Workshop H. PJM Basics: An Introduction to PJM Interconnection and How its Energy and Capacity Markets Operate

Transcription

1 Workshop H PJM Basics: An Introduction to PJM Interconnection and How its Energy and Capacity Markets Operate Tuesday, February 19, :45 p.m. to 3 p.m.

2 Biographical Information Adam J. Keech, Executive Director Market Operations, PJM Interconnection LLC, 2750 Monroe Blvd., Audubon, PA (610) Adam has worked at PJM for over 16 years in both Market Operations and System Operations. He is currently responsible for the efficient design and operation of PJM s electricity markets including the Day-ahead and Real-time Energy and Ancillary Service Markets, Financial Transmission Rights auctions and the capacity market. During his time in System Operations, he was the director of Dispatch Operations and was responsible for oversight of the PJM control room. Adam graduated from Rutgers University in 2002 with a bachelor s degree in Electrical Engineering. He earned a master s degree in Applied Statistics from West Chester University in PJM Interconnection, founded in 1927, ensures the reliability of the high-voltage electric power system serving 61 million people in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PJM coordinates and directs the operation of the region s transmission grid, which includes 62,556 miles of transmission lines; administers a competitive wholesale electricity market; and plans regional transmission expansion improvements to maintain grid reliability and relieve congestion. Louis M. D Alessandris, Senior Market Policy Specialist, FirstEnergy Corp. 76 S. Main St., General Office 16th 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 startup 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 Basics: Introduction to PJM 23rd Annual Ohio Energy Management Conference February 2019 Adam Keech Executive Director, Market Operations PJM Interconnection PJM 2017

5 PJM as Part of the Eastern Interconnection Key Statistics Member companies 1,000+ Millions of people served 65 Peak load in megawatts 165,492 MW of generating capacity 176,569 Miles of transmission lines 82, GWh of annual energy 792,314 Generation sources 1,304 Square miles of territory 243,417 States served 13 + DC 27% of generation in Eastern Interconnection 28% of load in Eastern Interconnection 20% of transmission assets in Eastern Interconnection 21% of U.S. GDP produced in PJM As of 2/ PJM 2017

6 PJM s Role as a Regional Transmission Organization 3 PJM 2017

7 How Is PJM Different from a Local Utility? Agreement for Operational Control Independence, Neutrality Coordinate Systems 4 PJM 2017

8 Value Proposition 5 PJM 2017

9 Independence and Governance Process Independent Board of Managers Members Committee Market Monitor Independent Board of Managers Stakeholder process provide balanced stakeholder input Established process for discussion of market evolution ISO funding and startup PJM 2017

10 PJM Markets 7 PJM 2017

11 RTO Operation 8 PJM 2017

12 Insights into the Regional Electricity Market Operated by PJM Lou D Alessandris Senior Market Policy Specialist Ohio Energy Management Conference Columbus, Ohio February 19, 2019

13 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 19,

14 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 Real-time market is a physical market based on actual system conditions Prices are set every five minutes based on actual conditions A generator that sells 100 MW in the day-ahead but only produces 95 MW must buy 5 MW in the real-time market If the generator produced 105 MW, it would sell 5 MW in the real-time market If your contract with your supplier is: Fixed: likely scheduling power in the day-ahead market If you use more power than your supplier forecast, it will have to buy power in the real-time market at the real-time price If you use less power than your supplier forecast, it will sell the excess power in the real-time market Hourly: likely using the real-time market Ohio Energy Management Conference February 19,

15 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 19,

16 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 19,

17 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 19,

18 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 Not Dispatched Dispatched 90 MW Dispatched 400 MW 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 19,

19 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 19,

20 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 19,

21 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 19,

22 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 19,

23 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 meter (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 19,

24 LMP February 18, 2015, 7:55am Ohio Energy Management Conference February 19,

25 Simple Examples Are NOT Reality The preceding examples were simplified for ease of understanding The PJM system is far more complex than the four generator/one load center (five 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 19,

26 Ohio Energy Management Conference February 19,

27 PJM Basic An Introduction To PJM s Energy, Capacity and Ancillary Service Markets and How These Markets Impact Electricity Prices 23 rd Annual Ohio Energy Management Conference February 19 20, 2019 Kevin Murray McNees Wallace & Nurick LLC 21 East State Street, 17th Floor Columbus, OH Direct Dial: murraykm@mcneeslaw.com 2019 McNees Wallace & Nurick LLC

28 Focus of This Presentation The Capacity Component of Your Bill. Explanation of Reliability Pricing Model ( RPM ). Factors that influence RPM outcomes McNees Wallace & Nurick LLC

29 RPM Capacity prices are set by the Reliability Pricing Model ( 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 McNees Wallace & Nurick LLC

30 RPM 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 ( EDUs ) are currently FRR entities. Capacity is typically the second largest component of a retail customer s overall power price McNees Wallace & Nurick LLC

31 Capacity Performance Capacity Performance ( CP ) is an additional feature of PJM s capacity market that was phased in. CP is a requirement that generators must meet their commitments to deliver electricity whenever PJM determines they are needed to meet power system emergencies. The failure to perform during peak hours triggers financial penalties McNees Wallace & Nurick LLC

32 RPM Process PJM determines the amount of capacity resources required to serve forecast peak load. PJM adds an installed reserve margin to load forecast. 15.9% reserve margin for June 1, 2019 to May 31, 2020 (second incremental auction ( IA ) parameters). 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. AEP Ohio, ATSI, Dayton Power & Light and Duke cleared as Rest of Market in base residual auction McNees Wallace & Nurick LLC

33 30 RPM Auction BRA is held three years prior to the start of Delivery Year. PJM Delivery Year runs June 1 to May 31. BRA to be held in May August 2019 will be for the 2022/2023 Delivery Year. Three Incremental Auctions ( IA ) 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 McNees Wallace & Nurick LLC

34 Rest of Market Base Residual Auction Clearing Prices Auction Date Delivery Period (June 1 to May 31) BRA Value ($/MW Day) Rest of Market May /2008 $40.80 July /2009 $ October /2010 $ February /2011 $ May /2012 $ May /2013 $16.46 May /2014 $27.73 May /2015 $ May /2016 $ May /2017 $59.37 May /2018 $ August /2019 $ May /2020 $ May /2021 $76.53 May /2022 $ * Capacity Performance fully phased in for 2020/2021 delivery period McNees Wallace & Nurick LLC

35 32 Capacity Performance Fundamental RPM rule changes went into effect Summer Outgrowth of 2014 Polar Vortex experience. Two capacity products: 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 (FERC complaint). Limited demand response ( DR ) and extended summer DR eliminated effective 2018/2019 Delivery Year. Effectively rolled into BC product McNees Wallace & Nurick LLC

36 33 Capacity Performance Capacity Performance fully phased in as of 2020/2021 delivery period. 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 McNees Wallace & Nurick LLC

37 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 McNees Wallace & Nurick LLC

38 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) 8/28/ : /4/ : /18/ : /5/ : /27/ : PLS 1.12 Zonal Forecast Pool Scaling X Requirement X Factor = Your Capacity Obligation Metered load must be grossed up to account for transmission level losses. PLS may also be subject to a weather normalization adjustment McNees Wallace & Nurick LLC

39 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 Price MW Day X X = $ Capacity Cost $79, McNees Wallace & Nurick LLC

40 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

41 Other Considerations End users with Interruptible retail utility rate contracts may not be allowed to participate in demand response ( DR ). Many of these rates have been phased out. Use of a curtailment service provider ( 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 McNees Wallace & Nurick LLC

42 Questions? McNees Wallace & Nurick LLC