FILED July 31, 2020 OFFICI/iL INDIANA UTILITY REGULATORY COMMISSION EXlIIBITS STATE OF INDIANA

INDIANA UTILITY REGULATORY COMMISSION

SUBDOCKET FOR REVIEW OF DUKE ) ENERGY INDIANA, LLC'S GENERATION ) CAUSE NO. 38707 FAC 123 Sl UNIT COMMITMENT DECISIONS ) IURC INTERVENOR's-f\£ ~ EXHIBli NO. z;) I /0-3()-~ 1 2 £, DATE REPORTER

ADVANCED ENERGY ECONOMY'S EXHIBIT 2

VERIFIED DIRECT TESTIMONY AND ATTACHMENTS OF ROBERT B. STODDARD Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 S1 Page 1 of25

1 L INTRODUCTION AND QUALIFICATIONS

2 Q. Please state your name, position and business address.

3 1. My name is Robert B. Stoddard. I am an economist and a managing director of Berkeley 4 Research Group, LLC ("BRG"). My business address is 1800 M Street NW, 2nd Floor, 5 Washington DC, 20036. At BRG, I am the co-lead of the power & renewables sector of the 6 Energy & Climate Practice and am responsible, among other things, for the firm's power 7 systems modeling.

8 Q. What professional positions have you held?

9 2. Prior to joining BRG earlier this year, I was the president and chief executive officer of

10 GWave LLC, an energy technology firm. As CEO of GWave, I provide executive

11 leadership for a technology startup developing a new generation of ocean wave energy

12 converters. I also was the founding principal of Power Market Economics LLC, a 13 consultancy focusing on innovations in market design to better integrate state policy 14 objectives in wholesale power markets. Prior to joining GWave in 2013, I led the global 15 energy practice at Charles River Associates, a finance and economics consultancy.

16 Q. What experience do you have as an energy market expert?

17 3. My consulting work focuses on electricity industry restructuring, capital investment in 18 power markets, and providing both strategic analyses and testimony for utilities, generation 19 owners, and governments regarding the practical implications of market design. I have

20 frequently testified before the Federal Energy Regulatory Commission ("FERC") as well

21 as before state utility commissions and legislatures on competitive market design and

22 operations, rates, and market power issues, particularly in the regions managed by Regional 23 Transmission Organizations ("RTOs") and Independent System Operators ("ISOs"). 24 Throughout my 30-year consulting career, I have often relied on detailed power systems 25 models to simulate power systems operations at a high granularity, both in testimony and 26 in advisory work. I am frequently invited to speak at professional conferences, including 27 recent conferences convened by FERC and the Office of the Attorney General of 28 Massachusetts on achieving state policy goals in federal markets. I hold degrees in Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 S1 Page 2 of25

1 economics from Amherst College and Yale University. My complete curriculum vitae is 2 Attachment RBS-I.

3 11 PURPOSE AND SUMMARY

4 Q. What are the topics of your testimony today?

5 4. I have been asked by AEE to address two areas: first, what financial implications flow from 6 the commitment and dispatch decisions made by Duke Energy Indiana, LLC ("Duke") 7 regarding a subset of its coal-fired electric generators; and second, what steps could Duke 8 have taken to mitigate current and future financial impacts from any uneconomic 9 operations. I note that each paragraph of my responses to the questions asked of me is

10 consecutively numbered, rather than labeled with the typical "A.", for ease of cross-

11 referencing within my testimony.

12 Q. How did you quantify the uneconomic dispatch decisions Duke made during the Fuel 13 Adjustment Clause period?

14 5. BRG used a state-of-the-art power systems model, ENELYTIX™, to simulate the 15 commitment and dispatch in the control area of the Midcontinent Independent System 16 Operator ("MISO"). Attachment RBS-2 describes the ENELYTIX computer model and 17 analytical capability. As I will discuss in detail later, we compared two modeled runs of the 18 period March 2019 through June 2020, which encompasses periods before and after the 19 relevant Fuel Adjustment Clause period in this subdocket to allow us to calibrate the model.

20 Our Base Case is designed to simulate the actual operation of the system, including the

21 historical commitment and dispatch of Duke's coal-fired generators. The Market Case, by

22 contrast, simulates the security-constrained least-cost commitment and dispatch of the 23 system, including Duke's coal-fired generators, respecting the operating limitations of 24 these units but allowing the system operator to dispatch them economically. Comparing the 25 Base Case to the Market Case therefore provides a sound basis for evaluating what savings 26 or costs were incurred by Duke electing to constrain MISO' s dispatch control of these coal­ 27 fired plants. Attachment RBS-3 provides the details of the analysis to which I refer when 28 discussing my findings. I refer to Attachment RBS-3 throughout my testimony as the 29 Technical Appendix. Intervenor AEE Exhibit 2 IURC Cause No. 38707 PAC 123 S1 Page 3 of25

1 Q. What excess costs do you estimate Duke incurred during the Fuel Adjustment Clause

2 period?

3 6. In summary, we confirmed that these coal-fired generators were operated at a significant 4 financial loss during the FAC 123 period. We also confirmed continued significant financial 5 loss operation of Duke's coal-fired generators during the FAC 124 period (and, indeed, 6 through the entire backcast period), which demonstrates that Duke's self-commitment 7 decisions in the FAC 123 period are not isolated events but rather demonstrate the 8 continuing harm to Duke's ratepayers through its self-commitment decisions. It also 9 demonstrates that decisions made by Duke within the reconciliation period have long-

10 lasting effects, well outside of the reconciliation. While the FAC 123 period is the period

11 at issue for rate recovery in this subdocket, I include information on the FAC 124 period to

12 demonstrate that the harm to Duke ratepayers is not isolated but continuing. As shown in 13 Table A, below, estimated losses were $20.57M during FAC 123 and $24.93M during FAC 14 124.1 These losses arise simply because the incremental cost of generating energy at these 15 plants-principally the cost of the coal bumed--exceeded, on average, the market value of 16 that energy. That there were losses is a matter of record, so this finding is expected. The 17 interesting conclusion, however, is that a significant portion of these losses were self- 18 inflicted. In the Market Case, the losses throughout the backcast period and, specifically, 19 during FAC 123, are markedly lower than in the Base Case, at $1.37M.2 The losses are

20 reduced because, when operated solely on the basis ofleast-cost system operations, Duke's

21 coal-fired plants were committed less often and dispatched to lower levels compared to

22 historical operations. This gap must arise either from some combination of actions by Duke 23 to self-commit, self-dispatch and under-bid the energy cost from these resources. These 24 decisions created readily avoidable losses of $19.20M during FAC 123 and an additional 25 $21.54M during FAC 124 (see Table A below and Table 9.E of the Technical Appendix).

26 Table A: Losses Attributable to Uneconomic Dispatch of Coal Units

Total Total Operating Operating Losses Losses Margin all Margin all Attributable to Attributable to

1 Throughout this testimony I abbreviate "million" as "M".

2 Including revenues of approximately $25,000 and $47,000, respectively, from provision of ancillary services Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 S1 Page 4 of25

Units Base Units Market Uneconomic Uneconomic Case$ Case$ Dispatch$ Dispatch% FAC 123 (20,572,065) (1,372,648) (19,199,417) 93% Subtotal FAC 124 (24,926,776) (3,389,991) (21,536,785) 86% Subtotal 1 Q. Should the Commission grant recovery of these losses attributable to uneconomic

2 dispatch?

3 7. No. Utilities should be granted cost recovery only for costs prudently incurred to meet their 4 service obligations. Based on my study of the data and our modeling, Duke has 5 systematically chosen to generate power from its own facilities rather than buying power 6 from the wholesale market. In so doing, Duke incurred higher costs entirely at its own 7 discretion. The incremental costs should, therefore, be disallowed from rate recovery.

8 Q. What would the impact on power rates for Duke's customers be were these excessive 9 costs allowed into rates?

10 8. These charges are a significant fraction of Duke's overall energy costs in FAC 123. We

11 estimate that the cost to serve load in the Base Case was about $240 million, so the extra

12 fuel costs that Duke uneconomically incurred are about 8 percent of the total energy costs 13 to serve Duke's load in FAC 123.

14 Q. Other than eliminating self-scheduling, are there other steps that Duke could have 15 taken to reduce its costs it seeks to recover under the Fuel Adjustment Clause?

16 9. Yes. Further savings could have been achieved by using selective, seasonal reserve 17 shutdowns. Such shutdowns are a standard practice in the utility business, as they allow 18 the utility to access the units during peak load periods (typically summer, or summer and 19 winter) while minimizing operating losses during months with low energy demand. For 20 example, FAC 123 occurs during the autumn "shoulder season," when operating capacity

21 reserves are rarely tapped. Had Duke put four of its least-economic coal-fired plants in

22 reserve shutdown during FAC 123, the cost to serve load would have been $9.37M lower 23 than in the Base Case.

24 10. A further loss mitigation strategy that was available to Duke is to have retired some or all 25 of these coal units altogether and replaced them with advanced energy resources, including Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 SI Page 5 of25

1 demand response, renewable energy generation, and storage. These are decisions that Duke

2 could have made during PAC 123 or PAC 124 but did not. To assess the cost of this inaction, 3 we modeled three additional cases, both for the year 2025: a Base Case, Advanced Case I 4 and Advanced Case II. In the 2025 Base Case, Duke continues to operate its coal-fired fleet 5 as it did in the Base Case (mirroring actual operations in 2019-2020). In the 2025 Advanced 6 Case I, Duke has retired the four coal-fired units that create operating losses, replacing 7 them with equivalent amounts of advanced energy solutions. In the 2025 Advanced Case 8 II, Duke has retired its entire coal-fired fleet and installed a greater amount of advanced 9 energy resources.

10 11. When we look across these three forecasts, it quickly becomes apparent that Duke's failure

11 to take proactive steps during PAC 123 to accelerate its coal unit retirements will continue

12 to be a costly omission in Duke's planning. Table B below summarizes these forecast cases.

13 Table B: Forecast Total Cost to Serve Duke Native Load 14 For 2025, in 2020$ millions

Total Cost of Serving Savings from Load 2025 Base 2025 Base 1,142 2025 Advanced 105.3 1,036 I 2025 Advanced 423.7 717 II 15

16 12. In summary, our study estimates that 93 percent of the operational losses during PAC 123, 17 and 86 percent during PAC 124, at Duke's coal-fired generators were a direct result of 18 Duke's decisions to commit and dispatch these units uneconomically. Potentially 100 19 percent of these losses could have been avoided in this, to the extent that MISO make-

20 whole payments would have spread the costs of uneconomic commitments more broadly

21 among MISO load-serving entities. Even when operated as economically as possible, many

22 of Duke's coal-fired generators still run operational losses as a result of their relatively 23 high costs and operational inflexibility relative to advanced energy resources and natural 24 gas-fired generators. To have mitigated these losses during PAC 123, and to mitigate future Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 S1 Page 6 of25

1 losses, Duke could have operated some of these units seasonally and made plans to

2 accelerate their retirement.

3 III. MODELING DATA AND METHODS

4 Q. Please provide more detail about the power system model you rely upon.

5 13. BRG used a state-of-the-art power system modeling suite, ENELYTIX™ and Power 6 System Optimizer ("PSO"), to simulate the commitment and dispatch in the MISO control 7 area. The model simulates the hourly, chronological commitment and dispatch of each 8 generator to meet load and reserve requirements in the control area. We include flows 9 between MISO and neighboring control areas based on historical patterns. PSO

10 incorporates security-constrained cost-minimization algorithms that closely parallels those

11 used by MISO in committing and dispatching the system. The model uses a database that

12 incorporates current, public information on the system transmission topology, generating 13 unit characteristics, load, and other relevant details. As part of its normal database 14 calibration work, ENELYTIX's publisher, the Newton Energy Group, LLC, includes in its 15 database adjustments to the operating parameters of many of the large utility-owned coal- 16 fired power plants in MISO to represent more accurately the widespread practice of 17 committing and dispatching these plants more than would be predicted based on their 18 operating characteristics or in comparison to similar non-utility generators. Table 6 in the 19 Technical Appendix lists the data sources we relied on for data inputs to the model.

20 Q. Could you please clarify the difference between "committing" and "dispatching" a

21 power plant?

22 14. Commitment is the decision of whether and when a generator should be operating at all. 23 Committing a unit is a costly decision that must be made hours or even days before the unit 24 is on-line and available to serve load. Coal-fired units, in particular, have long start-up 25 times. During that time, the unit will burn fuel and incur wear-and-tear. These costs are 26 collectively referred to as start-up costs. Generators have further time constraints, including 27 a minimum run-time and, once de-committed, minimum down-time.

28 15. Once a unit has been committed and has completed its start-up, it is available for dispatch. 29 A generator operates at some minimum generation level; for large fossil-fueled units this 30 range is typically about one-third to one-half of the maximum generation capability. Other Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 SI Page 7 of25

1 limitations on dispatch are the unit's ramp rate, which dictates the maximum change in the

2 generator set point from one interval to the next, and the unit's maximum capability. This 3 maximum may vary seasonally (reflecting ambient temperatures). Some units have a lower 4 "eco max" point that is the highest dispatch point for normal system operations.

5 Q. Are all these start-up costs and unit operational constraints included m the 6 ENELYTIX/PRO model you use?

7 16. Yes. We have used costs and constraints typical of these unit technologies as I am unable 8 to independently verify Duke's own internal assessments. In particular, the Edwardsport 9 station creates particular operational challenges-principally created by the syngas

10 operations there. The basic generation units there, however, are relatively modern

11 generators that could be operated flexibly using pipeline gas.

12 Q. When you discuss "costs" and "operating margins," what categories of costs are you 13 studying?

14 17. My study only considers costs that vary with the operating level of Duke's electric 15 generation fleet. Fuel is the principal variable cost. Other variable costs are generically 16 labeled "variable operations and maintenance" and include such items as chemicals and 17 increased maintenance costs associated with operations. I do not, however, consider other 18 station costs, such as general facility maintenance, payroll, and taxes. These costs are 19 mostly unchanged by short-term operational decisions at the plant, even though some of

20 these costs might be saved were a facility retired or seasonally mothballed.

21 Q. What steps did you take to assure that your model's results align with historical system

22 operation?

23 18. BRG calibrated a backcast from March 2019 through June 2020, inclusive. Our database 24 included actual loads and the market price of fuels for these months. Consequently, we 25 expected and achieved a close alignment between the backcast and historical actuals of two 26 indicators: system-average locational marginal prices ("LMPs") and the mix of resources 27 dispatched to serve load. These are shown in Charts 7 and 8 in the Technical Appendix.

28 19. In refining the backcast, we paid close attention to matching the predicted output of Duke's 29 coal-fired fleet with historical generation. While some of this alignment was made by using Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 SI Page 8 of25

1 Duke's specific coal costs, much of the alignment was achieved by forcing unit

2 commitment and dispatch. Ultimately, this Base Case closely mirrors the actual operation

3 of Duke's resources and, more generally, those ofMISO through the backcast period. This 4 alignment is shown in Charts 1-5 below and Tables 1-5 in the Technical Appendix.

5 Chart 1 6 MISO Generation by Unit Type, BRG Backcast (Base Case) Generation by Fuel: Enelytix Backtest 70,000,000

60,000,000

50,000,000

40,000,000

30,000,000

20,000,000

10,000,000

~ ~ ~ ~ (\,<::, ~~ ,,i::. '\,~ ~"' ).~~"' 't,,...,, ~"' ,,,,...,,1> 1> "y<::, 1> 1> 1> ,,,,,,..., ~,s, ...,0...., \,s, 0-.J. ,v.~ '<>~ ....~ v n Natural Gas Coal Wind Other Fuel Ill Water Uranium Ill Solar iii! Biomass !ill Petroleum Products ll!! Water !ill Energy Storage 7 Intervenor AEE Exhibit 2 IURC Cause No. 38707 PAC 123 S1 Page 9 of25

1 Chart2 2 MISO Generation by Unit Type, Actual Generation by Fuel: Historical Actual 70,000,000

60,000,000

50,000,000

40,000,000 ,s= ~ 30,000,000

20,000,000

10,000,000

~ ~ ~..,Oj ~ ~ ~°> ~ (t> (\,<:) ~ ~ 'j,~ 'Q-1/:, ~ 'Q-1/:, ~ 'j,~

4 Chart 3 5 Monthly Generation at Gibson Station

1,500,000

1,400,000

1,200,000 _,. I 1,()00,ooo ·,: ~.,"' 800,000 ! j 600,000

400,000

200,000

~ ~ ~ § ~ ~ ~ ~ § $ ~ ·~ ~ $ $ ~ ~ , ~ , , ~ ~ ~ ~ ~ 4 ~ ~· ~ ~ ~ ~, ~ ~

Ill.Gibson (Actual) • .G.ibson (Enelytix) 6 Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 S1 Page 10 of25

1 Chart 4 2 Monthly Generation at Cayuga Station

500,000

450,000

400,000

350,000 .t: I 1100,000 " 1 250,000 .." ~ 200,000 z" 150,000

100,000

50,000

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

~ ~ ~ ~ ~ ~ ~ ~ ~ .. ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

i% Cayuga (Actual) II! <:ayuga (Enelytix} 3

4 Chart 5 5 Monthly Generation at Edwardsport Station

70,000

50,000 .c 3 ~.· 41),000 0 ·~ "' & 30,()00 z'.i 20,000

10,000

:., Etlwardsport{Actualj III Erlwartlsport{Enelytix) 6

7 20. Although the alignment of backcast and actual LMPs was generally good across all 16 8 months of the backcast, our modeled prices in Indiana during the three months ofFAC 123 Intervenor AEE Exhibit 2 IURC Cause No. 38707 PAC 123 S1 Page 11 of25

1 were low. A closer examination showed that, while our backcast and historicals align well r- 2 in nearly all hours of these months, there were mid-day price spikes that our model did not 3 predict. This issue is commonplace in power system models and is generally caused by the 4 fact that the models have perfect information during unit commitment, while MISO 5 operators need to commit units based on necessarily imperfect load forecasts. Unit 6 maintenance outages (outside of Duke's fleet) may also have contributed to the spiky price 7 pattern. Rather than attempting to force the model to produce these spikes, we recalibrated 8 the LMPs during post-processing. The effects of this post-processing are shown by 9 contrasting Chart 8 to Chart 7 in the appendix.

10 Q. Was this recalibration a conservative assumption?

11 21. Yes: Had we simply used the modeled prices, our conclusions would undervalue Duke's

12 generation and underprice the cost of energy purchases from the market. This recalibration, 13 therefore, reduced our estimate of operating losses from Duke's generation.

14 Q. After calibrating your backcast, what was the next step in your analysis?

15 22. Our next step was to construct a Market Case. With the calibrated Base Case in hand, this 16 case was straightforward to produce by simply removing the forced commitment and 17 dispatch of Duke's coal-fired plants, discussed in paragraph 19 above. Without these 18 constraints, the model optimized the commitment and dispatch of Duke's fleet, as well as 19 the other resources available for economic dispatch, subject to their operating limitations

20 and system security constraints, to minimize the cost to serve load.

21 Q. In the Market Case did you change how other utilities changed the commitment and

22 dispatch of their coal-fired generators?

23 23. No. As I mentioned in paragraph 13 above, ENELYTIX's publisher has imposed must-run 24 requirements on many of the larger, utility-owned coal-fired power plants in its baseline 25 dataset for MISO. These requirements help align the model's predicted operations with 26 historical operations. Because this current matter is limited to how Duke, and not these 27 other utilities, commit and dispatch its generators, we left the configuration of units other 28 than Duke's unchanged between the Base and Market Cases. Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 S1 Page 12 of25

1 Q. You mentioned in your opening summary at paragraph 1010 that you also ran cases

2 for 2025. How did you develop the 2025 Base Case?

3 24. Our starting point for the 2025 Base Case was the 2025 baseline case provided with 4 ENELYTIX by Newton Energy Group. This baseline includes forecast load, planned 5 retirements, generation additions and expansions, changes to the transmission topology, 6 and fuel price forecasts for 2025. We refined this database further to incorporate fuel prices 7 reported to the EIA in the case of regulated gas and coal-fired generation assets, latest 8 commodity futures prices, and recent wind and solar generation profiles. Table 6 in the 9 Technical Appendix details all data sources for 2025. One notable assumption is that

10 Duke's unit costs of coal are unchanged from its 2020 unit costs, an assumption made

11 necessary by our late access to Confidential Information in this docket. To the extent that

12 Duke's unit coal costs rise over time, our assumption of flat coal prices would understate 13 the economic costs of continuing to operate any or all of Duke's coal-fired generators in 14 2025.

15 25. As with our backcast, we paid close attention to how Duke's coal-fired units are modeled 16 in the 2025 cases. We carried forward those modeling constraints on these units that we 17 developed for the Base Case to align the backcast and historical operations. 3 These 18 constraints force the model to commit and dispatch these coal units in the 2025 Base Case 19 consistently with how Duke operated these units in the backcast period.

20 Q. What other 2025 cases did you construct?

21 26. We also set up two other cases for 2025, Advanced Case I and Advanced Case II. In both

22 cases, we removed the constraints on Duke's coal-fired generators that I just discussed, as 23 we did in the backcast Market Case. In each 2025 Advanced Case, we retired certain of 24 Duke's coal-fired units. Those coal-fired generators that ran at an operating loss in the 2025 25 Base Case are retired in the 2025 Advanced Case I. In Advanced Case II, all of Duke's coal 26 fleet is retired.

27 Q. What resources did you include in these Advanced Cases to offset the coal unit 28 retirements?

3 See paragraph 19. Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 S1 Page 13 of25

1 27. Rather than attempting to create an optimized, integrated resource plan around these

2 retirements, I chose a simple heuristic. In each case we added enough advanced· energy 3 resources to match, in expectation, the energy that the retired units produced in the 2025 4 Base Case. Specifically, we added demand response resources, onshore wind, and 5 solar/storage hybrid in a ratio that is consistent with the ratio of these resource that Vectren 6 has proposed in its recent Integrated Resource Plan for replacing its retiring coal fleet: that 7 for each MW of demand response resource added, 10 MW of wind and 30 MW of solar or 8 solar/storage hybrid is added.4 (Because these solar/storage hybrids are a relatively new 9 resource type and the supply chain for them is less mature, we assume that 10 percent of

10 the new solar resources are collocated with storage.) Holding this ratio fixed, we calculated

11 the total installed capacity that would generate the required amount of energy over a year,

12 using locational resource profiles from the National Renewable Energy Laboratories. 13 Because we have not attempted to optimize this portfolio for Duke's particular situation, 14 my findings will understate the benefits of accelerating the coal retirements.

15 Q. Vectren's IRP also includes addition of gas turbines. Do your Advanced Cases also 16 include any new gas-fired generation?

17 28. Yes. Although the addition of these advanced energy resources balances the expected 18 energy that would otherwise be supplied from the retiring coal units, they do not contribute 19 as much capacity. My understanding is that Duke meets its planning reserve margin (PRM)

20 obligations to MISO through self-supply, i.e., with qualified resources that Duke controls

21 through ownership or contract. I have not studied whether it would be less costly for Duke

22 to build or contract for replacement capacity for the purposes of meeting its PRM 23 obligation after retiring coal generation. I note, though, that the recent Planning Reserve 24 Auction conducted by MISO cleared at only $5/MW-day in Indiana.5 This price is well 25 below the amortized cost of building new generation. MISO estimates that the Cost ofNew 26 Entry at $257.53/MW-day. Recent studies in neighboring PJM indicate that the amortized 27 cost of new, gas-fired capacity, net of expected market earnings from the sale of energy and 28 ancillary services, is in the range of$235 to $265/MW-day. Thus the cost for Duke to build

4 Vectren Public Stakeholder Meeting, June 15, 2020, Preferred Portfolio (p.14) https:i/v..ww.vectren.com/assets/dm,vnloads/planning/imNectren%20Stakeholder%20Meeting%204%20PDF.pdf 5 MlSO, "2020/2021 Planning Resource Auction (PRA) Results" April 14, 2020 (available at https:i/cdn.misoenergy.org/2020%202021 %20PRA%20Results385130.pd1) at p.5. Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 Sl Page 14 of25

1 new resources solely for the purpose of meeting its PRM obligations is about fifty-fold

2 higher than buying from the market at current prices.

3 29. Because of this substantial gap between the market cost of capacity in Indiana compared 4 to new construction costs, we included new gas-fired generation in very modest amounts. 5 In particular, in the Advanced Case II, in which all of Duke's coal is retired, we build a 6 replacement gas-fired combined cycle unit at Cayuga. This unit not only provides capacity 7 but allows Duke to continue to meet its contractual obligations to provide process steam 8 there. In the Advanced Case I, we added 373 MW of gas-fired peaker plant in place of the 9 CCGT, to avoid any potential modeling infeasibilities in the event that a probabilistically

10 generated random forced outage limit the ability of existing capacity to meet peak load.

11 However, this additional 'emergency capacity' was not required in any of the modeling

12 runs that we performed, and the combination of existing capacity, newly-added advanced 13 energy resources, and imports from nearby energy areas was sufficient to meet all load. 14 The replacement portfolios are shown in Table 7 of the Technical Appendix.

15 Q. You have now described five cases, two for the backcast period and three for 2025. 16 What were your next steps in the analysis?

17 30. We ran these five cases using the ENELYTIX/PRO software suite to simulate the hourly 18 operation of the MISO control area. Each run produces a very large dataset that includes, 19 inter alia, generation by unit, zonal load, and nodal and zonal LMPs. We used the data

20 query functions of the ENELYTIX platform to extract summary data from each run. From

21 these summaries, we are then able to analyze how operations and costs change between the 22 cases, comparing the backcast Market Case to the backcast Base Case, and separately 23 comparing the two 2025 Advanced Cases to the 2025 Base Case. I will discuss our findings 24 in the next section.

25 III ECONOMICANALYSIS

26 III.A. Backcast results show significant and avoidable economic losses due to 27 uneconomic scheduling of Duke's coal-fired generation

28 Q. What conclusions do you draw looking at the backcast Base Case?

29 31. Looking at the backcast Base Case on a standalone basis, I observe that Duke's coal-fired 30 generators modeled operating margins are, collectively, negative and large. During the Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 Sl Page 15 of25

1 three months of FAC 123, the model shows an operating loss of $20.57M. During FAC

2 124, this loss increases moderately, to $24.93M.

3 Q. How are you measuring operating margins?

4 32. I look at this question from the perspective of Duke's monthly settlement statement from 5 MISO. On the credit side of the ledger, net energy injections are credited at the 6 contemporaneous LMP. On the debit side of the ledger are the fuel and variable operating 7 and maintena,nce costs of the coal-fired generators. The difference between these is what I 8 refer to as the operating margin. As I noted earlier, I do not include any other station costs, 9 such as payroll and taxes. Nor do I include any costs of building or operating units that

10 would replace those units that are retired in the Advanced Cases.

11 Q. Looking at the operating losses in FAC 123, could Duke have mitigated these losses by

12 changing their unit commitment and dispatch strategy?

13 33. Yes. A substantial portion of these operating losses appear to result from excessive 14 commitment and dispatch of some of Duke's coal-fired generators. When the only limits 15 we placed on the commitment and dispatch of Duke's units were those reasonably required 16 by the units' physical operating limitations, as well as reasonably estimated costs of starting 17 and operating the units, we observe that the least-cost system dispatch results in materially 18 reduced operations at Duke's coal-fired units. Moreover, because these units are now 19 operating only in the highest priced periods, the operating margins improve. I summarize

20 these findings in Table 8.B in the Technical Appendix.

21 34. The bottom-line impact of optimizing the commitment and dispatch of Duke's fleet is

22 substantial. Comparing the Market Case to the Base Case for FAC 123, Duke would have 23 reduced self-generation by 360,735 MWh, replacing this energy generation with lower- 24 cost market purchases. The net savings would have been $16.19M. For FAC 124, swapping 25 1,000,649 MWh of load served by self-generation for lower-cost market purchases would 26 have resulted in net savings of $20.24M.6

6 Measured as the difference in DEI's total cost of serving its native load under each scenario Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 S1 Page 16 of25

1 Q. Do you know why the Duke units operated at higher levels historically than in your

2 Market Case?

3 35. Only indirectly. I make the reasonable assumption that Duke operates its generator fleet in 4 conformance with the operating instructions it receives from MISO; to do otherwise would 5 result in severe penalties. MISO's operations instructions are, however, strongly shaped or 6 even largely determined by information it receives from generation operators. Generation 7 owners may self-schedule their resource, overriding any economic assessment MISO 8 normally performs on unit commitment or dispatch. Generation owners with rate-based 9 authority, such as Duke, may also submit energy offers at prices of its choosing, rather than

10 at cost-based rates. Thus, the offered costs may be higher or lower than actual costs of

11 generation. MISO operators respond to these schedules and offers from generation owners.

12 They honor self-schedules unless doing so would violate a security constraint. They 13 dispatch resources based on the as-bid offers, rather than cost-based offers.7

14 36. I do not have access to the full record of communications between Duke and MISO. A 15 reasonable inference, however, is that Duke submitted some combination of self- 16 commitments, self-schedules, and below-cost energy offers from these coal-fired units to 17 mandate or distort MISO operators' commitment and dispatch decisions, resulting in total 18 generation that markedly exceeds the generation levels consistent with least-cost dispatch. 19 This uneconomic dispatch resulted in higher fuel costs and a higher cost to serve Duke's

20 load obligations, costs that Duke now seeks to recover under the Fuel Adjustment Clause.

21 Q. Turning your attention now just to the Market Case, do you have any observations

22 regarding the profitability of Duke's generation assets?

23 37. Yes. Even if Duke were to have allowed MISO to operate its coal-fired generators 24 optimally, these resources have small negative operating margins. During FAC 123 these 25 losses would have been $l.37M; in FAC 124, $3.40M.

26 Q. Are these negative operating margins, over the period of several months, ordinary in 27 your experience?

7 The market monitor may intervene in some circumstance if a generator's offer price exceeds its cost-based offer. Below-cost energy offers, however, are not subject to mitigation. Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 Sl Page 17 of25

1 38. No, in my experience such sustained losses from resources of this type are not the historic

2 norm. Traditionally, system planners have classified generators as baseload, cycling, or 3 peakers. Baseload units-historically large coal or nuclear plants-have relatively high 4 capital and fixed costs and low marginal operating costs. By contrast, peaking plants have 5 relatively low capital and fixed costs and high marginal operating costs. Cycling plants 6 strike a middle ground between these two categories.

7 39. There are sound reasons to expect that all generators will have negative total margins, 8 including return of and on capital, from energy market revenues alone; this is why the 9 RTOs in the Eastern Interconnection have some form of a capacity market, to top up this

10 expected revenue gap. But baseload and, to a lesser degree, cycling plants would typically

11 be showing positive operating margins; these positive margins justify the higher capital

12 costs of the resource. The fact that Duke's coal fleet would generate negative operating 13 margins even under optimal commitment and dispatch raises a red flag about their 14 continued viability.

15 Q. Are there any revenue streams from MISO other than energy and ancillary service 16 payments that these units might be paid?

17 40. Yes. Like other RTOs, MISO makes provision for what are collectively referred to as "make 18 whole payments." Broadly speaking, these payments top up the difference between bid cost 19 and market revenues for units that follow MISO dispatch instructions. Make whole

20 payments are an important element of the overall market design, as they ensure that

21 generators have no financial incentive to deviate from operator instructions.

22 Q. How would these make whole payments apply in the Base Case and the Market Case?

23 41. While I have not made any specific estimate of how the make whole payments would 24 change between these two cases, my informed judgement is that make whole payments 25 would have been higher in the Market Case than the Base Case. This conclusion may 26 appear counterintuitive, as the make whole payments are designed to bridge the gap 27 between operating costs and market revenues, and this gap is larger in the Base Case than 28 in the Market Case. These make whole payments come with two important caveats, 29 however: first, only resources that have been committed and dispatched by MISO are Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 SI Page 18 of25

1 eligible for make whole payments and, second, the level of the payment is determined by

2 the as-bid offer, rather than actual costs.

3 42. Given this constraint on make whole payments, I believe they would have had limited 4 applicability in the Base Case. As I discussed earlier, Duke appears to have used some 5 combination of self-commitment, self-scheduling and below-cost bidding to achieve the 6 non-optimally high levels of generation we observed during PAC 123 and PAC 124. But 7 any of these actions would have eliminated or reduced the ability of Duke to collect the 8 resulting operating losses through make whole payments. By contrast, all of the operation 9 of Duke's units in the Market Case are directed by MISO and are bid at actual marginal

10 costs. Thus, not only did Duke's self-scheduling practices during PAC 123 and PAC 124

11 result in uneconomically high operating losses, but they likely foreclosed the opportunity

12 of recovering as much as $1.40M in PAC 123 and $3.44M in PAC 124 through make whole 13 payments from MISO.

14 Q. Besides creating additional operating losses for Duke, do its scheduling practices have 15 an effect on the wholesale power markets?

16 43. Yes. As Table 8.C in the Technical Appendix shows, wholesale energy prices (that is, 17 LMPs) are suppressed by the uneconomic dispatch of Duke's coal units. This effect is quite 18 small in the 2019/2020 dispatch modeled in the Market Case compared to the Base Case 19 because the total amount of uneconomic energy is small in the broader context of the MISO

20 energy markets. In the Base Case, the weighted average LMP at generator nodes in the

21 Duke area during PAC 123 was $23.43/MWh; in the Market Case, this rose by $0.84 to

22 $24.27/MWh. 8 Similarly during PAC 124, the removing the uneconomic dispatch of 23 Duke's coal units raised the generator-node LMPs by $0.39, from $22.75/MWh to 24 $23 .14/MWh.

25 44. This price impact is a straightforward consequence of the uneconomic dispatch. MISO 26 calculates LMPs based on the cost to serve the next increment of load. In the Market Case, 27 LMPs are set using a supply curve for energy (sometimes called the "bid stack") that 28 reflects the true incremental cost of energy from Duke's units. By contrast, in the Base

8 The generation-weighted average is the average price across each hour, where each hour is weighted in proportion to the quantity of power generated. Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 S1 Page 19 of25

1 Case the bid stack is reordered in many hours, with Duke's coal-fired generation appearing

2 as zero-cost resources at the bottom of the stack. So, at any given level of load, MISO 3 operators will not need to go as high up the stack to meet load, and LMPs will be lower.

4 Q. But aren't lower energy prices good?

s 45. The goal of all regulated prices is to be at a just and reasonable levels-not higher than 6 they need to be, but not so low as to discourage economic investment. Wholesale market 7 pricing based on true costs is the design intent approved by FERC. Deviating from prices 8 built on true costs has consequences.

9 46. Lower prices do benefit load-serving entities that rely on market purchases to supply power

10 to their customers. In our model, Duke serves a significant portion of its customers'

11 requirements from the market. Consequently, any price suppression caused by Duke's

12 uneconomic dispatch would tend to lower the price it pays for purchased power. What 13 matters to customers, however, is the total cost to serve their requirements, summing 14 together the incremental cost of utility-owned generation and the cost of market purchases. 15 As shown in Table 8.C of the Technical Appendix, this total cost metric is higher in the 16 Base Case than in the Market Case by $36.43M. Simply put, the cost savings from fewer 17 and lower-priced market purchases in the Base Case do not fully offset Duke's higher 18 operating losses.

19 47. The harm of lower prices is subtler yet more pernicious. Price suppression wrought by

20 Duke's self-scheduling practices both encourages uneconomic energy consumption and

21 discourages what would otherwise be economic investments. The first of these is

22 straightforward economics: when a good is priced below its cost of production, 23 consumption of that good will be higher than it would be had the price reflected production 24 cost. This gap between price and cost creates dead-weight loss in the economy, in which 25 value is being destroyed by the act of over-consumption.

26 48. The disincentive to economic investment that results from low prices is particularly 27 troubling as Indiana and most other states seek to transition to more sustainable, healthier 28 sources of energy. Low energy prices discourage investments in energy efficiency 29 measures, even those that are proven to save consumers and businesses money over time. 30 · Low energy prices discourage investment by utilities, businesses, and individuals in Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 Sl Page 20 of25

1 cleaner, alternative energy resources by making the status quo appear less costly than it

2 really is. And low energy prices discourage investment in business innovation to rethink 3 industrial processes, the sort of innovation that offers opportunities for rebuilding a 4 competitive manufacturing economy in Indiana.

5 Q. Other than changing its offer strategy to MISO, are there other strategies that Duke 6 could have used to minimize its losses from its coal-fired generation?

7 49. Yes. There are two principal strategies that Duke could and should have pursued: selective 8 seasonal reserve shut downs and accelerate unit retirements.

9 Q. Starting with the first of these, seasonal reserve shut downs, what would this entail?

10 50. A seasonal reserve shut down of a generating unit entails, mechanically, a short-duration

11 shut down of a generating unit. This requires some investment to mothball the plant

12 appropriately at the beginning of the shut-down period, and further costs to transition back 13 to an operational state. There may be cost savings, however, by reducing annual operating 14 costs associated with staffing, service agreements, and other charges that would normally 15 be treated as "fixed operating expenses." Because this mothballing is, by design, short term, 16 the utility retains flexibility to bring the resource back into normal operation with relatively 17 short notice should need arise, such as a long-term outage of a baseload unit.

18 Q. Are there precedents for such seasonal shut downs?

19 51. Yes, such seasonal reserve shut downs are not uncommon. My first experience with them

20 was during my consulting work with Consolidated Edison Company of New York (ConEd),

21 which put its Arthur Kill Station on Staten Island into seasonal reserve shut down a few

22 years after creation of the New York Independent System Operator (NYISO) in 1998. With 23 competitively price energy now available to its customers, ConEd made the economic 24 decision that it was cheaper to buy power from the NYISO market than to self-generate at 25 Arthur Kill. The practice continues. Just recently, the Minnesota Public Utility Commission Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 S1 Page 21 of25

1 approved Xcel Energy's plan to put some of its coal-fired power plants in seasonal reserve

2 shut down to reduce charges to its customers.9

3 Q. Can you estimate what the economics of a seasonal shut-down would have been in 4 FAC 123?

5 52. Yes. To estimate this, we developed a variant of the Market Case. In this case, we model 6 four of Duke's coal-fired resources as unavailable for commitment: Cayuga 1 and the three 7 Edwardsport units. As in the Market Case, all other Duke coal-fired generators are available 8 for economic commitment and dispatch. The results of this run are shown in Table 8.D of 9 the Technical Appendix. The bottom line is that this selective, seasonal shut-down,

10 combined with economic operation of Duke's other resources, would have increased

11 customer savings during FAC 123 by $9.37M over the Market Case.

12 Q. Please discuss your second option, accelerated unit retirement.

13 53. In light of the high operating losses to its coal-fired generation in FAC 123 and FAC 124, 14 a reasonable standard to which Duke should be held is to evaluate how long these units 15 should continue to impose losses on its customers. Duke has proposed that the first coal 16 retirement would occur in 2026, but envisions a very long timeline for completely retiring 17 its Indiana coal-fired generation.

18 Q. Could some or all of these coal-fired generators be retired earlier without impairing 19 system reliability?

20 54. Certainly. I will preface my answer by noting that Duke is not the control area operator or

21 balancing authority; those tasks and the associated responsibilities for maintaining reliable

22 operations of the bulk power system rest with MISO. Simply put, it's not Duke's job to 23 plan for transmission-level reliability. 10

9 In the Matter ofNorthern States Power Co., 2020 WL 4016766 (Minn.P.U.C.); See also July 15, 2020, press release "Minnesota Public Utilities Commission Issues Order Approving Xcel Energy's Request to Operate Two Coal-Fired Plants Seasonally" (available at http://mn.gov/puc/newsroom/index.jsp?id=14-440509) summarizing the MPUC's order.

10 Duke does, of course, have responsibility for distribution-level reliability. I am unaware, however, that Duke has asserted that these transmission-connected coal-fired assets are needed to maintain the reliability of its distribution system operations. Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 SI Page 22 of25

1 55. From a strictly technical point of view, orderly coal-fire unit retirements elsewhere have

2 only required two or three years, at most. In PJM, for example, tens of thousands of 3 megawatts of coal-fired generation has been retired without longer lead times; the three- 4 year forward nature of PJM's capacity market was designed to offer ample time for 5 uneconomic coal-fired units to retire gracefully after failing to clear in the principal 6 auction. 11

7 56. Regarding reliability, coal-fired generators offer no benefits that cannot be replicated by 8 advanced energy resources. Even in small, literally islanded power grids like Hawaii, the 9 utility and its regulators are moving forward with a transition to 100 percent renewables,

10 so it is certainly feasible from a technical matter. On a larger scale, the UK grid has operated

11 without coal for over three months, with new large-scale renewables gaining ground.

12 Closer to home, both Vectren and NIPSCO have put forward concrete plans for sharply 13 reducing their coal operations and relying instead principally on advanced energy 14 resources.

15 57. This transition is assisted by two facts. First, the Duke service area is richly interconnected 16 to a large, robust wholesale market which itself is richly interconnected to a broad swath 17 of the U.S. power grid. This fact introduces geographic diversity both of load and of 18 renewable energy resources. A weather pattern that reduces wind or solar power in Indiana 19 may not impair renewable generation in Minnesota. The sun does not rise and set

20 throughout the broader market footprint at the same time. All this diversity of load and

21 resource adds up to a more reliable grid than if Indiana were islanded.

22 58. Second, advanced energy resources have improved their technical capabilities markedly 23 over time. Not only are modem wind turbines and solar panels able to extract more useful 24 energy from a broader range of meteorological conditions, but they incorporate more 25 features that allow for superior technical operations, such as low voltage ride through and 26 partial unit curtailment. Demand resources are increasingly responsive and cost-effective 27 means of managing peaks, and energy storage is playing an increasing role in balancing

11 I represented a major generator in the original settlement process that developed the Reliability Pricing Model; my client owned several large, high-cost coal-fired generators. Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 SI Page 23 of25

1 intermittent generation-the importance of which is underscored by the broad reforms to

2 the treatment of storage resources in FERC Order 841.

3 Q. If in 2019 Duke had responded to its high levels of operating losses at its coal-fired 4 units by contemplating their retirement, would the capital cost outlay have been a 5 reasonable barrier?

6 59. Advanced energy resources are increasingly cost-competitive. The fact that both Vectren 7 and NIPSCO are planning to use some combination of advanced energy resources to serve 8 customer requirements that are currently met by coal-fired generation is the clearest 9 evidence that such a transition is both feasible and economic in Indiana.

10 Q. Have you examined how the accelerated retirement of some or all of Duke's coal-fired

11 generators would affect market prices and consumer costs?

12 60. Yes. As I discussed in the previous section in paragraphs 24-29, we constructed three cases 13 examining the MISO market in 2025. The results of these cases are presented in Tables 14 IO.A, 10.B, and 10.C of the Technical Appendix. I make the following observations about 15 these findings:

16 61. First, Duke's coal-fired units---other than the Gibson units and Cayuga 2-continue to lose 17 money on an operating basis, albeit at lower levels. The small improvement in the financial 18 performance is largely the result of our baseline assumption of fairly modest overall 19 capacity expansion in the region, coupled with our assumption that coal prices remain flat.

20 As reserve margins tighten, prices tend to rise.

21 62. Second, when we compare Duke's cost to serve load between the 2025 Base Case and

22 either 2025 Advanced Case, there are substantial savings. The 2025 Advanced Case I 23 (which has a less ambitious coal retirement plan) results in $105.33M in customer savings 24 (expressed in nominal 2020 dollars). The 2025 Advanced Case II (which retires all of 25 Duke's coal-fired generators) results in $423.69M in customer savings. These savings 26 would offset, in whole or in part, the capital costs of building these advanced energy 27 resources.

28 63. Third, our analysis assumes no change to national climate policy, such as imposition of a 29 national carbon fee. I am not a political forecaster, but I observe that there is bipartisan Intervenor ABE Exhibit 2 IURC Cause No. 38707 FAC 123 Sl Page 24 of25

1 support for a carbon fee in Congress and growing support nationally for a more proactive

2 national policy in this area. Many major oil & gas companies openly support the idea of a 3 national carbon fee. Thus, prudent planning should consider a sensitivity case that includes 4 a carbon fee and the impact on all fossil-fueled plants, but particularly coal-fired 5 generators. Although I have not performed such a sensitivity analysis, directionally it is 6 clear that the Advanced Cases would be even more attractive.

7 64. Finally, I have made no attempt to optimize the portfolios in the Advanced Cases. They 8 reflect the resource balance proposed by Vectren, which is similarly but not identically 9 situated to Duke. Had Duke developed a serious analysis during FAC 123 to assess the

10 potential benefits of accelerated coal retirements, I expect that they would have performed

11 such an optimization analysis. By definition, an optimized portfolio will outperform either

12 of the candidate portfolios I study in the two Advanced Cases.

13 Q. Can you please summarize your testimony?

14 65. Yes. Using a state-of-the-art power system model, I contrast the operation of the Duke 15 units, within the broader context of the MISO markets. As my Base Case I replicate the 16 actual system operation in the periods surrounding and including FAC 123, including 17 constraints on the commitment and dispatch of Duke's coal fleet to align the modeled 18 behavior with actuals. In my Market Case, I remove these constraints, allowing the model 19 to optimize the overall MISO commitment and dispatch while honoring all operating and

20 reliability constraints. The contrast between these two cases is striking. Duke's coal units

21 operated at much higher levels in fact than they would have run solely on their economics.

22 This uneconomic dispatch accounts for 93 percent of the operating losses-principally fuel 23 costs. This pattern of systematic losses because of Duke's decisions to operate the coal- 24 fired generators uneconomically is not limited to FAC 123 but is a consistent pattern 25 throughout the period I examined, March 2019 to June 2020.

26 66. In conclusion, it is my opinion that Duke has not made every reasonable effort to acquire 27 fuel and generate or purchase power to provide electricity to its retail customers at the 28 lowest fuel cost reasonably possible in period FAC 123 (and FAC 124). Moreover, if 29 Duke's self-commitment decisions are not corrected, our modeling shows that this trend 30 will continue and that Duke's ratepayers will be charged hundreds of millions of dollars in Intervenor AEE Exhibit 2 IURC Cause No. 38707 FAC 123 S1 Page 25 of25

1 fuel costs that could have been avoided by greater reliance on economic commitment and

2 dispatch and an accelerated transition to advanced energy resources

3 Q. Does this conclude your testimony at this time?

4 67. Yes, it does. VERIFICATION

I hereby verify under the penalties of perjury that the foregoing representations are true to the best of my knowledge, information, and belief.

Dated: ~ ;,2JI2o I AEE Ex. 2 Attachment RBS-1 IURC Cause No. 38707 FAC 123 S1 Page 001 of 014 Curriculum Vitae ENERGY

ROBERT B. STODDARD BERKELEY RESEARCH GROUP, LLC 1800 M Street, 2nd Floor Washington, DC 20036

Direct: 202.480.2728 [email protected]

SUMMARY

Mr. Robert B. Stoddard, a Managing Director of BRG's Energy and Climate Change Practice, brings over 30 years of experience in economic consulting and the electric power industry. A seasoned energy market economist, Mr. Stoddard provides strategic and regulatory advice to many of the North America's largest utilities and independent power producers. His recent work focused on electricity industry restructuring and on strategic analyses and testimony for utilities, generation owners, and governments regarding the practical implications of market design and structure, particularly as environmental issues reshape the regulatory landscape.

Mr. Stoddard frequently testifies at the Federal Energy Regulatory Commission as well as to the utility commissions and legislatures of several states on competitive market design. market power issues, infrastructure siting, and energy trading. He has also testified in civil litigation and arbitration on the interpretation of, and damages relating to, energy contracts and energy asset valuation.

In September 2019, Governor Janet Mills of Maine appointed Mr. Stoddard to a three-year term on the Energy Working Group of the newly created Maine Climate Council. In this role, Mr. Stoddard will help define the strategies and tools to cut net carbon emissions in the state to net zero by 2045, while promoting economic growth and job development in the transition.

Prior to joining BRG, Mr. Stoddard was CEO of GWave LLC, a technology startup firm focused on developing a commercially sensible technology to harness the energy of ocean waves, through its later stages of technology development through to an exclusively licensing arrangement for its IP. His work focused on building the strategic partnerships and supply chains needed in global markets to ensure the long-term success of the company, as well as transitioning the firm from technology development through demonstration and commercialization.

Prior to joining GWave in May 2013, Mr. Stoddard led the energy practice of Charles River Associates, an international economic and finance consultancy. He holds degrees in economics from Yale University and Amherst College.

EDUCATION

MPhil, MA, Economics Yale University

BA summa cum laude, Economics and Music Amherst College AEE Ex. 2 Attachment RBS-1 IURC Cause No. 38707 FAC 123 S1 Page 002 of 014

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PREVIOUS POSITIONS

2017-2020 Principal, Power Market Economics LLC, Portland, Maine

2017-2020 Chief Executive Officer, GWave LLC, Boston, Massachusetts 2013-2017 Executive Vice President, GWave LLC

2013-2020 Senior Consultant, Charles River Associates, Boston, Massachusetts 2001-2013 Vice President & Practice Leader, Charles River Associates

2000-2001 Managing Consultant, PA Consulting, Cambridge, Massachusetts

1995-2000 Principal, Putnam, Hayes & Bartlett, Cambridge, Massachusetts

1993-1995 Managing Director, Health Economics, Quintiles, Cambridge Massachusetts

1990-1993 Senior Associate, Charles River Associates, Boston, Massachusetts

PROFESSIONAL EXPERIENCE

• Invited speaker and testifying expert in ongoing discussions in New York, New England and PJM on integrating public policy objectives-principally for renewable energy-into competitive wholesale markets. • Lead economist of the Dynamic Clean Energy Market design for ISO New England, working with a coalition of utilities, generators, and environmental groups to incorporate state carbon reduction goals within ISO's market structure. • Senior advisor to a major U.S. utility group exploring development of a regional Energy Imbalance Market to support increased renewable resource penetration in the region. • Expert economist for the PJM IPP trade group at the PJM Energy Price Formation Senior Task Force, charged with substantial design changes energy price formation through the use of enhanced operating reserve demand curves and other innovative approaches. • Project director and testifying expert for capacity market design litigation and settlement negotiations for the New England and PJM markets, representing coalitions of the major generation owners in the region. • Principal author of SDG&E and California Forward Capacity Market Advocates' proposal for a centralized capacity market structure to address resource adequacy needs of the California electricity markets. Subsequently offered a market-based approach to backstop capacity pricing in California on behalf of NRG Energy and the Independent Energy Producers Association. • In the redesign of the wholesale power market for the Republic of Ireland, responsible for development of rules regarding demand-side integration, interconnection management, financial transmission rights, and transmission loss representation.

2 AEE Ex. 2 Attachment RBS-1 IURC Cause No. 38707 FAG 123 S1 Page 003 of 014

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• Testifying expert on behalf of a major importer into the California electricity market on the allocation of financial transmission rights across external interties. • Project director for a review for the California Independent System Operator of transmission rights allocations in the proposed California wholesale market. • Principle drafter of the current form of the utility restructuring laws in Rhode Island, implementing improved retail market access. • Project director for a major policy initiative by a major generation owner to review key flaws in modern RTO design that distort competitive pricing and outcomes. • Project manager and testifying expert for litigation regarding the market rules governing use of phase angle regulators between New York and PJM. Subsequently, assisting the negotiated design of these rules pursuant to the FERC orders. • Prepared a white paper on capacity market design for Energia dos Portugal.

• Testifying expert successfully defending against charges of market manipulation by largest capacity importer to New England. • Led preparation of report successfully defending against charges of market manipulation by a power marketer scheduling transactions through multiple jurisdictions. • Lead expert defending a major financial institution against charges of manipulating ICE index markets (ongoing). • Lead economist in team developing alternative mitigation measures for buyer-side market power in the New England capacity market. • Testified on appropriate metrics for market power in PJM energy and capacity markets. • Testified as to vertical and horizontal market power issues related to affiliation of merchant generation and the host distribution utility. • Testifying expert and project director supporting the integration of Virginia Electric and Power (Dominion) into the PJM marketplace. • Project manager for an acquisition of generation assets in Connecticut by a competing supplier, using detailed hourly analyses of power flows and potential future competition, and presenting the results to the FERC, US Department of Justice, and the Connecticut Office of the Attorney General. • Project manager for a market power analyses needed to obtain federal and state regulatory approval of the merger of the leading natural gas transporter and distributor in the eastern US with a vertically integrated utility with substantial gas holdings. • Project manager for study of the potential competitive effects of the divestiture of substantially all the New York City utility generation to independent power producers, including detailed behavioral modeling that took account of the complex transmission system and design of market power mitigation measures for the energy and capacity markets.

3 AEE Ex. 2 Attachment RBS-1 IURC Cause No. 38707 FAG 123 S1 Page 004 of014

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Strategy • Led creation of business model and market-entry strategy for company developing an innovative renewable power technology. • Led creation of business model and business plan for a combined wind-farm I transmission company in Canada. • Assisted major utility in strategic and tactical plan to support transfer between Regional Transmission Organizations, providing both analytic and regulatory advisory support. • Directed the development of the master energy infrastructure strategy for the City of New York, working with key stakeholders to develop a strategy to develop the infrastructure needed to meet the city's future energy needs economically and reliably. • Developing a detailed forecasting model for capacity prices in PJM resulting from the new capacity market design and, using this information, worked with a major market participant's strategy and financing staff to identify under-valued assets for acquisition. • With senior management of a major utility, developing a transmission investment strategy to reflect shifting competitive opportunities, RTO market design, and state and federal regulation. Identifying of key opportunities to leverage and redirect capital expenditures to significantly decrease cost of delivered power and increase rate of return to corporate shareholders. • Developing a competitive bidding strategy for a complex hydroelectric generation asset to recognize opportunity costs, limitations of market rules, and effects of key transmission constraints in a two-settlement, locational pricing regime. • Assisting a leading provider of utility outsourcing services to develop a comprehensive regulatory strategy for its service offerings to a major utility.

Electricity contracts and project valuation • Testimony critiquing long-term power purchase agreements between Massachusetts electric distribution companies and Hydro Quebec U.S. • Reports to support long-term contracts with critical new generation facilities in Massachusetts. • Testimony to support the tax valuation of independent power production facilities in New York and Maryland, evaluating the free cash flows from sales of energy and other products' net of fuel, emissions, and other relevant costs. • Testimony successfully supporting claims against industrial customer in breach-of­ contract claims by a retail energy provider. • Testimony supporting the cost-effectiveness of a long-term power purchase agreement between Cape Wind and National Grid in furtherance of Massachusetts policy goals. • Testimony regarding the market value of a nuclear power facility excluding idiosyncratic nuclear risks using a comparable transactions analysis. • Expert testimony supporting the reliability must-run (RMR) applications of over 2 GW of generation in New England, documenting need for RMR contracts to maintain the financial viability of needed resources. The case resulted in a settlement agreement that provided 4 AEE Ex. 2 Attachment RBS-1 IURC Cause No. 38707 FAG 123 S1 Page 005 of 014

.. ENERGY

for significant support payments for these resources during the transition to compensatory market payments. • Testimony for a bankruptcy court regarding damages arising from a power purchase agreement that had been rejected at the time of bankruptcy. • Testimony in arbitration proceedings to determine the product specification and price of the capacity product contracted for in a period of regulatory change. • Support of project financials for major purchase of New York City generation to investor community. • Testimony in arbitration proceedings about the interpretation of, and damages owed under, the electricity section of a contract for the purchase of a large petrochemical refinery and resale of the refinery's output. • State-appointed auditor of Connecticut's utilities' first Standard Offer power procurement auction, reviewing reasonableness of pricing and the terms and conditions of contract offers to supply essentially all of the state's power needs for a three-year period. • Testimony on fuel costs adders reasonably allowable in a long-term power contract between NRG and Connecticut Light & Power and attendant retail rate design to fairly allocate the incremental costs. • Assisting Consolidated Edison Co. of New York negotiate the sale of its nuclear facilities and linked buyback of power for the license life of the units. • Working with Pinnacle West staff to develop options-based contracts to transfer power between its generating, trading, and distribution affiliates to preserve appropriate performance incentives.

SELECTED ARTICLES, PAPERS AND PRESENTATIONS • "Evolving Capacity Markets in a Modern Grid," invited paper for the Massachusetts Attorney General's Office Energy Market Symposium 2019: Wholesale Market Design in a Low/No-Carbon Electricity System, October 2019. • "Principles for Energy Price Formation," invited presentation to the Organization of PJM States, April 2018. • "Achieving State Policy Goals in Markets, invited presentation to the New England Council of Public Utility Commissioners, June 2017. • With Richard D. Tabors and Scott Englander, "Who's on First? The Coordination of Gas and Power Scheduling," Electricity Journal, Vol. 25, No. 5, June 2012, pp. 9-15. • With Richard D. Tabors, "The Confluence of Utility Regulation: Water, Electricity and Natural Gas," paper delivered at the 2012 Eastern Conference of the Center for Research in Regulated Industries at Rutgers University. • With Edward L. Kim, Richard D. Tabors and Todd E. Allmendinger, "Carbitrage: Utility Integration of Electric Vehicles and the Smart Grid," Electricity Journal, Vol. 25 No. 2, March 2012, pp.16-23.

5 AEE Ex. 2 Attachment RBS-1 IURC Cause No. 38707 FAG 123 S1 Page 006 of014 ENERGY

• With Richard D. Tabors, "Flaws in Reliability Options as a Mechanism for Resource Adequacy: Evidence from New England," paper delivered at the 2011 Eastern Conference of the Center for Research in Regulated Industries at Rutgers University. • With Harry Foster, "Optimal Pricing of Energy-Limited Resources in Capacity Markets," paper delivered at the 2009 Eastern Conference of the Center for Research in Regulated Industries at Rutgers University. • With Seabron Adamson, "Comparing Capacity Market and Payment Designs for Ensuring Supply Adequacy," Proceedings of the 42nd Hawaii International Conference on System Sciences, 2009.

PUBLIC TESTIMONY AND REPORTS • Proceeding on Motion of the Commission to Consider Resource Adequacy Matters, New York Public Service Commission Case 19-E-0530. Affidavit on behalf of NRG Energy on the importance of continuing transparent markets for energy, reserves and capacity and recommendations for strengthening New York's market design to achieve state environmental policies. November 2019. E t- • PJM Interconnection, L.L. C., FERC Docket Nos. EL 19-58-000 & EL 19-1468-000 (not consolidated). Affidavit on behalf of Calpine Corporation and LS Power Associates, LP. addressing the effect of proposed changes to reserves pricing on the capacity market. June 2019. • Petitions of Massachusetts electric distribution companies for approval of long-term contracts for renewable energy, pursuant to Section 83D of An Act Relative to Green Communities, St. 2008, c. 169, as amended by St. 2016, c. 188, § 12. Massachusetts Department of Public Utilities Docket Nos. D.P.U. 18-64 -65 and -66. Rebuttal and Surrebuttal testimony on behalf of NextEra Energy critiquing provisions of proposed contracts and the competitiveness of the award process. September 2018-February 2019. • Calpine Corporation, et al. v. PJM Interconnection, L.L.C., FERC Docket No. EL 16-49- 000. Affidavit and reply affidavit on behalf of NRG Power Marketing assessing the Commission's proposed Fixed Resource Requirement Alternative and other structures and proposing an alternative approach to integrating state policy resources in PJM's markets. October 2018. • CENTRAL MAINE POWER COMPANY Request for Approval of CPCN for the New England Clean Energy Connect Consisting of a 1,200 MW HVOC Transmission Line from Quebec-Maine Border to Lewiston (NECEC) and Related Network Upgrades, State of Maine Public Utilities Commission Docket No. 2017-00232. Surrebuttal testimony on behalf of NextEra Energy Resources critiquing claimed capacity market benefits of the proposed transmission project. August-December 2018. • CXA La Paloma, LLC v. California Independent System Operator Corporation, FERC Docket No. EL 18-177-000. Affidavit on behalf of the NRG Companies on the need for FERC action in restructuring the CAISO resource adequacy procurement process. August 2018. • PJM Interconnection, LLC, Docket No. ER18-1314-000. Affidavits on behalf of the NRG Companies assessing PJM's proposals for reforms to its capacity market to accommodate subsidized resources. May 2018. 6 AEE Ex. 2 Attachment RBS-1 IURC Cause No. 38707 FAC 123 S1 Page 007 of014

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• Grid Resilience in Regional Transmission Organizations and Independent System Operators, FERC Docket No. RM18-7-000. Design basis document for a Secure Energy Market to achieve resilience goals using markets, filed in comments of NRG Energy. May 2018. • Grid Reliability and Resilience Pricing, FERC Docket No. RM18-1-000. Affidavit on behalf of PJM Power Providers calling for meaningful reforms in PJM's energy markets to ensure proper price formation to guard against premature retirements and other inefficiencies, November 2017. • PJM Interconnection, L.L.C., FERC Docket No. ER13-535-000. Affidavit in support of NRG Energy protesting proposed changes to the Minimum Offer Price Rule in PJM's Reliability Pricing Model, December 2012, reply affidavit March 2013, affidavit on remand November 2017. • State Policies and Wholesale Markets Operated by ISO New England Inc., New York Independent System Operator, Inc., And PJM Interconnection, L.L.C., FERC Docket No. AD17-11-000. Prefiled comments "RTO Markets Must Change to Accommodate State Policies", April 2017, and invited remarks at FERC Technical Conference, May 2017. • California Independent System Operator Corporation, FERC Docket No. ER13-550-000. Affidavit in support of the NRG Companies and the Dynegy Companies, protesting the creation of a Flexible Capacity and Local Reliability Resource Retention Mechanism in lieu of a comprehensive market structure for resource adequacy, January 2013. • GenOn Bowline, LLC v. Town of Haverstraw, et al., Index No. SU-2009-6850 Hudson Valley Gas Corporation. v. Town of Haverstraw, et al., Supreme Court of the State of New York, County of Rockland, Index No. SU-2009-6860. Report projected energy and capacity revenues, March 2013; testimony January 2014. • "Analysis of the Impact of Salem Harbor Repowering on New England Air Emissions," CRA report authored by Mr. Stoddard on behalf of Footprint Power Salem Harbor Development LP, Massachusetts Electric Facilities Siting Board Docket 12-2, November 2012. • Capacity Deliverability Across the Midwest Independent Transmission System Operator, lnc.lPJM Interconnection, L.L.C. Seam, FERC Docket No. AD12-16-000. Affidavit supporting comments of Duke Energy Corporation, August 2012. • In the matter of, on the Commission's own motion, to initiate a proceeding to establish a state compensation mechanism for alternative electric supplier capacity in Indiana Michigan Power Company's Michigan service territory, MPSC Case No. U-17032. Testimony on behalf of FirstEnergy Solutions Corp. supporting use of RPM capacity pricing retail rates, July 2012. • In the Matter of the Application of Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company For Authority to Provide for a Standard Service Offer Pursuant to R. C. § 4928. 143 in the Form of an Electric Security Plan, PUCO Case No. 12-1230-EL-SSO. Rebuttal testimony on behalf of Applicants supporting reasonableness of multi-year contracts to hedge price risk, June 2012. • In the Matter of the Application of Columbus Southern Power Company and Ohio Power Company for Authority to Establish a Standard Service Offer Pursuant to §4928.143, Ohio

7 AEE Ex. 2 Attachment RBS-1 IURC Cause No. 38707 FAC 123 S1 Page 008 of 014

ENERGY

Rev. Code, in the Form of an Electric Security Plan, PUCO Case No. 11-346-EL-SSO et al. Testimony on behalf of FirstEnergy Solutions Corp. supporting use of RPM capacity pricing in retail rates. May 2012. • In the Matter of the Commission Review of the Capacity Charges of Ohio Power Company and Columbus Southern Power Company. PUCO Case No. 10-2929-EL-UNC. Testimony and deposition on behalf of FirstEnergy Solutions Corp. supporting use of market pricing for capacity, April 2012. • "Update to the Analysis of the Impact of Cape Wind on Lowering New England Energy Prices," CRA report authored by Mr. Stoddard, on behalf of Cape Wind Associates, LLC, filed in Petition of NSTAR Electric Company for Approval of a Proposed Long-Term Contract for Renewable Energy with Cape Wind Associates, LLC Pursuant to St. 2008, c. 169, § 83, March 2012. • FirstEnergy Solutions Corp. & Allegheny Energy Supply Company, L.L.C. v PJM Interconnection, L.L.C., FERC Docket EL 12-50-000. Affidavit in support of complaint seeking to require allocation of partial-year Auction Revenue Rights, March 2012. • California Independent System Operator, Inc., FERC Docket No. ER12-897-000. Affidavit in support of protest by NRG Energy, Inc. of proposed waiver of provisions of the Capacity Procurement Mechanism, February 2012. • FirstEnergy Solutions Corp. & Allegheny Energy Supply Company, L.L. C. v PJM Interconnection, L.L.C., FERC Docket EL 12-19-000. Affidavit in support of complaint seeking to fund Financial Transmission Rights solely from Day-Ahead Market settlement surplus, December 2011. • "Resource Adequacy in Ohio's Restructured Market," CRA report authored by Robert B. Stoddard, on behalf of Duke Energy Ohio, December 2011. • Bangor Hydro Electric Company and Maine Public Service Company Request for Exemptions and Reorganization Approvals, Maine Public Utilities C9mmission Docket No. 2011-170. Rebuttal testimony on behalf of Emera regarding potential horizontal and vertical market power issues of proposed acquisitions, September 2011; live testimony, December 2011, March 2012. • PJM Interconnection, L.L.C., Duke Energy Ohio, Inc. and Duke Energy Kentucky, Inc., FERC Docket No. ER12-91-000. Affidavit on behalf of Duke providing cost-benefit analysis of its proposed transition from MISO to PJM in support of inclusion of transition costs in transmission rates, October 2011; rebuttal affidavit, November 2011. f • In the Matter of Portland General Electric Company 2012 Annual Power Cost Update Tariff (Schedule 125), Oregon Public Utilities Commission Docket No. UE-228. Rebuttal testimony on behalf of Portland General Electric assessing reasonableness of its mid-term hedging strategy for gas and electricity procurement, August 2011. • California Independent System Operator Corporation, FERC Docket No. ER 11-2256. Affidavit on behalf of the Independent Energy Producers Association protesting flawed elements of the Capacity Procurement Mechanism, December 201 O; presentation to FERC Technical Conference, March 2011.

8 AEE Ex. 2 Attachment RBS-1 IURC Cause No. 38707 FAG 123 S1 Page 009 of 014

• Expert Report on behalf of Mirant Mid-Atlantic, LLC, Maryland Tax Court Case Nos. 09- RP-CH-261-265; 09-RP-CH-280-294; and 09-RP-CH-294-298, July 2010; live testimony, February 2011. • PJM Interconnection, LLC, FERC Docket No. ER11-2288. Affidavit on behalf of GenOn Energy Management, LLC and Edison Mission Energy protesting the creation of a summer-only demand resource capacity product and the continuation of a limited demand resource capacity product in the PJM Reliability Pricing Model, December 2010. • Testimony on behalf of the PJM Power Providers before the Maryland Public Service Commission in Administrative Docket PC22 regarding the PJM Reliability Pricing Model and the 2013/2014 Delivery Year Base Residual Auction Results, October 2010. • ISO New England Inc. and New England Power Pool, FERC Docket No. ER 10-787-000, and New England Power Generators Association v. ISO New-England, Inc., FERC Docket No. EL 10-50-000 (combined). Affidavit on behalf of New England Power Generators Association supporting need for revisions to Forward Capacity Market design, March 2010. Rebuttal affidavit, April 2010. Pre-filed testimony, July 2010; supplemental affidavits, September 2010. • Maryland Tax Court Case Nos. 09-RP-CH-261-265; 09-RP-CH-280-284; and 09-RP-CH- 294-298. Expert report projecting energy and capacity revenues for Mirant Mid-Atlantic Morgantown facility, July 201 0; live testimony February 2011. • Petition of Massachusetts Electric Company and Nantucket Electric Company each dlbla National Grid for Approval of Proposed Long-Term Contracts for Renewable Energy with Cape Wind Associates, LLC Pursuant to St. 2008, c. 169, § 83, Massachusetts D.P.U. Docket No. 10-54. Direct testimony on behalf of Cape Wind Associates, LLC, June 2010. • Richard Blumenthal, Attorney General for The State of Connecticut v. ISO New England Inc., Brookfield Energy Marketing Inc., et al. FERC Docket No. EL09-47-000, and The Connecticut Department of Public Utility Control and the Connecticut Office of Consumer Counsel v. ISO New England Inc., Brookfield Energy Marketing Inc., et al., f:ERC Docket No. EL09-48-000. Prefiled testimony on behalf of Brookfield Energy Marketing Inc. regarding scheduling of capacity imports. June 2009. Answering testimony, February 2010. • Pepco Energy Services, Inc. v. Constellation Energy Commodities Group, Inc. (ad hoc arbitration); expert report on behalf of Constellation on alleged mis-payment under a bilateral contract for PJM capacity, April 2008; testimony, October 2009. • Application of MidAmerican Energy Company for the Determination of Ratemaking Principles, IUB Docket No. RPU-2009-0003. Rebuttal testimony on behalf of NextEra Energy Resources, June 2009; surrebuttal testimony, July 2009, live testimony, August 2009. • Midwest Independent Transmission System Operator Inc., FERC Docket Nos. ER0B-394- 007 and -009. Affidavit regarding monitoring and mitigation of resource adequacy auctions on behalf of Duke Energy Corp., July 2009. • Calpine Corporation, Citigroup Energy Inc., Dynegy Power Marketing, Inc., J.P. Morgan Ventures Energy Corporation, BE CA, LLC, Mirant Energy Trading, LLC, NRG Energy,

9 AEE Ex. 2 Attachment RBS-1 IURC Cause No. 38707 FAG 123 S1 Page010of014

ENERGY

Inc., Powerex Corporation, and RR/ Energy, Inc. v. California Independent System Operator Corp., FERG Docket No. EL09-62-000. Affidavit on behalf of complainants, June 2009; reply affidavit, July 2009. • Report on /SO New England Internal Market Monitoring Unit Review of the Forward Capacity Market Auction Results and Design Elements, prepared for New England Power Generators Association, Inc. and filed in /SO New England, Inc., FERG Docket No. ER09- 1282-000 (June 2009). • Richard Blumenthal, Attorney General for Connecticut, v. ISO New England Inc. et al., FERG Docket Nos. EL09-47-000 and EL09-48-000. Prefiled testimony on behalf of Brookfield Energy Marketing Inc. regarding scheduling of capacity imports, June 2009. • Master Transmission Plan for New York City, report prepared for the New York City Economic Development Corporation, April 2009. • California Independent System Operator Corporation, FERG Docket No. ER09-589-000. Affidavit on behalf of Powerex Corp. regarding changes to the CAISO credit policy regarding unsecured credit, February 2009. • "Contracting and Investment: A Cross-Industry Assessment" report filed with Post­ Conference Comments of Reliant Energy, Inc., Credit and Capital Issues Affecting the Electric Power Industry, FERG Docket No. AD09-002-000, January 2009. • PJM Interconnection, LLC FERG Docket No. ER09-412-000. Affidavit and reply affidavit on behalf of Mirant, Edison Mission Energy, International Power, and FPL (NextEra Energy Resources) regarding omnibus changes to the PJM RPM capacity market tariff, January 2009. • Midwest Independent System Transmission Operator, Inc. FERG Docket Nos. ER08-394- 000, -003, -007. Affidavit on behalf of Duke Energy protesting the market monitoring standards proposed for the voluntary capacity auction in Midwest ISO, January 2009. • Devon Canada Corp. et al. v. Pittsfield Generating Company LP et al. Expert report for defendant re_garding damages from alleged breach of natural gas supply contract to a reliability must-run electric generator, December 2008. • Maryland Public Service Commission v. PJM Interconnection, LLC, FERG Docket Nos. EL08-34-000 and EL08-47-000. Affidavit on behalf on Mirant Parties on appropriate structural and behavioral market power tests in PJM, October 2008; reply affidavit, November 2008. • /SO New England, Inc., FERG Docket No. ER08-1209-000. Affidavit on behalf of the New England Power Generation Association on compensation to reliability resources, July 2008; reply affidavit, September 2008. • Midwest Independent Transmission System Operator, Inc. FERG Docket No. ER08-1169- 000. Affidavit on behalf of FPL Energy, LLC, regarding revisions to Generation Interconnection Procedures, July 2008. • RPM Buyers v. PJM Interconnection, LLC, FERG Docket No. EL08-67-000. Affidavit on behalf of PJM Power Providers opposing ex post changes to initial RPM auction results, June 2008.

10 AEE Ex. 2 Attachment RBS-1 IURC Cause No. 38707 FAG 123 S1 Page 011 of014 ...

• Assessment of Maine's Continued Participation in ISO New England and Alternatives, Expert report in Maine Public Utilities Commission Docket No. 2008-156, prepared on behalf of Bangor Hydro-Electric Company, June 2008; testimony to the MPUC, October 2008. • "Reliability at Stake: PJM's Reliability Pricing Model" report prepared for PJM Power Providers in conjunction with FERG technical conference to discuss the operation of forward capacity markets in New England and the PJM region, FERG Docket No. AD08-4- 000, May 2008. • Estimation of Indian Point 2 Fair Market Value Using a Statistical Analysis of Comparable Transactions, Testimony in Consolidated. Edison Co. of New York v. United States, No. 04-0033C (Fed.Cl.), February 2008. • Critique of the APPAICMU Study "Do RTOs Promote Renewables?" (with David Riker) commissioned by Electric Power Supply Association, January 2008. • Midwest Independent Transmission System Operator, Inc. Electric Tariff Failing Regarding Resource Adequacy, FERG Docket No. ER08-394-000. Affidavit on behalf of Duke Energy Corp. and FirstEnergy Services Co. on the urgency of implementing a uniform resource adequacy requirement, January 2008. • Mirant Energy Trading, LLC, et al. v PJM Interconnection, LLC, FERG Docket No. EL08-8- 000. Affidavit on the flaws in the market power mitigation rules for the Third Incremental Auction of the PJM Reliability Pricing Model capacity market., November 2007. • In the matter of the application of Midland Cogeneration Venture Limited Partnership for the Commission to eliminate the "availability caps" which limit Consumers Energy Company's recovery of capacity payments with respect to its power purchase agreement with Midland Cogeneration Venture Limited Partnership, Michigan P.S.C. Case No. U- 15320, testimony analyzing the relative economics of petitioner's facility to support the waiver. September 2007. • Wholesale Competition in Regions with Organized Electric Markets, FERG Docket Nos. RM07-19-000 and AD07-7-000. Affidavit on role of demand-side resources in organized electric markets on behalf of Duke Energy Corp., September 2007. • Order Instituting Rulemaking to Consider Refinements to and Further Development of the Commission's Resource Adequacy Requirements Program, California PUC Rulemaking 05-12-013. Principal author of SDG&E Track 2 Resource Adequacy Program Proposal, March 2007; principal author, "Joint Pre-Workshop Comments of the California Forward Capacity Market Advocates," May 2007, and "Proposal for a Forward California Capacity Market," August 2007. • People of the State of Illinois, ex rel. Illinois Attorney General Lisa Madigan v. Exelon Generating Co., LLC et al., FERG Docket No. EL07-47-000. Affidavit assessing reasonableness of outcomes in the Illinois power procurement auction on behalf of J. Aron & Company and Morgan Stanley Capital Group, July 2007. • PJM Interconnection, LLC, FERG Docket Nos. EL03-236-000 et al. Affidavit regarding three-pivotal-supplier market power test and scarcity pricing in PJM's energy markets on behalf of Mirant Energy Trading et al., May 2007.

11 AEE Ex. 2 Attachment RBS-1 IURC Cause No. 38707 FAG 123 S1 Page 012 of 014

ENERGY

• Midwest Independent Transmission System Operator, FERC Docket No. ER0?-550-000. Affidavit regarding resource adequacy issues in ancillary services market design on behalf of Duke Energy Co., March 2007. • PJM Interconnection LLC, FERC Docket No. EL05-148-000 et al. Affidavit regarding redesign of the long-run resource adequacy market in PJM on behalf of the Mirant Parties, October 2005; supplemental affidavit on behalf of the Mirant Parties, NRG and Williams Power Co., November 2005; presentation to FERC Technical Conference, February 2006; prefiled comments to FERC Technical Conference Panel 1, May 2006, on behalf of the Mirant Parties, Williams Power Co., and Dayton Power & Light; prefiled comments to FERC Technical Conference Panel 2, May 2006, on behalf of the Mirant Parties; supplemental affidavit on behalf of the Mirant Parties, June 2006; affidavit and reply affidavit supporting settlement agreement, September and October 2006. • Mystic Development, LLC, FERC Docket No. ER06-427-000. Affidavit analyzing future revenues in support of RMR filing, December 2005; supplemental affidavit, September 2006. ~ • In re USGen New England, Inc. Debtor. United States Bankruptcy Court for the District of Maryland, Case No. 03-30465. Expert report on damage resulting from PPA rejection on behalf of USGen New England, March 2006; supplemental report, September 2006. • California Independent System Operator Corporation, FERC Docket No. ER06-615-000. Joint affidavit with Paul Kevin Wellenius regarding FTR allocations under new CAISO market design on behalf of Powerex Corp, June 2006 • Fore River Development, LLC, FERC Docket No. ER06-822-000. Affidavit analyzing future revenues in support of RMR filing, December 2005. • Assessment of the New York City Electricity Market and Astoria, Gowanus, and Narrows Generating Stations. Report prepared for Morgan Stanley Senior Funding, Inc. related to financing for US Power Generating Co. and Madison Dearborn Capital Partners IV, LP., January 2006. • Review of Initial Execution of Protocol for Implementation of Commission Order No. 476. Report to FERC in Docket EL02-23-000, regarding operation of controllable lines between NYISO and PJM, on behalf of Con Edison, September and December 2005. • Honeywell International Inc. v. Sunoco, Inc. AAA Case No. 13 181Y0258804. Expert report, deposition and live testimony on contract energy pricing in petrochemicals, May 2005. • Con Edison Energy, Inc. v. ISO New England, Inc. and New England Power Pool, FERC Docket No. EL05-61-000. Affidavit on behalf of complainant regarding bidding rules in capacity deficiency auction, February 2005. • KeySpan Ravenswood LLC v. New York Independent System Operator, Inc., FERC Docket No. EL05-17-000. Affidavit on behalf of Consolidated Edison Company of New York, Inc. regarding retroactive damage claims from a capacity market, November 2004. • Devon Power LLC et al., FERC Docket No. ER03-563-030. Affidavit and rebuttal affidavit regarding design of locational installed capacity markets on behalf of FPL Energy, April and May 2004; answering testimony on behalf of Capacity Suppliers, November 2004; 12 AEE Ex. 2 Attachment RBS-1 IURC Cause No. 38707 FAG 123 S1 Page 013 of 014

ENERGY

cross-answering testimony, December 2004; supplemental cross-answering testimony, January 2005; deposition and hearing testimony, February to March 2005; affidavit supporting Settlement Agreement, March 2006. • Application of Dominion North Carolina Power to Join PJM as PJM South, North Carolina Utilities Commission, Case No. E-22 SUB 418. Direct testimony and cost-benefit study on behalf of applicant, April 2004; rebuttal testimony, December 2004; examination, January 2005. • Application of Virginia Electric and Power Company to Join PJM as PJM South, State Corporation Commission of Virginia Case No. PUE-2000-00551; direct testimony and cost-benefit study on behalf of applicant, June 2003; supplemental direct testimony, March 2004; rebuttal testimony, September 2004; examination, October 2004. • Consolidated Edison v. Public Service Electric and Gas Co. et al., FERG Docket No. EL02-23-000 (Phase II); direct testimony on behalf of Consolidated Edison Company of New York, Inc., June 2002 regarding transmission facilities contracts. Remand testimony, January to March 2003. • In the Matter of the Siting of Electric Transmission Facilities Proposed to be Located at the West 49th Street Substation of Consolidated Edison Company of New York, Inc. et al., New York State Public Service Commission Case Nos. 02-M-0132, 01-T-1474, 02-T-0036, 02-T- 0061; testimony on behalf of Consolidated Edison Company of New York, Inc., April 2002 (direct) and May 2002 (rebuttal). • Testimony before the Rhode Island Special Legislative Commission on the Quonset­ Davisville Steamplant, January and April 2002. • Testimony before the Committee on Corporations, Rhode Island House of Representatives, regarding 2002 House Bill 7786, An Act Relating to Public Utilities and Carriers, April 2002. • Keyspan-Ravenswood, Inc. v. New York Independent System Operator, FERG Docket No. EL02-59-000, direct testimony on behalf of Consolidated Edison Company of New York, Inc. regarding implementation of market power mitigation in installed capacity markets, March 2002. • DPUC Investigation Into Viability of Power Supply Contracts to the Connecticut Light and Power Company and the United Illuminating Company, Connecticut DPUC Docket No. 01-12-05, direct testimony on behalf of NRG Energy, Inc. and affiliates, February 2002. • Joint Study by the Department of Public Utility Control and the Office of the Consumer Counsel Regarding Electric Deregulation and How Best to Provide Electric Default Service After January 1, 2004, Connecticut DPUC Docket No. 01-12-06, direct testimony on behalf of NRG Energy, Inc. and affiliates, January 2002. • The Narragansett Electric Co. Rate Changes for January 1, 2002, Rhode Island PUC Docket No. 3402, direct testimony on behalf of the Hon. John B. Harwood, Speaker of the House of Representatives, State of Rhode Island and Providence Plantations, December 2001. • Wisvest-Connecticut, LLC et al., FERG Docket No. EC01-70-000, technical conference presentation on behalf of NRG Energy, Inc. and affiliates, September 2001.

13 AEE Ex. 2 Attachment RBS-1 IURC Cause No. 38707 FAG 123 S1 Page 014 of 014

•:: -BRG --ENERGY

• New York Independent System Operator, Inc., FERG Docket No. ER01-2536-000, affidavit on behalf of Consolidated Edison Co. of New York, the City of New York, the New York Energy Buyers Forum, and the Association for Energy Affordability, Inc., July 2001. • Testimony before the Committee on Corporations, Rhode Island House of Representatives regarding electricity restructuring; various dates, 2001. • Consolidated Edison Co. of New York, Inc., FERG Docket Nos. EL01-45-000 and ER01- 1385-000, affidavit and rebuttal affidavit Uoint with William H. Hieronymus) on behalf of Consolidated Edison Co. of New York, March and April, 2001. • Joint Petition of Consolidated Edison Co. of New York, Inc. and Entergy Nuclear Indian Point 2, LLC, for Authority to Transfer Certain Generating and Related Assets and for Related Relief, NYSPSC Case 01-E-0040, technical conference presentation on behalf of applicants, February 2001.

PROFESSIONAL MEMBERSHIPS

Energy Bar Association, Associate Member

Phi Beta Kappa

14 AEE Ex. 2 Attachment RBS-2 IURC Cause No. 38707 FAG 123 S1 Page 001 of 003

Description of the computer model and analytical capability BRG used to in this matter.

ENElYTJX® and Power System Optimizer {PSO)

ENELYTIX® 1 is a cloud-based energy market simulation environment implemented on the Amazon EC2 commercial cloud.

A central element of ENELYTIX is the Power System Optimizer ("PSO"), an advanced simulator of power markets. PSO provides ENELYTIX the capability to accurately model the decision processes used in a wide range of power planning and market structures including long-term system expansion, capacity markets, Day-ahead energy markets and Real-time energy markets. ENELYTIX has this capability because it can configure PSO to determine the optimum solution to each market structure. Figure A-1 illustrates the four key components of the PSO analytical structure: Inputs, Models, Algorithms and Outputs.

As a system expansion optimization model, PSO integrates resource adequacy requirements with the specific design of the capacity market and with the environmental compliance policies, such as state­ level and regional Renewable Portfolio Standards (RPS) and emission constraints. BRG did not use this feature of PSO in this matter.

As a production cost model, PSO is built on a Mixed Integer Programming (MIP) based unit commitment and economic dispatch structure that simulates the operation of the electric power system. PSO determines the security-constrained commitment and dispatch of each modeled generating unit, the loading of each element of the transmission system, and the locational marginal price (LMP) for each generator and load area. PSO supports both hourly and sub hourly timescales. In this project, the PSO is set up to model unit commitment and an hourly economic dispatch. In the commitment process, generating units in a region are turned on or kept on in order for the system to have enough generating capacity available to meet the expected peak load and required operating reserves in the region for the next day while minimizing the expected production cost, including unit commitment and min-gen operations costs. PSO then uses the set of committed units to dispatch the system on an hourly basis (equivalent to a day-ahead dispatch), whereby committed units throughout the modeled footprint are operated between their minimum and maximum operating points to minimize total production costs. The unit commitment in PSO is formulated as a mixed integer linear programming optimization problem which is solved to the true optima using the commercial CPLEX solver.

1 ENELYTIX® is a registered trademark of Newton Energy Group, LLC. AEE Ex. 2 Attachment RBS-2 IURC Cause No. 38707 FAC 123 S1 Page 002 of 003

Figure A - 1. Analytical Structure of PSO

- ~ i,,, ]'' 't X, ~ / ' Fuel prices -

• .c "Emi~sioo C Planning; allowance prices • New builds

"l Somi! inputsi:i;,uld bi! outputs • Retirements dependingonthe rno.deluseand. wnfiguiatlon .

The ENELYTIX/PSO modeling environment provides a realistic, objective and highly defendable analyses of the physical and financial performance of power systems, in particular power systems integrating variable renewable resources.

ENELYTIX modeling architecture

ENEL YTIX provides the advanced modeling features of PSO and the scalability of cloud computing. Figure A-2 illustrates the ENELYTIX architecture. This figure highlights the system services that support parallel processing of simulation projects. AEE Ex. 2 Attachment RBS-2 IURC Cause No. 38707 FAC 123 S1 Page 003 of 003

Figure A-2. Schematic of ENELYTIX Architecture

.· Automatic case generatior, parallelization, Reporting analytics, OLAP, ··•· scalaijle on-demand machine provisiQJling, run visualizationl drm-down, sidEa­ rnanagement, post processing )'ting by-side analysis in Excel-based environment

ENELYTIX complies with high standards of data security properly protecting confidential and Critical Energy Infrastructure Information (CEIi).

For additional information about ENEL YTIX, visit www.enelytix.com. AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAG 1·23 S1 Page 001 of 055

Table 1: Generation by Fuel Enelytix Backcast

Month Gas Coal Wind Blc1m1ass P<>1trnll<>11m t"rncmc,-. Water Interchange 6/1/2019 17,229,262 19,747,350 4,368,552 356,020 311,021 8,478,985 290,391 645,428 (140,316} 6,885,932 30,384 7/1/2019 21,008,397 2~,999,308 3,029,918 403,878 287,062 8,832,821 297,226 723,252 (204,693} 6,908,312 31,397 8/1/2019 20,471,074 22,990,542 3,247,215 367,835 286,469 9,496,910 263,589 692,606 (195,423} 6,694,430 31,397 9/1/2019 17,783,051 20,936,953 3,725,972 358,281 221,926 9,044,694 221,454 672,476 (134,372} 6,446,891 30,384 10/1/2019 16,653,953 15,670,853 5,409,704 359,825 246,420 9,416,630 139,534 563,680 (80,063} 4,870,710 31,397 11/1/2019 14,479,278 20,532,784 4,242,017 361,438 296,987 9,272,232 105,159 639,573 (21,221} 4,545,226 31,896 12/1/2019 18,410,331 18,476,797 4,588,092 364,348 313,195 9,705,881 74,259 606,416 (37,128} 4,983,697 32,959 1/1/2020 19,246,403 17,048,244 6,437,588 368,842 369,714 9,436,648 101,958 618,640 (36,260} 5,154,470 32,959 2/1/2020 19,112,679 15,190,714 5,410,655 341,869 415,712 8,420,556 128,840 549,318 (33,123} 4,806,226 30,833

Historical Actual

Solar Biomass Petroleum Products Water Interchange Energy 6/1/2019 16,499,523 20,561,193 1,258,019 487,505 200,571 8,789,262 73,680 380,847 132 200,571 7/1/2019 20,218,530 26,781,270 1,174,546 490,765 377,572 9,242,820 76,076 385,814 754 377,572 8/1/2019 19,922,792 24,260,336 985,261 475,324 358,260 9,619,889 73,462 390,752 444 358,260 9/1/2019 16,399,541 21,287,119 1,645,772 501,568 311,282 9,202,652 56,300 353,423 452 311,282 10/1/2019 16,058,223 16,741,805 2,068,813 447,044 135,580 8,659,583 41,189 370,986 (1) 135,580 11/1/2019 14,784,277 20,399,234 1,953,681 498,360 160,477 9,002,142 31,010 366,172 (14) 160,477 12/1/2019 15,838,667 19,742,571 2,123,918 511,559 141,553 10,064,839 24,629 377,142 1 141,553 1/1/2020 18,006,739 18,096,777 1,972,046 514,916 182,193 10,216,269 24,712 355,669 (184) 182,193 2/1/2020 16,226,546 15,854,593 2,499,472 445,017 193,547 9,319,346 41,167 336,883 (94} 193,547

I AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 002 of 055

Table 2: Gibson Station Generation Actual v. Backcast

Gibson (Actual) Gibson (Enelytix)

3/1/2019 1,360,557 1,281,790 4/1/2019 1,333,499 1,309,279 5/1/2019 1,083,746 1,062,148 6/1/2019 808,782 777,109 7/1/2019 1,141,581 1,093,555 8/1/2019 780,151 765,797 9/1/2019 807,566 795,096 10/1/2019 710,166 683,907 11/1/2019 860,933 842,681 12/1/2019 805,881 774,343 1/1/2020 542,570 525,307 2/1/2020 322,030 315,116

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Table 3: Cayuga Station Generation Actual v. Backcast

3/1/2019 337,408 336,850 4/1/2019 209,703 183,781 5/1/2019 234,130 211,554 6/1/2019 253,089 234,878 7/1/2019 428,997 406,838 8/1/2019 381,207 384,468 9/1/2019 10/1/2019 247,704 241,735 11/1/2019 364,187 336,596 12/1/2019 263,052 238,609 1/1/2020 279,031 278,695 2/1/2020 225,627 187,491

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Table 4: Edwardsport Station Generation Actual v. Backcast

Edwardsport Edwardsport (Actual) (Enelytix)

3/1/2019 54,593 52,359 4/1/2019 54,322 53,665 5/1/2019 28,736 28,762 6/1/2019 34,535 35,116 7/1/2019 57,913 58,244 8/1/2019 40,944 40,880 9/1/2019 26,829 27,871 10/1/2019 28,577 27,009 11/1/2019 66,547 66,547 12/1/2019 28,818 26,568 1/1/2020 62,812 62,077 2/1/2020 48,962 46,870 AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 005 of 055

Table 5: Gallagher Station Generation Actual v. Backcast

Gallagher Gallagher (Actual) (Enelytix)

3/1/2019 (1,349) 4/1/2019 (1,337) 5/1/2019 6/1/2019 12,032 7/1/2019 5,030 8/1/2019 (102) 9/1/2019 (1,300) 10/1/2019 11/1/2019 (2,144) 12/1/2019 (2,775) 1/1/2020 (2,338) 2/1/2020 3,739

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Table 6: BRG Model Change Log Enelytix Database Data Category BRG Modifications June 2020 Actual MISO historical hourly load for June Forecast using MISO/Purdue 2019 through February 2020, from MISO, Load University data and Enelytix adjacent regions from SPP, EIA APL own modeling Enelytix Base Case forecasts for 2025 scenarios (no modifications). SNL Financial Indiana Hub hourly LMP data LMPs Not applicable (for backcast tuning) SNL Financial and U.S. EIA, minor Unit Characteristics SNL Financial and U.S. EIA retirement and under construction updates NREL with minor adjustments to reflect Wind and Solar Resource NREL 2019 net capacity factors using EIA Forms Quality 860 and 923 SNL, EIA Form 923 and 860 for regulated Fuels SNL, EIA gas units and DEi coal units

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Table 7: Capacity Retirement and Addition

Summer Capacity (MW) '.v""'77''.¾7z1'-:ry·;,,,-,;~•h:,•."ry•,; Coal 4,722 1,090 Solar 4,914 718 Solar with Battery 546 80 Wind 1,820 266 Demand Response 182 27 Combined Cycle Gas Turbine 549 Combustion Turbine 373

Coal Retirement

Cayuga I Cayuga ST 2 495 Edwardsport IGCCI Edwardsport CC CTl 174.9 Edwardsport IGCCI Edwardsport CC CT2 174.9 Edwardsport IGCCI Edwardsport CC ST 245.2 SUM 1090

Coal Retirement All Coal Replacement Case Sµmmer Capacity (MW) Cayuga I Cayuga ST 1 500 Cayuga I Cayuga ST 2 495 Gibson I Gibson ST 2 630 Gibson I Gibson ST 1 630 Gibson I Gibson ST 3 630 Gibson I Gibson ST 4 622 Gibson I Gibson ST 5 620 Edwardsport IGCCJ Edwardsport CC CTl 174.9 Edwardsport IGCCI Edwardsport CC CT2 174.9 Edwardse_o_i-t IGCCI Edwardsport CC ST 245.2 SUM 4722

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Table 8.A Base Case Base Case Base Case Base Case Base Case Base Case Base Case Base Case Base Case Base Case Base Case Base Case Base Case DEi DEi DEi DEi DEi DEi DEi DEi DEi DEi DEi DEi DEi Implied Gibson, Amount Amount Paid DEi Energy Other DEi- Weighted Ancillary Total Cost to Cayuga, Received for for Power Market Operating Cost Operating DEi Load DEi Generation Purchased Owned Average Services Serve Native Edwardsport DEi Power Purchased by Revenue All Units Margin Energy Generators Generator Revenue Load Stations Total Generated DEi Node Price Production Production Month FAC Period Mwh Mwh Mwh $ $/MWh $ $ $ $ $ $ (Mwh) (Mwh) 9/1/2019 Ll23 3,236,755 1,392,749 1,844,005 822,967 569,782 $ 34,625,074 $ 24.86 $ 49,479,533 $ 31,962 $ 84,136,568 $ 36,255,680 $ 85,735,213 $ (1,598,644) 10/1/2019 L123 2,906,780 1,530,675 1,376,105 952,651 578,024 $ 32,857,987 $ 21.47 $ 33,257,052 $ 42,395 $ 66,157,435 $ 39,339,697 $ 72,596,749 $ (6,439,314) 11/1/2019 L123 3,036,338 1,786,425 1,249,914 1,245,824 540,600 $ 42,868,079 $ 24.00 $ 33,924,030 $ 31,113 $ 76,823,222 $ 48,846,690 $ 82,770,720 $ (5,947,497) 12/1/2019 L124 3,201,766 1,641,382 1,560,384 1,039,520 601,862 $ 37,441,786 $ 22.81 $ 36,285,359 $ 38,613 $ 73,765,759 $ 43,984,615 $ 80,269,974 $ (6,504,216) 1/1/2020 L124 3,315,961 1,477,933 1,838,028 866,079 611,854 $ 33,796,037 $ 22.87 $ 42,693,120 $ 103,176 $ 76,592,334 $ 40,414,560 $ 83,107,681 $ (6,515,347) 2/1/2020 L124 3,157,178 1,146,075 2,011,103 549,477 596,598 $ 25,788,362 $ 22.50 $ 45,916,489 $ 159,359 $ 71,864,209 $ 30,922,527 $ 76,839,016 $ (4,974,806) L123 Subtotal L123 Subtotal 9,179,873 4,709,849 4,470,024 3,021,443 1,688,406 $ 110,351,140 $ 23.43 $ 116,660,616 $ 105,470 $227,117,226 $ 124,442,066 $ 241,102,682 $ (13,985,456) Ll24 Subtotal L124 Subtotal 9,674,90S 4,265,390 5,409,S15 2,455,075 1,810,314 $ 97,026,18S $ 22.75 $ 124,894,969 $ 301,148 $222,222,302 $ 115,321,701 $240,216,670 $ (17,994,368) Total Total 18,854,778 8,975,239 9,879,539 5,476,518 3,498,721 $ 207,377,325 $ 23.11 $ 241,555,584 $ 406,618 $ 449,339,528 $ 239,763,768 $481,319,352 $ (31,979,824)

Table 8.B Market Case Market Case Market Case Market Case Market Case Market Case Market Case Market Case Market Case Market Case Market Case Market Case Market Case DEi DEi DEi DEi DEi DEi DEi DEi DEi DEi DEi DEi Implied Gibson, Amount Amount Paid DEi Energy Other DEi- Weighted Ancillary Total Cost to Cayuga, Received for for Power Market Operating Cost Operating DEi Load DEi Generation Purchased Owned Average Services Serve Native Edwardsport DEi Power Purchased by Revenue All Units Margin Energy Generators Generator Revenue Load Stations Total Generated DEi Node Price Production Production Month FAC Period Mwh Mwh Mwh $ $/MWh $ $ $ $ $ $ (Mwh) (Mwh) 9/1/2019 L123 3,236,755 1,911,698 1,325,057 1,357,167 554,531 $ 47,952,457 $ 25.08 $ 35,260,436 $ 38,636 $ 83,251,529 $ 45,073,804 $ 80,334,241 $ 2,917,288 10/1/2019 L123 2,906,780 754,490 2,152,289 161,550 592,941 $ 16,920,477 $ 22.43 $ 52,450,146 $ 45,742 $ 69,416,366 $ 14,378,634 $ 66,828,780 $ 2,587,585 11/1/2019 L123 3,036,338 1,682,925 1,353,413 1,140,262 542,664 $ 40,678,142 $ 24.17 $ 36,534,512 $ 27,997 $ 77,240,651 $ 41,213,274 $ 77,747,786 $ (507,135) 12/1/2019 L124 3,201,766 1,349,584 1,852,182 744,623 604,962 $ 31,166,432 $ 23.09 $ 42,739,660 $ 24,392 $ 73,930,484 $ 31,094,796 $ 73,834,456 $ 96,028 1/1/2020 L124 3,315,961 997,935 2,318,026 377,217 620,718 $ 23,473,778 $ 23.52 $ 53,914,156 $ 49,380 $ 77,437,314 $ 22,270,582 $ 76,184,737 $ 1,252,576 2/1/2020 L124 3,157,178 917,222 2,239,956 315,655 601,567 $ 20,907,369 $ 22.79 $ 50,787,932 $ 118,699 $ 71,814,001 $ 19,170,557 $ 69,958,489 $ 1,855,512 L123 Subtotal L123 Subtotal 9,179,873 4,349,114 4,830,759 2,658,978 1,690,136 $ 105,551,076 $ 24.27 $ 124,245,094 $ 112,375 $ 229,908,545 $ 100,665,713 $224,910,807 $ 4,997,738 L124 Subtotal L124 Subtotal 9,674,905 3,264,741 6,410,164 1,437,495 1,827,246 $ 75,S47,579 $ 23.14 $147,441,748 $ 192,471 $223,181,798 $ 72,535,934 $ 219,977,682 $ 3,204,117 Total Total 18,854,778 7,613,855 11,240,923 4,096,473 3,517,382 $ 181,098,656 $ 23, 79 $ 271,686,842 $ 304,846 $ 453,090,344 $ 173,201,646 $ 444,888,489 $ 8,201,855

Base Case - Base Case - Base Case - Base Case - Base Case - Base Case - Base Case - Base Case - Base Case· Base Case - Base Case - Base Case - Base Case - Table 8.C Market Case Market Case Market Case Market Case Market Case Market Case Market Case Market Case Market Case Market Case Market Case Market Case Market Case DEi DEi DEi DEi DEi DEi DEi DEi DEi DEi DEi DEi Implied Gibson, Amount Amount Paid DEi Energy Other DEi- Weighted Ancillary Total Cost to Cayuga, Received for for Power Market Operating Cost Operating DEi Load DEi Generation Purchased Owned Average Services Serve Native Energy Edwardsport DEi Power Purchased by Revenue All Units Margin Generators Generator Revenue Load Stations Total Generated DEi Node Price Production Production Month FAC Period Mwh Mwh Mwh $ $/MWh $ $ $ $ $ $ (Mwh) (Mwh) 9/1/2019 L123 (518,,949) 518,949 (534,199) 15,250 (13,327,383) $ (0.22) 14,219,097 $ (6,674) 885,040 (8,818,125) 5,400,972 (4,515,933) 10/1/2019 Ll23 776,185 (776,185) 791,101 (14,916} 15,937,510 $ (0.96) (19,193,094) $ (3,347) . (3,258,931) 24,961,063 5,767,969 (9,026,899)

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11/1/2019 L123 103,499 (103,499) 105,563 (2,064) 2,189,937 $ (0.17) (2,610,482) $ 3,116 (417,429) 7,633,416 5,022,934 (5,440,362) 12/1/2019 L124 291,798 (291,798) 294,897 (3,099) 6,275,354 $ (0.28) (6,454,300) $ 14,221 (164,725) 12,889,819 6,435,519 (6,600,244) 1/1/2020 L124 479,998 (479,998) 488,861 (8,864) 10,322,259 $ (0.66) (11,221,035) $ 53,796 (844,980) 18,143,978 6,922,943 (7,767,923) 2/1/2020 L124 228,853 (228,853) 233,822 (4,969) 4,880,992 $ (0.29) (4,871,443) $ 40,659 50,208 11,751,970 6,880,527 (6,830,318) L123 Subtotal L123 Subtotal 360,735 (360,735) 362,465 (1,730) $ 4,800,064 $ (0.84) $ (7,584,479) $ (6,904) $ (2,791,319) $ 23,776,354 $ 16,191,875 $ (18,983,194) L124 Subtotal L124 Subtotal 1,000,649 (1,000,649) 1,017,581 (16,932) $ 21,478,605 $ (0.39) $ (22,546,779) $ 108,677 $ (959,496) $ 42,785,767 $ 20,238,988 $ (21,198,485) Total Total 1,361,384 (1,361,384) 1,380,046 (18,662) 26,278,669 $ (0.68) {30,131,258) $ 101,773 (3,750,816) 66,562,121 36,430,863 (40,181,679)

L123 L123 L123 L123 L123 L123 L123 L123 L123 L123 L123 L123 L123 Uneconomic Uneconomic Uneconomic Uneconomic Uneconomic Uneconomic Uneconomic Uneconomic Uneconomic Uneconomic Uneconomic Uneconomic Uneconomic Table 8.D Retired Retired Retired Retired Retired Retired Retired Retired Retired Retired Retired Retired Retired DEi DEi DEi DEi DEi DEi DEi DEi DEi DEi DEi DEi Implied Gibson, Amount Amount Paid DEi Energy Other DEi- Weighted Ancillary Total Cost to Cayuga, Received for for Power Market Operating Cost Operating DEi Load DEi Generation Purchased Owned Average Services Serve Native Energy Edwardsport DEi Power Purchased by Revenue All Units Margin Generators Generator Revenue Load Stations Total Generated DEi Node Price Production Production Month FAC Period Mwh Mwh Mwh $ $/MWh $ $ $ $ $ $ (Mwh) (Mwh) 9/1/2019 L123 3,236,755 1,275,410 1,961,345 748,798 526,611 31,937,160 $ 25.04 52,732,316 28,642 84,698,117 30,812,806 83,545,122 1,152,996 10/1/2019 L123 2,906,780 1,403,282 1,503,498 792,630 610,651 30,028,878 $ 21.40 36,409,753 45,694 66,484,325 33,108,649 69,518,402 (3,034,077) 11/1/2019 L123 3,036,338 1,598,666 1,437,673 1,027,450 571,216 38,288,367 $ 23.95 38,698,243 58,279 77,044,890 39,974,873 78,673,116 (1,628,226) L123 Subtotal L123 Subtotal 9,179,873 4,277,357 4,902,516 2,568,878 1,708,479 $ 100,254,404 $ 23.44 $ 127,840,312 $ 132,615 $ 228,227,332 $ 103,896,328 $ 231,736,640 $ (3,509,308) Delta v Base Case Delta v Base Case 432,491 (432,491} 452,564 (20,073) $ 10,096,736 $ (0.01) (11,179,697) $ (27,145) $ (1,110,106) $ 20,545,738 $ 9,366,042 $ (10,476,148)

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Table 9.A: Coal Unit Operating Margin Analysis (Base Case - Market Case) Operati~g Scenario Month Unit FAC Period Production Energy Revenue Operating Cost VOM Cost Margin Name Month Starting Name Name MWh $ $ $ $ Base Case-Market Case 9/1/2019 Cayuga ST 1 I6416 Ll23 Base Case-Market Case 10/1/2019 Cayuga ST 1 I6416 L123 124,314 2,690,803 3,946,434 372,942 (1,255,631) Base Case-Market Case 11/1/2019 Cayuga ST 1 I6416 L123 155,766 3,741,302 4,732,591 467,297 (991,289) Base Case-Market Case 12/1/2019 Cayuga ST 1 I6416 L124 107,737 2,442,298 3,534,440 323,212 (1,092,142) Base Case-Market Case 1/1/2020 Cayuga ST 1 I 6416 L124 140,041 3,200,349 4,250,524 420,122 (1,050,175) Base Case-Market Case 2/1/2020 Cayuga ST 1 I6416 L124 96,626 2,185,030 3,087,805 289,878 (902,775) Base Case-Market Case Cayuga ST 1 I6416 L123 Subtotal 280,080 $ 6,432,105 $ 8,679,025 $ 840,239 $ (2,246,920) Base Case-Market Case Cayuga ST 1 I6416 L124 Subtotal 344,404 $ 7,827,677 $ 10,872,769 $ 1,033,212 $ (3,045,093)

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost VOM Cost Margin Name Month Starting Name Name MWh $ $ $ $ Base Case-Market Case 9/1/2019 Cayuga ST 2 I6417 L123 Base Case-Market Case 10/1/2019 Cayuga ST 2 I6417 L123 117,421 2,524,423 3,935,615 352,263 (1,411,192) Base Case-Market Case 11/1/2019 Cayuga ST 2 I 6417 L123 180,830 4,340,188 5,512,573 542,491 (1,172,385) Base Case-Market Case 12/1/2019 Cayuga ST 2 I6417 L124 130,871 2,996,241 4,339,738 392,614 (1,343,498) Base Case-Market Case 1/1/2020 Cayuga ST 2 I 6417 L124 138,654 3,163,229 4,359,189 415,963 (1,195,960) Base Case-Market Case 2/1/2020 Cayuga ST 2 I 6417 L124 90,865 2,035,706 3,012,919 272,596 (977,212) Base Case-Market Case Cayuga ST 2 I6417 L123 Subtotal 298,251 $ 6,864,610.94 $ 9,448,187.84 $ 894,754 $ (2,583,577) Base Case-Market Case Cayuga ST 2 I6417 L124 Subtotal 360,391 $ 8,195,176.43 $ 11,711,846.45 $ 1,081,173 $ (3,516,670)

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost VOM Cost Margin Name Month Starting Name Name MWh $ $ $ $ Base Case-Market Case 9/1/2019 Edwardsport CC CTl I 20460 L123 8,193 205,026 1,148,446 20,483 (943,421) Base Case-Market Case 10/1/2019 Edwardsport CC CTl I 20460 L123 8,156 177,215 965,648 20,389 (788,433) Base Case-Market Case 11/1/2019 Edwardsport CC CTl I 20460 L123 19,563 472,237 1,544,163 48,906 (1,071,926) Base Case-Market Case 12/1/2019 Edwardsport CC CTl I 20460 L124 8,471 195,197 1,147,572 21,179 (952,374) Base Case-Market Case 1/1/2020 Edwardsport CC CTl I 20460 L124 18,392 422,959 1,390,288 45,981 (967,329) Base Case-Market Case 2/1/2020 Edwardsport CC CTl I 20460 Ll24 13,357 301,493 1,076,215 33,391 (774,723) Base Case-Market Case Edwardsport CC CTl I 20460 L123 Subtotal 35,911 $ 854,477.30 $ 3,658,256.83 $ 89,778 $ (2,803,780) Base Case-Market Case Edwardsport CC: c:_I_J.__120460 L124 Subtotal 40,220 $ 919,648.54 $ 3,614,074.22 $ 100,551 $ (2,694,426)

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Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost VOM Cost Margin Name Month Starting Name Name MWh $ $ $ $ Base Case-Market Case 9/1/2019 Edwardsport CC CT2 I32161 L123 8,193 205,026 1,088,113 20,483 $ (883,087) Base Case-Market Case 10/1/2019 Edwardsport CC CT2 I 32161 L123 8,401 182,613 930,104 21,002 $ (747,491) Base Case-Market Case 11/1/2019 Edwardsport CC CT2 I 32161 L123 19,563 472,237 1,464,163 48,906 $ (991,926) Base Case-Market Case 12/1/2019 Edwardsport CC CT2 I 32161 L124 6,789 158,443 865,670 16,972 $ (707,227) Base Case-Market Case 1/1/2020 Edwardsport CC CT2 I 32161 L124 17,903 413,839 1,294,798 44,758 $ (880,958) Base Case-Market Case 2/1/2020 Edwardsport CC CT2 I 32161 L124 13,109 295,017 1,002,547 32,773 $ (707,530) Base Case-Market Case Edwardsport CC CT2 I 32161 L123 Subtotal 36,156 $ 859,875.85 $ 3,482,379.16 $ $ (2,622,503) Base Case-Market Case Edwardsport CC CT2 I32161 L124 Subtotal 37,801 $ 867,299.18 $ 3,163,014.91 $ 94,503 $ (2,295,716)

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost VOM Cost Margin Name Month Starting Name Name MWh $ $ $ $ Base Case-Market Case 9/1/2019 Edwardsport CC STI 32162 L123 9,000 211,087 1,088,228 22,500 $ (880,597) Base Case-Market Case 10/1/2019 Edwardsport CC STl32162 L123 (16,381) (404,171) 324,178 (40,954) $ (730,851) Base Case-Market Case 11/1/2019 Edwardsport CC ST I32162 L123 27,422 661,963 1,587,715 68,555 $ (925,752) Base Case-Market Case 12/1/2019 Edwardsport CC STl32162 L124 11,308 261,517 1,141,985 28,270 $ (880,468) Base Case-Market Case 1/1/2020 Edwardsport CC ST I32162 L124 25,782 592,887 1,430,337 64,454 $ (837,449) Base Case-Market Case 2/1/2020 Edwardsport CC ST I 32162 L124 16,985 368,702 1,073,404 42,462 $ (707,506) Base Case-Market Case Edwardsport CC ST I 32162 L123 Subtotal 20,041 $ 468,879.74 $ 3,000,121.43 $ 50,101 $ (2,537,200) Base Case-Market Case Edwardsport CC ST I 32162 L124 Subtotal 54,074 $ 1,223,106.08 $ 3,645,725.06 $ 135,186 $ (2,425,423_)

Operating Scenario Month Unit·· FAC Period Production Energy Revenue Operating Cost VOM Cost Margin Name Month Starting Name Name MWh $ $ $ $ Base Case-Market Case 9/1/2019 Gibson ST 1 I6456 L123 (141,561) (3,531,824) (3,084,545) (283,123) $ (449,964) Base Case-Market Case 10/1/2019 Gibson ST 1 I64S6 L123 115,094 2,376,360 3,167,860 230,187 $ (791,499) Base Case-Market Case 11/1/2019 Gibson ST 1 I 6456 L123 (127,221) (3,096,187) (3,138,195) (254,441) $ 41,273 Base Case-Market Case 12/1/2019 Gibson ST 1 I6456 L124 (100,918) (2,398,989) (2,209,867) (201,835) $ (193,443) Base Case-Market Case 1/1/2020 Gibson ST 1 I6456 L124 14,013 168,891 634,936 28,027 $ (466,082) Base Case-Market Case 2/1/2020 Gibson ST 1 I6456 L124 (47,852) (1,224,383) (814,157) (95,704) $ (419,457) Base Case-Market Case Gibson ST 1 I6456 L123 Subtotal (153,688) $ (4,251,650.38) $ (3,054,880.90) $ (307,376) $ (1,200,190) Base Case-Market Case Gibson ST 1 I6456 L124 Subtotal (134,756) $ (3,454,481.01) $ (2,389,087.95) $ (269,513)_ $ (1,078,982)

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Opj!rating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost VOM Cost Margin Name Month Starting Name Name MWh $ L $ $ Base Case-Market Case 9/1/2019 Gibson ST 2 I6457 L123 (106,738) (2,804,214) (2,454,171) (213,476) $ (352,101) Base Case-Market Case 10/1/2019 Gibson ST 2 I6457 L123 108,702 2,243,809 3,037,088 217,405 $ (793,279) Base Case-Market Case 11/1/2019 Gibson ST 2 I 6457 L123 (57,043} (1,461,085} (1,465,760} (114,085) $ 2,420 Base Case-Market Case 12/1/2019 Gibson ST 2 I 6457 L124 55,758 1,142,611. 1,507,224 111,516 $ (365,623) Base Case-Market Case 1/1/2020 Gibson ST 2 I6457 L124 57,538 1,195,176 1,835,358 115,075 $ (640,771} Base Case-Market Case 2/1/2020 Gibson ST 2 I6457 L124 49,041 1,051,924 1,736,940 98,082 $ (686,223) Base Case-Market Case Gibson ST 2 I6457 L123 Subtotal (55,078} $ (2,021,491.20} $ {882,843.39} $ (110,156) $ (1,142,961) Base Case-Market Case Gibson ST 2 I6457 L124 Subtotal 162,337 $ 3,389,710.97 $ 5,079,522.97 $ 324,673 $ (1,692,617}

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost VOM Cost Margin Name Month Starting Name Name MWh $ $ $ $ Base Case-Market Case 9/1/2019 Gibson ST 3 I6458 L123 (73,844} (1,968,059} (1,669,221} {147,687) $ (301,096} Base Case-Market Case 10/1/2019 Gibson ST 3 I 6458 L123 122,863 2,540,816 3,340,575 245,725 $ {799,759} Base Case-Market Case 11/1/2019 Gibson ST 3 j 6458 L123 (29,264} (800,229) (702,119} (58,527} $ (98,994} Base Case-Market Case 12/1/2019 Gibson ST 3 I6458 L124 83,306 1,790,351 2,237,893 166,612 $ (447,675) Base Case-Market Case 1/1/2020 Gibson ST 3 I6458 L124 51,493 1,046,190 1,750,780 102,986 $ {704,8d6} Base Case-Market Case 2/1/2020 Gibson ST 3 I6458 L124 48,469 1,037,878 1,721,037 96,939 $ (683,416) Base Case-Market Case Gibson ST 3 I 6458 L123 Subtotal 19,7S5 $ (227,471.62} $ 969,234.65 $ 39,511 $ (1,199,848} Base Case-Market Case Gibson ST 3 I6458 L124 Subtotal 183,269 $ 3,874,418.52 $ 5,709,709.48 $ 366,537 $ (1,835,897)

Opera ti pg Scenario Month Unit FAC Period Production Energy Revenue Operating Cost VOM Cost Margin Name Month Starting Name Name MWh $ $ $ $ Base Case-Market Case 9/1/2019 Gibson ST 4 I6459 Ll23 {158,627) {3,957,010} {3,411,499) (317,254) $ (547,519) Base Case-Market Case 10/1/2019 Gibson ST 4 I 6459 L123 81,520 1,555,587 2,376,570 163,040 $ {821,686} Base Case-Market Case 11/1/2019 Gibson ST 4 I6459 L123 (133,534} (3,242,122} (3,135,520} (267,069} $ (107,889} Base Case-Market Case 12/1/2019 Gibson ST 416459 L124 {93,859} (2,228,551} (2,028,766} {187,718} $ (202,124} Base Case-Market Case 1/1/2020 Gibson ST 4 I6459 L124 (60,672} (1,575,902} (1,270,506} (121,344) $ {314,441} Base Case-Market Case 2/1/2020 Gibson ST 4 I6459 L124 (105,089} (2,457,909} (2,138,841} (210,179} $ (335,309} Base Case-Market Case Gibson ST 4 I6459 L123 Subtotal (210,641} $ (5,643,545.49} $ (4,170,448.34} $ (421,282) $ {1,477,093} Base Case-Market Case Gibson ST 4 I6459 L124 Subtotal (259,620L__i_(6,_262,3~_1._.94L_$ J5!438,ll3.07} $ (519,241) $ (851,873} AEE Ex. 2 Attachment RBS~3 IURC Cause No. 38707 FAC 123 S1 Page 013 of 055

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost VOM Cost Margin Name Month Starting Name Name MWh $ $ $ $ Base Case-Market Case 9/1/2019 Gibson ST 5 I 6460 L123 (78,816) (2,191,242) (1,881,705) (157,632) $ (312,353) Base Case-Market Case 10/1/2019 Gibson ST 5 I 6460 L123 121,013 2,502,825 3,334,617 242,025 $ (831,793) Base Case-Market Case 11/1/2019 Gibson ST 5 I 6460 Ll23 49,481 1,017,041 1,257,402 98,961 $ (241,200) Base Case-Market Case 12/1/2019 Gibson ST 5 I 6460 Ll24 85,432 1,845,981 2,406,957 170,864 $ (560,976) Base Case-Market Case 1/1/2020 Gibson ST 5 I 6460 L124 85,717 1,890,991 2,655,173 171,435 $ (764,182) Base Case-Market Case 2/1/2020 Gibson ST 5 I 6460 L124 58,312 1,316,592 2,091,523 116,624 $ (774,930) Base Case-Market Case Gibson ST 5 I 6460 L123 Subtotal 91,677 $ 1,328,624 $ 2,710,314 $ 183,355 $ (1,385,346) Base Case-Market Case Gibson ST 5 I 6460 L124 Subtotal 229,462 $ 5,053,565 $ 7,153,653 $ 458,924 $ (2,100,088)

:1 AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 014 of 055

Table 9.B: Coal Unit Operating Margin Analysis (Base Case) Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Base Case 9/1/2019 Cayuga ST 1 J 6416 L123 $ $ $ Base Case 10/1/2019 Cayuga ST 1 J 6416 L123 124,314 $ 2,690,803 $ 3,946,434 $ (1,255,631) Base Case 11/1/2019 Cayuga ST 1 I6416 L123 155,766 $ 3,741,302 $ 4,732,591 $ (991,289) Base Case 12/1/2019 Cayuga ST 1 I6416 L124 107,737 $ 2,442,298 $ 3,534,440 $ (1,092,142) Base Case 1/1/2020 Cayuga ST 1 J 6416 L124 140,041 $ 3,200,349 $ 4,250,524 $ (1,050,175) Base Case 2/1/2020 Cayuga ST 1 I6416 L124 96,626 $ 2,185,030 $ 3,087,805 $ (902,775) Base Case Cayuga ST 1 J 6416 L123 Subtotal 280,080 $ 6,432,105 $ 8,679,025 $ (2,246,920) Base Case Cayuga ST 1 I6416 L124 Subtotal 344,404 $ 7,827,677 $ 10,872,769 $ (3,045,093)

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Base Case 9/1/2019 Cayuga ST 2 I6417 L123 $ $ $ Base Case 10/1/2019 Cayuga ST 2 I 6417 L123 117,421 $ 2,524,423 $ 3,935,615 $ (1,411,192) Base Case 11/1/2019 Cayuga ST 2 I6417 L123 180,830 $ 4,340,188 $ 5,512,573 $ (1,172,385) Base Case 12/1/2019 Cayuga ST 2 I 6417 L124 130,871 $ 2,996,241 $ 4,339,738 $ (1,343,498) Base Case 1/1/2020 Cayuga ST 2 I6417 L124 138,654 $ 3,163,229 $ 4,359,189 $ (1,195,960) Base Case 2/1/2020 Cayuga ST 2 J 6417 L124 90,865 $ 2,035,706 $ 3,012,919 $ (977,212) Base Case Cayuga ST 2 J 6417 L123 Subtotal 298,251 $ 6,864,611 $ 9,448,188 $ (2,583,577) Base Case Cayuga ST 2 I6417 L124 Subtotal 360,391 $ 8,195,176 $ 11,711,846 $ (3,516,670)

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Base Case 9/1/2019 Edwardsport CC en J 20460 L123 8,193 $ 205,026 $ 1,148,446 $ (943,421) Base Case 10/1/2019 Edwardsport cc en I 20460 L123 8,156 $ 177,215 $ 965,648 $ (788,433) Base Case 11/1/2019 Edwardsport cc en I 20460 L123 19,563 $ 472,237 $ 1,544,163 $ (1,071,926) Base Case 12/1/2019 Edwardsport CC en I 20460 L124 8,471 $ 195,197 $ 1,147,572 $ (952,374) Base Case 1/1/2020 Edwardsport cc en I 20460 L124 18,392 $ 422,959 $ 1,390,288 $ (967,329) Base Case 2/1/2020 Edwardsport cc en J 20460 L124 13,357 $ 301,493 $ 1,076,215 $ (774,723) Base Case Edwardsport cc en I 20460 L123 Subtotal 35,911 $ 854,477 $ 3,658,257 $ (2,803,780)

" AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 . Page 015 of 055

Base Case Edwardsport CC CTl I 20460 L124 Subtotal 40,220 $ 919,649 $ 3,614,074 $ (2,694,426)

,;;1 I' 11 AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 ' Page 016 of 055 ,

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Base Case 9/1/2019 Edwardsport CC CT2 J32161 L123 8,193 $ 205,026 $ 1,088,113 $ {883,087) Base Case 10/1/2019 Edwardsport CC CT2 J32161 L123 8,401 $ 182,613 $ 930,104 $ (747,491) Base Case 11/1/2019 Edwardsport CC CT2 J32161 L123 19,563 $ 472,237 $ 1,464,163 $ (991,926) Base Case 12/1/2019 Edwardsport CC CT2 I 32161 L124 6,789 $ 158,443 $ 865,670 $ (707,227) Base Case 1/1/2020 Edwardsport CC CT2 I32161 L124 17,903 $ 413,839 $ 1,294,798 $ (880,958) Base Case 2/1/2020 Edwardsport CC CT2 I32161 L124 13,109 $ 295,017 $ 1,002,547 $ (707,530} Base Case Edwardsport CC CT2 I32161 L123 Subtotal 36,156 $ 859,876 $ 3,482,379 $ (2,622,503) Base Case Edwardsport CC CT2 I32161 L124 Subtotal 37,801 $ 867,299 $ 3,163,015 $ (2,295,716)

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Base Case 9/1/2019 Edwardsport CC ST I32162 L123 11,485 $ 287,397.32 $ 1,174,753.92 $ (887,357) Base Case 10/1/2019 Edwardsport CC STJ 32162 L123 10,453 $ 227,763.59 $ 947,295.32 $ (719,532) Base Case 11/1/2019 Edwardsport CC ST I32162 L123 27,422 $ 661,963.31 $ 1,587,715.30 $ (925,752) Base Case 12/1/2019 Edwardsport CC STI 32162 L124 11,308 $ 261,516.79 $ 1,141,984.55 $ (880,468) Base Case 1/1/2020 Edwardsport CC ST I32162 L124 25,782 $ 592,887.38 $ 1,430,336.76 $ (837,449) Base Case 2/1/2020 Edwardsport CC ST I32162 Ll24 20,404 $ 463,136.12 $ 1,188,024.80 $ (724,889) Base Case Edwardsport CC ST I32162 L123 Subtotal 49,360 $ 1,177,124.22 $ 3,709,764.54 $ (2,532,640) Base Case Edwardsport CC STI 32162 L124 Subtotal 57,494 $ 1,317,540.29 $ 3,760,346.10 $ (2,442,806)

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Base Case 9/1/2019 Gibson ST 1 J6456 L123 163,065 $ 4,038,658 $ 4,219,279 $ (180,622) Base Case 10/1/2019 Gibson ST 1 I 6456 L123 135,096 $ 2,920,386 $ 3,725,921 $ (805,535) Base Case 11/1/2019 Gibson ST 1 I 6456 L123 172,377 $ 4,135,389 $ 4,525,079 $ (389,691} Base Case 12/1/2019 Gibson ST 1 I 6456 L124 161,293 $ 3,686,754 $ 4,273,788 $ (587,034) Base Case 1/1/2020 Gibson ST 1 I 6456 L124 108,404 $ 2,480,278 $ 3,234,599 $ (754,321) Base Case 2/1/2020 Gibson ST 1 J6456 L124 64,404 $ 1,455,863 $ 2,163,150 $ (707,287) Base Case Gibson ST 1 I 6456 L123 Subtotal 470,539 $ 11,094,432 $ 12,470,280 $ (1,375,848) Base Case Gibson ST 1 I 6456 L124 Subtotal 334,100 $ 7,622,895 $ 9,671,537 $ (2,048,641) AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 017 of055

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Base Case 9/1/2019 Gibson ST 2 I 6457 Ll23 160,605 $ 3,988,394 $ 4,293,581 $ (305,186) Base Case 10/1/2019 Gibson ST 2 I 6457 L123 128,043 $ 2,772,513 $ 3,585,884 $ {813,371) Base Case 11/1/2019 Gibson ST 2 I 6457 L123 172,377 $ 4,135,389 $ 4,588,671 $ (453,282) Base Case 12/1/2019 Gibson ST 2 I 6457 L124 161,293 $ 3,686,754 $ 4,333,771 $ (647,016) Base Case 1/1/2020 Gibson ST 2 I6457 L124 108,404 $ 2,480,278 $ 3,280,721 $ (800,443) Base Case 2/1/2020 Gibson ST 2 I 6457 L124 64,404 $ 1,455,863 $ 2,194,095 $ {738,232) Base Case Gibson ST 2 I 6457 L123 Subtotal 461,025 $ 10,896,296 $ 12,468,135 $ (1,571,839) Base Case Gibson ST 2 I 6457 L124 Subtotal 334,100 $ 7,622,895 $ 9,808,587 $ (2,185,691)

Operatin~ Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Base Case 9/1/2019 Gibson ST 3 I 6458 L123 156,753 $ 3,897,021 $ 4,268,971 $ (371,950) Base Case 10/1/2019 Gibson ST 3 I 6458 L123 142,204 $ 3,069,521 $ 3,889,021 $ (819,500) Base Case 11/1/2019 Gibson ST 3 I 6458 L123 170,744 $ 4,102,647 $ 4,622,348 $ (519,701:) Base Case 12/1/2019 Gibson ST 3 I 6458 L124 143,130 $ 3,250,404 $ 3,936,283 $ {685,879! Base Case 1/1/2020 Gibson ST 3 I 6458 L124 104,526 $ 2,400,622 $ 3,245,152 $ (844,530) Base Case 2/1/2020 Gibson ST 3 I6458 L124 64,404 $ 1,455,863 $ 2,191,914 $ (736,051} Base Case Gibson ST 3 I 6458 L123 Subtotal 469,700 $ 11,069,190 $ 12,780,340 $ (1,711,151) Base Case Gibson ST 3 I 6458 L124 Subtotal 312,059 $ 7,106,889 $ 9,373,350 $ (2,266,460)

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Base Case 9/1/2019 Gibson ST 4 I 6459 L123 154,176 $ 3,835,264 $ 4,054,540 $ (219,276) Base Case 10/1/2019 Gibson ST 4 I 6459 L123 138,599 $ 2,992,414 $ 3,808,279 $ (815,864) Base Case 11/1/2019 Gibson ST 4 I 6459 L123 157,522 $ 3,758,763 $ 4,201,444 $ (442,681) Base Case 12/1/2019 Gibson ST 4 I 6459 L124 159,261 $ 3,640,307 $ 4,204,375 $ (564,068) Base Case 1/1/2020 Gibson ST 416459 L124 97,277 $ 2,225,651 $ 3,052,743 $ (827,093) Base Case 2/1/2020 Gibson ST 4 I 6459 L124 63,592 $ 1,437,521 $ 2,127,837 $ (690,316) Base Case Gibson ST 4 I 6459 L123 Subtotal 450,297 $ 10,586,442 $ 12,064,263 $ (1,477,821) Base Case Gibson ST 4 I 6459 L124 Subtotal 320,130 $ 7,303,479 $ 9,384,956 $ (2,081,477) AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 018 of 055

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Base Case 9/1/2019 Gibson ST 5 I 6460 L123 160,497 $ 3,975,057 $ 4,262,413 $ {287,3S6) Base Case 10/1/2019 Gibson ST 5 I 6460 L123 139,964 $ 3,021,182 $ 3,878,467 $ (857,285) Base Case 11/1/2019 Gibson ST 5 I 6460 L123 169,662 $ 4,070,264 $ 4,571,609 $ {501,345) Base Case 12/1/2019 Gibson ST 5 I 6460 L124 149,367 $ 3,401,692 $ 4,149,040 $ {747,348) Base Case 1/1/2020 Gibson ST 5 I 6460 L124 106,696 $ 2,441,219 $ 3,268,736 $ (827,517) Base Case 2/1/2020 Gibson ST 5 I6460 L124 58,312 $ 1,316,592 $ 2,091,523 $ (774,930) Base Case Gibson ST 5 I6460 L123 Subtotal 470,124 $ 11,066,503 $ 12,712,489 $ (1,645,986) Base Case Gibson ST 5 I 6460 L124 Subtotal 314,375 $ 7,159,503 $ 9,509,298 $ {2,349,796)

I- I' Pl' I j,,, AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 019 of 055

Table 9.C: Coal Unit Operating Margin Analysis (Market Case) Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Market Case 9/1/2019 Cayuga ST 1 I 6416 L123 $ $ $ $ Market Case 10/1/2019 Cayuga ST 1 I6416 L123 $ $ $ $ Market Case 11/1/2019 Cayuga ST 1 I 6416 L123 $ $ $ $ Market Case 12/1/2019 Cayuga ST 1 I 6416 L124 $ $ $ $ Market Case 1/1/2020 Cayuga ST 1 I6416 L124 $ $ $ $ Market Case 2/1/2020 Cayuga ST 1 I 6416 L124 $ $ $ $ Market Case Cayuga ST 1 \ 6416 L123 Subtotal $ $ $ Market Case Cayuga ST 1 \ 6416 L124 Subtotal $ $ $

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Market Case 9/1/2019 Cayuga ST 2 \ 6417 L123 $ $ $ Market Case 10/1/2019 Cayuga ST 2 \ 6417 L123 $ $ $ Market Case 11/1/2019 Cayuga ST 2 \ 6417 L123 $ $ $ Market Case 12/1/2019 Cayuga ST 2 \ 6417 L124 $ $ $ Market Case 1/1/2020 Cayuga ST 2 \ 6417 L124 $ $ $ Market Case 2/1/2020 Cayuga ST 2 \ 6417 L124 $ $ $ Market Case Cayuga ST 2 I6417 L123 Subtotal $ $ $ Market Case Cayuga ST 2 \ 6417 L124 Subtotal $ $ $

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Market Case 9/1/2019 Edwardsport CC CTl I 20460 L123 $ $ $ Market Case 10/1/2019 Edwardsport CC CTl \ 20460 L123 $ $ $ Market Case 11/1/2019 Edwardsport CC CTl \ 20460 L123 $ $ $ Market Case 12/1/2019 Edwardsport CC CTl \ 20460 L124 $ $ $ Market Case 1/1/2020 Edwardsport CC CTl \ 20460 L124 $ $ $ Market Case 2/1/2020 Edwardsport CC CTl \ 20460 L124 $ $ $ Market Case Edwardsport CC CTl I 20460 L123 Subtotal $ $ $

!' 1, t·i.··I AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 020 of 055

Market Case Edwardsport CC C_Tl I 20460 L124 Subtotal $ $ $

VI ! AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 021 of 055

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Market Case 9/1/2019 Edwardsport CC CT2 I32161 L123 $ $ $ Market Case 10/1/2019 Edwardsport CC CT2 I32161 L123 $ $ $ Market Case 11/1/2019 Edwardsport CC CT2 I32161 L123 $ $ $ Market Case 12/1/2019 Edwardsport CC CT2 I32161 L124 $ $ $ Market Case 1/1/2020 Edwardsport CC CT2 I32161 L124 $ $ $ Market Case 2/1/2020 Edwardsport CC CT2 I32161 L124 $ $ $ Market Case Edwardsport CC CT2 I32161 L123 Subtotal $ $ $ Market Case Edwardsport CC CT2 I 32161 L124 Subtotal $ $ $

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Market Case 9/1/2019 Edwardsport CC ST I32162 L123 2,485 $ 76,310 $ 86,526 $ {6,760) Market Case 10/1/2019 Edwardsport CC ST I 32162 L123 26,834 $ 631,935 $ 623,118 $ 11,319 Market Case 11/1/2019 Edwardsport CC ST I32162 L123 $ $ $ Market Case 12/1/2019 Edwardsport CC ST I 32162 L124 $ $ $ Market Case 1/1/2020 Edwardsport CC ST I32162 L124 $ $ $ Market Case 2/1/2020 Edwardsport CC ST I 32162 L124 3,420 $ 94,434 $ 114,621 $ {17,383) Market Case Edwardsport CC STI 32162 L123 Subtotal 29,319 $ 708,244 $ 709,643 $ 4,559.22 Market Case Edwardsport CC ST I32162 L124 Subtotal 3,420 $ 94,434 $ 114,621 $ (17,383.06)

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Market Case 9/1/2019 Gibson ST 1 I6456 L123 304,627 $ 7,570,481 $ 7,303,825 $ 269,342 Market Case 10/1/2019 Gibson ST 1 I6456 L123 20,003 $ 544,026 $ 558,062 $ {14,036) Market Case 11/1/2019 Gibson ST 1 I6456 L123 299,597 $ 7,231,576 $ 7,663,274 $ {430,964) Market Case 12/1/2019 Gibson ST 1 I 6456 L124 262,210 $ 6,085,744 $ 6,483,655 $ {393,590) Market Case 1/1/2020 Gibson ST 1 I 6456 L124 94,390 $ 2,311,387 $ 2,599,663 $ (288,239) Market Case 2/1/2020 Gibson ST 1 I 6456 L124 112,256 $ 2,680,246 $ 2,977,307 $ {287,830) Market Case Gibson ST 1 I 6456 L123 Subtotal 624,227 $ 15,346,083 $ 15,525,161 $ {175,658) Market Case Gibson ST 1 I6456 L124 Subtotal 468,856 $ 11,077,376 $ 12,060,625 $ {969,660)

ii I II 'I AEE Ex. 2 Attachment RBS-3 · IURC Cause No. 38707 FAG 123 S1 Page 022 of 055

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Market Case 9/1/2019 Gibson ST 2 I6457 L123 267,343 $ 6,792,609 $ 6,747,751 $ 46,915 Market Case 10/1/2019 Gibson ST 2 I6457 L123 19,341 $ 528,705 $ 548,796 $ (20,092) Market Case 11/1/2019 Gibson ST 2 I6457 L123 229,419 $ 5,596,474 $ 6,054,431 $ (455,702) Market Case 12/1/2019 Gibson ST 2 I 6457 L124 105,535 $ 2,544,143 $ 2,826,546 $ (281,394) Market Case 1/1/2020 Gibson ST 2 I6457 L124 50,866 $ 1,285,102 $ 1,445,363 $ (159,672) Market Case 2/1/2020 Gibson ST 2 I 6457 L124 15,363 $ 403,939 $ 457,155 $ (52,009) Market Case Gibson ST 2 I6457 L123 Subtotal 516,103 $ 12,917,788 $ 13,350,979 $ (428,878) Market Case Gibson ST 2 I6457 L124 Subtotal 171,763 $ 4,233,184 $ 4,729,064 $ (493,075)

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Market Case 9/1/2019 Gibson ST 3 I6458 L123 230,596 $ 5,865,080 $ 5,938,192 $ (70,854) Market Case 10/1/2019 Gibson ST 3 j 6458 L123 19,341 $ 528,705 $ 548,446 $ {19,742) Market Case 11/1/2019 Gibson ST 3 j 6458 L123 200,007 $ 4,902,876 $ 5,324,468 $ (420,707) Market Case 12/1/2019 Gibson ST 3 j 6458 L124 59,824 $ 1,460,054 $ 1,698,391 $ (238,204) Market Case 1/1/2020 Gibson ST 3 I6458 L124 53,033 $ 1,354,432 $ 1,494,372 $ (139,724) Market Case 2/1/2020 Gibson ST 3 I6458 L124 15,934 $ 417,985 $ 470,877 $ (52,635) Market Case Gibson ST 3 I6458 L123 Subtotal 449,945 $ 11,296,661 $ 11,811,106 $ (511,303) Market Case Gibson ST 3 j 6458 Ll24 Subtotal 128,791 $ 3,232,471 $ 3,663,640 $ (430,563)

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Market Case 9/1/2019 Gibson ST 4 j 6459 L123 312,803 $ 7,792,274 $ 7,466,040 $ 328,243 Market Case 10/1/2019 Gibson ST 4 I6459 L123 57,079 $ 1,436,827 $ 1,431,708 $ 5,822 Market Case 11/1/2019 Gibson ST 4 I6459 L123 291,056 $ 7,000,886 $ 7,336,964 $ (334,792) Market Case 12/1/2019 Gibson ST 4 I6459 L124 253,119 $ 5,868,858 $ 6,233,142 $ (361,944)

Market Case 1/1/2020 Gibson ST 4 J 6459 L124 157,949 $ 3,801,552 $ 4,323,249 $ (512,652) Market Case 2/1/2020 Gibson ST 4 I6459 L124 168,682 $ 3,895,430 $ 4,266,678 $ (355,007)

Market Case Gibson ST 4 J 6459 L123 Subtotal 660,938 $ 16,229,988 $ 16,234,712 $ (728)

Market Case Gibson ST 4 J 6459 L124 Subtotal 579,751 $ 13,565,841 $ 14,823,069 $ (1,229,604) AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAG 123 S1 Page 023 of 055

Operating Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Margin Name Month Starting Name Name MWh $ $ $ Market Case 9/1/2019 Gibson ST 5 I 6460 L123 239,313 $ 6,166,298 $ 6,144,118 $ 24,997 Market Case 10/1/2019 Gibson ST 5 I 6460 L123 18,952 $ 518,357 $ 543,849 $ (25,492) Market Case 11/1/2019 Gibson ST 5 I6460 L123 120,182 $ 3,053,223 $ 3,314,207 $ (260,145) Market Case 12/1/2019 Gibson ST 5 I6460 L124 63,935 $ 1,555,711 $ 1,742,082 $ (186,372) Market Case 1/1/2020 Gibson ST 5 I6460 L124 20,979 $ 550,227 $ 613,563 $ (63,335) Market Case 2/1/2020 Gibson ST 5 I 6460 L124 $ $ - $ Market Case Gibson ST 5 I 6460 L123 Subtotal 378,446 $ 9,737,879 $ 10,002,175 $ (260,640) Market Case Gibson ST 5 I 6460 L124 Subtotal 84,914 $ 2,105,938 $ 2,355,645 $ (249,707)

II< AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 024 of 055

Table 9.D: Coal Unit Operating Margin Analysis (L123 Uneconomic Units Retired Case)

Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Operating Margin

Name Month Starting Name Name MWh $ $ $ L123 Uneconomic Units Retired 9/1/2019 Cayuga ST 1 I 6416 L123 $ $ $ $ L123 Uneconomic Units Retired 10/1/2019 Cayuga ST 1 I 6416 L123 $ 120,745 $ 2,611,343 $ 3,832,651 $ (1,221,308.15) L123 Uneconomic Units Retired 11/1/2019 Cayuga ST 1 I 6416 L123 $ 182,639 $ 4,391,160 $ 5,375,744 $ (984,583.92) L123 Uneconomic Units Retired 12/1/2019 Cayuga ST 1 I 6416 L124 $ 109,302 $ 2,522,393 $ 3,482,711 $ (960,317.26) L123 Uneconomic Units Retired 1/1/2020 Cayuga ST 1 I 6416 L124 $ $ $ $ L123 Uneconomic Units Retired 2/1/2020 Cayuga ST 1 I 6416 L124 $ $ $ $ L123 Uneconomic Units Retired Cayuga ST 1 I 6416 L123 Subtotal $ 303,384 $ 7,002,503 $ 9,208,395 $ (2,205,892) L123 Uneconomic Units Retired Cayuga ST 1 I 6416 L124 Subtotal $ 109,302 $ 2,522,393 $ 3,482,711 $ (960,317)

Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Operating Margin

Name Month Starting Name Name MWh $ $ $ L123 Uneconomic Units Retired 9/1/2019 Cayuga ST 2 I 6417 L123 $ $ $ $ L123 Uneconomic Units Retired 10/1/2019 Cayuga ST 2 I 6417 L123 $ $ $ $ L123 Uneconomic Units Retired 11/1/2019 Cayuga ST 2 I 6417 L123 $ $ $ $ L123 Uneconomic Units Retired 12/1/2019 Cayuga ST 2 I 6417 L124 $ $ $ $ L123 Uneconomic Units Retired 1/1/2020 Cayuga ST 2 I 6417 L124 $ $ $ $ L123 Uneconomic Units Retired 2/1/2020 Cayuga ST 2 I 6417 L124 $ $ $ $ L123 Uneconomic Units Retired Cayuga ST 2 I 6417 L123 Subtotal $ $ $ L123 Uneconomic Units Retired Cayuga ST 2 I 6417 L124 Subtotal $ $ $

Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Operating Margin

Name Month Starting Name Name MWh $ $ $ L123 Uneconomic Units Retired 9/1/2019 Edwardsport CC en I 20460 L123 $ $ $ $ L123 Uneconomic Units Retired 10/1/2019 Edwardsport CC en I 20460 L123 $ $ $ $ L123 Uneconomic Units Retired 11/1/2019 Edwardsport CC en I 20460 L123 $ $ $ $ L123 Uneconomic Units Retired 12/1/2019 Edwardsport CC en I 20460 L124 $ $ $ $ L123 Uneconomic Units Retired 1/1/2020 Edwardsport CC en I 20460 L124 $ $ $ $ L123 Uneconomic Units Retired 2/1/2020 Edwardsport CC en I20460 L124 $ $ $ $ L123 Uneconomic Units Retired Edwardsport CC en I 20460 L123 Subtotal $ $ $ L123 Uneconomic Units Retired Edwardsport cc en I 20460 L124 Subtotal $ $ $

,pl JI !l',i AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAG 123 S1 Page 025 of 055

Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Operating Margin

Name Month Starting Name Name MWh $ $ $ L123 Uneconomic Units Retired 9/1/2019 Edwardsport CC CT2 I 32161 L123 $ $ $ $ L123 Uneconomic Units Retired 10/1/2019 Edwardsport CC CT2 I 32161 L123 $ $ $ $ L123 Uneconomic Units Retired 11/1/2019 Edwardsport CC CT2 I 32161 L123 $ $ $ $ Ll23 Uneconomic Units Retired 12/1/2019 Edwardsport CC CT2 I 32161 L124 $ $ $ $ L123 Uneconomic Units Retired 1/1/2020 Edwardsport CC CT2 I 32161 L124 $ $ $ $ L123 Uneconomic Units Retired 2/1/2020 Edwardsport CC CT2 I 32161 L124 $ $ $ $ L123 Uneconomic Units Retired Edwardsport CC CT2 I 32161 L123 Subtotal $ $ $ L123 Uneconomic Units Retired Edwardsport CC CT2 I 32161 L124 Subtotal $ $ $

Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Operating Margin

Name Month Starting Name Name MWh $ $ $ L123 Uneconomic Units Retired 9/1/2019 Edwardsport CC STI 32162 L123 $ $ $ $ L123 Uneconomic Units Retired 10/1/2019 Edwardsport CC STl32162 L123 $ $ $ $ L123 Uneconomic Units Retired 11/1/2019 Edwardsport CC ST I 32162 L123 $ $ $ $ L123 Uneconomic Units Retired 12/1/2019 Edwardsport CC ST I 32162 L124 $ $ $ $ L123 Uneconomic Units Retired 1/1/2020 Edwardsport CC STI 32162 L124 $ $ $ $ L123 Uneconomic Units Retired 2/1/2020 Edwardsport CC STI 32162 L124 $ $ $ $ L123 Uneconomic Units Retired Edwardsport CC STI 32162 Ll23 Subtotal $ $ $ L123 Uneconomic Units Retired Edwardsport CC ST I 32162 L124 Subtotal $ $ $

Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Operating Margin

Name Month Starting Name Name MWh $ $ $ L123 Uneconomic Units Retired 9/1/2019 Gibson ST 1 I 6456 L123 $ 151,045.55 $ 3,770,437.7 $ 4,072,208.6 $ {301,771) L123 Uneconomic Units Retired 10/1/2019 Gibson ST 1 I 6456 L123 $ 142,203.60 $ 3,047,717.6 $ 3,838,848.6 $ {791,131) Ll23 Uneconomic Units Retired 11/1/2019 Gibson ST l I 6456 L123 $ 172,376.78 $ 4,125,740.1 $ 4,525,079.1 $ {399,339) L123 Uneconomic Units Retired 12/1/2019 Gibson ST 1 I 6456 L124 $ 156,004.80 $ 3,571,820.3 $ 4,134,101.2 $ {562,281) L123 Uneconomic Units Retired 1/1/2020 Gibson ST 1 I 6456 L124 $ $ $ $ L123 Uneconomic Units Retired 2/1/2020 Gibson ST 1 I 6456 L124 $ $ $ $ L123 Uneconomic Units Retired Gibson ST 1 I 6456 Ll23 Subtotal 465,626 $ 10,943,895.48 $ 12,436,136,25 $ {1,492,241) L123 Uneconomic Units Retired Gibson ST 1 I 6456 L124 Subtotal 156,005 $ 3,571,820.29 $ 4,134,101.21 $ (562,281)

H !''1 •I AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAG 123 S1 Page 026 of 05.5

Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Operating Margin

Name Month Starting Name Name MWh $ $ $ L123 Uneconomic Units Retired 9/1/2019 Gibson ST 2 I 6457 L123 $ 150,650.90 $ 3,773,638.5 $ 4,034,548.2 $ {260,910) L123 Uneconomic Units Retired 10/1/2019 Gibson ST 2 I 6457 L123 $ 117,769.91 $ 2,505,368.3 $ 3,388,365.5 $ (882,997) L123 Uneconomic Units Retired 11/1/2019 Gibson ST 2 I 6457 L123 $ 170,242.49 $ 4,075,345.8 $ 4,614,549.4 $ (539,204) L123 Uneconomic Units Retired 12/1/2019 Gibson ST 2 I 6457 L124 $ 156,004.80 $ 3,571,820.3 $ 4,192,123.9 $ (620,304) L123 Uneconomic Units Retired 1/1/2020 Gibson ST 2 I 6457 L124 $ $ $ $ L123 Uneconomic Units Retired 2/1/2020 Gibson ST 2 I 6457 L124 $ $ $ $ L123 Uneconomic Units Retired Gibson ST 2 I 6457 L123 Subtotal 438,663 $ 10,354,352.56 $ 12,037,463.04 $ {1,683,110) L123 Uneconomic Units Retired Gibson ST 2 I 6457 L124 Subtotal 156,005 $ 3,571,820.29 $ 4,192,123.95 $ (620,304)

Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Operating Margin

Name Month Starting Name Name MWh $ $ $ L123 Uneconomic Units Retired 9/1/2019 Gibson ST 3 I 6458 L123 $ 150,304.23 $ 3,750,038.9 $ 4,103,723.3 $ (353,684) L123 Uneconomic Units Retired 10/1/2019 Gibson ST 3 I 6458 L123 $ 142,203.60 $ 3,047,717.6 $ 3,889,021.0 $ (841,303) L123 Uneconomic Units Retired 11/1/2019 Gibson ST 3 I 6458 L123 $ 162,324.40 $ 3,885,706.0 $ 4,398,628.6 $ {512,923) L123 Uneconomic Units Retired 12/1/2019 Gibson ST 3 I 6458 L124 $ 156,004.80 $ 3,571,820.3 $ 4,188,103.6 $ {616,283) L123 Uneconomic Units Retired 1/1/2020 Gibson ST 3 I 6458 L124 $ $ $ $ L123 Uneconomic Units Retired 2/1/2020 Gibson ST 3 I 6458 L124 $ $ $ $ L123 Uneconomic Units Retired Gibson ST 3 I 6458 Ll23 Subtotal 454,832 $ 10,683,462.57 $ 12,391,372.94 $ (1,707,910) L123 Uneconomic Units Retired Gibson ST 3 I 6458 L124 Subtotal 156,005 $ 3,571,820.29 $ 4,188,103.64 $ (616,283)

Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Operating Margin

Name Month Starting Name Name MWh $ $ $ L123 Uneconomic Units Retired 9/1/2019 Gibson ST 4 I 6459 L123 $ 141,133.96 $ 3,560,221.6 $ 3,717,606.5 $ (157,385) L123 Uneconomic Units Retired 10/1/2019 Gibson ST 4 I 6459 L123 $ 135,411.66 $ 2,900,519.2 $ 3,803,402.4 $ {902,883) L123 Uneconomic Units Retired 11/1/2019 Gibson ST 4 I 6459 L123 $ 170,205.11 $ 4,073,762.3 $ 4,451,587.8 $ {377,826) L123 Uneconomic Units Retired 12/1/2019 Gibson ST 416459 L124 $ 140,257.07 $ 3,219,413.6 $ 3,784,918.1 $ (565,504) Ll23 Uneconomic Units Retired 1/1/2020 Gibson ST 4 I 6459 L124 $ $ $ $ L123 Uneconomic Units Retired 2/1/2020 Gibson ST 4 I 6459 L124 $ $ $ $ L123 Uneconomic Units Retired Gibson ST 4 I 6459 L123 Subtotal 446,751 $ 10,534,503.05 $ 11,972,596.63 $ (1,438,094) L123 Uneconomic Units Retired Gibson ST 4 I 6459 L124 Subtotal 140,257 $ 3,219,413.64 $ 3,784,918.07 $ {565,504) AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAG 123 S1 Page 027 of 055

Scenario Month Unit FAC Period Production Energy Revenue Operating Cost Operating Margin

Name Month Starting Name Name MWh $ $ $ L123 Uneconomic Units Retired 9/1/2019 Gibson ST 5 I 6460 L123 $ 155,663.81 $ 3,890,856.0 $ 4,131,531.7 $ {240,676) L123 Uneconomic Units Retired 10/1/2019 Gibson ST 5 I 6460 L123 $ 134,296.41 $ 2,886,708.2 $ 3,801,078.5 $ (914,370) L123 Uneconomic Units Retired 11/1/2019 Gibson ST 5 I 6460 L123 $ 169,662.19 $ 4,060,767.8 $ 4,571,609.0 $ (510,841) L123 Uneconomic Units Retired 12/1/2019 Gibson ST 5 I 6460 L124 $ 153,548.03 $ 3,515,571.2 $ 4,176,645.8 $ (661,075) L123 Uneconomic Units Retired 1/1/2020 Gibson ST 5 I 6460 L124 $ $ $ $ L123 Uneconomic Units Retired 2/1/2020 Gibson ST 5 I 6460 L124 $ $ $ $ L123 Uneconomic Units Retired Gibson ST 5 I 6460 L123 Subtotal 459,622 $ 10,838,332.05 $ 12,504,219.14 $ (1,665,887) L123 Uneconomic Units Retired Gibson ST 5 I 6460 Ll24 Subtotal 153,548 $ 3,515,571.15 $ 4,176,645.83 $ (661,075)

),! 11 " AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 028 of 055

Table 9.E: Total Coal Unit Operating Margin Analysis Summary

Total Coal Units Total Operating Losses Attributable Operating Margin all Margin all Units to Uneconomic Losses Attributable to Units Base Case$ Market Case $ Dispatch$ Uneconomic Dispatch % L123 Subtotal (20,572,065) (1,372,648) (19,199,417) 93% L124 Subtotal (24,926,776) (3,389,991) (21,536,785) 86%

Total Coal Units Operating Losses all Operating Margin all Total Revenues from Units excl. Ancillary Units Market Case $ Ancillary Services $ Services$ L123 Subtotal (1,372,648) 24,485 (1,397,133) L124 Subtotal (3,389,991) 47,428 (3,437,419)

flj•·! AEE Ex, 2 Alteohmenl RBS-3 IURC Cause No, 38707 FAC 123 s11t Page 029 of 055

Table 10.A: Operating Margin Analysis for 2025 Scenarios Amount Received Amount Paid for DEi Generator Net Market Operating Cost All O 1 . d Wh Load Weighted Total Cost to Serve Case Month DEi Coal DEi Other for DEi Power DEi Power t Replacement Weighted LMP Revenue Units pera ng Margin Loa M LMP Native Load Generated Purchased Name M/D/YYYY MWh MWh MWh $/MWh $ $ $ $ $ MWh $/MWh $ 2025 Advanced Case I 1/1/2025 1,464,871 145,439 517,605 $ 28.92 $ 62,760,230 $ 45,650,748 $ 17,109,481 $ 49,201,909 $ (32,092,427) 3,640,743 $ 30.18 $ 94,852,657 2025 Advanced Case I 2/1/2025 1,299,566 134,195 376,579 $ 27.31 $ 50,161,946 $ 35,040,230 $ 15,121,717 $ 41,070,829 $ (25,949,112) 3,042,490 $ 28.44 $ 76,111,059 2025 Advanced Case I 3/1/2025 1,440,938 196,991 511,484 $ 26.82 $ 58,223,568 $ 31,862,339 $ 26,361,229 $ 47,186,016 $ (20,824,787) 3,292,285 $ 27.88 $ 79,048,355 2025 Advanced Case I 4/1/2025 1,402,513 212,530 339,017 $ 26.72 $ 53,171,361 $ 29,423,327 $ 23,748,034 $ 40,862,965 $ (17,114,951) 3,017,490 $ 27.67 $ 70,286,312 2025 Advanced Case I 5/1/2025 1,134,463 204,152 450,330 $ 25.31 $ 46,055,877 $ 38,181,841 $ 7,874,036 $ 37,365,525 $ (29,491,489) 3,245,216 $ 26.22 $ 75,547,366 2025 Advanced Case I 6/1/2025 908,499 212,665 599,921 $ 27.31 $ 49,327,563 $ 51,283,366 $ (1,955,803) $ 36,819,796 $ (38,775,600) 3,532,129 $ 28.32 $ 88,103,162 2025 Advanced Case I 7/1/2025 1,335,562 192,872 671,926 $ 31.31 $ 73,967,750 $ 52,857,437 $ 21,110,312 $ 49,447,972 $ (28,337,660) 3,821,439 $ 32.61 $ 102,305,409 2025 Advanced Case I 8/1/2025 942,525 166,317 609,114 $ 28.29 $ 51,426,799 $ 53,869,891 $ (2,443,092) $ 39,014,952 $ (41,458,044) 3,556,398 $ 29.30 $ 92,884,843 2025 Advanced Case I 9/1/2025 779,756 142,617 612,093 $ 26.95 $ 42,813,185 $ 50,001,496 $ (7,188,311) $ 33,383,381 $ (40,571,692) 3,326,344 $ 27.90 $ 83,384,877 2025 Advanced Case J 10/1/2025 759,641 185,375 609,374 $ 26.05 $ 41,123,879 $ 44,955,078 $ (3,831,199) $ 33,853,945 $ (37,685,143) 3,225,250 $ 26.91 $ 78,809,023 2025 Advanced Case I 11/1/2025 1,023,894 114,381 633,556 $ 29.87 $ 53,922,038 $ 44,522,937 $ 9,399,101 $ 41,237,891 $ (31,838,790) 3,212,125 $ 30.91 $ 85,760,828 2025 Advanced Case l 12/1/2025 859,614 124,555 339,114 $ 31.49 $ 42,400,815 $ 77,189,680 $ (34,788,865) $ 31,437,006 $ {66,225,870) 3,682,628 $ 32.72 $ 108,626,686 2025 Advanced case I Total (LMPs = Average} 13,351,843 2,032,289 6,270,113 $ 28.03 $ 625,355,011 $ 554,838,371 $ 70,516,640 $ 480,882,207 $ (410,365,567) 40,594,539 $ 29.09 $ 1,035,720,578

Amount Received Amount Paid for Generator Total Cost to Serve Case Month DEi Coal DEi Replacement DEi Other for DEi Power DEi Power Market Revenue Operating Co~:~~ Operating Margin Load MWh Load Weig~:: Weighted LMP Native Load Generated Purchased Name M/D/YYYY MWh MWh MWh $/MWh $ $ $ $ $ MWh $/MWh $ 2025 Advanced Case JI 1/1/2025 1,373,791 522.130 $ 29.25 56,079,651 52,983,301 $ 3,096,350 23,616,347 $ (20,519,997) 3,640,743 $ 30.37 $ 76,599,648 2025 Advanced Case II 2/1/2025 1,236,993 320,681 $ 27.69 43,343,656 42,628,576 $ 715,080 16,332,802 $ (15,617,722) 3,042,490 $ 28.71 $ 58,961,378 2025 Advanced Case II 3/1/2025 1,710,767 530,538 $ 26.81 61,127,921 29,218,764 $ 31,909,156 21,353,577 $ 10,555,579 3,292,285 $ 27.80 $ 50,572,342 2025 Advanced Case II 4/1/2025 1,849,494 394,398 $ 26.14 59,725,011 20,936,493 $ 38,788,517 17,485,367 $ 21,303,151 3,017,490 $ 27.06 $ 38,421,860 2025 Advanced Case II 5/1/2025 1,794,963 430,033 $ 25.11 57,400,700 26,557,695 $ 30,842,806 17,455,503 $ 13,387,303 3,245,216 $ 26.03 $ 44,013,398 2025 Advanced Case II 6/1/2025 1,839,715 597,195 $ 27.06 69,989,145 30,862,027 $ 39,127,118 21,404,476 $ 17,722,642 3,532,129 $ 28.18 $ 52,266,502 2025 Advanced Case II 7/1/2025 1,714,467 637,169 $ 30.60 79,590,429 47,135,600 $ 32,454,628 24,386,135 $ 6,066,493 3,821,439 $ 32.07 $ 71,523,935 2025 Advanced Case II 8/1/2025 1,514,571 594,672 $ 27.57 62,429,209 41,448,680 $ 20,980,529 22,164,064 $ (1,163,535) 3,556,396 $ 28.64 $ 63,612,744 2025 Advanced Case II 9/1/2025 1,338,508 554,558 $ 27,15 53,324,067 40,270,940 $ 13,053,128 19,698,169 $ (6,645,041) 3,326,344 $ 28.10 $ 59,969,109 2025 Advanced Case II 10/1/2025 1,678,097 537,217 $ 26.43 59,441,710 27,636,219 $ 31,805,490 20,272,617 $ 11,532,874 3,225,250 $ 27.36 $ 47,908,836 2025 Advanced Case II 11/1/2025 1,188,245 645,796 $ 29.89 55,077,424 42,515,564 $ 12,561,860 24,654,191 $ (12,092,331) 3,212,125 $ 30.85 $ 67,169,755 2025 Advanced Case II 12/1/2025 1,262,518 330,647 $ 31.27 49,979,327 67,756,703 $ (17,777,376) 18,590,191 $ (36,367,567) 3,682,628 $ 32.43 $ 86,346,894 2025 Advanced Case JI Total (LMPs = Average) 18,502,129 6,095,235 $ 27.93 $ 707,506,249 $ 469,950,962 $ 237,557,288 $ 247,415,439 $ (9,656,151) 40,594,539 $ 26.97 $ 717,366,401

Amount Received Amount Paid for Generator Lo d MWh Load Weighted Total Cost to Serve Case Month DEi Coal DEi Replacement DEi Other for DEi Power DEi Power Market Revenue Operating Co~:~~ Operating Margin Weighted LMP a LMP Native Load Generated Purchased Name M/O/YYYY MWh MWh MWh $/MWh $ $ $ $ $ MWh $/MWh $ 2025 Base Case 1/1/2025 1,712,708 493,407 $ 28.73 64,460,498 43,002,094 $ 21,458,404 58,058,561 $ (36,600,157) 3,640,743 29.97 $ 101,060,655 2025 Base Case 2/1/2025 1,540,016 351,637 $ 27.60 52,871,198 33,075,230 $ 19,795,968 49,568,480 $ (29,772,512) 3,042,490 28.75 $ 82,643,710 2025 Base Case 3/1/2025 1,700,462 496,422 $ 27.13 60,193,031 30,647,961 $ 29,345,050 56,717,353 $ (27,372,302) 3,292,285 28.21 $ 87,565,334 2025 Base Case 4/1/2025 263,767 414,556 $ 27.76 19,451,835 66,543,959 $ (47,092,124) 23,108,504 $ (70,200,629) 3,017,490 28.45 $ 89,652,464 2025 Base Case 5/1/2025 969,303 476,159 $ 25.65 37,232,358 47,715,003 $ (10,482,645) 38,667,089 $ (49,349,734) 3,245,216 26.51 $ 86,582,092 2025 Base Case 6/1/2025 1,057,319 615,251 $ 27.76 46,334,560 53,498,577 $ (5,164,017) 44,962,915 $ (50,126,932) 3,532,129 26.77 $ 98,461,492 2025 Base Case 7/1/2025 1,614,653 647,976 $ 31.63 76,059,356 51,336,163 $ 24,723,193 59,809,617 $ (35,086,424) 3,821,439 32.94 $ 111,145,780 2025 Base Case 8/1/2025 1,173,271 620,612 $ 28.10 52,617,360 51,319,036 $ 1,298,323 46,506,706 $ (47,206,362) 3,556,398 29.12 $ 99,825,742 2025 Base case 9/1/2025 711,992 604,614 $ 27.11 37,083,352 56,364,260 $ (19,280,907) 34,374,166 $ (53,655,076) 3,326,344 26.05 $ 90,738,428 2025 Base Case 10/1/2025 944,645 621,652 $ 26.67 42,215,441 45,668,074 $ (3,452,633) 42,163,065 $ (45,615,698) 3,225,250 27.53 $ 87,831,139 2025 Base Case 11/1/2025 1,232,648 647,701 $ 30.00 57,313,239 41,294,140 $ 161019,098 50,615,750 $ (34,596,652) 3,212,125 31.01 $ 91,909,890 2025 Base Case 12/1/2025 1,079,803 322,096 $ 31.18 44,556,191 73,965,168 $ (29,408,977) 39,673,615 $ (69,082,592) 3,682,628 32.43 $ 113,638,783 2025 Base Case Total (LMPs =Average) 14,000,808 6,314,483 $ 28.26 $ 592,388,419 $ 594,629,665 $ (2,241,267) $ 546,425,823 $ (548,667,090) 40,594,539 $ 29.31 $ 1,141,055,509 AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S' Page 030 of 055

Table 10.B: Coal Unit Operating Margin Analysis for 2025 Scenarios Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I 1/1/2025 Cayuga ST 1 [ 6416 200,342 5,976,026 5,560,620 $ 415,406 2025 Advanced Case I 2/1/2025 Cayuga ST 1 [ 6416 161,168 4,517,179 4,496,176 $ 21,003

2025 Advanced Case I 3/1/2025 Cayuga ST 1 J 6416 169,263 4,593,602 4,732,336 $ (138,734) 2025 Advanced Case I 4/1/2025 Cayuga ST 1 [ 6416 106,336 2,887,929 3,207,408 $ (319,479)

2025 Advanced Case I 5/1/2025 Cayuga ST 1 J 6416 118,699 3,059,896 3,524,900 $ (465,004) 2025 Advanced Case I 6/1/2025 Cayuga ST 1 [ 6416 123,810 3,496,673 3,602,388 $ (105,714)

2025 Advanced Case I 7/1/2025 Cayuga ST 1 J 6416 217,544 7,193,873 5,891,764 $ 1,302,109 2025 Advanced Case I 8/1/2025 Cayuga ST 1 [ 6416 177,947 5,257,960 4,948,574 $ 309,387

2025 Advanced Case I 9/1/2025 Cayuga ST 1 J 6416 $

2025 Advanced Case I 10/1/2025 Cayuga ST 1 J 6416 99,237 2,633,963 3,135,736 $ (501,773) 2025 Advanced Case I 11/1/2025 Cayuga ST 1 [ 6416 182,639 5,549,963 5,029,494 $ 520,468

2025 Advanced Case I 12/1/2025 Cayuga ST 1 J 6416 132,180 4,211,304 3,846,815 $ 364,489

2025 Advanced Case I Cayuga ST 1 J 6416 1,689,165 49,378,368 47,976,211 1,402,158

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I 1/1/2025 Cayuga ST 2 I 6417 $ 2025 Advanced Case I 2/1/2025 Cayuga ST 2 [ 6417 $

2025 Advanced Case I 3/1/2025 Cayuga ST 2 J 6417 $ 2025 Advanced Case I 4/1/2025 Cayuga ST 2 I 6417 $ 2025 Advanced Case I 5/1/2025 Cayuga ST 2 I 6417 $ 2025 Advanced Case I 6/1/2025 Cayuga ST 2 I 6417 $

2025 Advanced Case I 7/1/2025 Cayuga ST 2 J 6417 $

2025 Advanced Case I 8/1/2025 Cayuga ST 2 J 6417 $

2025 Advanced Case I 9/1/2025 Cayuga ST 2 J 6417 $ 2025 Advanced Case I 10/1/2025 Cayuga ST 2 I 6417 $ 2025 Advanced Case I 11/1/2025 Cayuga ST 2 I 6417 $ 2025 Advanced Case I 12/1/2025 Cayuga ST 2 I 6417 $

2025 Advanced Case I Cayuga ST 2 J 6417 AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S 1 Page 031 of 055

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I 1/1/2025 Edwardsport CC CTl I 20460 $ 2025 Advanced Case I 2/1/2025 Edwardsport CC CTl I 20460 $ 2025 Advanced Case I 3/1/2025 Edwardsport CC CTl [ 20460 $ 2025 Advanced Case I 4/1/2025 Edwardsport CC CTl I 20460 $ 2025 Advanced Case I 5/1/2025 Edwardsport CC CTl I 20460 $ 2025 Advanced Case I 6/1/2025 Edwardsport CC CTl I 20460 $ 2025 Advanced Case I 7/1/2025 Edwardsport CC CTl I 20460 $ 2025 Advanced Case I 8/1/2025 Edwardsport CC CTl I 20460 $ 2025 Advanced Case I 9/1/2025 Edwardsport CC CTl I 20460 $ 2025 Advanced Case I 10/1/2025 Edward sport CC CTl I 20460 $ 2025 Advanced Case I 11/1/2025 Edward sport CC CTl I 20460 $ 2025 Advanced Case I 12/1/2025 Edwardsport CC CTl I 20460 $ 2025 Advanced Case I Edwardsport CC CTl [ 20460

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I 1/1/2025 Edwardsport CC CT2 I 32161 $ 2025 Advanced Case I 2/1/2025 Edwardsport CC CT2 I 32161 $ 2025 Advanced Case I 3/1/2025 Edwardsport CC CT2 [ 32161 $ 2025 Advanced Case I 4/1/2025 Edwardsport CC CT2 [ 32161 $ 2025 Advanced Case I 5/1/2025 Edwardsport CC CT2 I 32161 $ 2025 Advanced Case I 6/1/2025 Edwardsport CC CT2 [ 32161 $ 2025 Advanced Case I 7/1/2025 Edwardsport CC CT2 I 32161 $ 2025 Advanced Case I 8/1/2025 Edwardsport CC CT2 [32161 $ 2025 Advanced Case I 9/1/2025 Edwardsport CC CT2 [32161 $ 2025 Advanced Case I 10/1/2025 Edwardsport CC CT2 I 32161 $ 2025 Advanced Case I 11/1/2025 Edwardsport CC CT2 [ 32161 $ 2025 Advanced Case I 12/1/2025 Edwardsport CC CT2 [ 32161 $ 2025 Advanced Case I Edwardsport CC CT2 I 32161

,I 11 11- '-I AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 032 of 055

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I 1/1/2025 Edwardsport CC ST I 32162 $ 2025 Advanced Case I 2/1/2025 Edwardsport CC ST I 32162 $ 2025 Advanced Case I 3/1/2025 Edwardsport CC ST I 32162 $ 2025 Advanced Case I 4/1/2025 Edwardsport CC ST I 32162 $ 2025 Advanced Case I 5/1/2025 Edwardsport CC STI 32162 $ 2025 Advanced Case I 6/1/2025 Edwardsport CC ST I 32162 $ 2025 Advanced Case I 7/1/2025 Edwardsport CC ST I 32162 $ 2025 Advanced Case I 8/1/2025 Edwardsport CC ST I 32162 $ 2025 Advanced Case I 9/1/2025 Edwardsport CC ST I 32162 $ 2025 Advanced Case I 10/1/2025 Edwardsport CC ST I 32162 $ 2025 Advanced Case I 11/1/2025 Edwardsport CC ST I 32162 $ 2025 Advanced Case I 12/1/2025 Edwardsport CC STI 32162 $ 2025 Advanced Case I Edwardsport CC ST I 32162

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I 1/1/2025 Gibson ST 1 I 6456 262,408 7,612,320 6,120,014 $ 1,492,305 2025 Advanced Case I 2/1/2025 Gibson ST 1 I6456 228,4'.l.8 6,227,772 5,405,132 $ 822,640 2025 Advanced Case I 3/1/2025 Gibson ST 1 I 6456 260,465 6,994,873 6,126,197 $ 868,677 2025 Advanced Case I 4/1/2025 Gibson ST 1 I 6456 251,469 6,723,353 5,899,802 $ 823,551 2025 Advanced Case I 5/1/2025 Gibson ST 1 I 6456 218,993 5,591,850 5,232,478 $ 359,372 2025 Advanced Case I 6/1/2025 Gibson ST 1 I 6456 163,214 4,540,893 4,070,214 $ 470,679 2025 Advanced Case I 7/1/2025 Gibson ST 1 I 6456 230,800 7,496,925 5,473,354 $ 2,023,571 2025 Advanced Case I 8/1/2025 Gibson ST 116456 157,459 4,592,833 3,977,554 $ 615,279 2025 Advanced Case I 9/1/2025 Gibson ST 1 I 6456 159,157 4,394,138 4,046,982 $ 347,157 2025 Advanced Case I 10/1/2025 Gibson ST 1 I 6456 136,237 3,595,699 3,587,783 $ 7,916 2025 Advanced Case I 11/1/2025 Gibson ST 1 I 6456 172,377 5,145,258 4,257,071 $ 888,187 2025 Advanced Case I 12/1/2025 Gibson ST 1 I 6456 118,688 3,611,619 3,153,441 $ 458,178 2025 Advanced Case I Gibson ST 1 l6456 2,359,686 66,527,533 57,350,022 9,177,511 AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 033 of 055

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I 1/1/2025 Gibson ST 2 I 6457 262,408 7,612,320 6,203,895 $ 1,408,424 2025 Advanced Case I 2/1/2025 Gibson ST 2 I 6457 220,233 5,956,410 5,204,804 $ 751,606 2025 Advanced Case I 3/1/2025 Gibson ST 2 I6457 261,560 7,024,594 6,312,445 $ 712,149 2025 Advanced Case I 4/1/2025 Gibson ST 2 I6457 269,840 7,248,708 6,331,402 $ 917,305 2025 Advanced Case I 5/1/2025 Gibson ST 2 I6457 218,993 5,591,850 5,304,352 $ 287,497 2025 Advanced Case I 6/1/2025 Gibson ST 2 I 6457 157,184 4,371,905 3,976,596 $ 395,309 2025 Advanced Case I 7/1/2025 Gibson ST 2 I6457 221,760 7,298,761 5,410,197 $ 1,888,565 2025 Advanced Case I 8/1/2025 Gibson ST 2 I 6457 153,674 4,502,257 4,091,093 $ 411,161 2025 Advanced Case I 9/1/2025 Gibson ST 2 I 6457 157,577 4,326,375 4,062,559 $ 263,816 2025 Advanced Case I 10/1/2025 Gibson ST 2 I6457 135,040 3,576,533 3,686,058 $ (109,525) 2025 Advanced Case I 11/1/2025 Gibson ST 2 I6457 160,495 4,865,270 4,019,936 $ 845,334 2025 Advanced Case I 12/1/2025 Gibson ST 2 I6457 158,318 4,984,172 4,115,518 $ 868,654 2025 Adva need Case I Gibson ST 2 I6457 2,377,083 67,359,154 58,718,855 8,640,299

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margi;n Name Month Starting Name MWh $ $ $ 2025 Advanced Case I 1/1/2025 Gibson ST 3 I6458 251,416 7,303,101 6,019,135 $ 1,283,966 2025 Advanced Case I 2/1/2025 Gibson ST 3 I6458 237,293 6,484,783 5,602,727 $ 882,056 2025 Advanced Case I 3/1/2025 Gibson ST 3 I6458 264,274 7,043,365 6,213,752 $ 829,613 2025 Advanced Case I 4/1/2025 Gibson ST 3 I 6458 242,835 6,448,365 5,777,420 $ 670,945 2025 Advanced Case I 5/1/2025 Gibson ST 3 I64S8 186,852 4,737,993 4,610,486 $ 127,507 2025 Advanced Case I 6/1/2025 Gibson ST 3 I 6458 163,214 4,540,893 4,122,723 $ 418,170 2025 Advanced Case I 7/1/2025 Gibson ST 3 I6458 217,304 7,085,975 5,297,951 $ 1,788,024 2025 Advanced Case I 8/1/2025 Gibson ST 3 I6458 157,459 4,592,833 4,028,923 $ 563,910 2025 Advanced Case I 9/1/2025 Gibson ST 3 I6458 163,065 4,507,990 4,119,645 $ 388,345 2025 Advanced Case I 10/1/2025 Gibson ST 3 I 6458 124,321 3,289,583 3,403,273 $ (113,689) 2025 Advanced Case I 11/1/2025 Gibson ST 3 I 6458 172,377 5,145,258 4,311,945 $ 833,313 2025 Advanced Case I 12/1/2025 Gibson ST 3 I6458 161,293 5,060,066 4,108,104 $ 951,961 2025 Advanced Case I Gibson ST 3 j 6458 2,341,703 66,240,205 57,616,084 8,624,121

'I" AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 034 of 055

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I 1/1/2025 Gibson ST 4 I 6459 259,102 7,516,416 6,021,042 $ 1,495,374 2025 Advanced Case I 2/1/2025 Gibson ST 4 I 6459 234,303 6,403,085 5,442,322 $ 960,763 2025 Advanced Case I 3/1/2025 Gibson ST 4 I 6459 243,588 6,416,539 5,789,727 $ 626,812 2025 Advanced Case I 4/1/2025 Gibson ST 416459 266,441 7,157,385 6,144,869 $ 1,012,517 2025 Advanced Case I 5/1/2025 Gibson ST 4 I 6459 216,234 5,521,401 5,147,803 $ 373,598 2025 Advanced Case I 6/1/2025 Gibson ST 4 I 6459 150,504 4,231,870 3,739,145 $ 492,725 2025 Advanced Case I 7/1/2025 Gibson ST 4 I 6459 227,893 7,402,475 5,384,799 $ 2,017,676 2025 Advanced Case I 8/1/2025 Gibson ST 4 I 6459 153,040 4,476,738 3,929,560 $ 547,178 2025 Advanced Case I 9/1/2025 Gibson ST 416459 155,917 4,302,034 3,950,554 $ 351,480 2025 Advanced Case I 10/1/2025 Gibson ST 4 I 6459 140,412 3,698,578 3,607,004 $ 91,574 2025 Advanced Case I 11/1/2025 Gibson ST 4 I 6459 170,205 5,080,436 4,188,124 $ 892,312 2025 Advanced Case I 12/1/2025 Gibson ST 4 I 6459 130,382 4,078,820 3,340,480 $ 738,339 2025 Advanced Case I Gibson ST 4 I 6459 2,348,021 66,285,777 56,685,429 9,600,348

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I 1/1/2025 Gibson ST 5 I 6460 229,194 6,694,499 5,645,562 $ 1,048,938 2025 Advanced Case I 2/1/2025 Gibson ST 5 I 6460 218,153 5,996,470 5,295,442 $ 701,028 2025 Advanced Case I 3/1/2025 Gibson ST 5 I 6460 241,788 6,396,809 5,994,895 $ 401,914 2025 Advanced Case I 4/1/2025 Gibson ST 5 I 6460 265,591 7,134,555 6,307,895 $ 826,660 2025 Advanced Case I 5/1/2025 Gibson ST 5 I 6460 174,690 4,392,080 4,371,349 $ 20,732 2025 Advanced Case I 6/1/2025 Gibson ST 5 I 6460 150,573 4,218,462 3,928,353 $ 290,109 2025 Advanced Case I 7/1/2025 Gibson ST 5 I 6460 220,260 7,186,297 5,358,537 $ 1,827,760 2025 Advanced Case I 8/1/2025 Gibson ST 5 I 6460 142,946 4,134,095 3,786,534 $ 347,561 2025 Advanced Case I 9/1/2025 Gibson ST 5 I 6460 144,039 3,988,021 3,771,841 $ 216,180 2025 Advanced Case I 10/1/2025 Gibson ST 5 I 6460 124,394 3,275,337 3,380,707 $ (105,369) 2025 Advanced Case I 11/1/2025 Gibson ST 5 I 6460 165,802 4,953,947 4,281,340 $ 672,607 2025 Advanced Case I 12/1/2025 Gibson ST 516460 158,753 4,980,380 4,096,775 $ 883,604 2025 Advanced Case I Gibson ST 5 I 6460 2,236,183 63,350,951 56,219,229 7,131,722

t-iH AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAG 123 si Page 035 of 055

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Base Case 1/1/2025 Cayuga ST 1 I 6416 174,215 5,175,893 4,785,522 $ 390,371 2025 Base Case 2/1/2025 Cayuga ST 1 I 6416 167,041 4,679,135 4,655,907 $ 23,228 2025 Base Case 3/1/2025 Cayuga ST 1 I6416 154,394 4,237,931 4,428,146 $ (190,215) 2025 Base Case 4/1/2025 Cayuga ST 1 I6416 21,250 587,376 1,153,313 $ (565,938) 2025 Base Case 5/1/2025 Cayuga ST 1 I6416 112,702 2,942,852 3,419,560 $ (476,708) 2025 Base Case 6/1/2025 Cayuga ST 1 I6416 127,681 3,658,560 3,717,116 $ (58,556) 2025 Base Case 7/1/2025 Cayuga ST 1 I6416 209,359 7,018,223 5,740,463 $ 1,277,760 2025 Base Case 8/1/2025 Cayuga ST 1 I 6416 193,190 5,647,640 5,304,395 $ 343,245 2025 Base Case 9/1/2025 Cayuga ST 1 I6416 $ 2025 Base Case 10/1/2025 Cayuga ST 1 I6416 120,932 3,262,489 3,700,359 $ (437,870) 2025 Base Case 11/1/2025 Cayuga ST 1 I6416 182,639 5,567,238 5,029,494 $ 537,744 2025 Base Case 12/1/2025 Cayuga ST 1 I6416 132,180 4,190,862 3,846,815 $ 344,046 2025 Base Case Cayuga ST 1 I6416 1,595,583 46,968,197 45,781,091 1,187,106

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Base Case 1/1/2025 Cayuga ST 2 I6417 217,805 6,363,383 6,096,836 $ 266,547 2025 Base Case 2/1/2025 Cayuga ST 2 I6417 142,756 4,004,743 4,130,041 $ (125,299) 2025 Base Case 3/1/2025 Cayuga ST 2 I6417 156,562 4,316,816 4,533,369 $ (216,552) 2025 Base Case 4/1/2025 Cayuga ST 2 I 6417 45,854 1,283,418 1,820,790 $ (537,371) 2025 Base Case 5/1/2025 Cayuga ST 2 I6417 77,244 1,968,750 2,686,951 $ (718,201) 2025 Base Case 6/1/2025 Cayuga ST 2 I 6417 126,417 3,613,166 3,811,440 $ (198,275) 2025 Base Case 7/1/2025 Cayuga ST 2 I6417 215,390 7,171,489 6,039,519 $ 1,131,970 2025 Base Case 8/1/2025 Cayuga ST 2 I 6417 164,091 4,848,431 4,725,740 $ 122,692 2025 Base Case 9/1/2025 Cayuga ST 216417 $ 2025 Base Case 10/1/2025 Cayuga ST 2 I6417 106,484 2,882,166 3,385,567 $ (503,40:i) 2025 Base Case 11/1/2025 Cayuga ST 2 I6417 180,830 5,490,937 5,155,974 $ 334,964 2025 Base Case 12/1/2025 Cayuga ST 2 I6417 118,249 3,739,433 3,626,715 $ 112,719 2025 Base Case Cayuga SI_ll 6417 1,551,682 45,682,732 46,012,940 ___ (330,208)

" ' I ·1 1·1 AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAG 123 S1 Page 036 of 055

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Base Case 1/1/2025 Edwardsport CC en I 20460 15,341 448,293 1,492,609 $ (1,044,316) 2025 Base Case 2/1/2025 Edwardsport CC en I 20460 17,004 474,821 1,450,800 $ (975,980) 2025 Base Case 3/1/2025 Edward sport cc en I 20460 15,504 424,471 1,484,712 $ (1,060,242} 2025 Base Case 4/1/2025 Edward sport CC en I 20460 16,589 468,182 1,501,270 $ (1,033,087) 2025 Base Case 5/1/2025 Edwardsport cc en I 20460 4,619 122,095 1,110,989 $ (988,893) 2025 Base Case 6/1/2025 Edwardsport cc en I 20460 10,546 301,934 1,304,260 $ {1,002,326) 2025 Base Case 7/1/2025 Edwardsport cc en I 20460 17,685 587,447 1,569,044 $ (981,597) 2025 Base Case 8/1/2025 Edward sport CC en I 20460 12,504 365,109 1,400,087 $ (1,034,979) 2025 Base Case 9/1/2025 Edward sport CC en I 20460 8,063 227,247 1,200,569 $ (973,322) 2025 Base Case 10/1/2025 Edward sport CC en I 20460 4,450 120,367 1,137,157 $ (1,016,791) 2025 Base Case 11/1/2025 Edwardsport CC en I 20460 19,563 593,288 1,598,233 $ (1,004,945) 2025 Base Case 12/1/2025 Edwardsport CC en I 20460 8,233 260,239 1,252,979 $ {992,741) 2025 Base Case Edwardsport_(_( cnJ ~0460 150,101 4,393,493 16,502,711 {12,109,2181

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Base Case 1/1/2025 Edward sport CC CT2 I 32161 14,463 420,569 1,326,954 $ {906,385) 2025 Base Case 2/1/2025 Edwardsport CC CT2 I 32161 17,004 474,821 1,375,431 $ (900,610) 2025 Base Case 3/1/2025 Edwardsport CC CT2 I 32161 15,696 428,243 1,424,453 $ {996,210) 2025 Base Case 4/1/2025 Edwardsport CC CT2 l32161 16,589 468,182 1,423,143 $ (954,96~) 2025 Base Case 5/1/2025 Edwardsport CC CT2 I 32161 4,702 124,025 1,085,024 $ (960,999} 2025 Base Case 6/1/2025 Edwardsport CC CT2 I 32161 10,546 301,934 1,235,868 $ (933,934) 2025 Base Case 7/1/2025 Edwardsport CC CT2 I 32161 16,921 563,162 1,437,171 $ (874,009) 2025 Base Case 8/1/2025 Edwardsport CC CT2 I 32161 12,504 365,109 1,326,828 $ {961,719) 2025 Base Case 9/1/2025 Edwardsport CC CT2 I 32161 8,193 230,459 1,139,945 $ (909,486) 2025 Base Case 10/1/2025 Edwardsport CC CT2 I 32161 4,461 122,663 1,077,235 $ (954,572) 2025 Base Case 11/1/2025 Edwardsport CC CT2 I 32161 18,239 562,187 1,435,078 $ (872,891} 2025 Base Case 12/1/2025 Edwardsport CC CT2 I 32161 7,374 231,204 1,049,107 $ {817,904) 2025 Base Case Edwardsport CC CT2 I 32161 146,692 4,292,558 15,336,238 (11,043,680)

,n1 11 fl''! 1: AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 037 of 055

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Base Case 1/1/2025 Edwardsport CC ST I 32162 21,421 626,782 1,552,018 $ (925,235) 2025 Base Case 2/1/2025 Edwardsport CC ST I 32162 23,836 665,585 1,490,369 $ (824,784) 2025 Base Case 3/1/2025 Edwardsport CC ST I 32162 22,496 616,982 1,555,358 $ (938,376) 2025 Base Case 4/1/2025 Edwardsport CC ST I 32162 17,877 507,582 1,410,504 $ (902,922) 2025 Base Case 5/1/2025 Edward sport CC ST I 32162 9,270 239,206 1,233,728 $ (994,522) 2025 Base Case 6/1/2025 Edward sport CC ST I 32162 14,783 423,240 1,335,280 $ (912,040) 2025 Base Case 7/1/2025 Edwardsport CC ST I 32162 21,369 706,222 1,416,600 $ (710,378) 2025 Base Case 8/1/2025 Edwardsport CC ST I 32162 16,103 472,119 1,370,977 $ (898,858) 2025 Base Case 9/1/2025 Edwardsport CC ST I 32162 11,485 323,048 1,230,390 $ (907,342) 2025 Base Case 10/1/2025 Edwardsport CC ST I 32162 11,367 306,790 1,284,382 $ (977,593) 2025 Base Case 11/1/2025 Edwardsport CC ST I 32162 14,379 465,286 1,325,452 $ (860,166) 2025 Base Case 12/1/2025 Edwardsport CC ST I 32162 11,875 375,624 1,297,080 $ (921,455) 2025 Base Case Edwardsport CC ST I 32162 196,262 5,728,465 16,502,138 (10,773,673)

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margi'n Name Month Starting Name MWh $ $ $ 2025 Base Case 1/1/2025 Gibson ST 1 I 6456 262,408 7,567,012 6,120,014 $ 1,446,997 2025 Base Case 2/1/2025 Gibson ST 1 I 6456 237,293 6,548,736 5,531,782 $ 1,016,955 2025 Base Case 3/1/2025 Gibson ST 1 I 6456 272,646 7,392,317 6,330,552 $ 1,061,765 2025 Base Case 4/1/2025 Gibson ST 1 I 6456 29,292 857,560 1,240,930 $ (383,370) 2025 Base Case 5/1/2025 Gibson ST 1 I 6456 151,903 3,898,731 3,776,454 $ 122,277 2025 Base Case 6/1/2025 Gibson ST 1 I 6456 151,796 4,337,312 3,937,816 $ 399,496 2025 Base Case 7/1/2025 Gibson ST 1 I 6456 227,787 7,513,337 5,478,610 $ 2,034,727 2025 Base Case 8/1/2025 Gibson ST 1 I 6456 153,815 4,460,731 3,964,816 $ 495,915 2025 Base Case 9/1/2025 Gibson ST 1 I 6456 122,600 3,473,104 3,068,887 $ 404,216 2025 Base Case 10/1/2025 Gibson ST 1 I 6456 142,204 3,831,253 3,666,447 $ 164,806 2025 Base Case 11/1/2025 Gibson ST 1 I 6456 172,377 5,173,831 4,257,071 $ 916,760 2025 Base Case 12/1/2025 Gibson ST 1 I 6456 161,293 5,031,868 4,055,746 $ 976,122 2025 Base Case Gibson ST 1 I 6456 2,085,412 60,085,790 51,429,124 8,656,666 AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 038 of 055

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Base Case 1/1/2025 Gibson ST 2 I 6457 262,408 7,567,012 6,203,895 $ 1,363,116 2025 Base Case 2/1/2025 Gibson ST 2 j 6457 237,293 6,548,736 5,607,597 $ 941,139 2025 Base Case 3/1/2025 Gibson ST 2 I 6457 272,646 7,392,317 6,417,283 $ 975,034 2025 Base Case 4/1/2025 Gibson ST 2 I 6457 29,292 857,560 1,359,011 $ (501,452) 2025 Base Case 5/1/2025 Gibson ST 2 I 6457 158,800 4,071,769 4,035,100 $ 36,669 2025 Base Case 6/1/2025 Gibson ST 2 I 6457 163,214 4,621,508 4,126,334 $ 495,174 2025 Base Case 7/1/2025 Gibson ST 2 I 6457 226,110 7,411,202 5,512,643 $ 1,898,559 2025 Base Case 8/1/2025 Gibson ST 2 I 6457 153,153 4,416,287 4,000,379 $ 415,908 2025 Base Case 9/1/2025 Gibson ST 2 I 6457 135,699 3,781,358 3,516,263 $ 265,095 2025 Base Case 10/1/2025 Gibson ST2l6457 132,168 3,566,969 3,530,040 $ 36,929 2025 Base Case 11/1/2025 Gibson ST 2 I 6457 172,377 5,173,831 4,315,718 $ 858,113 2025 Base Case 12/1/2025 Gibson ST 2 I 6457 161,293 5,031,868 4,111,706 $ 920,163 2025 Base Case Gibson ST 216457 2,104,452 60,440,416 52,735,970 7,704,447

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Base Case 1/1/2025 Gibson ST 3 I 6458 262,408 7,567,012 6,198,507 $ 1,368,505 2025 Base Case 2/1/2025 Gibson ST 3 I 6458 229,929 6,362,467 5,507,692 $ 854,775 2025 Base Case 3/1/2025 Gibson ST 3 I 6458 252,954 6,826,208 6,107,562 $ 718,646 2025 Base Case 4/1/2025 Gibson ST 3 I 6458 29,292 857,560 1,357,763 $ (500,204) 2025 Base Case 5/1/2025 Gibson ST 3 I 6458 165,028 4,215,055 4,185,248 $ 29,807 2025 Base Case 6/1/2025 Gibson ST 3 I 6458 152,078 4,348,224 3,922,611 $ 425,613 2025 Base Case 7/1/2025 Gibson ST 3 I 6458 230,800 7,576,882 5,543,658 $ 2,033,224 2025 Base Case 8/1/2025 Gibson ST 3 I 6458 157,459 4,549,044 4,028,923 $ 520,121 2025 Base Case 9/1/2025 Gibson ST 3 I 6458 122,618 3,487,776 3,259,493 $ 228,284 2025 Base Case 10/1/2025 Gibson ST 3 I 6458 142,204 3,831,253 3,713,877 $ 117,375 2025 Base Case 11/1/2025 Gibson ST 3 I 6458 172,377 5,173,831 4,311,945 $ 861,886 2025 Base Case 12/1/2025 Gibson ST 3 I 6458 161,293 5,031,868 4,108,104 $ 923,764 2025 Base Case Gibson ST 3 I 6458 2,078,440 59,_§_2 7, 18Q__ 52,245,384 ·--- 7,581,796

;1 I t1 I P AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 039 of 055 '

i Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Base Case 1/1/2025 Gibson ST 4 j 6459 237,497 6,875,760 5,589,192 $ 1,286,568 2025 Base Case 2/1/2025 Gibson ST 4 j 6459 234,303 6,466,233 5,442,322 $ 1,023,911 2025 Base Case 3/1/2025 Gibson ST 4j6459 269,211 7,299,185 6,228,188 $ 1,070,99{ 2025 Base Case 4/1/2025 Gibson ST 4j6459 28,923 846,756 1,257,198 $ (410,442) 2025 Base Case 5/1/2025 Gibson ST 4 I6459 162,949 4,161,952 3,999,242 $ 162,710 2025 Base Case 6/1/2025 Gibson ST 4 j 6459 139,613 4,024,454 3,550,346 $ 474,108 2025 Base Case 7/1/2025 Gibson ST 4 I6459 227,893 7,481,425 5,384,799 $ 2,096,626 2025 Base Case 8/1/2025 Gibson ST 416459 155,475 4,491,733 3,913,099 $ 578,634 2025 Base Case 9/1/2025 Gibson ST 4 j 6459 161,011 4,485,195 4,001,288 $ 483,907 2025 Base Case 10/1/2025 Gibson ST 4j 6459 140,412 3,782,985 3,607,004 $ 175,981 2025 Base Case 11/1/2025 Gibson ST 4 I6459 170,205 5,108,649 4,188,124 $ 920,525 2025 Base Case 12/1/2025 Gibson ST 4 I6459 159,261 4,968,475 3,990,031 $ 978,444 2025 Base Case Gibson ST 4 I 6459 2,086,752 59,992,802 51,150,833 8,841,969

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Base Case 1/1/2025 Gibson ST 5 I6460 244,743 7,035,857 5,940,682 $ 1,095,175 2025 Base Case 2/1/2025 Gibson ST 5 I6460 233,556 6,445,607 5,586,817 $ 858,790 2025 Base Case 3/1/2025 Gibson ST 5 I6460 268,352 7,275,903 6,393,480 $ 882,422 2025 Base Case 4/1/2025 Gibson ST 5 I 6460 28,830 844,055 1,354,659 $ {510,604) 2025 Base Case 5/1/2025 Gibson ST 5 I6460 122,086 3,075,476 3,348,669 $ (273,194) 2025 Base Case 6/1/2025 Gibson ST 5 I 6460 160,644 4,548,728 4,111,317 $ 437,411 2025 Base Case 7/1/2025 Gibson ST 5 I6460 221,538 7,313,464 5,467,203 $ 1,846,26i 2025 Base Case 8/1/2025 Gibson ST 5 I6460 154,979 4,477,405 4,017,831 $ 459,574 2025 Base Case 9/1/2025 Gibson ST 5 I6460 142,322 3,866,498 3,718,217 $ 148,282 2025 Base Case 10/1/2025 Gibson ST 5 j 6460 139,964 3,770,918 3,703,731 $ 67,187 2025 Base Case 11/1/2025 Gibson ST 5 I6460 129,664 3,686,255 3,368,942 $ 317,3B 2025 Base Case 12/1/2025 Gibson ST 5 I 6460 158,753 4,952,626 4,096,775 $ 855,85'.). 2025 Base Case Gibson ST 5 j 6460 2,005,432 57,292,792 51,108,325 6,184,467

r I ilj AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 040 of 055

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I minus 2025 Base Case 1/1/2025 Cayuga ST 1 \ 6416 $ 26,128 $ 800,133 $ 775,097 $ 25,035 2025 Advanced Case I minus 2025 Base Case 2/1/2025 Cayuga ST 1 \ 6416 $ (5,873) $ (161,956) $ (159,731) $ (2,225) 2025 Advanced Case I minus 2025 Base Case 3/1/2025 Cayuga ST 1 \ 6416 $ 14,869 $ 355,671 $ 304,190 $ 51,482 2025 Advanced Case I minus 2025 Base Case 4/1/2025 Cayuga ST 1 \ 6416 $ 85,086 $ 2,300,553 $ 2,054,095 $ 246,458 2025 Advanced Case I minus 2025 Base Case 5/1/2025 Cayuga ST 1 \ 6416 $ 5,997 $ 117,044 $ 105,340 $ 11,704 2025 Advanced Case I minus 2025 Base Case 6/1/2025 Cayuga ST 1 \ 6416 $ (3,872) $ (161,886) $ (114,729) $ (47,158) 2025 Advanced Case I minus 2025 Base Case 7/1/2025 Cayuga ST 1 \ 6416 $ 8,184 $ 175,650 $ 151,301 $ 24,349 2025 Advanced Case I minus 2025 Base Case 8/1/2025 Cayuga ST 1 \ 6416 $ (15,243) $ (389,679) $ {355,821) $ (33,858) 2025 Advanced Case I minus 2025 Base Case 9/1/2025 Cayuga ST 1 \ 6416 $ $ $ $ 2025 Advanced Case I minus 2025 Base Case 10/1/2025 Cayuga ST 1 \ 6416 $ {21,694) $ (628,526) $ (564,623) $ (63,903) 2025 Advanced Case I minus 2025 Base Case 11/1/2025 Cayuga ST 1 \ 6416 $ $ (17,275) $ $ (17,275) 2025 Advanced Case I minus 2025 Base Case 12/1/2025 Cayuga ST 1 \ 6416 $ $ 20,443 $ $ 20,443 2025 Advanced Case I minus ·2025 Base Case Cayuga ST 1 \ 6416 93,582 2,410,172 2,195,120 215,052

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margi/l Name Month Starting Name MWh $ $ $ 2025 Advanced Case I minus 2025 Base Case 1/1/2025 Cayuga ST 2 \ 6417 $ (217,805) $ (6,363,383) $ (6,096,836) $ (266,547) 2025 Advanced Case I minus 2025 Base Case 2/1/2025 Cayuga ST 2 \ 6417 $ (142,756) $ (4,004,743) $ (4,130,041) $ 125,299 2025 Advanced Case I minus 2025 Base Case 3/1/2025 Cayuga ST 2 \ 6417 $ (156,562) $ (4,316,816) $ (4,533,369) $ 216,552 2025 Advanced Case I minus 2025 Base Case 4/1/2025 Cayuga ST 2 \ 6417 $ (45,854) $ (1,283,418) $ (1,820,790) $ 537,37i 2025 Advanced Case I minus 2025 !3ase Case 5/1/2025 Cayuga ST 2 \ 6417 $ {77,244) $ (1,968,750) $ (2,686,951) $ 718,2ot 2025 Advanced Case I minus 2025 Base Case 6/1/2025 Cayuga ST 2 I 6417 $. (126,417) $ (3,613,166) $ (3,811,440) $ 198,275 2025 Advanced Case I minus 2025 Base Case 7/1/2025 Cayuga ST 2 \ 6417 $ (215,390) $ (7,171,489) $ (6,039,519) $ (1,131,970) 2025 Advanced Case I minus 2025 Base Case 8/1/2025 Cayuga ST 2 \ 6417 $ (164,091) $ (4,848,431) $ (4,725,740) $ {122,692) 2025 Advanced Case I minus 2025 Base Case 9/1/2025 Cayuga ST 2\6417 $ $ $ $ 2025 Advanced Case I minus 2025 Base Case 10/1/2025 Cayuga ST 2 I6417 $ (106,484) $ (2,882,166) $ (3,385,567) $ 503,401 2025 Advanced Case I minus 2025 Base Case 11/1/2025 Cayuga ST 2 \ 6417 $ {180,830) $ (5,490,937) $ (5,155,974) $ (334,964) 2025 Advanced Case I minus 2025 Base Case 12/1/2025 Cayuga ST 2 \ 6417 $ (118,249) $ (3,739,433) $ (3,626,715) $ (112,719) 2025 Advanced Case I minus 2025 Base Case Cayu_g

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I minus 2025 Base Case 1/1/2025 Edwardsport CC CTl I20460 $ (15,341) $ {448,293) $ (1,492,609) $ 1,044,316 2025 Advanced Case I minus 2025 Base Case 2/1/2025 Edward sport CC CTl I20460 $ (17,004) $ {474,821) $ (1,450,800) $ 975,980 2025 Advanced Case I minus 2025 Base Case 3/1/2025 Edwardsport CC CTl I 20460 $ (15,504) $ (424,471) $ (1,484,712) $ 1,060,242 2025 Advanced Case I minus 2025 Base Case 4/1/2025 Edward sport CC CTl I20460 $ (16,589) $ (468,182) $ {1,501,270) $ 1,033,087 2025 Advanced Case I minus 2025 Base Case 5/1/2025 Edward sport CC CTl I20460 $ (4,619) $ (122,095) $ {1,110,989) $ 988,893 2025 Advanced Case I minus 2025 Base Case 6/1/2025 Edwardsport cc en I 20460 $ {10,546) $ {301,934) $ {1,304,260) $ 1,002,326 2025 Advanced Case I minus 2025 Base Case 7/1/2025 Edwardsport cc en I 20460 $ {17,685) $ (587,447) $ (1,569,044) $ 981,597 2025 Advanced Case I minus 2025 Base Case 8/1/2025 Edwardsport CC CTl I20460 $ (12,504) $ (365,109) $ (1,400,087) $ 1,034,979 2025 Advanced Case I minus 2025 Base Case 9/1/2025 Edwardsport CC CTl I 20460 $ (8,063) $ (227,247) $ (1,200,569) $ 973,322 2025 Advanced Case I minus 2025 Base Case 10/1/2025 Edwardsport CC CTl I20460 $ (4,450) $ {120,367) $ (1,137,157) $ 1,016,791 2025 Advanced Case I minus 2025 Base Case 11/1/2025 Edwardsport CC CTl I20460 $ (19,563) $ (593,288) $ (1,598,233) $ 1,004,945 2025 Advanced Case I minus 2025 Base Case 12/1/2025 Edwardsport CC CTl I20460 $ (8,233) $ (260,239) $ (1,252,979) $ 992,74t 2025 Advanced Case I minus 2025 Base Case Edwardsport CC CTl I 20460 (150,101) (4,393,493) (16,502,711) 12,109,21$

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margiln Name Month Starting Name MWh $ $ $ 2025 Advanced Case I minus 2025 Base Case 1/1/2025 Edwardsport CC CT2 I32161 $ (14,463) $ (420,569) $ (1,326,954) $ 906,385 2025 Advanced Case I minus 2025 Base Case 2/1/2025 Edwardsport CC CT2 I32161 $ (17,004) $ (474,821) $ (1,375,431) $ 900,610 2025 Advanced Case I minus 2025 Base Case 3/1/2025 Edwardsport CC CT2 I32161 $ (15,696) $ (428,243) $ (1,424,453) $ 996,21(') I 2025 Advanced Case I minus 2025 Base Case 4/1/2025 Edwardsport CC CT2 I32161 $ (16,589) $ (468,182) $ (1,423,143) $ 954,961 2025 Advanced Case I minus 2025 Base Case 5/1/2025 Edwardsport CC CT2 I32161 $ (4,702) $ (124,025) $ (1,085,024) $ 960,999 2025 Advanced Case I minus 2025 Base Case 6/1/2025 Edwardsport CC CT2 I32161 $ (10,546) $ (301,934) $ (1,235,868) $ 933,934 2025 Advanced Case I minus 2025 Base Case 7/1/2025 Edwardsport CC CT2 I32161 $ (16,921) $ (563,162) $ (1,437,171) $ 874,009 2025 Advanced Case I minus 2025 Base Case 8/1/2025 Edwardsport CC CT2 I32161 $ (12,504) $ (365,109) $ (1,326,828) $ 961,719 2025 Advanced Case I minus 2025 Base Case 9/1/2025 Edwardsport CC CT2 I32161 $ (8,193) $ (230,459) $ (1,139,945) $ 909,486 2025 Advanced Case I minus 2025 Base Case 10/1/2025 Edwardsport CC CT2 I32161 $ (4,461) $ (122,663) $ (1,077,235) $ 954,572 2025 Advanced Case I minus 2025 Base Case 11/1/2025 Edwardsport CC CT2 I32161 $ (18,239) $ (562,187) $ (1,435,078) $ 872,891 2025 Advanced Case I minus 2025 Base Case 12/1/2025 Edwardsport CC CT2 I32161 $ (7,374) $ (231,204) $ (1,049,107) $ 817,904 2025 Advanced Case I minus 2025 Base Case Edwardsport CC_CT21?2161 (146,692) (4,292,558) i15,336,238) 11,043,680

I" AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAG 123 S1 Page 042 of 055

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I minus 2025 Base Case 1/1/2025 Edwardsport CC ST I 32162 $ (21,421) $ (626,782) $ (1,552,018) $ 925,235 2025 Advanced Case I minus 2025 Base Case 2/1/2025 Edwardsport CC ST I 32162 $ (23,836) $ (665,585) $ (1,490,369) $ 824,784 2025 Advanced Case I minus 2025 Base Case 3/1/2025 Edwardsport CC ST I 32162 $ (22,496) $ (616,982) $ (1,555,358) $ 938,376 2025 Advanced Case I minus 2025 Base Case 4/1/2025 Edwardsport CC ST I 32162 $ (17,877) $ (507,582) $ (1,410,504) $ 902,922 2025 Advanced Case I minus 2025 Base Case 5/1/2025 Edwardsport CC ST I 32162 $ (9,270) $ (239,206) $ (1,233,728) $ 994,522 2025 Advanced Case I minus 2025 Base Case 6/1/2025 Edwardsport CC ST I 32162 $ (14,783) $ (423,240) $ {1,335,280) $ 912,040 2025 Advanced Case I minus 2025 Base Case 7/1/2025 Edwardsport CC ST I 32162 $ {21,369) $ (706,222) $ {1,416,600) $ 710,378 2025 Advanced Case I minus 2025 Base Case 8/1/2025 Edwardsport CC ST I 32162 $ (16,103) $ (472,119) $ (1,370,977) $ 898,858 2025 Advanced Case I minus 2025 Base Case 9/1/2025 Edwardsport CC ST I 32162 $ (11,485) $ (323,048) $ (1,230,390) $ 907,342 2025 Advanced Case I minus 2025 Base Case 10/1/2025 Edwardsport CC ST I 32162 $ (11,367) $ (306,790) $ (1,284,382) $ 977,593 2025 Advanced Case I minus 2025 Base Case 11/1/2025 Edwardsport CC ST I 32162 $ (14,379) $ (465,286) $ (1,325,452) $ 860,166 2025 Advanced Case I minus 2025 Base Case 12/1/2025 Edwardsport CC ST I32162 $ (11,875) $ (375,624) $ (1,297,080) $ 921,455 2025 Advanced Case I minus 2025 Base Case Edwardsport CC ST I 32162 (196,262) {S,Z28,465) {16,502,138) 10,7731673

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I minus 2025 Base Case 1/1/2025 Gibson ST 1 I 6456 $ $ 45,308 $ $ 45,308 2025 Advanced Case I minus 2025 Base Case 2/1/2025 Gibson ST 1 I 6456 $ (8,875) $ {320,964) $ (126,649) $ {194,315) 2025 Advanced Case I minus 2025 Base Case 3/1/2025 Gibson ST 1 I 6456 $ (12,181) $ (397,444) $ (204,355) $ (193,089) 2025 Advanced Case I minus 2025 Base Case 4/1/2025 Gibson ST 1 I 6456 $ 222,178 $ 5,865,793 $ 4,658,872 $ 1,206,922 2025 Advanced Case I minus 2025 Base Case 5/1/2025 Gibson ST 1 I 6456 $ 67,090 $ 1,693,119 $ 1,456,024 $ 237,095 2025 Advanced Case I minus 2025 Base Case 6/1/2025 Gibson ST 1 I 6456 $ 11,418 $ 203,581 $ 132,398 $ 71,183 2025 Advanced Case I minus 2025 Base Case 7/1/2025 Gibson ST 1 I 6456 $ 3,014 $ (16,412) $ (5,256) $ (11,156) 2025 Advanced Case I minus 2025 Base Case .8/1/2025 Gibson ST 1 I 6456 $ 3,643 $ 132,102 $ 12,739 $ 119,364 2025 Advanced Case I minus 2025 Base Case 9/1/2025 Gibson ST 1 I 6456 $ 36,557 $ 921,035 $ 978,095 $ (57,060) 2025 Advanced Case I minus 2025 Base Case 10/1/2025 Gibson ST 1 I 6456 $ (5,967) $ {235,554) $ (78,664) $ (156,889) 2025 Advanced Case I minus 2025 Base Case 11/1/2025 Gibson ST 1 I 6456 $ $ (28,573) $ $ (28,573) 2025 Advanced Case I minus 2025 Base Case 12/1/2025 Gibson ST 1 I 6456 $ (42,604) $ (1,420,249) $ (902,305) $ (517,944) 2025 Advanced Case I minus 2025 Base Case Gibson ST 1 I 6456 274,274 6,441,743 5,920,898 520,845

fl ·1 AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S 1 Page 043 of 055

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025'Advanced Case I minus 2025 Base Case 1/1/2025 Gibson ST 2 I 6457 $ $ 45,308 $ $ 45,30~ 2025 Advanced Case I minus 2025 Base Case 2/1/2025 Gibson ST 2 I 6457 $ (17,059) $ {592,326) $ (402,794) $ {189,533) 2025 Advanced Case I minus 2025 Base Case 3/1/2025 Gibson ST 2 I 6457 $ (11,086) $ {367,723) $ (104,838) $ (262,885) 2025 Advanced Case I minus 2025 Base Case 4/1/2025 Gibson ST 2 I 6457 $ 240,549 $ 6,391,148 $ 4,972,391 $ 1,418,757 2025 Advanced Case I minus 2025 Base Case 5/1/2025 Gibson ST 2 I 6457 $ 60,193 $ 1,520,081 $ 1,269,253 $ 250,828 2025 Advanced Case I minus 2025 Base Case 6/1/2025 Gibson ST 2 I 6457 $ (6,030) $ (249,603) $ (149,738) $ {99,865) 2025 Advanced Case I minus 2025 Base Case 7/1/2025 Gibson ST 2 I6457 $ (4,349) $ (112,441) $ {102,447) $ {9,994) 2025 Advanced Case I minus 2025 Base Case 8/1/2025 Gibson ST 2 I 6457 $ 522 $ 85,970 $ 90,714 $ (4,744) 2025 Advanced Case I minus 2025 Base Case 9/1/2025 Gibson ST 2 I 6457 $ 21,878 $ 545,017 $ 546,297 $ (1,279) 2025 Advanced Case I minus 2025 Base Case 10/1/2025 Gibson ST 2 I 6457 $ 2,872 $ 9,563 $ 156,018 $ (146,454) 2025 Advanced Case I minus 2025 Base Case 11/1/2025 Gibson ST 2 I 6457 $ (11,882) $ (308,560) $ {295,782) $ (12,779) 2025 Advanced Case I minus 2025 Base Case 12/1/2025 Gibson ST 2 I 6457 $ (2,974) $ {47,697) $ 3,812 $ (51,509) 2025 Advanced Case I minus 2025 Base Case Gibson ST 2 I 6457 272,631 6,918,737 5,982,885 935,852

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I minus 2025 Base Case 1/1/2025 Gibson ST 3 I 6458 $ (10,992) $ (263,910) $ (179,372) $ (84,539) 2025 Advanced Case I minus 2025 Base Case 2/1/2025 Gibson ST 3 I 6458 $ 7,364 $ 122,316 $ 95,035 $ 27,281 2025 Advanced Case I minus 2025 Base Case 3/1/2025 Gibson ST 3 I 6458 $ 11,320 $ 217,157 $ 106,190 $ 110,967 2025 Advanced Case I minus 2025 Base Case 4/1/2025 Gibson ST 3 I 6458 $ 213,543 $ 5,590,805 $ 4,419,656 $ 1,171,149 2025 Advanced Case I minus 2025 Base Case 5/1/2025 Gibson ST 3 I 6458 $ 21,824 $ 522,938 $ 425,238 $ 97,700 2025 Advanced Case I minus 2025 Base Case 6/1/2025 Gibson ST 3 I 6458 $ 11,137 $ 192,668 $ 200,112 $ {7,443) 2025 Advanced Case I minus 2025 Base Case 7/1/2025 Gibson ST 3 I 6458 $ {13,496) $ (490,907) $ (245,707) $ (245,200) 2025 Advanced Case I minus 2025 Base Case 8/1/2025 Gibson ST 3 I 6458 $ $ 43,789 $ $ 43,789 2025 Advanced Case I minus 2025 Base Case 9/1/2025 Gibson ST 3 I 6458 $ 40,447 $ 1,020,214 $ 860,153 $ 160,061 2025 Advanced Case I minus 2025 Base Case 10/1/2025 Gibson ST 3 I 6458 $ (17,883) $ (541,669) $ (310,605) $ {231,065) 2025 Advanced Case I minus 2025 Base Case 11/1/2025 Gibson ST 3 I 6458 $ $ (28,573) $ $ (28,573) 2025 Advanced Case I minus 2025 Base Case 12/1/2025 Gibson ST 3 I 6458 $ $ 28,197 $ $ 28,197 2025 Advanced Case I minus 2025 Base Case Gibson ST 3 I 6458 263,263 6,413,025 5,370,701 1,042,325

,,,1 I' f AEE Ex. 2 Attachment RBS-'.l IURC Cause No. 38707 FAC 123 S 11 Page 044 of 055

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I minus 2025 Base Case 1/1/2025 Gibson ST 4 [ 6459 $ 21,605 $ 640,656 $ 431,850 $ 208,806 2025 Advanced Case I minus 2025 Base Case 2/1/2025 Gibson ST 4 [ 6459 $ $ (63,148) $ $ (63,148) 2025 Advanced Case I minus 2025 Base Case 3/1/2025 Gibson ST 4 I 6459 $ (25,623) $ (882,646) $ (438,461) $ (444,185) 2025 Advanced Case I minus 2025 Base Case 4/1/2025 Gibson ST 4 [ 6459 $ 237,518 $ 6,310,630 $ 4,887,670 $ 1,422,959 2025 Advanced Case I minus 2025 Base Case 5/1/2025 Gibson ST 4 I 6459 $ 53,285 $ 1,359,449 $ 1,148,561 $ 210,888 2025 Advanced Case I minus 2025 Base Case 6/1/2025 Gibson ST 4[6459 $ 10,891 $ 207,416 $ 188,799 $ 18,617 2025 Advanced Case I minus 2025 Base Case 7/1/2025 Gibson ST 4[6459 $ $ (78,950) $ $ (78,950) 2025 Advanced Case I minus 2025 Base Case 8/1/2025 Gibson ST 4 [ 6459 $ {2,435) $ (14,996) $ 16,461 .$ (31,456) 2025 Advanced Case I minus 2025 Base Case 9/1/2025 Gibson ST 4 I 6459 $ (5,094) $ (183,161) $ (50,734) $ (132,427) 2025 Advanced Case I minus 2025 Base Case 10/1/2025 Gibson ST 4 [ 6459 $ $ (84,407) $ $ (84,407) 2025 Advanced Case I minus 2025 Base Case 11/1/2025 Gibson ST 4 [ 6459 $ $ (28,213) $ $ (28,213) 2025 Advanced Case I minus 2025 Base Case 12/1/2025 Gibson ST 4 I 6459 $ (28,879) $ (889,655) $ (649,550) $ (240,104) 2025 Advanced Case I minus 2025 Base Case Gibson ST 4 [ 6459 261,269 6,292,975 5,534,596 758,379

Scenario Month Unit Production Energy Revenue Operating Cost Operating Margin Name Month Starting Name MWh $ $ $ 2025 Advanced Case I minus 2025 Base Case 1/1/2025 Gibson ST 5 [ 6460 $ {15,549) $ (341,358) $ (295,120) $ (46,237) 2025 Advanced Case I minus 2025 Base Case 2/1/2025 Gibson ST 5 I 6460 $ (15,403) $ (449,136) $ (291,375) $ (157,76'.I,.) 2025 Advanced Case I minus 2025 Base Case 3/1/2025 Gibson ST 5 I 6460 $ (26,564) $ (879,094) $ (398,585) $ (480,509) 2025 Advanced Case I minus 2025 Base Case 4/1/2025 Gibson ST 5 I 6460 $ 236,760 $ 6,290,500 $ 4,953,236 $ 1,337,264 2025 Advanced Case I minus 2025 Base Case 5/1/2025 Gibson ST 5[6460 $ 52,604 $ 1,316,604 $ 1,022,679 $ 293,925 2025 Advanced Case I minus 2025 Base Case 6/1/2025 Gibson ST 5 I 6460 $ (10,071) $ (330,266) $ (182,965) $ (147,302) 2025 Advanced Case I minus 2025 Base Case 7/1/2025 Gibson ST 5 [6460 $ (1,278) $ (127,167) $ (108,666) $ (18,501) 2025 Advanced Case I minus 2025 Base Case 8/1/2025 Gibson ST 5 [ 6460 $ (12,032) $ (343,311) $ (231,297) $ (112,013) 2025 Advanced Case I minus 2025 Base Case 9/1/2025 Gibson ST 5 [ 6460 $ 1,716 $ 121,523 $ 53,625 $ 67,898 2025 Advanced Case I minus 2025 Base Case 10/1/2025 Gibson ST 5 I 6460 $ (15,570) $ (495,581) $ (323,025) $ (172,556) 2025 Advanced Case I minus 2025 Base Case 11/1/2025 Gibson ST 5 [ 6460 $ 36,138 $ 1,267,692 $ 912,398 $ 355,294 2025 Advanced Case I minus 2025 Base Case 12/1/2025 Gibson ST 5 I 6460 $ $ 27,753 $ $ 27,753 2025 Advanced Case I minus 2025 Base Case Gibson ST 5 [ 6460 230,752 6,058,159 5,110,904 947,255

" AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 045 of 055

Table 10.C: Summary of 2025 Scenario Results Cost to Serve Load Operating Margin Case Savings from Savings from M$ M$ 2025 Base 2025 Base 2025 Base 1,141 -549 2025 Advanced I 1,036 105.3 -410 138.3 2025 Advanced II 717 423.7 -10 538.8

I AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1" Page 046 of 055

Table 11: Enelytix Plant Technical Parameters Average Summer number of Average Forced VOM StartupCost StartupHeat StartupCost StartupHeat StartupCost StartupHeat Units In Model Name in Model Unit Type Heat Rate Ramp-up Rate Capacity forced outages Outage Duration Cold Cold Wann Wann Hot Hot er ear Long Name Name MW Btu/KWh MW/Min Days $/MWh $/MW-start MMBtu/start $/MW-start MMBtu/start $/MW-start MMBtu/start Cayuga CT!Cayuga CT 4 Cayuga CT 416422 GTgo50+ 80 92 15,0 3.1 2.8 10.0 10.0 CayugalCayuga ST 1 Cayuga ST 116416 STc600 500 505 3.0 8,9 1.8 3,0 35,0 45.0 33,8 22.5 CayugalCayuga ST 2 Cayuga ST 216417 STc600 495 500 3.0 8,9 1.8 3,0 35.0 45.0 33.8 22.5 Edwardsport IGCCIEdwardsport CC CT1 Edwardsport CC CT1120460 IGCC 174.9 181.7 10,0 5.9 1.5 2.5 21.0 35,0 26,3 17.5 Edwardsport IGCC]Edwardsport CC CT2 Edwardsport CC CT2!32161 IGCC 174.9 181.7 10.0 5,9 1.5 2,5 21.0 35,0 26.3 17.5 Edwardsport IGCCIEdwardsport CC ST Edwardsport CC STl32162 JGCC 245.2 254.7 10.0 5.9 1,5 2.5 21.0 35,0 26,3 '17,5 GibsonjGibson ST 1 Gibson ST 116456 STc600+ 630 635 3.0 7.2 2.1 2.0 35.0 45,0 33,8 '22.5 GibsonjGibson ST 2 Gibson ST 216457 STc600+ 630 635 3,0 7.2 2.1 2.0 35,0 45.0 33,8 22.5 GlbsonlGibson ST 3 Gibson ST 316458 STc600+ 630 635 3,0 7.2 2.1 2.0 35.0 45.0 33.8 22.5 Glbson!Glbson ST 4 Gibson ST 416459 STc600+ 622 627 3.0 7.2 2.1 2.0 35,0 45,0 33,8 22.5 GlbsonlGlbson ST 5 Gibson ST 516460 STc600+ 620 625 3,0 7.2 2.1 2.0 35,0 45.0 33,8 22.5 Henry County[Henry County CT 1 Henry County CT 116461 GTg50 43 47 15.0 2.5 6,9 10.0 10.0 Henry CountylHenry County CT 2 Henry County CT 216462 GTgS0 43 47 15.0 2.5 6,9 10.0 10.0 Henry CountylHenry County CT 3 Henry County CT 316463 GTg50 43 47 15.0 2.5 6,9 10.0 10,0 Noblesville CCl628jCC Noblesville CCj628ICC CCgo100+ 264 310 10.0 5,9 1.5 2.5 21.0 35.0 26.3 17.5 Purdue University - Wade Utility Plant!Purdue University ST GEN1 Purdue University ST GEN1I5986 STg100 30.8 30.8 6,0 1.6 11,4 6.0 35.0 40.0 30.0 :20.0 R. GallagherlR Gallagher ST 2 R Gallagher ST 216443 STc250 140 140 3,0 7.8 2.1 4.0 35,0 45.0 33.8 22.5 R. GallagherlR Gallagher ST 4 R Gallagher ST 416445 STc250 140 140 3.0 7,8 2.1 4.0 35.0 45.0 33.8 22.5 Sugar Creek Facilityl415ICC Sugar Creek Facilityl415JCC CCg100+ 549 563 10.0 5,9 1.5 2.5 21.0 35.0 26.3 17.5 Vermi111on GeneratlnglVermllllon Generating CT1 Vermllllon Generating CT1l1044 GTg50+ 72 92 15.0 3.1 2.8 10.0 10.0 Vermillion GeneratingjVermillion Generating CT2 Vermllllon Generating CT2l1045 GTg50+ 72 94 15.0 3.1 2.8 10.0 10.0 Vermillion GeneratinglVermillion Generating CT3 Vermillion Generating CT3l1046 GTg50+ 71 95 15.0 3,1 2,8 10.0 10.0 Vermillton Generatlng!Vermlllion Generating CT4 Vermillion Generating CT4j1047 GTgS0+ 73 92 15.0 3.1 2.8 10.0 10.0 Vermilllon GeneratlnglVermllllon Generating CT5 Vermillion Generating CT5j1048 GTg50+ 71 92 15.0 3.1 2.8 10.0 10.0 Vermlllion GeneratinglVermilllon Generating CT6 Vermillfon Generating CT6l1049 GTg50+ 72 95 15.0 3.1 2,8 10,0 10.0 Vermnlion Generatingl\/ermillion Generating CT7 Vermlllion Generating CT7I1050 GTgS0+ 72 94 15,0 3.1 2.8 10.0 10,0 Vermlllion GeneratlnglVermilllon Generating CTB Vermillion Generating CT811051 GTg50+ 73 90 15.0 3,1 2.8 10.0 10,0 Wabash Valley Power IGCCIWabash Valley Power IGCC CC 1A Wabash Valley Power IGCC CC 1Af6447 GTgS0+ 138 168 15.0 3,1 2.8 10,0 10.0 Wabash River Highland PlantlWabash Valley Power IGCC CT A1 Wabash Valley Power IGCC CT A1I44259 GTgS0+ 160 160 15.0 3,1 2.8 10,0 10.0 Wheatland Power FacllltylWheatland Power Facility CTG1 Wheatland Power Facility CTG1J16621 GTg50+ 111 126 15.0 3,1 2.8 10,0 10.0 Wheatland Power FacilitylWheatland Power Facility CTG2 Wheatland Power Facility CTG2I16622 GTgS0+ 114 126 15,0 3.1 2.8 10.0 10,0 Wheatland Power FacilltylWheatland Power Facility CTG3 Wheatland Power Facility CTG3I16623 GTg50+ 114 129 15.0 3,1 2.8 10,0 10,0 Wheatland Power Facll!ty]Wheatland Power Facility CTG4 Wheatland Power Facility CTG4j16624 GTgS0+ 111 127 15.0 3.1 2.8 10,0 10.0 AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAG 123 S1 Page 047 of 055

Table 12: BRG Coal Plants Scheduling Assumptions Scheduling Units in Model Name in Model Dispatch Assumption Assumption Monthly average actual capacity factors distributed according to hourly Cayuga 1 Cayuga ST 116416 Self-Scheduled actual load Monthly average actual capacity factors distributed according to hourly Cayuga 2 Cayuga ST 216417 Self-Scheduled actual load Monthly average actual capacity factors distributed according to hourly Edwardsport 1 Edwardsport CC CT1I20460 Self-Scheduled actual load Monthly average actual capacity factors distributed according to hourly Edwardsport 2 Edwardsport CC CT2I32161 Self-Scheduled actual load Monthly average actual capacity factors distributed according to hourly Edwardsport 3 Edwardsport CC STl32162 Self-Scheduled actual load Monthly average actual capacity factors distributed according to hourly Gibson 1 Gibson ST 116456 Self-Scheduled actual load Monthly average actu.al capacity factors distributed according to hourly Gibson 2 Gibson ST 216457 Self-Scheduled actual load Monthly average actual capacity factors distributed according to hourly Gibson 3 Gibson ST 316458 Self-Scheduled actual load Monthly average actual capacity factors distributed according to hourly Gibson 4 Gibson ST 416459 Self-Scheduled actual load Monthly average actual capacity factors distributed according to hourly Gibson 5 Gibson ST 516460 Self-Scheduled actual load R. GallagherlR Gallagher ST 2 R Gallagher ST 216443 Economic Dispatch None - Economic dispatch only R. GallagherlR Gallagher ST 4 R Gallagher ST 416445 Economic Dispatch None - Economic dispatch only AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 048 of 055

Generation by Fuel: Enelytix Backtest 70,000,000

60,000,000

50,000,000

40,000,000 .c 3: ~ 30,000,000

20,000,000

10,000,000

C\,(;). ~ ~ ~ ~ ~ ~ ~ ~ ')..'V' ')..,,,,~ ')..'V' ')..'V' ')..'\,(;) '\,(;) ')..'V' ')..'V' ')..'V' ~,t...; q,\t...; o,\t...; ~~ ~t...; ~t...; -t...; ~t...; II Natural Gas Coal Wind Other Fuel !I Water II Uranium ■ Solar ■ Biomass II Petroleum Products II Water II Energy Storage

•">,j,1 ;'f AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 049 of 055

Generation by Fuel: Historical Actual 70,000,000

60,000,000

50,000,000

40,000,000 .c: $ ~ 30,000,000

20,000,000

10,000,000

~°> ~ ~ ~°> ~ ~°> ~ Cl,~ Cl,~ ).~ ).~ ).~ ).~ ).'\,~ ).~ ).'\,~ ).'\,~ ).~ \"-y l\y~\"-y l\y~"-y ~~"-y ~"-y ~"-y

■ Natural Gas Coal Wind Other Fuel Water Uranium ■ Solar ■ Biomass Ill Petroleum Products Interchange ■ Energy Storage AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 050 of 055 "

Gibson Station Generation 1,600,000

1,400,000

1,200,000

..c: ~ 1,000,000 s::: 0 +i (tJ... 800,000 Cl.I C: Cl.I l!) +,I 600,000 zCl.I

400,000

200,000

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ (o~ A~~~~~~~~ '? "' ~;i ' Cb o, ~~ ~~ iv' ~ '\:

■ Gibson (Actual) ■ Gibson (Enelytix)

II' AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 051 of 055

Cayuga Station Generation 500,000

450,000

400,000

350,000 .c $ ~ 300,000 s::: 0 ·.;; ~ 250,000 Cl) s::: Cl) CJ..... 200,000 zCl) 150,000

100,000

50,000

~ ~ ~ -~ ~ ~ ~ ~ ~ ~°> ~<::> ~<::> ~ ~ ~ ~ ~ ~ ~ ~ ~<::> ef' ).'v<::> ).'v<::> \"y\ \~ \"',,\ \~ \"y\ \"y\ \~ \"y\ 1']\ ~\ <,\ (o\ "\ \ (b\ 0)\ "ye:)\ "y~"y "y~"y ~"y ~"y

Cayuga (Actual) a Cayuga (Enelytix} AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 052 of 055

Edwardsport Station Generation 70,000

60,000

50,000 ..c: $ ~ c: 40,000 ....0 ro ~ (lJ C: QJ 30,000 (.!:).... zQJ 20,000

10,000

~ ~~ ~ ~ ~~ ~ ~~ ~~ ~~ ~ r\;(;) Cl,(;) ~ ~ "\,(;) "\,(;) ~ "\,(;) ').."'(;) '{v(;) ).~ ')..'11(:) ,,,(;) \~ ~\1'y\ t:;,.\~ ~,~ eo\~ ~\1'y\ ct,\~ ~\",; 1'y(;)\",; 1'y1'y\"-; 1'yv,.",; 1'y\1'y\ v,.1'y\

Edwardsport (Actual) ■ Edwardsport (Enelytix) AEE Ex. 2 Attachment RBS-3 IURC Cause No. 38707 FAC 123 S1 Page 053 of 055

Gallagher Station Generation 14,000

12,000

10,000

8,000 .cs ~ S 6,000 ~ n, i.. QJ a3 4,000 ______,,,,,,_,,,,,,.,.,. ,.,.,...... ~.... zQJ 2,000

~ ~°' ~°' ~°' ~ - ~°' (2,000),,\~\ .. . ~~~~ ...... !\~·~~ A\~1' ················":x~···········!\~·-·····~~-·-··~~ ~-- 1' ~~~ ~ b ' ~ q ~ ❖

(4,000)

■ Gallagher (Actual) ■ Gallagher (Enelytix)

1· $/MWh -v,. -v,. -v,. -v,. -V')- -v,. -v,. -V>- -v,. -V,. ~ ~ N N W W ~ ~ I ~ 0 ~ 0 ~ 0 ~ 0 ~ I 5.. 6/1/2019 QJ ~ 6/15/2019 ~ 6/29/2019 ~ 7/13/2019 ~ ~ ~ 7/27/2019 ·:. ~ ro 8/10/2019 ~ :C -v,...... ~-41,-""'&~ll!!ro, C s: 8/24/2019 ~- er

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10/19/2019 ii;~~ ~ ~"' O'Q 1 111212019 "=-i~-~=~- ~ ~ ·•"'·"" ~ ~~~~:~:~~: ~ I DJ w,ff";jj# < g, 12/14/2019 ~ ~- ro ~t,,, ~ 12/28/2019 ◄;"'. ~

X 1/11/2020 I"""' S o [ 1/25/2020 ~~Fti-,"::,,.;;~~ ~ ~ 2/8/2020 :..~::1~' ~ C§. 2/22/2020 -c ~ ~ 0

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