Second Quarter 2017 Investor Update Conference Call July 28, 2017 - - PowerPoint PPT Presentation

July 28, 2017

Second Quarter 2017 Investor Update Conference Call

Calpine Corporation

Forward‐Looking Statements The information contained in this presentation includes certain estimates, projections and other forward‐looking information that reflect Calpine’s current views with respect to future events and financial performance. These estimates, projections and other forward‐looking information are based on assumptions that Calpine believes, as of the date hereof, are reasonable. Inevitably, there will be differences between such estimates and actual results, and those differences may be material. There can be no assurance that any estimates, projections or forward‐looking information will be realized. All such estimates, projections and forward‐looking information speak only as of the date hereof. Calpine undertakes no duty to update or revise the information contained herein other than as required by law. You are cautioned not to place undue reliance on the estimates, projections and other forward‐looking information in this presentation as they are based on current expectations and general assumptions and are subject to various risks, uncertainties and other factors, including those set forth in Calpine’s Quarterly Reports on Form 10‐Q for the three months ended March 31 and June 30, 2017, its Annual Report on Form 10‐K for the year ended December 31, 2016 and in other documents that Calpine files with the SEC. Many of these risks, uncertainties and other factors are beyond Calpine’s control and may cause actual results to differ materially from the views, beliefs and estimates expressed herein. Calpine’s reports and other information filed with the SEC, including the risk factors identified in its Annual Report on Form 10‐K for the year ended December 31, 2016, can be found on the SEC’s website at www.sec.gov and on Calpine’s website at www.calpine.com. Reconciliation to U.S. GAAP Financial Information The following presentation includes certain “non‐GAAP financial measures” as defined in Regulation G under the Securities Exchange Act

• f 1934, as amended. Schedules are included herein that reconcile the non‐GAAP financial measures included in the following

presentation to the most directly comparable financial measures calculated and presented in accordance with U.S. GAAP.

Calpine Corporation 1

Safe Harbor Statement

Calpine Corporation 2

Welcome and Safe Harbor Bryan Kimzey

Vice President, Investor Relations

CEO Review Thad Hill

President, Chief Executive Officer

Financial Review Zamir Rauf

EVP, Chief Financial Officer

Agenda

Calpine Corporation

($ millions)

Adjusted Unlevered Free Cash Flow1 Adjusted EBITDA1 Guidance

• Operations: CPN fleet operated well
• Markets:

– Texas: Houston zone separation + Forward spark spread rally – Mid‐Atlantic: Attractive print in latest capacity auction – California: Heat wave drove spark spreads above expectations

• Gov/Reg: Despite IL and NY court rulings, progress made against

nuke bailout efforts in CT, OH, NJ, PA

Key 2Q Messages

3

Reaffirming 2017 Guidance

Evaluating potential sale of Calpine2

1 A non‐GAAP financial measure. Reconciliations of Adj. EBITDA to Net Income (Loss) and Adj. Unlevered FCF to Cash Provided by Operating Activities, the most comparable U.S. GAAP measures, are included in the appendix. 2 Calpine’s Board of Directors, together with management and financial and legal advisors, are in discussions regarding a potential sale of Calpine. The Board plans to proceed in a timely manner, but has not set a definitive timetable for

completion of this process. There can be no assurance that these discussions will result in a transaction of any kind, or if a transaction is undertaken, as to terms or timing. Calpine does not intend to disclose developments or provide updates on the status of these discussions unless or until it is determined that further disclosure is appropriate or required by law.

Second Quarter Performance Consistent with Last Year

Adjusted EBITDA1 ($M)

$452 $419 2Q16 2Q17

Gas transportation credit ($40M)

$52 $44 $42 Peer (current) 2013‐2015 3 Year Avg 2016 Wholesale Gas Fleet Costs ($/kW)

2.1 0.1 3.2 2.6 0.5 0.3 3.0 2.5 West ‐ Gas West ‐ Geo Texas East CPN 2Q16 2Q17

3,685 1,350 12,607 9,125 2,210 1,413 11,152 7,463 West ‐ Gas West ‐ Geo Texas East 2Q16 2Q17

Portfolio Changes

4 Calpine Corporation

1 As compared to our SEC filings, generation shown here includes net interest in generation from our unconsolidated power plants and plants owned but not operated by us. 2 According to EEI safety survey (2016). 3 Source for peer current cost and target: NRG investor presentation, 7/12/17. CPN costs exclude Geysers and Retail.

Generation in Key Markets (000 MWh)1 Employee Total Reportable Incident Rate

Key YoY Drivers:  Near‐record hydro  Delta outage  Reversal of coal/gas switching  Osprey, Mankato

Forced Outage Factor (FOF, %)

Geysers wildfire Geysers wildfire Delta outage Delta

• utage

1.9 0.1 2.7 2.2 5.4 3.0

Calpine Cost Leadership3 ($/kW)

14.5

Focused on Best‐in‐Class Operations

10.7

EEI top quartile2

CPN

Peer Cost Target

$12 $13 $14 $15 $16 $17 $18 2018 2019 2020 Houston Spark Spread ($/MWh) 04/13/17 07/14/17 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 10 12 14 16 18 20 22 24 NorCal Non‐Renewable Supply / Load (MW) Hour Ending Load Available Resources Outages $‐ $50 $100 $150 $200 $250 2018/19 2019/20 2020/21 Auction Cleearing Price ($/MW‐d) RTO CPN MW‐weighted price EMAAC

East Texas California

5 Calpine Corporation

3

1 Source: CAISO, Calpine. Data shown for 6/21/17. Calculation of non‐renewable supply excludes wind, solar, geothermal and estimated hydro in Northern California, as well as net imports. 2 Spark spreads based on 7,000 Btu/kWh heat rate. 3 Prices shown for Capacity Performance product in all years. CPN reflects MW‐weighted average clearing price for capacity that cleared in each auction and does not include any capacity sold under bilateral contracts.

2

During Recent Heat Wave, Northern Calif. Operated at a Tight Margin On‐Peak Spark Spread Rally Recent Events Shaping Landscape

• f Texas Power Market

Locationally Advantaged PJM Fleet Benefits from Premium Zone Separation Key Debate Remains Market Design Integrity in Face of State Actions

• Looking ahead:

‒ Diablo Canyon nuclear plant to retire ‒ Per CAISO report, potential for additional retirements of uneconomic gas‐fired resources

• How will CAISO and other stakeholders react?
• Panda bankruptcy
• Potential ExGen bankruptcy?
• Retirements of Clear Lake, Greens Bayou
• Cancellation of development projects (CPN, NRG)
• PUCT consideration of Hogan/Pope report

+ Proposed tariff reforms in PJM and ISO‐NE to

address subsidized resources

• Nuclear bailout efforts:

+ Battles underway in CT, OH, NJ, PA;

trending positively

– IL and NY courts dismissed complaints;

IL appeal filed and granted

+ New FERC commissioner appointments

? DOE study

What happens with:

• Nuclear / OTC

retirements

• Potential

retirements of gas‐fired resources

1

Total Non‐Renewable Supply

Regional Power Market Trends

Non‐renewable:

Recent Heat Wave Demonstrates Gas Assets Critical Now and for the Foreseeable Future

FINANCIAL UPDATE

Calpine Corporation 6

7 Calpine Corporation

Full Year Guidance On Track

Full Year Drivers (YoY)

2Q in Line with Expectations

Second Quarter Drivers (YoY)

1 A non‐GAAP financial measure. Reconciliations of Adj. EBITDA to Net Income (Loss) and Adj. Unlevered FCF to Cash Provided by Operating Activities, the most comparable U.S. GAAP measures, are included in the appendix.

($ millions)

Bal‐2017 (YoY) Taxes/Other: $11 Taxes/Other: $10

Reaffirming Full Year Guidance

Full year guidance on track, due to 2H17 uplift

1 1

1 1

1

1

Primary Drivers: — Gas transportation billing credit (2Q16)  Higher contribution from retail hedging activity (Solutions acquisition)  Higher realized spark spreads in the evening peaks, partially offset by lower generation Primary Drivers: — Sales of Mankato (Oct 16) and Osprey (Jan 17) — Lower market spark spreads — Expiration of PPA at York Energy Center  Higher contribution from retail hedging activity (Solutions and NAP acquisitions) Primary Drivers:  Higher on‐peak realized spark spreads in Houston zone  Higher contribution from retail hedging activities (Solutions acquisition) — Lower generation due to higher natural gas prices Generation2

8

($ millions, 000 MWh)

West Region Texas Region East Region

Commodity Margin1,3 Commodity Margin1 Commodity Margin1 Generation2 Generation2

1 A non‐GAAP financial measure. Reconciliations of Income (Loss) from Operations to Commodity Margin, the most comparable U.S. GAAP measure, are included in the appendix. 2 As compared to our SEC filings, generation shown here includes net interest in generation from unconsolidated projects and plants owned but not operated by us. 3 South Point excluded from all results.

Calpine Corporation

Regional Commodity Margin1: 2Q 2017 vs. 2016

Osprey, Mankato

Wholesale Energy Margin + Wholesale Regulatory & Other Margin Wholesale Margin + Retail Margin (2017E: $375M ‐ $425M) Total Commodity Margin

9

Use in conjunction with modeling tips in appendix

3 3

Change to Commodity Margin ($M)

Natural Gas Price Sensitivity2

(assuming no change in heat rate)

Market Heat Rate Sensitivity2

(assuming no change in gas price)

Change to Commodity Margin ($M)

Sensitivities are assumed to occur across the portfolio and the sensitivities on strategic options only capture intrinsic value.

3 Volumes are on a delta hedge basis. Delta volumes are the expected volume based on the probability of economic dispatch at a future date based on current market prices for that future date. This is lower than the notional volume, which is plant

capacity, less known performance and operating constraints. In addition to planned upgrades, volumes assume addition of York 2 and retirement of Wolfskill and King City Peakers in 2018.

4 Represents Calpine’s forecasted average annual capacity of net ownership interest with peaking capacity, excluding equity plants. Capacity additions/deletions are reflected in anticipated month of completion. 5 Spark spread in NP‐15, ERCOT and NEPOOL based upon 7,000 btu/kWh production heat rate and in PJM‐W based upon 8,000 btu/kWh production heat rate. NP‐15 adjusted to deduct cost of carbon cap‐and‐trade,

without which, spark spreads would have been $9.29 and $11.97, respectively. NEPOOL adjusted to deduct cost of RGGI, without which, sparks spreads would have been $12.07 and $11.94, respectively.

1 Wholesale Energy Margin + Wholesale Regulatory & Other Margin = Wholesale

Margin + Retail Margin = Total Commodity Margin.

2 Estimated as of 7/14/17. Excludes immaterial proprietary positions. Hedged

margin excludes unconsolidated projects and includes the current mark‐to‐ market adjustments of all executed transactions. Changing market heat rates will change delta volumes and gas price exposures.

2017 2018 2019

Hedged Wholesale Margin ($/MWh)2 $18 $20 $27

• Avg. MW in

Operation2,4

(excl. unconsol.)

25,410 25,830 26,175 $ Wholesale Energy Margin1,2 as % of Wholesale Margin (by year):

71% 67% 69%

Comparable hedge level, 1Q17 Call Volume estimates (MM MWh): ~95

Standalone Treatment of Retail Margin1: Key Messages: 1) 2017 volumes up in California and Texas versus prior estimates 2) Highly hedged in 2017 3) Added ERCOT hedges in 2018 and 2019 4) Retail platform adding stability

Calpine Corporation

Wholesale Hedge and Retail Margin Disclosure

2017 On Peak Spark Spread5

Last Call (04/13/17) This Call (07/14/17) NP‐15 $4.02 $6.51 ERCOT‐Houston $14.55 $16.08 PJM‐W $13.15 $12.61 NEPOOL $10.78 $10.48 Nat Gas (HH) $3.28 $3.03

APPENDIX

Calpine Corporation 10

2Q17 2Q16 2Q17 2Q16 Total MWh Generated (in thousands) 1 22,238 26,767 Average Capacity Factor, excl. Peakers 44.4% 50.2% West 3,623 5,035 West 23.8% 33.1% Texas 11,152 12,607 Texas 56.3% 61.7% East 7,463 9,125 East 50.3% 51.7% Average Availability 82.2% 85.6% Steam Adjusted Heat Rate (Btu/KWh) 7,318 7,313 West 72.5% 85.6% West 7,547 7,316 Texas 84.2% 88.9% Texas 7,058 7,138 East 87.4% 82.4% East 7,646 7,570 YTD17 YTD16 YTD17 YTD16 Total MWh Generated (in thousands) 1 43,519 51,311 Average Capacity Factor, excl. Peakers 43.6% 48.8% West 9,072 11,453 West 30.0% 38.0% Texas 20,862 24,083 Texas 52.5% 58.9% East 13,585 15,775 East 45.9% 46.3% Average Availability 84.8% 87.8% Steam Adjusted Heat Rate (Btu/KWh) 7,331 7,289 West 79.4% 88.0% West 7,410 7,324 Texas 85.6% 87.8% Texas 7,086 7,095 East 88.0% 87.7% East 7,678 7,581

11

1 Generation has been adjusted to include net interest in generation from our unconsolidated power plants and plants owned but not operated by us. 2 Generation, average availability and steam adjusted heat rate excludes power plants and units that are inactive.

Calpine Corporation

Selected Operating Statistics

1,2 2 2 1,2 2 2

Primary Drivers:  Higher contribution from retail hedging activities (Solutions acquisition)  Higher realized spark spreads in the evening peaks — Gas transportation billing credit (2Q16) Primary Drivers: — Sales of Mankato (Oct 16) and Osprey (Jan 17) — Expiration of PPA at York Energy Center — Lower market spark spreads — Lower capacity revenues in first quarter  Higher contribution from retail hedging activity (Solutions and NAP acquisitions)  Addition of PPA at Morgan in Feb 2016 Primary Drivers:  Higher market spark spreads  Higher contribution from retail hedging activities (Solutions acquisition) — Lower contribution from wholesale hedging activity — Lower generation due to higher natural gas prices Generation2

12

($ millions, 000 MWh)

West Region Texas Region East Region

Commodity Margin1,3 Commodity Margin1 Commodity Margin1 Generation2 Generation2

1 A non‐GAAP financial measure. Reconciliations of Income (Loss) from Operations to Commodity Margin, the most comparable U.S. GAAP measure, are included in the appendix. 2 As compared to our SEC filings, generation shown here includes net interest in generation from unconsolidated projects and plants owned but not operated by us. 3 South Point excluded from all results.

Calpine Corporation

Regional Commodity Margin1: YTD 2017 vs. 2016

Osprey, Mankato

Calpine Corporation 13

1. Estimate annual generation (MWh) based on market outlook relative to disclosed historical generation with adjustments for asset acquisitions, asset divestitures and plants reaching commercial operations as well as changes in gas and coal price environments.

• Note: Estimated generation in this step should exclude volumes from unconsolidated

investments (Greenfield, Whitby). Margin from these plants is captured in step 7 below. 2. Estimate hedged wholesale energy margin based on disclosed % hedged (blue bars) and disclosed hedge margin ($/MWh).

• Note: 2017 hedged wholesale margin ($/MWh) is full year average including YTD
• settlements. 2017 hedge profile is for balance of year only (applicable for steps 3 and 4

as well). 3. Estimate Geysers unhedged wholesale energy margin using MWh estimate (historically, ~6 million MWh), assuming that the Geysers unhedged % is the same as the entire portfolio in 2017 and ~50% in 2018 ‐ 2019. Apply NP‐15 ATC prices. 4. Estimate gas fleet unhedged wholesale energy margin based on rough assumptions:

• Dispatched generation tends to capture a premium to the block on‐peak spark spread

for open volume. This premium varies significantly with, and is inversely related to, dispatch volumes. For 2017, this relationship is captured within our guidance. For years past 2017, depending upon your volume assumption in step 1 above, use the following rules of thumb for applying the premium:

• For this exercise, hedge profile is assumed to be relatively flat across all regions, and

disclosed regional steam adjusted plant heat rates should be considered when calculating spark spreads. 5. Adjust wholesale energy margin to capture items such as ancillary services and storage positions (benefit of small tens of millions), as well as environmental allowance costs in California (AB32) and in states that participate in RGGI.

• To consider Calpine's AB32 costs, apply our combined‐cycle average emissions rate
• f 860 lb/MWh for the California combined‐cycle plants and assume that ~25% of

those costs are passed on to our customers per contractual arrangements. Note: This step is only required if the on‐peak spark spread used in step 4 has not been adjusted to capture carbon cost in California.

• To consider Calpine’s RGGI costs, apply our combined‐cycle average emissions rate
• f 860 lb/MWh for our power plants in ME, MA, NH, NY, and DE and assume that we

retain 100% of these costs. Note: This step is only required if the on‐peak spark spread used in step 4 has not been adjusted to capture RGGI credit cost for affected plants. 6. The sum of steps 2 through 5 above will provide you with an estimate of our Wholesale Energy Margin. To estimate the contribution of Wholesale Reliability and Other Margin (regulatory capacity and REC revenue) and arrive at an estimate of total Wholesale Margin, simply divide the Wholesale Energy Margin by the disclosed percentages of Wholesale Energy Margin as a % of total Wholesale Margin. 7. Add estimated Retail Margin for all periods to arrive at total Commodity Margin. (For 2017, Retail Margin is estimated at $375 million ‐ $425 million.) 8. Add estimated margin from unconsolidated investments (Greenfield, Whitby) by multiplying Calpine capacity (net interest) by $110/kw‐yr in all periods shown.

• Since these margins from unconsolidated investments are not included in

Commodity Margin, but are included in Adjusted EBITDA, it is necessary to additionally estimate expenses related to unconsolidated investments for purposes

• f calculating Adjusted EBITDA.

9. When modeling operating costs for the consolidated power plants and retail entities, use 2016 reported plant operating expense1 and sales, general and administrative expense2 and other operating expense and apply an inflationary factor for 2017 and subsequent periods, with adjustments for asset/retail acquisitions, asset divestitures and plants reaching commercial operations.

• To capture the impact of net portfolio changes on total costs from 2016 to 2017, add

~$130 million to total costs1,2 in 2017 as compared to 2016, primarily to account for Solutions and NAP retail acquisitions. Volume Projection (excl. unconsolidated) (MM MWh) Recommended Premium to On‐ Peak Spark Spread <90 10% ‐ 20% 90 – 100 0% ‐ 10% 100 – 110… (10)% ‐ 0%

Note: Tips are provided to help investors consider simplifying techniques to apply the information disclosed to date in their modeling efforts. These tips are naturally less precise than models based on detailed

• perational, contract, and hedge position data might be.

1 Excluding major maintenance expense, non‐cash loss on disposal of assets, and stock‐based compensation. 2 Excluding stock‐based compensation.

Although Calpine’s fleet can be difficult to model, simplifying techniques may help

Calpine Corporation 14

Total Debt: $ 11,922 Add: Net Debt from Unconsolidated Projects3 112 Add: Debt Issuance Costs4 138 Net Debt $ 11,636 $8,659

Corporate Revolver First Lien Term Loans Senior Secured Notes

Total Corporate Debt Corporate Debt

$1,842 $3,403

• Steamboat

− Freeport − Morgan

• Bethpage
• Otay Mesa
• Pasadena1
• Russell City
• Los Esteros

Projects

• Hidalgo
• King City
• Stony Brook
• Other

Projects

• Brazos Valley
• Magic Valley
• Bosque
• Fore River
• Westbrook
• Guadalupe

Projects Project Debt $1,525 CCFC $1,547 Capital Lease Obligations & Other $191

Less: 25% Russell City Debt2 (109)

Unsecured Notes $3,414

Less: Cash, Cash Equivalents & Restr. Cash (427)

All balances as of 6/30/17.

1 In 4Q15, we entered into an agreement with one of the two lessors of our Pasadena Power Plant to purchase their 50% interest. The transaction is expected to close during 2017. 2 Equal to minority interest in debt associated with Russell City Energy Center, excluding debt issuance costs. 3 Equal to our net interest in total debt, less cash and cash equivalents and restricted cash from unconsolidated subsidiaries as disclosed in 10‐K. 4 Reported as a component of Other Assets prior to 1/1/16.

($ millions)

$ –

Capital Structure Chart

15

Geographic Diversity Dispatch Technology

As of 07/28/2017

• Geographically diversified portfolio: Scale in America’s most competitive power markets
• Featuring one of smallest environmental footprints in America’s power generation sector
• Largest operator of combined heat and power (cogeneration) technology in America
• Largest geothermal power producer in America

Calpine Corporation

National Portfolio of Approximately 26,000 MW

Technology Load Type Location COD With Peaking Capacity CPN Interest With Peaking Capacity, Net West Region Agnews Power Plant Natural Gas Intermediate CA 1990 28 100% 28 Creed Energy Center Natural Gas Peaking CA 2003 47 100% 47 Delta Energy Center Natural Gas Intermediate CA 2002 857 100% 857 Feather River Energy Center Natural Gas Peaking CA 2002 47 100% 47 Geysers (13 plants) Geothermal Baseload CA 1971 ‐ 1989 725 100% 725 Gilroy Cogeneration Plant* Natural Gas Intermediate CA 1988 130 100% 130 Gilroy Energy Center Natural Gas Peaking CA 2002 141 100% 141 Goose Haven Energy Center Natural Gas Peaking CA 2003 47 100% 47 Hermiston Power Project Natural Gas Intermediate OR 2002 635 100% 635 King City Cogeneration Plant* Natural Gas Intermediate CA 1989 120 100% 120 King City Peaking Energy Center (1) Natural Gas Peaking CA 2002 44 100% 44 Lambie Energy Center Natural Gas Peaking CA 2003 47 100% 47 Los Esteros Critical Energy Facility Natural Gas Intermediate CA 2013 309 100% 309 Los Medanos Energy Center* Natural Gas Intermediate CA 2001 572 100% 572 Metcalf Energy Center Natural Gas Intermediate CA 2005 605 100% 605 Otay Mesa Energy Center Natural Gas Intermediate CA 2009 608 100% 608 Pastoria Energy Center Natural Gas Intermediate CA 2005 749 100% 749 Riverview Energy Center Natural Gas Peaking CA 2003 47 100% 47 Russell City Energy Center Natural Gas Intermediate CA 2013 619 75% 464 South Point Energy Center (2) Natural Gas Intermediate AZ 2001 530 100% 530 Sutter Energy Center (2) Natural Gas Intermediate CA 2001 578 100% 578 Wolfskill Energy Center (1) Natural Gas Peaking CA 2003 48 100% 48 Yuba City Energy Center Natural Gas Peaking CA 2002 47 100% 47 Total ‐ West Region 7,425 Texas Region Baytown Energy Center* Natural Gas Intermediate TX 2002 842 100% 842 Bosque Energy Center Natural Gas Intermediate TX 2000/2011 762 100% 762 Brazos Valley Power Plant Natural Gas Intermediate TX 2003 609 100% 609 Channel Energy Center* Natural Gas Intermediate TX 2001 808 100% 808 Corpus Christi Energy Center* Natural Gas Intermediate TX 2002 500 100% 500 Deer Park Energy Center* Natural Gas Intermediate TX 2003 1,204 100% 1,204 Freeport Energy Center* Natural Gas Intermediate TX 2007 236 100% 236 Freestone Energy Center Natural Gas Intermediate TX 2002 994 75% 746 Guadalupe Energy Center Natural Gas Intermediate TX 2001/2011 1,000 100% 1,000 Hidalgo Energy Center Natural Gas Intermediate TX 2000 476 79% 374 Magic Valley Generation Station Natural Gas Intermediate TX 2002 712 100% 712 Pasadena Power Plant* Natural Gas Intermediate TX 1998 781 100% 781 Texas City Power Plant* Natural Gas Intermediate TX 1987 453 100% 453 Total ‐ Texas Region 9,027

Calpine Corporation 16

Calpine Operating Power Plants

As of July 28, 2017

Technology Load Type Location COD With Peaking Capacity CPN Interest With Peaking Capacity, Net East Region Auburndale Peaking Energy Center Natural Gas Peaking FL 2002 117 100% 117 Bayview Oil Peaking VA 1963 12 100% 12 Bethlehem Natural Gas / Oil Intermediate PA 2003 1,130 100% 1,130 Bethpage Energy Center 3 Natural Gas Intermediate NY 2005 80 100% 80 Bethpage Peaker Natural Gas Peaking NY 2002 48 100% 48 Bethpage Power Plant Natural Gas Intermediate NY 1989 56 100% 56 Cumberland Natural Gas / Oil Peaking NJ 1990/2009 191 100% 191 Edge Moor* Natural Gas / Oil Peaking DE 1965 725 100% 725 Fore River Energy Center Natural Gas / Oil Intermediate MA 2003 731 100% 731 Garrison Energy Center Natural Gas Intermediate DE 2015 309 100% 309 Granite Ridge Energy Center Natural Gas Intermediate NH 2003 695 100% 695 Greenfield Energy Centre Natural Gas Intermediate Ontario, CA 2008 1,038 50% 519 Hay Road Natural Gas / Oil Intermediate DE 1989 1,130 100% 1,130 Kennedy Int'l Airport Power Plant* Natural Gas Intermediate NY 1995 121 100% 121 Mid‐Atlantic Peakers** Natural Gas / Oil Peaking NJ/DE/MD/VA 1965‐1991 371 100% 371 Morgan Energy Center* Natural Gas Intermediate AL 2003 807 100% 807 Pine Bluff Energy Center* Natural Gas Intermediate AR 2001 215 100% 215 RockGen Energy Center Natural Gas Peaking WI 2001 503 100% 503 Stony Brook Power Plant* Natural Gas Intermediate NY 1995 47 100% 47 Vineland Solar Solar Peaking NJ 2009 4 100% 4 Westbrook Energy Center Natural Gas Intermediate ME 2001 552 100% 552 Whitby Cogen* Natural Gas Intermediate Ontario, CA 1998 50 50% 25 York Energy Center Natural Gas Intermediate PA 2011 565 100% 565 Zion Energy Center Natural Gas Peaking IL 2002 503 100% 503 Total ‐ East Region 9,456 TOTAL ‐ CALPINE 25,908 Projects Under Construction York 2 Energy Center Natural Gas Intermediate PA 2018 (est) 828 100% 828 Projects Under Advanced Development Washington Parish Energy Center(3) Natural Gas Peaking LA 2021 (est) 361 100% 361 * Indicates cogeneration plant ** Includes Carll's Corner, Christiana, Crisfield, Delaware City, Mickleton, Sherman Avenue, Tasley, West.

(1) Upon expiration of the tolling agreements on December 31, 2017, we will assess the future of these facilities. (2) We suspended operations to assess the future of these facilities. (3) A third party will purchase a 100% ownership interest in this power plant upon achieving commercial operation.

Calpine Corporation 17

Calpine Operating Power Plants (cont’d)

As of July 28, 2017

Calpine Corporation 18

Commodity Margin includes revenues recognized on our wholesale and retail power sales activity, electric capacity sales, renewable energy credit sales, steam sales, realized settlements associated with

• ur marketing, hedging, optimization and trading activity, fuel and purchased energy expenses, commodity transmission and transportation expenses and environmental compliance expenses. We

believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin does not intend to represent income (loss) from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly‐ titled measures reported by other companies.

($ millions)

RegG Reconciliation: Commodity Margin

Calpine Corporation 19

Commodity Margin includes revenues recognized on our wholesale and retail power sales activity, electric capacity sales, renewable energy credit sales, steam sales, realized settlements associated with

• ur marketing, hedging, optimization and trading activity, fuel and purchased energy expenses, commodity transmission and transportation expenses and environmental compliance expenses. We

believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin does not intend to represent income (loss) from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly‐ titled measures reported by other companies.

RegG Reconciliation: Commodity Margin (cont’d)

($ millions)

Calpine Corporation 20

Adjusted Free Cash Flow represents cash flows from operating activities including the effects of maintenance capital expenditures, adjustments to reflect the Adjusted Free Cash Flow from unconsolidated investments and to exclude the noncontrolling interest and other miscellaneous adjustments such as the effect of changes in working capital. Adjusted Unlevered Free Cash Flow is calculated on the same basis at Adjusted Free Cash Flow but excludes the effect of cash interest, net, and

• perating lease payments, thus capturing the performance of our business

independent of its capital structure. Adjusted Free Cash Flow and Adjusted Unlevered Free Cash Flow are presented because we believe they are useful measures of liquidity to assist in comparing financial results from period to period

• n a consistent basis and to readily view operating trends, as measures for planning

and forecasting overall expectations and for evaluating actual results against such expectations and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial results. Adjusted Free Cash Flow and Adjusted Unlevered Free Cash Flow are liquidity measures and are not intended to represent cash flows from operations, the most directly comparable U.S. GAAP measure, and are not necessarily comparable to similarly titled measures reported by other companies. Adjusted EBITDA represents net loss attributable to Calpine before net (income) attributable to the noncontrolling interest, interest, taxes, depreciation and amortization, and is also adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark‐to‐market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock‐based compensation expense,

• perating lease expense, non‐cash gains and losses from foreign currency

translations, major maintenance expense, gains or losses on the repurchase, modification or extinguishment of debt, non‐cash GAAP‐related adjustments to levelize revenues from tolling agreements and any unusual or non‐recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated

• investments. We adjust for these items in our Adjusted EBITDA as our management

believes that these items would distort their ability to efficiently view and assess our core operating trends. We believe that investors commonly adjust EBITDA information to eliminate the effects of restructuring and other expenses, which vary widely from company to company and impair comparability. Adjusted EBITDA is not intended to represent net income (loss) as defined by U.S. GAAP as an indicator of

• perating performance and is not necessarily comparable to similarly titled

measures reported by other companies. We are presenting Adjusted EBITDA along with a reconciliation to Adjusted Unlevered Free Cash Flow to demonstrate the relationship between our traditional performance measure, Adjusted EBITDA, and

• ur new liquidity measure, Adjusted Unlevered Free Cash Flow.

($ and shares in millions)

RegG Reconciliation: Adjusted EBITDA , Adjusted Unlevered Free Cash Flow and Adjusted Free Cash Flow

Calpine Corporation 21

Adjusted Free Cash Flow represents cash flows from operating activities including the effects of maintenance capital expenditures, adjustments to reflect the Adjusted Free Cash Flow from unconsolidated investments and to exclude the noncontrolling interest and other miscellaneous adjustments such as the effect of changes in working capital. Adjusted Unlevered Free Cash Flow is calculated on the same basis at Adjusted Free Cash Flow but excludes the effect of cash interest, net, and operating lease payments, thus capturing the performance of our business independent of its capital structure. Adjusted Free Cash Flow and Adjusted Unlevered Free Cash Flow are presented because we believe they are useful measures of liquidity to assist in comparing financial results from period to period on a consistent basis and to readily view operating trends, as measures for planning and forecasting overall expectations and for evaluating actual results against such expectations and in communications with our Board

• f Directors, shareholders, creditors, analysts and investors concerning our financial results. Adjusted Free Cash Flow and Adjusted Unlevered Free Cash Flow are liquidity measures and are not intended to

represent cash flows from operations, the most directly comparable U.S. GAAP measure, and are not necessarily comparable to similarly titled measures reported by other companies.

RegG Reconciliation: Adjusted Unlevered Free Cash Flow and Adjusted Free Cash Flow

($ millions)

Calpine Corporation 22

RegG Reconciliation: 2017 Guidance