Ohio Energy. Workshop I PJM 101 Insights into the Regional Electricity Market Operated by PJM and How Electricity Prices are Impacted

Transcription

1 Ohio Energy Workshop I PJM 101 Insights into the Regional Electricity Market Operated by PJM and How Electricity Prices are Impacted Tuesday, February 16, :45 p.m. to 3 p.m.

2 Biographical Information Paul M. Sotkiewicz, Ph.D., Chief Economist Market Services Division, PJM Interconnection LLC, 2750 Monroe Blvd., Audubon, PA Paul M. Sotkiewicz, Ph.D., chief economist Market Services Division, PJM Interconnection. Dr. Sotkiewicz provides analysis and advice with respect to the PJM market design and market performance including demand response mechanisms, intermittent and renewable resource integration, market power mitigation strategies, capacity markets, ancillary service markets, and the potential effects of environmental policies on the PJM markets. Dr. Sotkiewicz is currently working on gas/electric coordination, EPA GHG, and RPM capacity market design issues. Previously, Dr. Sotkiewicz has led PJM s initiative to reform shortage pricing and the PJM analysis of the effects of the recent EPA-issued MATS and CSAPR regulations on generation retirements. Dr. Sotkiewicz also led the teams that developed the whitepapers examining transmission cost allocation and the potential effects of climate change policy on the PJM energy market. Dr. Sotkiewicz has also been involved in multiple capacity market design changes including the Minimum Offer Price Rule, the examination of changes to demand response compensation, the development of Price Responsive Demand. Prior to joining PJM, Dr. Sotkiewicz served as the Director of Energy Studies at the Public Utility Research Center (PURC), University of Florida where he designed and delivered executive education and outreach programs in electric utility regulatory policy and strategy for professionals in government, regulatory agencies, and industry. Dr. Sotkiewicz served as an Economist in the Office of Economic Policy and later on the Chief Economic Advisor s staff at the United States Federal Energy Regulatory Commission (FERC) where he conducted research, analysis, and advice on market design issues related to the ISO/RTO markets. Dr. Sotkiewicz was an Instructor in the Department of Economics at the University of Minnesota where he earned the Walter Heller Award for Outstanding Teaching of Economic Principles four times. Dr. Sotkiewicz earned a Bachelor of Arts in history and economics from the University of Florida, a Master of Arts and Doctorate in Economics from the University of Minnesota. 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.

3 Biographical Information Kevin Murray, Executive Director, Industrial Energy Users-Ohio 21 East State Street 17th Floor, Columbus, Ohio 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.

4 PJM 101: Overview of PJM and its Markets 20th Annual Ohio Energy Management Conference February 16, 2016 Paul M. Sotkiewicz, Ph.D. Senior Economic Policy Advisor PJM Interconnection, LLC PJM 2015

5 PJM as Part of the Eastern Interconnection KEY STATISTICS Member companies 900+ Millions of people served 61 Peak load in megawatts 165,492 MWs of generating capacity 183,604 Miles of transmission lines 62, GWh of annual energy 791,089 Generation sources 1,376 21% of U.S. GDP produced in PJM Square miles of territory 243,417 States served 13 + DC As of 4/1/ PJM 2015

6 PJM Evolution 3 PJM 2015

7 Elements of A Regional Transmission Organization Independent Governance Wholesale Electric Markets Regional Reliability Market Monitoring Information Resource Transmission Planning 4 PJM 2015

8 Reliability Grid Operations Supply/Demand Balance Transmission monitoring 1 PJM Focus on Just 3 Things Regional Planning 15-Year Outlook 2 Market Operation Energy Capacity Ancillary Services 3 5 PJM 2015

9 PJM s Role as a Regional Transmission Organization 6 PJM 2015

10 How Is PJM Different from a Local Utility? Agreement for Operational Control Independence, Neutrality Coordinate Systems 7 PJM 2015

11 PJM Authority Provided by Contract PJM OATT TO Agreement Reliability Assurance Agreement PJM OATT NERC Security Coordinator Regional Transmission Provider Regional Control Area Operator Market Developer & Coordinator Regional Transmission Planner PJM Operating Agreement 8 PJM 2015

12 Market Design Philosophy Incentive-based Security constrained unit commitment and dispatch Bilateral transactions and self-supply properly form the bulk of trades Participants should have all available options to meet their needs Energy is the market focus Transparent pricing and customer confidence are critical to investment 9 9 PJM 2015

13 PJM Markets and Their Interaction 10 PJM 2015

14 PJM Wholesale Cost 11 PJM 2015

15 PJM Wholesale Cost - Other 12 PJM 2015

16 PJM 101: An Introduction To PJM s Energy, Capacity and Ancillary Service Markets and How These Markets Impact Electricity Prices 20th Annual Ohio Energy Management Conference February 16 17, 2016 Kevin Murray McNees Wallace & Nurick LLC 21 East State Street 17th Floor Columbus, OH Direct Dial: murraykm@mwncmh.com 2015 McNees Wallace & Nurick LLC

17 Focus of This Presentation The Capacity Component of Your Bill Explanation of Reliability Pricing Model ( RPM ) Factors that influence RPM outcomes Demand Response Current options for managing energy and capacity spend Relationship to peak shaving options NOTE: This session covers what is ; PJM 201 (Wednesday at 11:15) will cover what may be McNees Wallace & Nurick LLC

18 What is New? Since last year s conference, PJM has implemented significant changes that impact the capacity product and prospective clearing prices: Capacity Performance o Phased in Transition Load Forecasting Methodology McNees Wallace & Nurick LLC

19 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.), or 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 McNees Wallace & Nurick LLC

20 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 ) 17 An area can be constrained due to transmission limitations These LDAs are cleared separately in RPM auction o o RPM Process Starting June 1, 2015, American Transmission Systems, Inc. ( ATSI ) is a separate LDA o 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 2015 McNees Wallace & Nurick LLC

21 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 will be 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 o 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 McNees Wallace & Nurick LLC

22 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 McNees Wallace & Nurick LLC

23 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 yearround, including the coldest winter day o 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 o Subject to non performance charge during emergency conditions during June through September o BC product eliminated effective 2020/2021 Delivery Year Limited DR and extended summer DR eliminated effective 2018/2019 Delivery Year o Effectively rolled into BC product Annual Demand Response ( DR ) can provide CP McNees Wallace & Nurick LLC

24 Capacity Perfomance Enhanced penalties for non performance by CP resources Resource's 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 o o 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 McNees Wallace & Nurick LLC

25 CP 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 McNees Wallace & Nurick LLC

26 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 McNees Wallace & Nurick LLC

27 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 24 PLS may also be subject to a weather normalization adjustment 2015 McNees Wallace & Nurick LLC

28 Calculating Your Capacity Cost Reliability Price Model (RPM) The final RPM rate consists of a weighted average of the Base Residual Auction and the three incremental auctions 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 25 X 2013/2014 RPM Rate $232.55/MW-Day 2015 McNees Wallace & Nurick LLC X Days 365 = Capacity Cost $56,021.30/yr, $4,668.44/mo or $0.014/KWh

29 Your 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 McNees Wallace & Nurick LLC

30 Demand Response Options (as they currently exist) 1. DR Resources (participation in capacity auctions) On par with generation resources o Limited DR, Extended Summer DR, Annual DR exist through 2017/2018 o Eligibility to participate as CP or BC, beginning 2018/2019 o 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 McNees Wallace & Nurick LLC

31 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 28 Minimum amount is 100 kw unless aggregating multiple sites Maximum curtailment amount cannot exceed the customer facility's peak load contribution value ( PLC ) that is in effect at the time of the registration On site generation can be used to meet curtailment obligation 2015 McNees Wallace & Nurick LLC

32 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 McNees Wallace & Nurick LLC

33 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 McNees Wallace & Nurick LLC

34 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 McNees Wallace & Nurick LLC

35 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, May: 10:00 AM to 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 McNees Wallace & Nurick LLC

36 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 o Curtailments outside of this window eligible for Bonus Payments One hour test curtailment required if no curtailment events occur McNees Wallace & Nurick LLC

37 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 following May and between 6:00 AM and 9:00 PM during the months of November and April Participant is provided up to two hours' advance notification One hour test curtailment required if no curtailment events occur McNees Wallace & Nurick LLC

38 Other PJM DR Programs Economic DR Under PJM's Economic DR Program (ELRP), two programs: (compensation is based on real time or day ahead LMP prices) I. Real Time ( RT ) Dispatchable II. 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 McNees Wallace & Nurick LLC

39 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 Customer contracts with 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 demand response programs (Order 745) McNees Wallace & Nurick LLC

40 Questions? McNees Wallace & Nurick LLC

41 Appendix McNees Wallace & Nurick LLC

42 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 McNees Wallace & Nurick LLC

43 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 McNees Wallace & Nurick LLC

44 EE Resources To be eligible to offer into an RPM Auction, an EE installation must: 41 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) 2015 McNees Wallace & Nurick LLC

45 An Introduction to PJM s Energy, Capacity and Ancillary Service Markets and How These Markets Impact Electricity Prices Lou D Alessandris Senior Market Policy Specialist Ohio Energy Management Conference Columbus, Ohio February 16, 2016

46 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 the PJM system Ohio Energy Management Conference February 16,

47 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 February 16,

48 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 the 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 February 16,

49 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 February 16,

50 System Energy Price The System Energy Price is 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 February 16,

51 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 February 16,

52 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 February 16,

53 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 February 16,

54 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 February 16,

55 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 February 16,

56 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 February 16,

57 LMP February 18, 2015, 7:55am Ohio Energy Management Conference February 16,

58 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 February 16,

59 Ohio Energy Management Conference February 16,