EPA s Clean Power Plan Proposal Review of PJM Analyses Preliminary Results

Transcription

1 EPA s Clean Power Plan Proposal Review of PJM Analyses Preliminary Results Paul Sotkiewicz Chief Economist Muhsin Abdur-Rahman Senior Engineer, Market Simulation Members Committee Webinar November 17, 2014

2 PJM s Role PJM has been tasked with assessing potential impacts of the EPA Clean Power Plan Proposal on PJM states; however, as an RTO, PJM: Maintains neutrality on carbon policy Acts as an independent source of information on carbon policy implications Does not forecast market outcomes but rather models outcomes based on a specific set of assumptions 2

3 Overview of PJM Analyses Analysis Regional Economic Modeling Emissions Target Utilized Mass target using June 2 EPA guidance for conversion from rate based targets Mass target using November 6 EPA guidance for conversion from rate based Rate based target State by State Economic Modeling Mass target using November 6 EPA guidance for mass conversion from rate based targets Reliability Analysis (to be completed) Power flow analyses modeling retirement of at-risk units identified from the regional economic modeling 3

4 Section I: Modeling Approach

5 Overview of Regional Compliance Modeling Approach Using Mass-Based Emissions Targets Used PROMOD for simulation modeling PROMOD models hourly security constrained economic generation commitment and dispatch Assumptions consistent with 2014 RTEP Market Efficiency Analysis 14 scenarios adjusted new generation, energy efficiency, renewable energy, nuclear retirements, and gas price assumptions. (PJM is not modeling each EPA Building Block independently) Convert to mass-based emissions targets Converted rate-based emissions targets to mass-based targets for the states / portion of states within PJM; aggregated to represent the emissions target for PJM region Input CO 2 price to re-dispatch generation until emissions target achieved Assume new gas units are regulated under 111(b), not 111(d) Emissions from new gas units are not counted toward the emissions target 5

6 Used PROMOD for simulation modeling Overview of Regional Compliance Modeling Approach Using Rate-Based Emissions Targets PROMOD models hourly security constrained economic generation commitment and dispatch Assumptions consistent with 2014 RTEP Market Efficiency Analysis 14 scenarios adjusted new generation, energy efficiency, renewable energy, nuclear retirements, and gas price assumptions. (PJM is not modeling each EPA Building Block independently) Used rate-based emissions targets Calculate performance credit and penalty for each 111(d) covered source based on unit emissions rate and EPA provided benchmark target rate Model CO 2 performance credit / penalty as a bid adder/decrement to the simulation until emissions rate target is achieved Assume new gas units are regulated under 111(b), not 111(d) Emissions from new gas units are not counted toward the emissions target 6

7 Existing Source vs. New Source Performance Standards Proposals Relevant dates Units impacted Standard Impact on units 111(d) Interim compliance Final compliance 2030 and beyond Existing and Under-construction: ST Coal, NGCC, ST Gas/Oil, High-utilization CT Gas/Oil, IGCC and some CHP State-based compliance with a CO 2 emissions rate target or converted to a mass-based target Reduced net energy market revenues Potentially CO 2 allowance price or restrictions on unit operation 111(b) Scheduled promulgation January 2015 New Gas-Fired CT, fossil-fired utility boilers and IGCC units Federal compliance (NSPS): Large CT - 1,000 lbs/mwh Steam Turbine and IGCC: 1,100 lbs/mwh (12 mos.) 1,000-1,050 lbs/mwh (84 mos.) New gas/dual fuel CCs meet limit New coal units require partial carbon capture and sequestration or similar to meet limits 7

8 Production cost resulting incremental variable cost due to re-dispatch from one higher emitting resource to another lower emitting resource until the mass-based emissions target is achieved Carbon Price Price on emissions for 111(d) covered sources that is derived from re-dispatching lower variable cost/ higher emitting sources to higher variable cost/lower emitting sources Calculating Costs Load energy payment energy costs borne by load; Through simulation implementing a CO 2 price will increase the marginal cost of energy, thus increasing load energy payments (congestion and marginal losses may also change but were not separately identified) Incremental production cost is a 111(d) compliance cost 8

9 Calculating Costs Capital cost estimated total new investment associated with addition of new generation (PJM Interconnection Queue and State based RPS) and Energy Efficiency Based on generic overnight capital costs in 2012 dollars Transmission cost Based on transmission upgrades made necessary as a result of generation retirements Incremental investments in new generation, energy efficiency programs and transmission upgrades also may be 111(d) compliance costs 9

10 Model Years Clean Power Plan "Glide Path" interim goal allows averaging emissions compliance from PROMOD is not capable of dynamically modeling a glidepath Similar to EPA s modeling approach, PJM modeled individual years OPSI requested PJM analyze three years: 2020, 2025 and 2029 PJM s modeling, therefore, should not be interpreted to suggest that compliance must be achieved by 2020, 2025 or

11 Section II: Mass-based and Emission Rate Targets

12 Historic Trends and Policies Affecting CO 2 Mass Reduction Pre-2020 MATS compliance has led to many announced coal steam retirements by 2016 and is independent of 111(d) policy Sustained low natural gas prices combined with sluggish load growth exert economic pressure on less efficient coal units to retire independent of 111(d) policy PJM announced deactivation s mitigate impacts of 2020 emissions target and provide some margin for output increases consistent with load growth 12

13 Impact of Retirements and New Resources Relative to 2012 Baseline: Mass Basis 2012 CO 2 Emissions (Millions of Short Tons) 50,000 45,000 40,000 35, NGCC ICAP Versus 2020 Modeled ICAP (MW) 111(b) 111(d) 13, ,000 25,000 20,000 15,000 26,895 32, (d) Covered Units 111(d) Covered Units Less: Announced Generator Deactivations 10,000 5,

14 Target Mass Calculation EPA Eq.1 - Implied in June 2 TSD Mass Target =State Rate x (2012 Covered Sources + Renewables + Nuclear, ar-new + Incremental EE) State with higher EE and RPS targets has higher mass limit Constant mass target as EE and RPS are only variable to change as rate declines EPA Eq. 2 - Implied in November 6 TSD Mass Target = State Rate x ( 2012 Covered Source Renewable + Nuclear,ar-new + Net New Load growth ) No crediting for new renewables and incremental EE Declining mass target over interim compliance period 14

15 CO 2 Short Tons (Millions) PJM Historic Emissions vs 111(d) Mass-Based Limits June 2 nd TSD Interim Goal ( average) Modeled 2020 Modeled 2025 CO2 Historic Emissions 111(d) CO2 Emission Limit Modeled 2029 Final Goal (2030 and thereafter) 15

16 Tons (Short Millions) 442 PJM Region Carbon Emissions Target Mass Limits: November 6 Guidance

17 140, , ,000 80,000 State-Wide CO 2 Mass Limits (Nov. 6 EPA Guidance) PA, OH and WV 2012 Actual 2012 Adjusted 2020 Goal Interim Goal Final Goal 60,000 40,000 20,000 0 Pennsylvania Ohio West Virginia 2012 Adjusted = 2012 Total CO 2 Emissions Less: 2012 Emissions From PJM Announced Unit Deactivations 17

18 State-Wide CO 2 Mass Limits (Nov. 6 EPA Guidance) IL*, VA, IN*, MD, KY*, NJ, DE and NC* *Limit Calculated based upon generation MWh s and associated CO 2 tons serving load within PJM Balancing authority 45,000 40,000 35,000 30, Actual 2012 Adjusted 2020 Goal Interim Goal Final Goal 25,000 20,000 15,000 10,000 5,000 0 Illinois Virginia Indiana Maryland Kentucky New Jersey Delaware North Carolina 2012 Adjusted = 2012 Total CO 2 Emissions Less: 2012 Emissions From PJM Announced Unit Deactivations 18

19 PJM Region Carbon Emissions Target Rates lb per MWh 1,900 1,700 1,721 1,500 1,417 1,406 1,393 1,379 1,363 1,344 1,324 1,305 1,283 1,261 1,300 1,

20 Section III: Scenario Descriptions

21 Planning Model Resource Capacity The PJM Planning model already consists of a significant amount of renewables due to the inclusion of interconnection queue projects with an Interconnection Service Agreement and or Facilities Study agreement Commercial Likelihood of ISA projects > 70% Commercial Likelihood of Completion for FSA Projects > 50% Resources from the interconnection queue are modeled at their full energy resource value Most resources have an in-service date prior to the start of the interim compliance period Base planning model meets PJM IRM Target in all years 21

22 OPSI Compliance Alternatives Evaluated OPSI Scenarios Fossil & Nuclear Resources Renewables Energy Efficiency (EE) OPSI 2a OPSI 2b.1 OPSI 2b.2 Existing and Planned Resources (ISA and FSA only) PJM RPS Requirement Existing and Planned Resources (Non-Renewable: ISA and FSA only, *Wind/Solar FSA, ISA, SIS and FEAS Existing and Planned Resources (ISA and FSA only) 100% EPA EE 50% EPA EE Goals OPSI 2b.3 OPSI 2b.4 Existing and Planned Resources (ISA and FSA only) Increase Natural Gas Price by 50% Existing and Planned Resources (ISA and FSA only) 50 % Reduction in Nuclear Capacity PJM RPS Requirement 100% EPA EE OPSI 2c Same as OPSI 2a but state-by-state compliance 22

23 PJM Compliance Alternatives Evaluated Fossil Resources Nuclear Renewables Energy Efficiency (EE) PJM 1 Existing and Planned Resources (ISA and FSA only) EPA Expected Renewables 50% EPA EE PJM 2 Existing and Planned Resources (ISA and FSA only) Existing Wind & Solar 17/18 BRA Cleared PJM 3 Adjust planned natural gas capacity based on historic commercial probability Existing Wind & Solar 100% EPA EE PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 PJM 9 PJM 10 Existing and Planned Resources (ISA and FSA only) Existing and Planned Resources (ISA and FSA only) Adjust planned natural gas capacity based on historic commercial probability Existing and Planned Resources (ISA and FSA only) Adjust planned natural gas capacity based on historic commercial probability 10% Nuclear Retirement Same as PJM 5 except Reduce new NGCC capacity to not exceed IRM Target Same as PJM 7 with Henry Hub gas price set to 50% higher Same as PJM 4 Scenario but simulated for state-by-state compliance Same as PJM 4 Scenario but simulated to achieve regional mass target Trend Wind/Solar and Energy Efficiency Based on historic growth Rates: Wind and Solar IS, UC Energy Efficiency - PJM BRA Cleared MW 23

24 Section IV: Regional Compliance Mass Target Emissions and Price Comparisons

25 CO 2 Emissions With no Carbon Price Tons (Millions) OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 25

26 $ Per Ton $60 $40 $20 EPA Eq. 1 EPA Eq. 2 Implied Carbon (CO 2 ) Price in 2020, 2025 and 2029 Comparison of June 2 EPA guidance versus Nov 6 guidance 2020 $0 $60 $40 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM $20 $0 $60 $40 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM $20 $0 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 26

27 EPA Eq. 2 $ Billions $80 111(d) $60 $40 $20 BASE & 2025 Load Energy Payment Comparison of June 2 EPA guidance versus Nov 6 guidance EPA Eq. 1 $80 $60 $40 $20 111(d) BASE $0 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 $0 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 $100 $80 111(d) BASE 2025 $100 $80 111(d) BASE $60 $60 $40 $40 $20 $0 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1PJM 2PJM 3PJM 4PJM 5PJM 6PJM 7PJM 8 $20 $0 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 27

28 2029 Load Energy Payment Comparison of June 2 nd EPA guidance versus Nov 6 th guidance $ Billions EPA Eq. 2 $120 $100 $80 $60 $40 $20 $0 $100 $80 $60 $40 $20 $0 111(d) OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 111(d) BASE BASE EPA Eq. 1 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 28

29 $ Per MWh $ (d) Base $80 $60 $40 $20 $ & 2025 PJM Average Locational Marginal Price Comparison of June 2 EPA guidance versus Nov 6 guidance 2020 $100 $80 $60 $40 $20 $0 111(d) BASE $120 $100 $80 $60 $40 $20 $0 111(d) Base 2025 $100 $80 $60 $40 $20 $0 111(d) BASE 29

30 $120 $100 $80 $60 $40 $20 $0 $120 $100 $80 $60 $40 $20 $0 111(d) Base 2029 PJM Average Locational Marginal Price Comparison of June 2 EPA guidance versus Nov 6 guidance EPA Eq. 2 OPSI 2a OPSI 2b.1OPSI 2b.2OPSI 2b.3OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 111(d) BASE EPA Eq. 1 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 30

31 $ Billions $4.0 $3.0 $2.0 $1.0 Variable Compliance Costs (Implied CO 2 Allowance Value Not Included) in Fuel and Variable O&M Costs due to 111(d) Policy EPA Eq. 2 $0.0 $2.0 $1.5 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM EPA Eq. 1 $1.0 $0.5 $0.0 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 31

32 Section V: State Versus Regional Compliance Notes: Unless otherwise noted All results are based on November 6th guidance, EPA Equation #2

33 Regional vs. State Compliance Modeling Regional Approach A single price on CO 2 is applied to all carbon emitting resources across PJM. This in turn raises the costs of carbon intensive resources, impacting dispatch, which is done on a lowest cost basis. The approach results in satisfying the emissions target with the least cost mix of resources to meet PJM load requirements. State by State Approach Each state has an individually determined price on CO 2 applied to the carbon emitting resources located within it to ensure satisfaction of emissions target. Those prices are applied, and PJM dispatches the resources across the region to determine the least cost mix to meet the total PJM load requirements. The approach results in each state satisfying its emissions target and the resource mix being the least-cost combination, as influenced by disparate CO 2 prices, to meet the PJM load requirements. 33

34 Description of Scenarios Evaluated For State Analysis Driver OPSI 2a PJM 4 Renewables 81.9 GWH 50.2 GWH New NGCC 19 GW 19 GW Nuclear 33.4 GW 33.4 GW Gas Price Economic Forecast Economic Forecast Energy Efficiency 23.3 GWh 9.2 GWh States only evaluated for compliance with 2020 interim target 34

35 $ Per Ton Carbon Price under State Compliance Versus Regional Compliance For year 2020 State Compliance Regional Compliance Tons (Millions) State Compliance Regional Compliance 0.00 PJM 4 OPSI 2a 340 PJM 4 OPSI 2a 35

36 $ Per Ton $18 $16 $14 $12 $10 $8 $6 $4 $2 $0 Individual State Implied Carbon (CO 2 ) Prices For year 2020 PJM 4 OPSI 2a DE IL IN KY MD MI NC NJ OH PA VA WV 36

37 $ Billions PJM Total Load Payment State Versus Regional Compliance For Year 2020 $50.00 $45.00 $40.00 $35.00 $30.00 $25.00 $20.00 $15.00 $10.00 $5.00 State Compliance Regional Compliance $0.00 PJM 4 OPSI 2a 37

38 Implied CO 2 Allowance Cost Comparison and State Energy Cost Impact of Individual State Compliance Versus Regional Compliance For 2020 $450 $400 $350 $300 $250 $200 $150 $100 $50 $0 CO 2 Allowance Implied Value $ Millions OPSI 2a Scenario IL IN OH WV $100 $90 $80 $70 $60 $50 $40 $30 $20 $10 $0 Change in Energy Costs to Load $Millions (Exclude Congestion Component) OPSI 2a Scenario DE DC IL IN KY MD MI NJ NC OH PA TN VA WV Regional Compliance Case did not result in redispatch Consequently, there is no additional compliance costs 38

39 Implied CO 2 Allowance Cost Comparison and State Energy Cost Impact of Individual State Compliance Versus Regional Compliance For 2020 $1,400 CO 2 Allowance Implied Value $ Millions State Compliance $2,000 Change in Energy Costs to Load $Millions (Exclude Congestion Component) $1,200 $1,000 PJM 4 Scenario Regional Compliance $1,800 $1,600 $1,400 PJM 4 Scenario $800 $600 $1,200 $1,000 $800 $400 $600 $200 $0 DE IL IN KY MD NC NJ OH PA VA WV $400 $200 $0 DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 39

40 Section VI: Rate Based Versus Mass-Based Compliance Notes: Rate Based Compliance Impacts were measured using the PJM #4 Scenario for 2025 and CO 2 rate target is equivalent to the interim (average) target for 2020 through 2029 All results are based on November 6th guidance, EPA Equation #2 40

41 Implementation of Rate-Based Method Individual Resource Price adder to be applied to all covered units Unit Price Adder = Heat Rate x (Emissions Rate Target Rate) x CO 2 price Emissions Rate < Target Rate yields production credit Emissions Rate > Target Rate yields transfer payment Unit s bid price reflects either production credit or penalty as a function of performance System CO 2 Target Rate = lbs of CO 2 from affected Sources Nuclear, ar + Renewables + Incremental EE + Affected Source MWh s 41

42 PJM Locational Marginal Price: PJM 4 Rate Based (Performance) Versus Mass-Based Regional Compliance $ Per MWh $80 Rate Based $70 Mass Based $60 $50 $40 $30 $20 $10 $

43 $60 $50 PJM Implied Carbon (CO 2 ) Price: PJM 4 Under Rate Based (Performance) Versus Mass Based Compliance Rate Based CO2 Price Mass Based CO2 Price $40 $30 $20 $10 $

44 Total PJM Load Payment: PJM 4 Rate Based (Performance) Versus Mass-based Compliance $ Billions $70 $65 Rate Based Mass Based $60 $55 $50 $45 $40 $35 $

45 Total PJM Production Costs Comparison: PJM 4 Rate Based (Performance) Standard Versus Mass Based Standard $ Billions $36 $34 Rate Based Mass Based $32 $30 $28 $26 $24 $22 $

46 CO 2 Tons (Millions) Total PJM CO 2 Simulated Emissions: PJM 4 Rate Based "Performance" Versus Mass Based Standard Rate Mass

47 Section VII: Economic Analysis of Steam Turbine Retirement Risk Note: units that have already announced deactivation are not included in this analysis; the analysis focused on incremental retirement risk 47

48 Economic Retirement Risk Analysis Key Variables Technology type and Avoidable Cost Rates (ACR) Determines annual avoidable costs used in calculating Market Seller Offer Caps in RPM Net Energy Market Revenues are based on simulation and exclude ancillary service revenue In the RPM Capacity Market, the price of capacity, and the quantity of capacity resources are determined within the auction framework Net Cost of New Entry (Combustion Turbine) is the benchmark price at which resource adequacy is achieved at the Reliability Requirement. For a regulated utility, this would be a reasonable benchmark for making the decision to retain an existing unit, or retiring the unit and building a natural gas CT 48

49 Economic Retirement Risk Criteria Economic Risks is assessed based on Energy Market Revenues Net of Fixed (ACR) and Variable Operating Costs benchmarked against the following criteria: > 1.5 Net CONE Net CONE 1.5 Net CONE ½ Net CONE Net CONE < ½ Net CONE Financial Viability Above max RPM LDA price Above the cost of new entry gas CT Would clear before new entry gas CT Likely to clear Assuming no additional capital costs Risk Very High or Most at Risk High at Risk or at some Risk Low 49

50 MW 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 > 1.5 Net Cone 1/2 Net Cone - Net Cone Net Cone Net Cone MAAC Region Steam Turbine 2020 Regional Mass Compliance Related Retirement Risk Analysis EPA Eq. 2 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 3,000 2,000 1,000 Net Cone Net Cone 1/2 Net Cone - Net Cone > 1.5 Net Cone EPA Eq ,000 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 50

51 MW 20,000 15,000 10,000 > 1.5 Net Cone 1/2 Net Cone - Net Cone Net Cone Net Cone Rest of RTO Region Steam Turbine 2020 Regional Mass Compliance Related Retirement Risk Analysis EPA Eq. 2 5, ,000 8,000 6,000 4,000 2,000 0 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 Net Cone Net Cone 1/2 Net Cone - Net Cone > 1.5 Net Cone EPA Eq. 1 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 51

52 MW 5,000 4,000 3,000 2,000 1, ,000 3,000 2,000 > 1.5 Net Cone 1/2 Net Cone - Net Cone Net Cone Net Cone MAAC Region Steam Turbine 2025 Regional Mass Compliance Related Retirement Risk Analysis OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 Net Cone Net Cone 1/2 Net Cone - Net Cone > 1.5 Net Cone EPA Eq. 2 EPA Eq. 1 1,000 0 OPSI 2a OPSI 2b.1OPSI 2b.2OPSI 2b.3OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 52

53 MW 20,000 15,000 10,000 > 1.5 Net Cone 1/2 Net Cone - Net Cone Net Cone Net Cone Rest of RTO Region Steam Turbine 2025 Regional Mass Compliance Related Retirement Risk Analysis EPA Eq. 2 5, ,000 5,000 4,000 3,000 2,000 1, ,000 OPSI 2a OPSI 2b.1OPSI 2b.2OPSI 2b.3OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 Net Cone Net Cone 1/2 Net Cone - Net Cone > 1.5 Net Cone EPA Eq. 1 OPSI 2a OPSI 2b.1OPSI 2b.2OPSI 2b.3OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 53

54 MW 6,000 5,000 4,000 3,000 2,000 1,000 0 > 1.5 Net Cone 1/2 Net Cone - Net Cone Net Cone Net Cone MAAC Region Steam Turbine 2029 Regional Mass Compliance Related Retirement Risk Analysis EPA Eq. 2 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 2,000 1,500 1, Net Cone Net Cone 1/2 Net Cone - Net Cone > 1.5 Net Cone EPA Eq. 1 0 OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 54

55 MW 40,000 30,000 20,000 > 1.5 Net Cone 1/2 Net Cone - Net Cone Net Cone Net Cone Rest of RTO Region Steam Turbine 2029 Regional Mass Compliance Related Retirement Risk Analysis EPA Eq. 2 10,000 7,000 6,000 5,000 4,000 3,000 2,000 1, OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 Net Cone Net Cone EPA Eq. 1 1/2 Net Cone - Net Cone > 1.5 Net Cone OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 55

56 MW 20,000 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 Rest of RTO MAAC State By State Versus Regional Mass Based Compliance Steam Turbine Units Requiring > ½ Net Cone to cover Fixed Costs Evaluated in ,939 17,732 1,263 1,306 OPSI 2a Regional OPSI 2a State OPSI 2a (Regional) High Renewables and High EE Case does not require re-dispatch of resources consequently there are no new retirements due to regional policy implementation 56

57 25,000 20,000 MW Rest of RTO MAAC State By State Versus Regional Mass Based Compliance Steam Turbine Units Requiring > ½ Net Cone to cover Fixed Costs Evaluated in ,000 10,000 16,723 5, ,040 1,845 PJM 4 Regional 3,182 PJM 4 State 57

58 MW Rest of RTO MAAC Rate Versus Mass Based Compliance (PJM 4) Steam Turbine Units Requiring > ½ Net Cone to Cover Fixed Costs 2025 MW Rest of RTO MAAC ,899 11, ,362 20, ,410 PJM 4 Mass 2,196 PJM 4 Rate ,992 PJM 4 Mass 1,554 PJM 4 Rate 58

59 Section VIII: Natural Gas Combine Cycle Operational Analysis 59

60 PJM Historic Capacity Factors vs Gas Price 85% $10 Capacity Factor (%) 75% 65% 55% 45% 35% 25% Coal Steam Capacity Factor Henry Hub Gas Price ($/MMBtu) Natural Gas Combined Cycle $9 $8 $7 $6 $5 $4 $3 $2 $1 Henry Hub Gas Price ($/mmbtu) 15% $0 60

61 Capacity Factor (%) 70% 2020 NGCC Capacity Factors by Scenario Impact of 111(d) Policy 60% 50% 40% 30% 20% 10% Policy Base 0% OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 61

62 Capacity Factor Impacts Policy CF (%) Ratio of Resources under 111(b) Versus Under 111(d) Ratio with 111(d) Policy Ratio Without 111(d) Policy OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 Average Average (no OPSI 2b.3) 62

63 $/MW-Day $100 $50 $0 -$50 -$100 -$150 -$ (d) Policy NGCC Average Revenue Requirement 2020,2025 & 2029 With and Without 111(d) Policy $100 $50 $0 -$50 -$100 No Policy -$250 -$ (b) NGCC 111(d) NGCC -$ (b) NGCC 111(d) NGCC -$350 -$200 63

64 Section IX: Appendix 64

65 Reliability Analysis PJM expects to have initiated the reliability analysis and have preliminary results for some of the reliability criteria tests by the end of November Using the mass based and rate based economic modeling of regional compliance, identify potential retirements Through power flow analysis using the 2022 RTEP case, identify potential reliability criteria violations that would result due to the potential retirements Estimate potential transmission infrastructure costs based: Generally, on the level of transmission upgrades required for the recent Mercury Air Toxics Standard (MATS) related generation retirements, and Specifically, on the average cost to upgrade identified limiting transmission facilities Reliability criteria testing will continue beyond the end of November and be reviewed with stakeholders at the TEAC Actual transmission costs may vary (significantly) depending on whether upgrades to existing facilities or new green field transmission projects are needed. 65

66 $Billions $120 $100 $80 $60 Generic Capital Investment Costs By Scenario $2012 Total Overnight Construction Costs ( ) EE NGCC Solar Wind $40 $20 $- Planning OPSI 2a OPSI 2b.1 OPSI 2b.2 OPSI 2b.3 OPSI 2b.4 OPSI 2c PJM 1 PJM 2 PJM 3 PJM 4 PJM 5 PJM 6 PJM 7 PJM 8 These costs are generic total build costs and should not be misinterpreted as resulting from compliance with the Clean Power Plan. These costs may be incurred before, during or after the interim compliance period for 111(d). 66

67 Sources for Generic Capital Cost Assumptions Lazard s Levelized Cost of Energy Analysis version 7.0 (referred to as the Lazard Report) United States Energy Information Administration Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants, April 2013 (referred to as the EIA report) National Renewable Energy Laboratory Distributed Generation Energy Technology Capital Costs (referred to as the NREL report) 67