not all) of these have been phased out Use of CSP can address auction timing concerns or advance commitment concerns A customer contracts with a CSP to facilitate participation in PJM markets for a fee The DR programs are subject to PJM revision/amendment from year to year On January 25, 2016 the U.S. Supreme Court reversed a ruling by the Court of Appeals for the District of Columbia Circuit and upheld FERC authorized DR programs (Order 745) 53

56 Energy Efficiency (EE) Resources EE Resources may participate in RPM auctions BC and CP EE differentiation akin to DR, beginning for 2018/2019 Delivery Year EE Resources are projects involving installation of more efficient devices or equipment, or implementation of more efficient processes/systems that exceed then current building codes, appliance standards, or other relevant standards An EE resource is used as a capacity resource in the auction, thus an EE resource that clears in an auction is paid the resource clearing price times the MW amount cleared 54

57 Examples of EE Resources Efficient lighting installation Efficient appliance installation Efficient air conditioning installation Building insulation Process improvements Permanent load shifts that are not dispatched based on price or other factors 55

58 EE Resources To be eligible to offer into an RPM Auction, an EE installation must: Be scheduled for completion prior to the delivery year Not be reflected in the peak load forecast posted for the BRA auction for the delivery year initially offered Exceed relevant standards at time of installation as known at time of commitment Achieve load reduction during defined EE performance hours (weekdays from June 1 through August 31, between 2:00 PM and 6:00 PM) Not be dispatchable (dispatchable demand may be offered as a DR in RPM) 56